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lpi-20210930

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 September 30, 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 November 1, 2021: 17,070,650

LAREDO PETROLEUM, INC.

TABLE OF CONTENTS


			Page
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS			iii
Part I			1
Item 1. Consolidated Financial Statements (Unaudited)			1
Consolidated balance sheets as of September 30, 2021 and December 31, 2020			1
Consolidated statements of operations for the three and nine months ended September 30, 2021 and 2020			2
Consolidated statements of stockholders' equity continuous quarterly presentation for the three and nine months ended September 30, 2021 and 2020			3
Consolidated statements of cash flows for the nine months ended September 30, 2021 and 2020			5
Condensed notes to the consolidated financial statements:			6
Note 1—Organization and basis of presentation			6
Note 2—New accounting standards			7
Note 3—Acquisitions and divestiture			7
Note 4—Leases			9
Note 5—Property and equipment			10
Note 6—Debt			12
Note 7—Stockholders' equity			15
Note 8—Equity Incentive Plan			16
Note 9—Derivatives			20
Note 10—Fair value measurements			24
Note 11—Net income (loss ) per common share			27
Note 12—Commitments and contingencies			27

Note 13—Supplemental cash flow and non-cash information			29
Note 14—Asset retirement obligations			29
Note 15—Revenue recognition			30
Note 16—Income taxes			30
Note 17—Related parties			30
Note 18—Organizational restructurings			30
Note 19—Subsequent events			31
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations			32
Item 3. Quantitative and Qualitative Disclosures About Market Risk			54
Item 4. Controls and Procedures			56
Part II			57
Item 1. Legal Proceedings			57
Item 1A. Risk Factors			57
Item 2. Purchases of Equity Securities			57
Item 3. Defaults Upon Senior Securities			57
Item 4. Mine Safety Disclosures			57
Item 5. Other Information			57
Item 6. Exhibits			58
SIGNATURES			59

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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 effects, duration, government response or other implications of the coronavirus ("COVID-19") pandemic, or the threat and occurrence of other epidemic or pandemic diseases;

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

•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;

•United States ("U.S.") and international economic conditions and legal, tax, political and administrative developments, including the effects of the recent U.S. presidential, congressional and state elections on energy, trade and environmental policies and existing and future laws and government regulations;

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

•the ongoing instability and uncertainty in the 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 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 successfully integrate acquired businesses, assets and properties;

•our ability to realize the anticipated benefits of the Sabalo/Shad Acquisition and the Pioneer Acquisition (as defined below), including effectively managing our expanded acreage;

•competition in the oil and natural gas industry;

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

•drilling and operating risks, including risks related to hydraulic fracturing activities, and those related to inclement or extreme weather impacting our ability to produce existing wells and/or drill and 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;

iii

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•capital requirements for our operations and projects;

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

•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 gathering, processing, storage and export capacity in the Permian Basin and refining capacity in the U.S. Gulf Coast;

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

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

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

•our ability to secure or generate sufficient electricity to produce our wells without 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" and elsewhere in this Quarterly Report, under "Part I, Item 1A. Risk Factors" and "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in our Annual Report on Form 10-K for the fiscal year ended December 31, 2020 (the "2020 Annual Report"), and in our Current Report on Form 8-K, filed with the Securities and Exchange Commission (the "SEC") on May 11, 2021, and those set forth from time to time in our other filings with 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.

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Part I

Item 1. Consolidated Financial Statements (Unaudited)

Laredo Petroleum, Inc.

Consolidated balance sheets

(in thousands, except share data)

(Unaudited)


	September 30, 2021		December 31, 2020
Assets
Current assets:
Cash and cash equivalents	$	51,396	$	48,757
Accounts receivable, net	122,657		63,976
Derivatives	3,272		7,893

Other current assets	17,222		15,964
Total current assets	194,547		136,590
Property and equipment:
Oil and natural gas properties, full cost method:
Evaluated properties	8,608,464		7,874,932
Unevaluated properties not being depleted	167,219		70,020
Less: accumulated depletion and impairment	(6,948,645)		(6,817,949)
Oil and natural gas properties, net	1,827,038		1,127,003
Midstream service assets, net	107,863		112,697
Other fixed assets, net	32,192		32,011
Property and equipment, net	1,967,093		1,271,711

Derivatives	35,742		—
Operating lease right-of-use assets	15,236		17,973
Other noncurrent assets, net	46,354		16,336
Total assets	$	2,258,972	$	1,442,610
Liabilities and stockholders' equity
Current liabilities:
Accounts payable and accrued liabilities	$	61,341	$	38,279
Accrued capital expenditures	53,655		28,275
Undistributed revenue and royalties	85,265		24,728

Derivatives	288,794		31,826
Operating lease liabilities	11,386		11,721
Other current liabilities	74,370		62,766
Total current liabilities	574,811		197,595
Long-term debt, net	1,349,896		1,179,266
Derivatives	37,453		12,051

Asset retirement obligations	55,680		64,775
Operating lease liabilities	6,064		8,918
Other noncurrent liabilities	11,006		1,448
Total liabilities	2,034,910		1,464,053
Commitments and contingencies
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of September 30, 2021 and December 31, 2020	—		—
Common stock, $0.01 par value, 22,500,000 shares authorized and 16,111,452 and 12,020,164 issued and outstanding as of September 30, 2021 and December 31, 2020, respectively	161		120
Additional paid-in capital	2,715,196		2,398,464
Accumulated deficit	(2,491,295)		(2,420,027)

Total stockholders' equity	224,062		(21,443)
Total liabilities and stockholders' equity	$	2,258,972	$	1,442,610

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 September 30,				Nine months ended September 30,
	2021		2020		2021		2020
Revenues:
Oil sales	$	229,329	$	93,329	$	514,752	$	283,412
NGL sales	47,949		24,935		133,121		49,721
Natural gas sales	33,998		14,198		98,186		29,357
Midstream service revenues	1,739		1,751		4,292		6,715
Sales of purchased oil	66,235		39,334		173,500		119,922
Total revenues	379,250		173,547		923,851		489,127
Costs and expenses:
Lease operating expenses	29,837		19,840		68,526		62,471
Production and ad valorem taxes	17,937		8,753		45,957		24,935
Transportation and marketing expenses	11,660		13,161		34,477		37,886
Midstream service expenses	1,014		1,073		2,572		3,058
Costs of purchased oil	68,805		42,720		183,458		138,134
General and administrative	15,008		11,473		49,182		34,694
Organizational restructuring expenses	—		—		9,800		4,200
Depletion, depreciation and amortization	62,678		47,015		140,763		174,891
Impairment expense	—		196,088		1,613		789,235
Other operating expenses	1,798		1,102		4,099		3,325
Total costs and expenses	208,737		341,225		540,447		1,272,829
Gain on sale of oil and natural gas properties, net	95,223		—		93,482		—
Operating income (loss)	265,736		(167,678)		476,886		(783,702)
Non-operating income (expense):
Gain (loss) on derivatives, net	(96,240)		(45,250)		(467,547)		162,049
Interest expense	(30,406)		(26,828)		(82,222)		(78,870)

Loss on extinguishment of debt	—		—		—		(13,320)
Loss on disposal of assets, net	(22)		(607)		(28)		(1,057)
Write-off of debt issuance costs	—		—		—		(1,103)
Other income, net	441		533		2,236		608
Total non-operating income (expense), net	(126,227)		(72,152)		(547,561)		68,307
Income (loss) before income taxes	139,509		(239,830)		(70,675)		(715,395)
Income tax (expense) benefit:
Current	(1,300)		—		(1,300)		—
Deferred	(1,377)		2,398		707		7,154
Total income tax (expense) benefit	(2,677)		2,398		(593)		7,154
Net income (loss)	$	136,832	$	(237,432)	$	(71,268)	$	(708,241)
Net income (loss) per common share:
Basic	$	8.68	$	(20.32)	$	(5.29)	$	(60.76)
Diluted	$	8.56	$	(20.32)	$	(5.29)	$	(60.76)
Weighted-average common shares outstanding:
Basic	15,756		11,686		13,464		11,657
Diluted	15,993		11,686		13,464		11,657

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

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Laredo Petroleum, Inc.

Consolidated statements of stockholders' equity

(in thousands)

(Unaudited)


debt is	Common stock			Additional paid-in capital		Treasury stock (at cost)			Accumulated deficit
	Shares	Amount				Shares	Amount				Total
Balance, June 30, 2021	13,573	$	136	$	2,473,709	—	$	—	$	(2,628,127)	$	(154,282)


Restricted stock awards	39	—		—		—	—		—		—
Restricted stock forfeitures	(1)	—		—		—	—		—		—


Stock exchanged for tax withholding	—	—		—		9	(848)		—		(848)

Retirement of treasury stock	(9)	—		(848)		(9)	848		—		—
Exercise of stock options	2	—		173		—	—		—		173
Share-settled equity-based compensation	—	—		2,220		—	—		—		2,220

Equity issued for acquisition of oil and natural gas properties	2,507	25		239,942		—	—		—		239,967

Net income	—	—		—		—	—		136,832		136,832
Balance, September 30, 2021	16,111	$	161	$	2,715,196	—	$	—	$	(2,491,295)	$	224,062

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

Restricted stock awards	68	1		(1)		—	—		—		—
Restricted stock forfeitures	(2)	—		—		—	—		—		—


Stock exchanged for tax withholding	—	—		—		1	(12)		—		(12)

Retirement of treasury stock	(1)	—		(12)		(1)	12		—		—



Share-settled equity-based compensation	—	—		2,936		—	—		—		2,936
Net loss	—	—		—		—	—		(237,432)		(237,432)
Balance, September 30, 2020	12,004	$	120	$	2,395,487	—	$	—	$	(2,254,095)	$	141,512

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

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Laredo Petroleum, Inc.

Consolidated statements of stockholders' equity

(in thousands)

(Unaudited)


	Common stock			Additional paid-in capital		Treasury stock (at cost)			Accumulated deficit
	Shares	Amount				Shares	Amount				Total
Balance, December 31, 2020	12,020	$	120	$	2,398,464	—	$	—	$	(2,420,027)	$	(21,443)


Restricted stock awards	233	2		(2)		—	—		—		—
Restricted stock forfeitures	(42)	—		—		—	—		—		—


Stock exchanged for tax withholding	—	—		—		53	(2,589)		—		(2,589)

Retirement of treasury stock	(53)	—		(2,589)		(53)	2,589		—		—
Exercise of stock options	2	—		173		—	—		—		173
Share-settled equity-based compensation	—	—		6,730		—	—		—		6,730
Issuance of common stock, net of costs	1,438	14		72,478		—	—		—		72,492
Equity issued for acquisition of oil and natural gas properties	2,507	25		239,942		—	—		—		239,967
Performance share conversion	6	—		—		—	—		—		—
Net loss	—	—		—		—	—		(71,268)		(71,268)
Balance, September 30, 2021	16,111	$	161	$	2,715,196	—	$	—	$	(2,491,295)	$	224,062

	Common stock			Additional paid-in capital		Treasury stock (at cost)			Accumulated deficit
	Shares	Amount				Shares	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	220	31		(31)		—	—		—		—
Restricted stock forfeitures	(46)	(2)		2		—	—		—		—


Stock exchanged for tax withholding	—	—		—		35	(774)		—		(774)

Retirement of treasury stock	(35)	(5)		(769)		(35)	774		—		—



Share-settled equity-based compensation	—	—		8,653		—	—		—		8,653
Net loss	—	—		—		—	—		(708,241)		(708,241)
Balance, September 30, 2020	12,004	$	120	$	2,395,487	—	$	—	$	(2,254,095)	$	141,512

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

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Laredo Petroleum, Inc.

Consolidated statements of cash flows

(in thousands)

(Unaudited)


	Nine months ended September 30,
	2021		2020
Cash flows from operating activities:
Net loss	$	(71,268)	$	(708,241)
Adjustments to reconcile net loss to net cash provided by operating activities:
Share-settled equity-based compensation, net	5,609		6,111
Depletion, depreciation and amortization	140,763		174,891
Impairment expense	1,613		789,235
Gain on sale of oil and natural gas properties, net	(93,482)		—
Mark-to-market on derivatives:
(Gain) loss on derivatives, net	467,547		(162,049)
Settlements (paid) received for matured derivatives, net	(191,507)		186,435
Settlements received for early-terminated commodity derivatives, net	—		6,340

Premiums received (paid) for commodity derivatives	9,041		(51,070)
Amortization of debt issuance costs	3,608		3,304



Amortization of operating lease right-of-use assets	9,907		10,133
Loss on extinguishment of debt	—		13,320
Deferred income tax benefit	(707)		(7,154)
Other, net	3,387		4,519
Changes in operating assets and liabilities:
Accounts receivable, net	(58,681)		24,925
Other current assets	(3,026)		4,451
Other noncurrent assets, net	(30,285)		(3,619)
Accounts payable and accrued liabilities	21,342		5,569
Undistributed revenue and royalties	56,268		(7,631)
Other current liabilities	11,203		(8,216)
Other noncurrent liabilities	5,780		(7,633)
Net cash provided by operating activities	287,112		273,620
Cash flows from investing activities:
Acquisitions of oil and natural gas properties, net	(627,044)		(23,563)
Capital expenditures:

Oil and natural gas properties	(278,847)		(278,277)
Midstream service assets	(2,375)		(2,517)
Other fixed assets	(3,226)		(3,024)
Proceeds from dispositions of capital assets, net of selling costs	393,742		1,242
Net cash used in investing activities	(517,750)		(306,139)
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility	425,000		45,000
Payments on Senior Secured Credit Facility	(650,000)		(185,000)
Issuance of January 2025 Notes and January 2028 Notes	—		1,000,000
Issuance of July 2029 Notes	400,000		—
Extinguishment of debt	—		(808,855)
Proceeds from issuance of common stock, net of costs	72,492		—

Stock exchanged for tax withholding	(2,589)		(774)
Proceeds from exercise of stock options	173		—
Payments for debt issuance costs	(14,597)		(18,451)
Other liabilities	2,798		—
Net cash provided by financing activities	233,277		31,920
Net increase (decrease) in cash and cash equivalents	2,639		(599)
Cash and cash equivalents, beginning of period	48,757		40,857
Cash and cash equivalents, end of period	$	51,396	$	40,258

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 one 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, 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 September 30, 2021, results of operations for the three and nine months ended September 30, 2021 and 2020 and cash flows for the nine months ended September 30, 2021 and 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 2020 Annual Report.

Reclassifications

Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. In connection with the Working Interest Sale (as defined below), the $1.7 million "Transaction expenses" line item, which was recorded during the three months ended June 30, 2021, has been reclassified to be presented net with the "Gain on sale of oil and natural gas properties, net" line item on the unaudited consolidated statements of operations for the nine months ended September 30, 2021. This resulted in a $1.7 million reclassification between operating cash flows and investing cash flows on the unaudited consolidated statements of cash flows during the nine months ended September 30, 2021. There was no impact on previously reported total assets, total liabilities, net income (loss) or stockholders' equity for the periods presented.

Significant accounting policies

See Note 2 in the 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 as of 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.

See Note 2.b in the 2020 Annual Report for further information regarding the use of estimates and assumptions.


Table of Contents			Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note 2—New accounting standards

The Company 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 September 30, 2021.

Note 3—Acquisitions and divestitures

a. 2021 Acquisitions and divestiture

Pioneer Acquisition

On September 17, 2021, the Company entered into a purchase and sale agreement (the "Pioneer PSA") with Pioneer Natural Resources USA, Inc ("PXD"), DE Midland III, LLC ("DEM"), Parsley Minerals, LLC ("PM") and Parsley Energy, L.P. ("PE" and collectively with PXD, DEM, and PM, "Seller") pursuant to which the Company agreed to purchase (the "Pioneer Acquisition"), effective as of July 1, 2021, certain oil and gas properties in the Midland Basin, including approximately 20,000 net acres located in western Glasscock County, Texas, as well as related assets and contracts, for an aggregate purchase price of $160.0 million of cash, subject to customary closing price adjustments, and 959,691 shares of the Company's common stock, par value $0.01 per share. Under the terms of the Pioneer PSA, the Company paid a cash deposit to the Seller in an amount equal to $20.5 million, which is included in "Other noncurrent assets, net" on the unaudited consolidated balance sheets as of September 30, 2021.

The Company expects to finalize its allocation of the purchase consideration as soon as practicable after completion of the Pioneer Acquisition.

For income tax purposes, the Pioneer Acquisition will be treated as an asset purchase such that the tax basis in the assets and liabilities will generally reflect the allocated fair value at closing. Therefore, the Company does not anticipate a material tax consequence for deferred income taxes related to the Pioneer Acquisition.

Subsequent to September 30, 2021, the Company completed the Pioneer Acquisition. See Note 19.a for additional discussion.

Sabalo/Shad Acquisition

On May 7, 2021, the Company entered into two separate purchase and sale agreements, one (the "Sabalo PSA") with Sabalo Energy, LLC and its subsidiary, Sabalo Operating, LLC (collectively, "Sabalo"), and the other (the "Shad PSA" and together with the Sabalo PSA, the "Sabalo/Shad PSAs") with Shad Permian, LLC ("Shad") to acquire certain Midland Basin oil and gas properties, including approximately 21,000 net acres and approximately 120 gross (109 net) operated locations and approximately 150 gross (18 net) non-operated locations, located in Howard and Borden Counties, Texas, (collectively, the "Sabalo/Shad Acquisition"). Shad and Sabalo are unaffiliated, but owned interest in the same assets.

On July 1, 2021 ("Sabalo/Shad Closing Date") the Company closed the Sabalo/Shad Acquisition, effective April 1, 2021, for an aggregate purchase price of $862.9 million, comprised of (i) $606.1 million in cash (ii) 2,506,964 shares of the Company's common stock, par value $0.01 per share, based upon the share price as of the Sabalo/Shad Closing Date, and (iii) $16.8 million in transaction related expenses, inclusive of customary closing adjustments, subject to post-closing adjustments.

The Sabalo/Shad Acquisition was accounted for as a single transaction because the Sabalo PSA and Shad PSA were entered into at the same time and in contemplation of one another to form a single transaction designed to achieve an overall economic effect. The Company determined that the Sabalo/Shad Acquisition was an asset acquisition, as substantially all of the gross assets acquired are concentrated in a group of similar identifiable assets. Accordingly, the consideration paid was allocated to the individual assets acquired and liabilities assumed based on their relative fair values and all transaction costs associated were capitalized.


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The following table presents components of the purchase price, inclusive of customary closing adjustments:


(in thousands, except for share and share price data)	July 1, 2021
Shares of Company common stock	2,506,964
Company common stock price at the Sabalo/Shad Closing Date	$	95.72
Value of Company common stock consideration	$	239,967

Cash consideration	$	606,126
Transaction costs	$	16,847
Total purchase price	$	862,940

The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on the Sabalo/Shad Closing Date:


(in thousands)	July 1, 2021
Evaluated properties	$	502,916
Unevaluated properties	$	364,293
Revenue suspense liabilities assumed	(4,269)
Allocated purchase price	$	862,940

The Company funded the Sabalo/Shad Acquisition aggregate purchase price and related transaction costs with proceeds from borrowings under its Senior Secured Credit Facility and the Working Interest Sale described below.

Working Interest Sale

On May 7, 2021, the Company entered into a purchase and sale agreement (the "Sixth Street PSA") with Piper Investments Holdings, LLC, an affiliate of Sixth Street Partners, LLC ("Sixth Street") to sell 37.5% of the Company's working interest in certain producing wellbores and the related properties primarily located within Glasscock and Reagan Counties, Texas, subject to certain excluded assets and title diligence procedures (the "Working Interest Sale").

On July 1, 2021 (the "Sixth Street Closing Date") the Company closed the Working Interest Sale for cash proceeds of $405.0 million. In addition to such proceeds, the Sixth Street PSA also provided the Company with the right to receive up to a maximum of $93.7 million in additional cash consideration if certain cash flow targets related to divested oil and natural gas property operations are met ("Sixth Street Contingent Consideration"). The Sixth Street Contingent Consideration is made up of quarterly payments through June 2027 totaling up to $38.7 million and a potential balloon payment of $55.0 million in June 2027. On the Sixth Street Closing Date, the fair value of the Sixth Street Contingent Consideration was determined to be $33.8 million. The Sixth Street Contingent Consideration is accounted for as a contingent consideration derivative, with all gains and losses as a result of changes in the fair value of the contingent consideration derivative recognized in earnings in the period in which the changes occur. See Notes 9.c and 10.a for further discussion of the Sixth Street Contingent Consideration.

Subsequent to the Sixth Street Closing Date, the Company continues to own and operate its remaining working interest in the properties sold to Sixth Street; however, the results of operations and cash flows related to the 37.5% working interests sold were eliminated from the Company's financial statements. This divestiture did not represent a strategic shift and will not have a major effect on the Company's future operations or financial results.

Pursuant to the rules governing full cost accounting, the Company recorded a gain on the Working Interest Sale of $93.5 million, net of transaction expenses of $11.6 million on the Company's consolidated statements of operations, subject to post-closing adjustments, as this divestment represented more than 25% of the Company's June 30, 2021 proved reserves. For the purposes of calculating the gain, total capitalized costs were allocated between reserves sold and reserves retained as of the Sixth Street Closing Date.

Leasehold acquisitions

During the three months ended September 30, 2021, the Company acquired certain oil and natural gas leasehold interests in Howard County, Texas, totaling approximately 455 net acres for an aggregate purchase price of $4.0 million.


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b. 2020 Asset acquisitions

On October 16, 2020 and November 16, 2020, the Company 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 customary post-closing purchase price adjustments.

On April 30, 2020, the Company closed an acquisition of 180 net acres in Howard County, Texas for $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 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 Notes 9.c and 10.a for additional discussion of this contingent 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 were capitalized and are included in "Oil and natural gas properties" on the consolidated balance sheet.

c. 2020 Divestiture

On April 9, 2020, the Company closed a divestiture of 80 net acres and working interests in two producing wells in Glasscock County, Texas for $0.7 million, net of customary post-closing 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 did not represent a strategic shift and has not had a major effect on the Company's future operations or financial results.

d. 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 or 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 September 30, 2021, the Company had an average working interest of 97% in wells associated with Laredo's active drilling program over the next 12 months. See Note 5 in the 2020 Annual Report for additional discussion of the Company's leases.


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Note 5—Property and equipment

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


(in thousands)	September 30, 2021		December 31, 2020
Evaluated oil and natural gas properties	$	8,608,464	$	7,874,932
Less accumulated depletion and impairment	(6,948,645)		(6,817,949)
Evaluated oil and natural gas properties, net	1,659,819		1,056,983

Unevaluated oil and natural gas properties not being depleted	167,219		70,020

Midstream service assets	183,645		181,718
Less accumulated depreciation and impairment	(75,782)		(69,021)
Midstream service assets, net	107,863		112,697

Depreciable other fixed assets	39,851		37,454
Less accumulated depreciation and amortization	(26,560)		(24,344)
Depreciable other fixed assets, net	13,291		13,110

Land	18,901		18,901

Total property and equipment, net	$	1,967,093	$	1,271,711

See Note 10.b for discussion of impairments of inventory during the nine months ended September 30, 2021. See Note 6 in the 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 incurred capital expenditures 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. See Note 3.a for discussion of the Company's sale of oil and natural gas properties and the resulting gain recognized during the three months ended September 30, 2021.


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The following table presents incurred capital expenditures 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 September 30,				Nine months ended September 30,
(in thousands)	2021		2020		2021		2020
Property acquisition costs:
Evaluated	$	745,240	$	—	$	745,240	$	7,586
Unevaluated	127,505		—		127,505		16,468
Exploration costs	8,143		3,479		27,413		13,563
Development costs	127,031		37,649		279,032		256,374
Total oil and natural gas properties incurred capital expenditures	$	1,007,919	$	41,128	$	1,179,190	$	293,991

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

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


	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2021		2020		2021		2020
Capitalized employee-related costs	$	4,614	$	4,976	$	13,703	$	13,573

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 September 30,				Nine months ended September 30,
(in thousands except per BOE data)	2021		2020		2021		2020
Depletion expense of evaluated oil and natural gas properties	$	59,250	$	43,648	$	130,625	$	164,705
Depletion expense per BOE sold	$	8.40	$	5.40	$	5.94	$	6.72

The full cost ceiling is based principally on the estimated future net cash flows from proved oil, NGL and natural gas reserves, which exclude the effect of the Company's commodity derivative transactions, discounted at 10%. 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 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 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 September 30, 2021 and, as such, the Company did not record a third-quarter full cost ceiling impairment.


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


	September 30, 2021		June 30, 2021		March 31, 2021		December 31, 2020
Benchmark Prices:
Oil ($/Bbl)	$	54.17	$	46.26	$	36.49	$	36.04
NGL ($/Bbl)(1)	$	28.57	$	23.69	$	19.24	$	16.63
Natural gas ($/MMBtu)	$	2.68	$	2.06	$	1.69	$	1.21
Realized Prices:
Oil ($/Bbl)	$	54.86	$	47.31	$	38.28	$	37.69
NGL ($/Bbl)	$	18.50	$	14.01	$	9.92	$	7.43
Natural gas ($/Mcf)	$	2.03	$	1.51	$	1.20	$	0.79

_____________________________________________________________________________

(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 September 30,				Nine months ended September 30,
(in thousands)	2021		2020		2021		2020
Full cost ceiling impairment expense	$	—	$	196,088	$	—	$	779,718

Note 6—Debt

a. July 2029 Notes

On July 16, 2021, the Company completed a private offering and sale of $400.0 million in aggregate principal amount of 7 3/4% senior unsecured notes due 2029 (the "July 2029 Notes"). Interest for the July 2029 Notes is payable semi-annually, in cash in arrears on January 31 and July 31 of each year, commencing January 31, 2022 with interest from closing to that date. The terms of the July 2029 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 July 2029 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain automatic customary releases, including the sale, disposition or transfer of all of the capital stock or of all or substantially all of the assets of a subsidiary guarantor to one or more persons that are not the Company or a restricted subsidiary, exercise of legal defeasance or covenant defeasance options or satisfaction and discharge of the applicable indenture, designation of a subsidiary guarantor as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the applicable indenture, release from guarantee under the Senior Secured Credit Facility, or liquidation or dissolution (collectively, the "Releases").

The Company received net proceeds of approximately $392.0 million from the July 2029 Notes, after deducting underwriting discounts and commissions and estimated offering expenses. The proceeds from the offering were used for general corporate purposes, including repaying a portion of the borrowings outstanding under the Senior Secured Credit Facility.

b. 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


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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.

The Company received net proceeds of $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 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 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.

c. 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 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.

d. Senior Secured Credit Facility

On May 7, 2021, the Company entered into the Sixth Amendment (the “Sixth Amendment”) to the Fifth Amended and Restated Credit Agreement, among the Company, as borrower, Wells Fargo Bank, N.A., as administrative agent, LMS and GCM, as guarantors, and the banks signatory thereto (as amended, the "Senior Secured Credit Facility"). The Sixth Amendment, among other things, reaffirmed the Senior Secured Credit Facility borrowing base at $725.0 million and amended the Senior Secured Credit Facility to permit (i) the Sabalo/Shad Acquisition and the other transactions contemplated by the Sabalo/Shad PSAs and (ii) the Working Interest Sale and the other transactions contemplated by the Sixth Street PSA, in each case, subject to the terms of the Sixth Amendment and the Senior Secured Credit Facility.

On July 16, 2021, the Company entered into the Seventh Amendment (the "Seventh Amendment") to the Senior Secured Credit Facility. The Seventh Amendment, among other things, included technical amendments (including in connection with


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Eurodollar advances), extended the maturity date by two years to July 16, 2025 (subject to a springing maturity date of July 29, 2024 if any of the January 2025 Notes are outstanding on such date), increased the applicable margins for advances made thereunder, increased certain commitment and letter of credit fees, revised certain exceptions to the limitations on the payment of distributions and the repayment of unsecured debt and decreased the leverage ratio for quarterly periods ending on and after September 30, 2021.

See Note 19.b for discussion of (i) additional borrowings on and (ii) an increase in the borrowing base of the Senior Secured Credit Facility subsequent to September 30, 2021.

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

e. Debt issuance costs

The Company capitalized $13.1 million and $14.6 million in debt issuance costs during the three and nine months ended September 30, 2021, respectively, in connection with entering into the Sixth Amendment and Seventh Amendment to the Senior Secured Credit Facility and the issuance of the July 2029 Notes. The Company capitalized debt issuance costs of $18.4 million during the nine months ended September 30, 2020 in connection with the issuance of the January 2025 Notes and January 2028 Notes. The Company wrote off debt issuance costs during the nine months ended September 30, 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. No debt issuance costs were written off during the nine months ended September 30, 2021.

The Company had total debt issuance costs of $27.7 million and $17.0 million, net of accumulated amortization of $25.7 million and $22.1 million, as of September 30, 2021 and December 31, 2020, respectively. Debt issuance costs related to the Company's January 2025 Notes, January 2028 Notes and July 2029 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" 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 6.f for additional discussion of debt issuance costs.


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f. 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:


	September 30, 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	$	(6,874)	$	571,039	$	577,913	$	(8,676)	$	569,237
January 2028 Notes	361,044		(5,233)		355,811		361,044		(6,015)		355,029
July 2029 Notes	400,000		(6,954)		393,046		—		—		—
Senior Secured Credit Facility(1)	30,000		—		30,000		255,000		—		255,000
Long-term debt, net	$	1,368,957	$	(19,061)	$	1,349,896	$	1,193,957	$	(14,691)	$	1,179,266

______________________________________________________________________________

(1)Debt issuance costs, net related to the Senior Secured Credit Facility of $8.6 million and $2.3 million as of September 30, 2021 and December 31, 2020, respectively, are included in "Other noncurrent assets, net" on the unaudited consolidated balance 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 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 September 30, 2021, the Company has sold 1,438,105 shares of its common stock pursuant to the ATM Program for net proceeds of approximately $72.5 million, after underwriting commissions and other related expenses, thus completing the ATM Program. Proceeds from the share sales were utilized to reduce borrowings on the Senior Secured Credit Facility.

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 Certificate of Incorporation, 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.

On June 1, 2020, the amendment to the 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


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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 Equity Incentive Plan (defined below), that proportionately reduced the number of shares that may be granted.

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 (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.b for additional discussion of the reverse stock split and Authorized Share Reduction. On May 20, 2021, the Company's stockholders approved an amendment to the Equity Incentive Plan to, among other things, increase the maximum number of shares of the Company's common stock issuable under the Equity Incentive Plan from 1,492,500 to 2,432,500 shares.

See Note 9.a in the 2020 Annual Report for additional discussion of the Company's equity-based compensation awards.

a. Restricted stock awards

Restricted stock awards granted to employees vest on a 33%, 33% and 34% schedule per year beginning on the first anniversary of the grant date and 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 nine months ended September 30, 2021:


(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, 2020	309	$	44.88
Granted	233	$	38.38
Forfeited	(42)	$	42.06
Vested(1)	(149)	$	57.11
Outstanding as of September 30, 2021	351	$	35.66

_____________________________________________________________________________

(1)The aggregate intrinsic value of vested restricted stock awards for the nine months ended September 30, 2021 was $7.0 million.

The Company utilizes the closing stock price on the grant date to determine the fair value of restricted stock awards. As of September 30, 2021, unrecognized equity-based compensation related to the restricted stock awards expected to vest was $9.1 million. Such cost is expected to be recognized over a weighted-average period of 2.04 years.


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b. Stock option awards

The following table reflects the stock option award activity for the nine months ended September 30, 2021:


(in thousands, except for weighted-average exercise price and weighted-average remaining contractual term)	Stock option awards	Weighted-average exercise price (per share)		Weighted-average remaining contractual term (years)
Outstanding as of December 31, 2020	11	$	257.42	4.00
Exercised	(2)	$	82.00
Expired or canceled	(2)	$	374.77
Outstanding and exercisable as of September 30, 2021	7	$	275.88	3.49

The intrinsic value of the vested and exercisable stock option awards as of September 30, 2021 was zero.

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, 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 requisite service period of the awards. For portions of awards with performance criteria, 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 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 nine months ended September 30, 2021:


(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

Forfeited	(10)	$	74.70
Vested(1)	(15)	$	184.43
Outstanding as of September 30, 2021	72	$	64.78

______________________________________________________________________________

(1)The performance share awards granted on February 16, 2018 had a performance period of January 1, 2018 to December 31, 2020 and, as their market and performance criteria were partially satisfied, resulted in a 43% payout. As such, the granted awards vested and were converted into 6,343 shares of the Company's common stock during the nine months ended September 30, 2021 based on this 43% payout.

As of September 30, 2021, unrecognized equity-based compensation related to the performance share awards expected to vest was $0.8 million. Such cost is expected to be recognized over a weighted-average period of 0.41 years. As of September 30, 2021, the expense per performance share, which is the fair value per performance share adjusted for the estimated payout of the performance criteria, was $83.51.


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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. 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 September 30, 2021, unrecognized equity-based compensation related to the outperformance share award expected to vest was $0.3 million. Such cost is expected to be recognized over a weighted-average period of 1.95 years.

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, 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, 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 performance period. The expense related to the performance unit awards is recognized on a straight-line basis over the 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 250% for the 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 the ATSR Appreciation is zero or less.


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The following table presents the assumptions used to estimate the fair value per performance unit for the performance unit awards granted in 2021:


	March 9, 2021
Remaining performance period	2.81 years
Risk-free interest rate(1)	0.32		%
Dividend yield	—		%
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 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 expected volatility.

The following table reflects the performance unit award activity for the nine months ended September 30, 2021:


(in thousands)						Performance units
Outstanding as of December 31, 2020						99
Granted						110


Outstanding as of September 30, 2021						209

As of September 30, 2021, unrecognized equity-based compensation related to the performance unit awards expected to vest was $16.9 million. Such cost is expected to be recognized over a weighted-average period of 2.07 years. As of September 30, 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 2021 and 2020 performance unit awards was $119.77 and $131.19, 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.

The following table reflects the phantom unit award activity for the nine months ended September 30, 2021:


(in thousands)						Phantom units
Outstanding as of December 31, 2020						75
Granted						5
Forfeited						(22)
Vested(1)						(25)
Outstanding as of September 30, 2021						33

______________________________________________________________________________

(1)On March 5, 2021, the vested phantom unit awards were settled and paid out in cash at a fair value of $34.24 based on the Company's closing stock 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 September 30, 2021, unrecognized equity-based compensation related to the phantom unit awards expected to vest was $2.0 million. Such cost is expected to be recognized over a weighted-average period of 1.58 years.


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g. Equity-based compensation

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


	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2021		2020		2021		2020
Equity awards:
Restricted stock awards	$	1,810	$	2,140	$	5,630	$	6,682
Performance share awards	366		739		962		1,777
Outperformance share award	44		44		131		131
Stock option awards	—		13		7		63
Total share-settled equity-based compensation, gross	$	2,220	$	2,936	$	6,730	$	8,653
Less amounts capitalized	(409)		(895)		(1,121)		(2,542)
Total share-settled equity-based compensation, net	$	1,811	$	2,041	$	5,609	$	6,111
Liability awards:
Performance unit awards	$	1,380	$	18	$	8,552	$	208
Phantom unit awards	269		29		1,202		140
Total cash-settled equity-based compensation, gross	$	1,649	$	47	$	9,754	$	348
Less amounts capitalized	(60)		(14)		(353)		(57)
Total cash-settled equity-based compensation, net	$	1,589	$	33	$	9,401	$	291
Total equity-based compensation, net	$	3,400	$	2,074	$	15,010	$	6,402

Note 9—Derivatives

The Company has three types of derivative instruments as of September 30, 2021: (i) commodity derivatives, (ii) a debt interest rate derivative and (iii) a contingent consideration derivative. See Notes (i) 2.e in the 2020 Annual Report for discussion of the Company's significant accounting policies for derivatives and presentation and (ii) 10.a for discussion of fair value measurement of derivatives on a recurring basis. 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 September 30,				Nine months ended September 30,
(in thousands)	2021		2020		2021		2020
Commodity	$	(101,394)	$	(45,219)	$	(472,296)	$	155,278
Interest rate	(17)		9		(43)		(329)
Contingent consideration	5,171		(40)		4,792		7,100
Gain (loss) on derivatives, net	$	(96,240)	$	(45,250)	$	(467,547)	$	162,049

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 2020 Annual Report for discussion of transaction types and settlement indexes.

During the nine months ended September 30, 2021, the Company’s derivatives were settled based on reported prices on commodity exchanges, with (i) oil derivatives settled based on WTI NYMEX and Brent ICE pricing, (ii) NGL derivatives settled


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based on Mont Belvieu OPIS pricing and (iii) natural gas derivatives settled based on Henry Hub NYMEX and Waha Inside FERC pricing.

During the nine months ended September 30, 2021, in connection with the Working Interest Sale, the Company entered into derivative positions on behalf of Sixth Street. Following the closing of the Working Interest Sale on July 1, 2021, all of the hedges entered into on behalf of Sixth Street were novated to Sixth Street as intended.

During the nine months ended September 30, 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 nine months ended September 30, 2020, the Company completed a hedge restructuring by early terminating collars and entering into new swaps. The following table 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


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


	Remaining Year 2021		Year 2022
Oil:





WTI NYMEX - Swaps:
Volume (Bbl)	368,000		365,000
Weighted-average price ($/Bbl)	$	69.46	$	64.40
WTI NYMEX - Collars:
Volume (Bbl)	92,000		3,394,500
Weighted-average floor price ($/Bbl)	$	63.00	$	58.23
Weighted-average ceiling price ($/Bbl)	$	67.65	$	69.39
Total WTI NYMEX:
Total volume (Bbl)	460,000		3,759,500
Weighted-average floor price ($/Bbl)	$	68.16	$	58.83
Weighted-average ceiling price ($/Bbl)	$	69.09	$	68.91





Brent ICE - Swaps:
Volume (Bbl)	1,890,600		4,124,500
Weighted-average price ($/Bbl)	$	51.29	$	48.34
Brent ICE - Collars:
Volume (Bbl)	331,200		1,551,250
Weighted-average floor price ($/Bbl)	$	55.00	$	56.65
Weighted-average ceiling price ($/Bbl)	$	66.53	$	65.44
Total Brent ICE:
Total volume (Bbl)	2,221,800		5,675,750
Weighted-average floor price ($/Bbl)	$	51.84	$	50.61

Weighted-average ceiling price ($/Bbl)	$	53.56	$	53.01









































NGL:

Purity Ethane - Swaps:
Volume (Bbl)	230,000		1,533,000
Weighted-average price ($/Bbl)	$	12.01	$	11.42
Non-TET Propane - Swaps:
Volume (Bbl)	610,788		1,168,000
Weighted-average price ($/Bbl)	$	22.90	$	35.91
Non-TET Normal Butane - Swaps:
Volume (Bbl)	203,596		365,000
Weighted-average price ($/Bbl)	$	25.87	$	41.58
Non-TET Isobutane - Swaps:
Volume (Bbl)	55,568		109,500
Weighted-average price ($/Bbl)	$	26.55	$	42.00
Non-TET Natural Gasoline - Swaps:
Volume (Bbl)	222,088		365,000
Weighted-average price ($/Bbl)	$	38.16	$	60.65

Total NGL volume (Bbl)	1,322,040		3,540,500
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	Remaining Year 2021		Year 2022
Natural gas:



Henry Hub NYMEX - Swaps:
Volume (MMBtu)	10,718,000		3,650,000
Weighted-average price ($/MMBtu)	$	2.59	$	2.73
Henry Hub NYMEX - Collars:
Volume (MMBtu)	—		29,200,000
Weighted-average floor price ($/MMBtu)	$	—	$	3.09
Weighted-average ceiling price ($/MMBtu)	$	—	$	3.84
Total Henry Hub NYMEX:
Total volume with floor price (MMBtu)	10,718,000		32,850,000
Weighted-average floor price ($/MMBtu)	$	2.59	$	3.05
Total volume with ceiling price (MMBtu)	10,718,000		32,850,000
Weighted-average ceiling price ($/MMBtu)	$	2.59	$	3.71
Waha Inside FERC to Henry Hub NYMEX - Basis Swaps:
Volume (MMBtu)	14,278,400		29,017,500
Weighted-average differential ($/MMBtu)	$	(0.47)	$	(0.36)

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 summarizes the Company's interest rate 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 Sixth Street PSA provided for potential contingent payments to be paid to the Company if certain cash flow targets are met related to divested oil and natural gas property operations. The Sixth Street Contingent Consideration provides the Company with the right to receive up to a maximum of $93.7 million in additional cash consideration, comprised of potential quarterly payments through June 2027 totaling up to $38.7 million and a potential balloon payment of $55.0 million in June 2027. The fair value of the Sixth Street Contingent Consideration was $33.8 million as of the acquisition date and $39.0 million as of September 30, 2021. See Note 3.a for further discussion of the Working Interest Sale associated with the Sixth Street Contingent Consideration.

The Company's asset acquisition of oil and natural gas properties that closed on April 30, 2020 provided 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. As the maximum thresholds were met, the Company paid the maximum amount of the $1.2 million contingent consideration to the counterparty during the three months ended September 30, 2021. See Note 3.b for further discussion of the Company's asset acquisition associated with this contingent consideration.

At each quarterly reporting period, the Company remeasures contingent consideration with the change in fair value recognized in earnings.


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Note 10—Fair value measurements

See the beginning of Note 11 in the 2020 Annual Report for information about the fair value hierarchy levels.

a. Fair value measurement on a recurring basis

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

Balance sheet presentation

The following tables present the Company's derivatives by (i) balance sheet classification, (ii) derivative type and (iii) fair value hierarchy 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:


	September 30, 2021
(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:
Current:
Commodity - Oil	$	—	$	10,836	$	—	$	10,836	$	(10,836)	$	—
Commodity - NGL	—		—		—		—		—		—
Commodity - Natural gas	—		3,497		—		3,497		(3,497)		—

Contingent consideration	—		3,272		—		3,272		—		3,272
Noncurrent:
Commodity - Oil	$	—	$	6,657	$	—	$	6,657	$	(6,657)	$	—
Commodity - NGL	—		—		—		—		—		—
Commodity - Natural gas	—		1,497		—		1,497		(1,497)		—


Contingent consideration	—		35,742		—		35,742		—		35,742
Liabilities:
Current:
Commodity - Oil	$	—	$	(171,158)	$	—	$	(171,158)	$	10,836	$	(160,322)
Commodity - NGL	—		(62,658)		—		(62,658)		—		(62,658)
Commodity - Natural gas	—		(69,180)		—		(69,180)		3,497		(65,683)

Interest rate - LIBOR	—		(131)		—		(131)		—		(131)
Contingent consideration	—		—		—		—		—		—
Noncurrent:
Commodity - Oil	$	—	$	(35,279)	$	—	$	(35,279)	$	6,657	$	(28,622)
Commodity - NGL	—		(3,406)		—		(3,406)		—		(3,406)
Commodity - Natural gas	—		(6,922)		—		(6,922)		1,497		(5,425)


Interest rate - LIBOR	—		—		—		—		—		—
Contingent consideration	—		—		—		—		—		—
Net derivative liability positions	$	—	$	(287,233)	$	—	$	(287,233)	$	—	$	(287,233)


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	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	$	—	$	32,958	$	—	$	32,958	$	(24,930)	$	8,028
Commodity - NGL	—		2,720		—		2,720		(2,720)		—
Commodity - Natural gas	—		521		—		521		(656)		(135)


Contingent consideration	—		—		—		—		—		—
Noncurrent:
Commodity - Oil	$	—	$	—	$	—	$	—	$	—	$	—
Commodity - NGL	—		—		—		—		—		—
Commodity - Natural gas	—		535		—		535		(535)		—


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


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


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

See Note 11.a in the 2020 Annual Report for discussion of the significant Level 2 inputs used in the fair value mark-to-market analysis of commodity, interest rate and 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 Working Interest Sale provides for potential contingent payments to be paid to the Company. The fair value of the Sixth Street Contingent Consideration was $33.8 million as of the acquisition date and $39.0 million as of September 30, 2021. See Note 3.a for further discussion of the Working Interest Sale associated with the Sixth Street Contingent Consideration.

The Company's acquisition of oil and natural gas properties that closed on April 30, 2020 provided for potential contingent payments to be paid by the Company. During the three months ended September 30, 2021, the maximum amount of the $1.2 million contingent consideration was distributed to the counterparty. The fair value of the contingent consideration derivative liability was $0.8 million as of December 31, 2020. See Note 3.b for further discussion of the Company's asset acquisition associated with this contingent consideration.

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 $1.6 million and $1.3 million impairment expense of inventory recorded during the nine months ended September 30, 2021 and 2020, respectively, pertaining to line-fill and other inventories.


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(Unaudited)

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 nine months ended September 30, 2020, pertaining to midstream service assets. There were no impairments of long-lived assets recorded during the nine months ended September 30, 2021.

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:


	September 30, 2021				December 31, 2020
(in thousands)	Long-term debt		Fair value(1)		Long-term debt		Fair value(1)
January 2025 Notes	$	577,913	$	598,862	$	577,913	$	499,299
January 2028 Notes	361,044		390,415		361,044		299,667
July 2029 Notes	400,000		401,000		—		—
Senior Secured Credit Facility	30,000		30,023		255,000		255,187
Total	$	1,368,957	$	1,420,300	$	1,193,957	$	1,054,153

______________________________________________________________________________

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


Table of Contents			Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note 11—Net income (loss) per common share

Basic and diluted net income (loss) per common share are 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 months ended September 30, 2021, the dilutive effects of these awards were calculated utilizing the treasury stock method. For the nine months ended September 30, 2021 and the three and nine months ending September 30, 2020, all of these awards were anti-dilutive due to the Company's net loss and, therefore, were excluded from the calculation of diluted net loss per common share.

The 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 September 30,				Nine months ended September 30,
(in thousands, except for per share data)	2021		2020		2021		2020



Net income (loss) (numerator)	$	136,832	$	(237,432)	$	(71,268)	$	(708,241)
Weighted-average common shares outstanding (denominator):
Basic(1)	15,756		11,686		13,464		11,657
Dilutive non-vested restricted stock awards	187		—		—		—

Dilutive non-vested performance share awards(2)	50		—		—		—

Diluted	15,993		11,686		13,464		11,657
Net income (loss) per common share:



Basic	$	8.68	$	(20.32)	$	(5.29)	$	(60.76)
Diluted	$	8.56	$	(20.32)	$	(5.29)	$	(60.76)

_____________________________________________________________________________

(1)For the three and nine months ended September 30, 2021, the weighted-average common shares outstanding used in the computation of basic and diluted net income (loss) per share includes the effects of equity issued by the Company during the periods. There was no comparable equity issued during the three and nine months ended September 30, 2020. See Notes 3.a and 7.a for additional discussion of equity issued by the Company.

(2)The dilutive effect of the non-vested performance share awards for the three months ended September 30, 2021 was calculated assuming the performance period ended on September 30, 2021.

The effect of the outstanding stock option awards was excluded from the calculation of diluted net income per common share for the three months ended September 30, 2021. The inclusion of these stock option awards would be anti-dilutive as their exercise prices were greater than the average closing price during the period.

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 contracts

The Company enters into drilling rig contracts to ensure availability of desired rigs to facilitate drilling plans. The Company has two operating leases for terms of multiple months, both of which contain early termination clauses that 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 no penalties incurred for early contract termination for either of the nine months ended September 30, 2021 or 2020. As these drilling rig contracts are operating leases with an initial term greater than 12 months, the present value of the future commitment as of September 30,


Table of Contents			Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

2021 is included in current and noncurrent "Operating lease liabilities" on the unaudited consolidated balance sheet as of September 30, 2021. See Note 5 in the 2020 Annual Report for additional discussion of 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. 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 $2.8 million during the nine months ended September 30, 2021, which is recorded in "Transportation and marketing expenses" on the unaudited consolidated statement of operations. The Company expensed firm transportation payments on excess capacity of $2.2 million during the nine months ended September 30, 2020, which is recorded in "Transportation and marketing expenses" on the unaudited consolidated statement of operations. The Company's estimated aggregate liability of firm transportation payments on excess capacity is $4.1 million as of September 30, 2021, and is included in "Accounts payable and accrued liabilities" on the unaudited consolidated balance sheet. As of September 30, 2021, future firm sale and transportation commitments of $229.6 million are expected to be satisfied and, as such, are not recorded as a liability on the unaudited consolidated balance sheet.

d. Sand purchase commitment

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 September 30, 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 $0.1 million at the end of the contract period.

e. Federal and state regulations

Oil and natural gas exploration, production and related operations are subject to extensive federal and state laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases the cost of doing business and affects profitability. The Company believes that it is in compliance with currently applicable federal and state regulations related to oil and natural gas exploration and production, and that compliance with the current regulations will not have a material adverse impact on the financial position or results of operations of the Company. These rules and regulations are frequently amended or reinterpreted; therefore, the Company is unable to predict the future cost or impact of complying with these regulations.

f. Environmental

The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, among other things, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed in the period incurred. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Management believes no materially significant liabilities of this nature existed as of September 30, 2021 or December 31, 2020.


Table of Contents			Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note 13—Supplemental cash flow and non-cash information

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


	Nine months ended September 30,
(in thousands)	2021		2020
Supplemental cash flow information:
Cash paid for interest, net of $3,081 and $2,290 of capitalized interest, respectively	$	95,684	$	73,725
Net cash received for income taxes(1)	$	—	$	(2,129)
Supplemental non-cash investing information:
Fair value of contingent consideration asset (liability) on transaction date(2)	$	33,832	$	(225)
Change in accrued capital expenditures	$	25,380	$	(11,267)

Capitalized share-settled equity-based compensation	$	1,121	$	2,542
Capitalized asset retirement cost	$	2,668	$	1,107

_____________________________________________________________________________

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

(2)See Notes 3.a, 3.b and 9.c for discussion of the Company's 2021 Working Interest Sale of oil and natural gas properties and 2020 acquisition of oil and natural gas properties, both of which include contingent considerations. See Note 10.a for discussion of the quarterly remeasurement of these contingent considerations.

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


	Nine months ended September 30,
(in thousands)	2021		2020
Right-of-use assets obtained in exchange for operating lease liabilities(1)	$	7,532	$	2,349

_____________________________________________________________________________

(1)See Note 4 for additional discussion of the Company's leases.

Note 14—Asset retirement obligations

See Note 2.k in the 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:


	Nine months ended September 30,
(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	2,668		1,107
Accretion expense(1)	3,207		3,325
Liabilities settled due to plugging and abandonment or removed due to sale	(14,904)		(887)


Liability at end of period	$	59,297	$	66,263

_____________________________________________________________________________

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


Table of Contents			Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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 September 30, 2021, the Company had federal net operating loss ("NOL") carryforwards totaling $2.1 billion, and of this amount, $1.7 billion will begin to expire in 2026 and $366.8 million will not expire but may be limited in future periods, and state of Oklahoma net operating loss carryforwards totaling $34.4 million that will begin to expire in 2032. In connection with the Working Interest Sale, which closed during the three months ended September 30, 2021, and the resulting estimated tax gain, the Company expects to use a portion of its NOL carryforwards for federal tax purposes and has recorded corresponding current tax expense of $1.3 million for Texas franchise taxes.

As of September 30, 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 September 30, 2021, the Company's ability to capitalize intangible drilling costs, rather than expensing these costs and future projections of Oklahoma sourced income. As of September 30, 2021, a total valuation allowance of $503.3 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 $2.2 million, which is included in "Other noncurrent assets, net" on the unaudited consolidated balance sheets.

Since September 30, 2015, the Company has recorded a full valuation allowance against its federal and Oklahoma net deferred tax position. As such, the Company's effective tax rate is 1%, due to the Texas franchise tax. The Company's effective tax rate is affected by changes in valuation allowances, recurring permanent differences and discrete items that may occur in any given year, but are not consistent from year to year.

Note 17—Related parties

Halliburton

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 statements of cash flows for the periods presented:


	Nine months ended September 30,
(in thousands)	2021		2020

Capital expenditures for oil and natural gas properties	$	42,074	$	51,393

Note 18—Organizational restructurings

On June 29, 2021 (the "Effective Date"), the Company committed to a company-wide reorganization effort (the “Plan”) that included a workforce reduction of 14 individuals, or approximately 5% of the workforce. The reduction in workforce was communicated to employees on the Effective Date and implemented immediately, subject to certain administrative procedures. The Company put the Plan in place in order to better position the Company for the future. In connection with the Plan, the Company incurred an aggregate of $9.8 million of one-time charges during the nine months ended September 30, 2021 comprising of compensation, tax, professional, outplacement and insurance related expenses. All equity-based compensation awards held by the affected employees were forfeited and the corresponding equity-based compensation totaling $1.1 million was reversed during the nine months ended September 30, 2021. See Note 8 for additional information on the associated forfeiture activity.


Table of Contents			Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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 connection with these changes, the Company incurred $4.2 million of one-time charges during the nine months ended September 30, 2020, comprised of compensation, tax, professional, outplacement and insurance-related expenses. 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 nine months ended September 30, 2020.

Note 19—Subsequent events

a. 2021 Acquisition

On October 18, 2021, the Company closed the Pioneer Acquisition, and issued the 959,691 shares of its common stock constituting a portion of the purchase price in reliance on the exemption from registration requirements under the Securities Act, pursuant to Section 4(a)(2) thereof. The Company funded the cash portion of the purchase price and related transaction costs with respect to the Pioneer Acquisition with cash on hand and borrowings under its Senior Secured Credit Facility. See Note 3.a for additional discussion of the Pioneer Acquisition.

b. Senior Secured Credit Facility

On October 7, 2021 and October 18, 2021, the Company borrowed an additional $20.0 million and $110.0 million, respectively, on the Senior Secured Credit Facility. As a result, the outstanding balance under the Senior Secured Credit Facility was $160.0 million as of November 1, 2021. See Note 6.d for additional discussion of the Senior Secured Credit Facility.

On October 20, 2021, in connection with the Pioneer Acquisition and pursuant to the regular semi-annual redetermination, the Company’s lenders increased the borrowing base under the Senior Secured Credit Facility to $1.0 billion. The aggregate elected commitment under the Senior Secured Credit Facility remained unchanged at $725.0 million.

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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 nine months ended September 30, 2021 and 2020, 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 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 September 30, 2021, we had assembled 165,966 net acres in the Permian Basin.

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


	Three months ended September 30,				2021 compared to 2020
(in thousands)	2021		2020			Change (#)		Change (%)
Oil sales volumes (MBbl)	3,250		2,311			939		41	%
Oil equivalents sales volumes (MBOE)	7,057		8,083			(1,026)		(13)	%
Oil, NGL and natural gas sales(1)	$	311,276	$	132,462		$	178,814	135	%
Net income (loss)(2)	$	136,832	$	(237,432)		$	374,264	158	%
Free Cash Flow (a non-GAAP financial measure)(3)	$	(19,895)	$	71,117		$	(91,012)	(128)	%
Adjusted EBITDA (a non-GAAP financial measure)(3)	$	133,441	$	137,281		$	(3,840)	(3)	%

_____________________________________________________________________________

(1)Our oil, NGL and natural gas sales increased as a result of a 169% increase in average sales price per BOE and were partially offset by a 13% decrease in total volumes sold.

(2)Our net loss for the three months ended September 30, 2020 includes a non-cash full cost ceiling impairment of $196.1 million.

(3)See pages 50-52 for discussion and calculations of these non-GAAP financial measures.

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	Nine months ended September 30,				2021 compared to 2020
(in thousands)	2021		2020		Change (#)		Change (%)
Oil sales volumes (MBbl)	7,840		7,809		31		—	%
Oil equivalents sales volumes (MBOE)	21,985		24,522		(2,537)		(10)	%
Oil, NGL and natural gas sales(1)	$	746,059	$	362,490	$	383,569	106	%
Net loss(2)	$	(71,268)	$	(708,241)	$	636,973	90	%
Free Cash Flow (a non-GAAP financial measure)(3)	$	(27,585)	$	(9,952)	$	(17,633)	(177)	%
Adjusted EBITDA (a non-GAAP financial measure)(3)	$	323,755	$	386,966	$	(63,211)	(16)	%

_____________________________________________________________________________

(1)Our oil, NGL and natural gas sales increased as a result of a 130% increase in average sales price per BOE and were partially offset by a 10% decrease in total volumes sold.

(2)Our net loss for the nine months ended September 30, 2020 includes a non-cash full cost ceiling impairment of $779.7 million.

(3)See pages 50-52 for discussion and calculations of these non-GAAP financial measures.

Recent developments

2021 Acquisitions and divestiture

On October 18, 2021, we closed the Pioneer Acquisition, and issued the 959,691 shares of our common stock constituting a portion of the purchase price in reliance on the exemption from registration requirements under the Securities Act, pursuant to Section 4(a)(2) thereof. See Note 3.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of the Pioneer Acquisition.

On July 1, 2021, we closed the Sabalo/Shad Acquisition, and issued the 2,506,964 shares of our common stock constituting a portion of the purchase price in reliance on the exemption from registration requirements under the Securities Act, pursuant to Section 4(a)(2) thereof. On July 1, 2021, we also closed the Working Interest Sale. See Note 3.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of the Sabalo/Shad Acquisition and Working Interest Sale.

July 2029 Notes

On July 16, 2021, we closed a private offering and sale of $400.0 million in aggregate principal amount of 7 3/4% senior unsecured notes due 2029. We received net proceeds from the offering of approximately $392.0 million (after deducting underwriting discounts and commissions and estimated offering expenses), which we used for general corporate purposes, including, repaying a portion of the borrowings outstanding under our Senior Secured Credit Facility.

Senior Secured Credit Facility

On October 20, 2021, in connection with the Pioneer Acquisition and pursuant to the regular semi-annual redetermination, our lenders increased the borrowing base under the Senior Secured Credit Facility to $1.0 billion. The aggregate elected commitment under the Senior Secured Credit Facility remained unchanged at $725.0 million.

On October 7, 2021, and October 18, 2021 we borrowed an additional $20.0 million and $110.0 million, respectively, on the Senior Secured Credit Facility. As a result, the outstanding balance under the Senior Secured Credit Facility was $160.0 million as of November 1, 2021. See Notes 6.d and 19.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of the Senior Secured Credit Facility.

COVID-19

Although much of the demand for oil and natural gas lost during COVID-19 has recovered, we are not able to predict the duration or ultimate impact that the pandemic will have on our business, financial condition and results of operations. We continue to closely monitor local infection rates and to conform to guidelines and best practices encouraged by the Centers for Disease Control and Prevention, the World Health Organization and other governmental and regulatory authorities as we have implemented appropriate return-to-work policies while minimizing interruptions to our operations. To date, these measures have not had a material effect on our workforce productivity.

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Volatility in commodity prices

In the spring of 2020, action by members of OPEC+ attempting to stabilize the oil market and a slow reaction by U.S. and global producers to reduce oil production at a rate sufficient to match the sharp economic slowdown caused by COVID-19, resulted in an oversupply of oil that caused WTI oil prices to fall to -$37 per barrel on April 20, 2020. Following the April 20th low, WTI oil prices rebounded in the second half of 2020 and have averaged $65 per barrel during the nine months ended September 30, 2021 and $67 per barrel through October 2021.

We maintain an active, multi-year commodity derivatives strategy to minimize commodity price volatility and support cash flows needed for operations. For 2021, we currently have WTI oil derivatives in place for 0.5 million barrels at a weighted-average floor price of $68.16 WTI per barrel and Brent oil derivatives in place for 2.2 million barrels at a weighted-average floor price of $51.84 Brent per barrel. For 2022, we currently have WTI oil derivatives in place for 3.8 million barrels at a weighted-average floor price of $58.83 WTI per barrel and Brent oil derivatives in place for 5.7 million barrels at a weighted-average floor price of $50.61 Brent per barrel.

Pricing and reserves

Our results of operations are heavily influenced by oil, NGL and natural gas prices. Historically, commodity prices have experienced significant fluctuations; however, the volatility in prices has substantially increased as a result of 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 and 10.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our commodity derivatives.

Our reserves are reported in three streams: oil, NGL and natural gas. The Realized Prices utilized to value our proved reserves as of September 30, 2021 and 2020, are as follows:


	September 30, 2021		September 30, 2020
Realized Prices:
Oil ($/Bbl)	$	54.86	$	41.08
NGL ($/Bbl)	$	18.50	$	7.71
Natural gas ($/Mcf)	$	2.03	$	0.68

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 for each of the quarterly periods in 2020 and, as such, we recorded non-cash full cost ceiling impairments totaling $889.5 million during the year ended December 31, 2020. No such full cost ceiling impairment was recorded during the nine months ending September 30, 2021. Additionally, given current commodity prices, we do not anticipate recording a full cost ceiling impairment in the fourth quarter of 2021. See Note 5 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of the full cost method of accounting and our Realized Prices.

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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 U.S. and do not include the effects of derivatives. See Note 15 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report and Note 14 in our 2020 Annual Report for additional information regarding our revenue recognition policies.

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


	Three months ended September 30,				2021 compared to 2020
	2021		2020		Change (#)		Change (%)

Oil sales	60	%	54	%	6	%	11	%
NGL sales	13	%	14	%	(1)	%	(7)	%
Natural gas sales	10	%	8	%	2	%	25	%
Midstream service revenues	—	%	1	%	(1)	%	(100)	%
Sales of purchased oil	17	%	23	%	(6)	%	(26)	%
Total	100	%	100	%


	Nine months ended September 30,				2021 compared to 2020
	2021		2020		Change (#)		Change (%)

Oil sales	56	%	58	%	(2)	%	(3)	%
NGL sales	14	%	10	%	4	%	40	%
Natural gas sales	11	%	6	%	5	%	83	%
Midstream service revenues	—	%	1	%	(1)	%	(100)	%
Sales of purchased oil	19	%	25	%	(6)	%	(24)	%
Total	100	%	100	%

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

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


	Three months ended September 30,			2021 compared to 2020
		2021		2020		Change (#)		Change (%)
Sales volumes:
Oil (MBbl)		3,250		2,311		939		41	%
NGL (MBbl)		1,830		2,760		(930)		(34)	%
Natural gas (MMcf)		11,860		18,072		(6,212)		(34)	%
Oil equivalents (MBOE)(1)(2)		7,057		8,083		(1,026)		(13)	%
Average daily oil equivalent sales volumes (BOE/D)(2)		76,703		87,857		(11,154)		(13)	%
Average daily oil sales volumes (Bbl/D)(2)		35,329		25,120		10,209		41	%
Sales revenues (in thousands):
Oil		$	229,329	$	93,329	$	136,000	146	%
NGL		47,949		24,935		23,014		92	%
Natural gas		33,998		14,198		19,800		139	%
Total oil, NGL and natural gas sales revenues		$	311,276	$	132,462	$	178,814	135	%
Average sales prices(2):
Oil ($/Bbl)(3)		$	70.56	$	40.38	$	30.18	75	%
NGL ($/Bbl)(3)		$	26.20	$	9.04	$	17.16	190	%
Natural gas ($/Mcf)(3)		$	2.87	$	0.79	$	2.08	263	%
Average sales price ($/BOE)(3)		$	44.11	$	16.39	$	27.72	169	%
Oil, with commodity derivatives ($/Bbl)(4)		$	53.94	$	59.93	$	(5.99)	(10)	%
NGL, with commodity derivatives ($/Bbl)(4)		$	9.31	$	10.46	$	(1.15)	(11)	%
Natural gas, with commodity derivatives ($/Mcf)(4)		$	1.45	$	0.92	$	0.53	58	%
Average sales price, with commodity derivatives ($/BOE)(4)		$	29.70	$	22.76	$	6.94	30	%

__________________________________________________________________________

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

(2)The numbers presented in the three months ended September 30, 2021 and 2020 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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	Nine months ended September 30,			2021 compared to 2020
		2021		2020		Change (#)		Change (%)
Sales volumes:
Oil (MBbl)		7,840		7,809		31		—	%
NGL (MBbl)		6,702		7,979		(1,277)		(16)	%
Natural gas (MMcf)		44,659		52,401		(7,742)		(15)	%
Oil equivalents (MBOE)(1)(2)		21,985		24,522		(2,537)		(10)	%
Average daily oil equivalent sales volumes (BOE/D)(2)		80,530		89,496		(8,966)		(10)	%
Average daily oil sales volumes (Bbl/D)(2)		28,717		28,500		217		1	%
Sales revenues (in thousands):
Oil		$	514,752	$	283,412	$	231,340	82	%
NGL		133,121		49,721		83,400		168	%
Natural gas		98,186		29,357		68,829		234	%
Total oil, NGL and natural gas sales revenues		$	746,059	$	362,490	$	383,569	106	%
Average sales prices(2):
Oil ($/Bbl)(3)		$	65.66	$	36.29	$	29.37	81	%
NGL ($/Bbl)(3)		$	19.86	$	6.23	$	13.63	219	%
Natural gas ($/Mcf)(3)		$	2.20	$	0.56	$	1.64	293	%
Average sales price ($/BOE)(3)		$	33.94	$	14.78	$	19.16	130	%
Oil, with commodity derivatives ($/Bbl)(4)		$	49.33	$	55.35	$	(6.02)	(11)	%
NGL, with commodity derivatives ($/Bbl)(4)		$	10.40	$	8.35	$	2.05	25	%
Natural gas, with commodity derivatives ($/Mcf)(4)		$	1.53	$	0.92	$	0.61	66	%
Average sales price, with commodity derivatives ($/BOE)(4)		$	23.86	$	22.32	$	1.54	7	%

_____________________________________________________________________________

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

(2)The numbers presented in the nine months ended September 30, 2021 and 2020 columns are based on actual amounts and are not calculated using the rounded numbers presented in the table above or the table below.

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The following tables present net settlements (paid) received 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 for such periods:


	Three months ended September 30,				2021 compared to 2020
(in thousands)	2021		2020		Change ($)		Change (%)
Net settlements (paid) received for matured commodity derivatives:
Oil	$	(43,838)	$	45,581	$	(89,419)	(196)	%
NGL	(30,905)		3,921		(34,826)		(888)	%
Natural gas	(16,747)		2,382		(19,129)		(803)	%
Total	$	(91,490)	$	51,884	$	(143,374)	(276)	%
Net premiums paid previously or upon settlement attributable to commodity derivatives that matured during the respective period:
Oil	$	(10,182)	$	(405)	$	(9,777)	(2,414)	%


	Nine months ended September 30,				2021 compared to 2020
(in thousands)	2021		2020		Change ($)		Change (%)
Net settlements (paid) received for matured commodity derivatives:
Oil	$	(96,675)	$	150,467	$	(247,142)	(164)	%
NGL	(63,434)		16,938		(80,372)		(475)	%
Natural gas	(30,046)		19,053		(49,099)		(258)	%
Total	$	(190,155)	$	186,458	$	(376,613)	(202)	%
Net premiums paid previously or upon settlement attributable to commodity derivatives that matured during the respective period:
Oil	$	(31,370)	$	(1,682)	$	(29,688)	(1,765)	%

Changes in average sales prices and sales volumes caused the following changes to our oil, NGL and natural gas revenues between the three and nine months ended September 30, 2021 and 2020:


(in thousands)	Oil			NGL			Natural gas			Total
Third-quarter 2020 Revenues	$	93,329		$	24,935		$	14,198		$	132,462
Effect of changes in average sales prices	98,069			31,416			24,680			154,165
Effect of changes in sales volumes	37,931			(8,402)			(4,880)			24,649

Third-quarter 2021 Revenues	$	229,329		$	47,949		$	33,998		$	311,276
Change ($)	$	136,000		$	23,014		$	19,800		$	178,814
Change (%)	146		%	92		%	139		%	135		%


(in thousands)	Oil			NGL			Natural gas			Total
Third-quarter year-to-date 2020 Revenues	$	283,412		$	49,721		$	29,357		$	362,490
Effect of changes in average sales prices	230,226			91,360			73,167			394,753
Effect of changes in sales volumes	1,114			(7,960)			(4,338)			(11,184)

Third-quarter year-to-date 2021 Revenues	$	514,752		$	133,121		$	98,186		$	746,059
Change ($)	$	231,340		$	83,400		$	68,829		$	383,569
Change (%)	82		%	168		%	234		%	106		%

In the three and nine months ended September 30, 2021, we experienced significant increases in oil, NGL and natural gas sales prices compared to the same periods in 2020.

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


	Three months ended September 30,				2021 compared to 2020
(in thousands)	2021		2020			Change ($)		Change (%)
Midstream service revenues	$	1,739	$	1,751		$	(12)	(1)	%
Sales of purchased oil	$	66,235	$	39,334		$	26,901	68	%


	Nine months ended September 30,				2021 compared to 2020
(in thousands)	2021		2020			Change ($)		Change (%)
Midstream service revenues	$	4,292	$	6,715		$	(2,423)	(36)	%
Sales of purchased oil	$	173,500	$	119,922		$	53,578	45	%

Midstream service revenues. Our midstream service revenues decreased for the three and nine months ended September 30, 2021, compared to the same periods in 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 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 and we utilize purchased oil to fulfill portions of our commitments. We anticipate continuing this practice in the future. Sales of purchased oil increased during the three and nine months ended September 30, 2021, compared to the same periods in 2020 primarily due to an increase in sales prices for purchased oil sold.

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 information regarding costs and expenses and selected average costs and expenses per BOE sold for the periods presented and the corresponding changes for such periods:


	Three months ended September 30,				2021 compared to 2020
(in thousands except for per BOE sold data)	2021		2020		Change ($)		Change (%)
Costs and expenses:
Lease operating expenses	$	29,837	$	19,840	$	9,997	50	%
Production and ad valorem taxes	17,937		8,753		9,184		105	%
Transportation and marketing expenses	11,660		13,161		(1,501)		(11)	%
Midstream service expenses	1,014		1,073		(59)		(5)	%
Costs of purchased oil	68,805		42,720		26,085		61	%

General and administrative (excluding LTIP)	11,332		9,366		1,966		21	%
General and administrative (LTIP):
LTIP cash	2,065		266		1,799		676	%
LTIP non-cash	1,611		1,841		(230)		(12)	%




Depletion, depreciation and amortization	62,678		47,015		15,663		33	%
Impairment expense	—		196,088		(196,088)		(100)	%
Other operating expenses	1,798		1,102		696		63	%
Total costs and expenses	$	208,737	$	341,225	$	(132,488)	(39)	%
Selected average costs and expenses per BOE sold(1):
Lease operating expenses	$	4.23	$	2.45	$	1.78	73	%
Production and ad valorem taxes	2.54		1.08		1.46		135	%
Transportation and marketing expenses	1.65		1.63		0.02		1	%
Midstream service expenses	0.14		0.13		0.01		8	%
General and administrative (excluding LTIP)	1.61		1.16		0.45		39	%
Total selected operating expenses	$	10.17	$	6.45	$	3.72	58	%
General and administrative (LTIP):
LTIP cash	$	0.29	$	0.03	$	0.26	867	%
LTIP non-cash	$	0.23	$	0.23	$	—	—	%
Depletion, depreciation and amortization	$	8.88	$	5.82	$	3.06	53	%

_____________________________________________________________________________

(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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	Nine months ended September 30,				2021 compared to 2020
(in thousands except for per BOE sold data)	2021		2020		Change ($)		Change (%)
Costs and expenses:
Lease operating expenses	$	68,526	$	62,471	$	6,055	10	%
Production and ad valorem taxes	45,957		24,935		21,022		84	%
Transportation and marketing expenses	34,477		37,886		(3,409)		(9)	%
Midstream service expenses	2,572		3,058		(486)		(16)	%
Costs of purchased oil	183,458		138,134		45,324		33	%

General and administrative (excluding LTIP)	33,479		28,543		4,936		17	%
General and administrative (LTIP):
LTIP cash	10,905		862		10,043		1,165	%
LTIP non-cash	4,798		5,289		(491)		(9)	%
Organizational restructuring expenses	9,800		4,200		5,600		133	%


Depletion, depreciation and amortization	140,763		174,891		(34,128)		(20)	%
Impairment expense	1,613		789,235		(787,622)		(100)	%
Other operating expenses	4,099		3,325		774		23	%
Total costs and expenses	$	540,447	$	1,272,829	$	(732,382)	(58)	%
Selected average costs and expenses per BOE sold(1):
Lease operating expenses	$	3.12	$	2.55	$	0.57	22	%
Production and ad valorem taxes	2.09		1.02		1.07		105	%
Transportation and marketing expenses	1.57		1.54		0.03		2	%
Midstream service expenses	0.12		0.12		—		—	%
General and administrative (excluding LTIP)	1.52		1.16		0.36		31	%
Total selected operating expenses	$	8.42	$	6.39	$	2.03	32	%
General and administrative (LTIP):
LTIP cash	$	0.50	$	0.04	$	0.46	1,150	%
LTIP non-cash	$	0.22	$	0.22	$	—	—	%
Depletion, depreciation and amortization	$	6.40	$	7.13	$	(0.73)	(10)	%

_____________________________________________________________________________

(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, increased for the three and nine months ended September 30, 2021, compared to the same periods in 2020. LOE are daily expenses incurred to bring oil, NGL and natural gas out of the ground and to market, together with the daily expenses 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 and decreasing failures and related workover expenses. LOE has increased during 2021 due to higher operating costs on Howard County wells compared to operating costs on our established acreage, along with increased costs associated with the Sabalo/Shad Acquisition.

Production and ad valorem taxes. Production and ad valorem taxes increased for the three and nine months ended September 30, 2021, compared to the same periods in 2020 due to increased sales prices. Production taxes are based on and fluctuate in proportion to our oil, NGL and natural gas sales 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 decreased for the three and nine months ended September 30, 2021, compared to the same periods in 2020. These are expenses 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 ship the majority of our produced oil to the U.S. Gulf Coast, which we believe provides a long-term pricing advantage versus the Midland market.

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Additionally, firm 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.

Midstream service expenses. Midstream service expenses decreased for the three and nine months ended September 30, 2021, compared to the same periods in 2020. These are expenses incurred to operate and maintain our (i) integrated oil and natural gas gathering and transportation systems and related facilities, (ii) centralized oil storage tanks, (iii) natural gas lift, fuel for drilling and completion activities and centralized compression infrastructure and (iv) water storage, recycling and transportation facilities.

Costs of purchased oil. Costs of purchased oil increased for the three and nine months ended September 30, 2021, compared to the same periods in 2020 primarily due to increased contracted prices of purchased oil on pipelines. We are a firm shipper on both the Bridgetex and Gray Oak pipelines 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"), increased for the three and nine months ended September 30, 2021, compared to the same periods in 2020, mainly due to an increase in accrued bonus expected to be paid in 2022 as a result of our favorable performance through the first nine months of 2021.

LTIP cash expense increased for the three and nine months ended September 30, 2021, compared to the same periods in 2020. In 2020, we began utilizing cash awards for the majority of our employee base rather than equity awards. As such, in 2021 we expect LTIP cash expense to increase compared to 2020. During the three and nine months ended September 30, 2021, the value of our performance unit awards and phantom unit awards increased significantly, mainly due to the performance of our stock, as compared to the same periods in 2020.

LTIP non-cash expense decreased slightly for the three and nine months ended September 30, 2021, compared to the same periods in 2020. The decrease in LTIP non-cash expense for the three and nine months ended September 30, 2021 was due to equity award forfeitures related to the second-quarter 2021 workforce reduction, which were still being expensed in the first half of 2020, and 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.

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


	Three months ended September 30,				2021 compared to 2020
(in thousands)	2021		2020		Change ($)		Change (%)
Depletion of evaluated oil and natural gas properties	$	59,250	$	43,648	$	15,602	36	%
Depreciation of midstream service assets	2,384		2,436		(52)		(2)	%
Depreciation and amortization of other fixed assets	1,044		931		113		12	%
Total DD&A	$	62,678	$	47,015	$	15,663	33	%
Depletion expense per BOE sold	$	8.40	$	5.40	$	3.00	56	%


	Nine months ended September 30,				2021 compared to 2020
(in thousands)	2021		2020		Change ($)		Change (%)
Depletion of evaluated oil and natural gas properties	$	130,625	$	164,705	$	(34,080)	(21)	%
Depreciation of midstream service assets	7,187		7,394		(207)		(3)	%
Depreciation and amortization of other fixed assets	2,951		2,792		159		6	%
Total DD&A	$	140,763	$	174,891	$	(34,128)	(20)	%
Depletion expense per BOE sold	$	5.94	$	6.72	$	(0.78)	(12)	%

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Depletion expense per BOE increased for the three months ended September 30, 2021, compared to the same period in 2020 primarily due to the increased value in our proved reserves as a result of the Sabalo/Shad Acquisition and improvements in commodity prices. Depletion expense per BOE decreased for the nine months ended September 30, 2021, compared to the same period in 2020 as a result of the full cost impairments incurred during 2020, but was partially offset by the aforementioned increased value of our proved developed reserves. See Note 5 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.

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


	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2021		2020		2021		2020
Full cost ceiling impairment expense	$	—	$	196,088	$	—	$	779,718
Midstream service asset impairment expense	—		—		—		8,183
Line-fill and other inventories impairment expense	—		—		1,613		1,334
Total impairment expense	$	—	$	196,088	$	1,613	$	789,235

The unamortized cost of evaluated oil and natural gas properties did not exceed the full cost ceiling as of March 31, 2021, June 30, 2021 and September 30, 2021 and, as a result, we did not record full cost ceiling impairments for such periods. As of March 31, 2020, June 30, 2020 and September 30, 2020, the unamortized cost of evaluated oil and natural gas properties exceeded the full cost ceiling and, as a result, we recorded non-cash full cost ceiling impairments of $177.2 million, $406.4 million and $196.1 million, respectively, for such periods. 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.

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 NRV, with cost determined using the weighted-average cost method. See Note 10.b to our unaudited consolidated financial statements included elsewhere in this Quarterly 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 and Note 14 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

Gain on sale of oil and natural gas properties, net. During the three and nine months ended September 30,2021, we recorded a gain in connection with the Working Interest Sale. See Note 3.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion regarding the gain on sale of our oil and natural gas properties.

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Non-operating income (expense)

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


	Three months ended September 30,				2021 compared to 2020
(in thousands)	2021		2020		Change ($)		Change (%)
Loss on derivatives, net	$	(96,240)	$	(45,250)	$	(50,990)	(113)	%
Interest expense	(30,406)		(26,828)		(3,578)		(13)	%


Loss on disposal of assets, net	(22)		(607)		585		96	%
Other income, net	441		533		(92)		(17)	%

Total non-operating expense, net	$	(126,227)	$	(72,152)	$	(54,075)	(75)	%


	Nine months ended September 30,				2021 compared to 2020
(in thousands)	2021		2020		Change ($)		Change (%)
Gain (loss) on derivatives, net	$	(467,547)	$	162,049	$	(629,596)	(389)	%
Interest expense	(82,222)		(78,870)		(3,352)		(4)	%

Loss on extinguishment of debt	—		(13,320)		13,320		100	%
Loss on disposal of assets, net	(28)		(1,057)		1,029		97	%
Write-off of debt issuance costs	—		(1,103)		1,103		100	%
Other income, net	2,236		608		1,628		268	%

Total non-operating income (expense), net	$	(547,561)	$	68,307	$	(615,868)	(902)	%

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


	Three months ended September 30,				2021 compared to 2020
(in thousands)	2021		2020		Change ($)		Change (%)
Non-cash loss on derivatives, net	$	(3,514)	$	(103,430)	$	99,916	97	%
Settlements (paid) received for matured derivatives, net	(92,726)		51,840		(144,566)		(279)	%
Settlements received for early-terminated commodity derivatives, net	—		6,340		(6,340)		(100)	%

Loss on derivatives, net	$	(96,240)	$	(45,250)	$	(50,990)	(113)	%


	Nine months ended September 30,				2021 compared to 2020
(in thousands)	2021		2020		Change ($)		Change (%)
Non-cash gain (loss) on derivatives, net	$	(285,081)	$	20,344	$	(305,425)	(1,501)	%
Settlements (paid) received for matured derivatives, net	(191,507)		186,435		(377,942)		(203)	%
Settlements received for early terminations of commodity derivatives, net	—		6,340		(6,340)		(100)	%
Premiums received (paid) for commodity derivatives	9,041		(51,070)		60,111		118	%
Gain (loss) on derivatives, net	$	(467,547)	$	162,049	$	(629,596)	(389)	%

Non-cash gain (loss) on derivatives, net is the result of (i) new and 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 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 market prices. Settlements paid or received for matured derivatives are for our (i) commodity derivative contracts, which are based on the settlement prices compared to the prices specified in the derivative contracts, (ii) interest rate derivative and (iii) contingent consideration derivatives.

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During the nine months ended September 30, 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, are $50.6 million in aggregate premiums paid at the inception of the contacts.

During the nine months ended September 30, 2021, in connection with the Working Interest Sale, we entered into derivative positions on behalf of Sixth Street. Following the closing of the Working Interest Sale on July 1, 2021, all of the hedges entered into on behalf of Sixth Street were novated to Sixth Street as intended.

See Notes 9 and 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 for the three and nine months ended September 30, 2021, compared to the same periods in 2020. See Notes 6 and 19.b 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 nine months ended September 30, 2020. See Note 6.c to our 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.

Loss on disposal of assets, net. 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 nine months ended September 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 period in 2021. See Note 6.e to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our debt issuance costs.

Income tax (expense) benefit

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


	Three months ended September 30,				2021 compared to 2020
(in thousands)	2021		2020		Change ($)		Change (%)
Current	$	(1,300)	$	—	$	(1,300)	(100)	%
Deferred	$	(1,377)	$	2,398	$	(3,775)	(157)	%


	Nine months ended September 30,				2021 compared to 2020
(in thousands)	2021		2020		Change ($)		Change (%)
Current	$	(1,300)	$	—	$	(1,300)	(100)	%
Deferred	$	707	$	7,154	$	(6,447)	(90)	%

We are subject to federal and state income taxes and the Texas franchise tax. The deferred income tax (expense) benefit for the periods presented is attributed to deferred Texas franchise tax. With the rise in oil prices and the addition of oily, high-margin inventory, we have recently seen positive indications that we will use a portion of our NOLs. However, as of September 30, 2021, we believe it is more likely than not that a portion of the NOL loss carryforwards are not fully realizable. We continue 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 our oil, NGL and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of September 30, 2021, our ability to capitalize intangible drilling costs, rather than expensing these costs and future projections

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of Oklahoma sourced income. As of September 30, 2021, a total valuation allowance of $503.3 million has been recorded to offset our federal and Oklahoma net deferred tax assets, resulting in a Texas net deferred tax asset of $2.2 million. The effective tax rate for our operations was 1%, due to the Texas franchise tax. Our effective tax rate is affected by changes in valuation allowances, recurring permanent differences and discrete items that may occur in any given year, but are not consistent from year to year.

In connection with the Working Interest Sale, which closed during the three months ended September 30, 2021, and the resulting estimated tax gain, we expect to use a portion of our NOL carryforwards for federal tax purposes and we have recorded corresponding current tax expense of $1.3 million for Texas franchise taxes for the three and nine months ended September 30, 2021.

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 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

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 impact of COVID-19 and OPEC+ actions on the energy industry, we believe that our cash flows from operations, the net effect of our hedges and the 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.

We continually monitor the markets and consider which financing alternatives, including debt and equity capital resources, joint ventures and asset sales, are available to meet our future planned capital 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, 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 Notes 6 and 19.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

Due to the inherent volatility in the prices of oil, NGL and natural gas and the sometimes wide pricing differentials between where we produce and sell such commodities, we engage in commodity derivative transactions 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 such 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 Note 9.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of our commodity hedge restructuring during the nine months ended September 30, 2021 and corresponding summary of open commodity derivative positions as of September 30, 2021 for commodity derivatives that were entered into through September 30, 2021.

We continually seek to maintain a financial profile that provides operational flexibility. As of September 30, 2021, we had cash and cash equivalents of $51.4 million and available capacity under the Senior Secured Credit Facility, after the reduction of outstanding letters of credit, of $650.9 million, resulting in total liquidity of $702.3 million. As of November 1, 2021, we had cash and cash equivalents of $86.4 million and available capacity under the Senior Secured Credit Facility, after the reduction for outstanding letters of credit, of $520.9 million, resulting in total liquidity of $607.3 million. We believe that our operating

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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 for such periods:


	Nine months ended September 30,				2021 compared to 2020
(in thousands)	2021		2020		Change ($)		Change (%)
Net cash provided by operating activities	$	287,112	$	273,620	$	13,492	5	%
Net cash used in investing activities	(517,750)		(306,139)		(211,611)		(69)	%
Net cash provided by financing activities	233,277		31,920		201,357		631	%
Net increase (decrease) in cash and cash equivalents	$	2,639	$	(599)	$	3,238	541	%

Cash flows from operating activities

Net cash provided by operating activities increased during the nine months ended September 30, 2021, compared to the same period in 2020. Notable cash changes include (i) an increase in total oil, NGL and natural gas sales revenues of $383.6 million, (ii) a decrease of $317.8 million due to changes in net settlements for matured derivatives, net of premiums, mainly due to increases in commodity prices and (iii) a decrease of $5.2 million due to net changes in operating assets and liabilities. Other significant changes include an increase in costs of purchased oil partially offset by sales of purchased oil and transportation and marketing expenses. The increase in total oil, NGL and natural gas sales revenues was due to a 130% increase in average sales price per BOE and was partially offset by a 10% decrease in total volumes sold. For additional information, see "—Results of 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. Commodity prices during the periods presented have been most impacted by the effects of COVID-19 on demand and the effects of the OPEC+ actions 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 2020 Annual Report.

Cash flows from investing activities

Net cash used in investing activities increased for the nine months ended September 30, 2021, compared to the same period in 2020, mainly due to capital expenditures for the Sabalo/Shad Acquisition and partially offset by proceeds from the Working Interest Sale. 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 for such periods:

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	Nine months ended September 30,				2021 compared to 2020
(in thousands)	2021		2020		Change ($)		Change (%)
Acquisitions of oil and natural gas properties, net	$	(627,044)	$	(23,563)	$	(603,481)	(2,561)	%

Capital expenditures:
Oil and natural gas properties	(278,847)		(278,277)		(570)		—	%
Midstream service assets	(2,375)		(2,517)		142		6	%
Other fixed assets	(3,226)		(3,024)		(202)		(7)	%


Proceeds from dispositions of capital assets, net of selling costs	393,742		1,242		392,500		31,602	%
Net cash used in investing activities	$	(517,750)	$	(306,139)	$	(211,611)	(69)	%

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


	Three months ended September 30,				2021 compared to 2020
(in thousands)	2021		2020		Change ($)		Change (%)
Oil and natural gas properties	$	135,174	$	41,128	$	94,046	229	%
Midstream service assets	567		1,103		(536)		(49)	%
Other fixed assets	1,685		495		1,190		240	%
Total incurred capital expenditures, excluding non-budgeted acquisition costs	$	137,426	$	42,726	$	94,700	222	%


	Nine months ended September 30,				2021 compared to 2020
(in thousands)	2021		2020		Change ($)		Change (%)
Oil and natural gas properties	$	306,445	$	269,937	$	36,508	14	%
Midstream service assets	2,422		2,697		(275)		(10)	%
Other fixed assets	3,229		3,092		137		4	%
Total incurred capital expenditures, excluding non-budgeted acquisition costs	$	312,096	$	275,726	$	36,370	13	%

See Note 5 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding our incurred capital expenditures 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 capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. Subject to financing alternatives, we may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We continually monitor and may adjust our projected capital expenditures in response to world developments, such as those we 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 provided by financing activities increased for the nine months ended September 30, 2021, compared to the same period in 2020. Notable 2021 activity includes borrowings on our Senior Secured Credit Facility, proceeds from the issuance of our July 2029 Notes and proceeds from our ATM Program, partially offset by 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 and borrowings on our Senior Secured Credit Facility. For further discussion of our financing activities related to debt instruments, see Notes 6 and 19.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

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


	Nine months ended September 30,				2021 compared to 2020
(in thousands)	2021		2020		Change ($)		Change (%)
Borrowings on Senior Secured Credit Facility	$	425,000	$	45,000	$	380,000	844	%
Payments on Senior Secured Credit Facility	(650,000)		(185,000)		(465,000)		(251)	%





Issuance of January 2025 Notes and January 2028 Notes	—		1,000,000		(1,000,000)		(100)	%
Issuance of July 2029 Notes	400,000		—		400,000		100	%
Extinguishment of debt	—		(808,855)		808,855		100	%
Proceeds from issuance of common stock, net of costs	72,492		—		72,492		100	%
Stock exchanged for tax withholding	(2,589)		(774)		(1,815)		(234)	%
Proceeds from exercise of stock options	173		—		173		100	%
Payments for debt issuance costs	(14,597)		(18,451)		3,854		21	%
Other liabilities	2,798		—		2,798		100	%
Net cash provided by financing activities	$	233,277	$	31,920	$	201,357	631	%

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 September 30, 2021, the Senior Secured Credit Facility, which matures on July 16, 2025, had a maximum credit amount of $2.0 billion, a borrowing base and an aggregate elected commitment of $725.0 million each, with $30.0 million outstanding, and was subject to an interest rate of 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 September 30, 2021 and December 31, 2020, we had one letter of credit outstanding of $44.1 million under the Senior Secured Credit Facility. The Senior Secured Credit Facility is fully and unconditionally guaranteed by LMS and GCM. On October 7, 2021 and October 18, 2021, we borrowed an additional $20.0 million and $110.0 million, respectively, on the Senior Secured Credit Facility. As a result, the outstanding balance under the Senior Secured Credit Facility was $160.0 million as of November 1, 2021. The borrowing base under the Senior Secured Credit Facility was increased to $1.0 billion on October 20, 2021 with the aggregate elected commitment amount remaining unchanged at $725.0 million.

See Notes 6.d and 19.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our Senior Secured Credit Facility.

January 2025 Notes, January 2028 Notes and July 2029 Notes

The following table presents principal amounts and applicable interest rates for our outstanding January 2025 Notes, January 2028 Notes and July 2029 Notes (together the "Senior Unsecured Notes") as of September 30, 2021:


(in millions, except for interest rates)	Principal		Interest rate
January 2025 Notes	$	577.9	9.500	%
January 2028 Notes	361.0		10.125	%
July 2029 Notes	400.0		7.750	%
Total Senior Unsecured Notes	$	1,338.9

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. On July 16, 2021, we closed a private offering and sale of $400.0 million in aggregate principal amount of our 7 3/4% senior unsecured notes due 2029. See Note 6 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our Senior Unsecured Notes.

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Supplemental Guarantor information

As discussed in Note 6 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. On July 16, we issued $400.0 million in aggregate principal amount of the July 2029 Notes. As of September 30, 2021, $1.3 billion 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, January 2028 Notes and July 2029 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.

Obligations and commitments

Our significant contractual obligations and commitments include our Senior Unsecured Notes, firm sale and transportation commitments, Senior Secured Credit Facility, asset retirement obligations and lease commitments. Since December 31, 2020, there have been no material changes other than to our debt and firm sale and transportation commitments. See Notes 6 and 19.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our debt.

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. Future firm sale and transportation commitments of $229.6 million are expected to be satisfied as of September 30, 2021 and are not recorded as a liability on the unaudited consolidated balance sheet. These commitments have decreased during the nine months ended September 30, 2021, and are mainly due to our fulfillment of contractual commitments, partially offset by changes to existing sales commitments. Of this amount, $67.9 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 nine months ended September 30, 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 $2.8 million. See Note 12.c to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our firm sale and transportation commitments.

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 incurred capital expenditures, 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 Free Cash Flow (non-GAAP) for the periods presented:


	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2021		2020		2021		2020
Net cash provided by operating activities(1)	$	97,674	$	102,058	$	287,112	$	273,620
Less:
Change in current assets and liabilities, net	(3,142)		(8,360)		27,106		19,098
Change in noncurrent assets and liabilities, net	(16,715)		(3,425)		(24,505)		(11,252)
Cash flows from operating activities before changes in operating assets and liabilities, net(1)	117,531		113,843		284,511		265,774
Less incurred capital expenditures, excluding non-budgeted acquisition costs:
Oil and natural gas properties(2)	135,174		41,128		306,445		269,937
Midstream service assets(2)	567		1,103		2,422		2,697
Other fixed assets	1,685		495		3,229		3,092
Total incurred capital expenditures, excluding non-budgeted acquisition costs	137,426		42,726		312,096		275,726
Free Cash Flow (non-GAAP)	$	(19,895)	$	71,117	$	(27,585)	$	(9,952)

_____________________________________________________________________________

(1)In connection with the Working Interest Sale, $1.7 million of transaction expenses, which were recorded in the second quarter of 2021, have been reclassified to be presented net with the gain recorded on the sale of oil and natural gas properties for the nine months ended September 30, 2021. This resulted in a $1.7 million reclassification between operating cash flows and investing cash flows during the nine months ended September 30, 2021. See Note 1 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of this reclassification.

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

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

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methods, the book value of assets, capital structure and the method by which assets were acquired, among other factors;

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

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

There are significant limitations to the use of Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss 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 September 30,				Nine months ended September 30,
(in thousands)	2021		2020		2021		2020
Net income (loss)	$	136,832	$	(237,432)	$	(71,268)	$	(708,241)
Plus:
Share-settled equity-based compensation, net	1,811		2,041		5,609		6,111
Depletion, depreciation and amortization	62,678		47,015		140,763		174,891

Impairment expense	—		196,088		1,613		789,235
Gain on sale of oil and natural gas properties, net	(95,223)		—		(93,482)		—
Organizational restructuring expenses	—		—		9,800		4,200
Mark-to-market on derivatives:
(Gain) loss on derivatives, net	96,240		45,250		467,547		(162,049)
Settlements (paid) received for matured derivatives, net	(92,726)		51,840		(191,507)		186,435
Settlements received for early-terminated commodity derivatives, net	—		6,340		—		6,340
Net premiums paid for commodity derivatives that matured during the period(1)	(10,182)		—		(31,370)		(477)
Accretion expense	906		1,102		3,207		3,325
Loss on disposal of assets, net	22		607		28		1,057
Interest expense	30,406		26,828		82,222		78,870
Loss on extinguishment of debt	—		—		—		13,320
Write-off of debt issuance costs	—		—		—		1,103
Income tax expense (benefit)	2,677		(2,398)		593		(7,154)
Adjusted EBITDA (non-GAAP)	$	133,441	$	137,281	$	323,755	$	386,966

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(1)Reflects net premiums paid previously or upon settlement that are attributable to derivatives settled in the respective periods presented.

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.

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There have been no material changes in our critical accounting policies and procedures during the nine months ended September 30, 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 2020 Annual Report.

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. See Notes 4 and 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

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 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. By removing a portion of the price volatility associated with future sales volumes, we expect to mitigate, but not eliminate, the potential effects of variability in cash flows from operations.

The fair values of our open commodity derivative positions are largely determined by the relevant forward commodity price curves of the indexes associated with our open derivative positions. We had a $326.1 million net liability position from the fair values of our open commodity derivatives as of September 30, 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 derivative positions as of September 30, 2021:


(in thousands)	10% Increase		10% Decrease
Commodity	$	(116,873)	$	114,845

See Notes 9.a and 10.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our commodity derivatives.

Interest rate risk

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


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






January 2025 Notes	$	—		$	577.9		$	—
Fixed interest rate	—		%	9.500		%	—		%
January 2028 Notes	$	—		$	—		$	361.0
Fixed interest rate	—		%	—		%	10.125		%
July 2029 Notes	$	—		$	—		$	400.0
Fixed interest rate	—		%	—		%	7.750		%
Senior Secured Credit Facility	$	30.0		$	—		$	—
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 $0.1 million total liability position from the net fair value of our open interest rate derivative as of September 30, 2021. The following table provides a sensitivity analysis of the projected incremental effect on 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 September 30, 2021:


(in thousands)	1% incremental addition to		1% incremental subtraction from
Interest rate	$	578	$	(578)

See Notes 6, 10.c and 19.b and to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our debt. See Notes 9.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 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 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, 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, management 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. We routinely assess the recoverability of all material trade and other receivables to determine collectability.

See Notes 2.d and 14 in the 2020 Annual Report for additional discussion of our accounts receivable and revenue recognition, respectively.

Customer performance risk

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

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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.

Item 4. Controls and Procedures

Evaluation of disclosure controls and procedures

As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of Laredo's disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act), was performed under the supervision and with the participation of Laredo's management, including our principal executive officer and principal financial officer. Based on that evaluation, these officers concluded that Laredo's disclosure controls and procedures were effective as of September 30, 2021. Our disclosure controls and other procedures are designed to provide reasonable assurance that the information required to be disclosed in the reports we file and submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to Laredo's management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Evaluation of changes in internal control over financial reporting

There were no changes in our internal control over financial reporting during the quarter ended September 30, 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.

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 2020 Annual Report and Current Report on Form 8-K, filed with the SEC on May 11, 2021, and those set forth from time to time in our other filings with the SEC. 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 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.

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
July 1, 2021 - July 31, 2021	8,309	$	95.72	—	$	—
August 1, 2021 - August 31, 2021	—	$	—	—	$	—
September 1, 2021 - September 30, 2021	968	$	53.91	—	$	—
Total	9,277			—

______________________________________________________________________________

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

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

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.

Item 5. Other Information

Not applicable.

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Item 6. Exhibits

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

Exhibit

Description

Form

Exhibit

Filing Date

2.1#

Purchase and Sale Agreement, dated September 17 , 2021, by and among Laredo Petroleum, Inc., Pioneer Natural Resources USA, Inc., DE Midland III LLC, Parsley Minerals, LLC, and Parsley Energy, L.P.

8-K

2.1

9/20/2021

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

3.3

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

8-K

3.1

1/6/2014

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

4.2

Indenture, dated as of July 16, 2021, among Laredo Petroleum, Inc., Laredo Midstream Services, LLC, Garden City Minerals, LLC and Wells Fargo Bank, National Association, as trustee.

8-K

4.1

7/16/2021

10.1#

Purchase Agreement, dated July 13, 2021, among Laredo Petroleum, Inc., Laredo Midstream Services, LLC, Garden City Minerals, LLC and Wells Fargo Securities, LLC, as representative of the several initial purchasers named therein.

8-K

10.1

7/16/2021

10.2#

Seventh Amendment to the Fifth Amended and Restated Credit Agreement, dated as of July 16, 2021, 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

10.2

7/16/2021

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.

31.2*

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.

95.1*

Mine Safety Disclosures.

101

The following financial information from Laredo’s Quarterly Report on Form 10-Q for the quarter ended September 30, 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).

______________________________________________________________________________

* Filed herewith.

** Furnished herewith.

# Certain schedules and exhibits to this agreement have been omitted in accordance with Item 601(a)(5) of Regulation S-K. A copy of any omitted schedule and/or exhibit will be furnished to the Securities and Exchange Commission on request.

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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: November 4, 2021	By:	/s/ Jason Pigott
		Jason Pigott
		President and Chief Executive Officer
		(principal executive officer)

Date: November 4, 2021	By:	/s/ Bryan J. Lemmerman
		Bryan J. Lemmerman
		Senior Vice President and Chief Financial Officer
		(principal financial officer)

Date: November 4, 2021	By:	/s/ Jessica R. Wren
		Jessica R. Wren
		Senior Director of Financial Accounting and SEC Reporting
		(principal accounting officer)

Document

EXHIBIT 31.1

CERTIFICATION

I, Jason Pigott, certify that:

1.I have reviewed this Quarterly Report on Form 10-Q of Laredo Petroleum, Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


Date: November 4, 2021
			/s/ Jason Pigott
			Jason Pigott
			President and Chief Executive Officer

Document

EXHIBIT 31.2

CERTIFICATION

I, Bryan J. Lemmerman, certify that:

1.I have reviewed this Quarterly Report on Form 10-Q of Laredo Petroleum, Inc.;

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


Date: November 4, 2021
			/s/ Bryan J. Lemmerman
			Bryan J. Lemmerman
			Senior Vice President and Chief Financial Officer

Document

EXHIBIT 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, Jason Pigott, President and Chief Executive Officer of Laredo Petroleum, Inc. (the "Company"), and Bryan J. Lemmerman, Senior Vice President and Chief Financial Officer of the Company, certify that, to their knowledge:

(1)the Quarterly Report on Form 10-Q of the Company for the period ending September 30, 2021, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


November 4, 2021
			/s/ Jason Pigott
			Jason Pigott
			President and Chief Executive Officer


November 4, 2021
			/s/ Bryan J. Lemmerman
			Bryan J. Lemmerman
			Senior Vice President and Chief Financial Officer

Document

EXHIBIT 95.1

Mine Safety Disclosures

Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") and Item 104 of Regulation S-K (17 CFR 229.104) require certain disclosures by companies required to file periodic reports under the Securities Exchange Act of 1934, as amended, that operate mines regulated under the Federal Mine Safety and Health Act of 1977 (as amended by the Mine Improvement and New Emergency Response Act of 2006, the "Mine Act").

Laredo Petroleum, Inc., (“Laredo”), on April 15, 2020, acquired surface and sand rights on approximately 628 acres in Howard County, Texas, and in October 2020 entered into an agreement with Hi-Crush, Inc. and its subsidiary OnCore Processing, LLC (“OnCore”) to construct and operate an in-field sand mine to support Laredo’s exploration and development operations. Operations began in November 2020 and are subject to regulation by the U.S. Federal Mine Safety and Health Administration ("MSHA").

MSHA inspects mining facilities on a regular basis and issues various citations and orders when it believes a violation has occurred under the Mine Act. Citations and orders may be appealed with the potential of reduced or dismissed penalties. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Act and Item 104 of Regulation S-K (17 CFR 229.104) are outlined below.

Mine Safety Data

The following provides additional information about references used in the table below to describe the categories of violations, orders or citations issued by MSHA under the Mine Act:

•Section 104 Significant Substantial (“S&S”) Citations: Citations for violations of mandatory health or safety standards that could significantly and substantially contribute to the cause and effect of a mine safety or health hazard.

•Section 104(b) Orders: Orders which represents a failure to abate a citation under section 104(a) within the period of time prescribed by MSHA. This results in an order of immediate withdrawal from the area of the mine affected by the condition until MSHA determines that the violation has been abated.

•Section 104(d) Citations and Orders: Citations and orders for an unwarrantable failure to comply with mandatory health or safety standards.

•Section 110(b)(2) Violations: Flagrant violations.

•Section 107(a) Orders: Orders for situations in which MSHA determined an "imminent danger" (as defined by MSHA) existed.

•Notice of Pattern of Violations: Notice of a pattern of violations of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of mine health or safety hazards under section 104(e) of the Mine Act.

•Notice of Potential Pattern of Violations: Notice of the potential to have a pattern of violations under section 104(e).

•Pending Legal Actions: Legal actions before the Federal Mine Safety and Health Review Commission ("FMSHRC") initiated.

For the quarter ended September 30, 2021


Citation, Order, Violation or Action			OnCore(a)
Section 104 S&S citations (#)			None
Section 104(b) orders (#)			None
Section 104(d) citations and orders (#)			None
Section 110(b)(2) violations (#)			None


Citation, Order, Violation or Action			OnCore(a)
Section 107(a) orders (#)			None
Proposed assessments under MSHA ($)(b)			None
Mining-related fatalities (#)			None
Notice of pattern of violations (yes/no)			None
Notice of potential pattern of violations (yes/no)			None
Pending legal actions (#)			None

(a)The definition of mine under section 3 of the Mine Act includes the mine, as well as other items used in, or to be used in, or resulting from, the work of extracting minerals, such as land, structures, facilities, equipment, machines, tools and minerals preparation facilities. Unless otherwise indicated, any of these other items associated with a single mine have been aggregated in the totals for that mine. MSHA assigns an identification number to each mine and may or may not assign separate identification numbers to related facilities such as preparation facilities. We are providing the information in the table by mine rather than MSHA identification number because that is how we manage and operate our mining business and we believe this presentation will be more useful to investors than providing information based on MSHA identification numbers.

(b)Represents the total dollar value of the proposed assessment from MSHA under the Mine Act pursuant to the citations and/ or orders preceding such dollar value in the corresponding row.