Edgar Filing: Laredo Petroleum, Inc.

1Q15 Laredo Petroleum, Inc.

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended March 31, 2015

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, 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 900
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 ý		Accelerated filer o

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 May 4, 2015: 213,878,297

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 March 31, 2015 and December 31, 2014	1
	Consolidated statements of operations for the three months ended March 31, 2015 and 2014	2
	Consolidated statement of stockholders' equity for the three months ended March 31, 2015	3
	Consolidated statements of cash flows for the three months ended March 31, 2015 and 2014	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.	Repurchase of Equity Securities	54
Item 3.	Defaults Upon Senior Securities	54
Item 4.	Mine Safety Disclosures	54
Item 5.	Other Information	55
Item 6.	Exhibits	56
Signatures		57
Exhibit Index		58

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 (the "Exchange Act"). These forward-looking statements include statements, projections and estimates concerning our operations, performance, business strategy, oil and natural gas reserves, drilling program capital expenditures, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, derivative activities and potential financing. Forward-looking statements are generally accompanied by words such as "estimate," "project," "predict," "believe," "expect," "anticipate," "potential," "could," "may," "will," "foresee," "plan," "goal," "should," "intend," "pursue," "target," "continue," "suggest" or the negative thereof or other variations thereof 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 volatility of oil and natural gas prices;


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


•	the continuation of restrictions on the export of domestic crude oil and its potential to cause weakness in domestic pricing;

•

the potentially insufficient refining capacity in the U.S. Gulf Coast to refine all of the light sweet crude oil being produced in the United States, which, coupled with the export limitations noted above and a continuing increase in light sweet crude oil production, could result in widening price discounts to world crude prices and potential shut-in of production due to lack of sufficient markets;


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


•	regulations that prohibit or restrict our ability to apply hydraulic fracturing to our oil and natural gas wells and to access and dispose of water used in these operations;


•	legislation or regulations that prohibit or restrict our ability to drill new allocation wells;


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


•	our ability to discover, estimate, develop and replace 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;


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


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


•	risks related to the geographic concentration of our assets;


•	capital requirements for our operations and projects;


•	our ability to maintain or increase the borrowing capacity under our Senior Secured Credit Facility (as defined below) or access other means of providing capital and liquidity;


•	our ability to generate sufficient cash to service our indebtedness, fund our capital requirements and to generate future profits;


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


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


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


•	restrictions contained in our debt agreements, including our Senior Secured Credit Facility and the indentures governing our senior unsecured notes, as well as debt that could be incurred in the future, and;

iii


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

These forward-looking statements involve a number of risks and uncertainties that could cause actual results to differ materially from those suggested by the forward-looking statements. Forward-looking statements should, therefore, be considered in light of various factors, including those set forth under "Part I, Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations," "Part II, Item 1A. Risk Factors" and elsewhere in this Quarterly Report, 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, 2014 (the "2014 Annual Report"), and those set forth from time to time in our other filings with the Securities and Exchange Commission (the "SEC"). These documents are available through our website or through the SEC's Electronic Data Gathering and Analysis Retrieval system at http://www.sec.gov. In light of such risks and uncertainties, we caution you not to place undue reliance on these forward-looking statements. These forward-looking statements speak only as of the date of this Quarterly Report, or if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities law.

PART I

Item 1. Consolidated Financial Statements (Unaudited)

Laredo Petroleum, Inc.

Consolidated balance sheets

(in thousands, except share data)

(Unaudited)



	March 31, 2015			December 31, 2014
Assets
Current assets:
Cash and cash equivalents	$	569,093		$	29,321
Accounts receivable, net	110,003			126,929
Derivatives	195,078			194,601
Other current assets	27,430			14,402
Total current assets	901,604			365,253
Property and equipment:
Oil and natural gas properties, full cost method:
Evaluated properties	4,692,853			4,446,781
Unevaluated properties not being amortized	307,845			342,731
Midstream service assets	139,224			117,052
Other fixed assets	60,901			56,165
Total property and equipment	5,200,823			4,962,729
Less accumulated depletion, depreciation, amortization and impairment	(1,680,364		)	(1,608,647		)
Net property and equipment	3,520,459			3,354,082
Derivatives	118,587			117,788
Debt issuance costs, net	33,513			28,463
Investment in equity method investee	72,350			58,288
Other assets, net	8,510			8,675
Total assets	$	4,655,023		$	3,932,549
Liabilities and stockholders' equity
Current liabilities:
Accounts payable	$	30,410		$	39,008
Short-term debt	551,230			—
Undistributed revenue and royalties	46,216			65,438
Accrued capital expenditures	118,175			148,241
Deferred income taxes	73,753			71,191
Derivatives	—			115
Other current liabilities	73,048			101,032
Total current liabilities	892,832			425,025
Long-term debt	1,300,000			1,801,295
Deferred income taxes	106,835			105,754
Asset retirement obligations	32,136			31,042
Other noncurrent liabilities	4,108			6,232
Total liabilities	2,335,911			2,369,348
Commitments and contingencies
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued at March 31, 2015 and December 31, 2014	—			—
Common stock, $0.01 par value, 450,000,000 shares authorized, and 213,883,270 and 143,686,491 issued, at March 31, 2015 and December 31, 2014, respectively	2,139			1,437
Additional paid-in capital	2,064,852			1,309,171
Retained earnings	252,121			252,593
Total stockholders' equity	2,319,112			1,563,201
Total liabilities and stockholders' equity	$	4,655,023		$	3,932,549

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

Laredo Petroleum, Inc.

Consolidated statements of operations

(in thousands, except per share data)

(Unaudited)



	Three months ended March 31,
	2015			2014
Revenues:
Oil, NGL and natural gas sales	$	118,118		$	173,214
Midstream service revenues	1,309			96
Sales of purchased oil	31,267			—
Total revenues	150,694			173,310
Costs and expenses:
Lease operating expenses	32,380			21,785
Midstream service expenses	1,574			845
Production and ad valorem taxes	9,086			12,450
Minimum volume commitments	1,656			516
Costs of purchased oil	31,200			—
General and administrative	21,855			27,654
Restructuring expenses	6,042			—
Accretion of asset retirement obligations	579			415
Depletion, depreciation and amortization	71,942			49,607
Impairment expense	878			—
Total costs and expenses	177,192			113,272
Operating income (loss)	(26,498		)	60,038
Non-operating income (expense):
Gain (loss) on derivatives, net	63,155			(31,112		)
Income (loss) from equity method investee	(433		)	16
Interest expense	(32,414		)	(28,986		)
Interest and other income	123			83
Write-off of debt issuance costs	—			(124		)
Loss on disposal of assets, net	(762		)	(21		)
Non-operating income (expense), net	29,669			(60,144		)
Income (loss) before income taxes	3,171			(106		)
Income tax expense:
Deferred	(3,643		)	(107		)
Total income tax expense	(3,643		)	(107		)
Net loss	$	(472	)	$	(213	)
Net loss per common share:
Basic	$	—		$	—
Diluted	$	—		$	—
Weighted-average common shares outstanding:
Basic	162,426			141,067
Diluted	162,426			141,067

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

Laredo Petroleum, Inc.

Consolidated statement of stockholders' equity

(in thousands)

(Unaudited)



	Common Stock					Additional paid-in capital			Treasury Stock (at cost)					Retained earnings
	Shares		Amount			Additional paid-in capital			Shares		Amount			Retained earnings			Total
Balance, December 31, 2014	143,686		$	1,437		$	1,309,171		—		$	—		$	252,593		$	1,563,201
Restricted stock awards	1,749		18			(18		)	—		—			—			—
Restricted stock forfeitures	(368	)	(4		)	4			—		—			—			—
Vested restricted stock exchanged for tax withholding	—		—			—			184		(2,283		)	—			(2,283		)
Retirement of treasury stock	(184	)	(2		)	(2,281		)	(184	)	2,283			—			—
Equity issuance, net of offering costs	69,000		690			753,473			—		—			—			754,163
Stock-based compensation	—		—			4,503			—		—			—			4,503
Net loss	—		—			—			—		—			(472		)	(472		)
Balance, March 31, 2015	213,883		$	2,139		$	2,064,852		—		$	—		$	252,121		$	2,319,112

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

Laredo Petroleum, Inc.

Consolidated statements of cash flows

(in thousands)

(Unaudited)



	Three months ended March 31,
	2015			2014
Cash flows from operating activities:
Net loss	$	(472	)	$	(213	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Deferred income tax expense	3,643			107
Depletion, depreciation and amortization	71,942			49,607
Impairment expense	878			—
Non-cash stock-based compensation, net of amounts capitalized	4,788			4,329
Accretion of asset retirement obligations	579			415
Mark-to-market on derivatives:
(Gain) loss on derivatives, net	(63,155		)	31,112
Cash settlements received (paid) for matured derivatives, net	63,141			(1,431		)
Cash settlements received for early terminations of derivatives, net	—			76,660
Change in net present value of deferred premiums paid for derivatives	43			65
Cash premiums paid for derivatives	(1,421		)	(1,959		)
Amortization of debt issuance costs	1,377			1,207
Write-off of debt issuance costs	—			124
Cash settlement of performance unit awards	(2,738		)	—
Other	1,163			(47		)
Decrease (increase) in accounts receivable	16,926			(3,619		)
Increase in other assets	(14,478		)	(4,616		)
Decrease in accounts payable	(8,598		)	(8,001		)
Decrease in undistributed revenues and royalties	(19,222		)	(1,052		)
Decrease in other accrued liabilities	(28,714		)	(14,893		)
Increase in other noncurrent liabilities	187			224
Increase in fair value of performance unit awards	996			98
Net cash provided by operating activities	26,865			128,117
Cash flows from investing activities:
Capital expenditures:
Acquisition of mineral interests	—			(7,305		)
Oil and natural gas properties	(243,733		)	(187,040		)
Midstream service assets	(20,434		)	(10,520		)
Other fixed assets	(3,919		)	(3,369		)
Investment in equity method investee	(14,495		)	(11,300		)
Proceeds from dispositions of capital assets, net of costs	35			268
Net cash used in investing activities	(282,546		)	(219,266		)
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility	175,000			—
Payments on Senior Secured Credit Facility	(475,000		)	—
Issuance of March 2023 Notes	350,000			—
Issuance of January 2022 Notes	—			450,000
Proceeds from issuance of common stock, net of offering costs	754,163			—
Purchase of treasury stock	(2,283		)	(3,274		)
Proceeds from exercise of employee stock options	—			1,585
Payments for debt issuance costs	(6,427		)	(7,796		)
Net cash provided by financing activities	795,453			440,515
Net increase in cash and cash equivalents	539,772			349,366
Cash and cash equivalents, beginning of period	29,321			198,153
Cash and cash equivalents, end of period	$	569,093		$	547,519

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

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note 1—Organization

Laredo Petroleum, Inc. ("Laredo"), together with its subsidiaries, Laredo Midstream Services, LLC ("LMS") and Garden City Minerals, LLC ("GCM"), is an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties primarily in the Permian Basin in West Texas. LMS and GCM (together, the "Guarantors") guarantee all of Laredo's debt instruments.

In these notes, the "Company," (i) when used in the present tense, prospectively or from October 24, 2014 to March 31, 2015, refers to Laredo, LMS and GCM collectively, unless the context indicates otherwise or (ii) when used for historical periods from December 31, 2013 to October 23, 2014, refers to Laredo and LMS collectively, unless the context indicates otherwise. All amounts, dollars and percentages presented in these unaudited consolidated financial statements and the related notes are rounded and therefore approximate.

The Company operates in two business segments, which are (i) exploration and production and (ii) midstream and marketing. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties primarily in the Permian Basin in West Texas. The midstream and marketing segment provides the exploration and production segment and certain third parties with (i) any products and services that need to be delivered by infrastructure, including oil and natural gas gathering services as well as rig fuel, natural gas lift and water in the primary drilling corridors and (ii) takeaway optionality in the field and firm service commitments to maximize oil, natural gas liquids ("NGL") and natural gas revenues.

Note 2—Basis of presentation and significant accounting policies

a. 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 the investee's net income (loss) is included in the unaudited consolidated statements of operations. See Note 14 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 accompanying consolidated financial statements have not been audited by the Company's independent registered public accounting firm, except that the consolidated balance sheet as of December 31, 2014 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 March 31, 2015 and the results of operations and cash flows for the three months ended March 31, 2015 and 2014.

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 the 2014 Annual Report.

b. 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. The interim results reflected in the unaudited consolidated financial statements are not necessarily indicative of the results that may be expected for other interim periods or for the full year.

Significant estimates include, but are not limited to, (i) estimates of the Company's reserves of oil, NGL and natural gas, (ii) future cash flows from oil and natural gas properties, (iii) depletion, depreciation and amortization, (iv) asset retirement obligations, (v) stock-based compensation, (vi) deferred income taxes, (vii) fair value of assets acquired and liabilities assumed in an acquisition and (viii) fair values of commodity derivatives, interest rate derivatives, commodity deferred premiums and performance unit awards. 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

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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.

c. Reclassifications

Certain amounts in the accompanying unaudited consolidated financial statements have been reclassified to conform to the 2015 presentation. These reclassifications had no impact to previously reported total assets, total liabilities, net income or loss, stockholders' equity or cash flows.

d. Treasury stock

Laredo's employees may elect to have the Company withhold shares of stock to satisfy their tax withholding obligations that arise upon the lapse of restrictions on their stock awards. Such treasury stock is recorded at cost and retired upon acquisition.

e. Accounts receivable

The Company sells oil, NGL and natural gas to various customers and participates with other parties in the drilling, completion and operation of oil and natural gas wells. The Company's accounts receivable 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 of 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 amounts greater than 90 days and over a specified amount are reviewed individually for collectability. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is remote.

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



(in thousands)	March 31, 2015		December 31, 2014
Oil, NGL and natural gas sales	$	44,859	$	57,070
Joint operations, net⁽¹⁾	25,752		33,808
Matured derivatives	20,829		16,098
Purchased oil and other product sales	17,963		18,917
Other	600		1,036
Total	$	110,003	$	126,929

______________________________________________________________________________


(1)	Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.1 million and $0.8 million as of March 31, 2015 and December 31, 2014, respectively.

f. Derivatives

The Company uses derivatives 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.

Derivatives are recorded at fair value and are included net on the unaudited consolidated balance sheets as assets or liabilities. The Company nets the fair value of derivatives by counterparty where the right of offset exists. The Company determines the fair value of its derivatives by 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 (see Notes 8 and 9).

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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 derivatives are included in cash flows from operating activities (see Note 8).

g. Property and equipment

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



(in thousands)	March 31, 2015			December 31, 2014
Evaluated oil and natural gas properties	$	4,692,853		$	4,446,781
Less accumulated depletion and impairment	(1,654,807		)	(1,586,237		)
Evaluated oil and natural gas properties, net	3,038,046			2,860,544

Unevaluated properties not being amortized	307,845			342,731

Midstream service assets	139,224			117,052
Less accumulated depreciation	(10,214		)	(8,590		)
Midstream service assets, net	129,010			108,462

Depreciable other fixed assets	47,289			42,933
Less accumulated depreciation and amortization	(15,343		)	(13,820		)
Depreciable other fixed assets, net	31,946			29,113

Land	13,612			13,232

Total property and equipment, net	$	3,520,459		$	3,354,082

For the three months ended March 31, 2015 and 2014, depletion expense was $16.08 per barrel of oil equivalent ("BOE") sold and $19.61 per BOE sold, respectively.

The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of finding oil and natural gas are capitalized and amortized on a composite unit of production method based on proved oil, NGL and natural gas reserves. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including related employee costs, associated with production and general corporate activities are expensed in the period incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas.

The Company excludes the costs directly associated with acquisition and evaluation of unevaluated properties from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties. The Company capitalizes a portion of its interest costs on its unevaluated properties. Capitalized interest becomes a part of the cost of the unevaluated properties and is subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated property are assessed on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of evaluated reserves, and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion.

The full cost ceiling is based principally on the estimated future net cash flows from proved oil and natural gas properties discounted at 10%. Full cost companies are required to use the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices were defined by contractual arrangements, to calculate the discounted future revenues. In the event the unamortized cost of evaluated oil and natural gas properties being amortized exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

h. Debt issuance costs

Debt issuance 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 $6.4 million of debt issuance costs during the three months ended March 31, 2015 as a result of the issuance of the March 2023 Notes (as defined below). The Company capitalized $7.8 million of debt issuance costs during the three months ended March 31, 2014 as a result of the issuance of the January 2022 Notes (as defined below). The Company had total debt issuance costs of $33.5 million and $28.5 million, net of accumulated amortization of $20.7 million and $19.4 million, as of March 31, 2015 and December 31, 2014, respectively.

As a result of changes in the borrowing base of the Senior Secured Credit Facility (as defined below) due to the issuance of the January 2022 Notes, the Company wrote-off approximately $0.1 million of debt issuance costs during the three months ended March 31, 2014. No debt issuance costs were written-off during the three months ended March 31, 2015. See Notes 5.a, 5.b and 5.e for definition of and information regarding the March 2023 Notes, January 2022 Notes and the Senior Secured Credit Facility, respectively.

Future amortization expense of debt issuance costs as of March 31, 2015 is as follows:



(in thousands)
Remaining 2015	$	4,587
2016	6,165
2017	6,236
2018	6,026
2019	2,913
Thereafter	7,586
Total	$	33,513

i. Other current assets and liabilities

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



(in thousands)	March 31, 2015		December 31, 2014
Prepaid expenses	$	18,043	$	6,451
Materials and supplies inventory and other	9,387		7,951
Total other current assets	$	27,430	$	14,402

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



(in thousands)	March 31, 2015		December 31, 2014
Accrued interest payable	$	27,969	$	37,689
Lease operating expense payable	17,121		11,963
Other accrued liabilities	27,958		51,380
Total other current liabilities	$	73,048	$	101,032

j. Asset retirement obligations

Asset retirement obligations associated with the retirement of tangible long-lived assets are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is charged to expense through depletion, or for midstream asset retirement cost through depreciation, of the associated 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.

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 into 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) estimated removal and/or remediation costs for midstream assets, (iv) estimated remaining life of midstream assets, (v) future inflation factors and (vi) the Company's average credit adjusted risk-free rate.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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.

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 become reasonably determinable.

The following reconciles the Company's asset retirement obligation liability for the periods presented:



(in thousands)	Three months ended March 31, 2015			Year ended December 31, 2014
Liability at beginning of period	$	32,198		$	21,743
Liabilities added due to acquisitions, drilling, midstream service asset construction and other	515			6,370
Accretion expense	579			1,787
Liabilities settled upon plugging and abandonment	(188		)	(450		)
Revision of estimates	—			2,748
Liability at end of period	$	33,104		$	32,198

k. 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 assets and liabilities approximate their fair values. See Note 5 for fair value disclosures related to the Company's debt obligations. The Company carries its derivatives at fair value. See Notes 8 and 9 for details regarding the fair value of the Company's derivatives.

l. Compensation awards

Stock-based compensation expense is included in "General and administrative" in the Company's unaudited consolidated statements of operations over the awards' vesting periods and is based on their grant date fair value. The Company utilizes the closing stock price on the grant date, 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 values of the performance share awards and performance unit awards. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil and gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the unaudited consolidated balance sheets. See Note 6 for further discussion regarding the restricted stock awards, restricted stock option awards, performance share awards and performance unit awards.

m. 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 incurred. 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 March 31, 2015 or December 31, 2014.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

n. Long-lived assets, materials and supplies and line-fill

Impairment losses are recorded on property and equipment used in operations and other long-lived assets when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset.

Materials and supplies are comprised of equipment used in developing oil and natural gas properties and are included in "Other current assets" and "Other assets, net" on the unaudited consolidated balance sheets. They are carried at the lower of cost or market ("LCM"). The market price for materials and supplies is determined utilizing the Company's recent prices paid to acquire materials. During the three months ended March 31, 2015, the Company reduced materials and supplies by $0.8 million in order to reflect the balance at LCM. The adjustment is included in "Impairment expense" in the unaudited consolidated statements of operations and in "Other operating costs and expenses" for the Company's exploration and production segment presented in Note 16. The Company determined an LCM adjustment was not necessary for materials and supplies during the three months ended March 31, 2014.

Minimum volumes of product in a pipeline system which enables the system to operate is known as line-fill, and is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. Beginning in the fourth quarter of 2014, the Company owns oil line-fill in third-party pipelines, which is accounted for at LCM with cost determined using the weighted-average cost method, and is included in "Other assets, net" on the unaudited consolidated balance sheets. The LCM adjustment is determined utilizing a quoted market price adjusted for regional price differentials (Level 2). For the three months ended March 31, 2015, the Company recorded an LCM adjustment of $0.1 million related to its line-fill, which is included in "Impairment expense" in the unaudited consolidated statements of operations and as "Other operating costs and expenses" for the Company's midstream and marketing segment presented in Note 16.

o. Non-cash investing and supplemental cash flow information

The following presents the non-cash investing and supplemental cash flow information for the periods presented:



	Three months ended March 31,
(in thousands)	2015			2014
Non-cash investing information:
Change in accrued capital expenditures	$	(30,066	)	$	10,622
Change in accrued capital contribution to equity method investee	$	—		$	5,574
Capitalized asset retirement cost	$	515		$	576
Supplemental cash flow information:
Capitalized interest	$	98		$	—

Note 3—Equity offering

On March 5, 2015, the Company completed the sale of 69,000,000 shares of Laredo's common stock at a price to the public of $11.05 per share (the "March 2015 Equity Offering"). The Company received net proceeds of $754.2 million, after underwriting discounts, commissions and offering expenses. Entities affiliated with Warburg Pincus LLC ("Warburg Pincus") purchased 29,800,000 shares in the March 2015 Equity Offering, following which Warburg Pincus owned 41.0% of Laredo's common stock. There were no comparative offerings of the Company's stock during the three months ended March 31, 2014.

Note 4—Acquisitions

a. 2014 acquisition of leasehold interests

On August 28, 2014, the Company completed a material acquisition of leasehold interests totaling 8,156 net acres in the Midland Basin, primarily within the Company's core development area, for $192.5 million. The acquisition was accounted for as an acquisition of assets.

b. 2014 acquisition of mineral interests

On February 25, 2014, the Company completed the acquisition of the mineral interests underlying 278 net acres in Glasscock County, Texas in the Permian Basin for $7.3 million. These mineral interests entitle the Company to receive royalty

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

interests on all production from this acreage with no additional future capital or operating expenses required. As such, the purchase was accounted for as an acquisition of assets.

c. 2014 acquisitions of evaluated and unevaluated oil and natural gas properties

The Company accounts for acquisitions of evaluated and unevaluated oil and natural gas properties 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.

The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair values of evaluated and unevaluated oil and natural gas properties. The fair values of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) reserves, (ii) future operating and development costs, (iii) future commodity prices and (iv) a market-based weighted-average cost of capital rate. The market-based weighted-average cost of capital rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating the value of the unevaluated properties, the discounted future net revenues of probable and possible reserves are reduced by additional risk-weighting factors.

On June 11, 2014, the Company completed the acquisition of evaluated and unevaluated oil and natural gas properties, totaling 460 net acres, located in Reagan County, Texas for $4.7 million, net of closing adjustments. On June 23, 2014, the Company completed the acquisition of evaluated and unevaluated oil and natural gas properties, totaling 24 net acres, located in Glasscock County, Texas for $1.8 million. The results of operations prior to June 2014 do not include results from these acquisitions.

Note 5—Debt

a. March 2023 Notes

On March 18, 2015, the Company completed an offering of $350.0 million in aggregate principal amount of 6 1/4% senior unsecured notes due 2023 (the "March 2023 Notes"), and entered into an Indenture (the "Base Indenture"), as supplemented by the Supplemental Indenture (the "Supplemental Indenture" and, together with the Base Indenture, the "Indenture"), among Laredo, LMS and GCM, as guarantors, and Wells Fargo Bank, National Association, as trustee. The March 2023 Notes will mature on March 15, 2023 with interest accruing at a rate of 6 1/4% per annum and payable semi-annually in cash in arrears on March 15 and September 15 of each year, commencing September 15, 2015. The March 2023 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain automatic customary releases, including the sale, disposition, or transfer of all of the capital stock or of all or substantially all of the assets of a subsidiary guarantor to one or more persons that are not the Company or a restricted subsidiary, exercise of legal defeasance or covenant defeasance options or satisfaction and discharge of the Indenture, designation of a subsidiary guarantor as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the Indenture, release from guarantee under the Senior Secured Credit Facility, or liquidation or dissolution (collectively, the "Releases").

The March 2023 Notes were offered and sold pursuant to a prospectus supplement dated March 4, 2015 and the base prospectus dated March 22, 2013, relating to the Company's effective shelf registration statement on Form S-3 (File No. 333-187479). The Company received net proceeds of $343.6 million from the offering, after deducting the initial purchasers' discount and the estimated outstanding offering expenses. In April 2015, the Company used the proceeds of the offering to fund a portion of the Company's redemption of the January 2019 Notes (defined below). See Note 19.a for additional discussion of this early redemption.

The Company may redeem, at its option, all or part of the March 2023 Notes at any time on or after March 15, 2018, at the applicable redemption price plus accrued and unpaid interest to, but not including, the date of redemption. Further, before March 15, 2018, the Company may on one or more occasions redeem up to 35% of the aggregate principal amount of the March 2023 Notes in an amount not exceeding the net proceeds from one or more private or public equity offerings at a redemption price of 106.25% of the principal amount of the March 2023 Notes, plus accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the March 2023 Notes remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of each such equity offering. If a change of control occurs prior to March 15, 2016, the Company may redeem all, but not less than all, of the March 2023 Notes at a redemption price equal to 110% of the principal amount of the March 2023 Notes plus any accrued and unpaid interest to, but not including, the date of redemption.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

b. January 2022 Notes

On January 23, 2014, the Company completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior unsecured notes due 2022 (the "January 2022 Notes"). The January 2022 Notes will mature on January 15, 2022 and bear an interest rate of 5 5/8% per annum, payable semi-annually, in cash in arrears on January 15 and July 15 of each year, commencing July 15, 2014. The January 2022 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases.

c. May 2022 Notes

On April 27, 2012, the Company completed an offering of $500.0 million in aggregate principal amount of 7 3/8% senior unsecured notes due 2022 (the "May 2022 Notes"). The May 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 May 2022 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases.

d. January 2019 Notes

On January 20, 2011, the Company completed an offering of $350.0 million 9 1/2% senior unsecured notes due 2019 (the "January Notes") and on October 19, 2011, the Company completed an offering of an additional $200.0 million 9 1/2% senior unsecured notes due 2019 (the "October Notes" and together with the January Notes, the "January 2019 Notes"). The January 2019 Notes were due to mature on February 15, 2019 and bore 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 January 2019 Notes were fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases.

Utilizing proceeds from the March 2023 Notes and the March 2015 Equity Offering, the Company redeemed the January 2019 Notes in full on April 6, 2015. As such, the Company classified the January 2019 Notes as "Short-term debt" in the March 31, 2015 unaudited consolidated balance sheet. See Note 19.a for discussion of the early redemption of the January 2019 Notes.

e. Senior Secured Credit Facility

As of March 31, 2015, the Fourth Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility"), which matures on November 4, 2018, had a maximum credit amount of $2.0 billion, a borrowing base of $1.15 billion and an aggregate elected commitment of $900.0 million with no amounts outstanding. It contains both financial and non-financial covenants, all of which the Company was in compliance with as of March 31, 2015. Laredo is required to pay an annual commitment fee on the unused portion of the financial institutions' commitment of 0.375% to 0.5%, based on the ratio of outstanding revolving credit to the total commitment under the Senior Secured Credit Facility. 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. No letters of credit were outstanding as of March 31, 2015 or 2014.

Subsequent to March 31, 2015, the Company made borrowings on the Senior Secured Credit Facility and the borrowing base and the aggregate elected commitment amounts were increased. See Note 19.b for additional information.

f. 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 values of the Company's debt for the periods presented:



	March 31, 2015				December 31, 2014
(in thousands)	Carrying value		Fair value		Carrying value		Fair value
January 2019 Notes⁽¹⁾	$	551,230	$	576,653	$	551,295	$	550,000
January 2022 Notes	450,000		436,500		450,000		396,014
May 2022 Notes	500,000		519,375		500,000		467,529
March 2023 Notes	350,000		350,875		—		—
Senior Secured Credit Facility	—		—		300,000		300,279
Total value of debt	$	1,851,230	$	1,883,403	$	1,801,295	$	1,713,822

______________________________________________________________________________


(1)	The carrying value of the January 2019 Notes includes the October Notes unamortized bond premium of $1.2 million and $1.3 million as of March 31, 2015 and December 31, 2014, respectively.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The fair values of the debt outstanding on the January 2019 Notes, the January 2022 Notes, May 2022 Notes and the March 2023 Notes were determined using the March 31, 2015 and December 31, 2014 quoted market price (Level 1) for each respective instrument. The fair value of the outstanding debt on the Senior Secured Credit Facility as of December 31, 2014 was estimated utilizing pricing models for similar instruments (Level 2). See Note 9 for information about fair value hierarchy levels.

Note 6—Employee compensation

The Company has a Long-Term Incentive Plan (the "LTIP"), which provides for the granting of incentive awards in the form of restricted stock awards, restricted stock option awards, performance share awards, performance unit awards and other awards. The LTIP provides for the issuance of 10.0 million shares.

The Company recognizes the fair value of stock-based compensation awards expected to vest over the requisite service period as a charge against earnings, net of amounts capitalized. The Company's stock-based compensation awards are accounted for as equity instruments and its performance unit awards are accounted for as liability awards. Stock-based compensation is included in "General and administrative" in the unaudited consolidated statements of operations. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of oil and natural gas properties into the full-cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the unaudited consolidated balance sheets.

a. Restricted stock awards

All restricted stock awards are treated as issued and outstanding in the accompanying unaudited consolidated financial statements. Per the award agreement terms, 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. If the employee's termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. Restricted stock awards granted to officers and employees vest in a variety of vesting schedules including (i) 20% at the grant date and then 20% annually thereafter, (ii) 33%, 33% and 34% per year beginning on the first anniversary date of the grant, (iii) 50% in year two and 50% in year three, (iv) fully on the first anniversary of the grant date and (v) fully on the third anniversary of the grant date. Restricted stock awards granted to non-employee directors vest fully on the first anniversary of the grant date.

The following table reflects the outstanding restricted stock awards for the three months ended March 31, 2015:



(in thousands, except for weighted-average grant date fair values)	Restricted stock awards		Weighted-average grant date fair value (per award)
Outstanding at December 31, 2014	2,205		$	22.63
Granted	1,749		$	11.90
Forfeited	(368	)	$	22.86
Vested⁽¹⁾	(718	)	$	22.27
Outstanding at March 31, 2015	2,868		$	16.14

______________________________________________________________________________


(1)	The vesting of certain restricted stock awards could result in federal and state income tax expense or benefit related to the difference between the market price of the common stock at the date of vesting and the date of grant. See Note 7 for additional discussion regarding the tax impact of vested restricted stock awards.

The Company utilizes the closing stock price on the grant date to determine the fair value of service vesting restricted stock awards. As of March 31, 2015, unrecognized stock-based compensation related to the restricted stock awards was $36.9 million. Such cost is expected to be recognized over a weighted-average period of 2.29 years.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

b. Restricted stock option awards

Restricted stock option awards granted under the LTIP vest and are exercisable in four equal installments on each of the four anniversaries of the grant date. The following table reflects the stock option award activity for the three months ended March 31, 2015:



(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, 2014	1,367		$	20.76	8.17
Granted	632		$	11.93	9.91
Exercised⁽¹⁾	—		$	—	—
Expired or canceled	(7	)	$	21.46	—
Forfeited	(114	)	$	18.03	—
Outstanding at March 31, 2015	1,878		$	17.95	8.60
Vested and exercisable at end of period⁽²⁾	617		$	20.67	7.68
Vested, exercisable, and expected to vest at end of period⁽³⁾	1,837		$	17.98	8.59

_____________________________________________________________________________


(1)	The exercise of stock option awards could result in federal and state income tax expense or benefit related to the difference between the fair value of the stock option award at the date of grant and the intrinsic value of the stock option award when exercised. See Note 7 for additional discussion regarding the tax impact of exercised stock option awards.


(2)	The vested and exercisable options at March 31, 2015 had no aggregate intrinsic value.


(3)	The aggregate intrinsic value of vested, exercisable and expected to vest options at March 31, 2015 was $0.7 million.

The Company utilizes the Black-Scholes option pricing model to determine the fair value of restricted stock option awards 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 option awards will be outstanding prior to exercise and the associated volatility. As of March 31, 2015, unrecognized stock-based compensation related to the restricted stock option awards was $10.3 million. Such cost is expected to be recognized over a weighted-average period of 3.05 years.

The assumptions used to estimate the fair value of restricted stock options granted on February 27, 2015 are as follows:



Risk-free interest rate⁽¹⁾	1.70		%
Expected option life⁽²⁾	6.25 years
Expected volatility⁽³⁾	52.59		%
Fair value per stock option	$	6.15

______________________________________________________________________________


(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 limited exercise history at the time of valuation relating to terminations and modifications, expected option life assumptions were developed using the simplified method in accordance with GAAP.


(3)	The Company utilized its own volatility in order to develop the expected volatility.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

In accordance with the LTIP and stock option agreement, the options granted will become exercisable in accordance with the following schedule based upon the number of full years of the optionee's continuous employment or service with the Company, following the date of grant:



Full years of continuous employment	Incremental percentage of option exercisable		Cumulative percentage of option exercisable
Less than one	—	%	—	%
One	25	%	25	%
Two	25	%	50	%
Three	25	%	75	%
Four	25	%	100	%

No shares of common stock may be purchased unless the optionee has remained in continuous employment with the Company for one year from the grant date. Unless terminated sooner, the option will expire if and to the extent it is not exercised within 10 years from the grant date. The unvested portion of a stock option award shall expire upon termination of employment, and the vested portion of a stock option award shall remain exercisable for (i) one year following termination of employment by reason of the holder's death or disability, but not later than the expiration of the option period, or (ii) 90 days following termination of employment for any reason other than the holder's death or disability, and other than the holder's termination of employment for cause. Both the unvested and the vested but unexercised portion of a stock option award shall expire upon the termination of the option holder's employment or service by the Company for cause.

c. Performance share awards

The performance share awards granted to management on February 27, 2015 (the "2015 Performance Share Awards") and on February 27, 2014 (the "2014 Performance Share Awards") are subject to a combination of market and service vesting criteria. A Monte Carlo simulation prepared by an independent third party was utilized in order to determine the grant date fair value of these awards. The Company has determined the 2014 Performance Share Awards and the 2015 Performance Share Awards are equity awards and recognizes the associated expense on a straight-line basis over the three-year requisite service period of the awards. These awards will be settled, if at all, in stock at the end of the requisite service period based on the achievement of certain performance criteria.

The 2015 Performance Share Awards have a performance period of January 1, 2015 to December 31, 2017 and any shares earned under such awards are expected to be issued in the first quarter of 2018 if the performance criteria are met. During the three months ended March 31, 2015, 602,501 2015 Performance Share Awards were granted and all remain outstanding at March 31, 2015. The 271,667 outstanding 2014 Performance Share Awards have a performance period of January 1, 2014 to December 31, 2016 and any shares earned under such awards are expected to be issued in the first quarter of 2017 if the performance criteria are met.

As of March 31, 2015, unrecognized stock-based compensation related to the 2015 Performance Share Awards and the 2014 Performance Share Awards was $14.0 million. Such cost is expected to be recognized over a weighted-average period of 2.60 years.

The assumptions used to estimate the fair value of the 2015 Performance Share Awards granted on February 27, 2015 are as follows:



Risk-free rate⁽¹⁾	0.95		%
Dividend yield	—		%
Expected volatility⁽²⁾	53.78		%
Laredo stock closing price as of February 27, 2015	$	11.93
Fair value per performance share	$	16.23

______________________________________________________________________________


(1)	The risk-free rate was derived using a zero-coupon yield derived from the Treasury Constant Maturities yield curve on the grant date.


(2)	The Company utilized a peer historical look-back, weighted with the Company's own volatility, to develop the expected volatility.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

d. Stock-based compensation award expense

The following has been recorded to stock-based compensation expense for the periods presented:



	Three months ended March 31,
(in thousands)	2015		2014
Restricted stock award compensation, net of amounts capitalized	$	3,280	$	3,486
Restricted stock option award compensation, net of amounts capitalized	673		628
Restricted performance share award compensation, net of amounts capitalized	835		215
Total stock-based compensation, net of amounts capitalized	$	4,788	$	4,329

e. Performance unit awards

The performance unit awards issued to management on February 15, 2013 (the "2013 Performance Unit Awards") and on February 3, 2012 (the "2012 Performance Unit Awards") are subject to a combination of market and service vesting criteria. A Monte Carlo simulation prepared by an independent third party is utilized to determine the fair values of these awards at the grant date and to re-measure the fair values at the end of each reporting period until settlement in accordance with GAAP. The volatility criteria utilized in the Monte Carlo simulation is based on the volatility of the Company's stock price and the stock price volatilities of a group of peer companies defined in each award agreement. 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 of these awards for each period 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.

The 44,481 outstanding 2013 Performance Unit Awards have a performance period of January 1, 2013 to December 31, 2015 and are expected to be paid in the first quarter of 2016 if the performance criteria are met. The 27,381 outstanding 2012 Performance Unit Awards had a performance period of January 1, 2012 to December 31, 2014 and, as their performance criteria were satisfied, they were paid at $100 per unit during the three months ended March 31, 2015.

Compensation expense for the 2012 Performance Unit Awards and the 2013 Performance Unit Awards is included in "General and administrative" in the Company's unaudited consolidated statements of operations, and the corresponding liabilities are included in "Other current liabilities" and "Other noncurrent liabilities" in the unaudited consolidated balance sheets. Due to the quarterly re-measurement of the fair value of the 2013 Performance Unit Awards as of March 31, 2015, compensation expense for the three months ended March 31, 2015 was $1.0 million. Compensation expense related to the 2012 Performance Unit Awards and the 2013 Performance Unit Awards amounted to $0.1 million for the three months ended March 31, 2014.

Note 7—Income taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carry-forwards. Under this method, deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income (loss) in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is determined it is more likely than not that the related tax benefit will not be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary.

The Company evaluates uncertain tax positions for recognition and measurement in the unaudited consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the unaudited consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

settlement. The Company had no unrecognized tax benefits related to uncertain tax positions in the unaudited consolidated financial statements at March 31, 2015 or December 31, 2014.

The Company is subject to corporate income taxes and the Texas franchise tax. Income tax expense for the periods presented consisted of the following:



	Three months ended March 31,
(in thousands)	2015			2014
Current taxes	$	—		$	—
Deferred taxes	(3,643		)	(107		)
Income tax expense	$	(3,643	)	$	(107	)

Income tax expense differed from amounts computed by applying the applicable federal income tax rate of 35% to pre-tax earnings as a result of the following:



	Three months ended March 31,
(in thousands)	2015			2014
Income tax expense computed by applying the statutory rate	$	(1,110	)	$	37
State income tax, net of federal tax benefit and increase in valuation allowance	91			1,287
Non-deductible stock-based compensation	(91		)	(116		)
Stock-based compensation tax deficiency	(2,457		)	(141		)
Change in deferred tax valuation allowance	(5		)	(1,078		)
Other items	(71		)	(96		)
Income tax expense	$	(3,643	)	$	(107	)

The impact of significant discrete items is separately recognized in the quarter in which they occur. The vesting of certain restricted stock awards 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 exercise of stock option awards could result in federal and state income tax expense or benefits related to the difference between the fair value of the stock option on the grant date and the intrinsic value of the stock option when exercised. The tax impact resulting from vestings of restricted stock awards and exercise of option awards are discrete items. During the three months ended March 31, 2015 and 2014, 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 on the grant date. As a result, the income tax deduction related to such shares is less than the expense previously recognized for book purposes. During the three months ended March 31, 2014, certain restricted stock options were exercised, for which the related income tax deduction was less than the expense previously recognized for book purposes. There were no stock options exercised during the three months ended March 31, 2015. 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, such shortfalls are included in income tax expense.

The following table presents the tax impact of these shortfalls for the periods presented:



	Three months ended March 31,
(in thousands)	2015			2014
Vesting of restricted stock	$	(2,501	)	$	(1	)
Exercise of restricted stock options	—			(142		)
Tax expense due to shortfalls	$	(2,501	)	$	(143	)

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Significant components of the Company's net deferred tax liability for the periods presented are as follows:



(in thousands)	March 31, 2015			December 31, 2014
Oil and natural gas properties, midstream service assets and other fixed assets	$	(456,797	)	$	(424,712	)
Net operating loss carry-forward	388,163			353,724
Derivatives	(117,565		)	(121,365		)
Stock-based compensation	6,892			10,718
Accrued bonus	656			3,256
Capitalized interest	3,126			3,049
Other	(3,759		)	(316		)
Gross deferred tax liability	(179,284		)	(175,646		)
Valuation allowance	(1,304		)	(1,299		)
Net deferred tax liability	$	(180,588	)	$	(176,945	)

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



(in thousands)	March 31, 2015			December 31, 2014
Deferred tax asset	$	—		$	—
Deferred tax liability	(180,588		)	(176,945		)
Deferred tax liability	$	(180,588	)	$	(176,945	)

The Company had federal net operating loss carry-forwards totaling $1.1 billion and state of Oklahoma net operating loss carry-forwards totaling $81.8 million as of March 31, 2015. These carry-forwards begin expiring in 2026. As of March 31, 2015, the Company believes the federal and the 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 the 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 March 31, 2015, 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's federal and state operating loss carry-forwards include windfall tax deductions from vestings of certain restricted stock awards and stock option exercises that were not recorded in the Company's income tax provision. The amount of windfall tax benefit recognized in additional paid-in capital is limited to the amount of benefit realized currently in income taxes payable. As of March 31, 2015, the Company had suspended additional paid-in capital credits of $4.5 million related to windfall tax deductions. Upon realization of the net operating loss carry-forwards from such windfall tax deductions, the Company would record a benefit of up to $4.5 million in additional paid-in capital.

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 March 31, 2015, a full valuation allowance of $1.3 million was recorded against the deferred tax asset related to the Company's charitable contribution carry-forward of $3.6 million.

The Company's income tax returns for the years 2012 through 2014 remain open and subject to examination by federal tax authorities and/or the tax authorities in Oklahoma and Texas which are the jurisdictions where the Company has or had operations. Additionally, the statute of limitations for examination of federal net operating loss carry-forwards typically does not begin to run until the year the attribute is utilized in a tax return.

Note 8—Derivatives

a. 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 production. As of March 31, 2015, the Company had 34 open derivative contracts with financial institutions that extend from April 2015 to December 2017. None of these contracts were designated as hedges for accounting purposes. The contracts are recorded at fair value on the balance sheet and gains and losses

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

are recognized in current period earnings. Gains and losses on derivatives are reported on the unaudited consolidated statements of operations in the "Gain (loss) on derivatives, net" line item.

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 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. 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.

Each put transaction has an established floor price. The Company pays its counterparty a premium, which can be deferred until settlement, 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 oil basis swap transactions have an established fixed basis differential. The Company's oil basis swaps' differential is between the West Texas Intermediate-Argus Americas Crude (Midland) ("WTI Midland") index crude oil price and the WTI NYMEX (defined below) index crude oil price. When the WTI NYMEX price less the fixed basis differential is greater than the actual WTI Midland price, the difference multiplied by the hedged contract volume is paid to the Company by the counterparty. When the WTI NYMEX price less the fixed basis differential is less than the actual WTI Midland price, the difference multiplied by the hedged contract volume is paid by the Company to the counterparty.

During the first quarter of 2014, the Company unwound a physical commodity contract and the associated oil basis swap financial derivative contract which hedged the differential between the Light Louisiana Sweet Argus and the Brent International Petroleum Exchange index oil prices. Prior to its unwind, the physical commodity contract qualified to be scoped out of mark-to-market accounting in accordance with the normal purchase and normal sale scope exemption. Once modified to settle financially in the unwind agreement, the contract ceased to qualify for the normal purchase and normal sale scope exemption, therefore requiring it to be marked-to-market. The Company received net proceeds of $76.7 million from the early termination of these contracts. The Company agreed to settle the contracts early due to the counterparty's decision to exit the physical commodity trading business.

The following represents cash settlements received for derivatives for the periods presented:



	Three months ended March 31,
(in thousands)	2015		2014
Cash settlements received (paid) for matured commodity derivatives	$	63,141	$	(1,431	)
Early terminations of commodity derivatives received	—		76,660
Cash settlements received for derivatives, net	$	63,141	$	75,229

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table summarizes open positions as of March 31, 2015, and represents, as of such date, derivatives in place through December 2017 on annual production volumes:



	Remaining Year 2015			Year 2016		Year 2017
Oil positions:⁽¹⁾
Puts:
Hedged volume (Bbl)	342,000			—		—
Weighted-average price ($/Bbl)	$	75.00		$	—	$	—
Swaps:
Hedged volume (Bbl)	504,000			1,573,800		—
Weighted-average price ($/Bbl)	$	96.56		$	84.82	$	—
Collars:
Hedged volume (Bbl)	4,922,140			2,556,000		2,628,000
Weighted-average floor price ($/Bbl)	$	79.81		$	80.00	$	77.22
Weighted-average ceiling price ($/Bbl)	$	95.40		$	93.77	$	97.22
Totals:
Total volume hedged with ceiling price (Bbl)	5,426,140			4,129,800		2,628,000
Weighted-average ceiling price ($/Bbl)	$	95.51		$	90.36	$	97.22
Total volume hedge with floor price (Bbl)	5,768,140			4,129,800		2,628,000
Weighted-average floor price ($/Bbl)	$	80.99		$	81.84	$	77.22
Basis swaps:⁽²⁾
Hedged volume (Bbl)	2,750,000			—		—
Weighted-average price ($/Bbl)	$	(1.95	)	$	—	$	—
Natural gas positions:⁽³⁾
Collars:
Hedged volume (MMBtu)	21,520,000			18,666,000		—
Weighted-average floor price ($/MMBtu)	$	3.00		$	3.00	$	—
Weighted-average ceiling price ($/MMBtu)	$	5.96		$	5.60	$	—

_______________________________________________________________________________


(1)	Oil derivatives are settled based on the average of the daily settlement prices for the First Nearby Month of the West Texas Intermediate NYMEX Light Sweet Crude Oil Futures Contract for each NYMEX Trading Day during each month ("WTI NYMEX").


(2)	The associated oil basis swaps are settled on the differential between the WTI Midland and the WTI NYMEX index oil prices.


(3)	Natural gas derivatives are settled based on the Inside FERC index price for West Texas Waha for the calculation period.

b. Balance sheet presentation

In accordance with the Company's standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives. The Company's oil and natural gas commodity derivatives are presented on a net basis as "Derivatives" on the unaudited consolidated balance sheets. See Note 9.a for a summary of the fair value of derivatives on a gross basis.

By using derivatives to hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. For the Company, 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, thereby creating 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 derivative counterparties. The Company minimizes the credit risk in derivatives by: (i) limiting its exposure to any single counterparty, (ii) entering into derivatives only with

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

counterparties that 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.

Note 9—Fair value measurements

The Company accounts for its oil and natural gas commodity derivatives at fair value. The fair value of derivatives 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 months ended March 31, 2015 or 2014.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

a. Fair value measurement on a recurring basis

The following tables summarize the Company's fair value hierarchy by commodity on a gross basis and the net presentation on the unaudited consolidated balance sheets for derivative assets and liabilities measured at fair value on a recurring basis for the periods presented:



(in thousands)	Level 1		Level 2			Level 3			Total gross fair value			Amounts offset			Net fair value presented on the consolidated balance sheets
As of March 31, 2015:
Assets
Current:
Oil derivatives	$	—	$	190,569		$	—		$	190,569		$	(3,238	)	$	187,331
Natural gas derivatives	—		11,815			—			11,815			—			11,815
Oil deferred premiums	—		—			—			—			(3,545		)	(3,545		)
Natural gas deferred premiums	—		—			—			—			(523		)	(523		)
Noncurrent:
Oil derivatives	$	—	$	118,663		$	—		$	118,663		$	—		$	118,663
Natural gas derivatives	—		4,738			—			4,738			—			4,738
Oil deferred premiums	—		—			—			—			(4,814		)	(4,814		)
Natural gas deferred premiums	—		—			—			—			—			—
Liabilities
Current:
Oil derivatives	$	—	$	(3,238	)	$	—		$	(3,238	)	$	3,238		$	—
Natural gas derivatives	—		—			—			—			—			—
Oil deferred premiums	—		—			(3,545		)	(3,545		)	3,545			—
Natural gas deferred premiums	—		—			(523		)	(523		)	523			—
Noncurrent:
Oil derivatives	$	—	$	—		$	—		$	—		$	—		$	—
Natural gas derivatives	—		—			—			—			—			—
Oil deferred premiums	—		—			(4,814		)	(4,814		)	4,814			—
Natural gas deferred premiums	—		—			—			—			—			—
Net derivative position	$	—	$	322,547		$	(8,882	)	$	313,665		$	—		$	313,665

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)



(in thousands)	Level 1		Level 2		Level 3			Total gross fair value			Amounts offset			Net fair value presented on the consolidated balance sheets
As of December 31, 2014:
Assets
Current:
Oil derivatives	$	—	$	190,303	$	—		$	190,303		$	—		$	190,303
Natural gas derivatives	—		9,647		—			9,647			—			9,647
Oil deferred premiums	—		—		—			—			(4,653		)	(4,653		)
Natural gas deferred premiums	—		—		—			—			(696		)	(696		)
Noncurrent:
Oil derivatives	$	—	$	117,963	$	—		$	117,963		$	—		$	117,963
Natural gas derivatives	—		3,646		—			3,646			—			3,646
Oil deferred premiums	—		—		—			—			(3,821		)	(3,821		)
Natural gas deferred premiums	—		—		—			—			—			—
Liabilities
Current:
Oil derivatives	$	—	$	—	$	—		$	—		$	—		$	—
Natural gas derivatives	—		—		—			—			—			—
Oil deferred premiums	—		—		(4,768		)	(4,768		)	4,653			(115		)
Natural gas deferred premiums	—		—		(696		)	(696		)	696			—
Noncurrent:
Oil derivatives	$	—	$	—	$	—		$	—		$	—		$	—
Natural gas derivatives	—		—		—			—			—			—
Oil deferred premiums	—		—		(3,821		)	(3,821		)	3,821			—
Natural gas deferred premiums	—		—		—			—			—			—
Net derivative position	$	—	$	321,559	$	(9,285	)	$	312,274		$	—		$	312,274

These items are included in "Derivatives" 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 each derivative contract's corresponding commodity index price, 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 1.69% 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 contract entered into that contained a deferred premium; 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 a third-party valuation of the deferred premiums for reasonableness.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table presents actual cash payments required for deferred premiums as of March 31, 2015, and for the calendar years following:



(in thousands)
Remaining 2015	$	3,746
2016	358
2017	4,585
2018	426
Total	$	9,115

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



	Three months ended March 31,
(in thousands)	2015			2014
Balance of Level 3 at beginning of period	$	(9,285	)	$	(12,684	)
Change in net present value of deferred premiums for derivatives	(43		)	(65		)
Total purchases and settlements:
Purchases	(975		)	—
Settlements	1,421			1,959
Balance of Level 3 at end of period	$	(8,882	)	$	(10,790	)

b. Fair value measurement on a nonrecurring basis

The Company accounts for the impairment of long-lived assets, 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 is classified as Level 3, based on the use of internally developed cash-flow models. See Note 2.n for discussion of the Company's impairment of materials and supplies and line-fill for the three months ended March 31, 2015.

The accounting policies for impairment of oil and natural gas properties are discussed in Note 2.g. 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 evaluated reserves and other relevant data.

Note 10—Credit risk

The Company's oil, NGL and natural gas sales are made 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 oil and natural gas 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 derivatives to hedge its exposure to oil and natural gas price volatility. These transactions expose the Company to potential credit risk from its counterparties. In accordance with the Company's standard practice, its derivatives are subject to counterparty netting under agreements governing such derivatives; therefore, the credit risk associated with its derivative counterparties is somewhat mitigated. See Notes 8 and 9 for additional information regarding the Company's derivatives.

Note 11—Commitments and contingencies

a. Litigation

From time to time the Company is involved in legal proceedings and/or may be 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.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

b. Drilling contracts

The Company has committed to drilling contracts with various third parties to complete its various drilling projects. The contracts contain early termination clauses that require the Company to potentially pay penalties to the third parties should the Company cease drilling efforts. These penalties would negatively impact the Company's financial statements upon early contract termination, especially if a significant number of such contracts were terminated early in their respective terms. In the fourth quarter of 2014, the Company announced a reduced 2015 capital expenditure budget compared to 2014. As a result, the Company began releasing rigs as drilling contracts came close to expiration and incurred charges of $0.5 million in the fourth quarter of 2014. No comparable amounts were recorded in the three months ended March 31, 2015 or 2014. Future commitments of $33.7 million as of March 31, 2015 are not recorded in the accompanying unaudited consolidated balance sheets. Management does not currently anticipate the early termination of any existing contracts in 2015 that would result in a substantial penalty.

c. 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 federal and state 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. These rules and regulations are frequently amended or reinterpreted; therefore, the Company is unable to predict the future cost or impact of complying with these regulations.

d. Other commitments

See Note 14 for discussion regarding the commitments to the Company's non-consolidated variable interest entity ("VIE").

Note 12—Restructuring

Following the recent drop in oil prices, in an effort to reduce costs and to better position the Company for ongoing efficient growth, on January 20, 2015, the Company executed a company-wide restructuring and reduction in force (the "RIF") that included (i) the relocation of certain employees in the Company's Dallas, Texas area office to the Company's other existing offices in Tulsa, Oklahoma and Midland, Texas; (ii) closing the Company's Dallas, Texas area office; (iii) a workforce reduction of approximately 75 employees and (iv) the release of 24 contract personnel. The reduction in workforce was communicated to employees on January 20, 2015 and was generally effective immediately. The relocation of Company employees is expected to be completed by June 1, 2015. The Company's compensation committee approved the RIF and the severance package offered in connection with the RIF. The Company incurred expenses of $6.0 million during the three months ended March 31, 2015 related to the RIF. As of March 31, 2015, no additional RIF expenses are expected to be incurred.

Note 13—Net loss per share

Basic net loss per share is computed by dividing net loss by the weighted-average number of common shares outstanding for the period. Diluted net loss per share reflects the potential dilution of non-vested restricted stock awards, performance share awards and outstanding restricted stock options. For the three months ended March 31, 2015 and 2014, all of these potentially dilutive items were anti-dilutive due to the Company's net loss and, therefore, were excluded from the calculation of diluted net loss per share.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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



	Three months ended March 31,
(in thousands, except for per share data)	2015			2014
Net loss (numerator):
Net loss—basic and diluted	$	(472	)	$	(213	)
Weighted-average common shares outstanding (denominator)⁽¹⁾:
Basic	162,426			141,067
Diluted	162,426			141,067
Net loss per share:
Basic	$	—		$	—
Diluted	$	—		$	—

______________________________________________________________________________


(1)	For the three months ended March 31, 2015, weighted-average common shares outstanding used in the computation of basic and diluted net loss per share attributable to stockholders has been computed taking into account the March 2015 Equity Offering.

Note 14—Variable interest entity

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. 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.

During the three months ended March 31, 2015 and 2014, LMS contributed $14.5 million and $11.3 million, respectively, to Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, and its wholly-owned subsidiaries (together "Medallion"). LMS holds 49% of Medallion ownership units. Medallion was established for the purpose of developing midstream solutions and providing midstream infrastructure to bring discovered oil, NGL and natural gas to market. LMS 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 operating and business decisions. The Company has determined that Medallion is a VIE. However, LMS is not considered to be the primary beneficiary of the VIE because LMS 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 Medallion's net income (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 sheets as "Investment in equity method investee."

During the three months ended March 31, 2015, Medallion continued construction of its pipeline infrastructure, including a lateral extension in Reagan County, Texas from its Reagan Station to its Santa Rita Station, in order to gather third-party production. As of March 31, 2015, LMS has committed to fund an estimated $3.9 million to Medallion. See Note 15.a for a discussion of items included in the unaudited consolidated financial statements related to Medallion.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note 15—Related Parties

a. Medallion

The following table summarizes items included in the unaudited consolidated statements of operations related to Medallion for the periods presented:



	Three months ended March 31,
(in thousands)	2015		2014
Midstream service revenues	$	97	$	—
Minimum volume commitments	1,656		516
Interest and other income	108		—

The following table summarizes items included in the unaudited consolidated balance sheets related to Medallion for the periods presented:



(in thousands)	March 31, 2015		December 31, 2014
Accounts receivable, net	$	97	$	—
Other assets, net	1,209		1,110
Other current liabilities	4,264		3,443

b. Targa Resources Corp.

The Company has a gathering and processing arrangement with affiliates of Targa Resources Corp. ("Targa"). One of Laredo's directors is on the board of directors of Targa.

The following table summarizes the net oil, NGL and natural gas sales (oil, NGL and natural gas sales less production taxes) received from Targa and included in the unaudited consolidated statements of operations for the periods presented:



	Three months ended March 31,
(in thousands)	2015		2014
Oil, NGL and natural gas sales	$	19,631	$	22,479

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



(in thousands)	March 31, 2015		December 31, 2014
Accounts receivable, net	$	6,088	$	12,869

Note 16—Segments

Beginning in 2015, the Company is presenting financial results by segment to highlight the growing value of its midstream and marketing segment and its interest in Medallion, as Medallion's third-party revenues increase.

The Company operates in two business segments, which are (i) exploration and production and (ii) midstream and marketing. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties. The midstream and marketing segment provides the exploration and production segment and certain third parties with (i) any products and services that need to be delivered by infrastructure, including oil and natural gas gathering services as well as rig fuel, natural gas lift and water in the primary drilling corridors and (ii) takeaway optionality in the field and firm service commitments to maximize oil, NGL and natural gas revenues.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following tables present selected financial information regarding the Company's operating segments for the periods presented:



(in thousands)	Exploration and production			Midstream and marketing			Intercompany eliminations			Consolidated company
Three months ended March 31, 2015
Oil, NGL and natural gas sales	$	118,211		$	112		$	(205	)	$	118,118
Midstream service revenues	—			3,683			(2,374		)	1,309
Sales of purchased oil	—			31,267			—			31,267
Total revenues	118,211			35,062			(2,579		)	150,694
Lease operating expenses, including production tax	43,845			—			(2,379		)	41,466
Midstream service expenses	—			3,342			(112		)	3,230
Costs of purchased oil	—			31,200			—			31,200
General and administrative⁽¹⁾	19,778			2,077			—			21,855
Depletion, depreciation and amortization⁽²⁾	70,257			1,685			—			71,942
Other operating costs and expenses⁽³⁾	7,191			308			—			7,499
Operating loss	$	(22,860	)	$	(3,550	)	$	(88	)	$	(26,498	)
Other financial information:
Loss from equity method investee	$	—		$	(433	)	$	—		$	(433	)
Interest expense⁽⁴⁾	$	(31,087	)	$	(1,327	)	$	—		$	(32,414	)
Capital expenditures⁽⁵⁾	$	247,613		$	20,473		$	—		$	268,086
Gross property and equipment⁽⁶⁾	$	5,057,149		$	216,345		$	(321	)	$	5,273,173
Three months ended March 31, 2014
Oil, NGL and natural gas sales	$	173,214		$	—		$	—		$	173,214
Midstream service revenues	—			1,030			(934		)	96
Total revenues	173,214			1,030			(934		)	173,310
Lease operating expenses, including production tax	35,169			—			(934		)	34,235
Midstream service expenses	—			1,361			—			1,361
General and administrative⁽¹⁾	26,316			1,338			—			27,654
Depletion, depreciation and amortization⁽²⁾	48,968			639			—			49,607
Other operating costs and expenses⁽³⁾	415			—			—			415
Operating income (loss)	$	62,346		$	(2,308	)	$	—		$	60,038
Other financial information:
Income from equity method investee	$	—		$	16		$	—		$	16
Interest expense⁽⁴⁾	$	(28,374	)	$	(612	)	$	—		$	(28,986	)
Capital expenditures⁽⁵⁾	$	190,409		$	10,520		$	—		$	200,929
Gross property and equipment⁽⁶⁾	$	3,729,711		$	82,293		$	—		$	3,812,004

_______________________________________________________________________________


(1)	General and administrative costs were allocated based on the number of employees in the respective segment as of March 31, 2015 and 2014, respectively. However, the payroll and deferred compensation costs component of general and administrative for each segment is based on actual costs for the three months ended March 31, 2015.


(2)	Depletion, depreciation and amortization for other fixed assets related to office furnishings were allocated based on the number of employees in the respective segment as of March 31, 2015 and 2014, respectively.


(3)	Includes the following expenses: restructuring expense, accretion of asset retirement obligations and impairments for the three months ended March 31, 2015 and 2014. These expenses are based on actual costs for the three months ended March 31, 2015 and 2014.


(4)	Interest expense is allocated based on gross property and equipment and total contributions to the Company's equity method investee as of March 31, 2015 and 2014, respectively.


(5)	Capital expenditures excludes acquisition of mineral interests for the three months ended March 31, 2014.


(6)	Gross property and equipment includes investment in equity method investee totaling $72.4 million and $22.8 million for the three months ended March 31, 2015 and 2014, respectively. Other fixed assets related to office furnishings were allocated based on the number of employees in the respective segment on March 31, 2015 and 2014, respectively.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note 17—Subsidiary guarantees

Laredo and the Guarantors have fully and unconditionally guaranteed the January 2019 Notes, the January 2022 Notes, the May 2022 Notes, the March 2023 Notes and the Senior Secured Credit Facility, subject to the Releases. In accordance with practices accepted by the SEC, Laredo has prepared condensed consolidating financial statements to quantify the assets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following unaudited condensed consolidating balance sheets as of March 31, 2015 and December 31, 2014, unaudited condensed consolidating statements of operations and unaudited condensed consolidating statements of cash flows for the three months ended March 31, 2015 and 2014 present 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 LMS and for GCM are recorded on Laredo's statements of financial position, statements of operations and statements of cash flows as they are disregarded entities for income tax purposes. Laredo and the Guarantors are not restricted from making intercompany distributions to each other. See Note 19.a for a discussion of the early redemption of the January 2019 Notes.

Condensed consolidating balance sheet

March 31, 2015

(Unaudited)



(in thousands)	Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable, net	$	91,902	$	18,101	$	—		$	110,003
Other current assets	781,157		10,444		—			791,601
Total oil and natural gas properties, net	3,338,965		7,247		(321		)	3,345,891
Total midstream service assets, net	—		129,010		—			129,010
Total other fixed assets, net	45,243		315		—			45,558
Investment in subsidiaries and equity method investee	222,981		72,350		(222,981		)	72,350
Total other long-term assets	156,275		4,335		—			160,610
Total assets	$	4,636,523	$	241,802	$	(223,302	)	$	4,655,023

Accounts payable	$	29,126	$	1,284	$	—		$	30,410
Other current liabilities	847,151		15,271		—			862,422
Long-term debt	1,300,000		—		—			1,300,000
Other long-term liabilities	140,813		2,266		—			143,079
Stockholders' equity	2,319,433		222,981		(223,302		)	2,319,112
Total liabilities and stockholders' equity	$	4,636,523	$	241,802	$	(223,302	)	$	4,655,023

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating balance sheet

December 31, 2014

(Unaudited)



(in thousands)	Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable, net	$	107,860	$	19,069	$	—		$	126,929
Other current assets	238,300		24		—			238,324
Total oil and natural gas properties, net	3,196,231		7,277		(233		)	3,203,275
Total midstream service assets, net	—		108,462		—			108,462
Total other fixed assets, net	42,046		299		—			42,345
Investment in subsidiaries and equity method investee	163,349		58,288		(163,349		)	58,288
Total other long-term assets	150,430		4,496		—			154,926
Total assets	$	3,898,216	$	197,915	$	(163,582	)	$	3,932,549

Accounts payable	$	38,453	$	555	$	—		$	39,008
Other current liabilities	354,217		31,800		—			386,017
Long-term debt	1,801,295		—		—			1,801,295
Other long-term liabilities	140,817		2,211		—			143,028
Stockholders' equity	1,563,434		163,349		(163,582		)	1,563,201
Total liabilities and stockholders' equity	$	3,898,216	$	197,915	$	(163,582	)	$	3,932,549

Condensed consolidating statement of operations

For the three months ended March 31, 2015

(Unaudited)



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Total operating revenues	$	118,146		$	35,127		$	(2,579	)	$	150,694
Total operating costs and expenses	143,308			36,375			(2,491		)	177,192
Operating loss	(25,162		)	(1,248		)	(88		)	(26,498		)
Interest expense and other, net	(32,291		)	—			—			(32,291		)
Other non-operating income (expense)	60,712			(433		)	1,681			61,960
Income (loss) before income tax	3,259			(1,681		)	1,593			3,171
Deferred income tax expense	(3,643		)	—			—			(3,643		)
Net loss	$	(384	)	$	(1,681	)	$	1,593		$	(472	)

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating statement of operations

For the three months ended March 31, 2014

(Unaudited)



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Total operating revenues	$	173,214		$	1,030		$	(934	)	$	173,310
Total operating costs and expenses	112,510			1,696			(934		)	113,272
Operating income (loss)	60,704			(666		)	—			60,038
Interest expense and other, net	(28,903		)	—			—			(28,903		)
Other non-operating income (expense)	(31,907		)	(33		)	699			(31,241		)
Loss before income tax	(106		)	(699		)	699			(106		)
Deferred income tax expense	(107		)	—			—			(107		)
Net loss	$	(213	)	$	(699	)	$	699		$	(213	)

Condensed consolidating statement of cash flows

For the three months ended March 31, 2015

(Unaudited)



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash flows provided by (used in) operating activities	$	51,531		$	(26,347	)	$	1,681		$	26,865
Change in investments between affiliates	(59,634		)	61,315			(1,681		)	—
Capital expenditures and other	(247,578		)	(34,968		)	—			(282,546		)
Net cash flows provided by financing activities	795,453			—			—			795,453
Net increase in cash and cash equivalents	539,772			—			—			539,772
Cash and cash equivalents at beginning of period	29,320			1			—			29,321
Cash and cash equivalents at end of period	$	569,092		$	1		$	—		$	569,093

Condensed consolidating statement of cash flows

For the three months ended March 31, 2014

(Unaudited)



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash flows provided by operating activities	$	126,666		$	752		$	699		$	128,117
Change in investments between affiliates	(20,370		)	21,069			(699		)	—
Capital expenditures and other	(197,445		)	(21,821		)	—			(219,266		)
Net cash flows provided by financing activities	440,515			—			—			440,515
Net increase in cash and cash equivalents	349,366			—			—			349,366
Cash and cash equivalents at beginning of period	198,153			—			—			198,153
Cash and cash equivalents at end of period	$	547,519		$	—		$	—		$	547,519

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note 18—Recent accounting pronouncements

In April 2015, the Financial Accounting Standards Board ("FASB") issued new guidance in Subtopic 835-30, Interest-Imputation of Interest which seeks to simplify the presentation of debt issuance costs. These amendments require that debt issuance costs related to a recognized debt liability be presented in an entity's balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this guidance. Entities should apply the amendments on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. The guidance is effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period. Early adoption is permitted. The Company early-adopted this standard on April 1, 2015 and will apply the provisions in its second-quarter unaudited consolidated financial statements.

In May 2014, the FASB issued a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—Revenue Recognition. The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard's application impact to individual financial statement line items. This standard is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard.

Note 19—Subsequent events

a. Redemption of the January 2019 Notes

On April 6, 2015 (the "Redemption Date"), the entire $550.0 million outstanding principal amount of the Company's January 2019 Notes was redeemed at a redemption price of 104.750% of the principal amount of the January 2019 Notes, plus accrued and unpaid interest up to, but not including, the Redemption Date. On the Redemption Date, the Company recognized a loss on extinguishment of $38.9 million, related to the difference between the redemption price and the net carrying amount of the extinguished January 2019 Notes.

b. Senior Secured Credit Facility

On April 6 and April 30, 2015, the Company borrowed $50.0 million and $10.0 million, respectively, on the Senior Secured Credit Facility. The outstanding balance under the Senior Secured Credit Facility was $60.0 million at May 6, 2015.

On May 4, 2015, the Company entered into the Third Amendment to the Senior Secured Credit Facility, pursuant to which, among other things, the borrowing base and aggregate elected commitment amounts increased to $1.25 billion and $1.0 billion, respectively.

c. Potential transaction

The Company had previously announced that it was evaluating various financing sources and had ongoing discussions regarding a drilling fund opportunity involving a portion of its northern Permian-Garden City properties as well as additional operational locations in its southern area. Although the Company received significant interest, it has not reached terms that it believes would be beneficial to its stockholders. Further pursuit of a drilling fund or joint development opportunity may occur, but there can be no assurance of any discussions or transactions of this nature.

As the Company pursues reserves and production growth in the Permian Basin, it will continue to consider and monitor which financing alternatives, including debt and equity capital resources, joint ventures, drilling funds and asset sales, are available to meet additional or accelerated future planned capital expenditures. There can be no assurance that any transaction will be completed.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note 20—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 March 31,
(in thousands)	2015		2014
Property acquisition costs:
Evaluated	$	—	$	25
Unevaluated	—		7,280
Exploration	4,513		8,499
Development costs⁽¹⁾	206,672		188,313
Total costs incurred	$	211,185	$	204,117

____________________________________________________________________________


(1)	The costs incurred for oil and natural gas development activities include $0.5 million and $0.6 million in asset retirement obligations for the three months ended March 31, 2015 and 2014, 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 as well as our audited consolidated financial statements and notes thereto included in our 2014 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 (i) when used in the present tense, prospectively or from October 24, 2014 to March 31, 2015, refer to Laredo, LMS and GCM collectively and (ii) when used for historical periods from December 31, 2013 to October 23, 2014, refer to Laredo and LMS collectively, unless the context otherwise indicates or requires. All amounts, dollars and percentages presented in this Quarterly Report are rounded and therefore approximate.

Executive overview

We are an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties primarily in the Permian Basin in West Texas. Since our inception, we have grown primarily through our drilling program coupled with select strategic acquisitions and joint ventures.

Our financial and operating performance for the three months ended March 31, 2015 included the following:


•	Oil, NGL and natural gas sales of $118.1 million, compared to $173.2 million for the three months ended March 31, 2014;


•	Average daily sales volumes of 47,487 BOE/D, compared to 27,041 BOE/D for the three months ended March 31, 2014; and


•	Adjusted EBITDA (a non-GAAP financial measure) of $118.6 million, compared to $187.3 million for the three months ended March 31, 2014.

Recent developments

Three-stream reporting

As of January 1, 2015, all of our natural gas processing agreements with various processors had been modified to allow us to take title to the NGL resulting from the processing of our natural gas. Based on this, we elected to report reserves, sales volumes, prices and revenues for oil, NGL and natural gas separately for periods after January 1, 2015. This is known as "three-stream reporting." For periods prior to January 1, 2015, we presented our reserves, sales volumes, prices and revenues for oil and natural gas, which combined NGL with the natural gas stream, and did not separately report NGL. This change impacts the comparability of 2015 with prior periods.

Drop in oil prices

We review the carrying value of our oil and natural gas properties under the full cost accounting rules of the SEC on a quarterly basis. The substantial decrease in oil, NGL and natural gas prices that began in the second half of 2014 and has continued into the second quarter of 2015, if continued or maintained, may require us to incur non-cash full cost impairments in the future, which could have a material adverse effect on our results of operations for the periods in which the impairments are incurred.

Potential transaction

We had previously announced that we were evaluating various financing sources and had ongoing discussions regarding a drilling fund opportunity involving a portion of our northern Permian-Garden City properties as well as additional operational locations in our southern area. Although we received significant interest, we have not reached terms that we believe would be beneficial to our stockholders. Further pursuit of a drilling fund or joint development opportunity may occur, but there can be no assurance of any discussions or transactions of this nature.

As we pursue reserves and production growth in the Permian Basin, we will continue to consider and monitor which financing alternatives, including debt and equity capital resources, joint ventures, drilling funds and asset sales, are available to meet additional or accelerated future planned capital expenditures. There can be no assurance that any transaction will be completed.

Amendment to the Senior Secured Credit Facility

On May 4, 2015, we entered into the Third Amendment to the Senior Secured Credit Facility, pursuant to which, among other things, the borrowing base and aggregate elected commitment amounts were increased to $1.25 billion and $1.0 billion, respectively. For more information regarding the Third Amendment to the Senior Secured Credit Facility, see "Part II, 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" below.

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 March 31, 2015, we had assembled 166,381 net acres in the Permian Basin, of which 149,141 net acres are located in our Permian-Garden City area.

Reserves and pricing

Our results of operations are heavily influenced by commodity prices, which have significantly declined in recent months. Prices for oil, NGL and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and natural gas activities, commodity prices have experienced significant fluctuations, and additional changes in commodity prices may affect the economic viability of and ability to fund drilling projects, as well as the economic valuation and economic recovery of oil and natural gas reserves.

Our reserves as of March 31, 2015 were reported in three streams: oil, NGL and natural gas. Our reserves as of March 31, 2014 were reported in two streams: oil and liquids-rich natural gas with the economic value of the NGL in our natural gas included in the wellhead natural gas price. The unweighted arithmetic average first-day-of-the-month index prices for the prior 12 months ended March 31, 2015 and March 31, 2014 used to value our reserves were $79.21 per Bbl for oil, $31.25 per Bbl for NGL and $3.73 per MMBtu for natural gas, respectively, and $95.02 per Bbl for oil and $3.90 per MMBtu for liquids-rich natural gas, respectively. The prices used to estimate proved reserves for all periods do not include 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.

We have entered into a number of commodity derivatives, which have enabled us to offset a portion of the changes in our cash flow caused by price fluctuations on our production as discussed in "Item 3. Quantitative and Qualitative Disclosures About Market Risk."

Sources of our revenue

Our revenues are primarily derived from the sale of oil, NGL and natural gas and the sale of purchased oil within the continental United States and do not include the effects of derivatives. For the three months ended March 31, 2015, our revenues were comprised of sales of 60% oil, 9% NGL, 10% natural gas and 21% sale of purchased oil. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold and/or changes in commodity prices.

Results of operations

Three months ended March 31, 2015 as compared to the three months ended March 31, 2014

Sales volumes, oil, NGL and natural gas revenues and pricing

The following table sets forth information regarding sales volumes, oil, NGL and natural gas revenues and average sales prices per BOE sold, for the periods presented:



	Three months ended March 31,
	2015			2014
Sales volumes⁽¹⁾:
Oil (MBbl)	2,172			1,421
NGL (MBbl)	989			—
Natural gas (MMcf)	6,680			6,076
Oil equivalents (MBOE)⁽²⁾⁽³⁾	4,274			2,434
Average daily sales volumes (BOE/D)⁽³⁾	47,487			27,041
% Oil	51		%	58		%
Oil, NGL and natural gas revenues (in thousands)⁽¹⁾:
Oil	$	90,615		$	130,427
NGL	13,187			—
Natural gas	14,316			42,787
Total revenues	$	118,118		$	173,214
Average sales prices⁽¹⁾:
Oil, realized ($/Bbl)⁽⁴⁾	$	41.73		$	91.78
NGL, realized ($/Bbl)⁽⁴⁾	$	13.34		$	—
Natural gas, realized ($/Mcf)⁽⁴⁾	$	2.14		$	7.04
Average price, realized ($/BOE)⁽⁴⁾	$	27.64		$	71.17
Oil, hedged ($/Bbl)⁽⁵⁾	$	69.51		$	89.94
NGL, hedged ($/Bbl)⁽⁵⁾	$	13.34		$	—
Natural gas, hedged ($/Mcf)⁽⁵⁾	$	2.35		$	6.92
Average price, hedged ($/BOE)⁽⁵⁾	$	42.08		$	69.79

________________________________________________________________________


(1)	For periods prior to January 1, 2015, we presented our sales volumes, revenues and average sales prices for oil and natural gas, which combined NGL with the natural gas stream, and did not separately report NGL. This change impacts the comparability of the two periods presented.


(2)	Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl.


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


(4)	Realized oil, NGL and natural gas prices are the actual prices realized at the wellhead after all adjustments for 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.

(5)

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 commodity derivatives in accordance with GAAP and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to instruments that 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 cash settlements received (paid) for matured commodity derivatives and premiums incurred previously or upon settlement attributable to instruments that settled during the periods utilized in our calculation of the hedged prices presented above:



	Three months ended March 31,
(in thousands)	2015			2014
Cash settlements received (paid) for matured commodity derivatives:
Oil	$	61,586		$	(894	)
Natural gas	1,555			(537		)
Total	$	63,141		$	(1,431	)
Premiums paid attributable to contracts that matured during the respective period:
Oil	$	(1,245	)	$	(1,729	)
Natural gas	(176		)	(230		)
Total	$	(1,421	)	$	(1,959	)

Changes in prices and volumes caused the following changes to our oil, NGL and natural gas revenues between the three months ended March 31, 2015 and 2014:



(in thousands)	Oil			NGL			Natural gas			Total net dollar effect of change
2014 Revenues	$	130,427		$	—		$	42,787		$	173,214
Effect of changes in price	(108,693		)	13,191			(32,731		)	(128,233		)
Effect of changes in volumes	68,896			—			4,251			73,147
Other	(15		)	(4		)	9			(10		)
2015 Revenues	$	90,615		$	13,187		$	14,316		$	118,118

Oil revenue. Our oil revenue is a function of oil production volumes sold and average sales prices received for those volumes. The decrease in oil revenue of $39.8 million, or 31%, for the three months ended March 31, 2015 as compared to the three months ended March 31, 2014, is mainly due to a 55% decrease in average oil prices realized, partially offset by a 53% increase in oil production.

NGL and natural gas revenues. On January 1, 2015, we began utilizing three-stream reporting, which impacts the comparability of 2015 with prior periods. Our NGL and natural gas revenues are a function of NGL and natural gas production, volumes sold and average sales prices received for those volumes. The total decrease in NGL and natural gas revenues from the three months ended March 31, 2015 as compared to the three months ended March 31, 2014, is mainly related to a decrease in average prices realized on our natural gas and NGL production. Stripping out the NGL component from our liquids-rich natural gas results in a lower price received for residue natural gas during the three months ended March 31, 2015 as compared to the same period 2014 in which we received revenues from liquids-rich natural gas. The decrease in prices is partially offset by an increase in NGL and natural gas production period-over-period.

Costs and expenses

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



	Three months ended March 31,
(in thousands except for per BOE sold data)	2015		2014
Costs and expenses:
Lease operating expenses	$	32,380	$	21,785
Midstream service expenses	1,574		845
Production and ad valorem taxes	9,086		12,450
Minimum volume commitments	1,656		516
Costs of purchased oil	31,200		—
General and administrative⁽¹⁾	21,855		27,654
Restructuring expenses	6,042		—
Accretion of asset retirement obligations	579		415
Depletion, depreciation and amortization	71,942		49,607
Impairment expense	878		—
Total costs and expenses	$	177,192	$	113,272
Average costs per BOE sold⁽²⁾:
Lease operating expenses	$	7.58	$	8.95
Midstream service expenses	0.37		0.35
Production and ad valorem taxes	2.13		5.12
General and administrative⁽¹⁾	5.11		11.36
Depletion, depreciation and amortization	16.83		20.38
Total	$	32.02	$	46.16

________________________________________________________________________


(1)	General and administrative includes non-cash stock-based compensation, net of amount capitalized, of $4.8 million and $4.3 million for the three months ended March 31, 2015 and 2014, respectively.


(2)	For periods prior to January 1, 2015, we presented our average costs per BOE sold, which combined NGL with the natural gas stream, and did not separately report NGL. This change impacts the comparability of the two periods presented.

Lease operating expenses. For the three months ended March 31, 2015, lease operating expenses, which include workover expenses, increased by $10.6 million, or 49%, compared to the same period in 2014. The increase was mainly due to increases in (i) well count and (ii) well service and workover expenses.

Midstream service expenses. Midstream service expenses represent costs incurred to operate and maintain our (i) oil and natural gas gathering and transportation systems and related facilities, (ii) centralized oil storage tanks, (iii) natural gas lift, rig fuel and centralized compression infrastructure and (iv) water storage, recycling and transportation facilities. These expenses increased by $0.7 million, or 86%, for the three months ended March 31, 2015 compared to the same period in 2014, due to the expanded midstream service component of our business.

Production and ad valorem taxes. Production and ad valorem taxes decreased by $3.4 million, or 27%, for the three months ended March 31, 2015 compared to the same period in 2014, of which $3.3 million of the decrease is related to production taxes. Production taxes are based on and fluctuate proportionately with our oil, NGL and natural gas revenues. The proportionate decrease was partially offset by relatively flat ad valorem taxes during the three months ended March 31, 2015 compared to the same period in 2014.

Costs of purchased oil. See "—Results of Operations - midstream and marketing" for a discussion of these costs.

General and administrative ("G&A"). The table below shows the changes in the significant components of G&A expense for the periods presented:



(in thousands)	Three months ended March 31, 2015 compared to 2014
Changes in G&A:
Charitable contributions	$	(3,093	)
Professional fees	(2,148		)
Salaries, benefits and bonuses, net of amount capitalized	(801		)
Stock-based compensation, net of amount capitalized	459
Performance unit awards	898
Other	(1,114		)
Total change in G&A	$	(5,799	)

G&A expense, excluding stock-based compensation, decreased by $6.3 million, or 27%, for the three months ended March 31, 2015 compared to the same period in 2014. The decrease is primarily due to (i) our $3.0 million charitable contribution pledge during the three months ended March 31, 2014, which will be paid in annual payments through 2024, and (ii) fees paid to a consulting company engaged in 2014 to assist us with the optimization of our development operations.

Stock-based compensation, net of amount capitalized, increased by $0.5 million, or 11%, for the three months ended March 31, 2015 compared to the same period in 2014, mainly due to the issuance of (i) 1,748,517 restricted stock awards at a weighted-average grant price of $11.90 per share to new and existing employees and non-employee directors, (ii) 631,639 non-qualified restricted stock options to management and (iii) 602,501 performance share awards to management compared to the issuance of (i) 1,068,503 restricted stock awards at a weighted-average grant price of $25.63 per share to new and existing employees and non-employee directors, (ii) 336,140 non-qualified restricted stock options to management and (iii) 271,667 performance share awards to management in the same period in 2014.

The fair values for each of our restricted stock awards issued were calculated based on the value of our stock price on the grant date in accordance with GAAP and are being expensed on a straight-line basis over their associated requisite service periods. The fair values for each of our non-qualified restricted stock options awards were determined using a Black-Scholes valuation model in accordance with GAAP and are being expensed on a straight-line basis over their associated four-year requisite service periods.

Our performance share awards are accounted for as equity awards. The fair values of the performance share awards issued were based on a projection of the performance of our stock price relative to a peer group, defined in each performance share awards' agreement, utilizing a forward-looking Monte Carlo simulation. The fair values for each of our performance share awards will not be re-measured after their initial grant-date valuation and are being expensed on a straight-line basis over their associated three-year requisite service periods.

Our performance unit awards, which settle in cash if performance criteria are met, are accounted for as liability awards. The associated expense for these awards increased by $0.9 million for the three months ended March 31, 2015 compared to the same period in 2014 mainly due to the quarterly re-measurement of the 2013 Performance Unit Awards based on the performance of our stock price relative to the peer group utilized in the forward-looking Monte Carlo simulation. The 2012 Performance Unit Awards performance criteria were satisfied at December 31, 2014, and they were paid at $100 per unit during the three months ended March 31, 2015. This payout did not affect quarter-to-date expense as they were fully accrued at December 31, 2014.

See Notes 2.l and 6 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding our stock and performance based compensation.

Restructuring expenses. Following the recent drop in commodity prices, restructuring expenses relate to our first-quarter 2015 RIF, which was an effort to reduce costs and better position ourselves for ongoing efficient growth. For the three months ended March 31, 2015, restructuring expenses were $6.0 million. As of March 31, 2015, no additional RIF expenses are expected to be incurred. See Note 12 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of the RIF.

Depletion, depreciation and amortization ("DD&A"). The following table provides components of our DD&A expense for the periods presented:



	Three months ended March 31,
(in thousands except for per BOE sold data)	2015		2014
Depletion of evaluated oil and natural gas properties	$	68,728	$	47,742
Depreciation of midstream service assets	1,647		570
Depreciation and amortization of other fixed assets	1,567		1,295
Total DD&A	$	71,942	$	49,607
DD&A per BOE sold	$	16.83	$	20.38

DD&A increased by $22.3 million, or 45%, for the three months ended March 31, 2015 as compared to the same period in 2014, mainly due to the increase in our production.

Impairment expense. Impairment expense for the three months ended March 31, 2015 was $0.9 million, which consists of LCM adjustments of $0.8 million for materials and supplies and $0.1 million for our line-fill. There were no comparable amounts for the three months ended March 31, 2014.

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 March 31,
(in thousands)	2015			2014
Non-operating income (expense):
Gain (loss) on derivatives, net	$	63,155		$	(31,112	)
Income (loss) from equity method investee	(433		)	16
Interest expense	(32,414		)	(28,986		)
Interest and other income	123			83
Write-off of debt issuance costs	—			(124		)
Loss on disposal of assets, net	(762		)	(21		)
Non-operating income (expense), net	$	29,669		$	(60,144	)

Derivatives. The table below shows the changes in the components of gain (loss) on derivatives, net for the periods presented:



(in thousands)	Three months ended March 31, 2015 compared to 2014
Changes in gain (loss) on derivatives, net:
Fair value of derivatives outstanding	$	106,355
Early terminations of derivatives received	(76,660		)
Cash settlements received for matured derivatives	64,572
Total change in gain (loss) on derivatives, net	$	94,267

The increase in fair value of derivatives outstanding for the three months ended March 31, 2015 compared to the same period in 2014 is the result of the changing relationship between our contract prices and the associated forward curves used to calculate the fair value of our derivatives 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. The increase in total gain (loss) on derivatives, net was partially offset by the cash received for the early settlement in February 2014 of our oil basis swap differential between the Light Louisiana Sweet Argus and the Brent International Petroleum Exchange index oil prices. Net cash settlements received for matured derivatives are based on the cash settlement prices of our matured derivatives compared to the prices specified in the derivative contracts.

See Notes 2.f, 8 and 9 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 derivatives.

Interest expense. Interest expense increased by $3.4 million, or 12%, for the three months ended March 31, 2015, compared to the same period in 2014. The increase is primarily due to (i) interest accruing on the January 2022 Notes from

January 23, 2014, (ii) an outstanding balance on the Senior Secured Credit Facility through March 4, 2015 for the three months ended March 31, 2015 compared to no outstanding balance for the three months ended March 31, 2014 and (iii) the issuance of the March 2023 Notes, which began accruing interest on March 18, 2015.

The table below shows the changes in the significant components of interest expense for the three months ended March 31, 2015 as compared to the same period in 2014:



(in thousands)	Three months ended March 31, 2015 compared to 2014
Changes in interest expense:
January 2022 Notes	$	1,477
Senior Secured Credit Facility, net of capitalized interest	1,141
March 2023 Notes	790
Other	20
Total change in interest expense	$	3,428

Disposal of assets. Loss on disposal of assets increased $0.7 million for three months ended March 31, 2015 compared to the same period in 2014 as a result of losses related to the sales and write-off of materials and supplies.

Income tax expense. The fluctuations in net income and loss before and after income tax expense are shown in the table below:



	Three months ended March 31,
(in thousands)	2015			2014
Income (loss) before income taxes	$	3,171		$	(106	)
Income tax expense	(3,643		)	(107		)
Net loss	$	(472	)	$	(213	)

For the three months ended March 31, 2015 and 2014, the effective tax rate on income (loss) before income taxes was not meaningful due to the significant effect of discrete items on a relatively small amount of net loss. Our effective tax rate is affected by recurring permanent differences and by discrete items that may occur in any given year, but are not consistent from year to year. We expect the fiscal year 2015 annual effective tax rate, excluding discrete items, applicable to forecasted income before income taxes to be 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. 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.

During the three months ended March 31, 2015 and 2014, certain restricted stock awards vested at times when our stock price was lower than the fair value of those restricted stock awards 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 three months ended March 31, 2014, 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. As a result of these differences in book compensation cost and related tax deduction, the tax impact of these shortfalls increased by $2.4 million for the three months ended March 31, 2015 compared to the same period in 2014.

We utilize a one-pool approach when accounting for the pool of windfall tax benefits in which employees and non-employees are grouped into a single pool. As of March 31, 2015 and 2014, we did not have any eligible windfall tax benefits to offset future shortfalls as no excess tax benefits had been recognized, and therefore the tax impact of these shortfalls is included in income tax expense for these respective periods. We expect income tax provisions for future reporting periods will be impacted by this stock compensation tax deduction shortfall; however, we cannot predict the stock compensation shortfall impact because of dependency upon the future market price of our stock.

Results of operations - midstream and marketing

The following table presents selected financial information regarding our midstream and marketing operating segment for the three months ended March 31, 2015 and 2014.



	Three months ended March 31,
(in thousands)	2015			2014
Natural gas sales	$	112		$	—
Midstream service revenues	3,683			1,030
Sales of purchased oil	31,267			—
Total revenues	35,062			1,030
Lease operating expenses, including production tax	—			—
Midstream service expenses	3,342			1,361
Costs of purchased oil	31,200			—
General and administrative⁽¹⁾	2,077			1,338
Depletion, depreciation and amortization⁽²⁾	1,685			639
Other operating costs and expenses⁽³⁾	308			—
Operating loss	$	(3,550	)	$	(2,308	)
Other financial information:
Income (loss) from equity method investee	$	(433	)	$	16
Interest expense⁽⁴⁾	$	(1,327	)	$	(612	)

_______________________________________________________________________________


(1)	G&A costs were allocated based on the number of employees in the respective segment as of March 31, 2015 and 2014, respectively. However, the payroll and deferred compensation costs component of G&A for each segment is based on actual costs for the three months ended March 31, 2015.


(2)	DD&A for other fixed assets related to office furnishings were allocated based on the number of employees in the respective segment as of March 31, 2015 and 2014, respectively.


(3)	Includes the following expenses: restructuring expense, accretion of asset retirement obligations and impairments for the three months ended March 31, 2015 and 2014. These expenses are based on actual costs for the three months ended March 31, 2015 and 2014.


(4)	Interest expense is allocated based on gross property and equipment and total contributions to our equity method investee as of March 31, 2015 and 2014.

Natural gas sales. These revenues are related to our midstream and marketing segment providing our exploration and production segment with processed natural gas for use in the field. The corresponding cost component of these transactions are included in "Midstream service expenses." There were no comparable natural gas sales during the three months ended March 31, 2014.

Midstream service revenues. Our midstream service revenues from operations increased by $2.7 million during the three months ended March 31, 2015 compared to the same period 2014. This increase is due to (i) greater NGL and pipeline condensate sales, (ii) higher volumes of gathered natural gas and (iii) oil throughput fees generated by our oil gathering line which was not operational during the comparable period ended 2014.

Sales of purchased oil. Sales of purchased oil for the three months ended March 31, 2015 was $31.3 million. During the fourth quarter of in 2014, we began purchasing oil from producers in West Texas, transporting the product on the Bridgetex Pipeline and selling the product to a third party in the Houston market.

Midstream service expenses. Midstream service expenses increased by $2.0 million, or 146%, for the three months ended March 31, 2015 compared to the same period in 2014, due to the expanded midstream service component of our business.

Costs of purchased oil. Costs of purchased oil for the three months ended March 31, 2015 was $31.2 million. These costs include purchasing oil from a producer and transporting the purchased oil on the Bridgetex Pipeline to the Houston market.

Income (loss) from equity method investee. We own 49% of the ownership units of Medallion. As such, we account for this investment under the equity method of accounting with our proportionate share of net income (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 sheets as "Investment in equity method investee." See Note 14 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding this investment.

Interest expense. Interest expense increased $0.7 million during the three months ended March 31, 2015 compared to the same period in 2014. Interest is allocated to the midstream and marketing segment based on its gross property and equipment and total contributions to its equity method investee. We have expanded the midstream and marketing component of our business and built out our service facilities significantly in the past year, thereby increasing the interest expense that is allocated to this segment.

Liquidity and capital resources

Our primary sources of liquidity have been cash flows from operations, proceeds from equity offerings, proceeds from senior unsecured note offerings and borrowings under our Senior Secured Credit Facility. As we pursue reserves and production growth in the Permian Basin, we continually monitor and consider which financing alternatives, including debt and equity capital resources, joint ventures and asset sales, are available to meet our future planned or accelerated capital expenditures. Our primary uses of capital have been for the acquisition, exploration and development of oil and natural gas properties, LMS's infrastructure development and investments in Medallion, our equity method investee.

On March 5, 2015, we completed the sale of 69,000,000 shares of Laredo's common stock at a price to the public of $11.05 per share, from which we received net proceeds of $754.2 million, after underwriting discounts, commissions and offering expenses. Entities affiliated with Warburg Pincus purchased 29,800,000 shares in the March 2015 Equity Offering, following which Warburg Pincus owned 41.0% of our common stock.

On March 18, 2015, we completed an offering of $350.0 million in aggregate principal amount of 6 1/4% senior unsecured notes due 2023, which will mature on March 15, 2023 and bear an interest rate of 6 1/4% per annum payable semi-annually in cash in arrears on March 15 and September 15 of each year, commencing September 15, 2015.

As of March 31, 2015, we had no amounts outstanding under our Senior Secured Credit Facility and $1.85 billion in senior unsecured notes. We had $900.0 million available for borrowings under our Senior Secured Credit Facility and $569.1 million in cash on hand for total available liquidity of $1.47 billion as of March 31, 2015.

On May 4, 2015, our aggregate elected commitment increased to $1.0 billion and our borrowing base increased to $1.25 billion on our Senior Secured Credit Facility. Subsequent to March 31, 2015, we borrowed $60.0 million on our Senior Secured Credit Facility. As of May 5, 2015 we had $1.36 billion in debt outstanding, $940.0 million available for borrowings under our Senior Secured Credit Facility and $12.9 million in cash on hand for total available liquidity of $952.9 million.

Our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations in the event of possible future 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 periods presented are as follows:



	Three months ended March 31,
(in thousands)	2015			2014
Net cash provided by operating activities	$	26,865		$	128,117
Net cash used in investing activities	(282,546		)	(219,266		)
Net cash provided by financing activities	795,453			440,515
Net increase in cash and cash equivalents	$	539,772		$	349,366

Cash flows provided by operating activities

Net cash provided by operating activities was $26.9 million and $128.1 million for the three months ended March 31, 2015 and 2014, respectively. The decrease of $101.3 million was largely due to the $76.7 million net proceeds received for early terminations of commodity derivative contracts during the three months ended March 31, 2014. Other notable changes in net cash provided by operating activities were an increase of $22.3 million in DD&A due to increased production offset by a reduction in working capital.

Our operating cash flows are sensitive to a number of variables, the most significant of which are the volatility of oil, NGL and natural gas prices and production levels. 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

Net cash used in investing activities were $282.5 million and $219.3 million for the three months ended March 31, 2015 and 2014, respectively. The increase of $63.3 million is mainly attributable to increased capital expenditures for oil and natural gas properties and midstream service assets during the three months ended March 31, 2015.

Our cash used in investing activities for the periods presented are summarized in the table below:



	Three months ended March 31,
(in thousands)	2015			2014
Capital expenditures:
Acquisition of mineral interests	$	—		$	(7,305	)
Oil and natural gas properties	(243,733		)	(187,040		)
Midstream service assets	(20,434		)	(10,520		)
Other fixed assets	(3,919		)	(3,369		)
Investment in equity method investee	(14,495		)	(11,300		)
Proceeds from dispositions of capital assets, net of costs	35			268
Net cash used in investing activities	$	(282,546	)	$	(219,266	)

Capital expenditure budget

Our board of directors approved a capital expenditure budget of approximately $525.0 million for calendar year 2015, excluding acquisitions. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted. Due to service cost reductions, we now expect our 2015 capital expenditures, excluding acquisitions, to be approximately $475.0 million.

The amount, timing and allocation of capital expenditures are largely discretionary and within management's control. If oil, NGL and natural gas prices decline below our acceptable levels, or costs increase above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods 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. Subject to financing alternatives, we may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We consistently monitor and may adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing and joint venture opportunities, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, reduction of service costs, contractual obligations, internally generated cash flow and other factors both within and outside our control.

Cash flows provided by financing activities

Our cash flows provided by financing activities were $795.5 million and $440.5 million for the three months ended March 31, 2015 and 2014, respectively. For the three months ended March 31, 2015, our primary sources of cash provided by financing activities were the issuance of our March 2023 Notes and proceeds from our March 2015 Equity Offering, partially offset by our payment in full of our Senior Secured Credit Facility. During the three months ended March 31, 2014, our primary source of cash provided by financing activities were proceeds from the issuance of our January 2022 Notes.

Our cash provided by financing activities for the periods presented are summarized in the table below:



	Three months ended March 31,
(in thousands)	2015			2014
Borrowings on Senior Secured Credit Facility	$	175,000		$	—
Payments on Senior Secured Credit Facility	(475,000		)	—
Issuance of March 2023 Notes	350,000			—
Issuance of January 2022 Notes	—			450,000
Proceeds from issuance of common stock, net of offering costs	754,163			—
Purchase of treasury stock	(2,283		)	(3,274		)
Proceeds from exercise of employee stock options	—			1,585
Payments for debt issuance costs	(6,427		)	(7,796		)
Net cash provided by financing activities	$	795,453		$	440,515

Debt

As of March 31, 2015, we were a party only to our Senior Secured Credit Facility and the indentures governing our senior unsecured notes.

Senior Secured Credit Facility. As of March 31, 2015, our Senior Secured Credit Facility, which matures November 4, 2018, had a maximum credit amount of $2.0 billion, a borrowing base of $1.15 billion, an aggregate elected commitment amount of $900.0 million and no amounts outstanding.

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, in each case, plus an applicable margin based on the ratio of the outstanding amount on the Senior Secured Credit Facility to the elected commitment. We are also required to pay an annual commitment fee on the unused portion of the bank's commitment of 0.375% to 0.5%.

Our Senior Secured Credit Facility is secured by a first-priority lien on our assets, 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 contains both financial and non-financial covenants. We were in compliance with these ratios as of March 31, 2015 and expect to be in compliance with them for the foreseeable future.

Senior unsecured notes. On March 18, 2015, we completed an offering of $350.0 million in aggregate principal amount of 6 1/4% senior unsecured notes due 2023. Our March 2023 Notes will mature on March 15, 2023 and bear an interest rate of 6 1/4% per annum and payable semi-annually in cash in arrears on March 15 and September 15 of each year, commencing September 15, 2015. Our March 2023 Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by LMS, GCM and certain of our future restricted subsidiaries. Our March 2023 Notes were issued under and are governed by an indenture and supplement thereto, each dated March 18, 2015 (collectively, the "2015 indenture"), among Laredo and Wells Fargo Bank, National Association, as trustee. The 2015 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 March 2023 Notes may be accelerated in certain circumstances upon an event of default as set forth in the 2015 indenture.

On January 23, 2014, we completed an offering of $450.0 million aggregate principal amount of 5 5/8% senior unsecured notes due 2022. Our January 2022 Notes will mature on January 15, 2022 and bear an interest rate of 5 5/8% per annum, payable semi-annually, in cash in arrears on January 15 and July 15 of each year, commencing July 15, 2014. Our January 2022 Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by LMS, GCM and certain of our future restricted subsidiaries. Our January 2022 Notes were issued under and are governed by an indenture

dated January 23, 2014 (the "2014 indenture"), among Laredo and Wells Fargo Bank, National Association, as trustee. The 2014 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 January 2022 Notes may be accelerated in certain circumstances upon an event of default as set forth in the 2014 indenture.

On April 27, 2012, we completed an offering of $500.0 million aggregate principal amount of 7 3/8% senior unsecured notes due 2022. Our May 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. Our May 2022 Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by LMS, GCM and certain of our future restricted subsidiaries. Our May 2022 Notes were issued under and are governed by an indenture and supplement thereto, each dated April 27, 2012 (collectively, the "2012 indenture"), among Laredo and Wells Fargo Bank, National Association, as trustee. 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 May 2022 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, we 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. Our January 2019 Notes were due to mature on February 15, 2019 and bore 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 January 2019 Notes were fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by LMS, GCM and certain of our future restricted subsidiaries. Our January 2019 Notes were issued under and are governed by an indenture dated January 20, 2011, among Laredo and Wells Fargo Bank, National Association, as trustee (the "2011 indenture"). The 2011 indenture contained 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.

Utilizing proceeds from the March 2023 Notes and the March 2015 Equity Offering, we redeemed the January 2019 Notes in full on April 6, 2015. See Note 19.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for information regarding the early redemption of the January 2019 Notes.

Refer to Note 4 of our audited consolidated financial statements included in the 2014 Annual Report and Note 5 of our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of the March 2023 Notes, January 2022 Notes, May 2022 Notes, January 2019 Notes and our Senior Secured Credit Facility.

As of May 6, 2015, we had a total of $1.3 billion of senior unsecured notes outstanding and $60.0 million outstanding on the Senior Secured Credit Facility.

Obligations and commitments

As of March 31, 2015, our contractual obligations included our March 2023 Notes, January 2022 Notes, May 2022 Notes, January 2019 Notes, Senior Secured Credit Facility, drilling contract commitments, derivatives, performance unit liability awards, asset retirement obligations, office and equipment leases and capital contribution commitments to our equity method investee. From December 31, 2014 to March 31, 2015, the material changes in our contractual obligations included (i) an increase of $525.0 million in principal and interest due to the March 2023 Notes offering, (ii) a decrease of $300.0 million outstanding on our Senior Secured Credit Facility, (iii) a decrease of $38.8 million on our interest obligations for our senior unsecured notes as semi-annual interest payments were made in January and February 2015, (iv) a decrease in our outstanding capital contribution commitment to our equity method investee due to a payment by us of $14.5 million towards construction of pipeline extensions by Medallion and (v) a decrease of $11.5 million for drilling contract commitments (on contracts other than those on a well-by-well basis).

Refer to Notes 2, 5, 6, 8, 9, 11 and 14 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our contractual obligations.

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 net income or loss and other performance measures prepared in accordance with GAAP, such as operating income or loss 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 or loss, operating income or loss 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, depletion, depreciation and amortization, impairment expense, restructuring expenses, write-off of debt issuance costs, bad debt expense, gains or losses on disposal of assets, total gains or losses on derivatives, cash settlements of matured commodity derivatives, cash settlements on early terminated commodity derivatives, premiums paid for derivatives 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, book value of assets, capital structure and the method by which assets were acquired, among other factors;


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


•	is used by our management for various purposes, including as a measure of operating performance, in presentations to our board of directors and 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 loss to Adjusted EBITDA:



	Three months ended March 31,
(in thousands)	2015			2014
Net loss	$	(472	)	$	(213	)
Plus:
Interest expense	32,414			28,986
Depletion, depreciation and amortization	71,942			49,607
Impairment expense	878			—
Restructuring expenses	6,042			—
Write-off of debt issuance costs	—			124
Loss on disposal of assets, net	762			21
(Gain) loss on derivatives, net	(63,155		)	31,112
Cash settlements received (paid) for matured commodity derivatives, net	63,141			(1,431		)
Cash settlements received for early terminations of commodity derivatives, net	—			76,660
Premiums paid for derivatives that matured during the period⁽¹⁾	(1,421		)	(1,959		)
Non-cash stock-based compensation, net of amounts capitalized	4,788			4,329
Deferred income tax expense	3,643			107
Adjusted EBITDA	$	118,562		$	187,343

______________________________________________________________________________


(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 unaudited consolidated financial statements.

In management’s opinion, the more significant reporting areas impacted by our judgments and estimates are (i) the choice of accounting method for oil and natural gas activities, (ii) estimation of oil and natural gas reserve quantities and standardized measure of future net revenues, (iii) revenue recognition, (iv) fair value of assets acquired and liabilities assumed in an acquisition, (v) impairment of oil and natural gas properties, (vi) asset retirement obligations, (vii) valuation of derivatives and deferred premiums, (viii) valuation of stock-based compensation and performance unit compensation and (ix) 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 these estimates, as additional information becomes known.

There have been no material changes in our critical accounting policies and procedures during the three months ended March 31, 2015. For our other critical accounting policies and procedures, please see our disclosure of critical accounting policies in "Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations" of the 2014 Annual Report. Additionally, see Note 2 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 April 2015, the FASB issued new guidance in Subtopic 835-30, Interest-Imputation of Interest which seeks to simplify the presentation of debt issuance costs. These amendments require that debt issuance costs related to a recognized debt liability be presented in an entity's balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this guidance. Entities should apply the amendments on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. The guidance is effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period. Early adoption is permitted. We early-adopted this standard on April 1, 2015 and will apply the provisions in our second-quarter unaudited consolidated financial statements.

In May 2014, the FASB issued a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—Revenue Recognition. The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard’s application impact to individual financial statement line items. This standard is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. We are currently evaluating this standard and our existing revenue recognition policies to determine what impact this guidance will have on our consolidated financial statements upon adoption.

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," in our case, refers to the risk of loss arising from adverse changes in oil, NGL and natural gas prices and in 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, NGL and natural gas prices, we use commodity derivatives, such as collars, swaps, puts and basis swaps to hedge price risk associated with a significant portion of our anticipated 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 flows 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 in our unaudited consolidated statements of operations.

The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant price indices. As of March 31, 2015, a 10% change in the forward curves associated with our commodity derivatives would have changed our net positions to the following amounts:



(in thousands)	10% Increase		10% Decrease
Commodity derivatives	$	246,281	$	387,725

As of March 31, 2015 and December 31, 2014, the fair values of our open derivative contracts were $313.7 million and $312.3 million, respectively. Refer to Notes 8 and 9 of our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional disclosures regarding our derivatives.

Interest rate risk

Our Senior Secured Credit Facility bears interest at a floating rate and, as of March 31, 2015, we had no indebtedness outstanding on our Senior Secured Credit Facility. Our January 2019 Notes, January 2022 Notes, May 2022 Notes and March 2023 Notes bear fixed interest rates and we had $550.0 million (excluding the remaining premium of $1.2 million), $450.0 million, $500.0 million and $350.0 million outstanding, respectively, as of March 31, 2015, as shown in the table below.



	Expected maturity date
(in millions except for interest rates)	2015			2016			2017			2018			2019			Thereafter			Total
January 2019 Notes - fixed rate⁽¹⁾	$	—		$	—		$	—		$	—		$	550.0		$	—		$	550.0
Average interest rate	—		%	—		%	—		%	—		%	9.500		%	—		%	9.500		%
January 2022 Notes - fixed rate	$	—		$	—		$	—		$	—		$	—		$	450.0		$	450.0
Average interest rate	—		%	—		%	—		%	—		%	—		%	5.625		%	5.625		%
May 2022 Notes - fixed rate	$	—		$	—		$	—		$	—		$	—		$	500.0		$	500.0
Average interest rate	—		%	—		%	—		%	—		%	—		%	7.375		%	7.375		%
March 2023 Notes - fixed rate	$	—		$	—		$	—		$	—		$	—		$	350.0		$	350.0
Average interest rate	—		%	—		%	—		%	—		%	—		%	6.250		%	6.250		%
Senior Secured Credit Facility - variable rate	$	—		$	—		$	—		$	—		$	—		$	—		$	—
Average interest rate	—		%	—		%	—		%	—		%	—		%	—		%	—		%

______________________________________________________________________________


(1)	See Note 19.a of our unaudited consolidated financial statements included elsewhere in this Quarterly Report for a discussion of the early redemption of our January 2019 Notes.

Counterparty and customer credit risk

Our principal exposures to credit risk are through (i) the receivables from derivatives ($313.7 million as of March 31, 2015), (ii) receivables resulting from the sale of our oil, NGL and natural gas production ($44.9 million as of March 31, 2015), which we market to energy marketing companies and refineries, (iii) joint interest receivables ($25.8 million as of March 31, 2015) (iv) receivables from matured derivatives ($20.8 million as of March 31, 2015) and (v) receivables from midstream product sales ($18.0 million as of March 31, 2015).

We are subject to credit risk due to the concentration of (i) our oil, NGL and natural gas receivables with several significant customers and (ii) our midstream service product sales receivable with one significant customer. On occasion we 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 also are lenders in our Senior Secured Credit Facility. The terms of the ISDA Agreements provide the counterparties and us with rights of offset upon the occurrence of defined acts of default by either a counterparty or us 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 10 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional disclosures regarding credit risk.

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 Exchange Act), was performed under the supervision and with the participation of Laredo's management, including our principal executive officer and principal financial officer. Based on that evaluation, these officers concluded that Laredo's disclosure controls and procedures were effective as of March 31, 2015. 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 March 31, 2015 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 may not 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 2014 Annual Report as well as the updated risk factor set forth below. Other than with respect to the updated risk factor below, there have been no material changes in our risk factors from those described in the 2014 Annual Report. The risks described in the 2014 Annual Report are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

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

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

The process is typically regulated by state oil and gas commissions. The U.S. Environmental Protection Agency (the "EPA"), however, recently asserted federal regulatory authority over hydraulic fracturing under the Federal Safe Drinking Water Act's ("SDWA") Underground Injection Control ("UIC") Program. Under this assertion of authority, the EPA requires facilities to obtain permits to use diesel fuel in hydraulic fracturing operations. The U.S. Energy Policy Act of 2005, which exempts hydraulic fracturing from regulation under the SDWA, prohibits the use of diesel fuel in the fracturing process without a UIC permit. On February 12, 2014, the EPA published a revised UIC Program guidance for oil and natural gas hydraulic fracturing activities using diesel fuel. The guidance document describes how regulations of Class II wells, which are those wells injecting fluids associated with oil and natural gas production activities, may be tailored to address the purported unique risks of diesel fuel injection during the hydraulic fracturing process. Although the EPA is not the permitting authority for UIC Class II programs in Texas, where we maintain acreage, the EPA is encouraging state programs to review and consider use of the above-mentioned draft guidance. Also, the EPA is updating chloride water quality criteria for the protection of aquatic life under the Clean Water Act, which criteria are used by states for establishing acceptable discharge limits. The EPA is expected to release draft criteria in early 2016. In addition, in May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking public comment on its intent to develop and issue regulations under the Toxic Substances Control Act regarding the disclosure of information related to the chemicals used in hydraulic fracturing. The public comment period ended on September 18, 2014. On November 3, 2011, the EPA released its Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources. The study will include both analysis of existing data and investigative activities designed to generate future data. The EPA issued a progress report in December 2012, held several technical workshops during 2013, and expects to release a draft report for public comment and peer review in 2015.

In August 2012, the EPA adopted rules that subject oil and natural gas production, processing, transmission, and storage operations to regulation under the New Source Performance Standards ("NSPS") and National Emission Standards for Hazardous Air Pollutants programs. The rule includes NSPS standards for completions of hydraulically fractured gas wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The final rule seeks to achieve a 95% reduction in volatile organic compounds ("VOC") emitted by requiring the use of reduced emission completions or "green completions" on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community. In response, the EPA has issued, and will likely continue to issue, revised

rules responsive to some of these requests for reconsideration. For example, in September 2013 and December 2014, the EPA published updates to the 2012 performance standards. Specifically, on September 23, 2014, the EPA finalized the portion of the rule addressing VOC emissions from storage tanks, including a phase-in period and an alternative emissions limit for older tanks. On December 19, 2014, the EPA issued clarification on the manner in which gases and liquids should be handled during well completion operations, as well as changes to the requirements for storage vessels. In addition, on January 14, 2015, the EPA announced a series of steps it plans to take to address methane and smog-forming VOC emissions from the oil and gas industry. These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. In addition, on March 26, 2015, the Federal Bureau of Land Management (the "BLM") published a final rule governing hydraulic fracturing on Federal and Indian lands. The rule requires public disclosure of chemicals used in hydraulic fracturing on Federal and Indian lands, confirmation that wells used in fracturing operations meet appropriate construction standards, development of appropriate plans for managing flowback water that returns to the surface, increased standards for interim storage of recovered waste fluids, and submission to the BLM of detailed information on the geology, depth and location of preexisting wells. This rule will take effect on June 24, 2015, although it is the subject of several pending lawsuits recently filed by industry groups and at least one state. We have already commenced similar disclosure with state regulators. In addition, legislation is pending in Congress to repeal the hydraulic fracturing exemption from the SDWA, provide for Federal regulation of hydraulic fracturing, and require public disclosure of the chemicals used in the fracturing process. Finally, on April 7, 2015, the EPA published in the Federal Register a proposed rule requiring federal pre-treatment standards for wastewater generated during the hydraulic fracturing process. Hydraulic fracturing stimulation requires the use of a significant volume of water with some resulting "flowback," as well as "produced water." The EPA asserts that this water may contain radioactive materials and other pollutants and, therefore, may deteriorate drinking water quality if not properly treated before discharge. The Clean Water Act prohibits the discharge of wastewater into federal or state waters. Thus, "flowback" and "produced water" must either be injected into permitted disposal wells or transported to public or private treatment facilities for treatment, or recycled. The EPA asserts that due to some contaminants in hydraulic fracturing wastewater, most treatment facilities are unable to properly treat the wastewater before introducing it into public waters. If adopted, the new pre-treatment rules will require shale gas operations to pre-treat wastewater before transferring it to treatment facilities. The proposed rule is undergoing a public comment period, which ends on June 8, 2015.

Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For example, pursuant to legislation adopted by the State of Texas in 2011, the chemical components used in the hydraulic fracturing process, as well as the volume of water used, have been required to be disclosed to the Texas Railroad Commission ("RRC") and the public since February 1, 2012. Furthermore, on May 23, 2013, the RRC issued the "well integrity rule," which updates the RRC's Rule 13 requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit to the RRC cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The "well integrity rule" took effect in January 2014. Additionally, on October 28, 2014, the RRC adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed, new disposal well. The disposal well rule amendments also clarify the RRC's authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The disposal well rule amendments became effective November 17, 2014. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular.

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

Item 2. Repurchase of Equity Securities



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
January 1, 2015 - January 31, 2015	5,726	$	9.78	—	—
February 1, 2015 - February 28, 2015	174,395	$	12.54	—	—
March 1, 2015 - March 31, 2015	3,381	$	11.74	—	—
Total	183,502

______________________________________________________________________________


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

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Disclosure pursuant to Section 13(r) of the Securities Exchange Act of 1934

Pursuant to Section 13(r) of the Exchange Act, we may be required to disclose in our annual and quarterly reports to the SEC, whether we or any of our "affiliates" knowingly engaged in certain activities, transactions or dealings relating to Iran or with certain individuals or entities targeted by U.S. economic sanctions. Disclosure is generally required even where the activities, transactions or dealings were conducted in compliance with applicable law. Because the SEC defines the term "affiliate" broadly, it includes any entity under common "control" with us (with the term "control" also being construed broadly by the SEC).

The description of the activities below has been provided to us by Warburg Pincus LLC ("WP"), affiliates of which: (i) beneficially own more than 10% of our outstanding common stock and/or are members of our board of directors and (ii) beneficially own more than 10% of the equity interests of, and have the right to designate members of the board of directors of, Santander Asset Management Investment Holdings Limited ("SAMIH"). SAMIH may therefore be deemed to be under common "control" with us; however, this statement is not meant to be an admission that common control exists.

The disclosure below relates solely to activities conducted by SAMIH and its non-U.S. affiliates that may be deemed to be under common "control" with us. The disclosure does not relate to any activities conducted by us or by WP and does not involve our or WP's management. Neither WP nor Laredo has had any involvement in or control over the disclosed activities of SAMIH, and neither WP nor Laredo has independently verified or participated in the preparation of the disclosure. Neither WP nor Laredo is representing to the accuracy or completeness of the disclosure nor do WP or we undertake any obligation to correct or update it.

We understand that SAMIH's affiliates intend to disclose in their next annual or quarterly SEC report that Santander UK holds frozen savings and current accounts for two customers resident in the U.K. who are currently designated by the U.S. for terrorism. The accounts held by each customer were blocked after the customer's designation and remained blocked and dormant throughout the first quarter of 2015. No revenue has been generated by Santander UK on these accounts.

An Iranian national, resident in the U.K., who is currently designated by the U.S. under the Iranian Financial Sanctions Regulations and the Weapons of Mass Destruction Proliferators Sanctions Regulations ("NPWMD sanctions program"), holds a mortgage with Santander UK that was issued prior to any such designation. No further drawdown has been made (or would be permitted) under this mortgage although Santander UK continues to receive repayment installments. In the first quarter of 2015, total revenue in connection with the mortgage was approximately £800 and net profits were negligible relative to the overall profits of Santander UK. Santander UK does not intend to enter into any new relationships with this customer, and any disbursements will only be made in accordance with applicable sanctions. The same Iranian national also holds two investment accounts with Santander Asset Management UK Limited. The accounts have remained frozen during the first quarter of 2015. The investment returns are being automatically reinvested, and no disbursements have been made to the customer. Total revenue for the Santander Group in connection with the investment accounts was approximately £70 and net profits in the first quarter of 2015 were negligible relative to the overall profits of Banco Santander, S.A.

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 May 4, 2015, we entered into the Third Amendment to Fourth Amended and Restated Credit Agreement among Laredo, 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 borrowing base was increased to $1.25 billion and the aggregate elected commitment amount was increased to $1.0 billion, (ii) the basket for "permitted investments" was changed to an aggregate of 5% of consolidated net tangible assets, (iii) the amount available under the "other" permitted investment basket was increased to $20.0 million and (iv) certain other terms of the Senior Secured Credit Facility were amended as set forth in the Amendment. 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 10.3 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			Certificate of Ownership and Merger, dated as of December 30, 2013 (incorporated by reference to Exhibit 3.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on January 6, 2014).

3.3			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).

4.2			Indenture, dated as of March 18, 2015, among Laredo Petroleum, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on March 24, 2015).

4.3			Supplemental Indenture, dated as of March 18, 2015, among Laredo Petroleum, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on March 24, 2015).

4.4			Form of 6 1/4% Senior Notes due 2023 (incorporated by reference to Exhibit 4.3 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on March 24, 2015).

10.1			Non-Exclusive Aircraft Lease Agreement, dated January 1, 2015, between Lariat Ranch, LLC and Laredo Petroleum, Inc. (incorporated by reference to Exhibit 10.14 of Laredo's Annual Report on Form 10-K (File No. 001-35380) filed on February 26, 2015).

10.2			Waiver Letter to Fourth Amended and Restated Credit Agreement, dated March 3, 2015, among Laredo Petroleum, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the other financial institutions signatory thereto (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on March 4, 2015).

10.3*			Third Amendment to Fourth Amended and Restated Credit Agreement, dated as of May 4, 2015, among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, Laredo Midstream Services, LLC, Garden City Minerals, LLC 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 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, INC.

Date: May 7, 2015	By:	/s/ Randy A. Foutch
		Randy A. Foutch
		Chairman and Chief Executive Officer
		(principal executive officer)

Date: May 7, 2015	By:	/s/ Richard C. Buterbaugh
		Richard C. Buterbaugh
		Executive Vice President and Chief Financial Officer
		(principal financial officer)

	By:
Date: May 7, 2015	By:	/s/ Michael T. Beyer
		Michael T. Beyer
		Vice President - Controller and Chief Accounting Officer
		(principal 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			Certificate of Ownership and Merger, dated as of December 30, 2013 (incorporated by reference to Exhibit 3.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on January 6, 2014).

3.3			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).

4.2			Indenture, dated as of March 18, 2015, among Laredo Petroleum, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on March 24, 2015).

4.3			Supplemental Indenture, dated as of March 18, 2015, among Laredo Petroleum, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on March 24, 2015).

4.4			Form of 6 1/4% Senior Notes due 2023 (incorporated by reference to Exhibit 4.3 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on March 24, 2015).

10.1			Non-Exclusive Aircraft Lease Agreement, dated January 1, 2015, between Lariat Ranch, LLC and Laredo Petroleum, Inc. (incorporated by reference to Exhibit 10.14 of Laredo's Annual Report on Form 10-K (File No. 001-35380) filed on February 26, 2015).

10.2			Waiver Letter to Fourth Amended and Restated Credit Agreement, dated March 3, 2015, among Laredo Petroleum, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the other financial institutions signatory thereto (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on March 4, 2015).

10.3*			Third Amendment to Fourth Amended and Restated Credit Agreement, dated as of May 4, 2015, among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, Laredo Midstream Services, LLC, Garden City Minerals, LLC 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.