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Vital Energy, Inc. - Quarter Report: 2021 March (Form 10-Q)


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 March 31, 2021
 or
☐     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)
Delaware45-3007926
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
15 W. Sixth Street Suite 900 
TulsaOklahoma74119
(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 classTrading symbolName of each exchange on which registered
Common stock, $0.01 par value per shareLPINew 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 May 3, 2021: 12,898,823


LAREDO PETROLEUM, INC.
TABLE OF CONTENTS
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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 from the COVID-19 pandemic and actions by the Organization of the Petroleum Exporting Countries members and other oil exporting nations ("OPEC+");
•the volatility of oil, NGL and natural gas prices, including in our area of operation in the Permian Basin;
•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;
•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;
•capital requirements for our operations and projects;
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•our ability to continue to maintain the borrowing capacity under our Fifth Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility") or access other means of obtaining capital and liquidity, especially during periods of sustained low commodity prices;
•our ability to comply with restrictions contained in our debt agreements, including our Senior Secured Credit Facility and the indentures governing our senior unsecured notes, as well as debt that could be incurred in the future;
•our ability to generate sufficient cash to service our indebtedness, fund our capital requirements and generate future profits;
•our ability to hedge, and regulations that affect our ability to hedge;
•the availability and costs of drilling and production equipment, supplies, labor and oil and natural gas processing and other services;
•the availability and costs of sufficient 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 those set forth from time to time in our other filings with the Securities and Exchange Commission (the "SEC"). These documents are available through our website or through the SEC's Electronic Data Gathering and Analysis Retrieval system at http://www.sec.gov. In light of such risks and uncertainties, we caution you not to place undue reliance on these forward-looking statements. These forward-looking statements speak only as of the date of this Quarterly Report, or if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities law.
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Part I

Item 1.    Consolidated Financial Statements (Unaudited)

Laredo Petroleum, Inc.
Consolidated balance sheets
(in thousands, except share data)
(Unaudited)
  March 31, 2021December 31, 2020
Assets  
Current assets:  
Cash and cash equivalents$44,262 $48,757 
Accounts receivable, net67,704 63,976 
Derivatives— 7,893 
Other current assets26,123 15,964 
Total current assets138,089 136,590 
Property and equipment: 
Oil and natural gas properties, full cost method: 
Evaluated properties7,953,141 7,874,932 
Unevaluated properties not being depleted60,260 70,020 
Less accumulated depletion and impairment(6,852,688)(6,817,949)
Oil and natural gas properties, net1,160,713 1,127,003 
Midstream service assets, net111,083 112,697 
Other fixed assets, net31,576 32,011 
Property and equipment, net1,303,372 1,271,711 
Operating lease right-of-use assets14,955 17,973 
Other noncurrent assets, net18,487 16,336 
Total assets$1,474,903 $1,442,610 
Liabilities and stockholders' equity 
Current liabilities: 
Accounts payable and accrued liabilities$49,065 $38,279 
Accrued capital expenditures27,924 28,275 
Undistributed revenue and royalties32,018 24,728 
Derivatives128,394 31,826 
Operating lease liabilities11,263 11,721 
Other current liabilities43,579 62,766 
Total current liabilities292,243 197,595 
Long-term debt, net1,145,374 1,179,266 
Derivatives29,821 12,051 
Asset retirement obligations66,280 64,775 
Operating lease liabilities6,459 8,918 
Other noncurrent liabilities3,294 1,448 
Total liabilities1,543,471 1,464,053 
Commitments and contingencies
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of March 31, 2021 and December 31, 2020
— — 
Common stock, $0.01 par value, 22,500,000 shares authorized and 12,899,660 and 12,020,164 issued and outstanding as of March 31, 2021 and December 31, 2020, respectively
129 120 
Additional paid-in capital2,426,769 2,398,464 
Accumulated deficit(2,495,466)(2,420,027)
Total stockholders' equity(68,568)(21,443)
Total liabilities and stockholders' equity$1,474,903 $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 March 31,
 20212020
Revenues:
Oil sales$127,701 $119,978 
NGL sales41,678 11,558 
Natural gas sales33,078 4,349 
Midstream service revenues1,296 2,683 
Sales of purchased oil46,477 66,424 
Total revenues250,230 204,992 
Costs and expenses:
Lease operating expenses18,918 22,040 
Production and ad valorem taxes13,283 9,244 
Transportation and marketing expenses12,127 13,544 
Midstream service expenses858 1,170 
Costs of purchased oil49,916 79,297 
General and administrative13,073 12,562 
Depletion, depreciation and amortization38,109 61,302 
Impairment expense— 186,699 
Other operating expenses1,143 1,106 
Total costs and expenses147,427 386,964 
Operating income (loss)102,803 (181,972)
Non-operating income (expense):
Gain (loss) on derivatives, net(154,365)297,836 
Interest expense(25,946)(24,970)
Loss on extinguishment of debt— (13,320)
Loss on disposal of assets, net(72)(602)
Other income, net1,379 91 
Total non-operating income (expense), net(179,004)259,035 
Income (loss) before income taxes
(76,201)77,063 
Income tax benefit (expense):
Deferred762 (2,417)
Total income tax benefit (expense)762 (2,417)
Net income (loss)$(75,439)$74,646 
Net income (loss) per common share (1):
Basic$(6.33)$6.43 
Diluted$(6.33)$6.39 
Weighted-average common shares outstanding(1):
Basic11,918 11,618 
Diluted11,918 11,673 
______________________________________________________________________________
(1)For the three months ended March 31, 2020, net income per common share and weighted-average common shares outstanding were retroactively adjusted for the Company's 1-for-20 reverse stock split effective June 1, 2020 as discussed in Note 7.b.
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 stockAdditional
paid-in capital		Treasury stock
(at cost)		Accumulated deficit 
 SharesAmountSharesAmountTotal
Balance, December 31, 202012,020 $120 $2,398,464 — $— $(2,420,027)$(21,443)
Restricted stock awards188 2 (2)— — — — 
Restricted stock forfeitures(1)— — — — — — 
Stock exchanged for tax withholding— — — 37 (1,290)— (1,290)
Retirement of treasury stock(37)— (1,290)(37)1,290 — — 
Share-settled equity-based compensation— — 2,738 — — — 2,738 
Issuance of common stock, net of costs724 7 26,859 — — — 26,866 
Performance share conversion6 — — — — — — 
Net loss— — — — — (75,439)(75,439)
Balance, March 31, 202112,900 $129 $2,426,769 — $— $(2,495,466)$(68,568)
Common stockAdditional
paid-in capital		Treasury stock
(at cost)		Accumulated deficit
Shares (1)
Amount
Shares (1)
AmountTotal
Balance, December 31, 201911,865 $2,373 $2,385,355 — $— $(1,545,854)$841,874 
Restricted stock awards138 28 (28)— — — — 
Restricted stock forfeitures(7)(2)2 — — — — 
Stock exchanged for tax withholding— — — 26 (640)— (640)
Retirement of treasury stock(26)(5)(635)(26)640 — — 
Share-settled equity-based compensation— — 3,341 — — — 3,341 
Net income— — — — — 74,646 74,646 
Balance, March 31, 202011,970 $2,394 $2,388,035 — $— $(1,471,208)$919,221 
______________________________________________________________________________
(1) Shares presented were retroactively adjusted for the Company's 1-for-20 reverse stock split effective June 1, 2020 as discussed in Note 7.b.
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)
  Three months ended March 31,
  20212020
Cash flows from operating activities:
  
Net income (loss)$(75,439)$74,646 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Share-settled equity-based compensation, net2,068 2,376 
Depletion, depreciation and amortization38,109 61,302 
Impairment expense— 186,699 
Mark-to-market on derivatives:
(Gain) loss on derivatives, net154,365 (297,836)
Settlements (paid) received for matured derivatives, net(41,174)47,723 
Premiums received (paid) for commodity derivatives9,041 (477)
Amortization of debt issuance costs989 1,217 
Amortization of operating lease right-of-use assets2,997 4,377 
Loss on extinguishment of debt— 13,320 
Deferred income tax (benefit) expense(762)2,417 
Other, net1,491 1,327 
Changes in operating assets and liabilities:
Accounts receivable, net(3,728)9,635 
Other current assets(10,264)4,033 
Other noncurrent assets, net(1,636)(2,964)
Accounts payable and accrued liabilities9,065 25,059 
Undistributed revenue and royalties7,290 (4,937)
Other current liabilities(19,622)(15,082)
Other noncurrent liabilities(1,639)(3,246)
Net cash provided by operating activities71,151 109,589 
Cash flows from investing activities:
Acquisitions of oil and natural gas properties, net— (22,876)
Capital expenditures:
Oil and natural gas properties(68,329)(135,376)
Midstream service assets(329)(761)
Other fixed assets(551)(829)
Proceeds from dispositions of capital assets, net of selling costs189 51 
Net cash used in investing activities(69,020)(159,791)
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility15,000 — 
Payments on Senior Secured Credit Facility(50,000)(100,000)
Issuance of January 2025 Notes and January 2028 Notes— 1,000,000 
Extinguishment of debt— (808,855)
Proceeds from issuance of common stock, net of costs26,866 — 
Stock exchanged for tax withholding(1,290)(640)
Payments for debt issuance costs— (18,383)
Other liabilities2,798 — 
Net cash (used in) provided by financing activities(6,626)72,122 
Net (decrease) increase in cash and cash equivalents(4,495)21,920 
Cash and cash equivalents, beginning of period48,757 40,857 
Cash and cash equivalents, end of period$44,262 $62,777 
 The accompanying notes are an integral part of these unaudited consolidated financial statements.

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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 March 31, 2021, results of operations for the three months ended March 31, 2021 and 2020 and cash flows for the three months ended March 31, 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.
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 at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ.
See Note 2.b in the 2020 Annual Report for further information regarding the use of estimates and assumptions.
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 March 31, 2021.
Note 3—Acquisitions and divestiture
a.    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
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Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
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.
b.    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.
c.    Exchange of unevaluated oil and natural gas properties
From time to time, the Company exchanges undeveloped acreage with third parties. The exchanges are recorded at fair value and the difference is accounted for as an adjustment of capitalized costs with no gain or loss recognized pursuant to the rules governing full cost accounting, unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas.
Note 4—Leases
The Company has recognized operating lease right-of-use assets and operating lease liabilities on the unaudited consolidated balance sheets for leases of commercial real estate with lease terms extending into 2027 and drilling, completion, production and other equipment leases with lease terms extending into 2022. The Company's lease costs include those that are recognized in net income (loss) during the period and capitalized as part of the cost of another asset in accordance with GAAP.
The lease costs related to drilling, completion and production activities are reflected at the Company's net ownership, which is consistent with the principles of proportional consolidation, and lease commitments are reflected on a gross basis. As of March 31, 2021, the Company had an average working interest of 97% in Laredo-operated active productive wells. See Note 5 in the 2020 Annual Report for additional discussion of the Company's leases.
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Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
Note 5—Property and equipment
The following table presents the Company's property and equipment as of the dates presented:
(in thousands)March 31, 2021December 31, 2020
Evaluated oil and natural gas properties$7,953,141 $7,874,932 
Less accumulated depletion and impairment(6,852,688)(6,817,949)
Evaluated oil and natural gas properties, net1,100,453 1,056,983 
Unevaluated oil and natural gas properties not being depleted60,260 70,020 
Midstream service assets182,405 181,718 
Less accumulated depreciation and impairment(71,322)(69,021)
Midstream service assets, net111,083 112,697 
Depreciable other fixed assets37,612 37,454 
Less accumulated depreciation and amortization(24,937)(24,344)
Depreciable other fixed assets, net12,675 13,110 
Land18,901 18,901 
Total property and equipment, net$1,303,372 $1,271,711 
See Note 10.b for discussion of impairments of long-lived assets during the three months ended March 31, 2020. 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 costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion.
Sales of oil and natural gas properties, whether or not being depleted currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas.

7
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
The following table presents costs incurred in the acquisition, exploration and development of oil and natural gas properties, with asset retirement obligations included in evaluated property acquisition costs and development costs, for the periods presented:
 Three months ended March 31,
(in thousands)20212020
Property acquisition costs:   
Evaluated$—  $7,586 
Unevaluated— 15,556 
Exploration costs3,957 6,710 
Development costs64,492 146,158 
Total oil and natural gas properties costs incurred$68,449 $176,010 
The aforementioned total oil and natural gas properties costs incurred included certain employee-related costs as shown in the table below.
The following table presents capitalized employee-related costs incurred in the acquisition, exploration and development of oil and natural gas properties for the periods presented:
Three months ended March 31,
(in thousands)20212020
Capitalized employee-related costs$4,241 $4,505 
The following table presents depletion expense, which is included in "Depletion, depreciation and amortization" on the unaudited consolidated statements of operations, and depletion expense per BOE sold of evaluated oil and natural gas properties for the periods presented:
Three months ended March 31,
(in thousands except per BOE data)20212020
Depletion expense of evaluated oil and natural gas properties$34,725 $57,752 
Depletion expense per BOE sold$4.88 $7.33 
The full cost ceiling is based principally on the estimated future net cash flows from proved oil, NGL and natural gas reserves, which exclude the effect of the Company's commodity derivative transactions, discounted at 10%. SEC guidelines require companies to use the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period before differentials ("Benchmark Prices"). The Benchmark Prices are then adjusted for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point ("Realized Prices") without giving effect to the Company's commodity derivative transactions. The Realized Prices are utilized to calculate the estimated future net cash flows in the full cost ceiling calculation. Significant inputs included in the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of operating and development costs, anticipated production of proved reserves and other relevant data. In the event the unamortized cost of evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, as defined by the SEC, the excess is expensed in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible. The unamortized cost of evaluated oil and natural gas properties being depleted did not exceed the full cost ceiling as of March 31, 2021, and as such, the Company did not record a first-quarter full cost ceiling impairment.
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Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
The following table presents the Benchmark Prices and the Realized Prices as of the dates presented:
March 31, 2021December 31, 2020September 30, 2020June 30, 2020
Benchmark Prices:
   Oil ($/Bbl)$36.49 $36.04 $39.88 $43.60 
   NGL ($/Bbl)(1)
$19.24 $16.63 $16.95 $16.87 
   Natural gas ($/MMBtu)$1.69 $1.21 $1.06 $0.87 
Realized Prices:
   Oil ($/Bbl)$38.28 $37.69 $41.08 $44.97 
   NGL ($/Bbl)$9.92 $7.43 $7.71 $7.66 
   Natural gas ($/Mcf)$1.20 $0.79 $0.68 $0.53 
_____________________________________________________________________________
(1)    Based on the Company's average composite NGL barrel.
The following table presents full cost ceiling impairment expense, which is included in "Impairment expense" on the unaudited consolidated statements of operations for the periods presented:
Three months ended March 31,
(in thousands)20212020
Full cost ceiling impairment expense$— $177,182 
Note 6—Debt
a.   January 2025 Notes and January 2028 Notes
On January 24, 2020, the Company completed an offer and sale (the "Offering") of $600.0 million in aggregate principal amount of 9 1/2% senior unsecured notes due 2025 (the "January 2025 Notes") and $400.0 million in aggregate principal amount of 10 1/8% senior unsecured notes due 2028 (the "January 2028 Notes"). Interest for both the January 2025 Notes and January 2028 Notes is payable semi-annually, in cash in arrears on January 15 and July 15 of each year. The first interest payment was made on July 15, 2020, and consisted of interest from closing to that date. The terms of the January 2025 Notes and January 2028 Notes include covenants, which are in addition to but different than similar covenants in the Senior Secured Credit Facility, which limit the Company's ability to incur indebtedness, make restricted payments, grant liens and dispose of assets.
The January 2025 Notes and January 2028 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain automatic customary releases, including the sale, disposition or transfer of all of the capital stock or of all or substantially all of the assets of a subsidiary guarantor to one or more persons that are not the Company or a restricted subsidiary, exercise of legal defeasance or covenant defeasance options or satisfaction and discharge of the applicable indenture, designation of a subsidiary guarantor as a non-guarantor 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 $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
9
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
of $22.3 million related to the difference between the consideration paid and the net carrying amounts of the extinguished portions of the January 2025 Notes and January 2028 Notes.
b.   January 2022 Notes and March 2023 Notes
On January 23, 2014, the Company completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior unsecured notes due 2022 (the "January 2022 Notes"). The January 2022 Notes were due to mature on January 15, 2022 and bore an interest rate of 5 5/8% per annum, payable semi-annually, in cash in arrears on January 15 and July 15 of each year, commencing July 15, 2014. The January 2022 Notes were fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases.
On March 18, 2015, the Company completed an offering of $350.0 million in aggregate principal amount of 6 1/4% senior unsecured notes due 2023 (the "March 2023 Notes"). The March 2023 Notes were due to mature on March 15, 2023 and bore an interest rate of 6 1/4% per annum, payable semi-annually, in cash in arrears on March 15 and September 15 of each year, commencing September 15, 2015. The March 2023 Notes were fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases.
On January 6, 2020, the Company commenced cash tender offers and consent solicitations for any or all of its outstanding January 2022 Notes and March 2023 Notes (collectively, the "Tender Offers"). On January 24, 2020 and February 6, 2020, the Company settled the Tender Offers for the outstanding principal amounts of $428.9 million and $299.4 million, respectively, for consideration for tender offers and early tender premiums of $431.6 million and $304.1 million for the January 2022 Notes and March 2023 Notes, respectively, plus accrued and unpaid interest. On January 29, 2020, the Company redeemed the remaining $21.1 million of January 2022 Notes not tendered under the Tender Offers at a redemption price of 100.000% of the principal amount thereof, plus accrued and unpaid interest. On March 15, 2020, the Company redeemed the remaining $50.6 million of March 2023 Notes not tendered under the Tender Offers at a redemption price of 101.563% of the principal amount thereof, plus accrued and unpaid interest. The Company recognized a loss on extinguishment of $13.3 million related to the difference between the consideration for tender offers, early tender premiums and redemption prices and the net carrying amounts of the extinguished January 2022 Notes and March 2023 Notes.
c.    Senior Secured Credit Facility
As of March 31, 2021, the Senior Secured Credit Facility, which matures on April 19, 2023, had a maximum credit amount of $2.0 billion, a borrowing base and an aggregate elected commitment of $725.0 million each, with $220.0 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 the Company was in compliance with for all periods presented. Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $80.0 million. As of March 31, 2021 and December 31, 2020, the Company 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. For additional information see Note 7.c in the 2020 Annual Report. See Note 18.a for discussion of a borrowing and a payment on the Senior Secured Credit Facility subsequent to March 31, 2021.
The Company's measurements of Adjusted EBITDA (non-GAAP) for financial reporting as compared to compliance under its debt agreements differ.
d.    Debt issuance costs
The Company capitalized debt issuance costs of $18.4 million during the three months ended March 31, 2020 in connection with the issuance of the January 2025 Notes and January 2028 Notes. No debt issuance costs were capitalized during the three months ended March 31, 2021. The Company wrote off debt issuance costs during the three months ended March 31, 2020 in connection with the extinguishment of the January 2022 Notes and March 2023 Notes, which are included in "Loss on extinguishment of debt" on the unaudited consolidated statement of operations. No debt issuance costs were written off during the three months ended March 31, 2021.
The Company had total debt issuance costs of $15.7 million and $17.0 million, net of accumulated amortization of $23.1 million and $22.1 million, as of March 31, 2021 and December 31, 2020, respectively. Debt issuance costs related to the Company's January 2025 and January 2028 Notes are included in "Long-term debt, net" on the unaudited consolidated balance sheets. Debt issuance costs related to the Senior Secured Credit Facility are included in "Other noncurrent assets, net"
10
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
on the unaudited consolidated balance sheets. Debt issuance costs are amortized on a straight-line basis over the respective terms of the notes and the Senior Secured Credit Facility. See Note 7.e for additional discussion of debt issuance costs.
e.    Long-term debt, net
The following table presents the Company's long-term debt and debt issuance costs, net included in "Long-term debt, net" on the unaudited consolidated balance sheets as of the dates presented:
 March 31, 2021December 31, 2020
(in thousands)Long-term debtDebt issuance costs, netLong-term debt, netLong-term debtDebt issuance costs, netLong-term debt, net
January 2025 Notes577,913 (7,931)569,982 577,913 (8,676)569,237 
January 2028 Notes361,044 (5,652)355,392 361,044 (6,015)355,029 
Senior Secured Credit Facility(1)
220,000 — 220,000 255,000 — 255,000 
Long-term debt, net $1,158,957 $(13,583)$1,145,374 $1,193,957 $(14,691)$1,179,266 
______________________________________________________________________________
(1)Debt issuance costs, net related to the Senior Secured Credit Facility of $2.1 million and $2.3 million as of March 31, 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 March 31, 2021, the Company has sold 723,579 shares of its common stock pursuant to the ATM Program for net proceeds of approximately $26.9 million, after underwriting commissions and other related expenses. Proceeds from the share sales were utilized to reduce borrowings on the Senior Secured Credit Facility. The timing of any additional sales will depend on a variety of factors to be determined by the Company.
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.
11
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
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 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.
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 three months ended March 31, 2021:
(in thousands, except for weighted-average grant-date fair value)Restricted stock awardsWeighted-average
grant-date fair value
 (per share)
Outstanding as of December 31, 2020309 $44.88 
Granted188 $34.45 
Forfeited(1)$83.04 
Vested(1)
(103)$65.07 
Outstanding as of March 31, 2021393 $34.50 
_____________________________________________________________________________
(1)The aggregate intrinsic value of vested restricted stock awards for the three months ended March 31, 2021 was $3.5 million.
The Company utilizes the closing stock price on the grant date to determine the fair value of restricted stock awards. As of March 31, 2021, unrecognized equity-based compensation related to the restricted stock awards expected to vest was $11.9 million. Such cost is expected to be recognized over a weighted-average period of 2.18 years.
b.    Stock option awards
As of March 31, 2021, the 11,362 outstanding stock option awards had a weighted-average exercise price of $257.42 per award and a weighted-average remaining contractual term of 3.75 years. There was no activity related to the stock option awards during the three months ended March 31, 2021. The vested and exercisable stock option awards as of March 31, 2021 had no intrinsic value.
12
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
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 three months ended March 31, 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, 202097 $84.06 
Vested(1)
(15)$184.43 
Outstanding as of March 31, 202182 $65.98 
______________________________________________________________________________
(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 three months ended March 31, 2021 based on this 43% payout.
As of March 31, 2021, unrecognized equity-based compensation related to the performance share awards expected to vest was $2.2 million. Such cost is expected to be recognized over a weighted-average period of 0.92 years. As of March 31, 2021, the expense per performance share, which is the fair value per performance share adjusted for the estimated payout of the performance criteria, was $88.16.
d.    Outperformance share award
An outperformance share award was granted during the year ended December 31, 2019, in conjunction with the appointment of the Company's President, and is accounted for as an equity award. 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 March 31, 2021, unrecognized equity-based compensation related to the outperformance share award expected to vest was $0.4 million. Such cost is expected to be recognized over a weighted-average period of 3.25 years.
13
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
e.    Performance unit awards
Performance unit awards, which the Company has determined are liability awards since they are settled in cash, are subject to a combination of market, performance and service vesting criteria. For portions of awards with market criteria, 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.

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 period2.81 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 three months ended March 31, 2021:
(in thousands)Performance units
Outstanding as of December 31, 202099 
Granted110 
Outstanding as of March 31, 2021209 
14
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
As of March 31, 2021, unrecognized equity-based compensation related to the performance unit awards expected to vest was $7.0 million. Such cost is expected to be recognized over a weighted-average period of 2.62 years. As of March 31, 2021, the expense per performance unit, which is the fair value per performance unit adjusted for the estimated payout of the performance criteria, for the 2021 and 2020 performance unit awards was $39.77 and $41.82, respectively.
f.    Phantom unit awards
Phantom unit awards, which the Company has determined are liability awards, represent the holder's right to receive the cash equivalent of one share of common stock of the Company for each phantom unit as of the applicable vesting date, subject to withholding requirements. Phantom unit awards granted to employees vest 33%, 33% and 34% per year beginning on the first anniversary of the grant date.
The following table reflects the phantom unit award activity for the three months ended March 31, 2021:
(in thousands, except for weighted-average fair value)Phantom units
Outstanding as of December 31, 202075 
Granted5 
Vested(1)
(25)
Outstanding as of March 31, 202155 
______________________________________________________________________________
(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 March 31, 2021, unrecognized equity-based compensation related to the phantom unit awards expected to vest was $1.6 million. Such cost is expected to be recognized over a weighted-average period of 2.08 years.
g.    Equity-based compensation
The following table reflects equity-based compensation expense for the periods presented:
Three months ended March 31,
(in thousands)20212020
Equity awards:
Restricted stock awards$1,963 $2,498 
Performance share awards725 756 
Outperformance share award43 44 
Stock option awards7 43 
Total share-settled equity-based compensation, gross$2,738 $3,341 
Less amounts capitalized(670)(965)
Total share-settled equity-based compensation, net$2,068 $2,376 
Liability awards:
Performance unit awards$820 $24 
Phantom unit awards506 25 
Total cash-settled equity-based compensation, gross$1,326 $49 
Less amounts capitalized (198)(10)
Total cash-settled equity-based compensation, net$1,128 $39 
Total equity-based compensation, net$3,196 $2,415 
15
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
Note 9—Derivatives
The Company has three types of derivative instruments as of March 31, 2021: (i) commodity derivatives, (ii) a debt interest rate derivative and (iii) a contingent consideration derivative. See Notes (i) 2.e in the 2020 Annual Report for the Company's significant accounting policies for derivatives and presentation, (ii) 10.a for fair value measurement of derivatives on a recurring basis and (iii) 18.b for derivatives subsequent events. The Company's derivatives were not designated as hedges for accounting purposes, and the Company does not enter into such instruments for speculative trading purposes. Accordingly, the changes in fair value are recognized in "Gain (loss) on derivatives, net" under "Non-operating income (expense)" on the unaudited consolidated statements of operations.
The following table summarizes components of the Company's gain (loss) on derivatives, net by type of derivative instrument for the periods presented:
Three months ended March 31,
(in thousands)20212020
Commodity$(154,033)$291,361 
Interest rate4 — 
Contingent consideration(336)6,475 
Gain (loss) on derivatives, net$(154,365)$297,836 
a.    Commodity
Due to the inherent volatility in oil, NGL and natural gas prices and differences in the prices of oil, NGL and natural gas between where the Company produces and where the Company sells such commodities, the Company engages in commodity derivative transactions, such as puts, swaps, collars and basis swaps, to hedge price risk associated with a portion of the Company's anticipated sales volumes. By removing a portion of the price volatility associated with future sales volumes, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations. See Note 9 in the 2020 Annual Report for discussion of transaction types and settlement indexes.
During the three months ended March 31, 2021, the Company’s derivatives were settled based on reported prices on commodity exchanges, with (i) oil derivatives settled based on Brent ICE pricing, (ii) NGL derivatives settled based on Mont Belvieu OPIS pricing and (iii) natural gas derivatives settled based on Henry Hub NYMEX and Waha Inside FERC pricing.
During the three months ended March 31, 2021, the Company completed a hedge restructuring by (i) selling 2,254,500 calendar year 2021 $55.00 per barrel Brent ICE puts, which volumetrically offset existing calendar year 2021 $55.00 per barrel Brent ICE puts, and receiving aggregate premiums of $9.0 million at inception of the contracts and (ii) entering into 2,254,500 calendar year 2021 Brent ICE swaps at a weighted-average price of $55.09 per barrel. Associated with the aforementioned existing calendar year 2021 $55.00 per barrel Brent ICE puts, which were entered into during 2020, were $50.6 million in aggregate premiums paid at the inception of the contacts.
During the three months ended March 31, 2020, the Company completed a hedge restructuring by early terminating collars and entering into new swaps. The following table presents the commodity derivatives that were terminated:
Aggregate volumes (Bbl)Floor price ($/Bbl)Ceiling price ($/Bbl)Contract period
WTI NYMEX - Collars912,500 $45.00 $71.00 January 2021 - December 2021
16
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
The following table summarizes open commodity derivative positions as of March 31, 2021, for commodity derivatives that were entered into through March 31, 2021, for the settlement periods presented:
 Remaining Year 2021Year 2022
Oil: 
Brent ICE - Swaps:
Volume (Bbl)5,651,250 3,759,500 
Weighted-average price ($/Bbl)$51.29 $47.05 
Brent ICE - Collars: 
Volume (Bbl)440,000 821,250 
Weighted-average floor price ($/Bbl)$45.00 $53.67 
Weighted-average ceiling price ($/Bbl)$59.50 $62.40 
Total Brent ICE:
Total volume (Bbl)6,091,250 4,580,750 
Weighted-average floor price ($/Bbl)$50.83 $48.24 
Weighted-average ceiling price ($/Bbl)$51.88 $49.81 
NGL:
Mont Belvieu OPIS:
Purity Ethane - Swaps:
Volume (Bbl)687,500 — 
Weighted-average price ($/Bbl)$12.01 $— 
Non-TET Propane - Swaps:
Volume (Bbl)1,825,725 — 
Weighted-average price ($/Bbl)$22.90 $— 
Non-TET Normal Butane - Swaps:
Volume (Bbl)608,575 — 
Weighted-average price ($/Bbl)$25.87 $— 
Non-TET Isobutane - Swaps:
Volume (Bbl)166,100 — 
Weighted-average price ($/Bbl)$26.55 $— 
Non-TET Natural Gasoline - Swaps:
Volume (Bbl)663,850 — 
Weighted-average price ($/Bbl)$38.16 $— 
Total NGL volume (Bbl)3,951,750 — 
Natural gas: 
Henry Hub NYMEX - Swaps: 
Volume (MMBtu)32,037,500 3,650,000 
Weighted-average price ($/MMBtu)$2.59 $2.73 
Waha Inside FERC to Henry Hub NYMEX - Basis Swaps: 
Volume (MMBtu)42,680,000 18,067,500 
Weighted-average differential ($/MMBtu)$(0.47)$(0.41)


17
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
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 rateContract period
LIBOR - Swap$100,000 0.345 %April 16, 2020 - April 18, 2022
c.    Contingent consideration
The Company's asset acquisition of oil and natural gas properties that closed on April 30, 2020 provides for potential contingent payments to be paid by the Company if the arithmetic average of the monthly settlement WTI NYMEX prices exceed certain thresholds for the contingency period beginning on January 1, 2021 and ending on the earlier of December 31, 2022 or the date the counterparty has received the maximum consideration of $1.2 million. See Note 3.a for further discussion of the Company's asset acquisition associated with potential contingent consideration payments. At each quarterly reporting period, the Company remeasures its contingent consideration with the changes in fair values recognized in earnings.
18
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
Note 10—Fair value measurements
See the beginning of Note 11 in the 2020 Annual Report for information about the fair value hierarchy levels.
a.    Fair value measurement on a recurring basis
See Note 9 for further discussion of the Company's derivatives, and see Note 2.e in the 2020 Annual Report for the Company's significant accounting policies for derivatives.
Balance sheet presentation
The following tables present the Company's derivatives by (i) balance sheet classification, (ii) derivative type and (iii) fair value hierarchy level, and provide a total, on a gross basis and a net basis reflected in "Derivatives" on the unaudited consolidated balance sheets as of the dates presented:
March 31, 2021
(in thousands)Level 1Level 2Level 3Total gross fair valueAmounts offsetNet fair value presented on the unaudited consolidated balance sheets
Assets:
Current:
Commodity - Oil$— $6,197 $— $6,197 $(6,197)$— 
Commodity - NGL— 1,735 — 1,735 (1,735)— 
Commodity - Natural gas— (195)— (195)195 — 
Noncurrent:
Commodity - Oil$— $3,928 $— $3,928 $(3,928)$— 
Commodity - NGL— — — — — — 
Commodity - Natural gas— 545 — 545 (545)— 
Liabilities:
Current:
Commodity - Oil$— $(73,960)$— $(73,960)$6,197 $(67,763)
Commodity - NGL— (39,133)— (39,133)1,735 (37,398)
Commodity - Natural gas— (21,726)— (21,726)(195)(21,921)
Interest rate - LIBOR— (197)— (197)— (197)
Contingent consideration— (1,115)— (1,115)— (1,115)
Noncurrent:
Commodity - Oil$— $(32,534)$— $(32,534)$3,928 $(28,606)
Commodity - NGL— — — — — — 
Commodity - Natural gas— (1,746)— (1,746)545 (1,201)
Interest rate - LIBOR— (13)— (13)— (13)
Contingent consideration— (1)— (1)— (1)
Net derivative liability positions$— $(158,215)$— $(158,215)$— $(158,215)
19
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
December 31, 2020
(in thousands)Level 1Level 2Level 3Total gross fair valueAmounts offsetNet fair value presented on the
consolidated balance sheets
Assets:
Current:
Commodity - Oil$— $32,958 $— $32,958 $(24,930)$8,028 
Commodity - NGL— 2,720 — 2,720 (2,720)— 
Commodity - Natural gas— 521 — 521 (656)(135)
Noncurrent:
Commodity - Oil$— $— $— $— $— $— 
Commodity - NGL— — — — — — 
Commodity - Natural gas— 535 — 535 (535)— 
Liabilities:
Current:
Commodity - Oil$— $(25,118)$— $(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 Company's acquisition of oil and natural gas properties that closed on April 30, 2020 provides for potential contingent payments to be paid by the Company. The fair value of the contingent consideration derivative liability was $1.1 million and $0.8 million as of March 31, 2021 and December 31, 2020, respectively. See Note 3.a for further discussion of the Company's asset acquisition associated with the potential contingent consideration payments.
b.    Fair value measurement on a nonrecurring basis
See Note 2.i in the 2020 Annual Report for the Level 2 fair value hierarchy input assumptions used in estimating the net realizable value ("NRV") of inventory used to determine the $1.3 million impairment expense of inventory recorded during the three months ended March 31, 2020, pertaining to line-fill and other inventories. There were no impairments of inventory recorded during the three months ended March 31, 2021.
See Note 11.b in the 2020 Annual Report for the Level 3 fair value hierarchy input assumptions used in the fair value measurement of long-lived assets used to determine the $8.2 million impairment expense of long-lived assets recorded during the three months ended March 31, 2020, pertaining to midstream service assets. There were no impairments of long-lived assets recorded during the three months ended March 31, 2021.
20
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
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:
 March 31, 2021December 31, 2020
(in thousands)Long-term
debt
Fair
value(1)
Long-term
debt
Fair
value(1)
January 2025 Notes$577,913 $556,288 $577,913 $499,299 
January 2028 Notes361,044 346,064 361,044 299,667 
Senior Secured Credit Facility220,000 220,130 255,000 255,187 
Total$1,158,957 $1,122,482 $1,193,957 $1,054,153 
______________________________________________________________________________
(1)The fair values of the outstanding notes were determined using the Level 1 fair value hierarchy quoted market prices for each respective instrument as of March 31, 2021 and December 31, 2020. The fair values of the outstanding debt under the Senior Secured Credit Facility were estimated utilizing the Level 2 fair value hierarchy pricing model for similar instruments as of March 31, 2021 and December 31, 2020.
Note 11—Net income (loss) per common share
Basic and diluted net income (loss) per common share are computed by dividing net income (loss) by the weighted-average common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution of non-vested restricted stock awards, outstanding stock option awards, non-vested performance share awards and the non-vested outperformance share award. See Note 8 for additional discussion of these awards. For the three months ended March 31, 2021, all of these awards were anti-dilutive due to the Company's net loss and, therefore, were excluded from the calculation of diluted net loss per common share. The dilutive effects of these awards were calculated utilizing the treasury stock method for the three months ended March 31, 2020.
The following table reflects the calculations of basic and diluted (i) weighted-average common shares outstanding and (ii) net income (loss) per common share for the periods presented:
Three months ended March 31,
(in thousands, except for per share data)20212020
Net income (loss) (numerator)$(75,439)$74,646 
Weighted-average common shares outstanding (denominator)(1):
Basic 11,918 11,618 
Diluted11,918 11,673 
Net income (loss) per common share(1):
Basic$(6.33)$6.43 
Diluted$(6.33)$6.39 
_____________________________________________________________________________
(1)For the three months ended March 31, 2020, shares and per share data have been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 7.b.
21
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
Note 12—Commitments and contingencies
a.    Litigation
From time to time, the Company is subject to various legal proceedings arising in the ordinary course of business, including proceedings for which the Company may not have insurance coverage. While many of these matters involve inherent uncertainty, as of the date hereof, the Company does not currently believe that any such legal proceedings will have a material adverse effect on the Company's business, financial position, results of operations or liquidity.
b.    Drilling rig contract
The Company 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 three months ended March 31, 2021 or 2020. As these drilling rig contracts are operating leases, the present value of the future commitment as of March 31, 2021 related to the drilling rig contract with an initial term greater than 12 months is included in current and noncurrent "Operating lease liabilities" on the unaudited consolidated balance sheet as of March 31, 2021. The future commitment of $1.7 million as of March 31, 2021 related to the drilling rig contract with an initial term less than 12 months is not recorded on the unaudited consolidated balance sheets. 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 $1.6 million during the three months ended March 31, 2021, which is recorded in "Transportation and marketing expenses" on the unaudited consolidated statement of operations. No firm transportation payments on excess pipeline capacity were incurred during the three months ended March 31, 2020. The Company's estimated aggregate liability of firm transportation payments on excess capacity is $4.4 million as of March 31, 2021, and is included in "Accounts payable and accrued liabilities" on the unaudited consolidated balance sheet. As of March 31, 2021, future firm sale and transportation commitments of $258.8 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 March 31, 2021, under the terms of this agreement, the Company is required to purchase a certain volume remaining under its commitment or it would incur a shortfall payment of $3.4 million at the end of the contract period.
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.
22
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
f.    Environmental
The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, among other things, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed in the period incurred. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Management believes no materially significant liabilities of this nature existed as of March 31, 2021 or December 31, 2020.
Note 13—Supplemental cash flow and non-cash information
The following table presents supplemental cash flow and non-cash information for the periods presented:
Three months ended March 31,
(in thousands)20212020
Supplemental cash flow information:
Cash paid for interest, net of $449 and $1,181 of capitalized interest, respectively
$48,030 $23,697 
Supplemental non-cash investing information:
Change in accrued capital expenditures$(351)$16,272 
Capitalized share-settled equity-based compensation$670 $965 
Capitalized asset retirement cost$397 $886 
Note 14—Asset retirement obligations
See Note 2.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:
Three months ended March 31,
(in thousands)20212020
Liability at beginning of period$68,326 $62,718 
Liabilities added due to acquisitions, drilling, midstream service asset construction and other397 886 
Accretion expense (1)
1,143 1,106 
Liabilities settled due to plugging and abandonment or removed due to sale(57)(497)
Liability at end of period$69,809 $64,213 
_____________________________________________________________________________
(1)Accretion expense is included in "Other operating expenses" on the unaudited consolidated statements of operations.
Note 15—Revenue recognition
Oil, NGL and natural gas sales and sales of purchased oil are generally recognized at the point in time that control of the product is transferred to the customer. Midstream service revenues are recognized over time as the customer benefits from these services when provided. A more detailed summary of the underlying contracts that give rise to the Company's revenues and methods of recognition can be found in Note 14 in the 2020 Annual Report.
Note 16—Income taxes
The Company is subject to federal and state income taxes and the Texas franchise tax. As of March 31, 2021, the Company had federal net operating loss carryforwards totaling $2.1 billion, and of this amount, $1.7 billion will begin to expire in 2026 and $397.6 million will not expire but may be limited in future periods, and state of Oklahoma net operating loss
23
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
carryforwards totaling $34.5 million that will begin to expire in 2032. As of March 31, 2021, the Company believes it is more likely than not that a portion of the net operating loss carryforwards are not fully realizable. The Company continues to consider new evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance is needed. Such consideration includes projected future cash flows from its oil, NGL and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of March 31, 2021, the Company's ability to capitalize intangible drilling costs, rather than expensing these costs and future projections of Oklahoma sourced income. As of March 31, 2021, a total valuation allowance of $505.1 million has been recorded to offset the Company's federal and Oklahoma net deferred tax assets, resulting in a Texas net deferred tax asset of $2.2 million, which is included in "Other noncurrent assets, net" on the unaudited consolidated balance sheets.
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:
 Three months ended March 31,
(in thousands)20212020
Capital expenditures for oil and natural gas properties$11,780 $27,225 
24
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
Note 18—Subsequent events
a.    Senior Secured Credit Facility
On April 6, 2021 and April 26, 2021, the Company borrowed an additional $20.0 million and made a $10.0 million payment, respectively, on the Senior Secured Credit Facility. As a result, the outstanding balance under the Senior Secured Credit Facility was $230.0 million as of May 3, 2021. See Note 6.c for additional discussion of the Company's Senior Secured Credit Facility.
b.    Commodity derivatives
The following table presents the commodity derivatives that were entered into by the Company subsequent to March 31, 2021:
Aggregate volumes (Bbl)Weighted-average price ($/Bbl)Contract period
Brent ICE - Swaps365,000 $61.55 January 2022 - December 2022

The following table summarizes the resulting open oil derivative position as of March 31, 2021, updated for the above derivative transactions through May 3, 2021, for the settlement periods presented:
 Remaining Year 2021Year 2022
Oil: 
Brent ICE - Swaps:
Volume (Bbl)5,651,250 4,124,500 
Weighted-average price ($/Bbl)$51.29 $48.34 
Brent ICE - Collars: 
Volume (Bbl)440,000 821,250 
Weighted-average floor price ($/Bbl)$45.00 $53.67 
Weighted-average ceiling price ($/Bbl)$59.50 $62.40 
Total Brent ICE:
Total volume (Bbl)6,091,250 4,945,750 
Weighted-average floor price ($/Bbl)$50.83 $49.22 
Weighted-average ceiling price ($/Bbl)$51.88 $50.67 
See Note 9 for additional discussion regarding the Company's derivatives. There has been no other derivative activity subsequent to March 31, 2021.
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Table of Contents
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 months ended March 31, 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 March 31, 2021, we had assembled 133,352 net acres in the Permian Basin.
Our financial and operating performance included the following for the periods presented and the corresponding changes for such periods:
Three months ended March 31,2021 compared to 2020
(in thousands)20212020Change (#)Change (%)
Oil sales volumes (MBbl)2,183 2,655 (472)(18)%
Oil equivalents sales volumes (MBOE)7,109 7,874 (765)(10)%
Oil, NGL and natural gas sales(1)
$202,457 $135,885 $66,572 49 %
Net income (loss)$(75,439)$74,646 $(150,085)(201)%
Free Cash Flow (a non-GAAP financial measure)(2)
$21,760 $(57,523)$79,283 138 %
Adjusted EBITDA (a non-GAAP financial measure)(2)
$93,323 $116,848 $(23,525)(20)%
_____________________________________________________________________________
(1)Our oil, NGL and natural gas sales increased as a result of a 65% increase in average sales price per BOE and were partially offset by a 10% decrease in total volumes sold.
(2)See pages 39-40 for discussions and calculations of these non-GAAP financial measures.
Recent developments
ATM Program
On February 23, 2021, we entered into an equity distribution agreement with Wells Fargo Securities, LLC acting as sales agent and/or principal, pursuant to which we may offer and sell, from time to time through the sales agent, shares of our common stock having an aggregate gross sales price of up to $75.0 million through the ATM Program.
As of March 31, 2021, we have sold 723,579 shares of our common stock pursuant to the ATM Program for net proceeds of approximately $26.9 million, after underwriting commissions and other related expenses. Proceeds from the share sale were utilized to reduce borrowings on the Senior Secured Credit Facility. The timing of any additional sales will depend on a variety of factors to be determined by us. See Note 7.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of the ATM Program.

26
Table of Contents
Weather
During February 2021, severe winter weather affected our operations resulting in downtime and delays that impacted total and oil production for first-quarter 2021 by an estimated 5,700 BOE per day and 1,700 barrels of oil per day, respectively. Production impacts were less than originally anticipated and operations returned to pre-storm levels sooner than anticipated.
COVID-19
COVID-19 continues to affect the demand for oil and natural gas and we are not able to predict the duration or ultimate impact that it 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 to transition to 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.
On March 27, 2020, the CARES Act was enacted in response to the COVID-19 pandemic. It included provisions intended to provide relief to individuals and businesses in the form of loans and grants, and tax changes, among other provisions. We did not seek relief in the form of loans or grants from the CARES Act; however, we have benefited from the provision where the AMT credit carryforwards do not expire and are fully refundable.
Volatility in Commodity Prices
In 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 $58 per barrel during first-quarter 2021 and averaged $59 per barrel through April 2021.
We maintain an active, multi-year commodity derivatives strategy to minimize commodity price volatility and support cash flows needed for operations. For 2021, we currently have oil derivatives in place for 6.1 million barrels at a weighted-average floor price of $50.83 Brent per barrel. For 2022, we currently have oil derivatives in place for 4.9 million barrels at a weighted-average floor price of $49.22 Brent per barrel.
Pricing and reserves
Our results of operations are heavily influenced by oil, NGL and natural gas prices. Historically, commodity prices have experienced significant fluctuations; however, the volatility in prices has substantially increased as a result of world developments in 2020. The duration of such developments may affect the economic viability of, and our ability to fund, our drilling projects, as well as the economic valuation and economic recovery of oil, NGL and natural gas reserves.
We have entered into a number of commodity derivative contracts that have enabled us to offset a portion of the changes in our cash flow caused by fluctuations in price and basis differentials for our sales of oil, NGL and natural gas, as discussed in "Item 3. Quantitative and Qualitative Disclosures About Market Risk." See Notes 9, 10.a and 18.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our commodity derivatives.
Our reserves are reported in three streams: oil, NGL and natural gas. The Realized Prices utilized to value our proved reserves as of March 31, 2021 and March 31, 2020, are as follows:
March 31, 2021March 31, 2020
Realized Prices:
   Oil ($/Bbl)$38.28 $52.47 
   NGL ($/Bbl)$9.92 $10.47 
   Natural gas ($/Mcf)$1.20 $0.28 
The Realized Prices used to estimate proved reserves do not include derivative transactions. The unamortized cost of evaluated oil and natural gas properties being depleted exceeded the full cost ceiling 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,
27
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2020. No such full cost ceiling impairment was recorded as of March 31, 2021. Additionally, given current commodity prices, we do not anticipate recording a full cost ceiling impairment in the second quarter of 2021. See Note 5 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of the full cost method of accounting and our Realized Prices.
Horizontal drilling of unconventional wells using enhanced completions techniques, including, but not limited to, hydraulic fracturing, is a continually evolving process and, as such, forecasting the long-term production of such wells is inherently uncertain and subject to varying interpretations. As we receive and process geological and production data from these wells over time, we analyze such data to confirm whether previous assumptions regarding original forecasted production, inventory and reserves continue to appear accurate or require modification. While all production forecasts have elements of uncertainty over the life of the related wells, we have observed over multiple years that oil decline rates are impacted by the vertical and horizontal spacing of wells. In 2020, all wells in our established acreage and Western Glasscock were drilled and completed at the wider spacing to mitigate this effect. Wells in Howard County were and continue to be completed at various horizontal spacing patterns as we test the optimum spacing in that area. In order to mitigate potential negative revisions in future years, we have taken a conservative approach in regards to oil rate forecasts on future wells in Howard County.
Initial production results, production decline rates, well density, completions design and operating method are examples of the numerous uncertainties and variables inherent in the estimation of proved reserves in future periods. The quantity of proved reserves is one of the many variables inherent in the calculation of depletion.
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 table presents our sources of revenue as a percentage of total revenues for the periods presented and the corresponding changes for such periods:
Three months ended March 31,2021 compared to 2020
20212020Change (#)Change (%)
Oil sales51 %59 %(8)%(14)%
NGL sales17 %6 %11 %183 %
Natural gas sales13 %2 %11 %550 %
Midstream service revenues1 %1 %— %— %
Sales of purchased oil18 %32 %(14)%(44)%
Total100 %100 %

28
Table of Contents
Oil, NGL and natural gas sales volumes, revenues and prices
The following table presents information regarding our oil, NGL and natural gas sales volumes, sales revenues and average sales prices for the periods presented and the corresponding changes for such periods:
 Three months ended March 31,2021 compared to 2020
20212020Change (#)Change (%)
Sales volumes:  
Oil (MBbl)2,183 2,655 (472)(18)%
NGL (MBbl)2,321 2,467 (146)(6)%
Natural gas (MMcf)15,630 16,512 (882)(5)%
Oil equivalents (MBOE)(1)(2)
7,109 7,874 (765)(10)%
Average daily oil equivalent sales volumes (BOE/D)(2)
78,989 86,532 (7,543)(9)%
Average daily oil sales volumes (Bbl/D)(2)
24,261 29,178 (4,917)(17)%
Sales revenues (in thousands):  
Oil$127,701 $119,978 $7,723 6 %
NGL41,678 11,558 30,120 261 %
Natural gas33,078 4,349 28,729 661 %
Total oil, NGL and natural gas sales revenues$202,457 $135,885 $66,572 49 %
Average sales prices(2):
  
Oil ($/Bbl)(3)
$58.48 $45.19 $13.29 29 %
NGL ($/Bbl)(3)
$17.96 $4.68 $13.28 284 %
Natural gas ($/Mcf)(3)
$2.12 $0.26 $1.86 715 %
Average sales price ($/BOE)(3)
$28.48 $17.26 $11.22 65 %
Oil, with commodity derivatives ($/Bbl)(4)
$45.03 $56.59 $(11.56)(20)%
NGL, with commodity derivatives ($/Bbl)(4)
$11.25 $6.85 $4.40 64 %
Natural gas, with commodity derivatives ($/Mcf)(4)
$1.66 $0.94 $0.72 77 %
Average sales price, with commodity derivatives ($/BOE)(4)
$21.15 $23.21 $(2.06)(9)%
__________________________________________________________________________
(1)BOE is calculated using a conversion rate of six Mcf per one Bbl.
(2)The numbers presented in the three months ended March 31, 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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The following table presents 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 March 31,2021 compared to 2020
(in thousands)20212020Change ($)Change (%)
Net settlements (paid) received for matured commodity derivatives:
Oil$(18,371)$31,147 $(49,518)(159)%
NGL(15,576)5,337 (20,913)(392)%
Natural gas(7,173)11,239 (18,412)(164)%
Total$(41,120)$47,723 $(88,843)(186)%
Net premiums paid previously or upon settlement attributable to commodity derivatives that matured during the respective period:
Oil$(11,005)$(877)$(10,128)(1,155)%
Changes in average sales prices and sales volumes caused the following changes to our oil, NGL and natural gas revenues between the three months ended March 31, 2021 and 2020:
(in thousands)OilNGLNatural gasTotal 
First-quarter 2020 revenues$119,978 $11,558 $4,349 

$135,885 
Effect of changes in average sales prices29,036 30,807 28,961 88,804 
Effect of changes in sales volumes(21,313)(687)(232)(22,232)
First-quarter 2021 revenues$127,701 $41,678 $33,078 $202,457 
Change ($)$7,723 $30,120 $28,729 $66,572 
Change (%)6 %261 %661 %49 %
In the three months ended March 31, 2021, we experienced significant increases in oil, NGL and natural gas sales prices compared to the same period in 2020. Offsetting such price increases, winter storms during February 2021 disrupted both production activities and drilling and completions operations, impacting total and oil production for first-quarter 2021 by an estimated 5,700 BOE per day and 1,700 barrels of oil per day, respectively. Despite the weather impact, first-quarter 2021 oil production was positively impacted by our first package of wells in Howard County.
The following table presents midstream service revenues and sales of purchased oil for the periods presented and the corresponding changes for such periods:
 
 		Three months ended March 31,2021 compared to 2020
(in thousands) 20212020Change ($)Change (%)
Midstream service revenues$1,296 $2,683 $(1,387)(52)%
Sales of purchased oil$46,477 $66,424 $(19,947)(30)%
Midstream service revenues. Our midstream service revenues decreased for the three months ended March 31, 2021 compared to the same period 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
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purchased oil decreased during the three months ended March 31, 2021, compared to the same period in 2020 primarily due to decreased shipments of purchased oil on pipelines.
We enter into purchase transactions with third parties and separate sale transactions. These transactions are presented on a gross basis as we act as the principal in the transaction by assuming control of the commodities purchased and the responsibility to deliver the commodities sold. Revenue is recognized when control transfers to the purchaser/customer at the delivery point based on the price received. The transportation costs associated with these transactions are presented as a component of costs of purchased oil. See "—Costs and expenses - Costs of purchased oil."
Costs and expenses
The following table presents 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 March 31,2021 compared to 2020
(in thousands except for per BOE sold data)20212020Change ($)Change (%)
Costs and expenses:  
Lease operating expenses$18,918 $22,040 $(3,122)(14)%
Production and ad valorem taxes13,283 9,244 4,039 44 %
Transportation and marketing expenses12,127 13,544 (1,417)(10)%
Midstream service expenses858 1,170 (312)(27)%
Costs of purchased oil49,916 79,297 (29,381)(37)%
General and administrative (excluding LTIP)9,635 10,465 (830)(8)%
General and administrative (LTIP):
LTIP cash1,620 133 1,487 1,118 %
LTIP non-cash1,818 1,964 (146)(7)%
Depletion, depreciation and amortization38,109 61,302 (23,193)(38)%
Impairment expense— 186,699 (186,699)(100)%
Other operating expenses1,143 1,106 37 3 %
Total costs and expenses$147,427 $386,964 $(239,537)(62)%
Selected average costs and expenses per BOE sold(1):
Lease operating expenses$2.66 $2.80 $(0.14)(5)%
Production and ad valorem taxes1.87 1.17 0.70 60 %
Transportation and marketing expenses1.71 1.72 (0.01)(1)%
Midstream service expenses0.12 0.15 (0.03)(20)%
General and administrative (excluding LTIP)1.36 1.33 0.03 2 %
Total selected operating expenses$7.72 $7.17 $0.55 8 %
General and administrative (LTIP):
LTIP cash$0.23 $0.02 $0.21 1,050 %
LTIP non-cash$0.26 $0.25 $0.01 4 %
Depletion, depreciation and amortization$5.36 $7.78 $(2.42)(31)%
_____________________________________________________________________________
(1)Selected average costs and expenses per BOE sold are based on actual amounts and are not calculated using the rounded numbers presented in the table above.
Lease operating expenses ("LOE"). LOE, which includes workover expenses, and LOE per BOE sold both decreased for the three months ended March 31, 2021, compared to the same period in 2020. LOE are daily costs incurred to bring oil, NGL and natural gas out of the ground and to market, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and non-routine workover expenses related to our oil and natural gas properties. We continue to focus on economic efficiencies associated with the usage and procurement of products and services related to LOE and decreasing failures and related workover expenses. We expect LOE to increase during 2021 due to higher expected operating costs on the wells coming on-line in Howard County compared to operating costs on our established acreage.
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Production and ad valorem taxes. Production and ad valorem taxes increased for the three months ended March 31, 2021, compared to the same period in 2020. 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 months ended March 31, 2021, compared to the same period in 2020. These are costs incurred for the delivery of produced oil to customers in the U.S. Gulf Coast market via the Bridgetex pipeline and the Gray Oak pipeline. We 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. 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. We also recognized $2.0 million in marketing expense due to negative natural gas prices in March 2020.
Midstream service expenses. Midstream service expenses decreased for the three months ended March 31, 2021, compared to the same period in 2020. These are costs 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 decreased for the three months ended March 31, 2021, compared to the same period in 2020 primarily due to decreased shipments of purchased oil on pipelines. We 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"), decreased 8% for the three months ended March 31, 2021, compared to the same period in 2020, mainly due to a decrease in employee-related costs as a result of the measures taken during second-quarter 2020 to align our cost structure with operational activity, which included a workforce reduction.
LTIP cash expense increased for the three months ended March 31, 2021, compared to the same period 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. LTIP non-cash expense decreased slightly for the three months ended March 31, 2021, compared to the same period in 2020. The decrease in LTIP non-cash expense was due to equity award forfeitures related to the second-quarter 2020 workforce reduction, which were still being expensed in first-quarter 2020, and 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 table presents 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 March 31,2021 compared to 2020
(in thousands)20212020Change ($)Change (%)
Depletion of evaluated oil and natural gas properties$34,725 $57,752 $(23,027)(40)%
Depreciation of midstream service assets2,422 2,592 (170)(7)%
Depreciation and amortization of other fixed assets962 958 4 — %
Total DD&A$38,109 $61,302 $(23,193)(38)%
Depletion expense per BOE sold$4.88 $7.33 $(2.45)(33)%
Both DD&A and depletion expense per BOE decreased for the three months ended March 31, 2021, compared to the same period in 2020 as a result of the full cost impairments incurred during 2020. See Note 5 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report and "—Pricing and reserves" for additional information regarding the full cost method of accounting.
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Impairment expense.  The following table presents the components of our impairment expense for the periods presented:
 Three months ended March 31,
(in thousands)20212020
Full cost ceiling impairment expense$— $177,182 
Midstream service asset impairment expense— 8,183 
Line-fill and other inventories impairment expense— 1,334 
Total impairment expense$— $186,699 
The unamortized cost of evaluated oil and natural gas properties did not exceed the full cost ceiling as of March 31, 2021 and, as a result, we did not record a full cost ceiling impairment for such period. As of March 31, 2020, the unamortized cost of evaluated oil and natural gas properties exceeded the full cost ceiling and, as a result, we recorded a non-cash full cost ceiling impairment of $177.2 million for such period. See Note 5 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report and "—Pricing and reserves" for additional discussion of our full cost ceiling calculation.
Impairments are recorded on long-lived assets when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset. All inventory is carried at the lower of cost or NRV, with cost determined using the weighted-average cost method. See Note 10.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion regarding the fair value measurement of our inventory and long-lived assets.
Other operating expenses. These costs include accretion expense due to the passage of time on our asset retirement obligations. See Note 2.k in our 2020 Annual report for additional information regarding our asset retirement obligations.
Non-operating income (expense)
The following table presents the components of non-operating income (expense), net for the periods presented and the corresponding changes for such periods:
 Three months ended March 31,2021 compared to 2020
(in thousands)20212020Change ($)Change (%)
Gain (loss) on derivatives, net$(154,365)$297,836 $(452,201)(152)%
Interest expense(25,946)(24,970)(976)(4)%
Loss on extinguishment of debt— (13,320)13,320 100 %
Loss on disposal of assets, net(72)(602)530 88 %
Other income, net1,379 91 1,288 1,415 %
Total non-operating income (expense), net$(179,004)$259,035 $(438,039)(169)%
Gain (loss) on derivatives, net. The following table presents the changes in the components of gain (loss) on derivatives, net for the periods presented and the corresponding changes for such periods:
Three months ended March 31,2021 compared to 2020
(in thousands)20212020Change ($)Change (%)
Non-cash gain (loss) on derivatives, net$(122,232)$250,590 $(372,822)(149)%
Settlements (paid) received for matured derivatives, net(41,174)47,723 (88,897)(186)%
Premiums received (paid) for commodity derivatives9,041 (477)9,518 1,995 %
Gain (loss) on derivatives, net$(154,365)$297,836 $(452,201)(152)%
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
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market prices. Settlements paid or received for matured derivatives are for our commodity derivative contracts, which are based on the settlement prices compared to the prices specified in the derivative contracts, and for our interest rate derivative.
During the three months ended March 31, 2021, we completed a hedge restructuring by (i) selling 2,254,500 calendar year 2021 $55.00 per barrel Brent ICE puts, which volumetrically offset existing calendar year 2021 $55.00 per barrel Brent ICE puts, and receiving aggregate premiums of $9.0 million at inception of the contracts and (ii) entering into 2,254,500 calendar year 2021 Brent ICE swaps at a weighted-average price of $55.09 per barrel. Associated with the aforementioned existing calendar year 2021 $55.00 per barrel Brent ICE puts, which were entered into during 2020, are $50.6 million in aggregate premiums paid at the inception of the contacts.
See Notes 9 and 10.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information regarding our derivatives.
Interest expense. Interest expense remained consistent for the three months ended March 31, 2021, compared to the same period in 2020. See Notes 6 and 18.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding our long-term debt.
Loss on extinguishment of debt. We recognized a loss on extinguishment of debt related to the difference between the consideration for tender offers, early tender premiums and redemption prices and the net carrying amounts of the extinguished January 2022 Notes and March 2023 Notes during the three months ended March 31, 2020. See Note 6.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding the extinguishment of our January 2022 Notes and March 2023 Notes.
Loss on disposal of assets, net. Loss on disposal of assets, net, decreased for the three months ended March 31, 2021 compared to 2020. From time to time, we dispose of inventory, midstream service assets and other fixed assets. The associated gain or loss recorded during the period fluctuates depending upon the volume of the assets disposed, their associated net book value and, in the case of a disposal by sale, the sale price.
Income tax benefit (expense)
The following table presents income tax benefit (expense) for the periods presented and the corresponding changes for such periods:
Three months ended March 31,2021 compared to 2020
(in thousands)20212020Change ($)Change (%)
Deferred$762 $(2,417)$3,179 132 %
We are subject to federal and state income taxes and the Texas franchise tax. The deferred income tax benefit (expense) for the periods presented is attributed to deferred Texas franchise tax. As of March 31, 2021, we determined it was more likely than not that our federal and Oklahoma net deferred tax assets were not realizable through future net income. As of March 31, 2021, a total valuation allowance of $505.1 million has been recorded to offset our federal and Oklahoma net deferred tax assets, resulting in a Texas net deferred tax asset of $2.2 million. The effective tax rate for our operations was not meaningful for the periods presented and we expect it to remain at or under 1%, due to the full valuation allowance against our federal and Oklahoma net deferred tax assets.
Issuances, sales and/or exchanges of our common stock, taken together with prior transactions with respect to our common stock, could trigger an ownership change and therefore a limitation on our ability to utilize our NOL carryforwards which could result in taxable income in future years. For 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 negative impact of
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COVID-19 and OPEC+ actions on the energy industry, we believe our cash flows from operations, favorable hedges and availability under our Senior Secured Credit Facility provide sufficient liquidity to manage our cash needs and contractual obligations and to fund our expected capital expenditures.
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 18.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.
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. Due to the inherent volatility in interest rates, we have entered into an interest rate derivative swap to hedge interest rate risk associated with a portion of our anticipated outstanding debt under the Senior Secured Credit Facility. We will pay a fixed rate over the contract term for that portion. By removing a portion of the (i) price volatility associated with future sales volumes and (ii) interest rate volatility associated with anticipated outstanding debt, we expect to mitigate, but not eliminate, the potential effects of variability in cash flows from operations. See "Part I. Item 3. Quantitative and Qualitative Disclosures About Market Risk" below.
See Note 9.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of our commodity hedge restructuring during the three months ended March 31, 2021 and corresponding summary of open commodity derivative positions as of March 31, 2021 for commodity derivatives that were entered into through March 31, 2021.
We continually seek to maintain a financial profile that provides operational flexibility. As of March 31, 2021, we had cash and cash equivalents of $44.3 million and available capacity under the Senior Secured Credit Facility, after the reduction for outstanding letters of credit, of $460.9 million, resulting in total liquidity of $505.2 million. As of May 3, 2021, we had cash and cash equivalents of $48.4 million and available capacity under the Senior Secured Credit Facility, after the reduction for outstanding letters of credit, of $450.9 million, resulting in total liquidity of $499.3 million. We believe that our operating cash flows and the aforementioned liquidity sources provide us with the financial resources to manage our business needs, to implement our currently planned capital expenditure budget and, at our discretion, to fund any share repurchases, pay down, repurchase or refinance debt or adjust our planned capital expenditure budget.
Cash flows
The following table presents our cash flows for the periods presented and the corresponding changes for such periods:
 Three months ended March 31,2021 compared to 2020
(in thousands)20212020Change ($)Change (%)
Net cash provided by operating activities$71,151 $109,589 $(38,438)(35)%
Net cash used in investing activities(69,020)(159,791)90,771 57 %
Net cash (used in) provided by financing activities(6,626)72,122 (78,748)(109)%
Net (decrease) increase in cash and cash equivalents$(4,495)$21,920 $(26,415)(121)%
Cash flows from operating activities
Net cash provided by operating activities decreased during the three months ended March 31, 2021, compared to the same period in 2020. Notable cash changes include (i) a decrease of $79.4 million due to changes in net settlements for matured derivatives, net of premiums, mainly due to increases in commodity prices, (ii) an increase in total oil, NGL and natural gas
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sales revenues of $66.6 million and (iii) a decrease of $33.0 million due to net changes in operating assets and liabilities. Other significant changes include a decrease 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 65% 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 have been most impacted by the effects of COVID-19 on demand and the effects of the OPEC+ actions, and earlier in the year, related transportation and storage constraints, particularly in the State of Texas, on supply. These factors are not within our control and are difficult to predict. For additional information on risks related to our business, see "Part I. Item 3. Quantitative and Qualitative Disclosures About Market Risk" and "Part II. Item 1A. Risk Factors" included elsewhere in this Quarterly Report and "Part I. Item 1A. Risk Factors" in our 2020 Annual Report.
Cash flows from investing activities
Net cash used in investing activities decreased for the three months ended March 31, 2021, compared to the same period in 2020, mainly due to a decrease in capital expenditures for oil and natural gas properties and a decrease in acquisitions of oil and natural gas properties. See Note 3 to our unaudited consolidated financial statements included elsewhere in the Quarterly Report for additional discussion of our acquisitions of oil and natural gas properties.
The following table presents the components of our cash flows from investing activities for the periods presented and the corresponding changes for such periods:
 Three months ended March 31,2021 compared to 2020
(in thousands)20212020Change ($)Change (%)
Acquisitions of oil and natural gas properties, net$— $(22,876)$22,876 100 %
Capital expenditures:
Oil and natural gas properties(68,329)(135,376)67,047 50 %
Midstream service assets(329)(761)432 57 %
Other fixed assets(551)(829)278 34 %
Proceeds from dispositions of capital assets, net of selling costs189 51 138 271 %
Net cash used in investing activities$(69,020)$(159,791)$90,771 57 %
The following table presents the components of our costs incurred, excluding non-budgeted acquisition costs, for the periods presented and the corresponding changes for such periods:
Three months ended March 31,2021 compared to 2020
(in thousands)20212020Change ($)Change (%)
Oil and natural gas properties$68,449 $152,868 $(84,419)(55)%
Midstream service assets876 923 (47)(5)%
Other fixed assets600 823 (223)(27)%
Total costs incurred, excluding non-budgeted acquisition costs$69,925 $154,614 $(84,689)(55)%
See Note 5 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding our costs incurred in the exploration and development of oil and natural gas properties.
The amount, timing and allocation of capital expenditures are largely discretionary and within management's control. If oil, NGL and natural gas prices are below our acceptable levels, or costs are above our acceptable levels, we may choose to defer a portion of our capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash
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flow. Subject to financing alternatives, we may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We continually monitor and may adjust our projected capital expenditures in response to world developments, such as those we experienced in 2020, as well as success or lack of success in drilling activities, changes in prices, availability of financing and joint venture opportunities, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs and supplies, changes in service costs, contractual obligations, internally generated cash flow and other factors both within and outside our control.
Cash flows from financing activities
Net cash (used in) provided by financing activities decreased for the three months ended March 31, 2021, compared to the same period in 2020. Notable 2021 activity includes proceeds from our ATM Program and net payments on our Senior Secured Credit Facility. Notable 2020 activity includes the issuance of our January 2025 Notes and January 2028 Notes, partially offset by the extinguishment of our January 2022 Notes and March 2023 Notes and payments on our Senior Secured Credit Facility. For further discussion of our financing activities related to debt instruments, see Notes 6 and 18.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.
The following table presents the components of our cash flows from financing activities for the periods presented and the corresponding changes for such periods:
 Three months ended March 31,2021 compared to 2020
(in thousands)20212020Change ($)Change (%)
Borrowings on Senior Secured Credit Facility$15,000 $— $15,000 100 %
Payments on Senior Secured Credit Facility(50,000)(100,000)50,000 50 %
Issuance of January 2025 Notes and January 2028 Notes— 1,000,000 (1,000,000)(100)%
Extinguishment of debt— (808,855)808,855 100 %
Proceeds from issuance of common stock, net of costs26,866 — 26,866 100 %
Stock exchanged for tax withholding(1,290)(640)(650)(102)%
Payments for debt issuance costs— (18,383)18,383 100 %
Other liabilities2,798 — 2,798 100 %
Net cash (used in) provided by financing activities$(6,626)$72,122 $(78,748)(109)%
We are the borrower under our Senior Secured Credit Facility and a party to the indentures governing our Senior Unsecured Notes.
Senior Secured Credit Facility
As of March 31, 2021, the Senior Secured Credit Facility, which matures on April 19, 2023, had a maximum credit amount of $2.0 billion, a borrowing base and an aggregate elected commitment of $725.0 million each, with $220.0 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 March 31, 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 April 6, 2021 and April 26, 2021, we borrowed an additional $20.0 million and made a $10.0 million payment, respectively, on the Senior Secured Credit Facility. As a result, the outstanding balance under the Senior Secured Credit Facility was $230.0 million as of May 3, 2021.
See Notes 6.c and 18.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our Senior Secured Credit Facility.

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January 2025 Notes and January 2028 Notes
The following table presents principal amounts and applicable interest rates for our outstanding January 2025 Notes and January 2028 Notes (together the "Senior Unsecured Notes") as of March 31, 2021:
(in millions, except for interest rates)PrincipalInterest rate
January 2025 Notes$577.9 9.500 %
January 2028 Notes361.0 10.125 %
Total Senior Unsecured Notes$938.9 
The net proceeds from the January 2025 Notes and January 2028 Notes were used to fund the tender offers and redemptions of the remaining principle amounts of the January 2022 Notes and March 2023 Notes. See Notes 6.a and 6.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our senior unsecured notes.
Supplemental Guarantor information
As discussed in Note 6.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report, on January 24, 2020, we issued $600.0 million in aggregate principal amount of the January 2025 Notes and $400.0 million in aggregate principal amount of the January 2028 Notes. As of March 31, 2021, $938.9 million of our Senior Unsecured Notes remained outstanding. Each of our wholly owned subsidiaries, LMS and GCM (each, a "Guarantor," and together, the "Guarantors"), jointly and severally, and fully and unconditionally, guarantees the January 2025 Notes and the January 2028 Notes. We do not have any non-guarantor subsidiaries.
The guarantees are senior unsecured obligations of each Guarantor and rank equally in right of payment with other existing and future senior indebtedness of such Guarantor, and senior in right of payment to all existing and future subordinated indebtedness of such Guarantor. The guarantees of the Senior Unsecured Notes by the Guarantors are subject to certain Releases. The obligations of each Guarantor under its note guarantee are limited as necessary to prevent such note guarantee from constituting a fraudulent conveyance under applicable law. Further, the rights of holders of the Senior Unsecured Notes against the Guarantors may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Laredo is not restricted from making investments in the Guarantors and the Guarantors are not restricted from making intercompany distributions to Laredo or each other.
As we do not have any non-guarantor subsidiaries, the assets, liabilities and results of operations of the combined issuer and Guarantors are not materially different than the corresponding amounts presented in our unaudited consolidated financial statements included elsewhere in this Quarterly Report. Accordingly, we have omitted the summarized financial information of the issuer and the Guarantors that would otherwise be required.
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 18.a 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 $258.8 million are expected to be satisfied as of March 31, 2021 and are not recorded as a liability on the unaudited consolidated balance sheet. These commitments have decreased during the three months ended March 31, 2021, and are mainly due to our fulfillment of contractual commitments, partially offset by changes to existing sales commitments. Of this amount, $77.7 million is related to transportation commitments with a certain pipeline pertaining to the gathering of our production from our established acreage that extends into 2024. We believe we will be able to meet the majority of this commitment, however, as development plans evolve and refine, we may be unable to meet a portion of this commitment. For the three months ended March 31, 2021, we were unable to satisfy a portion of this particular commitment with produced or purchased oil and,as such, expensed firm transportation payments on excess capacity of $1.6 million. See Note 12.c to our
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unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our firm sale and transportation commitments.
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.
Free Cash Flow
Free Cash Flow is a non-GAAP financial measure that we define as net cash provided by operating activities (GAAP) before changes in operating assets and liabilities, net, less costs incurred, excluding non-budgeted acquisition costs. Free Cash Flow does not represent funds available for future discretionary use because it excludes funds required for future debt service, capital expenditures, acquisitions, working capital, income taxes, franchise taxes and other commitments and obligations. However, our management believes Free Cash Flow is useful to management and investors in evaluating operating trends in our business that are affected by production, commodity prices, operating costs and other related factors. There are significant limitations to the use of Free Cash Flow as a measure of performance, including the lack of comparability due to the different methods of calculating Free Cash Flow reported by different companies.
The following table presents a reconciliation of net cash provided by operating activities (GAAP) to Free Cash Flow (non-GAAP) for the periods presented:
Three months ended March 31,
(in thousands)20212020
Net cash provided by operating activities$71,151 $109,589 
Less:
Change in current assets and liabilities, net(17,259)18,708 
Change in noncurrent assets and liabilities, net(3,275)(6,210)
Cash flows from operating activities before changes in operating assets and liabilities, net91,685 97,091 
Less costs incurred, excluding non-budgeted acquisition costs:
Oil and natural gas properties(1)
68,449 152,868 
Midstream service assets(1)
876 923 
Other fixed assets600 823 
Total costs incurred, excluding non-budgeted acquisition costs69,925 154,614 
Free Cash Flow (non-GAAP)$21,760 $(57,523)
_____________________________________________________________________________
(1)Includes capitalized share-settled equity-based compensation and asset retirement costs.

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Adjusted EBITDA
Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss (GAAP) plus adjustments for share-settled equity-based compensation, depletion, depreciation and amortization, impairment expense, mark-to-market on derivatives, premiums paid or received for commodity derivatives that matured during the period, accretion expense, gains or losses on disposal of assets, interest expense, income taxes and other non-recurring income and expenses. Adjusted EBITDA provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, working capital movement or tax position. Adjusted EBITDA does not represent funds available for future discretionary use because it excludes funds required for debt service, capital expenditures, working capital, income taxes, franchise taxes and other commitments and obligations. However, our management believes Adjusted EBITDA is useful to an investor in evaluating our operating performance because this measure:
•is widely used by investors in the oil and natural gas industry to measure a company's operating performance without regard to items that can vary substantially from company to company depending upon accounting methods, the book value of assets, capital structure and the method by which assets were acquired, among other factors;
•helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and
• is used by our management for various purposes, including as a measure of operating performance, in presentations to our board of directors and as a basis for strategic planning and forecasting.
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 March 31,
(in thousands)20212020
Net income (loss)$(75,439)$74,646 
Plus:
Share-settled equity-based compensation, net2,068 2,376 
Depletion, depreciation and amortization38,109 61,302 
Impairment expense— 186,699 
Mark-to-market on derivatives:
(Gain) loss on derivatives, net154,365 (297,836)
Settlements (paid) received for matured derivatives, net(41,174)47,723 
Net premiums paid for commodity derivatives that matured during the period(1)
(11,005)(477)
Accretion expense1,143 1,106 
Loss on disposal of assets, net72 602 
Interest expense25,946 24,970 
Loss on extinguishment of debt— 13,320 
Income tax (benefit) expense(762)2,417 
Adjusted EBITDA (non-GAAP)$93,323 $116,848 
_____________________________________________________________________________
(1)Reflects net premiums paid previously or upon settlement that are attributable to derivatives settled in the respective periods presented.

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Critical accounting policies and estimates
The discussion and analysis of our financial condition and results of operations are based upon our unaudited consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our unaudited consolidated financial statements.
There have been no material changes in our critical accounting policies and procedures during the three months ended March 31, 2021. See our critical accounting policies in "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" of the 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 and contingent consideration derivative positions are largely determined by the relevant forward commodity price curves of the indexes associated with our open derivative positions. We had a $156.9 million net liability position from the fair values of our open commodity derivatives and a $1.1 million liability position from the fair value of our potential contingent consideration payments associated with an asset acquisition, each as of March 31, 2021. The following table provides a sensitivity analysis of the projected incremental effect on income (loss) before income taxes of a hypothetical 10% change in the relevant forward commodity price curves of the indexes associated with our open commodity and contingent consideration derivative positions as of March 31, 2021:
(in thousands)10% Increase 10% Decrease
Commodity$(82,555)$82,096 
Contingent consideration(7)25 
Total$(82,562)$82,121 
See Notes 9.a, 9.c, 10.a and 18.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our commodity and contingent consideration derivatives.
Interest rate risk
Our Senior Secured Credit Facility bears interest at a floating rate and our notes bear interest at fixed rates. The maturity years, outstanding balances and interest rates on our long-term debt as of March 31, 2021 were as follows:
 Maturity year
(in millions except for interest rates)20232025Thereafter
January 2025 Notes$— $577.9 $— 
Fixed interest rate— %9.500 %— %
January 2028 Notes$— $— $361.0 
Fixed interest rate— %— %10.125 %
Senior Secured Credit Facility$220.0 $— $— 
Floating interest rate2.625 %— %— %
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 $0.2 million total liability position from the net fair value of our open interest rate derivative as of March 31, 2021. The following table provides a sensitivity analysis of the projected incremental effect on income (loss) before income taxes of a hypothetical 1% incremental addition to or subtraction from the relevant LIBOR forward curve interest rates associated with our open interest rate derivative position as of March 31, 2021:
(in thousands)1% incremental addition to 1% incremental subtraction from
Interest rate$1,082 $(1,082)
See Notes 6, 10.c and 18.a 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.
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Item 4.    Controls and Procedures
Evaluation of disclosure controls and procedures
As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of Laredo's disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act), was performed under the supervision and with the participation of Laredo's management, including our principal executive officer and principal financial officer. Based on that evaluation, these officers concluded that Laredo's disclosure controls and procedures were effective as of March 31, 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 March 31, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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Part II

Item 1.    Legal Proceedings
From time to time, we are subject to various legal proceedings arising in the ordinary course of business, including proceedings for which we may not have insurance coverage. While many of these matters involve inherent uncertainty as of the date hereof, we do not currently believe that any such legal proceedings will have a material adverse effect on our business, financial position, results of operations or liquidity.
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Item 1A.    Risk Factors
In addition to the other information set forth in this Quarterly Report, you should carefully consider the risks discussed in our 2020 Annual Report. Depending on the duration of the COVID-19 pandemic and its severity and related economic repercussions, the negative impact of many of the related risks discussed in our 2020 Annual Report 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.



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Item 2.    Purchases of Equity Securities
The following table summarizes purchases of common stock by Laredo:
Period
Total number of shares purchased(1)
Weighted-average price paid per shareTotal number of shares purchased as
part of publicly announced plans		Maximum value that may yet be purchased under the program as of the respective period-end date
January 1, 2021 - January 31, 2021197 $20.33 — $— 
February 1, 2021 - February 28, 202123,073 $34.35 — $— 
March 1, 2021 - March 31, 202114,394 $34.24 — $— 
Total37,664 — 
______________________________________________________________________________
(1)Represents shares that were withheld by us to satisfy tax withholding obligations that arose upon the lapse of restrictions on restricted stock awards.

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Item 3.    Defaults Upon Senior Securities
None.
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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.
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Item 5.    Other Information
Not applicable.
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Item 6.    Exhibits
Incorporated by reference (File No. 001-35380, unless otherwise indicated)
Exhibit DescriptionFormExhibitFiling Date
 8-K3.112/22/2011
8-K3.16/1/2020
8-K3.11/6/2014
8-K3.13/4/2021
 8-A12B/A4.11/7/2014
10-K10.182/22/2021
10-K10.212/22/2021
10-Q22.15/7/2020
 
 
 
101 The following financial information from Laredo’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2021, formatted in Inline XBRL: (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Stockholders’ Equity, (iv) Consolidated Statements of Cash Flows and (v) Condensed Notes to the Consolidated Financial Statements.
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
______________________________________________________________________________
*    Filed herewith.
**    Furnished herewith.
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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: May 6, 2021By:/s/ Jason Pigott
  Jason Pigott
  President and Chief Executive Officer
  (principal executive officer)
   
Date: May 6, 2021By:/s/ Bryan J. Lemmerman
  Bryan J. Lemmerman
  Senior Vice President and Chief Financial Officer
  (principal financial officer)
Date: May 6, 2021By:/s/ Jessica R. Wren
Jessica R. Wren
Interim Principal Accounting Officer
(principal accounting officer)
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