Edgar Filing: Laredo Petroleum, Inc.

Document

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 September 30, 2016

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 October 31, 2016: 241,927,779

TABLE OF CONTENTS



		Page
Cautionary Statement Regarding Forward-Looking Statements		iii
	Part I
Item 1.	Consolidated Financial Statements (Unaudited):
	Consolidated balance sheets as of September 30, 2016 and December 31, 2015	1
	Consolidated statements of operations for the three and nine months ended September 30, 2016 and 2015	2
	Consolidated statement of stockholders' equity for the nine months ended September 30, 2016	3
	Consolidated statements of cash flows for the nine months ended September 30, 2016 and 2015	4
	Condensed notes to the consolidated financial statements:
	1. Organization	5
	2. Basis of presentation and significant accounting policies	5
	3. Equity offerings	12
	4. Acquisitions and divestiture	12
	5. Debt	13
	6. Employee compensation	15
	7. Income taxes	19
	8. Derivatives	20
	9. Fair value measurements	24
	10. Net income (loss) per common share	27
	11. Credit risk	28
	12. Commitments and contingencies	28
	13. 2015 Restructuring	29
	14. Variable interest entity	29
	15. Related parties	30
	16. Segments	32
	17. Subsidiary guarantors	35
	18. Recently issued or adopted accounting pronouncements	38
	19. Subsequent events	40
	20. Supplementary information	41
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	42
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	60
Item 4.	Controls and Procedures	62
	Part II
Item 1.	Legal Proceedings	63
Item 1A.	Risk Factors	63
Item 2.	Repurchase of Equity Securities	63
Item 3.	Defaults Upon Senior Securities	63
Item 4.	Mine Safety Disclosures	63
Item 5.	Other Information	63
Item 6.	Exhibits	65
Signatures		66
Exhibit Index		67

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, and substantial decline in, oil, natural gas liquids ("NGL") and natural gas prices, which remain at low levels;


•	revisions to our reserve estimates as a result of changes in commodity prices and uncertainties;


•	impacts to our financial statements as a result of impairment write-downs;


•	our ability to discover, estimate, develop and replace oil, NGL and natural gas reserves;


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


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


•	the ongoing instability and uncertainty in the United States 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, NGL and natural gas;


•	capital requirements for our operations and projects;


•	our ability to maintain the borrowing capacity under our Senior Secured Credit Facility (as defined below) or access other means of obtaining capital and liquidity, especially during periods of sustained low commodity prices;


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


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


•	the potentially insufficient refining capacity in the United States Gulf Coast to refine all of the light sweet crude oil being produced in the United States, which could result in widening price discounts to world crude prices and potential shut-in of production due to lack of sufficient markets;


•	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;


•	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;


•	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;

iii


•	the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses, assets and properties;


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


•	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" 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, 2015 (the "2015 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)



	September 30, 2016			December 31, 2015
Assets
Current assets:
Cash and cash equivalents	$	30,360		$	31,154
Accounts receivable, net	81,223			87,699
Derivatives	64,484			198,805
Other current assets	14,329			14,574
Total current assets	190,396			332,232
Property and equipment:
Oil and natural gas properties, full cost method:
Evaluated properties	5,403,754			5,103,635
Unevaluated properties not being depleted	215,738			140,299
Less accumulated depletion and impairment	(4,480,161		)	(4,218,942		)
Oil and natural gas properties, net	1,139,331			1,024,992
Midstream service assets, net	126,672			131,725
Other fixed assets, net	39,639			43,538
Property and equipment, net	1,305,642			1,200,255
Derivatives	21,872			77,443
Investment in equity method investee	229,912			192,524
Other assets, net	8,626			10,833
Total assets	$	1,756,448		$	1,813,287
Liabilities and stockholders' equity
Current liabilities:
Accounts payable	$	20,033		$	14,181
Undistributed revenue and royalties	24,674			34,540
Accrued capital expenditures	36,909			61,872
Derivatives	1,628			—
Other current liabilities	77,011			106,222
Total current liabilities	160,255			216,815
Long-term debt, net	1,353,232			1,416,226
Derivatives	3,101			—
Asset retirement obligations	49,016			44,759
Other noncurrent liabilities	3,743			4,040
Total liabilities	1,569,347			1,681,840
Commitments and contingencies
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of September 30, 2016 and December 31, 2015	—			—
Common stock, $0.01 par value, 450,000,000 shares authorized and 241,967,107 and 213,808,003 issued and outstanding as of September 30, 2016 and December 31, 2015, respectively	2,420			2,138
Additional paid-in capital	2,384,342			2,086,652
Accumulated deficit	(2,199,661		)	(1,957,343		)
Total stockholders' equity	187,101			131,447
Total liabilities and stockholders' equity	$	1,756,448		$	1,813,287

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 September 30,						Nine months ended September 30,
	2016			2015			2016			2015
Revenues:
Oil, NGL and natural gas sales	$	114,805		$	104,607		$	290,473		$	348,279
Midstream service revenues	2,488			1,873			5,921			4,908
Sales of purchased oil	42,441			43,860			116,670			130,178
Total revenues	159,734			150,340			413,064			483,365
Costs and expenses:
Lease operating expenses	18,177			25,112			57,920			86,698
Production and ad valorem taxes	7,066			7,895			21,483			26,481
Midstream service expenses	1,039			1,092			2,826			4,263
Minimum volume commitments	1,582			—			1,582			5,235
Costs of purchased oil	44,232			46,961			121,190			132,578
General and administrative	26,105			22,913			66,058			67,976
Restructuring expenses	—			—			—			6,042
Accretion of asset retirement obligations	883			599			2,587			1,771
Depletion, depreciation and amortization	35,158			66,777			110,813			210,831
Impairment expense	—			906,850			162,027			1,397,327
Total costs and expenses	134,242			1,078,199			546,486			1,939,202
Operating income (loss)	25,492			(927,859		)	(133,422		)	(1,455,837		)
Non-operating income (expense):
Gain (loss) on derivatives, net	6,850			142,580			(43,783		)	141,836
Income from equity method investee	265			2,104			6,259			4,585
Interest expense	(23,077		)	(23,348		)	(70,294		)	(79,732		)
Interest and other income	33			92			143			388
Loss on early redemption of debt	—			—			—			(31,537		)
Write-off of debt issuance costs	—			—			(842		)	—
Loss on disposal of assets, net	(78		)	(94		)	(379		)	(1,937		)
Non-operating income (expense), net	(16,007		)	121,334			(108,896		)	33,603
Income (loss) before income taxes	9,485			(806,525		)	(242,318		)	(1,422,234		)
Income tax (expense) benefit:
Deferred	—			(41,258		)	—			176,945
Total income tax (expense) benefit	—			(41,258		)	—			176,945
Net income (loss)	$	9,485		$	(847,783	)	$	(242,318	)	$	(1,245,289	)
Net income (loss) per common share:
Basic	$	0.04		$	(4.01	)	$	(1.09	)	$	(6.38	)
Diluted	$	0.04		$	(4.01	)	$	(1.09	)	$	(6.38	)
Weighted-average common shares outstanding:
Basic	234,639			211,204			221,303			195,081
Diluted	238,108			211,204			221,303			195,081

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)					Accumulated deficit
	Shares		Amount			Additional paid-in capital			Shares		Amount			Accumulated deficit			Total
Balance, December 31, 2015	213,808		$	2,138		$	2,086,652		—		$	—		$	(1,957,343	)	$	131,447
Restricted stock awards	2,976		30			(30		)	—		—			—			—
Restricted stock forfeitures	(414	)	(4		)	4			—		—			—			—
Vested restricted stock exchanged for tax withholding	—		—			—			295		(1,613		)	—			(1,613		)
Retirement of treasury stock	(295	)	(3		)	(1,610		)	(295	)	1,613			—			—
Exercise of employee stock options	17		—			208			—		—			—			208
Equity issuances, net of offering costs	25,875		259			275,793			—		—			—			276,052
Stock-based compensation	—		—			23,325			—		—			—			23,325
Net loss	—		—			—			—		—			(242,318		)	(242,318		)
Balance, September 30, 2016	241,967		$	2,420		$	2,384,342		—		$	—		$	(2,199,661	)	$	187,101

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

Laredo Petroleum, Inc.

Consolidated statements of cash flows

(in thousands)

(Unaudited)



	Nine months ended September 30,
	2016			2015
Cash flows from operating activities:
Net loss	$	(242,318	)	$	(1,245,289	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Deferred income tax benefit	—			(176,945		)
Depletion, depreciation and amortization	110,813			210,831
Impairment expense	162,027			1,397,327
Loss on early redemption of debt	—			31,537
Bad debt expense	—			107
Non-cash stock-based compensation, net of amounts capitalized	19,562			17,933
Mark-to-market on derivatives:
(Gain) loss on derivatives, net	43,783			(141,836		)
Cash settlements received for matured derivatives, net	157,626			175,879
Cash settlements received for early terminations of derivatives, net	80,000			—
Change in net present value of deferred premiums paid for derivatives	184			141
Cash premiums paid for derivatives	(86,972		)	(3,918		)
Amortization of debt issuance costs	3,231			3,612
Write-off of debt issuance costs	842			—
Income from equity method investee	(6,259		)	(4,585		)
Cash settlement of performance unit awards	(6,394		)	(2,738		)
Other, net	2,973			3,709
Decrease in accounts receivable	6,476			26,147
Increase in other assets	(594		)	(1,234		)
Increase (decrease) in accounts payable	5,852			(15,361		)
Decrease in undistributed revenues and royalties	(9,866		)	(27,092		)
Increase (decrease) in other accrued liabilities	4,785			(25,676		)
(Decrease) increase in other noncurrent liabilities	(297		)	221
Increase in fair value of performance unit awards	—			2,734
Net cash provided by operating activities	245,454			225,504
Cash flows from investing activities:
Capital expenditures:
Acquisitions of oil and natural gas properties	(115,600		)	—
Oil and natural gas properties	(276,735		)	(490,351		)
Midstream service assets	(4,231		)	(35,237		)
Other fixed assets	(982		)	(8,539		)
Investment in equity method investee	(58,712		)	(63,011		)
Proceeds from dispositions of capital assets, net of selling costs	365			65,261
Net cash used in investing activities	(455,895		)	(531,877		)
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility	214,682			310,000
Payments on Senior Secured Credit Facility	(279,682		)	(475,000		)
Issuance of March 2023 Notes	—			350,000
Redemption of January 2019 Notes	—			(576,200		)
Proceeds from issuance of common stock, net of offering costs	276,052			754,163
Purchase of treasury stock	(1,613		)	(2,749		)
Proceeds from exercise of employee stock options	208			—
Payments for debt issuance costs	—			(6,759		)
Net cash provided by financing activities	209,647			353,455
Net (decrease) increase in cash and cash equivalents	(794		)	47,082
Cash and cash equivalents, beginning of period	31,154			29,321
Cash and cash equivalents, end of period	$	30,360		$	76,403

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, and the transportation of oil and natural gas from such 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" refers to Laredo, LMS and GCM 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: (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 Laredo's exploration and production segment and third parties with products and services that need to be delivered by midstream infrastructure, including oil and natural gas gathering services as well as rig fuel, natural gas lift and water delivery and takeaway in and around Laredo's primary production corridors.

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 accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All material intercompany transactions and account balances have been eliminated in the consolidation of accounts. The Company 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 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, 2015 is derived from audited consolidated financial statements. In the opinion of management, the accompanying unaudited consolidated financial statements reflect all necessary adjustments to present fairly the Company's financial position as of September 30, 2016, results of operations for the three and nine months ended September 30, 2016 and 2015 and cash flows for the nine months ended September 30, 2016 and 2015.

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 2015 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) impairments, (v) asset retirement obligations, (vi) stock-based compensation, (vii) deferred income taxes, (viii) fair value of assets acquired and liabilities assumed in an acquisition and (ix) fair values of derivatives, deferred premiums and performance unit awards. As fair value is a market-based measurement, it is determined based on the assumptions that would be used by market participants. These estimates and assumptions are based on management's best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions. Management

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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 2016 presentation. These reclassifications had no impact to previously reported balance sheets, net income (loss) or stockholders' equity.

d. Accounts receivable

The Company sells produced oil, NGL and natural gas and purchased oil to various customers and participates with other parties in the development and operation of oil and natural gas properties. 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.

Joint interest operations 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 some or all of 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 consisted of the following components for the periods presented:



(in thousands)	September 30, 2016		December 31, 2015
Oil, NGL and natural gas sales	$	39,590	$	25,582
Sales of purchased oil and other products	14,018		11,775
Matured derivatives	13,783		27,469
Joint operations, net⁽¹⁾	13,550		21,375
Other	282		1,498
Total	$	81,223	$	87,699

______________________________________________________________________________


(1)	Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.2 million as of both September 30, 2016 and December 31, 2015.

e. Derivatives

The Company uses derivatives to reduce exposure to fluctuations in the prices of oil, NGL 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 in the form of puts, swaps, collars and, in prior periods, basis swaps.

Derivatives are recorded at fair value and are presented on a net basis 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 Note 9 for discussion regarding the fair value of the Company's derivatives.

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 Notes 8 and 9 for discussion regarding the Company's derivatives.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

f. Property and equipment

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



(in thousands)	September 30, 2016			December 31, 2015
Evaluated oil and natural gas properties	$	5,403,754		$	5,103,635
Less accumulated depletion and impairment	(4,480,161		)	(4,218,942		)
Evaluated oil and natural gas properties, net	923,593			884,693

Unevaluated properties not being depleted	215,738			140,299

Midstream service assets	148,934			147,811
Less accumulated depreciation and impairment	(22,262		)	(16,086		)
Midstream service assets, net	126,672			131,725

Depreciable other fixed assets	46,167			46,799
Less accumulated depreciation and amortization	(21,442		)	(18,169		)
Depreciable other fixed assets, net	24,725			28,630

Land	14,914			14,908

Total property and equipment, net	$	1,305,642		$	1,200,255

For the three months ended September 30, 2016 and 2015, depletion expense was $6.71 per barrel of oil equivalent ("BOE") sold and $15.32 per BOE sold, respectively. For the nine months ended September 30, 2016 and 2015, depletion expense was $7.55 per BOE sold and $15.87 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 exploring for and developing oil, NGL and natural gas are capitalized and depleted 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 depleted 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, NGL and natural gas.

The following table presents capitalized employee-related costs for the periods presented:



	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2016		2015		2016		2015
Capitalized employee-related costs	$	6,149	$	2,830	$	12,598	$	7,724

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. 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.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The full cost ceiling is based principally on the estimated future net revenues from proved oil and natural gas properties discounted at 10%. Per the SEC guidelines, 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 before differentials ("Benchmark Prices"). The Benchmark Prices are then adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead ("Realized Prices"). The Realized Prices are utilized to calculate the discounted future net revenues in the full cost ceiling calculation.

In the event the unamortized cost of evaluated oil and natural gas properties being depleted 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.

The following table presents the Benchmark Prices, Realized Prices and the corresponding non-cash full cost ceiling impairments recorded as of the periods presented:



	For the quarters ended
	September 30, 2016		June 30, 2016		March 31, 2016		December 31, 2015		September 30, 2015		June 30, 2015		March 31, 2015
Benchmark Prices:
Oil ($/Bbl)	$	38.17	$	39.63	$	42.77	$	46.79	$	55.73	$	68.17	$	79.21
NGL ($/Bbl)	$	17.29	$	17.08	$	17.51	$	18.75	$	21.87	$	26.73	$	31.25
Natural gas ($/MMBtu)	$	2.18	$	2.17	$	2.31	$	2.47	$	2.89	$	3.22	$	3.73
Realized Prices:
Oil ($/Bbl)	$	36.39	$	37.96	$	41.33	$	45.58	$	54.28	$	66.68	$	77.72
NGL ($/Bbl)	$	10.91	$	10.80	$	11.25	$	12.50	$	15.25	$	19.56	$	23.75
Natural gas ($/Mcf)	$	1.65	$	1.64	$	1.75	$	1.89	$	2.30	$	2.62	$	3.09
Non-cash full cost ceiling impairment (in thousands)	$	—	$	—	$	161,064	$	975,011	$	906,420	$	488,046	$	—

Full cost ceiling impairment expense is included in the "Impairment expense" line item in the unaudited consolidated statements of operations and in the financial information provided for the Company's exploration and production segment presented in Note 16.

g. Long-lived assets and inventory

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 inventory used in developing oil and natural gas properties and midstream service assets are carried at the lower of cost or market ("LCM") with cost determined using the weighted-average cost method and are included in "Other current assets" and "Other assets, net" on the unaudited consolidated balance sheets. The market price for materials and supplies is determined utilizing a replacement cost approach (Level 2).

Beginning at March 31, 2016, frac pit water inventory used in developing oil and natural gas properties is carried at LCM with cost determined using the weighted-average cost method and is included in "Other current assets" on the unaudited consolidated balance sheets. The market price for frac pit water inventory is determined utilizing a replacement cost approach (Level 2).

The minimum volume of product in a pipeline system that 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. 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).

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table presents inventory impairments recorded as of the periods presented:



	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2016		2015		2016		2015
Inventory impairments:
Materials and supplies⁽¹⁾	$	—	$	—	$	963	$	2,320
Line-fill⁽²⁾	—		430		—		541
Total inventory impairments	$	—	$	430	$	963	$	2,861

______________________________________________________________________________


(1)	Included in "Impairment expense" in the unaudited consolidated statements of operations and in "Impairment expense" for the Company's exploration and production segment presented in Note 16.


(2)	Included in "Impairment expense" in the unaudited consolidated statements of operations and in "Impairment expense" for the Company's midstream and marketing segment presented in Note 16.

h. Debt issuance costs

Debt issuance fees, which are recorded 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 $6.8 million of debt issuance costs during the nine months ended September 30, 2015 mainly as a result of the issuance of the March 2023 Notes (as defined below). No debt issuance costs were capitalized in the nine months ended September 30, 2016. The Company had total debt issuance costs of $19.9 million and $23.9 million, net of accumulated amortization of $20.3 million and $17.0 million, as of September 30, 2016 and December 31, 2015, respectively.

The Company wrote-off approximately $0.8 million of debt issuance costs during the nine months ended September 30, 2016 as a result of changes in the borrowing base and aggregate elected commitment of the Senior Secured Credit Facility, which are included in the unaudited consolidated statements of operations in the "Write-off of debt issuance costs" line item. During the nine months ended September 30, 2015, the Company wrote-off approximately $6.6 million of debt issuance costs as a result of the early redemption of the January 2019 Notes (as defined below), which are included in the unaudited consolidated statements of operations in the "Loss on early redemption of debt" line item. Unamortized debt issuance costs related to the Company's senior unsecured notes are presented in "Long-term debt, net" on the Company's unaudited consolidated balance sheets. Unamortized debt issuance costs related to the Senior Secured Credit Facility are presented in "Other assets, net" on the Company's unaudited consolidated balance sheets. See Note 5.g for additional discussion of debt issuance costs.

Future amortization expense of debt issuance costs as of the period presented is as follows:



(in thousands)	September 30, 2016
Remaining 2016	$	1,048
2017	4,238
2018	4,068
2019	2,915
2020	3,005
Thereafter	4,585
Total	$	19,859

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

i. Other current assets and liabilities

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



(in thousands)	September 30, 2016		December 31, 2015
Inventory⁽¹⁾	$	8,022	$	6,974
Prepaid expenses and other	6,307		7,600
Total other current assets	$	14,329	$	14,574

______________________________________________________________________________


(1)	See Note 2.g for discussion of inventory held by the Company.

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



(in thousands)	September 30, 2016		December 31, 2015
Accrued interest payable	$	21,561	$	24,208
Accrued compensation and benefits	18,474		14,342
Purchased oil payable	14,520		12,189
Lease operating expense payable	11,336		13,205
Capital contribution payable to equity method investee⁽¹⁾	—		27,583
Other accrued liabilities	11,120		14,695
Total other current liabilities	$	77,011	$	106,222

______________________________________________________________________________


(1)	See Notes 14 and 15 for additional discussion regarding our equity method investee.

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 service assets 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, (iii) estimated removal and/or remediation costs for midstream service assets, (iv) estimated remaining life of midstream service assets, (v) future inflation factors and (vi) the Company's average credit adjusted risk-free rate. 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 assets and perform other remediation of the sites where such pipeline 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 assets in the periods in which settlement dates become reasonably determinable.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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



(in thousands)	Nine months ended September 30, 2016			Year ended December 31, 2015
Liability at beginning of period	$	46,306		$	32,198
Liabilities added due to acquisitions, drilling, midstream service asset construction and other	1,417			2,236
Accretion expense	2,587			2,423
Liabilities settled upon plugging and abandonment	(874		)	(146		)
Liabilities removed due to sale of property	—			(2,005		)
Revision of estimates⁽¹⁾	252			11,600
Liability at end of period	$	49,688		$	46,306

_____________________________________________________________________________


(1)	The revision of estimates that occurred during the year ended December 31, 2015 was mainly related to a change in the estimated remaining life per well due to the decline in commodity prices.

k. Fair value measurements

The carrying amounts reported in the unaudited consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, undistributed revenue and royalties, accrued capital expenditures and other accrued assets and liabilities approximate their fair values. See Note 5.f for fair value disclosures related to the Company's debt obligations. The Company carries its derivatives at fair value. See Note 9 for details regarding the fair value of the Company's derivatives.

l. 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.

m. Compensation awards

Stock-based compensation expense, net of amounts capitalized, is included in "General and administrative" in the unaudited consolidated statements of operations over the awards' vesting periods and is based on the awards' grant date fair value. The Company utilizes the closing stock price on the grant date, less an expected forfeiture rate, to determine the fair values 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, in prior periods, the 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.

n. 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 September 30, 2016 or December 31, 2015.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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:



	Nine months ended September 30,
(in thousands)	2016			2015
Non-cash investing information:
Change in accrued capital expenditures	$	(24,963	)	$	(98,958	)
Change in accrued capital contribution to equity method investee⁽¹⁾	$	(27,583	)	$	34,322
Capitalized asset retirement cost	$	1,669		$	1,675
Supplemental cash flow information:
Capitalized interest	$	199		$	227

______________________________________________________________________________


(1)	See Notes 14 and 15.a for additional discussion regarding our equity method investee.

Note 3—Equity offerings

On July 19, 2016, the Company completed the sale of 13,000,000 shares of Laredo's common stock (the "July 2016 Equity Offering") for net proceeds of approximately $136.3 million, after underwriting discounts, commissions and offering expenses. On August 9, 2016, the underwriters exercised their option to purchase an additional 1,950,000 shares of Laredo's common stock, which resulted in net proceeds to the Company of approximately $20.5 million, after underwriting discounts, commissions and offering expenses.

On May 16, 2016, the Company completed the sale of 10,925,000 shares of Laredo's common stock (the "May 2016 Equity Offering") for net proceeds of $119.3 million, after underwriting discounts, commissions and offering expenses.

On March 5, 2015, the Company completed the sale of 69,000,000 shares of Laredo's common stock (the "March 2015 Equity Offering") for 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.

Note 4—Acquisitions and divestiture

a. 2016 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 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 value of evaluated and unevaluated oil and natural gas properties. The fair value of these properties are measured using a discounted cash flow model that converts future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) forecasted oil, NGL and natural gas reserve quantities; (ii) future commodity strip prices as of the closing dates adjusted for transportation and regional price differentials; (iii) forecasted ad valorem taxes, production taxes, income taxes, general and administrative expenses, operating expenses and and development costs; and (iv) a peer group weighted-average cost of capital rate 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 proved undeveloped and probable reserves are reduced by additional reserve adjustment factors. These assumptions represent Level 3 inputs under the fair value hierarchy, as described in Note 9.

During the three months ended September 30, 2016, the Company entered into an agreement to acquire approximately 9,200 net acres of additional leasehold interests in western Glasscock and Reagan counties (which includes production of approximately 300 net BOE/D from existing vertical wells) within the Company's core development area for an aggregate purchase price of $125.0 million subject to customary closing adjustments. On July 13 and August 24, 2016, the Company closed portions of this acquisition for $94.4 million and $21.2 million, respectively. See Note 19.b for discussion regarding the final closing under this agreement relating to certain remaining interests that were subject to preferential purchase rights that were satisfied subsequent to September 30, 2016.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table reflects an aggregate of the final estimate of the fair value of the acquired assets and liabilities during the three months ended September 30, 2016:



(in thousands)	Fair value of acquisitions
Fair value of net assets:
Evaluated oil and natural gas properties	$	4,800
Unevaluated oil and natural gas properties	110,800
Asset retirement cost	1,105
Total assets acquired	116,705
Asset retirement obligations	(1,105		)
Net assets acquired	$	115,600
Fair value of consideration paid for net assets:
Cash consideration	$	115,600

b. 2015 Divestiture of non-strategic assets

On September 15, 2015, the Company completed the sale of non-strategic and primarily non-operated properties and associated production totaling 6,060 net acres and 123 producing properties in the Midland Basin to a third-party buyer for a purchase price of $65.5 million. After transaction costs reflecting an economic effective date of July 1, 2015, the net proceeds were $64.8 million, net of working capital adjustments and post-closing adjustments. The purchase price, excluding post-closing adjustments, was allocated to oil and natural gas properties pursuant to the rules governing full cost accounting.

Effective at closing, the operations and cash flows of these properties were eliminated from the ongoing operations of the Company, and the Company has no continuing involvement in the properties. This divestiture does not represent a strategic shift and will not have a major effect on the Company's operations or financial results.

The following table presents revenues and expenses of the oil and natural gas properties sold included in the accompanying unaudited consolidated statements of operations for the periods presented:



(in thousands)	Three months ended September 30, 2015		Nine months ended September 30, 2015
Oil, NGL and natural gas sales	$	1,090	$	5,138
Expenses⁽¹⁾	$	1,081	$	5,791

_____________________________________________________________________________


(1)	Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense.

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"). The March 2023 Notes 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. 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 applicable indenture, designation of a subsidiary guarantor as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the applicable indenture, release from guarantee under the Senior Secured Credit Facility, or liquidation or dissolution (collectively, the "Releases").

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 in aggregate principal amount of 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 in aggregate principal amount of 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.

On April 6, 2015 (the "Redemption Date"), utilizing a portion of the proceeds from the March 2015 Equity Offering and the March 2023 Notes offering, the entire $550.0 million outstanding principal amount of the 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 the Redemption Date. The Company recognized a loss on extinguishment of $31.5 million related to the difference between the redemption price and the net carrying amount of the extinguished January 2019 Notes.

e. Senior Secured Credit Facility

As of September 30, 2016, 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 and an aggregate elected commitment of $815.0 million with $70.0 million outstanding and was subject to an interest rate of 2.06%. It contains both financial and non-financial covenants, all of which the Company was in compliance with as of September 30, 2016. 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 September 30, 2016 or 2015.

On October 24, 2016, pursuant to a regular semi-annual redetermination, the lenders reaffirmed the borrowing base under the Senior Secured Credit Facility. Additionally, the Company's aggregate elected commitment remained unchanged.

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:



	September 30, 2016				December 31, 2015
(in thousands)	Long-term debt		Fair value		Long-term debt		Fair value
January 2022 Notes	$	450,000	$	440,010	$	450,000	$	388,301
May 2022 Notes	500,000		517,160		500,000		460,000
March 2023 Notes	350,000		340,535		350,000		301,000
Senior Secured Credit Facility	70,000		69,974		135,000		134,993
Total value of debt	$	1,370,000	$	1,367,679	$	1,435,000	$	1,284,294

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The fair values of the debt outstanding on the January 2022 Notes, May 2022 Notes and the March 2023 Notes were determined using the September 30, 2016 and December 31, 2015 quoted market price (Level 1) for each respective instrument. The fair values of the outstanding debt on the Senior Secured Credit Facility as of September 30, 2016 and December 31, 2015 were estimated utilizing pricing models for similar instruments (Level 2). See Note 9 for information about fair value hierarchy levels.

g. Long-term debt, net

The following table summarizes the net presentation of the Company's long-term debt and debt issuance cost on the unaudited consolidated balance sheets for the periods presented:



	September 30, 2016							December 31, 2015
(in thousands)	Long-term debt		Debt issuance costs, net			Long-term debt, net		Long-term debt		Debt issuance costs, net			Long-term debt, net
January 2022 Notes	$	450,000	$	(5,207	)	$	444,793	$	450,000	$	(5,939	)	$	444,061
May 2022 Notes	500,000		(6,396		)	493,604		500,000		(7,066		)	492,934
March 2023 Notes	350,000		(5,165		)	344,835		350,000		(5,769		)	344,231
Senior Secured Credit Facility⁽¹⁾	70,000		—			70,000		135,000		—			135,000
Total	$	1,370,000	$	(16,768	)	$	1,353,232	$	1,435,000	$	(18,774	)	$	1,416,226

______________________________________________________________________________


(1)	Debt issuance costs related to our Senior Secured Credit Facility are recorded in "Other assets, net" on the unaudited consolidated balance sheets.

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. During the nine months ended September 30, 2016, stockholders approved an increase in the maximum number of shares of the Company's common stock issuable under the LTIP from 10,000,000 shares to 24,350,000 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 in prior periods, its performance unit awards were 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 service vesting 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 for reasons other than death or disability, 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. Historically, restricted stock awards granted to officers and employees vest in a variety of vesting schedules including (i) 33%, 33% and 34% per year beginning on the first anniversary date of the grant, (ii) 50% in year two and 50% in year three, (iii) fully on the first anniversary of the grant date and (iv) 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.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table reflects the outstanding restricted stock awards for the nine months ended September 30, 2016:



(in thousands, except for weighted-average grant date fair values)	Restricted stock awards		Weighted-average grant date fair value (per award)
Outstanding as of December 31, 2015	2,539		$	15.26
Granted	2,976		$	12.27
Forfeited	(414	)	$	14.05
Vested	(1,174	)	$	16.05
Outstanding as of September 30, 2016	3,927		$	12.89

The Company utilizes the closing stock price on the grant date to determine the fair value of service vesting restricted stock awards. As of September 30, 2016, unrecognized stock-based compensation related to the restricted stock awards expected to vest was $36.2 million. Such cost is expected to be recognized over a weighted-average period of 2.06 years.

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 nine months ended September 30, 2016:



(in thousands, except for weighted-average price and contractual term)	Restricted stock option awards		Weighted-average price (per option)		Weighted-average remaining contractual term (years)
Outstanding as of December 31, 2015	1,778		$	17.86	7.91
Granted	1,016		$	4.18
Exercised	(17	)	$	11.93
Expired or canceled	(87	)	$	21.71
Forfeited	(297	)	$	12.47
Outstanding as of September 30, 2016	2,393		$	12.62	7.92
Vested and exercisable at end of period⁽¹⁾	853		$	19.49	6.41
Expected to vest at end of period⁽²⁾	1,535		$	8.78	8.76

_____________________________________________________________________________


(1)	The vested and exercisable options as of September 30, 2016 had $0.1 million aggregate intrinsic value.


(2)	The restricted stock options expected to vest as of September 30, 2016 had $8.4 million aggregate intrinsic value.

The Company utilizes the Black-Scholes option pricing model to determine the fair value of restricted stock option awards and recognizes 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 September 30, 2016, unrecognized stock-based compensation related to restricted stock option awards expected to vest was $11.2 million. Such cost is expected to be recognized over a weighted-average period of 2.92 years.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The assumptions used to estimate the fair value of the 22,324 restricted stock options granted on April 1, 2016 and the 994,022 restricted stock options contingently granted on February 19, 2016 and subsequently approved by stockholders on May 25, 2016 are as follows:



	April 1, 2016			May 25, 2016
Risk-free interest rate⁽¹⁾	1.44		%	1.58		%
Expected option life⁽²⁾	6.25 years			6.25 years
Expected volatility⁽³⁾	61.34		%	61.94		%
Fair value per stock option	$	4.44		$	9.75

____________________________________________________________________________


(1)	United States Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, correlating 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 historical volatility in order to develop the expected volatility.

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 during the nine months ended September 30, 2016 (the "2016 Performance Share Awards"), 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 to determine the grant date fair value of these awards. The Company has determined these 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 1,676,695 outstanding 2016 Performance Share Awards have a performance period of January 1, 2016 to December 31, 2018, and any shares earned under such awards are expected to be issued in the first quarter of 2019 if the performance criteria are met. The 454,164 outstanding 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. The 200,516 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.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table reflects the performance share award activity for the nine months ended September 30, 2016:



(in thousands, except for weighted-average grant date fair values)	Performance share awards		Weighted-average grant date fair value (per award)
Outstanding as of December 31, 2015	874		$	20.06
Granted	1,801		$	17.71
Forfeited	(344	)	$	19.37
Vested	—		$	—
Outstanding as of September 30, 2016	2,331		$	18.35

As of September 30, 2016, unrecognized stock-based compensation related to the performance share awards was $30.1 million. Such cost is expected to be recognized over a weighted-average period of 2.25 years.

The assumptions used to estimate the fair values of the 32,495 performance share awards granted on April 1, 2016 and the 1,768,297 performance share awards contingently granted on February 19, 2016 and subsequently approved by stockholders on May 25, 2016 are as follows:



	April 1, 2016			May 25, 2016
Risk-free rate⁽¹⁾	0.87		%	1.02		%
Dividend yield	—		%	—		%
Expected volatility⁽²⁾	71.54		%	74.73		%
Laredo stock closing price on grant date	$	7.71		$	12.36
Fair value per performance share	$	9.83		$	17.86

______________________________________________________________________________


(1)	The risk-free rate was derived using a term-matched zero-coupon yield derived from the treasury constant maturities yield curve on the grant date.


(2)	The Company utilized its own historical volatility over a look-back period equal to the length of the remaining performance period from the grant date in order to develop the expected volatility.

d. Stock-based compensation expense

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



	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2016			2015			2016			2015
Restricted stock award compensation	$	6,540		$	5,177		$	15,000		$	12,635
Restricted stock option award compensation	1,653			1,030			3,054			2,979
Restricted performance share award compensation	3,450			1,469			5,271			3,742
Total stock-based compensation, gross	11,643			7,676			23,325			19,356
Less amounts capitalized in oil and natural gas properties	(1,992		)	(799		)	(3,763		)	(1,423		)
Total stock-based compensation, net of amounts capitalized	$	9,651		$	6,877		$	19,562		$	17,933

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") were subject to a combination of market and service vesting criteria. These awards were accounted for as liability awards as they were settled in cash at the end of the requisite service period based on the achievement of certain performance criteria.

The 44,481 settled 2013 Performance Unit Awards had a performance period of January 1, 2013 to December 31, 2015 and, as their performance criteria were satisfied, they were paid at $143.75 per unit during the first quarter of 2016. The 27,381 settled 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 $100.00 per unit during the first quarter of 2015.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

For the three and nine months ended September 30, 2015, compensation expense for the 2013 Performance Unit Awards is included in "General and administrative" in the Company's unaudited consolidated statements of operations, and as of December 31, 2015, the corresponding liability is included in "Other current liabilities" on the unaudited consolidated balance sheets. Due to the quarterly re-measurement of the fair value of the 2013 Performance Unit Awards as of September 30, 2015, compensation expense for the three and nine months ended September 30, 2015 was $1.0 million and $2.7 million, respectively.

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.

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 settlement. The Company had no unrecognized tax benefits related to uncertain tax positions in the unaudited consolidated financial statements as of September 30, 2016 or December 31, 2015.

The Company is subject to federal and state income taxes and the Texas franchise tax. Income tax (expense) benefit for the periods presented consisted of the following:



	Three months ended September 30,					Nine months ended September 30,
(in thousands)	2016		2015			2016		2015
Current taxes	$	—	$	—		$	—	$	—
Deferred taxes	—		(41,258		)	—		176,945
Income tax (expense) benefit	$	—	$	(41,258	)	$	—	$	176,945

Income tax (expense) benefit 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 September 30,						Nine months ended September 30,
(in thousands)	2016			2015			2016			2015
Income tax (expense) benefit computed by applying the statutory rate	$	(3,320	)	$	282,284		$	84,811		$	497,782
State income tax and change in valuation allowance	111			(5,677		)	298			190
Non-deductible stock-based compensation	—			(45		)	—			(151		)
Stock-based compensation tax deficiency	(121		)	(330		)	(4,133		)	(3,168		)
Change in deferred tax valuation allowance	3,373			(317,391		)	(80,845		)	(317,407		)
Other items	(43		)	(99		)	(131		)	(301		)
Income tax (expense) benefit	$	—		$	(41,258	)	$	—		$	176,945

For the three and nine months ended September 30, 2016, and 2015, the effective tax rate was not meaningful due to the valuation allowance recorded. The Company's effective tax rate is affected by changes in valuation allowances, recurring permanent differences and by discrete items that may occur in any given year, but are not consistent from year to year.

A valuation allowance is established to reduce deferred tax assets if it is determined that 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. During the year ended December 31, 2015 and the nine months ended September 30, 2016, in evaluating whether it was more likely than not that the Company's net deferred tax assets were realizable through future net income, management considered all available positive and negative evidence, including (i) its earnings history, (ii) its ability to recover net operating

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

loss carry-forwards, (iii) the existence of significant proved oil, NGL and natural gas reserves, (iv) its ability to use tax planning strategies, (v) its current price protection utilizing oil and natural gas hedges, (vi) its future revenue and operating cost projections and (vii) the current market prices for oil, NGL and natural gas. Based on all the evidence available, during the year ended December 31, 2015, management determined it was more likely than not that the net deferred tax assets were not realizable, and therefore recorded a valuation allowance of $676.0 million. During the nine months ended September 30, 2016, an additional valuation allowance of $79.8 million was recorded.

The Company early-adopted a new accounting standard that simplified the accounting for stock-based compensation. As a result, the Company recorded a cumulative-effect adjustment to retained earnings as of January 1, 2016 for all windfall tax benefits that were not previously recognized because the related tax deduction had not reduced current taxes payable. The resulting deferred tax asset was assessed for realizability in accordance with GAAP. Due to the Company's valuation allowance position, a cumulative-effect adjustment was recorded to retained earnings as of January 1, 2016, and therefore, the net effect of the early-adoption of this new accounting standard was zero. See Note 18 for additional discussion of the early-adoption of this new accounting standard.

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



(in thousands)	September 30, 2016			December 31, 2015
Oil and natural gas properties, midstream service assets and other fixed assets	$	234,410		$	306,997
Net operating loss carry-forward	550,894			479,022
Derivatives	(29,212		)	(98,675		)
Stock-based compensation	11,526			11,597
Equity method investee	(21,238		)	(31,711		)
Accrued bonus	5,817			4,763
Capitalized interest	1,981			2,525
Other	3,005			2,820
Net deferred tax asset before valuation allowance	757,183			677,338
Valuation allowance	(757,183		)	(677,338		)
Net deferred tax asset	$	—		$	—

The Company had federal net operating loss carry-forwards totaling $1.6 billion and state of Oklahoma net operating loss carry-forwards totaling $42.2 million as of September 30, 2016. These carry-forwards begin expiring in 2026.

The Company's income tax returns for the years 2013 through 2015 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. Derivatives

The Company engages in derivative transactions such as puts, swaps, collars and, in prior periods, basis swaps to hedge price risks due to unfavorable changes in oil, NGL and natural gas prices related to its production. As of September 30, 2016, the Company had 29 open derivative contracts with financial institutions that extend from October 2016 to December 2018. None of these contracts were designated as hedges for accounting purposes. The contracts are recorded at fair value on the unaudited consolidated balance sheets and gains and losses are recognized in earnings. Gains and losses on derivatives are reported on the unaudited consolidated statements of operations on the "Gain (loss) on derivatives, net" line item.

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.

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.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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.

In the prior year, the oil basis swap transactions had an established fixed basis differential. The Company's oil basis swaps' differential was between the West Texas Intermediate-Argus Americas Crude (Midland) ("WTI Midland") index crude oil price and the West Texas Intermediate NYMEX ("WTI NYMEX") index crude oil price. When the WTI NYMEX price less the fixed basis differential was greater than the actual WTI Midland price, the difference multiplied by the hedged contract volume was paid to the Company by the counterparty. When the WTI NYMEX price less the fixed basis differential was less than the actual WTI Midland price, the difference multiplied by the hedged contract volume was paid by the Company to the counterparty.

The Company's oil derivatives are settled based on the month's average daily NYMEX index price for the First Nearby Month of the West Texas Intermediate Light Sweet Crude Oil Futures Contract. The Company's NGL derivatives are settled based on the month's average daily OPIS index price for Mont Belvieu Purity Ethane and TET Propane. The Company's natural gas derivatives are settled based on the Inside FERC index price for West Texas Waha for the calculation period.

During the nine months ended September 30, 2016, the Company successfully completed a hedge restructuring by early terminating the floors of certain derivative contract collars that resulted in a termination amount of $80 million, which was settled in full by applying the proceeds to prepay the premiums on two new derivatives entered into during the restructuring.

During the nine months ended September 30, 2016, the following derivatives were terminated:



	Aggregate volumes (Bbl)	Floor price ($/Bbl)		Contract period
Oil:
Put portion of the associated collars	2,263,000	$	80.00	January 2017 - December 2017

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

During the nine months ended September 30, 2016, the following derivatives were entered into:



	Aggregate volumes⁽¹⁾	Floor price⁽²⁾		Ceiling price⁽²⁾		Contract period
Oil:
Put⁽³⁾	2,263,000	$	60.00	$	—	January 2017 - December 2017
Put⁽⁴⁾	2,098,750	$	60.00	$	—	January 2017 - December 2018
Put⁽⁵⁾	600,000	$	40.00	$	—	May 2016 - December 2016
Swap	1,095,000	$	52.12	$	—	January 2018 - December 2018
Swap	1,003,750	$	51.90	$	—	January 2017 - December 2017
Swap	1,003,750	$	51.17	$	—	January 2017 - December 2017
NGL:
Swap - Ethane	444,000	$	11.24	$	—	January 2017 - December 2017
Swap - Propane	375,000	$	22.26	$	—	January 2017 - December 2017
Natural gas:⁽⁶⁾
Put	8,040,000	$	2.50	$	—	January 2017 - December 2017
Put	8,220,000	$	2.50	$	—	January 2018 - December 2018
Collar	5,256,000	$	2.50	$	3.05	January 2017 - December 2017
Collar	4,635,500	$	2.50	$	3.60	January 2018 - December 2018

_____________________________________________________________________________


(1)	Oil and NGL are in Bbl and natural gas is in MMBtu.


(2)	Oil and NGL are in $/Bbl and natural gas is in $/MMBtu.


(3)	As part of the Company's hedge restructuring, this put replaced the early terminated put portion of the restructured derivative contract collars. A premium of $40.0 million was paid at contract inception.


(4)	As part of the Company's hedge restructuring, a premium of $40.0 million was paid at contract inception.


(5)	There are $1.2 million in deferred premiums associated with this contract.


(6)	There are $5.1 million in deferred premiums associated with these contracts.

See Note 19.a for discussion of additional hedges entered into subsequent to September 30, 2016.

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



	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2016		2015		2016		2015
Cash settlements received for matured derivatives, net	$	44,307	$	66,142	$	157,626	$	175,879
Cash settlements received for early terminations of derivatives, net⁽¹⁾	—		—		80,000		—
Cash settlements received for derivatives, net	$	44,307	$	66,142	$	237,626	$	175,879

_____________________________________________________________________________


(1)	The settlement amount for the nine months ended September 30, 2016 includes $4.0 million in deferred premiums which were settled net with the early terminated contracts from which they derive.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table summarizes open positions as of September 30, 2016, and represents, as of such date, derivatives in place through December 2018 on annual production volumes:



	Remaining year 2016		Year 2017		Year 2018
Oil positions:
Puts:
Hedged volume (Bbl)	549,000		1,049,375		1,049,375
Weighted-average price ($/Bbl)	$	42.95	$	60.00	$	60.00
Swaps:
Hedged volume (Bbl)	395,600		2,007,500		1,095,000
Weighted-average price ($/Bbl)	$	84.82	$	51.54	$	52.12
Collars:
Hedged volume (Bbl)	916,750		2,628,000		—
Weighted-average floor price ($/Bbl)	$	73.98	$	60.00	$	—
Weighted-average ceiling price ($/Bbl)	$	89.62	$	97.22	$	—
Totals:
Total volume hedged with floor price (Bbl)	1,861,350		5,684,875		2,144,375
Weighted-average floor price ($/Bbl)	$	67.13	$	57.01	$	55.98
Total volume hedged with ceiling price (Bbl)	1,312,350		4,635,500		1,095,000
Weighted-average ceiling price ($/Bbl)	$	88.18	$	77.44	$	52.12
NGL positions:
Swaps - Ethane:
Hedged volume (Bbl)	—		444,000		—
Weighted-average price ($/Bbl)	$	—	$	11.24	$	—
Swaps - Propane:
Hedged volume (Bbl)	—		375,000		—
Weighted-average price ($/Bbl)	$	—	$	22.26	$	—
Totals:
Total volume hedged with floor price (Bbl)	—		819,000		—
Total volume hedged with ceiling price (Bbl)	—		819,000		—
Natural gas positions:
Puts:
Hedged volume (MMBtu)	—		8,040,000		8,220,000
Weighted-average price ($/MMBtu)	$	—	$	2.50	$	2.50
Collars:
Hedged volume (MMBtu)	4,692,000		10,731,000		4,635,500
Weighted-average floor price ($/MMBtu)	$	3.00	$	2.76	$	2.50
Weighted-average ceiling price ($/MMBtu)	$	5.60	$	3.53	$	3.60
Totals:
Total volume hedged with floor price (MMBtu)	4,692,000		18,771,000		12,855,500
Weighted-average floor price ($/MMBtu)	$	3.00	$	2.65	$	2.50
Total volume hedged with ceiling price (MMBtu)	4,692,000		10,731,000		4,635,500
Weighted-average ceiling price ($/MMBtu)	$	5.60	$	3.53	$	3.60

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

b. Balance sheet presentation

In accordance with the Company's standard practice, its derivatives are subject to counterparty netting under agreements governing such derivatives. The Company's oil, NGL and natural gas 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, NGL 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, NGL 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 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, NGL and natural gas 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 or nine months ended September 30, 2016 or 2015.

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 as of the periods presented:



(in thousands)	Level 1		Level 2			Level 3			Total gross fair value			Amounts offset			Net fair value presented on the unaudited consolidated balance sheets
As of September 30, 2016:
Assets
Current:
Oil derivatives	$	—	$	67,377		$	—		$	67,377		$	(281	)	$	67,096
NGL derivative⁽¹⁾	—		362			—			362			(181		)	181
Natural gas derivatives	—		2,691			—			2,691			(1,282		)	1,409
Oil deferred premiums	—		—			—			—			(3,595		)	(3,595		)
Natural gas deferred premiums	—		—			—			—			(607		)	(607		)
Noncurrent:
Oil derivatives	$	—	$	21,954		$	—		$	21,954		$	170		$	22,124
NGL derivative⁽¹⁾	—		(72		)	—			(72		)	72			—
Natural gas derivatives	—		2,602			—			2,602			(2,602		)	—
Oil deferred premiums	—		—			—			—			(252		)	(252		)
Natural gas deferred premiums	—		—			—			—			—			—
Liabilities
Current:
Oil derivatives	$	—	$	(134	)	$	—		$	(134	)	$	281		$	147
NGL derivative	—		(181		)	—			(181		)	181			—
Natural gas derivatives	—		(638		)	—			(638		)	1,282			644
Oil deferred premiums	—		—			(4,349		)	(4,349		)	3,595			(754		)
Natural gas deferred premiums	—		—			(2,272		)	(2,272		)	607			(1,665		)
Noncurrent:
Oil derivatives	$	—	$	(1,920	)	$	—		$	(1,920	)	$	(170	)	$	(2,090	)
NGL derivative	—		(132		)	—			(132		)	(72		)	(204		)
Natural gas derivatives	—		(278		)	—			(278		)	2,602			2,324
Oil deferred premiums	—		—			(252		)	(252		)	252			—
Natural gas deferred premiums	—		—			(3,131		)	(3,131		)	—			(3,131		)
Net derivative position	$	—	$	91,631		$	(10,004	)	$	81,627		$	—		$	81,627

_____________________________________________________________________________


(1)	The associated contract is in an overall asset position.

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 unaudited consolidated balance sheets
As of December 31, 2015:
Assets
Current:
Oil derivatives	$	—	$	194,940	$	—		$	194,940		$	—		$	194,940
Natural gas derivatives	—		13,166		—			13,166			—			13,166
Oil deferred premiums	—		—		—			—			(9,301		)	(9,301		)
Natural gas deferred premiums	—		—		—			—			—			—
Noncurrent:
Oil derivatives	$	—	$	80,302	$	—		$	80,302		$	—		$	80,302
Natural gas derivatives	—		2,459		—			2,459			—			2,459
Oil deferred premiums	—		—		—			—			(4,877		)	(4,877		)
Natural gas deferred premiums	—		—		—			—			(441		)	(441		)
Liabilities
Current:
Oil derivatives	$	—	$	—	$	—		$	—		$	—		$	—
Natural gas derivatives	—		—		—			—			—			—
Oil deferred premiums	—		—		(9,301		)	(9,301		)	9,301			—
Natural gas deferred premiums	—		—		—			—			—			—
Noncurrent:
Oil derivatives	$	—	$	—	$	—		$	—		$	—		$	—
Natural gas derivatives	—		—		—			—			—			—
Oil deferred premiums	—		—		(4,877		)	(4,877		)	4,877			—
Natural gas deferred premiums	—		—		(441		)	(441		)	441			—
Net derivative position	$	—	$	290,867	$	(14,619	)	$	276,248		$	—		$	276,248

These items are included as "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 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 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 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 for the calendar years presented:



(in thousands)	September 30, 2016
Remaining 2016	$	2,697
2017	5,354
2018	2,100
Total	$	10,151

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



	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2016			2015			2016			2015
Balance of Level 3 at beginning of period	$	(12,662	)	$	(12,087	)	$	(14,619	)	$	(9,285	)
Change in net present value of deferred premiums for derivatives	(51		)	(53		)	(184		)	(141		)
Total purchases and settlements:
Purchases	—			(437		)	(6,072		)	(5,821		)
Settlements⁽¹⁾	2,709			1,248			10,871			3,918
Balance of Level 3 at end of period	$	(10,004	)	$	(11,329	)	$	(10,004	)	$	(11,329	)

_____________________________________________________________________________


(1)	The amount for the nine months ended September 30, 2016 includes $3.9 million which represents the present value of deferred premiums settled in the Company's restructuring upon their early termination.

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. The Company accounts for the impairment of inventory, if any, at LCM on a nonrecurring basis. For purposes of market measurement, it was determined that the impairment of inventory is classified as Level 2, based on the use of a replacement cost approach. See Note 2.g for discussion regarding the Company's impairment of (i) materials and supplies for the nine months ended September 30, 2016 and 2015 and (ii) line-fill for the three and nine months ended September 30, 2015.

The accounting policies for impairment of oil and natural gas properties are discussed in Note 2.f. 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. See Note 2.f for discussion regarding the prices used in the calculation of discounted cash flows for the quarters ended September 30, 2016, June 30, 2016, March 31, 2016, December 31, 2015, September 30, 2015, June 30, 2015 and March 31, 2015.

Note 10—Net income (loss) per common share

Basic net income (loss) per common share is computed by dividing net income (loss) by the weighted-average number of common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution of non-vested restricted stock awards, performance share awards and outstanding stock options. For the nine months ended September 30, 2016 and for the three and nine months ended September 30, 2015, 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.

The effect of the Company's outstanding stock options was excluded from the calculation of diluted net income per common share for the three months ended September 30, 2016. The inclusion of these options would be anti-dilutive due to the following: (i) utilizing the treasury stock method, the sum of the assumed proceeds exceeded the average stock price during the period for the restricted stock option awards granted in 2016 and (ii) the exercise prices for all other outstanding stock options

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

were greater than the average market price during the period. See Note 6.b for additional discussion of stock option award activity.

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



	Three months ended September 30,					Nine months ended September 30,
(in thousands, except for per share data)	2016		2015			2016			2015
Net income (loss) (numerator):
Net income (loss)—basic and diluted	$	9,485	$	(847,783	)	$	(242,318	)	$	(1,245,289	)
Weighted-average common shares outstanding (denominator):
Basic⁽¹⁾	234,639		211,204			221,303			195,081
Non-vested restricted stock awards⁽²⁾	253		—			—			—
Performance share awards⁽³⁾	3,216		—			—			—
Diluted	238,108		211,204			221,303			195,081
Net income (loss) per common share:
Basic	$	0.04	$	(4.01	)	$	(1.09	)	$	(6.38	)
Diluted	$	0.04	$	(4.01	)	$	(1.09	)	$	(6.38	)

_____________________________________________________________________________


(1)	Weighted-average common shares outstanding used in the computation of basic and diluted net income (loss) per common share attributable to stockholders was computed taking into account equity offerings that occurred during the respective periods. See Note 3 for additional discussion of the Company's equity offerings.


(2)	For the three months ended September 30, 2016, the dilutive effect of the non-vested restricted stock awards was calculated utilizing the treasury stock method.

(3)

For the three months ended September 30, 2016, the dilutive effect of the performance share awards was calculated utilizing the Company's total shareholder return from the beginning of each performance share awards' respective performance period to September 30, 2016 in comparison to the peers specified in each performance share awards' respective agreement. See Note 6.c for additional discussion of the Company's performance share awards.

Note 11—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. The Company's sales of purchased oil are made to one customer. 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, NGL 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 2.e, 8 and 9 for additional information regarding the Company's derivatives.

Note 12—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 contract

The Company has committed to several drilling contracts with a third party to facilitate the Company's drilling plans. One of these contracts contains an early termination clause that requires the Company to potentially pay penalties to the third party should the Company cease drilling efforts. This penalty would negatively impact the Company's financial statements upon early contract termination. The future commitment of $1.5 million as of September 30, 2016 is not recorded in the accompanying unaudited consolidated balance sheets. Management does not currently anticipate the early termination of this contract in 2016.

c. Firm sale and transportation commitments

The Company has committed to deliver for sale or transportation fixed volumes of product under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. If not fulfilled, the Company is subject to deficiency payments. These commitments are normal and customary for the Company's business. In certain instances, the Company has used spot market purchases to meet its commitments in certain locations or due to favorable pricing. Management anticipates continuing this practice in the future. Also, if production is not sufficient to satisfy the Company's delivery commitments, the Company can and may use spot market purchases to fulfill the commitments. During the three months ended September 30, 2016, the Company incurred $1.6 million in deficiency payments which are reported on the unaudited consolidated statements of operations on the "Minimum volume commitments" line item. During the nine months ended September 30, 2015, the Company incurred $5.2 million in deficiency payments, of which $3.0 million was a result of a negotiated buyout of a minimum volume commitment for future periods to Medallion (as defined below). See Note 14 for additional discussion regarding Medallion, the Company's variable interest entity ("VIE"). Future commitments of $386.8 million as of September 30, 2016 are not recorded in the accompanying unaudited consolidated balance sheets.

d. 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.

e. Other commitments

See Notes 2.i, 14 and 15.a for the amount of and discussion regarding the commitments to the Company's non-consolidated VIE.

Note 13—2015 Restructuring

Following the fourth-quarter 2014 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 from 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 RIF was communicated to employees on January 20, 2015 and was generally effective immediately. The Company's compensation committee approved the RIF and the related severance package. The Company incurred $6.0 million in expenses during the nine months ended September 30, 2015 related to the RIF. There were no comparative amounts recorded in the nine months ended September 30, 2016.

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

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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.

LMS contributed $16.0 million and $58.7 million during the three and nine months ended September 30, 2016, respectively, and $48.5 million and $63.0 million during the three and nine months ended September 30, 2015, 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's ownership units. Medallion was established for the purpose of developing midstream solutions and providing midstream infrastructure to bring 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 reflected in the unaudited consolidated statements of operations as "Income from equity method investee" and the carrying amount reflected in the unaudited consolidated balance sheets as "Investment in equity method investee." The Company has elected to classify distributions received from Medallion using the cumulative earnings approach. No such distributions have been received to date.

During the nine months ended September 30, 2016 and 2015, Medallion continued expansion activities on existing portions of its pipeline infrastructure in order to gather and transport additional third-party oil production. During the nine months ended September 30, 2015, Medallion began recognizing revenue due to its main pipeline becoming fully operational. See Note 15.a for discussion of items included in the Company's unaudited consolidated financial statements related to Medallion.

During the nine months ended September 30, 2015, the Company negotiated a buyout of a minimum volume commitment to Medallion, which was related to natural gas gathering infrastructure Medallion constructed on acreage that the Company does not plan to develop. The portion of the buyout that was related to the Company's minimum volume commitment for future periods was $3.0 million and is included in the unaudited consolidated statements of operations in the line item "Minimum volume commitments" for the period in which the buyout was settled.

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 September 30,				Nine months ended September 30,
(in thousands)	2016		2015		2016		2015
Midstream service revenues	$	—	$	—	$	—	$	487
Minimum volume commitments	$	—	$	—	$	—	$	5,235
Interest and other income	$	—	$	50	$	—	$	158

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table summarizes items included in the unaudited consolidated balance sheets related to Medallion as of the dates presented:



(in thousands)	September 30, 2016		December 31, 2015
Accounts receivable, net	$	—	$	1,163
Other assets, net⁽¹⁾	$	1,025	$	1,025
Other current liabilities⁽²⁾	$	102	$	27,583

______________________________________________________________________________


(1)	Amounts included in "Other assets, net" above represent LMS owned line-fill in Medallion's pipeline.


(2)	Amounts included in "Other current liabilities" above represent LMS' accrued line-fill purchase in Medallion's pipeline as of September 30, 2016 and capital contribution payable to Medallion as of December 31, 2015.

b. Targa Resources Corp.

The Company has a gathering and processing arrangement with affiliates of Targa Resources Corp. ("Targa"). One of Laredo's directors was on the board of directors of Targa until May 18, 2015.

The following table summarizes the oil, NGL and natural gas sales and midstream service revenues received from Targa included in the unaudited consolidated statements of operations for the periods presented:



	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2016		2015		2016		2015
Oil, NGL and natural gas sales	$	24,169	$	23,540	$	60,086	$	77,183
Midstream service revenues	$	101	$	—	$	338	$	—

The following table summarizes the amounts included in accounts receivable, net from Targa in the unaudited consolidated balance sheets as of the dates presented:



(in thousands)	September 30, 2016		December 31, 2015
Accounts receivable, net	$	9,447	$	6,097

c. Archrock Partners, L.P.

The Company has a compression arrangement with affiliates of Archrock Partners, L.P., formerly Exterran Partners L.P. ("Archrock"). One of Laredo's directors is on the board of directors of Archrock GP LLC, an affiliate of Archrock.

The following table summarizes the lease operating expenses related to Archrock included in the unaudited consolidated statements of operations for the periods presented:



	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2016		2015		2016		2015
Lease operating expenses	$	498	$	391	$	1,499	$	1,167

The following table summarizes the capital expenditures related to Archrock included in the unaudited consolidated statements of cash flows for the periods presented:



	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2016		2015		2016		2015
Capital expenditures:
Midstream service assets	$	—	$	—	$	20	$	64

The following table summarizes the amounts included in accounts payable from Archrock in the unaudited consolidated balance sheets as of the dates presented:



(in thousands)	September 30, 2016		December 31, 2015
Accounts payable	$	—	$	13

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

d. Helmerich & Payne, Inc.

The Company has had drilling contracts with Helmerich & Payne, Inc. ("H&P"). Laredo's Chairman and Chief Executive Officer is on the board of directors of H&P.

The following table summarizes the capitalized oil and natural gas properties related to H&P included in the unaudited consolidated statements of cash flows for the periods presented:



	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2016		2015		2016		2015
Capital expenditures:
Oil and natural gas properties	$	—	$	—	$	—	$	2,434

Note 16—Segments

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table presents selected financial information, for the periods presented, regarding the Company's operating segments on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis:



(in thousands)	Exploration and production			Midstream and marketing			Eliminations			Consolidated company
Three months ended September 30, 2016:
Oil, NGL and natural gas sales	$	115,188		$	488		$	(871	)	$	114,805
Midstream service revenues	—			15,357			(12,869		)	2,488
Sales of purchased oil	—			42,441			—			42,441
Total revenues	115,188			58,286			(13,740		)	159,734
Lease operating expenses, including production and ad valorem tax	28,624			—			(3,381		)	25,243
Midstream service expenses, including minimum volume commitments	1,582			9,079			(8,040		)	2,621
Costs of purchased oil	—			44,232			—			44,232
General and administrative⁽¹⁾	23,883			2,222			—			26,105
Depletion, depreciation and amortization⁽²⁾	32,883			2,275			—			35,158
Impairment expense	—			—			—			—
Other operating costs and expenses⁽³⁾	832			51			—			883
Operating income	$	27,384		$	427		$	(2,319	)	$	25,492
Other financial information:
Income from equity method investee	$	—		$	265		$	—		$	265
Interest expense⁽⁴⁾	$	(21,631	)	$	(1,446	)	$	—		$	(23,077	)
Capital expenditures⁽⁵⁾	$	(79,843	)	$	(806	)	$	—		$	(80,649	)
Gross property and equipment⁽⁶⁾	$	5,682,251		$	384,091		$	(6,923	)	$	6,059,419
Three months ended September 30, 2015:
Oil, NGL and natural gas sales	$	105,025		$	753		$	(1,171	)	$	104,607
Midstream service revenues	—			7,917			(6,044		)	1,873
Sales of purchased oil	—			43,860			—			43,860
Total revenues	105,025			52,530			(7,215		)	150,340
Lease operating expenses, including production and ad valorem tax	35,531			—			(2,524		)	33,007
Midstream service expenses	—			5,240			(4,148		)	1,092
Costs of purchased oil	—			46,961			—			46,961
General and administrative⁽¹⁾	20,713			2,200			—			22,913
Depletion, depreciation and amortization⁽²⁾	64,664			2,113			—			66,777
Impairment expense	906,420			430			—			906,850
Other operating costs and expenses⁽³⁾	548			51			—			599
Operating loss	$	(922,851	)	$	(4,465	)	$	(543	)	$	(927,859	)
Other financial information:
Income from equity method investee	$	—		$	2,104		$	—		$	2,104
Interest expense⁽⁴⁾	$	(22,030	)	$	(1,318	)	$	—		$	(23,348	)
Capital expenditures	$	(117,962	)	$	(979	)	$	—		$	(118,941	)
Gross property and equipment⁽⁶⁾	$	5,178,245		$	314,138		$	(908	)	$	5,491,475

_______________________________________________________________________________

(1)

General and administrative expense was allocated based on the number of employees in the respective segment as of September 30, 2016 and 2015. Certain components of general and administrative expense, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment.


(2)	Depletion, depreciation and amortization were actual expenses for each segment with the exception of the allocation of depreciation of other fixed assets, which is based on the number of employees in the respective segment as of September 30, 2016 and 2015.


(3)	Other operating costs and expenses primarily consist of accretion of asset retirement obligations. These are actual costs and expenses and were not allocated.


(4)	Interest expense was allocated to the exploration and production segment based on gross property and equipment as of September 30, 2016 and 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of September 30, 2016 and 2015.


(5)	Capital expenditures excludes acquisition of oil and natural gas properties for the three months ended September 30, 2016.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)


(6)	Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $229.9 million and $160.2 million as of September 30, 2016 and 2015, respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of September 30, 2016 and 2015.



(in thousands)	Exploration and production			Midstream and marketing			Eliminations			Consolidated company
Nine months ended September 30, 2016:
Oil, NGL and natural gas sales	$	290,856		$	488		$	(871	)	$	290,473
Midstream service revenues	—			37,762			(31,841		)	5,921
Sales of purchased oil	—			116,670			—			116,670
Total revenues	290,856			154,920			(32,712		)	413,064
Lease operating expenses, including production and ad valorem tax	87,781			—			(8,378		)	79,403
Midstream service expenses, including minimum volume commitments	1,582			22,160			(19,334		)	4,408
Costs of purchased oil	—			121,190			—			121,190
General and administrative⁽¹⁾	60,380			5,678			—			66,058
Depletion, depreciation and amortization⁽²⁾	104,144			6,669			—			110,813
Impairment expense	162,027			—			—			162,027
Other operating costs and expenses⁽³⁾	2,430			157			—			2,587
Operating loss	$	(127,488	)	$	(934	)	$	(5,000	)	$	(133,422	)
Other financial information:
Income from equity method investee	$	—		$	6,259		$	—		$	6,259
Interest expense⁽⁴⁾	$	(65,984	)	$	(4,310	)	$	—		$	(70,294	)
Capital expenditures⁽⁵⁾	$	(277,717	)	$	(4,231	)	$	—		$	(281,948	)
Gross property and equipment⁽⁶⁾	$	5,682,251		$	384,091		$	(6,923	)	$	6,059,419
Nine months ended September 30, 2015:
Oil, NGL and natural gas sales	$	348,915		$	1,086		$	(1,722	)	$	348,279
Midstream service revenues	—			15,962			(11,054		)	4,908
Sales of purchased oil	—			130,178			—			130,178
Total revenues	348,915			147,226			(12,776		)	483,365
Lease operating expenses, including production and ad valorem tax	120,799			—			(7,620		)	113,179
Midstream service expenses, including minimum volume commitments	4,399			9,580			(4,481		)	9,498
Costs of purchased oil	—			132,578			—			132,578
General and administrative⁽¹⁾	61,838			6,138			—			67,976
Depletion, depreciation and amortization⁽²⁾	204,908			5,923			—			210,831
Impairment expense	1,396,786			541			—			1,397,327
Other operating costs and expenses⁽³⁾	7,520			293			—			7,813
Operating loss	$	(1,447,335	)	$	(7,827	)	$	(675	)	$	(1,455,837	)
Other financial information:
Income from equity method investee	$	—		$	4,585		$	—		$	4,585
Interest expense⁽⁴⁾	$	(75,962	)	$	(3,770	)	$	—		$	(79,732	)
Loss on early redemption of debt⁽⁷⁾	$	(30,056	)	$	(1,481	)	$	—		$	(31,537	)
Capital expenditures	$	(498,834	)	$	(35,293	)	$	—		$	(534,127	)
Gross property and equipment⁽⁶⁾	$	5,178,245		$	314,138		$	(908	)	$	5,491,475

_______________________________________________________________________________

(1)


(2)	Depletion, depreciation and amortization were actual expenses for each segment with the exception of the allocation of depreciation of other fixed assets, which is based on the number of employees in the respective segment as of September 30, 2016 and 2015.


(3)	Other operating costs and expenses consist of accretion of asset retirement obligations for the nine months ended September 30, 2016 and 2015 and restructuring expense for the nine months ended September 30, 2015. These are actual costs and expenses and were not allocated.


(4)	Interest expense was allocated to the exploration and production segment based on gross property and equipment as of September 30, 2016 and 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of September 30, 2016 and 2015.


(5)	Capital expenditures excludes acquisition of oil and natural gas properties for the nine months ended September 30, 2016.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)


(6)	Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $229.9 million and $160.2 million as of September 30, 2016 and 2015, respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of September 30, 2016 and 2015.


(7)	Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment as of September 30, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of September 30, 2015.

Note 17—Subsidiary guarantors

The Guarantors have fully and unconditionally guaranteed the January 2022 Notes, the May 2022 Notes, the March 2023 Notes and the Senior Secured Credit Facility (and had guaranteed the January 2019 Notes until the Redemption Date), 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 September 30, 2016 and December 31, 2015, unaudited condensed consolidating statements of operations for the three and nine months ended September 30, 2016 and 2015 and unaudited condensed consolidating statements of cash flows for the nine months ended September 30, 2016 and 2015 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. During the three and nine months ended September 30, 2016, certain assets were transferred from Laredo to LMS and from LMS to Laredo at historical cost.

Condensed consolidating balance sheet

September 30, 2016

(Unaudited)



(in thousands)	Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable, net	$	67,102	$	14,121	$	—		$	81,223
Other current assets	107,713		1,460		—			109,173
Oil and natural gas properties, net	1,136,943		9,311		(6,923		)	1,139,331
Midstream service assets, net	—		126,672		—			126,672
Other fixed assets, net	39,035		604		—			39,639
Investment in subsidiaries and equity method investee	363,717		229,912		(363,717		)	229,912
Other long-term assets	26,629		3,869		—			30,498
Total assets	$	1,741,139	$	385,949	$	(370,640	)	$	1,756,448

Accounts payable	$	19,113	$	920	$	—		$	20,033
Other current liabilities	121,888		18,334		—			140,222
Long-term debt, net	1,353,232		—		—			1,353,232
Other long-term liabilities	52,882		2,978		—			55,860
Stockholders' equity	194,024		363,717		(370,640		)	187,101
Total liabilities and stockholders' equity	$	1,741,139	$	385,949	$	(370,640	)	$	1,756,448

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating balance sheet

December 31, 2015

(Unaudited)



(in thousands)	Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable, net	$	74,613	$	13,086	$	—		$	87,699
Other current assets	244,477		56		—			244,533
Oil and natural gas properties, net	1,017,565		9,350		(1,923		)	1,024,992
Midstream service assets, net	—		131,725		—			131,725
Other fixed assets, net	43,210		328		—			43,538
Investment in subsidiaries and equity method investee	301,891		192,524		(301,891		)	192,524
Other long-term assets	84,360		3,916		—			88,276
Total assets	$	1,766,116	$	350,985	$	(303,814	)	$	1,813,287

Accounts payable	$	12,203	$	1,978	$	—		$	14,181
Other current liabilities	158,283		44,351		—			202,634
Long-term debt, net	1,416,226		—		—			1,416,226
Other long-term liabilities	46,034		2,765		—			48,799
Stockholders' equity	133,370		301,891		(303,814		)	131,447
Total liabilities and stockholders' equity	$	1,766,116	$	350,985	$	(303,814	)	$	1,813,287

Condensed consolidating statement of operations

For the three months ended September 30, 2016

(Unaudited)



(in thousands)	Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Total revenues	$	115,091		$	58,383	$	(13,740	)	$	159,734
Total costs and expenses	90,073			55,590		(11,421		)	134,242
Operating income	25,018			2,793		(2,319		)	25,492
Interest expense and other, net	(23,044		)	—		—			(23,044		)
Other non-operating income	9,830			254		(3,047		)	7,037
Income before income tax	11,804			3,047		(5,366		)	9,485
Income tax	—			—		—			—
Net income	$	11,804		$	3,047	$	(5,366	)	$	9,485

Condensed consolidating statement of operations

For the nine months ended September 30, 2016

(Unaudited)



(in thousands)	Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Total revenues	$	290,724		$	155,052	$	(32,712	)	$	413,064
Total costs and expenses	424,274			149,924		(27,712		)	546,486
Operating income (loss)	(133,550		)	5,128		(5,000		)	(133,422		)
Interest expense and other, net	(70,151		)	—		—			(70,151		)
Other non-operating income (expense)	(33,617		)	6,237		(11,365		)	(38,745		)
Income (loss) before income tax	(237,318		)	11,365		(16,365		)	(242,318		)
Income tax	—			—		—			—
Net income (loss)	$	(237,318	)	$	11,365	$	(16,365	)	$	(242,318	)

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating statement of operations

For the three months ended September 30, 2015

(Unaudited)



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Total revenues	$	104,920		$	52,635		$	(7,215	)	$	150,340
Total costs and expenses	1,030,143			54,728			(6,672		)	1,078,199
Operating loss	(925,223		)	(2,093		)	(543		)	(927,859		)
Interest expense and other, net	(23,256		)	—			—			(23,256		)
Other non-operating income	142,497			2,013			80			144,590
Loss before income tax	(805,982		)	(80		)	(463		)	(806,525		)
Deferred income tax expense	(41,258		)	—			—			(41,258		)
Net loss	$	(847,240	)	$	(80	)	$	(463	)	$	(847,783	)

Condensed consolidating statement of operations

For the nine months ended September 30, 2015

(Unaudited)



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Total revenues	$	348,753		$	147,388		$	(12,776	)	$	483,365
Total costs and expenses	1,802,810			148,493			(12,101		)	1,939,202
Operating loss	(1,454,057		)	(1,105		)	(675		)	(1,455,837		)
Interest expense and other, net	(79,344		)	—			—			(79,344		)
Other non-operating income	111,842			4,494			(3,389		)	112,947
Income (loss) before income tax	(1,421,559		)	3,389			(4,064		)	(1,422,234		)
Deferred income tax benefit	176,945			—			—			176,945
Net income (loss)	$	(1,244,614	)	$	3,389		$	(4,064	)	$	(1,245,289	)

Condensed consolidating statement of cash flows

For the nine months ended September 30, 2016

(Unaudited)



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash flows provided by operating activities	$	244,213		$	12,606		$	(11,365	)	$	245,454
Change in investment between affiliates	(61,677		)	50,312			11,365			—
Capital expenditures and other	(392,977		)	(62,918		)	—			(455,895		)
Net cash flows provided by financing activities	209,647			—			—			209,647
Net decrease in cash and cash equivalents	(794		)	—			—			(794		)
Cash and cash equivalents at beginning of period	31,153			1			—			31,154
Cash and cash equivalents at end of period	$	30,359		$	1		$	—		$	30,360

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating statement of cash flows

For the nine months ended September 30, 2015

(Unaudited)



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash flows provided by (used in) operating activities	$	229,065		$	(172	)	$	(3,389	)	$	225,504
Change in investment between affiliates	(101,858		)	98,469			3,389			—
Capital expenditures and other	(433,580		)	(98,297		)	—			(531,877		)
Net cash flows provided by financing activities	353,455			—			—			353,455
Net increase in cash and cash equivalents	47,082			—			—			47,082
Cash and cash equivalents at beginning of period	29,320			1			—			29,321
Cash and cash equivalents at end of period	$	76,402		$	1		$	—		$	76,403

Note 18—Recently issued or adopted accounting pronouncements

The Company considers the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB"). The ASUs listed below were either adopted during the nine months ended September 30, 2016 or the discussion of the ASU was determined to be meaningful to the Company's consolidated financial statements.

In August 2016, the FASB issued new guidance in Topic 230, Classification of Certain Cash Receipts and Cash Payments, to address the following cash flow issues: (i) debt prepayment or debt extinguishment costs; (ii) settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; (iii) contingent consideration payments made after a business combination; (iv) proceeds from the settlement of insurance claims; (v) proceeds from the settlement of corporate-owned life insurance policies; (vi) distributions received from equity method investees; (vii) beneficial interests in securitization transactions and (viii) separately identifiable cash flows and application of the predominance principle. The amendments in this update are effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. If practical, the amendments in this ASU should be applied using a retrospective transition method to each period presented. The Company elected to early-adopt this guidance in the third quarter of 2016 on a retrospective basis, and the adoption did not have an effect on its unaudited consolidated financial statements.

In March, April and May 2016, the FASB, issued new guidance in Topic 606, Revenue from Contracts with Customers, to address the following potential implementation issues of the new revenue standard: (a) to clarify the implementation guidance on principal versus agent considerations, (b) to clarify the identification of performance obligations and the licensing implementation guidance and (c) to address certain issues in the guidance on assessing collectibility, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition. The effective date and transition requirements for the amendments in these updates are the same as the effective date and transition requirements for the guidance issued in May 2014 and August 2015 to Topic 606. These updates are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the impact this ASU will have on its consolidated financial statements upon adoption.

In March 2016, the FASB issued new guidance in Topic 718, Compensation—Stock Compensation, which seeks to simplify the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The amendments in this update are effective for annual periods beginning after December 15, 2016 and interim periods within those annual periods. Early adoption is permitted for any entity in any interim or annual period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the applicable amendments in the same period. The Company elected to early-adopt this guidance in the third quarter of 2016 utilizing the adoption methods required by the ASU. The Company will continue its current accounting policy of estimating forfeitures. See Note 7 for discussion of additional accounting consequences related to the adoption of this ASU.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

In February 2016, the FASB issued new guidance in Topic 842, Leases. The core principle of the new guidance is that a lessee should recognize the assets and liabilities that arise from leases in the statement of financial position. A lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. When measuring assets and liabilities arising from a lease, a lessee (and a lessor) should include payments to be made in optional periods only if the lessee is reasonably certain to exercise an option to extend the lease or not to exercise an option to terminate the lease. Similarly, optional payments to purchase the underlying asset should be included in the measurement of lease assets and lease liabilities only if the lessee is reasonably certain to exercise that purchase option. Reasonably certain is a high threshold that is consistent with and intended to be applied in the same way as the reasonably assured threshold in the previous leases guidance. In addition, also consistent with the previous leases guidance, a lessee (and a lessor) should exclude most variable lease payments in measuring lease assets and lease liabilities, other than those that depend on an index or a rate or are in substance fixed payments. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous GAAP. There continues to be a differentiation between finance leases and operating leases. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous GAAP unless the lease is modified, except that lessees are required to recognize a right-of-use asset and a lease liability for all operating leases at each reporting date based on the present value of the remaining minimum rental payments that were tracked and disclosed under previous GAAP. The amendments in this update are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application of the amendments in this update is permitted. The Company is currently evaluating the impact this ASU will have on its consolidated financial statements upon adoption.

In July 2015, the FASB issued new guidance in Topic 330, Inventory, which seeks to simplify the measurement of inventory. The amendments in this update apply to inventory that is measured using all methods excluding last-in, first-out and the retail inventory method. The main substantive provision of this guidance is for an entity to change the subsequent measurement of inventory, within the scope of this guidance, from LCM to the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2016, including interim periods within those fiscal years and should be applied prospectively with earlier application permitted as of the beginning of an interim or annual reporting period. The Company does not expect the adoption of this ASU to have a material impact on its consolidated financial statements.

In April 2015, the FASB issued new guidance in Subtopic 350-40, Intangibles—Goodwill and Other—Internal-Use Software. The amendments in this update provide guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, then the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. The guidance will not change GAAP for a customer's accounting for service contracts. In addition, the guidance in this update supersedes paragraph 350-40-25-16. The amendments in this update are effective for annual periods beginning after December 15, 2015, including interim periods within those annual periods and should be applied prospectively to all arrangements entered into or materially modified after the effective date or retrospectively. The Company adopted this ASU in the first quarter of 2016 on a prospective basis, and the adoption did not have an effect on its 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

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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 ASU is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the impact this ASU will have on its consolidated financial statements upon adoption.

Note 19—Subsequent events

a. New derivative contracts

Subsequent to September 30, 2016, the following new derivatives were entered into:



	Aggregate volumes⁽¹⁾	Floor price⁽²⁾		Ceiling price⁽²⁾		Contract period
Oil:
Collar⁽³⁾⁽⁴⁾	1,168,000	$	50.00	$	60.75	January 2017 - December 2017
Natural gas:
Collar⁽³⁾	3,723,000	$	3.00	$	3.54	January 2017 - December 2017

_____________________________________________________________


(1)	Oil is in Bbl and natural gas is in MMBtu.


(2)	Oil is in $/Bbl and natural gas is in $/MMBtu.


(3)	See Note 8.a for information regarding the Company's derivative settlement indices.


(4)	There are $1.7 million in deferred premiums associated with this contract.

b. Acquisition of evaluated and unevaluated oil and natural gas properties

On October 11, 2016, the Company conducted the third and final closing under the acquisition agreement described in Note 4.a. This closing covered certain remaining interests that were subject to preferential purchase rights and consents, and the value of the interests acquired in this closing was $9.1 million before customary closing adjustments, bringing the total purchase price paid under this agreement to $124.7 million.

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, NGL and natural gas assets are presented below:



	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2016		2015		2016		2015
Property acquisition costs:							—
Evaluated⁽¹⁾	$	5,905	$	—	$	5,905	$	—
Unevaluated	110,800		—		110,800		—
Exploration	6,718		7,803		33,750		16,157
Development costs⁽²⁾	72,411		64,451		225,103		381,641
Total costs incurred	$	195,834	$	72,254	$	375,558	$	397,798

____________________________________________________________________________


(1)	Evaluated property acquisition costs include $1.1 million in asset retirement obligations for the three and nine months ended September 30, 2016.


(2)	Development costs include $0.3 million in asset retirement obligations for the three months ended September 30, 2016 and 2015 and $0.5 million and $1.3 million for the nine months ended September 30, 2016 and 2015, 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 2015 Annual Report. The following discussion contains "forward-looking statements" that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. Please see "Cautionary Statement Regarding Forward-Looking Statements." Except for purposes of the unaudited consolidated financial statements and condensed notes thereto included elsewhere in this Quarterly Report, references in this Quarterly Report to "Laredo," "we," "us," "our" or similar terms refer to Laredo, LMS and GCM 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, and the transportation of oil, NGL and natural gas from such 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 September 30, 2016 included the following:


•	Oil, NGL and natural gas sales of $114.8 million, compared to $104.6 million for the three months ended September 30, 2015;


•	Average daily sales volumes of 51,276 BOE/D, compared to 44,820 BOE/D for the three months ended September 30, 2015;


•	Net income of $9.5 million, compared to net loss of $847.8 million, which included a non-cash full cost ceiling impairment of $906.4 million, for the three months ended September 30, 2015; and


•	Adjusted EBITDA (a non-GAAP financial measure) of $118.0 million, compared to $121.6 million for the three months ended September 30, 2015. See page 58 for a reconciliation of adjusted EBITDA.

Our financial and operating performance for the nine months ended September 30, 2016 included the following:


•	Oil, NGL and natural gas sales of $290.5 million, compared to $348.3 million for the nine months ended September 30, 2015;


•	Average daily sales volumes of 48,392 BOE/D, compared to 46,270 BOE/D for the nine months ended September 30, 2015;


•	Net loss of $242.3 million, including a non-cash full cost ceiling impairment of $161.1 million, compared to net loss of $1.25 billion, including a non-cash full cost ceiling impairment of $1.39 billion, for the nine months ended September 30, 2015; and


•	Adjusted EBITDA (a non-GAAP financial measure) of $326.3 million, compared to $359.3 million for the nine months ended September 30, 2015. See page 58 for a reconciliation of adjusted EBITDA.

Pricing, reserves and non-cash full cost ceiling impairment

Our results of operations are heavily influenced by oil, NGL and natural gas prices, which remain at low levels. Oil, NGL and natural gas price fluctuations are caused by changes in global and regional supply and demand, 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 our ability to fund, our drilling projects, as well as the economic valuation and economic recovery of oil, NGL and natural gas reserves.

Our reserves as of September 30, 2016 and December 31, 2015 are reported in three streams: oil, NGL and natural gas. Our net book value of evaluated oil and natural gas properties did not exceed the full cost ceiling amount as of September 30, 2016. As such, we did not record a third-quarter non-cash full cost ceiling impairment. See Note 2.f to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for prices used to value our reserves and additional discussion of our full cost impairments in prior periods.

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

Recent developments

July 2016 equity offering

On July 19, 2016, we completed the sale of 13,000,000 shares of Laredo's common stock for net proceeds of $136.3 million, after underwriting discounts, commissions and offering expenses, which were used to repay borrowings under our Senior Secured Credit Facility. On August 9, 2016, the underwriters exercised their option to purchase an additional 1,950,000 shares of our common stock which resulted in net proceeds of approximately $20.5 million, after underwriting discounts, commissions and offering expenses.

Acquisition of proved and unproved oil and natural gas properties

During the three months ended September 30, 2016, we entered into an agreement to acquire approximately 9,200 net acres of additional leasehold interests in western Glasscock and Reagan counties within our core development area (which includes production of approximately 300 net BOE/D from existing vertical wells) for an aggregate purchase price of $125.0 million, subject to customary closing adjustments. On July 13 and August 24, 2016, we closed portions of this acquisition for $94.4 million and $21.2 million, respectively. For further discussion of this acquisition, see Note 4.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report. On October 11, 2016, we conducted the third and final closing under this agreement. This closing covered certain remaining interests that were subject to preferential purchase rights and consents, and the value of the interests acquired in this closing was $9.1 million before customary closing adjustments, bringing the total purchase price paid under this agreement to $124.7 million.

Senior Secured Credit Facility reaffirmation

On October 24, 2016, pursuant to a regular semi-annual redetermination, our lenders reaffirmed the borrowing base under our Senior Secured Credit Facility at $815.0 million. Our aggregate elected commitment of $815.0 million remained unchanged.

Potential future commodity price impact on our fourth-quarter full cost ceiling impairment test

Oil, NGL and natural gas prices have somewhat stabilized in comparison to prices during the preceding 11-month period. As set forth below, if prices remain at or above the current levels, subject to numerous factors and inherent limitations, and if all other factors remain constant, we estimate that we will not incur a non-cash full cost ceiling impairment in the fourth quarter of 2016. Our hypothetical fourth-quarter 2016 prices of (a) $37.79 per barrel for oil, (b) $11.78 per barrel for NGL and (c) $1.75 per Mcf for natural gas (the "Pro Forma Prices") are higher than the Realized Prices utilized in our third-quarter full cost ceiling impairment test. The Pro Forma Prices use a slightly modified Realized Price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for oil, NGL and natural gas on the first day of the month for the 11 months ended November 1, 2016, with the price for November 1, 2016 held constant for the remaining twelfth month of the calculation. See Note 2.f to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for the Realized Prices utilized in our quarterly full cost ceiling impairment tests.

There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in future periods. In addition to unknown future commodity prices, other uncertainties include (i) changes in drilling and completion costs, (ii) changes in oilfield service costs, (iii) production results, (iv) our ability, in a low price environment, to strategically drill the most economic locations in our multi-stack horizontal targets, (v) income tax impacts, (vi) potential recognition of additional proved undeveloped reserves, (vii) any potential value added to our proved reserves when testing recoverability from drilling unbooked locations and (viii) the inherent significant volatility in the commodity prices for oil, NGL and natural gas exemplified by the large swings in recent months.

Each of the above factors is evaluated on a quarterly basis and if there is a material change in any factor it is incorporated into our internal reserve estimation utilized in our quarterly accounting estimates. We use our internal reserve estimates to evaluate, also on a quarterly basis, the reasonableness of our reserve development plans for our reported reserves. Changes in circumstance, including commodity pricing, economic factors and the other uncertainties described above may lead to changes in our reserve development plans.

Core areas of operations

The oil and liquids-rich Permian Basin is characterized by multiple target horizons, extensive production histories, long-lived reserves, high drilling success rates and high initial production rates. As of September 30, 2016, we had assembled 130,010 net acres in the Permian Basin.

Sources of our revenue

Our revenues are primarily derived from the sale of produced oil, NGL and natural gas within the continental United States and the sale of purchased oil. Our revenues do not include the effects of derivatives. For the nine months ended September 30, 2016, our revenues were comprised of sales of 53% produced oil, 9% produced NGL, 8% produced natural gas, 28% purchased oil and 2% midstream services. Our oil, NGL and natural gas revenues may vary significantly from period to period as a result of changes in volumes of production and/or changes in commodity prices. Our sales of purchased oil revenue may vary due to changes in oil prices and market differentials. Our midstream service revenues may vary due to oil throughput fees and the level of services provided to third parties for (i) gathered natural gas, (ii) gas lift fees and (iii) water services.

Results of operations consolidated

Three and nine months ended September 30, 2016 as compared to the three and nine months ended September 30, 2015

Oil, NGL and natural gas sales volumes, revenues and pricing

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



	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
Sales volumes:
Oil (MBbl)	2,150			1,844			6,168			5,954
NGL (MBbl)	1,272			1,150			3,491			3,234
Natural gas (MMcf)	7,766			6,778			21,600			20,663
Oil equivalents (MBOE)⁽¹⁾⁽²⁾	4,718			4,124			13,260			12,632
Average daily sales volumes (BOE/D)⁽²⁾	51,276			44,820			48,392			46,270
% Oil	46		%	45		%	47		%	47		%
Oil, NGL and natural gas sales (in thousands):
Oil	$	84,083		$	79,084		$	218,478		$	268,093
NGL	14,678			11,913			37,850			39,181
Natural gas	16,044			13,610			34,145			41,005
Total oil, NGL and natural gas sales	$	114,805		$	104,607		$	290,473		$	348,279
Average sales prices:
Oil, realized ($/Bbl)⁽³⁾	$	39.10		$	42.88		$	35.42		$	45.03
NGL, realized ($/Bbl)⁽³⁾	$	11.54		$	10.36		$	10.84		$	12.12
Natural gas, realized ($/Mcf)⁽³⁾	$	2.07		$	2.01		$	1.58		$	1.98
Average price, realized ($/BOE)⁽³⁾	$	24.34		$	25.37		$	21.91		$	27.57
Oil, hedged ($/Bbl)⁽⁴⁾	$	57.57		$	76.74		$	57.76		$	72.69
NGL, hedged ($/Bbl)⁽⁴⁾	$	11.54		$	10.36		$	10.84		$	12.12
Natural gas, hedged ($/Mcf)⁽⁴⁾	$	2.31		$	2.37		$	2.18		$	2.34
Average price, hedged ($/BOE)⁽⁴⁾	$	33.15		$	41.11		$	33.27		$	41.19

________________________________________________________________________


(1)	BOE is calculated using a conversion rate of six Mcf per one Bbl.


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


(3)	Realized oil, NGL and natural gas prices are the actual prices realized at the wellhead adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. The prices presented are based on actual results and are not calculated using the rounded numbers presented in the table above.

(4)

Hedged prices reflect the after-effect of our hedging transactions on our average sales prices. Our calculation of such after-effects includes current period settlements of matured 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 for matured 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 September 30,						Nine months ended September 30,
(in thousands)	2016			2015			2016			2015
Cash settlements received for matured derivatives:
Oil	$	42,442		$	63,510		$	144,750		$	168,068
Natural gas	1,865			2,632			12,876			7,811
Total	$	44,307		$	66,142		$	157,626		$	175,879
Premiums paid attributable to contracts that matured during the respective period:
Oil	$	(2,709	)	$	(1,073	)	$	(6,972	)	$	(3,391	)
Natural gas	—			(175		)	—			(527		)
Total	$	(2,709	)	$	(1,248	)	$	(6,972	)	$	(3,918	)

Changes in average realized sales prices and sales volumes caused the following changes to our oil, NGL and natural gas revenues between the three months ended September 30, 2016 and 2015:



(in thousands)	Oil			NGL		Natural gas		Total net dollar effect of change
2015 Revenues	$	79,084		$	11,913	$	13,610	$	104,607
Effect of changes in average realized sales prices	(8,140		)	1,492		450		(6,198		)
Effect of changes in sales volumes	13,139			1,273		1,984		16,396
2016 Revenues	$	84,083		$	14,678	$	16,044	$	114,805

Changes in average realized sales prices and sales volumes caused the following changes to our oil, NGL and natural gas revenues between the nine months ended September 30, 2016 and 2015:



(in thousands)	Oil			NGL			Natural gas			Total net dollar effect of change
2015 Revenues	$	268,093		$	39,181		$	41,005		$	348,279
Effect of changes in average realized sales prices	(59,264		)	(4,448		)	(8,720		)	(72,432		)
Effect of changes in sales volumes	9,649			3,117			1,860			14,626
2016 Revenues	$	218,478		$	37,850		$	34,145		$	290,473

Oil revenue. Our oil revenue is a function of oil production volumes sold and average sales prices received for those volumes. The increase in oil revenue of $5.0 million, or 6%, for the three months ended September 30, 2016 as compared to the three months ended September 30, 2015, is mainly due to a 17% increase in oil sales volumes, partially offset by a 9% decrease in average oil prices realized.

The decrease in oil revenue of $49.6 million, or 19%, for the nine months ended September 30, 2016 as compared to the nine months ended September 30, 2015, is mainly due to a 21% decrease in average oil prices realized, partially offset by a 4% increase in oil sales volumes.

NGL and natural gas revenues. 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 increase in NGL revenue of $2.8 million, or 23%, for the three months ended September 30, 2016 as compared to the three months ended September 30, 2015 is mainly due to an 11% increase in both average NGL prices realized and NGL sales volumes. The increase in natural gas revenue of $2.4 million, or 18%, for the three months ended September 30, 2016 as compared to the three months ended September 30, 2015, is mainly due to a 15% increase in natural gas sales volumes and a 3% increase in average natural gas prices realized.

The decrease in NGL revenue of $1.3 million, or 3%, for the nine months ended September 30, 2016 as compared to the nine months ended September 30, 2015, is mainly due to an 11% decrease in average NGL prices realized, partially offset by an 8% increase in NGL sales volumes. The decrease in natural gas revenue of $6.9 million, or 17%, for the nine months ended September 30, 2016 as compared to the nine months ended September 30, 2015, is mainly due to a 20% decrease in average natural gas prices realized, partially offset by a 5% increase in natural gas sales volumes.

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 September 30,				Nine months ended September 30,
(in thousands except for per BOE sold data)	2016		2015		2016		2015
Costs and expenses:
Lease operating expenses	$	18,177	$	25,112	$	57,920	$	86,698
Production and ad valorem taxes	7,066		7,895		21,483		26,481
Midstream service expenses	1,039		1,092		2,826		4,263
Minimum volume commitments	1,582		—		1,582		5,235
Costs of purchased oil	44,232		46,961		121,190		132,578
General and administrative:
Cash	16,454		16,036		46,496		50,043
Non-cash stock-based compensation	9,651		6,877		19,562		17,933
Restructuring expenses	—		—		—		6,042
Accretion of asset retirement obligations	883		599		2,587		1,771
Depletion, depreciation and amortization	35,158		66,777		110,813		210,831
Impairment expense	—		906,850		162,027		1,397,327
Total	$	134,242	$	1,078,199	$	546,486	$	1,939,202
Average costs per BOE sold:
Lease operating expenses	$	3.85	$	6.09	$	4.37	$	6.86
Production and ad valorem taxes	1.50		1.91		1.62		2.10
Midstream service expenses	0.22		0.26		0.21		0.34
General and administrative:
Cash	3.49		3.89		3.51		3.96
Non-cash stock-based compensation	2.05		1.67		1.48		1.42
Depletion, depreciation and amortization	7.45		16.19		8.36		16.69
Total	$	18.56	$	30.01	$	19.55	$	31.37

Lease operating expenses. Lease operating expenses, which include workover expenses, decreased by $6.9 million, or 28%, and $28.8 million, or 33%, for the three and nine months ended September 30, 2016, respectively, compared to the same periods in 2015. Previous investments in field infrastructure, primarily in our four production corridors, including water takeaway and recycling facilities and centralized compression, have lowered expenses and reduced well downtime. We continue to focus on economic efficiencies associated with the usage and procurement of products and services related to lease operating expenses.

Production and ad valorem taxes. Production and ad valorem taxes decreased by $0.8 million, or 11%, and $5.0 million, or 19%, for the three and nine months ended September 30, 2016, respectively, compared to the same periods in 2015. The quarter-over-quarter decrease is the combination of a $2.0 million decrease in ad valorem taxes partially offset by a $1.2 million increase in production taxes. The year-to-date decrease over the comparable period in 2015 is the combination of a $2.2 million decrease in production taxes and a $2.8 million decrease in ad valorem taxes. Ad valorem taxes are based on and fluctuate in proportion to the value of our reserves. Production taxes are based on and fluctuate in proportion to our oil, NGL and natural gas revenue.

Midstream service expenses. See "—Results of operations - midstream and marketing" for a discussion of these expenses.

Minimum volume commitments. Amounts included in minimum volume commitments increased by $1.6 million for the three months ended September 30, 2016 and decreased by $3.7 million for the nine months ended September 30, 2016, respectively, compared to the same periods in 2015. The quarter-over-quarter increase is a result of deficiency payments incurred relating to our under-delivery of the contractual amount pursuant to one of our natural gas contracts. We intend to renegotiate the contract in the fourth quarter of 2016 to minimize further deficiency payments. The year-to-date decrease over the comparable period in 2015 is mainly the result of our buyout of a minimum volume commitment to Medallion that related to natural gas gathering infrastructure constructed by Medallion on acreage that we do not plan to develop. See Notes 12.c and

14 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of minimum volume commitments.

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

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 September 30, 2016 compared to 2015			Nine months ended September 30, 2016 compared to 2015
Changes in G&A:
Performance unit awards	$	(1,060	)	$	(2,734	)
Stock-based compensation, net of amounts capitalized	2,774			1,629
Professional fees	(438		)	(1,542		)
Salaries, benefits and bonuses, net of amounts capitalized	2,851			1,427
Other	(935		)	(698		)
Total changes in G&A	$	3,192		$	(1,918	)

G&A expense, excluding stock-based compensation, increased by $0.4 million, or 3%, and decreased by $3.5 million, or 7%, for the three and nine months ended September 30, 2016, respectively, compared to the same periods in 2015. The quarter-over-quarter increase is mainly due to an increase in salaries, benefits and bonuses, net of amounts capitalized, partially offset by decreased expenses relating to performance unit awards and professional fees. The year-to-date decrease over the comparable period in 2015 is mainly due to decreases in expenses related to performance unit awards and professional fees partially offset by an increase in salaries, benefits and bonuses, net of amounts capitalized. Expense incurred for our 2013 Performance Unit Awards were $1.0 million and $2.7 million during the three and nine months ended September 30, 2015, respectively. There was no comparable expense during the three and nine months ended September 30, 2016. The performance criteria of these awards were satisfied on December 31, 2015. They were paid during the first quarter of 2016 and were accounted for as liability awards.

Stock-based compensation, net of amounts capitalized, increased by $2.8 million, or 40%, and $1.6 million, or 9%, for the three and nine months ended September 30, 2016, respectively, compared to the same periods in 2015. These increases are mainly due to the issuance of restricted stock awards, restricted option awards and performance share awards in connection with amendments to our LTIP approved by stockholders on May 25, 2016. For further discussion of our stock-based compensation, see Note 6 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

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 and are included in stock-based compensation expense. 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.

See Notes 2.m 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. Restructuring expenses relate to the first-quarter 2015 RIF that was undertaken to reduce expenses and better position ourselves for future operations in a low commodity price environment. Restructuring expenses of $6.0 million were incurred during the nine months ended September 30, 2015. No comparable expenses were recorded during the nine months ended September 30, 2016. See Note 13 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 September 30,				Nine months ended September 30,
(in thousands except for per BOE sold data)	2016		2015		2016		2015
Depletion of evaluated oil and natural gas properties	$	31,679	$	63,167	$	100,136	$	200,440
Depreciation of midstream service assets	2,036		2,000		6,204		5,580
Depreciation and amortization of other fixed assets	1,443		1,610		4,473		4,811
Total DD&A	$	35,158	$	66,777	$	110,813	$	210,831

DD&A decreased by $31.6 million, or 47%, and $100.0 million, or 47%, for the three and nine months ended September 30, 2016, respectively, compared to the same periods in 2015, mainly due to the impact of our full cost ceiling impairments totaling $2.4 billion during the year ended December 31, 2015 and $161.1 million during the three months ended March 31, 2016.

Impairment expense. Our net book value of evaluated oil and natural gas properties exceeded the full cost ceiling amount at March 31, 2016, September 30, 2015 and June 30, 2015, and as a result, we recorded non-cash full cost ceiling impairments of $161.1 million, $906.4 million and $488.0 million, respectively. For further discussion of our non-cash full cost ceiling impairments, see Note 2.f to our unaudited consolidated financial statements included elsewhere in this Quarterly Report. See Note 2.g to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for amounts of and information regarding other less material components of impairment expense.

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



	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2016			2015			2016			2015
Non-operating income (expense):
Gain (loss) on derivatives, net	$	6,850		$	142,580		$	(43,783	)	$	141,836
Income from equity method investee	265			2,104			6,259			4,585
Interest expense	(23,077		)	(23,348		)	(70,294		)	(79,732		)
Interest and other income	33			92			143			388
Loss on early redemption of debt	—			—			—			(31,537		)
Write-off of debt issuance costs	—			—			(842		)	—
Loss on disposal of assets, net	(78		)	(94		)	(379		)	(1,937		)
Non-operating income (expense), net	$	(16,007	)	$	121,334		$	(108,896	)	$	33,603

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



(in thousands)	Three months ended September 30, 2016 compared to 2015			Nine months ended September 30, 2016 compared to 2015
Changes in gain (loss) on derivatives, net:
Fair value of derivatives outstanding	$	(113,895	)	$	(247,366	)
Early terminations of derivatives received	—			80,000
Cash settlements received for matured derivatives	(21,835		)	(18,253		)
Total changes in gain (loss) on derivatives, net	$	(135,730	)	$	(185,619	)

The change in fair value of derivatives outstanding for the three and nine months ended September 30, 2016 compared to the same periods in 2015 is the result of the changing relationship between our outstanding 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 change in gain (loss) on derivatives, net for the nine months ended September 30, 2016 compared to 2015 was partially offset by proceeds received in a hedge restructuring in which we early terminated floors of certain derivative contract collars, resulting in a termination amount due to us of $80.0 million. The $80.0 million was settled in full by applying the proceeds to the premiums on two new derivatives entered into as part of the hedge restructuring. 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.e, 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.

Income from equity method investee. See "—Results of operations - midstream and marketing" for a discussion of this income.

Interest expense. The table below shows the changes in the significant components of interest expense for the periods presented:



(in thousands)	Three months ended September 30, 2016 compared to 2015			Nine months ended September 30, 2016 compared to 2015
Changes in interest expense:
January 2019 Notes	$	—		$	(13,865	)
March 2023 Notes	61			4,740
Senior Secured Credit Facility, net of capitalized interest	(299		)	(99		)
Other	(33		)	(214		)
Total change in interest expense	$	(271	)	$	(9,438	)

Interest expense decreased by $0.3 million, or 1%, and $9.4 million, or 12%, for the three and nine months ended September 30, 2016, respectively, compared to the same periods in 2015. These decreases are primarily due to the early redemption of the January 2019 Notes on April 6, 2015, which is partially offset by the 2015 issuance of the March 2023 Notes. The March 2023 Notes, which began accruing interest on March 18, 2015, have both a lower interest rate and a lower principal amount than the January 2019 Notes.

Loss on disposal of assets, net. Loss on disposal of assets, net did not change significantly for the three months ended September 30, 2016 as compared to the same period in 2015, and decreased by $1.6 million for the nine months ended September 30, 2016 as compared to the same period in 2015 as a result of lower losses related to the sales and write-off of materials and supplies and other fixed assets.

Income tax (expense) benefit. Income tax (expense) benefit for the periods presented was as follows:



	Three months ended September 30,					Nine months ended September 30,
(in thousands)	2016		2015			2016		2015
Income tax (expense) benefit	$	—	$	(41,258	)	$	—	$	176,945

During the year ended December 31, 2015, we recorded a valuation allowance against our net deferred tax asset due to uncertainties in the timing of the realization of our deferred tax assets. Because of continued uncertainties in the oil and gas markets, we recorded an additional valuation allowance of $79.8 million during the nine months ended September 30, 2016. Due to the recording of these valuation allowances, our effective rates are not meaningful for the three and nine months ended September 30, 2016 and 2015. For further discussion of our valuation allowance, see Note 7 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

Results of operations - midstream and marketing

The following table presents selected financial information regarding our midstream and marketing operating segment for the periods presented:



	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2016			2015			2016			2015
Natural gas sales	$	488		$	753		$	488		$	1,086
Midstream service revenues	15,357			7,917			37,762			15,962
Sales of purchased oil	42,441			43,860			116,670			130,178
Total revenues	58,286			52,530			154,920			147,226
Midstream service expenses	9,079			5,240			22,160			8,745
Costs of purchased oil	44,232			46,961			121,190			132,578
General and administrative⁽¹⁾	2,222			2,200			5,678			6,138
Depreciation and amortization⁽²⁾	2,275			2,113			6,669			5,923
Other operating costs and expenses⁽³⁾	51			481			157			1,669
Operating income (loss)	$	427		$	(4,465	)	$	(934	)	$	(7,827	)
Other financial information:
Income from equity method investee	$	265		$	2,104		$	6,259		$	4,585
Interest expense⁽⁴⁾	$	(1,446	)	$	(1,318	)	$	(4,310	)	$	(3,770	)
Loss on early redemption of debt⁽⁵⁾	$	—		$	—		$	—		$	(1,481	)

_______________________________________________________________________________


(1)	G&A expense was allocated based on the number of employees in the midstream and marketing segment as of September 30, 2016 and 2015. Certain components of G&A expense, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment.


(2)	Depreciation and amortization were actual expenses for the midstream and marketing segment with the exception of the allocation of depreciation of other fixed assets, which was based on the number of employees in the midstream and marketing segment as of September 30, 2016 and 2015.

(3)

Other operating costs and expenses consist of restructuring expense for the nine months ended September 30, 2015, accretion of asset retirement obligations for the three and nine months ended September 30, 2016 and 2015, impairment for the three and nine months ended September 30, 2015 and minimum volume commitments for the nine months ended September 30, 2015. These are actual costs and expenses and were not allocated.


(4)	Interest expense was allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of September 30, 2016 and 2015.


(5)	Loss on early redemption of debt was allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of September 30, 2015.

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." See Note 16 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information on the operating segments.

Midstream service revenues. Our midstream service revenues from operations increased by $7.4 million and $21.8 million for the three and nine months ended September 30, 2016, respectively, compared to the same periods in 2015. These increases are mainly due to (i) water service revenue that we began recognizing in the third quarter of 2015 and (ii) an increase in volumes of natural gas provided for natural gas lift mainly in our production corridors over the prior periods.

Sales of purchased oil. Sales of purchased oil decreased by $1.4 million and $13.5 million for the three and nine months ended September 30, 2016, respectively, compared to the same periods in 2015 primarily due to the decrease in oil prices. We purchase oil from third parties in West Texas, transport it on the Bridgetex Pipeline and sell it to a third party in the Houston market.

Midstream service expenses. Midstream service expenses increased by $3.8 million and $13.4 million for the three and nine months ended September 30, 2016, respectively, compared to the same periods in 2015. Midstream service expenses primarily 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. The increases are due to continued expansion of the midstream service component of our business.

Costs of purchased oil. Costs of purchased oil decreased by $2.7 million and $11.4 million for the three and nine months ended September 30, 2016, respectively, compared to the same periods in 2015 primarily due to the decrease in oil prices. These costs include purchasing oil from third parties and transporting it on the Bridgetex Pipeline.

G&A. Our consolidated G&A expense has increased for the three months ended September 30, 2016 and decreased for the nine months ended September 30, 2016 compared to the same periods in 2015. See "—Results of operations consolidated" for a discussion of these costs.

Depreciation and amortization. Depreciation and amortization increased by $0.2 million and $0.7 million for the three and nine months ended September 30, 2016, respectively, compared to the same periods in 2015 due to the continued expansion of our midstream service infrastructure.

Income 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 reflected in the unaudited consolidated statements of operations as "Income from equity method investee" and the carrying amount reflected in the unaudited consolidated balance sheets as "Investment in equity method investee." Income from equity method investee decreased by $1.8 million, or 87%, and increased by $1.7 million, or 37%, for the three and nine months ended September 30, 2016, respectively, compared to the same periods in 2015. The quarter-over-quarter decrease is due to additional depreciation expense taken in the third quarter of 2016. During the nine months ended September 30, 2016, Medallion continued expansion activities on existing portions of its pipeline infrastructure in order to gather additional third-party oil production. Medallion began recognizing revenue during the first quarter of 2015 due to its main pipeline becoming fully operational. The Medallion pipeline system transported 118,000 barrels of oil per day ("BOPD") and 55,000 BOPD for the three months ended September 30, 2016 and 2015, respectively, and 100,000 BOPD and 37,000 BOPD during the nine months ended September 30, 2016 and 2015, respectively. 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 by $0.1 million and $0.5 million for three and nine months ended September 30, 2016, respectively, compared to the same periods in 2015. Consolidated interest, which has decreased for the three and nine months ended September 30, 2016 compared to the same periods in 2015, is allocated to the midstream and marketing segment based on its gross property and equipment and life-to-date contributions to its equity method investee. We have expanded the midstream and marketing component of our business, built out our service facilities and have continued our capital contributions to Medallion since prior periods, thereby increasing the interest expense that is allocated to this segment. See "—Results of operations consolidated" for a discussion of these decreases.

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, borrowings under our Senior Secured Credit Facility and proceeds from asset dispositions. We believe cash flows from operations (including our hedging program) and availability under our Senior Secured Credit Facility provide sufficient liquidity to manage our cash needs and contractual obligations and to fund expected capital expenditures. Our primary operational uses of capital have been for the acquisition, exploration and development of oil and natural gas properties, LMS' infrastructure development and investments in Medallion.

A significant portion of our capital expenditures can be adjusted and managed by us. We continually monitor the capital markets and our capital structure and consider which financing alternatives, including equity and debt capital resources, joint ventures and asset sales, are available to meet our future planned or accelerated capital expenditures. We may make changes to our capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity and/or achieving cost efficiency. Such financing alternatives, including capital market transactions and debt repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

We continually seek to maintain a financial profile that provides operational flexibility. However, as evidenced by the decline in our Realized Prices used in our reserves compared to the prior year, the decrease in oil, NGL and natural gas prices may have a negative impact on our ability to raise additional capital and/or maintain our desired levels of liquidity. As of November 1, 2016, we had $745.0 million available for borrowings under our Senior Secured Credit Facility. We believe that our operating cash flow and the aforementioned liquidity sources provide us with the financial resources to implement our planned exploration and development activities. We use derivatives to reduce exposure to fluctuations in the prices of oil, NGL

and natural gas. As of November 1, 2016 utilizing the mid-point of our fourth-quarter guidance, approximately 84% of our anticipated oil production for the last three months of 2016 is hedged at a weighted-average floor price of $67.13 per Bbl and approximately 59% of our anticipated natural gas production for the last three months of 2016 is hedged at a weighted-average floor price of $3.00 per MMBtu.

The following table summarizes our hedge positions that were in place as of November 2, 2016 for the calender years presented:



	Remaining year 2016		Year 2017		Year 2018
Oil positions:⁽¹⁾
Total volume hedged with floor price (Bbl)	1,861,350		6,852,875		2,144,375
Weighted-average floor price ($/Bbl)	$	67.13	$	55.82	$	55.98
NGL positions - Ethane:
Total volume hedged with floor price (Bbl)	—		444,000		—
Weighted-average floor price ($/Bbl)	$	—	$	11.24	$	—
NGL positions - Propane:
Total volume hedged with floor price (Bbl)	—		375,000		—
Weighted-average floor price ($/Bbl)	$	—	$	22.26	$	—
Natural gas positions:⁽¹⁾
Total volume hedged with floor price (MMBtu)	4,692,000		22,494,000		12,855,500
Weighted-average floor price ($/MMBtu)	$	3.00	$	2.70	$	2.50

_______________________________________________________________________________


(1)	Includes derivatives entered into subsequent to September 30, 2016.

See Note 8.a to our unaudited consolidated financial statements located elsewhere in this Quarterly Report for information regarding our derivative settlement indices.

The following table presents a projection of estimated cash received in future periods from oil, NGL and natural gas derivative contracts in place as of September 30, 2016 adjusted for any new hedge transactions entered into between October 1, 2016 and November 1, 2016, utilizing the total volumes hedged with a floor price and the weighted-average floor price for the periods presented:



(in thousands)	Remaining year 2016		Year 2017		Year 2018
Projected oil, NGL and natural gas hedge cash proceeds⁽¹⁾	$	31,948	$	37,945	$	10,089

_______________________________________________________________________________

(1)

For this illustration we utilized the October 25, 2016 (i) WTI index oil spot price of $49.45 per Bbl, (ii) Mont Belvieu Purity Ethane-OPIS spot price of $9.92 (converted to $/Bbl), (iii) Mont Belvieu Propane (TET)-OPIS spot price of $24.89 (converted to $/Bbl) and (iv) Waha natural gas spot price of $2.63 per MMBtu. Prices used were held constant for all periods presented. Additionally, we reduced our projected oil, NGL and natural gas hedge cash proceeds by the actual cash payments required for deferred premiums for the calendar years presented.

By removing a significant portion of the price volatility associated with future production, we expect to mitigate, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations in commodity prices.

On September 15, 2015, we completed the sale of non-strategic and primarily non-operated properties and associated production totaling 6,060 net acres and 123 producing properties in the Midland Basin to a third-party buyer for a purchase price of $65.5 million. After transaction costs reflecting an economic effective date of July 1, 2015, the net proceeds were $64.8 million, net of working capital adjustments and post-closing cost adjustments.

On March 5, 2015, we completed the sale of 69,000,000 shares of Laredo's common stock for 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.

On May 16, 2016, we completed the sale of 10,925,000 shares of Laredo's common stock for net proceeds of $119.3 million, after underwriting discounts, commissions and offering expenses.

As of September 30, 2016, we had $70.0 million outstanding under our Senior Secured Credit Facility and $1.3 billion in senior unsecured notes. We had $745.0 million available for borrowings under our Senior Secured Credit Facility and $30.4 million in cash on hand for total available liquidity of $775.4 million as of September 30, 2016.

As of November 1, 2016, we had $1.4 billion in debt outstanding, $745.0 million available for borrowings under our Senior Secured Credit Facility and $10.2 million in cash on hand for total available liquidity of $755.2 million. A continued decline in oil, NGL and natural gas prices will negatively impact our future borrowing base redeterminations.

Our derivative positions will help us stabilize a portion of our expected cash flows from operations in the event of future declines in the price of oil, NGL and natural gas. See "Item 3. Quantitative and Qualitative Disclosures About Market Risk" below.

Cash flows

Our cash flows for the periods presented are as follows:



	Nine months ended September 30,
(in thousands)	2016			2015
Net cash provided by operating activities	$	245,454		$	225,504
Net cash used in investing activities	(455,895		)	(531,877		)
Net cash provided by financing activities	209,647			353,455
Net (decrease) increase in cash and cash equivalents	$	(794	)	$	47,082

Cash flows provided by operating activities

Net cash provided by operating activities was $245.5 million and $225.5 million for the nine months ended September 30, 2016 and 2015, respectively. The increase of $20.0 million during the nine months ended September 30, 2016 compared to the same period in 2015 consisted of notable cash flow changes of (i) a decrease in impairment expense of $1.24 billion, (ii) a decreased mark-to-market derivative loss of $247.4 million, (iii) a decrease in depletion, depreciation and amortization expense of $100.0 million, (iv) an increase of $83.1 million in cash premiums paid for derivatives, (v) an increase in working capital changes of $49.9 million and (vi) a decrease of $31.5 million related to our loss on the early redemption of our January 2019 Notes.

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 was $455.9 million and $531.9 million for the nine months ended September 30, 2016 and 2015, respectively. The decrease of $76.0 million is mainly attributable to the decrease in our 2016 capital budget compared to 2015, partially offset by current period acquisitions of oil and natural gas properties and in prior period proceeds from sale of non-strategic and primarily non-operated properties and associated production. See Notes 4.a and 4.b to our unaudited consolidated financial statements located elsewhere in this Quarterly Report for discussion of our current period acquisition and prior period divestiture.

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



	Nine months ended September 30,
(in thousands)	2016			2015
Capital expenditures:
Acquisitions of oil and natural gas properties	$	(115,600	)	$	—
Oil and natural gas properties	(276,735		)	(490,351		)
Midstream service assets	(4,231		)	(35,237		)
Other fixed assets	(982		)	(8,539		)
Investment in equity method investee	(58,712		)	(63,011		)
Proceeds from dispositions of capital assets, net of selling costs	365			65,261
Net cash used in investing activities	$	(455,895	)	$	(531,877	)

Capital expenditure budget

During the second quarter of 2016, our board of directors approved an increase to the 2016 capital expenditure budget of approximately $75.0 million. Our revised capital expenditure budget is $420.0 million for calendar year 2016, excluding acquisitions and investments in Medallion. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted. In addition, as a 49% owner of Medallion, we do not direct the expansion activities of this entity and therefore cannot predict future capital commitments related to Medallion.

The amount, timing and allocation of capital expenditures, other than with respect to Medallion, 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

Net cash provided by financing activities was $209.6 million and $353.5 million for the nine months ended September 30, 2016 and 2015, respectively. For the nine months ended September 30, 2016, our primary sources of cash provided by financing activities were borrowings on our Senior Secured Credit Facility and proceeds from our May 2016 Equity Offering and July 2016 Equity Offering, partially offset by payments on our Senior Secured Credit Facility. For the nine months ended September 30, 2015, our primary sources of cash provided by financing activities were borrowings on our Senior Secured Credit Facility, 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 and redemption of our January 2019 Notes.

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



	Nine months ended September 30,
(in thousands)	2016			2015
Borrowings on Senior Secured Credit Facility	$	214,682		$	310,000
Payments on Senior Secured Credit Facility	(279,682		)	(475,000		)
Issuance of March 2023 Notes	—			350,000
Redemption of January 2019 Notes	—			(576,200		)
Proceeds from issuance of common stock, net of offering costs	276,052			754,163
Purchase of treasury stock	(1,613		)	(2,749		)
Proceeds from exercise of employee stock options	208			—
Payments for debt issuance costs	—			(6,759		)
Net cash provided by financing activities	$	209,647		$	353,455

Debt

As of September 30, 2016, 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 September 30, 2016, our Senior Secured Credit Facility, which matures November 4, 2018, had a maximum credit amount of $2.0 billion, a borrowing base and an aggregate elected commitment of $815.0 million and $70.0 million outstanding.

The borrowing base under our Senior Secured Credit Facility is subject to a semi-annual redetermination based on the lenders' evaluation of our oil, NGL and natural gas reserves. The lenders have the right to call for an interim redetermination of the borrowing base once between any two redetermination dates and in other specified circumstances. On October 24, 2016, pursuant to a regular semi-annual redetermination, the lenders reaffirmed the borrowing base under our Senior Secured Credit Facility at $815.0 million. Our aggregate elected commitment of $815.0 million remained unchanged.

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 based 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 certain of 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 covenants as of September 30, 2016 and expect to be in compliance with them for the foreseeable future.

Senior unsecured notes. The following table presents principal amounts and applicable interest rates for our outstanding senior unsecured notes as of September 30, 2016:



(in millions, except for interest rates)	Principal		Interest rate
January 2022 Notes	$	450.0	5.625	%
May 2022 Notes	$	500.0	7.375	%
March 2023 Notes	$	350.0	6.250	%

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 5.d 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 5 of our audited consolidated financial statements included in the 2015 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 November 1, 2016, we had a total of $1.3 billion of senior unsecured notes outstanding and $70.0 million outstanding on the Senior Secured Credit Facility.

Obligations and commitments

As of September 30, 2016, our contractual obligations included our March 2023 Notes, January 2022 Notes, May 2022 Notes, Senior Secured Credit Facility, firm sale and transportation commitments, drilling contract commitments, derivative deferred premiums, asset retirement obligations and office and equipment leases. From December 31, 2015 to September 30, 2016, the material changes in our contractual obligations included (i) a decrease of $65.6 million on our interest obligations for our senior unsecured notes as semi-annual interest payments were made in January, March, May, July and September of 2016, (ii) a decrease of $65.0 million outstanding on our Senior Secured Credit Facility, (iii) a decrease of $38.9 million in our firm sale and transportation commitments, (iv) a decrease of $27.6 million in our outstanding capital contribution commitment to our equity method investee due to payments made to Medallion in first-quarter 2016, (v) a decrease of $8.8 million for drilling contract commitments (on contracts other than those on a well-by-well basis) and (vi) a decrease of $6.4 million in our performance unit liability awards as the 2013 Performance Unit Awards were paid in first-quarter 2016.

Refer to Notes 2, 5, 6, 8, 9, 12, 14 and 15 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 deferred income tax expense or benefit, depletion, depreciation and amortization, bad debt expense, impairment expense, non-cash stock-based compensation, accretion of asset retirement obligations, restructuring expenses, gains or losses on derivatives, cash settlements received for matured derivatives, cash settlements on early terminated derivatives, cash premiums paid for derivatives, interest expense, write-off of debt issuance costs, gains or losses on disposal of assets, loss on early redemption of debt, buyout of minimum volume commitment, income from equity method investee and proportionate Adjusted EBITDA of equity method investee. 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.

As of September 30, 2016, we changed the methodology for calculating Adjusted EBITDA by including adjustments for both accretion of asset retirement obligations and our proportionate share of our equity method investee's Adjusted EBITDA. Accordingly, the prior periods' Adjusted EBITDA has been modified for comparability.

The following presents a reconciliation of Net income (loss) (GAAP) to Adjusted EBITDA (non-GAAP):



	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2016			2015			2016			2015
Net income (loss)	$	9,485		$	(847,783	)	$	(242,318	)	$	(1,245,289	)
Plus:
Deferred income tax expense (benefit)	—			41,258			—			(176,945		)
Depletion, depreciation and amortization	35,158			66,777			110,813			210,831
Bad debt expense	—			107			—			107
Impairment expense	—			906,850			162,027			1,397,327
Non-cash stock-based compensation, net of amounts capitalized	9,651			6,877			19,562			17,933
Accretion of asset retirement obligations	883			599			2,587			1,771
Restructuring expenses	—			—			—			6,042
Mark-to-market on derivatives:
(Gain) loss on derivatives, net	(6,850		)	(142,580		)	43,783			(141,836		)
Cash settlements received for matured derivatives, net	44,307			66,142			157,626			175,879
Cash settlements received for early terminations of derivatives, net	—			—			80,000			—
Cash premiums paid for derivatives	(2,709		)	(1,248		)	(86,972		)	(3,918		)
Interest expense	23,077			23,348			70,294			79,732
Write-off of debt issuance costs	—			—			842			—
Loss on disposal of assets, net	78			94			379			1,937
Loss on early redemption of debt	—			—			—			31,537
Buyout of minimum volume commitment	—			—			—			3,014
Income from equity method investee	(265		)	(2,104		)	(6,259		)	(4,585		)
Proportionate Adjusted EBITDA of equity method investee⁽¹⁾	5,194			3,295			13,981			5,774
Adjusted EBITDA	$	118,009		$	121,632		$	326,345		$	359,311

_______________________________________________________________________________


(1)	Proportionate Adjusted EBITDA of Medallion, our equity method investee, is calculated as follows:



	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2016		2015		2016		2015
Income from equity method investee	$	265	$	2,104	$	6,259	$	4,585
Adjusted for proportionate share of:
Depreciation and amortization	4,929		1,191		7,722		2,666
Buyout of minimum volume commitment	—		—		—		(1,477		)
Proportionate Adjusted EBITDA of equity method investee	$	5,194	$	3,295	$	13,981	$	5,774

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 a 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, NGL and natural gas reserve quantities and standardized measure of future net revenues, (iii) impairment of oil and natural gas properties, (iv) revenue recognition, (v) estimation of income taxes, (vi) asset retirement obligations, (vii) valuation of derivatives and deferred premiums, (viii) valuation of stock-based compensation and performance unit compensation and (ix) fair value of assets acquired and liabilities assumed in an acquisition. 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 nine months ended September 30, 2016. 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 2015 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

See Note 18 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for information regarding recent accounting pronouncements.

Off-balance sheet arrangements

Currently, we do not have any off-balance sheet arrangements other than operating leases, a drilling contract commitment and firm sale and transportation commitments, which are included in "Obligations and commitments." See Note 12 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information.

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 derivatives, such as puts, swaps, collars and, in prior periods, basis swaps to hedge price risk associated with a significant portion of our anticipated production. By removing a portion 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 values of our 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 derivatives are largely determined by estimates of the forward curves of the relevant price indices. As of September 30, 2016, a 10% change in the forward curves associated with our derivatives would have changed our net positions to the following amounts:



(in thousands)	10% Increase		10% Decrease
Derivatives	$	40,761	$	128,569

As of September 30, 2016 and December 31, 2015, the fair values of our open derivative contracts were $81.6 million and $276.2 million, respectively. Refer to Notes 2.e, 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 September 30, 2016, we had $70.0 million outstanding on our Senior Secured Credit Facility. Our January 2022 Notes, May 2022 Notes and March 2023 Notes bear fixed interest rates and we had $450.0 million, $500.0 million and $350.0 million outstanding, respectively, as of September 30, 2016, as shown in the table below.



	Expected maturity date
(in millions except for interest rates)	2018			2022			2023			Total
January 2022 Notes - fixed rate	$	—		$	450.0		$	—		$	450.0
Interest rate	—		%	5.625		%	—		%	5.625		%
May 2022 Notes - fixed rate	$	—		$	500.0		$	—		$	500.0
Interest rate	—		%	7.375		%	—		%	7.375		%
March 2023 Notes - fixed rate	$	—		$	—		$	350.0		$	350.0
Interest rate	—		%	—		%	6.250		%	6.250		%
Senior Secured Credit Facility - variable rate	$	70.0		$	—		$	—		$	70.0
Average interest rate⁽¹⁾	2.005		%	—		%	—		%	2.005		%

______________________________________________________________________________


(1)	For the nine months ended September 30, 2016.

Counterparty and customer credit risk

As of September 30, 2016, our principal exposures to credit risk are through receivables of (i) $86.4 million from the fair values of our open derivative contracts, (ii) $39.6 million from the sale of our oil, NGL and natural gas production that we market to energy marketing companies and refineries, (iii) $14.0 million from sales of purchased oil and other products, (iv) $13.8 million from matured derivatives and (v) $13.6 million from joint-interest partners.

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 11 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 September 30, 2016. Our disclosure controls and other procedures are designed to provide reasonable assurance that the information required to be disclosed in the reports we file and submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to Laredo's management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Evaluation of changes in internal control over financial reporting

There were no changes in our internal control over financial reporting during the quarter ended September 30, 2016 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 2015 Annual Report. There have been no material changes in our risk factors from those described in the 2015 Annual Report. The risks described in the 2015 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.

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
July 1, 2016 - July 31, 2016	2,797	$	10.45	—	—
August 1, 2016 - August 31, 2016	3,406	$	10.19	—	—
September 1, 2016 - September 30, 2016	672	$	12.24	—	—
Total	6,875

______________________________________________________________________________


(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 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 we or WP undertake any obligation to correct or update it.

We understand that one or more SEC-reporting affiliates of SAMIAH intends to disclose in their next annual or quarterly SEC report that:

(a) Santander UK plc ("Santander UK") holds two savings accounts and one current account for two customers resident in the United Kingdom ("UK") who are currently designated by the United States ("US") under the Specially Designated Global Terrorist ("SDGT") sanctions program. Revenues and profits generated by Santander UK on these accounts in the nine months ended September 30, 2016 were negligible relative to the overall revenues and profits of Banco Santander SA.

(b) Santander UK held a savings account for a customer resident in the UK who is currently designated by the US under the SDGT sanctions program. The savings account was closed on July 26, 2016. Revenue generated by Santander UK on this account in the nine months ended September 30, 2016 was negligible relative to the overall revenues of Banco Santander SA.

(c) Santander UK holds two frozen current accounts for two UK nationals who are designated by the US under the SDGT sanctions program. The accounts held by each customer have been frozen since their designation and have remained frozen through the nine months ended September 30, 2016. The accounts are in arrears (£1,844.73 in debit combined) and are currently being managed by Santander UK Collections & Recoveries department. Revenues and profits generated by Santander UK on these accounts in the nine months ended September 30, 2016 were negligible relative to the overall revenues and profits of Banco Santander SA.

(d) Santander UK holds three current accounts and a savings account for two customers resident in the UK who are currently designated by the US under the Transnational Criminal Organizations ("TCO") sanctions program. Revenues and profits generated by Santander UK on these accounts in the nine months ended September 30, 2016 were negligible relative to the overall revenues and profits of Banco Santander SA.

(e) In addition, during the nine months ended September 30, 2016, Santander UK had an OFAC match on a power of attorney account. A party listed on the account is currently designated by the US under the SDGT sanctions program and the Iranian Financial Sanctions Regulations. The power of attorney was removed from the account on July 29, 2016. During the nine months ended September 30, 2016, related revenues and profits generated by Santander UK were negligible relative to the overall revenues and profits of Banco Santander SA.

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			Second Amended and Restated Bylaws of Laredo Petroleum, Inc. (incorporated by reference to Exhibit 3.3 of Laredo's Annual Report on Form 10-K (File No. 001-35380) filed on February 17, 2016).

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).

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: November 3, 2016	By:	/s/ Randy A. Foutch
		Randy A. Foutch
		Chairman and Chief Executive Officer
		(principal executive officer)

Date: November 3, 2016	By:	/s/ Richard C. Buterbaugh
		Richard C. Buterbaugh
		Executive Vice President and Chief Financial Officer
		(principal financial officer)

Date: November 3, 2016	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			Second Amended and Restated Bylaws of Laredo Petroleum, Inc. (incorporated by reference to Exhibit 3.3 of Laredo's Annual Report on Form 10-K (File No. 001-35380) filed on February 17, 2016).

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).

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.