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, 2015~~March 31, 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 ~~November~~May 2, ~~2015: 213,804,059~~2016: 213,406,700

TABLE OF CONTENTS



		Page
Cautionary Statement Regarding Forward-Looking Statements		iii
	Part I
Item 1.	Consolidated Financial Statements (Unaudited)	1
	Consolidated balance sheets as of ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014~~2015	1
	Consolidated statements of operations for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~	2
	Consolidated statement of stockholders' equity for the ~~nine~~three months ended ~~September 30, 2015~~March 31, 2016	3
	Consolidated statements of cash flows for the ~~nine~~three months ended ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~	4
	Condensed notes to the consolidated financial statements	5
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	37
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	5653
Item 4.	Controls and Procedures	5855
	Part II
Item 1.	Legal Proceedings	5956
Item 1A.	Risk Factors	5956
Item 2.	Repurchase of Equity Securities	5956
Item 3.	Defaults Upon Senior Securities	5956
Item 4.	Mine Safety Disclosures	6056
Item 5.	Other Information	6056
Item 6.	Exhibits	6258
Signatures		6359
Exhibit Index		6460

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;~~prices, which remain at low levels;

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

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

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

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

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;

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

the ongoing instability and uncertainty in the U.S. and international financial and consumer markets that could adversely affect the liquidity available to us and our customers and the demand for commodities, including oil, 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;~~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 U.S. Gulf Coast to refine all of the light sweet crude oil being produced in the U.S., 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;

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

~~iii~~

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

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

iii

These forward-looking statements involve a number of risks and uncertainties that could cause actual results to differ materially from those suggested by the forward-looking statements. Forward-looking statements should, therefore, be considered in light of various factors, including those set forth under "Part I, Item 2. Management's Discussion and Analysis of Financial Condition and Results of ~~Operations," "Part II, Item 1A. Risk Factors"~~Operations" and elsewhere in this Quarterly Report, ~~under "Part II, Item 1A. Risk Factors" in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2015,~~ under "Part I, Item 1A. Risk Factors" and "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in our Annual Report on Form 10-K for the fiscal year ended December 31, ~~2014~~2015 (the ~~"2014~~"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, 2015			December 31, 2014			March 31, 2016			December 31, 2015
Assets
Current assets:
Cash and cash equivalents	$	76,403		$	29,321		$	12,095		$	31,154
Accounts receivable, net	100,675			126,929			85,173			87,699
Derivatives	184,157			194,601			166,794			198,805
Other current assets	14,207			14,402			16,796			14,574
Total current assets	375,442			365,253			280,858			332,232
Property and equipment:
Oil and natural gas properties, full cost method:
Evaluated properties	4,895,042			4,446,781			5,216,178			5,103,635
Unevaluated properties not being amortized	225,045			342,731
Midstream service assets	149,068			117,052
Other fixed assets	62,114			56,165
Total property and equipment	5,331,269			4,962,729
Less accumulated depletion, depreciation, amortization and impairment	(3,212,194		)	(1,608,647		)
Net property and equipment	2,119,075			3,354,082
Deferred income taxes	68,069			—
Unevaluated properties not being depleted							116,905			140,299
Less accumulated depletion and impairment							(4,417,833		)	(4,218,942		)
Oil and natural gas properties, net							915,250			1,024,992
Midstream service assets, net							130,007			131,725
Other fixed assets, net							42,476			43,538
Property and equipment, net							1,087,733			1,200,255
Derivatives	97,850			117,788			63,414			77,443
Investment in equity method investee	160,206			58,288			194,822			192,524
Other assets, net	11,853			15,290			10,337			10,833
Total assets	$	2,832,495		$	3,910,701		$	1,637,164		$	1,813,287
Liabilities and stockholders' equity
Liabilities and stockholders' (deficit) equity
Current liabilities:
Accounts payable	$	23,647		$	39,008		$	23,382		$	14,181
Undistributed revenue and royalties	38,346			65,438			26,282			34,540
Accrued capital expenditures	49,283			148,241			43,657			61,872
Deferred income taxes	68,069			71,191
Derivatives	—			115
Other current liabilities	112,204			101,032			62,753			106,222
Total current liabilities	291,549			425,025			156,074			216,815
Long-term debt, net	1,415,566			1,779,447			1,476,890			1,416,226
Deferred income taxes	—			105,754
Derivatives							234			—
Asset retirement obligations	32,557			31,042			45,711			44,759
Other noncurrent liabilities	4,141			6,232			3,971			4,040
Total liabilities	1,743,813			2,347,500			1,682,880			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, 2015 and December 31, 2014	—			—
Common stock, $0.01 par value, 450,000,000 shares authorized, and 213,839,893 and 143,686,491 issued, as of September 30, 2015 and December 31, 2014, respectively	2,138			1,437
Stockholders' (deficit) equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of March 31, 2016 and December 31, 2015							—			—
Common stock, $0.01 par value, 450,000,000 shares authorized and 213,447,648 and 213,808,003 issued and outstanding as of March 31, 2016 and December 31, 2015, respectively							2,134			2,138
Additional paid-in capital	2,079,240			1,309,171			2,089,864			2,086,652
(Accumulated deficit) retained earnings	(992,696		)	252,593
Total stockholders' equity	1,088,682			1,563,201
Total liabilities and stockholders' equity	$	2,832,495		$	3,910,701
Accumulated deficit							(2,137,714		)	(1,957,343		)
Total stockholders' (deficit) equity							(45,716		)	131,447
Total liabilities and stockholders' (deficit) equity							$	1,637,164		$	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,						Three months ended March 31,
	2015			2014			2015			2014			2016			2015
Revenues:
Oil, NGL and natural gas sales	$	104,607		$	199,490		$	348,279		$	555,576		$	73,142		$	118,118
Midstream service revenues	1,873			751			4,908			1,019			1,801			1,309
Sales of purchased oil	43,860			—			130,178			—			31,614			31,267
Total revenues	150,340			200,241			483,365			556,595			106,557			150,694
Costs and expenses:
Lease operating expenses	25,112			25,165			86,698			67,129			20,518			32,380
Production and ad valorem taxes	7,895			12,550			26,481			38,160			6,435			9,086
Midstream service expenses	1,092			1,225			4,263			3,596			609			1,574
Minimum volume commitments	—			675			5,235			1,779			—			1,656
Costs of purchased oil	46,961			—			132,578			—			32,946			31,200
General and administrative	22,913			27,078			67,976			84,284			19,451			21,855
Restructuring expenses	—			—			6,042			—			—			6,042
Accretion of asset retirement obligations	599			442			1,771			1,279			844			579
Depletion, depreciation and amortization	66,777			63,942			210,831			166,605			41,478			71,942
Impairment expense	906,850			—			1,397,327			—			161,064			878
Total costs and expenses	1,078,199			131,077			1,939,202			362,832			283,345			177,192
Operating income (loss)	(927,859		)	69,164			(1,455,837		)	193,763
Operating loss													(176,788		)	(26,498		)
Non-operating income (expense):
Gain (loss) on derivatives, net	142,580			92,790			141,836			(1,447		)
Gain on derivatives, net													17,885			63,155
Income (loss) from equity method investee	2,104			(61		)	4,585			(86		)	2,298			(433		)
Interest expense	(23,348		)	(30,549		)	(79,732		)	(90,192		)	(23,705		)	(32,414		)
Interest and other income	92			33			388			310			99			123
Loss on early redemption of debt	—			—			(31,537		)	—
Write-off of debt issuance costs	—			—			—			(124		)
Loss on disposal of assets, net	(94		)	(2,192		)	(1,937		)	(2,418		)	(160		)	(762		)
Non-operating income (expense), net	121,334			60,021			33,603			(93,957		)	(3,583		)	29,669
Income (loss) before income taxes	(806,525		)	129,185			(1,422,234		)	99,806			(180,371		)	3,171
Income tax (expense) benefit:
Income tax expense:
Deferred	(41,258		)	(45,778		)	176,945			(35,511		)	—			(3,643		)
Total income tax (expense) benefit	(41,258		)	(45,778		)	176,945			(35,511		)
Net income (loss)	$	(847,783	)	$	83,407		$	(1,245,289	)	$	64,295
Net income (loss) per common share:
Total income tax expense													—			(3,643		)
Net loss													$	(180,371	)	$	(472	)
Net loss per common share:
Basic	$	(4.01	)	$	0.59		$	(6.38	)	$	0.46		$	(0.85	)	$	—
Diluted	$	(4.01	)	$	0.58		$	(6.38	)	$	0.45		$	(0.85	)	$	—
Weighted-average common shares outstanding:
Basic	211,204			141,413			195,081			141,261			211,560			162,426
Diluted	211,204			143,813			195,081			143,583			211,560			162,426

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

Laredo Petroleum, Inc.

Consolidated statement of stockholders' equity (deficit)

(in thousands)

(Unaudited)


	Common Stock					Additional paid-in capital				Treasury Stock (at cost)						Retained earnings (accumulated deficit)								Common Stock						Additional paid-in capital				Treasury Stock (at cost)						Accumulated deficit
	Shares		Amount						Shares			Amount				Retained earnings (accumulated deficit)			Total				Shares			Amount				Additional paid-in capital			Shares			Amount				Accumulated deficit			Total
Balance, December 31, 2014	143,686		$	1,437		Additional paid-in capital	$	1,309,171			—			$	—		$	252,593			$	1,563,201
Balance, December 31, 2015																								213,808			$	2,138		$	2,086,652			—			$	—		$	(1,957,343	)		$	131,447
Restricted stock awards	1,894		18			(18		)		—			—			—				—				24			—			—				—			—			—				—
Restricted stock forfeitures	(519	)	(5		)	5				—			—			—				—				(108	)		(1		)	1				—			—			—				—
Vested restricted stock exchanged for tax withholding	—		—			—				221			(2,749		)	—				(2,749		)		—			��			—				276			(1,412		)	—				(1,412		)
Retirement of treasury stock	(221	)	(2		)	(2,747		)		(221	)		2,749			—				—				(276	)		(3		)	(1,409		)		(276	)		1,412			—				—
Equity issuance, net of offering costs	69,000		690			753,473				—			—			—				754,163
Stock-based compensation	—		—			19,356				—			—			—				19,356				—			—			4,620				—			—			—				4,620
Net loss	—		—			—				—			—			(1,245,289		)		(1,245,289		)		—			—			—				—			—			(180,371		)		(180,371		)
Balance, September 30, 2015	213,840		$	2,138		$	2,079,240			—			$	—		$	(992,696	)		$	1,088,682
Balance, March 31, 2016																								213,448			$	2,134		$	2,089,864			—			$	—		$	(2,137,714	)		$	(45,716	)

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,						Three months ended March 31,
	2015			2014			2016			2015
Cash flows from operating activities:
Net income (loss)	$	(1,245,289	)	$	64,295
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred income tax (benefit) expense	(176,945		)	35,511
Net loss							$	(180,371	)	$	(472	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Deferred income tax expense							—			3,643
Depletion, depreciation and amortization	210,831			166,605			41,478			71,942
Impairment expense	1,397,327			—			161,064			878
Loss on early redemption of debt	31,537			—
Bad debt expense	107			—
Non-cash stock-based compensation, net of amounts capitalized	17,933			16,919			3,838			4,788
Mark-to-market on derivatives:
(Gain) loss on derivatives, net	(141,836		)	1,447
Cash settlements received (paid) for matured derivatives, net	175,879			(1,320		)
Gain on derivatives, net							(17,885		)	(63,155		)
Cash settlements received for matured derivatives, net							65,937			63,141
Cash settlements received for early terminations of derivatives, net	—			76,660			80,000			—
Change in net present value of deferred premiums paid for derivatives	141			170			72			43
Cash premiums paid for derivatives	(3,918		)	(5,599		)	(81,850		)	(1,421		)
Amortization of debt issuance costs	3,612			3,823			1,120			1,377
Cash settlement of performance unit awards	(2,738		)	—			(6,394		)	(2,738		)
Other, net	(876		)	4,137			(1,292		)	1,742
Decrease (increase) in accounts receivable	26,147			(26,449		)
Decrease in accounts receivable							2,526			16,926
Increase in other assets	(1,234		)	(8,656		)	(2,186		)	(14,478		)
(Decrease) increase in accounts payable	(15,361		)	39,456
(Decrease) increase in undistributed revenues and royalties	(27,092		)	14,105
Increase (decrease) in accounts payable							9,201			(8,598		)
Decrease in undistributed revenues and royalties							(8,258		)	(19,222		)
Decrease in other accrued liabilities	(25,676		)	(7,908		)	(10,414		)	(28,714		)
Increase in other noncurrent liabilities	221			2,373
(Decrease) increase in other noncurrent liabilities							(69		)	187
Increase in fair value of performance unit awards	2,734			767			—			996
Net cash provided by operating activities	225,504			376,336			56,517			26,865
Cash flows from investing activities:
Capital expenditures:
Acquisition of oil and natural gas properties	—			(6,493		)
Acquisition of mineral interests	—			(7,305		)
Oil and natural gas properties	(490,351		)	(925,121		)	(105,155		)	(243,733		)
Midstream service assets	(35,237		)	(45,263		)	(1,937		)	(20,434		)
Other fixed assets	(8,539		)	(13,612		)	(630		)	(3,919		)
Investment in equity method investee	(63,011		)	(37,581		)	(26,660		)	(14,495		)
Proceeds from dispositions of capital assets, net of costs	65,261			1,627			218			35
Net cash used in investing activities	(531,877		)	(1,033,748		)	(134,164		)	(282,546		)
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility	310,000			75,000			85,000			175,000
Payments on Senior Secured Credit Facility	(475,000		)	—			(25,000		)	(475,000		)
Issuance of March 2023 Notes	350,000			—			—			350,000
Issuance of January 2022 Notes	—			450,000
Redemption of January 2019 Notes	(576,200		)	—
Proceeds from issuance of common stock, net of offering costs	754,163			—			—			754,163
Purchase of treasury stock	(2,749		)	(4,075		)	(1,412		)	(2,283		)
Proceeds from exercise of employee stock options	—			1,885
Payments for debt issuance costs	(6,759		)	(7,791		)	—			(6,427		)
Net cash provided by financing activities	353,455			515,019			58,588			795,453
Net increase (decrease) in cash and cash equivalents	47,082			(142,393		)
Net (decrease) increase in cash and cash equivalents							(19,059		)	539,772
Cash and cash equivalents, beginning of period	29,321			198,153			31,154			29,321
Cash and cash equivalents, end of period	$	76,403		$	55,760		$	12,095		$	569,093

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

The Company operates in two business segments, which are (i) exploration and production and (ii) midstream and marketing. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties primarily in the Permian Basin in West Texas. The midstream and marketing segment provides Laredo's exploration and production segment and ~~certain~~ third parties with ~~(i) any~~ 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 in and around Laredo's primary ~~drilling corridors and (ii) takeaway optionality in the field and firm service commitments to maximize Laredo's oil, NGL and natural gas revenues.~~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, ~~2014~~2015 is derived from audited consolidated financial statements. ~~See Notes 2.g, 5.g and 18 for discussion regarding the Company's early-adoption of new accounting guidance regarding the presentation of debt issuance costs.~~ 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, 2015,~~March 31, 2016, results of operations for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~ and cash flows for the ~~nine~~three months ended ~~September 30, 2015~~March 31, 2016 and ~~2014.~~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 ~~2014~~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) asset retirement obligations, (v) stock-based compensation, (vi) deferred income taxes, (vii) fair value of assets acquired and liabilities assumed in an acquisition and (viii) fair values of ~~commodity~~ derivatives, ~~commodity~~ deferred premiums and performance unit awards.

~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

As fair value is a market-based measurement, it is determined based on the assumptions that would be used by market ~~participants would use.~~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 believes its estimates and

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods.

c. Reclassifications

Certain amounts in the accompanying unaudited consolidated financial statements have been reclassified to conform to the ~~2015~~2016 presentation. These reclassifications had no impact to previously reported net ~~income or~~ loss, stockholders' equity or cash flows.

d. Accounts receivable

The Company sells produced and purchased oil, NGL and natural gas 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.

~~Amounts~~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 ~~consist~~consisted of the following components for the periods presented:


(in thousands)	September 30, 2015		December 31, 2014		March 31, 2016		December 31, 2015
Oil, NGL and natural gas sales	$	34,512	$	57,070	$	31,060	$	25,582
Joint operations, net⁽¹⁾	25,553		33,808		23,027		21,375
Matured derivatives	21,729		16,098		18,084		27,469
Purchased oil and other product sales	14,436		18,917
Sales of purchased oil and other products					12,324		11,775
Other	4,445		1,036		678		1,498
Total	$	100,675	$	126,929	$	85,173	$	87,699


(1)	Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.2 million ~~and $0.8 million~~ as of ~~September 30, 2015~~both March 31, 2016 and December 31, ~~2014, respectively.~~2015.

e. Derivatives

The Company uses derivatives to reduce exposure to fluctuations in the prices of oil and natural gas. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations in commodity prices. These transactions are in the form of puts, swaps, collars ~~swaps, puts~~ 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 Notes 8 and 9).~~parties. See Note 9 for discussion regarding the fair value of the Company's derivatives.

~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

The Company's derivatives were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the unaudited consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating ~~activities (see Note 8).~~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 ~~for~~as of the periods presented:


(in thousands)	September 30, 2015			December 31, 2014			March 31, 2016			December 31, 2015
Evaluated oil and natural gas properties	$	4,895,042		$	4,446,781		$	5,216,178		$	5,103,635
Less accumulated depletion and impairment	(3,180,822		)	(1,586,237		)	(4,417,833		)	(4,218,942		)
Evaluated oil and natural gas properties, net	1,714,220			2,860,544			798,345			884,693

Unevaluated properties not being amortized	225,045			342,731
Unevaluated properties not being depleted							116,905			140,299

Midstream service assets	149,068			117,052			148,112			147,811
Less accumulated depreciation	(14,057		)	(8,590		)	(18,105		)	(16,086		)
Midstream service assets, net	135,011			108,462			130,007			131,725

Depreciable other fixed assets	47,220			42,933			46,748			46,799
Less accumulated depreciation and amortization	(17,315		)	(13,820		)	(19,186		)	(18,169		)
Depreciable other fixed assets, net	29,905			29,113			27,562			28,630

Land	14,894			13,232			14,914			14,908

Total property and equipment, net	$	2,119,075		$	3,354,082		$	1,087,733		$	1,200,255

For the three months ended ~~September 30,~~March 31, 2016 and 2015, ~~and 2014,~~ depletion expense was $~~15.32~~9.00 per barrel of oil equivalent ("BOE") sold and ~~$20.25 per BOE sold, respectively. For the nine months ended September 30, 2015 and 2014, depletion expense was $15.87 per BOE sold and $19.83~~$16.08 per BOE sold, respectively.

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

The full cost ceiling is based principally on the estimated future net ~~cash flows~~revenues from proved oil and natural gas properties discounted at 10%. ~~Full cost~~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 ("~~SEC~~Benchmark Prices")~~, unless prices were defined by contractual arrangements,~~. 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 ~~revenues. In~~net revenues in the ~~event the unamortized~~full cost ~~of evaluated~~ceiling calculation.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

In the event the unamortized cost of evaluated oil and natural gas properties being ~~amortized~~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 ~~full cost ceiling value of~~following table presents the ~~Company's reserves was calculated based on SEC~~Benchmark Prices, ~~as of September 30, 2015, which do not include derivative transactions, of (i) $55.73 per barrel for oil, (ii) $21.87 per barrel for NGL~~Realized Prices and ~~(iii) $2.89 per MMBtu for natural gas, adjusted by area for energy content, transportation fees and regional price differentials. Using these SEC Prices,~~ the ~~Company's net book value of evaluated oil and natural gas properties exceeded the full cost ceiling amount as of September 30, 2015. As a result, the Company recorded a third-quarter~~corresponding non-cash full cost ceiling ~~impairment of $906.4 million.~~

~~As of June 30, 2015, the full cost ceiling value~~impairments recorded as of the Company's reserves was calculated based on SEC Prices as of June 30, 2015, which did not include derivative transactions, of (i) $68.17 per barrel for oil, (ii) $26.73 per barrel for NGL and (iii) $3.22 per MMBtu for natural gas, adjusted by area for energy content, transportation fees, and regional price differentials. Using these SEC Prices, the Company's net book value of evaluated oil and natural gas properties exceeded the full cost ceiling amount as of June 30, 2015. As a result, the Company recorded a second-quarter non-cash full cost ceiling impairment of $488.0 million.periods presented:



	For the quarters ended
	March 31, 2016		December 31, 2015		September 30, 2015		June 30, 2015		March 31, 2015
Benchmark Prices
Oil ($/Bbl)	$	42.77	$	46.79	$	55.73	$	68.17	$	79.21
NGL ($/Bbl)	$	17.51	$	18.75	$	21.87	$	26.73	$	31.25
Natural gas ($/MMBtu)	$	2.31	$	2.47	$	2.89	$	3.22	$	3.73
Realized Prices
Oil ($/Bbl)	$	41.33	$	45.58	$	54.28	$	66.68	$	77.72
NGL ($/Bbl)	$	11.25	$	12.50	$	15.25	$	19.56	$	23.75
Natural gas ($/Mcf)	$	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 ~~for the three and nine months ended September 30, 2015~~is included in the unaudited consolidated statements of operations was $906.4 million and $1.39 billion, respectively. The Company's net book value of evaluated oil and natural gas properties did not exceed the full cost ceiling amount at March 31, 2014, June 30, 2014 or September 30, 2014. The amounts are included in "Impairment expense" line item in the unaudited consolidated statements of operations and in ~~"Other operating costs and expenses"~~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.

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.

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 March 31,
(in thousands)	2016		2015
Inventory impairments:
Materials and supplies⁽¹⁾	$	—	$	767
Line-fill⁽²⁾	—		111
Total inventory impairments	$	—	$	878


(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~~$6.4 million of debt issuance costs during the ~~nine~~three months ended ~~September 30,~~March 31, 2015 mainly as a result of the issuance of the March 2023 Notes (as defined below). ~~The Company capitalized $7.8 million of~~No debt issuance costs ~~during~~were capitalized in the ~~nine~~three months ended ~~September 30, 2014 mainly as a result of the issuance of the January 2022 Notes (as defined below).~~March 31, 2016. The Company had total debt issuance costs of ~~$25.0~~$22.8 million and ~~$28.5~~$23.9 million, net of accumulated amortization of $~~15.9~~18.2 million and $~~19.4~~17.0 million, as of ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014,~~2015, respectively.

~~The Company wrote-off approximately $6.6 million of~~No debt issuance costs were written off during the ~~nine~~three months ended September 30, 2015 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. During the nine months ended September 30, 2014, the Company wrote-off approximately $0.1 million of debt issuance costs as a result of changes in the borrowing base of the Senior Secured Credit Facility (as defined below) due to the issuance of the January 2022 Notes, which are included in the unaudited consolidated statements of operations in the "Write-off of debt issuance costs" line item. See Notes 5.a, 5.b, 5.d and 5.e for definition of and information regarding the March ~~2023 Notes, January 2022 Notes, January 2019 Notes and the Senior Secured Credit Facility, respectively.~~

As of September 30, 2015, the Company has early-adopted new guidance that seeks to simplify the presentation of debt issuance costs and has applied its provisions retrospectively. The adoption of this standard resulted in the reclassification of $19.4 million and $21.8 million of unamortized31, 2016 or 2015. Unamortized debt issuance costs related to the Company's senior unsecured notes ~~from "Other assets, net" to~~are presented in "Long-term debt, net" ~~within its consolidated balance sheets as of September 30, 2015 and December 31, 2014, respectively. Other than this reclassification, the adoption of this standard did not have an impact~~ on the Company's unaudited consolidated ~~financial statements. Debt~~balance sheets. Unamortized debt issuance costs related to the Senior Secured Credit Facility ~~remain recorded~~are presented in "Other assets, net" on the Company's unaudited consolidated balance sheets. See Notes ~~5.g~~5.a and 185.e for definitions of and information regarding the March 2023 Notes and the Senior Secured Credit Facility, respectively. 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)	March 31, 2016
Remaining 2016	$	3,383
2017	4,575
2018	4,349
2019	2,915
2020	3,005
Thereafter	4,585
Total	$	22,812

i. Other current assets and liabilities

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



(in thousands)	March 31, 2016		December 31, 2015
Inventory⁽¹⁾	$	8,538	$	6,974
Prepaid expenses and other	8,258		7,600
Total other current assets	$	16,796	$	14,574


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

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

~~Future amortization expense of debt issuance costs as of September 30, 2015 is as follows:~~

(in thousands)
Remaining 2015
$ 1,116
2016
4,503
2017
4,575
2018
4,349
2019
2,915
Thereafter
7,589
Total
$ 25,047

~~h. Other current liabilities~~

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


(in thousands)	September 30, 2015		December 31, 2014		March 31, 2016		December 31, 2015
Capital contribution payable to equity method investee⁽¹⁾	$	34,322	$	—
Accrued interest payable	21,635		37,689		$	21,663	$	24,208
Costs of purchased oil payable	15,047		20,114		12,423		12,189
Lease operating expense payable	14,117		11,963		11,624		13,205
Accrued compensation and benefits					5,492		14,342
Capital contribution payable to equity method investee⁽¹⁾					923		27,583
Other accrued liabilities	27,083		31,266		10,628		14,695
Total other current liabilities	$	112,204	$	101,032	$	62,753	$	106,222


(1)	See Notes 14, 15 and ~~19.a~~19.b for additional discussion regarding our equity method investee.

i.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 asset retirement cost through depreciation, of the associated asset. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as corresponding accretion expense.

The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, which converts future cash flows into a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment cost per well based on Company experience, (ii) estimated remaining life per well, ~~based on the reserve life per well,~~ (iii) estimated removal and/or remediation costs for midstream 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 and gas gathering assets and perform other remediation of the sites where such pipeline and gas gathering assets are located upon the retirement of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. The Company will record an asset retirement obligation for pipeline and gas gathering assets in the periods in which settlement dates become reasonably determinable.

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



(in thousands)	Three months ended March 31, 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	107			2,236
Accretion expense	844			2,423
Liabilities settled upon plugging and abandonment	(194		)	(146		)
Liabilities removed due to sale of property	—			(2,005		)
Revision of estimates⁽¹⁾	—			11,600
Liability at end of period	$	47,063		$	46,306

(in thousands) Nine months ended September 30, 2015 Year ended December 31, 2014
Liability at beginning of period $ 32,198
$ 21,743
Liabilities added due to acquisitions, drilling, midstream service asset construction and other 1,675
6,370
Accretion expense 1,771
1,787
Liabilities settled upon plugging and abandonment (122 ) (450 )
Liabilities removed due to sale of property (2,005 ) —
Revision of estimates —
2,748
Liability at end of period $ 33,517
$ 32,198


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

~~j. 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.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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 ~~Notes 8 and~~Note 9 for details regarding the fair value of the Company's derivatives.

l. Treasury stock

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 value of service vesting restricted stock awards and a Black-Scholes pricing model to determine the fair values of service vesting restricted stock option awards. The Company utilizes a Monte Carlo simulation prepared by an independent third party to determine the fair values of the performance share awards and, 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.

~~m. Long-lived assets, materials and supplies and line-fill~~

Materials and supplies are used in developing oil and natural gas properties, are carried at the lower of cost or market ("LCM") 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 the Company's recent prices paid to acquire materials. During the nine months ended September 30, 2015, the Company reduced materials and supplies by $2.3 million in order to reflect the balance at LCM. The adjustment is included in "Impairment expense" in the unaudited consolidated statements of operations and in "Other operating costs and expenses" for the Company's exploration and production segment presented in Note 16. The Company determined an LCM adjustment was not necessary for materials and supplies during the three months ended September 30, 2015, or during the three and nine months ended September 30, 2014.

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. Beginning in the fourth quarter of 2014, the Company owns oil line-fill in third-party pipelines, which is accounted for at LCM with cost determined using the weighted-average cost method, and is included in "Other assets, net" on the unaudited consolidated balance sheets. The LCM adjustment is determined utilizing a quoted market price adjusted for regional price differentials (Level 2). For the three and nine months ended September 30, 2015, the Company recorded LCM adjustments of $0.4 million

~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

and $0.5 million, respectively, related to its line-fill, which is included in "Impairment expense" in the unaudited consolidated statements of operations and as "Other operating costs and expenses" for the Company's midstream and marketing segment presented in Note 16.

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, 2015~~March 31, 2016 or December 31, ~~2014.~~2015.

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,						Three months ended March 31,
(in thousands)	2015			2014			2016			2015
Non-cash investing information:
Change in accrued capital expenditures	$	(98,958	)	$	23,945		$	(18,215	)	$	(30,066	)
Change in accrued capital contribution to equity method investee⁽¹⁾	$	34,322		$	(2,598	)	$	(26,660	)	$	—
Capitalized asset retirement cost	$	1,675		$	4,767		$	107		$	515
Supplemental cash flow information:
Capitalized interest	$	227		$	51		$	39		$	98


(1)	See Notes 14, 15 and ~~19.a~~19.b for additional discussion regarding our equity method investee.

Note 3—2015 Equity offering

On March 5, 2015, the Company completed the sale of 69,000,000 shares of Laredo's common stock at a price to the public of $11.05 per share (the "March 2015 Equity Offering"). The Company received net proceeds of $754.2 million, after underwriting discounts, commissions and offering expenses. Entities affiliated with Warburg Pincus LLC ("Warburg Pincus") purchased 29,800,000 shares in the March 2015 Equity Offering, following which Warburg Pincus owned 41.0% of Laredo's common stock. There were no comparative offerings of ~~the Company's~~Laredo's common stock during the three ~~or nine~~ months ended ~~September 30, 2014.~~March 31, 2016.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note 4—~~Acquisitions~~Divestiture

a. 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 ~~sales~~purchase price of $65.5 million. After transaction costs ~~and adjustments at closing~~ reflecting an economic effective date of July 1, 2015, the net proceeds were ~~$65.2~~$64.8 million, net of working capital adjustments and ~~subject to~~ post-closing ~~cost~~ 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.

~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

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~~period presented:


	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2015		2014		2015		2014		Three months ended March 31, 2015
Oil, NGL and natural gas sales	$	1,371	$	5,644	$	5,419	$	15,574	$	2,078
Expenses⁽¹⁾	1,781		3,042		6,565		7,789		2,612


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

~~b. 2014 acquisition of leasehold interests~~

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

~~c. 2014 acquisition of mineral interests~~

~~On February 25, 2014, the Company completed the acquisition of the mineral interests underlying 278 net acres in Glasscock County, Texas in the Midland Basin for~~ ~~$7.3 million~~. These mineral interests entitle the Company to receive royalty payments on all production from this acreage with no additional future capital or operating expenses required. As such, the purchase was accounted for as an acquisition of assets.

~~d. 2014 acquisitions of evaluated and unevaluated oil and natural gas properties~~

The Company accounts for acquisitions of evaluated and unevaluated oil and natural gas properties under the acquisition method of accounting. Accordingly, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions are expensed as incurred.

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

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

Note 5—Debt

a. March 2023 Notes

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

~~Laredo Petroleum, Inc.~~

~~Condensed notes to~~ the ~~consolidated financial statements~~

~~(Unaudited)~~

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

The March 2023 Notes were offered and sold pursuant to a prospectus supplement dated March 4, 2015 and the base prospectus dated March 22, 2013, relating to the Company's effective shelf registration statement on Form S-3 (File No. 333-187479). The Company received net proceeds of $343.6 million from the offering, after deducting the underwriters' discount and the estimated outstanding offering expenses. In April 2015, the Company used the proceeds of the offering to fund a portion of the Company's redemption of the January 2019 Notes (as defined below). See Note 5.d for additional discussion of this early redemption.

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

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.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

d. January 2019 Notes

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

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, 2015,~~March 31, 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 of ~~$1.25~~$1.15 billion and an aggregate elected commitment of $1.0 billion with ~~$135.0~~$195.0 million outstanding and was subject to an interest rate of ~~1.7500%~~1.94%. It contains both financial and non-financial covenants, all of which the Company was in compliance with as of ~~September 30, 2015.~~March 31, 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

~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

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, 2015~~March 31, 2016 or ~~2014.~~2015.

See Note ~~19.b~~19.a for ~~information regarding~~discussion of additional borrowings on, and changes ~~subsequent~~ to ~~September 30, 2015, in~~the borrowing base and aggregate elected commitment under, the Senior Secured Credit ~~Facility's borrowing base.~~Facility subsequent to March 31, 2016.

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, 2015 December 31, 2014
(in thousands)
Carrying
value

Fair
value

Carrying
value

Fair
value
January 2019 Notes⁽¹⁾
$ —
$ —
$ 551,295
$ 550,000
January 2022 Notes 450,000
405,000
450,000
396,014
May 2022 Notes 500,000
487,500
500,000
467,529
March 2023 Notes 350,000
318,500
—
—
Senior Secured Credit Facility 135,000
134,981
300,000
300,279
Total value of debt $ 1,435,000
$ 1,345,981
$ 1,801,295
$ 1,713,822


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



	March 31, 2016				December 31, 2015
(in thousands)	Long-term debt		Fair value		Long-term debt		Fair value
January 2022 Notes	$	450,000	$	378,000	$	450,000	$	388,301
May 2022 Notes	500,000		432,500		500,000		460,000
March 2023 Notes	350,000		293,125		350,000		301,000
Senior Secured Credit Facility	195,000		194,946		135,000		134,993
Total value of debt	$	1,495,000	$	1,298,571	$	1,435,000	$	1,284,294

The fair values of the debt outstanding on the ~~January 2019 Notes,~~ January 2022 Notes, May 2022 Notes and the March 2023 Notes were determined using the ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014~~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, 2015~~March 31, 2016 and December 31, ~~2014~~2015 were estimated utilizing pricing models for similar instruments (Level 2). See Note 9 for information about fair value hierarchy levels.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

g. Debt issuance costs

The following ~~tables summarize~~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, 2015							December 31, 2014							March 31, 2016							December 31, 2015
(in thousands)	Carrying value		Debt issuance costs, net			Long-term debt, net		Carrying value		Debt issuance costs, net			Long-term debt, net		Long-term debt		Debt issuance costs, net			Long-term debt, net		Long-term debt		Debt issuance costs, net			Long-term debt, net
January 2019 Notes	$	—	$	—		$	—	$	551,295	$	(7,031	)	$	544,264
January 2022 Notes	450,000		(6,183		)	443,817		450,000		(6,916		)	443,084		$	450,000	$	(5,696	)	$	444,304	$	450,000	$	(5,939	)	$	444,061
May 2022 Notes	500,000		(7,281		)	492,719		500,000		(7,901		)	492,099		500,000		(6,847		)	493,153		500,000		(7,066		)	492,934
March 2023 Notes	350,000		(5,970		)	344,030		—		—			—		350,000		(5,567		)	344,433		350,000		(5,769		)	344,231
Senior Secured Credit Facility⁽¹⁾	135,000		—			135,000		300,000		—			300,000		195,000		—			195,000		135,000		—			135,000
Total	$	1,435,000	$	(19,434	)	$	1,415,566	$	1,801,295	$	(21,848	)	$	1,779,447	$	1,495,000	$	(18,110	)	$	1,476,890	$	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. The LTIP provides for the issuance of 10.0 million shares. On March 30, 2016, the Company's compensation committee recommended, and the Company's board of directors adopted, subject to stockholder approval, an amendment to the LTIP to, among other things, increase the number of shares of common stock available for issuance under the LTIP by 14,350,000 shares (the "Amendment"), enabling the continued use of the LTIP for share-based awards. The Company is seeking stockholder approval of the Amendment in connection with its 2016 Annual Meeting of Stockholders on May 25, 2016.

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

~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

accounted for as equity instruments, and in prior periods, its performance unit awards ~~are~~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 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. Restricted stock awards granted to officers and employees vest in a variety of vesting schedules including (i) ~~20%~~ ~~at the grant date and then~~ ~~20%~~ ~~annually thereafter, (ii)~~ 33%, 33% and 34% per year beginning on the first anniversary date of the grant, ~~(iii)~~(ii) 50% in year two and 50% in year three, ~~(iv)~~(iii) fully on the first anniversary of the grant date and ~~(v)~~(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~~three months ended ~~September 30, 2015:~~March 31, 2016:


(in thousands, except for weighted-average grant date fair values)	Restricted stock awards		Weighted-average grant date fair value (per award)		Restricted stock awards		Weighted-average grant date fair value (per award)
Outstanding as of December 31, 2014	2,205		$	22.63
Outstanding as of December 31, 2015					2,539		$	15.26
Granted	1,894		$	11.98	24		$	5.45
Forfeited	(519	)	$	20.90	(108	)	$	16.69
Vested⁽¹⁾	(984	)	$	22.39	(981	)	$	16.24
Outstanding as of September 30, 2015	2,596		$	15.32
Outstanding as of March 31, 2016					1,474		$	14.34


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

The Company utilizes the closing stock price on the grant date to determine the fair value of service vesting restricted stock awards. As of ~~September 30, 2015,~~March 31, 2016, unrecognized stock-based compensation related to the restricted stock awards expected to vest was ~~$26.4~~$16.6 million. Such cost is expected to be recognized over a weighted-average period of ~~1.90~~1.60 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~~three months ended ~~September 30, 2015:~~March 31, 2016:


(in thousands, except for weighted-average exercise price and contractual term)	Restricted stock option awards		Weighted-average exercise price (per option)		Weighted-average remaining contractual term (years)
Outstanding as of December 31, 2014	1,367		$	20.76	8.17
(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	632		$	11.93		—		$	—
Exercised	—		$	—		—		$	—
Expired or canceled	(58	)	$	19.51		(2	)	$	20.94
Forfeited	(139	)	$	18.17		(126	)	$	16.07
Outstanding as of September 30, 2015	1,802		$	17.90	8.05
Outstanding as of March 31, 2016						1,650		$	18.00	7.46
Vested and exercisable at end of period⁽¹⁾	569		$	20.78	6.89	955		$	19.55	6.86
Expected to vest at end of period⁽²⁾	1,214		$	16.49	8.60	685		$	15.76	8.31


(1)	The vested and exercisable options as of ~~September 30, 2015~~March 31, 2016 had no aggregate intrinsic value.


(2)	The restricted stock options expected to vest as of ~~September 30, 2015~~March 31, 2016 had no aggregate intrinsic value.

~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

The Company utilizes the Black-Scholes option pricing model to determine the fair value of restricted stock option awards and ~~is recognizing~~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, 2015,~~March 31, 2016, unrecognized stock-based compensation related to ~~the~~ restricted stock option awards expected to vest was ~~$8.0~~$5.4 million. Such cost is expected to be recognized over a weighted-average period of ~~2.51~~2.14 years.

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

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


~~(1)~~	~~U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, 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 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.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

c. Performance share awards

The performance share awards granted to management on February 27, 2015 (the "2015 Performance Share Awards") and on February 27, 2014 (the "2014 Performance Share Awards") are subject to a combination of market and service vesting criteria. A Monte Carlo simulation prepared by an independent third party was utilized 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 520,896 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. ~~During the nine months ended September 30, 2015, 602,501 2015 Performance Share Awards were granted and all remain outstanding as of September 30, 2015.~~ The ~~271,667~~232,118 outstanding 2014 Performance Share Awards have a performance period of

~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

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.

The following table reflects the performance share award activity for the three months ended March 31, 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	—		$	—
Forfeited	(121	)	$	20.25
Vested	—		$	—
Outstanding as of March 31, 2016	753		$	20.03

As of ~~September 30, 2015,~~March 31, 2016, unrecognized stock-based compensation related to the 2015 Performance Share Awards and the 2014 Performance Share Awards was ~~$11.4~~$7.3 million. Such cost is expected to be recognized over a weighted-average period of ~~2.09~~1.63 years.

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

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


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


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

d. Stock-based compensation award 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,				Three months ended March 31,
(in thousands)	2015		2014		2015		2014		2016		2015
Restricted stock award compensation, net of amounts capitalized	$	4,588	$	4,866	$	11,724	$	13,303	$	3,192	$	3,280
Restricted stock option award compensation, net of amounts capitalized	925		763		2,740		2,226		525		673
Restricted performance share award compensation, net of amounts capitalized	1,364		565		3,469		1,390		121		835
Total stock-based compensation, net of amounts capitalized	$	6,877	$	6,194	$	17,933	$	16,919	$	3,838	$	4,788

e. Performance unit awards

The performance unit awards issued to management on February 15, 2013 (the "2013 Performance Unit Awards") and on February 3, 2012 (the "2012 Performance Unit Awards") ~~are~~were subject to a combination of market and service vesting criteria. These awards ~~are~~were accounted for as liability awards as they ~~are~~were settled in cash at the end of the requisite service period based on the achievement of certain performance criteria. A Monte Carlo simulation prepared by an independent third party is utilized to determine the fair values of these awards at the grant date and to re-measure the fair values at the end of each reporting period until settlement in accordance with GAAP. The volatility criteria utilized in the Monte Carlo simulation is based on the volatility of the Company's stock price and the stock price volatilities of a group of peer companies defined in each respective award agreement. The liability and related compensation expense of these awards for each period is recognized by dividing the fair value of the total liability by the requisite service period and recording the pro rata share for the period for which service has already been provided. As there are inherent uncertainties related to these factors and the Company's judgment in applying them to the fair value determinations, there is risk that the recorded performance unit compensation may not accurately reflect the amount ultimately earned by the members of management.

The 44,481 ~~outstanding~~settled 2013 Performance Unit Awards ~~have~~had a performance period of January 1, 2013 to December 31, 2015 and, ~~are expected to be~~as their performance criteria were satisfied, they were paid inat $143.75 per unit during the first quarter of ~~2016 if the performance criteria are met.~~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~~$100.00 per unit during the first quarter of 2015.

~~Compensation~~For the three months ended March 31, 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

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

~~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,~~March 31, 2015, compensation expense for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2015 was $1.0 ~~million~~million.

f. 2016 contingent awards

On February 19, 2016, following the filing of the 2015 Annual Report, the Company's compensation committee approved contingent awards to employees for 2016. These contingent awards consist of restricted stock awards, stock option awards and ~~$2.7 million, respectively. Compensation expense related~~performance share awards (payable in the Company's common stock), in the aggregate amounts identified in the schedule set forth below. All of these contingent awards are conditional and subject to stockholder approval of the ~~2012 Performance Unit Awards and~~Amendment. If such stockholder approval is not obtained, the ~~2013 Performance Unit Awards amounted to a $0.4 million reversal and $0.8 million for the three and nine months ended September 30, 2014, respectively.~~following contingent awards will be canceled:



Contingent award type		Number of awards
Restricted stock⁽¹⁾		2,771,474
Stock options⁽²⁾		994,022
Performance shares⁽³⁾		1,790,067
Total		5,555,563


(1)	If stockholder approval of the Amendment is obtained, these restricted stock awards granted in 2016 will vest 33%, 33% and 34% per year beginning on February 19, 2017.


(2)	If stockholder approval of the Amendment is obtained, these stock option awards will (i) have an exercise price of $4.10 per share, (ii) have an expiration date of February 19, 2026 and (iii) vest and become exercisable on a time basis in four equal installments on each of the first four anniversaries beginning February 19, 2017.


(3)	If stockholder approval of the Amendment is obtained, these performance share awards will have a performance period of January 1, 2016 to December 31, 2018 and will be paid in the Company's common stock in the first quarter of 2019 if the performance criteria are met.

Note 7—Income taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carry-forwards. Under this method, deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income (loss) in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is determined 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.

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~~has no unrecognized tax benefits related to uncertain tax positions in the unaudited consolidated financial statements as of ~~September 30, 2015~~March 31, 2016 or December 31, ~~2014.~~2015.

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


	Three months ended September 30,						Nine months ended September 30,					Three months ended March 31,
(in thousands)	2015			2014			2015		2014			2016		2015
Current taxes	$	—		$	—		$	—	$	—		$	—	$	—
Deferred taxes	(41,258		)	(45,778		)	176,945		(35,511		)	—		(3,643		)
Income tax (expense) benefit	$	(41,258	)	$	(45,778	)	$	176,945	$	(35,511	)
Income tax expense												$	—	$	(3,643	)

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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


	Three months ended September 30,						Nine months ended September 30,						Three months ended March 31,
(in thousands)	2015			2014			2015			2014			2016			2015
Income tax benefit (expense) computed by applying the statutory rate	$	282,284		$	(45,215	)	$	497,782		$	(34,932	)	$	63,130		$	(1,110	)
State income tax, net of federal tax benefit and increase in valuation allowance	(5,677		)	247			190			1,881
State income tax and change in valuation allowance													728			91
Non-deductible stock-based compensation	(45		)	(152		)	(151		)	(391		)	—			(91		)
Stock-based compensation tax deficiency	(330		)	(4		)	(3,168		)	(160		)	(3,822		)	(2,457		)
Increase in deferred tax valuation allowance	(317,391		)	(22		)	(317,407		)	(1,134		)	(59,895		)	(5		)
Other items	(99		)	(632		)	(301		)	(775		)	(141		)	(71		)
Income tax (expense) benefit	$	(41,258	)	$	(45,778	)	$	176,945		$	(35,511	)
Income tax expense													$	—		$	(3,643	)

~~The~~For the three months ended March 31, 2016, the effective tax rate on loss before income taxes was not meaningful due to the valuation allowance recorded. For the three months ended March 31, 2015, the effective tax rate on income ~~(loss)~~ before income taxes was ~~35% for~~not meaningful due to the ~~three months ended 2014 and 36% for the nine months ended September 30, 2014.~~significant effect of discrete items on a relatively small amount of income. The Company's effective tax rate is affected by ~~recurring permanent differences,~~ 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. ~~For each~~

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 ~~three~~deferred tax assets and ~~nine~~adjusts the amount of such allowances, if necessary. During the year ended December 31, 2015 and the three months ended ~~September 30,~~March 31, 2016, in evaluating whether it was more likely than not that the Company's net deferred tax assets were realized through future net income, management considered all available positive and negative evidence, including (i) its earnings history, (ii) its ability to recover net operating loss carry-forwards, (iii) the existence of significant proved oil 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 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 ~~Company~~net deferred tax assets were not realizable, and therefore recorded a valuation allowance of $326.2 million for its deferred tax assets due to uncertainty regarding their realization. As such, the effective tax rates on the Company's loss before income taxes for the same periods are not meaningful. No comparable amounts were recorded in$676.0 million. During the three ~~and nine~~ months ended ~~September 30, 2014.~~March 31, 2016, an additional valuation allowance of $57.7 million was recorded.

~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

The impact of significant discrete items is separately recognized in the quarter in which ~~they~~the discrete items occur. The vesting of certain restricted stock awards could result in federal and state income tax expense or benefits related to the difference between the market price of the common stock at the date of vesting and the ~~date of grant.~~grant date. The exercise of stock option awards could result in federal and state income tax expense or benefits related to the difference between the fair value of the stock option onat the grant date and the intrinsic value of the stock option when exercised. The tax impact resulting from vestings of restricted stock awards and exercise of option awards are discrete items. During the three ~~and nine~~ months ended ~~September 30,~~March 31, 2016 and 2015, ~~and 2014,~~ certain shares related to restricted stock awards vested at times when the Company's stock price was lower than the fair value of those shares onat the ~~grant date.~~time of the grant. As a result, the income tax deduction related to such shares is less than the expense previously recognized for book purposes. During the three ~~and nine~~ months ended ~~September 30, 2014, certain~~March 31, 2016 and 2015, no restricted stock options were exercised, for which the related income tax deduction was less than the expense previously recognized for book purposes. There were no stock options exercised during the three and nine months ended September 30, 2015.exercised. In accordance with GAAP, such shortfalls reduce additional paid-in capital to the extent windfall tax benefits have been previously recognized. However, the Company has not previously recognized any windfall tax ~~benefits; therefore,~~benefits. Therefore, such shortfalls are included in income tax expense.

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


	Three months ended September 30,						Nine months ended September 30,						Three months ended March 31,
(in thousands)	2015			2014			2015			2014			2016			2015
Vesting of restricted stock	$	(336	)	$	(4	)	$	(3,225	)	$	(5	)	$	(3,875	)	$	(2,501	)
Exercise of restricted stock options	—			(1		)	—			(158		)	—			—
Tax expense due to shortfalls	$	(336	)	$	(5	)	$	(3,225	)	$	(163	)	$	(3,875	)	$	(2,501	)

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

(in thousands) September 30, 2015 December 31, 2014
Oil and natural gas properties, midstream service assets and other fixed assets $ (27,816 ) $ (424,712 )
Net operating loss carry-forward 462,324
353,724
Derivatives (107,862 ) (121,365 )
Stock-based compensation 11,051
10,718
Equity method investee (19,079 ) —
Accrued bonus 3,448
3,256
Capitalized interest 2,851
3,049
Other 2,628
(316 )
Net deferred tax asset (liability) before valuation allowance 327,545
(175,646 )
Valuation allowance (327,545 ) (1,299 )
Net deferred tax asset (liability) $ —
$ (176,945 )

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

(in thousands) September 30, 2015 December 31, 2014
Deferred tax asset $ 68,069
$ —
Deferred tax liability (68,069 ) (176,945 )
Deferred tax asset (liability) $ —
$ (176,945 )

~~The Company had federal net operating loss carry-forwards totaling~~ ~~$1.3 billion~~ ~~and state of Oklahoma net operating loss carry-forwards totaling~~ ~~$58.9 million~~ as of September 30, 2015. These carry-forwards begin expiring in 2026. As of September 30, 2015, the Company believes a portion of the net operating loss carry-forwards are not fully realizable. The Company considered all available evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance was needed. Such consideration included estimated future projected earnings based on existing reserves and projected future cash flows from its oil and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of September 30, 2015, the Company's ability to capitalize intangible drilling costs, rather than expensing these costs in order to prevent an operating loss carry-forward from expiring unused, and future projections of Oklahoma sourced income.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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



(in thousands)	March 31, 2016			December 31, 2015
Oil and natural gas properties, midstream service assets and other fixed assets	$	324,601		$	306,997
Net operating loss carry-forward	507,227			479,022
Derivatives	(82,908		)	(98,675		)
Stock-based compensation	7,530			11,597
Equity method investee	(27,728		)	(31,711		)
Accrued bonus	1,337			4,763
Capitalized interest	2,359			2,525
Other	2,593			2,820
Net deferred tax asset before valuation allowance	735,011			677,338
Valuation allowance	(735,011		)	(677,338		)
Net deferred tax asset	$	—		$	—

The ~~Company's~~Company had federal net operating loss carry-forwards totaling $1.4 billion and state of Oklahoma net operating loss carry-forwards totaling $40.9 million as of March 31, 2016. These carry-forwards begin expiring in 2026. Additionally, these carry-forwards include windfall tax deductions from vestings of certain restricted stock awards and stock option exercises that were not recorded in the Company's income tax provision. The amount of windfall tax benefit recognized in additional paid-in capital is limited to the amount of benefit realized currently in income taxes payable. As of ~~September 30, 2015,~~March 31, 2016, the Company had suspended additional paid-in capital credits of $4.5 million related to windfall tax deductions. Upon realization of the net operating loss carry-forwards from such windfall tax deductions, the Company would record a benefit of up to $4.5 million in additional paid-in capital.

~~The Company maintains a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. As of September 30, 2015, a valuation allowance of~~ ~~$327.5 million~~ ~~has been recorded against the deferred tax asset.~~

The Company's income tax returns for the years 2012 through ~~2014~~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. ~~Commodity derivatives~~Derivatives

The Company engages in derivative transactions such as puts, swaps, collars ~~swaps, puts~~ and, in prior periods, basis swaps to hedge price risks due to unfavorable changes in oil and natural gas prices related to its production. As of ~~September 30, 2015,~~March 31, 2016, the Company had 3721 open derivative contracts with financial institutions that extend from ~~October 2015~~April 2016 to December ~~2017.~~2018. None of these contracts were designated as hedges for accounting purposes. The contracts are recorded at fair value on the unaudited consolidated balance ~~sheet~~sheets and gains and losses are recognized in current period earnings. Gains and losses on derivatives are reported on the unaudited consolidated statements of operations inon 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.

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

~~Each swap transaction has an established fixed price. When~~In the ~~settlement price is below~~prior year, 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.

~~The~~ oil basis swap transactions ~~have~~had an established fixed basis differential. The Company's oil basis swaps' differential iswas between the West Texas Intermediate-Argus Americas Crude (Midland) ("WTI Midland") index crude

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

oil price and the West Texas Intermediate NYMEX ("WTI ~~NYMEX (defined below)~~NYMEX") index crude oil price. When the WTI NYMEX price less the fixed basis differential iswas greater than the actual WTI Midland price, the difference multiplied by the hedged contract volume iswas paid to the Company by the counterparty. When the WTI NYMEX price less the fixed basis differential iswas less than the actual WTI Midland price, the difference multiplied by the hedged contract volume iswas paid by the Company to the counterparty.

During the ~~first quarter of 2014,~~three months ended March 31, 2016, the Company ~~unwound~~successfully completed a ~~physical commodity contract and~~hedge restructuring by early terminating the ~~associated oil basis swap financial~~floors of certain derivative contract collars that ~~hedged~~resulted in a termination amount of $80 million, which was settled in full by applying the ~~differential between~~proceeds to prepay the ~~Light Louisiana Sweet Argus and~~premiums on two new derivatives entered into during the ~~Brent International Petroleum Exchange index oil prices. Prior to its unwind,~~restructuring.

During the ~~physical commodity contract qualified to be scoped out of mark-to-market accounting in accordance with~~three months ended March 31, 2016, the ~~normal purchase and normal sale scope exemption. Once modified to settle financially in~~following derivatives were terminated:



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

During the ~~unwind agreement,~~three months ended March 31, 2016, the ~~contract ceased to qualify~~following derivatives were entered into:



	Aggregate volumes	Floor price		Contract period
Oil (volumes in Bbl):
Put⁽¹⁾	2,263,000	$	60.00	January 2017 - December 2017
Put⁽²⁾	2,098,750	$	60.00	January 2017 - December 2018
Natural gas (volumes in MMBtu):⁽³⁾
Put	8,040,000	$	2.50	January 2017 - December 2017
Put	8,220,000	$	2.50	January 2018 - December 2018


(1)	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.


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


(3)	There are $4.3 million in deferred premiums associated with these contracts.

The following represents cash settlements received for derivatives, net for the normal purchase and normal sale scope exemption, therefore requiring it to be marked-to-market. The Company received net proceeds of $76.7 million from the early termination of these contracts. The Company agreed to settle the contracts early due to the counterparty's decision to exit the physical commodity trading business.periods presented:



	Three months ended March 31,
(in thousands)	2016		2015
Cash settlements received for matured derivatives, net	$	65,937	$	63,141
Cash settlements received for early terminations of derivatives, net⁽¹⁾	80,000		—
Cash settlements received for derivatives, net	$	145,937	$	63,141


(1)	The settlements amount for the three months ended March 31, 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 represents cash settlements received (paid) for derivatives for the periods presented:~~

Three months ended September 30, Nine months ended September 30,
(in thousands) 2015 2014 2015 2014
Cash settlements received (paid) for matured commodity derivatives $ 66,142
$ 4,531
$ 175,879
$ (1,320 )
Early terminations of commodity derivatives received —
—
—
76,660
Cash settlements received for derivatives, net $ 66,142
$ 4,531
$ 175,879
$ 75,340

The following table summarizes open positions as of ~~September 30, 2015,~~March 31, 2016, and represents, as of such date, derivatives in place through December ~~2017~~2018 on annual production volumes:


	Remaining Year 2015			Year 2016		Year 2017		Remaining Year 2016		Year 2017		Year 2018
Oil positions:⁽¹⁾
Puts:
Hedged volume (Bbl)	114,000			—		—		972,000		1,049,375		1,049,375
Weighted-average price ($/Bbl)	$	75.00		$	—	$	—	$	45.00	$	60.00	$	60.00
Swaps:
Hedged volume (Bbl)	168,000			1,573,800		—		1,182,500		—		—
Weighted-average price ($/Bbl)	$	96.56		$	84.82	$	—	$	84.82	$	—	$	—
Collars:
Hedged volume (Bbl)	1,641,880			3,654,000		2,628,000		2,743,750		2,628,000		—
Weighted-average floor price ($/Bbl)	$	79.81		$	73.99	$	77.22	$	73.99	$	60.00	$	—
Weighted-average ceiling price ($/Bbl)	$	95.41		$	89.63	$	97.22	$	89.63	$	97.22	$	—
Totals:
Total volume hedged with floor price (Bbl)								4,898,250		3,677,375		1,049,375
Weighted-average floor price ($/Bbl)								$	70.85	$	60.00	$	60.00
Total volume hedged with ceiling price (Bbl)	1,809,880			5,227,800		2,628,000		3,926,250		2,628,000		—
Weighted-average ceiling price ($/Bbl)	$	95.51		$	88.18	$	97.22	$	88.18	$	97.22	$	—
Total volume hedged with floor price (Bbl)	1,923,880			5,227,800		2,628,000
Weighted-average floor price ($/Bbl)	$	80.99		$	77.25	$	77.22
Basis swaps:⁽²⁾
Hedged volume (Bbl)	920,000			—		—
Weighted-average price ($/Bbl)	$	(1.95	)	$	—	$	—
Natural gas positions:⁽³⁾
Natural gas positions:⁽²⁾
Puts:
Hedged volume (MMBtu)								—		8,040,000		8,220,000
Weighted-average price ($/MMBtu)								$	—	$	2.50	$	2.50
Collars:
Hedged volume (MMBtu)	7,192,000			18,666,000		5,475,000		14,025,000		5,475,000		—
Weighted-average floor price ($/MMBtu)	$	3.00		$	3.00	$	3.00	$	3.00	$	3.00	$	—
Weighted-average ceiling price ($/MMBtu)	$	5.96		$	5.60	$	4.00	$	5.60	$	4.00	$	—
Totals:
Total volume hedged with floor price (MMBtu)								14,025,000		13,515,000		8,220,000
Weighted-average floor price ($/MMBtu)								$	3.00	$	2.70	$	2.50
Total volume hedged with ceiling price (MMBtu)								14,025,000		5,475,000		—
Weighted-average ceiling price ($/MMBtu)								$	5.60	$	4.00	$	—


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


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


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

b. Balance sheet presentation

In accordance with the Company's standard practice, its ~~commodity~~ derivatives are subject to counterparty netting under agreements governing such derivatives. The Company's oil and natural gas ~~commodity~~ derivatives are presented on a net

~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

basis as "Derivatives" on the unaudited consolidated balance sheets. See Note 9.a for a summary of the fair value of derivatives on a gross basis.

By using derivatives to hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. For the Company, market risk is the exposure to changes in the market price of oil and natural gas, which are subject to fluctuations from a variety of factors, including changes in supply and demand. Credit risk is the failure of the

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, thereby creating credit risk. The Company's counterparties are participants in the Senior Secured Credit Facility, which is secured by the Company's oil and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from its derivative counterparties. The Company minimizes the credit risk in derivatives by: (i) limiting its exposure to any single counterparty, (ii) entering into derivatives only with counterparties that meet the Company's minimum credit quality standard or have a guarantee from an affiliate that meets the Company's minimum credit quality standard and (iii) monitoring the creditworthiness of the Company's counterparties on an ongoing basis.

Note 9—Fair value measurements

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

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

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



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

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

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

When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on an annual basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. Transfers between fair value hierarchy levels are recognized and reported in the period in which the transfer occurred. No transfers between fair value hierarchy levels occurred during the three ~~or nine~~ months ended ~~September 30, 2015~~March 31, 2016 or ~~2014.~~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 ~~for~~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 consolidated balance sheets			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, 2015:
As of March 31, 2016:
Assets
Current:
Oil derivatives	$	—	$	180,141		$	—		$	180,141		$	(1,805	)	$	178,336		$	—	$	160,789	$	—		$	160,789		$	—		$	160,789
Natural gas derivatives	—		10,747			—			10,747			—			10,747			—		14,401		—			14,401			—			14,401
Oil deferred premiums	—		—			—			—			(4,751		)	(4,751		)	—		—		—			—			(7,736		)	(7,736		)
Natural gas deferred premiums	—		—			—			—			(175		)	(175		)	—		—		—			—			(660		)	(660		)
Noncurrent:
Oil derivatives	$	—	$	100,594		$	—		$	100,594		$	—		$	100,594		$	—	$	62,443	$	—		$	62,443		$	—		$	62,443
Natural gas derivatives	—		3,659			—			3,659			—			3,659			—		5,395		—			5,395			(3,345		)	2,050
Oil deferred premiums	—		—			—			—			(5,964		)	(5,964		)	—		—		—			—			(747		)	(747		)
Natural gas deferred premiums	—		—			—			—			(439		)	(439		)	—		—		—			—			(332		)	(332		)
Liabilities
Current:
Oil derivatives	$	—	$	(1,805	)	$	—		$	(1,805	)	$	1,805		$	—		$	—	$	—	$	—		$	—		$	—		$	—
Natural gas derivatives	—		—			—			—			—			—			—		—		—			—			—			—
Oil deferred premiums	—		—			(4,751		)	(4,751		)	4,751			—			—		—		(7,736		)	(7,736		)	7,736			—
Natural gas deferred premiums	—		—			(175		)	(175		)	175			—			—		—		(660		)	(660		)	660			—
Noncurrent:
Oil derivatives	$	—	$	—		$	—		$	—		$	—		$	—		$	—	$	—	$	—		$	—		$	—		$	—
Natural gas derivatives	—		—			—			—			—			—			—		—		—			—			3,345			3,345
Oil deferred premiums	—		—			(5,964		)	(5,964		)	5,964			—			—		—		(747		)	(747		)	747			—
Natural gas deferred premiums	—		—			(439		)	(439		)	439			—			—		—		(3,911		)	(3,911		)	332			(3,579		)
Net derivative position	$	—	$	293,336		$	(11,329	)	$	282,007		$	—		$	282,007		$	—	$	243,028	$	(13,054	)	$	229,974		$	—		$	229,974

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)


(in thousands)	Level 1		Level 2		Level 3			Total gross fair value			Amounts offset			Net fair value presented on the consolidated balance sheets			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, 2014:
As of December 31, 2015:
Assets
Current:
Oil derivatives	$	—	$	190,303	$	—		$	190,303		$	—		$	190,303		$	—	$	194,940	$	—		$	194,940		$	—		$	194,940
Natural gas derivatives	—		9,647		—			9,647			—			9,647			—		13,166		—			13,166			—			13,166
Oil deferred premiums	—		—		—			—			(4,653		)	(4,653		)	—		—		—			—			(9,301		)	(9,301		)
Natural gas deferred premiums	—		—		—			—			(696		)	(696		)	—		—		—			—			—			—
Noncurrent:
Oil derivatives	$	—	$	117,963	$	—		$	117,963		$	—		$	117,963		$	—	$	80,302	$	—		$	80,302		$	—		$	80,302
Natural gas derivatives	—		3,646		—			3,646			—			3,646			—		2,459		—			2,459			—			2,459
Oil deferred premiums	—		—		—			—			(3,821		)	(3,821		)	—		—		—			—			(4,877		)	(4,877		)
Natural gas deferred premiums	—		—		—			—			—			—			—		—		—			—			(441		)	(441		)
Liabilities
Current:
Oil derivatives	$	—	$	—	$	—		$	—		$	—		$	—		$	—	$	—	$	—		$	—		$	—		$	—
Natural gas derivatives	—		—		—			—			—			—			—		—		—			—			—			—
Oil deferred premiums	—		—		(4,768		)	(4,768		)	4,653			(115		)	—		—		(9,301		)	(9,301		)	9,301			—
Natural gas deferred premiums	—		—		(696		)	(696		)	696			—			—		—		—			—			—			—
Noncurrent:
Oil derivatives	$	—	$	—	$	—		$	—		$	—		$	—		$	—	$	—	$	—		$	—		$	—		$	—
Natural gas derivatives	—		—		—			—			—			—			—		—		—			—			—			—
Oil deferred premiums	—		—		(3,821		)	(3,821		)	3,821			—			—		—		(4,877		)	(4,877		)	4,877			—
Natural gas deferred premiums	—		—		—			—			—			—			—		—		(441		)	(441		)	441			—
Net derivative position	$	—	$	321,559	$	(9,285	)	$	312,274		$	—		$	312,274		$	—	$	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 ~~commodity~~ derivatives include each derivative contract's corresponding commodity index price, appropriate risk-adjusted discount rates and other relevant data.

The Company's deferred premiums associated with its ~~commodity~~ derivative contracts are categorized as Level 3, as the Company utilizes a net present value calculation to determine the valuation. They are considered to be measured on a recurring basis as the derivative contracts they derive from are measured on a recurring basis. As ~~commodity~~ derivative contracts containing deferred premiums are entered into, the Company discounts the associated deferred premium to its net present value at the contract trade date, using the Senior Secured Credit Facility rate at the trade date (historical input rates range from 1.69% to 3.56%), and then records the change in net present value to interest expense over the period from trade until the final settlement date at the end of the contract. After this initial valuation, the net present value of each deferred premium is not adjusted; therefore, significant increases (decreases) in the Senior Secured Credit Facility rate would result in a significantly lower (higher) fair value measurement for each new contract entered into that contained a deferred premium; however, the valuation for the deferred premiums already recorded would remain unaffected. While the Company believes the sources utilized to arrive at the fair value estimates are reliable, different sources or methods could have yielded different fair value estimates; therefore, on a quarterly basis, the valuation is compared to counterparty valuations and a third-party valuation of the deferred premiums for reasonableness.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table presents actual cash payments required for deferred premiums ~~as of September 30, 2015, and~~ for the calendar years ~~following:~~presented:


(in thousands)			March 31, 2016
Remaining 2015	$	1,249
2016	4,471
Remaining 2016			$	6,779
2017	5,418		4,397
2018	426		2,100
Total	$	11,564	$	13,276

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



	Three months ended March 31,
(in thousands)	2016			2015
Balance of Level 3 at beginning of period	$	(14,619	)	$	(9,285	)
Change in net present value of deferred premiums for derivatives	(72		)	(43		)
Total purchases and settlements:
Purchases	(4,112		)	(975		)
Settlements⁽¹⁾	5,749			1,421
Balance of Level 3 at end of period	$	(13,054	)	$	(8,882	)


(1)	The amount for the three months ended March 31, 2016 includes $3.9 million which represents the present value of deferred premiums settled in the Company's restructuring upon their early termination.

Three months ended September 30, Nine months ended September 30,
(in thousands)
2015 2014 2015 2014
Balance of Level 3 at beginning of period
$ (12,087 ) $ (9,025 ) $ (9,285 )
$ (12,684 )
Change in net present value of deferred premiums for derivatives
(53 ) (50 ) (141 )
(170 )
Total purchases and settlements:

Purchases
(437 ) (3,800 ) (5,821 )
(3,800 )
Settlements
1,248
1,820
3,918

5,599
Balance of Level 3 at end of period
$ (11,329 ) $ (11,055 ) $ (11,329 )
$ (11,055 )

b. Fair value measurement on a nonrecurring basis

The Company accounts for the impairment of long-lived assets, if any, at fair value on a nonrecurring basis. For purposes of fair value measurement, it was determined that the impairment of long-lived assets is classified as Level 3, based on the use of internally developed cash flow models. See Note ~~2.m~~2.g for discussion regarding the Company's ~~impairment of line-fill during the three months ended September 30, 2015 and~~ impairments of materials and supplies and line-fill ~~during~~for the ~~nine~~three months ended ~~September 30,~~March 31, 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 and the Company's ~~second and third-quarter~~first-quarter 2016 full cost ceiling ~~impairments.~~impairment.

Note 10—Net loss per share

Basic net loss per share is computed by dividing net loss by the weighted-average number of common shares outstanding for the period. Diluted net loss per share reflects the potential dilution of non-vested restricted stock awards, performance share awards and outstanding restricted stock options. For the three months ended March 31, 2016 and 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 following is the calculation of basic and diluted weighted-average common shares outstanding and net loss per share for the periods presented:



	Three months ended March 31,
(in thousands, except for per share data)	2016			2015
Net loss (numerator):
Net loss—basic and diluted	$	(180,371	)	$	(472	)
Weighted-average common shares outstanding (denominator):
Basic	211,560			162,426
Diluted	211,560			162,426
Net loss per share:
Basic	$	(0.85	)	$	—
Diluted	$	(0.85	)	$	—

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note ~~10—~~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 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 ~~11—~~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 contracts

The Company has committed to drilling contracts with various third parties to complete its various drilling projects. The contracts contain early termination clauses that require the Company to potentially pay penalties to ~~the~~ third parties should the Company cease drilling efforts. These penalties would negatively impact the Company's financial statements upon early contract termination, especially if a significant number of such contracts were terminated early in their respective terms. In the fourth quarter of 2014, the Company announced a reduced 2015 capital expenditure budget compared to 2014. As a result, the Company began releasing rigs as drilling contracts came close to expiration and incurred charges of $0.5 million in the fourth quarter of 2014. No comparable amounts were recorded in the three and nine months ended September 30, 2015 or 2014. Future commitments of ~~$18.4~~$3.5 million as of ~~September 30, 2015~~March 31, 2016 are not recorded in the accompanying unaudited consolidated balance sheets. Management does not currently anticipate the early termination of any existing contracts in ~~2015~~2016 that would result in a substantial penalty.

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 minimal volume penalties. These commitments are normal and customary for the Company's business. Future commitments of $411.8 million as of March 31, 2016 are not recorded in the accompanying unaudited consolidated balance sheets. The Company's production has been equivalent or greater than its delivery commitments during the most recent year, and management expects such production will continue to exceed the Company's future commitments. However, 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.

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.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

e. Other commitments

See Notes ~~2.h,~~2.i, 15.a and ~~19.a~~19.b for the amount of and discussion regarding the commitments to the Company's non-consolidated variable interest entity ("VIE").

Note ~~12—~~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 infrom 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~~three months ended ~~September 30,~~March 31, 2015 related to the RIF.

~~Note 13—Net income (loss) per share~~

Basic net income (loss) per 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 share reflects the potential dilution of non-vested restricted stock awards, performance share awards and outstanding restricted stock options. For There were no comparative amounts recorded in 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 income (loss) per share.~~March 31, 2016.

For the three and nine months ended September 30, 2014, the Performance Share Awards' total shareholder return was below their agreement's payout threshold, and therefore the Performance Share Awards were excluded from the calculation of diluted net income per share. The effects of the Company's then outstanding (i) restricted stock options that were granted in February 2014 to purchase 336,140 shares of common stock at $25.60 per share and (ii) restricted stock options that were granted in February 2012 to purchase 306,177 shares of common stock at $24.11 per share (the "February 2012 Option Grant"), were excluded from the calculation of diluted net income per share for the three and nine months ended September 30, 2014 because the exercise price of those options was greater than the average market price during the period, and therefore the inclusion of these outstanding options would have been anti-dilutive.

~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

~~The following is the calculation of basic and diluted weighted-average common shares outstanding and net 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) 2015 2014 2015 2014
Net income (loss) (numerator):

Net income (loss)—basic and diluted $ (847,783 ) $ 83,407
$ (1,245,289 ) $ 64,295
Weighted-average common shares outstanding (denominator)⁽¹⁾:

Basic 211,204

141,413
195,081
141,261
Non-vested restricted stock awards —
2,334
—
2,246
Outstanding restricted stock options⁽²⁾
—
66
—
76
Diluted 211,204

143,813
195,081
143,583
Net income (loss) per share:
Basic $ (4.01 ) $ 0.59
$ (6.38 ) $ 0.46
Diluted $ (4.01 ) $ 0.58
$ (6.38 ) $ 0.45


~~(1)~~	For the three and nine months ended September 30, 2015, weighted-average common shares outstanding used in the computation of basic and diluted net loss per share attributable to stockholders has been computed taking into account the March 2015 Equity Offering.


~~(2)~~	For the three and nine months ended September 30, 2014, the dilutive effect of the Company's then outstanding options that were granted in February 2013 to purchase 780,281 shares of common stock at $17.34 per share was calculated utilizing the treasury stock method.

Note 14—Variable interest entity

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

LMS contributed ~~$48.5~~$26.7 million and ~~$63.0~~$14.5 million during the three ~~and nine~~ months ended ~~September 30,~~March 31, 2016 and 2015, ~~respectively, and $18.1 million and $37.6 million during the three and nine months ended September 30, 2014,~~ respectively, to Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, and its wholly-owned subsidiaries (together "Medallion"). See Note ~~19.a~~19.b for discussion onregarding a contribution made to Medallion subsequent to ~~September 30,~~March 31, 2016. All LMS cash contributions made during the three months ended March 31, 2016 were for commitments that were fully accrued for in the Company's audited consolidated financial statements at December 31, 2015.

LMS holds 49% of ~~Medallion~~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 (loss) reflected in the unaudited consolidated statements of operations as "Income (loss) from equity method investee" and the carrying amount reflected in the unaudited consolidated balance sheets as "Investment in equity method investee."

~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

During the ~~nine~~three months ended ~~September 30, 2015,~~March 31, 2016, Medallion continued expansion activities on existing portions of its pipeline infrastructure in order to gather and transport additional third-party oil ~~production and began recognizing revenue due to its main pipeline becoming fully operational.~~production. 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

Laredo Petroleum, Inc.

Condensed notes to the ~~Company's minimum volume commitment for future periods was $3.0 million and is included in the unaudited~~ consolidated financial statements ~~of operations in the line item "Minimum volume commitments" for the period in which the buyout was settled.~~

(Unaudited)

Note 15—Related Parties

a. Medallion

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


	Three months ended September 30,				Nine months ended September 30,				Three months ended March 31,
(in thousands)	2015		2014		2015		2014		2016		2015
Midstream service revenues	$	—	$	—	$	487	$	—	$	—	$	97
Minimum volume commitments	—		675		5,235		1,779		—		1,656
Interest and other income	50		—		158		—		—		108

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

(in thousands) September 30, 2015 December 31, 2014
Other assets, net $ 1,269
$ 1,110
Other current liabilities 34,322
3,443

Amounts included in "Other assets, net" above represent LMS owned line-fill in Medallion's pipeline and amounts included in "Other current liabilities" above represent LMS's capital contribution payable to Medallion, of which a portion was paid subsequent to September 30, 2015. See Note 14 for additional discussion of Medallion and Note 19.a for additional discussionas of the ~~subsequent payment to Medallion.~~dates presented:



(in thousands)	March 31, 2016		December 31, 2015
Accounts receivable, net	$	—	$	1,163
Other assets, net⁽¹⁾	1,025		1,025
Other current liabilities⁽²⁾	923		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' capital contribution payable to Medallion. See Note 14 for additional discussion of Medallion and Note 19.b for additional discussion of the subsequent payment to Medallion.

b. Targa Resources Corp.

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

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


	Three months ended September 30,				Nine months ended September 30,				Three months ended March 31,
(in thousands)	2015		2014		2015		2014		2016		2015
Oil, NGL and natural gas sales	$	23,540	$	24,148	$	77,183	$	70,624	$	17,805	$	19,631
Midstream service revenues									135		—

The following table summarizes the amounts included in ~~oil, NGL and natural gas sales~~accounts receivable, net from Targa in the unaudited consolidated balance sheets as of the dates presented:



(in thousands)	March 31, 2016		December 31, 2015
Accounts receivable, net	$	7,877	$	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 March 31,
(in thousands)	September 30, 2015		December 31, 2014		2016		2015
Accounts receivable, net	$	7,138	$	12,869
Lease operating expenses					$	475	$	385

~~Note 16—Segments~~

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

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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 March 31,
(in thousands)	2016		2015
Capital expenditures:
Midstream service assets	$	20	$	46

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)	March 31, 2016		December 31, 2015
Accounts payable	$	18	$	13

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 March 31,
(in thousands)	2016		2015
Capital expenditures:
Oil and natural gas properties	$	—	$	2,257

Note 16—Segments

The Company operates in two business segments, which are (i) exploration and production and (ii) midstream and marketing. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas ~~properties.~~properties primarily in the Permian Basin in West Texas. The midstream and marketing segment provides Laredo's exploration and production segment and ~~certain~~ third parties with ~~(i) any~~ 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 in and around Laredo's primary ~~drilling corridors and (ii) takeaway optionality in the field and firm service commitments to maximize Laredo's oil, NGL and natural gas revenues.~~production corridors.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following ~~tables present~~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 ~~periods presented:~~Company on a consolidated basis:


(in thousands)	Exploration and production			Midstream and marketing			Eliminations			Consolidated company			Exploration and production			Midstream and marketing			Eliminations			Consolidated company
Three months ended September 30, 2015:
Three months ended March 31, 2016:
Oil, NGL and natural gas sales	$	105,025		$	753		$	(1,171	)	$	104,607		$	73,142		$	—		$	—		$	73,142
Midstream service revenues	—			7,917			(6,044		)	1,873			—			11,267			(9,466		)	1,801
Sales of purchased oil	—			43,860			—			43,860			—			31,614			—			31,614
Total revenues	105,025			52,530			(7,215		)	150,340			73,142			42,881			(9,466		)	106,557
Lease operating expenses, including production tax	35,531			—			(2,524		)	33,007
Lease operating expense, including production tax													29,364			—			(2,411		)	26,953
Midstream service expenses	—			5,240			(4,148		)	1,092			—			6,509			(5,900		)	609
Costs of purchased oil	—			46,961			—			46,961			—			32,946			—			32,946
General and administrative⁽¹⁾	20,713			2,200			—			22,913			17,679			1,772			—			19,451
Depletion, depreciation and amortization⁽²⁾	64,664			2,113			—			66,777			39,292			2,186			—			41,478
Impairment expense													161,064			—			—			161,064
Other operating costs and expenses⁽³⁾	906,968			481			—			907,449			792			52			—			844
Operating loss	$	(922,851	)	$	(4,465	)	$	(543	)	$	(927,859	)	$	(175,049	)	$	(584	)	$	(1,155	)	$	(176,788	)
Other financial information:
Income from equity method investee	$	—		$	2,104		$	—		$	2,104		$	—		$	2,298		$	—		$	2,298
Interest expense⁽⁴⁾	$	(22,030	)	$	(1,318	)	$	—		$	(23,348	)	$	(22,303	)	$	(1,402	)	$	—		$	(23,705	)
Capital expenditures	$	(117,962	)	$	(979	)	$	—		$	(118,941	)	$	(105,785	)	$	(1,937	)	$	—		$	(107,722	)
Gross property and equipment⁽⁵⁾	$	5,178,245		$	314,138		$	(908	)	$	5,491,475		$	5,392,865		$	347,892		$	(3,078	)	$	5,737,679
Three months ended September 30, 2014:
Three months ended March 31, 2015:
Oil, NGL and natural gas sales	$	199,968		$	619		$	(1,097	)	$	199,490		$	118,211		$	112		$	(205	)	$	118,118
Midstream service revenues	—			1,875			(1,124		)	751			—			3,683			(2,374		)	1,309
Sales of purchased oil													—			31,267			—			31,267
Total revenues	199,968			2,494			(2,221		)	200,241			118,211			35,062			(2,579		)	150,694
Lease operating expenses, including production tax	39,218			—			(1,503		)	37,715
Midstream service expenses, including minimum volume commitments	—			2,519			(619		)	1,900
Lease operating expense, including production tax													43,845			—			(2,379		)	41,466
Midstream service expenses													—			3,342			(112		)	3,230
Costs of purchased oil													—			31,200			—			31,200
General and administrative⁽¹⁾	25,145			1,933			—			27,078			19,778			2,077			—			21,855
Depletion, depreciation and amortization⁽²⁾	62,298			1,644			—			63,942			70,257			1,685			—			71,942
Impairment expense													767			111			—			878
Other operating costs and expenses⁽³⁾	414			28			—			442			6,424			197			—			6,621
Operating income (loss)	$	72,893		$	(3,630	)	$	(99	)	$	69,164
Operating loss													$	(22,860	)	$	(3,550	)	$	(88	)	$	(26,498	)
Other financial information:
Loss from equity method investee	$	—		$	(61	)	$	—		$	(61	)	$	—		$	(433	)	$	—		$	(433	)
Interest expense⁽⁴⁾	$	(29,584	)	$	(965	)	$	—		$	(30,549	)	$	(31,087	)	$	(1,327	)	$	—		$	(32,414	)
Capital expenditures	$	(518,388	)	$	(19,052	)	$	—		$	(537,440	)	$	(247,613	)	$	(20,473	)	$	—		$	(268,086	)
Gross property and equipment⁽⁵⁾	$	4,489,599		$	146,483		$	(99	)	$	4,635,983		$	5,057,149		$	216,345		$	(321	)	$	5,273,173

(1)

General and administrative costs were allocated based on the number of employees in the respective segment ~~as of September 30, 2015~~for the three months ended March 31, 2016 and ~~2014. However, payroll, deferred compensation, vehicle costs and the capitalization of payroll and deferred compensation associated with land and geology, which are~~2015. Certain components of general and administrative ~~are~~costs were not allocated and were based on actual costs for each segment, which primarily consisted of payroll, deferred compensation and vehicle costs for the three months ended ~~September 30, 2015~~March 31, 2016 and ~~2014.~~2015. Costs associated with land and geology were not allocated to the midstream and marketing segment for the three months ended March 31, 2016 and 2015.


(2)	Depletion, depreciation and amortization iswere based on actual costs 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, 2015~~for the three months ended March 31, 2016 and ~~2014.~~2015.

(3)

~~Includes~~Other operating costs and expenses includes accretion of asset retirement obligations ~~and impairments~~ for the three months ended ~~September 30, 2015~~March 31, 2016 and restructuring expense and accretion of asset retirement obligations for the three months ended ~~September 30, 2014.~~March 31, 2015. These expenses are based on actual costs and are not allocated. ~~See Notes 2.f and 2.m for discussion of the Company's impairments.~~

(4)

Interest expense iswas allocated to the exploration and production segment based on gross property and equipment for the three months ended March 31, 2016 and 2015 and allocated to the midstream and marketing segment based on gross property and equipment and ~~total~~life-to-date contributions to the Company's equity method investee ~~as of September 30, 2015~~for the three months ended March 31, 2016 and ~~2014.~~2015.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

(5)

Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling ~~$160.2~~$194.8 million and ~~$40.8~~$72.4 million as of ~~September 30,~~March 31, 2016 and 2015, ~~and 2014,~~ respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of ~~September 30, 2015~~March 31, 2016 and ~~2014.~~

2015.

~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

(in thousands) Exploration and production Midstream and marketing Eliminations Consolidated
company
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 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
Other operating costs and expenses⁽³⁾
1,404,306

834

—
1,405,140
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⁽⁴⁾
$ (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
Nine months ended September 30, 2014:
Oil, NGL and natural gas sales $ 556,054
$ 619
$ (1,097 ) $ 555,576
Midstream service revenues —
4,447
(3,428 ) 1,019
Total revenues 556,054
5,066
(4,525 ) 556,595
Lease operating expenses, including production tax 109,096
—
(3,807 ) 105,289
Midstream service expenses, including minimum volume commitments —
5,994
(619 ) 5,375
General and administrative⁽¹⁾
79,203
5,081
—
84,284
Depletion, depreciation and amortization⁽²⁾
163,527
3,078
—
166,605
Other operating costs and expenses⁽³⁾
1,251
28
—
1,279
Operating income (loss) $ 202,977
$ (9,115 ) $ (99 ) $ 193,763
Other financial information:
Loss from equity method investee $ —
$ (86 ) $ —
$ (86 )
Interest expense⁽⁴⁾
$ (87,687 ) $ (2,505 ) $ —
$ (90,192 )
Capital expenditures⁽⁵⁾
$ (938,719 ) $ (45,277 ) $ —
$ (983,996 )
Gross property and equipment⁽⁶⁾
$ 4,489,599
$ 146,483
$ (99 ) $ 4,635,983

~~(1)~~

General and administrative costs were allocated based on the number of employees in the respective segment as of September 30, 2015 and 2014. However, payroll, deferred compensation, vehicle costs and the capitalization of payroll and deferred compensation associated with land and geology, which are components of general and administrative, are based on actual costs for each segment for the nine months ended September 30, 2015 and 2014.


~~(2)~~	Depletion, depreciation and amortization is based on actual costs for each segment with the exception of the allocation of other fixed assets, which is based on the number of employees in the respective segment as of September 30, 2015 and 2014.


~~(3)~~	Includes accretion of asset retirement obligations and impairments for the nine months ended September 30, 2015 and accretion of asset retirement obligations for the nine months ended September 30, 2014. These expenses are based on actual costs and are not allocated. See Notes 2.f and 2.m for discussion of the Company's impairments.


~~(4)~~	Interest expense and loss on early redemption of debt are allocated based on gross property and equipment and total contributions to the Company's equity method investee as of September 30, 2015 and 2014.


~~(5)~~	~~Capital expenditures excludes acquisition of mineral interests and acquisition of oil and natural gas properties for the nine months ended September 30, 2014.~~


~~(6)~~	Gross property and equipment includes investment in equity method investee totaling $160.2 million and $40.8 million as of September 30, 2015 and 2014, respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of September 30, 2015 and 2014.

~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

Note 17—Subsidiary ~~guarantees~~guarantors

~~Laredo and the~~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, 2015~~March 31, 2016 and December 31, ~~2014,~~2015, and unaudited condensed consolidating statements of operations ~~for the three and nine months ended September 30, 2015 and 2014~~ and unaudited condensed consolidating statements of cash flows for the ~~nine~~three months ended ~~September 30,~~March 31, 2016 and 2015, ~~and 2014~~ present financial information for Laredo on a stand-alone basis (carrying any investment in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in subsidiaries under the equity method), and the consolidation and elimination entries necessary to arrive at the information for the Company on a condensed consolidated basis. Deferred income taxes for LMS and for GCM are recorded on Laredo's statements of financial position, statements of operations and statements of cash flows as they are disregarded entities for income tax purposes. Laredo and the Guarantors are not restricted from making intercompany distributions to each other. During the three months ended March 31, 2016, certain assets were transferred from LMS to Laredo at historical cost. See Note 5.d for a discussion of the early redemption of the January 2019 Notes.

Condensed consolidating balance sheet

~~September 30, 2015~~March 31, 2016

(Unaudited)


(in thousands)	Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company		Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable, net	$	84,918	$	15,757	$	—		$	100,675	$	72,730		$	12,443	$	—		$	85,173
Other current assets	274,460		307		—			274,767		194,176			1,509		—			195,685
Total oil and natural gas properties, net	1,930,771		9,402		(908		)	1,939,265		908,987			9,341		(3,078		)	915,250
Total midstream service assets, net	—		135,011		—			135,011		—			130,007		—			130,007
Total other fixed assets, net	44,444		355		—			44,799		42,187			289		—			42,476
Investment in subsidiaries and equity method investee	267,498		160,206		(267,498		)	160,206		331,788			194,822		(331,788		)	194,822
Total other long-term assets	173,277		4,495		—			177,772		69,899			3,852		—			73,751
Total assets	$	2,775,368	$	325,533	$	(268,406	)	$	2,832,495	$	1,619,767		$	352,263	$	(334,866	)	$	1,637,164

Accounts payable	$	23,049	$	598	$	—		$	23,647	$	22,826		$	556	$	—		$	23,382
Other current liabilities	213,178		54,724		—			267,902		115,620			17,072		—			132,692
Long-term debt, net	1,415,566		—		—			1,415,566		1,476,890			—		—			1,476,890
Other long-term liabilities	33,985		2,713		—			36,698		47,069			2,847		—			49,916
Stockholders' equity	1,089,590		267,498		(268,406		)	1,088,682
Total liabilities and stockholders' equity	$	2,775,368	$	325,533	$	(268,406	)	$	2,832,495
Stockholders' (deficit) equity										(42,638		)	331,788		(334,866		)	(45,716		)
Total liabilities and stockholders' (deficit) equity										$	1,619,767		$	352,263	$	(334,866	)	$	1,637,164

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating balance sheet

December 31, ~~2014~~2015

(Unaudited)


(in thousands)	Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company		Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable, net	$	107,860	$	19,069	$	—		$	126,929	$	74,613	$	13,086	$	—		$	87,699
Other current assets	238,300		24		—			238,324		244,477		56		—			244,533
Total oil and natural gas properties, net	3,196,231		7,277		(233		)	3,203,275		1,017,565		9,350		(1,923		)	1,024,992
Total midstream service assets, net	—		108,462		—			108,462		—		131,725		—			131,725
Total other fixed assets, net	42,046		299		—			42,345		43,210		328		—			43,538
Investment in subsidiaries and equity method investee	163,349		58,288		(163,349		)	58,288		301,891		192,524		(301,891		)	192,524
Total other long-term assets	128,582		4,496		—			133,078		84,360		3,916		—			88,276
Total assets	$	3,876,368	$	197,915	$	(163,582	)	$	3,910,701	$	1,766,116	$	350,985	$	(303,814	)	$	1,813,287

Accounts payable	$	38,453	$	555	$	—		$	39,008	$	12,203	$	1,978	$	—		$	14,181
Other current liabilities	354,217		31,800		—			386,017		158,283		44,351		—			202,634
Long-term debt, net	1,779,447		—		—			1,779,447		1,416,226		—		—			1,416,226
Other long-term liabilities	140,817		2,211		—			143,028		46,034		2,765		—			48,799
Stockholders' equity	1,563,434		163,349		(163,582		)	1,563,201		133,370		301,891		(303,814		)	131,447
Total liabilities and stockholders' equity	$	3,876,368	$	197,915	$	(163,582	)	$	3,910,701	$	1,766,116	$	350,985	$	(303,814	)	$	1,813,287

Condensed consolidating statement of operations

For the three months ended ~~September 30, 2015~~March 31, 2016

(Unaudited)

(in thousands)
Laredo
Subsidiary Guarantors
Intercompany
eliminations

Consolidated
company
Total operating revenues
$ 104,920

$ 52,635

$ (7,215 )
$ 150,340
Total operating 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 taxes
(805,982 )
(80 )
(463 )
(806,525 )
Deferred income tax expense
(41,258 )
—

—

(41,258 )
Net loss
$ (847,240 )
$ (80 )
$ (463 )
$ (847,783 )



(in thousands)	Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Total revenues	$	73,122		$	42,901	$	(9,466	)	$	106,557
Total costs and expenses	250,064			41,592		(8,311		)	283,345
Operating income (loss)	(176,942		)	1,309		(1,155		)	(176,788		)
Interest expense and other, net	(23,606		)	—		—			(23,606		)
Other non-operating income	21,332			2,291		(3,600		)	20,023
Income (loss) before income tax	(179,216		)	3,600		(4,755		)	(180,371		)
Income tax	—			—		—			—
Net income (loss)	$	(179,216	)	$	3,600	$	(4,755	)	$	(180,371	)

~~Condensed consolidating statement of operations~~

~~For the nine months ended September 30, 2015~~

~~(Unaudited)~~

(in thousands) Laredo Subsidiary Guarantors Intercompany
eliminations Consolidated
company
Total operating revenues $ 348,753
$ 147,388
$ (12,776 ) $ 483,365
Total operating 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 taxes (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 )

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating statement of operations

For the three months ended ~~September 30, 2014~~March 31, 2015

(Unaudited)

(in thousands) Laredo Subsidiary Guarantors
Intercompany
eliminations

Consolidated
company
Total operating revenues $ 199,968
$ 2,494
$ (2,221 ) $ 200,241
Total operating costs and expenses 129,062
4,137
(2,122 ) 131,077
Operating income (loss) 70,906
(1,643 ) (99 ) 69,164
Interest expense and other, net (30,516 ) —
—
(30,516 )
Other non-operating income (expense) 88,894
(157 ) 1,800
90,537
Income (loss) before income taxes 129,284
(1,800 ) 1,701
129,185
Deferred income tax expense (45,778 ) —
—
(45,778 )
Net income (loss) $ 83,506
$ (1,800 ) $ 1,701
$ 83,407

~~Condensed consolidating statement of operations~~

~~For the nine months ended September 30, 2014~~

~~(Unaudited)~~

(in thousands) Laredo Subsidiary Guarantors Intercompany
eliminations Consolidated
company
Total operating revenues $ 556,054
$ 5,066
$ (4,525 ) $ 556,595
Total operating costs and expenses 358,168
9,090
(4,426 ) 362,832
Operating income (loss) 197,886
(4,024 ) (99 ) 193,763
Interest expense and other, net (89,882 ) —
—
(89,882 )
Other non-operating expense (8,099 ) (234 ) 4,258
(4,075 )
Income (loss) before income taxes 99,905
(4,258 ) 4,159
99,806
Deferred income tax expense (35,511 ) —
—
(35,511 )
Net income (loss) $ 64,394
$ (4,258 ) $ 4,159
$ 64,295



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

Condensed consolidating statement of cash flows

For the ~~nine~~three months ended ~~September 30,~~March 31, 2016

(Unaudited)



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash flows provided by operating activities	$	58,163		$	1,954		$	(3,600	)	$	56,517
Change in investment between affiliates	(30,235		)	26,635			3,600			—
Capital expenditures and other	(105,575		)	(28,589		)	—			(134,164		)
Net cash flows provided by financing activities	58,588			—			—			58,588
Net decrease in cash and cash equivalents	(19,059		)	—			—			(19,059		)
Cash and cash equivalents at beginning of period	31,153			1			—			31,154
Cash and cash equivalents at end of period	$	12,094		$	1		$	—		$	12,095

Condensed consolidating statement of cash flows

For the three months ended March 31, 2015

(Unaudited)


(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash flows provided by (used in) operating activities	$	229,065		$	(172	)	$	(3,389	)	$	225,504		$	51,531		$	(26,347	)	$	1,681		$	26,865
Change in investments between affiliates	(101,858		)	98,469			3,389			—
Change in investment between affiliates													(59,634		)	61,315			(1,681		)	—
Capital expenditures and other	(433,580		)	(98,297		)	—			(531,877		)	(247,578		)	(34,968		)	—			(282,546		)
Net cash flows provided by financing activities	353,455			—			—			353,455			795,453			—			—			795,453
Net increase in cash and cash equivalents	47,082			—			—			47,082			539,772			—			—			539,772
Cash and cash equivalents at beginning of period	29,320			1			—			29,321			29,320			1			—			29,321
Cash and cash equivalents at end of period	$	76,402		$	1		$	—		$	76,403		$	569,092		$	1		$	—		$	569,093

Note 18—Recent accounting pronouncements

In March 2016, the Financial Accounting Standards Board ("FASB") issued new guidance in Topic 718, Compensation—Stock Compensation, which seeks to simplifythe 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 is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

~~Condensed consolidating~~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

~~For~~ 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 ~~nine months ended September 30, 2014~~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 guidance will have on its consolidated financial statements upon adoption of this standard.

~~(Unaudited)~~

(in thousands) Laredo Subsidiary Guarantors
Intercompany
eliminations

Consolidated
company
Net cash flows provided by (used in) operating activities $ 373,834
$ (1,756 ) $ 4,258
$ 376,336
Change in investments between affiliates (79,356 ) 83,614
(4,258 ) —
Capital expenditures and other (951,890 ) (81,858 ) —
(1,033,748 )
Net cash flows provided by financing activities 515,019
—
—
515,019
Net decrease in cash and cash equivalents (142,393 ) —
—
(142,393 )
Cash and cash equivalents at beginning of period 198,153
—
—
198,153
Cash and cash equivalents at end of period $ 55,760
$ —
$ —
$ 55,760

~~Note 18—Recent accounting pronouncements~~

In July 2015, the ~~Financial Accounting Standards Board ("FASB")~~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 update 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 is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard.

In April 2015, the FASB issued new guidance in Subtopic ~~835-30,~~350-40, ~~Interest-Imputation of Interest,~~Intangibles—Goodwill and Other—Internal-Use Software. which seeks to simplify the presentation of debt issuance costs. These amendments require that debt issuance costs related to a recognized debt liability be presented in an entity's balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The ~~recognition and measurement guidance for debt issuance costs are not affected by the~~ amendments in this ~~guidance. Entities~~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 ~~apply~~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 elected to adopt this guidance in the first quarter of 2016 on a ~~retrospective~~prospective basis, ~~wherein~~and the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. The Company has early-adopted this standard as of September 30, 2015, and has applied its provisions retrospectively. The adoption of this standard resulted in the reclassification of $19.4 million and $21.8 million of unamortized debt issuance costs related to the Company's senior unsecured notes from "Other assets, net" to "Long-term debt, net" within its consolidated balance sheets as of September 30, 2015 and December 31, 2014, respectively. Other than this reclassification, the adoption of this standard did not have an ~~impact~~effect on ~~the Company's~~its unaudited consolidated financial statements. The effect of this change in accounting principle on previously reported interim periods are decreases to each of total assets and total liabilities of $26.6 million and $20.1 million as of March 31, 2015 and June 30, 2015, respectively. See Notes 2.g and 5.g for additional discussion of debt issuance costs.

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

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard's application impact to individual financial statement line items. This standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard.

~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

Note 19—Subsequent events

a. ~~Medallion capital call~~Senior Secured Credit Facility

On ~~October~~April 1, 2016, the Company borrowed $15.0 million on the Senior Secured Credit Facility. The outstanding balance under the Senior Secured Credit Facility was $210.0 million as of May 3, 2016. Additionally, effective May 2, 2016, in connection with the regular semi-annual redetermination of the borrowing base under the Senior Secured Credit Facility, the borrowing base and aggregate elected commitment were each reduced to $815.0 million.

b. Medallion contribution

On April 15, ~~2015,~~2016, the Company contributed ~~$10.4~~$0.9 million to fund continued expansion activities on existing portions of Medallion's pipeline infrastructure in order to gather additional third-party production. As of ~~September 30, 2015,~~March 31, 2016, the Company had recorded a capital contribution payable ~~which included~~for the amount of this capital call. ~~For~~See Note 14 for additional discussion regarding ~~the Senior Secured Credit Facility~~Medallion and see Note ~~5.e.~~

~~b. Senior secured credit facility~~

~~On October 30, 2015, in connection with its regular semi-annual redetermination, the Company entered into the Fourth Amendment to the Senior Secured Credit Facility,~~pursuant to which, among other things, the borrowing base decreased to $1.15 billion, while the maximum credit amount and aggregate elected commitment remained at $2.0 billion and $1.0 billion, respectively, and the amount15.a for discussion of ~~“permitted investments” in Medallion increased to $225.0 million~~items included in the ~~aggregate at any time.~~Company's unaudited consolidated financial statements related to Medallion.

c. New ~~commodity~~ derivative contracts

Subsequent to ~~September 30, 2015,~~March 31, 2016, the Company entered into the following new ~~commodity~~ derivative contracts:


	Aggregate volumes	Floor price		Contract period	Aggregate volumes	Floor price		Ceiling price		Contract period
Oil (volumes in Bbl):(1)
Put⁽¹⁾	1,296,000	$	45.00	January 1, 2016 - December 31, 2016	600,000	$	40.00	$	—	May 2016 - December 2016
Natural gas (volumes in MMBtu):⁽²⁾
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)	The associated ~~commodity derivatives~~derivative will be settled based on the WTI NYMEX index oil price. ~~A total of $4.5~~There are $1.2 million in deferred premiums associated with this contract.


(2)	The associated derivatives will be settled based on the Inside FERC index price for West Texas Waha. There are $0.8 million in deferred premiums associated with these contracts.

d. Leasehold acquisition

Subsequent to March 31, 2016, the Company acquired or entered into agreements to acquire 1,114 net acres of additional leasehold interests in Glasscock county within the Company's core development area, for an aggregate purchase price of $10.8 million.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note 20—Supplementary information

Costs incurred in oil, NGL 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 for the periods presented:~~below:


	Three months ended September 30,				Nine months ended September 30,				Three months ended March 31,
(in thousands)	2015		2014		2015		2014		2016		2015
Property acquisition costs:							—
Evaluated	$	—	$	—	$	—	$	3,873	$	—	$	—
Unevaluated	—		—		—		9,925		—		—
Exploration⁽¹⁾	7,803		200,711		16,157		217,353		7,263		4,513
Development costs⁽²⁾⁽¹⁾	64,451		325,118		381,641		733,671		81,886		206,672
Total costs incurred	$	72,254	$	525,829	$	397,798	$	964,822	$	89,149	$	211,185


(1)	The ~~Company acquired significant leasehold interests during the three months ended September 30, 2014.~~


~~(2)~~	~~The~~ costs incurred for oil, NGL and natural gas development activities include ~~$0.3~~$0.1 million and ~~$1.6~~$0.5 million in asset retirement obligations for the three months ended ~~September 30,~~March 31, 2016 and 2015, ~~and 2014, respectively, and $1.3 million and $3.1 million for the nine months ended September 30, 2015 and 2014,~~ respectively.

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited consolidated financial statements and condensed notes thereto included elsewhere in this Quarterly Report as well as our audited consolidated financial statements and notes thereto included in our ~~2014~~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 ~~(i) when used in the present tense, prospectively or from October 24, 2014,~~ refer to Laredo, LMS and GCM ~~collectively and (ii)when used for historical periods from December 31, 2013 to October 23, 2014, refer to Laredo and LMS~~ collectively unless the context otherwise indicates or requires. All amounts, dollars and percentages presented in this Quarterly Report are rounded and therefore approximate.

Executive overview

We are an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties, and the transportation of oil 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, 2015~~March 31, 2016 included the following:

Oil, NGL and natural gas sales of $~~104.6~~73.1 million, compared to ~~$199.5~~$118.1 million for the three months ended ~~September 30, 2014;~~March 31, 2015;

Average daily sales volumes of ~~44,820~~46,202 BOE/D, compared to ~~32,970~~47,487 BOE/D for the three months ended ~~September 30, 2014;~~March 31, 2015;

Net loss of ~~$847.8~~$180.4 million, including a non-cash full cost ceiling impairment of ~~$906.4~~$161.1 million, compared to net ~~income~~loss of ~~$83.4~~$0.5 million for the three months ended ~~September 30, 2014;~~March 31, 2015; and

Adjusted EBITDA (a non-GAAP financial measure) of ~~$119.8~~$96.1 million, compared to ~~$142.0~~$118.6 million for the three months ended ~~September 30, 2014.~~

~~Our financial and operating performance for the nine months ended September 30, 2015 included the following:~~

~~Oil, NGL and natural gas sales of $348.3 million, compared to $555.6 million for the nine months ended September 30, 2014;~~

~~Average daily sales volumes of 46,270 BOE/D, compared to 29,577 BOE/D for the nine months ended September 30, 2014;~~

~~Net loss of $1.25 billion, including a non-cash full cost ceiling impairment of $1.39 billion, compared to net income of $64.3 million for the nine months ended September 30, 2014; and~~

~~Adjusted EBITDA (a non-GAAP financial measure) of $356.4 million, compared to $447.3 million for the nine months ended September 30, 2014.~~

~~Three-stream reporting~~

As of January 1, 2015, all of our natural gas processing agreements with various processors had been modified to allow us to take title to the NGL resulting from the processing of our natural gas. Based on this, we elected to report reserves, sales volumes, prices and revenues for oil, NGL and natural gas separately for periods after January 1,March 31, 2015. This is known as "three-stream reporting." For periods prior to January 1, 2015, we presented our reserves, sales volumes, prices and revenues for oil and natural gas, which combined NGL with the natural gas stream, and did not separately report NGL. This change impacts the comparability of 2015 with prior periods.

Reserves, pricing and non-cash full cost ceiling impairment

Our results of operations are heavily influenced by ~~commodity prices, which historically experience significant fluctuations, have significantly declined and have remained low in recent months. Prices for~~ oil, NGL and natural gas ~~can fluctuate widely in response to relatively minor~~prices, which have significantly declined and remain at low levels. Oil, NGL and natural gas price fluctuations are caused by changes in ~~the~~ global and regional supply of and demand, ~~for oil, NGL and natural gas,~~ market uncertainty, economic conditions and a variety of additional factors. ~~A continuation~~Since the inception of ~~low~~our oil and natural gas activities, commodity

prices ~~will~~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 ~~internal~~ reserves as of ~~September 30,~~March 31, 2016 and December 31, 2015 are reported in three streams: oil, NGL and natural gas. Our reserves as of December 31, 2014 were reported in two streams: oil and liquids-rich natural gas with the economic value of the NGL in our natural gas included in the wellhead natural gas price. The SEC Prices used to value our reserves as of September 30, 2015 were $55.73 per Bbl for oil, $21.87 per Bbl for NGL and $2.89 per MMBtu for natural gas, as of December 31, 2014 were $91.48 per Bbl for oil and $4.25 per MMBtu for liquids-rich natural gas and as of September 30, 2014 were $95.56 per Bbl for oil and $4.16 per MMBtu for liquids-rich natural gas, respectively. The SEC Prices do not include derivative transactions for any period. Primarily, as a result of these lower prices, our internal September 30, 2015 estimated proved reserves decreased 37 MMBOE from our three-stream December 31, 2014 reserves of 297 MMBOE. In order to convert our two-stream December 31, 2014 reserves of 247 MMBOE to three-stream, we utilized actual gas plant economics of 30% shrink and a yield of 127 Bbl of NGL per MMcf. Additionally, using these SEC Prices, our netNet book value of evaluated oil and natural gas properties exceeded the full cost ceiling amount as of ~~September 30, 2015.~~March 31, 2016. As such, we recorded a ~~third-quarter~~first-quarter non-cash full cost ceiling impairment of ~~$906.4~~$161.1 million. 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 ~~this~~our full cost impairment.

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

Potential future low commodity price impact on our ~~development plans, reserves and~~ full cost impairment

Oil, NGL and natural gas prices have remained low in the ~~fourth~~second quarter of ~~2015.~~2016. If prices remain at or below the current low levels, subject to numerous factors and inherent limitations, and if all other factors remain constant, we will incur an additional non-cash full cost impairment in the ~~fourth~~second quarter of 2016, which will have an adverse effect on our results of operations. Furthermore, at September 30, 2015, as discussed above, we had material reductions in our proved reserves and we will have further reductions at December 31, 2015, due to price-related changes in our proved developed reserves and the potential to modify our development plans for future years as will be determined during the fourth quarter.

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 and natural gas ~~recently~~ 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.

~~Although we do not disclose reserve quantities on a quarterly basis, we~~We have set forth below a calculation of a potential future ~~further reduction of our proved reserves.~~full cost impairment. Such implied impairment ~~and decrease in reserves~~ should not be interpreted to be indicative of our development plan or of our actual future results. Each of the uncertainties noted above has been evaluated for material known trends to be potentially included in the estimation of possible ~~fourth-quarter~~second-quarter effects. Based on such review, we determined that (i) the impact of decreased commodity prices, is(ii) changes in cost estimates and (iii) changes in reserves are the only significant known ~~variable~~variables necessary in the following scenario.

~~Both our~~Our hypothetical ~~fourth-quarter~~second-quarter 2016 full cost ceiling calculation ~~and our hypothetical reserves estimates have~~has been prepared (i) by substituting ~~(i) $45.85~~(a) $37.96 per barrel for oil, ~~(ii) $12.57~~(b) $10.85 per barrel for NGL and ~~(iii) $1.88~~(c) $1.61 per MMBtu for natural gas (the "Pro Forma Prices") for the respective ~~SEC~~Realized Prices as of ~~September 30, 2015.~~March 31, 2016 and (ii) by incorporating a reduction in lease operating costs of 1%, updated drilling and completion costs and changes in our reserves. All other inputs and assumptions have been held constant. Accordingly, this estimation strictly isolates the estimated impact of more current commodity prices on the 2015 year-end SEC Prices that will be utilized in our full cost ceiling calculation and our reserves estimate. The Pro Forma Prices use a slightly modified ~~SEC~~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~~May 1, ~~2015,~~2016, with the price for ~~November~~May 1, ~~2015~~2016 held constant for the remaining twelfth month of the calculation. Based ~~solely~~ on ~~the substitution of the Pro Forma Prices into our September 30, 2015 internal reserve estimates,~~these inputs, the implied ~~fourth-quarter~~second-quarter impairment would be ~~$535 million and the implied impact to our three-stream December 31, 2014 reserves of 297 MMBOE would be a reduction of 64 MMBOE.~~$21 million. We

believe that substituting the Pro Forma Prices ~~into~~and updating our ~~September 30, 2015~~cost and reserve estimates in our March 31, 2016 internal reserve estimates may help provide users with an understanding of the ~~potential fourth-quarter price~~ impact of known trends on our ~~December 31, 2015~~June 30, 2016 full cost ceiling test and in preparing our year-end reserve estimates.

Recent developments

~~Amendment to~~Borrowing base redetermination under the Senior Secured Credit Facility

~~On October 30, 2015,~~Effective May 2, 2016, in connection with our regular semi-annual redetermination ~~we entered into~~of the ~~Fourth Amendment to~~borrowing base under the Senior Secured Credit Facility, ~~pursuant to which, among other things,~~ the borrowing base ~~decreased to $1.15 billion, while the maximum credit amount~~ and aggregate elected commitment ~~remained at $2.0 billion and $1.0 billion, respectively, and the amount of “permitted investments” in Medallion increased~~amounts were each reduced to ~~$225.0 million in the aggregate at any time.~~$815.0 million. For more information regarding the ~~Fourth Amendment to the Senior Secured Credit Facility,~~borrowing base redetermination, see Notes 5.e and ~~19.b~~19.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report and "Part II, Item 5. Other Information-Item 1.01 Entry into a material definitive agreement" below.

Core areas of operations

The oil and liquids-rich Permian Basin is characterized by multiple target horizons, extensive production histories, long-lived reserves, high drilling success rates and high initial production rates. As of ~~September 30, 2015,~~March 31, 2016, we had assembled ~~142,895~~132,676 net acres in the Permian Basin.

Sources of our revenue

Our revenues are primarily derived from the sale of oil, NGL and natural gas within the continental United States and the sale of purchased oil ~~within the continental United States~~ and do not include the effects of derivatives. For the three months ended ~~September 30, 2015,~~March 31, 2016, our revenues were comprised of sales of ~~53%~~52% oil, 8% NGL, 9%8% natural gas, ~~29% sale~~30% sales of purchased oil and ~~1% midstream service revenues. For the nine months ended September 30, 2015, our revenues were comprised of sales of 55% oil, 8% NGL, 9% natural gas, 27% sale of purchased oil and 1%~~2% midstream service revenues. 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. 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 ~~(iii) oil throughput fees~~ and ~~(iv)~~(iii) water services. ~~Our sales of purchased oil revenue may vary due to changes in oil prices.~~

Results of operations consolidated

Three ~~and nine~~ months ended ~~September 30, 2015~~March 31, 2016 as compared to the three ~~and nine~~ months ended ~~September 30, 2014~~March 31, 2015

~~Sales volumes, oil,~~Oil, NGL and natural gas sales volumes, revenues and pricing

The following table sets forth information regarding ~~sales volumes,~~ 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,						Three months ended March 31,
	2015			2014			2015			2014			2016			2015
Sales volumes⁽¹⁾:
Sales volumes:
Oil (MBbl)	1,844			1,778			5,954			4,712			2,006			2,172
NGL (MBbl)	1,150			—			3,234			—			1,066			989
Natural gas (MMcf)	6,778			7,533			20,663			20,176			6,796			6,680
Oil equivalents (MBOE)⁽³⁾⁽²⁾	4,124			3,033			12,632			8,074			4,204			4,274
Average daily sales volumes (BOE/D)⁽³⁾⁽²⁾	44,820			32,970			46,270			29,577			46,202			47,487
% Oil	45		%	59		%	47		%	58		%	48		%	51		%
Oil, NGL and natural gas revenues (in thousands)⁽¹⁾:
Oil, NGL and natural gas revenues (in thousands):
Oil	$	79,084		$	155,829		$	268,093		$	429,175		$	55,194		$	90,615
NGL	11,913			—			39,181			—			9,052			13,187
Natural gas	13,610			43,661			41,005			126,401			8,896			14,316
Oil, NGL and natural gas sales	$	104,607		$	199,490		$	348,279		$	555,576
Average sales prices⁽¹⁾:
Total													$	73,142		$	118,118
Average sales prices:
Oil, realized ($/Bbl)⁽⁴⁾⁽³⁾	$	42.88		$	87.65		$	45.03		$	91.09		$	27.51		$	41.73
NGL, realized ($/Bbl)⁽⁴⁾⁽³⁾	$	10.36		$	—		$	12.12		$	—		$	8.50		$	13.34
Natural gas, realized ($/Mcf)⁽⁴⁾⁽³⁾	$	2.01		$	5.80		$	1.98		$	6.26		$	1.31		$	2.14
Average price, realized ($/BOE)⁽⁴⁾⁽³⁾	$	25.37		$	65.78		$	27.57		$	68.80		$	17.40		$	27.64
Oil, hedged ($/Bbl)⁽⁵⁾⁽⁴⁾	$	76.74		$	88.86		$	72.69		$	89.73		$	56.84		$	69.51
NGL, hedged ($/Bbl)⁽⁵⁾⁽⁴⁾	$	10.36		$	—		$	12.12		$	—		$	8.50		$	13.34
Natural gas, hedged ($/Mcf)⁽⁵⁾⁽⁴⁾	$	2.37		$	5.87		$	2.34		$	6.24		$	2.08		$	2.35
Average price, hedged ($/BOE)⁽⁵⁾⁽⁴⁾	$	41.11		$	66.66		$	41.19		$	67.95		$	32.64		$	42.08


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


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


~~(3)~~(2)	The volumes presented are based on actual results and are not calculated using the rounded numbers presented in the table above.

~~(4)~~(3)

Realized oil, NGL and natural gas prices are the actual prices realized at the wellhead ~~after all adjustments~~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.

~~(5)~~(4)

Hedged prices reflect the after-effect of our ~~commodity~~ hedging transactions on our average sales prices. Our calculation of such after-effects include current period settlements of matured ~~commodity~~ derivatives in accordance with GAAP and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to instruments that settled in the period. The prices presented are based on actual results and are not calculated using the rounded numbers presented in the table above.

The following table presents cash settlements received ~~(paid)~~ for matured ~~commodity~~ derivatives and premiums incurred previously or upon settlement attributable to instruments that settled during the periods utilized in our calculation of the hedged prices presented above:


	Three months ended September 30,						Nine months ended September 30,						Three months ended March 31,
(in thousands)	2015			2014			2015			2014			2016			2015
Cash settlements received (paid) for matured commodity derivatives:
Cash settlements received for matured derivatives:
Oil	$	63,510		$	3,745		$	168,068		$	(1,486	)	$	60,692		$	61,586
Natural gas	2,632			786			7,811			166			5,245			1,555
Total	$	66,142		$	4,531		$	175,879		$	(1,320	)	$	65,937		$	63,141
Premiums paid attributable to contracts that matured during the respective period:
Oil	$	(1,073	)	$	(1,590	)	$	(3,391	)	$	(4,908	)	$	(1,850	)	$	(1,245	)
Natural gas	(175		)	(230		)	(527		)	(691		)	—			(176		)
Total	$	(1,248	)	$	(1,820	)	$	(3,918	)	$	(5,599	)	$	(1,850	)	$	(1,421	)

Changes in prices and volumes caused the following changes to our oil, NGL and natural gas revenues between the three months ended ~~September 30, 2015~~March 31, 2016 and ~~2014:~~2015:

(in thousands) Oil NGL Natural gas
Total net dollar
effect of change
2014 Revenues $ 155,829
$ —
$ 43,661

$ 199,490
Effect of changes in price (82,566 ) 11,909
(25,689 ) (96,346 )
Effect of changes in volumes 5,816
—
(4,374 )
⁽¹⁾
1,442
Other 5
4
12
21
2015 Revenues $ 79,084
$ 11,913
$ 13,610
$ 104,607


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

~~Changes in prices and volumes caused the following changes to our oil, NGL and natural gas revenues between the nine months ended September 30, 2015 and 2014:~~


(in thousands)	Oil			NGL			Natural gas				Total net dollar effect of change			Oil			NGL			Natural gas			Total net dollar effect of change
2014 Revenues	$	429,175		$	—		$	126,401			$	555,576
2015 Revenues														$	90,615		$	13,187		$	14,316		$	118,118
Effect of changes in price	(274,241		)	39,195			(88,437		)		(323,483		)	(28,514		)	(5,157		)	(5,670		)	(39,341		)
Effect of changes in volumes	113,153			—			3,050			⁽¹⁾	116,203			(6,907		)	1,022			250			(5,635		)
Other	6			(14		)	(9		)		(17		)
2015 Revenues	$	268,093		$	39,181		$	41,005			$	348,279
2016 Revenues														$	55,194		$	9,052		$	8,896		$	73,142


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

Oil revenue. Our oil revenue is a function of oil production volumes sold and average sales prices received for those volumes. The decrease in oil revenue of ~~$76.7~~$35.4 million, or ~~49%~~39%, for the three months ended ~~September 30, 2015~~March 31, 2016 as compared to the three months ended ~~September 30, 2014,~~March 31, 2015, is mainly due to a ~~51%~~34% decrease in average oil prices realized ~~partially offset by~~and a ~~4% increase~~8% decrease in oil production.

The decrease in oil revenue of $161.1 million, or 38%, for the nine months ended September 30, 2015 as compared to the nine months ended September 30, 2014, is mainly due to a 51% decrease in average oil prices realized, partially offset by a 26% increase in oil production.

NGL and natural gas revenues. ~~On January 1, 2015, we began utilizing three-stream reporting, which impacts the comparability of 2015 with prior periods.~~ Our NGL and natural gas revenues are a function of NGL and natural gas production volumes sold and average sales prices received for those volumes. The ~~total~~ decrease in NGL ~~and natural gas revenues from~~revenue of $4.1 million, or 31%, for the

three ~~and nine~~ months ended ~~September 30, 2015~~March 31, 2016 as compared to the ~~periods in 2014,~~three months ended March 31, 2015, is mainly ~~related~~due to a 36% decrease in average NGL prices ~~realized on our~~realized. The decrease in natural gas ~~and NGL production. Stripping out the NGL component from our liquids-rich natural gas results in a lower price received~~revenue of $5.4 million, or 38%, for ~~residue natural gas during~~ the three ~~and nine~~ months ended ~~September 30, 2015~~March 31, 2016 as compared to the ~~same periods in 2014 in which we received revenues from liquids-rich natural gas. The~~three months ended March 31, 2015, is mainly due to a 39% decrease in ~~prices is partially offset by an increase in NGL and~~average natural gas ~~production during the three and nine months ended September 30, 2015 as compared to the same periods in 2014, converted to a three-stream basis.~~prices realized.

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,				Three months ended March 31,
(in thousands except for per BOE sold data)	2015		2014		2015		2014		2016		2015
Costs and expenses:
Lease operating expenses	$	25,112	$	25,165	$	86,698	$	67,129	$	20,518	$	32,380
Production and ad valorem taxes	7,895		12,550		26,481		38,160		6,435		9,086
Midstream service expenses	1,092		1,225		4,263		3,596		609		1,574
Minimum volume commitments	—		675		5,235		1,779		—		1,656
Costs of purchased oil	46,961		—		132,578		—		32,946		31,200
General and administrative⁽¹⁾	22,913		27,078		67,976		84,284		19,451		21,855
Restructuring expenses	—		—		6,042		—		—		6,042
Accretion of asset retirement obligations	599		442		1,771		1,279		844		579
Depletion, depreciation and amortization	66,777		63,942		210,831		166,605		41,478		71,942
Impairment expense	906,850		—		1,397,327		—		161,064		878
Total costs and expenses	$	1,078,199	$	131,077	$	1,939,202	$	362,832
Average costs per BOE sold⁽²⁾:
Total									$	283,345	$	177,192
Average costs per BOE sold:
Lease operating expenses	$	6.09	$	8.30	$	6.86	$	8.31	$	4.88	$	7.58
Production and ad valorem taxes	1.91		4.14		2.10		4.73		1.53		2.13
Midstream service expenses	0.26		0.40		0.34		0.45		0.14		0.37
General and administrative⁽¹⁾	5.56		8.93		5.38		10.44		4.63		5.11
Depletion, depreciation and amortization	16.19		21.08		16.69		20.63		9.87		16.83
Total	$	30.01	$	42.85	$	31.37	$	44.56	$	21.05	$	32.02


(1)	General and administrative includes non-cash stock-based compensation, net of amounts capitalized, of ~~$6.9~~$3.8 million and ~~$6.2~~$4.8 million for the three months ended ~~September 30,~~March 31, 2016 and 2015, ~~and 2014, respectively, and $17.9 million and $16.9 million for the nine months ended September 30, 2015 and 2014,~~ respectively.


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

Lease operating expenses. Lease operating expenses, which include workover expenses, ~~remained relatively flat~~decreased by $11.9 million, or 37%, for the three months ended ~~September 30, 2015~~March 31, 2016 as compared to the same period in ~~2014, and increased by $19.6 million, or 29%, for the nine months ended September 30, 2015 as compared to the same period~~2015. Previous investments in ~~2014. For the nine months ended September 30, 2015 compared to the same period in 2014, the increase is mainly due to increases~~field infrastructure, primarily in our ~~(i) producing wells~~four production corridors, including water takeaway and ~~(ii)~~recycling facilities and centralized compression, lowered costs and reduced well ~~service~~downtime. We continue to focus on the usage and ~~workover expenses.~~procurement of products and services related to direct operating costs.

Production and ad valorem taxes. Production and ad valorem taxes decreased by ~~$4.7~~$2.7 million, or ~~37%, and $11.7 million, or 31%~~29%, for the three ~~and nine~~ months ended ~~September 30, 2015, respectively,~~March 31, 2016 as compared to the same ~~periods~~period in ~~2014.~~2015. This change is mainly due to a decrease in production taxes ~~which are based on and fluctuate proportionately with our oil, NGL and natural gas revenues, which decreased by $5.5 million and $11.8~~of $2.2 million for the three ~~and nine~~ months ended ~~September 30, 2015, respectively,~~March 31, 2016 compared to the same ~~periods~~period in ~~2014~~2015 as a result of the corresponding decrease in oil, NGL and natural gas revenues. Production taxes are based on and fluctuate in proportion to our oil, NGL and natural gas revenue.

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

Minimum volume commitments. ~~Minimum volume commitments decreased by $0.7 million~~See "—Results of operations - midstream and ~~increased by $3.5 million~~marketing" for ~~the three and nine months ended September 30, 2015, respectively, compared to the same periods in 2014. These changes are mainly~~ a ~~result~~discussion of the second-quarter 2015 negotiated buyout of a minimum volume commitment to Medallion, which was related to natural gas gathering infrastructure constructed by Medallion on acreage that we do not plan to develop.these costs.

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

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


(in thousands)	Three months ended September 30, 2015 compared to 2014			Nine months ended September 30, 2015 compared to 2014			Three months ended March 31, 2016 compared to 2015
Changes in G&A:
Performance unit awards							$	(996	)
Stock-based compensation, net of amounts capitalized							(950		)
Professional fees	$	(1,903	)	$	(5,687	)	(390		)
Salaries, benefits and bonuses, net of amount capitalized	(1,873		)	(3,924		)
Charitable contributions	(43		)	(3,205		)
Performance unit awards	1,445			1,967
Stock-based compensation, net of amount capitalized	683			1,015
Other	(2,474		)	(6,474		)	(68		)
Total changes in G&A	$	(4,165	)	$	(16,308	)	$	(2,404	)

G&A expense, excluding stock-based compensation, decreased by ~~$5.0~~$1.5 million, or ~~24%, and $17.4 million, or 26%~~9%, for the three ~~and nine~~ months ended ~~September 30, 2015, respectively,~~March 31, 2016 compared to the same ~~periods~~period in ~~2014.~~2015. This decrease is primarily related to our performance unit awards, which prior to their payouts, were accounted for as liability awards. The ~~decreases are primarily~~associated expense for these awards decreased by $1.0 million for the three months ended March 31, 2016 compared to the same period in 2015. This fluctuation is due to ~~(i) professional fees~~the 2013 Performance Unit Awards performance criteria being satisfied at December 31, 2015, and the awards being paid to a consulting company in the prior period that was engaged to assist us with the optimization of our development operations, (ii) reduced personnel expenses as a result of the RIF which occurred early inat $143.75 per unit during the first quarter of 2016. As the 2013 Performance Unit Awards were fully accrued at December 31, 2015, no additional expense was recorded during the three months ended March 31, 2016. There are no outstanding awards of this type at March 31, 2016.

An additional contributor to the decrease in G&A expense, excluding stock-based compensation, is a decrease in professional fees of $0.4 million for the three months ended March 31, 2016 compared to the same period in 2015. This decrease is primarily due to our March 2015 Equity Offering and ~~(iii)~~the issuance of our ~~$3.0 million charitable contribution pledge expensed in~~March 2023 Notes that occurred during the ~~prior period, which will be paid in annual installments through 2024.~~three months ended March 31, 2015. No comparable offerings were made during the three months ended March 31, 2016.

Stock-based compensation, net of ~~amount~~amounts capitalized, ~~increased~~decreased by ~~$0.7 million, or 11%, and~~ $1.0 million, or 6%20%, for the three ~~and nine~~ months ended ~~September 30, 2015, respectively,~~March 31, 2016 compared to the same ~~periods~~period in ~~2014. These changes are mainly due~~2015. During the three months ended March 31, 2015 we issued 1,748,517 restricted stock awards at a weighted-average grant price of $11.90 per share to new and existing employees and non-employee directors. During the ~~issuance of 631,639 non-qualified~~three months ended March 31, 2016, restricted stock awards, restricted stock options ~~to management~~ and ~~602,501~~ performance share awards were approved by our compensation committee; however, these awards are contingent and subject to ~~management~~stockholder approval of the Amendment to the LTIP at our 2016 Annual Meeting of Stockholders on May 25, 2016. These awards are not considered granted for accounting purposes until such Amendment is approved by our stockholders; as such, no expense has been recorded for these contingent awards during the ~~nine~~three months ended ~~September 30, 2015, compared~~March 31, 2016. For further discussion of our stock-based compensation, see Note 6 to ~~the issuance of 336,140 non-qualified restricted stock options to management and 271,667 performance share awards to management~~our unaudited consolidated financial statements included elsewhere in ~~the same period in 2014, partially offset by forfeitures of restricted stock awards and restricted stock options as a result of the RIF.~~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.~~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.

Our performance unit awards, which settle in cash if performance criteria are met, are accounted for as liability awards. The associated expense for these awards increased by $1.4 million and $2.0 million for the three and nine months ended September 30, 2015, respectively, compared to the same periods in 2014. These fluctuations are mainly due to the quarterly re-measurement of the 2013 Performance Unit Awards based on the performance of our stock price relative to the peer group utilized in the forward-looking Monte Carlo simulation. The 2012 Performance Unit Awards performance criteria were satisfied at December 31, 2014, and they were paid at $100 per unit during the first quarter of 2015. This payout did not affect 2015 expense as they were fully accrued at December 31, 2014.

See Notes ~~2.l~~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 ~~which~~that was ~~an effort~~undertaken to reduce costs and better position ourselves for ~~ongoing efficient growth.~~future operations in a low commodity price environment. Restructuring expenses of $6.0 million were incurred induring the ~~first quarter of~~three months ended March 31, 2015. ~~As of September 30, 2015, no additional RIF~~No comparable expenses ~~are expected to be incurred in 2015.~~were recorded during the three months ended March 31, 2016. See Note 1213 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,				Three months ended March 31,
(in thousands except for per BOE sold data)	2015		2014		2015		2014		2016		2015
Depletion of evaluated oil and natural gas properties	$	63,167	$	61,429	$	200,440	$	160,126	$	37,827	$	68,728
Depreciation of midstream service assets	2,000		1,207		5,580		2,899		2,071		1,647
Depreciation and amortization of other fixed assets	1,610		1,306		4,811		3,580		1,580		1,567
Total DD&A	$	66,777	$	63,942	$	210,831	$	166,605	$	41,478	$	71,942
DD&A per BOE sold	$	16.19	$	21.08	$	16.69	$	20.63	$	9.87	$	16.83

DD&A ~~increased~~decreased by $~~2.8~~30.5 million, or 4%42%~~, and $44.2 million, or 27%~~, for the three ~~and nine~~ months ended ~~September 30, 2015, respectively, as~~March 31, 2016 compared to the same ~~periods~~period in ~~2014,~~2015, mainly due to ~~increases~~our full cost ceiling impairments totaling $2.4 billion during the year ended December 31, 2015. We expect DD&A per BOE will further decrease in the second quarter of 2016 due to our ~~production.~~first-quarter 2016 impairment.

Impairment expense. Our net book value of evaluated oil and natural gas properties exceeded the full cost ceiling amount as of ~~September 30, 2015.~~March 31, 2016. As a result, we recorded a ~~third-quarter~~first-quarter 2016 non-cash full cost ceiling impairment of ~~$906.4 million. Additionally, as of June 30, 2015, we recorded a second-quarter non-cash full cost ceiling impairment of $488.0~~$161.1 million. There ~~were~~was no comparable full cost impairment during the same period in 2015. For further discussion of our non-cash full cost celling impairments, see Note 2.f to our unaudited consolidated financial statements included elsewhere in ~~2014.~~this Quarterly Report.

Other less material components of impairment expense are LCM adjustments of $2.3 million for materials and supplies for the nine months ended September 30, 2015, and $0.4 million and $0.5 million for our line-fill for the three and nine months ended September 30, 2015, respectively. There were no comparable impairments in 2014.

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


	Three months ended September 30,						Nine months ended September 30,						Three months ended March 31,
(in thousands)	2015			2014			2015			2014			2016			2015
Non-operating income (expense):
Gain (loss) on derivatives, net	$	142,580		$	92,790		$	141,836		$	(1,447	)
Gain on derivatives, net													$	17,885		$	63,155
Income (loss) from equity method investee	2,104			(61		)	4,585			(86		)	2,298			(433		)
Interest expense	(23,348		)	(30,549		)	(79,732		)	(90,192		)	(23,705		)	(32,414		)
Interest and other income	92			33			388			310			99			123
Loss on early redemption of debt	—			—			(31,537		)	—
Write-off of debt issuance costs	—			—			—			(124		)
Loss on disposal of assets, net	(94		)	(2,192		)	(1,937		)	(2,418		)	(160		)	(762		)
Non-operating income (expense), net	$	121,334		$	60,021		$	33,603		$	(93,957	)	$	(3,583	)	$	29,669

~~Derivatives.~~Gain 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, 2015 compared to 2014			Nine months ended September 30, 2015 compared to 2014			Three months ended March 31, 2016 compared to 2015
Changes in gain (loss) on derivatives, net:
Changes in gain on derivatives, net:
Fair value of derivatives outstanding	$	(11,821	)	$	42,744		$	(128,066	)
Early terminations of derivatives received	—			(76,660		)	80,000
Cash settlements received for matured derivatives	61,611			177,199			2,796
Total changes in gain (loss) on derivatives, net	$	49,790		$	143,283
Total changes in gain on derivatives, net							$	(45,270	)

The ~~changes~~change in fair value of derivatives outstanding for the three ~~and nine~~ months ended ~~September 30, 2015~~March 31, 2016 compared to the same ~~periods~~period in ~~2014, are~~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~~three months ended ~~September 30, 2015~~March 31, 2016 compared to ~~2014~~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 ~~cash received for~~proceeds to the ~~early settlement in February 2014~~premiums on two new derivatives entered into as part of ~~our oil basis swap differential between~~ the ~~Light Louisiana Sweet Argus and the Brent International Petroleum Exchange index oil prices. Net cash~~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 (loss) from equity method investee. Income ~~(loss)~~ from equity method investee increased by ~~$2.2 million and $4.7~~$2.7 million for the three ~~and nine~~ months ended ~~September 30, 2015, respectively,~~March 31, 2016 compared to the same ~~periods~~period in ~~2014.~~2015. During the ~~nine~~three months ended ~~September 30, 2015,~~March 31, 2016, Medallion, our equity method investee, continued expansion activities on existing portions of its pipeline infrastructure in order to gather additional third-party oil ~~production and~~production. Medallion began recognizing revenue during the first quarter of 2015 due to its main pipeline becoming fully operational. The Medallion pipeline system transported more than 83,000 barrels of oil per day ("BOPD") during the three months ended March 31, 2016 compared to more than 10,000 BOPD in the time that the system was operational during the three months ended March 31, 2015.

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



(in thousands)	Three months ended March 31, 2016 compared to 2015
Changes in interest expense:
January 2019 Notes	$	(12,998	)
March 2023 Notes	4,679
Senior Secured Credit Facility, net of capitalized interest	(226		)
Other	(164		)
Total change in interest expense	$	(8,709	)

Interest expense decreased by ~~$7.2~~$8.7 million, or ~~24%, and 10.5 million, or 12%~~27%, for the three ~~and nine~~ months ended ~~September 30, 2015, respectively,~~March 31, 2016 compared to the same ~~periods~~period in ~~2014. The decreases are~~2015. This decrease is primarily due to the ~~early-redemption~~early redemption of the January 2019 Notes on April 6, 2015, which ~~are~~is partially offset by the 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.

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

(in thousands) Three months ended September 30, 2015 compared to 2014 Nine months ended September 30, 2015 compared to 2014
Changes in interest expense:

January 2019 Notes $ (13,001 ) $ (25,143 )
March 2023 Notes 5,408
11,667
Senior Secured Credit Facility, net of capitalized interest 585
2,054
January 2022 Notes —
1,477
Other (193 ) (515 )
Total changes in interest expense $ (7,201 ) $ (10,460 )

Loss on ~~early redemption~~disposal of ~~debt.~~ During the nine months ended September 30, 2015, we redeemed the entire $550.0 million outstanding principal amount of the January 2019 Notes at a redemption price of 104.750% of the principal amount, plus accrued and unpaid interest up to the Redemption Date. We recognized a loss on extinguishment of $31.5 million related to the difference between the redemption price and the net carrying amount of the January 2019 Notes.

~~Disposal of assets.~~assets, net. Loss on disposal of assets, net decreased ~~$2.1 million and $0.5~~$0.6 million for the three ~~and nine~~ months ended ~~September 30, 2015, respectively,~~March 31, 2016 compared to the same ~~periods~~period in ~~2014~~2015 as a result of ~~higher~~lower losses related to the sales ~~and write-off~~ of materials and supplies and other fixed assets during ~~2014~~2016 as compared to 2015.

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


	Three months ended September 30,						Nine months ended September 30,						Three months ended March 31,
(in thousands)	2015			2014			2015			2014			2016			2015
Income (loss) before income taxes	$	(806,525	)	$	129,185		$	(1,422,234	)	$	99,806		$	(180,371	)	$	3,171
Income tax (expense) benefit	(41,258		)	(45,778		)	176,945			(35,511		)
Net income (loss)	$	(847,783	)	$	83,407		$	(1,245,289	)	$	64,295
Income tax expense													—			(3,643		)
Net loss													$	(180,371	)	$	(472	)

~~The effective tax rate on income (loss) before income taxes was 35% for the three months ended 2014 and 36% for the nine months ended September 30, 2014, respectively.~~ Our effective tax rate is affected by ~~recurring permanent differences,~~ 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. For ~~each of~~ the three ~~and nine~~ months ended ~~September 30,~~March 31, 2016, the effective tax rate on loss before income taxes was not meaningful due to the valuation allowance recorded. For the three months ended March 31, 2015, the effective tax rate on income before income taxes was not meaningful due to the significant effect of discrete items on a relatively small amount of income. For the three months ended March 31, 2016, we recorded aan additional valuation allowance of ~~$326.2~~$57.7 million for our deferred tax assets due to uncertainty regarding their realization. ~~As such, the effective tax rates on~~For further discussion of our ~~loss before income taxes~~

~~for the same periods are not meaningful. No comparable amounts were recorded in the three and nine months ended September 30, 2014.~~

~~As of September 30, 2015, we expect the fiscal year 2015 annual effective tax rate, excluding any~~ valuation allowance, ~~and discrete items, applicable~~see Note 7 to ~~forecasted income before income taxes to be 35%. Significant factors that could impact the annual effective tax rate include management's assessment of certain tax matters, changes~~our unaudited consolidated financial statements included elsewhere in certain non-deductible expenses and shortfalls related to restricted stock awards that vest and stock options that are exercised during the year. GAAP requires the application of the estimated annual effective rate in determining the interim period tax provision unless a rate cannot be reliably estimated, such as when a small change in pre-tax income or loss creates significant variations in the customary relationship between income tax expense or benefit and pre-tax income or loss in interim periods. In such a situation, the interim period tax provision should be based on actual year-to-date results.this Quarterly Report.

During the three ~~and nine~~ months ended ~~September 30,~~March 31, 2016 and 2015, ~~and 2014,~~ certain shares related to restricted stock awards vested at times when ~~our~~the Company's stock price was lower than the fair value of those shares onat the ~~grant date.~~time of the grant. As a result, the income tax deduction related to such shares is less than the expense previously recognized for book purposes. During the three ~~and nine~~ months ended ~~September 30, 2014, certain~~March 31, 2016 and 2015, no restricted stock options were exercised, for which the related income tax deduction was less than the expense previously recognized for book purposes. There were no stock options exercised during the three and nine months ended September 30, 2015.exercised. As a result of these differences in book compensation cost and related tax deduction, the tax impact of these shortfalls increased by ~~$0.3 million and $3.1~~$1.4 million for the three ~~and nine~~ months ended ~~September 30, 2015, respectively,~~March 31, 2016 compared to the same ~~periods~~period in ~~2014.~~2015.

We utilize a one-pool approach when accounting for the pool of windfall tax benefits in which employees and non-employees are grouped into a single pool. As of ~~September 30,~~March 31, 2016 and 2015, ~~and 2014,~~ we did not have any eligible windfall tax benefits to offset future shortfalls as no excess tax benefits had been recognized, and therefore the tax impact of these shortfalls is included in income tax expense for these respective periods. We expect income tax provisions for future reporting periods will be impacted by this stock compensation tax deduction shortfall; however, we cannot predict the stock compensation shortfall

impact because of dependency upon the future market price of our stock. See Notes 6.a, 6.b and 7 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information.

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,						Three months ended March 31,
(in thousands)	2015			2014			2015			2014			2016			2015
Natural gas sales	$	753		$	619		$	1,086		$	619		$	—		$	112
Midstream service revenues	7,917			1,875			15,962			4,447			11,267			3,683
Sales of purchased oil	43,860			—			130,178			—			31,614			31,267
Total revenues	52,530			2,494			147,226			5,066			42,881			35,062
Midstream service expenses, including minimum volume commitments	5,240			2,519			9,580			5,994			6,509			3,342
Costs of purchased oil	46,961			—			132,578			—			32,946			31,200
General and administrative⁽¹⁾	2,200			1,933			6,138			5,081			1,772			2,077
Depletion, depreciation and amortization⁽²⁾	2,113			1,644			5,923			3,078
Depreciation and amortization⁽²⁾													2,186			1,685
Other operating costs and expenses⁽³⁾	481			28			834			28			52			308
Operating loss	$	(4,465	)	$	(3,630	)	$	(7,827	)	$	(9,115	)	$	(584	)	$	(3,550	)
Other financial information:
Income (loss) from equity method investee	$	2,104		$	(61	)	$	4,585		$	(86	)	$	2,298		$	(433	)
Interest expense⁽⁴⁾	$	(1,318	)	$	(965	)	$	(3,770	)	$	(2,505	)	$	(1,402	)	$	(1,327	)
Loss on early redemption of debt⁽⁴⁾	$	—		$	—		$	(1,481	)	$	—

(1)

G&A ~~costs were~~was allocated based on the number of employees in the ~~respective~~midstream and marketing segment asfor the three months ended March 31, 2016 and 2015. Certain components of ~~September 30, 2015~~G&A were not allocated and ~~2014. However,~~were based on actual costs to the midstream and marketing segment which primarily consisted of payroll, deferred compensation and vehicle costs for the three months ended March 31, 2016 and ~~the capitalization of payroll and deferred compensation~~2015. Costs associated with land and geology ~~which are components of G&A, are based on actual costs for each~~were not allocated to the midstream and marketing segment for the three ~~and nine~~ months ended ~~September 30, 2015~~March 31, 2016 and ~~2014.~~2015.


(2)	~~DD&A is~~Depreciation and amortization was based on actual costs for ~~each~~the midstream and marketing segment with the exception of the allocation of other fixed ~~assets,~~asset depreciation, which iswas based on the number of employees in the ~~respective~~midstream and marketing segment ~~as of September 30, 2015~~for the three months ended March 31, 2016 and ~~2014.~~2015.

(3)

~~Includes~~Other operating costs and expenses includes accretion of asset retirement obligations for the ~~following expenses:~~three months ended March 31, 2016 and restructuring expense, accretion of asset retirement obligations and ~~impairments~~impairment expense for the three ~~and nine~~ months ended ~~September 30, 2015 and 2014.~~March 31, 2015. These expenses are based on actual costs to the midstream and marketing segment and are not allocated. ~~See Notes 2.f and 2.m to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of our impairments.~~


(4)	Interest expense was allocated to the midstream and ~~loss on early redemption of debt are allocated~~marketing segment based on gross property and equipment and ~~total~~life-to-date contributions to ~~our~~the Company's equity method investee ~~as of September 30, 2015~~for the three months ended March 31, 2016 and ~~2014.~~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 ~~$6.0 million and $11.5~~$7.6 million during the three ~~and nine~~ months ended ~~September 30, 2015, respectively,~~March 31, 2016 compared to the same ~~periods~~period in ~~2014. These increases are~~2015. This increase is mainly due to (i) ~~higher volumes of gathered natural gas, (ii)~~ water service revenue that we began recognizing in the third quarter of 2015 ~~(iii) oil throughput fees generated by our oil gathering line which was not operational until July~~and (ii) an increase in volumes of ~~the comparable periods ended 2014 and (iv)~~natural gas provided for natural gas lift ~~fees generated~~mainly in our ~~drilling~~production corridors ~~that were not operational until September of~~over the ~~comparable periods ended 2014.~~prior period.

Sales of purchased oil. Sales of purchased oil was $31.6 million and $31.3 million for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2016 and 2015, ~~were $43.9 million and $130.2 million,~~ respectively. ~~During the fourth quarter of 2014, we began purchasing~~We purchase oil from producers in West Texas, ~~transporting~~transport the product on the Bridgetex Pipeline and ~~selling~~sell the product to a third party in the Houston market.

Midstream service expenses, including minimum volume commitments. Midstream service expenses, including minimum volume commitments in 2015, increased by ~~$2.7 million and $3.6~~$3.2 million for the three ~~and nine~~ months ended ~~September 30, 2015, respectively,~~March 31, 2016 compared to the

same ~~periods~~period in ~~2014.~~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 was $32.9 million and $31.2 million for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2016 and 2015, ~~was $47.0 million and $132.6 million,~~ respectively. These costs include purchasing oil from producers and transporting the purchased oil on the Bridgetex Pipeline to the Houston market.

G&A. Our consolidated G&A expense has decreased for the three months ended March 31, 2016 compared to the same period in 2015. See "—Results of operations consolidated" for a discussion of these costs.

Depreciation and amortization. Depreciation and amortization increased by $0.5 million for the three months ended March 31, 2016 compared to the same period in 2015 due to the continued expansion of our midstream service infrastructure.

Income (loss) from equity method investee. We own 49% of the ownership units of Medallion. As such, we account for this investment under the equity method of accounting with our proportionate share of net income (loss) reflected in the unaudited consolidated statements of operations as "Income (loss) from equity method investee" and the carrying amount reflected in the unaudited consolidated balance sheets as "Investment in equity method investee." During the year ended December 31, 2015, Medallion began recognizing revenue due to its main pipeline becoming fully operational. See Note 14 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding this investment. ~~During the nine months ended September 30, 2015, Medallion began recognizing revenue due to its main pipeline becoming fully operational.~~

Interest expense. Interest expense increased by ~~$0.4~~$0.1 million ~~and $1.3 million during the~~for three ~~and nine~~ months ended ~~September 30, 2015, respectively,~~March 31, 2016 compared to the same period in ~~2014.~~2015. Interest is allocated to the midstream and marketing segment based on its gross property and equipment and ~~total~~life-to-date contributions to its equity method investee. We have expanded the midstream and marketing component of our business and built out our service facilities ~~significantly~~ in the past year, thereby increasing the interest expense that is allocated to this segment. The increase is slightly offset by a significant decrease in our consolidated interest expense. See "—Results of operations consolidated" for a discussion of this decrease.

~~Loss on early redemption of debt.~~ We recognized a loss on extinguishment related to the difference between the redemption price and the net carrying amount of the extinguished January 2019 Notes during the nine months ended September 30, 2015. Loss on early redemption of debt is allocated to the midstream and marketing segment based on its gross property and equipment and total contributions to its equity method investee.

Liquidity and capital resources

Our primary sources of liquidity have been cash flows from operations, proceeds from equity offerings, proceeds from senior unsecured note offerings, ~~and~~ borrowings under our Senior Secured Credit ~~Facility.~~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. A significant portion of our capital expenditures can be adjusted and managed by us. As we pursue reserves and the economic development of production in the Permian Basin, we continually monitor and consider which financing alternatives, including debt and equity capital resources, joint ventures and asset sales, are available to meet our future planned or accelerated capital expenditures. Our primary operational uses of capital have been for the acquisition, exploration and development of oil and natural gas properties, ~~LMS's~~LMS' infrastructure development and investments in ~~Medallion,~~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 ~~method investee.~~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 ~~September 30, 2015,~~May 3, 2016, we had ~~$865.0~~$605.0 million available for borrowings under our Senior Secured Credit Facility. We believe that our operating cash flow and the aforementioned liquidity sources combined with our capital budget for ~~2015~~2016 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 and natural gas. As of ~~November 2, 2015,~~May 4, 2016, approximately 100% of our anticipated oil production for the last ~~three~~nine months of ~~2015~~2016 is hedged at a weighted-average floor price of ~~$80.99~~$67.48 per Bbl and approximately ~~60%~~75% of our anticipated natural gas and NGL production for the last ~~three~~nine months of ~~2015~~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 for the calender years presented:


	Year 2015		Year 2016⁽¹⁾		Year 2017		Remaining year 2016		Year 2017		Year 2018
Oil positions⁽²⁾:
Oil positions:⁽¹⁾⁽²⁾
Total volume hedged with floor price (Bbl)	7,685,020		6,523,800		2,628,000		5,498,250		3,677,375		1,049,375
Weighted-average floor price ($/Bbl)	$	80.99	$	70.84	$	77.22	$	67.48	$	60.00	$	60.00
Natural gas positions⁽³⁾:
Natural gas positions:⁽¹⁾⁽³⁾
Total volume hedged with floor price (MMBtu)	28,600,000		18,666,000		5,475,000		14,025,000		18,771,000		12,855,500
Weighted-average floor price ($/MMBtu)	$	3.00	$	3.00	$	3.00	$	3.00	$	2.65	$	2.50


(1)	Includes derivatives entered into subsequent to ~~September 30, 2015.~~March 31, 2016.


(2)	Oil derivatives are settled based on the WTI NYMEX index oil prices.


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

The following table presents a projection of estimated cash received in future periods from oil and natural gas derivative contracts in place as of March 31, 2016 adjusted for any new hedge transactions entered into between April 1, 2016 and May 4, 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 and natural gas hedge cash proceeds⁽¹⁾	$	159,235	$	84,394	$	28,132

(1)

For this illustration we utilized the April 26, 2016 WTI index oil spot price of $40.50 held constant for all periods presented and the April 26, 2016 Waha natural gas spot price of $1.74 held constant for all periods presented. Additionally, we reduced our projected oil 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 ~~sales~~purchase price of $65.5 million. After transaction costs ~~and adjustments at closing~~ reflecting an economic effective date of July 1, 2015, the net proceeds were ~~$65.2~~$64.8 million, net of working capital adjustments and ~~subject to~~ post-closing cost adjustments.

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

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

As of ~~September 30, 2015,~~March 31, 2016, we had ~~$135.0~~$195.0 million outstanding under our Senior Secured Credit Facility and $1.3 billion in senior unsecured notes. WePrior to the semi-annual redetermination of the borrowing base under our Senior Secured Credit Facility, we had ~~$865.0~~$805.0 million available for borrowings under our Senior Secured Credit Facility and $~~76.4~~12.1 million in cash on hand for total available liquidity of ~~$941.4~~$817.1 million as of ~~September 30, 2015.~~March 31, 2016.

As of ~~November~~May 3, ~~2015~~2016, we had ~~$1.4~~$1.5 billion in debt outstanding, ~~$865.0~~$605.0 million available for borrowings under the redetermined borrowing base under our Senior Secured Credit Facility and ~~$50.9~~$7.3 million in cash on hand for total available liquidity of ~~$915.9~~$612.3 million. A continued decline in oil and natural gas prices will negatively impact our future borrowing base redeterminations. See “Part II, Item 5. Other Information-Item 1.01 Entry into a material definitive agreement” below for additional information regarding the reduction in the borrowing base and aggregate elected commitment amounts under our Senior Secured Credit Facility.

Our ~~commodity~~ derivative positions will help us stabilize a portion of our expected cash flows from operations in the event of ~~possible~~ future declines in the price of oil and natural gas. 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,						Three months ended March 31,
(in thousands)	2015			2014			2016			2015
Net cash provided by operating activities	$	225,504		$	376,336		$	56,517		$	26,865
Net cash used in investing activities	(531,877		)	(1,033,748		)	(134,164		)	(282,546		)
Net cash provided by financing activities	353,455			515,019			58,588			795,453
Net increase (decrease) in cash and cash equivalents	$	47,082		$	(142,393	)
Net (decrease) increase in cash and cash equivalents							$	(19,059	)	$	539,772

Cash flows provided by operating activities

Net cash provided by operating activities was ~~$225.5~~$56.5 million and ~~$376.3~~$26.9 million for the ~~nine~~three months ended ~~September 30,~~March 31, 2016 and 2015, ~~and 2014,~~ respectively. The ~~decrease~~increase of ~~$150.8~~$29.7 million during the three months ended March 31, 2016 compared to the same period in 2015 was largely due to the ~~$76.7 million net proceeds received for early terminations~~price related decrease in oil, NGL and natural gas revenue; however, notable cash flow changes consist of commodity derivative contracts during the nine months ended September 30, 2014. Other notable changes in net cash provided by operating activities were (i) increases of $1.31 billion in net loss and $212.5 million in deferred income tax benefit, (ii) an increase of $143.3 million in gain on derivatives, net and (iii) a $53.8 million reduction in working capital. These changes were partially offset by (i) an increase ~~of $1.40 billion~~ in impairment expense ~~during the nine months ended September 30, 2015,~~of $160.2 million, (ii) ~~an increase of $177.2 million in cash settlements received for matured derivatives, net, (iii) an increase of $44.2 million~~a decrease in depletion, depreciation and amortization expense of $30.5 million and ~~(iv) a $31.5 million loss on early redemption~~(iii) an increase in working capital changes of ~~debt during the nine months ended September 30, 2015.~~$45.0 million.

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 ~~$531.9~~$134.2 million and ~~$1.03 billion~~$282.5 million for the ~~nine~~three months ended ~~September 30,~~March 31, 2016 and 2015, ~~and 2014,~~ respectively. The decrease of ~~$501.9~~$148.4 million is mainly attributable to a ~~$434.8~~$138.6 million decrease in capital expenditures for oil and natural gas properties and a ~~$63.6~~$18.5 million ~~increase~~decrease in ~~proceeds mainly from our third-quarter 2015 divestiture of non-strategic and primarily non-operated properties.~~capital expenditures for midstream service assets. These changes were partially offset by a ~~$25.4~~$12.2 million increase in investment in our equity method investee.

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


	Nine months ended September 30,						Three months ended March 31,
(in thousands)	2015			2014			2016			2015
Capital expenditures:
Acquisition of oil and natural gas properties	$	—		$	(6,493	)
Acquisition of mineral interests	—			(7,305		)
Oil and natural gas properties	(490,351		)	(925,121		)	$	(105,155	)	$	(243,733	)
Midstream service assets	(35,237		)	(45,263		)	(1,937		)	(20,434		)
Other fixed assets	(8,539		)	(13,612		)	(630		)	(3,919		)
Investment in equity method investee	(63,011		)	(37,581		)	(26,660		)	(14,495		)
Proceeds from dispositions of capital assets, net of costs	65,261			1,627			218			35
Net cash used in investing activities	$	(531,877	)	$	(1,033,748	)	$	(134,164	)	$	(282,546	)

Capital expenditure budget

~~During the second quarter of 2015, our~~Our board of directors approved ~~an increased~~a capital expenditure budget of approximately ~~$595.0~~$345.0 million for calendar year 2015, which includes capital requirements of our equity method investee but excludes acquisitions. During the third-quarter of 2015, our board of directors approved an additional $55.0 million of contributions to Medallion to be used for additional expansion projects.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. Since we do not direct the expansion activities of Medallion as a 49% owner, we cannot predict future capital commitments.

The amount, timing and allocation of capital expenditures are largely discretionary and within management's control. If oil, NGL and natural gas prices decline below our acceptable levels, or costs increase above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. Subject to financing alternatives, we may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We consistently monitor and may adjust our projected capital

expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing and joint venture opportunities, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, reduction of service costs, contractual obligations, internally generated cash flow and other factors both within and outside our control.

Cash flows provided by financing activities

~~Our net~~Net cash ~~flows~~ provided by financing activities were ~~$353.5~~$58.6 million and ~~$515.0~~$795.5 million for the ~~nine~~three months ended ~~September 30,~~March 31, 2016 and 2015, ~~and 2014,~~ respectively. For the ~~nine~~three months ended ~~September 30,~~March 31, 2016, our primary sources of cash provided by financing activities were borrowings on our Senior Secured Credit Facility, partially offset by payments on our Senior Secured Credit Facility. For the three months ended March 31, 2015, our primary sources of cash provided by financing activities were ~~proceeds from our March 2015 Equity Offering,~~ the issuance of our March 2023 Notes and ~~borrowings on~~proceeds from our March 2015 Equity Offering, partially offset by our payment in full of our Senior Secured Credit Facility, partially offset by the redemption of our January 2019 Notes and the payments on our Senior Secured Credit Facility during the quarter ended March 31, 2015. During the nine months ended September 30, 2014, our primary source of cash provided by financing activities was proceeds from the issuance of our January 2022 Notes. Facility.

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


	Nine months ended September 30,						Three months ended March 31,
(in thousands)	2015			2014			2016			2015
Borrowings on Senior Secured Credit Facility	$	310,000		$	75,000		$	85,000		$	175,000
Payments on Senior Secured Credit Facility	(475,000		)	—			(25,000		)	(475,000		)
Issuance of March 2023 Notes	350,000			—			—			350,000
Issuance of January 2022 Notes	—			450,000
Redemption of January 2019 Notes	(576,200		)	—
Proceeds from issuance of common stock, net of offering costs	754,163			—			—			754,163
Purchase of treasury stock	(2,749		)	(4,075		)	(1,412		)	(2,283		)
Proceeds from exercise of employee stock options	—			1,885
Payments for debt issuance costs	(6,759		)	(7,791		)	—			(6,427		)
Net cash provided by financing activities	$	353,455		$	515,019		$	58,588		$	795,453

Debt

As of ~~September 30, 2015,~~March 31, 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, 2015,~~March 31, 2016, our Senior Secured Credit Facility, which matures November 4, 2018, had a maximum credit amount of $2.0 billion, a borrowing base of ~~$1.25~~$1.15 billion, an aggregate elected commitment amount of $1.0 billion and ~~$135.0~~$195.0 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. Effective May 2, 2016, in connection with the lenders' regular semi-annual redetermination of the borrowing base, the borrowing base and aggregate elected commitment amounts were each reduced to $815.0 million. See "Part II, Item 5. Other Information-Item 1.01 Entry into a material definitive agreement" below for additional information regarding the reduction in the borrowing base and aggregate elected commitment under our Senior Secured Credit Facility.

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 ratios as of ~~September 30, 2015~~March 31, 2016 and expect to be in compliance with them for the foreseeable future. ~~See "Part II, Item 5. Other Information-Item 1.01 Entry into a material definitive agreement" below for additional information regarding the Fourth Amendment to the Senior Secured Credit Facility.~~

Senior unsecured notes. ~~On March 18, 2015, we completed an offering of $350.0 million in aggregate~~The following table presents principal ~~amount of 6 1/4%~~amounts and applicable interest rates for our outstanding senior unsecured notes ~~due 2023. Our~~as of March 2023 Notes will mature on March 15, 2023 and bear an interest rate of 6 1/4% per annum and payable semi-annually in cash in arrears on March 15 and September 15 of each year, commencing September 15, 2015. Our March 2023 Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by LMS, GCM and certain of our future restricted subsidiaries. Our March 2023 Notes were issued under and are governed by an indenture and supplement thereto, each dated March 18, 2015 (collectively, the "2015 indenture"), among Laredo and Wells Fargo Bank, National Association, as trustee. The 2015 indenture contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of dividends or similar restricted payments, entering into transactions with affiliates and limitations on asset sales. Indebtedness under our March 2023 Notes may be accelerated in certain circumstances upon an event of default as set forth in the 2015 indenture.31, 2016:

On January 23, 2014, we completed an offering of $450.0 million aggregate principal amount of 5 5/8% senior unsecured notes due 2022. Our January 2022 Notes will mature on January 15, 2022 and bear an interest rate of 5 5/8% per annum, payable semi-annually, in cash in arrears on January 15 and July 15 of each year, commencing July 15, 2014. Our January 2022 Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by LMS, GCM and certain of our future restricted subsidiaries. Our January 2022 Notes were issued under and are governed by an indenture dated January 23, 2014 (the "2014 indenture"), among Laredo and Wells Fargo Bank, National Association, as trustee. The 2014 indenture contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of dividends or similar restricted payments, entering into transactions with affiliates and limitations on asset sales. Indebtedness under our January 2022 Notes may be accelerated in certain circumstances upon an event of default as set forth in the 2014 indenture.

On April 27, 2012, we completed an offering of $500.0 million aggregate principal amount of 7 3/8% senior unsecured notes due 2022. Our May 2022 Notes will mature on May 1, 2022 and bear an interest rate of 7 3/8% per annum, payable semi-annually, in cash in arrears on May 1 and November 1 of each year, commencing November 1, 2012. Our May 2022 Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by LMS, GCM and certain of our future restricted subsidiaries. Our May 2022 Notes were issued under and are governed by an indenture and supplement thereto, each dated April 27, 2012 (collectively, the "2012 indenture"), among Laredo and Wells Fargo Bank, National Association, as trustee. The 2012 indenture contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of dividends or similar restricted payments, entering into transactions with affiliates and limitations on asset sales. Indebtedness under our May 2022 Notes may be accelerated in certain circumstances upon an event of default as set forth in the 2012 indenture.

On January 20, 2011 and October 19, 2011, we completed the offerings of $350.0 million principal amount and $200.0 million principal amount, respectively, of 9 1/2% senior unsecured notes due 2019. Our January 2019 Notes were due to mature on February 15, 2019 and bore an interest rate of 9 1/2% per annum, payable semi-annually, in cash in arrears on February 15 and August 15 of each year. Our January 2019 Notes were fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by LMS, GCM and certain of our future restricted subsidiaries. Our January 2019 Notes were issued under and are governed by an indenture dated January 20, 2011, among Laredo and Wells Fargo Bank, National Association, as trustee (the "2011 indenture"). The 2011 indenture contained customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of dividends or similar restricted payments, entering into transactions with affiliates and limitations on asset sales.



(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 45 of our audited consolidated financial statements included in the ~~2014~~2015 Annual Report and ~~Note~~Notes 5 and 19 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 4, 2015,~~May 3, 2016, we had a total of $1.3 billion of senior unsecured notes outstanding and ~~$135.0~~$210.0 million outstanding on the Senior Secured Credit Facility.

Obligations and commitments

As of ~~September 30, 2015,~~March 31, 2016, our contractual obligations included our March 2023 Notes, January 2022 Notes, May 2022 Notes, Senior Secured Credit Facility, drilling contract commitments, ~~derivatives, performance unit liability awards,~~firm sale and transportation commitments, derivative deferred premiums, asset retirement obligations, office and equipment leases and capital contribution commitments to our equity method investee. From December 31, ~~2014~~2015 to ~~September 30, 2015,~~March 31, 2016, the material changes in our contractual obligations included (i) ~~a decrease of $759.0 million in principal and interest due to the redemption of the January 2019 Notes, (ii)~~ an increase of ~~$525.0 million in principal and interest due to the March 2023 Notes offering, (iii) a decrease of $165.0~~$60.0 million outstanding on our Senior Secured Credit Facility, ~~(iv)~~(ii) a decrease of ~~$80.8~~$23.6 million on our interest obligations for our senior unsecured notes as semi-annual interest payments were made in January ~~February, May, July~~ and ~~September 2015,~~March of 2016, (iii) a decrease of $13.8 million in our firm sale and transportation commitments, (iv) ~~an increase~~a decrease of ~~$16.0~~$26.7 million in our outstanding capital contribution commitment to our equity method investee due to ~~new commitments~~payments made to ~~fund the construction of pipeline extensions to capture additional third-party production and~~Medallion during first-quarter 2016, (v) a decrease of ~~$26.8~~$6.8 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, ~~11,~~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, restructuring expenses, gains or losses on derivatives, cash settlements ofreceived for matured ~~commodity~~ derivatives, cash settlements onreceived for early ~~terminated commodity~~terminations of derivatives, premiums paid for derivatives, ~~that matured during the period,~~ interest expense, write-off of debt issuance costs, gains or losses on disposal of assets, loss on early redemption of debt and buyout of minimum volume commitment. Adjusted EBITDA provides no information regarding a ~~company’s~~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~~company's operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods, book value of assets, capital structure and the method by which assets were acquired, among other factors;

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

is used by our management for various purposes, including as a measure of operating performance, in presentations to our board of directors and as a basis for strategic planning and forecasting.

There are significant limitations to the use of Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations to different companies and the different methods of calculating Adjusted EBITDA reported by different companies. Our measurements of Adjusted EBITDA for financial reporting as compared to compliance under our debt agreements differ.

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

Three months ended September 30,
Nine months ended September 30,
(in thousands) 2015
2014
2015
2014
Net income (loss) $ (847,783 )
$ 83,407

$ (1,245,289 )
$ 64,295
Plus:

Deferred income tax expense (benefit) 41,258

45,778

(176,945 )
35,511
Depletion, depreciation and amortization 66,777

63,942

210,831

166,605
Bad debt expense
107

—

107

—
Impairment expense
906,850

—

1,397,327

—
Non-cash stock-based compensation, net of amounts capitalized 6,877

6,194

17,933

16,919
Restructuring expenses —
—
6,042
—
(Gain) loss on derivatives, net
(142,580 )
(92,790 )
(141,836 )
1,447
Cash settlements received (paid) for matured commodity derivatives, net
66,142

4,531

175,879

(1,320 )
Cash settlements received for early terminations of commodity derivatives, net
—

—

—

76,660
Premiums paid for derivatives that matured during the period⁽¹⁾
(1,248 )
(1,820 )
(3,918 )
(5,599 )
Interest expense 23,348

30,549

79,732

90,192
Write-off of debt issuance costs —
—
—
124
Loss on disposal of assets, net
94

2,192

1,937

2,418
Loss on early redemption of debt —
—
31,537
—
Buyout of minimum volume commitment —
—
3,014
—
Adjusted EBITDA $ 119,842

$ 141,983

$ 356,351

$ 447,252


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



	Three months ended March 31,
(in thousands)	2016			2015
Net loss	$	(180,371	)	$	(472	)
Plus:
Deferred income tax expense	—			3,643
Depletion, depreciation and amortization	41,478			71,942
Impairment expense	161,064			878
Non-cash stock-based compensation, net of amounts capitalized	3,838			4,788
Restructuring expenses	—			6,042
Gain on derivatives, net	(17,885		)	(63,155		)
Cash settlements received for matured derivatives, net	65,937			63,141
Cash settlements received for early terminations of derivatives, net	80,000			—
Premiums paid for derivatives	(81,850		)	(1,421		)
Interest expense	23,705			32,414
Loss on disposal of assets, net	160			762
Adjusted EBITDA	$	96,076		$	118,562

Critical accounting policies and estimates

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

In ~~management’s~~management's opinion, the more significant reporting areas impacted by our judgments and estimates are (i) the choice of accounting method for oil and natural gas activities, (ii) estimation of oil and natural gas reserve quantities and standardized measure of future net revenues, (iii) ~~revenue recognition, (iv) fair value of assets acquired and liabilities assumed in an acquisition, (v)~~ impairment of oil and natural gas properties, (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) ~~estimation~~fair value of ~~income taxes. Management’s~~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~~three months ended ~~September 30, 2015.~~March 31, 2016. For our other critical accounting policies and procedures, please see our disclosure of critical accounting policies in "Part II, Item 7. ~~Management’s~~Management's Discussion and Analysis of Financial Condition and Results of Operations" of the

~~2014~~ 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

As of September 30, 2015, we early adopted new guidance regarding the presentation of debt issuance costs. For additional discussion of this early adoption and other recent accounting pronouncements, seeSee Note 18 to our unaudited consolidated financial statements included elsewhere in this Quarterly ~~Report.~~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, drilling contracts 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 ofin oil, NGL and natural gas prices, we use ~~commodity~~ derivatives, such as puts, swaps, collars ~~swaps, puts~~ and, in prior periods, basis swaps to hedge price risk associated with a significant portion of our anticipated production. By removing a ~~majority~~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 ~~commodity~~ derivatives using an independent third-party valuation and recognize the associated gain or loss in our unaudited consolidated statements of operations.

The fair values of our ~~commodity~~ derivatives are largely determined by estimates of the forward curves of the relevant price indices. As of ~~September 30, 2015,~~March 31, 2016, a 10% change in the forward curves associated with our ~~commodity~~ derivatives would have changed our net positions to the following amounts:


(in thousands)	10% Increase		10% Decrease		10% Increase		10% Decrease
Commodity derivatives	$	234,463	$	335,425
Derivatives					$	193,960	$	271,550

As of ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014,~~2015, the fair values of our open derivative contracts were ~~$282.0~~$230.0 million and ~~$312.3~~$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, 2015,~~March 31, 2016, we had ~~$135.0~~$195.0 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, 2015,~~March 31, 2016, as shown in the table below.


	Expected maturity date																					Expected maturity date
(in millions except for interest rates)	2015			2016			2017			2018			2019			Thereafter			Total			2018			2022			2023			Total
January 2022 Notes - fixed rate	$	—		$	—		$	—		$	—		$	—		$	450.0		$	450.0		$	—		$	450.0		$	—		$	450.0
Average interest rate	—		%	—		%	—		%	—		%	—		%	5.625		%	5.625		%	—		%	5.625		%	—		%	5.625		%
May 2022 Notes - fixed rate	$	—		$	—		$	—		$	—		$	—		$	500.0		$	500.0		$	—		$	500.0		$	—		$	500.0
Average interest rate	—		%	—		%	—		%	—		%	—		%	7.375		%	7.375		%	—		%	7.375		%	—		%	7.375		%
March 2023 Notes - fixed rate	$	—		$	—		$	—		$	—		$	—		$	350.0		$	350.0		$	—		$	—		$	350.0		$	350.0
Average interest rate	—		%	—		%	—		%	—		%	—		%	6.250		%	6.250		%	—		%	—		%	6.250		%	6.250		%
Senior Secured Credit Facility - variable rate	$	—		$	—		$	—		$	135.0		$	—		$	—		$	135.0		$	195.0		$	—		$	—		$	195.0
Average interest rate	—		%	—		%	—		%	1.724		%	—		%	—		%	1.724		%	1.944		%	—		%	—		%	1.944		%

Counterparty and customer credit risk

As of ~~September 30, 2015,~~March 31, 2016, our principal exposures to credit risk are through receivables of (i) ~~$282.0~~$230.2 million from ~~derivatives,~~the fair values of our open derivative contracts, (ii) ~~$34.5~~$31.1 million from the sale of our oil, NGL and natural gas production ~~which~~that we market to energy marketing companies and refineries, (iii) ~~$25.6~~$23.0 million from ~~joint interest parties,~~joint-interest partners, (iv) ~~$21.7~~$18.1 million from matured derivatives and (v) ~~$14.4~~$12.3 million from ~~midstream product sales.~~sales of purchased oil and other products.

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 1011 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, 2015.~~March 31, 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, 2015~~March 31, 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 ~~2014~~2015 Annual ~~Report and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2015, as well as the updated risk factor set forth below. Other than such updates, there~~Report. There have been no material changes in our risk factors from those described in the ~~2014~~2015 Annual ~~Report and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2015.~~Report. The risks described in the ~~2014~~2015 Annual Report ~~and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2015~~ 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.

~~Risks related to our business~~

~~As a result of the sustained commodity price decrease, we have taken and may be required to take further write-downs of the carrying values of our properties.~~

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we have been required to and may be required to further write-down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings.

Oil, NGL and natural gas prices have significantly declined since mid-2014 and have remained low in the third-quarter of 2015. Primarily as a result of these lower prices, our September 30, 2015 estimated proved reserves decreased 37 MMBOE from our December 31, 2014 reserves, converted to three streams. Additionally, we recorded non-cash full cost ceiling impairments of $488.0 million and $906.4 million in the second and third quarters of 2015, respectively. If prices remain at or below current levels, we will incur another impairment charge in the fourth quarter of 2015 and may incur further charges in the future. Such charges could have a material adverse effect on our results of operations for the periods in which they are taken. See Note 2.h to our audited consolidated financial statements included in our 2014 Annual Report for additional information.

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, 2015 - July 31, 2015 2,952
$ 10.65
—
—
August 1, 2015 - August 31, 2015 4,419
$ 8.70
—
—
September 1, 2015 - September 30, 2015 8,872
$ 9.92
—
—
Total 16,243



Period	Total number of shares withheld⁽¹⁾	Average price per share		Total number of shares purchased as part of publicly announced plans	Maximum number of shares that may yet be purchased under the plan
January 1, 2016 - January 31, 2016	1,954	$	7.59	—	—
February 1, 2016 - February 29, 2016	271,133	$	5.08	—	—
March 1, 2016 - March 31, 2016	3,130	$	7.00	—	—
Total	276,217


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

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

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

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

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

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

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

(a) Santander UK plc ("Santander UK") holds two frozen savings accounts and ~~one~~two frozen current ~~account~~accounts for ~~two~~three customers, resident in the U.K., who are currently designated by the U.S. ~~for terrorism.~~under the Specially Designed Global Terrorist ("SDGT") sanctions program. The accounts held by each customer were blocked after the customer's designation and have remained blocked and dormant throughout the ~~nine months ended September 30, 2015.~~first quarter of 2016. Revenue generated by Santander UK on these accounts ~~is negligible.~~in the first quarter of 2016 was £3.67 whilst net profits in the first quarter of 2016 were negligible relative to the overall profits of Banco Santander, S.A.

(b) An Iranian national, resident in the U.K., who is currently designated by the U.S. under the Iranian Financial Sanctions Regulations ("IFSR") and the Weapons of Mass Destruction Proliferators Sanctions Regulations, ~~("NPWMD sanctions program"),~~ holds a mortgage with Santander UK that was issued prior to any such designation. No further drawdown has been made (or would be allowed) under this mortgage although Santander UK continues to receive repayment installments. In the ~~nine months ended September 30, 2015,~~first quarter of 2016, total revenue generated by Santander UK in connection with the mortgage was ~~approximately £2,928 while~~£201.22 whilst net profits were negligible relative to the overall profits of Banco Santander, ~~UK.~~S.A. Santander UK does not intend to enter into any new relationships with this customer, and any disbursements will only be made in accordance with applicable sanctions. The same Iranian national also holds two investment accounts with Santander ~~Asset Management UK~~ISA Managers Limited. The funds in both accounts are invested in the same portfolio fund. The accounts have remained frozen during the ~~nine months ended September 30, 2015.~~first quarter of 2016. The investment returns are being automatically reinvested, and no disbursements have been made to the customer. Total revenue ~~for~~in the first quarter of 2016 generated by Santander ~~Group~~UK in connection with the investment accounts was ~~approximately £161 while~~£4.89 whilst net profits in the ~~nine months ended September 30, 2015~~first quarter 2016 were negligible relative to the overall profits of Banco Santander, S.A.

~~In addition, during the third-quarter of 2015, two additional Santander UK customers were designated. First, a~~(c) A U.K. national designated by the U.S. under the Specially Designated Global Terrorist ("SDGT") sanctions program who is on the U.S. Specially Designated National ("SDN") list. This customer holds a bank account which generated revenue of approximately £183 during the third quarter of 2015. A stop was placed on the account. Net profits in the third quarter of 2015 were negligible relative to the overall profits of Santander UK. Second, a U.K. national also designated by the U.S. under the SDGT sanctions program ~~and on~~holds a Santander UK current account. The account remained in arrears through the ~~U.S. SDN list, held a bank account. No transactions were made in the third~~first quarter of ~~2015~~2016 (£1,344.01 in debt) and is currently being managed by Santander UK Collections & Recoveries department.

(d) In addition, during the first quarter of 2016, Santander UK has identified an OFAC match on a power of attorney account. A party listed on the account is ~~blocked~~currently designated by the U.S. under the SDGT and IFSR sanctions programs. During the first quarter of 2016, related revenue generated by Santander UK was £73.81 whilst net profits in ~~arrears.~~the first quarter of 2016 were negligible relative to the overall profits of Banco Santander, S.A.

Item 1.01 Entry into a material definitive agreement

~~On October 30, 2015,~~Effective May 2, 2016, in connection with ~~our~~the regular semi-annual redetermination of the borrowing base under our Senior Secured Credit Facility, we ~~entered into~~received the ~~Fourth Amendment to Fourth Amended and Restated Credit Agreement among Laredo,~~Memorandum of Borrowing Base Reduction attached hereto as Exhibit 10.1 from Wells Fargo Bank, N.A., asthe administrative agent under the ~~guarantors signatory thereto and the banks signatory thereto (the "Amendment"). Pursuant to the Amendment, among~~

~~other things, (i)~~Senior Secured Credit Facility, providing that the borrowing base ~~was decreased from $1.25 billion~~and aggregate elected commitment amounts were each reduced to ~~$1.15 billion,~~$815.0 million. This redetermined borrowing base shall remain in effect until the earlier of (i) the next scheduled semi-annual redetermination date or (ii) the ~~amount of “permitted investments” in Medallion (regardless of whether made before, on or following~~date the ~~date~~borrowing base is otherwise adjusted pursuant to the terms of the ~~Amendment) was increased to $225.0 million in the aggregate at any time and (iii) certain~~Senior Secured Credit Facility. The other terms of the Senior Secured Credit Facility ~~including certain non-financial representations~~remain unchanged and ~~warranties~~are discussed in Note 5.e to our unaudited consolidated financial statements included elsewhere in this Quarterly Report and ~~covenants, were amended as set forth~~Note 5.f to our audited consolidated financials included in our 2015 Annual Report. As of May 4, 2016, the ~~Amendment. The~~outstanding balance under the Senior Secured Credit Facility ~~matures on November 4, 2018 and has a maximum credit amount of $2.0 billion and an aggregate elected commitment of $1.0 billion.~~ was $210.0 million.

The foregoing ~~summary~~description of the ~~Amendment~~Memorandum of Borrowing Base Reduction is ~~not complete~~a summary only and is qualified in its entirety by reference to the complete text of the ~~Amendment,~~Memorandum of Borrowing Base Reduction, a copy of which is ~~filed~~attached as Exhibit 10.1 to this Quarterly Report and is incorporated herein by ~~reference into this Item 1.01.~~reference.

Item 2.03 Creation of a direct financial obligation or an obligation under an off-balance sheet arrangement of a registrant

The disclosure set forth under Item 1.01 above is incorporated by reference into this Item 2.03.

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, ~~Holdings,~~ Inc. (incorporated by reference to Exhibit ~~3.2~~3.3 of Laredo's ~~Current~~Annual Report on Form ~~8-K~~10-K (File No. 001-35380) filed on ~~December 22, 2011)~~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).

10.1*			~~Fourth Amendment to Fourth Amended and Restated Credit Agreement,~~Memorandum of Borrowing Base Reduction, dated ~~as of October 30, 2015, among Laredo Petroleum, Inc.,~~May 2, 2016, from Wells Fargo, Bank, N.A.~~, as administrative agent,~~ to Laredo ~~Midstream Services, LLC, Garden City Minerals, LLC and the banks signatory thereto.~~Petroleum, Inc.

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~~May 5, ~~2015~~2016	By:	/s/ Randy A. Foutch
		Randy A. Foutch
		Chairman and Chief Executive Officer
		(principal executive officer)

Date: ~~November~~May 5, ~~2015~~2016	By:	/s/ Richard C. Buterbaugh
		Richard C. Buterbaugh
		Executive Vice President and Chief Financial Officer
		(principal financial officer)

	By:
Date: ~~November~~May 5, ~~2015~~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, ~~Holdings,~~ Inc. (incorporated by reference to Exhibit ~~3.2~~3.3 of Laredo's ~~Current~~Annual Report on Form ~~8-K~~10-K (File No. 001-35380) filed on ~~December 22, 2011)~~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).

10.1*			~~Fourth Amendment to Fourth Amended and Restated Credit Agreement,~~Memorandum of Borrowing Base Reduction, dated ~~as of October 30, 2015, among Laredo Petroleum, Inc.,~~May 2, 2016, from Wells Fargo, Bank, N.A.~~, as administrative agent,~~ to Laredo ~~Midstream Services, LLC, Garden City Minerals, LLC and the banks signatory thereto.~~Petroleum, Inc.

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.

6460



(in thousands)
Remaining 2015	$	1,116
2016	4,503
2017	4,575
2018	4,349
2019	2,915
Thereafter	7,589
Total	$	25,047



(in thousands)	Nine months ended September 30, 2015			Year ended December 31, 2014
Liability at beginning of period	$	32,198		$	21,743
Liabilities added due to acquisitions, drilling, midstream service asset construction and other	1,675			6,370
Accretion expense	1,771			1,787
Liabilities settled upon plugging and abandonment	(122		)	(450		)
Liabilities removed due to sale of property	(2,005		)	—
Revision of estimates	—			2,748
Liability at end of period	$	33,517		$	32,198



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



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	%



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