UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended ~~September 30, 2017~~March 31, 2019

oTRANSITION 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.~~(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)

Securities registered pursuant to Section 12(b) of the Exchange Act:



Title of each class	Trading symbol	Name of each exchange on which registered
Common stock, $0.01 par value	LPI	New York Stock Exchange ("NYSE")

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 30, 2017: 242,512,535~~April 29, 2019: 236,555,114

LAREDO PETROLEUM, INC.

TABLE OF CONTENTS



		Page
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS	iii
	Part I
~~Item 1.~~	~~Consolidated Financial Statements (Unaudited)~~:
	~~Consolidated balance sheets as of September 30, 2017 and December 31, 2016~~	1
Item 1. Consolidated Financial Statements (Unaudited)	1
Consolidated balance sheets as of March 31, 2019 and December 31, 2018	1
Consolidated statements of operations for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2019 and ~~2016~~2018	2
	Consolidated ~~statement~~statements of stockholders' equity for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 and 2018	3
	Consolidated statements of cash flows for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 and ~~2016~~2018	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—~~Divestiture~~Leases	126
	Note 4—~~Debt~~Property and equipment	139
	Note 5—~~Employee compensation~~Debt	1410
Note 6—Stockholders' equity and Equity Incentive Plan	11
Note ~~6—Income taxes~~7—Derivatives	15
Note 8—Fair value measurements	18
	~~Note 7—Derivatives~~	18
	~~Note 8—Fair value measurements~~	22
	Note 9—Net income (loss) per common share	2620
Note 10—Commitments and contingencies	21
Note ~~10—Credit risk~~11—Supplemental cash flow and non-cash information	22
Note 12—Asset retirement obligations	23
Note 13—Revenue recognition	23
Note 14—Income taxes	24
Note 15—Related party	24
Note 16—Subsidiary guarantors	24
Note 17—Subsequent events	27
	~~Note 11—Commitments and contingencies~~	27
	~~Note 12—Related parties~~	28
	~~Note 13—Segments~~	28
	~~Note 14—Subsidiary guarantors~~	31
	~~Note 15—Recently issued or adopted accounting pronouncements~~	34
	~~Note 16—Subsequent events~~	35
	~~Note 17—Supplementary information~~	36
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	3729
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	5241
Item 4. Controls and Procedures	~~Controls and Procedures~~	54
	~~Part II~~
~~Item 1.~~	~~Legal Proceedings~~	5543
~~Item 1A.~~Part II	~~Risk Factors~~	5544
Item 2.1. Legal Proceedings	~~Repurchase of Equity Securities~~	5544
Item 3.1A. Risk Factors	~~Defaults Upon Senior Securities~~	5544
Item 4.2. Purchases of Equity Securities	~~Mine Safety Disclosures~~	5545
Item 5.3. Defaults Upon Senior Securities	~~Other Information~~	5545
Item 6.4. Mine Safety Disclosures	~~Exhibits~~	5745
~~SIGNATURES~~Item 5. Other Information	5845
Item 6. Exhibits	46
SIGNATURES	47

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, natural gas liquids ("NGL") 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")~~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;

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

the long-term performance of wells that were completed using different technologies;

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;

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

capital requirements for our operations and projects;

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

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;

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;

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

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

our ability to ~~generate sufficient cash~~recruit and retain the qualified personnel necessary to ~~service~~operate our ~~indebtedness, fund our capital requirements and generate future profits;~~

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

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;

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

changes in the regulatory environment and changes in United States or international legal, tax, political, administrative or economic conditions, including regulations that prohibit or restrict our

iii

Table of Contents

ability to apply hydraulic fracturing to our oil and natural gas wells and to access and dispose of water used in these operations;

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

our ability to execute our strategies;

competition in the oil and natural gas industry;

~~the adverse outcome and impact of litigation, legal proceedings, investigations or 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 comply with federal, state and local regulatory ~~requirements; and~~

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

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~~2018 (the ~~"2016~~"2018 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			March 31, 2019			December 31, 2018
Assets
Current assets:
Cash and cash equivalents	$	20,818		$	32,672		$	44,544		$	45,151
Accounts receivable, net	89,840			86,867			107,520			94,321
Derivatives	15,611			20,947			7,610			39,835
Other current assets	16,196			14,291			13,056			13,445
Total current assets	142,465			154,777			172,730			192,752
Property and equipment:
Oil and natural gas properties, full cost method:
Evaluated properties	5,863,536			5,488,756			6,951,343			6,752,631
Unevaluated properties not being depleted	211,720			221,281			92,467			130,957
Less accumulated depletion and impairment	(4,616,246		)	(4,514,183		)	(4,913,384		)	(4,854,017		)
Oil and natural gas properties, net	1,459,010			1,195,854			2,130,426			2,029,571
Midstream service assets, net	130,407			126,240			131,118			130,245
Other fixed assets, net	41,902			44,773			39,098			39,819
Property and equipment, net	1,631,319			1,366,867			2,300,642			2,199,635
Derivatives	4,345			8,718			5,970			11,030
Investment in equity method investee (Note 16.a)	276,435			243,953
Other assets, net	11,762			8,031
Operating lease right-of-use assets							19,035			—
Other noncurrent assets, net							16,412			16,888
Total assets	$	2,066,326		$	1,782,346		$	2,514,789		$	2,420,305
Liabilities and stockholders' equity
Current liabilities:
Accounts payable	$	22,795		$	15,054
Accounts payable and accrued liabilities							$	76,644		$	69,504
Accrued capital expenditures							36,418			29,975
Undistributed revenue and royalties	33,222			26,838			51,730			48,841
Accrued capital expenditures	70,001			30,845
Derivatives	4,170			20,993			11,057			7,359
Operating lease liabilities							10,896			—
Other current liabilities	93,072			94,215			16,877			44,786
Total current liabilities	223,260			187,945			203,622			200,465
Long-term debt, net	1,440,968			1,353,909			1,064,081			983,636
Derivatives	362			5,694			3,563			—
Asset retirement obligations	52,181			50,604			54,555			53,387
Operating lease liabilities							11,301			—
Other noncurrent liabilities	3,330			3,621			6,235			8,587
Total liabilities	1,720,101			1,601,773			1,343,357			1,246,075
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 March 31, 2019 and December 31, 2018							—			—
Common stock, $0.01 par value, 450,000,000 shares authorized and 239,191,487 and 233,936,358 issued and outstanding as of March 31, 2019 and December 31, 2018, respectively							2,392			2,339
Additional paid-in capital	2,421,469			2,396,236			2,381,926			2,375,286
Accumulated deficit	(2,077,669		)	(2,218,082		)	(1,212,886		)	(1,203,395		)
Total stockholders' equity	346,225			180,573			1,171,432			1,174,230
Total liabilities and stockholders' equity	$	2,066,326		$	1,782,346		$	2,514,789		$	2,420,305

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

Laredo Petroleum, Inc.

Consolidated statements of operations

(in thousands, except per share data)

(Unaudited)


	Three months ended September 30,						Nine months ended September 30,						Three months ended March 31,
	2017			2016			2017			2016			2019			2018
Revenues:
Oil, NGL and natural gas sales	$	157,558		$	114,805		$	438,131		$	290,473
Oil sales													$	129,171		$	150,914
NGL sales													32,235			28,360
Natural gas sales													11,970			18,160
Midstream service revenues	2,446			2,488			8,148			5,921			2,883			2,359
Sales of purchased oil	45,814			42,441			135,546			116,670			32,688			59,903
Total revenues	205,818			159,734			581,825			413,064			208,947			259,696
Costs and expenses:
Lease operating expenses	19,594			18,177			56,690			57,920			22,609			21,951
Production and ad valorem taxes	9,558			7,066			26,811			21,483			7,219			11,812
Transportation and marketing expenses													4,759			—
Midstream service expenses	1,174			1,039			2,986			2,826			1,603			693
Costs of purchased oil	47,385			44,232			141,661			121,190			32,691			60,664
General and administrative	25,000			26,105			72,605			66,058			21,519			24,725
Depletion, depreciation and amortization	41,212			35,158			113,327			110,813			63,098			45,553
Impairment expense	—			—			—			162,027
Other operating expenses	1,443			2,465			3,906			4,169			1,052			1,106
Total costs and expenses	145,366			134,242			417,986			546,486			154,550			166,504
Operating income (loss)	60,452			25,492			163,839			(133,422		)
Operating income													54,397			93,192
Non-operating income (expense):
Gain (loss) on derivatives, net	(27,441		)	6,850			38,127			(43,783		)	(48,365		)	9,010
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		)	(15,547		)	(13,518		)
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		)	(939		)	(2,617		)
Other income, net													867			453
Non-operating expense, net	(49,425		)	(16,007		)	(23,426		)	(108,896		)	(63,984		)	(6,672		)
Income (loss) before income taxes	11,027			9,485			140,413			(242,318		)	(9,587		)	86,520
Income tax:
Income tax benefit:
Deferred	—			—			—			—			96			—
Total income tax	—			—			—			—
Total income tax benefit													96			—
Net income (loss)	$	11,027		$	9,485		$	140,413		$	(242,318	)	$	(9,491	)	$	86,520
Net income (loss) per common share:
Basic	$	0.05		$	0.04		$	0.59		$	(1.09	)	$	(0.04	)	$	0.36
Diluted	$	0.05		$	0.04		$	0.57		$	(1.09	)	$	(0.04	)	$	0.36
Weighted-average common shares outstanding:
Basic	239,306			234,639			239,017			221,303			230,476			238,228
Diluted	244,887			238,108			244,693			221,303			230,476			239,319

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

Laredo Petroleum, Inc.

Consolidated ~~statement~~statements 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, 2018																								233,936			$	2,339		$	2,375,286			—			$	—		$	(1,203,395	)		$	1,174,230
Restricted stock awards	1,213		12			(12		)		—			—			—				—				5,986			60			(60		)		—			—			—				—
Restricted stock forfeitures	(264	)	(3		)	3				—			—			—				—				(48	)		—			—				—			—			—				—
Performance share conversion	150		2			(2		)		—			—			—				—
Vested stock exchanged for tax withholding	—		—			—				545			(7,638		)	—				(7,638		)
Stock exchanged for tax withholding																								—			—			—				683			(2,612		)	—				(2,612		)
Stock exchanged for cost of exercise of stock options																								—			—			—				18			(76		)	—				(76		)
Retirement of treasury stock	(545	)	(5		)	(7,633		)		(545	)		7,638			—				—				(701	)		(7		)	(2,681		)		(701	)		2,688			—				—
Exercise of stock options	44		—			358				—			—			—				358				18			—			76				—			—			—				76
Stock-based compensation	—		—			32,519				—			—			—				32,519				—			—			9,305				—			—			—				9,305
Net income	—		—			—				—			—			140,413				140,413
Balance, September 30, 2017	242,527		$	2,425		$	2,421,469			—			$	—		$	(2,077,669	)		$	346,225
Net loss																								—			—			—				—			—			(9,491		)		(9,491		)
Balance, March 31, 2019																								239,191			$	2,392		$	2,381,926			—			$	—		$	(1,212,886	)		$	1,171,432



	Common Stock					Additional paid-in capital			Treasury Stock (at cost)					Accumulated deficit
	Shares		Amount			Additional paid-in capital			Shares		Amount			Accumulated deficit			Total
Balance, December 31, 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 13.a)	—		—			—			—		—			141,118			141,118
Restricted stock awards	3,052		30			(30		)	—		—			—			—
Restricted stock forfeitures	(13	)	—			—			—		—			—			—
Share repurchases	—		—			—			6,728		(58,475		)	—			(58,475		)
Stock exchanged for tax withholding	—		—			—			512		(4,353		)	—			(4,353		)
Retirement of treasury stock	(7,240	)	(72		)	(62,756		)	(7,240	)	62,828			—			—
Stock-based compensation	—		—			11,441			—		—			—			11,441
Net income	—		—			—			—		—			86,520			86,520
Balance, March 31, 2018	238,320		$	2,383		$	2,380,917		—		$	—		$	(1,441,470	)	$	941,830

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

Laredo Petroleum, Inc.

Consolidated statements of cash flows

(in thousands)

(Unaudited)


	Nine months ended September 30,						Three months ended March 31,
	2017			2016			2019			2018
Cash flows from operating activities:
Net income (loss)	$	140,413		$	(242,318	)	$	(9,491	)	$	86,520
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred income tax benefit							(96		)	—
Depletion, depreciation and amortization	113,327			110,813			63,098			45,553
Impairment expense	—			162,027
Non-cash stock-based compensation, net of amounts capitalized	26,877			19,562
Non-cash stock-based compensation, net							7,406			9,339
Mark-to-market on derivatives:
(Gain) loss on derivatives, net	(38,127		)	43,783			48,365			(9,010		)
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 received (paid) for matured derivatives, net							102			(2,236		)
Change in net present value of derivative deferred premiums	199			184			95			211
Cash premiums paid for derivatives	(13,542		)	(86,972		)
Premiums paid for derivatives							(4,016		)	(4,024		)
Amortization of debt issuance costs	3,132			3,231			846			793
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		)
Amortization of operating lease right-of-use assets							3,056			—
Other, net	3,445			2,973			3,779			4,304
(Increase) decrease in accounts receivable	(2,973		)	6,476			(13,373		)	1,147
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
Decrease in other noncurrent liabilities	(290		)	(297		)
Increase in other current assets							(2,769		)	(2,483		)
Decrease (increase) in other noncurrent assets							57			(100		)
Increase in accounts payable and accrued liabilities							7,140			30,516
Increase in undistributed revenue and royalties							2,889			2,541
Decrease in other current liabilities							(30,637		)	(16,226		)
Increase (decrease) in other noncurrent liabilities							1,007			(374		)
Net cash provided by operating activities	272,051			245,454			77,458			146,471
Cash flows from investing activities:
Capital expenditures:
Acquisitions of oil and natural gas properties	—			(115,600		)
Oil and natural gas properties	(381,165		)	(276,735		)	(152,729		)	(195,025		)
Midstream service assets	(11,680		)	(4,231		)	(2,262		)	(3,362		)
Other fixed assets	(3,604		)	(982		)	(505		)	(3,963		)
Investment in equity method investee (Note 16.a)	(24,572		)	(58,712		)
Proceeds from disposition of equity method investee, net of selling costs							—			1,655
Proceeds from dispositions of capital assets, net of selling costs	64,128			365			43			1,021
Net cash used in investing activities	(356,893		)	(455,895		)	(155,453		)	(199,674		)
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility	155,000			214,682			80,000			55,000
Payments on Senior Secured Credit Facility	(70,000		)	(279,682		)
Proceeds from issuance of common stock, net of offering costs	—			276,052
Purchase of treasury stock	(7,638		)	(1,613		)
Proceeds from exercise of stock options	358			208
Payments for debt issuance costs	(4,732		)	—
Net cash provided by financing activities	72,988			209,647
Share repurchases							—			(53,714		)
Stock exchanged for tax withholding							(2,612		)	(4,353		)
Net cash provided by (used in) financing activities							77,388			(3,067		)
Net decrease in cash and cash equivalents	(11,854		)	(794		)	(607		)	(56,270		)
Cash and cash equivalents, beginning of period	32,672			31,154			45,151			112,159
Cash and cash equivalents, end of period	$	20,818		$	30,360		$	44,544		$	55,889

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~~2018 is derived from audited consolidated financial statements. In the opinion of management, the ~~accompanying~~ unaudited consolidated financial statements reflect all necessary adjustments to present fairly the Company's financial position as of ~~September 30, 2017,~~March 31, 2019 and results of operations ~~for the three and nine months ended September 30, 2017 and 2016~~ and cash flows for each of the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 and ~~2016.~~2018.

Certain disclosures have been condensed or omitted from ~~these~~the unaudited consolidated financial statements. Accordingly, ~~these~~the unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the ~~2016~~2018 Annual Report.

b. Significant accounting policies

See Note 2 in the 2018 Annual Report for discussion of significant accounting policies and Note 3 for those related to the adoption of Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 842, Leases ("ASC 842").

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 use of estimates and assumptions, see Note 2.b in the 2018 Annual Report, Note 3 pertaining to the Company's leases and Note 6.c pertaining to the Company's 2019 performance unit awards.

Note 2—Recently issued or adopted accounting pronouncements

The Company considers the applicability and impact of all accounting standard updates ("ASU") issued by the FASB. The discussion of the ASU listed below was determined to be meaningful to the Company's unaudited consolidated financial statements and footnotes during the three months ended March 31, 2019.

a. Leases

On January 1, 2019, the Company adopted ASC 842 using the modified retrospective approach and applying the optional transition method as of the beginning of the period of adoption. Results for the period beginning after January 1, 2019 are presented under ASC 842, while prior periods are not ~~necessarily indicative~~adjusted and continue to be reported under ASC 840. The Company utilized the transition package of expedients to leases that commenced before the effective date. ASC 842 supersedes previous lease guidance in ASC 840, Leases ("ASC 840"). The core principle of the ~~results~~new guidance is that ~~may be expected for other interim periods or~~a lessee should recognize in the statement of financial position a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the ~~full year.~~

~~Significant estimates include, but are not limited~~lease term related to ~~(i) estimates~~its leases. For leases with a term 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. As12 months or less, a lessee is permitted to make



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

~~fair value is a market-based measurement, it is determined based~~an accounting policy election, by class of underlying asset, not to recognize lease assets and lease liabilities. See Note 3 for further discussion of the ASC 842 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~~statements.

Note 3—Leases

a. Impact of ASC 842 adoption

Prior to ~~conform to the 2017 presentation. These reclassifications had no impact on previously reported balance sheets or stockholders' equity.~~

~~d. Accounts receivable~~

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

The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging and existing industry and economic data. The Company reviews its allowance for doubtful accounts quarterly. Past due amounts greater than 90 days and 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~~

~~The Company uses derivatives to reduce exposure to fluctuations in the prices of oil, NGL and natural gas. By removing a significant portion of the price volatility associated with future production,~~January 1, 2019, the Company ~~expects to mitigate, but~~accounted for leases under ASC 840 and did not ~~eliminate,~~record any right-of-use assets or corresponding lease liabilities. Upon the ~~potential effects~~adoption of ~~variability~~ASC 842 on January 1, 2019, the Company recognized $22.1 million in ~~cash flows from operations due to fluctuations~~operating lease right-of-use assets and $25.3 million 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~~operating lease liabilities on the unaudited consolidated balance sheets for operating leases with a term greater than 12 months. The difference between the two balances of $3.2 million is mainly due to free rent and lease build-out incentives that were recorded as ~~assets and/or liabilities.~~deferred lease liabilities under ASC 840. These deferred lease liabilities are subtracted from the right-of-use asset opening balance under ASC 842. 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. Inputstransition did not result ina material impact 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.

~~The Company's derivatives were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in~~ the unaudited consolidated statements of operations nor was there a related impact to the unaudited consolidated statements of stockholders' equity.

The Company utilized the modified retrospective approach in adopting the new standard and applied the optional transition method as of the beginning of the period of ~~change. Gains~~adoption, along with the transition package of practical expedients, and ~~losses~~implemented certain accounting policy decisions which include: (i) short-term lease recognition exemption, (ii) establishing a balance sheet recognition capitalization threshold, (iii) not evaluating existing or expired land easements that were not previously accounted for as leases under ASC 840 and (iv) accounting for certain asset classes at a portfolio level by not separating the lease and non-lease components and accounting for the agreement as a single lease component.

The Company determines whether a contract is or contains a lease at inception of the contract, based on ~~derivatives~~answers to a series of questions that address whether an identified asset exists and whether the Company has the right to obtain substantially all of the benefit of the asset and to control its use over the full term of the agreement. When available, the Company uses the rate implicit in the lease to discount lease payments to present value; however, most of the Company's leases do not provide a readily determinable implicit rate, In such cases, the Company is required to use its incremental borrowing rate ("IBR"). The Company determines its IBR using both a "credit notching" approach and a "recovery method" approach. The results of these approaches are then weighted equally and averaged in order to determine the concluded IBR. This concluded IBR is utilized to discount the lease payments based on information available at lease commencement. There are no material residual value guarantees, nor any restrictions or covenants included in the Company's lease agreements.

Mineral leases, including oil and natural gas leases granting the right to explore for those natural resources and rights to use the land in which those natural resources are contained, are not included in the scope of ASC 842.

The Company has recognized in the unaudited consolidated balance sheets leases of commercial real estate with lease terms extending through 2027 and drilling, completion, production and other equipment leases with lease terms extending through 2020. We have various other drilling, completion and production equipment leases on a short-term basis reflected in our short-term lease costs.

Certain of the Company's leases include provisions for variable payments. These variable payments are typically determined based on a measure of throughput, actual days or another measure of usage and are not included in the calculation of lease liabilities and right-of-use assets. For our drilling rigs, the variable lease costs include the payments that depend on the performance or usage of the underlying asset, the costs to move and the costs to repair the drilling rigs. For certain of our commercial office buildings, utilities and common area maintenance charges are variable and are included as an operating lease expense. For our equipment leases, the variable lease cost is the amount incurred under our contracts that are beyond the minimum rental fee, inclusive of maintenance.

The Company's short-term lease costs include those that are recognized in ~~cash flows from operating activities. See Notes 7~~net income (loss) during the period and ~~8.a for discussion regarding~~capitalized as part of the cost of another asset in accordance with other GAAP. The costs related to drilling, completion and production activities are reflected at the Company's ~~derivatives.~~net ownership, which is consistent with the principals of proportional consolidation, and lease commitments are reflected on a gross basis. As of March 31, 2019, the Company had an average working interest of 97% in all Laredo-operated currently producing wells in its core operating area.

The Company does not have any significant finance leases.

Certain of the Company's lease asset classes include options to renew on a month-to-month basis. The Company considers contract-based, asset-based, market-based, and entity-based factors to determine the term over which it is reasonably certain to extend the lease in determining its right-of-use assets and liabilities.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

~~f. Other current assets~~The Company's material leases do not include options to purchase the leased property.

Of the Company's commercial leases, the Company subleases certain office space to third parties where it is the primary obligor under the head lease. The lease terms on those subleases each contain renewal options that do not extend past the term of the head lease. The subleases do not contain residual value guarantees. Sublease income is recognized based on the contract terms and, ~~liabilities~~upon the adoption of ASC 842, is included as a reduction of lease expense under our head lease.

Lease costs

The table below presents certain information related to the lease costs for the Company's operating leases for the period presented:



(in thousands)	Three months ended March 31, 2019
Components of total lease cost:
Operating lease cost	$	3,528
Short-term lease cost	46,326
Variable lease cost	518
Sublease income	(247		)
Total lease cost	$	50,125

Other ~~current assets consisted~~information

See Note 11 for disclosure of cash paid for amounts included in the ~~following components~~measurement of lease liabilities and supplemental non-cash adjustments. See Note 15 for disclosure of related-party lease amounts.

Lease terms and discount rates

The table below presents certain information related to the weighted-average remaining lease term and weighted-average discount rate for the Company's operating leases as of the ~~dates~~date presented:

(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)~~	~~See Note 2.i for discussion of inventory held by the Company.~~	March 31, 2019
Operating leases:
Weighted-average remaining lease term		4.00 years
Weighted-average discount rate		8.28	%

~~Other current~~



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Maturities of operating lease liabilities ~~consisted~~

The table below reconciles the undiscounted cash flows for each of the ~~following components~~first five years and the total remaining years to the operating lease liabilities recorded on the unaudited consolidated balance sheet as of the ~~dates~~date presented:



(in thousands)	March 31, 2019
Operating leases:
Remaining 2019	$	12,260
2020	3,331
2021	3,029
2022	2,360
2023	1,252
Thereafter	4,243
Total minimum lease payments	26,475
Less: lease liability expense	(4,278		)
Present value of future minimum lease payments	22,197
Less: current obligations under leases	(10,896		)
Long-term lease obligations	$	11,301

Disclosure for the period prior to adoption of ASC 842

The Company leases office space under operating leases expiring on various dates through 2027. The following table presents future minimum rental payments required:



(in thousands)	December 31, 2018
2019	$	3,092
2020	3,179
2021	3,128
2022	2,560
2023	1,358
Thereafter	4,556
Total future minimum rental payments required	$	17,873

The Company subleases office space with $5.9 million of total future minimum rentals to be received as of December 31, 2018. For the period prior to the adoption of ASC 842, rent income is included in "Other income, net" on the unaudited consolidated statements of operations.



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)

Note 4—Property and equipment

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



(in thousands)	March 31, 2019			December 31, 2018
Evaluated oil and natural gas properties	$	6,951,343		$	6,752,631
Less accumulated depletion and impairment	(4,913,384		)	(4,854,017		)
Evaluated oil and natural gas properties, net	2,037,959			1,898,614

Unevaluated oil and natural gas properties not being depleted	92,467			130,957

Midstream service assets	175,681			172,308
Less accumulated depreciation and impairment	(44,563		)	(42,063		)
Midstream service assets, net	131,118			130,245

Depreciable other fixed assets	45,591			45,431
Less accumulated depreciation and amortization	(24,752		)	(23,871		)
Depreciable other fixed assets, net	20,839			21,560

Land	18,259			18,259

Total property and equipment, net	$	2,300,642		$	2,199,635

(in thousands) September 30, 2017 December 31, 2016
Evaluated oil and natural gas properties $ 5,863,536
$ 5,488,756
Less accumulated depletion and impairment (4,616,246 ) (4,514,183 )
Evaluated oil and natural gas properties, net 1,247,290
974,573

Unevaluated properties not being depleted 211,720
221,281

Midstream service assets 161,144
150,629
Less accumulated depreciation and impairment (30,737 ) (24,389 )
Midstream service assets, net 130,407
126,240

Depreciable other fixed assets 50,767
52,491
Less accumulated depreciation and amortization (23,779 ) (22,632 )
Depreciable other fixed assets, net 26,988
29,859

Land 14,914
14,914

Total property and equipment, net $ 1,631,319
$ 1,366,867

For the three months ended ~~September 30, 2017~~March 31, 2019 and ~~2016,~~2018, depletion expense for the Company's evaluated oil and natural gas properties was ~~$6.80~~$8.76 per barrel of oil equivalent ("BOE") sold and ~~$6.71 per BOE sold, respectively. For the nine months ended September 30, 2017 and 2016, depletion expense was $6.57 per BOE sold and $7.55~~$7.34 per BOE sold, respectively.

The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs incurred for the purpose of exploring for 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 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~~related employee costs incurred for the purpose of exploring for or developing oil and natural gas properties for the periods presented:



	Three months ended March 31,
(in thousands)	2019		2018
Capitalized related employee costs	$	6,682	$	6,529

Three months ended September 30, Nine months ended September 30,
(in thousands) 2017 2016 2017 2016
Capitalized employee-related costs $ 6,938
$ 6,149
$ 17,911
$ 12,598

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 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



	Three months ended March 31,
(in thousands)	2019		2018
Property acquisition costs:
Evaluated	$	—	$	—
Unevaluated	—		—
Exploration costs	7,505		6,137
Development costs	152,717		149,038
Total costs incurred	$	160,222	$	155,175


~~(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.~~

Note 4—5—Debt

a. March 2023 Notes

On March 18, 2015, the Company completed an offering of $350.0 million in aggregate principal amount of 6 1/4% senior unsecured notes due 2023 (the "March 2023 Notes"). The March 2023 Notes will mature on March 15, 2023 and bear an interest rate of 6 1/4% per annum, payable semi-annually, in cash in arrears on March 15 and September 15 of each year, commencing September 15, 2015. The March 2023 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain automatic customary releases, including the sale, disposition or transfer of all of the capital stock or of all or substantially all of the assets of a subsidiary guarantor to one or more persons that are not the Company or a restricted subsidiary, exercise of legal defeasance or covenant defeasance options or satisfaction and discharge of the applicable indenture, designation of a subsidiary guarantor as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the applicable indenture, release from guarantee under the Senior Secured Credit Facility, or liquidation or dissolution (collectively, the "Releases"). The Company may redeem, at its option, all or part of the March 2023 Notes ~~are callable by the Company beginning March 15, 2018~~at any time at a price of ~~104.688%~~103.125% 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 January 15, 2017~~at any time at a price of ~~104.219%~~101.406% 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 million~~ in aggregate principal amount of 7 3/8% senior unsecured notes due 2022 (the "May 2022 Notes"). The May 2022 Notes will mature on May 1, 2022 and bear an interest rate of 7 3/8% per annum, payable semi-annually, in cash in arrears on May 1 and November 1 of each year, commencing November 1, 2012. The May 2022 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases. The May 2022 Notes became callable by the Company on May 1, 2017 at 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 of the outstanding $500.0 million in aggregate principal amount of the May 2022 Notes subsequent to September 30, 2017.~~

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 ~~September 30, 2017,~~March 31, 2019, the 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, with ~~$155.0~~$270.0 million outstanding and was subject to an interest rate of ~~3.25%~~3.75%. 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 not been redeemed or refinanced on or prior to the date 90 days before their respective stated maturity dates (as applicable, the "Early Maturity Date"), 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 portion of the financial institutions' commitment of 0.375% to 0.5%, based on the ratio of outstanding revolving credit to the total commitment under the Senior Secured Credit Facility.for all periods presented. 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~~$80.0 million. As of March 31, 2019 and December 31, 2018, the Company had one letter of credit ~~were~~ outstanding as of ~~September 30, 2017 or 2016.~~$14.7 million under the Senior Secured Credit Facility. For additional information see Note 7.d in the 2018 Annual Report. See Note ~~16.b~~17.a for discussion of ~~additional borrowings on and~~ the ~~repayment~~regular semi-annual borrowing base redetermination of the Senior Secured Credit Facility subsequent to ~~September 30, 2017.~~March 31, 2019.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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

~~e. Fair value of debt~~

~~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:~~

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 30, 2017 and December 31, 2016 quoted market price (Level 1) for each respective instrument. The fair values of the outstanding debt on the Senior Secured Credit Facility as of September 30, 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.

f.d. 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							March 31, 2019							December 31, 2018
(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	$	(2,766	)	$	447,234	$	450,000	$	(3,010	)	$	446,990
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		(3,153		)	346,847		350,000		(3,354		)	346,646
Senior Secured Credit Facility⁽¹⁾	155,000		—			155,000		70,000		—			70,000		270,000		—			270,000		190,000		—			190,000
Total	$	1,455,000	$	(14,032	)	$	1,440,968	$	1,370,000	$	(16,091	)	$	1,353,909	$	1,070,000	$	(5,919	)	$	1,064,081	$	990,000	$	(6,364	)	$	983,636

______________________________________________________________________________


(1)	Debt issuance costs, net related to our Senior Secured Credit Facility of ~~$6.4~~$6.6 million and ~~$2.7~~$7.0 million as of ~~September 30, 2017~~March 31, 2019 and December 31, ~~2016,~~2018, respectively, are reported in "Other noncurrent assets, net" on the unaudited consolidated balance sheets.

Note ~~5—Employee compensation~~6—Stockholders' equity and Equity Incentive Plan

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 share repurchases 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 year ended December 31, 2018, the Company ~~has~~repurchased 11,048,742 shares of common stock at a ~~Long-Term~~weighted-average price of $8.78 per common share for a total of $97.1 million under this program. All shares were retired upon repurchase. There were no share repurchases under this program during the three months ended March 31, 2019.

b. Treasury stock

Treasury stock is recorded at cost, which includes incremental direct transaction costs, and is retired upon acquisition as a result (i) from share repurchases under the share repurchase program, (ii) from the withholding of shares of stock to satisfy tax withholding obligations that arise upon the lapse of restrictions on restricted stock awards and the exercise of stock options at the awardee's election and (iii) share repurchases to cover the cost of the exercise of stock options at the awardee's election.

c. Equity Incentive Plan

The Laredo Petroleum, Inc. Omnibus Equity Incentive Plan (the ~~"LTIP"~~"Equity Incentive Plan")~~, 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~~Equity Incentive Plan provides for the issuance of up to 24,350,000 shares of Laredo's common stock. On March 20, 2019, the Company's compensation committee recommended, and the Company's board of directors adopted, subject to stockholder approval, an amendment (the "Second Amendment") to the Equity Incentive Plan to, among other things, increase the number of shares of common stock available for issuance under the Equity Incentive Plan by 5,500,000 shares, which would bring the total available shares to issue to 29,850,000. The Company is seeking stockholder approval of the Second Amendment at its 2019 Annual Meeting of Stockholders on May 16, 2019.

The Company recognizes the fair value of stock-based compensation awards and performance unit 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,~~awards and ~~in prior periods, its performance unit awards were accounted for as liability awards. Stock-based compensation is~~are included in "General and administrative" inon the unaudited consolidated statements of operations. The Company's performance unit awards are accounted for as liability awards and are included in "General and administrative" on the unaudited consolidated statements of operations and the corresponding liabilities are included in "Other noncurrent liabilities" on the unaudited consolidated balance sheets. The Company capitalizes a portion of stock-based compensation and performance unit award 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 and performance unit award compensation is included ~~as an addition to "Oil and natural gas~~in "Evaluated 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~~that mainly include (i) 33%, 33% and 34% per year beginning on the first anniversary ~~date~~ of the grant date and (ii) fully on the first anniversary of the grant ~~date and (iii) fully on the third anniversary of the grant~~ date. ~~Beginning August 2017, stock~~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~~three months ended ~~September 30, 2017:~~March 31, 2019:


(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, 2018					4,196		$	9.91
Granted	1,213		$	13.92	5,986		$	3.43
Forfeited	(264	)	$	12.88	(48	)	$	6.25
Vested⁽¹⁾	(1,618	)	$	13.78	(2,261	)	$	10.05
Outstanding as of September 30, 2017	3,209		$	12.82
Outstanding as of March 31, 2019					7,873		$	4.96

_____________________________________________________________________________


(1)	The total intrinsic value of vested restricted stock awards for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 was ~~$22.5~~$8.6 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 30, 2017,~~March 31, 2019, unrecognized stock-based compensation related to the restricted stock awards expected to vest was ~~$26.7~~$34.3 million. Such cost is expected to be recognized over a weighted-average period of ~~1.73~~2.34 years.

b. Stock option awards

Stock option awards granted under the ~~LTIP~~Equity Incentive Plan 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 March 31, 2019, the 2,466,022 outstanding stock option awards have a weighted-average exercise price of $12.64 per award ~~activity for~~and a weighted-average remaining contractual term of 3.05 years. There were de minimis exercises and expirations or cancellations of stock option awards during the ~~nine~~three months ended ~~September 30, 2017:~~March 31, 2019. There were no grants or forfeits of stock option awards during the three months ended March 31, 2019.

(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



~~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,~~March 31, 2019, unrecognized stock-based compensation related to stock option awards expected to vest was ~~$9.4~~$3.0 million. Such cost is expected to be recognized over a weighted-average period of ~~2.52~~1.35 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~~which the Company has determined are equity awards, are subject to a combination of market, performance and service vesting criteria. AFor awards with market criteria or portions of awards with market criteria, which include: (i) the 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) the Company's absolute three-year total shareholder return ("ATSR Appreciation") and (iii) the Company's total shareholder return ("TSR"), a Monte Carlo simulation prepared by an independent third party is utilized to determine the ~~grant date~~grant-date fair value ~~of these awards. The Company has determined these awards are equity awards~~ and ~~recognizes~~ the associated expense is recognized on a straight-line basis over the three-year requisite service period of the awards. ~~Any~~For portions of awards with performance criteria, which is the Company's three-year return on average capital employed ("ROACE Percentage"), the grant-date fair value is equal to the Company's closing stock price on the grant date, and for each reporting period, the associated expense fluctuates and is adjusted based on an estimated probability of how many shares are to be awarded for the three-year performance period. Such estimated shares, if earned, ~~under such 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~~three months ended ~~September 30, 2017:~~March 31, 2019:



(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, 2018	3,436		$	13.74
Vested⁽¹⁾	(1,503	)	$	17.68
Outstanding as of March 31, 2019	1,933		$	10.68

______________________________________________________________________________

(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
Granted 696
$ 18.96
Forfeited (67 ) $ 18.12
Vested⁽¹⁾
(200 ) $ 28.56
Outstanding as of September 30, 2017 2,754
$ 17.77

(1)

~~These~~The performance share awards granted on May 25, 2016 had a performance period of January 1, ~~2014~~2016 to December 31, ~~2016~~2018 and, as their ~~vesting and performance~~market criteria were not satisfied, ~~each award~~resulted in a TSR modifier of 0% based on the Company finishing in the ninth percentile of its peer group for relative TSR. As such, the granted units lapsed and were not converted into ~~0.75 shares representing 150,388 shares of~~the Company's common stock ~~issued~~ during the first quarter of ~~2017.~~2019.

As of ~~September 30, 2017,~~March 31, 2019, unrecognized stock-based compensation related to the performance share awards expected to vest was ~~$25.2~~$9.1 million. Such cost is expected to be recognized over a weighted-average period of ~~1.77~~1.56 years.

Stock-based compensation expense

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



	Three months ended March 31,
(in thousands)	2019			2018
Restricted stock award compensation	$	5,323		$	6,045
Stock option award compensation	818			1,069
Performance share award compensation	3,164			4,327
Total stock-based compensation, gross	9,305			11,441
Less amounts capitalized in evaluated oil and natural gas properties	(1,899		)	(2,102		)
Total stock-based compensation, net	$	7,406		$	9,339

See Note 17.d for discussion of the Company's workforce reduction subsequent to March 31, 2019.

Performance unit awards

Performance unit awards, which the Company has determined are liability awards, are subject to a combination of market, performance and service vesting criteria and can be settled in cash, stock or a combination of cash and stock at the election of the Company's board of directors. For portions of awards with market criteria, which include the RTSR Performance Percentage (as defined above) and the ATSR Appreciation (as defined above), a Monte Carlo simulation prepared by an independent third party is utilized to determine the grant-date fair value and is re-measured on the last day of each reporting period until settlement, with the associated expense adjusted, in accordance with GAAP. For portions of awards with performance criteria, which is the ROACE Percentage (as defined above), the grant-date fair value is equal to the Company's closing stock price on the grant date, and subsequently the fair value is equal to the Company's closing stock price on the last day of each reporting period until settlement, with the associated expense adjusted, in accordance with GAAP. Additionally, the associated expense related to awards with performance criteria fluctuates and is adjusted based on an estimated probability of payout that will be awarded for the three-year performance period as of the last day of each reporting period until settlement. The performance unit award compensation expense is recognized on a straight-line basis over the three-year requisite service period of the awards. These awards are accounted for as liability awards as the current election by the Company's board of directors is to settle the awards in cash, and if earned, are expected to be paid 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 unit award activity for the three months ended March 31, 2019:



(in thousands)		Performance unit awards
Outstanding as of December 31, 2018		—
Granted⁽¹⁾		2,813
Outstanding as of March 31, 2019		2,813

______________________________________________________________________________

(1)

The amount potentially payable in cash at the end of the requisite service period for the performance unit awards granted on February 28, 2019 will be determined based on three criteria: (i) RTSR Performance Percentage, (ii) ATSR Appreciation and (iii) 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 value of each performance unit granted at the maturity date. 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. These awards have a performance period of January 1, 2019 to December 31, 2021.

As of March 31, 2019, unrecognized performance unit award compensation related to the performance unit awards expected to vest was $8.2 million. Such cost is expected to be recognized over a weighted-average period of 2.92 years.

The assumptions used to estimate the fair ~~values~~value of the ~~696,460~~ performance ~~share~~unit awards ~~granted during~~as of the ~~nine months ended September 30, 2017~~date presented are as follows:



	March 31, 2019⁽¹⁾
(.25) RTSR Factor + (.25) ATSR Factor fair value assumptions:
Remaining performance period	2.76 years
Risk-free interest rate⁽²⁾	2.20		%
Dividend yield	—		%
Expected volatility⁽³⁾	55.13		%
Closing stock price on March 29, 2019	$	3.09
Fair value per performance unit award (market criteria)	$	3.18

(.50) ROACE Factor fair value assumption:
Closing stock price on March 29, 2019	$	3.09
Fair value per performance unit award (performance criteria)	$	3.09

Combined fair value per performance unit award	$	3.14

______________________________________________________________________________

Granted on
February 17, 2017
Risk-free interest rate⁽¹⁾
1.44 %
Dividend yield — %
Expected volatility⁽²⁾
74.00 %
Laredo stock closing price on grant date $ 14.12
Fair value per performance share award $ 18.96

(1)

The $3.14 per unit fair value consists of a (i) $3.18 per unit fair value, determined utilizing a Monte Carlo simulation on March 31, 2019, for the combined (.25) RTSR Factor and (.25) ATSR Factor and (ii) $3.09 per unit 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 March 29, 2019 and based on a 100% estimated probability of payout to be awarded for the three-year performance period as of March 31, 2019.


(2)	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.~~March 29, 2019.


~~(2)~~(3)	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.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

~~Note 6—Income taxes~~Performance unit award compensation expense

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~~ ~~$1.9 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, the Company believes a portion of the net operating loss carry-forwards are not fully realizable. The Company considered all available evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance was needed. Such consideration included 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 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 millionfollowing has been recorded ~~against~~to performance unit award compensation expense for the ~~Company's deferred tax position.~~periods presented:



	Three months ended March 31,
(in thousands)	2019			2018
Performance unit award compensation, gross	$	238		$	—
Less amounts capitalized in evaluated oil and natural gas properties	(46		)	—
Total performance unit award compensation, net	$	192		$	—

Note 7—Derivatives

~~a. Derivatives~~

~~The~~Due to the inherent volatility in oil, NGL and natural gas prices, commodity transportation costs and differences in the prices of oil, NGL and natural gas between where the Company produces and where the Company sells such commodities, the Company engages in derivative transactions, such as puts, swaps, collars and basis swaps ~~and call spreads~~ to hedge price ~~risks due to unfavorable changes in oil, NGL and natural gas prices related to its~~risk associated with a portion of the Company's anticipated production. AsBy removing a portion of ~~September 30, 2017,~~the price volatility associated with future production, the Company ~~had~~ 44 ~~open derivative contracts with financial institutions that extend~~expects to mitigate, but not eliminate, the potential effects of variability in cash flows from ~~October 2017 to December 2019. None~~operations. See Notes 2.f and 9 in the 2018 Annual Report for discussion of ~~these contracts were designated as hedges~~the Company's accounting policies for ~~accounting purposes. The contracts are recorded at fair value~~derivatives and information on the ~~unaudited consolidated balance sheets~~transaction types 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.~~settlement indexes, respectively.

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~~The following table summarizes open derivative positions as of March 31, 2019, for derivatives ~~are settled based on the month's average daily NYMEX index price~~that were entered into through March 31, 2019, for the first nearby month of the West Texas Intermediate Light Sweet Crude Oil Futures Contract. The oil basis swaps are settled based on the swaps' differential between the Argus Americas Crude West Texas Intermediate ("WTI") index prices for WTI Midland-weighted average and WTI Cushing-WTI formula basis price less the differential price for the trade month. The Company's NGL derivatives are settled based on the month's average daily OPIS index price for Mont Belvieu Purity Ethane and TET Propane. The Company's natural gas derivatives are settled based on the Inside FERC index price for West Texas WAHA for the calculation period.settlement periods presented:



	Remaining year 2019			Year 2020		Year 2021
Oil:
Puts:
Volume (Bbl)	6,050,000			366,000		—
Weighted-average floor price ($/Bbl)	$	47.45		$	45.00	$	—
Volume with deferred premium (Bbl)	3,575,000			—		—
Weighted-average deferred premium price ($/Bbl)	$	3.21		$	—	$	—
Swaps:
Volume (Bbl)	495,000			695,400		—
Weighted-average price ($/Bbl)	$	53.45		$	52.18	$	—
Collars:
Volume (Bbl)	—			1,134,600		912,500
Weighted-average floor price ($/Bbl)	$	—		$	45.00	$	45.00
Weighted-average ceiling price ($/Bbl)	$	—		$	76.13	$	71.00
Totals:
Total volume with floor price (Bbl)	6,545,000			2,196,000		912,500
Weighted-average floor price ($/Bbl)	$	47.91		$	47.27	$	45.00
Total volume with ceiling price (Bbl)	495,000			1,830,000		912,500
Weighted-average ceiling price ($/Bbl)	$	53.45		$	67.03	$	71.00
Basis Swaps:
WTI Midland to WTI NYMEX:
Volume (Bbl)	1,840,000			—		—
Weighted-average price ($/Bbl)	$	(2.89	)	$	—	$	—
WTI Midland to WTI formula basis:
Volume (Bbl)	552,000			—		—
Weighted-average price ($/Bbl)	$	(4.37	)	$	—	$	—
WTI Houston to WTI Midland:
Volume (Bbl)	910,000			—		—
Weighted-average price ($/Bbl)	$	7.30		$	—	$	—
NGL:
Swaps - Purity Ethane:
Volume (Bbl)	1,787,500			366,000		912,500
Weighted-average price ($/Bbl)	$	14.22		$	13.60	$	12.01
Swaps - Non-TET Propane:
Volume (Bbl)	1,430,000			1,244,400		730,000
Weighted-average price ($/Bbl)	$	27.97		$	26.58	$	25.52
Swaps - Non-TET Normal Butane:
Volume (Bbl)	550,000			439,200		255,500
Weighted-average price ($/Bbl)	$	30.73		$	28.69	$	27.72
Swaps - Non-TET Isobutane:
Volume (Bbl)	137,500			109,800		67,525
Weighted-average price ($/Bbl)	$	31.08		$	29.99	$	28.79
Swaps - Non-TET Natural Gasoline:
Volume (Bbl)	467,500			402,600		237,250
Weighted-average price ($/Bbl)	$	45.80		$	45.15	$	44.31
TABLE CONTINUES ON NEXT PAGE

During the nine months ended September 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

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)



	Remaining year 2019			Year 2020			Year 2021
Total NGL volume (Bbl)	4,372,500			2,562,000			2,202,775
Natural gas:
Henry Hub NYMEX Swaps:
Volume (MMBtu)	29,425,000			23,790,000			14,052,500
Weighted-average price ($/MMBtu)	$	3.09		$	2.72		$	2.63
Basis Swaps:
Volume (MMBtu)	29,425,000			32,574,000			23,360,000
Weighted-average price ($/MMBtu)	$	(1.51	)	$	(0.76	)	$	(0.47	)

~~The following represents cash settlements received for derivatives, net~~See Note 8.a for the ~~periods presented:~~fair value measurement of derivatives. See Note 17.c for the Company's subsequent hedge restructuring and corresponding summary of open derivative positions as of March 31, 2019 for derivative terminations and trade activity through May 1, 2019.

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.~~



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note 8—Fair value measurements

See Note 10 in the 2018 Annual Report for discussion of the Company's accounting policies for fair value measurements.

a. Fair value measurement on a recurring basis

The following ~~table summarizes open positions~~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 included in "Derivatives" on the unaudited consolidated balance sheets as of ~~September 30, 2017, and represents, as of such date, derivatives in place through December 2019 on annual production:~~the dates presented:

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)	Level 1		Level 2			Level 3			Total gross fair value			Amounts offset			Net fair value presented on the unaudited consolidated balance sheets
As of March 31, 2019:
Assets:
Current:
Oil derivatives	$	—	$	4,911		$	—		$	4,911		$	(5,242	)	$	(331	)
NGL derivatives	—		7,541			—			7,541			(6,210		)	1,331
Natural gas derivatives	—		19,694			—			19,694			(5,943		)	13,751
Oil derivative deferred premiums	—		—			—			—			(7,141		)	(7,141		)
Noncurrent:
Oil derivatives	$	—	$	2,432		$	—		$	2,432		$	(646	)	$	1,786
NGL derivatives	—		2,518			—			2,518			(1,506		)	1,012
Natural gas derivatives	—		3,446			—			3,446			(274		)	3,172
Oil derivative deferred premiums	—		—			—			—			—			—
Liabilities:
Current:
Oil derivatives	$	—	$	(11,996	)	$	—		$	(11,996	)	$	5,242		$	(6,754	)
NGL derivatives	—		(5,871		)	—			(5,871		)	6,210			339
Natural gas derivatives	—		(5,082		)	—			(5,082		)	5,943			861
Oil derivative deferred premiums	—		—			(12,644		)	(12,644		)	7,141			(5,503		)
Noncurrent:
Oil derivatives	$	—	$	(2,991	)	$	—		$	(2,991	)	$	646		$	(2,345	)
NGL derivatives	—		(3,916		)	—			(3,916		)	1,506			(2,410		)
Natural gas derivatives	—		918			—			918			274			1,192
Oil derivative deferred premiums	—		—			—			—			—			—
Net derivative asset (liability) positions	$	—	$	11,604		$	(12,644	)	$	(1,040	)	$	—		$	(1,040	)



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

~~b. Balance sheet presentation~~



(in thousands)	Level 1		Level 2			Level 3			Total gross fair value			Amounts offset			Net fair value presented on the unaudited consolidated balance sheets
As of December 31, 2018:
Assets:
Current:
Oil derivatives	$	—	$	44,425		$	—		$	44,425		$	(7,907	)	$	36,518
NGL derivatives	—		1,974			—			1,974			—			1,974
Natural gas derivatives	—		18,991			—			18,991			(3,267		)	15,724
Oil derivative deferred premiums	—		—			—			—			(14,381		)	(14,381		)
Noncurrent:
Oil derivatives	$	—	$	10,626		$	—		$	10,626		$	—		$	10,626
NGL derivatives	—		1,024			—			1,024			—			1,024
Natural gas derivatives	—		108			—			108			(728		)	(620		)
Oil derivative deferred premiums	—		—			—			—			—			—
Liabilities:
Current:
Oil derivatives	$	—	$	(9,059	)	$	—		$	(9,059	)	$	7,907		$	(1,152	)
NGL derivatives	—		—			—			—			—			—
Natural gas derivatives	—		(7,290		)	—			(7,290		)	3,267			(4,023		)
Oil derivative deferred premiums	—		—			(16,565		)	(16,565		)	14,381			(2,184		)
Noncurrent:
Oil derivatives	$	—	$	—		$	—		$	—		$	—		$	—
NGL derivatives	—		—			—			—			—			—
Natural gas derivatives	—		(728		)	—			(728		)	728			—
Oil derivative deferred premiums	—		—			—			—			—			—
Net derivative asset (liability) positions	$	—	$	60,071		$	(16,565	)	$	43,506		$	—		$	43,506

~~In accordance~~Significant Level 2 inputs associated with the Company's standard practice, its derivatives are subject to counterparty netting under their governing agreements. The Company's oil, NGL and natural gas derivatives are presented on a net basis as "Derivatives" on the unaudited consolidated balance sheets. See Note 8.a for a summarycalculation of discounted cash flows used in the fair value mark-to-market analysis of derivatives ~~on a gross basis.~~

~~By using derivatives to hedge exposures to changes in~~include each derivative contract's corresponding commodity ~~prices, the Company exposes itself to credit risk~~index price(s), appropriate risk-adjusted discount rates and ~~market risk. For the Company, market risk is the exposure to changes in the market~~forward price of oil, NGL and natural gas, which are subject to fluctuations from a variety of factors, including changes in supply and demand. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, thereby creating credit risk. The Company's counterparties are participants in the Senior Secured Credit Facility, which is secured by the Company's oil, NGL and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from its derivative counterparties. The Company minimizes the credit risk in derivatives by: (i) limiting its exposure to any single counterparty, (ii) entering into derivatives only with counterparties that meet the Company's minimum credit quality standard or have a guarantee from an affiliate that meets the Company's minimum credit quality standard and (iii) monitoring the creditworthiness of the Company's counterparties on an ongoing basis.

~~Note 8—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~~curve models for substantially 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~~instruments generated from a compilation of data gathered from third parties.

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

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



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

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

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

When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on an annual basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. Transfers between fair value hierarchy levels are recognized and reported in the period in which the transfer occurred. No transfers between fair value hierarchy levels occurred during the nine months ended September 30, 2017 or 2016.



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

(in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the unaudited consolidated balance sheets
As of September 30, 2017:
Assets
Current:
Oil derivatives $ —
$ 27,097
$ —
$ 27,097
$ (8,732 ) $ 18,365
NGL derivatives —
—
—
—
—
—
Natural gas derivatives —
4,955
—
4,955
(4,955 ) —
Oil deferred premiums —
—
—
—
(2,754 ) (2,754 )
Natural gas deferred premiums —
—
—
—
—
—
Noncurrent:
Oil derivatives $ —
$ 12,471
$ —
$ 12,471
$ (4,052 ) $ 8,419
NGL derivatives —
—
—
—
—
—
Natural gas derivatives —
1,277
—
1,277
(256 ) 1,021
Oil deferred premiums —
—
—
—
(4,376 ) (4,376 )
Natural gas deferred premiums —
—
—
—
(719 ) (719 )
Liabilities
Current:
Oil derivatives $ —
$ (1,556 ) $ —
$ (1,556 ) $ 8,732
$ 7,176
NGL derivatives —
(1,509 ) —
(1,509 ) —
(1,509 )
Natural gas derivatives —
—
—
—
4,955
4,955
Oil deferred premiums —
—
(14,277 ) (14,277 ) 2,754
(11,523 )
Natural gas deferred premiums —
—
(3,269 ) (3,269 ) —
(3,269 )
Noncurrent:
Oil derivatives $ —
$ (121 ) $ —
$ (121 ) $ 4,052
$ 3,931
NGL derivatives —
—
—
—
—
—
Natural gas derivatives —
—
—
—
256
256
Oil deferred premiums —
—
(8,810 ) (8,810 ) 4,376
(4,434 )
Natural gas deferred premiums —
—
(834 ) (834 ) 719
(115 )
Net derivative position $ —
$ 42,614
$ (27,190 ) $ 15,424
$ —
$ 15,424



~~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
As of December 31, 2016:
Assets
Current:
Oil derivatives $ —
$ 22,527
$ —
$ 22,527
$ —
$ 22,527
NGL derivatives —
—
—
—
—
—
Natural gas derivatives —
270
—
270
(270 ) —
Oil deferred premiums —
—
—
—
(1,580 ) (1,580 )
Natural gas deferred premiums —
—
—
—
—
—
Noncurrent:
Oil derivatives $ —
$ 8,718
$ —
$ 8,718
$ —
$ 8,718
NGL derivatives —
—
—
—
—
—
Natural gas derivatives —
1,377
—
1,377
(1,377 ) —
Oil deferred premiums —
—
—
—
—
—
Natural gas deferred premiums —
—
—
—
—
—
Liabilities
Current:
Oil derivatives $ —
$ (9,789 ) $ —
$ (9,789 ) $ —
$ (9,789 )
NGL derivatives —
(2,803 ) —
(2,803 ) —
(2,803 )
Natural gas derivatives —
(3,639 ) —
(3,639 ) 270
(3,369 )
Oil deferred premiums —
—
(3,569 ) (3,569 ) 1,580
(1,989 )
Natural gas deferred premiums —
—
(3,043 ) (3,043 ) —
(3,043 )
Noncurrent:
Oil derivatives $ —
$ (4,552 ) $ —
$ (4,552 ) $ —
$ (4,552 )
NGL derivatives —
—
—
—
—
—
Natural gas derivatives —
(133 ) —
(133 ) 1,377
1,244
Oil deferred premiums —
—
—
—
—
—
Natural gas deferred premiums —
—
(2,386 ) (2,386 ) —
(2,386 )
Net derivative position $ —
$ 11,976
$ (8,998 ) $ 2,978
$ —
$ 2,978

These items are included as "Derivatives" on the unaudited consolidated balance sheets. Significant Level 2 assumptions associated with the calculation of discounted cash flows used in the mark-to-market analysis of derivatives include each derivative contract's corresponding commodity index price, appropriate risk-adjusted discount rates and other relevant data.

The Company's deferred premiums associated with its derivative contracts are categorized as Level 3, as the Company utilizes a net present value calculation to determine the valuation. They are considered to be measured on a recurring basis as the derivative contracts they derive from are measured on a recurring basis. As derivative contracts containing deferred premiums are entered into, the Company discounts the associated deferred premium to its net present value at the contract trade date, using the Senior Secured Credit Facility rate at the trade date ~~(historical input rates range from~~ ~~1.69%~~ to ~~3.56%~~), and then records the change in net present value to interest expense over the period from trade until the final settlement date at the end of the contract. After this initial valuation, the net present value of each deferred premium is not adjusted; therefore, significant increases (decreases) in the Senior Secured Credit Facility rate would result in a significantly lower (higher) fair value measurement for each new contract entered into that contained a deferred premium; however, the valuation for the deferred premiums already recorded would remain unaffected. While the Company believes the sources utilized to arrive at the fair value estimates are reliable, different sources or methods could have yielded different fair value ~~estimates; therefore, on a quarterly basis, the valuation is compared to counterparty valuations and a third-party valuation of the~~estimates. The deferred premiums ~~for reasonableness.~~are included in "Derivatives" on the unaudited consolidated balance sheets, and as of March 31, 2019, their input rates range from 2.31% to 3.32% with a net fair value weighted-average rate of 2.74%.



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 30, 2017~~March 31, 2019 for the periods presented:



(in thousands)	March 31, 2019
Remaining 2019	$	11,486
2020	1,295
Total	$	12,781

(in thousands) September 30, 2017
Remaining 2017 $ 1,441
2018 20,335
2019 5,774
2020 391
Total $ 27,941

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,						Three months ended March 31,
(in thousands)	2017			2016			2017			2016			2019			2018
Balance of Level 3 at beginning of period	$	(12,554	)	$	(12,662	)	$	(8,998	)	$	(14,619	)	$	(16,565	)	$	(28,683	)
Change in net present value of derivative deferred premiums(1)	(88		)	(51		)	(199		)	(184		)	(95		)	(211		)
Total purchases and settlements:
Total purchases and settlements of derivative deferred premiums:
Purchases	(15,996		)	—			(22,994		)	(6,072		)	—			(5,422		)
Settlements⁽¹⁾	1,448			2,709			5,001			10,871			4,016			4,024
Balance of Level 3 at end of period	$	(27,190	)	$	(10,004	)	$	(27,190	)	$	(10,004	)	$	(12,644	)	$	(30,292	)

____________________________________________________________________________


(1)	These amounts are included in "Interest expense" in the unaudited consolidated statements of operations.

See Note 2.f in the 2018 Annual Report for discussion of the Company's accounting policies for derivatives.

b. 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:



	March 31, 2019				December 31, 2018
(in thousands)	Long-term debt		Fair value⁽¹⁾		Long-term debt		Fair value⁽¹⁾
January 2022 Notes	$	450,000	$	412,313	$	450,000	$	402,885
March 2023 Notes	350,000		312,375		350,000		316,624
Senior Secured Credit Facility	270,000		270,112		190,000		190,054
Total	$	1,070,000	$	994,800	$	990,000	$	909,563

______________________________________________________________________________

(1)

The ~~amount~~fair values of the debt outstanding on the January 2022 Notes and the March 2023 Notes were determined using the March 31, 2019 and December 31, 2018 Level 1 fair value hierarchy quoted market price for ~~the nine months ended September 30, 2016 includes $3.9 million that represents the present~~each respective instrument. The fair value of ~~deferred premiums settled~~the outstanding debt on the Senior Secured Credit Facility as of March 31, 2019 and December 31, 2018 was estimated utilizing the Level 2 fair value hierarchy pricing model for similar instruments. See Note 10 in the ~~Company's hedge restructuring upon their early termination.~~2018 Annual Report for information about the fair value hierarchy levels.

~~b. Fair value measurement on a nonrecurring basis~~

The Company accounts for the impairment of long-lived assets, if any, at fair value on a nonrecurring basis. For purposes of fair value measurement, it was determined that the impairment of long-lived assets is classified as Level 3, based on the use of internally developed cash flow models. 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. See 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 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 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 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



~~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 and non-vested performance share awards. See Note 6.c for additional discussion of these awards. For the ~~nine~~three months ended ~~September 30, 2016,~~March 31, 2019, 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~~income (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 share for~~ For the three ~~and nine~~ months ended ~~September 30, 2017. The inclusion~~March 31, 2018, the 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 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~~method. For additional discussion of these ~~options would be anti-dilutive due~~dilutive effects, see Note 10 in the first-quarter 2018 Quarterly Report.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes 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.consolidated financial statements

(Unaudited)

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 March 31,
(in thousands, except for per share data)	2017		2016		2017		2016			2019			2018
Net income (loss) (numerator):
Net income (loss)—basic and diluted	$	11,027	$	9,485	$	140,413	$	(242,318	)	$	(9,491	)	$	86,520
Weighted-average common shares outstanding (denominator):
Basic⁽¹⁾	239,306		234,639		239,017		221,303			230,476			238,228
Non-vested performance share awards⁽²⁾	4,801		3,216		4,702		—
Non-vested restricted stock awards⁽³⁾	650		253		845		—
Outstanding stock option awards⁽³⁾	130		—		129		—
Dilutive non-vested restricted stock awards										—			1,064
Dilutive outstanding stock option awards										—			27
Diluted	244,887		238,108		244,693		221,303			230,476			239,319
Net income (loss) per common share:
Basic	$	0.05	$	0.04	$	0.59	$	(1.09	)	$	(0.04	)	$	0.36
Diluted	$	0.05	$	0.04	$	0.57	$	(1.09	)	$	(0.04	)	$	0.36

_____________________________________________________________________________

(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 months ended March 31, 2018. See Note ~~2.o~~6.a for additional discussion of the Company's ~~equity offerings.~~share repurchase program.

~~(2)~~

The dilutive effect of the non-vested performance share awards was calculated utilizing the Company's total shareholder return ("TSR") from the beginning of each performance share awards' respective performance period to the end of the respective period presented in comparison to the TSR of the peers specified in each performance share award's respective 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—~~10—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~~may not have insurance coverage. While many of these matters involve inherent uncertainty, as of the ~~loss is probable and the amount is reasonably estimable. Except with regard to the specific litigation noted below,~~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)~~ See Note 17.b for discussion of a favorable settlement received by the Company, ~~("Shell") filed an Original Petition and Request for Disclosure~~which occurred subsequent to March 31, 2019, in connection with the District Court of Harris County, Texas, alleging that the crude oil purchase agreement entered into between Shell and Laredo effective October 1, 2016 does not accurately reflect the compensation to be paid to Shell under certain circumstances dueCompany's damage claims asserted in a previously disclosed litigation matter relating to a ~~drafting mistake. Shell seeks reformation~~breach and wrongful termination 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 agreement, court costs and attorneys’ fees. The Company does not believe there was a drafting mistake made in the crude oil purchase agreement. The Company believes it has substantive defenses and intends to vigorously defend its position. 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 the costs (and resulting increased crude oil price realization) as reflected in the terms of the crude oil purchase agreement.

b. Drilling contracts

The Company has committed to several drilling rig contracts with a third ~~party~~parties to facilitate the Company's drilling plans. ~~Two~~Certain of these contracts are for ~~a term~~terms 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~~three months ended ~~September 30, 2017~~March 31, 2019 or ~~2016.~~2018. As the Company's current drilling rig contracts are considered leases under the scope of ASC 842, the present value of the future commitment as of March 31, 2019 related to drilling contracts with an initial term greater than 12 months is included in "Operating lease liabilities" under "Current liabilities" on the unaudited consolidated balance sheet as of March 31, 2019. The future commitment of ~~$3.0~~$2.2 million as of ~~September 30, 2017~~March 31, 2019 related to drilling contracts with a term less than 12 months is not recorded in the ~~accompanying~~ unaudited consolidated balance sheets. See Note 3.a for further discussion of the impact of the ASC 842 adoption. Management does not currently anticipate the early termination of ~~this contract~~these contracts in ~~2017.~~

2019.

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.~~firm transportation payments on excess pipeline capacity and other contractual penalties. 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~~firm transportation payments on excess pipeline capacity and other contractual penalties of $0.5 million and ~~$1.1~~$0.1 million during the three ~~and nine~~ months ended ~~September 30, 2017, respectively,~~March 31, 2019 and ~~$1.6 million during~~2018, respectively. These firm transportation payments on excess pipeline capacity and other contractual penalties are netted with the ~~three and nine months ended September 30, 2016, which are reported on the unaudited consolidated statements of operations~~respective revenue stream in the ~~"Other operating~~unaudited



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

~~expenses" line item.~~consolidated statements of operations. Future commitments of ~~$369.4~~$358.5 million as of ~~September 30, 2017~~March 31, 2019 are not recorded in the ~~accompanying~~ unaudited consolidated balance sheets. ~~For information regarding~~

d. Sand purchase and supply agreement

During the ~~TA related~~second quarter of 2018, the Company entered into a sand purchase and supply agreement, for a term of one year, whereby it has committed to ~~Medallion, see Note 2.h.~~buy a certain volume of in-basin sand, utilized in the Company's completion activities, for a fixed price. As of March 31, 2019, under the terms of this agreement, the Company is required to purchase a certain percentage of the volume commitment or it would incur a shortfall payment of $1.1 million at the end of the 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 March 31, 2019 or December 31, 2018.

Note ~~12—Related parties~~11—Supplemental cash flow and non-cash information

~~a. Medallion~~

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



	Three months ended March 31,
(in thousands)	2019		2018
Supplemental cash flow information:
Capitalized interest	$	242	$	255
Supplemental non-cash investing information:
Increase (decrease) in accrued capital expenditures	$	6,443	$	(43,336	)
Capitalized stock-based compensation in evaluated oil and natural gas properties	$	1,899	$	2,102
Capitalized asset retirement costs	$	271	$	130
Supplemental non-cash financing information:
Increase in accrued stock repurchases	$	—	$	4,761

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

The following table ~~summarizes items included~~presents supplemental cash flow and non-cash information related to leases:



(in thousands)	Three months ended March 31, 2019
Supplemental cash paid for amounts included in the measurement of lease liabilities information:
Operating cash flows for operating leases	$	3,564
Supplemental non-cash adjustments information:
Right-of-use assets obtained in exchange for operating lease liabilities	$	22,090

See Note 3 for discussion of the Company's leases.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note 12—Asset retirement obligations

See Note 2.k in the 2018 Annual Report for discussion of the Company's accounting policies for asset retirement obligations.

The following table reconciles the Company's asset retirement obligation liability associated with tangible long-lived assets for the periods presented:



	Three months ended March 31,
(in thousands)	2019			2018
Liability at beginning of period	$	56,882		$	55,506
Liabilities added due to acquisitions, drilling, midstream service asset construction and other	271			130
Accretion expense	1,052			1,106
Liabilities settled due to plugging and abandonment or removed due to sale	(447		)	(440		)
Liability at end of period	$	57,758		$	56,302

Note 13—Revenue recognition

a. Impact of ASC 606 adoption on the 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 in the Midland Basin. Prior to the Medallion Sale (defined below), LMS held 49% of Medallion's ownership units. 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' total net cash proceeds before taxes for its 49% ownership interest in Medallion were $831.3 million.

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 County and Glasscock County 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.

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.

In adopting 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 date of the Medallion Sale (i) the Company transferred and legally isolated its full interests in Medallion to Global Infrastructure Partners ("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 2018 beginning balance of accumulated deficit, presented on the unaudited consolidated statements of ~~operations related to Medallion~~stockholders' equity, in accordance with the modified retrospective approach of adoption. See Notes 4.c and 5.a in the 2018 Annual Report 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~~further discussion of the Medallion Sale, ~~subsequent to September 30, 2017.~~the TA and the adoption of ASC 606.

b. ~~Archrock Partners, L.P.~~Revenue recognition

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.

~~Note 13—Segments~~

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 oilOil, NGL and natural gas ~~properties. The midstream and marketing segment provides Laredo's exploration and production segment and third parties with~~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, natural gas lift and ~~water delivery and takeaway.~~



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

water delivery, recycling and takeaway 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 can be found in Note 5.b in the 2018 Annual Report.

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 carryforwards totaling $1.9 billion and state of Oklahoma net operating loss carryforwards totaling $36.0 million as of March 31, 2019, which begin expiring in 2026 and 2032, respectively. Due to the enactment of Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the "Tax Act"), $157.2 million of the federal net operating loss carryforward will not expire but may be limited in future periods. As of March 31, 2019, the Company believes it is more likely than not that a portion of the net operating loss carryforwards 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 March 31, 2019, the Company's ability to capitalize intangible drilling costs, rather than expensing these costs in order to prevent an operating loss carryforward from expiring unused and future projections of Oklahoma sourced income. As of March 31, 2019, a total valuation allowance of $239.0 million has been recorded against the net deferred tax asset, resulting in a net Texas deferred tax liability of $5.0 million, which is included in "Other noncurrent liabilities" on the unaudited consolidated balance sheets.

The Company paid Alternative Minimum Tax ("AMT") related to the Medallion Sale in 2017. The payment of AMT creates an AMT credit carryforward. Due to changes in the Tax Act, AMT credit carryforwards do not expire and are now refundable over a five-year period. Therefore, as of March 31, 2019, a receivable has been recorded in the amount of $4.1 million, of which $2.1 million is included in "Accounts receivable, net" and $2.0 million is included in "Other noncurrent assets, net" on the unaudited consolidated balance sheets.

Note 15—Related party

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

The drilling contract with H&P is considered a lease under the scope of ASC 842 and, as the initial term is greater than 12 months, it is capitalized as an operating lease and is included in "Operating lease right-of-use-assets." The present value of the future commitment is included in "Operating lease liabilities" under "Current liabilities" on the unaudited consolidated balance sheet as of March 31, 2019.

The following table presents ~~selected financial information, for~~ the ~~periods presented, regarding~~operating lease liability related to H&P included in 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~~unaudited consolidated ~~basis:~~

balance sheet:

(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



(in thousands)	March 31, 2019
Operating lease liabilities	$	7,900

The following table presents the capital expenditures for oil and natural gas properties paid to H&P included in the unaudited consolidated statements of cash flows:



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



	Three months ended March 31,
(in thousands)	2019		2018
Capital expenditures for oil and natural gas properties	$	2,982	$	—

~~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—~~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, 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 30, 2017~~March 31, 2019 and December 31, ~~2016, unaudited condensed consolidating~~2018, (ii) statements of operations for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2019 and ~~2016~~2018 and ~~unaudited condensed consolidating~~(iii) statements of cash flows for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 and ~~2016~~2018 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



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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)~~March 31, 2019


(in thousands)	Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company		Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable, net	$	74,133	$	15,707	$	—		$	89,840	$	94,635	$	12,885	$	—		$	107,520
Other current assets	49,922		2,703		—			52,625		63,836		1,374		—			65,210
Oil and natural gas properties, net	1,464,197		9,244		(14,431		)	1,459,010		2,145,399		9,076		(24,049		)	2,130,426
Midstream service assets, net	—		130,407		—			130,407		—		131,118		—			131,118
Other fixed assets, net	41,502		400		—			41,902		39,061		37		—			39,098
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
Investment in subsidiaries										135,199		—		(135,199		)	—
Other noncurrent assets, net										37,245		4,172		—			41,417
Total assets	$	2,054,729	$	438,959	$	(427,362	)	$	2,066,326	$	2,515,375	$	158,662	$	(159,248	)	$	2,514,789

Accounts payable	$	20,975	$	1,820	$	—		$	22,795
Accounts payable and accrued liabilities										$	57,291	$	19,353	$	—		$	76,644
Other current liabilities	179,550		20,915		—			200,465		125,377		1,601		—			126,978
Long-term debt, net	1,440,968		—		—			1,440,968		1,064,081		—		—			1,064,081
Other long-term liabilities	52,580		3,293		—			55,873
Stockholders' equity	360,656		412,931		(427,362		)	346,225
Other noncurrent liabilities										73,145		2,509		—			75,654
Total stockholders' equity										1,195,481		135,199		(159,248		)	1,171,432
Total liabilities and stockholders' equity	$	2,054,729	$	438,959	$	(427,362	)	$	2,066,326	$	2,515,375	$	158,662	$	(159,248	)	$	2,514,789

Condensed consolidating balance sheet

December 31, 2018



(in thousands)	Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable, net	$	83,424	$	10,897	$	—		$	94,321
Other current assets	97,045		1,386		—			98,431
Oil and natural gas properties, net	2,043,009		9,113		(22,551		)	2,029,571
Midstream service assets, net	—		130,245		—			130,245
Other fixed assets, net	39,751		68		—			39,819
Investment in subsidiaries	128,380		—		(128,380		)	—
Other noncurrent assets, net	23,783		4,135		—			27,918
Total assets	$	2,415,392	$	155,844	$	(150,931	)	$	2,420,305

Accounts payable and accrued liabilities	$	54,167	$	15,337	$	—		$	69,504
Other current liabilities	121,297		9,664		—			130,961
Long-term debt, net	983,636		—		—			983,636
Other noncurrent liabilities	59,511		2,463		—			61,974
Total stockholders' equity	1,196,781		128,380		(150,931		)	1,174,230
Total liabilities and stockholders' equity	$	2,415,392	$	155,844	$	(150,931	)	$	2,420,305



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

~~Condensed consolidating balance sheet~~

~~December 31, 2016~~

~~(Unaudited)~~

(in thousands) Laredo Subsidiary
Guarantors Intercompany
eliminations Consolidated
company
Accounts receivable, net $ 70,570
$ 16,297
$ —
$ 86,867
Other current assets 65,884
2,026
—
67,910
Oil and natural gas properties, net 1,194,801
9,293
(8,240 ) 1,195,854
Midstream service assets, net —
126,240
—
126,240
Other fixed assets, net 44,221
552
—
44,773
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
Total assets $ 1,764,569
$ 402,045
$ (384,268 ) $ 1,782,346

Accounts payable $ 14,427
$ 627
$ —
$ 15,054
Other current liabilities 150,531
22,360
—
172,891
Long-term debt, net 1,353,909
—
—
1,353,909
Other long-term liabilities 56,889
3,030
—
59,919
Stockholders' equity 188,813
376,028
(384,268 ) 180,573
Total liabilities and stockholders' equity $ 1,764,569
$ 402,045
$ (384,268 ) $ 1,782,346

Condensed consolidating statement of operations

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

~~(Unaudited)~~March 31, 2019


(in thousands)	Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company			Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Total revenues	$	157,902		$	63,686	$	(15,770	)	$	205,818		$	173,521		$	54,332	$	(18,906	)	$	208,947
Total costs and expenses	97,686			62,245		(14,565		)	145,366			119,735			52,223		(17,408		)	154,550
Operating income	60,216			1,441		(1,205		)	60,452			53,786			2,109		(1,498		)	54,397
Interest expense	(23,697		)	—		—			(23,697		)	(15,547		)	—		—			(15,547		)
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
Other non-operating income (expense), net												(46,328		)	93		(2,202		)	(48,437		)
Income (loss) before income taxes												(8,089		)	2,202		(3,700		)	(9,587		)
Total income tax benefit												96			—		—			96
Net income (loss)												$	(7,993	)	$	2,202	$	(3,700	)	$	(9,491	)

Condensed consolidating statement of operations

For the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2018

~~(Unaudited)~~



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Total revenues	$	197,825		$	76,300		$	(14,429	)	$	259,696
Total costs and expenses	105,688			74,564			(13,748		)	166,504
Operating income	92,137			1,736			(681		)	93,192
Interest expense	(13,518		)	—			—			(13,518		)
Other non-operating income (expense), net	8,582			(256		)	(1,480		)	6,846
Income before income taxes	87,201			1,480			(2,161		)	86,520
Total income tax	—			—			—			—
Net income	$	87,201		$	1,480		$	(2,161	)	$	86,520

Condensed consolidating statement of cash flows

For the three months ended March 31, 2019

(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
Net cash provided by (used in) operating activities	$	82,020		$	(2,360	)	$	(2,202	)	$	77,458
Capital expenditures and other, net	(160,015		)	2,360			2,202			(155,453		)
Net cash provided by financing activities	77,388			—			—			77,388
Net decrease in cash and cash equivalents	(607		)	—			—			(607		)
Cash and cash equivalents, beginning of period	45,150			1			—			45,151
Cash and cash equivalents, end of period	$	44,543		$	1		$	—		$	44,544

Condensed consolidating statement of cash flows

For the three months ended March 31, 2018



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash provided by operating activities	$	140,247		$	7,704		$	(1,480	)	$	146,471
Capital expenditures and other, net	(193,450		)	(7,704		)	1,480			(199,674		)
Net cash used in financing activities	(3,067		)	—			—			(3,067		)
Net decrease in cash and cash equivalents	(56,270		)	—			—			(56,270		)
Cash and cash equivalents, beginning of period	112,158			1			—			112,159
Cash and cash equivalents, end of period	$	55,888		$	1		$	—		$	55,889



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

~~Condensed consolidating~~Note 17—Subsequent events

a. Senior Secured Credit Facility

On April 30, 2019, pursuant to the regular semi-annual redetermination, the lenders decreased the borrowing base and aggregate elected commitment under the Senior Secured Credit Facility to $1.1 billion each.

b. Litigation settlement

On April 12, 2019, the Company finalized and received a favorable settlement of $42.5 million in connection with its damage claims asserted in a previously disclosed litigation matter relating to a breach and wrongful termination of a crude oil purchase agreement. The Company does not anticipate the receipt of further payments in connection with this matter as this settlement constituted a full and final satisfaction of the Company's claims. Given that this amount is considered a gain contingency, it was not recorded as income during the period ending March 31, 2019, or in any prior period. The Company intends to recognize this settlement amount as other non-operating income in its unaudited consolidated statement of operations for the quarter ending June 30, 2019.

~~For~~c. Derivatives

Subsequent to March 31, 2019, the ~~three months ended September 30, 2016~~

~~(Unaudited)~~Company completed a hedge restructuring by early terminating puts and collars and entered into new swaps. The Company paid a net termination amount of $5.4 million, that included both the full settlement of the deferred premiums associated with the early-terminated puts, partially offset by the value at the time of termination of the early-terminated puts and collars. The present value of these deferred premium liabilities, classified under Level 3 of the fair value hierarchy, upon their early termination was $7.2 million. See Note 10 in the 2018 Annual Report for information about the fair value hierarchy levels. The following table details the derivatives that were terminated:



	Aggregate volumes (Bbl)	Weighted-average floor price ($/Bbl)		Weighted-average ceiling price ($/Bbl)		Contract period
Oil puts	5,087,500	$	46.03	$	—	April 2019 - December 2019
Oil collars	1,134,600	$	45.00	$	76.13	January 2020 - December 2020

(in thousands) Laredo
Subsidiary
Guarantors
Intercompany
eliminations
Consolidated
company
Total revenues $ 115,091
$ 58,383
$ (13,740 ) $ 159,734
Total costs and expenses 90,073
55,590
(11,421 ) 134,242
Operating income 25,018
2,793
(2,319 ) 25,492
Interest expense (23,077 ) —
—
(23,077 )
Other non-operating income 9,863
254
(3,047 ) 7,070
Income before income tax 11,804
3,047
(5,366 ) 9,485
Income tax —
—
—
—
Net income $ 11,804
$ 3,047
$ (5,366 ) $ 9,485

~~Condensed consolidating statement~~The following table summarizes open derivative positions as of ~~operations~~

~~For~~March 31, 2019, for derivative terminations and trade activity through May 1, 2019, for the ~~nine months ended September 30, 2016~~

~~(Unaudited)~~settlement periods presented:



	Remaining year 2019		Year 2020		Year 2021
Oil:
Puts:
Volume (Bbl)	962,500		366,000		—
Weighted-average floor price ($/Bbl)	$	55.00	$	45.00	$	—
Volume with deferred premium (Bbl)	962,500		—		—
Weighted-average deferred premium price ($/Bbl)	$	4.39	$	—	$	—
Swaps:
Volume (Bbl)	5,912,500		7,173,600		—
Weighted-average price ($/Bbl)	$	61.31	$	59.50	$	—
Collars:
Volume (Bbl)	—		—		912,500
Weighted-average floor price ($/Bbl)	$	—	$	—	$	45.00
Weighted-average ceiling price ($/Bbl)	$	—	$	—	$	71.00
Totals:
Total volume with floor price (Bbl)	6,875,000		7,539,600		912,500
Weighted-average floor price ($/Bbl)	$	60.42	$	58.79	$	45.00
Total volume with ceiling price (Bbl)	5,912,500		7,173,600		912,500
Weighted-average ceiling price ($/Bbl)	$	61.31	$	59.50	$	71.00

TABLE CONTINUES ON NEXT PAGE

(in thousands) Laredo
Subsidiary
Guarantors
Intercompany
eliminations
Consolidated
company
Total revenues $ 290,724
$ 155,052
$ (32,712 ) $ 413,064
Total costs and expenses 424,274
149,924
(27,712 ) 546,486
Operating income (loss) (133,550 ) 5,128
(5,000 ) (133,422 )
Interest expense (70,294 ) —
—
(70,294 )
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 )
Income tax —
—
—
—
Net income (loss) $ (237,318 ) $ 11,365
$ (16,365 ) $ (242,318 )

~~Condensed consolidating statement of cash flows~~

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

~~(Unaudited)~~

(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



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)



	Remaining year 2019			Year 2020			Year 2021
Basis Swaps:
WTI Midland to WTI NYMEX:
Volume (Bbl)	1,840,000			—			—
Weighted-average price ($/Bbl)	$	(2.89	)	$	—		$	—
WTI Midland to WTI formula basis:
Volume (Bbl)	552,000			—			—
Weighted-average price ($/Bbl)	$	(4.37	)	$	—		$	—
WTI Houston to WTI Midland:
Volume (Bbl)	910,000			—			—
Weighted-average price ($/Bbl)	$	7.30		$	—		$	—
NGL:
Swaps - Purity Ethane:
Volume (Bbl)	1,787,500			366,000			912,500
Weighted-average price ($/Bbl)	$	14.22		$	13.60		$	12.01
Swaps - Non-TET Propane:
Volume (Bbl)	1,430,000			1,244,400			730,000
Weighted-average price ($/Bbl)	$	27.97		$	26.58		$	25.52
Swaps - Non-TET Normal Butane:
Volume (Bbl)	550,000			439,200			255,500
Weighted-average price ($/Bbl)	$	30.73		$	28.69		$	27.72
Swaps - Non-TET Isobutane:
Volume (Bbl)	137,500			109,800			67,525
Weighted-average price ($/Bbl)	$	31.08		$	29.99		$	28.79
Swaps - Non-TET Natural Gasoline:
Volume (Bbl)	467,500			402,600			237,250
Weighted-average price ($/Bbl)	$	45.80		$	45.15		$	44.31
Total NGL volume (Bbl)	4,372,500			2,562,000			2,202,775
Natural gas:
Henry Hub NYMEX Swaps:
Volume (MMBtu)	29,425,000			23,790,000			14,052,500
Weighted-average price ($/MMBtu)	$	3.09		$	2.72		$	2.63
Basis Swaps:
Volume (MMBtu)	29,425,000			32,574,000			23,360,000
Weighted-average price ($/MMBtu)	$	(1.51	)	$	(0.76	)	$	(0.47	)

d. Workforce reduction

On April 2, 2019, the Company announced the retirement of two of its Senior Officers. Additionally, on April 8, 2019 (the "Effective Date"), the Company committed to a company-wide reorganization effort (the "Plan") that includes a workforce reduction of approximately 20%, which included an Executive Officer. The reduction in workforce was communicated to employees on the Effective Date and implemented immediately, subject to certain administrative procedures. The Company's board of directors approved the Plan in response to recent market conditions and to reduce costs and better position the Company for the future. In connection with the retirements on April 2, 2019 and with the Plan, the Company estimates that it will incur an aggregate of approximately $12.0 million of one-time charges in the second quarter of 2019 comprising of compensation, taxes, professional fees, outplacement and insurance-related expenses.

~~Condensed consolidating statement of cash flows~~

~~For the nine months ended September 30, 2016~~

~~(Unaudited)~~

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

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

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



~~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, a lessee (and a lessor) should exclude most variable lease payments in measuring lease assets and lease liabilities, other than those that depend on an index or a rate or are in substance fixed payments. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous GAAP. There continues to be a differentiation between finance leases and operating leases. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous GAAP unless the lease is modified, except that lessees are required to recognize a right-of-use asset and a lease liability for all operating leases at each reporting date based on the present value of the remaining minimum rental payments that were tracked and disclosed under previous GAAP. The amendments in this 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 be 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.

~~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~~	~~Laredo Petroleum, Inc.~~

~~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 for additional discussion regarding Medallion, and see Note 12.a for discussion of items included in the Company's unaudited consolidated financial statements related to Medallion.~~

~~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) 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, the Company borrowed $10.0 million, $15.0 million and $10.0 million, respectively, on the Senior Secured Credit Facility. On October 30, 2017, the Company repaid borrowings outstanding on the Senior Secured Credit Facility in 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 as of October 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.

~~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~~2018 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 30, 2017 included the following:~~

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

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

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

Adjusted EBITDA (a non-GAAP financial measure) of $130.9 million, compared to $118.0 million for the three months ended September 30, 2016. See page 49 for a discussion and reconciliation of Adjusted EBITDA.

~~Our financial and operating performance for the nine months ended September 30, 2017~~March 31, 2019 included the following:

Oil, NGL and natural gas sales of ~~$438.1~~$173.4 million, compared to ~~$290.5~~$197.4 million for the ~~nine~~three months ended ~~September 30, 2016;~~March 31, 2018, this decrease in sales is the result of a 26% decrease in average sales price per BOE, partially offset by a 19% increase in MBOE volumes sold;

Average daily sales volumes of ~~57,044~~75,276 BOE/D, compared to ~~48,392~~63,314 BOE/D for the ~~nine~~three months ended ~~September 30, 2016;~~March 31, 2018;

Net ~~income~~loss of ~~$140.4~~$9.5 million, compared to a net ~~loss~~income of ~~$242.3 million, including a non-cash full cost ceiling impairment of $161.1~~$86.5 million for the ~~nine~~three months ended ~~September 30, 2016;~~March 31, 2018; and

Adjusted EBITDA (a non-GAAP financial measure) of ~~$352.6~~$122.9 million, compared to ~~$326.3~~$143.4 million for the ~~nine~~three months ended ~~September 30, 2016.~~March 31, 2018. See page 4942 for a discussion and reconciliation of Adjusted EBITDA.

Recent developments

~~Medallion sale~~Potential future low commodity price impact on our second-quarter 2019 full cost ceiling impairment test

~~On October 30, 2017, LMS, together with MMH, which is owned~~Oil, NGL and ~~controlled by an affiliate~~natural gas prices decreased in the first quarter of ~~EMG, completed~~2019. If prices remain at or below the ~~previously announced Medallion Sale to an affiliate of GIP, for cash consideration of $1.825 billion,~~current levels, subject to ~~customary post-closing adjustments. LMS' net cash proceeds~~numerous factors and inherent limitations, some of which are discussed below, and all other factors remain constant, it is possible we will incur a non-cash full cost ceiling impairment in second-quarter 2019, which will have an adverse effect on our results of operations.

There are numerous uncertainties inherent in the estimation of proved reserves and accounting for ~~its 49% ownership interest~~oil and natural gas properties in ~~Medallion are $829.6 million, before post-closing adjustments~~future periods. In addition to unknown future commodity prices, other uncertainties include (i) changes in drilling and ~~taxes, but after deduction~~completion costs, (ii) changes in oilfield service costs, (iii) production results, (iv) our ability, in a low price environment, to strategically drill the most economic locations in our multi-stack horizontal targets, (v) income tax impacts, (vi) potential recognition of ~~its proportionate share of fees and other expenses associated with the Medallion Sale. The Medallion Sale closed pursuant~~additional proved undeveloped reserves, (vii) any potential value added to ~~the membership interest purchase and sale agreement, which provides for potential post-closing additional cash consideration that is structured~~our proved reserves when testing recoverability from drilling unbooked locations, (viii) revisions to production curves based on ~~GIP's realized profit at exit. There can~~additional data and (ix) the inherent significant volatility in the commodity prices for oil, NGL and natural gas recently exemplified by price changes in recent months.

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

Set forth below is a calculation of a potential future impairment of our evaluated oil and natural gas properties. Such implied impairment should not be ~~no assurance as~~interpreted to ~~when and whether any~~be indicative of our development plan or of our actual future results. Each of the uncertainties noted above has been evaluated for material known trends to be potentially included in the estimation of possible second-quarter effects. Based on such ~~additional consideration will be paid.~~review, we determined that the impact of decreased commodity prices is the only significant known variable necessary in calculating the following scenario.

Our hypothetical second-quarter 2019 full cost ceiling calculation has been prepared by substituting (i) $56.49 per Bbl for oil, (ii) $20.15 per Bbl for NGL and (iii) $0.92 per Mcf for natural gas (collectively, the "Pro Forma Second-Quarter Prices") for the respective Realized Prices (as defined below) as of March 31, 2019. All other inputs and assumptions have been held constant. Accordingly, this estimation strictly isolates the estimated impact of low commodity prices on the second-quarter 2019 Realized Prices that will be utilized in our full cost ceiling calculation. The Pro Forma Second-Quarter Prices use a slightly modified Realized Price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for oil, NGL and natural gas for the 12 months ended April 1, 2019. Based solely on the substitution of the Pro Forma Second-Quarter Prices into our March 31, 2019 reserve estimates, we would not have a second-quarter 2019 impairment. Under the same assumptions as above, but reducing the oil price to $56.30 per barrel ("Pro Forma Oil Price"), our full cost ceiling would approximately equal our after-tax net book basis to be recovered, implying a potential impairment of our evaluated oil and natural gas properties if the oil Realized Price applied to our reserves decreased below this Pro Forma Oil Price during second-quarter 2019. We believe that substituting these prices into our March 31, 2019 reserve estimates may help provide users with an understanding of the potential impact on our second-quarter 2019 full cost ceiling test.

See "Part I, Item 1A. Risk Factors—Risks related to our business—As a result of the volatility in prices for oil, NGL and natural gas, we have taken and may be required to take further write-downs of the carrying values of our properties" in our 2018 Annual Report.

Succession plan

We have implemented and been focused on a succession plan, which also included retirements and reductions in force (described below) that included a former Executive Officer and two former Senior Officers. On April 24, 2019, our board of directors announced the appointment of Mikell J. Pigott as President of the Company, effective as of May ~~2022 Notes call~~28, 2019. The board also appointed Mr. Pigott to become a member of the board, effective May 28, 2019, and to hold office until the 2020 annual meeting of stockholders or until his successor has been duly elected and qualified. As part of our comprehensive succession planning process, Mr. Pigott will succeed Randy A. Foutch, as the Company's Chief Executive Officer during the fourth quarter of 2019. The terms of Mr. Pigott’s offer are included in an exhibit to this Quarterly Report.

Litigation settlement

On April 15, 2019, we finalized and received a favorable settlement of $42.5 million in connection with our damage claims asserted in a previously disclosed litigation matter relating to a breach and wrongful termination of a crude oil purchase agreement. We do not anticipate the receipt of further payments in connection with this matter as this settlement constituted a full and final satisfaction of our claims. Given that this amount is considered a gain contingency, it was not recorded as income during the period ending March 31, 2019, or in any prior period. We intend to recognize this settlement amount as other non-operating income in our unaudited consolidated statement of operations for ~~redemption~~the quarter ending June 30, 2019.

Workforce reduction

On ~~October 30, 2017,~~April 2, 2019, we ~~issued~~announced the retirement of two of our Senior Officers. Additionally, on April 8, 2019, we committed to a ~~press release announcing~~Plan that includes a workforce reduction of approximately 20%, which included an Executive Officer. The reduction in workforce was communicated to employees on April 8, 2019 and implemented immediately, subject to certain administrative procedures. Our board of directors approved the Plan in response to recent market conditions and to reduce costs and better position us for the future. In connection with the retirements on April 2, 2019 and with the Plan, we estimate that we ~~have called for redemption~~will incur an aggregate of approximately $12.0 million of one-time charges in the ~~outstanding $500.0 million aggregate principal amount~~second quarter of ~~our May 2022 Notes.~~ 2019 comprising of compensation, taxes, professional fees, outplacement and insurance-related expenses.

Core area of operations

The ~~redemption date for~~oil and liquids-rich Permian Basin is characterized by multiple target horizons, long-lived reserves, high drilling success rates and high initial production rates. As of March 31, 2019, we had assembled 122,461 net acres in 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.Permian Basin.

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 to value our reserves as of September 30, 2017 and September 30, 2016 were $44.59 per Bbl for oil, $16.55 per Bbl for NGL and $2.16 per Mcf for natural gas, and $36.39 per Bbl for 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.

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 fluctuations in price ~~fluctuations~~and basis differentials for our sales of oil, NGL and natural gas, as discussed in "Item 3. Quantitative and Qualitative Disclosures About Market Risk."

~~Core areas~~The unweighted arithmetic average first-day-of-the-month prices for oil, NGL and natural gas for each month within the 12-month period prior to the end of ~~operations~~

the reporting period before pricing differentials, adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the prices received at the wellhead ("Realized Prices"), utilized to value our reserves as of March 31, 2019 and March 31, 2018, were $56.72 per Bbl for oil, $20.46 per Bbl for NGL and $1.09 per Mcf for natural gas, and $48.72 per Bbl for oil, $18.83 per Bbl for NGL and $1.97 per Mcf for natural gas, respectively. The Realized Prices used to estimate proved reserves do not include derivative transactions. The unamortized cost of our evaluated oil and ~~liquids-rich Permian Basin~~natural gas properties did not exceed the full cost ceiling amount as of March 31, 2019 or March 31, 2018. See Note 4 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of our full cost method of accounting.

Horizontal drilling of unconventional wells using enhanced completions techniques, including, but not limited to, hydraulic fracturing, is ~~characterized by multiple target horizons, extensive~~a relatively new process and, as such, forecasting the long-term production ~~histories, long-lived~~of such wells is inherently uncertain and subject to varying interpretations. As we receive and process geological and production data from these wells over time, we analyze such data to confirm whether previous assumptions regarding original forecasted production and reserves ~~high drilling success~~continue to appear accurate or require modification. While all production forecasts have elements of uncertainty over the life of the related wells, we are seeing indications that the oil portion of such reserves may be less than originally anticipated and the decline curves may be steeper than originally anticipated.

Initial production results, production decline rates, well density, completion design and ~~high initial production rates. As~~operating method are examples of ~~September 30, 2017, we had assembled 125,466 net acres~~the numerous uncertainties and variables inherent in the ~~Permian Basin.~~estimation of proved reserves in future periods. The quantity of proved reserves is one of the many variables inherent in the calculation of depletion. Negative revisions in the estimated quantities of proved reserves have the effect of increasing the rates of depletion on the affected properties, which decreases earnings and increases losses through higher depletion expense. We have experienced increased depletion per BOE sold for first-quarter 2019.

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) natural gas lift, ~~fees~~rig fuel and centralized compression infrastructure and (iii) water ~~services.~~storage, recycling and transportation infrastructure. See Notes 2.n and 5.b to our consolidated financial statements in our 2018 Annual Report for additional information regarding our revenue recognition policies.

The following table presents our sources of revenue as a percentage of total revenues:



	Three months ended March 31,
	2019		2018
Oil sales	62	%	58	%
NGL sales	15	%	11	%
Natural gas sales	6	%	7	%
Midstream service revenues	1	%	1	%
Sales of purchased oil	16	%	23	%
Total	100	%	100	%

Results of operations ~~consolidated~~

For the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2019 as compared to the three ~~and nine~~ months ended ~~September 30, 2016~~March 31, 2018

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

The following table ~~sets forth~~presents information regarding our 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 March 31,
	2019			2018
Sales volumes:
Oil (MBbl)	2,534			2,439
NGL (MBbl)	2,099			1,563
Natural gas (MMcf)	12,849			10,173
Oil equivalents (MBOE)⁽¹⁾⁽²⁾	6,775			5,698
Average daily sales volumes (BOE/D)⁽²⁾	75,276			63,314
% Oil⁽²⁾	37		%	43		%
Sales revenues (in thousands):
Oil	$	129,171		$	150,914
NGL	32,235			28,360
Natural gas	11,970			18,160
Total oil, NGL and natural gas sales revenues	$	173,376		$	197,434
Average sales prices⁽²⁾:
Oil, without derivatives ($/Bbl)⁽³⁾	$	50.97		$	61.87
NGL, without derivatives ($/Bbl)⁽³⁾	$	15.36		$	18.14
Natural gas, without derivatives ($/Mcf)⁽³⁾	$	0.93		$	1.79
Average price, without derivatives ($/BOE)⁽³⁾	$	25.59		$	34.65
Oil, with derivatives ($/Bbl)⁽⁴⁾	$	47.66		$	58.53
NGL, with derivatives ($/Bbl)⁽⁴⁾	$	15.33		$	18.11
Natural gas, with derivatives ($/Mcf)⁽⁴⁾	$	1.11		$	1.85
Average price, with derivatives ($/BOE)⁽⁴⁾	$	24.68		$	33.34

_____________________________________________________________________________


(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 and are not calculated using the rounded numbers presented in the table above.~~

(4)

~~Hedged prices reflect~~

Price reflects the ~~after-effect~~after-effects of our ~~hedging~~derivative transactions on our average sales prices. Our calculation of such after-effects includes ~~current period~~ settlements of matured derivatives during the respective periods in accordance with GAAP and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to ~~instruments~~derivatives that settled induring 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.~~respective periods.

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~~average sales prices with derivatives presented above:


	Three months ended September 30,						Nine months ended September 30,						Three months ended March 31,
(in thousands)	2017			2016			2017			2016			2019			2018
Cash settlements received (paid) for matured derivatives:
Settlements (paid) received for matured derivatives:
Oil	$	13,182		$	42,442		$	33,399		$	144,750		$	(2,095	)	$	(3,736	)
NGL	(897		)	—			(1,761		)	—			(57		)	(47		)
Natural gas	1,350			1,865			3,153			12,876			2,254			1,547
Total	$	13,635		$	44,307		$	34,791		$	157,626		$	102		$	(2,236	)
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	)	$	(6,300	)	$	(4,403	)
Natural gas	(769		)	—			(2,301		)	—			—			(841		)
Total	$	(1,131	)	$	(2,709	)	$	(4,684	)	$	(6,972	)	$	(6,300	)	$	(5,244	)

Changes in average ~~realized~~ sales prices without derivatives and sales volumes caused the following changes to our oil, NGL and natural gas revenues between the three months ended ~~September 30, 2017~~March 31, 2019 and ~~2016:~~2018:

(in thousands) 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
Effect of changes in sales volumes 10,733
2,520
3,850
17,103
2017 Revenues $ 110,194
$ 27,700
$ 19,664
$ 157,558



(in thousands)	Oil			NGL			Natural gas			Total net effect of change
2018 Revenues	$	150,914		$	28,360		$	18,160		$	197,434
Effect of changes in average sales prices	(27,602		)	(5,847		)	(10,967		)	(44,416		)
Effect of changes in sales volumes	5,859			9,722			4,777			20,358
2019 Revenues	$	129,171		$	32,235		$	11,970		$	173,376

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

(in thousands) 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
Effect of changes in sales volumes 30,412
7,544
7,199
45,155
2017 Revenues $ 313,875
$ 68,329
$ 55,927
$ 438,131

~~Oil~~ revenue. Our oil sales revenue is a function of oil production volumes sold and average oil sales prices received for those volumes. The ~~increase~~decrease in oil sales revenue of ~~$26.1~~$21.7 million, or ~~31%~~14%, for the three months ended ~~September 30, 2017~~March 31, 2019 as compared to the ~~three months ended September 30, 2016~~same period in 2018 is due to ~~a 16% increase~~an 18% decrease in average oil sales prices ~~realized~~ and was partially offset by a ~~13%~~4% increase in oil sales volumes.

The increase in oil revenue of $95.4 million, or 44%, for the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016 is due to a 26% increase in average oil prices realized and a 14% increase in oilNGL sales ~~volumes.~~

~~NGL~~ revenue. Our NGL sales revenue is a function of NGL production volumes sold and average NGL sales prices received for those volumes. The increase in NGL sales revenue of ~~$13.0~~$3.9 million, or ~~89%~~14%, for the three months ended ~~September 30, 2017~~March 31, 2019 as compared to the ~~three months ended September 30, 2016~~same period in 2018 is due to a ~~61% increase in average NGL prices realized and a 17%~~34% increase in NGL sales ~~volumes.~~

~~The increase in NGL revenue of $30.5 million, or 81%, for the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016 is due to~~volumes and was partially offset by a ~~51% increase~~15% decrease in average NGL ~~prices realized and a 20% increase in NGL~~ sales ~~volumes.~~prices.

Natural gas sales revenue. Our natural gas sales revenue is a function of natural gas production volumes sold and average natural gas sales prices received for those volumes. The ~~increase~~decrease in natural gas sales revenue of ~~$3.6~~$6.2 million, or ~~23%~~34%, for the three months ended ~~September 30, 2017~~March 31, 2019 as compared to the ~~three months ended September 30, 2016~~same period in 2018 is due to a ~~24%~~48% decrease in average natural gas sales prices and was partially offset by a 26% increase in natural gas sales ~~volumes partially offset~~volumes.

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



	Three months ended March 31,
(in thousands)	2019		2018
Midstream service revenues	$	2,883	$	2,359
Sales of purchased oil	$	32,688	$	59,903

Midstream service revenues. Our midstream service revenues increased by ~~a 1% decrease in average natural gas prices realized.~~

~~The increase in natural gas revenue of $21.8~~$0.5 million, or ~~64%~~22%, for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019, as compared to the ~~nine~~same period in 2018. These revenues fluctuate and will vary due to oil throughput fees and the level of services provided to third parties.

Sales of purchased oil. These revenues are a function of the volumes and prices of purchased oil sold to customers and are offset by the costs of purchased oil. Sales of purchased oil decreased by $27.2 million, or 45%, for the three months ended ~~September 30, 2016 is~~March 31, 2019 as compared to the same period in 2018 mainly due to a ~~35% increase~~decrease in ~~average natural gas prices realized~~the volumes of purchased oil sold. We enter into purchase transactions with third parties and separate sale transactions. These transactions are presented on a ~~21% increase~~gross basis as we act as the principal in ~~natural gas sales volumes.~~the transaction by assuming control of the commodities purchased and the responsibility to deliver the commodities sold. Revenue is recognized when control transfers to the purchaser/customer at the delivery point

based on the price received. The transportation costs associated with these transactions are presented as a component of costs of purchased oil. See "—Costs and expenses - Costs of purchased oil."

Costs and expenses

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


	Three months ended September 30,				Nine months ended September 30,				Three months ended March 31,
(in thousands except for per BOE sold data)	2017		2016		2017		2016		2019		2018
Costs and expenses:
Lease operating expenses	$	19,594	$	18,177	$	56,690	$	57,920	$	22,609	$	21,951
Production and ad valorem taxes	9,558		7,066		26,811		21,483		7,219		11,812
Transportation and marketing expenses									4,759		—
Midstream service expenses	1,174		1,039		2,986		2,826		1,603		693
Costs of purchased oil	47,385		44,232		141,661		121,190		32,691		60,664
General and administrative:
Cash	16,034		16,454		45,728		46,496		14,113		15,386
Non-cash stock-based compensation, net of amounts capitalized	8,966		9,651		26,877		19,562
Non-cash stock-based compensation, net									7,406		9,339
Depletion, depreciation and amortization	41,212		35,158		113,327		110,813		63,098		45,553
Impairment expense	—		—		—		162,027
Other operating expenses	1,443		2,465		3,906		4,169		1,052		1,106
Total	$	145,366	$	134,242	$	417,986	$	546,486
Average costs per BOE sold⁽¹⁾:
Total costs and expenses									$	154,550	$	166,504
Average costs and expenses per BOE sold⁽¹⁾:
Lease operating expenses	$	3.55	$	3.85	$	3.64	$	4.37	$	3.34	$	3.85
Production and ad valorem taxes	1.73		1.50		1.72		1.62		1.07		2.07
Transportation and marketing expenses									0.70		—
Midstream service expenses	0.21		0.22		0.19		0.21		0.24		0.12
General and administrative:
Cash	2.90		3.49		2.94		3.51		2.08		2.70
Non-cash stock-based compensation, net of amounts capitalized	1.62		2.05		1.73		1.48
Non-cash stock-based compensation, net									1.09		1.64
Depletion, depreciation and amortization	7.46		7.45		7.28		8.36		9.31		7.99
Total	$	17.47	$	18.56	$	17.50	$	19.55
Total costs and expenses									$	17.83	$	18.37

_____________________________________________________________________________


(1)	Average costs and expenses 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~~$0.7 million, or ~~8%, and decreased by $1.2 million, or 2%~~3%, for the three ~~and nine~~ months ended ~~September 30, 2017, respectively,~~March 31, 2019 compared to the same ~~periods~~period in ~~2016.~~2018. On a per BOE sold basis, lease operating expenses decreased ~~8% and 17%~~by 13% for the three ~~and nine~~ months ended ~~September 30, 2017, respectively,~~March 31, 2019 compared to the same ~~periods~~period in ~~2016 mainly due to previous investments in field infrastructure.~~2018. 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~~decreased by ~~$2.5~~$4.6 million, or ~~35%, and $5.3 million, or 25%~~39%, for the three ~~and nine~~ months ended ~~September 30, 2017, respectively,~~March 31, 2019 compared to the same ~~periods~~period in ~~2016.~~2018. The ~~quarter-over-quarter increase~~decrease is mainly due to a ~~$1.5~~$4.5 million ~~increase in~~ production ~~taxes and a $1.0 million increase in ad valorem taxes. The year-to-date increase over~~tax refund, related to additional marketing costs claimed for fiscal years 2013 through 2016, recorded during 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.~~three months ended March 31, 2019. Production taxes, which are established by federal, state or local taxing authorities, 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.

~~Midstream service~~Transportation and marketing expenses. ~~See "—Results of operations - midstream~~Transportation 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 decreased by $1.1~~marketing expenses were $4.8 million or 4%, and increased by $6.5 million, or 10%, for the three and nine months ended September 30, 2017, 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~~March 31, 2019. In July 2018, we began recognizing transportation and marketing expense incurred for the delivery of produced oil to the customer in the U.S. Gulf Coast market. We did not have any comparable transactions during the same period in 2018.

Midstream service expenses. Midstream service expenses increased by $0.9 million, or 131%, for the three months ended March 31, 2019 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~~2018. This increase is mainly due to an increase in ~~production volumes sold for~~water service costs during 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~~2019, which corresponds to 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 statementssimilar increase in water service revenue 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~~during 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.~~ period. 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 representare 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~~decreased by ~~$20.5~~$28.0 million, or ~~17%~~46%, for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 compared to the same period in ~~2016 primarily~~2018 mainly due to a decrease in the ~~increases in oil prices.~~volumes of purchased oil. These are costs ~~include purchasing~~incurred for obtaining oil from third parties and, in some cases, transporting ~~it on~~such oil utilized in our marketing activities.

General and administrative ("G&A"). TotalG&A decreased by $3.2 million, or 13%, for the ~~Bridgetex Pipeline.~~

~~Income from equity method investee.~~ ~~As of September 30, 2017, LMS owned 49% of~~three months ended March 31, 2019 compared to the ~~ownership units of Medallion. Subsequent~~same period in 2018 mainly due to ~~September 30, 2017, LMS~~decreases in stock-based compensation, net and ~~MMH consummated~~professional fees. Stock-based compensation, net, decreased by $1.9 million, or 21%, for the ~~sale of 100% of~~three months ended March 31, 2019 compared to the ~~ownership interests~~same period in ~~Medallion to an affiliate of GIP.~~2018. See Note ~~16.a~~6.c to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for ~~additional~~ information regarding ~~this sale.~~our stock-based compensation.

~~Prior to~~Depletion, depreciation and amortization ("DD&A"). The following table presents the ~~sale, weaccounted for~~components of our investment in Medallion under the equity method of accounting with our proportionate share of net income reflected in the unaudited consolidated statements of operations as "Income from equity method investee" and the carrying amount reflected in the unaudited consolidated balance sheets as "Investment in equity method investee." Income from equity method investeeDD&A expense:



	Three months ended March 31,
(in thousands)	2019		2018
Depletion of evaluated oil and natural gas properties	$	59,370	$	41,817
Depreciation of midstream service assets	2,501		2,405
Depreciation and amortization of other fixed assets	1,227		1,331
Total DD&A	$	63,098	$	45,553

DD&A increased by ~~$2.1 million and $1.7~~$17.5 million, or ~~795% and 26%~~39%, for the three ~~and nine~~ months ended ~~September 30, 2017, respectively,~~March 31, 2019 compared to the same ~~periods~~period in ~~2016. The quarter-over-quarter~~2018. This increase is mainly due to ~~Medallion's transportation fee revenue, resulting from higher throughput volumes partially offset by~~(i) the previous reduction in our December 31, 2018 reserve volume, (ii) an increase in ~~Medallion's operating expenses. The year-to-date~~the depletion base and (iii) an increase ~~over the comparable period~~ in ~~2016 is mainly due to Medallion's transportation fee revenue, resulting from higher throughput~~production 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 oilsold. Depletion per ~~day ("BOPD") and 118,000 BOPD~~BOE increased 19% for the three months ended ~~September 30, 2017~~March 31, 2019 compared to the same period in 2018. For further discussion of our depletion per BOE see "—Pricing and ~~2016, respectively,~~reserves."

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



	Three months ended March 31,
(in thousands)	2019			2018
Gain (loss) on derivatives, net	$	(48,365	)	$	9,010
Interest expense	(15,547		)	(13,518		)
Loss on disposal of assets, net	(939		)	(2,617		)
Other income, net	867			453
Non-operating expense, net	$	(63,984	)	$	(6,672	)

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 March 31, 2019 compared to 2018
Decrease in fair value of derivatives outstanding	$	(59,713	)
Change in settlements received (paid) for matured derivatives, net	2,338
Total change in gain (loss) on derivatives, net	$	(57,375	)

The decrease in fair value of derivatives outstanding is the result of new and ~~an average~~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 ~~166,168 BOPD~~our derivatives. In general, if no new contracts are entered into, we experience gains during periods of decreasing market prices and ~~100,000 BOPD~~losses during periods of increasing market prices. Settlements received or paid for matured derivatives are based on the ~~nine months ended September 30, 2017~~settlement prices of our matured derivatives compared to the prices specified in the derivative contracts. See Notes 7 and ~~2016, respectively.~~

~~See Note 2.h, 12.a and 16.a~~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.

Interest expense. Interest expense increased by $2.0 million, or 15%, for the three months ended March 31, 2019 compared to the same period in 2018 mainly due to an increase in the amount outstanding on our Senior Secured Credit Facility.

Loss on disposal of assets, net. Loss on disposal of assets, net decreased by $1.7 million for the three months ended March 31, 2019 compared to the same period in 2018. From time to time, we dispose of 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. Income tax benefit for the three months ended March 31, 2019 was $0.1 million. We are subject to federal and state income taxes and the Texas franchise tax. As of March 31, 2019, we determined it was more likely than not that our deferred tax assets were not realizable through future net income. We maintain a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized and, as of March 31, 2019, we have recorded a total valuation allowance of $239.0 million against our federal and Oklahoma deferred tax assets. As such, the effective tax rates for our operations were 1% and 0% for the three months ended March 31, 2019 and 2018, respectively. 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. 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 and 4 to~~For further discussion of our ~~unaudited consolidated financial statements~~financing activities included elsewhere in this Quarterly Report, see: (i) Note 5 for ~~additional discussion~~our debt instruments and (ii) Note 6.a and "Part II. Item 2. Purchases of Equity Securities" below for our ~~divestiture~~$200.0 million share repurchase program authorized by our board of directors and commenced in February 2018. We also continuously look for other opportunities to maximize shareholder value.

Due to the inherent volatility in oil, NGL and natural gas ~~properties~~prices, commodity transportation costs and ~~debt, respectively.~~

We continually seek 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.

~~We use derivatives to reduce exposure to fluctuations~~differences in the prices of oil, NGL and natural ~~gas. See Note 7.a~~gas between where we produce and where we sell such commodities, we engage in derivative transactions, such as puts, swaps, collars and basis swaps to hedge price risk associated with a portion of 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.anticipated production. 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.operations. See ~~"Item~~"Part I. Item 3. Quantitative and Qualitative Disclosures About Market Risk" below.

See Note 17.c to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of our hedge restructuring, which occurred subsequent to March 31, 2019, and corresponding summary of open derivative positions as of March 31, 2019 for derivative terminations and trade activity through May 1, 2019.

See Note 7 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for a summary of open derivative positions as of March 31, 2019 for derivatives that were entered into through March 31, 2019.

We continually seek to maintain a financial profile that provides operational flexibility. As of March 31, 2019, we had cash and cash equivalents of $44.5 million and available capacity under the Senior Secured Credit Facility of $915.3 million, resulting in total liquidity of $959.8 million. As of April 30, 2019, we had cash and cash equivalents of $85.0 million and available capacity under the Senior Secured Credit Facility of $815.3 million, resulting in total liquidity of $900.3 million. We believe that our operating cash flow, the receipt of the litigation settlement proceeds 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, pay down debt or increase our planned capital expenditure budget. We expect 2019 to be a transitional year as we tailor our operational cadence and corporate cost structure, including G&A expense, to balance capital expenditures and cash flow from operations. We have aligned personnel costs with activity levels with a recent reduction in force. We have restructured our oil hedges, securing additional cash flow to increase activity and substantially accelerating the time frame in which we expect to generate free cash flow while growing oil production.

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,						Three months ended March 31,
(in thousands)	2017			2016			2019			2018
Net cash provided by operating activities	$	272,051		$	245,454		$	77,458		$	146,471
Net cash used in investing activities	(356,893		)	(455,895		)	(155,453		)	(199,674		)
Net cash provided by financing activities	72,988			209,647
Net cash provided by (used in) financing activities							77,388			(3,067		)
Net decrease in cash and cash equivalents	$	(11,854	)	$	(794	)	$	(607	)	$	(56,270	)

Cash flows from operating activities

Net cash provided by operating activities ~~increased~~decreased by ~~$26.6~~$69.0 million, or 47%, for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019, compared to the same period in ~~2016~~2018, mainly due to decreased revenues along with a decrease of $52.2 million from net working capital changes. The decrease in revenues is due to the ~~price-related increase~~decrease in average sales prices for oil, NGL and natural gas ~~revenues; however, notable cash~~partially offset by increased sales volumes of all production streams. See "—Results of operations" for additional discussion of changes ~~included (i) a decrease of $125.2 million~~ in ~~cash settlements received for matured 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.~~revenues.

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 2018 Annual Report.

Cash flows from investing activities

Net cash used in investing activities decreased ~~$99.0~~by $44.2 million, ~~during~~or 22%, for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019, compared to the same period in ~~2016~~2018, and is mainly attributable to ~~(i) proceeds we received from~~ a ~~January 2017 divestiture of~~decrease in capital expenditures on oil and natural gas ~~properties and (ii) a decrease in contributions made to Medallion.~~ properties.

The ~~year-over-year increase in total capital expenditures for oil and natural gas properties, midstream service assets and other fixed assets was substantially offset by~~following table presents the components of our cash

outflow for 2016 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 and the 2016 acquisitions.

~~Our net cash used in~~ flows from investing ~~activities for the periods presented is summarized in the table below:~~activities:


	Nine months ended September 30,						��	Three months ended March 31,
(in thousands)	2017			2016				2019			2018
Capital expenditures:
Acquisitions of oil and natural gas properties	$	—		$	(115,600	)
Oil and natural gas properties	(381,165		)	(276,735		)		(152,729		)	(195,025		)
Midstream service assets	(11,680		)	(4,231		)		(2,262		)	(3,362		)
Other fixed assets	(3,604		)	(982		)		(505		)	(3,963		)
Investment in equity method investee (Note 16.a)	(24,572		)	(58,712		)
Proceeds from disposition of equity method investee, net of selling costs								—			1,655
Proceeds from dispositions of capital assets, net of selling costs	64,128			365				43			1,021
Net cash used in investing activities	$	(356,893	)	$	(455,895	)		$	(155,453	)	$	(199,674	)

Capital expenditure budget

~~During~~Our goal is to achieve cash flow neutrality, and therefore, our capital spending in 2019 will ultimately be influenced by commodity price changes, as well as any changes in service costs and drilling and completions efficiencies. Due to the ~~fourth~~increased cash flow secured from the successful execution of our WTI NYMEX hedge restructuring and litigation settlement proceeds received discussed herein, both of which occurred subsequent to March 31, 2019, during the second quarter of ~~2017,~~2019, we adjusted our ~~board of directors approved an increase~~expected capital expenditures, excluding non-budgeted acquisitions, to the 2017 capital expenditure budget of $100.0 million which represents service cost inflation, additional completion optimization testing and data collection. Our revised capital expenditure budget is $630.0$465.0 million for calendar year ~~2017, excluding acquisitions and investments in Medallion.~~2019, an increase of $100.0 million from the previously announced level. 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 financing activities

~~For~~Net cash used in financing activities decreased by $80.5 million for the ~~nine~~three months ended ~~September 30, 2017,~~March 31, 2019, compared to the same period in 2018, and is mainly attributable to first-quarter 2018 share repurchases under our ~~net cash provided by financing activities was the result of~~share repurchase program that commenced in February 2018 and increased borrowings on our Senior Secured Credit ~~Facility partially offset by (i) payments on our Senior Secured Credit Facility, (ii)~~Facility. During the ~~purchase~~year ended December 31, 2018, we repurchased 11,048,742 shares of ~~treasury~~common stock at a weighted-average price of $8.78 per common share for a total of $97.1 million under this program. All shares were retired upon repurchase. There were no share repurchases under this program during the three months ended March 31, 2019. As of March 31, 2019, we had authorization remaining to ~~satisfy employees' tax withholding upon vesting~~repurchase until its expiration in February 2020, $102.9 million 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 increasecommon stock.

For further discussion 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 ~~were borrowings on~~included elsewhere in this Quarterly Report, see: (i) Note 5 for our ~~Senior Secured Credit Facility~~debt instruments and ~~proceeds~~(ii) Note 6.a and "Part II. Item 2. Purchases of Equity Securities" below for our $200.0 million share repurchase program authorized by our board of directors and commenced in February 2018.

The following table presents the components of our cash flows from ~~our July 2016 Equity Offering and May 2016 Equity Offering, partially offset by payments on our Senior Secured Credit Facility.~~

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

Nine months ended September 30,
(in thousands) 2017 2016
Borrowings on Senior Secured Credit Facility $ 155,000
$ 214,682
Payments on Senior Secured Credit Facility (70,000 ) (279,682 )
Proceeds from issuance of common stock, net of offering costs —
276,052
Purchase of treasury stock (7,638 ) (1,613 )
Proceeds from exercise of stock options 358
208
Payments for debt issuance costs (4,732 ) —
Net cash provided by financing activities $ 72,988
$ 209,647



	Three months ended March 31,
(in thousands)	2019			2018
Borrowings on Senior Secured Credit Facility	$	80,000		$	55,000
Share repurchases	—			(53,714		)
Stock exchanged for tax withholding	(2,612		)	(4,353		)
Net cash provided by (used in) financing activities	$	77,388		$	(3,067	)

Debt

As of ~~September 30, 2017,~~March 31, 2019, 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. The Senior Secured Credit Facility ~~and $20.8 million in cash~~matures on ~~hand for total available liquidity of $865.8 million. On October 30, 2017, we used a portion of~~April 19, 2023, provided that if either 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~~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 ~~November 29, 2017, and holders will receive a redemption price of 103.688% of~~90 days before their respective stated maturity dates, 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~~will mature 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.~~ such Early Maturity Date. As of ~~September 30, 2017, our~~March 31, 2019, the 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, with $270.0 million outstanding and ~~$155.0 million outstanding.~~

~~The borrowing base under our Senior Secured Credit Facility is~~was subject to ~~a semi-annual redetermination based on the lenders' evaluation~~an interest rate of ~~our oil, NGL and natural gas reserves.~~3.75%. 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, provided that if either of the January 2022 Notes or May 2022 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 to a regular semi-annual redetermination, the lenders reaffirmed the $1.0 billion borrowing base under 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 Base Rate or at the end of one-, two-, three-, six- or, to the extent available, 12-month interest periods (and in the case of six- and 12-month interest periods, every three months prior to the end of such interest period) at an Adjusted London Interbank Offered Rate, in each case, plus an applicable margin, which ranges from 1.0% to 2.0% for Adjusted Base Rate loans and from 2.0% to 3.0% for Adjusted London Interbank Offered Rate loans, based on the ratio of the outstanding revolving credit on our Senior Secured Credit Facility to the elected commitment. We are also required to pay an annual commitment fee based on the unused portion of the bank's commitment of 0.375% to 0.5%.

Our Senior Secured Credit Facility is secured by a first-priority lien on certain of our assets, including oil and natural gas properties constituting at least 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~~covenants, all of which we were in compliance with ~~these covenants as~~for all periods presented. Additionally, the Senior Secured Credit Facility provides for the issuance of ~~September 30, 2017.~~letters of credit, limited to the lesser of total capacity or $80.0 million. As of March 31, 2019 and December 31, 2018, we had one letter of credit of $14.7 million outstanding under the Senior Secured Credit Facility. For additional information, see Note 7.d in the 2018 Annual Report. See Note 17.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of the regular semi-annual borrowing base redetermination of the Senior Secured Credit Facility subsequent to March 31, 2019.

Senior unsecured notes. The following table presents principal amounts and applicable interest rates for our outstanding senior unsecured notes as of ~~September 30, 2017:~~March 31, 2019:


(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 5.a and 5.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 30, 2017,~~March 31, 2019, 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, Senior Secured Credit Facility, asset retirement obligations, operating lease liabilities, derivative deferred premiums, ~~asset retirement obligations~~a short-term drilling contract and ~~office~~a sand purchase and ~~equipment leases.~~supply agreement. From December 31, ~~2016~~2018 to ~~September 30, 2017,~~March 31, 2019, the material changes in our contractual obligations included (i) an increase of ~~$85.0~~$80.0 million in outstanding borrowings on our Senior Secured Credit Facility, (ii) a decrease of ~~$71.6 million in our firm sale and transportation commitments, (iii) 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~~of 2019, (iii) a decrease of $7.4 million for firm sale and ~~September~~transportation commitments due to our fulfillment of ~~2017,~~contractual commitments, (iv) ~~an increase~~a decrease of ~~$18.8~~$4.0 million in derivative deferred premiums ~~mainly~~ due to ~~new derivative contracts~~premiums paid for derivatives and (v) a decrease of ~~$4.9~~$2.8 million for our in-basin sand purchase and supply agreement due to purchases made.

Due to the adoption of FASB ASC 842 during the three months ended March 31, 2019, we have recorded contracts previously recognized as off balance sheet operating leases, with a term greater than 12 months, as right-of-use assets and lease liabilities. As of March 31, 2019, we have recorded on our unaudited consolidated balance sheets included elsewhere in this Quarterly Report total operating lease liabilities of $22.2 million, which includes our current drilling rig contract with an initial term greater than 12 months. The future commitment of $2.2 million as of March 31, 2019 related to our drilling contract with a term less than 12 months is not recorded in the unaudited consolidated balance sheets included elsewhere in this Quarterly Report. This represents an increase of $22.2 million in total operating lease liabilities and a decrease of $14.3 million in unrecorded drilling contracts commitments ~~(on contracts other than those on a well-by-well basis).~~from December 31, 2018 to March 31, 2019.

~~Refer to~~See Notes ~~2, 4,~~3, 5, 7, 8, ~~11, 16.b~~10, 12 and ~~16.c~~17.c 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,~~taxes, 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.

is widely used by investors in the oil and natural gas industry to measure a company's operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods, book value of assets, capital structure and the method by which assets were acquired, among other factors;

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

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

There are significant limitations to the use of Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations to different companies and the different methods of calculating Adjusted EBITDA

reported by different companies. Our measurements of Adjusted EBITDA for financial reporting as compared to compliance under our debt agreements differ.

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

Three months ended September 30,
Nine months ended September 30,
(in thousands) 2017
2016
2017
2016
Net income (loss) $ 11,027

$ 9,485

$ 140,413

$ (242,318 )
Plus:

Depletion, depreciation and amortization 41,212

35,158

113,327

110,813
Impairment expense
—

—

—

162,027
Non-cash stock-based compensation, net of amounts capitalized 8,966

9,651

26,877

19,562
Accretion expense 951

883

2,822

2,587
Mark-to-market on derivatives:

(Gain) loss on derivatives, net
27,441

(6,850 )
(38,127 )
43,783
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 )
Interest expense 23,697

23,077

69,590

70,294
Write-off of debt issuance costs —

—

—

842
Loss on disposal of assets, net
991

78

400

379
Income from equity method investee (2,371 ) (265 ) (7,910 ) (6,259 )
Proportionate Adjusted EBITDA of equity method investee⁽¹⁾
6,789
5,194
19,755
13,981
Adjusted EBITDA $ 130,890

$ 118,009

$ 352,630

$ 326,345


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

Three months ended September 30, Nine months ended September 30,
(in thousands) 2017 2016 2017
2016
Income from equity method investee $ 2,371
$ 265
$ 7,910
$ 6,259
Adjusted for proportionate share of:

Depreciation and amortization 4,418
4,929
11,845
7,722
Proportionate Adjusted EBITDA of equity method investee $ 6,789
$ 5,194
$ 19,755
$ 13,981



	Three months ended March 31,
(in thousands)	2019			2018
Net income (loss)	$	(9,491	)	$	86,520
Plus:
Deferred income tax benefit	(96		)	—
Depletion, depreciation and amortization	63,098			45,553
Non-cash stock-based compensation, net	7,406			9,339
Accretion expense	1,052			1,106
Mark-to-market on derivatives:
(Gain) loss on derivatives, net	48,365			(9,010		)
Settlements received (paid) for matured derivatives, net	102			(2,236		)
Premiums paid for derivatives	(4,016		)	(4,024		)
Interest expense	15,547			13,518
Loss on disposal of assets, net	939			2,617
Adjusted EBITDA	$	122,906		$	143,383

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~~three months ended ~~September 30, 2017. For~~March 31, 2019. See 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~~2018 Annual Report. ~~Additionally,~~Furthermore, see Notes 3 and 6.c to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of the impact of the adoption of ASC 842 and estimates pertaining to our 2019 performance unit awards, respectively.

Recent issued or adopted accounting pronouncements

For discussion of recently issued or adopted accounting pronouncements, see Note 2 to our unaudited consolidated financial statements included elsewhere in this Quarterly ~~Report for a discussion of additional accounting policies and estimates made by management.~~

~~Recent accounting pronouncements~~

Report. See Note 153 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for ~~information regarding recent accounting pronouncements.~~additional discussion related to the adoption of ASC 842.

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 and our sand purchase and supply agreement, which are described in "—Obligations and commitments." In addition, we have certain operating leases with a term less than or equal to 12 months that we have made an accounting policy election to not record on the unaudited consolidated balance sheets. See ~~Note 11~~Notes 3 and 10 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional ~~information.~~information on our leases and commitments and contingencies, respectively.

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, commodity transportation costs and differences in the prices of oil, NGL and natural gas between where we ~~use derivatives,~~produce and where we sell such commodities, we engage in derivative transactions, such as puts, swaps, collars and basis swaps ~~and 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~~operations.

During a significant portion of 2018, Midland market crude oil prices experienced an increased discount to WTI Cushing and WTI Houston prices. These discounts have narrowed in 2019, however they remain volatile. During a significant portion of 2018 and the first quarter of 2019, the West Texas WAHA market natural gas prices experienced an increased discount to Henry Hub NYMEX prices and continues to remain volatile. The discounts are primarily due to ~~fluctuations~~limited pipeline capacity constraining transportation of crude oil and natural gas out of the Permian Basin to major market hubs including, but not limited to, Cushing, Oklahoma and the United States Gulf Coast. These pipeline constraints may continue to affect Midland market crude oil prices and West Texas WAHA market natural gas prices until further transportation capacity becomes operational or until basin-wide crude oil and natural gas production decreases from its current levels. We will continue to pursue avenues to attempt to protect our oil and natural gas value from basin differentials by securing crude oil transportation capacity, which enables us to sell oil in ~~commodity prices. We have not elected hedge accounting on these~~multiple markets, and entering into basis-swap derivatives, and, therefore, the gains and losses on open positions are reflected in earnings. At each period end, we estimate the fair values of our derivatives using an independent third-party valuation and recognize the associated gain or loss in our unaudited consolidated statements of operations included elsewhere in this Quarterly Report.which provides pricing protection.

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 30, 2017,~~March 31, 2019, 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) asset derivative position						$	(46,647	)	$	45,720

As of ~~September 30, 2017~~March 31, 2019 and December 31, ~~2016,~~2018, the net ~~fair values~~derivative positions were a liability of ~~our open derivative contracts were $15.4~~$1.0 million and ~~$3.0~~an asset of $43.5 million, respectively. ~~Refer~~See Notes 7, 8.a and 17.b 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 30, 2017 and the Senior Secured Credit Facility's average floating interest rate for the nine months ended September 30, 2017~~March 31, 2019 were as follows:



	Maturity year
(in millions except for interest rates)	2022			2023⁽¹⁾
Senior Secured Credit Facility	$	—		$	270.0
Floating interest rate	—		%	3.750		%
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, 2017,~~See Note 10 to our ~~principal exposures to~~unaudited consolidated financial statements and "Part II, Item 1. Legal Proceedings" included elsewhere in this Quarterly Report and Note 13 in the 2018 Annual Report for additional disclosures regarding credit ~~risk were through receivables of (i) $62.1 million from sales of our oil, NGL~~risk. See Notes 2.e 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~~5 in the 2018 Annual Report for additional information regarding our accounts receivable and ~~termination events by a party~~revenue recognition, respectively. See Notes 7, 8.a 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 Note 10~~17.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional disclosures regarding ~~credit risk.~~our derivatives.

Item 4. Controls and Procedures

Evaluation of disclosure controls and procedures

As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of Laredo's disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act), was performed under the supervision and with the participation of Laredo's management, including our principal executive officer and principal financial officer. Based on that evaluation, these officers concluded that Laredo's disclosure controls and procedures were effective as of ~~September 30, 2017.~~March 31, 2019. Our disclosure controls and other procedures are designed to provide reasonable assurance that the information required to be disclosed in the reports we file and submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to Laredo's management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Evaluation of changes in internal control over financial reporting

There were no changes in our internal control over financial reporting during the quarter ended ~~September 30, 2017~~March 31, 2019 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 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 agreement, court costs and attorneys’ fees. The Company does not believe there was a drafting mistake made in the crude oil purchase agreement. The Company believes it has substantive defenses and intends to vigorously defend its position. The Company is unable to determine a probability of the outcome of this litigation at this time.

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~~2018 Annual Report. There have been no material changes in our risk factors from those described in the ~~2016~~2018 Annual Report. The risks described in ~~the 2016 Annual Report~~such reports are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

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

The following table summarized 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⁾
January 1, 2019 - January 31, 2019	18,230	$	4.18	—	$	102,945,283
February 1, 2019 - February 28, 2019	681,136	$	3.83	—	$	102,945,283
March 1, 2019 - March 31, 2019	1,448	$	3.43	—	$	102,945,283
Total	700,814			—

______________________________________________________________________________


(1)	~~Represents~~Included in these amounts are (i) 18,107 shares ~~that were~~exchanged for the cost of exercise of stock options and (ii) 682,707 shares withheld by us to satisfy ~~employee~~ tax withholding obligations that arose upon the lapse of restrictions on restricted stock ~~awards.~~awards and the exercise of stock options.

(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. 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 our common stock and the nature of other investment opportunities available to us.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

~~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.

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/~~8-A12B/A (File No. ~~333-176439)~~001-35380) filed on ~~November 14, 2011)~~January 7, 2014).
~~10.1~~10.1*#			~~First~~Form of Officer Severance and Release Agreement, as of April 2019.
10.2*			Consulting Agreement, dated April 3, 2019, between Laredo Petroleum, Inc. and Schooley Ventures, LLC.
10.3*#			Offer Letter, dated April 17, 2019, between Laredo Petroleum, Inc. and Mr. Jason Pigott.
10.4*#			Form of Performance Share Unit Award Agreement.
10.5*#			Amended and Restated Form of Indemnification Agreement between Laredo Petroleum, Inc. and each of the officers and directors thereof.
10.6*			Schedule 1, amended and restated as of April 30, 2019, to the 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 Current Report on Form 8-K (File No. 001-35380) filed on October 30, 2017).~~thereto.
31.1*			Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
31.2*			Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
32.1**			Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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.
XML			Extracted XBRL Instance Document.

______________________________________________________________________________


*	Filed herewith.


**	Furnished herewith.


#	Management contract or compensatory plan or arrangement.

* Filed herewith.

** Furnished herewith.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



	LAREDO PETROLEUM, INC.

Date: ~~November~~May 2, ~~2017~~2019	By:	/s/ Randy A. Foutch
		Randy A. Foutch
		Chairman and Chief Executive Officer
		(principal executive officer)

Date: ~~November~~May 2, ~~2017~~2019	By:	/s/ ~~Richard C. Buterbaugh~~Michael T. Beyer
		~~Richard C. Buterbaugh~~ Michael T. Beyer
		~~Executive~~Senior Vice President and Chief Financial Officer
		(principal financial ~~officer)~~

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

5847



(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



(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	%



	Granted on February 17, 2017
Risk-free interest rate⁽¹⁾	1.44		%
Dividend yield	—		%
Expected volatility⁽²⁾	74.00		%
Laredo stock closing price on grant date	$	14.12
Fair value per performance share award	$	18.96



	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
TABLE CONTINUES ON NEXT PAGE



(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