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~~June 30, ~~2017~~2018

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 website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 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, a smaller reporting company or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer ý		Accelerated filer o

Non-accelerated filer o		Smaller reporting company o
(Do not check if a smaller reporting company)

Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý

Number of shares of registrant's common stock outstanding as of ~~October~~July 30, ~~2017: 242,512,535~~2018: 235,151,105

LAREDO PETROLEUM, INC.

TABLE OF CONTENTS



		Page
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS	iii
	Part I	1
Item 1.	Consolidated Financial Statements (Unaudited):	1
	Consolidated balance sheets as of ~~September~~June 30, ~~2017~~2018 and December 31, ~~2016~~2017	1
	Consolidated statements of operations for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016~~2017	2
	Consolidated statement of stockholders' equity for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018	3
	Consolidated statements of cash flows for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016~~2017	4
	Condensed notes to the consolidated financial statements:	5
	Note 1—Organization and basis of presentation	5
	Note 2—~~Basis of presentation and significant~~Recently issued or adopted accounting ~~policies~~pronouncements	5
Note 3—Acquisitions and divestitures	6
Note ~~3—Divestiture~~4—Revenue recognition	8
Note 5—Property and equipment	11
Note 6—Debt	12
	Note ~~4—Debt~~7—Stockholders' equity and stock-based compensation	13
	Note ~~5—Employee compensation~~	14
	~~Note 6—Income taxes~~	18
	~~Note 7—~~8—Derivatives	1816
Note 9—Fair value measurements	19
Note ~~8—Fair value measurements~~10—Net income per common share	22
	~~Note 9—Net income (loss) per common share~~	26
	~~Note 10—Credit risk~~	27
	Note 11—Commitments and contingencies	2723
	Note 12—~~Related parties~~Supplemental cash flow information	2825
	Note 13—~~Segments~~Asset retirement obligations	2825
Note 14—Income taxes	26
Note ~~14—~~15—Related party	26
Note 16—Subsidiary guarantors	3126
	Note ~~15—Recently issued or adopted accounting pronouncements~~	34
	~~Note 16—~~17—Subsequent events	35
	~~Note 17—Supplementary information~~	3630
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	3731
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	5244
Item 4.	Controls and Procedures	5445
	Part II	46
Item 1.	Legal Proceedings	5546
Item 1A.	Risk Factors	5546
Item 2.	~~Repurchase~~ Purchases of Equity Securities	5548
Item 3.	Defaults Upon Senior Securities	5548
Item 4.	Mine Safety Disclosures	5548
Item 5.	Other Information	5548
Item 6.	Exhibits	5749
SIGNATURES	5850

Table of Contents

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in or incorporated by reference into this Quarterly Report on Form 10-Q (this "Quarterly Report") are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). These forward-looking statements include statements, projections and estimates concerning our operations, performance, business strategy, oil and natural gas reserves, drilling program capital expenditures, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, derivative activities and potential financing. Forward-looking statements are generally accompanied by words such as "estimate," "project," "predict," "believe," "expect," "anticipate," "potential," "could," "may," "will," "foresee," "plan," "goal," "should," "intend," "pursue," "target," "continue," "suggest" or the negative thereof or other variations thereof or other words that convey the uncertainty of future events or outcomes. Forward-looking statements are not guarantees of performance. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Among the factors that significantly impact our business and could impact our business in the future are:

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

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

~~impacts to our financial statements as a result of impairment write-downs;~~the Permian Basin;

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

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

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

capital requirements for our operations and projects;

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

the availability and costs of sufficient pipeline and transportation facilities and gathering and processing capacity in the Permian Basin, including the impact on steel costs and supplies following the Administration'simposed 25% global tariffs on certain imported steel mill products;

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

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

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

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

the impact of share repurchases or our suspension or discontinuation of the share repurchase program at any time;

the potential impact on production of oil, NGL and natural gas from our wells due to tighter spacing of our wells;

our ability to hedge and regulations that affect our ability to hedge;

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

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

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

risks related to the geographic concentration of our assets;

changes in the regulatory environment and changes in United States or international legal, political, administrative or economic conditions, including 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;

iii

Table of Contents

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

our ability to execute our strategies;

competition in the oil and natural gas industry;

the adverse outcome and impact of litigation, legal proceedings, investigations orand insurance or other claims, including the adverse outcome and impact of pending or protracted litigation;

~~changes in the regulatory environment and changes in United States or 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 increased costs of drilling and production equipment, labor and oil and natural gas processing and other services in the Permian Basin;~~

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

~~iii~~

~~Table of Contents~~

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

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

~~our ability to recruit and retain~~ the ~~qualified personnel necessary to operate our business.~~impact of the new tax laws enacted on December 22, 2017.

These forward-looking statements involve a number of risks and uncertainties that could cause actual results to differ materially from those suggested by the forward-looking statements. Forward-looking statements should, therefore, be considered in light of various factors, including those set forth under "Part I, Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" and elsewhere in this Quarterly Report, under "Part I, Item 1A. Risk Factors" and "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in our Annual Report on Form 10-K for the fiscal year ended December 31, ~~2016~~2017 (the ~~"2016~~"2017 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.

Table of Contents

Part I

Item 1. Consolidated Financial Statements (Unaudited)

Laredo Petroleum, Inc.

Consolidated balance sheets

(in thousands, except share data)

(Unaudited)


	September 30, 2017			December 31, 2016			June 30, 2018			December 31, 2017
Assets
Current assets:
Cash and cash equivalents	$	20,818		$	32,672		$	36,604		$	112,159
Accounts receivable, net	89,840			86,867			101,321			100,645
Derivatives	15,611			20,947			8,059			6,892
Other current assets	16,196			14,291			23,710			15,686
Total current assets	142,465			154,777			169,694			235,382
Property and equipment:
Oil and natural gas properties, full cost method:
Evaluated properties	5,863,536			5,488,756			6,432,913			6,070,940
Unevaluated properties not being depleted	211,720			221,281			156,815			175,865
Less accumulated depletion and impairment	(4,616,246		)	(4,514,183		)	(4,746,413		)	(4,657,466		)
Oil and natural gas properties, net	1,459,010			1,195,854			1,843,315			1,589,339
Midstream service assets, net	130,407			126,240			134,827			138,325
Other fixed assets, net	41,902			44,773			42,384			40,721
Property and equipment, net	1,631,319			1,366,867			2,020,526			1,768,385
Derivatives	4,345			8,718			3,074			3,413
Investment in equity method investee (Note 16.a)	276,435			243,953
Other assets, net	11,762			8,031
Other noncurrent assets, net							15,993			16,109
Total assets	$	2,066,326		$	1,782,346		$	2,209,287		$	2,023,289
Liabilities and stockholders' equity
Current liabilities:
Accounts payable	$	22,795		$	15,054
Accounts payable and accrued liabilities							$	74,252		$	58,341
Accrued capital expenditures							73,843			82,721
Undistributed revenue and royalties	33,222			26,838			45,998			37,852
Accrued capital expenditures	70,001			30,845
Derivatives	4,170			20,993			44,119			22,950
Other current liabilities	93,072			94,215			45,208			75,555
Total current liabilities	223,260			187,945			283,420			277,419
Long-term debt, net	1,440,968			1,353,909			902,745			791,855
Derivatives	362			5,694			5,876			384
Asset retirement obligations	52,181			50,604			54,674			53,962
Other noncurrent liabilities	3,330			3,621			3,405			134,090
Total liabilities	1,720,101			1,601,773			1,250,120			1,257,710
Commitments and contingencies
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of September 30, 2017 and December 31, 2016	—			—
Common stock, $0.01 par value, 450,000,000 shares authorized and 242,526,932 and 241,929,070 issued and outstanding as of September 30, 2017 and December 31, 2016, respectively	2,425			2,419
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of June 30, 2018 and December 31, 2017							—			—
Common stock, $0.01 par value, 450,000,000 shares authorized and 235,193,588 and 242,521,143 issued and outstanding as of June 30, 2018 and December 31, 2017, respectively							2,352			2,425
Additional paid-in capital	2,421,469			2,396,236			2,364,833			2,432,262
Accumulated deficit	(2,077,669		)	(2,218,082		)	(1,408,018		)	(1,669,108		)
Total stockholders' equity	346,225			180,573			959,167			765,579
Total liabilities and stockholders' equity	$	2,066,326		$	1,782,346		$	2,209,287		$	2,023,289

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 June 30,						Six months ended June 30,
	2017			2016			2017			2016			2018			2017			2018			2017
Revenues:
Oil, NGL and natural gas sales	$	157,558		$	114,805		$	438,131		$	290,473
Oil sales													$	159,051		$	104,214		$	309,965		$	203,681
NGL sales													36,805			19,801			65,165			40,629
Natural gas sales													12,705			17,822			30,865			36,263
Midstream service revenues	2,446			2,488			8,148			5,921			1,976			2,703			4,335			5,702
Sales of purchased oil	45,814			42,441			135,546			116,670			140,509			42,461			200,412			89,732
Total revenues	205,818			159,734			581,825			413,064			351,046			187,001			610,742			376,007
Costs and expenses:
Lease operating expenses	19,594			18,177			56,690			57,920			22,642			20,104			44,593			37,096
Production and ad valorem taxes	9,558			7,066			26,811			21,483			12,405			8,472			24,217			17,253
Transportation and marketing expenses													1,534			—			1,534			—
Midstream service expenses	1,174			1,039			2,986			2,826			403			896			1,096			1,812
Costs of purchased oil	47,385			44,232			141,661			121,190			140,578			44,020			201,242			94,276
General and administrative	25,000			26,105			72,605			66,058			26,834			22,008			51,559			47,605
Depletion, depreciation and amortization	41,212			35,158			113,327			110,813			50,762			38,003			96,315			72,115
Impairment expense	—			—			—			162,027
Other operating expenses	1,443			2,465			3,906			4,169			1,121			1,437			2,227			2,463
Total costs and expenses	145,366			134,242			417,986			546,486			256,279			134,940			422,783			272,620
Operating income (loss)	60,452			25,492			163,839			(133,422		)
Operating income													94,767			52,061			187,959			103,387
Non-operating income (expense):
Gain (loss) on derivatives, net	(27,441		)	6,850			38,127			(43,783		)	(45,976		)	28,897			(36,966		)	65,568
Income from equity method investee (Note 16.a)	2,371			265			7,910			6,259
Income from equity method investee (see Note 3.c)													—			2,471			—			5,539
Interest expense	(23,697		)	(23,077		)	(69,590		)	(70,294		)	(14,424		)	(23,173		)	(27,942		)	(45,893		)
Interest and other income	333			33			527			143			443			49			896			194
Write-off of debt issuance costs	—			—			—			(842		)
Loss on disposal of assets, net	(991		)	(78		)	(400		)	(379		)
Non-operating expense, net	(49,425		)	(16,007		)	(23,426		)	(108,896		)
Income (loss) before income taxes	11,027			9,485			140,413			(242,318		)
Gain (loss) on disposal of assets, net													(1,358		)	805			(3,975		)	591
Non-operating income (expense), net													(61,315		)	9,049			(67,987		)	25,999
Income before income taxes													33,452			61,110			119,972			129,386
Income tax:
Deferred	—			—			—			—			—			—			—			—
Total income tax	—			—			—			—			—			—			—			—
Net income (loss)	$	11,027		$	9,485		$	140,413		$	(242,318	)
Net income (loss) per common share:
Net income													$	33,452		$	61,110		$	119,972		$	129,386
Net income per common share:
Basic	$	0.05		$	0.04		$	0.59		$	(1.09	)	$	0.14		$	0.26		$	0.51		$	0.54
Diluted	$	0.05		$	0.04		$	0.57		$	(1.09	)	$	0.14		$	0.25		$	0.51		$	0.53
Weighted-average common shares outstanding:
Basic	239,306			234,639			239,017			221,303			230,933			239,231			234,561			238,870
Diluted	244,887			238,108			244,693			221,303			231,706			244,417			235,501			244,385

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

Laredo Petroleum, Inc.

Consolidated statement of stockholders' equity

(in thousands)

(Unaudited)


	Common Stock					Additional paid-in capital				Treasury Stock (at cost)						Accumulated deficit								Common Stock						Additional paid-in capital				Treasury Stock (at cost)						Accumulated deficit
	Shares		Amount						Shares			Amount				Accumulated deficit			Total				Shares			Amount				Additional paid-in capital			Shares			Amount				Accumulated deficit			Total
Balance, December 31, 2016	241,929		$	2,419		Additional paid-in capital	$	2,396,236			—			$	—		$	(2,218,082	)		$	180,573
Balance, December 31, 2017																								242,521			$	2,425		$	2,432,262			—			$	—		$	(1,669,108	)		$	765,579
Adjustment to the beginning balance of accumulated deficit upon adoption of ASC 606 (see Note 4.a)																								—			—			—				—			—			141,118				141,118
Restricted stock awards	1,213		12			(12		)		—			—			—				—				3,193			32			(32		)		—			—			—				—
Restricted stock forfeitures	(264	)	(3		)	3				—			—			—				—				(126	)		(1		)	1				—			—			—				—
Performance share conversion	150		2			(2		)		—			—			—				—
Share repurchases																								—			—			—				9,879			(87,218		)	—				(87,218		)
Vested stock exchanged for tax withholding	—		—			—				545			(7,638		)	—				(7,638		)		—			—			—				515			(4,397		)	—				(4,397		)
Retirement of treasury stock	(545	)	(5		)	(7,633		)		(545	)		7,638			—				—				(10,394	)		(104		)	(91,511		)		(10,394	)		91,615			—				—
Exercise of stock options	44		—			358				—			—			—				358
Stock-based compensation	—		—			32,519				—			—			—				32,519				—			—			24,113				—			—			—				24,113
Net income	—		—			—				—			—			140,413				140,413				—			—			—				—			—			119,972				119,972
Balance, September 30, 2017	242,527		$	2,425		$	2,421,469			—			$	—		$	(2,077,669	)		$	346,225
Balance, June 30, 2018																								235,194			$	2,352		$	2,364,833			—			$	—		$	(1,408,018	)		$	959,167

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,						Six months ended June 30,
	2017			2016			2018			2017
Cash flows from operating activities:
Net income (loss)	$	140,413		$	(242,318	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net income							$	119,972		$	129,386
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization	113,327			110,813			96,315			72,115
Impairment expense	—			162,027
Non-cash stock-based compensation, net of amounts capitalized	26,877			19,562
Non-cash stock-based compensation, net							20,015			17,911
Mark-to-market on derivatives:
(Gain) loss on derivatives, net	(38,127		)	43,783			36,966			(65,568		)
Cash settlements received for matured derivatives, net	34,791			157,626
Cash settlements received for early terminations of derivatives, net	4,234			80,000
Settlements (paid) received for matured derivatives, net							(2,055		)	21,156
Settlements received for early terminations of derivatives, net							—			4,234
Change in net present value of derivative deferred premiums	199			184			396			111
Cash premiums paid for derivatives	(13,542		)	(86,972		)
Premiums paid for derivatives							(9,475		)	(12,094		)
Amortization of debt issuance costs	3,132			3,231			1,638			2,094
Write-off of debt issuance costs	—			842
Income from equity method investee (Note 16.a)	(7,910		)	(6,259		)
Cash settlement of performance unit awards	—			(6,394		)
Income from equity method investee (see Note 3.c)							—			(5,539		)
Other, net	3,445			2,973			6,910			1,414
(Increase) decrease in accounts receivable	(2,973		)	6,476			(2,331		)	14,760
Increase in other assets	(3,220		)	(594		)
Increase in accounts payable	7,741			5,852
Increase (decrease) in undistributed revenues and royalties	6,384			(9,866		)
(Decrease) increase in other accrued liabilities	(2,430		)	4,785
Increase in other current assets							(10,974		)	(3,545		)
Decrease in other noncurrent assets							1,835			29
Increase (decrease) in accounts payable and accrued liabilities							15,911			(13,718		)
Increase in undistributed revenues and royalties							8,146			5,328
Decrease in other current liabilities							(20,124		)	(11,008		)
Decrease in other noncurrent liabilities	(290		)	(297		)	(544		)	(165		)
Net cash provided by operating activities	272,051			245,454			262,601			156,901
Cash flows from investing activities:
Acquisitions of oil and natural gas properties							(16,340		)	—
Capital expenditures:
Acquisitions of oil and natural gas properties	—			(115,600		)
Oil and natural gas properties	(381,165		)	(276,735		)	(341,534		)	(232,219		)
Midstream service assets	(11,680		)	(4,231		)	(5,205		)	(6,117		)
Other fixed assets	(3,604		)	(982		)	(4,965		)	(2,683		)
Investment in equity method investee (Note 16.a)	(24,572		)	(58,712		)
Proceeds from disposition of equity method investee, net of selling costs (see Note 3.c)							1,655			—
Proceeds from dispositions of capital assets, net of selling costs	64,128			365			12,317			63,441
Net cash used in investing activities	(356,893		)	(455,895		)	(354,072		)	(177,578		)
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility	155,000			214,682			110,000			90,000
Payments on Senior Secured Credit Facility	(70,000		)	(279,682		)	—			(55,000		)
Proceeds from issuance of common stock, net of offering costs	—			276,052
Purchase of treasury stock	(7,638		)	(1,613		)
Share repurchases							(87,218		)	—
Vested stock exchanged for tax withholding							(4,397		)	(7,597		)
Proceeds from exercise of stock options	358			208			—			358
Payments for debt issuance costs	(4,732		)	—			(2,469		)	(4,732		)
Net cash provided by financing activities	72,988			209,647			15,916			23,029
Net decrease in cash and cash equivalents	(11,854		)	(794		)
Net (decrease) increase in cash and cash equivalents							(75,555		)	2,352
Cash and cash equivalents, beginning of period	32,672			31,154			112,159			32,672
Cash and cash equivalents, end of period	$	20,818		$	30,360		$	36,604		$	35,024

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



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note 1—Organization and basis of presentation

a. Organization

Laredo Petroleum, Inc. ("Laredo"), together with its wholly-owned 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 gathering of oil~~midstream and ~~liquids-rich natural gas from such properties,~~marketing services, primarily in the Permian Basin inof West Texas. LMS and GCM (together, the "Guarantors") guarantee all of Laredo's debt instruments. In these notes, the "Company" refers to Laredo, LMS and GCM collectively, unless the context indicates otherwise. All amounts, dollars and percentages presented in these unaudited consolidated financial statements and the related notes are rounded and, therefore, approximate.

As of September 30, 2017, LMS held 49% of the ownership units of Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, which, together with its wholly-owned subsidiaries (collectively, "Medallion"), is focused on developing midstream solutions and providing midstream infrastructure in the Midland Basin. Prior to the sale of Medallion, the Company accounted for Medallion as an equity method investment. See Note 16.a for discussion of the disposition of Medallion subsequent to September 30, 2017.

The Company operates in two business segments: (i) exploration and production and (ii) midstream and marketing. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties. The midstream and marketing segment provides Laredo's exploration and production segment and third parties with products and services that need to be delivered by midstream infrastructure, including oil and liquids-rich natural gas gathering services as well as rig fuel, natural gas lift and water delivery and takeaway.

~~Note 2—~~b. 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 is included in the unaudited consolidated statements of operations. See Note 2.h for additional discussion of the Company's equity method investment.

The accompanying unaudited 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, ~~2016~~2017 is derived from audited consolidated financial statements. In the opinion of management, the accompanying unaudited consolidated financial statements reflect all necessary adjustments to present fairly the Company's financial position as of ~~September~~June 30, ~~2017,~~2018, results of operations for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016~~2017 and cash flows for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016.~~2017.

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 ~~2016~~2017 Annual Report.

b. Significant accounting policies

See Note 2 "Basis of presentation and significant accounting policies" in the 2017 Annual Report for discussion of significant accounting policies.

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~~

For further information regarding the estimates and assumptions, see Note 2.b "Use of estimates in the preparation of consolidated financial statements" in the 2017 Annual Report. Furthermore, see Note 7.c for a discussion of estimates pertaining to the Company's 2018 performance share awards.

Reclassifications

Certain amounts in the accompanying unaudited consolidated financial statements ~~are not necessarily indicative~~have been reclassified to conform to the 2018 presentation. These reclassifications had no impact on previously reported total assets, total liabilities, net income, stockholders' equity or total operating, investing or financing cash flows.

Note 2—Recently issued or adopted accounting pronouncements

The Company considers the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB") to the FASB Accounting Standards Codification ("ASC"). The discussion of the ~~results that may~~ASUs listed below were determined to be ~~expected for other interim periods or for the full year.~~

~~Significant estimates include, but are not limited~~meaningful to ~~(i) estimates of~~ the Company's reserves of oil, NGL and natural gas, (ii) future cash flows from oil and natural gas properties, (iii) depletion, depreciation and amortization, (iv) impairments, (v) asset retirement obligations, (vi) stock-based compensation, (vii) deferred income taxes, (viii) fair value of assets acquired and liabilities assumed in an acquisition, (ix) fair value of derivatives and deferred premiums and (x) contingent liabilities. Asunaudited consolidated financial statements and/or footnotes during the six months ended June 30, 2018.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

~~fair value is~~a. Revenue recognition

On January 1, 2018, the Company adopted ASC 606, Revenue from Contracts with Customers ("ASC 606"), using the modified retrospective approach of adoption. ASC 606 supersedes previous revenue recognition requirements in ASC 605, Revenue Recognition ("ASC 605"), and includes a ~~market-based measurement, it is determined based~~five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. In addition, the new standard requires significantly expanded disclosures related to the nature, timing, amount and uncertainty of revenue and cash flows arising from contracts with customers. See Note 4 for further discussion of the ASC 606 adoption impact on the assumptions that would be used by market participants. These estimates and assumptions are based on management's best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods.

~~c. Reclassifications~~

~~Certain amounts in the accompanying~~Company's unaudited consolidated financial statements ~~have been reclassified~~and the Company's revenue recognition policies.

b. Leases

In February 2016, the FASB issued new guidance in ASC 842, Leases ("ASC 842"), which will supersede the current guidance in ASC 840, Leases ("ASC 840"). The core principle of the new guidance is that a lessee should recognize in the statement of financial position a liability to ~~conform~~make lease payments and a right-of-use asset representing its right to use the ~~2017 presentation. These reclassifications had no impact on~~underlying asset for the lease term for leases currently classified as operating leases. 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. In January 2018, the FASB issued new guidance in ASC 842 to provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously ~~reported balance sheets or stockholders' equity.~~

~~d. Accounts receivable~~accounted for as leases under ASC 840.

The ~~Company sells produced oil, NGL and natural gas and purchased oil to various customers and participates with other parties~~amendments in ~~the development and operation of oil and natural gas properties. The majority of the Company's accounts receivable~~these ASUs are ~~unsecured. Accounts receivable~~effective for ~~joint interest billings are recorded as amounts billed to customers less an allowance for doubtful accounts.~~

fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. The Company ~~maintains an allowance~~is evaluating the potential impact of adopting this guidance, and the primary effect will be to record assets and obligations for ~~doubtful accounts~~contracts currently recognized as operating leases with a term greater than 12 months and to evaluate operating leases with a term less than or equal to 12 months 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.accounting policy election. The Company ~~reviews its allowance~~has formed a team, including third-party consultants, to implement the standard and has identified the software that will be used to track and account for doubtful accounts quarterly. Past due amounts greater than 90 days and greater than a specified amount are reviewed individually for collectability. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is remote.

~~Accounts receivable consisted of the following components as of the dates presented:~~

(in thousands) September 30, 2017 December 31, 2016
Oil, NGL and natural gas sales $ 62,055
$ 46,999
Sales of purchased oil and other products 15,624
16,213
Joint operations, net⁽¹⁾
8,736
12,175
Matured derivatives 3,345
11,059
Other 80
421
Total $ 89,840
$ 86,867


~~(1)~~	Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.1 million and $0.2 million as of September 30, 2017 and December 31, 2016, respectively. As the operator of the majority of its wells, the Company has the ability to realize some or all of these receivables through the netting of production revenues.

~~e. Derivatives~~

lease activity. The Company ~~uses derivatives~~does not intend to ~~reduce exposure~~adopt the standard early.

c. Business combinations

In January 2017, the FASB issued new guidance in ASC 805, Business Combinations, to ~~fluctuations~~clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in ~~the prices~~this ASU provide a screen to determine when a set of ~~oil, NGL~~assets and ~~natural gas. By removing~~activities is not a ~~significant portion~~business. The screen requires that when substantially all 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, basis swaps and call spreads.

Derivatives are recorded at fair value and are presented on a net basis on the unaudited consolidated balance sheets as assets and/or liabilities. The Company nets the fair value of derivatives by counterparty where the right of offset exists. The Company determines the fair value of its derivatives by utilizing pricing models for substantially similar instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. See Note 8.a for discussion regarding the fair value of the ~~Company's derivatives.~~ gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. If the screen is not met, the amendments in this ASU require that to be considered a business, a set must include, at a minimum, an input and a substantive process that, together, significantly contribute to the ability to create an output.

The ~~Company's derivatives were~~primary effect of adoption of this ASU is that, depending on the facts and circumstances of each transaction, more transactions could be accounted for as acquisitions of assets. The Company adopted this ASU on January 1, 2018 on a prospective basis, and the adoption did not ~~designated as hedges~~have an effect on its unaudited consolidated financial statements. See Note 3.a for ~~accounting purposes for any~~discussion of the ~~periods presented. Accordingly,~~Company's 2018 acquisitions of evaluated and unevaluated oil and natural gas properties, which were accounted for as asset acquisitions under this ASU.

Note 3—Acquisitions and divestitures

a. 2018 acquisitions of evaluated and unevaluated oil and natural gas properties

During the ~~changes~~six months ended June 30, 2018, through multiple transactions, the Company acquired 895 net acres of additional leasehold interests and working interests in ~~fair value are recognized~~47 producing horizontal and vertical wells in Glasscock county in Texas for an aggregate purchase price of $16.4 million, subject to customary post-closing adjustments. These acquisitions were accounted for as asset acquisitions.

b. 2018 divestitures of evaluated and unevaluated oil and natural gas properties and midstream assets

During the ~~unaudited consolidated statements~~six months ended June 30, 2018, through multiple transactions, the Company completed the sale of ~~operations~~3,070 net acres and working interests in ~~the period~~24 producing vertical and horizontal wells and associated midstream service assets in Glasscock and Howard counties in Texas to third-party buyers for an aggregate sales price of ~~change. Gains~~$12.1 million, net of post-closing adjustments. Of this amount, $11.6 million, net of post-closing adjustments, was recorded as adjustments to oil and ~~losses on derivatives are included in cash flows from operating activities. See Notes 7 and 8.a for discussion regarding the Company's derivatives.~~natural gas



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

~~f. Other current assets and liabilities~~

~~Other current assets consisted~~properties pursuant to the rules governing full cost accounting. A loss of $1.0 million from the sale of the ~~following components~~associated midstream service assets was included in the line item "Gain (loss) on disposal of assets, net" in the unaudited consolidated statements of operations. Effective at the closings, the operations and cash flows of these properties and midstream service assets were eliminated from the ongoing operations of the Company, and the Company has no continuing involvement in the properties. These divestitures did not represent a strategic shift and will not have a major effect on the Company's future operations or financial results.

c. 2017 Medallion sale

Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, which, together with its wholly-owned subsidiaries (collectively, "Medallion"), was established for the purpose of developing midstream solutions and providing midstream infrastructure to bring oil to market from the Midland Basin. Prior to the Medallion Sale (defined below), LMS held 49% of Medallion's ownership units. LMS and the third-party 51% interest-holder agreed that the voting rights of Medallion, the profit and loss sharing and the additional capital contribution requirements would be equal to the ownership unit percentage held. Additionally, Medallion required a super-majority vote of 75% for many key operating and business decisions. The Company determined that Medallion was a variable interest entity ("VIE"). However, LMS was not considered to be the primary beneficiary of the VIE because LMS did not have the power to direct the activities that most significantly affected Medallion's economic performance. As such, prior to the Medallion Sale, Medallion was accounted for under the equity method of accounting. The Company's proportionate share of Medallion's net income is reflected in the unaudited consolidated statements of operations on the "Income from equity method investee" line item.

On October 30, 2017, LMS, together with Medallion Midstream Holdings, LLC, which is owned and controlled by an affiliate of the third-party interest-holder, The Energy & Minerals Group, completed the sale of 100% of the ownership interests in Medallion to an affiliate of Global Infrastructure Partners ("GIP") for cash consideration of $1.825 billion (the "Medallion Sale"). LMS' net cash proceeds for its 49% ownership interest in Medallion in 2017 were $829.6 million, before post-closing adjustments and taxes, but after deduction of its proportionate share of fees and other expenses associated with the Medallion Sale. On February 1, 2018, closing adjustments were finalized and LMS received additional net cash of $1.7 million for total net cash proceeds before taxes of $831.3 million. The proceeds were used to pay in-full borrowings on the Senior Secured Credit Facility, to redeem the May 2022 Notes (as defined below) and for working capital purposes. The Medallion Sale closed pursuant to the membership interest purchase and sale agreement, which provides for potential post-closing additional cash consideration that is structured based on GIP's realized profit at exit. There can be no assurance as to when and whether the additional consideration will be paid. The Medallion Sale did not represent a strategic shift and will not have a major effect on the Company's future operations or financial results.

LMS has a Transportation Services Agreement (the "TA") with a wholly-owned subsidiary of Medallion under which LMS receives firm transportation of the Company's crude oil production from Reagan and Glasscock counties in Texas to Colorado City, Texas that continues to be in effect after the Medallion Sale. Historically, the Company's crude oil purchasers have fulfilled the commitment by transporting crude oil, purchased from the Company, under the TA, as agent. As a result of the Company's continuing involvement with Medallion by guaranteeing cash flows under the TA, the Company recorded a deferred gain in the amount of its maximum exposure to loss related to such guarantees that would have been amortized over the TA's firm commitment transportation term through 2024 had the Company not adopted new revenue recognition guidance on January 1, 2018. The deferred gain is included in the unaudited consolidated balance sheets in each of the "Other current liabilities" and "Other noncurrent liabilities" line items as of December 31, 2017. See Note 4.a for discussion of the impact to the deferred gain upon the adoption of ASC 606.

d. 2017 divestiture of evaluated and unevaluated oil and natural gas properties

In January 2017, the Company completed the sale of 2,900 net acres and working interests in 16 producing vertical wells in the Midland Basin to a third-party buyer for a purchase price of $59.7 million. After transaction costs reflecting an economic effective date of October 1, 2016, the proceeds were $59.5 million, net of working capital and post-closing adjustments. A significant portion of these proceeds was used to pay down borrowings on the Senior Secured Credit Facility. The purchase price was recorded as an adjustment 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 did not represent a strategic shift and will not have a major effect on the Company's future operations or financial results.

e. Exchange of unevaluated oil and natural gas properties

From time to time, the Company exchanges undeveloped acreage with third parties. The exchanges are recorded at fair value and the difference is accounted for as an adjustment of capitalized costs with no gain or loss recognized pursuant to the



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

rules governing full cost accounting, unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas.

Note 4—Revenue recognition

a. Impact of ASC 606 adoption

Upon adoption of ASC 606 on January 1, 2018, for the three and six months ended June 30, 2018, the Company reclassified certain deficiency payments and other contractual penalties due to customers, historically included in the "Other operating expenses" line item in the unaudited consolidated statements of operations, and netted them with the revenue stream from which they derive as these payments to customers do not relate to the provision of a distinct good or service to the customer. In addition, there was an impact upon adoption related to the treatment of the gain on the Medallion Sale.

The impact of the adoption of ASC 606 on the results of operations for the periods presented is as follows:



	Three months ended June 30, 2018							Six months ended June 30, 2018
(in thousands)	As computed under ASC 605		As reported under ASC 606		Increase/(decrease)			As computed under ASC 605		As reported under ASC 606		Increase/(decrease)
Revenues:
Oil sales	$	161,192	$	159,051	$	(2,141	)	$	312,250	$	309,965	$	(2,285	)
NGL sales	$	36,805	$	36,805	$	—		$	65,165	$	65,165	$	—
Natural gas sales	$	12,705	$	12,705	$	—		$	30,865	$	30,865	$	—
Costs and expenses:
Other operating expenses	$	3,262	$	1,121	$	(2,141	)	$	4,512	$	2,227	$	(2,285	)

Net income	$	33,452	$	33,452	$	—		$	119,972	$	119,972	$	—

At December 31, 2017, the Medallion Sale was accounted for under the real estate guidance in ASC 360-20, Property, Plant, and Equipment ("ASC 360-20"), and the Company's maximum exposure to loss associated with future commitments under the TA was $141.1 million that was not recorded in the Company's unaudited consolidated balance sheets. Under ASC 360-20, as a result of the Company's continuing involvement with Medallion by guaranteeing cash flows under the TA, the Company recorded a deferred gain in the amount of its maximum exposure to loss related to such guarantees. This deferred gain would have been amortized over the TA's firm commitment transportation term through 2024 had the Company not adopted ASC 606 on January 1, 2018. See Note 3.c for further discussion of the Medallion Sale and the TA.

Upon the adoption of ASC 606, the guidance in ASC 360-20 was superseded by ASC 860, Transfers and Servicing ("ASC 860"). The Medallion Sale is within the scope of ASC 860 and qualifies for sale accounting and recognition of the previously deferred gain because as of the ~~dates presented:~~date of the Medallion Sale (i) the Company transferred and legally isolated its full interests in Medallion to GIP, (ii) GIP received the right to pledge or exchange Medallion ownership interests at its full discretion and (iii) the Company did not have effective control over Medallion. Therefore, the deferred gain of $141.1 million was recognized as an adjustment to the beginning balance of accumulated deficit, presented in the unaudited consolidated statements of stockholders' equity, in accordance with the modified retrospective approach of adoption.

b. Revenue recognition

Oil, NGL and natural gas revenues are generally recognized at the point in time that control of the product is transferred to the customer. Midstream service revenues are generated through fees for products and services that need to be delivered by midstream infrastructure, including oil and liquids-rich natural gas gathering services as well as rig fuel, gas lift and water delivery, recycling and takeaway (collectively, "Midstream Services") and are recognized over time as the customer benefits from these services when provided. A more detailed summary of the underlying contracts that give rise to the Company's revenue and method of recognition is included below.

Oil sales and sales of purchased oil

Under its oil sales contracts, the Company sells produced or purchased oil at the delivery point specified in the contract and collects an agreed-upon index price, net of pricing differentials. The delivery point may be at the wellhead, the inlet of the purchaser's pipeline or nominated pipeline or the Company's truck unloading facility. At the delivery point, the

(in thousands) September 30, 2017 December 31, 2016
Inventory⁽¹⁾
$ 8,623
$ 8,063
Prepaid expenses and other 7,573
6,228
Total other current assets $ 16,196
$ 14,291



~~(1)~~ Table of Contents	~~See Note 2.i for discussion of inventory held by the Company.~~Laredo Petroleum, Inc.

~~Other current liabilities consisted~~Condensed notes to the consolidated financial statements

(Unaudited)

purchaser typically takes custody, title and risk of loss of the ~~following components~~product and, therefore, control as defined under ASC 606 typically passes at the delivery point. The Company recognizes revenue at the net price received when control transfers to the purchaser.

From time to time, the Company engages in transactions in which it sells oil at the lease and subsequently repurchases the same volume of oil from that customer at a downstream delivery point under a separate agreement ("Repurchase Agreement") for use in the sale to the final customer. The commercial reasoning for such transactions may vary. Where a Repurchase Agreement exists, the Company must evaluate whether the customer obtains control of the oil at the lease and therefore whether it is appropriate to recognize revenue for the lease sale. Where the Company has an obligation or a right to repurchase the oil, the customer does not obtain control of the oil because it is limited in its ability to direct the use of, and obtain substantially all of the remaining benefits from the oil even though it may have physical possession of the oil. If the Company repurchases the oil for less than the original selling price, such a transaction will be classified as a lease. If the Company repurchases the oil for equal to or more than the original selling price, then the transaction represents a financing arrangement unless there is only a short passage of time between the sale and repurchase, in which case any excess amount paid represents an expense associated with the sale of oil to the final customer. The Company recognizes such repurchase expense and any transportation expenses incurred for the delivery of the oil to the final customer in the "Transportation and marketing expense" line item in the accompanying unaudited consolidated statements of operations.

Under certain of its customer contracts, the Company is subject to deficiency payments and other contractual penalties if it fails to deliver contractual minimum volumes to its customers. Such amounts are recorded as a reduction to the transaction price as these amounts do not represent payments to the customer for distinct goods or services and instead relate specifically to the failure to perform under the specific customer contract. Such amounts are recorded as a reduction to the transaction price when payment is determined as probable, typically when such a deficiency occurs.

NGL and natural gas sales

Under its natural gas processing contracts, the Company delivers produced natural gas to a midstream processing entity at the wellhead or the inlet of the processing entity's system. The processing entity processes the natural gas, sells the resulting NGL and residue gas to third parties and pays the Company for the NGL and residue gas with deductions that may include gathering, compression, processing and transportation fees. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For existing contracts, the Company has concluded that it is the agent in the ultimate sale to the third party and the midstream processing entity is the principal and that we have transferred control of unprocessed natural gas to the midstream processing entity; therefore, the Company recognizes revenue based on the net amount of the proceeds received from the midstream processing entity who represents the Company's customer. If for future contracts the Company was to conclude that it was the principal with the ultimate third party being the customer, the Company would recognize revenue for those contracts on a gross basis, with gathering, compression, processing, and transportation fees presented as an expense.

Midstream Services

Revenue from oil throughput agreements is recognized based on a rate per barrel for volumes transported. Under the Company's oil throughput agreements, a volumetric deduction is taken from customer oil as a pipeline loss allowance. While these amounts represent non-cash consideration under ASC 606, such deductions are immaterial. Revenue from natural gas throughput agreements is recognized based on a rate per MMbtu for volumes transported. Revenue from water delivery, recycling and takeaway is recognized based on the volumes of water for which the services are provided at the applicable contractual rate.

Imbalances

The Company recognizes revenue for all oil, NGL and natural gas sold to purchasers regardless of whether the sales are proportionate to the Company's ownership interest in the property. Production imbalances are recognized as a liability to the extent an imbalance on a specific property exceeds the Company's share of remaining proved oil, NGL and natural gas reserves. The Company is also subject to natural gas pipeline imbalances, which are recorded as accounts receivable or payable at values consistent with contractual arrangements with the owner of the pipeline. The Company did not have any producer or pipeline imbalance positions as of June 30, 2018 or December 31, 2017.

Significant judgments

The Company engages in various types of transactions in which unaffiliated midstream entities process the ~~dates presented:~~Company's liquids-rich natural gas and, in some scenarios, subsequently market resulting NGL and residue gas to third-party customers on the Company's behalf. These types of transactions require judgment to determine whether the Company is the principal or the



Table of Contents	Laredo Petroleum, Inc.

(in thousands) September 30, 2017 December 31, 2016
Accrued interest payable $ 21,832
$ 24,152
Accrued compensation and benefits 16,498
25,947
Purchased oil payable 16,070
17,213
Lease operating expense payable 11,442
10,572
Other accrued liabilities 27,230
16,331
Total other current liabilities $ 93,072
$ 94,215
Condensed notes to the consolidated financial statements

g. (Unaudited)

agent in the contract and, as a result, whether revenues are recorded gross or net. For existing contracts, the Company has determined that it serves as the agent in the sale of products under certain natural gas processing and marketing agreements with unaffiliated midstream entities in accordance with the control model in ASC 606. As a result, the Company presents revenue on a net basis for amounts expected to be received from third-party customers through the marketing process, with expenses and deductions incurred subsequent to control of the product(s) transferring to the unaffiliated midstream entity being netted against revenue.

Transaction price allocated to remaining performance obligations

A significant number of the Company's product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For the Company's product sales that have a contract term greater than one year and for its Midstream Services, the Company has utilized the practical expedient in ASC 606-10-50-14A that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company's product sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied. Under the Midstream Services contracts each unit of service represents a separate performance obligation and therefore performance obligations in respect of future services are wholly unsatisfied.

Contract balances

Under the Company's customer contracts, invoicing occurs once the Company's performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company's contracts do not give rise to contract assets or liabilities under ASC 606.

Prior period performance obligations

For sales of oil, NGL, natural gas and purchased oil, the Company records revenue in the month production is delivered to the purchaser. However, settlement statements and payment may not be received for 30 to 90 days after the date production is delivered and, as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales once payment is received from the purchaser. Such differences have historically not been significant. The Company uses knowledge of its properties, its properties' historical performance, spot market prices and other factors as the basis for these estimates. For the three and six months ended June 30, 2018, revenue recognized related to performance obligations satisfied in prior reporting periods was not material.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note 5—Property and equipment

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


(in thousands)	September 30, 2017			December 31, 2016			June 30, 2018			December 31, 2017
Evaluated oil and natural gas properties	$	5,863,536		$	5,488,756		$	6,432,913		$	6,070,940
Less accumulated depletion and impairment	(4,616,246		)	(4,514,183		)	(4,746,413		)	(4,657,466		)
Evaluated oil and natural gas properties, net	1,247,290			974,573			1,686,500			1,413,474

Unevaluated properties not being depleted	211,720			221,281
Unevaluated oil and natural gas properties not being depleted							156,815			175,865

Midstream service assets	161,144			150,629			171,875			171,427
Less accumulated depreciation and impairment	(30,737		)	(24,389		)	(37,048		)	(33,102		)
Midstream service assets, net	130,407			126,240			134,827			138,325

Depreciable other fixed assets	50,767			52,491			49,304			48,957
Less accumulated depreciation and amortization	(23,779		)	(22,632		)	(25,179		)	(23,150		)
Depreciable other fixed assets, net	26,988			29,859			24,125			25,807

Land	14,914			14,914			18,259			14,914

Total property and equipment, net	$	1,631,319		$	1,366,867		$	2,020,526		$	1,768,385

For the three months ended ~~September~~June 30, ~~2017~~2018 and ~~2016,~~2017, depletion expense for the Company's evaluated oil and natural gas properties was ~~$6.80~~$7.68 per barrel of oil equivalent ("BOE") sold and ~~$6.71~~$6.44 per BOE sold, respectively. For the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016,~~2017, depletion expense for the Company's evaluated oil and natural gas properties was ~~$6.57~~$7.52 per BOE sold and ~~$7.55~~$6.44 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~~employee-related costs incurred for the purpose of exploring for or developing oil and natural gas properties, are capitalized and depleted on a composite ~~unit of production~~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~~employee-related costs, associated with production and general corporate activities, are expensed in the period incurred. Sales of oil and natural gas



~~Table of Contents~~	~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

properties, whether or not being depleted currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas.

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


	Three months ended September 30,				Nine months ended September 30,				Three months ended June 30,				Six months ended June 30,
(in thousands)	2017		2016		2017		2016		2018		2017		2018		2017
Capitalized employee-related costs	$	6,938	$	6,149	$	17,911	$	12,598	$	6,735	$	5,763	$	13,264	$	10,973

The Company excludes the costs directly associated with the 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 to 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 properties are assessed on a quarterly basis for possible impairment. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of evaluated reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion.

The full cost ceiling is based principally on the estimated future net revenues from proved oil and natural gas properties discounted at 10%. The SEC guidelines require companies to use the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period before differentials ("Benchmark Prices"). The Benchmark Prices are then adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead ("Realized Prices"). The Realized Prices are utilized to calculate the discounted future net revenues in the full cost ceiling calculation.

In the event the unamortized cost of evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible.

Full cost ceiling impairment expense for the nine months ended September 30, 2016 was $161.1 million and is included in the "Impairment expense" line item in the unaudited consolidated statements of operations and in the financial information provided for the Company's exploration and production segment presented in Note 13. There was no full cost ceiling impairment expense recorded during the nine months ended September 30, 2017.

~~h. Variable interest entity~~

Medallion was established for the purpose of developing midstream solutions and providing midstream infrastructure to bring oil to market in the Midland Basin. As of September 30, 2017, LMS held 49% of Medallion's ownership units. LMS and the third-party 51% interest-holder agreed that the voting rights of Medallion, the profit and loss sharing and the additional capital contribution requirements would be equal to the ownership unit percentage held. Additionally, Medallion required a super-majority vote of 75% for many key operating and business decisions. The Company has determined that Medallion is a variable interest entity ("VIE"). However, LMS was not considered to be the primary beneficiary of the VIE because LMS did not have the power to direct the activities that most significantly affected Medallion's economic performance. As such, prior to its sale, Medallion was accounted for under the equity method of accounting. The Company's proportionate share of Medallion's net income is reflected in the unaudited consolidated statements of operations as "Income from equity method investee" and the carrying amount is reflected in the unaudited consolidated balance sheets as "Investment in equity method investee." The Company has elected to classify distributions received from Medallion using the cumulative earnings approach. No such distributions have been received through September 30, 2017.

LMS contributed $24.6 million to Medallion during the three and nine months ended September 30, 2017. LMS contributed $16.0 million and $58.7 million to Medallion during the three and nine months ended September 30, 2016, respectively. Medallion continued expansion activities on existing portions of its pipeline infrastructure in order to gather and transport additional third-party oil production during each of the nine months ended September 30, 2017 and 2016. See Note 12.a for discussion of items included in the Company's unaudited consolidated financial statements related to Medallion. See Note 16.a for discussion regarding an additional contribution made to Medallion subsequent to September 30, 2017.



~~Table of Contents~~	~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

On October 30, 2017, LMS, together with the third-party 51% interest holder, completed the previously announced sale of 100% of the ownership interests in Medallion (the "Medallion Sale"). LMS has a Transportation Services Agreement (the "TA") with a wholly-owned subsidiary of Medallion, under which LMS receives firm transportation of the Company's crude oil production from Reagan and Glasscock County, Texas to Colorado City, Texas that continues to be in effect after the Medallion Sale. Historically, the Company's crude oil purchasers have fulfilled the commitment by transporting crude oil, purchased from the Company, under the TA, as agent. As of September 30, 2017, the Company's maximum exposure to loss associated with future commitments under the TA is $146.2 million that is not recorded in the Company's unaudited consolidated balance sheets. As a result of the Company's continuing involvement with Medallion due to the TA surviving the closing of the Medallion Sale, the Company will record a deferred gain in the amount of its maximum exposure to loss as of October 30, 2017 during the fourth quarter of 2017. This deferred gain will be amortized over the TA's firm commitment transportation term through 2024. See Note 16.a for additional discussion of the Medallion Sale subsequent to September 30, 2017.

~~i. 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, which is used in the Company's production activities of oil and natural gas properties and midstream service assets, is carried at the lower of cost or net realizable value ("NRV"), with cost determined using the weighted-average cost method, and is included in "Other current assets" and "Other assets, net" on the unaudited consolidated balance sheets. The NRV for materials and supplies inventory is determined utilizing a replacement cost approach (Level 2).

The Company has frac pit water inventory, which is used in developing oil and natural gas properties and is carried at lower of cost or NRV, with cost determined using the weighted-average cost method, and is included in "Other current assets" on the unaudited consolidated balance sheets. The NRV for frac pit water inventory is determined utilizing a replacement cost approach (Level 2).

The minimum volume of product in a pipeline system that enables the system to operate is known as line-fill and is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. The Company owns oil line-fill in third-party pipelines, which is accounted for at lower of cost or NRV, with cost determined using the weighted-average cost method, and is included in "Other assets, net" on the unaudited consolidated balance sheets. The NRV is determined utilizing a quoted market price adjusted for regional price differentials (Level 2).

There were no long-lived asset impairments recorded during the nine months ended September 30, 2017 or 2016. Inventory impairments of $1.0 million were recorded for the nine months ended September 30, 2016. There were no inventory impairments recorded during the nine months ended September 30, 2017.

~~j. 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 $4.7 million of debt issuance costs during the nine months ended September 30, 2017 as a result of entering into the Fifth Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility"). No debt issuance costs were capitalized during the nine months ended September 30, 2016. The Company had total debt issuance costs of $20.4 million and $18.8 million, net of accumulated amortization of ~~$24.4 million~~ ~~and~~ ~~$21.3 million, as of September 30, 2017 and December 31, 2016, respectively.~~

No debt issuance costs were written off during the nine months ended September 30, 2017. The Company wrote-off $0.8 million of debt issuance costs during the nine months ended September 30, 2016 as a result of changes in the borrowing base and aggregate elected commitment of the Senior Secured Credit Facility, which is included in the unaudited consolidated statements of operations in the "Write-off of debt issuance costs" line item. Debt issuance costs related to the Company's senior unsecured notes are presented in "Long-term debt, net" on the Company's unaudited consolidated balance sheets. Debt issuance costs related to the Senior Secured Credit Facility are presented in "Other assets, net" on the Company's unaudited consolidated balance sheets. See Note 4.f for additional discussion of debt issuance costs.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

~~Future amortization expense of debt issuance costs as of September 30, 2017 for the periods presented is as follows:~~

(in thousands) September 30, 2017
Remaining 2017
$ 1,044
2018
4,223
2019
4,308
2020
4,396
2021
4,493
Thereafter
1,947
Total
$ 20,411

~~k. Asset retirement obligations~~

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

The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, which converts future cash flows into a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment cost per well based on Company experience, (ii) estimated remaining life per well, (iii) estimated removal and/or remediation costs for midstream service assets, (iv) estimated remaining life of midstream service assets, (v) future inflation factors and (vi) the Company's average credit adjusted risk-free rate. Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in addition to those noted above, the ultimate settlement of these amounts, the ultimate timing of such settlement and changes in legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, a corresponding adjustment will be made to the asset balance.

The Company is obligated by contractual and regulatory requirements to remove certain pipeline and gathering assets and perform other remediation of the sites where such pipeline and 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 gathering assets in the periods in which settlement dates are reasonably determinable.

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

(in thousands) Nine months ended September 30, 2017 Year ended December 31, 2016
Liability at beginning of period $ 52,207
$ 46,306
Liabilities added due to acquisitions, drilling, midstream service asset construction and other 492
1,528
Accretion expense 2,822
3,483
Liabilities settled upon plugging and abandonment (357 ) (1,242 )
Liabilities removed due to sale of property (871 ) —
Revision of estimates 178
2,132
Liability at end of period $ 54,471
$ 52,207

~~l. 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 4.e for fair value disclosures related to the Company's debt obligations. The Company carries its derivatives at fair value. See Note 8.a for details regarding the fair value of the Company's derivatives.



~~Table of Contents~~	~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

~~m. 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.

~~n. Compensation awards~~

Stock-based compensation expense, net of amounts capitalized, is included in "General and administrative" in the unaudited consolidated statements of operations over the awards' vesting periods and is based on the awards' grant date fair value. The Company utilizes the closing stock price on the grant date, less an expected forfeiture rate, to determine the fair values of service vesting restricted stock awards and a Black-Scholes pricing model to determine the fair values of service vesting restricted stock option awards. The Company utilizes a Monte Carlo simulation prepared by an independent third party to determine the fair values of the performance share awards and, in prior periods, the performance unit awards. The Company capitalizes a portion of stock-based compensation for employees who are directly involvedtable presents costs incurred in the acquisition, exploration and development of ~~its~~ oil and natural gas properties, ~~into the full cost pool. Capitalized stock-based compensation is~~with asset retirement obligations included ~~as an addition to "Oil~~in evaluated property acquisition costs and natural gas properties" in the unaudited consolidated balance sheets. See Note 5 for further discussion regarding the restricted stock awards, stock option awards, performance share awards and performance unit awards.

~~o. July 2016 and May 2016 Equity Offerings~~

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

On May 16, 2016, the Company completed the sale of 10,925,000 shares of Laredo's common stock (the "May 2016 Equity Offering") for net proceeds of $119.3 million, after underwriting discounts, commissions and offering expenses. There were no comparative offerings of Laredo's stock during the nine months ended September 30, 2017.

~~p. 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 thedevelopment 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, 2017 or December 31, 2016.

~~q. Non-cash investing and supplemental cash flow information~~

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

Nine months ended September 30,
(in thousands) 2017 2016
Non-cash investing information:
Change in accrued capital expenditures $ 39,156
$ (24,963 )
Change in accrued capital contribution to equity method investee⁽¹⁾
$ —
$ (27,583 )
Capitalized asset retirement cost $ 670
$ 1,669
Supplemental cash flow information:
Capitalized interest $ 756
$ 199


~~(1)~~	~~See Notes 2.h , 12.a and 16.a for additional discussion of the Company's equity method investee.~~



~~Table of Contents~~	~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

~~Note 3—Divestiture and acquisitions~~

~~a. 2017 Divestiture of evaluated and unevaluated oil and natural gas properties~~

In January 2017, the Company completed the sale of 2,900 net acres and working interests in 16 producing vertical wells in the Midland Basin to a third-party buyer for a purchase price of $59.7 million. After transaction costs reflecting an economic effective date of October 1, 2016, the proceeds were $59.5 million, net of working capital and post-closing adjustments. The Company completed the closing adjustments for this divestiture in May 2017. A portion of these proceeds was used to pay down borrowings on the Senior Secured Credit Facility. The purchase price was recorded as an adjustment 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.

~~b. 2016 Acquisitions of evaluated and unevaluated oil and natural gas properties~~

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

The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair value of evaluated and unevaluated oil and natural gas properties. The fair value of these properties are measured using a discounted cash flow model that converts future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) forecasted oil, NGL and natural gas reserve quantities; (ii) future commodity strip prices as of the closing dates adjusted for transportation and regional price differentials; (iii) forecasted ad valorem taxes, production taxes, income taxes, general and administrative expenses, operating expenses and development costs; and (iv) a peer group weighted-average cost of capital rate subject to additional project-specific risk factors. To compensate for the inherent risk of estimating the value of the unevaluated properties, the discounted future net revenues of proved undeveloped and probable reserves are reduced by additional reserve adjustment factors. These assumptions represent Level 3 inputs under the fair value hierarchy, as described in Note 8.

During the three months ended September 30, 2016, the Company entered into an agreement to acquire 9,200 net acres of additional leasehold interests and working interests in 81 producing vertical wells in western Glasscock and Reagan counties (which included production of 300 net barrels of oil equivalent per day ("BOE/D")) within the Company's core development area for an aggregate purchase price of $125.0 million subject to customary closing adjustments. On July 13 and August 24, 2016, the Company closed on portions of this agreement for $94.4 million and $21.2 million, respectively. The final closing under this agreement occurred in the fourth quarter of 2016 and related to certain remaining interests that were subject to preferential purchase rights that were satisfied subsequent to September 30, 2016.

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

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



~~Table of Contents~~	~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

~~c. Exchange of unevaluated oil and natural gas properties~~

~~From time to time, the Company exchanges undeveloped acreage with third parties, with no gain or loss recognized pursuant to the rules governing full cost accounting.~~



	Three months ended June 30,				Six months ended June 30,
(in thousands)	2018		2017		2018		2017
Property acquisition costs (see Note 3.a):							—
Evaluated	$	13,847	$	—	$	13,847	$	—
Unevaluated	2,790		—		2,790		—
Exploration costs	5,108		5,658		11,245		21,201
Development costs	178,796		125,738		327,834		236,896
Total costs incurred	$	200,541	$	131,396	$	355,716	$	258,097

Note 4—6—Debt

a. March 2023 Notes

On March 18, 2015, the Company completed an offering of $350.0 million in aggregate principal amount of 6 1/4% senior unsecured notes due 2023 (the "March 2023 Notes"). The March 2023 Notes will mature on March 15, 2023 and bear an interest rate of 6 1/4% per annum, payable semi-annually, in cash in arrears on March 15 and September 15 of each year, commencing September 15, 2015. The March 2023 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain automatic customary releases, including the sale, disposition or transfer of all of the capital stock or of all or substantially all of the assets of a subsidiary guarantor to one or more persons that are not the Company or a restricted subsidiary, exercise of legal defeasance or covenant defeasance options or satisfaction and discharge of the applicable indenture, designation of a subsidiary guarantor as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the applicable indenture, release from guarantee under the Senior Secured Credit Facility, or liquidation or dissolution (collectively, the "Releases"). The Company may redeem, at its option, all or part of the March 2023 Notes ~~are callable by the Company beginning~~at any time after March 15, 2018, at a price of 104.688% of face value with call premiums declining annually to 100% of face value on March 15, 2021 and ~~thereafter.~~thereafter plus 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. The Company may redeem, at its option, all or part of the January 2022 Notes ~~became callable by the Company on~~at any time after January 15, ~~2017~~2018, at a price of ~~104.219%~~102.813% of face value with call premiums declining annually to 100% of face value on January 15, 2020 and ~~thereafter.~~thereafter plus accrued and unpaid interest to, but not including, the date of redemption.

c. May 2022 Notes

On April 27, 2012, the Company completed an offering of ~~$500.0~~$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~~were due to mature on May 1, 2022 and ~~bear~~bore 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~~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. ~~The May~~

On November 29, 2017 (the "May 2022 Notes ~~became callable by the Company on May 1, 2017 at~~Redemption Date"), utilizing a ~~price of 103.688% of face value with call premiums declining annually to 100% of face value on May 1, 2020 and thereafter.~~

~~See Note 16.c for discussion regarding the commencement of a redemption~~portion of the ~~outstanding~~proceeds from the Medallion Sale, the entire $500.0 million ~~in aggregate~~outstanding principal amount of the May 2022 Notes ~~subsequent to September 30, 2017.~~

~~d. Senior Secured Credit Facility~~

Aswas redeemed at a redemption price of ~~September 30, 2017,~~103.688% of the ~~Senior Secured Credit Facility had a maximum credit~~principal amount of $2.0 billion, a borrowing base and an aggregate elected commitment each of $1.0 billion with $155.0 million outstanding and was subject to an interest rate of 3.25%. The Senior Secured Credit Facility has a maturity date of May 2, 2022, provided that if either the ~~January 2022 Notes or~~ May 2022 Notes, ~~have~~plus accrued and unpaid interest up to, but not ~~been redeemed or refinanced~~including, the May 2022 Notes Redemption Date. The Company recognized a loss on ~~or prior~~extinguishment of $23.8 million related to the ~~date 90 days before their respective stated maturity dates (as applicable,~~difference between the ~~"Early Maturity Date"),~~redemption price and the Senior Secured Credit Facility will mature on such Early Maturity Date. The Senior Secured Credit Facility contains both financial and non-financial covenants, all of which the Company was in compliance with as of September 30, 2017. Laredo is required to pay an annual commitment fee on the unused portionnet carrying amount of the financial institutions' commitment of 0.375% to 0.5%, based on the ratio of outstanding revolving credit to the total commitment under the Senior Secured Credit Facility. Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or ~~$20.0 million~~. No letters of credit were outstanding as of September 30, 2017 or 2016. See Note 16.b for discussion of additional borrowings on and the repayment of the Senior Secured Credit Facility subsequent to September 30, 2017.extinguished May 2022 Notes.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

~~On October 20, 2017, pursuant~~d. Senior Secured Credit Facility

The Senior Secured Credit Facility matures on April 19, 2023, provided that if either the January 2022 Notes or March 2023 Notes have not been refinanced on or prior to the date (as applicable, the "Early Maturity Date") that is 90 days before their respective stated maturity dates, the Senior Secured Credit Facility will mature on such Early Maturity Date. As of June 30, 2018, the Senior Secured Credit Facility had a ~~regular semi-annual redetermination, the lenders reaffirmed the $1.0~~maximum credit amount of $2.0 billion, a borrowing base of $1.3 billion and an aggregate elected commitment of $1.2 billion, with $110.0 million outstanding and was subject to an interest rate of 3.32%. The Senior Secured Credit Facility contains both financial and non-financial covenants, all of which the Company was in compliance with as of June 30, 2018. Laredo is required to pay a 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 aggregate elected commitment under the Senior Secured Credit Facility. ~~The Company's aggregate elected commitment~~Additionally, the Senior Secured Credit Facility provides for the issuance of ~~$1.0 billion remained unchanged.~~

~~e. Fair value~~letters of ~~debt~~

~~The Company has not elected~~credit, limited to ~~account for its debt instruments at fair value. The following table presents~~ the ~~carrying amounts and fair values~~lesser of ~~the Company's debt~~total capacity or $80.0 million. No letters of credit were outstanding as of ~~the dates presented:~~

September 30, 2017 December 31, 2016
(in thousands) Long-term
debt
Fair
value
Long-term
debt
Fair
value
January 2022 Notes $ 450,000
$ 457,110
$ 450,000
$ 456,382
May 2022 Notes 500,000
520,625
500,000
521,413
March 2023 Notes 350,000
363,342
350,000
365,649
Senior Secured Credit Facility 155,000
155,035
70,000
69,975
Total $ 1,455,000
$ 1,496,112
$ 1,370,000
$ 1,413,419

~~The fair values of the debt outstanding on the January 2022 Notes, the May 2022 Notes and the March 2023 Notes were determined using the September~~June 30, ~~2017 and~~2018 or December 31, ~~2016 quoted market price (Level 1)~~2017. See Note 17.b for ~~each respective instrument. The fair values~~discussion of ~~the outstanding debt~~additional borrowings and payments on the Senior Secured Credit Facility ~~as of September~~subsequent to June 30, ~~2017 and December 31, 2016 were estimated utilizing pricing models for similar instruments (Level 2). See Note 8 for information about fair value hierarchy levels.~~2018.

f.e. Long-term debt, net

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


	September 30, 2017							December 31, 2016							June 30, 2018							December 31, 2017
(in thousands)	Long-term debt		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		Long-term debt		Debt issuance costs, net			Long-term debt, net
January 2022 Notes	$	450,000	$	(4,230	)	$	445,770	$	450,000	$	(4,963	)	$	445,037	$	450,000	$	(3,499	)	$	446,501	$	450,000	$	(3,987	)	$	446,013
May 2022 Notes	500,000		(5,442		)	494,558		500,000		(6,164		)	493,836
March 2023 Notes	350,000		(4,360		)	345,640		350,000		(4,964		)	345,036		350,000		(3,756		)	346,244		350,000		(4,158		)	345,842
Senior Secured Credit Facility⁽¹⁾	155,000		—			155,000		70,000		—			70,000		110,000		—			110,000		—		—			—
Total	$	1,455,000	$	(14,032	)	$	1,440,968	$	1,370,000	$	(16,091	)	$	1,353,909	$	910,000	$	(7,255	)	$	902,745	$	800,000	$	(8,145	)	$	791,855


(1)	Debt issuance costs, net related to our Senior Secured Credit Facility of ~~$6.4~~$7.8 million and ~~$2.7~~$6.0 million as of ~~September~~June 30, ~~2017~~2018 and December 31, ~~2016,~~2017, respectively, are reported in "Other assets, net" on the unaudited consolidated balance sheets.

Note ~~5—Employee~~7—Stockholders' equity and stock-based compensation

a. Share repurchase program

In February 2018, the Company's board of directors authorized a $200 million share repurchase program commencing in February 2018. The repurchase program expires in February 2020. Share repurchases under the share repurchase program may be made through a variety of methods, which may include open market purchases, privately negotiated transactions and block trades. The timing and actual number of shares repurchased, if any, will depend upon several factors, including market conditions, business conditions, the trading price of the Company's common stock and the nature of other investment opportunities available to the Company. During the three months ended June 30, 2018, the Company ~~has~~repurchased 3,150,651 shares of common stock at a weighted-average price of $9.12 per common share for a total of $28.7 million under this program. During the six months ended June 30, 2018, the Company repurchased 9,878,552 shares of common stock at a weighted-average price of $8.83 per common share for a total of $87.2 million under this program. All shares were retired upon repurchase.

b. Treasury stock

Treasury stock is recorded at cost, which includes incremental direct transaction costs, and is retired upon acquisition as a result from share repurchases under the share repurchase program or from the withholding of shares of stock to satisfy employee tax withholding obligations that arise upon the lapse of restrictions on their stock awards at the employees' election.

c. Stock-based compensation

The Company's Long-Term Incentive Plan (the "LTIP")~~, which~~ provides for the granting of incentive awards in the form of restricted stock awards, stock option awards, performance share awards, performance unit awards and other awards. The LTIP provides for the issuance of up to 24,350,000 shares of Laredo's common stock.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The Company recognizes the fair value of stock-based compensation awards expected to vest over the requisite service period as a charge against earnings, net of amounts capitalized. The Company's stock-based compensation awards are accounted for as equity instruments and ~~in prior periods, its performance unit awards were accounted for as liability awards. Stock-based compensation is~~are included in the "General and administrative" line item 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~~or 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" inon the unaudited consolidated balance sheets.



~~Table of Contents~~	~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

a. Restricted stock awards

All service vesting restricted stock awards are treated as issued and outstanding in the accompanying unaudited consolidated financial statements. Per the award agreement terms, if an employee terminates employment prior to the restriction lapse date for reasons other than death or disability, the awarded shares are forfeited and canceled and are no longer considered issued and outstanding. If the employee's termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. ~~Historically, restricted~~Restricted stock awards granted to officers and employees vest in a variety of vesting schedules including (i) 33%, 33% and 34% per year beginning ~~on the first anniversary date of the grant, (ii) fully~~ on the first anniversary of the grant date and ~~(iii)~~(ii) fully on the ~~third~~first anniversary of the grant date. Beginning August 2017, stock awards granted to non-employee directors vest immediately ~~upon~~on the grant date. Restricted stock awards granted to non-employee directors prior to August 2017 vest on the first anniversary of the grant date.

The following table reflects the restricted stock award activity for the ~~nine~~six months ended ~~September~~June 30, ~~2017:~~2018:


(in thousands, except for weighted-average grant date fair values)	Restricted stock awards		Weighted-average grant date fair value (per award)
Outstanding as of December 31, 2016	3,878		$	12.88
(in thousands, except for weighted-average grant-date fair value)					Restricted stock awards		Weighted-average grant-date fair value (per award)
Outstanding as of December 31, 2017					3,169		$	12.81
Granted	1,213		$	13.92	3,193		$	8.43
Forfeited	(264	)	$	12.88	(126	)	$	10.55
Vested⁽¹⁾	(1,618	)	$	13.78	(1,791	)	$	12.34
Outstanding as of September 30, 2017	3,209		$	12.82
Outstanding as of June 30, 2018					4,445		$	9.91


(1)	The total intrinsic value of vested restricted stock awards for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 was ~~$22.5~~$15.6 million.

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~~June 30, ~~2017,~~2018, unrecognized stock-based compensation related to the restricted stock awards expected to vest was ~~$26.7~~$33.0 million. Such cost is expected to be recognized over a weighted-average period of ~~1.73~~2.00 years.

b. Stock option awards

Stock option awards granted under the LTIP vest and become exercisable in four equal installments on each of the four ~~annual~~ anniversaries of the grant date. ~~The following table reflects~~As of June 30, 2018, the 2,646,996 outstanding stock option ~~award activity for~~awards have a weighted-average exercise price of $12.70 and a weighted-average remaining contractual term of 6.56 years. There were no grants, exercises, forfeitures or cancellations of stock option awards during the ~~nine~~six months ended ~~September~~June 30, ~~2017:~~2018.

(in thousands, except for weighted-average exercise price and
weighted-average remaining contractual term)

Stock
option
awards
Weighted-average
exercise price
(per award) Weighted-average
remaining contractual term
(years)
Outstanding as of December 31, 2016 2,370
$ 12.54
7.71
Granted 391
$ 14.12

Exercised⁽¹⁾
(44 ) $ 8.17

Expired or canceled (57 ) $ 20.58

Outstanding as of September 30, 2017 2,660
$ 12.67
7.37
Vested and exercisable as of September 30, 2017⁽²⁾
1,273
$ 16.38
6.22
Expected to vest as of September 30, 2017⁽³⁾
1,387
$ 9.26
8.42


~~(1)~~	~~The total intrinsic value of exercised stock option awards for the nine months ended September 30, 2017 was $0.3 million.~~


~~(2)~~	~~The vested and exercisable stock option awards as of September 30, 2017 had an aggregate intrinsic value of $2.1 million.~~


~~(3)~~	~~The stock option awards expected to vest as of September 30, 2017 had an aggregate intrinsic value of $6.3 million.~~

The Company utilizes the Black-Scholes option pricing model to determine the fair value of stock option awards and recognizes the associated expense on a straight-line basis over the ~~four-year~~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 expected volatility. As of June 30, 2018, unrecognized stock-based compensation related to stock option awards expected to vest was $6.0 million. Such cost is expected to be recognized over a weighted-average period of 1.87 years.

Performance share awards

Performance share awards, which the Company has determined are equity awards, are subject to a combination of market, performance and service vesting criteria. For awards with market criteria or portions of awards with market criteria, which include the RTSR Performance Percentage (as defined below), the ATSR Appreciation (as defined below) and the Company's total shareholder return ("TSR"), a Monte Carlo simulation prepared by an independent third party is utilized to determine the grant-date fair value and the associated expense is recognized on a straight-line basis over the three-year requisite



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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 expected volatility. As of September 30, 2017, unrecognized stock-based compensation related to stock option awards expected to vest was $9.4 million. Such cost is expected to be recognized over a weighted-average period of 2.52 years.

~~The assumptions used to estimate the fair value of the 390,733 stock option awards granted during the nine months ended September 30, 2017 are as follows:~~

Granted on
February 17, 2017
Risk-free interest rate⁽¹⁾
2.14 %
Expected option life⁽²⁾
6.25 years
Expected volatility⁽³⁾
60.84 %
Fair value per stock option award $ 8.22


~~(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 stock option award.~~


~~(2)~~	As the Company had limited exercise history at the time of valuation relating to terminations and modifications, expected stock option award life assumptions were developed using the simplified method in accordance with GAAP.


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

In accordance with the LTIP and stock option agreement, the stock option awards 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 stock option award will expire if and to the extent it is not exercised within 10 years from the grant date. The unvested portion of a stock option award shall expire upon termination of employment, and the vested portion of a stock option award shall remain exercisable for (i) one year following termination of employment by reason of the holder's death or disability, but not later than the expiration of the option period, or (ii) ~~90 days~~ following termination of employment for any reason other than the holder's death or disability, and other than the holder's termination of employment for cause. Both the unvested and the vested but unexercised portion of a stock option award shall expire upon the termination of the option holder's employment or service by the Company for cause.

~~c. Performance share awards~~

Performance share awards granted to management are subject to a combination of market and service vesting criteria. A Monte Carlo simulation prepared by an independent third party is utilized 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. For portions of awards with performance criteria, which is the ROACE Percentage (as defined below), the grant-date fair value is equal to the Company's stock price on the grant date, and for each reporting period, the associated expense fluctuates and is trued-up based on an estimated probability of how many shares will be earned at the end of the three-year performance period. Any shares earned under ~~such~~performance share awards are expected to be issued in the first quarter following the completion of the requisite service period based on the achievement of certain market and performance criteria.



~~Table of Contents~~	~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

The following table reflects the performance share award activity for the ~~nine~~six months ended ~~September~~June 30, ~~2017:~~2018:


(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, 2016	2,325		$	18.35
(in thousands, except for weighted-average grant-date fair value)					Performance share awards		Weighted-average grant-date fair value (per award)
Outstanding as of December 31, 2017					2,745		$	17.77
Granted(1)	696		$	18.96	1,389		$	9.22
Forfeited	(67	)	$	18.12	(28	)	$	15.71
Vested⁽¹⁾⁽²⁾	(200	)	$	28.56	(454	)	$	16.23
Outstanding as of September 30, 2017	2,754		$	17.77
Outstanding as of June 30, 2018					3,652		$	14.55

(1)

~~These~~The amount of stock potentially payable at the end of the performance period for the performance share awards granted on February 16, 2018 will be determined based on three criteria: (i) relative three-year total shareholder return comparing the Company's shareholder return to the shareholder return of the peer group specified in the award agreement ("RTSR Performance Percentage"), (ii) absolute three-year total shareholder return ("ATSR Appreciation") and (iii) three-year return on average capital employed ("ROACE Percentage"). The RTSR Performance Percentage, ATSR Appreciation and ROACE Percentage will be used to identify the "RTSR Factor," the "ATSR Factor" and the "ROACE Factor," respectively, which are used to compute the "Performance Multiple" and ultimately to determine the final number of shares associated with each performance share unit granted at the maturity date (with all partial shares rounded, as appropriate). In computing the Performance Multiple, the RTSR Factor is given a 25% weight, the ATSR Factor a 25% weight and the ROACE Factor a 50% weight. The $9.22 per unit grant-date fair value consists of a (i) $10.08 per unit grant-date fair value, determined utilizing a Monte Carlo simulation, for the combined (.25) RTSR Factor and (.25) ATSR Factor and (ii) $8.36 per unit grant-date fair value for the (.50) ROACE Factor determined based on the closing price of the Company's common stock on the New York Stock Exchange on February 16, 2018. These awards have a performance period of January 1, 2018 to December 31, 2020.

(2)

The performance share awards granted on February 27, 2015 had a performance period of January 1, ~~2014~~2015 to December 31, ~~2016~~2017 and, as their ~~vesting and~~ performance criteria were not satisfied, ~~each award~~resulted in a TSR modifier of 0% based on the Company finishing in the 36th percentile of its peer group for relative TSR. As such, the units were not converted into ~~0.75 shares representing 150,388 shares of~~the Company's common stock ~~issued~~ during the first quarter of ~~2017.~~2018.

As of ~~September~~June 30, ~~2017,~~2018, unrecognized stock-based compensation related to the performance share awards expected to vest was ~~$25.2~~$23.7 million. Such cost is expected to be recognized over a weighted-average period of ~~1.77~~1.84 years.

The assumptions used to estimate the combined fair ~~values~~value for the (.25) RTSR Factor and the (.25) ATSR Factor for the market criteria portion of the ~~696,460~~ performance share awards granted ~~during~~on the ~~nine months ended September 30, 2017~~date presented are as follows:


	Granted on February 17, 2017			February 16, 2018
Risk-free interest rate⁽¹⁾	1.44		%	2.34		%
Dividend yield	—		%	—		%
Expected volatility⁽²⁾	74.00		%	65.49		%
Laredo stock closing price on grant date	$	14.12		$	8.36
Fair value per performance share award	$	18.96
Combined fair value per performance share award for the (.25) RTSR Factor and the (.25) ATSR Factor⁽³⁾				$	10.08


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


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

~~d. Stock-based compensation expense~~

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

Three months ended September 30, Nine months ended September 30,
(in thousands) 2017 2016 2017 2016
Restricted stock award compensation $ 5,422
$ 6,540
$ 16,856
$ 15,000
Stock option award compensation 1,159
1,653
3,600
3,054
Performance share award compensation 4,255
3,450
12,063
5,271
Total stock-based compensation, gross 10,836
11,643
32,519
23,325
Less amounts capitalized in oil and natural gas properties (1,870 ) (1,992 ) (5,642 ) (3,763 )
Total stock-based compensation, net of amounts capitalized $ 8,966
$ 9,651
$ 26,877
$ 19,562

~~e. Performance unit awards~~

The performance unit awards issued to management on February 15, 2013 (the "2013 Performance Unit Awards") were subject to a combination of market and service vesting criteria. These awards were accounted for as liability awards as they were settled in cash at the end of the requisite service period based on the achievement of certain performance criteria.

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


(3)	The market criteria portion of the performance share award represents 50% of each of the amount of stock potentially payable, if any, and the grant-date fair value of the award.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

~~Note 6—Income taxes~~Stock-based compensation expense

The ~~Company is subject~~following has been recorded to ~~federal and state income taxes and~~stock-based compensation expense for the ~~Texas franchise tax. The Company had federal net operating loss carry-forwards totaling~~ periods presented:~~$1.9 billion~~ ~~and state of Oklahoma net operating loss carry-forwards totaling~~ ~~$41.2 million~~ ~~as of September 30, 2017. These carry-forwards begin expiring in 2026. As of September 30, 2017,~~



	Three months ended June 30,						Six months ended June 30,
(in thousands)	2018			2017			2018			2017
Restricted stock award compensation	$	7,286		$	5,267		$	13,331		$	11,434
Stock option award compensation	971			1,144			2,040			2,441
Performance share award compensation	4,415			4,068			8,742			7,808
Total stock-based compensation, gross	12,672			10,479			24,113			21,683
Less amounts capitalized in oil and natural gas properties	(1,996		)	(1,792		)	(4,098		)	(3,772		)
Total stock-based compensation, net	$	10,676		$	8,687		$	20,015		$	17,911

Note 8—Derivatives

Due to 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,~~inherent volatility in ~~determining whether, based on the weight of that evidence, a valuation allowance was needed. Such consideration included projected future cash flows from its~~ oil, NGL and natural gas ~~reserves (including~~prices, the timing of those cash flows), the reversal of deferred tax liabilities recorded as of September 30, 2017, 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. As of September 30, 2017, a full valuation allowance of $712.2 million has been recorded against the Company's deferred tax position.

~~Note 7—Derivatives~~

~~a. Derivatives~~

~~The~~ Company engages in derivative transactions, such as puts, swaps, collars, basis swaps and, in the past, call spreads to hedge price ~~risks~~risk associated with a significant portion of the Company's anticipated production. By removing a 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 ~~unfavorable changes~~fluctuations in ~~oil, NGL and natural gas prices related to its production. As of September 30, 2017, the Company had~~ 44 open derivative contracts with financial institutions that extend from October 2017 to December 2019. None of these contracts were designated as hedges for accounting purposes. The contracts are recorded at fair value on the unaudited consolidated balance sheets and gains and losses are recognized in earnings. Gains and losses on derivatives are reported in the unaudited consolidated statements of operations in the "Gain (loss) on derivatives, net" line item.commodity prices.

Each put transaction has an established floor price. The Company pays its counterparty a premium, which can be paid at inception or 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 floor price multiplied by the hedged contract volume. When the settlement price is at or above the floor price in an individual month in the contract period, the put option expires with no settlement for that particular month, except with regard to the deferred premium, if any.

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. Depending on the terms, the Company may pay its counterparty a premium, which can be paid at inception or deferred until settlement. When the settlement price is below the price floor established by these collars, the counterparty pays the Company an amount 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. When the settlement price is between the price floor and price ceiling established by these collars in an individual month in the contract period, the collar expires with no settlement paid by either the Company or the counterparty for that particular month, except with regard to the deferred premium, if any.

Each basis swap transaction has an established fixed basis differential corresponding to two floating index prices. Depending on the difference of the two floating index prices in relationship to the fixed basis differential, the Company either receives an amount from its counterparty, or pays an amount to its counterparty, equal to the difference multiplied by the hedged contract volume.

Each call spread transaction has an established short call price and long call price. Depending on the terms, the counterparty may pay a premium to the Company to enter into the transaction. When the settlement price is above the short call price up to the long call price, the Company pays its counterparty an amount equal to the difference between the settlement price and the short call price multiplied by the hedged contract volume. When the settlement price is above the long call price, the Company pays the counterparty an amount equal to the difference between the long call price and the short call price multiplied by the hedged contract volume. When the settlement price is at or below the short call price in an individual month in the contract period, the call option expires with no settlement paid by either the Company or the counterparty for that particular month, except with regard to the deferred premium, if any.



~~Table of Contents~~	~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

Other than the oil basis swaps, the Company's oil derivatives are settled based on the month's average daily NYMEX index price for the first nearby month of the West Texas Intermediate Light Sweet Crude Oil Futures Contract. The oil basis swaps are settled based on either (i) the ~~swaps'~~ differential between the Argus Americas Crude West Texas Intermediate ("WTI") index



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

prices for WTI Midland-weighted average for the trade month and WTI Cushing-WTI formula basis for the trade month as compared to the basis swaps' fixed differential price ~~less~~or (ii) the differential between the Argus Americas Crude WTI Houston-weighted average price for the trade ~~month.~~month and the WTI Midland-weighted average price for the trade month as compared to the basis swaps' fixed differential price. The Company's NGL derivatives are settled based on the month's average daily OPIS index price for Mont Belvieu Purity Ethane, TET and ~~TET Propane. The~~Non-TET Propane, Non-TET Normal Butane, Non-TET Isobutane and Non-TET Natural Gasoline. Other than the natural gas basis swaps, the Company's natural gas derivatives are settled based on the Inside FERC index price for West Texas WAHA for the calculation period. The natural gas basis swaps are settled based on the differential between the Inside FERC index price for West Texas WAHA for the calculation period and the NYMEX Henry Hub index price for the calculation period as compared to the basis swaps' fixed differential price.

During the ~~nine~~three and six months ended ~~September~~June 30, 2017, the Company completed a hedge restructuring by early terminating a swap that resulted in a termination amount to the Company of $4.2 million that was settled in full by applying the proceeds to pay the premium on one new collar entered into during the ~~hedge~~ restructuring. The following details the derivative that was terminated:

Aggregate volumes (Bbl) Floor price ($/Bbl) Ceiling price ($/Bbl) Contract period
Oil swap 1,095,000
$ 52.12
$ 52.12
January 2018 - December 2018



	Aggregate volumes (Bbl)	Floor price ($/Bbl)		Ceiling price ($/Bbl)		Contract period
Oil swap	1,095,000	$	52.12	$	52.12	January 2018 - December 2018

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

~~During the nine months ended September 30, 2017, the following derivatives were entered into:~~

Aggregate volumes⁽¹⁾

Floor price⁽²⁾

Ceiling price⁽²⁾

Short call price⁽²⁾

Long call price⁽²⁾

Differential price⁽²⁾
Contract period
Oil⁽³⁾:

Call spread⁽⁴⁾
1,140,800
$ —
$ —
$ 60.00
$ 100.00
$ —
July 2017 - December 2017
Call spread⁽⁵⁾
184,000
$ —
$ —
$ 60.00
$ 80.00
$ —
July 2017 - December 2017
Put⁽⁶⁾
4,378,000
$ 50.00
$ —
$ —
$ —
$ —
January 2018 - December 2018
Collar 584,000
$ 50.00
$ 60.00
$ —
$ —
$ —
January 2018 - December 2018
Collar⁽⁷⁾
3,504,000
$ 40.00
$ 60.00
$ —
$ —
$ —
January 2018 - December 2018
Basis swap 1,825,000
$ —
$ —
$ —
$ —
$ (0.59 ) January 2018 - December 2018
Basis swap 365,000
$ —
$ —
$ —
$ —
$ (0.58 ) January 2018 - December 2018
Basis swap 730,000
$ —
$ —
$ —
$ —
$ (0.52 ) January 2018 - December 2018
Basis swap 730,000
$ —
$ —
$ —
$ —
$ (0.49 ) January 2018 - December 2018
Put 730,000
$ 50.00
$ —
$ —
$ —
$ —
January 2019 - December 2019
Natural gas:
Collar⁽⁸⁾
10,950,000
$ 2.50
$ 3.25
$ —
$ —
$ —
January 2018 - December 2018


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


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


~~(3)~~	~~There are $22.9 million in deferred premiums associated with these contracts.~~


~~(4)~~	~~A premium of $0.5 million was settled in full at inception by applying the proceeds to pay the premiums on a put entered into simultaneously.~~


~~(5)~~	~~A premium of $0.1 million was settled in full at inception by applying the proceeds to pay the premiums on a put entered into simultaneously.~~


~~(6)~~	~~Premiums of $4.9 million were paid at inception, of which $0.6 million were settled in full at inception by applying the proceeds from the call spreads entered into simultaneously.~~


~~(7)~~	~~A premium of $4.2 million was settled in full at inception as part of the Company's 2017 hedge restructuring by applying the proceeds of the terminated swap.~~


~~(8)~~	~~There are $0.9 million in deferred premiums associated with these contracts.~~



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table summarizes open positions as of June 30, 2018, and represents, ~~cash settlements received for~~as of such date, derivatives ~~net for the periods presented:~~in place through December 2020 on annual production volumes:

Three months ended September 30, Nine months ended September 30,
(in thousands) 2017 2016 2017 2016
Cash settlements received for matured derivatives, net⁽¹⁾
$ 13,635
$ 44,307
$ 34,791
$ 157,626
Cash settlements received for early terminations of derivatives, net⁽²⁾
—
—
4,234
80,000
Cash settlements received for derivatives, net $ 13,635
$ 44,307
$ 39,025
$ 237,626


~~(1)~~	~~The settlement amounts do not include premiums paid attributable to contracts that matured during the respective period.~~


~~(2)~~	~~The settlement amount for the nine months ended September 30, 2016 includes $4.0 million in deferred premiums that were settled net with the early terminated contracts from which they originated.~~



	Remaining year 2018			Year 2019		Year 2020
Oil:
Puts:
Hedged volume (Bbl)	2,735,550			5,949,500		366,000
Weighted-average floor price ($/Bbl)	$	51.93		$	48.31	$	45.00
Swaps:
Hedged volume (Bbl)	—			657,000		695,400
Weighted-average price ($/Bbl)	$	—		$	53.45	$	52.18
Collars:
Hedged volume (Bbl)	2,060,800			—		—
Weighted-average floor price ($/Bbl)	$	41.43		$	—	$	—
Weighted-average ceiling price ($/Bbl)	$	60.00		$	—	$	—
Totals:
Total volume hedged with floor price (Bbl)	4,796,350			6,606,500		1,061,400
Weighted-average floor price ($/Bbl)	$	47.42		$	48.82	$	49.70
Total volume hedged with ceiling price (Bbl)	2,060,800			657,000		695,400
Weighted-average ceiling price ($/Bbl)	$	60.00		$	53.45	$	52.18
Basis Swaps:
WTI Midland to WTI Cushing:
Hedged volume (Bbl)	1,840,000			—		—
Weighted-average price ($/Bbl)	$	(0.56	)	$	—	$	—
WTI Houston to WTI Midland:
Hedged volume (Bbl)	1,840,000			1,810,000		—
Weighted-average price ($/Bbl)	$	7.30		$	7.30	$	—
NGL:
Swaps - Purity Ethane:
Hedged volume (Bbl)	312,800			—		—
Weighted-average price ($/Bbl)	$	11.66		$	—	$	—
Swaps - Non-TET Propane:
Hedged volume (Bbl)	257,600			—		—
Weighted-average price ($/Bbl)	$	33.92		$	—	$	—
Swaps - Non-TET Normal Butane:
Hedged volume (Bbl)	92,000			—		—
Weighted-average price ($/Bbl)	$	38.22		$	—	$	—
Swaps - Non-TET Isobutane:
Hedged volume (Bbl)	36,800			—		—
Weighted-average price ($/Bbl)	$	38.33		$	—	$	—
Swaps - Non-TET Natural Gasoline:
Hedged volume (Bbl)	92,000			—		—
Weighted-average price ($/Bbl)	$	57.02		$	—	$	—
Total NGL volume hedged (Bbl)	791,200			—		—
TABLE CONTINUES ON NEXT PAGE



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

~~The following table summarizes open positions as of September 30, 2017, and represents, as of such date, derivatives in place through December 2019 on annual production:~~

Remaining year
2017
Year
2018 Year
2019
Oil positions:

Puts:

Hedged volume (Bbl) 264,500
5,427,375
730,000
Weighted-average price ($/Bbl) $ 60.00
$ 51.93
$ 50.00
Swaps:

Hedged volume (Bbl) 506,000
—
—
Weighted-average price ($/Bbl) $ 51.54
$ —
$ —
Collars:

Hedged volume (Bbl) 956,800
4,088,000
—
Weighted-average floor price ($/Bbl) $ 56.92
$ 41.43
$ —
Weighted-average ceiling price ($/Bbl) $ 86.00
$ 60.00
$ —
Call Spreads:
Hedged volume (Bbl) 662,400
—
—
Weighted-average short call price ($/Bbl) $ 60.00
$ —
$ —
Weighted-average long call price ($/Bbl) $ 97.22
$ —
$ —
Totals:
Total volume hedged with floor price (Bbl) 1,727,300
9,515,375
730,000
Weighted-average floor price ($/Bbl) $ 55.82
$ 47.42
$ 50.00
Total volume hedged with ceiling price (Bbl) 1,462,800
4,088,000
—
Weighted-average ceiling price ($/Bbl) $ 57.22
$ 60.00
$ —
Basis Swaps:
Hedged volume (Bbl) —
3,650,000
—
Weighted-average price ($/Bbl) $ —
$ (0.56 ) $ —
NGL positions:
Swaps - Ethane:
Hedged volume (Bbl) 111,000
—
—
Weighted-average price ($/Bbl) $ 11.24
$ —
$ —
Swaps - Propane:
Hedged volume (Bbl) 93,750
—
—
Weighted-average price ($/Bbl) $ 22.26
$ —
$ —
Natural gas positions:

Puts:
Hedged volume (MMBtu) 2,010,000
8,220,000
—
Weighted-average price ($/MMBtu) $ 2.50
$ 2.50
$ —
Collars:

Hedged volume (MMBtu) 4,793,200
15,585,500
—
Weighted-average floor price ($/MMBtu) $ 2.86
$ 2.50
$ —
Weighted-average ceiling price ($/MMBtu) $ 3.54
$ 3.35
$ —
Totals:
Total volume hedged with floor price (MMBtu) 6,803,200
23,805,500
—
Weighted-average floor price ($/MMBtu) $ 2.75
$ 2.50
$ —
Total volume hedged with ceiling price (MMBtu) 4,793,200
15,585,500
—
Weighted-average ceiling price ($/MMBtu) $ 3.54
$ 3.35
$ —



~~Table of Contents~~	~~Laredo Petroleum, Inc.~~



	Remaining year 2018			Year 2019			Year 2020
Natural gas:
Puts:
Hedged volume (MMBtu)	4,110,000			—			—
Weighted-average floor price ($/MMBtu)	$	2.50		$	—		$	—
Collars:
Hedged volume (MMBtu)	7,856,800			—			—
Weighted-average floor price ($/MMBtu)	$	2.50		$	—		$	—
Weighted-average ceiling price ($/MMBtu)	$	3.35		$	—		$	—
Totals:
Total volume hedged with floor price (MMBtu)	11,966,800			—			—
Weighted-average floor price ($/MMBtu)	$	2.50		$	—		$	—
Total volume hedged with ceiling price (MMBtu)	7,856,800			—			—
Weighted-average ceiling price ($/MMBtu)	$	3.35		$	—		$	—
Basis Swaps:
Hedged volume (MMBtu)	4,600,000			20,075,000			25,254,000
Weighted-average price ($/MMBtu)	$	(0.62	)	$	(1.05	)	$	(0.76	)

~~Condensed notes~~See Note 17.a for discussion of additional hedges entered into subsequent to June 30, 2018.

At each period end, the ~~consolidated financial statements~~

~~(Unaudited)~~

~~b. Balance sheet presentation~~

~~In accordance with~~Company nets the ~~Company's standard practice, its~~fair value of derivatives ~~are subject to~~by counterparty ~~netting under their governing agreements. The Company's oil, NGL~~where the right of offset exists and ~~natural gas derivatives are presented on a~~reports this net basis ason the "Derivatives" line items on the unaudited consolidated balance ~~sheets.~~sheets as assets and/or liabilities. See Note ~~8.a~~9.a for a summary of the fair value of derivatives on a gross basis.

~~By using~~ The Company's derivatives ~~to hedge exposures to~~were not designated as hedges for accounting purposes. Accordingly, the changes in ~~commodity prices, the Company exposes itself to credit risk and market risk. For the Company, market risk is the exposure to changes~~fair value are recognized in the ~~market price~~unaudited consolidated statements of oil, NGL and natural gas, which are subject to fluctuations from a variety of factors, including changes in supply and demand. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, thereby creating credit risk. The Company's counterparties are participantsoperations in the ~~Senior Secured Credit Facility, which is secured by the Company's oil, NGL~~"Gain (loss) on derivatives, net" line item. Gains and ~~natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral~~losses on derivatives are included in cash flows 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.operating activities.

Note 8—9—Fair value measurements

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

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

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



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

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

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



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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 ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 or ~~2016.~~2017.



~~Table of Contents~~	~~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 derivatives' fair value hierarchy by commodity and current and noncurrent assets and liabilities on a gross basis and the net presentation on the unaudited consolidated balance sheets ~~for derivative assets and liabilities~~ measured at fair value on a recurring basis as of the ~~periods~~dates presented:


(in thousands)	Level 1		Level 2			Level 3			Total gross fair value			Amounts offset			Net fair value presented on the unaudited consolidated balance sheets			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, 2017:
Assets
As of June 30, 2018:
Assets:
Current:
Oil derivatives	$	—	$	27,097		$	—		$	27,097		$	(8,732	)	$	18,365		$	—	$	25,431		$	—		$	25,431		$	(20,029	)	$	5,402
NGL derivatives	—		—			—			—			—			—			—		—			—			—			—			—
Natural gas derivatives	—		4,955			—			4,955			(4,955		)	—			—		17,759			—			17,759			(11,163		)	6,596
Oil deferred premiums	—		—			—			—			(2,754		)	(2,754		)
Natural gas deferred premiums	—		—			—			—			—			—
Oil derivative deferred premiums																		—		—			—			—			(2,703		)	(2,703		)
Natural gas derivative deferred premiums																		—		—			—			—			(1,236		)	(1,236		)
Noncurrent:
Oil derivatives	$	—	$	12,471		$	—		$	12,471		$	(4,052	)	$	8,419		$	—	$	6,674		$	—		$	6,674		$	(6,217	)	$	457
NGL derivatives	—		—			—			—			—			—			—		—			—			—			—			—
Natural gas derivatives	—		1,277			—			1,277			(256		)	1,021			—		6,087			—			6,087			(3,470		)	2,617
Oil deferred premiums	—		—			—			—			(4,376		)	(4,376		)
Natural gas deferred premiums	—		—			—			—			(719		)	(719		)
Liabilities
Oil derivative deferred premiums																		—		—			—			—			—			—
Natural gas derivative deferred premiums																		—		—			—			—			—			—
Liabilities:
Current:
Oil derivatives	$	—	$	(1,556	)	$	—		$	(1,556	)	$	8,732		$	7,176		$	—	$	(57,068	)	$	—		$	(57,068	)	$	20,029		$	(37,039	)
NGL derivatives	—		(1,509		)	—			(1,509		)	—			(1,509		)	—		(3,697		)	—			(3,697		)	—			(3,697		)
Natural gas derivatives	—		—			—			—			4,955			4,955			—		187			—			187			11,163			11,350
Oil deferred premiums	—		—			(14,277		)	(14,277		)	2,754			(11,523		)
Natural gas deferred premiums	—		—			(3,269		)	(3,269		)	—			(3,269		)
Oil derivative deferred premiums																		—		—			(16,982		)	(16,982		)	2,703			(14,279		)
Natural gas derivative deferred premiums																		—		—			(1,690		)	(1,690		)	1,236			(454		)
Noncurrent:
Oil derivatives	$	—	$	(121	)	$	—		$	(121	)	$	4,052		$	3,931		$	—	$	(8,903	)	$	—		$	(8,903	)	$	6,217		$	(2,686	)
NGL derivatives	—		—			—			—			—			—			—		—			—			—			—			—
Natural gas derivatives	—		—			—			—			256			256			—		(306		)	—			(306		)	3,470			3,164
Oil deferred premiums	—		—			(8,810		)	(8,810		)	4,376			(4,434		)
Natural gas deferred premiums	—		—			(834		)	(834		)	719			(115		)
Oil derivative deferred premiums																		—		—			(6,354		)	(6,354		)	—			(6,354		)
Natural gas derivative deferred premiums																		—		—			—			—			—			—
Net derivative position	$	—	$	42,614		$	(27,190	)	$	15,424		$	—		$	15,424		$	—	$	(13,836	)	$	(25,026	)	$	(38,862	)	$	—		$	(38,862	)



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)


(in thousands)	Level 1		Level 2			Level 3			Total gross fair value			Amounts offset			Net fair value presented on the unaudited consolidated balance sheets			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, 2016:
Assets
As of December 31, 2017:
Assets:
Current:
Oil derivatives	$	—	$	22,527		$	—		$	22,527		$	—		$	22,527		$	—	$	7,427		$	—		$	7,427		$	(3,721	)	$	3,706
NGL derivatives	—		—			—			—			—			—			—		—			—			—			—			—
Natural gas derivatives	—		270			—			270			(270		)	—			—		10,546			—			10,546			(4,817		)	5,729
Oil deferred premiums	—		—			—			—			(1,580		)	(1,580		)
Natural gas deferred premiums	—		—			—			—			—			—
Oil derivative deferred premiums																		—		—			—			—			(87		)	(87		)
Natural gas derivative deferred premiums																		—		—			—			—			(2,456		)	(2,456		)
Noncurrent:
Oil derivatives	$	—	$	8,718		$	—		$	8,718		$	—		$	8,718		$	—	$	11,613		$	—		$	11,613		$	(6,087	)	$	5,526
NGL derivatives	—		—			—			—			—			—			—		—			—			—			—			—
Natural gas derivatives	—		1,377			—			1,377			(1,377		)	—			—		934			—			934			(934		)	—
Oil deferred premiums	—		—			—			—			—			—
Natural gas deferred premiums	—		—			—			—			—			—
Liabilities
Oil derivative deferred premiums																		—		—			—			—			(2,113		)	(2,113		)
Natural gas derivative deferred premiums																		—		—			—			—			—			—
Liabilities:
Current:
Oil derivatives	$	—	$	(9,789	)	$	—		$	(9,789	)	$	—		$	(9,789	)	$	—	$	(12,477	)	$	—		$	(12,477	)	$	3,721		$	(8,756	)
NGL derivatives	—		(2,803		)	—			(2,803		)	—			(2,803		)	—		—			—			—			—			—
Natural gas derivatives	—		(3,639		)	—			(3,639		)	270			(3,369		)	—		—			—			—			4,817			4,817
Oil deferred premiums	—		—			(3,569		)	(3,569		)	1,580			(1,989		)
Natural gas deferred premiums	—		—			(3,043		)	(3,043		)	—			(3,043		)
Oil derivative deferred premiums																		—		—			(18,202		)	(18,202		)	87			(18,115		)
Natural gas derivative deferred premiums																		—		—			(3,352		)	(3,352		)	2,456			(896		)
Noncurrent:
Oil derivatives	$	—	$	(4,552	)	$	—		$	(4,552	)	$	—		$	(4,552	)	$	—	$	(2,389	)	$	—		$	(2,389	)	$	6,087		$	3,698
NGL derivatives	—		—			—			—			—			—			—		—			—			—			—			—
Natural gas derivatives	—		(133		)	—			(133		)	1,377			1,244			—		—			—			—			934			934
Oil deferred premiums	—		—			—			—			—			—
Natural gas deferred premiums	—		—			(2,386		)	(2,386		)	—			(2,386		)
Oil derivative deferred premiums																		—		—			(7,129		)	(7,129		)	2,113			(5,016		)
Natural gas derivative deferred premiums																		—		—			—			—			—			—
Net derivative position	$	—	$	11,976		$	(8,998	)	$	2,978		$	—		$	2,978		$	—	$	15,654		$	(28,683	)	$	(13,029	)	$	—		$	(13,029	)

These items are included asin the "Derivatives" line items on the unaudited consolidated balance ~~sheets.~~sheets as assets and/or liabilities. Significant Level 2 assumptions associated with the calculation of discounted cash flows used in the mark-to-market analysis of derivatives include each derivative contract's corresponding commodity index ~~price,~~price(s), appropriate risk-adjusted discount rates and other relevant data. The Company determines the fair value of its derivatives by utilizing pricing models for substantially similar instruments. Inputs to the pricing models include forward price curves generated from a compilation of data gathered from third parties.

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



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table presents ~~actual cash~~ payments required for derivative deferred premiums as of ~~September~~June 30, ~~2017~~2018 for the periods presented:


(in thousands)	September 30, 2017		June 30, 2018
Remaining 2017	$	1,441
2018	20,335
Remaining 2018			$	10,860
2019	5,774		13,511
2020	391		1,110
Total	$	27,941	$	25,481

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

Three months ended September 30, Nine months ended September 30,
(in thousands)
2017 2016 2017 2016
Balance of Level 3 at beginning of period
$ (12,554 ) $ (12,662 ) $ (8,998 )
$ (14,619 )
Change in net present value of derivative deferred premiums
(88 ) (51 ) (199 )
(184 )
Total purchases and settlements:

Purchases
(15,996 ) —
(22,994 )
(6,072 )
Settlements⁽¹⁾

1,448
2,709
5,001

10,871
Balance of Level 3 at end of period
$ (27,190 ) $ (10,004 ) $ (27,190 )
$ (10,004 )


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



	Three months ended June 30,						Six months ended June 30,
(in thousands)	2018			2017			2018			2017
Balance of Level 3 at beginning of period	$	(30,292	)	$	(13,025	)	$	(28,683	)	$	(8,998	)
Change in net present value of derivative deferred premiums	(185		)	(70		)	(396		)	(111		)
Total purchases and settlements of derivative deferred premiums:
Purchases	—			(905		)	(5,422		)	(6,998		)
Settlements	5,451			1,446			9,475			3,553
Balance of Level 3 at end of period	$	(25,026	)	$	(12,554	)	$	(25,026	)	$	(12,554	)

b. Fair value measurement on a nonrecurring basis

~~The Company accounts for the impairment of long-lived assets, if any, at fair~~See Note 10.b "Fair value measurement 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. No impairments of long-lived assets were recorded during the nine months ended September 30, 2017 or 2016.

The Company accounts for the impairment of inventory, if any, at lower of cost or NRV on a nonrecurring basis. For purposes of fair value measurement, it was determined that the impairment of inventory is classified as Level 2, based on the use of a replacement cost approach. Seebasis" and Note 2.i for discussion of the Company's inventory impairments recorded during the nine months ended September 30, 2016. No impairments of inventory were recorded during the nine months ended September 30, 2017.

The accounting policies for impairment of oil and natural gas properties are discussed in Note 2.g. Significant inputs included in the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of operating and development costs, anticipated production of evaluated reserves and other relevant data. See Note 2.g for discussion of the Company's full cost ceiling impairment recorded during the nine months ended September 30, 2016. There was no full cost ceiling impairment recorded during the nine months ended September 30, 2017.

~~The Company accounts for~~4.c "2016 acquisitions of evaluated and unevaluated oil and natural gas ~~properties under~~properties" in the ~~acquisition method of accounting. Accordingly,~~2017 Annual Report for the ~~Company conducts assessments of net assets acquired~~Company's accounting policies and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction costs associated with the acquisitions are expensed as incurred.

~~The Company makes various~~ assumptions in estimating the fair values of assets acquired and liabilities ~~assumed. The most significant assumptions relate to the estimated fair value~~assumed for acquisitions of evaluated and unevaluated oil and natural gas properties. See Note 3.a for additional discussion of the Company's acquisitions of evaluated and unevaluated oil and natural gas properties for the six months ended June 30, 2018.

c. Items not accounted for at fair value

The carrying amounts reported in the unaudited consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, accrued capital expenditures, undistributed revenue and royalties and other accrued assets and liabilities approximate their fair values.

The Company has not elected to account for its debt instruments at fair value. The following table presents the carrying amounts and fair values of the Company's debt as of the dates presented:



	June 30, 2018				December 31, 2017
(in thousands)	Long-term debt		Fair value		Long-term debt		Fair value
January 2022 Notes	$	450,000	$	444,938	$	450,000	$	454,500
March 2023 Notes	350,000		352,188		350,000		364,105
Senior Secured Credit Facility	110,000		110,028		—		—
Total	$	910,000	$	907,154	$	800,000	$	818,605

The fair values of the debt outstanding on the January 2022 Notes and the March 2023 Notes were determined using the June 30, 2018 and December 31, 2017 quoted market price (Level 1) for each respective instrument. The fair value of ~~these properties is measured using a discounted cash flow model that converts future cash flows to a single discounted amount. Significant inputs to~~ the ~~valuation include estimates of: (i) forecasted oil, NGL and natural gas reserve quantities; (ii) future commodity strip prices~~outstanding debt on the Senior Secured Credit Facility as of June 30, 2018 was estimated utilizing a pricing model for similar instruments (Level 2).

Note 10—Net income per common share

Basic net income per common share is computed by dividing net income by the closing dates adjusted for transportation and regional price differentials; (iii) forecasted ad valorem taxes, production taxes, income taxes, general and administrative expenses, operating expenses and development costs; and (iv) a peer group weighted-average ~~cost~~number of ~~capital rate subject to additional project-specific risk factors. To compensate~~common shares outstanding for the ~~inherent risk~~period. Diluted net income per common share reflects the potential dilution of ~~estimating the value of the unevaluated properties, the discounted future net revenues of~~non-vested restricted



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

proved undeveloped and probable reserves are reduced by additional reserve adjustment factors. These assumptions represent Level 3 inputs under the fair value hierarchy. See Note 3.b for additional discussion of the Company's acquisitions of evaluated and unevaluated oil and natural gas properties during the nine months ended September 30, 2016. No acquisitions were recorded during the nine months ended September 30, 2017.

~~Note 9—Net income (loss) per common share~~

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

~~The effect of the Company's~~ outstanding stock option awards ~~with the exception of the options granted in 2016, was excluded from the calculation of diluted net income per common~~and non-vested performance share ~~for the three and nine months ended September 30, 2017.~~awards. The ~~inclusion~~dilutive effects of these ~~options would be anti-dilutive due to the following: (i)~~awards were calculated utilizing the treasury stock ~~method, the sum of the assumed proceeds exceeded the average stock prices during the respective periods~~method. See Note 7.c for the outstanding stock option awards granted in 2015 and (ii) the exercise prices were greater than the average market prices during the respective periods for the outstanding stock option awards granted in 2012, 2013, 2014 and 2017.

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

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


	Three months ended September 30,				Nine months ended September 30,					Three months ended June 30,				Six months ended June 30,
(in thousands, except for per share data)	2017		2016		2017		2016			2018		2017		2018		2017
Net income (loss) (numerator):
Net income (loss)—basic and diluted	$	11,027	$	9,485	$	140,413	$	(242,318	)
Net income (numerator):
Net income—basic and diluted										$	33,452	$	61,110	$	119,972	$	129,386
Weighted-average common shares outstanding (denominator):
Basic⁽¹⁾	239,306		234,639		239,017		221,303			230,933		239,231		234,561		238,870
Non-vested performance share awards⁽²⁾	4,801		3,216		4,702		—
Non-vested restricted stock awards⁽³⁾	650		253		845		—
Non-vested restricted stock awards⁽²⁾										683		419		885		896
Outstanding stock option awards⁽³⁾	130		—		129		—			90		101		55		131
Non-vested performance share awards⁽⁴⁾										—		4,666		—		4,488
Diluted	244,887		238,108		244,693		221,303			231,706		244,417		235,501		244,385
Net income (loss) per common share:
Net income per common share:
Basic	$	0.05	$	0.04	$	0.59	$	(1.09	)	$	0.14	$	0.26	$	0.51	$	0.54
Diluted	$	0.05	$	0.04	$	0.57	$	(1.09	)	$	0.14	$	0.25	$	0.51	$	0.53

(1)

~~For the three and nine months ended September 30, 2016, weighted-average~~Weighted-average common shares outstanding used in the computation of basic and diluted net income ~~(loss)~~ per common share ~~attributable to stockholders~~ was computed taking into account ~~equity offerings~~share repurchases that occurred during the ~~respective periods.~~three and six months ended June 30, 2018. See Note ~~2.o~~7.a for additional discussion of the Company's ~~equity offerings.~~share repurchase program.


(2)	The ~~dilutive~~effect of a significant portion of the non-vested restricted stock awards was excluded from the calculation of diluted net income per common share for the three and six months ended June 30, 2018. The inclusion of these non-vested restricted stock awards would be anti-dilutive due to the sum of the assumed proceeds exceeding the average stock price during the period.


(3)	The effect of the outstanding stock option awards, with the exception of those granted in 2016, was excluded from the calculation of diluted net income per common share for the three and six months ended June 30, 2018. The inclusion of these stock option awards would be anti-dilutive as their exercise prices were greater than the average stock price during the period.

(4)

The effect of the non-vested performance share awards was excluded from the calculation of diluted net income per common share for the three and six months ended June 30, 2018 as the awards were below the respective agreements' payout thresholds. The effect of the non-vested performance share awards granted in 2018 was calculated utilizing the following criteria defined in Note 7.c: (i) the RTSR Performance Percentage, (ii) the ATSR Appreciation and (iii) the ROACE Percentage from the beginning of the performance period to June 30, 2018 for each of the criteria to identify the RTSR Factor, the ATSR Factor and the ROACE Factor, respectively, which were used to compute the Performance Multiple to determine the number of shares for the dilutive effect. The effects of the non-vested performance share awards granted in 2016 and 2017 were calculated utilizing the Company's ~~total shareholder return ("TSR")~~TSR from the beginning of each performance share awards' respective performance period to ~~the end of the respective period presented~~June 30, 2018 in comparison to the TSR of the peers specified in each respective performance share ~~award's respective~~awards' agreement. ~~See Note 5.c for additional discussion of the Company's performance share awards.~~


~~(3)~~	The dilutive effects of the non-vested restricted stock awards and the outstanding stock option awards were calculated utilizing the treasury stock method. See Notes 5.a and 5.b for additional discussion of the Company's restricted stock awards and stock option awards, respectively.



~~Table of Contents~~	~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

~~Note 10—Credit risk~~

The Company's oil, NGL and natural gas sales are made to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. The Company's joint operations accounts receivable are from a number of oil and natural gas companies, partnerships, individuals and others who own interests in the oil and natural gas properties operated by the Company. The Company's sales of purchased oil are generally made to one customer. Management believes that any credit risk imposed by a concentration in the oil and natural gas industry is offset by the creditworthiness of the Company's customer base and industry partners. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectability.

The Company uses derivatives to hedge its exposure to oil, NGL and natural gas price volatility. These transactions expose the Company to potential credit risk from its counterparties. In accordance with the Company's standard practice, its derivatives are subject to counterparty netting under agreements governing such derivatives; therefore, the credit risk associated with its derivative counterparties is somewhat mitigated. See Notes 2.e, 7 and 8.a for additional information regarding the Company's derivatives.

Note 11—Commitments and contingencies

a. Litigation

From time to time, the Company is ~~involved in~~subject to various legal proceedings ~~and/or may be subject to industry rulings that could bring rise to claims~~arising in the ordinary course of ~~business. In the case of a known contingency,~~business, including proceedings for which the Company ~~accrues a liability when the loss is probable and the amount is reasonably estimable. Except~~may not have insurance coverage. While many of these matters involve inherent uncertainty, except with regard to the specific litigation noted below, as of the date hereof, the Company ~~has concluded~~does not currently believe that ~~the likelihood is remote that the ultimate resolution of~~ any such ~~pending litigation or pending claims~~legal proceedings will ~~be material or~~ have a material adverse effect on the Company's business, financial position, results of operations or liquidity.

On May 3, 2017, Shell Trading (US) Company ("Shell") filed an Original Petition and Request for Disclosure in the District Court of Harris County, Texas, alleging that the crude oil purchase agreement entered into between Shell and Laredo



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

effective October 1, 2016 through June 30, 2020 does not accurately reflect the compensation to be paid to Shell under certain circumstances due to a drafting mistake. Shell seeks reformation of one clause of the crude oil purchase agreement on the grounds of alleged mutual mistake or, in the alternative, unilateral mistake, an award of the amounts Shell alleges it should have been or should be paid under the crude oil purchase agreement, court costs and ~~attorneys’~~attorneys' fees. The Company does not believe there was a drafting mistake made in the crude oil purchase agreement, which covered the sale to Shell of 19,000 barrels of crude oil per day of the Company's gross production as well as the purchase by the Company of like-quantity crude oil from Shell. On December 11, 2017, Shell filed its First Amended Petition, in which it asserted nine causes of action, including multiple new claims for breach of contract and fraud.

Effective May 1, 2018, Shell terminated the crude oil purchase agreement and ceased purchasing the Company's crude oil and selling crude oil to the Company under the terms of such agreement. As a result, the Company filed its Second Amended Answer and Original Counterclaim against Shell on June 15, 2018, in which the Company denies all allegations by Shell and seeks damages in excess of $150.0 million resulting from Shell's breach and wrongful termination of the crude oil purchase agreement. Shell filed a Second Amended Petition on June 1, 2018, in which it asserted a new cause of action against the Company for alleged repudiation of Shell's proposed reformed version of the crude oil purchase agreement, a version never signed or agreed to by the Company.

Through April 30, 2018, the date on which Shell wrongfully terminated the crude oil purchase agreement, the Company had accounted for the costs and crude oil price realization as reflected in the terms of the crude oil purchase agreement. The accompanying unaudited consolidated balance sheets do not include any amounts for damage claims or attorneys' fees sought by Shell. As of June 30, 2018, the Company ~~believes it has substantive defenses~~had estimated an aggregate amount of $37.4 million that is the subject of Shell's claims, which is generally based on the contractual amount in dispute under the pricing election that is the subject of Shell's claims applied to the barrels of crude oil purchased and ~~intends~~sold through the date on which Shell wrongfully terminated the crude oil purchase agreement. As a result of such termination, the Company's estimate of this unrecorded amount is not anticipated to ~~vigorously defend~~materially increase in the future. This estimate does not include damages sought by Shell pursuant to its ~~position.~~ latest repudiation claim asserted in its Second Amended Petition or amounts sought by Shell for recovery of attorneys' fees incurred for the prosecution of its claims.

The Company is unable to determine a probability of the outcome of this litigation at this time. As of September 30, 2017, the Company has estimated an amount of $8.7 million related to this litigation that is not recorded in the accompanying unaudited consolidated balance sheets. Under the current pricing election, which elections are made for six-month periods, this estimate of the unrecorded amount will increase through the life of the contract. The Company ~~has accounted for~~believes Shell's claims are meritless and the ~~costs (and resulting increased crude oil price realization) as reflected in the terms~~termination by Shell is improper and a breach of the crude oil purchase agreement. The Company therefore intends to vigorously defend itself against Shell's claims and pursue its rights under the terminated crude oil purchase agreement to seek all appropriate damages from Shell.

b. Drilling contracts

The Company has committed to several drilling contracts with a third ~~party~~parties to facilitate the Company's drilling plans. ~~Two~~Certain of these contracts are for a term of multiple months and contain an early termination ~~clause~~clauses that ~~requires~~require the Company to potentially pay ~~a penalty~~penalties to the third party should the Company cease drilling efforts. ~~This penalty~~These penalties would negatively impact the Company's financial statements upon early contract termination. There were no penalties incurred for early contract termination for either of the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 or ~~2016.~~2017. The future commitment of ~~$3.0~~$28.1 million as of ~~September~~June 30, ~~2017~~2018 is not recorded in the accompanying unaudited consolidated balance sheets. Management does not currently anticipate the early termination of ~~this contract~~these contracts in ~~2017.~~2018.

c. Firm sale and transportation commitments

The Company has committed to deliver for sale or transportation fixed volumes of product under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. If not fulfilled, the Company is subject to deficiency payments. These commitments are normal and customary for the Company's business. In certain instances, the Company has used spot market purchases to meet its commitments in certain locations or due to favorable pricing. Management anticipates continuing this practice in the future. The Company incurred deficiency payments and other contractual penalties of ~~$0.5~~$2.2 million and ~~$1.1~~$0.5 million during the three ~~and nine~~ months ended ~~September~~June 30, 2018 and 2017, respectively, and ~~$1.6~~$2.3 million and $0.6 million during the six months ended June 30, 2018 and 2017, respectively. For the three and ~~nine~~six months ended ~~September~~June 30, ~~2016, which~~2018, these deficiency payments and other contractual penalties are ~~reported on~~netted with the respective revenue stream in the unaudited consolidated statements of ~~operations~~operations. For the three and six months ended June 30, 2017, these deficiency payments and other penalties are included in the "Other operating expenses" line item in the unaudited consolidated statements of operations. See Note 4.a for additional information regarding the presentation of deficiency payments and other contractual penalties. Future commitments of $409.1 million as of June 30, 2018 are not recorded in the accompanying unaudited consolidated balance sheets. For information regarding the TA related to Medallion, see Note 3.c.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

~~expenses" line item. Future commitments~~d. Purchase commitment

During the three months ended June 30, 2018, the Company entered into a purchase and supply agreement, for a term of ~~$369.4~~one year, whereby it has committed to buy a certain volume of in-basin sand for a fixed price. As of June 30, 2018, under the terms of this agreement, the Company is required to purchase a certain percentage of the volume commitment or it will incur a shortfall payment of $8.0 million asat the end of ~~September 30, 2017 are not recorded in~~ the ~~accompanying unaudited consolidated balance sheets. For information regarding the TA related to Medallion, see Note 2.h.~~contract period.

d.e. 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.

f. 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 June 30, 2018 or December 31, 2017.

Note 12—~~Related parties~~

~~a. Medallion~~Supplemental cash flow information

The following table ~~summarizes items included in the unaudited consolidated balance sheets related to Medallion as of the dates presented:~~presents supplemental cash flow information:

(in thousands) December 31, 2016
Accrued capital expenditures $ 586
Other current liabilities $ 118

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

Three months ended September 30, Nine months ended September 30,
(in thousands) 2017 2016 2017 2016
Loss on disposal of assets, net $ (70 ) $ —
$ (70 ) $ —

~~See Note 2.h for discussion of the TA between LMS and a wholly-owned subsidiary of Medallion and see Note 16.a for discussion of the Medallion Sale subsequent to September 30, 2017.~~

~~b. 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.

~~As of December 31, 2016, amounts included in accounts payable from Archrock in the unaudited consolidated balance sheets totaled $0.2 million. No such amounts were included as of September 30, 2017.~~

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

Three months ended September 30, Nine months ended September 30,
(in thousands) 2017 2016 2017 2016
Lease operating expenses $ 72
$ 498
$ 728
$ 1,499

For the nine months ended September 30, 2016, amounts included in capital expenditures for midstream service assets from Archrock in the unaudited consolidated statements of cash flows totaled a de minimis amount. No such amounts were included for the nine month ends ended September 30, 2017.



	Six months ended June 30,
(in thousands)	2018			2017
Non-cash investing activities:
(Decrease) increase in accrued capital expenditures	$	(8,878	)	$	22,855
Capitalized stock-based compensation	$	4,098		$	3,772
Capitalized asset retirement costs	$	577		$	325
Other supplemental cash flow information:
Capitalized interest	$	498		$	490

Note 13—~~Segments~~Asset retirement obligations

~~The Company operates in two business segments: (i) exploration and production and (ii) midstream and marketing. The exploration and production segment is engaged~~See Note 2.m "Asset retirement obligations" in the acquisition, exploration and development of oil and natural gas properties. The midstream and marketing segment provides Laredo's exploration and production segment and third parties with products and services that need to be delivered by midstream infrastructure, including oil and liquids-rich natural gas gathering services as well as rig fuel, natural gas lift and water delivery and takeaway.2017 Annual Report for discussion on asset retirement obligations.



~~Table of Contents~~	~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

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

asset retirement obligation liability associated with tangible long-lived assets:

(in thousands)
Exploration and production
Midstream and marketing
Eliminations
Consolidated company
Three months ended September 30, 2017:
Revenues:
Oil, NGL and natural gas sales $ 158,037
$ 845
$ (1,324 ) $ 157,558
Midstream service revenues —
16,892
(14,446 ) 2,446
Sales of purchased oil —
45,814
—
45,814
Total revenues 158,037
63,551
(15,770 ) 205,818
Costs and expenses:
Lease operating expenses, including production and ad valorem taxes 32,417
—
(3,265 ) 29,152
Midstream service expenses —
12,474
(11,300 ) 1,174
Costs of purchased oil —
47,385
—
47,385
General and administrative⁽¹⁾
22,962
2,038
—
25,000
Depletion, depreciation and amortization⁽²⁾
38,802
2,410
—
41,212
Other operating expenses⁽³⁾
1,386
57
—
1,443
Operating income (loss) $ 62,470
$ (813 ) $ (1,205 ) $ 60,452
Other financial information:
Income from equity method investee $ —
$ 2,371
$ —
$ 2,371
Interest expense⁽⁴⁾
$ 22,184
$ 1,513
$ —
$ 23,697
Capital expenditures $ 149,867
$ 5,563
$ —
$ 155,430
Gross property and equipment⁽⁵⁾
$ 6,149,485
$ 443,462
$ (14,431 ) $ 6,578,516
Three months ended September 30, 2016:
Revenues:
Oil, NGL and natural gas sales $ 115,188
$ 488

$ (871 ) $ 114,805
Midstream service revenues —
15,357

(12,869 ) 2,488
Sales of purchased oil —
42,441

—
42,441
Total revenues 115,188
58,286
(13,740 ) 159,734
Costs and expenses:
Lease operating expenses, including production and ad valorem taxes 28,624
—

(3,381 ) 25,243
Midstream service expenses —
9,079

(8,040 ) 1,039
Costs of purchased oil —
44,232

—
44,232
General and administrative⁽¹⁾
23,883
2,222

—
26,105
Depletion, depreciation and amortization⁽²⁾
32,883
2,275

—
35,158
Other operating expenses⁽³⁾
2,414
51

—
2,465
Operating income $ 27,384
$ 427
$ (2,319 ) $ 25,492
Other financial information:
Income from equity method investee $ —
$ 265

$ —
$ 265
Interest expense⁽⁴⁾
$ 21,631
$ 1,446

$ —
$ 23,077
Capital expenditures $ 79,843
$ 806

$ —
$ 80,649
Gross property and equipment⁽⁵⁾
$ 5,682,251
$ 384,091
$ (6,923 ) $ 6,059,419
Nine months ended September 30, 2017:
Revenues:
Oil, NGL and natural gas sales $ 439,533
$ 2,486
$ (3,888 ) $ 438,131
Midstream service revenues —
52,630
(44,482 ) 8,148
Sales of purchased oil —
135,546
—
135,546
Total revenues 439,533
190,662
(48,370 ) 581,825
Costs and expenses:
Lease operating expenses, including production and ad valorem taxes 93,980
—
(10,479 ) 83,501
Midstream service expenses —
34,686
(31,700 ) 2,986
Costs of purchased oil —
141,661
—
141,661
General and administrative⁽¹⁾
66,526
6,079
—
72,605
Depletion, depreciation and amortization⁽²⁾
106,282
7,045
—
113,327
Other operating expenses⁽³⁾
3,741
165
—
3,906
Operating income $ 169,004
$ 1,026
$ (6,191 ) $ 163,839
Other financial information:
Income from equity method investee $ —
$ 7,910
$ —
$ 7,910
TABLE CONTINUES ON NEXT PAGE



	Six months ended June 30,
(in thousands)	2018			2017
Liability at beginning of period	$	55,506		$	52,207
Liabilities added due to acquisitions, drilling, midstream service asset construction and other	577			320
Accretion expense	2,227			1,871
Liabilities settled due to plugging and abandonment or sale	(1,815		)	(1,234		)
Revision of estimates	—			5
Liability at end of period	$	56,495		$	53,169



~~Table of Contents~~	~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

(in thousands)
Exploration and production
Midstream and marketing
Eliminations
Consolidated company
Interest expense⁽⁴⁾
$ 65,250
$ 4,340
$ —
$ 69,590
Capital expenditures $ 384,769
$ 11,680
$ —
$ 396,449
Gross property and equipment⁽⁵⁾
$ 6,149,485
$ 443,462
$ (14,431 ) $ 6,578,516
Nine months ended September 30, 2016:
Revenues:
Oil, NGL and natural gas sales $ 290,856
$ 488
$ (871 ) $ 290,473
Midstream service revenues —
37,762
(31,841 ) 5,921
Sales of purchased oil —
116,670
—
116,670
Total revenues 290,856
154,920
(32,712 ) 413,064
Costs and expenses:
Lease operating expenses, including production and ad valorem taxes 87,781
—
(8,378 ) 79,403
Midstream service expenses —
22,160
(19,334 ) 2,826
Costs of purchased oil —
121,190
—
121,190
General and administrative⁽¹⁾
60,380
5,678
—
66,058
Depletion, depreciation and amortization⁽²⁾
104,144
6,669
—
110,813
Impairment expense 162,027
—
—
162,027
Other operating expenses⁽³⁾
4,012
157
—
4,169
Operating loss $ (127,488 ) $ (934 ) $ (5,000 ) $ (133,422 )
Other financial information:
Income from equity method investee $ —
$ 6,259
$ —
$ 6,259
Interest expense⁽⁴⁾
$ 65,984
$ 4,310
$ —
$ 70,294
Capital expenditures $ 277,717
$ 4,231
$ —
$ 281,948
Gross property and equipment⁽⁵⁾
$ 5,682,251
$ 384,091
$ (6,923 ) $ 6,059,419

~~(1)~~

General and administrative expenses were allocated to the three months ended September 30, 2017, June 30, 2017, March 31, 2017, September 30, 2016, June 30, 2016 and March 31, 2016 based on the number of employees in the respective segment as of the respective three-month period end dates. Certain components of general and administrative expenses, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment.

~~(2)~~

Depletion, depreciation and amortization were actual expenses for each segment with the exception of the allocation of depreciation of other fixed assets, which was allocated to the three months ended September 30, 2017, June 30, 2017 and March 31, 2017 based on the number of employees in the respective segment as of the respective three-month period end dates. Depreciation of other fixed assets was allocated to the three and nine months ended September 30, 2016 based on the number of employees in the respective segment as of September 30, 2016. Certain components of depreciation and amortization of other fixed assets, primarily vehicles, were not allocated but were actual expenses for each segment.


~~(3)~~	~~Other operating expenses consist of accretion of asset retirement obligations and minimum volume commitments. These were actual expenses and were not allocated.~~

~~(4)~~

Interest expense for the three months ended September 30, 2017, June 30, 2017 and March 31, 2017 was allocated to the exploration and production segment based on gross property and equipment as of September 30, 2017, June 30, 2017 and March 31, 2017, respectively, and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of September 30, 2017, June 30, 2017 and March 31, 2017, respectively. Interest expense for the three and nine months ended September 30, 2016 was allocated to the exploration and production segment based on gross property and equipment as of September 30, 2016 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of September 30, 2016. Certain components of other fixed assets, primarily vehicles, were not allocated but were actual assets for each segment.

~~(5)~~

Gross property and equipment for the midstream and marketing segment includes equity method investment of $276.4 million and $229.9 million as of September 30, 2017 and 2016, respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of September 30, 2017 and 2016. Certain components of other fixed assets, primarily vehicles, were not allocated but were actual assets for each segment.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note 14—Income taxes

The Company is subject to federal and state income taxes and the Texas franchise tax. The Company had federal net operating loss carry-forwards totaling $1.7 billion and state of Oklahoma net operating loss carry-forwards totaling $40.3 million as of June 30, 2018, which begin expiring in 2026 and 2032, respectively. Due to the passing of Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act (the "Tax Act"), $23.0 million of the federal net operating loss carry-forward will not expire but may be limited in future periods. As of June 30, 2018, the Company believes it is more likely than not that a portion of the net operating loss carry-forwards are not fully realizable. The Company continues to consider new evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance is needed. Such consideration includes projected future cash flows from its oil, NGL and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of June 30, 2018, 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. As of June 30, 2018, a full valuation allowance of $315.1 million has been recorded against the Company's net deferred tax assets.

Note 15—Related party

The Company has a compression arrangement with an affiliate of Archrock Partners, Inc. ("Archrock"). One of Laredo's directors is on the board of directors of Archrock.

As of of June 30, 2018 and December 31, 2017, no amounts and a de minimis amount, respectively, were included in accounts payable from Archrock in the unaudited consolidated balance sheets.

The following table presents the lease operating expenses related to Archrock included in the unaudited consolidated statements of operations:



	Three months ended June 30,				Six months ended June 30,
(in thousands)	2018		2017		2018		2017
Lease operating expenses	$	16	$	232	$	129	$	656

Note 16—Subsidiary guarantors

The Guarantors have fully and unconditionally guaranteed the January 2022 Notes, the ~~May 2022 Notes, the~~ March 2023 Notes and the Senior Secured Credit Facility (and had guaranteed the May 2022 Notes until the May 2022 Notes Redemption Date), subject to the Releases. In accordance with practices accepted by the SEC, Laredo has prepared condensed consolidating financial statements to quantify the balance sheets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following unaudited condensed consolidating (i) balance sheets as of ~~September~~June 30, ~~2017~~2018 and December 31, ~~2016, unaudited condensed consolidating~~2017, (ii) statements of operations for the three and ~~nine~~six months ended ~~September~~June 30, 2018 and 2017 and ~~2016 and unaudited condensed consolidating~~(iii) statements of cash flows for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016~~2017 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~~Income taxes for LMS and for GCM are recorded on Laredo's balance sheets, statements of operations and statements of cash flows as they are disregarded entities for income tax purposes. Laredo and the Guarantors are not restricted from making intercompany distributions to each other. ~~During the three and nine months ended September 30, 2016, certain assets were transferred from Laredo to LMS and from LMS to Laredo at historical cost.~~

~~Condensed consolidating balance sheet~~

~~September 30, 2017~~

~~(Unaudited)~~

(in thousands) Laredo
Subsidiary
Guarantors
Intercompany
eliminations
Consolidated
company
Accounts receivable, net $ 74,133
$ 15,707
$ —
$ 89,840
Other current assets 49,922
2,703
—
52,625
Oil and natural gas properties, net 1,464,197
9,244
(14,431 ) 1,459,010
Midstream service assets, net —
130,407
—
130,407
Other fixed assets, net 41,502
400
—
41,902
Investment in subsidiaries and equity method investment 412,931
276,435
(412,931 ) 276,435
Other long-term assets 12,044
4,063
—
16,107
Total assets $ 2,054,729
$ 438,959
$ (427,362 ) $ 2,066,326

Accounts payable $ 20,975
$ 1,820
$ —
$ 22,795
Other current liabilities 179,550
20,915
—
200,465
Long-term debt, net 1,440,968
—
—
1,440,968
Other long-term liabilities 52,580
3,293
—
55,873
Stockholders' equity 360,656
412,931
(427,362 ) 346,225
Total liabilities and stockholders' equity $ 2,054,729
$ 438,959
$ (427,362 ) $ 2,066,326



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating balance sheet

~~December 31, 2016~~June 30, 2018

~~(Unaudited)~~


(in thousands)	Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company		Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable, net	$	70,570	$	16,297	$	—		$	86,867	$	84,212	$	17,109	$	—		$	101,321
Other current assets	65,884		2,026		—			67,910		66,601		1,772		—			68,373
Oil and natural gas properties, net	1,194,801		9,293		(8,240		)	1,195,854		1,854,379		9,175		(20,239		)	1,843,315
Midstream service assets, net	—		126,240		—			126,240		—		134,827		—			134,827
Other fixed assets, net	44,221		552		—			44,773		42,154		230		—			42,384
Investment in subsidiaries and equity method investment	376,028		243,953		(376,028		)	243,953
Other long-term assets	13,065		3,684		—			16,749
Investment in subsidiaries										128,875		—		(128,875		)	—
Other noncurrent assets, net										14,511		4,556		—			19,067
Total assets	$	1,764,569	$	402,045	$	(384,268	)	$	1,782,346	$	2,190,732	$	167,669	$	(149,114	)	$	2,209,287

Accounts payable	$	14,427	$	627	$	—		$	15,054
Accounts payable and accrued liabilities										$	51,541	$	22,711	$	—		$	74,252
Other current liabilities	150,531		22,360		—			172,891		196,199		12,969		—			209,168
Long-term debt, net	1,353,909		—		—			1,353,909		902,745		—		—			902,745
Other long-term liabilities	56,889		3,030		—			59,919
Other noncurrent liabilities										60,841		3,114		—			63,955
Stockholders' equity	188,813		376,028		(384,268		)	180,573		979,406		128,875		(149,114		)	959,167
Total liabilities and stockholders' equity	$	1,764,569	$	402,045	$	(384,268	)	$	1,782,346	$	2,190,732	$	167,669	$	(149,114	)	$	2,209,287

Condensed consolidating ~~statement of operations~~balance sheet

~~For the three months ended September 30,~~December 31, 2017

~~(Unaudited)~~

(in thousands)
Laredo Subsidiary
Guarantors Intercompany
eliminations Consolidated
company
Total revenues
$ 157,902

$ 63,686

$ (15,770 )
$ 205,818
Total costs and expenses
97,686

62,245

(14,565 )
145,366
Operating income
60,216

1,441

(1,205 )
60,452
Interest expense
(23,697 )
—

—

(23,697 )
Other non-operating income (expense)
(24,287 )
2,290

(3,731 )
(25,728 )
Income before income tax
12,232

3,731

(4,936 )
11,027
Income tax
—

—

—

—
Net income
$ 12,232

$ 3,731

$ (4,936 )
$ 11,027

~~Condensed consolidating statement of operations~~

~~For the nine months ended September 30, 2017~~

~~(Unaudited)~~

(in thousands) Laredo Subsidiary
Guarantors Intercompany
eliminations Consolidated
company
Total revenues $ 439,269
$ 190,926
$ (48,370 ) $ 581,825
Total costs and expenses 276,855
183,310
(42,179 ) 417,986
Operating income 162,414
7,616
(6,191 ) 163,839
Interest expense (69,590 ) —
—
(69,590 )
Other non-operating income 53,780
7,622
(15,238 ) 46,164
Income before income tax 146,604
15,238
(21,429 ) 140,413
Income tax —
—
—
—
Net income $ 146,604
$ 15,238
$ (21,429 ) $ 140,413



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Accounts receivable, net	$	79,413		$	21,232		$	—		$	100,645
Other current assets	132,219			2,518			—			134,737
Oil and natural gas properties, net	1,596,834			9,220			(16,715		)	1,589,339
Midstream service assets, net	—			138,325			—			138,325
Other fixed assets, net	40,344			377			—			40,721
Investment in subsidiaries	(7,566		)	—			7,566			—
Other noncurrent assets, net	15,526			3,996			—			19,522
Total assets	$	1,856,770		$	175,668		$	(9,149	)	$	2,023,289

Accounts payable and accrued liabilities	$	34,550		$	23,791		$	—		$	58,341
Other current liabilities	193,104			25,974			—			219,078
Long-term debt, net	791,855			—			—			791,855
Other noncurrent liabilities	54,967			133,469			—			188,436
Stockholders' equity	782,294			(7,566		)	(9,149		)	765,579
Total liabilities and stockholders' equity	$	1,856,770		$	175,668		$	(9,149	)	$	2,023,289



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating statement of operations

For the three months ended ~~September~~June 30, ~~2016~~2018

~~(Unaudited)~~


(in thousands)	Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Total revenues	$	115,091		$	58,383	$	(13,740	)	$	159,734		$	208,624		$	163,021		$	(20,599	)	$	351,046
Total costs and expenses	90,073			55,590		(11,421		)	134,242			115,602			158,433			(17,756		)	256,279
Operating income	25,018			2,793		(2,319		)	25,492			93,022			4,588			(2,843		)	94,767
Interest expense	(23,077		)	—		—			(23,077		)	(14,424		)	—			—			(14,424		)
Other non-operating income	9,863			254		(3,047		)	7,070
Income before income tax	11,804			3,047		(5,366		)	9,485
Other non-operating expense												(42,303		)	(1,025		)	(3,563		)	(46,891		)
Income before income taxes												36,295			3,563			(6,406		)	33,452
Income tax	—			—		—			—			—			—			—			—
Net income	$	11,804		$	3,047	$	(5,366	)	$	9,485		$	36,295		$	3,563		$	(6,406	)	$	33,452

Condensed consolidating statement of operations

For the ~~nine~~three months ended ~~September~~June 30, ~~2016~~2017

~~(Unaudited)~~


(in thousands)	Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company			Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Total revenues	$	290,724		$	155,052	$	(32,712	)	$	413,064		$	142,224		$	61,454	$	(16,677	)	$	187,001
Total costs and expenses	424,274			149,924		(27,712		)	546,486			91,140			58,299		(14,499		)	134,940
Operating income (loss)	(133,550		)	5,128		(5,000		)	(133,422		)
Operating income												51,084			3,155		(2,178		)	52,061
Interest expense	(70,294		)	—		—			(70,294		)	(23,173		)	—		—			(23,173		)
Other non-operating income (expense)	(33,474		)	6,237		(11,365		)	(38,602		)
Income (loss) before income tax	(237,318		)	11,365		(16,365		)	(242,318		)
Other non-operating income												35,377			2,414		(5,569		)	32,222
Income before income taxes												63,288			5,569		(7,747		)	61,110
Income tax	—			—		—			—			—			—		—			—
Net income (loss)	$	(237,318	)	$	11,365	$	(16,365	)	$	(242,318	)
Net income												$	63,288		$	5,569	$	(7,747	)	$	61,110

Condensed consolidating statement of ~~cash flows~~operations

For the ~~nine~~six months ended ~~September~~June 30, ~~2017~~

~~(Unaudited)~~2018

(in thousands) Laredo Subsidiary
Guarantors Intercompany
eliminations Consolidated
company
Net cash provided by operating activities $ 273,309
$ 13,980
$ (15,238 ) $ 272,051
Change in investment between affiliates (36,890 ) 21,652
15,238
—
Capital expenditures and other (321,261 ) (35,632 ) —
(356,893 )
Net cash provided by financing activities 72,988
—
—
72,988
Net decrease in cash and cash equivalents (11,854 ) —
—
(11,854 )
Cash and cash equivalents, beginning of period 32,671
1
—
32,672
Cash and cash equivalents, end of period $ 20,817
$ 1
$ —
$ 20,818



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Total revenues	$	406,449		$	239,321		$	(35,028	)	$	610,742
Total costs and expenses	221,290			232,997			(31,504		)	422,783
Operating income	185,159			6,324			(3,524		)	187,959
Interest expense	(27,942		)	—			—			(27,942		)
Other non-operating expense	(33,721		)	(1,281		)	(5,043		)	(40,045		)
Income before income taxes	123,496			5,043			(8,567		)	119,972
Income tax	—			—			—			—
Net income	$	123,496		$	5,043		$	(8,567	)	$	119,972



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating statement of operations

For the six months ended June 30, 2017



(in thousands)	Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Total revenues	$	281,367		$	127,240	$	(32,600	)	$	376,007
Total costs and expenses	179,169			121,065		(27,614		)	272,620
Operating income	102,198			6,175		(4,986		)	103,387
Interest expense	(45,893		)	—		—			(45,893		)
Other non-operating income	78,067			5,332		(11,507		)	71,892
Income before income taxes	134,372			11,507		(16,493		)	129,386
Income tax	—			—		—			—
Net income	$	134,372		$	11,507	$	(16,493	)	$	129,386

Condensed consolidating statement of cash flows

For the ~~nine~~six months ended ~~September~~June 30, ~~2016~~2018

~~(Unaudited)~~


(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company			Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash provided by operating activities	$	244,213		$	12,606		$	(11,365	)	$	245,454		$	254,991		$	12,653		$	(5,043	)	$	262,601
Change in investment between affiliates	(61,677		)	50,312			11,365			—			4,680			(9,723		)	5,043			—
Capital expenditures and other	(392,977		)	(62,918		)	—			(455,895		)	(351,142		)	(2,930		)	—			(354,072		)
Net cash provided by financing activities	209,647			—			—			209,647			15,916			—			—			15,916
Net decrease in cash and cash equivalents	(794		)	—			—			(794		)	(75,555		)	—			—			(75,555		)
Cash and cash equivalents, beginning of period	31,153			1			—			31,154			112,158			1			—			112,159
Cash and cash equivalents, end of period	$	30,359		$	1		$	—		$	30,360		$	36,603		$	1		$	—		$	36,604

Condensed consolidating statement of cash flows

~~Note 15—Recently issued or adopted accounting pronouncements~~

~~The Company considers~~For the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB"). The discussion of the ASUs listed below were determined to be meaningful to the Company's consolidated financial statements and/or footnotes during the ninesix months ended ~~September~~June 30, ~~2017.~~

~~In May 2014, the FASB issued a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic 605,~~ ~~Revenue Recognition,~~ ~~and industry-specific guidance in Subtopic 932-605,~~ ~~Extractive Activities—Oil and Gas—Revenue Recognition~~. The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard's application impact to individual financial statement line items. In March, April, May and December 2016,~~the FASB issued new guidance in Topic 606,~~ ~~Revenue from Contracts with Customers,~~ to address the following potential implementation issues of the new revenue standard: (a) to clarify the implementation guidance on principal versus agent considerations, (b) to clarify the identification of performance obligations and the licensing implementation guidance and (c) to address certain issues in the guidance on assessing collectability, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition. This standard is effective for annual reporting periods beginning after December 15, 2017 including interim periods within that reporting period. The Company follows the sales method of accounting for oil, NGL and natural gas production, which is generally consistent with the revenue recognition provision of the new standard. In regards to the exploration and production segment of its business, other than new disclosures, the Company does not anticipate the standard to have a material impact on its consolidated financial statements upon adoption based on its evaluation process. The evaluation process included (i) review of revenue contracts and transactions in both of the exploration and production and midstream and marketing segments and (ii) assessing the impact this guidance will have on our processes and internal controls. However, in light of the Medallion Sale, which occurred in the fourth quarter of 2017, the Company is currently evaluating the accounting impact and adoption method implications the adoption of this standard on the effective date of January 1, 2018 will have on the midstream and marketing segment of its business.

~~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 thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash provided by operating activities	$	159,048		$	9,360		$	(11,507	)	$	156,901
Change in investment between affiliates	(8,264		)	(3,243		)	11,507			—
Capital expenditures and other	(171,461		)	(6,117		)	—			(177,578		)
Net cash provided by financing activities	23,029			—			—			23,029
Net increase in cash and cash equivalents	2,352			—			—			2,352
Cash and cash equivalents, beginning of period	32,671			1			—			32,672
Cash and cash equivalents, end of period	$	35,023		$	1		$	—		$	35,024



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

~~in the same way as the reasonably assured threshold in the previous lease guidance. In addition, also consistent with the previous lease guidance,~~ Note 17—Subsequent events

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. . New derivative contracts

The recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous GAAP. There continues to be a differentiation between finance leases and operating leases. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous GAAP unless the lease is modified, except that lessees are required to recognize a right-of-use asset and a lease liability for all operating leases at each reporting date based on the present value of the remaining minimum rental paymentsfollowing table presents new oil derivatives that were tracked and disclosed under previous GAAP. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application of the amendments in this ASU is permitted. The Company is in the process of evaluating the potential impact of adopting this guidance, and the primary effect will beentered into subsequent to record assets and obligations for contracts currently recognized as operating leases with a term greater than 12 months and evaluate operating leases with a term less than or equal to 12 months for election. The Company does not intend to adopt the standard early.

~~In January 2017, the FASB issued new guidance in Topic 805,~~ ~~Business Combinations~~, to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. Under the current implementation guidance in Topic 805, there are three elements of a business—inputs, processes and outputs. While an integrated set of assets and activities (collectively referred to as a “set”) that is a business usually has outputs, outputs are not required to be present. In addition, all the inputs and processes that a seller uses in operating a set are not required if market participants can acquire the set and continue to produce outputs, for example, by integrating the acquired set with their own inputs and processes. The amendments in this ASU provide a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. If the screen is not met, the amendments in this ASU (i) require that to be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create an output and (ii) remove the evaluation of whether a market participant could replace missing elements. The amendments provide a framework to assist entities in evaluating whether both an input and a substantive process are present. The framework includes two sets of criteria to consider that depend on whether a set has outputs. Although outputs are not required for a set to be a business, outputs generally are a key element of a business; therefore, the FASB has developed more stringent criteria for sets without outputs. Lastly, the amendments in this ASU narrow the definition of the term output so that the term is consistent with how outputs are described in Topic 606. The amendments in this ASU are effective for annual periods beginning after December 15, 2017, including interim periods within those periods. The amendments in this ASU should be applied prospectively on or after the effective date. Early application of the amendments in this ASU is permitted. The Company is currently evaluating the impact this standard will have on its consolidated financial statements upon adoption.June 30, 2018:



	Aggregate volumes (Bbl)	Floor price ($/Bbl)		Ceiling price ($/Bbl)		Contract period
Put⁽¹⁾	2,080,500	$	45.00	$	—	January 2019 - December 2019
Collar	732,000	$	45.00	$	76.15	January 2020 - December 2020
Collar	402,600	$	45.00	$	76.10	January 2020 - December 2020
Collar	912,500	$	45.00	$	71.00	January 2021 - December 2021

~~Note 16—Subsequent events~~

~~a. Medallion sale and capital call~~

On October 30, 2017, LMS, together with Medallion Midstream Holdings, LLC ("MMH"), which is owned and controlled by an affiliate of The Energy & Minerals Group ("EMG"), completed the previously announced Medallion Sale of 100% of the ownership interests in Medallion to an affiliate of Global Infrastructure Partners ("GIP"), for cash consideration of $1.825 billion, subject to customary post-closing adjustments. LMS' net cash proceeds for its 49% ownership interest in Medallion are $829.6 million, before post-closing adjustments and taxes, but after deduction of its proportionate share of fees and other expenses associated with the Medallion Sale. The Medallion Sale closed pursuant to the membership interest purchase and sale agreement, which provides for potential post-closing additional cash consideration that is structured based on GIP's realized profit at exit. There can be no assurance as to when and whether the additional consideration will be paid.



~~Table of Contents~~ (1)	~~Laredo Petroleum, Inc.~~	There are $2.2 million in deferred premiums associated with these contracts.

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

On October 20, 2017, the Company made a capital contribution to Medallion of $7.2 million to fund continued expansion activities on existing portions of Medallion's pipeline infrastructure in order to gather additional third-party production.

See Note ~~2.h~~8 for ~~additional discussion~~information regarding ~~Medallion, and see Note 12.a for discussion of items included in~~ the Company's ~~unaudited consolidated financial statements related to Medallion.~~derivative settlement index for oil.

b. Senior Secured Credit Facility

On October 24, 2017, the Company entered into the First Amendment (the "First Amendment") to the Senior Secured Credit Facility. The First Amendment, among other things, clarifies the repayment of senior notes negative covenant to permit the Company to redeem senior notes with an amount not exceeding the net cash proceeds from the sale or disposition of properties not constituting Borrowing Base Properties (as defined in the Senior Secured Credit Facility)July 11, 2018 and ~~made within 365 days of the consummation of such sale or disposition, which would include the proceeds from the Medallion Sale.~~

In addition, on October 20, 2017, pursuant to a regular semi-annual redetermination, the lenders reaffirmed the borrowing base of $1.0 billion under the Senior Secured Credit Facility. The Company's aggregate elected commitment of $1.0 billion remained unchanged.

~~On October 5, 2017, October 11, 2017 and October 19, 2017,~~July 18, 2018, the Company borrowed ~~$10.0 million, $15.0~~$30.0 million and ~~$10.0~~$15.0 million, respectively, on the Senior Secured Credit Facility. On ~~October~~July 30, ~~2017,~~2018, the Company repaid ~~borrowings outstanding~~$20.0 million on the Senior Secured Credit ~~Facility in~~Facility. As a result, the ~~amount of $190.0 million with a portion of the proceeds from the Medallion Sale. There was no~~ outstanding balance under the Senior Secured Credit Facility was $135.0 million as of ~~October~~July 31, ~~2017.~~

~~c. May 2022 Notes call for redemption~~

On October 30, 2017, the Company issued a press release announcing that it called for redemption all $500.0 million aggregate principal amount of its May 2022 Notes. The redemption date for the May 2022 Notes is November 29, 2017, and holders will receive a redemption price of 103.688% of the principal amount of the May 2022 Notes, plus accrued and unpaid interest from November 1, 2017 through November 28, 2017.2018.

~~Note 17—Supplementary information~~

~~Costs incurred in oil and natural gas property acquisition, exploration and development activities~~

~~Costs incurred in the acquisition, exploration and development of oil, NGL and natural gas assets are presented below:~~

Three months ended September 30, Nine months ended September 30,
(in thousands) 2017 2016 2017 2016
Property acquisition costs:

—
Evaluated⁽¹⁾
$ —
$ 5,905
$ —
$ 5,905
Unevaluated —

110,800
—
110,800
Exploration costs 7,136

6,718
28,337
33,750
Development costs⁽²⁾
160,359

72,411
397,255
225,103
Total costs incurred $ 167,495

$ 195,834
$ 425,592
$ 375,558


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


~~(2)~~	Development costs include $0.4 million and $0.3 million in asset retirement obligations for the three months ended September 30, 2017 and 2016, respectively, and $0.6 million and $0.5 million for the nine months ended September 30, 2017 and 2016, 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 our 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 ~~2016~~2017 Annual Report. The following discussion contains "forward-looking statements" that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. Please see "Cautionary Statement Regarding Forward-Looking Statements." Except for purposes of the unaudited consolidated financial statements and condensed notes thereto included elsewhere in this Quarterly Report, references in this Quarterly Report to "Laredo," "we," "us," "our" or similar terms refer to Laredo, LMS and GCM collectively, unless the context otherwise indicates or requires. All amounts, dollars and percentages presented in this Quarterly Report are rounded and therefore approximate.

Executive overview

We are an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties, and ~~the gathering of oil~~midstream and ~~liquids-rich natural gas from such properties,~~marketing services, primarily in the Permian Basin inof 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~~June 30, ~~2017~~2018 included the following:

Oil, NGL and natural gas sales of ~~$157.6~~$208.6 million,, compared to ~~$114.8~~$141.8 million for the three months ended ~~September~~June 30, ~~2016;~~

2017;

Average daily sales volumes of ~~60,011~~67,206 BOE/D, compared to ~~51,276~~58,632 BOE/D for the three months ended ~~September~~June 30, ~~2016;~~2017;

Net income of ~~$11.0~~$33.5 million, compared to ~~a net income of $9.5~~$61.1 million for the three months ended ~~September~~June 30, ~~2016;~~2017; and

Adjusted EBITDA (a non-GAAP financial measure) of ~~$130.9~~$152.5 million, compared to ~~$118.0~~$114.3 million for the three months ended ~~September~~June 30, ~~2016.~~2017. See page 4941 for a discussion and reconciliation of Adjusted EBITDA.

Our financial and operating performance for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 included the following:

Oil, NGL and natural gas sales of ~~$438.1~~$406.0 million, compared to ~~$290.5~~$280.6 million for the ~~nine~~six months ended ~~September~~June 30, ~~2016;~~2017;

Average daily sales volumes of ~~57,044~~65,270 BOE/D, compared to ~~48,392~~55,536 BOE/D for the ~~nine~~six months ended ~~September~~June 30, ~~2016;~~2017;

Net income of ~~$140.4~~$120.0 million, compared to ~~a net loss of $242.3 million, including a non-cash full cost ceiling impairment of $161.1~~$129.4 million for the ~~nine~~six months ended ~~September~~June 30, ~~2016;~~2017; and

Adjusted EBITDA (a non-GAAP financial measure) of ~~$352.6~~$295.9 million, compared to ~~$326.3~~$221.7 million for the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~2017. See page 4941 for a discussion and reconciliation of Adjusted EBITDA.

~~Recent developments~~

~~Medallion sale~~

On October 30, 2017, LMS, together with MMH, which is owned and controlled by an affiliate of EMG, completed the previously announced Medallion Sale to an affiliate of GIP, for cash consideration of $1.825 billion, subject to customary post-closing adjustments. LMS' net cash proceeds for its 49% ownership interest in Medallion are $829.6 million, before post-closing adjustments and taxes, but after deduction of its proportionate share of fees and other expenses associated with the Medallion Sale. The Medallion Sale closed pursuant to the membership interest purchase and sale agreement, which provides for potential post-closing additional cash consideration that is structured based on GIP's realized profit at exit. There can be no assurance as to when and whether any such additional consideration will be paid.

~~May 2022 Notes call for redemption~~

On October 30, 2017, we issued a press release announcing that we have called for redemption the outstanding $500.0 million aggregate principal amount of our May 2022 Notes. The redemption date for the May 2022 Notes is November 29, 2017, and holders will receive a redemption price of 103.688% of the principal amount of the May 2022 Notes, plus accrued and unpaid interest from November 1, 2017 through November 28, 2017.

Pricing and reserves

Our results of operations are heavily influenced by oil, NGL and natural gas prices. Oil, NGL and natural gas price fluctuations are caused by changes in global and regional supply and demand, market uncertainty, economic conditions, transportation constraints and a variety of additional factors. Historically, commodity prices have experienced significant fluctuations, and additional changes in commodity prices may affect the economic viability of, and our ability to fund, our drilling projects, as well as the economic valuation and economic recovery of oil, NGL and natural gas reserves.

~~The Realized Prices utilized~~During the three months ended June 30, 2018, the Midland market crude oil price experienced an increased discount to ~~value our reserves as~~WTI-Cushing prices primarily due to limited pipeline capacity constraining transportation of ~~September~~crude oil out of the Permian Basin to major marketing hubs including, but not limited to, Cushing, Oklahoma and the United States Gulf Coast. As of June 30, ~~2017 and September 30, 2016 were $44.59~~2018, this discount for prompt month delivery was $12 per Bbl ~~for~~of oil. This pipeline constraint is expected to affect the Midland market oil ~~$16.55 per Bbl for NGL~~price until additional transportation capacity becomes operational or until basin-wide crude oil production decreases from its current historical levels. We have focused on achieving the ability to sell oil in multiple markets and ~~$2.16 per Mcf for natural gas, and $36.39 per Bbl for~~protecting the Company's oil $10.91 per Bbl for NGL and $1.65 per Mcf for natural gas, respectively. The Realized Prices used to estimate proved reserves as of all period end dates do not include derivative transactions. The unamortized cost of our evaluated oil and natural gas properties did not exceed the full cost ceiling amount as of September 30, 2017, June 30, 2017, March 31, 2017, September 30, 2016 or June 30, 2016. See Note 2.g to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for our discussion of our 2016 first-quarter full cost ceiling impairment.value from basin differentials by securing transportation capacity.

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

The unweighted arithmetic average first-day-of-the-month prices for each month within the 12-month period prior to the end of the reporting period before pricing differentials, adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received when control passes to the purchaser/customer (the "Realized Prices"), utilized to value our reserves as of June 30, 2018 and June 30, 2017, were $55.36 per Bbl for oil, $19.15 per Bbl for NGL and $1.80 per Mcf for natural gas, and $43.64 per Bbl for oil, $15.16 per Bbl for NGL and $2.15 per Mcf for natural gas, respectively. The Realized Prices used to estimate proved reserves do not include derivative transactions. See "—Costs and expenses- Transportation and marketing expenses" for costs incurred prior to control passing to the final customer. The unamortized cost of our evaluated oil and natural gas properties did not exceed the full cost ceiling amount as of June 30, 2018 or June 30, 2017. See Note 5 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of our full cost method of accounting.

Core ~~areas~~area 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~~June 30, ~~2017,~~2018, we had assembled ~~125,466~~122,044 net acres in the Permian Basin.

Sources of our revenue

Our revenues are derived from the sale of produced oil, NGL and natural gas, ~~within the continental United States,~~ the sale of purchased oil and providing midstream services to third ~~parties. Our revenues~~parties, all within the continental United States and do not include the effects of derivatives. For the three months ended September 30, 2017, our revenues were comprised of: 54% sales of produced oil, 13% sales of produced NGL, 10% sales of produced natural gas, 22% sales of purchased oil and 1% midstream services. For the nine months ended September 30, 2017, our revenues were comprised of: 54% sales of produced oil, 12% sales of produced NGL, 10% sales of produced natural gas, 23% sales of purchased oil and 1% midstream services. Our oil, NGL and natural gas revenues may vary significantly from period to period as a result of changes in volumes of production, pricing differentials and/or changes in commodity prices. Our sales of purchased oil revenue may vary due to changes in oil ~~prices.~~prices, pricing differentials and the amount of volumes purchased. Our midstream service revenues may vary due to oil throughput fees and the level of services provided to third parties for (i) ~~gathered~~oil and natural gas gathering and transportation systems and related facilities, (ii) gas lift, ~~fees~~rig fuel and centralized compression infrastructure and (iii) water ~~services.~~storage, recycling and transportation infrastructure. The following table presents our sources of revenue as a percentage of total revenues:



	Three months ended June 30,				Six months ended June 30,
	2018		2017		2018		2017
Oil sales	45	%	56	%	51	%	54	%
NGL sales	10	%	11	%	10	%	11	%
Natural gas sales	4	%	9	%	5	%	10	%
Midstream service revenues	1	%	1	%	1	%	1	%
Sales of purchased oil	40	%	23	%	33	%	24	%
Total	100	%	100	%	100	%	100	%

Results of operations consolidated

For the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 as compared to the three and ~~nine~~six months ended ~~September~~June 30, ~~2016~~2017

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

The following table ~~sets forth~~presents information regarding produced oil, NGL and natural gas sales volumes, revenues and average sales ~~prices, for the periods presented:~~prices:

Three months ended September 30, Nine months ended September 30,
2017 2016 2017 2016
Sales volumes:

Oil (MBbl) 2,425

2,150
7,027
6,168
NGL (MBbl) 1,491
1,272
4,187
3,491
Natural gas (MMcf) 9,630

7,766
26,154
21,600
Oil equivalents (MBOE)⁽¹⁾⁽²⁾
5,521

4,718
15,573
13,260
Average daily sales volumes (BOE/D)⁽²⁾
60,011

51,276
57,044
48,392
% Oil 44 %
46 % 45 % 47 %
Oil, NGL and natural gas sales (in thousands):

Oil $ 110,194

$ 84,083
$ 313,875
$ 218,478
NGL 27,700
14,678
68,329
37,850
Natural gas 19,664

16,044
55,927
34,145
Total oil, NGL and natural gas sales $ 157,558

$ 114,805
$ 438,131
$ 290,473
Average sales prices:

Oil, realized ($/Bbl)⁽³⁾
$ 45.44

$ 39.10
$ 44.67
$ 35.42
NGL, realized ($/Bbl)⁽³⁾
$ 18.58

$ 11.54
$ 16.32
$ 10.84
Natural gas, realized ($/Mcf)⁽³⁾
$ 2.04

$ 2.07
$ 2.14
$ 1.58
Average price, realized ($/BOE)⁽³⁾
$ 28.54

$ 24.34
$ 28.13
$ 21.91
Oil, hedged ($/Bbl)⁽⁴⁾
$ 50.72

$ 57.57
$ 49.08
$ 57.76
NGL, hedged ($/Bbl)⁽⁴⁾
$ 17.98

$ 11.54
$ 15.90
$ 10.84
Natural gas, hedged ($/Mcf)⁽⁴⁾
$ 2.10

$ 2.31
$ 2.17
$ 2.18
Average price, hedged ($/BOE)⁽⁴⁾
$ 30.80

$ 33.15
$ 30.07
$ 33.27



	Three months ended June 30,						Six months ended June 30,
	2018			2017			2018			2017
Sales volumes:
Oil (MBbl)	2,514			2,482			4,953			4,602
NGL (MBbl)	1,778			1,433			3,341			2,696
Natural gas (MMcf)	10,947			8,524			21,120			16,524
Oil equivalents (MBOE)⁽¹⁾⁽²⁾	6,116			5,336			11,814			10,052
Average daily sales volumes (BOE/D)⁽²⁾	67,206			58,632			65,270			55,536
% Oil⁽²⁾	41		%	47		%	42		%	46		%
Sales revenues (in thousands):
Oil	$	159,051		$	104,214		$	309,965		$	203,681
NGL	36,805			19,801			65,165			40,629
Natural gas	12,705			17,822			30,865			36,263
Total oil, NGL and natural gas sales revenues	$	208,561		$	141,837		$	405,995		$	280,573
Average sales Realized Prices⁽²⁾:
Oil, without derivatives ($/Bbl)⁽³⁾	$	63.26		$	42.00		$	62.58		$	44.26
NGL, without derivatives ($/Bbl)⁽³⁾	$	20.71		$	13.82		$	19.51		$	15.07
Natural gas, without derivatives ($/Mcf)⁽³⁾	$	1.16		$	2.09		$	1.46		$	2.19
Average price, without derivatives ($/BOE)⁽³⁾	$	34.10		$	26.58		$	34.37		$	27.91
Oil, with derivatives ($/Bbl)⁽⁴⁾	$	58.71		$	46.95		$	58.62		$	48.22
NGL, with derivatives ($/Bbl)⁽⁴⁾	$	20.07		$	13.61		$	19.15		$	14.75
Natural gas, with derivatives ($/Mcf)⁽⁴⁾	$	1.72		$	2.12		$	1.78		$	2.21
Average price, with derivatives ($/BOE)⁽⁴⁾	$	33.04		$	28.88		$	33.18		$	29.66


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


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

(3)

Realized oil, NGL and natural gas prices are the actual prices ~~realized at~~received when control passes to the ~~wellhead~~purchaser/customer 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~~See "—Costs and ~~are not calculated using~~expenses- Transportation and marketing expenses" for costs incurred prior to control passing to the ~~rounded numbers presented in the table above.~~final customer.

(4)

~~Hedged prices reflect~~

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

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


	Three months ended September 30,						Nine months ended September 30,						Three months ended June 30,						Six months ended June 30,
(in thousands)	2017			2016			2017			2016			2018			2017			2018			2017
Cash settlements received (paid) for matured derivatives:
Settlements (paid) received for matured derivatives:
Oil	$	13,182		$	42,442		$	33,399		$	144,750		$	(5,608	)	$	12,969		$	(9,344	)	$	20,217
NGL	(897		)	—			(1,761		)	—			(1,147		)	(296		)	(1,194		)	(864		)
Natural gas	1,350			1,865			3,153			12,876			6,936			1,032			8,483			1,803
Total	$	13,635		$	44,307		$	34,791		$	157,626		$	181		$	13,705		$	(2,055	)	$	21,156
Premiums paid attributable to contracts that matured during the respective period:
Premiums paid previously or upon settlement attributable to derivatives that matured during the respective period:
Oil	$	(362	)	$	(2,709	)	$	(2,383	)	$	(6,972	)	$	(5,838	)	$	(679	)	$	(10,241	)	$	(2,021	)
Natural gas	(769		)	—			(2,301		)	—			(845		)	(767		)	(1,686		)	(1,532		)
Total	$	(1,131	)	$	(2,709	)	$	(4,684	)	$	(6,972	)	$	(6,683	)	$	(1,446	)	$	(11,927	)	$	(3,553	)

Changes in average ~~realized~~ sales ~~prices~~Realized Prices without derivatives and sales volumes caused the following changes to our oil, NGL and natural gas revenues between the three months ended ~~September~~June 30, ~~2017~~2018 and ~~2016:~~2017:


(in thousands)	Oil		NGL		Natural gas			Total net effect of change		Oil		NGL		Natural gas			Total net effect of change
2016 Revenues	$	84,083	$	14,678	$	16,044		$	114,805
Effect of changes in average realized sales prices	15,378		10,502		(230		)	25,650
2017 Revenues										$	104,214	$	19,801	$	17,822		$	141,837
Effect of changes in average sales Realized Prices										53,469		12,254		(10,182		)	55,541
Effect of changes in sales volumes	10,733		2,520		3,850			17,103		1,368		4,750		5,065			11,183
2017 Revenues	$	110,194	$	27,700	$	19,664		$	157,558
2018 Revenues										$	159,051	$	36,805	$	12,705		$	208,561

Changes in average ~~realized~~ sales ~~prices~~Realized Prices and sales volumes caused the following changes to our oil, NGL and natural gas revenues between the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016:~~2017:


(in thousands)	Oil		NGL		Natural gas		Total net effect of change		Oil		NGL		Natural gas			Total net effect of change
2016 Revenues	$	218,478	$	37,850	$	34,145	$	290,473
Effect of changes in average realized sales prices	64,985		22,935		14,583		102,503
2017 Revenues									$	203,681	$	40,629	$	36,263		$	280,573
Effect of changes in average sales Realized Prices									90,718		14,828		(15,484		)	90,062
Effect of changes in sales volumes	30,412		7,544		7,199		45,155		15,566		9,708		10,086			35,360
2017 Revenues	$	313,875	$	68,329	$	55,927	$	438,131
2018 Revenues									$	309,965	$	65,165	$	30,865		$	405,995

Oil sales revenue. Our oil sales revenue is a function of oil production volumes sold and average oil sales ~~prices~~Realized Prices received for those volumes. The increase in oil sales revenue of ~~$26.1~~$54.8 million, or ~~31%~~53%, for the three months ended ~~September~~June 30, ~~2017~~2018 as compared to the ~~three months ended September 30, 2016~~same period in 2017 is due to a ~~16%~~51% increase in average oil ~~prices realized and~~sales Realized Prices with a ~~13%~~moderate increase in oil sales volumes.

The increase in oil sales revenue of ~~$95.4~~$106.3 million, or ~~44%~~52%, for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 as compared to the ~~nine months ended September 30, 2016~~same period in 2017 is due to a ~~26%~~41% increase in average oil ~~prices~~sales Realized Prices realized and ~~a 14%~~an 8% increase in oil sales volumes.

NGL sales revenue. Our NGL sales revenue is a function of NGL production volumes sold and average NGL sales ~~prices~~Realized Prices received for those volumes. The increase in NGL sales revenue of ~~$13.0~~$17.0 million, or ~~89%~~86%, for the three months ended ~~September~~June 30, ~~2017~~2018 as compared to the ~~three months ended September 30, 2016~~same period in 2017 is due to a ~~61%~~50% increase in average NGL ~~prices~~sales Realized Prices realized and a ~~17%~~24% increase in NGL sales volumes.

The increase in NGL sales revenue of ~~$30.5~~$24.5 million, or ~~81%~~60%, for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 as compared to the ~~nine months ended September 30, 2016~~same period in 2017 is due to a ~~51%~~29% increase in average NGL ~~prices realized~~sales Realized Prices received and a ~~20%~~24% increase in NGL sales volumes.

Natural gas sales revenue. Our natural gas sales revenue is a function of natural gas production volumes sold and average natural gas sales ~~prices~~Realized Prices received for those volumes. The ~~increase~~decrease in natural gas sales revenue of ~~$3.6~~$5.1 million, or ~~23%~~29%, for the three months ended ~~September~~June 30, ~~2017~~2018 as compared to the ~~three months ended September 30, 2016~~same period in 2017 is due to a ~~24%~~44% decrease in natural gas sales Realized Prices received, partially offset by a 28% increase in natural gas sales ~~volumes partially offset by a 1% decrease in average natural gas prices realized.~~volumes.

The ~~increase~~decrease in natural gas revenue of ~~$21.8~~$5.4 million, or ~~64%~~15%, for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 as compared to the ~~nine months ended September 30, 2016~~same period in 2017 is due to a ~~35% increase~~33% decrease in ~~average~~ natural gas ~~prices realized and~~sales Realized Prices received, partially offset by a ~~21%~~28% increase in natural gas sales volumes.

The following table presents midstream service and sales of purchased oil revenues:



	Three months ended June 30,				Six months ended June 30,
(in thousands)	2018		2017		2018		2017
Midstream service revenues	$	1,976	$	2,703	$	4,335	$	5,702
Sales of purchased oil	$	140,509	$	42,461	$	200,412	$	89,732

Midstream service revenues. Our midstream service revenues decreased by $0.7 million, or 27%, and by $1.4 million, or 24%, for the three and six months ended June 30, 2018, respectively, as compared to the same periods in 2017. These revenues are a function of the services provided through our (i) oil and natural gas gathering and transportation systems and related facilities, (ii) gas lift, rig fuel and centralized compression infrastructure and (iii) water storage, recycling and transportation infrastructure.

Sales of purchased oil. Sales of purchased oil increased by $98.0 million, or 231%, and by $110.7 million, or 123%, for the three and six months ended June 30, 2018, respectively, as compared to the same periods in 2017. These revenues are a function of the volume and price of purchased oil sold to customers and are fully offset by the increased cost of purchased oil. During the three months ended June 30, 2018, our volume of purchased oil sold to customers increased by 131%, as compared to the same period in 2017. This second-quarter 2018 increase in the volume of purchased oil sold is expected to decline to levels typical of previous periods in the third quarter of 2018.

Costs and expenses

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


	Three months ended September 30,				Nine months ended September 30,				Three months ended June 30,				Six months ended June 30,
(in thousands except for per BOE sold data)	2017		2016		2017		2016		2018		2017		2018		2017
Costs and expenses:
Lease operating expenses	$	19,594	$	18,177	$	56,690	$	57,920	$	22,642	$	20,104	$	44,593	$	37,096
Production and ad valorem taxes	9,558		7,066		26,811		21,483		12,405		8,472		24,217		17,253
Transportation and marketing expenses									1,534		—		1,534		—
Midstream service expenses	1,174		1,039		2,986		2,826		403		896		1,096		1,812
Costs of purchased oil	47,385		44,232		141,661		121,190		140,578		44,020		201,242		94,276
General and administrative:
Cash	16,034		16,454		45,728		46,496		16,158		13,321		31,544		29,694
Non-cash stock-based compensation, net of amounts capitalized	8,966		9,651		26,877		19,562
Non-cash stock-based compensation, net									10,676		8,687		20,015		17,911
Depletion, depreciation and amortization	41,212		35,158		113,327		110,813		50,762		38,003		96,315		72,115
Impairment expense	—		—		—		162,027
Other operating expenses	1,443		2,465		3,906		4,169		1,121		1,437		2,227		2,463
Total	$	145,366	$	134,242	$	417,986	$	546,486
Total costs and expenses									$	256,279	$	134,940	$	422,783	$	272,620
Average costs per BOE sold⁽¹⁾:
Lease operating expenses	$	3.55	$	3.85	$	3.64	$	4.37	$	3.70	$	3.77	$	3.78	$	3.69
Production and ad valorem taxes	1.73		1.50		1.72		1.62		2.03		1.59		2.05		1.72
Transportation and marketing expenses									0.25		—		0.13		—
Midstream service expenses	0.21		0.22		0.19		0.21		0.07		0.17		0.09		0.18
General and administrative:
Cash	2.90		3.49		2.94		3.51		2.64		2.50		2.67		2.95
Non-cash stock-based compensation, net of amounts capitalized	1.62		2.05		1.73		1.48
Non-cash stock-based compensation, net									1.75		1.63		1.69		1.78
Depletion, depreciation and amortization	7.46		7.45		7.28		8.36		8.30		7.12		8.15		7.17
Total	$	17.47	$	18.56	$	17.50	$	19.55
Total costs and expenses									$	18.74	$	16.78	$	18.56	$	17.49


(1)	Average costs per BOE sold are based on actual amounts and are not calculated using the rounded numbers presented in the table above.

Lease operating expenses. Lease operating expenses, which include workover expenses, increased by ~~$1.4~~$2.5 million, or 8%13%, and ~~decreased~~ by ~~$1.2~~$7.5 million, or 2%20%, for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, respectively, compared to the same periods in ~~2016.~~2017. On a per BOE sold basis, lease operating expenses ~~decreased 8% and 17%~~remained relatively flat for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017, respectively,~~2018 compared to the same periods in ~~2016 mainly due to previous investments in field infrastructure.~~2017. We continue to focus on economic efficiencies associated with the usage and procurement of products and services related to lease operating expenses.

Production and ad valorem taxes. Production and ad valorem taxes increased by ~~$2.5~~$3.9 million, or ~~35%~~46%, and ~~$5.3~~by $7.0 million, or ~~25%~~40%, for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, respectively, compared to the same periods in ~~2016.~~2017. The ~~quarter-over-quarter increase is~~increases are mainly due to ~~a $1.5 million increase~~increases in production taxes, and a $1.0 million increase in ad valorem taxes. The year-to-date increase over the comparable period in 2016 is due to a $6.6 million increase in production taxes partially offset by a $1.3 million decrease in ad valorem taxes. Production taxeswhich are based on and fluctuate in proportion to our oil, NGL and natural gas sales revenue. Ad valorem taxes are based on and fluctuate in proportion to the taxable value assessed by the various counties where our oil and natural gas properties are located.

Transportation and marketing expenses. Transportation and marketing expenses were $1.5 million for each of the three and six months ended June 30, 2018. There were no comparable amounts recorded during the same periods in 2017. Transportation and marketing expenses are the costs incurred to transport a portion of our production to the favorable Gulf Coast market.

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

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

~~General and administrative (~~"~~G&A~~"). ~~G&A~~Midstream service expenses decreased by ~~$1.1~~$0.5 million, or 4%55%, and ~~increased~~ by ~~$6.5~~$0.7 million, or ~~10%~~40%, for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, respectively, compared to the same periods in 2016. The quarter-over-quarter decrease is mainly due to an overall reduction in employee-related costs, partially offset by an increase in professional fees for the three months ended September 30, 2017 compared to the same period in 2016. The year-to-date increase over the comparable period in 2016 is mainly due to an increase in stock-based compensation, net of amounts capitalized, resulting from a greater number performance share awards granted to a larger base of management and employees during the nine months ended September 30, 2017 compared to the same period in 2016.

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 restricted stock option awards were determined using a Black-Scholes valuation model in accordance with GAAP and are being expensed on a straight-line basis over their associated four-year requisite service periods.

Our performance share awards are accounted for as equity awards and are included in stock-based compensation expense. The fair values for each of our 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 award agreement, utilizing a forward-looking Monte Carlo simulation. The fair values for each of our performance share awards will not be re-measured after the initial grant-date valuation and are being expensed on a straight-line basis over the associated three-year requisite service periods.

~~See Notes 2.n and 5 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding our stock-based compensation.~~

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

Three months ended September 30, Nine months ended September 30,
(in thousands except for per BOE sold data) 2017 2016 2017 2016
Depletion of evaluated oil and natural gas properties $ 37,538
$ 31,679
$ 102,290
$ 100,136
Depreciation of midstream service assets 2,241
2,036
6,569
6,204
Depreciation and amortization of other fixed assets 1,433
1,443
4,468
4,473
Total DD&A $ 41,212
$ 35,158
$ 113,327
$ 110,813

DD&A increased by $6.1 million, or 17%, and $2.5 million, or 2%, for the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016. The quarter-over-quarter increase is mainly due to an increase in production volumes sold for the three months ended September 30, 2017 compared to the same period in 2016. On a per BOE sold basis, DD&A decreased for the nine months ended September 30, 2017 compared to the same period in 2016, mainly due to positive well results and the impact of our full cost ceiling impairment of $161.1 million recorded as of March 31, 2016.

~~Impairment expense.~~ Our net book value of evaluated oil and natural gas properties exceeded the full cost ceiling amount as of March 31, 2016, and as a result, we recorded a non-cash full cost ceiling impairment of $161.1 million. There were no comparable full cost ceiling impairments recorded during the nine months ended September 30, 2017. For further discussion of our non-cash full cost ceiling impairment accounting policy, see Note 2.g to our unaudited consolidated financial statements included elsewhere in this Quarterly Report. There were no long-lived assets impairments recorded during the nine months ended September 30, 2017 or 2016. Inventory impairments of $1.0 million were recorded for the nine months ended September 30, 2016. There were no inventory impairments recorded during the nine months ended September 30, 2017. For further discussion of long-lived assets and inventory impairment accounting policies, see Note 2.i to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

~~Non-operating income (expense)~~

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

Three months ended September 30, Nine months ended September 30,
(in thousands) 2017 2016 2017
2016
Non-operating income (expense):

Gain (loss) on derivatives, net $ (27,441 ) $ 6,850
$ 38,127
$ (43,783 )
Income from equity method investee (Note 16.a) 2,371
265
7,910
6,259
Interest expense (23,697 ) (23,077 ) (69,590 ) (70,294 )
Interest and other income 333
33
527
143
Write-off of debt issuance costs —
—
—
(842 )
Loss on disposal of assets, net (991 ) (78 ) (400 ) (379 )
Non-operating expense, net $ (49,425 ) $ (16,007 ) $ (23,426 ) $ (108,896 )

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

(in thousands) Three months ended September 30, 2017 compared to 2016 Nine months ended September 30, 2017 compared to 2016
Changes in gain (loss) on derivatives, net:
Fair value of derivatives outstanding $ (3,619 ) $ 280,511
Cash settlements received for matured derivatives, net (30,672 ) (122,835 )
Cash settlements received for early terminations of derivatives, net —
(75,766 )
Total changes in gain (loss) on derivatives, net $ (34,291 ) $ 81,910

The changes in fair value of derivatives outstanding are the result of new, early-terminated and expiring contracts and the changing relationship between our outstanding contract prices and the future market prices in the forward curves, which we use to calculate the fair value of our derivatives. In general, if no contracts were entered into, terminated or modified, we experience gains during periods of decreasing market prices and losses during periods of increasing market prices. Net cash settlements received for matured derivatives are based on the cash settlement prices of our matured derivatives compared to the prices specified in the derivative contracts.

During the nine months ended September 30, 2017, we received proceeds from a hedge restructuring in which we early terminated a derivative contract swap, resulting in a termination amount due to us of $4.2 million. The $4.2 million was settled in full by applying the proceeds to pay the premium on one new derivative contract collar entered into during the hedge restructuring.

During the nine months ended September 30, 2016, we received proceeds from a hedge restructuring in which we early terminated floors of certain derivative contract collars, resulting in a termination amount due to us of $80.0 million. The $80.0 million was settled in full by applying the proceeds to the premiums on two new derivative contracts entered into as part of the hedge restructuring.

See Notes 2.e, 7 and 8.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information regarding our derivatives.

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

~~Interest expense.~~ Interest expense increased by $0.6 million and decreased by $0.7 million for the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016. These changes are primarily due to fluctuations in the outstanding balance and floating interest rate on our Senior Secured Credit Facility.

~~Income tax.~~ Since September 30, 2015, we have recorded a full valuation allowance against our net deferred tax position. As such, our effective tax rate was 0% during the three and nine months ended September 30, 2017 and 2016. For further discussion of our income tax position, see Note 6 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

~~Results of operations - midstream and marketing~~

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

Three months ended September 30, Nine months ended September 30,
(in thousands) 2017 2016 2017 2016
Revenues:
Natural gas sales $ 845
$ 488
$ 2,486
$ 488
Midstream service revenues 16,892
15,357
52,630
37,762
Sales of purchased oil 45,814
42,441
135,546
116,670
Total revenues 63,551
58,286
190,662
154,920
Costs and expenses:
Midstream service expenses 12,474
9,079
34,686
22,160
Costs of purchased oil 47,385
44,232
141,661
121,190
General and administrative⁽¹⁾
2,038
2,222
6,079
5,678
Depreciation and amortization⁽²⁾
2,410
2,275
7,045
6,669
Accretion of asset retirement obligations⁽³⁾
57
51
165
157
Operating income (loss) $ (813 ) $ 427
$ 1,026
$ (934 )
Other financial information:
Income from equity method investee $ 2,371
$ 265
$ 7,910
$ 6,259
Interest expense⁽⁴⁾
$ 1,513
$ 1,446
$ 4,340
$ 4,310

~~(1)~~

G&A expenses were allocated to the three months ended September 30, 2017, June 30, 2017, March 31, 2017, September 30, 2016, June 30, 2016 and March 31, 2016 based on the number of employees in the midstream and marketing segment as of the respective three-month period end dates. Certain components of G&A expenses, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for the segment. Land and geology expenses were not allocated to the midstream and marketing segment.

~~(2)~~

Depreciation and amortization were actual expenses for the midstream and marketing segment with the exception of the allocation of depreciation of other fixed assets, which was allocated to the three months ended September 30, 2017, June 30, 2017 and March 31, 2017 based on the number of employees in the midstream and marketing segment as of the respective three-month period end dates. Depreciation of other fixed assets was allocated to the three and nine months ended September 30, 2016 based on the number of employees in the midstream and marketing segment as of September 30, 2016. Certain components of depreciation and amortization of other fixed assets, primarily vehicles, were not allocated but were actual expenses for the segment.


~~(3)~~	~~Accretion of asset retirement obligations were actual expenses and were not allocated.~~

~~(4)~~

Interest expense for the three months ended September 30, 2017, June 30, 2017 and March 31, 2017 was allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of September 30, 2017, June 30, 2017 and March 31, 2017, respectively. Interest expense for the three and nine months ended September 30, 2016 was allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of September 30, 2016. Certain components of other fixed assets, primarily vehicles, were not allocated but were actual assets for the segment.

~~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 13 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information on our operating segments.

~~Midstream service revenues~~. Our midstream service revenues increased by $1.5 million and $14.9 million, or 10% and 39%, for the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016. These increases are mainly due to increased volume of water services provided.

~~Sales of purchased oil.~~ Sales of purchased oil increased by $18.9 million, or 16%, for the nine months ended September 30, 2017 compared to the same period in 2016 due to the increases in oil prices. For these sales of purchased oil, we

purchase oil from third parties in West Texas, transport it on the Bridgetex Pipeline and sell it to a third party in the Houston market. The net loss for the nine months ended September 30, 2017 compared to the same period in 2016 on these sales has increased by $1.6 million, or 35%, mainly due to the relative strengthening of the Midland market.

~~Midstream service expenses.~~ ~~Midstream service expenses increased by $3.4 million and $12.5 million, or 37% and 57%, for the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016.~~ 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. ~~These increases are due to the continued expansion of the midstream service component of our business.~~

Costs of purchased oil. Costs of purchased oil increased by ~~$20.5~~$96.6 million, or ~~17%~~219%, and by $107.0 million, or 113%, for the ~~nine~~three and six months ended ~~September~~June 30, ~~2017~~2018, respectively, compared to the same periods in 2017. These costs include the cost of obtaining oil from third parties and, in some cases, transporting such oil utilized in our marketing activities. Our costs of purchased oil may vary due to changes in oil prices, pricing differentials and the amount of volumes purchased. During the three months ended June 30, 2018, our volume of purchased oil increased by 132%, as compared to the same period in ~~2016 primarily~~2017. This second-quarter 2018 increase in the volume of purchased oil is expected to decline to levels typical of previous periods in the third quarter of 2018.

General and administrative ("G&A"). G&A increased by $4.8 million, or 22%, and by $4.0 million, or 8%, for the three and six months ended June 30, 2018, respectively, compared to the same periods in 2017 mainly due to increases in employee-related costs and professional fees. Non-cash stock-based compensation, net increased by $2.0 million, or 23%, and by $2.1 million, or 12%, for the three and six months ended June 30, 2018, respectively, compared to the same periods in 2017. A significant portion of this increase is due to the ~~increases~~immediate vesting of stock awards granted to our non-employee directors in ~~oil prices. These costs include purchasing oil from third parties and transporting it on the Bridgetex Pipeline.~~May 2018 compared to a one-year cliff-vest in May 2017.

~~Income from equity method investee.~~ As of September 30, 2017, LMS owned 49% of the ownership units of Medallion. Subsequent to September 30, 2017, LMS and MMH consummated the sale of 100% of the ownership interests in Medallion to an affiliate of GIP. See Note ~~16.a~~7.c to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for information regarding our stock-based compensation.

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



	Three months ended June 30,				Six months ended June 30,
(in thousands)	2018		2017		2018		2017
Depletion of evaluated oil and natural gas properties	$	46,985	$	34,338	$	88,802	$	64,752
Depreciation of midstream service assets	2,460		2,177		4,865		4,328
Depreciation and amortization of other fixed assets	1,317		1,488		2,648		3,035
Total DD&A	$	50,762	$	38,003	$	96,315	$	72,115

DD&A increased by $12.8 million, or 34%, and by $24.2 million, or 34%, for the three and six months ended June 30, 2018, respectively, compared to the same periods in 2017. The increases are mainly due to increases in the depletion base and production volumes sold.

Non-operating income (expense). The following table presents the components of non-operating income (expense):



	Three months ended June 30,						Six months ended June 30,
(in thousands)	2018			2017			2018			2017
Gain (loss) on derivatives, net	$	(45,976	)	$	28,897		$	(36,966	)	$	65,568
Income from equity method investee (see Note 3.c)	—			2,471			—			5,539
Interest expense	(14,424		)	(23,173		)	(27,942		)	(45,893		)
Interest and other income	443			49			896			194
Gain (loss) on disposal of assets, net	(1,358		)	805			(3,975		)	591
Non-operating income (expense), net	$	(61,315	)	$	9,049		$	(67,987	)	$	25,999

Gain (loss) on derivatives, net. The following table presents the changes in the components of gain (loss) on derivatives, net:



(in thousands)	Three months ended June 30, 2018 compared to 2017			Six months ended June 30, 2018 compared to 2017
Decrease in fair value of derivatives outstanding	$	(57,115	)	$	(75,089	)
Decrease in settlements received for matured derivatives, net	(13,524		)	(23,211		)
Decrease in settlements received for early terminations of derivatives, net	(4,234		)	(4,234		)
Total decrease in gain on derivatives, net	$	(74,873	)	$	(102,534	)

The change in fair value of derivatives outstanding is the result of new, early-terminated and expiring contracts and the changing relationship between our outstanding contract prices and the future market prices in the forward curves, which we use to calculate the fair value of our derivatives. In general, if no new contracts are entered into or terminated, we experience gains during periods of decreasing market prices and losses during periods of increasing market prices. Settlements received or paid for matured derivatives are based on the settlement prices of our matured derivatives compared to the prices specified in the derivative contracts.

During the three and six months ended June 30, 2017, we completed a hedge restructuring by early terminating a swap that resulted in a termination amount to us of $4.2 million that was settled in full by applying the proceeds to pay the premium on one new collar entered into during the restructuring.

See Notes 8, 9.a and 17.a 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 ~~this sale.~~our derivatives.

Income from equity method investee. Prior to the ~~sale,~~Medallion Sale on October 30, 2017, we owned 49% of the ownership interests of Medallion. As such, we previously accounted for ~~our~~this investment ~~in Medallion~~ under the equity method of accounting with our proportionate share of Medallion's net income reflected in the unaudited consolidated statements of operations as "Income from equity method ~~investee" and~~investee." For further discussion of the carrying amount reflected in the unaudited consolidated balance sheets as "Investment in equity method investee." Income from equity method investee increased by $2.1 million and $1.7 million, or 795% and 26%, for the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016. The quarter-over-quarter increase is mainly due to Medallion's transportation fee revenue, resulting from higher throughput volumes partially offset by an increase in Medallion's operating expenses. The year-to-date increase over the comparable period in 2016 is mainly due to Medallion's transportation fee revenue, resulting from higher throughput volumes partially offset by increases in Medallion's depreciation and operating expenses. During the nine months ended September 30, 2017, Medallion continued expansion activities on existing portions of its pipeline infrastructure in order to gather additional third-party oil production. The Medallion pipeline system transported an average of 180,218 barrels of oil per day ("BOPD") and 118,000 BOPD for the three months ended September 30, 2017 and 2016, respectively, and an average of 166,168 BOPD and 100,000 BOPD for the nine months ended September 30, 2017 and 2016, respectively.

~~See~~Sale, see Note ~~2.h, 12.a and 16.a~~3.c to our unaudited consolidated financial statements included elsewhere in this Quarterly ~~Report~~Report.

Interest expense. Interest expense decreased by $8.7 million, or 38%, and by $18.0 million, or 39%, for ~~additional information regarding~~the three and six months ended June 30, 2018, respectively, compared to the same periods in 2017, mainly due to the early redemption of the May 2022 Notes on November 29, 2017.

Gain (loss) on disposal of assets, net. Gain on disposal of assets, net, decreased by $2.2 million and by $4.6 million for the three and six months ended June 30, 2018, respectively, compared to the same periods in 2017. From time to time, we dispose of materials and supplies inventory, midstream service assets and other fixed assets. The associated gain or loss recorded during the period fluctuates depending upon the volume of the assets disposed, their associated net book value and, in the case of a disposal by sale, the sale price.

Income tax. Since September 30, 2015, we have recorded a full valuation allowance against our net deferred tax assets. As such, our effective tax rate was 0% for each of the three and six months ended June 30, 2018 and 2017. For further discussion of our valuation allowance, see Note 14 to our unaudited consolidated financial statements included elsewhere in this ~~investment.~~Quarterly Report.

Liquidity and capital resources

~~Our~~Historically, our primary sources of liquidity have been cash flows from operations, proceeds from equity offerings, proceeds from senior unsecured note offerings, borrowings under our Senior Secured Credit Facility and proceeds from the Medallion Sale and other asset ~~dispositions.~~sales. 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 our expected capital expenditures. Our primary operational uses of capital have been for the acquisition, exploration and development of oil and natural gas properties, ~~LMS'~~ infrastructure development and investments in ~~Medallion.~~

OnMedallion until its sale on October 30, 2017, LMS, together with MMH, which is owned and controlled by an affiliate of EMG, completed the previously announced Medallion Sale to an affiliate of GIP, for cash consideration of $1.825 billion, subject to customary post-closing adjustments. LMS' net cash proceeds for its 49% ownership interest in Medallion are $829.6 million, before post-closing adjustments and taxes, but after deduction of its proportionate share of fees and other expenses associated with the Medallion Sale. The Medallion Sale closed pursuant to the membership interest purchase and sale agreement, which provides for potential post-closing additional cash consideration that is structured based on GIP's realized profit at exit. There can be no assurance as to when and whether any such additional consideration will be paid.

A portion of the proceeds from the Medallion Sale was used to repay borrowings outstanding on our Senior Secured Credit Facility, and we have called for redemption all $500.0 million aggregate principal amount of our May 2022 Notes. See Notes 16.b and 16.c to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information.

In January 2017, we completed the sale of 2,900 net acres and working interests in 16 producing vertical wells in the Midland Basin to a third-party buyer for a purchase price of $59.7 million. After transaction costs reflecting an economic

~~effective date of October 1, 2016, the proceeds were $59.5 million, net of working capital and post-closing adjustments. We completed the closing adjustments for this divestiture in May~~ 2017. A portion of these proceeds was used to pay down borrowings on our Senior Secured Credit Facility. The purchase price was recorded as an adjustment to oil and natural gas properties pursuant to the rules governing full cost accounting.

A significant portion of our capital expenditures can be adjusted and managed by us. We continually monitor the capital markets and our capital structure and consider which financing alternatives, including equity and debt capital resources, joint ventures and asset sales, are available to meet our future planned or accelerated capital expenditures. We may make changes to our capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity and/or achieving cost efficiency. Such financing alternatives, including capital market transactions and debt and equity repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. See Notes 3, 6.c and 47.a to our unaudited consolidated financial statements and "Part II. Item 2. Purchases of Equity Securities" included elsewhere in this Quarterly Report for additional discussion of our ~~divestiture~~acquisitions and divestitures of oil and natural gas properties and ~~debt, respectively.~~

midstream assets, the Medallion Sale, the redemption of our May 2022 Notes and our $200.0 million share repurchase program, from time to time, authorized by our board of directors in February 2018. We ~~continually seek~~also continuously look for other opportunities to maintain a financial profile that provides operational flexibility. As of October 31, 2017, we had the full $1.0 billion borrowing base and aggregate elected commitment available for borrowings under our Senior Secured Credit Facility. We believe that our operating cash flow and the aforementioned liquidity sources provide us with the financial resources to implement our planned exploration and development activities.maximize shareholder value.

We use derivatives to reduce exposure to fluctuations in the prices of oil, NGL and natural gas. See Note 7.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for information regarding our derivative settlement indices and our open hedge positions as of September 30, 2017. As of November 2, 2017, we have not entered into additional hedges subsequent to September 30, 2017. 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. Our derivative positions will help us stabilize a portion of our expected cash flows from operations in the event of future declines in the prices of oil, NGL and natural gas. See ~~"Item~~"Part I. Item 3. Quantitative and Qualitative Disclosures About Market Risk" below. See Notes 8 and 17.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for information regarding our derivative settlement indices and our open hedge positions as of June 30, 2018 and derivatives entered into subsequent to June 30, 2018, respectively.

We continually seek to maintain a financial profile that provides operational flexibility. As of June 30, 2018, we had cash and cash equivalents of $36.6 million and undrawn capacity under the Senior Secured Credit Facility of $1.09 billion, resulting in total liquidity of $1.13 billion. As of July 31, 2018, we had cash and cash equivalents of $34.0 million and undrawn capacity under the Senior Secured Credit Facility of $1.07 billion, resulting in total liquidity of $1.10 billion. We believe that our operating cash flow and the aforementioned liquidity sources provide us with the financial resources to manage our business needs, to implement our planned capital expenditure budget and, at our discretion, to fund our share repurchase program.

Cash flows

~~Our~~The following table presents our cash ~~flows for the periods presented are summarized in the table below:~~flows:


	Nine months ended September 30,						Six months ended June 30,
(in thousands)	2017			2016			2018			2017
Net cash provided by operating activities	$	272,051		$	245,454		$	262,601		$	156,901
Net cash used in investing activities	(356,893		)	(455,895		)	(354,072		)	(177,578		)
Net cash provided by financing activities	72,988			209,647			15,916			23,029
Net decrease in cash and cash equivalents	$	(11,854	)	$	(794	)
Net (decrease) increase in cash and cash equivalents							$	(75,555	)	$	2,352

Cash flows ~~from~~provided by operating activities

Net cash provided by operating activities increased by ~~$26.6~~$105.7 million, or 67%, for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 compared to the same period in ~~2016~~2017 mainly due to increased revenues due to the ~~price-related~~ increase in average realized sales prices for oil and NGL and ~~natural gas revenues;~~increased sales volumes of all production with additional details included at "—Results of operations consolidated"; however, other notable cash changes included ~~(i)~~ a decrease of ~~$125.2~~$24.8 million in ~~cash~~ settlements received for matured derivatives and early terminations of derivatives, net of premiums paid, (ii) a cash outflow of $6.4 million related to the settlement of our last tranche of performance unit awards in first-quarter 2016 with no comparable amount incurred in 2017 and (iii) a decrease in working capital outflows of $1.2 million.paid.

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, mitigated to the extent of our derivatives' exposure, and ~~production~~sales volume levels. Regional and worldwide economic activity, weather, infrastructure, transportation capacity to reach markets, costs of operations, legislation and regulations 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~~risks related to our ~~financial position,~~business, see ~~"Item 3. Quantitative and Qualitative Disclosures About Market Risk."~~"Part I. Item 1A. Risk Factors" in our 2017 Annual Report.

Cash flows ~~from~~used in investing activities

Net cash used in investing activities ~~decreased $99.0~~increased by $176.5 million, ~~during~~or 99%, for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 compared to the same period in ~~2016~~2017 and is mainly attributable to (i) ~~proceeds we received from a January 2017 divestiture of~~an increase in capital expenditures on oil and natural gas properties, ~~and~~ (ii) a decrease in ~~contributions made to Medallion. The year-over-year increase in total~~proceeds from dispositions of capital ~~expenditures for oil and natural gas properties, midstream service~~ assets and ~~other fixed assets was substantially offset by cash~~

~~outflow for 2016~~(iii) second-quarter 2018 acquisitions of oil and natural gas properties. See Note 3 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of ~~the January 2017 divestiture~~our acquisitions and ~~the 2016 acquisitions.~~divestitures of oil and natural gas properties and midstream assets.

~~Our net~~The following table presents the components of our cash ~~used in~~flows from investing ~~activities for the periods presented is summarized in the table below:~~activities:


	Nine months ended September 30,						Six months ended June 30,
(in thousands)	2017			2016			2018			2017
Acquisitions of oil and natural gas properties							$	(16,340	)	$	—
Capital expenditures:
Acquisitions of oil and natural gas properties	$	—		$	(115,600	)
Oil and natural gas properties	(381,165		)	(276,735		)	(341,534		)	(232,219		)
Midstream service assets	(11,680		)	(4,231		)	(5,205		)	(6,117		)
Other fixed assets	(3,604		)	(982		)	(4,965		)	(2,683		)
Investment in equity method investee (Note 16.a)	(24,572		)	(58,712		)
Proceeds from disposition of equity method investee, net of selling costs (see Note 3.c)							1,655			—
Proceeds from dispositions of capital assets, net of selling costs	64,128			365			12,317			63,441
Net cash used in investing activities	$	(356,893	)	$	(455,895	)	$	(354,072	)	$	(177,578	)

Capital expenditure budget

~~During~~Due to the ~~fourth quarter~~increase in operational efficiencies and expected completions, we are increasing the drilling and completion portion of ~~2017,~~ our ~~board of directors approved~~capital budget to $545.0 million, an increase of $45.0 million from the previously announced level. Other capital expenditures are expected to remain unchanged at $85.0 million, bringing our total annual budgeted capital expenditures, excluding non-budgeted acquisitions, to $630.0 million. We are monitoring the ~~2017 capital expenditure budget~~impact of $100.0 million which represents service cost inflation, additional completion optimization testing and data collection. Our revised capital expenditure budget is $630.0 million for calendar year 2017, excluding acquisitions and investmentsthe steel import tariffs recently imposed by the Administration; however, we currently do not believe there will be an impact to us in ~~Medallion.~~2018. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.

The amount, timing and allocation of capital expenditures are largely discretionary and within management's control. If oil, 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 and supplies, changes in service costs, contractual obligations, internally generated cash flow and other factors both within and outside our control. ~~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 ~~from~~provided by financing activities

~~For the nine months ended September 30, 2017, our net~~Net cash provided by financing activities ~~was~~decreased by $7.1 million, or 31%, for the ~~result of borrowings on~~six months ended June 30, 2018, compared to the same period in 2017 and is mainly attributable to share repurchases under our ~~Senior Secured Credit Facility~~share repurchase program that commenced in February 2018. The decrease was partially offset by ~~(i)~~an absence of payments on our Senior Secured Credit Facility ~~(ii) the purchase of treasury stock to satisfy employees' tax withholding upon vesting of their stock-based compensation awards~~ and (iii) payments for debt issuance costs as a result of entering into the Fifth Amended and Restated Credit Agreement to our Senior Secured Credit Facility. The aforementioned increase in the purchase of treasury stock is mainly due to the increase of our stock price at the restricted stock awards' vest dates, which is utilized to determine the taxable compensation, compared to our stock price at the restricted stock awards' grant dates, which is utilized to determine the number of shares of restricted stock awards to be granted. For the nine months ended September 30, 2016, our primary sources of cash provided by financing activities wereincreased borrowings on our Senior Secured Credit ~~Facility~~Facility. Through June 30, 2018, we have repurchased 9,878,552 shares of common stock at a weighted-average price of $8.83 per common share for a total of $87.2 million under this program and, ~~proceeds~~upon repurchase, the shares were retired. As of June 30, 2018, we had authorization remaining to repurchase, from ~~our July 2016 Equity Offering and May 2016 Equity Offering, partially offset by payments on our Senior Secured Credit Facility.~~time to time, until February 2020, approximately $112.8 million in common stock, if any.

~~Our net~~The following table presents the components of our cash ~~provided by~~flows from financing ~~activities for the periods presented is summarized in the table below:~~activities:


	Nine months ended September 30,						Six months ended June 30,
(in thousands)	2017			2016			2018			2017
Borrowings on Senior Secured Credit Facility	$	155,000		$	214,682		$	110,000		$	90,000
Payments on Senior Secured Credit Facility	(70,000		)	(279,682		)	—			(55,000		)
Proceeds from issuance of common stock, net of offering costs	—			276,052
Purchase of treasury stock	(7,638		)	(1,613		)
Share repurchases							(87,218		)	—
Vested stock exchanged for tax withholding							(4,397		)	(7,597		)
Proceeds from exercise of stock options	358			208			—			358
Payments for debt issuance costs	(4,732		)	—			(2,469		)	(4,732		)
Net cash provided by financing activities	$	72,988		$	209,647		$	15,916		$	23,029

Debt

As of ~~September~~June 30, ~~2017,~~2018, we were a party only to our Senior Secured Credit Facility and the indentures governing our senior unsecured notes.

As of September 30, 2017, we had $1.5 billion in debt outstanding, $845.0 million available for borrowings under our Senior Secured Credit Facility and $20.8 million in cash on hand for total available liquidity of $865.8 million. On October 30, 2017, we used a portion of the proceeds from the Medallion Sale to repay borrowings outstanding under our Senior Secured Credit Facility.

On October 30, 2017, we issued a press release announcing that we have called for redemption all $500.0 million aggregate principal amount of our May 2022 Notes. The redemption date for the May 2022 Notes is November 29, 2017, and holders will receive a redemption price of 103.688% of the principal amount of the May 2022 Notes, plus accrued and unpaid interest from November 1, 2017 through November 28, 2017.

As of October 31, 2017, we had $1.3 billion in debt outstanding, $1.0 billion available for borrowings under our Senior Secured Credit Facility and $735.0 million in cash on hand for total available liquidity of $1.7 billion. The cash on hand amount includes proceeds from the Medallion Sale prior to the redemption of the May 2022 Notes, which is expected to be completed on November 29, 2017.

Senior Secured Credit Facility. As of ~~September~~June 30, ~~2017,~~2018, our Senior Secured Credit Facility had a maximum credit amount of $2.0 billion, a borrowing base of $1.3 billion and an aggregate elected commitment ~~each~~ of ~~$1.0~~$1.2 billion, ~~and $155.0~~with $110.0 million outstanding. See Note 17.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for subsequent borrowings and repayments on our Senior Secured Credit Facility.

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. The ~~maturity date of the~~ Senior Secured Credit Facility ~~is May 2, 2022,~~matures on April 19, 2023, provided that if either of the January 2022 Notes or ~~May 2022~~March 2023 Notes have not been ~~redeemed or~~ refinanced on or prior to the applicable Early Maturity Date, the Senior Secured Credit Facility will mature on such Early Maturity Date.

~~On October 20, 2017, pursuant~~ See Note 6.d to ~~a regular semi-annual redetermination, the lenders reaffirmed the $1.0 billion borrowing base under~~our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our Senior Secured Credit Facility. ~~Our aggregate elected commitment of $1.0 billion remained unchanged.~~

Principal amounts borrowed under our 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~~"Adjusted Base ~~Rate~~Rate" as defined in our Senior Secured Credit Facility, 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,~~a "LIBOR Rate" as defined in our Senior Secured Credit Facility, in each case, plus an applicable margin, which ranges from ~~1.0%~~0.25% to ~~2.0%~~1.25% for ~~Adjusted~~"Adjusted Base Rate ~~loans~~Loans" as defined in our Senior Secured Credit Facility, and from ~~2.0%~~1.25% to ~~3.0%~~2.25% for ~~Adjusted London Interbank Offered Rate loans,~~"Eurodollar Loans" as defined in our Senior Secured Credit Facility, based on the ratio of the outstanding revolving credit on our Senior Secured Credit Facility to the ~~elected commitment.~~borrowing base. We are also required to pay ~~an annual~~a commitment fee, which ranges from 0.375% to 0.50%, based on the ~~unused portion~~ratio of the ~~bank's commitment of 0.375%~~outstanding revolving credit on our Senior Secured Credit Facility to ~~0.5%.~~the aggregate elected commitment.

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 85% of the present value of our proved reserves owned now or in the future. Our Senior Secured Credit Facility contains both financial and non-financial covenants. We were in compliance with these covenants as of ~~September~~June 30, 2018 and December 31, 2017.

Senior unsecured notes. The following table presents principal amounts and applicable interest rates for our outstanding senior unsecured notes as of ~~September~~June 30, ~~2017:~~2018:


(in millions, except for interest rates)	Principal		Interest rate		Principal		Interest rate
January 2022 Notes	$	450.0	5.625	%	$	450.0	5.625	%
May 2022 Notes	500.0		7.375	%
March 2023 Notes	350.0		6.250	%	350.0		6.250	%
Total Senior Unsecured Notes	$	1,300.0
Total senior unsecured notes					$	800.0

~~Refer~~See Notes 6.a and 6.b to ~~Notes 4, 16.b and 16.c of~~ our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of the March 2023 Notes and January 2022 Notes, ~~May 2022 Notes and our Senior Secured Credit Facility.~~respectively.

Obligations and commitments

As of ~~September~~June 30, ~~2017,~~2018, our contractual obligations included our ~~March 2023 Notes,~~ January 2022 Notes, ~~May 2022~~March 2023 Notes, Senior Secured Credit Facility, drilling contract commitments, firm sale and transportation commitments, sand purchase and supply agreement, derivative deferred premiums, asset retirement obligations and office and equipment operating leases. From December 31, ~~2016~~2017 to ~~September~~June 30, ~~2017,~~2018, the material changes in our contractual obligations included (i) an increase of ~~$85.0~~$110.0 million in outstanding borrowings on our Senior Secured Credit Facility, (ii) ~~a decrease~~an increase of ~~$71.6~~$52.1 million ~~in our~~for firm sale and transportation commitments due to the timing of when contracts were entered into, completed and terminated, (iii) an increase of $24.6 million for drilling contract commitments due to the timing of when contracts were entered into and completed (on contracts other than those on a well-by-well basis), (iv) a decrease of ~~$65.6~~$23.6 million on our interest obligations for our senior unsecured notes as semi-annual interest payments were made in January and March ~~May, July and September of 2017, (iv)~~2018, (v) an increase of ~~$18.8~~$8.0 million due to a new in-basin sand purchase and supply agreement entered into during the second quarter of 2018 and (vi) a decrease of $3.9 million in derivative deferred premiums mainly due to premiums paid for derivatives partially offset by new ~~derivative contracts~~deferred premiums entered into.

During the three months ended June 30, 2018, we entered into a purchase and ~~(v)~~supply agreement for a ~~decrease~~term of ~~$4.9~~one year, whereby we have committed to buy a certain volume of in-basin sand for a fixed price. As of June 30, 2018, under the terms of this agreement, we are required to purchase a certain percentage of the volume commitment or we will incur a shortfall payment of $8.0 million ~~for drilling~~at the end of the contract ~~commitments (on contracts other than those on a well-by-well basis).~~period.

~~Refer to~~See Notes ~~2, 4, 7,~~6, 8, 9, 11, ~~16.b~~13 and ~~16.c~~17.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our contractual obligations.

Non-GAAP financial measure

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 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, ~~impairment expense,~~ non-cash stock-based compensation, net, ~~of amounts capitalized,~~ accretion expense, mark-to-market on derivatives, ~~cash~~ premiums paid for derivatives, interest expense, ~~write-off of debt issuance costs,~~ gains or losses on disposal of assets, income or loss from equity method investee, proportionate Adjusted EBITDA of equity method investee and other non-recurring income and expenses. 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 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, the 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 table presents a reconciliation of net income ~~(loss)~~ (GAAP) to Adjusted EBITDA (non-GAAP):


	Three months ended September 30,						Nine months ended September 30,						Three months ended June 30,						Six months ended June 30,
(in thousands)	2017			2016			2017			2016			2018			2017			2018			2017
Net income (loss)	$	11,027		$	9,485		$	140,413		$	(242,318	)
Net income													$	33,452		$	61,110		$	119,972		$	129,386
Plus:
Depletion, depreciation and amortization	41,212			35,158			113,327			110,813			50,762			38,003			96,315			72,115
Impairment expense	—			—			—			162,027
Non-cash stock-based compensation, net of amounts capitalized	8,966			9,651			26,877			19,562
Non-cash stock-based compensation, net													10,676			8,687			20,015			17,911
Accretion expense	951			883			2,822			2,587			1,121			943			2,227			1,871
Mark-to-market on derivatives:
(Gain) loss on derivatives, net	27,441			(6,850		)	(38,127		)	43,783			45,976			(28,897		)	36,966			(65,568		)
Cash settlements received for matured derivatives, net	13,635			44,307			34,791			157,626
Cash settlements received for early terminations of derivatives, net	—			—			4,234			80,000
Cash premiums paid for derivatives	(1,448		)	(2,709		)	(13,542		)	(86,972		)
Settlements (paid) received for matured derivatives, net													181			13,705			(2,055		)	21,156
Settlements received for early terminations of derivatives, net													—			4,234			—			4,234
Premiums paid for derivatives													(5,451		)	(9,987		)	(9,475		)	(12,094		)
Interest expense	23,697			23,077			69,590			70,294			14,424			23,173			27,942			45,893
Write-off of debt issuance costs	—			—			—			842
Loss on disposal of assets, net	991			78			400			379
(Gain) loss on disposal of assets, net													1,358			(805		)	3,975			(591		)
Income from equity method investee	(2,371		)	(265		)	(7,910		)	(6,259		)	—			(2,471		)	—			(5,539		)
Proportionate Adjusted EBITDA of equity method investee⁽¹⁾	6,789			5,194			19,755			13,981			—			6,601			—			12,966
Adjusted EBITDA	$	130,890		$	118,009		$	352,630		$	326,345		$	152,499		$	114,296		$	295,882		$	221,740


(1)	Proportionate Adjusted EBITDA of Medallion, our equity method investee until its sale on October 30, 2017, is calculated as follows:


	Three months ended September 30,				Nine months ended September 30,				Three months ended June 30,				Six months ended June 30,
(in thousands)	2017		2016		2017		2016		2018		2017		2018		2017
Income from equity method investee	$	2,371	$	265	$	7,910	$	6,259	$	—	$	2,471	$	—	$	5,539
Adjusted for proportionate share of:
Depreciation and amortization	4,418		4,929		11,845		7,722
Adjusted for proportionate share of depreciation and amortization									—		4,130		—		7,427
Proportionate Adjusted EBITDA of equity method investee	$	6,789	$	5,194	$	19,755	$	13,981	$	—	$	6,601	$	—	$	12,966

Critical accounting policies and estimates

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

In management's opinion, the more significant reporting areas impacted by our judgments and estimates are (i) the choice of accounting method for oil and natural gas activities, (ii) estimation of oil, NGL and natural gas reserve quantities and standardized measure of future net revenues, (iii) impairment of oil and natural gas properties, (iv) revenue recognition, (v) estimation of income taxes, (vi) asset retirement obligations, (vii) valuation of derivatives and deferred premiums, (viii) valuation of stock-based compensation, (ix) fair value of assets acquired and liabilities assumed in an acquisition and (x) estimates of contingent liabilities. 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~~six months ended ~~September~~June 30, ~~2017.~~2018. For our other critical accounting policies and procedures, please see our disclosure of critical accounting policies in "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" of the ~~2016~~2017 Annual Report. ~~Additionally,~~Furthermore, see ~~Note 2~~Notes 4 and 7.c to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for aadditional discussion of ~~additional accounting policies~~the impact of the adoption of ASC 606 and estimates ~~made by management.~~pertaining to our 2018 performance share awards.

Recent accounting pronouncements

See Note 152 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for information regarding recent accounting pronouncements.

Off-balance sheet arrangements

Currently, we do not have any off-balance sheet arrangements other than ~~operating leases,~~ drilling contracts, ~~and~~ firm sale and transportation commitments, a sand purchase and supply agreement and office and equipment operating leases which are described in "—Obligations and commitments." See Note 11 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~~risk-sensitive derivative instruments were entered into for hedging purposes, rather than for speculative trading.

Commodity price exposure

Due to the inherent volatility in oil, NGL and natural gas prices, we ~~use derivatives,~~engage in derivative transactions, such as puts, swaps, collars, basis swaps and, in the past, call spreads to hedge price risk associated with a significant portion of our anticipated production. By removing a portion of the price volatility associated with future production, we expect to ~~reduce,~~mitigate, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations in commodity prices.

During the three months ended June 30, 2018, the Midland market crude oil price experienced an increased discount to WTI-Cushing prices primarily due to limited pipeline capacity constraining transportation of crude oil out of the Permian Basin to major marketing hubs including, but not limited to, Cushing, Oklahoma and the United States Gulf Coast. As of June 30, 2018, this discount for prompt month delivery was $12 per Bbl of oil. This pipeline constraint is expected to affect the Midland market oil price until additional transportation capacity becomes operational or until basin-wide crude oil production decreases from its current historical levels. We have ~~not elected hedge accounting~~focused on ~~these derivatives~~achieving the ability to sell oil in multiple markets and ~~therefore,~~protecting the gains and losses on open positions are reflected in earnings. At each period end, we estimate the fair values of our derivatives using an independent third-party valuation and recognize the associated gain or loss in our unaudited consolidated statements of operations included elsewhere in this Quarterly Report.Company's oil value from basin differentials by securing transportation capacity.

The fair values of our ~~derivatives~~open derivative contracts are largely determined by ~~estimates of the~~ forward price curves of the relevant ~~price~~ indices. As of ~~September~~June 30, ~~2017,~~2018, a 10% change in the forward curves associated with our derivatives would have changed our unaudited consolidated balance sheet's net ~~positions~~derivative position to the following amounts:


(in thousands)	10% Increase			10% Decrease		10% Increase		10% Decrease
Derivatives	$	(17,128	)	$	51,649
Net liability derivative position						$	43,767	$	33,246

As of ~~September~~June 30, ~~2017~~2018 and December 31, ~~2016,~~2017, the net ~~fair values~~derivative positions were liabilities of ~~our open derivative contracts were $15.4~~$38.9 million and ~~$3.0~~$13.0 million, respectively. ~~Refer~~See Notes 8 and 9.a to ~~Notes 2.e, 7 and 8.a 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 our January 2022 Notes and March 2023 Notes bear interest at fixed rates. The ~~expected~~ maturity years, ~~carrying amounts~~outstanding balances and ~~fixed~~ interest rates on our long-term debt as of ~~September~~June 30, ~~2017 and the Senior Secured Credit Facility's average floating interest rate for the nine months ended September 30, 2017~~2018 were as follows:



	Maturity year
(in millions except for interest rates)	2022			2023⁽¹⁾
Senior Secured Credit Facility	$	—		$	110.0
Floating interest rate	—		%	3.324		%
January 2022 Notes	$	450.0		$	—
Fixed interest rate	5.625		%	—		%
March 2023 Notes	$	—		$	350.0
Fixed interest rate	—		%	6.250		%

Expected maturity year
(in millions except for interest rates) 2022 2023
Senior Secured Credit Facility - floating rate $ 155.0
$ —
Average interest rate 2.826 % — %
January 2022 Notes - fixed rate $ 450.0
$ —
Interest rate 5.625 % — %
May 2022 Notes - fixed rate $ 500.0
$ —
Interest rate 7.375 % — %
March 2023 Notes - fixed rate $ —
$ 350.0
Interest rate — % 6.250 %


(1)	The Senior Secured Credit Facility matures on April 19, 2023, provided that if either the January 2022 Notes or March 2023 Notes have not been refinanced on or prior to the applicable Early Maturity Date, the Senior Secured Credit Facility will mature on such Early Maturity Date.

Counterparty and customer credit risk

~~As of September 30,~~See Item 7A. "Quantitative and Qualitative Disclosures about Market Risk" in the 2017 our principal exposures to credit risk were through receivables of (i) $62.1 million from sales of our oil, NGL and natural gas production that we market to energy marketing companies and refineries, (ii) $20.0 million from the fair values of our open derivative contracts, (iii) $15.6 million from sales of purchased oil and other products, (iv) $8.7 million from joint-interest partners and (v) $3.3 million from matured derivatives.

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 sales of purchased oil receivable with one 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, each of whom is also a lender in our Senior Secured Credit Facility. The terms of the ISDA Agreements provide the non-defaulting or non-affected party the right to terminate the agreement upon the occurrence of

certain events of default and termination events by a party and also provide for the marking to market of outstanding positions and the offset of the mark to market amounts owed to and by the parties (and in certain cases, the affiliates of the non-defaulting or non-affected party) upon termination.

~~Refer to~~Annual Report, Note 1011 to our unaudited consolidated financial statements ~~included~~and "Part II, Item 1. Legal Proceedings" located elsewhere in this Quarterly Report for ~~additional disclosures regarding~~further discussion on our counterparty and customer 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~~June 30, ~~2017.~~2018. 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~~June 30, ~~2017~~2018 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, except with regard to the specific litigation noted below, as of the date hereof, we do not currently believe that any such legal proceedings will have a material adverse effect on our business, financial position, results of operations or liquidity.

On May 3, 2017, Shell filed an Original Petition and Request for Disclosure in the District Court of Harris County, Texas, alleging that the crude oil purchase agreement entered into between Shell and Laredo effective October 1, 2016 through June 30, 2020 does not accurately reflect the compensation to be paid to Shell under certain circumstances due to a drafting mistake. Shell seeks reformation of one clause of the crude oil purchase agreement on the grounds of alleged mutual mistake or, in the alternative, unilateral mistake, an award of the amounts Shell alleges it should have been or should be paid under the crude oil purchase agreement, court costs and ~~attorneys’~~attorneys' fees. ~~The Company does~~We do not believe there was a drafting mistake made in the crude oil purchase agreement, which covered the sale to Shell of 19,000 barrels of crude oil per day of our gross production, as well as the purchase by us of like-quantity crude oil from Shell. On December 11, 2017, Shell filed its First Amended Petition, in which it asserted nine causes of action, including multiple new claims for breach of contract and fraud.

Effective May 1, 2018, Shell terminated the crude oil purchase agreement and ceased purchasing our crude oil and selling crude oil to us under the terms of such agreement. As a result, we filed our Second Amended Answer and Original Counterclaim against Shell on June 15, 2018, in which we deny all allegations by Shell and seek damages in excess of $150.0 million resulting from Shell's breach and wrongful termination of the crude oil purchase agreement. Shell filed a Second Amended Petition on June 1, 2018, in which it asserted a new cause of action against us for alleged repudiation of Shell's proposed reformed version of the crude oil purchase agreement, a version never signed or agreed to by us.

Through April 30, 2018, the date on which Shell wrongfully terminated the crude oil purchase agreement, we had accounted for the costs and crude oil price realization as reflected in the terms of the crude oil purchase agreement. The ~~Company believes it has substantive defenses~~accompanying unaudited consolidated balance sheets located elsewhere in this Quarterly Report do not include any amounts for damage claims or attorneys' fees sought by Shell. As of June 30, 2018, we had estimated an aggregate amount of $37.4 million that is the subject of Shell's claims, which is generally based on the contractual amount in dispute under the pricing election that is the subject of Shell's claims applied to the barrels of crude oil purchased and ~~intends~~sold through the date on which Shell wrongfully terminated the crude oil purchase agreement. As a result of such termination, our estimate of this unrecorded amount is not anticipated to ~~vigorously defend~~materially increase in the future. This estimate does not include damages sought by Shell pursuant to its ~~position. The Company is~~latest repudiation claim asserted in its Second Amended Petition or amounts sought by Shell for recovery of attorneys' fees incurred for the prosecution of its claims.

We are unable to determine a probability of the outcome of this litigation at this time. We believe Shell's claims are meritless and the termination by Shell is improper and a breach of the crude oil purchase agreement. We therefore intend to vigorously defend ourselves against Shell's claims and pursue our rights under the terminated crude oil purchase agreement to seek all appropriate damages from Shell.

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 ~~2016~~2017 Annual Report. ~~There~~Other than the risk factor set forth below, there have been no material changes in our risk factors from those described in the ~~2016~~2017 Annual Report. The risks described in the ~~2016~~2017 Annual Report are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

Insufficient transportation capacity in the Permian Basin, and the challenges to alleviating such transportation constraints, could cause significant fluctuations in our realized oil pricesand our results of operations.

In our area of operation, the Permian Basin has been characterized by periods when oil production has surpassed local transportation capacity, resulting in substantial discounts to the price received for crude oil prices quoted for WTI oil. During the three months ended June 30, 2018, the Midland market crude oil price has experienced a substantial discount to WTI-Cushing prices, primarily due to limited pipeline capacity constraining transportation of crude oil out of the Permian Basin to major marketing hubs including, but not limited to Cushing, Oklahoma and the United States Gulf Coast. As of June 30, 2018, the price differential relative to WTI was $12 per barrel. The expansion and construction of pipeline facilities are affected by the availability and costs of necessary equipment, supplies, labor and other services, as well as the length of time to complete such projects. In addition, these projects can be affected by changes in international trade relationships, including the

imposition of trade restrictions or tariffs relating to crude oil and natural gas and any materials or products used to expand or construct pipeline facilities, such as certain imported steel mill products that are currently subject toa 25% global tariff on certain imported steel mill products. All of these factors could negatively impact our realized oil prices, as well as actual results of our operations.

Item 2. ~~Repurchase~~Purchases of Equity Securities

The following table summarizes purchases of common stock by Laredo:

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, 2017 - July 31, 2017 628
$ 10.52
—
—
August 1, 2017 - August 31, 2017 2,291
$ 12.80
—
—
September 1, 2017 - September 30, 2017 411
$ 12.70
—
—
Total 3,330



Period	Total number of shares purchased⁽¹⁾	Weighted-average price paid per share		Total number of shares purchased as part of publicly announced plans⁽²⁾	Maximum value that may yet be purchased under the program as of the respective period-end date ⁽²⁾
April 1, 2018 - April 30, 2018	3,152,591	$	9.12	3,150,651	$	112,782,213
May 1, 2018 - May 31, 2018	702	$	10.93	—	$	112,782,213
June 1, 2018 - June 30, 2018	2,040	$	9.48	—	$	112,782,213
Total	3,155,333			3,150,651


(1)	~~Represents~~Included in these amounts are 4,682 shares ~~that were~~ withheld by us to satisfy employee tax withholding obligations that arose upon the lapse of restrictions on restricted stock awards.

(2)

In February 2018, our board of directors authorized a $200 million share repurchase program commencing in February 2018. The repurchase program expires in February 2020. Repurchases of shares under this program totaled 3,150,651 at a cost of $28.7 million during the three months ended June 30, 2018. Share repurchases, if any, under the share repurchase program may be made through a variety of methods, which may include open market purchases, privately negotiated transactions and block trades.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

~~Item 7.01. Regulation FD Disclosure.~~

Attached as Exhibit 99.1 and incorporated herein by reference are unaudited pro forma condensed consolidated financial statements (the "Pro Forma Financial Statements") that give effect to the Medallion Sale, the repayment of the Senior Secured Credit Facility and the pending redemption of the May 2022 Notes (the"Subsequent Transactions"). We are voluntarily furnishing the Pro Forma Financial Statements, updated from the unaudited pro forma condensed consolidated financial statements included in the Form 8-K filed on October 30, 2017, which were based on prior financial statements, to assist investors in better understanding the impact of the Subsequent Transactions. See Notes 2.h and 16 included elsewhere in this Quarterly Report for additional discussion of the Subsequent Transactions.

Included in the Pro Forma Financial Statements are (i) an unaudited pro forma condensed consolidated balance sheet that has been prepared as if the Subsequent Transactions occurred as of September 30, 2017 and (ii) an unaudited pro forma condensed consolidated statement of operations for the nine months ended September 30, 2017 that has been prepared as if the Subsequent Transactions occurred on January 1, 2017. The Pro Forma Financial Statements furnished herewith are presented for illustrative purposes only and do not purport to represent what our results of operations or financial position would actually have been had the Subsequent Transactions occurred on the dates noted above, or to project our results of operations or financial position for any future periods. The Pro Forma Financial Statements are based on certain assumptions and adjustments described in the notes thereto and should be read together with the historical consolidated financial statements and the related notes included herein and in our 2016 Annual Report.

The information set forth under this Item 5 is intended to be furnished under this Item 5 and also "Item 7.01, Regulation FD Disclosure" of Form 8-K. Such information, including Exhibit 99.1 attached to this Form 10-Q, shall not be deemed "filed" for purposes of Section 18 of the Exchange Act, or otherwise subject to the liabilities of that section, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

~~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 United States ("US") 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 (and the term "control" is also 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, (ii) beneficially own more than 10% of the equity interests of, and have the right to designate members of the board of directors of Santander Asset Management Investment Holdings Limited ("SAMIH"). SAMIH may therefore be deemed to be under common "control" with us; however, this statement is not meant to be an admission that common control exists.

The disclosure below relates solely to activities conducted by SAMIH and its affiliates. The disclosure does not relate to any activities conducted by us or by WP and does not involve our or WP’s management. Neither Laredo nor WP has had any involvement in or control over the disclosed activities, and neither Laredo nor WP has independently verified or participated in the preparation of the disclosure. Neither Laredo nor WP is representing as to the accuracy or completeness of the disclosure nor do we or WP undertake any obligation to correct or update it.

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

(a) Santander UK plc ("Santander UK") holds two savings accounts and one current account for two customers resident in the United Kingdom ("UK") who are currently designated by the US under the Specially Designated Global Terrorist ("SDGT") sanctions program. Revenues and profits generated by Santander UK on these accounts in the nine months ended September 30, 2017 were negligible relative to the overall revenues and profits of Banco Santander SA.

(b) Santander UK holds two frozen current accounts for two UK nationals who are designated by the US under the SDGT sanctions program. The accounts held by each customer have been frozen since their designation and have remained frozen through the nine months ended September 30, 2017. The accounts are in arrears (£1,844.73 in debit combined) and are currently being managed by Santander UK Collections & Recoveries department. No revenues or profits were generated by Santander UK on this account in the nine months ended September 30, 2017.None.

Item 6. Exhibits



Exhibit Number			Description
2.1			Membership Interest Purchase and Sale Agreement, dated as of October 1, 2017, by and among Medallion Midland Acquisition, LLC, Medallion Gathering & Processing, LLC, Laredo Midstream Services, LLC, and Medallion Midstream Holdings, LLC (incorporated by reference to Exhibit 2.1 of ~~Laredo’s~~Laredo's Current Report on Form 8-K (File No. 001-35380) filed on October 30, 2017).
3.1			Amended and Restated Certificate of Incorporation of Laredo Petroleum Holdings, Inc. (incorporated by reference to Exhibit 3.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on December 22, 2011).
3.2			Certificate of Ownership and Merger, dated as of December 30, 2013 (incorporated by reference to Exhibit 3.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on January 6, 2014).
3.3			Second Amended and Restated Bylaws of Laredo Petroleum, Inc. (incorporated by reference to Exhibit 3.3 of Laredo's Annual Report on Form 10-K (File No. 001-35380) filed on February 17, 2016).
4.1			Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 of Laredo's Registration Statement on Form S-1/A (File No. 333-176439) filed on November 14, 2011).
10.1			~~First~~Third Amendment to Fifth Amended and Restated Credit Agreement, dated as of ~~October 24, 2017,~~April 19, 2018, among Laredo Petroleum, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, Laredo Midstream Services, LLC and Garden City Minerals, LLC, as guarantors and the banks signatory thereto (incorporated by reference to Exhibit 10.1 of ~~Laredo’s~~Laredo's Current Report on Form 8-K (File No. 001-35380) filed on ~~October 30, 2017)~~April 23, 2018).
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.
99.1**			September 30, 2017 unaudited pro forma condensed consolidated financial information of Laredo Petroleum, Inc., which gives pro forma effect to the following items: (i) the sale of the Company's ownership interests in Medallion, (ii) the repayment of the Company's senior secured credit facility and (iii) the redemption of the May 2022 Notes.
101.INS*			XBRL Instance Document.
101.SCH*			XBRL Schema Document.
101.CAL*			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.


*	Filed herewith.


**	Furnished herewith.


#	Management contract or compensatory plan or arrangement.

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~~August 2, ~~2017~~2018	By:	/s/ Randy A. Foutch
		Randy A. Foutch
		Chairman and Chief Executive Officer
		(principal executive officer)

Date: ~~November~~August 2, ~~2017~~2018	By:	/s/ Richard C. Buterbaugh
		Richard C. Buterbaugh
		Executive Vice President and Chief Financial Officer
		(principal financial officer)

Date: ~~November~~August 2, ~~2017~~2018	By:	/s/ Michael T. Beyer
		Michael T. Beyer
		Vice President - Controller and Chief Accounting Officer
		(principal accounting officer)

5850



(in thousands)	Nine months ended September 30, 2017			Year ended December 31, 2016
Liability at beginning of period	$	52,207		$	46,306
Liabilities added due to acquisitions, drilling, midstream service asset construction and other	492			1,528
Accretion expense	2,822			3,483
Liabilities settled upon plugging and abandonment	(357		)	(1,242		)
Liabilities removed due to sale of property	(871		)	—
Revision of estimates	178			2,132
Liability at end of period	$	54,471		$	52,207



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



(in thousands, except for weighted-average exercise price and weighted-average remaining contractual term)	Stock option awards		Weighted-average exercise price (per award)		Weighted-average remaining contractual term (years)
Outstanding as of December 31, 2016	2,370		$	12.54	7.71
Granted	391		$	14.12
Exercised⁽¹⁾	(44	)	$	8.17
Expired or canceled	(57	)	$	20.58
Outstanding as of September 30, 2017	2,660		$	12.67	7.37
Vested and exercisable as of September 30, 2017⁽²⁾	1,273		$	16.38	6.22
Expected to vest as of September 30, 2017⁽³⁾	1,387		$	9.26	8.42



	Granted on February 17, 2017
Risk-free interest rate⁽¹⁾	2.14		%
Expected option life⁽²⁾	6.25 years
Expected volatility⁽³⁾	60.84		%
Fair value per stock option award	$	8.22



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	%



	Aggregate volumes (Bbl)	Floor price ($/Bbl)		Ceiling price ($/Bbl)		Contract period
Oil swap	1,095,000	$	52.12	$	52.12	January 2018 - December 2018



	Aggregate volumes⁽¹⁾	Floor price⁽²⁾		Ceiling price⁽²⁾		Short call price⁽²⁾		Long call price⁽²⁾		Differential price⁽²⁾			Contract period
Oil⁽³⁾:
Call spread⁽⁴⁾	1,140,800	$	—	$	—	$	60.00	$	100.00	$	—		July 2017 - December 2017
Call spread⁽⁵⁾	184,000	$	—	$	—	$	60.00	$	80.00	$	—		July 2017 - December 2017
Put⁽⁶⁾	4,378,000	$	50.00	$	—	$	—	$	—	$	—		January 2018 - December 2018
Collar	584,000	$	50.00	$	60.00	$	—	$	—	$	—		January 2018 - December 2018
Collar⁽⁷⁾	3,504,000	$	40.00	$	60.00	$	—	$	—	$	—		January 2018 - December 2018
Basis swap	1,825,000	$	—	$	—	$	—	$	—	$	(0.59	)	January 2018 - December 2018
Basis swap	365,000	$	—	$	—	$	—	$	—	$	(0.58	)	January 2018 - December 2018
Basis swap	730,000	$	—	$	—	$	—	$	—	$	(0.52	)	January 2018 - December 2018
Basis swap	730,000	$	—	$	—	$	—	$	—	$	(0.49	)	January 2018 - December 2018
Put	730,000	$	50.00	$	—	$	—	$	—	$	—		January 2019 - December 2019
Natural gas:
Collar⁽⁸⁾	10,950,000	$	2.50	$	3.25	$	—	$	—	$	—		January 2018 - December 2018



	Remaining year 2017		Year 2018			Year 2019
Oil positions:
Puts:
Hedged volume (Bbl)	264,500		5,427,375			730,000
Weighted-average price ($/Bbl)	$	60.00	$	51.93		$	50.00
Swaps:
Hedged volume (Bbl)	506,000		—			—
Weighted-average price ($/Bbl)	$	51.54	$	—		$	—
Collars:
Hedged volume (Bbl)	956,800		4,088,000			—
Weighted-average floor price ($/Bbl)	$	56.92	$	41.43		$	—
Weighted-average ceiling price ($/Bbl)	$	86.00	$	60.00		$	—
Call Spreads:
Hedged volume (Bbl)	662,400		—			—
Weighted-average short call price ($/Bbl)	$	60.00	$	—		$	—
Weighted-average long call price ($/Bbl)	$	97.22	$	—		$	—
Totals:
Total volume hedged with floor price (Bbl)	1,727,300		9,515,375			730,000
Weighted-average floor price ($/Bbl)	$	55.82	$	47.42		$	50.00
Total volume hedged with ceiling price (Bbl)	1,462,800		4,088,000			—
Weighted-average ceiling price ($/Bbl)	$	57.22	$	60.00		$	—
Basis Swaps:
Hedged volume (Bbl)	—		3,650,000			—
Weighted-average price ($/Bbl)	$	—	$	(0.56	)	$	—
NGL positions:
Swaps - Ethane:
Hedged volume (Bbl)	111,000		—			—
Weighted-average price ($/Bbl)	$	11.24	$	—		$	—
Swaps - Propane:
Hedged volume (Bbl)	93,750		—			—
Weighted-average price ($/Bbl)	$	22.26	$	—		$	—
Natural gas positions:
Puts:
Hedged volume (MMBtu)	2,010,000		8,220,000			—
Weighted-average price ($/MMBtu)	$	2.50	$	2.50		$	—
Collars:
Hedged volume (MMBtu)	4,793,200		15,585,500			—
Weighted-average floor price ($/MMBtu)	$	2.86	$	2.50		$	—
Weighted-average ceiling price ($/MMBtu)	$	3.54	$	3.35		$	—
Totals:
Total volume hedged with floor price (MMBtu)	6,803,200		23,805,500			—
Weighted-average floor price ($/MMBtu)	$	2.75	$	2.50		$	—
Total volume hedged with ceiling price (MMBtu)	4,793,200		15,585,500			—
Weighted-average ceiling price ($/MMBtu)	$	3.54	$	3.35		$	—



(in thousands)	Exploration and production		Midstream and marketing			Eliminations			Consolidated company
Three months ended September 30, 2017:
Revenues:
Oil, NGL and natural gas sales	$	158,037	$	845		$	(1,324	)	$	157,558
Midstream service revenues	—		16,892			(14,446		)	2,446
Sales of purchased oil	—		45,814			—			45,814
Total revenues	158,037		63,551			(15,770		)	205,818
Costs and expenses:
Lease operating expenses, including production and ad valorem taxes	32,417		—			(3,265		)	29,152
Midstream service expenses	—		12,474			(11,300		)	1,174
Costs of purchased oil	—		47,385			—			47,385
General and administrative⁽¹⁾	22,962		2,038			—			25,000
Depletion, depreciation and amortization⁽²⁾	38,802		2,410			—			41,212
Other operating expenses⁽³⁾	1,386		57			—			1,443
Operating income (loss)	$	62,470	$	(813	)	$	(1,205	)	$	60,452
Other financial information:
Income from equity method investee	$	—	$	2,371		$	—		$	2,371
Interest expense⁽⁴⁾	$	22,184	$	1,513		$	—		$	23,697
Capital expenditures	$	149,867	$	5,563		$	—		$	155,430
Gross property and equipment⁽⁵⁾	$	6,149,485	$	443,462		$	(14,431	)	$	6,578,516
Three months ended September 30, 2016:
Revenues:
Oil, NGL and natural gas sales	$	115,188	$	488		$	(871	)	$	114,805
Midstream service revenues	—		15,357			(12,869		)	2,488
Sales of purchased oil	—		42,441			—			42,441
Total revenues	115,188		58,286			(13,740		)	159,734
Costs and expenses:
Lease operating expenses, including production and ad valorem taxes	28,624		—			(3,381		)	25,243
Midstream service expenses	—		9,079			(8,040		)	1,039
Costs of purchased oil	—		44,232			—			44,232
General and administrative⁽¹⁾	23,883		2,222			—			26,105
Depletion, depreciation and amortization⁽²⁾	32,883		2,275			—			35,158
Other operating expenses⁽³⁾	2,414		51			—			2,465
Operating income	$	27,384	$	427		$	(2,319	)	$	25,492
Other financial information:
Income from equity method investee	$	—	$	265		$	—		$	265
Interest expense⁽⁴⁾	$	21,631	$	1,446		$	—		$	23,077
Capital expenditures	$	79,843	$	806		$	—		$	80,649
Gross property and equipment⁽⁵⁾	$	5,682,251	$	384,091		$	(6,923	)	$	6,059,419
Nine months ended September 30, 2017:
Revenues:
Oil, NGL and natural gas sales	$	439,533	$	2,486		$	(3,888	)	$	438,131
Midstream service revenues	—		52,630			(44,482		)	8,148
Sales of purchased oil	—		135,546			—			135,546
Total revenues	439,533		190,662			(48,370		)	581,825
Costs and expenses:
Lease operating expenses, including production and ad valorem taxes	93,980		—			(10,479		)	83,501
Midstream service expenses	—		34,686			(31,700		)	2,986
Costs of purchased oil	—		141,661			—			141,661
General and administrative⁽¹⁾	66,526		6,079			—			72,605
Depletion, depreciation and amortization⁽²⁾	106,282		7,045			—			113,327
Other operating expenses⁽³⁾	3,741		165			—			3,906
Operating income	$	169,004	$	1,026		$	(6,191	)	$	163,839
Other financial information:
Income from equity method investee	$	—	$	7,910		$	—		$	7,910
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(in thousands)	Three months ended September 30, 2017 compared to 2016			Nine months ended September 30, 2017 compared to 2016
Changes in gain (loss) on derivatives, net:
Fair value of derivatives outstanding	$	(3,619	)	$	280,511
Cash settlements received for matured derivatives, net	(30,672		)	(122,835		)
Cash settlements received for early terminations of derivatives, net	—			(75,766		)
Total changes in gain (loss) on derivatives, net	$	(34,291	)	$	81,910



	Expected maturity year
(in millions except for interest rates)	2022			2023
Senior Secured Credit Facility - floating rate	$	155.0		$	—
Average interest rate	2.826		%	—		%
January 2022 Notes - fixed rate	$	450.0		$	—
Interest rate	5.625		%	—		%
May 2022 Notes - fixed rate	$	500.0		$	—
Interest rate	7.375		%	—		%
March 2023 Notes - fixed rate	$	—		$	350.0
Interest rate	—		%	6.250		%



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, 2017 - July 31, 2017	628	$	10.52	—	—
August 1, 2017 - August 31, 2017	2,291	$	12.80	—	—
September 1, 2017 - September 30, 2017	411	$	12.70	—	—
Total	3,330