UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended ~~June 30, 2020~~March 31, 2021

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

For the transition period from to

Commission File Number: 001-35380

Laredo Petroleum, Inc.

(Exact name of registrant as specified in its charter)


Delaware						45-3007926
(State or other jurisdiction of incorporation or organization)						(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 per share	LPI	New York Stock Exchange

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 ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically, if any, every Interactive Data File required to be submitted 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 such files). Yes ☒ No ☐

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.


Large accelerated filer	☒☐	Accelerated filer	☐☒

Non-accelerated filer	☐	Smaller reporting company	☐


Emerging growth company	☐

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. ☐

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

Number of shares of registrant's common stock outstanding as of ~~August~~May 3, ~~2020: 11,996,028~~2021: 12,898,823

LAREDO PETROLEUM, INC.

TABLE OF CONTENTS


			Page
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS			iii
Part I			1
Item 1. Consolidated Financial Statements (Unaudited)			1
Consolidated balance sheets as of ~~June 30, 2020~~March 31, 2021 and December 31, ~~2019~~2020			1
Consolidated statements of operations for the three ~~and six~~ months ended ~~June 30,~~March 31, 2021 and 2020 ~~and 2019~~			2
Consolidated statements of stockholders' equity continuous quarterly presentation for the three ~~and six~~ months ended ~~June 30,~~March 31, 2021 and 2020 ~~and 2019~~			3
Consolidated statements of cash flows for the ~~six~~three months ended ~~June 30,~~March 31, 2021 and 2020 ~~and 2019~~			54
Condensed notes to the consolidated financial statements:			65
Note 1—Organization and basis of presentation			65
Note 2—New accounting standards			65
Note 3—Acquisitions and ~~divestitures~~divestiture			75

Note 4—4 —Leases			6
Note 5 —Property and equipment			9
~~Note 5—Leases~~			117
Note 6—Debt			119
Note 7—Stockholders' equity			1311
Note 8—Equity Incentive Plan			1412
Note 9—Derivatives			2016
Note 10—Fair value measurements			2319
Note 11—Net ~~income (loss)~~loss per common share			2621
Note 12—Commitments and contingencies			2722

Note 13—Supplemental cash flow and non-cash information			2823
Note 14—Asset retirement obligations			2823
Note 15—Revenue recognition			2923
Note 16—Income taxes			2923
Note 17—Related parties			2924
Note ~~18—Organizational restructurings~~1			308
~~Note 19—~~—Subsequent events			3125
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations			3226
Item 3. Quantitative and Qualitative Disclosures About Market Risk			5742
Item 4. Controls and Procedures			6045
Part II			6246
Item 1. Legal Proceedings			6246
Item 1A. Risk Factors			6247
Item 2. Purchases of Equity Securities			6648
Item 3. Defaults Upon Senior Securities			6749
Item 4. Mine Safety Disclosures			6850
Item 5. Other Information			6951
Item 6. Exhibits			7052
SIGNATURES			7153

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 (the "Securities Act"), 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 ~~threat, occurrence, potential~~effects, duration, government response or other implications of the coronavirus ("COVID-19") pandemic, or the threat and occurrence of other epidemic or pandemic ~~diseases, including the recent outbreak of a novel strain of coronavirus ("COVID-19"), or any government response to such occurrence or threat;~~diseases;

•changes in domestic and global production, supply and demand for oil, NGL and natural gas, including the ~~recent decrease in demand and oversupply of oil and natural gas as a result of~~effects from the COVID-19 pandemic and actions by the Organization of the Petroleum Exporting Countries members and other oil exporting nations ("OPEC+");

•the volatility of oil, NGL and natural gas prices, including in our area of operation in the Permian ~~Basin, and the extent and duration of price reductions and increased production by the Organization of the Petroleum Exporting Countries members and other oil exporting nations ("OPEC+");~~

•~~the pipeline and storage constraints in the Permian Basin and the possibility of future production curtailment in the State of Texas;~~

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

•~~impacts of impairment write-downs on our financial statements;~~

•~~the effectiveness of our internal control over financial reporting and our ability to remediate a material weakness in our internal control over financial reporting;~~Basin;

•the potential impact of suspending drilling programs and completions activities or shutting in a portion of our wells, as well as costs to later restart, and co‐development considerations such as horizontal spacing, vertical spacing and parent‐child interactions on production of oil, NGL and natural gas from our wells;

•~~conditions of the energy industry and changes in the regulatory environment and in~~ United States or("U.S.") and international economic conditions and legal, tax, political and administrative ~~or economic conditions,~~developments, including the effects of the recent U.S. presidential, congressional and state elections on energy, trade and environmental policies ~~or regulations that restrict imports or exports from the United States or prohibit or restrict~~ and existing and future laws and government regulations;

•our ability to ~~apply hydraulic fracturing to our oil~~comply with federal, state and ~~natural gas wells and to access and dispose of water used in these operations;~~local regulatory requirements;

•the ongoing instability and uncertainty in the ~~United States~~U.S. and international energy, 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;

•our ability to ~~maintain listing on the New York Stock Exchange ("NYSE")~~execute our strategies, including our ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to ~~prevent~~successfully integrate acquired businesses, assets and properties;

•competition in the ~~decrease in market price~~oil and ~~liquidity of our common stock;~~natural gas industry;

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

•~~capital requirements for~~drilling and operating risks, including risks related to hydraulic fracturing activities, and those related to inclement or extreme weather impacting our ~~operations~~ability to produce existing wells and/or drill and ~~projects;~~complete new wells over an extended period of time;

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

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

•impacts of impairment write-downs on our financial statements;

•capital requirements for our operations and projects;

iii

Table of Contents

•our ability to continue to maintain the borrowing capacity under our Fifth Amended and Restated Credit Agreement (as 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 comply with restrictions contained in our debt agreements, including our Senior Secured Credit Facility and the indentures governing our senior unsecured notes, as well as debt that could be incurred in the future;

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

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

•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~~gathering, processing, storage and ~~transportation facilities~~export capacity in the Permian Basin and ~~gathering and processing capacity;~~

•~~our ability to maintain~~refining capacity in the borrowing capacity under our Fifth Amended and Restated Senior Secured Credit Facility (as 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;~~U.S. Gulf Coast;

•the impact of repurchases, if any, of securities from time to time;

•~~restrictions contained~~the effectiveness of our internal control over financial reporting and our ability to remediate a material weakness in our ~~debt agreements, including our Senior Secured Credit Facility and the indentures governing our Senior Unsecured Notes (as defined below), as well as debt that could be incurred in the future;~~internal control over financial reporting;

•our ability to maintain the health and safety of, as well as recruit and retain, qualified personnel necessary to operate our 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 oil prices and potential shut-in of production due to lack of sufficient markets;

•risks related to the geographic concentration of our assets; and

•our ability to secure or generate sufficient electricity to produce our wells without ~~limitations;~~

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

•~~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;~~

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

•~~and those related to inclement weather impacting our ability to produce existing wells and/or drill and complete new wells over an extended period of time; and~~

•~~our ability to comply with federal, state and local regulatory requirements.~~limitations.

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," under "Part II, Item 1A. Risk Factors"~~Operations" and elsewhere in this ~~Quarterly Report and our first-quarter 2020~~ 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, ~~2019~~2020 (the ~~"2019~~"2020 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)


		June 30, 2020		December 31, 2019			March 31, 2021		December 31, 2020
Assets	Assets					Assets
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	15,747	$	40,857	Cash and cash equivalents	$	44,262	$	48,757
Accounts receivable, net	Accounts receivable, net	69,113		85,223		Accounts receivable, net	67,704		63,976
Derivatives	Derivatives	151,704		51,929		Derivatives	0		7,893

Other current assets	Other current assets	19,695		22,470		Other current assets	26,123		15,964

Total current assets	Total current assets	256,259		200,479		Total current assets	138,089		136,590
Property and equipment:	Property and equipment:					Property and equipment:
Oil and natural gas properties, full cost method:	Oil and natural gas properties, full cost method:					Oil and natural gas properties, full cost method:
Evaluated properties	Evaluated properties	7,689,108		7,421,799		Evaluated properties	7,953,141		7,874,932
Unevaluated properties not being depleted	Unevaluated properties not being depleted	127,116		142,354		Unevaluated properties not being depleted	60,260		70,020
Less accumulated depletion and impairment	Less accumulated depletion and impairment	(6,429,794)		(5,725,114)		Less accumulated depletion and impairment	(6,852,688)		(6,817,949)
Oil and natural gas properties, net	Oil and natural gas properties, net	1,386,430		1,839,039		Oil and natural gas properties, net	1,160,713		1,127,003
Midstream service assets, net	Midstream service assets, net	116,826		128,678		Midstream service assets, net	111,083		112,697
Other fixed assets, net	Other fixed assets, net	33,001		32,504		Other fixed assets, net	31,576		32,011
Property and equipment, net	Property and equipment, net	1,536,257		2,000,221		Property and equipment, net	1,303,372		1,271,711

Derivatives		40,258		23,387

Operating lease right-of-use assets	Operating lease right-of-use assets	23,844		28,343		Operating lease right-of-use assets	14,955		17,973
Other noncurrent assets, net	Other noncurrent assets, net	13,970		12,007		Other noncurrent assets, net	18,487		16,336

Total assets	Total assets	$	1,870,588	$	2,264,437	Total assets	$	1,474,903	$	1,442,610
Liabilities and stockholders' equity	Liabilities and stockholders' equity					Liabilities and stockholders' equity
Current liabilities:	Current liabilities:					Current liabilities:
Accounts payable and accrued liabilities	Accounts payable and accrued liabilities	$	47,433	$	40,521	Accounts payable and accrued liabilities	$	49,065	$	38,279

Accrued capital expenditures	Accrued capital expenditures	21,304		36,328		Accrued capital expenditures	27,924		28,275
Undistributed revenue and royalties	Undistributed revenue and royalties	22,597		33,123		Undistributed revenue and royalties	32,018		24,728

Derivatives	Derivatives	192		7,698		Derivatives	128,394		31,826

Operating lease liabilities	Operating lease liabilities	11,696		14,042		Operating lease liabilities	11,263		11,721
Other current liabilities	Other current liabilities	54,567		39,184		Other current liabilities	43,579		62,766

Total current liabilities	Total current liabilities	157,789		170,896		Total current liabilities	292,243		197,595
Long-term debt, net	Long-term debt, net	1,258,164		1,170,417		Long-term debt, net	1,145,374		1,179,266
Derivatives	Derivatives	602		—		Derivatives	29,821		12,051

Asset retirement obligations	Asset retirement obligations	62,352		60,691		Asset retirement obligations	66,280		64,775
Operating lease liabilities	Operating lease liabilities	14,670		17,208		Operating lease liabilities	6,459		8,918
Other noncurrent liabilities	Other noncurrent liabilities	991		3,351		Other noncurrent liabilities	3,294		1,448

Total liabilities	Total liabilities	1,494,568		1,422,563		Total liabilities	1,543,471		1,464,053
Commitments and contingencies	Commitments and contingencies					Commitments and contingencies	0		0
Stockholders' equity:	Stockholders' equity:					Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and 0 issued as of June 30, 2020 and December 31, 2019		—		—
Common stock, $0.01 par value, 22,500,000 shares authorized and 11,939,307 and 11,864,604 issued and outstanding as of June 30, 2020 and December 31, 2019, respectively ⁽¹⁾		119		2,373
Preferred stock, $0.01 par value, 50,000,000 shares authorized and 0 issued as of March 31, 2021 and December 31, 2020						Preferred stock, $0.01 par value, 50,000,000 shares authorized and 0 issued as of March 31, 2021 and December 31, 2020	0		0
Common stock, $0.01 par value, 22,500,000 shares authorized and 12,899,660 and 12,020,164 issued and outstanding as of March 31, 2021 and December 31, 2020, respectively						Common stock, $0.01 par value, 22,500,000 shares authorized and 12,899,660 and 12,020,164 issued and outstanding as of March 31, 2021 and December 31, 2020, respectively	129		120
Additional paid-in capital	Additional paid-in capital	2,392,564		2,385,355		Additional paid-in capital	2,426,769		2,398,464
Accumulated deficit	Accumulated deficit	(2,016,663)		(1,545,854)		Accumulated deficit	(2,495,466)		(2,420,027)

Total stockholders' equity	Total stockholders' equity	376,020		841,874		Total stockholders' equity	(68,568)		(21,443)
Total liabilities and stockholders' equity	Total liabilities and stockholders' equity	$	1,870,588	$	2,264,437	Total liabilities and stockholders' equity	$	1,474,903	$	1,442,610

~~(1)Common stock shares were retroactively adjusted for the Company's 1-for-20 reverse stock split effective June 1, 2020. See Note 7.a.~~

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

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Laredo Petroleum, Inc.

Consolidated statements of operations

(in thousands, except per share data)

(Unaudited)


		Three months ended June 30,						Six months ended June 30,							Three months ended March 31,
		2020		2019		2020		2019			2021		2020
Revenues:	Revenues:									Revenues:
Oil sales	Oil sales	$	70,105	$	160,030	$	190,083	$	289,201	Oil sales	$	127,701	$	119,978
NGL sales	NGL sales	13,228		22,197		24,786		54,432		NGL sales	41,678		11,558
Natural gas sales	Natural gas sales	10,810		1,636		15,159		13,606		Natural gas sales	33,078		4,349
Midstream service revenues	Midstream service revenues	2,281		2,610		4,964		5,493		Midstream service revenues	1,296		2,683
Sales of purchased oil	Sales of purchased oil	14,164		30,170		80,588		62,858		Sales of purchased oil	46,477		66,424
Total revenues	Total revenues	110,588		216,643		315,580		425,590		Total revenues	250,230		204,992
Costs and expenses:	Costs and expenses:									Costs and expenses:
Lease operating expenses	Lease operating expenses	20,591		23,632		42,631		46,241		Lease operating expenses	18,918		22,040
Production and ad valorem taxes	Production and ad valorem taxes	6,938		11,328		16,182		18,547		Production and ad valorem taxes	13,283		9,244
Transportation and marketing expenses	Transportation and marketing expenses	11,181		4,891		24,725		9,650		Transportation and marketing expenses	12,127		13,544
Midstream service expenses	Midstream service expenses	815		607		1,985		2,210		Midstream service expenses	858		1,170

Costs of purchased oil	Costs of purchased oil	16,117		30,172		95,414		62,863		Costs of purchased oil	49,916		79,297
General and administrative	General and administrative	10,659		11,056		23,221		32,575		General and administrative	13,073		12,562
Organizational restructuring expenses		4,200		10,406		4,200		10,406

Depletion, depreciation and amortization	Depletion, depreciation and amortization	66,574		65,703		127,876		128,801		Depletion, depreciation and amortization	38,109		61,302

Impairment expense	Impairment expense	406,448		—		593,147		—		Impairment expense	0		186,699
Other operating expenses	Other operating expenses	1,117		1,020		2,223		2,072		Other operating expenses	1,143		1,106
Total costs and expenses	Total costs and expenses	544,640		158,815		931,604		313,365		Total costs and expenses	147,427		386,964
Operating income (loss)	Operating income (loss)	(434,052)		57,828		(616,024)		112,225		Operating income (loss)	102,803		(181,972)
Non-operating income (expense):	Non-operating income (expense):									Non-operating income (expense):
Gain (loss) on derivatives, net	Gain (loss) on derivatives, net	(90,537)		88,394		207,299		40,029		Gain (loss) on derivatives, net	(154,365)		297,836
Interest expense										Interest expense	(25,946)		(24,970)

Loss on extinguishment of debt										Loss on extinguishment of debt	0		(13,320)
Loss on disposal of assets, net										Loss on disposal of assets, net	(72)		(602)

Interest expense		(27,072)		(15,765)		(52,042)		(31,312)
Litigation settlement		—		42,500		—		42,500
Loss on extinguishment of debt		—		—		(13,320)		—
Gain (loss) on disposal of assets, net		152		(670)		(450)		(1,609)
Other income (expense), net		(16)		2,846		75		3,713
Write-off of debt issuance costs		(1,103)		—		(1,103)		—
Other income, net										Other income, net	1,379		91
Total non-operating income (expense), net	Total non-operating income (expense), net	(118,576)		117,305		140,459		53,321		Total non-operating income (expense), net	(179,004)		259,035
Income (loss) before income taxes	Income (loss) before income taxes	(552,628)		175,133		(475,565)		165,546		Income (loss) before income taxes	(76,201)		77,063
Income tax benefit (expense):	Income tax benefit (expense):									Income tax benefit (expense):

Deferred	Deferred	7,173		(1,751)		4,756		(1,655)		Deferred	762		(2,417)
Total income tax benefit (expense)	Total income tax benefit (expense)	7,173		(1,751)		4,756		(1,655)		Total income tax benefit (expense)	762		(2,417)

Net income (loss)	Net income (loss)	$	(545,455)	$	173,382	$	(470,809)	$	163,891	Net income (loss)	$	(75,439)	$	74,646
Net income (loss) per common share ⁽¹⁾:	Net income (loss) per common share ⁽¹⁾:									Net income (loss) per common share (1):

Basic	Basic	$	(46.75)	$	14.99	$	(40.44)	$	14.19	Basic	$	(6.33)	$	6.43

Diluted	Diluted	$	(46.75)	$	14.98	$	(40.44)	$	14.15	Diluted	$	(6.33)	$	6.39
Weighted-average common shares outstanding⁽¹⁾:	Weighted-average common shares outstanding⁽¹⁾:									Weighted-average common shares outstanding(1):
Basic	Basic	11,667		11,570		11,642		11,547		Basic	11,918		11,618
Diluted	Diluted	11,667		11,578		11,642		11,586		Diluted	11,918		11,673

(1)~~Net~~For the three months ended March 31, 2020, net income ~~(loss)~~ per common share and weighted-average common shares outstanding were retroactively adjusted for the Company's 1-for-20 reverse stock split effective June 1, 2020 as discussed in Note ~~7.a.~~

7.b.

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

Table of Contents

Laredo Petroleum, Inc.

Consolidated 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 ⁽¹⁾	Amount					Shares ⁽¹⁾			Amount					Total			Shares		Amount				Additional paid-in capital								Amount					Accumulated deficit
Balance, March 31, 2020		11,970	$	2,394	$	2,388,035	—		$	—		$	(1,471,208)	$	919,221
Balance, December 31, 2020																Balance, December 31, 2020		12,020	$	120	$	2,398,464					0				$	0				$	(2,420,027)				$	(21,443)

Reverse stock split		—	(2,277)		2,277		—		—			—		—

Restricted stock awards⁽²⁾	Restricted stock awards⁽²⁾	13	2		(2)		—		—			—		—		Restricted stock awards⁽²⁾		188	2		(2)				—			—					—					0
Restricted stock forfeitures⁽²⁾		(37)	—		—		—		—			—		—
Restricted stock forfeitures																Restricted stock forfeitures		(1)	—		—				—			—					—					0

Stock exchanged for tax withholding	Stock exchanged for tax withholding	—	—		—		7		(122)			—		(122)		Stock exchanged for tax withholding		—	—		—				37			(1,290)					—					(1,290)

Retirement of treasury stock⁽²⁾		(7)	—		(122)		(7)		122			—		—
Retirement of treasury stock																Retirement of treasury stock		(37)	—		(1,290)				(37)			1,290					—					0

Share-settled equity-based compensation	Share-settled equity-based compensation	—	—		2,376		—		—			—		2,376		Share-settled equity-based compensation		—	—		2,738				—			—					—					2,738
Issuance of common stock, net of costs																Issuance of common stock, net of costs		724	7		26,859				—			—					—					26,866

Performance share conversion																Performance share conversion		6	—		—				—			—					—					—
Net loss																Net loss		—	—		—				—			—					(75,439)					(75,439)
Balance, March 31, 2021																Balance, March 31, 2021		12,900	$	129	$	2,426,769			0			$	0				$	(2,495,466)				$	(68,568)

																		Common stock			Additional paid-in capital				Treasury stock (at cost)								Accumulated deficit
																		Shares (1)	Amount					Shares (1)			Amount									Total
Net loss		—	—		—		—		—			(545,455)		(545,455)
Balance, June 30, 2020		11,939	$	119	$	2,392,564	—		$	—		$	(2,016,663)	$	376,020

		Common stock					Additional paid-in capital		Treasury stock (at cost)								Accumulated deficit
		Shares ⁽¹⁾	Amount					Shares ⁽¹⁾			Amount					Total
Balance, March 31, 2019		11,960	$	2,392	$	2,381,926	—		$	—		$	(1,212,886)	$	1,171,432
Balance, December 31, 2019																Balance, December 31, 2019		11,865	$	2,373			$	2,385,355		0				$	0				$	(1,545,854)				$	841,874
Restricted stock awards	Restricted stock awards	53	11		(11)		—		—			—		—		Restricted stock awards		138	28		(28)				—			—					—					0
Restricted stock forfeitures	Restricted stock forfeitures	(138)	(28)		28		—		—			—		—		Restricted stock forfeitures		(7)	(2)		2				—			—					—					0

Stock exchanged for tax withholding	Stock exchanged for tax withholding	—	—		—		1		(34)			—		(34)		Stock exchanged for tax withholding		—	—		—				26			(640)					—					(640)

Retirement of treasury stock	Retirement of treasury stock	(1)	—		(34)		(1)		34			—		—		Retirement of treasury stock		(26)	(5)		(635)				(26)			640					—					0

Share-settled equity-based compensation	Share-settled equity-based compensation	—	—		(459)		—		—			—		(459)		Share-settled equity-based compensation		—	—		3,341				—			—					—					3,341
Net income	Net income	—	—		—		—		—			173,382		173,382		Net income		—	—		—				—			—					74,646					74,646
Balance, June 30, 2019		11,874	$	2,375	$	2,381,450	—		$	—		$	(1,039,504)	$	1,344,321
Balance, March 31, 2020																Balance, March 31, 2020		11,970	$	2,394	$	2,388,035			0			$	0				$	(1,471,208)				$	919,221

(1) Shares presented were retroactively adjusted for the Company's 1-for-20 reverse stock split effective June 1, 2020 as discussed in Note ~~7.a.~~

~~(2)~~The amounts presented for common stock and additional paid-in capital include (i) unadjusted amounts for the period April 1, 2020 to May 31, 2020 and (ii) adjusted amounts for the period June 1, 2020 to June 30, 2020. See the "Reverse stock split" line item for the retroactive adjustment for the life-to-date activity through May 31, 2020.

7.b.

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

~~Table of Contents~~

~~Laredo Petroleum, Inc.~~

~~Consolidated statements of stockholders' equity~~

~~(in thousands)~~

~~(Unaudited)~~

Common stock Additional
paid-in capital Treasury stock (at cost) Accumulated deficit

Shares ⁽¹⁾
Amount
Shares ⁽¹⁾
Amount Total
Balance, December 31, 2019 11,865 $ 2,373 $ 2,385,355 — $ — $ (1,545,854) $ 841,874
Reverse stock split — (2,277) 2,277 — — — —
Restricted stock awards⁽²⁾
152 30 (30) — — — —
Restricted stock forfeitures⁽²⁾
(44) (2) 2 — — — —
Stock exchanged for tax withholding — — — 34 (762) — (762)
Retirement of treasury stock⁽²⁾
(34) (5) (757) (34) 762 — —
Share-settled equity-based compensation — — 5,717 — — — 5,717
Net loss — — — — — (470,809) (470,809)
Balance, June 30, 2020 11,939 $ 119 $ 2,392,564 — $ — $ (2,016,663) $ 376,020
Common stock Additional
paid-in capital Treasury stock (at cost) Accumulated deficit
Shares ⁽¹⁾
Amount
Shares ⁽¹⁾
Amount Total
Balance, December 31, 2018 11,697 $ 2,339 $ 2,375,286 — $ — $ (1,203,395) $ 1,174,230
Restricted stock awards 353 71 (71) — — — —
Restricted stock forfeitures (141) (28) 28 — — — —
Stock exchanged for tax withholding — — — 35 (2,646) — (2,646)
Stock exchanged for cost of exercise of stock options — — — 1 (76) — (76)
Retirement of treasury stock (36) (7) (2,715) (36) 2,722 — —
Exercise of stock options 1 — 76 — — — 76
Share-settled equity-based compensation — — 8,846 — — — 8,846
Net income — — — — — 163,891 163,891
Balance, June 30, 2019 11,874 $ 2,375 $ 2,381,450 — $ — $ (1,039,504) $ 1,344,321

~~(1)Shares presented were retroactively adjusted for the Company's 1-for-20 reverse stock split effective June 1, 2020 as discussed in Note 7.a.~~

~~(2)~~The amounts presented for common stock and additional paid-in capital include (i) unadjusted amounts for the period January 1, 2020 to May 31, 2020 and (ii) adjusted amounts for the period June 1, 2020 to June 30, 2020. See the "Reverse stock split" line item for the retroactive adjustment for the life-to-date activity through May 31, 2020.

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

Table of Contents

Laredo Petroleum, Inc.

Consolidated statements of cash flows

(in thousands)

(Unaudited)


		Six months ended June 30,							Three months ended March 31,
		2020		2019			2021		2020
Cash flows from operating activities:	Cash flows from operating activities:					Cash flows from operating activities:
Net income (loss)	Net income (loss)	$	(470,809)	$	163,891	Net income (loss)	$	(75,439)	$	74,646
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	Adjustments to reconcile net income (loss) to net cash provided by operating activities:					Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Share-settled equity-based compensation, net	Share-settled equity-based compensation, net	4,070		6,983		Share-settled equity-based compensation, net	2,068		2,376
Depletion, depreciation and amortization	Depletion, depreciation and amortization	127,876		128,801		Depletion, depreciation and amortization	38,109		61,302
Impairment expense	Impairment expense	593,147		—		Impairment expense	0		186,699
Mark-to-market on derivatives:						Mark-to-market on derivatives:
(Gain) loss on derivatives, net						(Gain) loss on derivatives, net	154,365		(297,836)
Settlements (paid) received for matured derivatives, net						Settlements (paid) received for matured derivatives, net	(41,174)		47,723

Mark-to-market on derivatives:
Gain on derivatives, net		(207,299)		(40,029)
Settlements received for matured derivatives, net		134,595		23,582
Settlements paid for early terminations of commodity derivatives, net		—		(5,409)

Premiums paid for commodity derivatives		(51,070)		(6,249)
Premiums received (paid) for commodity derivatives						Premiums received (paid) for commodity derivatives	9,041		(477)
Amortization of debt issuance costs	Amortization of debt issuance costs	2,274		1,693		Amortization of debt issuance costs	989		1,217

Amortization of operating lease right-of-use assets	Amortization of operating lease right-of-use assets	7,242		6,309		Amortization of operating lease right-of-use assets	2,997		4,377
Loss on extinguishment of debt	Loss on extinguishment of debt	13,320		—		Loss on extinguishment of debt	0		13,320
Deferred income tax (benefit) expense	Deferred income tax (benefit) expense	(4,756)		1,655		Deferred income tax (benefit) expense	(762)		2,417
Other, net	Other, net	3,341		4,187		Other, net	1,491		1,327
Changes in operating assets and liabilities:	Changes in operating assets and liabilities:					Changes in operating assets and liabilities:
Decrease in accounts receivable, net		16,110		17,537
Decrease (increase) in other current assets		2,584		(4,200)
(Increase) decrease in other noncurrent assets, net		(3,130)		3,077
Increase (decrease) in accounts payable and accrued liabilities		6,912		(18,215)
Decrease in undistributed revenue and royalties		(10,526)		(4,110)

Increase (decrease) in other current liabilities		12,378		(18,134)
Decrease in other noncurrent liabilities		(4,697)		(100)

Accounts receivable, net						Accounts receivable, net	(3,728)		9,635
Other current assets						Other current assets	(10,264)		4,033
Other noncurrent assets, net						Other noncurrent assets, net	(1,636)		(2,964)
Accounts payable and accrued liabilities						Accounts payable and accrued liabilities	9,065		25,059
Undistributed revenue and royalties						Undistributed revenue and royalties	7,290		(4,937)
Other current liabilities						Other current liabilities	(19,622)		(15,082)
Other noncurrent liabilities						Other noncurrent liabilities	(1,639)		(3,246)
Net cash provided by operating activities	Net cash provided by operating activities	171,562		261,269		Net cash provided by operating activities	71,151		109,589
Cash flows from investing activities:	Cash flows from investing activities:					Cash flows from investing activities:
Acquisitions of oil and natural gas properties, net	Acquisitions of oil and natural gas properties, net	(23,563)		(2,880)		Acquisitions of oil and natural gas properties, net	0		(22,876)
Capital expenditures:	Capital expenditures:					Capital expenditures:

Oil and natural gas properties	Oil and natural gas properties	(241,939)		(284,616)		Oil and natural gas properties	(68,329)		(135,376)
Midstream service assets	Midstream service assets	(1,761)		(5,449)		Midstream service assets	(329)		(761)
Other fixed assets	Other fixed assets	(2,069)		(965)		Other fixed assets	(551)		(829)

Proceeds from dispositions of capital assets, net of selling costs	Proceeds from dispositions of capital assets, net of selling costs	728		936		Proceeds from dispositions of capital assets, net of selling costs	189		51
Net cash used in investing activities	Net cash used in investing activities	(268,604)		(292,974)		Net cash used in investing activities	(69,020)		(159,791)
Cash flows from financing activities:	Cash flows from financing activities:					Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility	Borrowings on Senior Secured Credit Facility	—		80,000		Borrowings on Senior Secured Credit Facility	15,000		0
Payments on Senior Secured Credit Facility	Payments on Senior Secured Credit Facility	(100,000)		(35,000)		Payments on Senior Secured Credit Facility	(50,000)		(100,000)
Issuance of January 2025 Notes and January 2028 Notes	Issuance of January 2025 Notes and January 2028 Notes	1,000,000		—		Issuance of January 2025 Notes and January 2028 Notes	0		1,000,000

Extinguishment of debt	Extinguishment of debt	(808,855)		—		Extinguishment of debt	0		(808,855)

Proceeds from issuance of common stock, net of costs						Proceeds from issuance of common stock, net of costs	26,866		0

Stock exchanged for tax withholding	Stock exchanged for tax withholding	(762)		(2,646)		Stock exchanged for tax withholding	(1,290)		(640)

Payments for debt issuance costs	Payments for debt issuance costs	(18,451)		—		Payments for debt issuance costs	0		(18,383)
Net cash provided by financing activities		71,932		42,354
Net increase (decrease) in cash and cash equivalents		(25,110)		10,649
Other liabilities						Other liabilities	2,798		0
Net cash (used in) provided by financing activities						Net cash (used in) provided by financing activities	(6,626)		72,122
Net (decrease) increase in cash and cash equivalents						Net (decrease) increase in cash and cash equivalents	(4,495)		21,920
Cash and cash equivalents, beginning of period	Cash and cash equivalents, beginning of period	40,857		45,151		Cash and cash equivalents, beginning of period	48,757		40,857
Cash and cash equivalents, end of period	Cash and cash equivalents, end of period	$	15,747	$	55,800	Cash and cash equivalents, end of period	$	44,262	$	62,777

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, primarily in the Permian Basin of West Texas. The Company has identified 1 operating segment: exploration and production. 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.

b. Basis of presentation

The 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 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 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, ~~2019~~2020 is derived from the Company's audited consolidated financial statements. In the opinion of management, the unaudited consolidated financial statements reflect all necessary adjustments to present fairly the Company's financial position as of ~~June 30, 2020,~~March 31, 2021, results of operations for the three ~~and six~~ months ended ~~June 30,~~March 31, 2021 and 2020 ~~and 2019~~ and cash flows for the ~~six~~three months ended ~~June 30, 2020~~March 31, 2021 and ~~2019.~~2020.

Certain disclosures have been condensed or omitted from the unaudited consolidated financial statements. Accordingly, the unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the ~~2019~~2020 Annual Report.

Significant accounting policies

See Note 2 in the ~~2019~~2020 Annual Report for discussion of significant accounting policies.

Use of estimates in the preparation of interim unaudited consolidated financial statements

The preparation of the 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.

~~For~~See Note 2.b in the 2020 Annual Report for further information regarding the use of estimates and ~~assumptions, see Note 2.b in the 2019 Annual Report and Notes 8.e and 8.f pertaining to the Company's 2020 performance unit awards and phantom unit awards, respectively.~~

~~Reclassifications~~

Certain amounts in the accompanying unaudited consolidated financial statements have been reclassified to conform to the 2020 presentation. These reclassifications had no impact on previously reported total assets, total liabilities, net income (loss), stockholders' equity or total operating, investing or financing cash flows.assumptions.

Note 2—New accounting standards

The Company ~~considers~~considered the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board to the Accounting Standards Codification ("ASC") and has determined there are no ASUs that are not yet adopted and meaningful to disclose as of ~~June 30, 2020.~~March 31, 2021.

Note 3—Acquisitions and divestiture

a. 2020 Asset acquisitions

On ~~January 1,~~October 16, 2020 and November 16, 2020, the Company ~~adopted ASU 2016-13~~closed a bolt-on acquisition of 2,758 and 80 net acres, respectively, including production of 210 BOE per day, in Howard County, Texas for an aggregate purchase price of $11.6 million, subject to ~~Topic 326,~~ ~~Financial Instruments—Credit Losses, that requires~~customary post-closing purchase price adjustments.

On April 30, 2020, the Company closed an ~~allowance~~acquisition of 180 net acres in Howard County, Texas for ~~expected credit losses~~$0.6 million. The acquisition also provides for one or more potential contingent payments to be recorded against newly recognized financial assets measured at an amortized cost basis. The measurement of expected credit losses is based on relevant information about past events, including historicalpaid by the Company if the arithmetic average


Table of Contents			Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

experience, current conditions, and reasonable and supportable forecasts that affect the collectability of the reported amount. The Company has included these factors in its analysis and determined there was minimal impact to the unaudited consolidated financial statements for the three and six months ended June 30, 2020.

~~Note 3—Acquisitions and divestitures~~

~~a. 2020 Asset acquisitions and divestitures~~

On April 30, 2020, the Company closed an acquisition of 180 net acres in Howard County, Texas for a total purchase price of $0.6 million. The acquisition also provides for one or more potential contingent payments to be paid by the Company if the arithmetic average of the monthly settlement West Texas Intermediate ("WTI") NYMEX prices exceed certain thresholds for the contingency period beginning on January 1, 2021 and ending on the earlier of December 31, 2022 or the date the counterparty has received the maximum consideration of $1.2 million. The fair value of ~~the~~this contingent consideration was $0.2 million as of the acquisition date, which was recorded as part of the basis in the oil and natural gas properties acquired and as a contingent consideration derivative liability. See ~~Note~~Notes 9.c and 10.a for ~~the fair value~~additional discussion of ~~the~~this contingent ~~consideration as of June 30, 2020.~~consideration.

On February 4, 2020, the Company closed a transaction for $22.5 million acquiring 1,180 net acres and divesting 80 net acres in Howard County, Texas.

All transaction costs ~~for the asset acquisitions~~ were capitalized and ~~were~~are included in "Oil and natural gas properties" on the consolidated balance sheet.

b. 2020 Divestiture

On April 9, 2020, the Company closed a divestiture of 80 net acres and working interests in 2 producing wells in Glasscock County, Texas for ~~a total sales price of~~ $0.7 million, net of customary ~~closing and subject to customary~~ post-closing ~~purchase~~sales price adjustments. The divestiture 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 oil and natural gas properties were eliminated from the ongoing operations of the Company, and the Company has no continuing involvement in the properties. This divestiture ~~does~~did not represent a strategic shift and ~~will~~has not ~~have~~had a major effect on the Company's future operations or financial results.

~~b. 2019 Acquisitions~~

~~Asset acquisitions~~

On December 12, 2019, the Company closed an acquisition of 7,360 net acres and 750 net royalty acres in Howard County, Texas for $131.7 million, net of customary closing and subject to customary post-closing purchase price adjustments. The acquisition also provides for a potential contingent payment, where the Company is required to pay $20.0 million if the arithmetic average of the monthly settlement WTI NYMEX prices for each consecutive calendar month for the one-year period beginning January 1, 2020 through December 31, 2020 exceeds a certain threshold. The fair value of the contingent consideration was $6.2 million as of the acquisition date, which was recorded as part of the basis in the oil and natural gas properties acquired and as a contingent consideration derivative liability. See Note 10.a for the fair value of the contingent consideration as of June 30, 2020. All transaction costs were capitalized and were included in "Oil and natural gas properties" on the consolidated balance sheet. This acquisition was primarily financed through borrowings under the Senior Secured Credit Facility. Post-closing is expected to be finalized during the third quarter of 2020.

~~On June 20, 2019, the Company acquired 640 net acres in Reagan County, Texas for $2.9 million.~~

~~Business combination~~

On December 6, 2019, the Company closed a bolt-on acquisition of 4,475 contiguous net acres and working interests in 49 producing wells in western Glasscock County, Texas, which included net production of 1,400 barrels of oil equivalent ("BOE") per day at the time of acquisition, for $64.6 million, net of customary closing purchase price adjustments. This acquisition was financed through borrowings under the Senior Secured Credit Facility. Post-closing was finalized during the three months ended June 30, 2020.

This acquisition was accounted for as a business combination. Accordingly, the Company conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair


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

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

values, while transaction costs associated with the acquisition were expensed. The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair values of evaluated and unevaluated oil and natural gas properties. The fair values of these properties were 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, 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 cash flows 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 10 in the 2019 Annual Report.

~~The following table reflects an aggregate of the final estimate of the fair values of the assets acquired and liabilities assumed in this business combination on December 6, 2019:~~


~~(in thousands)~~	~~Fair values of acquisition~~
~~Fair values of net assets:~~
~~Evaluated oil and natural gas properties~~	$	~~29,921~~
~~Unevaluated oil and natural gas properties~~	~~34,700~~
~~Asset retirement cost~~	~~2,728~~
~~Total assets acquired~~	~~67,349~~
~~Asset retirement obligations~~	~~(2,728)~~
~~Net assets acquired~~	$	~~64,621~~
~~Fair values of consideration paid for net assets:~~
~~Cash consideration~~	$	~~64,621~~

c. Exchange of unevaluated oil and natural gas properties

From time to time, the Company exchanges undeveloped acreage with third parties. The exchanges are recorded at fair value and the difference is accounted for as an adjustment of capitalized costs with no gain or loss recognized pursuant to the rules governing full cost accounting, unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas.

Note 4—Leases

The Company has recognized operating lease right-of-use assets and operating lease liabilities on the unaudited consolidated balance sheets for leases of commercial real estate with lease terms extending into 2027 and drilling, completion, production and other equipment leases with lease terms extending into 2022. The Company's lease costs include those that are recognized in net income (loss) during the period and capitalized as part of the cost of another asset in accordance with GAAP.

The lease costs related to drilling, completion and production activities are reflected at the Company's net ownership, which is consistent with the principles of proportional consolidation, and lease commitments are reflected on a gross basis. As of March 31, 2021, the Company had an average working interest of 97% in Laredo-operated active productive wells. See Note 5 in the 2020 Annual Report for additional discussion of the Company's leases.


Table of Contents			Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note 4—5—Property and equipment

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


(in thousands)	(in thousands)	June 30, 2020		December 31, 2019		(in thousands)	March 31, 2021		December 31, 2020
Evaluated oil and natural gas properties	Evaluated oil and natural gas properties	$	7,689,108	$	7,421,799	Evaluated oil and natural gas properties	$	7,953,141	$	7,874,932
Less accumulated depletion and impairment	Less accumulated depletion and impairment	(6,429,794)		(5,725,114)		Less accumulated depletion and impairment	(6,852,688)		(6,817,949)
Evaluated oil and natural gas properties, net	Evaluated oil and natural gas properties, net	1,259,314		1,696,685		Evaluated oil and natural gas properties, net	1,100,453		1,056,983

Unevaluated oil and natural gas properties not being depleted	Unevaluated oil and natural gas properties not being depleted	127,116		142,354		Unevaluated oil and natural gas properties not being depleted	60,260		70,020

Midstream service assets	Midstream service assets	181,239		180,932		Midstream service assets	182,405		181,718
Less accumulated depreciation and impairment	Less accumulated depreciation and impairment	(64,413)		(52,254)		Less accumulated depreciation and impairment	(71,322)		(69,021)
Midstream service assets, net	Midstream service assets, net	116,826		128,678		Midstream service assets, net	111,083		112,697

Depreciable other fixed assets	Depreciable other fixed assets	38,336		37,894		Depreciable other fixed assets	37,612		37,454
Less accumulated depreciation and amortization	Less accumulated depreciation and amortization	(24,533)		(23,649)		Less accumulated depreciation and amortization	(24,937)		(24,344)
Depreciable other fixed assets, net	Depreciable other fixed assets, net	13,803		14,245		Depreciable other fixed assets, net	12,675		13,110

Land	Land	19,198		18,259		Land	18,901		18,901

Total property and equipment, net	Total property and equipment, net	$	1,536,257	$	2,000,221	Total property and equipment, net	$	1,303,372	$	1,271,711

See Note 10.b for discussion of impairments of long-lived assets during the ~~six~~three months ended ~~June 30,~~March 31, 2020. See Note 6 in the ~~2019~~2020 Annual Report for additional discussion of the Company's property and equipment.

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 employee-related costs, incurred for the purpose of acquiring, exploring for or developing oil and natural gas properties, are capitalized and, once evaluated, depleted on a composite unit-of-production method based on estimates of proved oil, NGL and natural gas reserves. The depletion base includes estimated future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage values. Capitalized costs 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 employee-related costs, associated with production and general corporate activities are expensed in the period incurred.

The Company excludes unevaluated property acquisition costs and exploration costs 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 and such costs become 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 proved 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.

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


Table of Contents			Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table presents costs incurred in the acquisition, exploration and development of oil and natural gas properties, with asset retirement obligations included in evaluated property acquisition costs and development costs, for the periods presented:


		Three months ended June 30,						Six months ended June 30,							Three months ended March 31,
(in thousands)	(in thousands)	2020		2019		2020		2019		(in thousands)	2021		2020
Property acquisition costs:	Property acquisition costs:							—		Property acquisition costs:
Evaluated	Evaluated	$	—	$	—	$	7,586	$	—	Evaluated	$	0	$	7,586
Unevaluated	Unevaluated	912		2,880		16,468		2,880		Unevaluated	0		15,556
Exploration costs	Exploration costs	3,374		5,116		10,084		12,621		Exploration costs	3,957		6,710
Development costs	Development costs	72,567		123,664		218,725		276,381		Development costs	64,492		146,158
Total oil and natural gas properties costs incurred	Total oil and natural gas properties costs incurred	$	76,853	$	131,660	$	252,863	$	291,882	Total oil and natural gas properties costs incurred	$	68,449	$	176,010

The aforementioned total oil and natural gas properties costs incurred included certain employee-related costs as shown in the table below.

The following table presents capitalized employee-related costs incurred in the acquisition, exploration and development of oil and natural gas properties for the periods presented:


		Three months ended June 30,						Six months ended June 30,							Three months ended March 31,
(in thousands)	(in thousands)	2020		2019		2020		2019		(in thousands)	2021		2020
Capitalized employee-related costs	Capitalized employee-related costs	$	4,092	$	3,430	$	8,597	$	10,112	Capitalized employee-related costs	$	4,241	$	4,505

The following table presents depletion expense, which is included in "Depletion, depreciation and amortization" on the unaudited consolidated statements of operations, and depletion expense per BOE sold of evaluated oil and natural gas properties for the periods presented:


		Three months ended June 30,						Six months ended June 30,							Three months ended March 31,
		2020		2019		2020		2019
(in thousands except per BOE data)										(in thousands except per BOE data)	2021		2020
Depletion expense of evaluated oil and natural gas properties	Depletion expense of evaluated oil and natural gas properties	$	63,305	$	61,938	$	121,057	$	121,308	Depletion expense of evaluated oil and natural gas properties	$	34,725	$	57,752
Depletion expense per BOE sold	Depletion expense per BOE sold	$	7.39	$	8.27	$	7.36	$	8.51	Depletion expense per BOE sold	$	4.88	$	7.33

The full cost ceiling is based principally on the estimated future net ~~revenues~~cash flows from proved oil, NGL and natural gas reserves, which exclude the effect of the Company's commodity derivative transactions, 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, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the ~~wellhead~~delivery point ("Realized Prices") without giving effect to the Company's commodity derivative transactions. The Realized Prices are utilized to calculate the estimated future net ~~revenues~~cash flows in the full cost ceiling calculation. 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 proved reserves and other relevant data. 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 expensed in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible.

The unamortized cost of evaluated oil and natural gas properties being depleted did not exceed the full cost ceiling as of March 31, 2021, and as such, the Company did not record a first-quarter full cost ceiling impairment.

108


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Condensed notes to the consolidated financial statements

(Unaudited)

The following table presents the Benchmark Prices and the Realized Prices as of the dates presented:


		June 30, 2020		March 31, 2020		December 31, 2019		September 30, 2019		June 30, 2019			March 31, 2021		December 31, 2020		September 30, 2020		June 30, 2020
Benchmark Prices:	Benchmark Prices:											Benchmark Prices:
Oil ($/Bbl)	Oil ($/Bbl)	$	43.60	$	52.23	$	52.19	$	54.27	$	57.90	Oil ($/Bbl)	$	36.49	$	36.04	$	39.88	$	43.60
NGL ($/Bbl)⁽¹⁾	NGL ($/Bbl)⁽¹⁾	$	16.87	$	19.36	$	21.14	$	23.93	$	28.21	NGL ($/Bbl)(1)	$	19.24	$	16.63	$	16.95	$	16.87
Natural gas ($/MMBtu)	Natural gas ($/MMBtu)	$	0.87	$	0.58	$	0.87	$	0.85	$	1.14	Natural gas ($/MMBtu)	$	1.69	$	1.21	$	1.06	$	0.87
Realized Prices:	Realized Prices:											Realized Prices:
Oil ($/Bbl)	Oil ($/Bbl)	$	44.97	$	52.47	$	52.12	$	52.86	$	55.69	Oil ($/Bbl)	$	38.28	$	37.69	$	41.08	$	44.97
NGL ($/Bbl)	NGL ($/Bbl)	$	7.66	$	10.47	$	12.21	$	14.78	$	18.64	NGL ($/Bbl)	$	9.92	$	7.43	$	7.71	$	7.66
Natural gas ($/Mcf)	Natural gas ($/Mcf)	$	0.53	$	0.28	$	0.53	$	0.52	$	0.70	Natural gas ($/Mcf)	$	1.20	$	0.79	$	0.68	$	0.53

(1) Based on the Company's average composite NGL barrel.

The following table presents full cost ceiling impairment expense, which is included in "Impairment expense" on the unaudited consolidated statements of operations for the periods presented:

Three months ended June 30, Six months ended June 30,
(in thousands) 2020 2019 2020 2019
Full cost ceiling impairment expense $ 406,448 $ — $ 583,630 $ —

~~Note 5—Leases~~

The Company has recognized operating lease right-of-use assets and operating lease liabilities on the unaudited consolidated balance sheets for leases of commercial real estate with lease terms extending into 2027 and drilling, completions, production and other equipment leases with lease terms extending through 2025. The Company's lease costs include those that are recognized in net income (loss) during the period as well as those that are capitalized as part of the cost of another asset in accordance with other GAAP.

The lease costs related to drilling, completions and production activities are reflected at the Company's net ownership, which is consistent with the principals of proportional consolidation, and lease commitments are reflected on a gross basis. As of June 30, 2020, the Company had an average working interest of 97% in Laredo-operated active productive wells in its core operating area. See Note 5 in the 2019 Annual Report for additional discussion of the Company's leases.


	Three months ended March 31,
(in thousands)	2021		2020
Full cost ceiling impairment expense	$	0	$	177,182

Note 6—Debt

a. January 2025 Notes and January 2028 Notes

On January 24, 2020, the Company completed an offer and sale (the "Offering") of $600.0 million in aggregate principal amount of 9 1/2% senior unsecured notes due 2025 (the "January 2025 Notes") and $400.0 million in aggregate principal amount of 10 1/8% senior unsecured notes due 2028 (the "January 2028 Notes"). Interest for both the January 2025 Notes and January 2028 Notes is payable semi-annually, in cash in arrears on January 15 and July 15 of each year. The first interest payment was made on July 15, 2020, and consisted of interest from closing to that date. The terms of the January 2025 Notes and January 2028 Notes include covenants, which are in addition to but different than similar covenants in the Senior Secured Credit Facility, which limit the Company's ability to incur indebtedness, make restricted payments, grant liens and dispose of assets.

The January 2025 Notes and January 2028 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


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

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

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 received net proceeds of ~~approximately~~ $982.0 million from the Offering, after deducting underwriting discounts and commissions and estimated offering expenses. The proceeds from the Offering were used (i) to fund Tender Offers (defined below) for the Company's January 2022 Notes and March 2023 Notes (defined below), (ii) to repay the Company's January 2022 Notes and March 2023 Notes that remained outstanding after settling the Tender Offers and (iii) for general corporate purposes, including repayment of a portion of the borrowings outstanding under the ~~Company's~~ Senior Secured Credit Facility.

In November 2020, the Company's board of directors authorized a $50.0 million bond repurchase program. During the year ended December 31, 2020, the Company repurchased $22.1 million in aggregate principal amount of the January 2025 Notes and $39.0 million in aggregate principal amount of the January 2028 Notes for aggregate consideration of $13.9 million and $24.2 million, respectively, plus accrued and unpaid interest. The Company recognized a gain on extinguishment


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Condensed notes to the consolidated financial statements

(Unaudited)

of $22.3 million related to the difference between the consideration paid and the net carrying amounts of the extinguished portions of the January 2025 Notes and January 2028 Notes.

b. January 2022 Notes and March 2023 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 were due to mature on January 15, 2022 and bore 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 were fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases.

On 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 were due to mature on March 15, 2023 and bore 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 were fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases.

On January 6, 2020, the Company commenced cash tender offers and consent solicitations for any or all of its outstanding January 2022 Notes and March 2023 Notes (collectively, the "Tender Offers"). On January 24, 2020 and February 6, 2020, the Company settled the Tender Offers for the outstanding principal ~~outstanding~~ amounts of $428.9 million and $299.4 million, respectively, for consideration for tender offers and early tender premiums of $431.6 million and $304.1 million for the January 2022 Notes and March 2023 Notes, respectively, plus accrued and unpaid interest. On January 29, 2020, the Company redeemed the remaining $21.1 million of January 2022 Notes not tendered under the Tender Offers at a redemption price of 100.000% of the principal amount thereof, plus accrued and unpaid interest. On March 15, 2020, the Company redeemed the remaining $50.6 million of March 2023 Notes not tendered under the Tender Offers at a redemption price of 101.563% of the principal amount thereof, plus accrued and unpaid interest. The Company recognized a loss on extinguishment of $13.3 million related to the difference between the consideration for tender offers, early tender premiums and redemption prices and the net carrying amounts of the extinguished January 2022 Notes and March 2023 Notes.

c. Senior Secured Credit Facility

As of ~~June 30, 2020,~~March 31, 2021, the Senior Secured Credit Facility, which matures on April 19, 2023, had a maximum credit amount of $2.0 billion, a borrowing base and an aggregate elected commitment of $725.0 million each, with ~~$275.0~~$220.0 million outstanding, and was subject to an interest rate of ~~2.19%~~2.625%. The Senior Secured Credit Facility contains both financial and non-financial covenants, all of which the Company was in compliance with 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 $80.0 million. As of ~~June 30, 2020~~March 31, 2021 and December 31, ~~2019,~~2020, the Company had one letter of credit outstanding of $44.1 million ~~and $14.7 million, respectively,~~ under the Senior Secured Credit Facility. The Senior Secured Credit Facility is fully and unconditionally guaranteed by LMS and GCM. For additional information see Note ~~7.d~~7.c in the ~~2019~~2020 Annual Report. See Note ~~19.a~~18.a for discussion of ~~the (i) additional~~a borrowing and a payment on the Senior Secured Credit Facility ~~and (ii) waiver received from the lenders under the Senior Secured Credit Facility of certain representations and warranties relating~~subsequent to ~~the Company's~~ March 31, ~~2020 quarterly results subsequent to June 30, 2020.~~2021.

The Company's measurements of Adjusted EBITDA (non-GAAP) for financial reporting as compared to compliance under its debt agreements differ.

d. Debt issuance costs

The Company capitalized debt issuance costs of $18.4 million during the three months ended March 31, 2020 in connection with the issuance of the January 2025 Notes and January 2028 Notes. NaN debt issuance costs were capitalized during the three months ended March 31, 2021. The Company wrote off debt issuance costs during the three months ended March 31, 2020 in connection with the extinguishment of the January 2022 Notes and March 2023 Notes, which are included in "Loss on extinguishment of debt" on the unaudited consolidated statement of operations. NaN debt issuance costs were written off during the three months ended March 31, 2021.

The Company had total debt issuance costs of $15.7 million and $17.0 million, net of accumulated amortization of $23.1 million and $22.1 million, as of March 31, 2021 and December 31, 2020, respectively. Debt issuance costs related to the Company's January 2025 and January 2028 Notes are included in "Long-term debt, net" on the unaudited consolidated balance sheets. Debt issuance costs related to the Senior Secured Credit Facility are included in "Other noncurrent assets, net"


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Condensed notes to the consolidated financial statements

(Unaudited)

d.on the unaudited consolidated balance sheets. Debt issuance costs are amortized on a straight-line basis over the respective terms of the notes and the Senior Secured Credit Facility. See Note 7.e for additional discussion of debt issuance costs.

e. Long-term debt, net

The following table presents the Company's long-term debt and debt issuance costs, net included in "Long-term debt, net" on the unaudited consolidated balance sheets as of the dates presented:

June 30, 2020 December 31, 2019
(in thousands) Long-term debt Debt issuance costs, net Long-term debt, net Long-term debt Debt issuance costs, net Long-term debt, net
January 2022 Notes⁽¹⁾
$ — $ — $ — $ 450,000 $ (2,034) $ 447,966
March 2023 Notes⁽¹⁾
— — — 350,000 (2,549) 347,451
January 2025 Notes⁽²⁾
600,000 (9,979) 590,021 — — —
January 2028 Notes⁽²⁾
400,000 (6,857) 393,143 — — —
Senior Secured Credit Facility⁽³⁾
275,000 — 275,000 375,000 — 375,000
Long-term debt, net $ 1,275,000 $ (16,836) $ 1,258,164 $ 1,175,000 $ (4,583) $ 1,170,417


	March 31, 2021						December 31, 2020
(in thousands)	Long-term debt		Debt issuance costs, net		Long-term debt, net		Long-term debt		Debt issuance costs, net		Long-term debt, net
January 2025 Notes	577,913		(7,931)		569,982		577,913		(8,676)		569,237
January 2028 Notes	361,044		(5,652)		355,392		361,044		(6,015)		355,029
Senior Secured Credit Facility(1)	220,000		0		220,000		255,000		0		255,000
Long-term debt, net	$	1,158,957	$	(13,583)	$	1,145,374	$	1,193,957	$	(14,691)	$	1,179,266

(1)During the six months ended June 30, 2020, the Company wrote off debt issuance costs in connection with the extinguishment of the January 2022 Notes and the March 2023 Notes, which are included in "Loss on extinguishment of debt" on the unaudited consolidated statement of operations.

~~(2)Debt issuance costs for the January 2025 Notes and the January 2028 Notes are amortized on a straight-line basis over the respective terms of the notes.~~

~~(3)~~Debt issuance costs, net related to the Senior Secured Credit Facility of ~~$2.8~~$2.1 million and ~~$4.5~~$2.3 million as of ~~June 30, 2020~~March 31, 2021 and December 31, ~~2019,~~2020, respectively, are ~~reported~~included in "Other noncurrent assets, net" on the unaudited consolidated balance ~~sheets,~~sheets.

Note 7—Stockholders' equity

a. ATM Program

On February 23, 2021, the Company entered into an equity distribution agreement (the "Equity Distribution Agreement") with Wells Fargo Securities, LLC acting as sales agent and/or principal (the "Sales Agent"), pursuant to which the Company may offer and sell, from time to time through the Sales Agent, shares of its common stock, par value $0.01 per share (the "common stock"), having an aggregate gross sales price of up to $75.0 million through an "at-the-market" equity program (the "ATM Program").

Pursuant to the Equity Distribution Agreement, shares of common stock may be offered and sold in privately negotiated transactions or transactions that are ~~amortized~~deemed to be "at-the-market" offerings as defined in Rule 415 under the Securities Act, including by ordinary brokers’ transactions through the facilities of the New York Stock Exchange, to or through a market maker or as otherwise agreed with the Sales Agent. Under the terms of the Equity Distribution Agreement, the Company may also sell common stock from time to time to the Sales Agent as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common stock to the Sales Agent as principal would be pursuant to the terms of a separate terms agreement between the Company and the Sales Agent, which would be described in a separate prospectus supplement or pricing supplement.

As of March 31, 2021, the Company has sold 723,579 shares of its common stock pursuant to the ATM Program for net proceeds of approximately $26.9 million, after underwriting commissions and other related expenses. Proceeds from the share sales were utilized to reduce borrowings on the Senior Secured Credit Facility. The timing of any additional sales will depend on a ~~straight-line basis. In connection with~~variety of factors to be determined by the April 2020 reduction in borrowing base, the Company wrote off $1.1 million of debt issuance costs, which are included in "Write-off of debt issuance costs" on the unaudited consolidated statement of operations, and capitalized $0.1 million of debt issuance costs during the three months ended June 30, 2020.Company.

~~Note 7—Stockholders' equity~~

a.b. Reverse stock split and Authorized Share Reduction

On March 17, 2020, the board of directors authorized an amendment to the Company's amended and restated certificate of incorporation ("Certificate of Incorporation") to effect, at the discretion of the board of directors (i) a reverse stock split that would reduce the number of shares of outstanding common stock in accordance with a ratio to be determined by the board of directors within a range of 1-for-5 and 1-for-20 currently outstanding and (ii) a reduction of the number of authorized shares of common stock by a corresponding proportion ("Authorized Share Reduction").

On May 14, 2020, after receiving stockholder approval of the amendment to the ~~Company's~~ Certificate of Incorporation, ~~to effect, at the discretion of the board of directors, the reverse stock split and the Authorized Share Reduction,~~ the board of directors approved the implementation of the reverse stock split at a ratio of 1-for-20 currently outstanding shares of common stock, and the related corresponding Authorized Share Reduction.


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Condensed notes to the consolidated financial statements

(Unaudited)

On June 1, 2020, the amendment to the ~~Company's~~ Certificate of Incorporation became effective and effected the 1-for-20 reverse stock split of the Company's issued and outstanding common stock and the related Authorized Share Reduction from 450,000,000 to 22,500,000 authorized shares, par value $0.01 per share, with authorized shares of preferred stock remaining unchanged at 50,000,000, par value $0.01 per share, for a total of 72,500,000 shares of capital stock. See Note 8 for discussion of the ~~amendment to the~~ Equity Incentive Plan to(defined below), that proportionately ~~reduce~~reduced the number of ~~awards~~shares that may be granted.


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~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

b.c. Treasury stock

Treasury stock is recorded at cost, which includes incremental direct transaction costs, and is retired upon acquisition as a result of (i) stock exchanged to satisfy tax withholding that arises upon the lapse of restrictions on share-settled equity-based awards at the awardee's election or (ii) stock exchanged for the cost of exercise of stock options at the awardee's election.

Note 8—Equity Incentive Plan

The Laredo Petroleum, Inc. Omnibus Equity Incentive Plan ~~as amended and restated as of May 16, 2019~~ (the "Equity Incentive Plan"), provides for the granting of incentive awards in the form of restricted stock awards, stock option awards, performance share awards, outperformance share awards, performance unit awards, phantom unit awards and other awards. On June 1, 2020, in connection with the effectiveness of the reverse stock split and Authorized Share Reduction, the board of directors approved and adopted an amendment to the Equity Incentive Plan to proportionately adjust the limitations on awards that may be granted under the Equity Incentive Plan. Following the amendment, an aggregate of 1,492,500 shares of common stock may be issued under the Equity Incentive Plan. See Note ~~7.a~~7.b for additional discussion of the reverse stock split and Authorized Share Reduction.

~~The Company recognizes~~See Note 9.a in the ~~fair value~~2020 Annual Report for additional discussion of the Company's equity-based compensation awards, expected to vest over the requisite service period, as a charge against earnings, net of amounts capitalized. The Company's restricted stock awards, stock option awards, performance share awards and outperformance share award are accounted for as equity awards and the Company's performance unit awards and phantom unit awards are accounted for as liability awards. Equity-based compensation expense is included in "General and administrative" on the unaudited consolidated statements of operations. The Company capitalizes a portion of equity-based compensation for employees who are directly involved in the acquisition, exploration or development of oil and natural gas properties into the full cost pool. Capitalized equity-based compensation is included in "Evaluated properties" on the unaudited consolidated balance sheets.

a. Restricted stock awards

All service vesting restricted stock awards are treated as issued and outstanding in the unaudited consolidated financial statements. Per the award agreement terms, if employment is terminated prior to the restriction lapse date for reasons other than death or disability, the restricted stock awards are forfeited and canceled and are no longer considered issued and outstanding. If the termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. Restricted stock awards granted to employees vest inon a ~~variety of schedules that mainly include (i)~~ 33%, 33% and 34% ~~vesting~~schedule per year beginning on the first anniversary of the grant date and ~~(ii) full vesting on the first anniversary of the grant date. Restricted~~restricted stock awards granted to non-employee directors vest immediately on the grant date.

The following table reflects the restricted stock award activity for the ~~six~~three months ended ~~June 30, 2020:~~March 31, 2021:


(in thousands, except for weighted-average grant-date fair value)	(in thousands, except for weighted-average grant-date fair value)	Restricted stock awards⁽¹⁾	Weighted-average grant-date fair value (per share)⁽¹⁾		(in thousands, except for weighted-average grant-date fair value)	Restricted stock awards	Weighted-average grant-date fair value (per share)
Outstanding as of December 31, 2019		275	$	85.89
Outstanding as of December 31, 2020					Outstanding as of December 31, 2020	309	$	44.88
Granted	Granted	152	$	18.14	Granted	188	$	34.45
Forfeited	Forfeited	(44)	$	51.06	Forfeited	(1)	$	83.04
Vested⁽²⁾⁽¹⁾	Vested⁽²⁾⁽¹⁾	(123)	$	85.25	Vested⁽²⁾⁽¹⁾	(103)	$	65.07
Outstanding as of June 30, 2020		260	$	52.48
Outstanding as of March 31, 2021					Outstanding as of March 31, 2021	393	$	34.50

(1)~~Shares and per share data have been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 7.a.~~

~~(2)~~The aggregate intrinsic value of vested restricted stock awards for the ~~six~~three months ended ~~June 30, 2020~~March 31, 2021 was ~~$2.9~~$3.5 million.

The Company utilizes the closing stock price on the grant date to determine the fair value of restricted stock awards. As of ~~June 30, 2020,~~March 31, 2021, unrecognized equity-based compensation related to the restricted stock awards expected to vest was ~~$10.5~~$11.9 million. Such cost is expected to be recognized over a weighted-average period of ~~1.72~~2.18 years.

b. Stock option awards

As of March 31, 2021, the 11,362 outstanding stock option awards had a weighted-average exercise price of $257.42 per award and a weighted-average remaining contractual term of 3.75 years. There was no activity related to the stock option awards during the three months ended March 31, 2021. The vested and exercisable stock option awards as of March 31, 2021 had 0 intrinsic value.


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Condensed notes to the consolidated financial statements

(Unaudited)

~~b. Stock option awards~~

As of June 30, 2020, the 16,499 outstanding stock option awards have a weighted-average exercise price of $248.04 per award and a weighted-average remaining contractual term of 3.17 years. The stock option awards were adjusted for the Company's 1-for-20 reverse stock split as discussed in Note 7.a. There were de minimis cancellations and forfeitures of stock option awards during the six months ended June 30, 2020, and there were no grants or exercises. The vested and exercisable stock option awards as of June 30, 2020 had 0 intrinsic value.

c. Performance share awards

Performance share awards, which the Company has determined are equity awards, are subject to a combination of market, performance and service vesting criteria. For portions of awards with market criteria, which include: (i) the relative three-year total shareholder return ("TSR") comparing the Company's shareholder return to the shareholder return of the peer group specified in each award agreement ("RTSR Performance Percentage") and (ii) the Company's absolute three-year total shareholder return ("ATSR Appreciation"), a Monte Carlo simulation prepared by an independent third party is utilized to determine the grant-date (or modification date) fair value, and the associated expense is recognized on a straight-line basis over the ~~three-year~~three-year requisite service period of the awards. For portions of awards with performance criteria, ~~which is the Company's three-year return on average capital employed ("ROACE Percentage"),~~ the fair value is equal to the Company's closing stock price on the grant date (or modification date), and for each reporting period, the associated expense fluctuates and is adjusted based on an estimated payout of the number of shares of common stock to be delivered on the payment date for the ~~three-year~~three-year performance period.

These awards were granted in 2019 and 2018, and their market criteria consists of: (i) the relative three-year total shareholder return ("TSR") comparing the Company's shareholder return to the shareholder return of the peer group specified in each award agreement ("RTSR Performance Percentage") and (ii) the Company's absolute three-year total shareholder return ("ATSR Appreciation"). The performance criteria for these awards consists of the Company's three-year return on average capital employed ("ROACE Percentage"). Any shares earned under performance share awards are expected to be issued in the first quarter following the completion of the respective requisite service periods based on the achievement of certain market and performance criteria, and the payout can range from 0% to 200%.

The following table reflects the performance share award activity for the ~~six~~three months ended ~~June 30, 2020:~~March 31, 2021:

(in thousands, except for weighted-average grant-date fair value)
Performance
share awards⁽¹⁾
Weighted-average
grant-date
fair value
(per share)¹⁾
Outstanding as of December 31, 2019 115 $ 107.05
Forfeited (10) $ 111.75
Lapsed⁽²⁾
(8) $ 379.20
Outstanding as of June 30, 2020 97 $ 84.12


(in thousands, except for weighted-average grant-date fair value)	Performance share awards	Weighted-average grant-date fair value (per share)
Outstanding as of December 31, 2020	97	$	84.06

Vested(1)	(15)	$	184.43
Outstanding as of March 31, 2021	82	$	65.98

(1)~~Shares and per share data have been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 7.a.~~

~~(2)~~The performance share awards granted on February ~~17, 2017~~16, 2018 had a performance period of January 1, ~~2017~~2018 to December 31, ~~2019~~2020 and, as their market and performance criteria were ~~not~~partially satisfied, resulted in a ~~TSR modifier of 0% based on the Company finishing in the 15th percentile of its peer group for relative TSR.~~43% payout. As such, the granted ~~units lapsed~~awards vested and were ~~not~~ converted into 6,343 shares of the Company's common stock during the three months ended March 31, ~~2020.~~2021 based on this 43% payout.


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

~~Condensed notes~~As of March 31, 2021, unrecognized equity-based compensation related to the ~~consolidated financial statements~~

~~(Unaudited)~~

~~The following table presents the fair values per~~ performance share ~~and~~awards expected to vest was $2.2 million. Such cost is expected to be recognized over a weighted-average period of 0.92 years. As of March 31, 2021, the expense per performance share, which is the fair value per performance share adjusted for the estimated payout of the performance criteria, ~~for the outstanding performance share awards as of June 30, 2020 for the grant dates presented:~~

June 3, 2019
February 28, 2019⁽¹⁾
February 16, 2018
Market Criteria:
(1/4) RTSR Factor + (1/4) ATSR Factor:
Grant-date fair value per performance share⁽²⁾
$ 49.00 $ 79.61 $ 201.65
Expense per performance share as of June 30, 2020⁽²⁾
$ 49.00 $ 79.61 $ 201.65
Performance Criteria:
(1/2) ROACE Factor:
Grant-date fair value per performance share⁽²⁾
$ 51.80 $ 69.80 $ 167.20
Estimated payout for expense as of June 30, 2020 175 % 175 % 68 %
Expense per performance share as of June 30, 2020⁽²⁾⁽³⁾
$ 90.65 $ 122.15 $ 113.70
Combined:
Grant-date fair value per performance share⁽²⁾⁽⁴⁾
$ 50.40 $ 74.71 $ 184.43
Expense per performance share as of June 30, 2020⁽²⁾⁽⁵⁾
$ 69.83 $ 100.88 $ 157.68

~~(1)~~The fair values of the performance shares granted on February 28, 2019 are based on the May 16, 2019 modification date. See Note 8.b in the 2019 Annual Report for additional information on the award conversion.

~~(2)Per share data has been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 7.a.~~

~~(3)~~As the (1/2) ROACE Factor is based on performance criteria, the expense fluctuates based on the estimated payout and is redetermined each reporting period and the life-to-date recognized expense for the respective awards is adjusted accordingly.

~~(4)The combined grant-date fair value per performance share is the combination of the fair value per performance share weighted for the market and performance criteria for the respective awards.~~

~~(5)The combined expense per performance share is the combination of the expense per performance share for market and performance criteria for the respective awards.~~

~~As of June 30, 2020, unrecognized equity-based compensation related to the performance share awards expected to vest~~ was ~~$4.6 million. Such cost is expected to be recognized over a weighted-average period of 1.56 years.~~$88.16.

d. Outperformance share award

An outperformance share award was granted during the year ended December 31, 2019, in conjunction with the appointment of the Company's President, and is accounted for as an equity award. ~~The award was adjusted for the Company's 1-for-20 reverse stock split as discussed in Note 7.a.~~ If earned, the payout ranges from 0 to 50,000 shares in the Company's common stock per the vesting schedule. This award is subject to a combination of market and service vesting criteria, therefore, a Monte Carlo simulation prepared by an independent third party was utilized to determine the grant-date fair value with the associated expense recognized over the requisite service period. The payout of this award is based on the highest 50 consecutive trading day average closing stock price of the Company that occurs during the performance period that commenced on June 3, 2019 and ends on June 3, 2022 ("Final Date"). Of the earned outperformance shares, one-third of the award will vest on the Final Date, one-third will vest on the first anniversary of the Final Date and one-third will vest on the second anniversary of the Final Date, provided that the participant has been continuously employed with the Company through the applicable vesting date.

As of ~~June 30, 2020,~~March 31, 2021, unrecognized equity-based compensation related to the outperformance share award expected to vest was ~~$0.5~~$0.4 million. Such cost is expected to be recognized over a weighted-average period of ~~4.00~~3.25 years.


Table of Contents			Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

e. Performance unit awards

Performance unit awards, which the Company has determined are liability awards since they are settled in cash, are subject to a combination of market, performance and service vesting criteria. For portions of awards with market criteria, ~~which include: (i) the RTSR Performance Percentage (as defined above) and (ii) the ATSR Appreciation (as defined above),~~ a Monte Carlo simulation prepared by an independent third party is utilized to determine the fair value, and is re-measured at each reporting period until settlement. For portions of awards with performance criteria, ~~which is the ROACE Percentage (as defined above),~~ the Company's closing stock price is utilized to determine the fair value and is re-measured on the last trading day of each reporting period until settlement and, additionally, the associated expense fluctuates based on an estimated payout for the ~~three-year~~three-year performance period. The expense related to the performance unit awards is recognized on a straight-line basis over the ~~three-year~~three-year requisite service period of the awards, and the life-to-date recognized expense is adjusted accordingly at each reporting period based on the quarterly fair value re-measurements and redetermination of the estimated payout for the performance criteria.

For performance unit awards granted in 2021, the market criteria consists of: (i) annual relative total shareholder return comparing the Company's shareholder return to the shareholder return of the E&P companies listed in the Russell 2000 index ("Relative TSR") and (ii) annual absolute total shareholder return ("Absolute Return"), together the "PSU Matrix." The performance criteria for these awards consists of: (i) earnings before interest , taxes, depreciation, amortization and exploration expense ("EBITDAX") and three-year total debt reduction (the "EBITDAX/Total Debt Component") and (ii) growth in inventory (the "Inventory Growth Component"). Any units earned are expected to be paid in cash during the first quarter following the completion of the requisite service period, based on the achievement of certain market and performance criteria, and the payout can range from 0% to ~~200%. Per~~250% for the ~~award agreement terms,~~market criteria and 0% to 200% for the performance criteria.

For performance unit awards granted in 2020, the market criteria consists of: (i) the RTSR Performance Percentage and (ii) the ATSR Appreciation. The performance criteria for these awards consists of the ROACE Percentage. Any units earned are expected to be paid in cash during the first quarter following the completion of the requisite service period, based on the achievement of certain market and performance criteria, and the payout can range from 0% to 200%, but is capped at 100% if ~~employment~~the ATSR Appreciation is ~~terminated prior~~zero or less.

The following table presents the assumptions used to estimate the ~~restriction lapse date~~fair value per performance unit for ~~reasons other than death or disability,~~ the performance unit awards ~~are forfeited and canceled. If~~granted in 2021:


	March 9, 2021
Remaining performance period	2.81 years
Risk-free interest rate(1)	0.32		%
Dividend yield	0		%
Expected volatility(2)	114.60		%
Closing stock price on grant date	$	34.66

(1)The remaining performance period matched zero-coupon risk-free interest rate was derived from the ~~termination of employment is by reason of death or disability, and~~U.S. Treasury constant maturities yield curve on grant date.

(2)The Company utilized its own remaining performance period matched historical volatility in order to develop the market and performance criteria are satisfied, then the holder of the earned performance unit awards will receive a prorated payment based on the number of days the participant was employed with the Company during the performance period.expected volatility.

The following table reflects the performance unit award activity for the ~~six~~three months ended ~~June 30, 2020:~~March 31, 2021:


(in thousands)						Performance units⁽¹⁾
Outstanding as of December 31, ~~2019~~⁽²⁾						—
~~Granted~~⁽³⁾						~~123~~
~~Forfeited~~2020						~~(24)~~99
Granted						110


Outstanding as of ~~June 30, 2020~~March 31, 2021						99209

~~(1)Units have been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 7.a.~~

~~(2)~~The performance unit awards granted on February 28, 2019 were originally determined to be liability awards due to the board of directors election to settle the awards in cash. These awards were converted to performance share awards during the three months ended June 30, 2019. See Note 8.b in the 2019 Annual Report for additional information on the award conversion.

~~(3)~~The amounts potentially payable in cash at the end of the requisite service period for the performance unit awards granted on March 5, 2020 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 to be paid in cash on the payment date per the award agreement, subject to withholding requirements. In computing the Performance Multiple, the RTSR Factor is given a 1/3 weight, the ATSR Factor a 1/3 weight and the ROACE Factor a 1/3 weight. These awards have a performance period of January 1, 2020 to December 31, 2022.

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Condensed notes to the consolidated financial statements

(Unaudited)

~~The following table presents (i)~~As of March 31, 2021, unrecognized equity-based compensation related to the ~~fair values per~~ performance unit ~~and the assumptions used~~awards expected to ~~estimate these fair values per performance unit and (ii)~~vest was $7.0 million. Such cost is expected to be recognized over a weighted-average period of 2.62 years. As of March 31, 2021, the expense per performance unit, which is the fair value per performance unit adjusted for the estimated payout of the performance criteria, for the ~~outstanding~~2021 and 2020 performance unit awards ~~as of June 30, 2020 for the grant date presented:~~


	~~March 5, 2020~~
~~Market criteria:~~
~~(1/3) RTSR Factor + (1/3) ATSR Factor:~~
~~Fair value assumptions:~~
~~Remaining performance period~~	~~2.52 years~~
~~Risk-free interest rate~~⁽¹⁾	~~0.19~~		%
~~Dividend yield~~	—		%
~~Expected volatility~~⁽²⁾	~~113.53~~		%
~~Closing stock price on June 30, 2020~~	$	~~13.86~~
~~Fair value per performance unit as of June 30, 2020~~	$	~~20.00~~
~~Expense per performance unit as of June 30, 2020~~	$	~~20.00~~
~~Performance criteria:~~
~~(1/3) ROACE Factor:~~
~~Fair value assumptions:~~
~~Closing stock price on June 30, 2020~~	$	~~13.86~~
~~Fair value per performance unit as of June 30, 2020~~	$	~~13.86~~
~~Estimated payout for expense as of June 30, 2020~~	~~100.00~~		%
~~Expense per performance unit as of June 30, 2020~~⁽³⁾	$	~~13.86~~
~~Combined:~~
~~Fair value per performance unit as of June 30, 2020~~⁽⁴⁾	$	~~17.96~~
~~Expense per performance unit as of June 30, 2020~~⁽⁵⁾	$	~~17.96~~

~~(1)The remaining performance period matched zero-coupon risk-free interest rate~~ was ~~derived from the United States ("U.S.") Treasury constant maturities yield curve on June 30, 2020.~~

~~(2)The Company utilized its own remaining performance period matched historical volatility in order to develop the expected volatility.~~

~~(3)As the (1/3) ROACE Factor is based on performance criteria, the expense fluctuates based on the estimated payout~~$39.77 and ~~is redetermined each reporting period and the life-to-date recognized expense for the award is adjusted accordingly.~~

~~(4)The combined fair value per performance unit is the combination of the fair value per performance unit weighted for the market and performance criteria for the award.~~

~~(5)The combined expense per performance unit is the combination of the expense per performance unit for market and performance criteria for the award.~~

As of June 30, 2020, unrecognized equity-based compensation related to the performance unit awards expected to vest was $1.6 million. Such cost is expected to be recognized over a weighted-average period of 2.75 years.$41.82, respectively.

f. Phantom unit awards

Phantom unit awards, which the Company has determined are liability awards, represent the holder's right to receive the cash equivalent of one share of common stock of the Company for each phantom unit as of the applicable vesting date, subject to withholding requirements. Phantom unit awards granted to employees vest 33%, 33% and 34% per year beginning on the first anniversary of the grant date. ~~Per the award agreement terms, if employment is terminated prior to the restriction lapse date~~


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

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

for reasons other than death or disability, the phantom unit awards are forfeited and canceled. If the termination of employment is by reason of death or disability, all of the holder's phantom unit awards automatically vest.

The following table reflects the phantom unit award activity for the ~~six~~three months ended ~~June 30, 2020:~~March 31, 2021:

(in thousands, except for weighted-average fair value)
Phantom units⁽¹⁾
Fair value
as of June 30, 2020
(per unit)¹⁾
Outstanding as of December 31, 2019 — $ —
Granted 75 $ 13.86
Outstanding as of June 30, 2020 75 $ 13.86


(in thousands, except for weighted-average fair value)						Phantom units
Outstanding as of December 31, 2020						75
Granted						5

Vested(1)						(25)
Outstanding as of March 31, 2021						55

(1)~~Units~~On March 5, 2021, the vested phantom unit awards were settled and ~~per unit data have been retroactively adjusted to reflect~~paid out in cash at a fair value of $34.24 based on the Company's ~~1-for-20 reverse~~closing stock ~~split effective June 1, 2020, as described in Note 7.a.~~price on the vesting date.

The Company utilizes the closing stock price on the last day of each reporting period to determine the fair value of phantom unit awards and the life-to-date recognized expense is adjusted accordingly. As of ~~June 30, 2020,~~March 31, 2021, unrecognized equity-based compensation related to the phantom unit awards expected to vest was ~~$0.9~~$1.6 million. Such cost is expected to be recognized over a weighted-average period of ~~2.75~~2.08 years.

g. Equity-based compensation

The following table reflects equity-based compensation expense for the periods presented:

Three months ended June 30, Six months ended June 30,
(in thousands) 2020 2019 2020 2019
Equity awards:
Restricted stock awards $ 2,044 $ 2,559 $ 4,542 $ 7,882
Performance share awards 282 (3,191) 1,038 (27)
Outperformance share award 43 13 87 13
Stock option awards 7 160 50 978
Total share-settled equity-based compensation, gross 2,376 (459) 5,717 8,846
Less amounts capitalized (682) 36 (1,647) (1,863)
Total share-settled equity-based compensation, net 1,694 (423) 4,070 6,983
Liability awards:
Phantom unit awards 86 — 111 —
Performance unit awards⁽¹⁾
166 (238) 190 —
Total cash-settled equity-based compensation, gross 252 (238) 301 —
Less amounts capitalized (33) 46 (43) —
Total cash-settled equity-based compensation, net 219 (192) 258 —
Total equity-based compensation, net $ 1,913 $ (615) $ 4,328 $ 6,983

~~(1)~~The performance unit award compensation for the three months ended March 31, 2019 was reversed during the second quarter of 2019 due to the awards' conversion from liability to equity and new fair values were assigned under performance share awards. See Note 8 in the 2019 Annual Report for discussion of this conversion and related modification accounting.

~~See Note 18 for discussion of the Company's organizational restructurings and the related equity-based compensation reversals during the three months ended June 30, 2020 and 2019.~~


	Three months ended March 31,
(in thousands)	2021		2020
Equity awards:
Restricted stock awards	$	1,963	$	2,498
Performance share awards	725		756
Outperformance share award	43		44
Stock option awards	7		43
Total share-settled equity-based compensation, gross	$	2,738	$	3,341
Less amounts capitalized	(670)		(965)
Total share-settled equity-based compensation, net	$	2,068	$	2,376
Liability awards:
Performance unit awards	$	820	$	24
Phantom unit awards	506		25
Total cash-settled equity-based compensation, gross	$	1,326	$	49
Less amounts capitalized	(198)		(10)
Total cash-settled equity-based compensation, net	$	1,128	$	39
Total equity-based compensation, net	$	3,196	$	2,415

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Condensed notes to the consolidated financial statements

(Unaudited)

Note 9—Derivatives

The Company has 3 types of derivative instruments as of ~~June 30, 2020:~~March 31, 2021: (i) commodity derivatives, ~~("Commodity"),~~ (ii) a debt interest rate derivative ~~("Interest rate")~~ and (iii) a contingent consideration ~~derivatives ("Contingent consideration").~~derivative. See ~~Note 10.a for the fair value measurement on a recurring basis of derivatives and Note 2.f~~Notes (i) 2.e in the ~~2019~~2020 Annual Report for the Company's significant accounting policies for ~~derivatives.~~derivatives and presentation, (ii) 10.a for fair value measurement of derivatives on a recurring basis and (iii) 18.b for derivatives subsequent events. The Company's derivatives were not designated as hedges for accounting purposes, and the Company does not enter into such instruments for speculative trading purposes. Accordingly, the changes in fair value are recognized in "Gain (loss) on derivatives, net" under "Non-operating income (expense)" on the unaudited consolidated statements of operations.

The following table summarizes components of the Company's gain (loss) on derivatives, net by type of derivative instrument for the periods presented:


		Three months ended June 30,						Six months ended June 30,							Three months ended March 31,
(in thousands)	(in thousands)	2020		2019		2020		2019		(in thousands)	2021		2020
Commodity	Commodity	$	(90,864)	$	88,394	$	200,497	$	40,029	Commodity	$	(154,033)	$	291,361
Interest rate	Interest rate	(338)		—		(338)		—		Interest rate	4		0
Contingent consideration	Contingent consideration	665		—		7,140		—		Contingent consideration	(336)		6,475
Gain (loss) on derivatives, net	Gain (loss) on derivatives, net	$	(90,537)	$	88,394	$	207,299	$	40,029	Gain (loss) on derivatives, net	$	(154,365)	$	297,836

a. Commodity

Due to the inherent volatility in oil, NGL and natural gas prices 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 commodity derivative transactions, such as puts, swaps, collars and basis swaps, to hedge price risk associated with a portion of the Company's anticipated sales volumes. By removing a portion of the price volatility associated with future sales volumes, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations. See Note 9 in the ~~2019~~2020 Annual Report for ~~information on the~~discussion of transaction types and settlement indexes. ~~The Brent ICE to WTI NYMEX basis swaps, which~~

During the ~~Company entered into in~~three months ended March 31, 2021, the ~~first quarter of 2020, are~~Company’s derivatives were settled based on ~~the differential between the basis swaps' fixed differential as compared to the differential between the arithmetic average of each day's index~~reported prices ~~for the first nearby month~~ on ~~the~~commodity exchanges, with (i) oil derivatives settled based on Brent ICE pricing, dates in each calculation period, for only days when both indices settle, with the index prices being (i) the ICE Brent Crude Oil Futures Contract except for the last day of trading for the applicable expiring Brent Crude Oil Futures Contract whereby the second nearby month of the Brent Crude Oil Futures Contract settlement price will be used(ii) NGL derivatives settled based on Mont Belvieu OPIS pricing and ~~(ii) the~~(iii) natural gas derivatives settled based on Henry Hub NYMEX ~~West Texas Intermediate Light Sweet Crude Oil Futures Contract. See Note 19.b for a discussion of derivatives entered into subsequent to June 30, 2020.~~

In regards to the Company's basis swaps, when the settlement basis differential is below the fixed basis differential, the counterparty pays the Company an amount equal to the difference between the fixed basis differential and the settlement basis differential multiplied by the hedged contract volume. When the settlement basis differential is above the fixed basis differential, the Company pays the counterparty an amount equal to the difference between the settlement basis differential and the fixed basis differential multiplied by the hedged contract volume.Waha Inside FERC pricing.

During the ~~six~~three months ended ~~June 30,~~March 31, 2021, the Company completed a hedge restructuring by (i) selling 2,254,500 calendar year 2021 $55.00 per barrel Brent ICE puts, which volumetrically offset existing calendar year 2021 $55.00 per barrel Brent ICE puts, and receiving aggregate premiums of $9.0 million at inception of the contracts and (ii) entering into 2,254,500 calendar year 2021 Brent ICE swaps at a weighted-average price of $55.09 per barrel. Associated with the aforementioned existing calendar year 2021 $55.00 per barrel Brent ICE puts, which were entered into during 2020, were $50.6 million in aggregate premiums paid at the inception of the contacts.

During the three months ended March 31, 2020, the Company completed a hedge restructuring by early terminating collars and entering into new swaps.

The following table ~~details~~presents the commodity derivatives that were terminated:


	Aggregate volumes (Bbl)	Floor price ($/Bbl)		Ceiling price ($/Bbl)		Contract period
WTI NYMEX - Collars	912,500	$	45.00	$	71.00	January 2021 - December 2021

2016


Table of Contents			Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table summarizes open commodity derivative positions as of ~~June 30, 2020,~~March 31, 2021, for commodity derivatives that were entered into through ~~June 30, 2020,~~March 31, 2021, for the settlement periods presented:


		Remaining year 2020		Year 2021		Year 2022			Remaining Year 2021		Year 2022
Oil:	Oil:							Oil:

WTI NYMEX - Swaps:
Volume (Bbl)		3,606,400		—		—
Weighted-average price ($/Bbl)		$	59.50	$	—	$	—
Brent ICE:
Puts⁽¹⁾:
Volume (Bbl)		—		2,463,750		—
Weighted-average floor price ($/Bbl)		$	—	$	55.00	$	—

Swaps:
Volume (Bbl)		1,196,000		2,555,000		—
Weighted-average price ($/Bbl)		$	63.07	$	53.19	$	—
Collars:
Volume (Bbl)		—		584,000		—
Weighted-average floor price ($/Bbl)		$	—	$	45.00	$	—
Weighted-average ceiling price ($/Bbl)		$	—	$	59.50	$	—
Total Brent ICE:
Total volume with floor (Bbl)		1,196,000		5,602,750		—
Weighted-average floor price ($/Bbl)		$	63.07	$	53.13	$	—
Total volume with ceiling (Bbl)		1,196,000		3,139,000		—
Weighted-average ceiling price ($/Bbl)		$	63.07	$	54.37	$	—

Total oil volume with floor (Bbl)		4,802,400		5,602,750		—
Total oil volume with ceiling (Bbl)		4,802,400		3,139,000		—
Basis Swaps:

Brent ICE to WTI NYMEX - Basis Swaps

Brent ICE - Swaps:								Brent ICE - Swaps:
Volume (Bbl)	Volume (Bbl)	1,803,200		—		—		Volume (Bbl)	5,651,250		3,759,500
Weighted-average differential ($/Bbl)		$	5.09	$	—	$	—
Weighted-average price ($/Bbl)								Weighted-average price ($/Bbl)	$	51.29	$	47.05
Brent ICE - Collars:								Brent ICE - Collars:
Volume (Bbl)								Volume (Bbl)	440,000		821,250
Weighted-average floor price ($/Bbl)								Weighted-average floor price ($/Bbl)	$	45.00	$	53.67
Weighted-average ceiling price ($/Bbl)								Weighted-average ceiling price ($/Bbl)	$	59.50	$	62.40
Total Brent ICE:								Total Brent ICE:
Total volume (Bbl)								Total volume (Bbl)	6,091,250		4,580,750
Weighted-average floor price ($/Bbl)								Weighted-average floor price ($/Bbl)	$	50.83	$	48.24

Weighted-average ceiling price ($/Bbl)								Weighted-average ceiling price ($/Bbl)	$	51.88	$	49.81

NGL - Mont Belvieu OPIS:

NGL:								NGL:
Mont Belvieu OPIS:								Mont Belvieu OPIS:
Purity Ethane - Swaps:	Purity Ethane - Swaps:							Purity Ethane - Swaps:
Volume (Bbl)	Volume (Bbl)	184,000		912,500		—		Volume (Bbl)	687,500		0
Weighted-average price ($/Bbl)	Weighted-average price ($/Bbl)	$	13.60	$	12.01	$	—	Weighted-average price ($/Bbl)	$	12.01	$	0
Non-TET Propane - Swaps:	Non-TET Propane - Swaps:							Non-TET Propane - Swaps:
Volume (Bbl)	Volume (Bbl)	625,600		730,000		—		Volume (Bbl)	1,825,725		0
Weighted-average price ($/Bbl)	Weighted-average price ($/Bbl)	$	26.58	$	25.52	$	—	Weighted-average price ($/Bbl)	$	22.90	$	0
Non-TET Normal Butane - Swaps:	Non-TET Normal Butane - Swaps:							Non-TET Normal Butane - Swaps:
Volume (Bbl)	Volume (Bbl)	220,800		255,500		—		Volume (Bbl)	608,575		0
Weighted-average price ($/Bbl)	Weighted-average price ($/Bbl)	$	28.69	$	27.72	$	—	Weighted-average price ($/Bbl)	$	25.87	$	0
Non-TET Isobutane - Swaps:	Non-TET Isobutane - Swaps:							Non-TET Isobutane - Swaps:
Volume (Bbl)	Volume (Bbl)	55,200		67,525		—		Volume (Bbl)	166,100		0
Weighted-average price ($/Bbl)	Weighted-average price ($/Bbl)	$	29.99	$	28.79	$	—	Weighted-average price ($/Bbl)	$	26.55	$	0
Non-TET Natural Gasoline - Swaps:	Non-TET Natural Gasoline - Swaps:							Non-TET Natural Gasoline - Swaps:
Volume (Bbl)	Volume (Bbl)	202,400		237,250		—		Volume (Bbl)	663,850		0
Weighted-average price ($/Bbl)	Weighted-average price ($/Bbl)	$	45.15	$	44.31	$	—	Weighted-average price ($/Bbl)	$	38.16	$	0

Total NGL volume (Bbl)	Total NGL volume (Bbl)	1,288,000		2,202,775		—		Total NGL volume (Bbl)	3,951,750		0
TABLE CONTINUES ON NEXT PAGE
Natural gas:								Natural gas:

Henry Hub NYMEX - Swaps:								Henry Hub NYMEX - Swaps:
Volume (MMBtu)								Volume (MMBtu)	32,037,500		3,650,000
Weighted-average price ($/MMBtu)								Weighted-average price ($/MMBtu)	$	2.59	$	2.73

Waha Inside FERC to Henry Hub NYMEX - Basis Swaps:								Waha Inside FERC to Henry Hub NYMEX - Basis Swaps:
Volume (MMBtu)								Volume (MMBtu)	42,680,000		18,067,500
Weighted-average differential ($/MMBtu)								Weighted-average differential ($/MMBtu)	$	(0.47)	$	(0.41)

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Condensed notes to the consolidated financial statements

(Unaudited)

Natural gas:
Henry Hub NYMEX - Swaps:
Volume (MMBtu) 11,960,000 42,522,500 —
Weighted-average price ($/MMBtu) $ 2.72 $ 2.59 $ —
Waha Inside FERC to Henry Hub NYMEX - Basis Swaps:
Volume (MMBtu) 21,160,000 41,610,000 7,300,000
Weighted-average differential ($/MMBtu) $ (0.82) $ (0.55) $ (0.53)

~~(1) Associated with these open positions were $50.6 million of premiums, which were paid at the respective contracts' inception during the three months ended June 30, 2020.~~

b. Interest rate

Due to the inherent volatility in interest rates, the Company has entered into an interest rate derivative swap to hedge interest rate risk associated with a portion of the Company's anticipated outstanding debt under the Senior Secured Credit Facility. The Company will pay a fixed rate over the contract term for that portion. By removing a portion of the interest rate volatility associated with anticipated outstanding debt, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations.

The following table ~~details~~summarizes the Company's interest rate ~~derivative that was entered into during the three months ended June 30, 2020:~~derivative:


	Notional amount (in thousands)		Fixed rate		Contract period
LIBOR - Swap	$	100,000	0.345	%	April 16, 2020 - April 18, 2022

c. Contingent consideration

The Company's asset acquisition of oil and natural gas properties that closed on April 30, 2020 provides for potential contingent payments to be paid by the Company if the arithmetic average of the monthly settlement WTI NYMEX prices exceed certain thresholds for the contingency period beginning on January 1, 2021 and ending on the earlier of December 31, 2022 or the date the counterparty has received the maximum consideration of $1.2 million.

See ~~Notes~~Note 3.a ~~and 3.b~~ for further discussion of the Company's asset ~~acquisitions~~acquisition associated with potential contingent consideration payments. At each quarterly reporting period, the Company remeasures ~~each~~its contingent consideration with the changes in fair values recognized in earnings. ~~See Note 10.a for the fair value of the contingent considerations as of June 30, 2020.~~

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Condensed notes to the consolidated financial statements

(Unaudited)

Note 10—Fair value measurements

See the beginning of Note 1011 in the ~~2019~~2020 Annual Report for information about the fair value hierarchy levels.

a. Fair value measurement on a recurring basis

See ~~Notes~~Note 9 ~~and 19.b~~ for further discussion of the Company's derivatives, and see Note ~~2.f~~2.e in the ~~2019~~2020 Annual Report for the Company's significant accounting policies for derivatives.

Balance sheet presentation

The following tables present the Company's ~~derivatives' three-level~~derivatives by (i) balance sheet classification, (ii) derivative type and (iii) fair value hierarchy ~~by (i) assets and liabilities, (ii) current and noncurrent, (iii) commodity, interest rate and contingent consideration derivatives and (iv) oil, NGL, natural gas, LIBOR and/or deferred premiums,~~level, and provide a total, on a gross basis and a net basis reflected in "Derivatives" on the unaudited consolidated balance sheets as of the dates presented:


		June 30, 2020																							March 31, 2021
(in thousands)	(in thousands)	Level 1		Level 2		Level 3		Total gross fair value		Amounts offset		Net fair value presented on the unaudited consolidated balance sheets		(in thousands)	Level 1		Level 2		Level 3		Total gross fair value		Amounts offset		Net fair value presented on the unaudited consolidated balance sheets
Assets:	Assets:													Assets:
Current:	Current:													Current:
Commodity - Oil	Commodity - Oil	$	—	$	136,828	$	—	$	136,828	$	(2,560)	$	134,268	Commodity - Oil	$	0	$	6,197	$	0	$	6,197	$	(6,197)	$	0
Commodity - NGL	Commodity - NGL	—		17,023		—		17,023		—		17,023		Commodity - NGL	0		1,735		0		1,735		(1,735)		0
Commodity - Natural gas	Commodity - Natural gas	—		10,491		—		10,491		(10,078)		413		Commodity - Natural gas	0		(195)		0		(195)		195		0
Commodity - Oil deferred premiums		—		—		—		—		—		—

Noncurrent:	Noncurrent:													Noncurrent:
Commodity - Oil	Commodity - Oil	$	—	$	33,684	$	—	$	33,684	$	(2,983)	$	30,701	Commodity - Oil	$	0	$	3,928	$	0	$	3,928	$	(3,928)	$	0
Commodity - NGL	Commodity - NGL	—		7,381		—		7,381		—		7,381		Commodity - NGL	0		0		0		0		0		0
Commodity - Natural gas	Commodity - Natural gas	—		3,604		—		3,604		(1,428)		2,176		Commodity - Natural gas	0		545		0		545		(545)		0

Liabilities:	Liabilities:													Liabilities:
Current:	Current:													Current:
Commodity - Oil	Commodity - Oil	$	—	$	(2,560)	$	—	$	(2,560)	$	2,560	$	—	Commodity - Oil	$	0	$	(73,960)	$	0	$	(73,960)	$	6,197	$	(67,763)
Commodity - NGL	Commodity - NGL	—		—		—		—		—		—		Commodity - NGL	0		(39,133)		0		(39,133)		1,735		(37,398)
Commodity - Natural gas	Commodity - Natural gas	—		(10,078)		—		(10,078)		10,078		—		Commodity - Natural gas	0		(21,726)		0		(21,726)		(195)		(21,921)
Commodity - Oil deferred premiums		—		—		—		—		—		—

Interest rate - LIBOR	Interest rate - LIBOR	—		(177)		—		(177)		—		(177)		Interest rate - LIBOR	0		(197)		0		(197)		0		(197)
Contingent consideration	Contingent consideration	—		(15)		—		(15)		—		(15)		Contingent consideration	0		(1,115)		0		(1,115)		0		(1,115)
Noncurrent:	Noncurrent:													Noncurrent:
Commodity - Oil	Commodity - Oil	$	—	$	(2,983)	$	—	$	(2,983)	$	2,983	$	—	Commodity - Oil	$	0	$	(32,534)	$	0	$	(32,534)	$	3,928	$	(28,606)
Commodity - NGL	Commodity - NGL	—		—		—		—		—		—		Commodity - NGL	0		0		0		0		0		0
Commodity - Natural gas	Commodity - Natural gas	—		(1,428)		—		(1,428)		1,428		—		Commodity - Natural gas	0		(1,746)		0		(1,746)		545		(1,201)

Interest rate - LIBOR	Interest rate - LIBOR	—		(182)		—		(182)		—		(182)		Interest rate - LIBOR	0		(13)		0		(13)		0		(13)
Contingent consideration	Contingent consideration	—		(420)		—		(420)		—		(420)		Contingent consideration	0		(1)		0		(1)		0		(1)
Net derivative asset (liability) positions		$	—	$	191,168	$	—	$	191,168	$	—	$	191,168
Net derivative liability positions														Net derivative liability positions	$	0	$	(158,215)	$	0	$	(158,215)	$	—	$	(158,215)

2319


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Condensed notes to the consolidated financial statements

(Unaudited)

December 31, 2019
(in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the consolidated balance sheets
Assets:
Current:
Commodity - Oil $ — $ 11,723 $ — $ 11,723 $ (5,301) $ 6,422
Commodity - NGL — 13,787 — 13,787 (1,297) 12,490
Commodity - Natural gas — 33,494 — 33,494 — 33,494
Commodity - Oil deferred premiums — — — — (477) (477)
Noncurrent:
Commodity - Oil $ — $ 1,577 $ — $ 1,577 $ — $ 1,577
Commodity - NGL — 9,547 — 9,547 — 9,547
Commodity - Natural gas — 12,263 — 12,263 — 12,263
Liabilities:
Current:
Commodity - Oil $ — $ (5,649) $ — $ (5,649) $ 5,301 $ (348)
Commodity - NGL — (1,297) — (1,297) 1,297 —
Commodity - Natural gas — — — — — —
Commodity - Oil deferred premiums — — (477) (477) 477 —
Interest rate - LIBOR — — — — — —
Contingent consideration — (7,350) — (7,350) — (7,350)
Noncurrent:
Commodity - Oil $ — $ — $ — $ — $ — $ —
Commodity - NGL — — — — — —
Commodity - Natural gas — — — — — —
Interest rate - LIBOR — — — — — —
Contingent consideration — — — — — —
Net derivative asset (liability) positions $ — $ 68,095 $ (477) $ 67,618 $ — $ 67,618

~~Commodity~~


	December 31, 2020
(in thousands)	Level 1		Level 2		Level 3		Total gross fair value		Amounts offset		Net fair value presented on the consolidated balance sheets
Assets:
Current:
Commodity - Oil	$	0	$	32,958	$	0	$	32,958	$	(24,930)	$	8,028
Commodity - NGL	0		2,720		0		2,720		(2,720)		0
Commodity - Natural gas	0		521		0		521		(656)		(135)


Noncurrent:
Commodity - Oil	$	0	$	0	$	0	$	0	$	0	$	0
Commodity - NGL	0		0		0		0		0		0
Commodity - Natural gas	0		535		0		535		(535)		0


Liabilities:
Current:
Commodity - Oil	$	0	$	(25,118)	$	0	$	(25,118)	$	24,930	$	(188)
Commodity - NGL	0		(16,185)		0		(16,185)		2,720		(13,465)
Commodity - Natural gas	0		(17,958)		0		(17,958)		656		(17,302)


Interest rate - LIBOR	0		(206)		0		(206)		0		(206)
Contingent consideration	0		(665)		0		(665)		0		(665)
Noncurrent:
Commodity - Oil	$	0	$	(10,932)	$	0	$	(10,932)	$	0	$	(10,932)
Commodity - NGL	0		0		0		0		0		0
Commodity - Natural gas	0		(1,476)		0		(1,476)		535		(941)


Interest rate - LIBOR	0		(63)		0		(63)		0		(63)
Contingent consideration	0		(115)		0		(115)		0		(115)
Net derivative liability positions	$	0	$	(35,984)	$	0	$	(35,984)	$	—	$	(35,984)

See Note ~~10.a~~11.a in the ~~2019~~2020 Annual Report for discussion of ~~(i)~~ the significant Level 2 inputs ~~associated with the calculation of discounted cash flows~~ used in the fair value mark-to-market analysis of commodity, ~~derivatives~~interest rate and ~~(ii) the Level 3 deferred premiums associated with the Company's commodity derivative contracts. These deferred premiums have settled as of June 30, 2020.~~

contingent consideration derivatives. The Company reviewed the third-party specialist's valuations of commodity, interest rate and contingent consideration derivatives, including the related inputs, and analyzed changes in fair values between reporting dates.

The Company's acquisition of oil and natural gas properties that closed on April 30, 2020 provides for potential contingent payments to be paid by the Company. The fair value of the contingent consideration derivative liability was $1.1 million and $0.8 million as of March 31, 2021 and December 31, 2020, respectively. See Note 3.a for further discussion of the Company's asset acquisition associated with the potential contingent consideration payments.

b. Fair value measurement on a nonrecurring basis

See Note 2.i in the 2020 Annual Report for the Level 2 fair value hierarchy input assumptions used in estimating the net realizable value ("NRV") of inventory used to determine the $1.3 million impairment expense of inventory recorded during the three months ended March 31, 2020, pertaining to line-fill and other inventories. There were 0 impairments of inventory recorded during the three months ended March 31, 2021.

See Note 11.b in the 2020 Annual Report for the Level 3 fair value hierarchy input assumptions used in the fair value measurement of long-lived assets used to determine the $8.2 million impairment expense of long-lived assets recorded during the three months ended March 31, 2020, pertaining to midstream service assets. There were 0 impairments of long-lived assets recorded during the three months ended March 31, 2021.

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Condensed notes to the consolidated financial statements

(Unaudited)

~~The following table summarizes the changes in net assets and liabilities classified as Level 3 measurements for the periods presented:~~

Three months ended June 30, Six months ended June 30,
(in thousands) 2020 2019 2020 2019
Balance of Level 3 at beginning of period $ — $ (12,644) $ (477) $ (16,565)
Change in net present value of commodity derivative deferred premiums⁽¹⁾
— (24) — (119)
Settlements of commodity derivative deferred premiums⁽²⁾
— 9,398 477 13,414
Balance of Level 3 at end of period $ — $ (3,270) $ — $ (3,270)

~~(1)This amount is included in "Interest expense" on the unaudited consolidated statements of operations for the three and six months ended June 30, 2019.~~

~~(2)The amounts for the three and six months ended June 30, 2019 include $7.2 million that represents the present value of deferred premiums settled upon their early termination.~~

~~Interest rate~~

Significant Level 2 inputs associated with the calculation of discounted cash flows used in the fair value mark-to-market analysis of the interest rate derivative include the LIBOR interest rate forward curve and a counterparty risk-adjusted discount rate generated from a compilation of data gathered by a third-party valuation specialist. The Company reviewed the third-party specialist's valuation of the interest rate derivative, including the related inputs, and will analyze changes in fair values between reporting dates.

~~Contingent consideration~~

The Company's asset acquisition of oil and natural gas properties that closed on April 30, 2020 provides for potential contingent payments to be paid by the Company. The fair value of the contingent consideration was $0.2 million as of the April 30, 2020 acquisition date, which was recorded as part of the basis in the oil and natural gas properties acquired and as a contingent consideration derivative liability. At each quarterly reporting period prior to the end of the contingency period, the Company will remeasure the contingent consideration with the changes in fair value recognized in earnings.

See Note 10.a in the 2019 Annual Report for discussion of the 2019 contingent consideration and for significant Level 2 inputs for the option pricing model used in the fair value mark-to-market analysis of contingent consideration derivatives. The Company reviewed the third-party specialist's valuations, including the related inputs, and has analyzed changes in fair values between the acquisition closing and/or reporting dates.

~~See Notes 3.a and 3.b for further discussion of the Company's asset acquisitions associated with the potential contingent consideration payments.~~

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

See Note 2.j in the 2019 Annual Report for the Level 2 fair value hierarchy input assumptions used in estimating the net realizable value of inventory used to account for the $1.3 million impairment expense of inventory recorded during the six months ended June 30, 2020, pertaining to line-fill and other inventories. There were 0 comparable impairments of inventory recorded during the six months ended June 30, 2019.

See Note 4.a in the 2019 Annual Report for the Level 3 fair value hierarchy input assumptions used in estimating the fair values of assets acquired and liabilities assumed for the acquisition of evaluated and unevaluated oil and natural gas properties accounted for as a business combination for the year ended December 31, 2019. There were 0 acquisitions of evaluated and unevaluated oil and natural gas properties accounted for as business combinations for the six months ended June 30, 2020 or 2019.


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

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

See Note 10.b in the 2019 Annual Report for the Level 3 fair value hierarchy input assumptions used in the fair value measurement of long-lived assets used to account for the $8.2 million impairment expense of long-lived assets recorded during the six months ended June 30, 2020, pertaining to midstream service assets. There were 0 comparable impairments of long-lived assets recorded during the six months ended June 30, 2019.

c. Items not accounted for at fair value

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

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


		June 30, 2020						December 31, 2019							March 31, 2021				December 31, 2020
(in thousands)	(in thousands)	Long-term debt		Fair value⁽¹⁾		Long-term debt		Fair value⁽¹⁾		(in thousands)	Long-term debt		Fair value(1)		Long-term debt		Fair value(1)
January 2022 Notes		$	—	$	—	$	450,000	$	439,875

March 2023 Notes		—		—		350,000		332,500
January 2025 Notes	January 2025 Notes	600,000		414,750		—		—		January 2025 Notes	$	577,913	$	556,288	$	577,913	$	499,299
January 2028 Notes	January 2028 Notes	400,000		278,632		—		—		January 2028 Notes	361,044		346,064		361,044		299,667
Senior Secured Credit Facility	Senior Secured Credit Facility	275,000		274,947		375,000		375,275		Senior Secured Credit Facility	220,000		220,130		255,000		255,187
Total	Total	$	1,275,000	$	968,329	$	1,175,000	$	1,147,650	Total	$	1,158,957	$	1,122,482	$	1,193,957	$	1,054,153

(1)The fair values of the outstanding ~~debt on the~~ notes were determined using the Level 1 fair value hierarchy quoted market prices for each respective instrument as of ~~June 30, 2020~~March 31, 2021 and December 31, ~~2019.~~2020. The fair values of the outstanding debt onunder the Senior Secured Credit Facility were estimated utilizing the Level 2 fair value hierarchy pricing model for similar instruments as of ~~June 30, 2020~~March 31, 2021 and December 31, ~~2019.~~2020.

Note 11—Net income (loss) per common share

Basic and diluted net income (loss) per common share isare computed by dividing net income (loss) by the weighted-average common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution of non-vested restricted stock awards, outstanding stock option awards, non-vested performance share awards and the non-vested outperformance share award. See Note 8 for additional discussion of these awards. For the three ~~and six~~ months ended ~~June 30, 2020,~~March 31, 2021, all of these awards were anti-dilutive due to the Company's net loss and, therefore, were excluded from the calculation of diluted net ~~income (loss)~~loss per common share. ~~For the three and six months ended June 30, 2019, the~~The dilutive effects of these awards were calculated utilizing the treasury stock ~~method. See Note 9 in~~method for the ~~second-quarter 2019 Quarterly Report for discussion~~three months ended March 31, 2020.

The following table reflects the calculations of ~~the awards excluded from the calculation of~~basic and diluted (i) weighted-average common shares outstanding and (ii) net income (loss) per common ~~share.~~share for the periods presented:


	Three months ended March 31,
(in thousands, except for per share data)	2021		2020



Net income (loss) (numerator)	$	(75,439)	$	74,646
Weighted-average common shares outstanding (denominator)(1):
Basic	11,918		11,618




Diluted	11,918		11,673
Net income (loss) per common share(1):



Basic	$	(6.33)	$	6.43




Diluted	$	(6.33)	$	6.39

(1)For the three months ended March 31, 2020, shares and per share data have been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 7.b.

2621


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Condensed notes to the consolidated financial statements

(Unaudited)

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

Three months ended June 30, Six months ended June 30,
(in thousands, except for per share data) 2020 2019 2020 2019
Net income (loss) (numerator) $ (545,455) $ 173,382 $ (470,809) $ 163,891
Weighted-average common shares outstanding (denominator)⁽¹⁾:
Basic 11,667 11,570 11,642 11,547
Dilutive non-vested restricted stock awards — 8 — 39
Diluted 11,667 11,578 11,642 11,586
Net income (loss) per common share⁽¹⁾:

Basic $ (46.75) $ 14.99 $ (40.44) $ 14.19
Diluted $ (46.75) $ 14.98 $ (40.44) $ 14.15

~~(1)Shares and per share data have been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 7.a.~~

Note 12—Commitments and contingencies

a. Litigation

From time to time, the Company is subject to various legal proceedings arising in the ordinary course of business, including proceedings for which the Company may not have insurance coverage. While many of these matters involve inherent uncertainty, as of the date hereof, the Company does not currently believe that any such legal proceedings will have a material adverse effect on the Company's business, financial position, results of operations or liquidity.

b. Drilling rig contract

The Company ~~has committed to a~~enters into drilling rig ~~contract with a third party~~contracts to ensure availability of desired rigs to facilitate ~~the Company's~~ drilling plans. ~~This contract is~~The Company has 2 operating leases for ~~a term~~terms of multiple months, ~~and contains an~~both of which contain early termination ~~clause~~clauses that ~~requires~~require the Company to potentially pay penalties to the third party should the Company cease drilling efforts. These penalties would negatively impact the Company's financial statements upon early contract termination. There were 0 penalties incurred for early contract termination for either of the ~~six~~three months ended ~~June 30, 2020~~March 31, 2021 or ~~2019.~~2020. As ~~the Company's current~~these drilling rig ~~contract is an~~contracts are operating ~~lease with an initial term greater than 12 months,~~leases, the present value of the future commitment as of ~~June 30, 2020~~March 31, 2021 related to the drilling rig contract with an initial term greater than 12 months is included in current and noncurrent ~~operating~~"Operating lease ~~liabilities~~liabilities" on the unaudited consolidated balance sheet as of ~~June 30, 2020. Management does~~March 31, 2021. The future commitment of $1.7 million as of March 31, 2021 related to the drilling rig contract with an initial term less than 12 months is not ~~currently anticipate~~recorded on the ~~early termination~~unaudited consolidated balance sheets. See Note 5 in the 2020 Annual Report for additional discussion of ~~this contract in 2020.~~the Company's leases.

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 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. ~~No contractual penalties~~A portion of the Company's commitments are related to transportation commitments with a certain pipeline pertaining to the gathering of the Company's production from established acreage that extends into 2024. The Company was unable to satisfy a portion of this particular commitment with produced or purchased oil, therefore, the Company expensed firm transportation payments on excess capacity of $1.6 million during the three months ended March 31, 2021, which is recorded in "Transportation and marketing expenses" on the unaudited consolidated statement of operations. NaN firm transportation payments on excess pipeline capacity were incurred during the ~~six~~three months ended ~~June 30,~~March 31, 2020. The ~~Company incurred contractual penalties~~Company's estimated aggregate liability of ~~$0.5~~firm transportation payments on excess capacity is $4.4 million as of March 31, 2021, and ~~$1.0 million during~~is included in "Accounts payable and accrued liabilities" on the ~~three and six months ended June 30, 2019, respectively. Future~~unaudited consolidated balance sheet. As of March 31, 2021, future firm sale and transportation commitments of ~~$306.4~~$258.8 million are expected to be satisfied, and as ~~of June 30, 2020~~such, are not recorded as a liability on the unaudited consolidated balance sheet.

d. Sand purchase commitment


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

During the year ended December 31, 2020, the Company entered into an agreement to take delivery of processed sand at a fixed price for one year, which is utilized in the Company's completions activities, from its sand mine that is operated by a third-party contractor. As of March 31, 2021, under the terms of this agreement, the Company is required to purchase a certain volume remaining under its commitment or it would incur a shortfall payment of $3.4 million at the end of the contract period.

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

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.


Table of Contents			Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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 0 materially significant liabilities of this nature existed as of ~~June 30, 2020~~March 31, 2021 or December 31, ~~2019.~~2020.

Note 13—Supplemental cash flow and non-cash information

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

Six months ended June 30,
(in thousands) 2020 2019
Supplemental cash flow information:
Cash paid for interest, net of $1,822 and $420 of capitalized interest, respectively $ 25,595 $ 29,721
Net cash received for income taxes⁽¹⁾
$ — $ (691)
Supplemental non-cash investing information:
Fair value of contingent consideration on acquisition date⁽²⁾
$ 225 $ —
(Decrease) increase in accrued capital expenditures $ (15,024) $ 2,335
Capitalized share-settled equity-based compensation $ 1,647 $ 1,863
Capitalized asset retirement cost $ 1,082 $ 356

~~(1)See Note 16 for additional discussion of the Company's income taxes.~~

~~(2)~~See Notes 3.a and 9.c for discussion of the Company's 2020 asset acquisition of oil and natural gas properties that includes a contingent consideration. See Note 10.a for discussion of the quarterly remeasurement of the contingent consideration.

~~The following table presents supplemental non-cash adjustments information related to operating leases for the periods presented:~~

Six months ended June 30,
(in thousands) 2020 2019
Right-of-use assets obtained in exchange for operating lease liabilities⁽¹⁾
$ 2,349 $ 25,212

~~(1)See Note 5 for additional discussion of the Company's leases.~~


	Three months ended March 31,
(in thousands)	2021		2020
Supplemental cash flow information:
Cash paid for interest, net of $449 and $1,181 of capitalized interest, respectively	$	48,030	$	23,697

Supplemental non-cash investing information:

Change in accrued capital expenditures	$	(351)	$	16,272

Capitalized share-settled equity-based compensation	$	670	$	965
Capitalized asset retirement cost	$	397	$	886

Note 14—Asset retirement obligations

See Note ~~2.l~~2.k in the ~~2019~~2020 Annual Report for discussion of the Company's significant 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)	2021		2020
Liability at beginning of period	$	68,326	$	62,718
Liabilities added due to acquisitions, drilling, midstream service asset construction and other	397		886
Accretion expense (1)	1,143		1,106
Liabilities settled due to plugging and abandonment or removed due to sale	(57)		(497)


Liability at end of period	$	69,809	$	64,213

(1)Accretion expense is included in "Other operating expenses" on the unaudited consolidated statements of operations.

Note 15—Revenue recognition

Oil, NGL and natural gas sales and sales of purchased oil are generally recognized at the point in time that control of the product is transferred to the customer. Midstream service revenues 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 revenues and methods of recognition can be found in Note 14 in the 2020 Annual Report.

Note 16—Income taxes

The Company is subject to federal and state income taxes and the Texas franchise tax. As of March 31, 2021, the Company had federal net operating loss carryforwards totaling $2.1 billion, and of this amount, $1.7 billion will begin to expire in 2026 and $397.6 million will not expire but may be limited in future periods, and state of Oklahoma net operating loss


Table of Contents			Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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

Six months ended June 30,
(in thousands) 2020 2019
Liability at beginning of period $ 62,718 $ 56,882
Liabilities added due to acquisitions, drilling, midstream service asset construction and other 1,082 356
Accretion expense 2,223 2,072
Liabilities settled due to plugging and abandonment or removed due to sale (778) (1,362)
Liability at end of period $ 65,245 $ 57,948

~~Note 15—Revenue recognition~~

Oil, NGL and natural gas sales and sales of purchased oil 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 fuel for drilling and completions activities, natural gas lift and 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 revenues and methods of recognition can be found in Note 13.b in the 2019 Annual Report.

~~Note 16—Income taxes~~

~~The Company is subject to federal and state income taxes and the Texas franchise tax. As of June 30, 2020, the Company had federal net operating loss~~ carryforwards totaling $2.0 billion, and of this amount, $1.7 billion will begin to expire in 2026 and $299.3 million will not expire but may be limited in future periods, and state of Oklahoma net operating loss carryforwards totaling $34.7$34.5 million that will begin to expire in 2032. As of ~~June 30, 2020,~~March 31, 2021, 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 ~~June 30, 2020,~~March 31, 2021, the Company's ability to capitalize intangible drilling costs, rather than expensing these costs and future projections of Oklahoma sourced income. As of ~~June 30, 2020,~~March 31, 2021, a total valuation allowance of ~~$404.5~~$505.1 million has been recorded to offset the Company's federal and Oklahoma net deferred tax assets, resulting in a Texas net deferred tax asset of ~~$2.3~~$2.2 million, which is included in "Other noncurrent assets, net" on the unaudited consolidated balance sheets.

With the passage of the Tax Cuts and Jobs Act of 2017, the Alternative Minimum Tax ("AMT") on corporations was appealed and a provision was added allowing corporations to offset future tax liabilities by the amount of AMT paid with an AMT credit carryforward. The Coronavirus Aid, Relief, and Economic Security Act, enacted March 27, 2020 ("CARES Act"), modified the opportunity for corporations to receive the AMT carryover refunds by adding in a provision where the AMT credit carryforwards do not expire and are fully refundable with the filing of the Company's 2019 consolidated tax return. The Company paid AMT in 2017, creating an AMT credit carryforward in the amount of $4.1 million, of which $2.0 million was received in 2019. The remaining $2.1 million is included in "Accounts receivable, net" on the unaudited consolidated balance sheet as of June 30, 2020.

Note 17—Related parties

~~a. Helmerich & Payne, Inc.~~Halliburton

The former Chairman of the Company's board of directors, whose term on the Company's board of directors ended on May 14, 2020, is on the board of directors of Helmerich & Payne, Inc. ("H&P"). During each of the six months ended June 30, 2020 and 2019, the Company has 1 drilling rig contract with H&P that is accounted for as a long-term operating lease due to its initial term of greater than 12 months, which is capitalized and included in "Operating lease right-of-use-assets" on the unaudited consolidated balance sheets. The present value of the future commitment is included in current and noncurrent operating lease liabilities on the unaudited consolidated balance sheets. Capital expenditures for oil and natural gas properties are capitalized and are included in "Evaluated oil and natural gas properties" on the unaudited consolidated


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

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

~~balance sheets. See Note 5 for additional discussion of the Company's significant accounting policies on leases. See Note 12.b for additional discussion of the Company's drilling rig contract.~~

~~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 for the periods presented:~~

Six months ended June 30,
(in thousands) 2020 2019
Capital expenditures for oil and natural gas properties⁽¹⁾
$ 18,104 $ 6,293

~~(1)Amount reflected for the six months ended June 30, 2020 is through the date of the former Chairman's expiration of term on the Company's board of directors on May 14, 2020.~~

~~b. Halliburton~~

~~Beginning in 2020, the~~ Chairman of the Company's board of directors is on the board of directors of Halliburton Company ("Halliburton"). Halliburton provides drilling and completions services to the Company.

The following table presents the capital expenditures for oil and natural gas properties paid to Halliburton included in the unaudited consolidated ~~statement~~statements of cash flows for the ~~period~~periods presented:


	~~Six months ended~~
~~(in thousands)~~	~~June 30, 2020~~

~~Capital expenditures for oil and natural gas properties~~	$	~~51,251~~

~~Note 18—Organizational restructurings~~

On June 17, 2020, the Company announced organizational changes, including a workforce reduction of 22 individuals which included a senior officer, that were implemented immediately, subject to certain administrative procedures. In light of the COVID-19 pandemic and lower oil prices, the Company’s board of directors continues to monitor and evaluate the Company’s business and strategy and to reduce costs and better position the Company for the future. In connection with these changes, the Company incurred $4.2 million of one-time charges during the three months ended June 30, 2020, comprised of compensation, tax, professional, outplacement and insurance-related expenses, with $1.7 million accrued in "Other current liabilities" on the unaudited consolidated balance sheet as of June 30, 2020. All equity-based compensation awards held by the affected employees were forfeited and the corresponding equity-based compensation was reversed totaling $0.8 million during the three months ended June 30, 2020. See Note 8 for additional information on the associated forfeiture activity.

On April 2, 2019, the Company announced the retirement of 2 of its senior officers. Additionally, on April 8, 2019, the Company committed to a company-wide reorganization effort (the "Plan") that included 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. The Company's board of directors approved the Plan in response to 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 incurred $10.4 million of one-time charges during the three months ended June 30, 2019 comprised of compensation, taxes, professional fees, outplacement and insurance-related expenses. All equity-based compensation awards held by the two senior officers, the executive officer and the employees who were affected by the Plan were forfeited and the corresponding equity-based compensation was reversed totaling $6.1 million during the three months ended June 30, 2019. See Note 6.c in the second-quarter 2019 Quarterly Report for additional information on the associated forfeiture activity.

The incurred charges were recorded as "Organizational restructuring expenses" and the equity-based compensation expense reversals are recorded in "General and administrative" on the unaudited consolidated statement of operations.


	Three months ended March 31,
(in thousands)	2021		2020

Capital expenditures for oil and natural gas properties	$	11,780	$	27,225

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Condensed notes to the consolidated financial statements

(Unaudited)

Note ~~19—~~18—Subsequent events

a. Senior Secured Credit Facility

On ~~July 14, 2020,~~April 6, 2021 and April 26, 2021, the Company borrowed an additional ~~$45.0~~$20.0 million ~~on the Senior Secured Credit Facility. On July 31, 2020, the Company~~and made a ~~$20~~$10.0 million payment, respectively, on the Senior Secured Credit Facility. As a result, the outstanding balance under the Senior Secured Credit Facility was ~~$300.0~~$230.0 million as of ~~August 4, 2020.~~

~~On August 5, 2020,~~May 3, 2021. See Note 6.c for additional discussion of the ~~Company received a waiver from the lenders under its~~Company's Senior Secured Credit ~~Facility of certain representations and warranties relating~~Facility.

b. Commodity derivatives

The following table presents the commodity derivatives that were entered into by the Company subsequent to ~~the Company's~~ March 31, 2020 quarterly results. Such representations and warranties were incorrect at the time they were given due to the Company's previously disclosed accounting error. Additionally, due to the accounting error the Company was temporarily not in compliance with the financial reporting covenants. As of the filing of its restated unaudited consolidated financial statements for the quarter ended March 31, 2020, the Company regained compliance with the financial reporting covenants under the Senior Secured Credit Facility and the waiver cured the past defaults of the representations and warranties. The Senior Secured Credit Facility contains both financial and non-financial covenants, all of which the Company was in compliance with for all periods presented.2021:

~~b. Derivatives~~

Aggregate volumes (Bbl)

Weighted-average price ($/Bbl)

Contract period

Brent ICE - Swaps

365,000

61.55

January 2022 - December 2022

~~The Company entered into additional Brent ICE swaps for 2021 and 2022 subsequent to June 30, 2020.~~

The following table summarizes the resulting open ~~Brent ICE swap positions~~oil derivative position as of ~~June 30, 2020,~~March 31, 2021, updated for ~~derivatives that were entered into~~the above derivative transactions through ~~August 5, 2020,~~May 3, 2021, for the settlement periods presented:


		Remaining year 2020		Year 2021		Year 2022			Remaining Year 2021		Year 2022
Oil:	Oil:							Oil:

Brent ICE swaps:
Brent ICE - Swaps:								Brent ICE - Swaps:
Volume (Bbl)	Volume (Bbl)	1,196,000		4,307,000		2,920,000		Volume (Bbl)	5,651,250		4,124,500
Weighted-average price ($/Bbl)	Weighted-average price ($/Bbl)	$	63.07	$	49.71	$	46.40	Weighted-average price ($/Bbl)	$	51.29	$	48.34
Brent ICE - Collars:								Brent ICE - Collars:
Volume (Bbl)								Volume (Bbl)	440,000		821,250
Weighted-average floor price ($/Bbl)								Weighted-average floor price ($/Bbl)	$	45.00	$	53.67
Weighted-average ceiling price ($/Bbl)								Weighted-average ceiling price ($/Bbl)	$	59.50	$	62.40
Total Brent ICE:								Total Brent ICE:
Total volume (Bbl)								Total volume (Bbl)	6,091,250		4,945,750
Weighted-average floor price ($/Bbl)								Weighted-average floor price ($/Bbl)	$	50.83	$	49.22

Weighted-average ceiling price ($/Bbl)								Weighted-average ceiling price ($/Bbl)	$	51.88	$	50.67

See Note ~~9.a~~9 for ~~a table that includes~~additional discussion regarding the Company's ~~other commodity derivative positions as of June 30, 2020.~~derivatives. There has been no other derivative activity subsequent to ~~June 30, 2020.~~

March 31, 2021.

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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 is for the three ~~and six~~ months ended ~~June 30,~~March 31, 2021 and 2020, ~~and 2019,~~ and 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 ~~2019~~2020 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" and "Part II, Item 1A. Risk Factors." 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. Unless otherwise specified, references to "average sales price" refer to average sales price excluding the effects of our derivative transactions. All amounts, dollars and percentages presented in this Quarterly Report are rounded and therefore approximate.

Executive overview

We are an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties, primarily in the Permian Basin of West Texas. The oil and liquids-rich Permian Basin is characterized by multiple target horizons, extensive production histories, long-lived reserves, high drilling success rates and high initial production rates. Since our inception, we have grown primarily through our drilling program, coupled with select strategic acquisitions and joint ventures. As of March 31, 2021, we had assembled 133,352 net acres in the Permian Basin.

Our financial and operating performance included the following for the periods presented and the corresponding ~~changes:~~changes for such periods:


		Three months ended June 30,						2020 compared to 2019							Three months ended March 31,			2021 compared to 2020
(in thousands)	(in thousands)	2020		2019		Change (#)		Change (%)		(in thousands)	2021		2020			Change (#)		Change (%)
Oil sales volumes (MBbl)	Oil sales volumes (MBbl)	2,843		2,771		72		3	%	Oil sales volumes (MBbl)	2,183		2,655			(472)		(18)	%
Oil equivalents sales volumes (MBOE)	Oil equivalents sales volumes (MBOE)	8,565		7,485		1,080		14	%	Oil equivalents sales volumes (MBOE)	7,109		7,874			(765)		(10)	%
Oil, NGL and natural gas sales⁽¹⁾	Oil, NGL and natural gas sales⁽¹⁾	$	94,143	$	183,863	$	(89,720)	(49)	%	Oil, NGL and natural gas sales(1)	$	202,457	$	135,885		$	66,572	49	%
Net income (loss)⁽²⁾	Net income (loss)⁽²⁾	$	(545,455)	$	173,382	$	(718,837)	(415)	%	Net income (loss)⁽²⁾	$	(75,439)	$	74,646		$	(150,085)	(201)	%
Free Cash Flow (a non-GAAP financial measure)⁽³⁾⁽²⁾	Free Cash Flow (a non-GAAP financial measure)⁽³⁾⁽²⁾	$	(23,546)	$	39,973	$	(63,519)	(159)	%	Free Cash Flow (a non-GAAP financial measure)⁽³⁾⁽²⁾	$	21,760	$	(57,523)		$	79,283	138	%
Adjusted EBITDA (a non-GAAP financial measure)⁽³⁾⁽²⁾	Adjusted EBITDA (a non-GAAP financial measure)⁽³⁾⁽²⁾	$	132,837	$	153,218	$	(20,381)	(13)	%	Adjusted EBITDA (a non-GAAP financial measure)⁽³⁾⁽²⁾	$	93,323	$	116,848		$	(23,525)	(20)	%

(1)Our oil, NGL and natural gas sales ~~decreased~~increased as a result of a ~~55% decrease~~65% increase in average sales price per BOE and were partially offset by a ~~14% increase~~10% decrease in total volumes sold.

(2)~~Our net loss~~See pages 39-40 for ~~the three months ended June 30, 2020 includes a non-cash full cost ceiling impairment of $406.4 million.~~

~~(3)See page 54 for~~ discussions ~~regarding and calculations of these non-GAAP financial measures.~~

~~Table of Contents~~

Six months ended June 30, 2020 compared to 2019
(in thousands) 2020 2019 Change (#) Change (%)
Oil sales volumes (MBbl) 5,498 5,305 193 4 %
Oil equivalents sales volumes (MBOE) 16,439 14,260 2,179 15 %
Oil, NGL and natural gas sales⁽¹⁾
$ 230,028 $ 357,239 $ (127,211) (36) %
Net income (loss)⁽²⁾
$ (470,809) $ 163,891 $ (634,700) (387) %
Free Cash Flow (a non-GAAP financial measure)⁽³⁾
$ (81,069) $ (10,992) $ (70,077) (638) %
Adjusted EBITDA (a non-GAAP financial measure)⁽³⁾
$ 249,685 $ 276,124 $ (26,439) (10) %

~~(1)Our oil, NGL and natural gas sales decreased as a result of a 44% decrease in average sales price per BOE and were partially offset by a 15% increase in total volumes sold.~~

~~(2)Our net loss for the six months ended June 30, 2020 includes a non-cash full cost ceiling impairment of $583.6 million.~~

~~(3)See page 54 for discussions regarding~~ and calculations of these non-GAAP financial measures.

Recent developments

~~Restatement of our unaudited consolidated financial statements for the quarter ended March 31, 2020~~ATM Program

On ~~August 5, 2020,~~February 23, 2021, we ~~filed~~entered into an ~~amendment~~equity distribution agreement with Wells Fargo Securities, LLC acting as sales agent and/or principal, pursuant to ~~our quarterly report~~which we may offer and sell, from time to ~~restate our unaudited consolidated financial statements for~~time through the quarter ended March 31, 2020 (the “Restated First Quarter Financials”) to correct an error in the future production costs component of the estimated present value (“PV-10”) of our reserves. The omitted costs caused an understatement of approximately $160 million of the full cost ceiling impairment expense and balances of accumulated depletion and impairment and accumulated deficit, and a corresponding overstatement of the same amount to both net income and the balance of our oil and natural gas properties for the first quarter of 2020. This error was identified in the course of preparing our unaudited consolidated financial statements for the quarter ended June 30, 2020. This error was isolated to our first-quarter estimate of the PV-10 of our reserves and had no impact on our prior financial statements, including the 2019 Annual Report. This Quarterly Report gives effect to the restated financial information for the quarter ended March 31, 2020. In addition, we have received a waiver from the lenders under our Senior Secured Credit Facility in connection with the error.

~~Reverse stock split~~

~~On June 1, 2020, we effected the previously announced 1-for-20 reverse stock split~~sales agent, shares of our common stock ~~and~~having an aggregate gross sales price of up to $75.0 million through the ~~related reduction~~ATM Program.

As of ~~the number of authorized~~March 31, 2021, we have sold 723,579 shares of our common stock ~~which~~pursuant to the ATM Program for net proceeds of approximately $26.9 million, after underwriting commissions and other related expenses. Proceeds from the share sale were ~~previously approved by our stockholders at our 2020 annual meeting~~utilized to reduce borrowings on the Senior Secured Credit Facility. The timing of ~~stockholders. Our common stock began trading,~~any additional sales will depend on a ~~split-adjusted basis and under our existing trading symbol, at the opening~~variety of ~~trading on June 2, 2020.~~factors to be determined by us. See Note 7.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of the ~~reverse stock split.~~ATM Program.

~~On July 1, 2020, we were notified that we were in compliance with the New York Stock Exchange's continued listing criterion of a minimum share price of $1 over a 30 trading-day period.~~

~~Organizational restructuring~~

On June 17, 2020, we announced organizational changes, including a workforce reduction of 22 individuals, which included a senior officer, that were implemented immediately, subject to certain administrative procedures. In light of the COVID-19 pandemic and lower oil prices, our board of directors continues to monitor and evaluate our business and strategy and to reduce costs and better position us for the future. In connection with the organizational changes, we announced the departure of our former Senior Vice President and Chief Financial Officer ("former CFO"), effective as of June 17, 2020. Our former CFO's departure was not the result of any dispute or disagreement with us or our accounting practices or financial statements. We incurred $4.2 million of one-time organizational restructuring expenses during the three months ended June 30, 2020, comprised of compensation, tax, professional, outplacement and insurance-related expenses. See Note 18 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of the organizational restructuring.

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~~On June 17, 2020, we announced~~Weather

During February 2021, severe winter weather affected our operations resulting in downtime and delays that ~~the board~~impacted total and oil production for first-quarter 2021 by an estimated 5,700 BOE per day and 1,700 barrels of ~~directors appointed Bryan J. Lemmerman as Senior Vice President—Chief Financial Officer~~oil per day, respectively. Production impacts were less than originally anticipated and ~~Assistant Secretary effective as of June 30, 2020.~~operations returned to pre-storm levels sooner than anticipated.

COVID-19

~~In December 2019, a highly transmissible and pathogenic strain of coronavirus surfaced in China, which has and is continuing~~COVID-19 continues to spread throughout the world, including the U.S. On January 30, 2020, the World Health Organization declared the outbreak of COVID-19 a "Public Health Emergency of International Concern," and on March 11, 2020, the World Health Organization characterized the outbreak as a "pandemic". Federal, state and local authorities have recommended stay-at-home orders and social distancing guidelines for U.S. residents and to avoid all unnecessary travel for any reason including non-essential jobs for an indeterminate amount of time until the spread of COVID-19 declines to acceptable lower levels. Such actions have resulted in a swift and unprecedented reduction in international and U.S. economic activity which, in turn, has adversely affectedaffect the demand for oil and natural gas and ~~caused significant volatility and disruption of the financial markets. We~~we are not able to predict the duration or ultimate impact that ~~COVID-19~~it will have on our business, financial condition and results of operations. We ~~are responding~~continue to these current events with thoughtful planning and are committed to maintaining safe and reliable operations. The health and safety of our employees, suppliers and customers remain a top priority. To protect the health and safety of our employees and business partners, we have instituted policies to promote social distancing, both in the office and at field locations. Additionally, the majority of our non-field based employees have successfully transitioned to working from home. We are closely ~~monitoring~~monitor local infection rates and ~~instituting~~to conform to guidelines and best practices encouraged by the ~~appropriate~~ Centers for Disease Control and Prevention, ~~guidelines~~the World Health Organization and other governmental and regulatory authorities to ~~determine~~transition to appropriate return-to-work policies while minimizing interruptions to our operations. ~~We do not believe that~~To date, these measures have not had a material effect on our workforce productivity.

On March 27, 2020, the CARES Act was enacted in response to the COVID-19 pandemic. It included provisions intended to provide relief to individuals and businesses in the form of loans and grants, and tax changes, among other provisions. ~~At this time, we have~~We did not ~~sought~~seek relief in the form of loans or grants from the CARES Act; however, we have benefited from the provision where the AMT credit carryforwards do not expire and are fully refundable.

Volatility in Commodity Prices

In ~~early March~~the spring of 2020, ~~concurrent with the spread of COVID-19 to the U.S. and just prior to the government actions mentioned above,~~action by members of OPEC+ ~~proposed production cuts in an attempt~~attempting to stabilize the oil ~~market. However, OPEC+ failed to reach an agreement~~market and some producers instead announced planned production increases, after which oil prices declined sharply. By mid-March 2020, WTI oil prices had declined to less than $25 per barrel, the lowest price since 2002. Although OPEC+ subsequently reached agreement in April 2020 on production cuts that went into effect in May 2020, oil prices continued to decline following announcement of the agreement. Further, producers in thea slow reaction by U.S. and ~~globally have not reduced~~global producers to reduce oil production at a rate sufficient to match the sharp ~~slowdown in~~ economic ~~activity~~slowdown caused by ~~measures to control the spread of~~ COVID-19, ~~resulting~~resulted in an oversupply of oil that ~~recently~~ caused WTI oil prices ~~per barrel~~ to fall to -$37 per barrel on April ~~20th. Since~~20, 2020. Following the April 20th low, WTI oil prices ~~have~~ rebounded ~~to around $40, trading in a range of $40 to $42~~ in the ~~month~~second half of ~~July.~~2020 and have averaged $58 per barrel during first-quarter 2021 and averaged $59 per barrel through April 2021.

We maintain an active, multi-year commodity derivatives strategy to minimize commodity price volatility and support cash flows needed for ~~operations.~~ operatFor July through December 2020, we currently have oil derivatives in place for 3.6 million barrels swapped at a weighted-average price of $59.50 WTI per barrel and 1.2 million barrels swapped at a weighted-average price of$63.07 Brent per barrel. We entered into derivatives subsequent to June 30, 2020 for both 2021 and 2022. ions. For 2021, we currently have oil derivatives in place for ~~7.4~~6.1 million barrels at a weighted-average floor price of ~~$51.11~~$50.83 Brent per barrel. For 2022, we currently have oil derivatives in place for ~~2.9~~4.9 million barrels at a weighted-average floor price of ~~$46.40~~$49.22 Brent per barrel.

With oil prices moving to above $40 late in the second quarter of 2020, and our execution of additional oil commodity hedges for 2021 and 2022 subsequent to June 30, 2020, we expect to add completions activity in the last four months of 2020 and drilling activity beginning in January of 2021. We currently expect capital expenditures for 2020 to be approximately $340 million to $350 million. We will continue to monitor commodity prices and service costs and adjust activity levels in order to proactively manage our cash flows and preserve liquidity. We will continue to utilize this slowdown as an opportunity to improve on our strong operations performance and to continue to reduce expenses to the lowest and most efficient cost structure possible.

~~Table of Contents~~

~~Senior Secured Credit Facility~~

On April 30, 2020, as a result of the semi-annual redetermination, we entered into the fourth amendment to our Senior Secured Credit Facility pursuant to which the borrowing base and aggregate elected commitment were reduced to $725.0 million each. Other than the decrease in borrowing base and aggregate elected commitment, among the more significant changes are: (i) margin applied to both Eurodollar and Adjusted Base Rate Loans and the fees charged in connection with letters of credit were increased by 0.500%, in each case, at all levels of Borrowing Base utilization; (ii) the aggregate amount of Asset Dispositions that may occur since the Determination Date of the Borrowing Base then in effect without triggering an automatic reduction of the Borrowing Base was reduced from 10% to 5% of the Borrowing Base then in effect; (iii) the definition of Permitted Investments was modified to eliminate a safe harbor for investments in partnerships and joint ventures and the general "other" safe harbor; and (iv) the definition of Permitted Investment and covenants limiting Distributions and Redemption of Senior Notes were modified such that Investment, Distributions and Redemptions of Senior Notes remain permitted, in each case, so long as immediately after giving effect to such Investment, Distribution or Redemption (a) the amount of Distributions, Investments and Redemptions from and after April 1, 2020 is not greater than $100 million, (b) no Default or Event of Default exists, (c) undrawn Commitments are greater than or equal to 35% of Total Commitments, (d) the pro forma ratio of Consolidated Current Assets to Consolidated Current Liabilities is not less than 1.00 to 1.00, and (e) the pro forma Consolidated Total Leverage Ratio is not greater than 2.50 to 1.00. All capitalized terms above have the meanings ascribed to them in the Fourth Amendment or the Senior Secured Credit Facility, as applicable. The financial covenant requiring a Consolidated Total Leverage Ratio of not greater than 4.25 to 1.00 at each fiscal quarter end for the preceding four fiscal quarters remains unchanged.

Pricing and reserves

Our results of operations are heavily influenced by oil, NGL and natural gas prices, which have experienced significant declines that continue in third-quarter 2020. Oil, NGL and natural gas price fluctuations are currently impacted by the COVID-19 pandemic and policies of OPEC+, which have generally increased supply, decreased demand, made more volatile economic and market conditions, caused transportation and storage constraints and led to a variety of additional issues on both a regional and global basis.prices. Historically, commodity prices have experienced significant fluctuations; however, the volatility in ~~the~~ prices has substantially increased as a result of ~~the recent~~ world developments in 2020. The duration of such developments 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.

We have entered into a number of commodity derivative contracts that have enabled us to offset a portion of the changes in our cash flow caused by fluctuations in price and basis differentials for our sales of oil, NGL and natural gas, as discussed in "Item 3. Quantitative and Qualitative Disclosures About Market Risk." See Notes 9, 10.a and ~~19.b~~18.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our commodity ~~derivatives, including those entered into subsequent to June 30, 2020.~~derivatives.

Our reserves ~~as of June 30, 2020 and December 31, 2019~~ are reported in three streams: oil, NGL and natural gas. ~~As discussed in Note 4 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report, the~~The Realized Prices utilized to value our proved reserves as of ~~June 30,~~March 31, 2021 and March 31, 2020, ~~and June 30, 2019,~~ are as follows:


		June 30, 2020		June 30, 2019			March 31, 2021		March 31, 2020
Realized Prices:	Realized Prices:					Realized Prices:
Oil ($/Bbl)	Oil ($/Bbl)	$	44.97	$	55.69	Oil ($/Bbl)	$	38.28	$	52.47
NGL ($/Bbl)	NGL ($/Bbl)	$	7.66	$	18.64	NGL ($/Bbl)	$	9.92	$	10.47
Natural gas ($/Mcf)	Natural gas ($/Mcf)	$	0.53	$	0.70	Natural gas ($/Mcf)	$	1.20	$	0.28

The Realized Prices used to estimate proved reserves do not include derivative transactions. The unamortized cost of evaluated oil and natural gas properties being depleted exceeded the full cost ceiling asfor each of ~~March 31, 2020 and June 30,~~the quarterly periods in 2020 and, as such, we recorded ~~first and second-quarter~~ non-cash full cost ceiling impairments ~~of $177.2~~totaling $889.5 million ~~and $406.4 million, respectively. No such impairments were recorded~~ during the ~~six months~~year ended June 30, 2019. As more specifically addressed in "Low commodity price potential impact on our third-quarter 2020 and Remaining Year 2020 full cost ceiling impairment tests" below, if prices remain at or below the current levels, subject to numerous factors and inherent limitations, and all other factors remain constant, we could incur additional significant non-cash full cost ceiling impairments in the third quarter of 2020 and Remaining Year 2020 (defined below), which will have an adverse effect on our results of operations. See Note 4December 31,

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2020. No such full cost ceiling impairment was recorded as of March 31, 2021. Additionally, given current commodity prices, we do not anticipate recording a full cost ceiling impairment in the second quarter of 2021. See Note 5 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of ~~our~~the full cost method of ~~accounting.~~accounting and our Realized Prices.

Horizontal drilling of unconventional wells using enhanced completions techniques, including, but not limited to, hydraulic fracturing, is a ~~relatively new~~continually evolving process and, as such, forecasting the long-term production 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, inventory and reserves continue to appear accurate or require modification. While all production forecasts have elements of uncertainty over the life of the related wells, we have ~~seen indications~~observed over multiple years that ~~the~~ oil decline rates are impacted by the vertical and horizontal spacing of ~~tightly spaced~~wells. In 2020, all wells ~~may be steeper than originally anticipated. In 2019, we began drilling~~in our established acreage and ~~completing wells~~Western Glasscock were drilled and completed at the wider spacing to mitigate this ~~effect~~effect. Wells in ~~established acreage.~~Howard County were and continue to be completed at various horizontal spacing patterns as we test the optimum spacing in that area. In order to mitigate potential negative revisions in future years, we have taken a conservative approach in regards to oil rate forecasts on future wells in Howard County.

Initial production results, production decline rates, well density, completions design and operating method are examples of the numerous uncertainties and variables inherent in the estimation of proved reserves in future periods. The quantity of proved reserves is one of the many variables inherent in the calculation of depletion.

~~The following tables present our depletion expense for our evaluated oil and natural gas properties per BOE sold for the periods presented and corresponding changes:~~

Three months ended June 30, 2020 compared to 2019
2020 2019 Change ($) Change (%)
Depletion expense per BOE sold $ 7.39 $ 8.27 $ (0.88) (11) %

Six months ended June 30, 2020 compared to 2019
2020 2019 Change ($) Change (%)
Depletion expense per BOE sold $ 7.36 $ 8.51 $ (1.15) (14) %

~~Low commodity price potential impact on our third-quarter 2020 and Remaining Year 2020 full cost ceiling impairment tests~~

We use the full cost method of accounting for our oil and natural gas properties, with the full cost ceiling, as defined by the SEC, based principally on the estimated future net revenues from our proved oil, NGL and natural gas reserves, which exclude the effect of our commodity derivative transactions, discounted at 10% under required SEC guidelines for pricing methodology. We review the carrying value of our oil and natural gas properties under the full cost accounting rules of the SEC on a quarterly basis. In the event the unamortized cost, or net book value, of evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, the excess is expensed in the period such excess occurs. Once incurred, a write-down of evaluated oil and natural gas properties is not reversible.

If prices remain at or below the current levels, subject to numerous factors and inherent limitations, some of which are discussed below, and all other factors remain constant, we could incur substantial non-cash full cost ceiling impairments in third-quarter 2020 and Remaining Year 2020, which will have an adverse effect on our statement of operations.

There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in future periods. In addition to unknown future commodity prices, other uncertainties include, but are not limited to (i) changes in drilling and completions 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-level horizontal targets, (v) government imposed curtailment of production, (vi) the potential to shut-in a portion or all of our wells, (vii) income tax impacts, (viii) potential recognition of additional proved undeveloped reserves, (ix) any potential value added to our proved reserves when testing recoverability from drilling unbooked locations, (x) revisions to production curves based on additional data and (xi) the inherent significant volatility in the commodity prices for oil, NGL and natural gas.

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 proved reserves. Changes in circumstance, including commodity pricing, economic factors and the other uncertainties described above may lead to changes in our development plans.

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Set forth below are calculations of potential future impairments of our evaluated oil and natural gas properties for the third-quarter 2020 and for the period of July 1 to December 31, 2020 ("Remaining Year 2020"). Such implied impairments should not be interpreted to be indicative of our development plan or of our actual future results. Each of the uncertainties noted above has been evaluated for material known trends to be potentially included in the estimation of possible third-quarter 2020 and Remaining Year 2020 effects. Based on such review, we determined that the impact of decreased commodity prices is the only significant known variable necessary in calculating the following scenario.

Our hypothetical third-quarter 2020 full cost ceiling calculation has been prepared by substituting (i) $41.29 per Bbl for oil, (ii) $7.34 per Bbl for NGL and (iii) $0.70 per Mcf for natural gas (collectively, the "Pro Forma Third-Quarter Prices") for the respective Realized Prices as of June 30, 2020. All other inputs and assumptions have been held constant. Accordingly, this estimation strictly isolates the estimated impact of low commodity prices on the third-quarter 2020 Realized Prices that will be utilized in our full cost ceiling calculation. The Pro Forma Third-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 10 months ended July 1, 2020 and holding the July 1, 2020 prices constant for the remaining eleventh and twelfth months of the calculation. Based solely on the substitution of the Pro Forma Third-Quarter Prices into our June 30, 2020 proved reserve estimates, the implied third-quarter 2020 impairment would be $100 million.

Our hypothetical Remaining Year 2020 full cost ceiling calculation has been prepared by substituting (i) $39.79 per Bbl for oil, (ii) $6.93 per Bbl for NGL and (iii) $0.80 per Mcf for natural gas (collectively, the "Pro Forma Remaining Year Prices") for the respective Realized Prices. All other inputs and assumptions have been held constant. Accordingly, this estimation strictly isolates the estimated impact of low commodity prices on the Remaining Year 2020 Realized Prices that will be utilized in our full cost ceiling calculation. The Pro Forma Remaining Year 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 seven months ended July 1, 2020 and using strip pricing as of July 20, 2020 for the remaining five months. Based solely on the substitution of the Pro Forma Remaining Year Prices into our June 30, 2020 proved reserve estimates, the implied Remaining Year 2020 impairment would be $145 million.

We believe that substituting these prices into our June 30, 2020 proved reserve estimates may help provide users with an understanding of the potential impact on our third-quarter 2020 and Remaining Year 2020 full cost ceiling tests.

See Note 4 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for prices used to value our reserves and additional discussion of our full cost impairments for the three and six months ended June 30, 2020.

~~Core area of operations~~

The oil and liquids-rich Permian Basin is characterized by multiple target horizons, extensive production histories, long-lived reserves, high drilling success rates and high initial production rates. As of June 30, 2020, we had assembled 130,993 net acres in the Permian Basin.

Results of operations

Revenues

Sources of our revenue

Our revenues are derived from the sale of produced oil, NGL and natural gas, the sale of purchased oil and providing midstream services to third parties, all within the continental ~~United States~~U.S. and do not include the effects of derivatives. ~~Our oil, NGL and natural gas revenues may vary significantly from period~~See Note 15 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, pricing differentials and the amount of volumes purchased. Our midstream service revenues may fluctuate and vary due to oil throughput fees and the level of services provided to third parties for (i) integrated oil and natural gas gathering and transportation systems and related facilities, (ii) natural gas lift, fuel for drilling and completions activities and centralized compression infrastructure and (iii) water storage, recycling and transportation infrastructure. See Notes 2.o and 13.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report and Note 14 in our ~~2019~~2020 Annual Report for additional information regarding our revenue recognition policies.

~~Table of Contents~~

The following ~~tables present~~table presents our sources of revenue as a percentage of total revenues for the periods presented and the corresponding ~~changes:~~changes for such periods:

Three months ended June 30, 2020 compared to 2019
2020 2019 Change (#) Change (%)
Oil sales 63 % 74 % (11) % (15) %
NGL sales 12 % 10 % 2 % 20 %
Natural gas sales 10 % 1 % 9 % 900 %
Midstream service revenues 2 % 1 % 1 % 100 %
Sales of purchased oil 13 % 14 % (1) % (7) %
Total 100 % 100 %


		Six months ended June 30,						2020 compared to 2019							Three months ended March 31,				2021 compared to 2020
		2020		2019		Change (#)		Change (%)			2021		2020		Change (#)		Change (%)

Oil sales	Oil sales	60	%	68	%	(8)	%	(12)	%	Oil sales	51	%	59	%	(8)	%	(14)	%
NGL sales	NGL sales	8	%	13	%	(5)	%	(38)	%	NGL sales	17	%	6	%	11	%	183	%
Natural gas sales	Natural gas sales	4	%	3	%	1	%	33	%	Natural gas sales	13	%	2	%	11	%	550	%
Midstream service revenues	Midstream service revenues	2	%	1	%	1	%	100	%	Midstream service revenues	1	%	1	%	—	%	—	%
Sales of purchased oil	Sales of purchased oil	26	%	15	%	11	%	73	%	Sales of purchased oil	18	%	32	%	(14)	%	(44)	%
Total	Total	100	%	100	%					Total	100	%	100	%

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

The following ~~tables present~~table presents information regarding our oil, NGL and natural gas sales volumes, sales revenues and average sales prices for the periods presented and the corresponding ~~changes:~~changes for such periods:


		Three months ended June 30,						2020 compared to 2019					Three months ended March 31,				2021 compared to 2020
		2020		2019		Change (#)		Change (%)			2021		2020		Change (#)		Change (%)
Sales volumes:	Sales volumes:									Sales volumes:
Oil (MBbl)	Oil (MBbl)	2,843		2,771		72		3	%	Oil (MBbl)	2,183		2,655		(472)		(18)	%
NGL (MBbl)	NGL (MBbl)	2,752		2,200		552		25	%	NGL (MBbl)	2,321		2,467		(146)		(6)	%
Natural gas (MMcf)	Natural gas (MMcf)	17,817		15,092		2,725		18	%	Natural gas (MMcf)	15,630		16,512		(882)		(5)	%
Oil equivalents (MBOE)⁽¹⁾⁽²⁾	Oil equivalents (MBOE)⁽¹⁾⁽²⁾	8,565		7,485		1,080		14	%	Oil equivalents (MBOE)(1)(2)	7,109		7,874		(765)		(10)	%
Average daily oil equivalent sales volumes (BOE/D)⁽²⁾	Average daily oil equivalent sales volumes (BOE/D)⁽²⁾	94,117		82,259		11,858		14	%	Average daily oil equivalent sales volumes (BOE/D)(2)	78,989		86,532		(7,543)		(9)	%
Average daily oil sales volumes (Bbl/D)⁽²⁾	Average daily oil sales volumes (Bbl/D)⁽²⁾	31,241		30,447		794		3	%	Average daily oil sales volumes (Bbl/D)(2)	24,261		29,178		(4,917)		(17)	%
Sales revenues (in thousands):	Sales revenues (in thousands):									Sales revenues (in thousands):
Oil	Oil	$	70,105	$	160,030	$	(89,925)	(56)	%	Oil	$	127,701	$	119,978	$	7,723	6	%
NGL	NGL	13,228		22,197		(8,969)		(40)	%	NGL	41,678		11,558		30,120		261	%
Natural gas	Natural gas	10,810		1,636		9,174		561	%	Natural gas	33,078		4,349		28,729		661	%
Total oil, NGL and natural gas sales revenues	Total oil, NGL and natural gas sales revenues	$	94,143	$	183,863	$	(89,720)	(49)	%	Total oil, NGL and natural gas sales revenues	$	202,457	$	135,885	$	66,572	49	%
Average sales prices⁽²⁾:	Average sales prices⁽²⁾:									Average sales prices(2):
Oil ($/Bbl)⁽³⁾	Oil ($/Bbl)⁽³⁾	$	24.66	$	57.76	$	(33.10)	(57)	%	Oil ($/Bbl)(3)	$	58.48	$	45.19	$	13.29	29	%
NGL ($/Bbl)⁽³⁾	NGL ($/Bbl)⁽³⁾	$	4.81	$	10.09	$	(5.28)	(52)	%	NGL ($/Bbl)(3)	$	17.96	$	4.68	$	13.28	284	%
Natural gas ($/Mcf)⁽³⁾	Natural gas ($/Mcf)⁽³⁾	$	0.61	$	0.11	$	0.50	455	%	Natural gas ($/Mcf)(3)	$	2.12	$	0.26	$	1.86	715	%
Average sales price ($/BOE)⁽³⁾	Average sales price ($/BOE)⁽³⁾	$	10.99	$	24.56	$	(13.57)	(55)	%	Average sales price ($/BOE)(3)	$	28.48	$	17.26	$	11.22	65	%
Oil, with commodity derivatives ($/Bbl)⁽⁴⁾	Oil, with commodity derivatives ($/Bbl)⁽⁴⁾	$	50.46	$	56.65	$	(6.19)	(11)	%	Oil, with commodity derivatives ($/Bbl)(4)	$	45.03	$	56.59	$	(11.56)	(20)	%
NGL, with commodity derivatives ($/Bbl)⁽⁴⁾	NGL, with commodity derivatives ($/Bbl)⁽⁴⁾	$	7.60	$	12.82	$	(5.22)	(41)	%	NGL, with commodity derivatives ($/Bbl)(4)	$	11.25	$	6.85	$	4.40	64	%
Natural gas, with commodity derivatives ($/Mcf)⁽⁴⁾	Natural gas, with commodity derivatives ($/Mcf)⁽⁴⁾	$	0.91	$	1.17	$	(0.26)	(22)	%	Natural gas, with commodity derivatives ($/Mcf)(4)	$	1.66	$	0.94	$	0.72	77	%
Average sales price, with commodity derivatives ($/BOE)⁽⁴⁾	Average sales price, with commodity derivatives ($/BOE)⁽⁴⁾	$	21.09	$	27.09	$	(6.00)	(22)	%	Average sales price, with commodity derivatives ($/BOE)(4)	$	21.15	$	23.21	$	(2.06)	(9)	%

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

(2)The numbers presented in the three months ended ~~June 30,~~March 31, 2021 and 2020 ~~and 2019~~ columns are based on actual amounts and are not calculated using the rounded numbers presented in the table above or the table below.

(3)Price reflects the average of actual sales prices received when control passes to the purchaser/customer adjusted for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point.

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

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Six months ended June 30, 2020 compared to 2019
2020 2019 Change (#) Change (%)
Sales volumes:
Oil (MBbl) 5,498 5,305 193 4 %
NGL (MBbl) 5,219 4,299 920 21 %
Natural gas (MMcf) 34,329 27,941 6,388 23 %
Oil equivalents (MBOE)⁽¹⁾⁽²⁾
16,439 14,260 2,179 15 %
Average daily oil equivalent sales volumes (BOE/D)⁽²⁾
90,324 78,787 11,537 15 %
Average daily oil sales volumes (Bbl/D)⁽²⁾
30,209 29,308 901 3 %
Sales revenues (in thousands):
Oil $ 190,083 $ 289,201 $ (99,118) (34) %
NGL 24,786 54,432 (29,646) (54) %
Natural gas 15,159 13,606 1,553 11 %
Total oil, NGL and natural gas sales revenues $ 230,028 $ 357,239 $ (127,211) (36) %
Average sales prices⁽²⁾:

Oil ($/Bbl)⁽³⁾
$ 34.57 $ 54.52 $ (19.95) (37) %
NGL ($/Bbl)⁽³⁾
$ 4.75 $ 12.66 $ (7.91) (62) %
Natural gas ($/Mcf)⁽³⁾
$ 0.44 $ 0.49 $ (0.05) (10) %
Average sales price ($/BOE)⁽³⁾
$ 13.99 $ 25.05 $ (11.06) (44) %
Oil, with commodity derivatives ($/Bbl)⁽⁴⁾
$ 53.42 $ 52.36 $ 1.06 2 %
NGL, with commodity derivatives ($/Bbl)⁽⁴⁾
$ 7.24 $ 14.04 $ (6.80) (48) %
Natural gas, with commodity derivatives ($/Mcf)⁽⁴⁾
$ 0.93 $ 1.14 $ (0.21) (18) %
Average sales price, with commodity derivatives ($/BOE)⁽⁴⁾
$ 22.10 $ 25.94 $ (3.84) (15) %

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

~~(2)~~The numbers presented in the six months ended June 30, 2020 and 2019 columns are based on actual amounts and are not calculated using the rounded numbers presented in the table above or the table below.

~~(3)~~Price reflects the average of actual sales prices received when control passes to the purchaser/customer adjusted for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point.

~~(4)~~Price reflects the after-effects of our commodity derivative transactions on our average sales prices. Our calculation of such after-effects includes settlements of matured commodity derivatives during the respective periods in accordance with GAAP and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to commodity derivatives that settled during the respective periods.

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The following ~~tables present~~table presents net settlements (paid) received ~~(paid)~~ for matured commodity derivatives and net premiums paid previously or upon settlement attributable to commodity derivatives that matured during the periods utilized in our calculation of the average sales prices, with commodity derivatives, for the periods presented and the corresponding ~~changes:~~changes for such periods:


		Three months ended June 30,						2020 compared to 2019							Three months ended March 31,				2021 compared to 2020
(in thousands)	(in thousands)	2020		2019		Change ($)		Change (%)		(in thousands)	2021		2020		Change ($)		Change (%)
Settlements received for matured commodity derivatives:
Net settlements (paid) received for matured commodity derivatives:										Net settlements (paid) received for matured commodity derivatives:
Oil	Oil	$	73,739	$	1,481	$	72,258	4,879	%	Oil	$	(18,371)	$	31,147	$	(49,518)	(159)	%
NGL	NGL	7,680		5,998		1,682		28	%	NGL	(15,576)		5,337		(20,913)		(392)	%
Natural gas	Natural gas	5,432		16,001		(10,569)		(66)	%	Natural gas	(7,173)		11,239		(18,412)		(164)	%
Total	Total	$	86,851	$	23,480	$	63,371	270	%	Total	$	(41,120)	$	47,723	$	(88,843)	(186)	%
Premiums paid previously or upon settlement attributable to commodity derivatives that matured during the respective period:
Net premiums paid previously or upon settlement attributable to commodity derivatives that matured during the respective period:										Net premiums paid previously or upon settlement attributable to commodity derivatives that matured during the respective period:
Oil	Oil	$	(400)	$	(4,541)	$	4,141	91	%	Oil	$	(11,005)	$	(877)	$	(10,128)	(1,155)	%

Six months ended June 30, 2020 compared to 2019
(in thousands) 2020 2019 Change ($) Change (%)
Settlements received (paid) for matured commodity derivatives:
Oil $ 104,886 $ (614) $ 105,500 17,182 %
NGL 13,017 5,941 7,076 119 %
Natural gas 16,671 18,255 (1,584) (9) %
Total $ 134,574 $ 23,582 $ 110,992 471 %
Premiums paid previously or upon settlement attributable to commodity derivatives that matured during the respective period:
Oil $ (1,277) $ (10,841) $ 9,564 88 %

Changes in average sales prices and sales volumes caused the following changes to our oil, NGL and natural gas revenues between the three ~~and six~~ months ended ~~June 30, 2020~~March 31, 2021 and ~~2019:~~2020:


(in thousands)	(in thousands)	Oil			NGL			Natural gas			Total			(in thousands)	Oil			NGL			Natural gas			Total
2019 Revenues		$	160,030		$	22,197		$	1,636		$	183,863
First-quarter 2020 revenues														First-quarter 2020 revenues	$	119,978		$	11,558		$	4,349		$	135,885
Effect of changes in average sales prices	Effect of changes in average sales prices	(94,095)			(14,545)			8,879			(99,761)			Effect of changes in average sales prices	29,036			30,807			28,961			88,804
Effect of changes in sales volumes	Effect of changes in sales volumes	4,170			5,576			295			10,041			Effect of changes in sales volumes	(21,313)			(687)			(232)			(22,232)

2020 Revenues		$	70,105		$	13,228		$	10,810		$	94,143
First-quarter 2021 revenues														First-quarter 2021 revenues	$	127,701		$	41,678		$	33,078		$	202,457
Change ($)	Change ($)	$	(89,925)		$	(8,969)		$	9,174		$	(89,720)		Change ($)	$	7,723		$	30,120		$	28,729		$	66,572
Change (%)	Change (%)	(56)		%	(40)		%	561		%	(49)		%	Change (%)	6		%	261		%	661		%	49		%

(in thousands) Oil NGL Natural gas Total
2019 Revenues $ 289,201 $ 54,432 $ 13,606 $ 357,239
Effect of changes in average sales prices (109,655) (41,301) (1,558) (152,514)
Effect of changes in sales volumes 10,537 11,655 3,111 25,303
2020 Revenues $ 190,083 $ 24,786 $ 15,159 $ 230,028
Change ($) $ (99,118) $ (29,646) $ 1,553 $ (127,211)
Change (%) (34) % (54) % 11 % (36) %

~~Beginning in~~In the three months ended March ~~2020,~~31, 2021, we experienced significant ~~decreases~~increases in oil, NGL and natural gas sales prices related to the OPEC+ caused price collapse and COVID-19 caused demand reduction. Oil sales prices have stabilized and recovered to some degree at the end of the second quarter of 2020, compared to the lows at the beginning of the second quarter, but are continuing to exhibit high volatility.

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~~Oil sales revenue.~~ ~~Our oil sales revenue is a function of oil production volumes sold and average oil sales prices received for those volumes. The decrease in oil sales revenue for the three months ended June 30, 2020,~~ compared to the same period in ~~2019 is due to a 57% decrease~~2020. Offsetting such price increases, winter storms during February 2021 disrupted both production activities and drilling and completions operations, impacting total and oil production for first-quarter 2021 by an estimated 5,700 BOE per day and 1,700 barrels of oil per day, respectively. Despite the weather impact, first-quarter 2021 oil production was positively impacted by our first package of wells in average oil sales prices and was partially offset by a 3% increase in oil sales volumes. The decrease in oil sales revenue for the six months ended June 30, 2020, compared to the same period in 2019 is due to a 37% decrease in average oil sales prices and was partially offset by a 4% increase in oil sales volumes.

~~NGL sales revenue.~~ Our NGL sales revenue is a function of NGL production volumes sold and average NGL sales prices received for those volumes. The decrease in NGL sales revenue for the three months ended June 30, 2020, compared to the same period in 2019 is due to a 52% decrease in average NGL sales prices and was partially offset by a 25% increase in NGL sales volumes. The decrease in NGL sales revenue for the six months ended June 30, 2020, compared to the same period in 2019 is due to a 62% decrease in average NGL sales prices and was partially offset by a 21% increase in NGL sales volumes.

~~Natural gas sales revenue.~~ Our natural gas sales revenue is a function of natural gas production volumes sold and average natural gas sales prices received for those volumes. The increase in natural gas sales revenue for the three months ended June 30, 2020, compared to the same period in 2019 is due to a 455% increase in average natural gas sales prices and an 18% increase in natural gas sales volumes. The increase in natural gas sales revenue for the six months ended June 30, 2020, compared to the same period in 2019 is due to a 23% increase in natural gas sales volumes and was partially offset by a 10% decrease in average natural gas sales prices.Howard County.

The following ~~tables present~~table presents midstream service revenues and sales of purchased oil ~~revenues~~ for the periods presented and the corresponding ~~changes:~~changes for such periods:

Three months ended June 30, 2020 compared to 2019
(in thousands) 2020 2019 Change ($) Change (%)
Midstream service revenues $ 2,281 $ 2,610 $ (329) (13) %
Sales of purchased oil $ 14,164 $ 30,170 $ (16,006) (53) %


		Six months ended June 30,						2020 compared to 2019							Three months ended March 31,			2021 compared to 2020
(in thousands)	(in thousands)	2020		2019		Change ($)		Change (%)		(in thousands)	2021		2020			Change ($)		Change (%)
Midstream service revenues	Midstream service revenues	$	4,964	$	5,493	$	(529)	(10)	%	Midstream service revenues	$	1,296	$	2,683		$	(1,387)	(52)	%
Sales of purchased oil	Sales of purchased oil	$	80,588	$	62,858	$	17,730	28	%	Sales of purchased oil	$	46,477	$	66,424		$	(19,947)	(30)	%

Midstream service revenues. Our midstream service revenues decreased for the three ~~and six~~ months ended ~~June 30, 2020~~March 31, 2021 compared to the same ~~periods~~period in ~~2019.~~2020. Midstream service revenues are generated by oil throughput fees and services provided to third parties for (i) integrated oil and natural gas gathering and transportation systems and related facilities, (ii) natural gas lift, fuel for drilling and completions activities and centralized compression infrastructure and (iii) water storage, recycling and transportation infrastructure, and are recognized over time as the customer benefits from these services when provided. These revenues fluctuate and will vary due to oil throughput fees and the level of services provided to third parties.

Sales of purchased oil. Sales of purchased oil ~~revenues~~ are a function of the volumes and prices of purchased oil sold to customers and are offset by the volumes and costs of purchased oil. We are a firm shipper on both the Bridgetex and Gray Oak pipelines ~~the latter of which we began shipment on during fourth-quarter 2019,~~ and we utilize purchased oil to fulfill portions of our commitments. We anticipate continuing this practice in the future. Sales of

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purchased oil decreased during the three months ended March 31, 2021, compared to the same period in 2020 primarily due to decreased shipments of purchased oil on pipelines.

We enter into purchase transactions with third parties and separate sale transactions. These transactions are presented on a gross basis as we act as the principal in 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."

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Costs and expenses

The following ~~tables present~~table presents information regarding costs and expenses and selected average costs and expenses per BOE sold for the periods presented and the corresponding ~~changes:~~changes for such periods:

Three months ended June 30, 2020 compared to 2019
(in thousands except for per BOE sold data) 2020 2019 Change ($) Change (%)
Costs and expenses:
Lease operating expenses $ 20,591 $ 23,632 $ (3,041) (13) %
Production and ad valorem taxes 6,938 11,328 (4,390) (39) %
Transportation and marketing expenses 11,181 4,891 6,290 129 %
Midstream service expenses 815 607 208 34 %
Costs of purchased oil 16,117 30,172 (14,055) (47) %
General and administrative (excluding LTIP) 8,712 12,157 (3,445) (28) %
General and administrative (LTIP):
LTIP cash 463 (192) 655 341 %
LTIP non-cash 1,484 (909) 2,393 263 %
Organizational restructuring expenses 4,200 10,406 (6,206) (60) %
Depletion, depreciation and amortization 66,574 65,703 871 1 %
Impairment expense 406,448 — 406,448 100 %
Other operating expenses 1,117 1,020 97 10 %
Total costs and expenses $ 544,640 $ 158,815 $ 385,825 243 %
Selected average costs and expenses per BOE sold⁽¹⁾:
Lease operating expenses $ 2.40 $ 3.16 $ (0.76) (24) %
Production and ad valorem taxes 0.81 1.51 (0.70) (46) %
Transportation and marketing expenses 1.31 0.65 0.66 102 %
Midstream service expenses 0.10 0.08 0.02 25 %
General and administrative (excluding LTIP) 1.02 1.62 (0.60) (37) %
Total selected operating expenses $ 5.64 $ 7.02 $ (1.38) (20) %
General and administrative (LTIP):
LTIP cash $ 0.05 $ (0.03) $ 0.08 267 %
LTIP non-cash $ 0.17 $ (0.12) $ 0.29 242 %
Depletion, depreciation and amortization $ 7.77 $ 8.78 $ (1.01) (12) %

~~(1)Selected 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.~~

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		Six months ended June 30,						2020 compared to 2019							Three months ended March 31,				2021 compared to 2020
(in thousands except for per BOE sold data)	(in thousands except for per BOE sold data)	2020		2019		Change ($)		Change (%)		(in thousands except for per BOE sold data)	2021		2020		Change ($)		Change (%)
Costs and expenses:	Costs and expenses:									Costs and expenses:
Lease operating expenses	Lease operating expenses	$	42,631	$	46,241	$	(3,610)	(8)	%	Lease operating expenses	$	18,918	$	22,040	$	(3,122)	(14)	%
Production and ad valorem taxes	Production and ad valorem taxes	16,182		18,547		(2,365)		(13)	%	Production and ad valorem taxes	13,283		9,244		4,039		44	%
Transportation and marketing expenses	Transportation and marketing expenses	24,725		9,650		15,075		156	%	Transportation and marketing expenses	12,127		13,544		(1,417)		(10)	%
Midstream service expenses	Midstream service expenses	1,985		2,210		(225)		(10)	%	Midstream service expenses	858		1,170		(312)		(27)	%
Costs of purchased oil	Costs of purchased oil	95,414		62,863		32,551		52	%	Costs of purchased oil	49,916		79,297		(29,381)		(37)	%

General and administrative (excluding LTIP)	General and administrative (excluding LTIP)	19,177		26,549		(7,372)		(28)	%	General and administrative (excluding LTIP)	9,635		10,465		(830)		(8)	%
General and administrative (LTIP):	General and administrative (LTIP):									General and administrative (LTIP):
LTIP cash	LTIP cash	596		—		596		100	%	LTIP cash	1,620		133		1,487		1,118	%
LTIP non-cash	LTIP non-cash	3,448		6,026		(2,578)		(43)	%	LTIP non-cash	1,818		1,964		(146)		(7)	%
Organizational restructuring expenses		4,200		10,406		(6,206)		(60)	%

Depletion, depreciation and amortization	Depletion, depreciation and amortization	127,876		128,801		(925)		(1)	%	Depletion, depreciation and amortization	38,109		61,302		(23,193)		(38)	%
Impairment expense	Impairment expense	593,147		—		593,147		100	%	Impairment expense	—		186,699		(186,699)		(100)	%
Other operating expenses	Other operating expenses	2,223		2,072		151		7	%	Other operating expenses	1,143		1,106		37		3	%
Total costs and expenses	Total costs and expenses	$	931,604	$	313,365	$	618,239	197	%	Total costs and expenses	$	147,427	$	386,964	$	(239,537)	(62)	%
Selected average costs and expenses per BOE sold⁽¹⁾:	Selected average costs and expenses per BOE sold⁽¹⁾:									Selected average costs and expenses per BOE sold(1):
Lease operating expenses	Lease operating expenses	$	2.59	$	3.24	$	(0.65)	(20)	%	Lease operating expenses	$	2.66	$	2.80	$	(0.14)	(5)	%
Production and ad valorem taxes	Production and ad valorem taxes	0.98		1.30		(0.32)		(25)	%	Production and ad valorem taxes	1.87		1.17		0.70		60	%
Transportation and marketing expenses	Transportation and marketing expenses	1.50		0.68		0.82		121	%	Transportation and marketing expenses	1.71		1.72		(0.01)		(1)	%
Midstream service expenses	Midstream service expenses	0.12		0.15		(0.03)		(20)	%	Midstream service expenses	0.12		0.15		(0.03)		(20)	%
General and administrative (excluding LTIP)	General and administrative (excluding LTIP)	1.17		1.86		(0.69)		(37)	%	General and administrative (excluding LTIP)	1.36		1.33		0.03		2	%
Total selected operating expenses	Total selected operating expenses	$	6.36	$	7.23	$	(0.87)	(12)	%	Total selected operating expenses	$	7.72	$	7.17	$	0.55	8	%
General and administrative (LTIP):	General and administrative (LTIP):									General and administrative (LTIP):
LTIP cash	LTIP cash	$	0.04	$	—	$	0.04	100	%	LTIP cash	$	0.23	$	0.02	$	0.21	1,050	%
LTIP non-cash	LTIP non-cash	$	0.21	$	0.42	$	(0.21)	(50)	%	LTIP non-cash	$	0.26	$	0.25	$	0.01	4	%
Depletion, depreciation and amortization	Depletion, depreciation and amortization	$	7.78	$	9.03	$	(1.25)	(14)	%	Depletion, depreciation and amortization	$	5.36	$	7.78	$	(2.42)	(31)	%

(1)Selected 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 ("LOE"). LOE, which includes workover expenses, and LOE per BOE sold both decreased for the three ~~and six~~ months ended ~~June 30, 2020,~~March 31, 2021, compared to the same ~~periods~~period in ~~2019.~~2020. LOE are daily costs incurred to bring oil, NGL and natural gas out of the ground and to market, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and non-routine workover expenses related to our oil and natural gas properties. We continue to focus on economic efficiencies associated with the usage and procurement of products and services related to ~~LOE.~~LOE and decreasing failures and related workover expenses. We expect LOE to increase during 2021 due to higher expected operating costs on the wells coming on-line in Howard County compared to operating costs on our established acreage.

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Production and ad valorem taxes. Production and ad valorem taxes ~~decreased~~increased for the three ~~and six~~ months ended ~~June 30, 2020,~~March 31, 2021, compared to the same ~~periods~~period in ~~2019.~~2020. 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 ~~revenues.~~revenues, and are established by federal, state or local taxing authorities. We take full advantage of all credits and exemptions in our various taxing jurisdictions. Ad valorem taxes are based on and fluctuate in proportion to the taxable value assessed by the various counties where our oil and natural gas properties are located.

Transportation and marketing expenses. Transportation and marketing expenses ~~increased~~decreased for the three ~~and six~~ months ended ~~June 30, 2020,~~March 31, 2021, compared to the same ~~periods~~period in ~~2019. We recognize transportation and marketing expenses~~2020. These are costs incurred for the delivery of produced oil to customers in the U.S. Gulf Coast market via the Bridgetex pipeline and the Gray Oak pipeline. We ~~began shipment on the Gray Oak pipeline during the fourth quarter of 2019. We plan to~~ ship the majority of our produced oil to the U.S. Gulf ~~Coast.~~Coast, which we believe provides a long-term pricing advantage versus the Midland market. Additionally, wefirm transportation payments on excess pipeline capacity associated with transportation agreements are included in transportation and marketing expenses. See Note 12.c to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our transportation commitments. We also recognized $2.0 million in marketing expense due to negative natural gas prices in March 2020.

Midstream service expenses. Midstream service expenses ~~increased~~decreased for the three months ended ~~June 30, 2020 and decreased for the six months ended June 30, 2020,~~March 31, 2021, compared to the same ~~periods~~period in ~~2019. Midstream service expenses~~2020. These are costs incurred to operate and maintain our (i) integrated oil and natural gas gathering and transportation systems and related

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facilities, (ii) centralized oil storage tanks, (iii) natural gas lift, fuel for drilling and ~~completions~~completion activities and centralized compression infrastructure and (iv) water storage, recycling and transportation facilities.

Costs of purchased oil. Costs of purchased oil decreased for the three months ended ~~June 30, 2020,~~March 31, 2021, compared to the same period in ~~2019~~2020 primarily due to ~~a decrease in oil prices, partially offset by increased~~decreased shipments ~~on pipelines. Costs~~ of purchased oil ~~increased for the six months ended June 30, 2020, compared to the same period in 2019 due to increased shipments~~ on ~~pipelines, partially offset by a decrease in oil prices.~~pipelines. We are a firm shipper on both the Bridgetex and Gray Oak pipelines ~~the latter of which we began shipment on during fourth-quarter 2019,~~ and we utilize purchased oil to fulfill portions of our commitments. While our long-haul transportation capacity on the Bridgetex pipeline and Gray Oak pipeline is expected to exceed our net production, consistent with our historic practice, we expect to continue to purchase third-party oil at the trading hubs to satisfy the deficit in our associated long-haul transportation commitments.

General and administrative ("G&A"). G&A, excluding employee compensation expense from our long-term incentive plan ("LTIP"), decreased 8% for the three ~~and six~~ months ended ~~June 30, 2020,~~March 31, 2021, compared to the same ~~periods~~period in ~~2019~~2020, mainly due to ~~decreases~~a decrease in employee-related costs as a result of the ~~cumulative~~ measures taken during second-quarter 2020 ~~and 2019~~ to align our cost structure with operational activity, which included a workforce ~~reductions.~~reduction.

~~Cash~~ LTIP ~~expense increased for the three and six months ended June 30, 2020, compared to the same periods in 2019, as these types of~~ cash ~~awards were not in place in second-quarter 2019. Non-cash~~ expense increased for the three months ended ~~June 30, 2020 and decreased for the six months ended June 30, 2020,~~March 31, 2021, compared to the same ~~periods~~period in ~~2019. Our organizational restructurings resulted~~2020. In 2020, we began utilizing cash awards for the majority of our employee base rather than equity awards. As such, in ~~equity-based compensation~~2021 we expect LTIP cash expense ~~net reversals due~~ to ~~forfeitures during each of~~increase compared to 2020. LTIP non-cash expense decreased slightly for the three months ended ~~June 30,~~March 31, 2021, compared to the same period in 2020. The decrease in LTIP non-cash expense was due to equity award forfeitures related to the second-quarter 2020 workforce reduction, which were still being expensed in first-quarter 2020, and ~~2019. In 2020, we took measures to decrease LTIP award compensation percentages across our remaining employee base.~~was partially offset by a smaller population of 2021 equity awards granted. See Note 8 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for information regarding our equity-based compensation.

~~Organizational restructuring expenses.~~ Organizational restructuring expenses are related to our workforce reductions and retirements in an effort to reduce costs and better position ourselves for the future in response to market conditions. We incurred $4.2 million and $10.4 million of one-time charges during the three and six months ended June 30, 2020 and 2019, respectively, comprised of compensation, taxes, professional fees, outplacement and insurance-related expenses. As of June 30, 2020, no additional organizational restructuring expenses are expected to be incurred. See Note 18 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of the organizational restructurings.

Depletion, depreciation and amortization ("DD&A"). The following ~~tables present~~table presents the components of our DD&A and depletion expense per BOE sold for the periods presented and the corresponding ~~changes:~~changes for such periods:


		Three months ended June 30,						2020 compared to 2019							Three months ended March 31,				2021 compared to 2020
(in thousands)	(in thousands)	2020		2019		Change ($)		Change (%)		(in thousands)	2021		2020		Change ($)		Change (%)
Depletion of evaluated oil and natural gas properties	Depletion of evaluated oil and natural gas properties	$	63,305	$	61,938	$	1,367	2	%	Depletion of evaluated oil and natural gas properties	$	34,725	$	57,752	$	(23,027)	(40)	%
Depreciation of midstream service assets	Depreciation of midstream service assets	2,366		2,543		(177)		(7)	%	Depreciation of midstream service assets	2,422		2,592		(170)		(7)	%
Depreciation and amortization of other fixed assets	Depreciation and amortization of other fixed assets	903		1,222		(319)		(26)	%	Depreciation and amortization of other fixed assets	962		958		4		—	%
Total DD&A	Total DD&A	$	66,574	$	65,703	$	871	1	%	Total DD&A	$	38,109	$	61,302	$	(23,193)	(38)	%
Depletion expense per BOE sold										Depletion expense per BOE sold	$	4.88	$	7.33	$	(2.45)	(33)	%

Six months ended June 30, 2020 compared to 2019
(in thousands) 2020 2019 Change ($) Change (%)
Depletion of evaluated oil and natural gas properties $ 121,057 $ 121,308 $ (251) — %
Depreciation of midstream service assets 4,958 5,044 (86) (2) %
Depreciation and amortization of other fixed assets 1,861 2,449 (588) (24) %
Total DD&A $ 127,876 $ 128,801 $ (925) (1) %

Both DD&A remained consistent for the three and six months ended June 30, 2020 compared to the same periods in 2019. Depletion expense per BOE decreased by $0.88, or 11%, and by $1.15, or 14%, for the three and six months ended June 30, 2020, respectively, compared to the same periods in 2019. We expect depletion expense to decrease as a result of full cost

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~~impairments incurred during 2020. For further discussion of our depletion base~~ and depletion expense per BOE ~~see Note 4 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report and "—Pricing and reserves."~~

~~Impairment expense.~~ ~~The following table presents the components of our impairment expense~~decreased for ~~the periods presented:~~

Three months ended June 30, Six months ended June 30,
(in thousands) 2020 2019 2020 2019
Full cost ceiling impairment expense $ 406,448 $ — $ 583,630 $ —
Midstream service asset impairment expense — — 8,183 —
Line-fill and other inventories impairment expense — — 1,334 —
Total impairment expense $ 406,448 $ — $ 593,147 $ —

Our net book value of evaluated oil and natural gas properties exceeded the full cost ceiling as of March 31, 2020 and June 30, 2020, and, as a result, we recorded full cost ceiling impairments of $177.2 million and $406.4 million during the three months ended March 31, 2021, compared to the same period in 2020 and June 30, 2020, respectively. There was no full cost ceiling impairment recorded for the six months ended June 30, 2019. The full cost ceiling is based principally on the estimated future net revenues from proved oil, NGL and natural gas reserves, which exclude the effectas a result of ~~our commodity derivative transactions, discounted at 10%. The Realized Prices are utilized to calculate the estimated 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 expensed in the period such excess occurs. Onceimpairments incurred a write-down of oil and natural gas properties is not reversible. With the continuing volatility in commodity prices, we may incur additional significant write-downs on our evaluated oil and natural gas properties.during 2020. See Note 45 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report and "—Pricing and reserves" for additional information regarding the full cost method of accounting.

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Impairment expense. The following table presents the components of our impairment expense for the periods presented:


	Three months ended March 31,
(in thousands)	2021		2020
Full cost ceiling impairment expense	$	—	$	177,182
Midstream service asset impairment expense	—		8,183
Line-fill and other inventories impairment expense	—		1,334
Total impairment expense	$	—	$	186,699

The unamortized cost of evaluated oil and natural gas properties did not exceed the full cost ceiling as of March 31, 2021 and, as a result, we did not record a full cost ceiling impairment for such period. As of March 31, 2020, the unamortized cost of evaluated oil and natural gas properties exceeded the full cost ceiling and, as a result, we recorded a non-cash full cost ceiling impairment of $177.2 million for such period. See Note 5 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report and "—Pricing and reserves" for additional discussion of our full cost ceiling calculation.

~~Impairment losses~~Impairments are recorded on 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. All inventory is carried at the lower of cost or ~~net realizable value ("NRV"),~~NRV, with cost determined using the weighted-average cost method. ~~For additional discussion of our long-lived assets and inventories, see~~See Note 10.b to our unaudited consolidated financial statements included elsewhere in this Quarterly ~~Report.~~Report for additional discussion regarding the fair value measurement of our inventory and long-lived assets.

Other operating expenses. These costs include accretion expense due to the passage of time on our asset retirement obligations. See Note 2.k in our 2020 Annual report for additional information regarding our asset retirement obligations.

Non-operating income (expense)

The following ~~tables~~table presents the components of non-operating income (expense), net for the periods presented and the corresponding ~~changes:~~changes for such periods:


		Three months ended June 30,						2020 compared to 2019							Three months ended March 31,				2021 compared to 2020
(in thousands)	(in thousands)	2020		2019		Change ($)		Change (%)		(in thousands)	2021		2020		Change ($)		Change (%)
Gain (loss) on derivatives, net	Gain (loss) on derivatives, net	$	(90,537)	$	88,394	$	(178,931)	(202)	%	Gain (loss) on derivatives, net	$	(154,365)	$	297,836	$	(452,201)	(152)	%
Interest expense	Interest expense	(27,072)		(15,765)		(11,307)		(72)	%	Interest expense	(25,946)		(24,970)		(976)		(4)	%
Litigation settlement		—		42,500		(42,500)		(100)	%

Gain (loss) on disposal of assets, net		152		(670)		822		123	%
Other income (expense), net		(16)		2,846		(2,862)		(101)	%
Write-off of debt issuance costs		(1,103)		—		(1,103)		(100)	%
Loss on extinguishment of debt										Loss on extinguishment of debt	—		(13,320)		13,320		100	%
Loss on disposal of assets, net										Loss on disposal of assets, net	(72)		(602)		530		88	%
Other income, net										Other income, net	1,379		91		1,288		1,415	%

Total non-operating income (expense), net	Total non-operating income (expense), net	$	(118,576)	$	117,305	$	(235,881)	(201)	%	Total non-operating income (expense), net	$	(179,004)	$	259,035	$	(438,039)	(169)	%

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Six months ended June 30, 2020 compared to 2019
(in thousands) 2020 2019 Change ($) Change (%)
Gain on derivatives, net $ 207,299 $ 40,029 $ 167,270 418 %
Interest expense (52,042) (31,312) (20,730) (66) %
Litigation settlement — 42,500 (42,500) (100) %
Loss on extinguishment of debt (13,320) — (13,320) (100) %
Loss on disposal of assets, net (450) (1,609) 1,159 72 %
Other income, net 75 3,713 (3,638) (98) %
Write-off of debt issuance costs (1,103) — (1,103) (100) %
Total non-operating income, net $ 140,459 $ 53,321 $ 87,138 163 %

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


		Three months ended June 30,						2020 compared to 2019							Three months ended March 31,				2021 compared to 2020
(in thousands)	(in thousands)	2020		2019		Change ($)		Change (%)		(in thousands)	2021		2020		Change ($)		Change (%)
Non-cash gain (loss) on derivatives, net	Non-cash gain (loss) on derivatives, net	$	(126,816)	$	72,556	$	(199,372)	(275)	%	Non-cash gain (loss) on derivatives, net	$	(122,232)	$	250,590	$	(372,822)	(149)	%
Settlements received for matured derivatives, net		86,872		23,480		63,392		270	%
Settlements paid for early terminations of commodity derivatives, net		—		(5,409)		5,409		100	%
Premiums paid for commodity derivatives		(50,593)		(2,233)		(48,360)		(2,166)	%
Settlements (paid) received for matured derivatives, net										Settlements (paid) received for matured derivatives, net	(41,174)		47,723		(88,897)		(186)	%

Premiums received (paid) for commodity derivatives										Premiums received (paid) for commodity derivatives	9,041		(477)		9,518		1,995	%
Gain (loss) on derivatives, net	Gain (loss) on derivatives, net	$	(90,537)	$	88,394	$	(178,931)	(202)	%	Gain (loss) on derivatives, net	$	(154,365)	$	297,836	$	(452,201)	(152)	%

Six months ended June 30, 2020 compared to 2019
(in thousands) 2020 2019 Change ($) Change (%)
Non-cash gain on derivatives, net $ 123,774 $ 28,105 $ 95,669 340 %
Settlements received for matured derivatives, net 134,595 23,582 111,013 471 %
Settlements paid for early terminations of commodity derivatives, net — (5,409) 5,409 100 %
Premiums paid for commodity derivatives (51,070) (6,249) (44,821) (717) %
Gain on derivatives, net $ 207,299 $ 40,029 $ 167,270 418 %

Non-cash gain (loss) on derivatives, net is the result of (i) new ~~matured~~ and ~~early-terminated~~matured contracts, including contingent consideration derivatives for the period subsequent to the acquisition date and through the end of the contingency period, 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.~~derivatives and (ii) new and matured interest rate swaps and the changing relationship between the contract interest rate and the LIBOR interest rate forward curve. In general, if outstanding commodity contracts are held constant, we experience gains during periods of decreasing market prices and losses during periods of increasing

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market prices. Settlements ~~received~~paid or ~~paid~~received for matured derivatives are for our commodity derivative contracts, which are based on the settlement prices ~~of our matured derivatives~~ compared to the prices specified in the derivative ~~contracts. During the three~~contracts, and ~~six months ended June 30, 2020, we recognized significant non-cash losses and gains, respectively, in the net fair value of~~for our ~~derivatives outstanding due to increases and decreases, respectively, in the applicable futures curves that we have hedged. We entered into 2021 puts during~~interest rate derivative.

During the three months ended ~~June 30,~~March 31, 2021, we completed a hedge restructuring by (i) selling 2,254,500 calendar year 2021 $55.00 per barrel Brent ICE puts, which volumetrically offset existing calendar year 2021 $55.00 per barrel Brent ICE puts, and receiving aggregate premiums of $9.0 million at inception of the contracts and (ii) entering into 2,254,500 calendar year 2021 Brent ICE swaps at a weighted-average price of $55.09 per barrel. Associated with the aforementioned existing calendar year 2021 $55.00 per barrel Brent ICE puts, which were entered into during 2020, ~~and paid~~are $50.6 million in aggregate premiums ~~to increase~~paid at the ~~put price received.~~inception of the contacts.

See Notes 9 ~~10.a~~ and ~~19.b~~10.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~~remained consistent for the three ~~and six~~ months ended ~~June 30, 2020,~~March 31, 2021, compared to the same ~~periods~~period in 2019. These increases are mainly due to the issuance of our January 2025 Notes and January 2028 Notes and the extinguishment of our January 2022 Notes and March 2023 Notes, resulting in an increase in the carrying amount of long-term debt along with higher fixed interest rates.2020. See Notes 6 and ~~19.a~~18.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding our long-term debt.

Loss on extinguishment of debt. We recognized a loss on extinguishment of debt related to the difference between the consideration for tender offers, early tender premiums and redemption prices and the net carrying amounts of the extinguished January 2022 Notes and March 2023 Notes during the ~~six~~three months ended ~~June 30,~~March 31, 2020. See Note 6.b to our

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unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding the extinguishment of our January 2022 Notes and March 2023 Notes.

~~Gain (loss)~~Loss on disposal of assets, net. ~~Gain (loss)~~Loss on disposal of assets, net, ~~increased~~decreased for the three ~~and six~~ months ended ~~June 30, 2020,~~March 31, 2021 compared to ~~the same periods in 2019.~~2020. 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.

~~Write-off of debt issuance costs.~~ We wrote-off $1.1 million of debt issuance costs during the three and six months ended June 30, 2020 as a result of decreases in the borrowing base and aggregate elected commitment of the Senior Secured Credit Facility. There were no debt issuance costs written off during the comparable periods. See Note 6.d to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our debt issuance costs.

Income tax benefit (expense)

The following ~~tables present~~table presents income tax benefit (expense) for the periods presented and the corresponding ~~changes:~~changes for such periods:


		Three months ended June 30,						2020 compared to 2019							Three months ended March 31,				2021 compared to 2020
(in thousands)	(in thousands)	2020		2019		Change ($)		Change (%)		(in thousands)	2021		2020		Change ($)		Change (%)

Deferred	Deferred	$	7,173	$	(1,751)	$	8,924	510	%	Deferred	$	762	$	(2,417)	$	3,179	132	%

Six months ended June 30, 2020 compared to 2019
(in thousands) 2020 2019 Change ($) Change (%)
Deferred $ 4,756 $ (1,655) $ 6,411 387 %

We are subject to federal and state income taxes and the Texas franchise tax. The deferred income tax benefit (expense) for the periods presented is attributed to deferred Texas franchise tax. As of ~~June 30, 2020,~~March 31, 2021, we determined it was more likely than not that our federal and Oklahoma net deferred tax assets were not realizable through future net income. As of ~~June 30, 2020,~~March 31, 2021, a total valuation allowance of ~~$404.5~~$505.1 million has been recorded to offset our federal and Oklahoma net deferred tax assets, resulting in a Texas net deferred tax asset of ~~$2.3~~$2.2 million. The effective tax rate for our operations was 1%not meaningful for the ~~three~~periods presented and ~~six months ended June 30, 2020.~~we expect it to remain at or under 1%, due to the full valuation allowance against our federal and Oklahoma net deferred tax assets.

Issuances, sales and/or exchanges of our common stock, taken together with prior transactions with respect to our common stock, could trigger an ownership change and therefore a limitation on our ability to utilize our NOL carryforwards which could result in taxable income in future years. For ~~further~~additional discussion of our income taxes, see Note 16 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

Liquidity and capital resources

~~In light of the recent world developments in 2020, we are closely monitoring our capital resources and business plans.~~ 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 asset dispositions. Our primary operational uses of capital have been for the acquisition, exploration and development of oil and natural gas properties and infrastructure development. While we cannot predict the duration and negative impact of

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COVID-19 and OPEC+ actions on the energy industry, we believe our cash flows from operations, favorable hedges 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 and infrastructure development.~~

~~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~~debt and ~~debt~~equity capital resources, joint ventures and asset sales, are available to meet our future planned capital ~~expenditures.~~expenditures, a significant portion of which we are able to adjust and manage. We also continually evaluate opportunities with respect to our capital structure, including issuances of new securities, as well as transactions involving our outstanding senior notes, which could take the form of open market or private repurchases, exchange or tender offers, or other similar transactions, and our common stock, which could take the form of open market or private repurchases. 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 markets transactions and, from time to time, debt and equity repurchases,~~or combination of alternatives, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. We continuously look for other opportunities to maximize shareholder value. For further discussion of our financing activities related to debt instruments, see ~~Note~~Notes 6 and 18.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report. ~~We continuously look for other opportunities to maximize shareholder value.~~

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Due to the inherent volatility in oil, NGL and natural gas prices and differences in the prices of oil, NGL and natural gas between where we produce and ~~where we~~ sell such commodities, we engage in commodity derivative transactions, such as puts, swaps, collars and basis swaps, to hedge price risk associated with a portion of our anticipated sales volumes. Due to the inherent volatility in interest rates, we have entered into an interest rate derivative swap to hedge interest rate risk associated with a portion of our anticipated outstanding debt under the Senior Secured Credit Facility. We will pay a fixed rate over the contract term for that portion. By removing a portion of the (i) price volatility associated with future sales volumes and (ii) interest rate volatility associated with anticipated outstanding debt, we expect to mitigate, but not eliminate, the potential effects of variability in cash flows from operations. See "Part I. Item 3. Quantitative and Qualitative Disclosures About Market Risk" below.

See ~~Notes~~Note 9.a ~~9.b and 19.b~~ to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of our ~~(i)~~ commodity hedge restructuring during the ~~six~~three months ended ~~June 30, 2020~~March 31, 2021 and corresponding summary of open commodity derivative positions as of ~~June 30, 2020~~March 31, 2021 for commodity derivatives that were entered into through June 30, 2020, (ii) interest rate derivative and (iii) summary of open Brent ICE swap positions as of June 30, 2020 updated for derivatives that were entered into through August 5, 2020, respectively.March 31, 2021.

We continually seek to maintain a financial profile that provides operational flexibility. As of ~~June 30, 2020,~~March 31, 2021, we had cash and cash equivalents of ~~$15.7~~$44.3 million and available capacity under the Senior Secured Credit Facility, after the reduction for outstanding letters of credit, of ~~$405.9~~$460.9 million, resulting in total liquidity of ~~$421.6~~$505.2 million. As of ~~August 4, 2020,~~May 3, 2021, we had cash and cash equivalents of ~~$21.0~~$48.4 million and available capacity under the Senior Secured Credit Facility, after the reduction for outstanding letters of credit, of ~~$380.9~~$450.9 million, resulting in total liquidity of ~~$401.9~~$499.3 million. We believe that our operating cash flows and the aforementioned liquidity sources provide us with the financial resources to manage our business needs, to implement our currently planned capital expenditure budget and, at our discretion, to fund any share repurchases, pay down, repurchase or refinance debt or adjust our planned capital expenditure budget.

Cash flows

The following table presents our cash flows for the periods presented and the corresponding ~~changes:~~changes for such periods:


		Six months ended June 30,						2020 compared to 2019							Three months ended March 31,				2021 compared to 2020
(in thousands)	(in thousands)	2020		2019		Change ($)		Change (%)		(in thousands)	2021		2020		Change ($)		Change (%)
Net cash provided by operating activities	Net cash provided by operating activities	$	171,562	$	261,269	$	(89,707)	(34)	%	Net cash provided by operating activities	$	71,151	$	109,589	$	(38,438)	(35)	%
Net cash used in investing activities	Net cash used in investing activities	(268,604)		(292,974)		24,370		8	%	Net cash used in investing activities	(69,020)		(159,791)		90,771		57	%
Net cash provided by financing activities		71,932		42,354		29,578		70	%
Net increase (decrease) in cash and cash equivalents		$	(25,110)	$	10,649	$	(35,759)	(336)	%
Net cash (used in) provided by financing activities										Net cash (used in) provided by financing activities	(6,626)		72,122		(78,748)		(109)	%
Net (decrease) increase in cash and cash equivalents										Net (decrease) increase in cash and cash equivalents	$	(4,495)	$	21,920	$	(26,415)	(121)	%

Cash flows from operating activities

Net cash provided by operating activities decreased during the ~~six~~three months ended ~~June 30, 2020,~~March 31, 2021, compared to the same period in ~~2019.~~2020. Notable cash changes include (i) ~~an increase~~a decrease of ~~$71.6~~$79.4 million due to changes in net settlements ~~received~~ for matured ~~and early terminated~~ derivatives, net of premiums, ~~paid,~~ mainly due to ~~decreases~~increases in commodity prices, (ii) ~~a decrease~~an increase in total oil, NGL and natural gas

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sales revenues of ~~$127.2~~$66.6 million and (iii) a decrease ~~in non-recurring litigation proceeds~~ of ~~$42.5 million and (iv) an increase of $43.8~~$33.0 million due to net changes in operating assets and liabilities. Other ~~contributing factors are increases for~~significant changes include a decrease in costs of purchased oil partially offset by sales of purchased oil and transportation and marketing expenses. The ~~decrease~~increase in total oil, NGL and natural gas sales revenues iswas due to a ~~44% decrease~~65% increase in average sales price per BOE and was partially offset by a ~~15% increase~~10% decrease in total volumes sold. For additional information, see "—Results of ~~operations", "—Costs and expenses" and "—Non-operating income (expense)~~operations.".

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 commodity derivatives' exposure, and sales volume levels. Regional and worldwide economic activity, weather, infrastructure, transportation capacity to reach markets, costs of operations, legislation and regulations, including potential government production curtailments, and other variable factors significantly impact the prices of these commodities. ~~Recently, however, commodity~~Commodity prices have been most impacted by the effects of COVID-19 on demand and the effects of the OPEC+ actions, and earlier in the year, related transportation and storage constraints, particularly in the State of Texas, on supply. These factors are not within our control and are difficult to predict. For additional information on risks related to our business, see "Part I. Item 3. Quantitative and Qualitative Disclosures About Market Risk" and "Part II. Item 1A. Risk Factors" included elsewhere in this Quarterly Report and "Part I. Item 1A. Risk Factors" in our ~~2019~~2020 Annual Report.

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Cash flows from investing activities

Net cash used in investing activities decreased for the ~~six~~three months ended ~~June 30, 2020,~~March 31, 2021, compared to the same period in ~~2019,~~2020, mainly due to a decrease in capital expenditures for oil and natural gas properties ~~partially offset by an increase~~and a decrease in acquisitions of oil and natural gas properties. See Note 3 to our unaudited consolidated financial statements included elsewhere in the Quarterly Report for additional discussion of our acquisitions of oil and natural gas properties.

The following table presents the components of our cash flows from investing activities for the periods presented and the corresponding ~~changes:~~changes for such periods:

Six months ended June 30, 2020 compared to 2019
(in thousands) 2020 2019 Change ($) Change (%)
Acquisitions of oil and natural gas properties, net $ (23,563) $ (2,880) $ (20,683) (718) %
Capital expenditures:
Oil and natural gas properties (241,939) (284,616) 42,677 15 %
Midstream service assets (1,761) (5,449) 3,688 68 %
Other fixed assets (2,069) (965) (1,104) (114) %
Proceeds from dispositions of capital assets, net of selling costs 728 936 (208) (22) %
Net cash used in investing activities $ (268,604) $ (292,974) $ 24,370 8 %

~~Cash flows from financing activities~~

Net cash provided by financing activities increased for the six months ended June 30, 2020, compared to the same period in 2019. Notable cash changes include the issuance of our January 2025 Notes and January 2028 Notes, partially offset by the extinguishment of our January 2022 Notes and March 2023 Notes and payments and borrowings on our Senior Secured Credit Facility. For further discussion of our financing activities related to debt instruments, see Note 6 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.


	Three months ended March 31,				2021 compared to 2020
(in thousands)	2021		2020		Change ($)		Change (%)
Acquisitions of oil and natural gas properties, net	$	—	$	(22,876)	$	22,876	100	%

Capital expenditures:
Oil and natural gas properties	(68,329)		(135,376)		67,047		50	%
Midstream service assets	(329)		(761)		432		57	%
Other fixed assets	(551)		(829)		278		34	%


Proceeds from dispositions of capital assets, net of selling costs	189		51		138		271	%
Net cash used in investing activities	$	(69,020)	$	(159,791)	$	90,771	57	%

The following table presents ~~the components of our cash flows from financing activities for the periods presented and corresponding changes:~~

Six months ended June 30, 2020 compared to 2019
(in thousands) 2020 2019 Change ($) Change (%)
Borrowings on Senior Secured Credit Facility $ — $ 80,000 $ (80,000) (100) %
Payments on Senior Secured Credit Facility (100,000) (35,000) (65,000) (186) %
Issuance of January 2025 Notes and January 2028 Notes 1,000,000 — 1,000,000 100 %
Extinguishment of debt (808,855) — (808,855) (100) %
Stock exchanged for tax withholding (762) (2,646) 1,884 71 %
Payments for debt issuance costs (18,451) — (18,451) (100) %
Net cash provided by financing activities $ 71,932 $ 42,354 $ 29,578 70 %

~~Expected capital expenditures~~

We intend to operate within cash flow in 2020 (excluding non-budgeted acquisitions) and, therefore, our capital spending in 2020 will ultimately be influenced by commodity price changes, production levels and, among other factors, changes in service costs and drilling and completions efficiencies. In early 2020, the Company significantly reduced planned operational activities as commodity prices suffered from historic declines amid COVID-19 related demand destruction and OPEC+ pricing and supply decisions, dramatically reducing expected returns on capital investments. A subsequent increase in commodity prices, paired with service cost reductions, has driven expected returns on our Howard County acreage back to levels that support a resumption of activity and, beginning in September 2020, the Company plans to operate a completions crew in Howard County. We currently expect capital expenditures for 2020 to be approximately $340 million to $350 million.We are prepared to adjust our capital expenditures further if oil, NGL and natural gas prices continue to exhibit volatility. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.

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~~The following tables present~~ the components of our costs incurred, excluding non-budgeted acquisition costs, for the periods presented and the corresponding ~~changes:~~changes for such periods:

Three months ended June 30, 2020 compared to 2019
(in thousands) 2020 2019 Change ($) Change (%)
Oil and natural gas properties $ 75,941 $ 128,780 $ (52,839) (41) %
Midstream service assets 671 3,064 (2,393) (78) %
Other fixed assets 1,774 453 1,321 292 %
Total costs incurred, excluding non-budgeted acquisition costs $ 78,386 $ 132,297 $ (53,911) (41) %


		Six months ended June 30,						2020 compared to 2019							Three months ended March 31,				2021 compared to 2020
(in thousands)	(in thousands)	2020		2019		Change ($)		Change (%)		(in thousands)	2021		2020		Change ($)		Change (%)
Oil and natural gas properties	Oil and natural gas properties	$	228,809	$	289,002	$	(60,193)	(21)	%	Oil and natural gas properties	$	68,449	$	152,868	$	(84,419)	(55)	%
Midstream service assets	Midstream service assets	1,594		6,437		(4,843)		(75)	%	Midstream service assets	876		923		(47)		(5)	%
Other fixed assets	Other fixed assets	2,597		967		1,630		169	%	Other fixed assets	600		823		(223)		(27)	%
Total costs incurred, excluding non-budgeted acquisition costs	Total costs incurred, excluding non-budgeted acquisition costs	$	233,000	$	296,406	$	(63,406)	(21)	%	Total costs incurred, excluding non-budgeted acquisition costs	$	69,925	$	154,614	$	(84,689)	(55)	%

See Note 45 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding our costs incurred in the exploration and development of oil and natural gas properties.

The amount, timing and allocation of capital expenditures are largely discretionary and within management's control. If oil, NGL and natural gas prices are below our acceptable levels, or costs are 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

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flow. Subject to financing alternatives, we may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We continually monitor and may adjust our projected capital expenditures in response to world developments, such as those we ~~are experiencing~~experienced in 2020, as well as 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.

Cash flows from financing activities

Net cash (used in) provided by financing activities decreased for the three months ended March 31, 2021, compared to the same period in 2020. Notable 2021 activity includes proceeds from our ATM Program and net payments on our Senior Secured Credit Facility. Notable 2020 activity includes the issuance of our January 2025 Notes and January 2028 Notes, partially offset by the extinguishment of our January 2022 Notes and March 2023 Notes and payments on our Senior Secured Credit Facility. For further discussion of our financing activities related to debt instruments, see Notes 6 and 18.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

The following table presents the components of our cash flows from financing activities for the periods presented and the corresponding changes for such periods:


	Three months ended March 31,				2021 compared to 2020
(in thousands)	2021		2020		Change ($)		Change (%)
Borrowings on Senior Secured Credit Facility	$	15,000	$	—	$	15,000	100	%
Payments on Senior Secured Credit Facility	(50,000)		(100,000)		50,000		50	%





Issuance of January 2025 Notes and January 2028 Notes	—		1,000,000		(1,000,000)		(100)	%
Extinguishment of debt	—		(808,855)		808,855		100	%
Proceeds from issuance of common stock, net of costs	26,866		—		26,866		100	%
Stock exchanged for tax withholding	(1,290)		(640)		(650)		(102)	%
Payments for debt issuance costs	—		(18,383)		18,383		100	%
Other liabilities	2,798		—		2,798		100	%
Net cash (used in) provided by financing activities	$	(6,626)	$	72,122	$	(78,748)	(109)	%

We are the borrower under our Senior Secured Credit Facility and a party to the indentures governing our Senior Unsecured Notes.

Senior Secured Credit Facility

As of ~~June 30, 2020,~~March 31, 2021, the Senior Secured Credit Facility, which matures on April 19, 2023, had a maximum credit amount of $2.0 billion, a borrowing base and an aggregate elected commitment of $725.0 million each, with ~~$275.0~~$220.0 million outstanding, and was subject to an interest rate of ~~2.19%~~2.625%. The Senior Secured Credit Facility contains both financial and non-financial covenants, all of which we were in compliance with 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 $80.0 million. As of ~~June 30, 2020~~March 31, 2021 and December 31, ~~2019,~~2020, we had one letter of credit outstanding of $44.1 million ~~and $14.7 million, respectively,~~ under the Senior Secured Credit Facility. The Senior Secured Credit Facility is fully and unconditionally guaranteed by LMS and GCM. On ~~July 14, 2020,~~April 6, 2021 and April 26, 2021, we borrowed ~~$45.0~~an additional $20.0 million ~~on the Senior Secured Credit Facility. On July 31, 2020, we~~and made a ~~$20~~$10.0 million payment, respectively, on the Senior Secured Credit Facility. As a result, the outstanding balance under the Senior Secured Credit Facility was ~~$300.0~~$230.0 million as of ~~August 4, 2020.~~May 3, 2021.

~~On August 5, 2020, we received a waiver from the lenders under~~See Notes 6.c and 18.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our Senior Secured Credit Facility of certain representations and warranties relating to our March 31, 2020 quarterly results. Such representations and warranties were incorrect at the time they were given due to our previously disclosed accounting error. Additionally, due to the accounting error we were temporarily not in compliance with our financial reporting covenants. As of the filing of our Restated First Quarter Financials, we regained compliance with the financial reporting covenants under our Senior Secured Credit Facility and the waiver curedFacility.

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the past defaults of our representations and warranties. The Senior Secured Credit Facility contains both financial and non-financial covenants, all of which we were in compliance with for all periods presented.

January 2025 Notes and January 2028 Notes

The following table presents principal amounts and applicable interest rates for our outstanding January 2025 Notes and January 2028 Notes (together the "Senior Unsecured Notes") as of ~~June 30, 2020:~~March 31, 2021:


(in millions, except for interest rates)	(in millions, except for interest rates)	Principal		Interest rate		(in millions, except for interest rates)	Principal		Interest rate
January 2025 Notes	January 2025 Notes	$	600.0	9.500	%	January 2025 Notes	$	577.9	9.500	%
January 2028 Notes	January 2028 Notes	400.0		10.125	%	January 2028 Notes	361.0		10.125	%
Total Senior Unsecured Notes	Total Senior Unsecured Notes	$	1,000.0			Total Senior Unsecured Notes	$	938.9

The net proceeds from the January 2025 Notes and January 2028 Notes were used to fund the tender offers and redemptions of the remaining principle amounts of the January 2022 Notes and March 2023 Notes. See Notes 6.a and 6.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our ~~Senior Unsecured Notes.~~senior unsecured notes.

Supplemental Guarantor information

As discussed in Note 6.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report, on January 24, 2020, we issued $600.0 million in aggregate principal amount of the January 2025 Notes and $400.0 million in aggregate principal amount of the January 2028 Notes. As of ~~June 30, 2020, $1.0 billion~~March 31, 2021, $938.9 million of our Senior Unsecured Notes remained outstanding. Each of our wholly owned subsidiaries, LMS and GCM (each, a "Guarantor," and together, the "Guarantors"), jointly and severally, and fully and unconditionally, guarantees the January 2025 Notes and the January 2028 Notes. We do not have any non-guarantor subsidiaries.

The guarantees are senior unsecured obligations of each Guarantor and rank equally in right of payment with other existing and future senior indebtedness of such Guarantor, and senior in right of payment to all existing and future subordinated indebtedness of such Guarantor. The guarantees of the Senior Unsecured Notes by the Guarantors are subject to certain Releases. The obligations of each Guarantor under its note guarantee are limited as necessary to prevent such note guarantee from constituting a fraudulent conveyance under applicable law. Further, the rights of holders of the Senior Unsecured Notes against the Guarantors may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Laredo is not restricted from making investments in the Guarantors and the Guarantors are not restricted from making intercompany distributions to Laredo or each other.

As we do not have any non-guarantor subsidiaries, the assets, liabilities and results of operations of the combined issuer and Guarantors are not materially different than the corresponding amounts presented in our unaudited consolidated financial statements included elsewhere in this Quarterly Report. Accordingly, we have omitted the summarized financial information of the issuer and the Guarantors that would otherwise be required.

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Obligations and commitments

~~The following table presents~~Our significant contractual obligations and commitments ~~as of June 30, 2020~~include our Senior Unsecured Notes, firm sale and transportation commitments, Senior Secured Credit Facility, asset retirement obligations and lease commitments. Since December 31, ~~2019~~2020, there have been no material changes other than to our debt and ~~their associated changes:~~

($ in thousands, except % change) June 30, 2020 December 31, 2019 Change ($) Change (%)
Senior Unsecured Notes⁽¹⁾
$ 1,606,563 $ 939,844 $ 666,719 71 %
Firm sale and transportation commitments⁽²⁾
306,381 322,790 (16,409) (5) %
Senior Secured Credit Facility⁽³⁾
275,000 375,000 (100,000) (27) %
Asset retirement obligations⁽⁴⁾
65,245 62,718 2,527 4 %
Lease commitments⁽⁵⁾
29,899 35,606 (5,707) (16) %
Commodity derivative deferred premiums⁽⁶⁾
— 477 (477) (100) %
Total $ 2,283,088 $ 1,736,435 $ 546,653 31 %

~~(1)Values presented include both our principal~~firm sale and interest obligations. The increase in such balance as of June 30, 2020 is due to (i) the issuance of our January 2025 Notes and January 2028 Notes, (ii) the extinguishment of our January 2022 Notes and March 2023 Notes and (iii) an increase in our interest rates as a result of such financing transactions.transportation commitments. See Notes ~~6.a~~6 and ~~6.b~~18.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our ~~Senior Unsecured Notes.~~debt.

~~(2)~~We have 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, we are subject to firm transportation payments on excess pipeline capacity and other contractual penalties. ~~The decrease in such~~Future firm sale and transportation commitments of $258.8 million are expected to be satisfied as of ~~June 30, 2020 is~~March 31, 2021 and are not recorded as a liability on the unaudited consolidated balance sheet. These commitments have decreased during the three months ended March 31, 2021, and are mainly due to our fulfillment of contractual commitments, partially offset by changes to existing sales commitments. Of this amount, $77.7 million is related to transportation commitments with a certain pipeline pertaining to the gathering of our production from our established acreage that extends into 2024. We believe we will be able to meet the majority of this commitment, however, as development plans evolve and refine, we may be unable to meet a portion of this commitment. For the three months ended March 31, 2021, we were unable to satisfy a portion of this particular commitment with produced or purchased oil and,as such, expensed firm transportation payments on excess capacity of $1.6 million. See Note 12.c to our

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unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our firm sale and transportation commitments.

~~(3)~~This table does not include future loan advances, repayments, commitment fees or other fees on our Senior Secured Credit Facility as we cannot determine with accuracy the timing of such items. Additionally, this table does not include interest expense as it is a floating rate instrument and we cannot determine with accuracy the future interest rates to be charged. The decrease in such balance as of June 30, 2020 is due to our payments. As of June 30, 2020, the principal on our Senior Secured Credit Facility is due on April 19, 2023. See Note 19.a for our borrowing and payment on our Senior Secured Credit Facility subsequent to June 30, 2020.

~~(4)~~Amounts represent our asset retirement obligation liabilities. See Note 14 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our asset retirement obligations.

~~(5)~~Amounts represent our minimum lease payments. The decrease in lease commitments as of June 30, 2020 is mainly due to settlements paid for our fulfillment of lease commitments, partially offset by a modification to an existing lease commitment. See Note 5 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our leases.

~~(6)~~Amounts represent payments required for deferred premiums on our commodity derivative contracts. The decrease in premiums as of June 30, 2020 is due to premiums paid for commodity derivatives. All deferred premiums have settled as of June 30, 2020. See Note 10.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our deferred premiums.

Non-GAAP financial measures

The non-GAAP financial measures of Free Cash Flow and Adjusted EBITDA, as defined by us, may not be comparable to similarly titled measures used by other companies. Therefore, these non-GAAP financial measures 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 flows from operating activities. Free Cash Flow and 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.

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Free Cash Flow

Free Cash Flow is a non-GAAP financial measure that we define as net cash provided by operating activities (GAAP) before changes in operating assets and liabilities, net, less costs incurred, excluding non-budgeted acquisition costs. Free Cash Flow does not represent funds available for future discretionary use because it excludes funds required for future debt service, capital expenditures, acquisitions, working capital, income taxes, franchise taxes and other commitments and obligations. However, our management believes Free Cash Flow is useful to management and investors in evaluating operating trends in our business that are affected by production, commodity prices, operating costs and other related factors. There are significant limitations to the use of Free Cash Flow as a measure of performance, including the lack of comparability due to the different methods of calculating Free Cash Flow reported by different companies.

The following table presents a reconciliation of net cash provided by operating activities (GAAP) to ~~cash flows from operating activities before changes in operating assets and liabilities, net, less costs incurred, excluding non-budgeted acquisition costs, for the calculation of~~ Free Cash Flow (non-GAAP) for the periods presented:


		Three months ended June 30,						Six months ended June 30,							Three months ended March 31,
(in thousands)	(in thousands)	2020		2019		2020		2019		(in thousands)	2021		2020
Net cash provided by operating activities	Net cash provided by operating activities	$	61,973	$	183,811	$	171,562	$	261,269	Net cash provided by operating activities	$	71,151	$	109,589
Less:	Less:									Less:
Change in current assets and liabilities, net	Change in current assets and liabilities, net	8,750		9,628		27,458		(27,122)		Change in current assets and liabilities, net	(17,259)		18,708
Change in noncurrent assets and liabilities, net	Change in noncurrent assets and liabilities, net	(1,617)		1,913		(7,827)		2,977		Change in noncurrent assets and liabilities, net	(3,275)		(6,210)
Cash flows from operating activities before changes in operating assets and liabilities, net	Cash flows from operating activities before changes in operating assets and liabilities, net	54,840		172,270		151,931		285,414		Cash flows from operating activities before changes in operating assets and liabilities, net	91,685		97,091
Less costs incurred, excluding non-budgeted acquisition costs:	Less costs incurred, excluding non-budgeted acquisition costs:									Less costs incurred, excluding non-budgeted acquisition costs:
Oil and natural gas properties⁽¹⁾	Oil and natural gas properties⁽¹⁾	75,941		128,780		228,809		289,002		Oil and natural gas properties(1)	68,449		152,868
Midstream service assets⁽¹⁾	Midstream service assets⁽¹⁾	671		3,064		1,594		6,437		Midstream service assets(1)	876		923
Other fixed assets	Other fixed assets	1,774		453		2,597		967		Other fixed assets	600		823
Total costs incurred, excluding non-budgeted acquisition costs	Total costs incurred, excluding non-budgeted acquisition costs	78,386		132,297		233,000		296,406		Total costs incurred, excluding non-budgeted acquisition costs	69,925		154,614
Free Cash Flow (non-GAAP)	Free Cash Flow (non-GAAP)	$	(23,546)	$	39,973	$	(81,069)	$	(10,992)	Free Cash Flow (non-GAAP)	$	21,760	$	(57,523)

(1)Includes capitalized share-settled equity-based compensation and asset retirement costs.

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Adjusted EBITDA

Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss (GAAP) plus adjustments for share-settled equity-based compensation, depletion, depreciation and amortization, impairment expense, mark-to-market on derivatives, premiums paid or received for commodity derivatives that matured during the period, accretion expense, gains or losses on disposal of assets, interest expense, income taxes and other non-recurring income and expenses. Adjusted EBITDA provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, working capital movement or tax position. Adjusted EBITDA does not represent funds available for future discretionary use because it excludes funds required for debt service, capital expenditures, 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 that 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.

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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 and the lack of comparability of results of operations to different companies due to 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) for the periods presented:


		Three months ended June 30,						Six months ended June 30,							Three months ended March 31,
(in thousands)	(in thousands)	2020		2019		2020		2019		(in thousands)	2021		2020
Net income (loss)	Net income (loss)	$	(545,455)	$	173,382	$	(470,809)	$	163,891	Net income (loss)	$	(75,439)	$	74,646
Plus:	Plus:									Plus:
Share-settled equity-based compensation, net	Share-settled equity-based compensation, net	1,694		(423)		4,070		6,983		Share-settled equity-based compensation, net	2,068		2,376
Depletion, depreciation and amortization	Depletion, depreciation and amortization	66,574		65,703		127,876		128,801		Depletion, depreciation and amortization	38,109		61,302

Impairment expense	Impairment expense	406,448		—		593,147		—		Impairment expense	—		186,699
Organizational restructuring expenses		4,200		10,406		4,200		10,406

Mark-to-market on derivatives:	Mark-to-market on derivatives:									Mark-to-market on derivatives:
(Gain) loss on derivatives, net	(Gain) loss on derivatives, net	90,537		(88,394)		(207,299)		(40,029)		(Gain) loss on derivatives, net	154,365		(297,836)
Settlements received for matured derivatives, net		86,872		23,480		134,595		23,582
Settlements paid for early terminations of commodity derivatives, net		—		(5,409)		—		(5,409)
Premiums paid for commodity derivatives that matured during the period⁽¹⁾		—		(2,233)		(477)		(6,249)
Settlements (paid) received for matured derivatives, net										Settlements (paid) received for matured derivatives, net	(41,174)		47,723

Net premiums paid for commodity derivatives that matured during the period(1)										Net premiums paid for commodity derivatives that matured during the period(1)	(11,005)		(477)
Accretion expense	Accretion expense	1,117		1,020		2,223		2,072		Accretion expense	1,143		1,106
(Gain) loss on disposal of assets, net		(152)		670		450		1,609
Loss on disposal of assets, net										Loss on disposal of assets, net	72		602
Interest expense	Interest expense	27,072		15,765		52,042		31,312		Interest expense	25,946		24,970
Loss on extinguishment of debt	Loss on extinguishment of debt	—		—		13,320		—		Loss on extinguishment of debt	—		13,320
Litigation settlement		—		(42,500)		—		(42,500)
Write-off of debt issuance costs		1,103		—		1,103		—

Income tax (benefit) expense	Income tax (benefit) expense	(7,173)		1,751		(4,756)		1,655		Income tax (benefit) expense	(762)		2,417

Adjusted EBITDA		$	132,837	$	153,218	$	249,685	$	276,124
Adjusted EBITDA (non-GAAP)										Adjusted EBITDA (non-GAAP)	$	93,323	$	116,848

(1)Reflects net premiums ~~incurred~~paid previously or upon settlement that are attributable to derivatives settled in the respective periods ~~presented and were not a result~~presented.

Table of ~~a hedge restructuring.~~Contents

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.

There have been no material changes in our critical accounting policies and procedures during the ~~six~~three months ended ~~June 30, 2020.~~March 31, 2021. See our critical accounting policies in "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" of the ~~2019~~2020 Annual Report.

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New accounting standards

For discussion of new accounting standards, see Note 2 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

Off-balance sheet arrangements

Currently, we do not have any off-balance sheet arrangements other than our firm sale and transportation commitments, which are described in "—Obligations and commitments" and certain operating leases with a term less than or equal to 12 months. ~~We have made an accounting policy election to not record the short-term operating leases on the unaudited consolidated balance sheets.~~ See Notes 54 and ~~12.c~~12 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information on our leases and commitments and contingencies, respectively.

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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 derivative instruments were entered into for hedging purposes, rather than for speculative trading.

Oil, NGL and natural gas price exposure

The fair values of our open commodity and contingent consideration derivative positions are largely determined by the relevant forward commodity price curves of the indexes associated with our open derivative positions. We had a ~~$192.0~~$156.9 million ~~total asset~~net liability position from the ~~net~~ fair values of our open commodity derivatives and a ~~$0.4~~$1.1 million liability position from the fair value of our potential contingent consideration payments associated with an asset ~~acquisitions,~~acquisition, each as of ~~June 30, 2020.~~March 31, 2021. The following table provides a sensitivity analysis of the projected incremental effect on income (loss) before income taxes of a hypothetical 10% change in the relevant forward commodity price curves of the indexes associated with our open commodity and contingent consideration derivative positions as of ~~June 30, 2020:~~March 31, 2021:


(in thousands)	(in thousands)	10% Increase		10% Decrease		(in thousands)	10% Increase		10% Decrease
Commodity	Commodity	$	(54,051)	$	56,370	Commodity	$	(82,555)	$	82,096
Contingent consideration	Contingent consideration	(105)		90		Contingent consideration	(7)		25
Total	Total	$	(54,156)	$	56,460	Total	$	(82,562)	$	82,121

See Notes 99.a, 9.c, 10.a and ~~10.a~~18.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our commodity and contingent consideration derivatives. See Notes 3.a and 3.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our asset acquisitions associated with the potential contingent consideration payments.

Interest rate risk

Our Senior Secured Credit Facility bears interest at a floating rate and our ~~Notes~~notes bear interest at fixed rates. The maturity years, outstanding balances and interest rates on our long-term debt as of ~~June 30, 2020~~March 31, 2021 were as follows:


		Maturity year																Maturity year
(in millions except for interest rates)	(in millions except for interest rates)	2023			2025			Thereafter			(in millions except for interest rates)	2023			2025			Thereafter

January 2025 Notes	January 2025 Notes	$	—		$	600.0		$	—		January 2025 Notes	$	—		$	577.9		$	—
Fixed interest rate	Fixed interest rate	—		%	9.500		%	—		%	Fixed interest rate	—		%	9.500		%	—		%
January 2028 Notes	January 2028 Notes	$	—		$	—		$	400.0		January 2028 Notes	$	—		$	—		$	361.0
Fixed interest rate	Fixed interest rate	—		%	—		%	10.125		%	Fixed interest rate	—		%	—		%	10.125		%
Senior Secured Credit Facility	Senior Secured Credit Facility	$	275.0		$	—		$	—		Senior Secured Credit Facility	$	220.0		$	—		$	—
Floating interest rate	Floating interest rate	2.188		%	—		%	—		%	Floating interest rate	2.625		%	—		%	—		%

Due to the inherent volatility in interest rates, we have entered into an interest rate derivative swap to hedge interest rate risk associated with a portion of our anticipated outstanding debt under the Senior Secured Credit Facility. We will pay a fixed rate over the contract term for that portion. By removing a portion of the interest rate volatility associated with anticipated outstanding debt, we expect to mitigate, but not eliminate, the potential effects of variability in cash flows from operations.

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The fair value of our open interest rate derivative position is largely determined by the LIBOR interest rate forward curve associated with our open position. We had a ~~$0.4~~$0.2 million total liability position from the net fair value of our open interest rate derivative as of ~~June 30, 2020.~~March 31, 2021. The following table provides a sensitivity analysis of the projected incremental effect on income (loss) before income taxes of a hypothetical 1% incremental addition to or subtraction from the relevant LIBOR forward curve interest rates associated with our open interest rate derivative position as of ~~June 30, 2020:~~March 31, 2021:


(in thousands)	(in thousands)	1% incremental addition to		1% incremental subtraction from		(in thousands)	1% incremental addition to		1% incremental subtraction from
Interest rate	Interest rate	$	1,360	$	(2,090)	Interest rate	$	1,082	$	(1,082)

See Notes 6, 10.c and ~~19.a~~18.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our debt. See Notes 99.b and 10.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our interest rate derivative.

Counterparty and customer credit risk

We use commodity and interest rate derivatives to hedge our exposure to commodity prices and interest rate volatility, respectively. These transactions expose us to potential credit risk from our counterparties. We have entered into International Swaps and Derivatives Association Master Agreements ("ISDA Agreements") with each of our commodity and interest rate derivative counterparties, each of whom is also a lender in our Senior Secured Credit Facility, which, together with hedge agreements with lenders under such facility, is secured by our oil, NGL and natural gas reserves; therefore, we are not required to post any additional collateral. We do not require collateral from our commodity and interest rate derivative counterparties. The terms of the ISDA Agreements provide the non-defaulting or non-affected party the right to terminate the agreement upon the occurrence of certain events of default and termination events by a party and also provide for the marking to market of outstanding positions and the offset of the mark to market amounts owed to and by the parties (and in certain cases, the affiliates of the non-defaulting or non-affected party) upon termination; therefore, the credit risk associated with our commodity and interest rate derivative counterparties is somewhat mitigated. We minimize the credit risk in commodity and interest rate derivatives by: (i) limiting our exposure to any single counterparty, (ii) entering into commodity and interest rate derivatives only with counterparties that meet our minimum credit quality standard or have a guarantee from an affiliate that meets our minimum credit quality standard and (iii) monitoring the creditworthiness of our counterparties on an ongoing basis. ~~We had a~~ ~~$192.0 million~~ ~~and~~ ~~$75.3 milliontotal asset position from the net fair values of our open commodity~~ ~~contracts as of~~ ~~June 30, 2020~~ ~~and December 31, 2019, respectively.~~ ~~See Notes 9, 10.a and 19.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of our commodity and interest rate derivatives.~~

We typically sell production to a relatively limited number of customers, as is customary in the exploration, development and production business. Our sales of purchased oil are generally made to ~~one to two~~a few customers. Our 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 us.

The majority of our accounts receivable are unsecured. On occasion we require our customers to post ~~collateral.~~collateral, and the inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In the current market environment, we believe that we could sell our production to numerous purchasers, so that the loss of any one of our major customers would not have a material adverse effect on our financial condition and results of operations solely by reason of such loss. We routinely assess the recoverability of all material trade and other receivables to determine collectability. As the operator of the majority of our wells, we have the ability to realize some or all of our joint operations account receivables through the netting of revenues. Additionally, m~~Management~~anagement believes that any credit risk imposed by a concentration in the oil and natural gas industry is offset by the creditworthiness of our customer base and industry partners.

In We routinely assess the ~~current market environment, we believe that the inability or failure~~recoverability of ~~any one of our major purchasers~~all material trade and other receivables to ~~meet its obligations to us or its insolvency or liquidation would have an adverse effect on our financial condition and potentially our results of operations.~~determine collectability.

See Notes ~~2.e~~2.d and 14 in the ~~2019~~2020 Annual Report for additional discussion of our accounts receivable and ~~credit risk,~~revenue recognition, respectively. ~~See Note 15 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of revenue recognition.~~

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Customer performance risk

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the inability or failure of any one of our major customers to physically take possession of our oil would have an adverse effect on our financial condition and potentially our results of operations.

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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 ~~officers.~~officer. Based on that evaluation, these officers concluded that Laredo's disclosure controls and procedures were ~~not~~ effective as of ~~June 30, 2020 due~~March 31, 2021. Our disclosure controls and other procedures are designed to provide reasonable assurance that the ~~material weakness~~information required to be disclosed in ~~our internal control over financial reporting described below.~~

~~Notwithstanding~~ the ~~identified material weakness,~~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 officers have determined, based on the procedures we have performed, that the unaudited consolidated financial statements included in this Quarterly Report on Form 10-Q fairly present in all material respects our financial condition and resultsofficer, as appropriate to allow timely decisions regarding required disclosure.

Evaluation of ~~operations for the three and six months ended June 30, 2020 and 2019 in accordance with GAAP.~~

~~Material Weakness in Internal Control over Financial Reporting~~

~~A material weakness (as defined in Rule 12b-2 under the Exchange Act) is a deficiency, or a combination of deficiencies,~~changes in internal control over financial reporting ~~such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.~~

Subsequent to June 30, 2020, we identified deficiencies that represented a material weakness in our internal control over financial reporting as of March 31, 2020 with respect to the design and maintenance of controls over the determination of the estimated present value ("PV-10") of our reserves. Specifically, we did not design and maintain effective controls to sufficiently review the completeness and accuracy of the future production costs component of the estimated PV-10 of our reserves and, thus, failed to identify the omission of the transportation costs from the future costs required to develop certain of our reserves. These deficiencies had the effect of causing an overstatement of approximately $160 million in the estimated PV-10 of our reserves as of March 31, 2020, which caused an understatement in our full cost ceiling impairment expense and related adjustments for the quarter. An amendment was filed to our quarterly report on Form 10-Q for the quarter ended March 31, 2020 to correct the error and restate the financial statements for the first quarter of 2020 included in such report.

~~Remediation Plan~~

As part of our commitment to strengthening our internal control over financial reporting, we are implementing remedial actions under the oversight of the Audit Committee of our board of directors to address these deficiencies, including:

•~~implementation of additional (or enhanced) procedures to verify the completeness and accuracy of data inputs into the reserves application for pricing and operating expenses;~~

•~~implementation of additional (or enhanced) procedures to perform enhanced detailed reviews of reserves report components, including (but not necessarily limited to) pricing and operating expenses; and~~

•revision and communication of the accounting controls, policies and procedures relating to identifying and assessing changes that could potentially impact the system of internal control governing the full cost ceiling test calculation.

We will continue to monitor the design and effectiveness of these and other processes, procedures, policies and controls and make any further changes management determines appropriate. We believe the control improvements described above will remediate the material weakness that management has identified. However, this material weakness will not be considered remediated until the applicable remedial controls operate effectively for a sufficient period of time.

~~Limitations on the Effectiveness of Controls~~

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is designed to provide reasonable assurance as to the reliability of our financial reporting and the preparation of financial statements in accordance with GAAP. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

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~~Changes in Internal Control Over Financial Reporting~~

~~Except for changes we are making in connection with the implementation of the remediation plan described above, there~~There were no changes in our internal control over financial reporting during the ~~three months~~quarter ended ~~June 30, 2020~~March 31, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Part II

Item 1. Legal Proceedings

From time to time, we are subject to various legal proceedings arising in the ordinary course of business, including proceedings for which we may not have insurance coverage. While many of these matters involve inherent uncertainty as of the date hereof, we 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.

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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 ~~2019~~2020 Annual Report. Depending on the duration of the COVID-19 pandemic and its severity and related economic repercussions, the negative impact of many of the related risks discussed in our 2020 Annual Report ~~and Amendment No. 1 to our first-quarter 2020 Quarterly Report. The~~may be heightened or exacerbated. Further, the risks described in 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 and adversely affect our business, financial condition or future results.

~~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 value of our properties.~~

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

Our unamortized cost of evaluated oil and natural gas properties being depleted exceeded the full cost ceiling as of June 30, 2020 and, as such, we recorded a non-cash full cost ceiling impairment of $406.4 million for the three months ended June 30, 2020. We recorded a non-cash full cost ceiling impairment of $177.2 million for the three months ended March 31, 2020 and $620.6 million for the year ended December 31, 2019. No such impairments were recorded during the years ended December 31, 2018 or 2017. If prices remain at or below the current levels, subject to numerous factors and inherent limitations, and all other factors remain constant, we will incur an additional non-cash full cost ceiling impairment in the third quarter of 2020 and Remaining Year 2020, which will have an adverse effect on our statement of operations. See "Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Pricing and reserves—Low commodity price potential impact on our third-quarter 2020 and Remaining Year 2020 full cost ceiling impairment tests" and Note 4 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of our full cost method of accounting.

~~Our business and operations have been and will likely continue to be adversely affected by the recent COVID-19 pandemic and responses.~~

The spread of the COVID-19 coronavirus caused, and is continuing to cause, severe disruptions in the worldwide and U.S. economy, including the global and domestic decreased demand for oil and natural gas, which has had an adverse effect on our business, financial condition and results of operations. Moreover, since the beginning of January 2020, the COVID-19 pandemic has caused significant disruption in the financial markets both globally and in the United States. The continued spread of the COVID-19 coronavirus could also negatively impact the availability of key personnel and adequate staffing for field operations necessary to conduct our business. If the COVID-19 coronavirus continues to spread or the response to contain the COVID-19 pandemic is unsuccessful, we could continue to experience a material adverse effect on our business, financial condition and results of operations.

As a result of multiple factors affecting levels of supply and demand in global oil and gas markets, storage constraints created by excess oil supply in both domestic and international markets and the COVID-19 pandemic have created a risk that our customers will not be able to physically take possession of our oil. In the current market environment, we believe that the inability or failure of any one of our major customers to physically take possession of our oil would have an adverse effect on our financial condition and potentially our results of operations.

Due to the rapid development and fluidity of this situation, we cannot make any prediction as to the ultimate material adverse impact of the COVID-19 pandemic on our business, financial condition and results of operations.

The sharp decline in oil and natural gas prices and continued volatility in the oil and natural gas markets have negatively impacted, and are likely to continue to negatively impact, our exploration and production activities and, as a result, our financial condition and results of operations.

Oil prices have declined sharply since March 2020 as a result of multiple factors affecting levels of supply and demand in global oil and gas markets, including the announcement of price reductions and production increases by OPEC+ as well as pipeline capacity and storage constraints created by excess oil supply in the Permian Basin and the COVID-19 pandemic. Oil and natural gas prices are expected to continue to be volatile as a result of the extent and duration of global production increases, the lack of storage capacity in Texas and the ongoing COVID-19 pandemic and as changes in oil and natural gas inventories, production curtailments, decreased industry demand and negative national and global economic performance are reported, and we cannot predict when prices will improve and stabilize.

Worldwide and U.S. political and economic developments, including the outcome of the U.S. presidential and congressional elections and resulting energy, monetary, trade and environmental policies, and military events, as well as natural disasters and global or national health pandemics, such as COVID-19, including the challenges to the health and safety of our employees, epidemics or concerns and other factors beyond our control contribute to oil and natural gas price levels and volatility and are likely to continue to do so in the future. Current levels in the price of oil, NGL and natural gas, as well as ongoing volatility, have had an adverse impact on the level of our budgeted capital expenditures, drilling and exploration and production activity and may force us to shut-in production of a portion or all of our wells that require significant costs to restart, which could continue to materially and adversely affect us, and we cannot predict the ultimate impact of this situation on our business, financial condition and results of operations.

The duration and extent to which the COVID-19 crisis and oil price volatility adversely affects our business, financial condition and results of operations will depend on future developments, which are highly uncertain and cannot be predicted, including the scope and duration of the pandemic and actions taken by oil producing countries, governmental authorities and other third parties in response. Current levels in the price of oil, NGL and natural gas, as well as ongoing volatility, have also had an adverse impact on both the level at which we are able to hedge our anticipated production and the cost, whether in terms of premiums for puts or foregone upside for collars, of such hedging which could continue to materially and adversely affect us, and we cannot predict the ultimate impact of this situation on, business, financial condition and results of operations.

We have identified a material weakness in our internal control over financial reporting. If we fail to remediate this material weakness or otherwise fail to develop, implement and maintain effective internal controls in future periods, our ability to report our financial condition and results of operations accurately and on a timely basis could be adversely affected.

We have identified a material weakness in our internal controls over the completeness and accuracy of the estimated PV-10 of our reserves. Accordingly, based on our management’s assessment, we concluded that, as of June 30, 2020, our disclosure controls and procedures were not effective. We also determined that this material weakness existed as of March 31, 2020.

A "material weakness" is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. We cannot assure you that we will adequately remediate the material weakness or that additional material weaknesses in our internal controls will not be identified in the future. All internal control systems, no matter how well designed, have inherent limitations. Any failure to maintain or implement required new or improved controls, or any difficulties we encounter in the implementation, could result in additional material weaknesses, or could result in material misstatements in our financial statements. These misstatements could result in restatements of our financial statements, cause us to fail to meet our reporting obligations or cause investors to lose confidence in our reported financial information.

We are in the process of remediating the identified material weakness in our internal control over financial reporting, but we are unable at this time to estimate when the remediation will be completed. If we fail to remediate this material weakness, there will continue to be an increased risk that our future financial statements could contain errors that will be undetected. Further and continued determinations that there are material weaknesses in the effectiveness of our internal controls could reduce our ability to obtain financing or could increase the cost of any financing we obtain and require additional

expenditures of resources to comply with applicable requirements. See “Item 4. Controls and Procedures” included elsewhere in this Quarterly Report for a discussion of the material weakness and our remediation plans.

~~Risk relating to our common stock~~

~~We cannot assure you that there will be a continued increase in our stock price or an increase in our marketability and liquidity following the reverse stock split.~~

Following implementation of the reverse stock split, there was an increase to the market price of our common stock, but there can be no assurance that an increase will continue or a decline will not occur. Some investors may view a reverse stock split negatively. We cannot assure you that our common stock will be more attractive to institutional or other long-term investors or that it will attract brokers and investors who trade in lower-priced stocks. The market price and liquidity of our common stock may decrease due to other factors, including the oil and gas market and our future performance. The percentage market price decline as an absolute number and as a percentage of our overall market capitalization may be greater than would occur in the absence of the reverse stock split. In addition, the reverse stock split increased the number of our stockholders who own "odd lots" of fewer than 100 shares of common stock. Brokerage commission and other costs of transactions in odd lots are generally higher than the costs of transactions of more than 100 shares of common stock. Accordingly, the reverse stock split may not achieve the desired results of a continued increase in our stock price, or an increase in our marketability and liquidity of our common stock, which could materially and adversely affect our business, financial condition and results of operations.

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Item 2. Purchases of Equity Securities

The following table summarizes purchases of common stock by Laredo:

Period
Total number of shares purchased⁽¹⁾
Weighted-average price paid per share Total number of shares purchased as
part of publicly announced plans Maximum value that may yet be purchased under the program as of the respective period-end date
April 1, 2020 - April 30, 2020 — $ — — $ —
May 1, 2020 - May 31, 2020⁽²⁾
174 $ 19.80 — $ —
June 1, 2020 - June 30, 2020 6,700 $ 17.56 — $ —
Total 6,874 —



Period	Total number of shares purchased(1)	Weighted-average price paid per share		Total number of shares purchased as part of publicly announced plans	Maximum value that may yet be purchased under the program as of the respective period-end date
January 1, 2021 - January 31, 2021	197	$	20.33	—	$	—
February 1, 2021 - February 28, 2021	23,073	$	34.35	—	$	—
March 1, 2021 - March 31, 2021	14,394	$	34.24	—	$	—
Total	37,664			—

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

~~(2)~~Shares and per share data reflect the effect of the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 7.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

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Item 3. Defaults Upon Senior Securities

None.

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Item 4. Mine Safety Disclosures

~~Not applicable.~~The operation of our Howard County, Texas sand mine is subject to regulation by the Federal Mine Safety and Health Administration (the "MSHA") under the Federal Mine Safety and Health Act of 1977 (the "Mine Act"). The MSHA may inspect our Howard County mine and may issue citations and orders when it believes a violation has occurred under the Mine Act. While we contract the mining operations of the Howard County mine to an independent contractor, we may be considered an "operator" for purpose of the Mine Act and may be issued notices or citations if MSHA believes that we are responsible for violations.

The information concerning mine safety violations and other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of the Regulation S-K is included in Exhibit 95.1 to this Quarterly Report.

6850

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Item 5. Other Information

Not applicable.

6951

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Item 6. Exhibits

Incorporated by reference (File No. 001-35380, unless otherwise indicated)

Exhibit

Description

Form

Exhibit

Filing Date

Exhibit

Description

Form

Exhibit

Filing Date

3.1

Amended and Restated Certificate of Incorporation of Laredo Petroleum Holdings, Inc.

8-K

3.1

12/22/2011

3.1

Amended and Restated Certificate of Incorporation of Laredo Petroleum Holdings, Inc.

8-K

3.1

12/22/2011

3.2

Certificate of Amendment to the Amended and Restated Certificate of Incorporation of Laredo Petroleum Holdings, Inc.

8-K

3.1

6/1/2020

3.2

Certificate of Amendment to the Amended and Restated Certificate of Incorporation of Laredo Petroleum Holdings, Inc.

8-K

3.1

6/1/2020

3.3

Certificate of Ownership and Merger, dated as of December 30, 2013.

8-K

3.1

1/6/2014

3.3

Certificate of Ownership and Merger, dated as of December 30, 2013.

8-K

3.1

1/6/2014

3.4

Second Amended and Restated Bylaws of Laredo Petroleum, Inc.

10-K

3.3

2/17/2016

3.4

Third Amended and Restated Bylaws of Laredo Petroleum, Inc., effective March 3, 2021.

8-K

3.1

3/4/2021

4.1

Form of Common Stock Certificate.

8-A12B/A

4.1

1/7/2014

4.1

Form of Common Stock Certificate.

8-A12B/A

4.1

1/7/2014

10.1

Fourth Amendment to Fifth Amended and Restated Credit Agreement, dated as of April 30, 2020, 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.

8-K

10.1

5/6/2020

10.1

Form of 2020 Performance Share Unit Award Agreement .

10-K

10.18

2/22/2021

10.2#

Amendment to the Laredo Petroleum, Inc. Omnibus Equity Incentive Plan, as amended and restated as of May 16, 2019.

8-K

10.1

6/1/2020

10.3*#

Offer Letter, dated June 12 , 2020, between Laredo Petroleum, Inc. and Mr. Bryan J. Lemmerman.

10.2

Form of Phantom Unit Agreement .

10-K

10.21

2/22/2021

10.3*

Form of 2021 Performance Share Unit Award Agreement.

22.1

List of Issuers and Guarantor Subsidiaries

10-Q

22.1

5/7/2020

22.1

List of Issuers and Guarantor Subsidiaries .

10-Q

22.1

5/7/2020

31.1*

Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.

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.

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.

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.

95.1*

Mine Safety Disclosures.

101

The following financial information from Laredo’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, formatted in Inline XBRL: (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Stockholders’ Equity, (iv) Consolidated Statements of Cash Flows and (v) Condensed Notes to the Consolidated Financial Statements.

101

The following financial information from Laredo’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2021, formatted in Inline XBRL: (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Stockholders’ Equity, (iv) Consolidated Statements of Cash Flows and (v) Condensed Notes to the Consolidated Financial Statements.

104

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

104

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

* Filed herewith.

** Furnished herewith.

~~# Management contract or compensatory plan or arrangement.~~

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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: ~~August~~May 6, ~~2020~~2021	By:	/s/ Jason Pigott
		Jason Pigott
		President and Chief Executive Officer
		(principal executive officer)

Date: ~~August~~May 6, ~~2020~~2021	By:	/s/ Bryan J. Lemmerman
		Bryan J. Lemmerman
		Senior Vice President and Chief Financial Officer
		(principal financial officer)

Date: ~~August~~May 6, ~~2020~~2021	By:	/s/ Jessica R. Wren
		Jessica R. Wren
		Interim Principal Accounting Officer
		(principal accounting officer)

7153


	Common stock					Additional paid-in capital		Treasury stock (at cost)								Accumulated deficit
	Shares ⁽¹⁾	Amount					Shares ⁽¹⁾			Amount					Total
Balance, December 31, 2019	11,865	$	2,373	$	2,385,355	—		$	—		$	(1,545,854)	$	841,874

Reverse stock split	—	(2,277)		2,277		—		—			—		—
Restricted stock awards⁽²⁾	152	30		(30)		—		—			—		—
Restricted stock forfeitures⁽²⁾	(44)	(2)		2		—		—			—		—


Stock exchanged for tax withholding	—	—		—		34		(762)			—		(762)

Retirement of treasury stock⁽²⁾	(34)	(5)		(757)		(34)		762			—		—

Share-settled equity-based compensation	—	—		5,717		—		—			—		5,717



Net loss	—	—		—		—		—			(470,809)		(470,809)
Balance, June 30, 2020	11,939	$	119	$	2,392,564	—		$	—		$	(2,016,663)	$	376,020

	Common stock					Additional paid-in capital		Treasury stock (at cost)								Accumulated deficit
	Shares ⁽¹⁾	Amount					Shares ⁽¹⁾			Amount					Total
Balance, December 31, 2018	11,697	$	2,339	$	2,375,286	—		$	—		$	(1,203,395)	$	1,174,230

Restricted stock awards	353	71		(71)		—		—			—		—
Restricted stock forfeitures	(141)	(28)		28		—		—			—		—


Stock exchanged for tax withholding	—	—		—		35		(2,646)			—		(2,646)
Stock exchanged for cost of exercise of stock options	—	—		—		1		(76)			—		(76)
Retirement of treasury stock	(36)	(7)		(2,715)		(36)		2,722			—		—
Exercise of stock options	1	—		76		—		—			—		76


Share-settled equity-based compensation	—	—		8,846		—		—			—		8,846
Net income	—	—		—		—		—			163,891		163,891
Balance, June 30, 2019	11,874	$	2,375	$	2,381,450	—		$	—		$	(1,039,504)	$	1,344,321


(in thousands, except for weighted-average grant-date fair value)	Performance share awards⁽¹⁾	Weighted-average grant-date fair value (per share)¹⁾
Outstanding as of December 31, 2019	115	$	107.05

Forfeited	(10)	$	111.75
Lapsed⁽²⁾	(8)	$	379.20
Outstanding as of June 30, 2020	97	$	84.12


	June 3, 2019			February 28, 2019⁽¹⁾			February 16, 2018
Market Criteria:
(1/4) RTSR Factor + (1/4) ATSR Factor:
Grant-date fair value per performance share⁽²⁾	$	49.00		$	79.61		$	201.65

Expense per performance share as of June 30, 2020⁽²⁾	$	49.00		$	79.61		$	201.65
Performance Criteria:
(1/2) ROACE Factor:
Grant-date fair value per performance share⁽²⁾	$	51.80		$	69.80		$	167.20
Estimated payout for expense as of June 30, 2020	175		%	175		%	68		%
Expense per performance share as of June 30, 2020⁽²⁾⁽³⁾	$	90.65		$	122.15		$	113.70
Combined:
Grant-date fair value per performance share⁽²⁾⁽⁴⁾	$	50.40		$	74.71		$	184.43
Expense per performance share as of June 30, 2020⁽²⁾⁽⁵⁾	$	69.83		$	100.88		$	157.68


(in thousands, except for weighted-average fair value)	Phantom units⁽¹⁾	Fair value as of June 30, 2020 (per unit)¹⁾
Outstanding as of December 31, 2019	—	$	—
Granted	75	$	13.86


Outstanding as of June 30, 2020	75	$	13.86


($ in thousands, except % change)	June 30, 2020		December 31, 2019		Change ($)		Change (%)
Senior Unsecured Notes⁽¹⁾	$	1,606,563	$	939,844	$	666,719	71	%
Firm sale and transportation commitments⁽²⁾	306,381		322,790		(16,409)		(5)	%
Senior Secured Credit Facility⁽³⁾	275,000		375,000		(100,000)		(27)	%
Asset retirement obligations⁽⁴⁾	65,245		62,718		2,527		4	%
Lease commitments⁽⁵⁾	29,899		35,606		(5,707)		(16)	%
Commodity derivative deferred premiums⁽⁶⁾	—		477		(477)		(100)	%
Total	$	2,283,088	$	1,736,435	$	546,653	31	%



Period	Total number of shares purchased⁽¹⁾	Weighted-average price paid per share		Total number of shares purchased as part of publicly announced plans	Maximum value that may yet be purchased under the program as of the respective period-end date
April 1, 2020 - April 30, 2020	—	$	—	—	$	—
May 1, 2020 - May 31, 2020⁽²⁾	174	$	19.80	—	$	—
June 1, 2020 - June 30, 2020	6,700	$	17.56	—	$	—
Total	6,874			—