UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT PURSUANT TO
SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Date of report (Date of earliest event reported): May 31, 2022
(Exact name of registrant as specified in charter)
| (State or other jurisdiction of incorporation or organization) | (Commission File Number) | (I.R.S. Employer Identification No.) | ||||||
| (Address of principal executive offices) | (Zip code) | |||||||
Registrant’s telephone number, including area code: (918 ) 513-4570
Not Applicable
(Former name or former address, if changed since last report)
Securities registered pursuant to Section 12(b) of the Exchange Act:
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Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
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| Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) | |||||||||||
| Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) | |||||||||||
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter). | |||||||||||
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. ☐ | |||||||||||
Item 7.01. Regulation FD Disclosure.
On May 31, 2022, Laredo Petroleum, Inc. (the “Company”) furnished a press release announcing that its board of directors has authorized a $200 million share repurchase program. The press release is available on the Company’s website, www.laredopetro.com, and is attached hereto as Exhibit 99.1 and incorporated into this Item 7.01 by reference.
On May 31, 2022, the Company also posted to its website a Corporate Presentation (the “Presentation”). The Presentation is available on the Company’s website, www.laredopetro.com, and is attached hereto as Exhibit 99.2 and incorporated into this Item 7.01 by reference.
All statements in the press release and Presentation, other than historical financial information, may be deemed to be 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”). Although the Company believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance, and actual results or developments may differ materially from those in the forward-looking statements. See the Company’s Annual Report on Form 10-K for the year ended December 31, 2021 and the Company’s other filings with the SEC for a discussion of other risks and uncertainties. The Company disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
In accordance with General Instruction B.2 of Form 8-K, the information furnished under this Item 7.01 of this Current Report on Form 8-K and the exhibits attached hereto are deemed to be “furnished” and shall not be deemed “filed” for the purpose of Section 18 of the Exchange Act, or otherwise subject to the liabilities of that section, nor shall such information and exhibits be deemed incorporated by reference into any filing under the Securities Act or the Exchange Act.
Item 9.01. Financial Statements and Exhibits.
(d) Exhibits.
| Exhibit Number | Description | |||||||
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL). | |||||||
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 hereunto duly authorized.
| LAREDO PETROLEUM, INC. | ||||||||
Date: May 31, 2022 | By: | /s/ Bryan J. Lemmerman | ||||||
| Bryan J. Lemmerman | ||||||||
| Senior Vice President and Chief Financial Officer | ||||||||
EXHIBIT 99.1
15 West 6th Street, Suite 900 · Tulsa, Oklahoma 74119 · (918) 513-4570 · Fax: (918) 513-4571
www.laredopetro.com
Laredo Petroleum Announces $200 Million Share Repurchase Program
Debt Repayment Target Increased to ~$700 Million
TULSA, OK - May 31, 2022 - Laredo Petroleum, Inc. (NYSE: LPI) ("Laredo" or the "Company") today announced that its board of directors authorized a $200 million share repurchase program. The two-year program is authorized through May 27, 2024.
Highlights:
•$200 million share repurchase program realizes the Company’s commitment to begin returning significant cash to shareholders approximately nine months ahead of schedule
•Debt repayment target updated to ~$700 million by year-end 2023
•On track to achieve targeted Net Debt1/Consolidated EBITDAX1 ratio target of 1.0x by first-quarter 2023
•Free Cash Flow1 for 2022-23 estimated at ~$900 million at current commodity prices
"Today’s buyback announcement is the continuation of a three-year effort to create a new Laredo Petroleum," stated Jason Pigott, President and Chief Executive Officer. "We have successfully repositioned the Company and are focused on high-return, disciplined investments in our oil-weighted developments. We expect to generate approximately $900 million of Free Cash Flow through the end of next year, enabling us to continue reducing debt while opportunistically repurchasing our shares."
The Company may purchase shares in accordance with applicable securities laws from time to time in open market or privately negotiated transactions. The Company intends to fund repurchases from available working capital and cash provided by operating activities. The timing, number and value of shares repurchased under the program will be at the discretion of management and the board of directors and will depend on a number of factors, including market conditions, business conditions, the trading price of the Company's common stock and the nature of other investment opportunities available to the Company. The program does not obligate Laredo to acquire any particular dollar amount or number of shares of its common stock, and the share repurchase program may be suspended from time to time, modified, extended or discontinued by the Company’s board of directors at any time.
1Non-GAAP financial measure; please see definitions of non-GAAP financial measures at the end of this release.
About Laredo
Laredo Petroleum, Inc. is an independent energy company with headquarters in Tulsa, Oklahoma. Laredo's business strategy is focused on the acquisition, exploration and development of oil and natural gas properties, primarily in the Permian Basin of West Texas.
Additional information about Laredo may be found on its website at www.laredopetro.com.
Forward-Looking Statements
This press release and any oral statements made regarding the contents of this release, including in the conference call referenced herein, contain forward-looking statements as defined under Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, that address activities that Laredo assumes, plans, expects, believes, intends, projects, indicates, enables, transforms, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. The forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Such statements are not guarantees of future performance and involve risks, assumptions and uncertainties.
General risks relating to Laredo include, but are not limited to, the decline in prices of oil, natural gas liquids and natural gas and the related impact to financial statements as a result of asset impairments and revisions to reserve estimates, the ability of the Company to execute its strategies, including its ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to its financial results and to successfully integrate acquired businesses, assets and properties, oil production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries and other producing countries ("OPEC+"), the outbreak of disease, such as the coronavirus ("COVID-19") pandemic, and any related government policies and actions, changes in domestic and global production, supply and demand for commodities, including as a result of the COVID-19 pandemic, actions by OPEC+ and the Russian-Ukrainian military conflict, long-term performance of wells, drilling and operating risks, the increase in service and supply costs, including as a result of inflationary pressures, tariffs on steel, pipeline transportation and storage constraints in the Permian Basin, the possibility of production curtailment, hedging activities, the impacts of severe weather, including the freezing of wells and pipelines in the Permian Basin due to cold weather, possible impacts of litigation and regulations, the impact of the Company's transactions, if any, with its securities from time to time, the impact of new laws and regulations, including those regarding the use of hydraulic fracturing, the impact of new environmental, health and safety requirements applicable to the Company's business activities, the possibility of the elimination of federal income tax deductions for oil and gas exploration and development and other factors, including those and other risks described in its Annual Report on Form 10-K for the year ended December 31, 2021 and those set forth from time to time in other filings with the Securities and Exchange Commission ("SEC"). These documents are available through Laredo's website at www.laredopetro.com under the tab "Investor Relations" or through the SEC's Electronic Data Gathering and Analysis Retrieval System at www.sec.gov. Any of these factors could cause Laredo's actual results and plans to differ materially from those in the forward-looking statements. Therefore, Laredo can give no assurance that its future results will be as estimated. Any forward-looking statement speaks only as of the date on which such statement is made. Laredo does not intend to, and disclaims any obligation to, correct, update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.
This press release and any accompanying disclosures include financial measures that are not in accordance with generally accepted accounting principles ("GAAP"), such as Consolidated EBITDAX and Free Cash Flow. While management believes that such measures are useful for investors, they should not be used as a replacement for financial measures that are in accordance with GAAP. For a reconciliation
2
of such non-GAAP financial measures to the nearest comparable measure in accordance with GAAP, please see the supplemental financial information at the end of this press release.
Unless otherwise specified, references to "average sales price" refer to average sales price excluding the effects of the Company's derivative transactions.
All amounts, dollars and percentages presented in this press release are rounded and therefore approximate.
Free Cash Flow (Unaudited)
Free Cash Flow is a non-GAAP financial measure that the Company defines as net cash provided by operating activities (GAAP) before changes in operating assets and liabilities, net, less incurred capital expenditures, excluding non-budgeted acquisition costs. Free Cash Flow does not represent funds available for future discretionary use because it excludes funds required for future debt service, capital expenditures, acquisitions, working capital, income taxes, franchise taxes and other commitments and obligations. However, management believes Free Cash Flow is useful to management and investors in evaluating operating trends in its 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.
Consolidated EBITDAX (Unaudited)
Consolidated EBITDAX is a non-GAAP financial measure defined in the Company's Senior Secured Credit Facility as net income or loss (GAAP) plus adjustments for extraordinary gains (or losses), non-cash recurring gains (or losses), depletion, depreciation and amortization expense, interest expense, any provisions for (or benefit from) income or franchise taxes, exploration expenses and other non-cash charges. Consolidated EBITDAX is used by the Company’s management for various purposes, including as a measure of operating performance and compliance under the Company's Senior Secured Credit Facility. Additional information on the calculation of Consolidated EBITDAX can be found in the Company's Senior Secured Credit Facility, as amended by the Eighth Amendment thereto, as filed with the SEC on April 19, 2022.
Net Debt (Unaudited)
Net Debt, a non-GAAP financial measure, is calculated as the face value of long-term debt plus any outstanding letters of credit,less cash and cash equivalents. Management believes Net Debt is useful to management and investors in determining the Company's leverage position since the Company has the ability, and may decide, to use a portion of its cash and cash equivalents to reduce debt.
Net Debt to Consolidated EBITDAX (Unaudited)
Net Debt to Consolidated EBITDAX, a non-GAAP financial measure, is calculated as Net Debt, including letters of credit, divided by Consolidated EBITDAX, as defined in the Company's Senior Secured Credit Facility. For the purposes of calculating Consolidated EBITDAX for the period ended March 31, 2022, the calculation is the annualization of the three quarters ended March 31, 2022. Net Debt to Consolidated EBITDAX is used by the Company’s management for various purposes, including as a measure of operating performance, in presentations to its board of directors and as a basis for strategic planning and forecasting.
Investor Contact:
Ron Hagood
918.858.5504
rhagood@laredopetro.com
3
June 2022 Investor Presentation
This presentation, including any oral statements made regarding the contents of this presentation, contains forward-looking statements as defined under Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, that address activities that Laredo Petroleum, Inc. (together with its subsidiaries, the “Company”, “Laredo” or “LPI”) assumes, plans, expects, believes, intends, projects, indicates, enables, transforms, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. The forward- looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Such statements are not guarantees of future performance and involve risks, assumptions and uncertainties. General risks relating to Laredo include, but are not limited to, the decline in prices of oil, natural gas liquids and natural gas and the related impact to financial statements as a result of asset impairments and revisions to reserve estimates, the ability of the Company to execute its strategies, including its ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to its financial results and to successfully integrate acquired businesses, assets and properties, oil production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries and other producing countries (“OPEC+”), the outbreak of disease, such as the coronavirus (“COVID-19”) pandemic, and any related government policies and actions, changes in domestic and global production, supply and demand for commodities, including as a result of the COVID-19 pandemic, actions by OPEC+ and the Russian-Ukrainian military conflict, long-term performance of wells, drilling and operating risks, the increase in service and supply costs, including as a result of inflationary pressures, tariffs on steel, pipeline transportation and storage constraints in the Permian Basin, the possibility of production curtailment, hedging activities, the impacts of severe weather, including the freezing of wells and pipelines in the Permian Basin due to cold weather, possible impacts of litigation and regulations, the impact of the Company’s transactions, if any, with its securities from time to time, the impact of new laws and regulations, including those regarding the use of hydraulic fracturing, the impact of new environmental, health and safety requirements applicable to the Company’s business activities, the possibility of the elimination of federal income tax deductions for oil and gas exploration and development and other factors, including those and other risks described in its Annual Report on Form 10-K for the year ended December 31, 2021, and those set forth from time to time in other filings with the Securities and Exchange Commission (“SEC”). These documents are available through Laredo’s website at www.laredopetro.com under the tab “Investor Relations” or through the SEC’s Electronic Data Gathering and Analysis Retrieval System at www.sec.gov. Any of these factors could cause Laredo’s actual results and plans to differ materially from those in the forward-looking statements. Therefore, Laredo can give no assurance that its future results will be as estimated. Any forward-looking statement speaks only as of the date on which such statement is made. Laredo does not intend to, and disclaims any obligation to, correct, update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. The SEC generally permits oil and natural gas companies, in filings made with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, and certain probable and possible reserves that meet the SEC’s definitions for such terms. In this presentation, the Company may use the terms “resource potential,” “resource play,” “estimated ultimate recovery,” or “EURs,” “type curve” and “standardized measure,” each of which the SEC guidelines restrict from being included in filings with the SEC without strict compliance with SEC definitions. These terms refer to the Company’s internal estimates of unbooked hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. “Resource potential” is used by the Company to refer to the estimated quantities of hydrocarbons that may be added to proved reserves, largely from a specified resource play potentially supporting numerous drilling locations. A “resource play” is a term used by the Company to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section potentially supporting numerous drilling locations, which, when compared to a conventional play, typically has a lower geological and/or commercial development risk. “EURs” are based on the Company’s previous operating experience in a given area and publicly available information relating to the operations of producers who are conducting operations in these areas. Unbooked resource potential and “EURs” do not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules and do not include any proved reserves. Actual quantities of reserves that may be ultimately recovered from the Company’s interests may differ substantially from those presented herein. Factors affecting ultimate recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, decreases in oil, natural gas liquids and natural gas prices, well spacing, drilling and production costs, availability and cost of drilling services and equipment, lease expirations, transportation constraints, regulatory approvals, negative revisions to reserve estimates and other factors, as well as actual drilling results, including geological and mechanical factors affecting recovery rates. “EURs” from reserves may change significantly as development of the Company’s core assets provides additional data. In addition, the Company’s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. “Type curve” refers to a production profile of a well, or a particular category of wells, for a specific play and/or area. The “standardized measure” of discounted future new cash flows is calculated in accordance with SEC regulations and a discount rate of 10%. Actual results may vary considerably and should not be considered to represent the fair market value of the Company’s proved reserves. This presentation includes financial measures that are not in accordance with generally accepted accounting principles (“GAAP”), such as Consolidated EBITDAX and Free Cash Flow. While management believes that such measures are useful for investors, they should not be used as a replacement for financial measures that are in accordance with GAAP. For definitions of such non-GAAP financial measures, please see the Appendix. Unless otherwise specified, references to “average sales price” refer to average sales price excluding the effects of the Company’s derivative transactions. All amounts, dollars and percentages presented in this presentation are rounded and therefore approximate. 2 Forward-Looking / Cautionary Statements
($624) ($644) ($482) ($351) ($454) ($550) ($550) ($246) ($106) $60 $12 ($3) ~$350 ~$550 FY-17A FY-18A FY-19A FY-20A FY-21A FY-22E FY-23E 35% 49% 28.4 41.0 FY-19A FY-22E Multi-Year Strategic Transformation Yields a “New” Laredo 3 Low-cost, efficient and safe operations Optimizing production through digital and innovative solutions Reducing emissions and flaring Local philanthropy and community engagement Committed to diversity and inclusion Added ~57,000 oil-weighted net acres in the Midland Basin ~8 years of inventory primarily across Howard County and western Glasscock County Strong proved reserve base Broad portfolio of digital solutions Hired key leadership roles including CEO, CFO, Chief Sustainability Officer and Chief Technology Officer Refreshed 75% of Board over the past three years Board is 50% diverse based on race/gender Separated Chairman and CEO roles Maximize Free Cash Flow1 Optimize capital structure through debt and leverage reductions Return of capital to shareholders Advance sustainability New Leadership New Strategy New Assets New Capabilities Expanded Inventory Shifted Commodity Mix Reduced Leverage Balanced Investment & Capital Discipline Generating Free Cash Flow1 Outspending Cash Flow Capital Discipline & Portfolio Repositioning FCF Generation2 ~$200MM Stock Repurchase Target ~$700MM Debt Reduction Target Capital Expenditures $MM Free Cash Flow $MM 1See Appendix for definitions of non-GAAP financial measures; 2Assumes WTI oil price $100 / $90 and HH gas price $7.45 / $5.90 for 2022 / 2023 Oil Production Mbo/d & Oil % Portfolio Repositioning 2019 - 2021 Return of Capital 2022+ Net Acres Oil-Weighted ~66,000 Eastern ~100,000
$1.47 Equity $1.47 Equity $1.47 Equity $1.25 Net Debt $0.55 Net Debt $0.55 Net Debt$2.7 $2.7 $3.5 $0.79 Equity Uplift $0.70 Equity Uplift $0.70 Equity Uplift Current $700 MM Debt Reduction 3.5x EV / '22E EBITDA 0.0x 1.0x 2.0x 3.0x 4.0x 5.0x 6.0x 7.0x 8.0x LPI Reducing Debt and Leverage Debt repayment target updated to $700 million by year-end 2023 Achieving leverage target of <1.0x in 1Q-23 Repurchasing Shares Opportunistically Two-year program authorized through May 27, 2024 $200 million stock repurchase target 1See Appendix for definitions of non-GAAP financial measures; 2Less than or equal to $55 breakeven oil price; 3Source JP Morgan Research as of 5/27/2022 3Peer Group (PXD, CTRA, DVN, EOG, HES, CPE, SM, MRO, RRC, CLR, FANG, MTDR, AR, CNX, EQT, PDCE, APA, CHK, MUR, SWN, OVV) “New” Laredo Focused on Driving Shareholder Value Enterprise Value / 2022E EBITDA - Peer Comparison3,4 4 Equitizing Enterprise Value - $B Avg. Multiple 4.4x 3.5x Multiple Maintaining Capital Discipline Strong asset performance supports steady reinvestment rate Ability to maintain current oil production at ~60% reinvestment rate Generating Free Cash Flow1 Two-year projected total of ~$900 million (2022-23) Sustainable Free Cash Flow supported by eight years of oil-weighted inventory2 Expanding Value Trading at a discount to Proved Developed Reserves value Highest 2022-23 Free Cash Flow yield in peer group4 Peer Group Debt Reduction Multiple Expansion Illustrative Value
FY2022-23E 0.0x 2.0x 4.0x 6.0x 8.0x 0% 20% 40% 60% ~$285 ~$310 ~$350 ~$385 ~$400 ~$550 ~$670 ~$800 $80 $90 $100 $110 $80 $90 $100 $110 1See Appendix for definitions of non-GAAP financial measures; 2Assumes WTI oil price $100 / $90 and HH gas price $7.45 / $5.90 for 2022 / 2023; 3Source JP Morgan Research as of 5/27/2022, 2022 4Peer Group (PXD, CTRA, DVN, EOG, HES, CPE, SM, MRO, RRC, CLR, FANG, MTDR, AR, CNX, EQT, PDCE, APA, CHK, MUR, SWN, OVV) Free Cash Flow Inflection Point Drives Return of Capital 5 Significant Free Cash Flow1,2 Generation - $MM EV/EBITDA vs. 2-Year FCF Yield – Peer Comparison3,4Free Cash Flow Sensitivities - $MM Benchmark WTI Oil Price (per BBL) (Benchmark HH Gas Price assumes $7.45/mcf) Avg. LPI 2-Year Free Cash Flow Yield 2022-23E E n te rp ris e V a lu e / 2 0 2 2 E E B IT D A Capex $171 MM ~$125 MM ~$125 MM ~$125 MM ~$550 MM ~$550 MM FCF Realized Hedge Loss 2022E Free Cash Flow Benchmark WTI Oil Price (per BBL) (Benchmark HH Gas Price assumes $5.90/mcf) 2023E Free Cash Flow Free Cash Flow Priorities Stock Repurchases Debt Reduction $900 MM 22% 78%
26 25 34 37 32 32 17 96% 78% 84% 0% 25% 50% 75% 100% 0 10 20 30 40 50 YE-20A YE-21A 1Q-22A 2Q-22E 3Q-22E 4Q-22E 1Q-22E 2.7x 2.1x 1.9x <1.7x <1.5x <1.2x <1.0x YE-20A YE-21A 1Q-22A 2Q-22E 3Q-22E 4Q-22E 1Q-23E 1Based on 17.3 million shares outstanding; 2See Appendix for definitions of non-GAAP financial measures; 3Assumes WTI oil price $100 / $90 and HH gas price $7.45 / $5.90 for 2022 / 2023 4As of 5/27/2022; 5Calculated using mid-point of oil volume guidance; 6Hedges executed as of 5/31/2022 Strengthening Financial Position through Debt Reductions 6 Rapidly Deleveraging through Free Cash Flow Generation Protecting Deleveraging Targets through Prudent Risk ManagementCurrent Debt Maturity Profile4 Net Debt to Consolidated EBITDAX2,3 Crude Oil Hedges Mbo/d vs. Hedged % of Oil $578 $361 $400 $0 $44 $956 2022 2023 2024 2025 2026 2028 2029 Borrowing Base $1,250 MM Elected Commitment $1,000 MM Cash Balance $86 MM Liquidity ~$1,042 MM 9.500% Sr. Notes 2025 10.125% Sr. Notes 2028 7.750% Sr. Notes 2029 Drawn Credit Facility Outstanding Letters of Credit Undrawn Credit Facility 2022-23 Debt Reduction Target ~$700 million Current Liquidity4 ~$1.04 billion Debt Reduction Equal to ~$40 per share1 1Q-23E Net Debt to Consolidated EBITDAX2,3 <1.0x Target ~81% Q2-Q4 2022E5,6 Crude Oil Hedges Hedge % of Crude Oil Projected
3.5x 2.4x 2.4x 2.4x 2.3x 2.3x 2.2x 2.1x 2.0x 2.0x 1.8x 1.8x Average 1.7x 1.6x 1.3x 1.3x 1.3x 1.2x 1.2x 1.1x 1.1x 1.1x 0.9xLPI 7 Significant Upside Potential Supported by Strong Reserves Value 1See Appendix for definitions of non-GAAP financial measures; 2SEC pricing $63 benchmark oil and $3.35 benchmark gas; 3Source Capital One Research as of mid-day 5/31/2022 4Peer Group (PXD, CTRA, DVN, EOG, HES, CPE, SM, MRO, RRC, CLR, FANG, MTDR, AR, CNX, EQT, PDCE, APA, CHK, MUR, SWN, OVV) PV-101,2 Reserve Value Sensitivity - $MM Proven Undeveloped (PUD) Proven Developed Producing (PDP) Current Adj. Enterprise Value/PDP – Peer Comparison3,4 Enterprise Value as of 5/27/2022 P e e r G ro u p
100 125 130 165 165 60 195 275 295 295 ≤$40 ≤$45 ≤$50 ≤$55 Inventory Upside Near-term Development Focus 1Gross operated location as of January 2022 (adjusted for 2021 completions) 2Locations may require the formation of drilling units to develop 3Flat oil price needed to achieve 10% IRR assuming gas price at 20:1 ratio Development Focus Areas ~460 ~320 ~1502 Avg. Breakeven Oil Price3 ~8 Years of Inventory1 Assumes: Current activity pace Low-risk, operated only Current development spacing <$55 breakeven oil price Howard Glasscock Howard W. Glasscock Eastern Reagan Midland Martin Sterling Mitchell ~160 Low Breakeven Oil Inventory Underpins Sustainable Free Cash Flow Generation 8 ~405 Howard W. Glasscock Eastern
0 50 100 150 200 250 0 90 180 270 360 C u m u la ti ve G ro s s E q u iv al e n t P ro d u ct io n p e r W e ll (M B O E) Producing Days 89% 82% 76% 57% 56% 50% 20% 16% 15% 11% 18% 23% 39% 16% 13% 7% 10% 20% 4% 28% 37% 74% 74% 65% 29.2 31.2 25.1 21.9 24.3 26.4 35.3 41.1 40.3 1Q-20 2Q-20 3Q-20 4Q-20 1Q-21 2Q-21 3Q-21 4Q-21 1Q-22 Eastern W. Glasscock Howard 1Production data normalized to 10,000’ lateral length, downtime days excluded; 2Gross operated location as of January 2022 (adjusted for 2021 completions) Strong Asset Performance Drives Consistent Reinvestment Rate Key Asset Statistics Oil Production Growth Driven by Howard County Howard W. Glasscock Net Acres ~33,000 ~33,000 LSS | WCA | WCB Locations2 ~130 ~205 MS | WCD Locations2 ~35 ~90 Total Development Locations2 ~165 ~295 Avg. Lateral Length (ft.) ~11,500’ ~10,500 Avg. WI (%) ~92% ~88% Howard Overview 2022 development program entirely focused on Howard County Consolidated acreage position facilitates drilling of more capital efficient longer laterals Integrating eight Middle Spraberry wells into the 2022 development plan W. Glasscock Overview Successful Wolfcamp D appraisal drilling unlocked ~90 locations, driven by optimized completion design 2024 development plan expected to focus on western Glasscock County North Howard Middle Spraberry (North Howard) Central Howard (2Q-21+) Central Howard (4Q-20 to 1Q-21) W. Glasscock 9 Average Well Performance1 Oil % of Total Production Howard ~80% W. Glasscock ~65%
10,750' 9,950' 10,000' 11,800' FY-19A FY-20A FY-21A FY-22E 1,274' 1,408' 1,653' 1,572' FY-19A FY-20A FY-21A YTD-22A 1,117' 1,314' 1,439' 1,539' FY-19A FY-20A FY-21A YTD-22A ~4 Yrs. Current Sand Inventory2 Drilling Ft. Per Day Per Rig Disciplined, Efficient Capital Program Maintains Prior Year Activity Levels 2022E Capital Program FY-22 Guidance Capital Expenditures ($MM) ~$550 Avg. Rig Count (Op) ~2.3 Avg. Frac Crews (Op) ~1.2 Spuds 65 Gross (62.9 Net) Completions 55 Gross (53.1 Net) Turn-in-Lines 55 Gross (53.1 Net) Production (MBOE/d) 82.0 – 86.0 Oil Production (MBO/d) 39.5 – 42.5 81% 8% 7% 4% Capital Expenditures by Category DC&E (op) Facilities & Land Corporate DC&E (non-op) 10 Continuous Improvement Drives Capital Efficient Drilling and Completion Program Company Owned Sand Mine Reduces Well Costs and Protects Against Inflation Avg. Completed Lateral Length 1Based on Howard County 10,000’ lateral length completions; 2Based on current pace of development Fractured Ft. Per Day Per Crew Located on Laredo owned surface acreage Operated by a third party Reduces emissions by: − Elimination of truck traffic − Utilization of wet sand >$400K Per Well Savings1
Industry Challenge Optimizing compression and operator routes Major contributors to production loss are well downtime and inconsistent gas-lift injection caused by poor compression run-time Data Model and A.I. Solution Dispatch operators to the highest priority wells Monitor compressor operating parameters and detect failures before they occur Initial Pilot Results Pre-Solution Post-Solution 11 Optimizing Production through Digital Solutions and Innovation Focus Delivering on highest value opportunities first Scalability Efficient resource allocation and broad leveraging of skillsets Efficiency Significantly improve use of the operators’ time and skill Automation Efficient resource allocation and broad leveraging of skillsets ESP Optimization Industry Challenge ESP wells need constant monitoring and fine tuning of operating settings to maximize production Excessive downtime driven by too much or too little horsepower, inadequate human coverage, and ultimately ESP failure Artificial Intelligence Solution Automatically recommends and adjusts back pressure, pump speed, and other settings to maximize production and ESP life Initial Pilot Results Key Digitals Solutions Developed and Proven by Laredo Keys to Success Compressor Failure & Dynamic Routing Pre-Solution Post-Solution Pre-Solution Post-Solution Oil Production Uplift Gas Production Uplift Miles Driven per Route Pre-Solution Post-Solution Compressor Run-Time ~$1.5 Million Incremental Cash Flow Achieved During First Month of Pilot ~$3.5 Million Incremental Cash Flow Achieved During First Eight Months of Pilot
1.95% 0.71% 0.37% 0.64% 0.78% FY-19A FY-20A FY-21A YTD-22A Zero routine flaring 12 <12.5 mtCO2e / MBOE <0.20% methane emissions1,2 18.08 17.54 12.50 2019 Baseline 2020 Performance Venting Reductions Flaring Reductions Pnuematics Reductions Combustion Reductions 2025 Target S co p e 1 E m is si o n s m tC O 2 e / M B O E Defined Scope 1 Emissions Reduction Plan Systematic Plan to Achieve Emissions Reductions TrustWellTM Certification First Permian operator to receive TrustWellTM responsibly sourced certification Gold certification awarded for production from 73 horizontal wells representing ~31,500 BOEPD of gross operated production in the certification area Uniquely positioned among Permian Basin operators to benefit as premium markets are developed for certified responsibly sourced production Targets for 2025 12019 calendar year as baseline; 2As a percentage of natural gas production Percentage of Produced Natural Gas Flared / Vented Acquisitions Impact eu i
Generating Significant Free Cash Flow1 Initiating Return of Capital to Shareholders Targeting Debt Reductions and Improved Leverage Equity Upside Potential vs. Peer Group2 1See Appendix for definitions of non-GAAP financial measures 2Peer Group (PXD, CTRA, DVN, EOG, HES, CPE, SM, MRO, RRC, CLR, FANG, MTDR, AR, CNX, EQT, PDCE, APA, CHK, MUR, SWN, OVV) Compelling Investment Opportunity 13
Appendix
2Q-22 & FY-22 GUIDANCE Guidance Commodity Prices Used for 2Q-22 Apr-22 May-22 Jun-22 2Q-22 Avg. Crude Oil: - - - - WTI NYMEX ($/BBO) $101.64 $104.19 $102.25 $102.71 Brent ICE ($/BBO) $105.81 $107.06 $105.36 $106.09 Natural Gas: - - - - Henry Hub ($/MMBTU) $5.34 $7.27 $7.24 $6.62 Waha ($/MMBTU) $4.48 $6.11 $6.36 $5.66 Natural Gas Liquids: - - - - C2 ($/BBL) $21.37 $22.47 $22.47 $22.11 C3 ($/BBL) $54.30 $54.02 $54.08 $54.13 IC4 ($/BBL) $69.71 $72.45 $70.04 $70.75 NC4 ($/BBL) $65.41 $67.88 $66.31 $66.55 C5+ ($/BBL) $95.12 $95.34 $94.76 $95.08 Composite ($/BBL)1 $46.65 $47.39 $47.10 $47.05 2Q-22 FY-22 Production: - - Total Production (MBOE/D) 85.0 – 88.0 82.0 – 86.0 Crude Oil Production (MBO/d) 40.0 – 42.0 39.5 – 42.5 Incurred Capital Expenditures ($MM): ~$125 ~$550 Average Sales Price Realizations (excluding derivatives): - - Crude Oil (% of WTI) 100% - Natural Gas Liquids (% of WTI) 34% - Natural Gas (% of Henry Hub) 68% - Net Settlements Received (Paid) for Matured Commodity Derivatives ($MM): - - Crude Oil ($MM) ($119) - Natural Gas Liquids ($MM) ($16) - Natural Gas ($MM) ($20) - Net Income (Expense) of Purchased Oil ($MM): $0 - Operating Costs & Expenses ($/BOE): - - Lease Operating Expenses $5.35 - Production & Ad Valorem Taxes (% of Oil, NGL & Natural Gas Revenues) 6.5% - Transportation and Marketing Expenses $1.65 - General and Administrative Expenses (excluding LTIP) $1.65 - General and Administrative Expenses (LTIP Cash) $0.45 - General and Administrative Expenses (LTIP Non-Cash) $0.25 - Depletion, Depreciation and Amortization $9.75 - Note: Supports average sales price realization and derivatives guidance 15 1Current NGL composition C2 (42%), C3 (33%), IC4 (3%), NC4 (11%) and C5+ (11%)
(Volume in MBO; Price in $/BBO) Q2-22 Q3-22 Q4-22 FY-22 Q1-23 Q2-23 Q3-23 Q4-23 FY-23 Brent Swaps 1,028 1,040 1,040 3,108 - - - - - WTD Price $48.34 $48.34 $48.34 $48.34 - - - - - Brent Collars 387 391 391 1,169 - - - - - WTD Floor Price $56.65 $56.65 $56.65 $56.65 - - - - - WTD Ceiling Price $65.44 $65.44 $65.44 $65.44 - - - - - WTI Swaps 884 92 92 1,068 - - - - - WTD Price $85.14 $64.40 $64.40 $81.57 - - - - - WTI Collars 1,026 1,408 1,408 3,842 1,530 1,547 460 460 3,997 WTD Floor Price $64.53 $72.32 $72.32 $70.24 $66.18 $66.18 $67.00 $67.00 $66.37 WTD Ceiling Price $77.06 $86.54 $86.54 $84.01 $80.29 $80.29 $84.04 $84.04 $81.16 Total Swaps/Collars 3,325 2,930 2,930 9,186 1,530 1,547 460 460 3,997 WTD Floor Price $64.09 $61.47 $61.47 $62.42 $66.18 $66.18 $67.00 $67.00 $66.37 (Volume in MBBL; Price in $/BBL) Q2-22 Q3-22 Q4-22 FY-22 Q1-23 Q2-23 Q3-23 Q4-23 FY-23 Ethane Swaps 382 386 386 1,155 - - - - - WTD Price $11.42 $11.42 $11.42 $11.42 - - - - - Propane Swaps 291 294 294 880 - - - - - WTD Price $35.91 $35.91 $35.91 $35.91 - - - - - Butane Swaps 91 92 92 275 - - - - - WTD Price $41.58 $41.58 $41.58 $41.58 - - - - - Isobutane Swaps 27 28 28 83 - - - - - WTD Price $42.00 $42.00 $42.00 $42.00 - - - - - Pentane Swaps 91 92 92 275 - - - - - WTD Price $60.65 $60.65 $60.65 $60.65 - - - - - (Volume in MMBTU; Price in $/MMBTU) Q2-22 Q3-22 Q4-22 FY-22 Q1-23 Q2-23 Q3-23 Q4-23 FY-23 Henry Hub Swaps 910,000 920,000 920,000 2,750,000 - - - - - WTD Price $2.73 $2.73 $2.73 $2.73 - - - - - Henry Hub Collars 7,280,000 7,360,000 7,360,000 22,000,000 3,600,000 3,640,000 3,680,000 3,680,000 14,600,000 WTD Floor Price $3.09 $3.09 $3.09 $3.09 $3.75 $3.75 $3.75 $3.75 $3.75 WTD Ceiling Price $3.84 $3.84 $3.84 $3.84 $7.88 $7.88 $7.88 $7.88 $7.88 Total Henry Hub Swaps/Collars 8,190,000 8,280,000 8,280,000 24,750,000 3,600,000 3,640,000 3,680,000 3,680,000 14,600,000 WTD Floor Price $3.05 $3.05 $3.05 $3.05 $3.75 $3.75 $3.75 $3.75 $3.75 Waha Basis Swaps 7,234,500 7,314,000 7,314,000 21,862,500 3,600,000 3,640,000 3,680,000 3,680,000 14,600,000 WTD Price ($0.36) ($0.36) ($0.36) ($0.36) ($1.52) ($1.52) ($1.52) ($1.52) ($1.52) 1Hedges executed as of 5/31/2022 Active Hedge Program to Protect Free Cash Flow 16
$3,716 $3,154 $3,902 $4,649 $5,398 SEC Pricing $55 $65 $75 $85Oil 38% NGL 31% Natural Gas 31% PD, 73% PUD, 27% 1SEC pricing $63 benchmark oil and $3.35 benchmark gas; 2Based only on wells categorized as Proved Developed as of YE-21 and decline calculated Q4 to Q4; 3 See Appendix for definitions of non-GAAP financial measures Oil Reserve Growth Driven by Strategic Portfolio Repositioning Highlights Proved reserves PV-103 improved by ~260% versus YE-20 Strategic acquisitions increased oil reserves by ~65 MMBLs, offset by the sale of 16 MBBLs, leading to an improved oil production mix PUD reserves improved driven by inventory depth and price resiliency PV-103 Reserve Value Sensitivity - $MM1 278 58 (88) 100 (30) 319 YE2020 Revisions & Extensions Sale of Reserves Purchase of Reserves 2021 Production YE2021 78% Oil Growth24% Oil 38% Oil Total Reserves and Resources - MMBOE Benchmark WTI Oil Price (Benchmark HH Gas Price assumes $3.50) Reserves by Category Annual Base Production Decline Expectations2 Reserves by Commodity FY-22 FY-23 FY-24 Howard Oil, MBO/d 57% 34% 24% Total Company 44% 29% 20% Howard Total Production, MBOE/d 53% 32% 23% Total Company 30% 20% 15% 17
1Data as of 12/31/2021; 2Data as of 5/31/2022 Corporate and Community Responsibility Local and Impactful Philanthropy >$820,000 Total amount donated since 2019 to improve our local communities1 Diversity and Inclusion Efforts1 EEO-1 Data Disclosed in Company’s 2021 ESG & Climate Risk Report 27% 26% 61% 50% Women in Workforce Minorities in Workforce Women and/or Minorities in Professional-or-higher Roles Female and Minority Directors2 18
Supplemental Non-GAAP Financial Measures Consolidated EBITDAX (Unaudited) Consolidated EBITDAX is a non-GAAP financial measure defined in the Company’s Senior Secured Credit Facility as net income or loss (GAAP) plus adjustments for extraordinary gains (or losses), non-cash recurring gains (or losses), depletion, depreciation and amortization expense, interest expense, any provisions for (or benefit from) income or franchise taxes, exploration expenses and other non-cash charges. Consolidated EBITDAX is used by the Company’s management for various purposes, including as a measure of operating performance and compliance under the Company’s Senior Secured Credit Facility. Additional information on the calculation of Consolidate EBITDAX can be found in the Company’s Senior Secured Credit Facility, as amended by the Eighth Amendment thereto, as filed with the SEC on April 19, 2022. The following table presents a reconciliation of net income (loss) (GAAP) to Consolidated EBITDAX (non-GAAP) for the periods presented: 19 (in thousands, unaudited) 3/31/2022 12/31/2021 9/30/2021 Net Income (loss) ($86,781) $216,276 $136,832 Plus: Share-settled equity-based compensation, net 2,053 2,066 1,811 Depletion, depreciation and amortization 73,492 74,592 62,678 Mark-to-market on derivatives: (Gain) loss on derivatives, net 325,816 (15,372) 96,240 Settlements paid for matured derivatives, net (125,370) (129,361) (92,726) Accretion expense 1,019 1,026 906 Gain on sale of oil and natural gas properties, net - - (95,223) Loss on disposal of assets, net 260 8,903 22 Interest expense 32,477 31,163 30,406 Income tax (benefit) expense (877) 3,052 2,677 Consolidated EBITDAX (non-GAAP) $222,089 $192,345 $143,623 Three months ended,
Supplemental Non-GAAP Financial Measures PV-10 (Unaudited) PV-10 is a non-GAAP financial measure that is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. Management believes that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to the Company's estimated proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of the Company's proved oil, NGL and natural gas assets. Further, investors may utilize the measure as a basis for comparison of the relative size and value of proved reserves to other companies. The Company uses this measure when assessing the potential return on investment related to proved oil, NGL and natural gas assets. However, PV-10 is not a substitute for the standardized measure of discounted future net cash flows. The PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of the Company's oil, NGL and natural gas reserves of the property. 20 (in millions) December 31, 2021 Standardized measure of discounted future net cash flows $3,425 Less present value of future income taxes discounted at 10% (291) PV-10 (non-GAAP) $3,716
Supplemental Non-GAAP Financial Measures Net Debt (Unaudited) Net Debt, a non-GAAP financial measure, is calculated as the face value of long-term debt plus any outstanding letters of credit, less cash and cash equivalents. Management believes Net Debt is useful to management and investors in determining the Company’s leverage position since the Company has the ability, and may decide, to use a portion of its cash and cash equivalents to reduce debt. Net Debt as of March 31, 2022 was $1.418 billion. Net Debt to Consolidated EBITDAX (Unaudited) Net Debt to Consolidated EBITDAX, a non-GAAP financial measure, is calculated as Net Debt, including letters of credit, divided by Consolidated EBITDAX, as defined in the Company's Senior Secured Credit Facility. For the purposes of calculating Consolidated EBITDAX for the period ended March 31, 2022 calculation is the annualization of the three quarters ended March 31, 2022. Net Debt to Consolidated EBITDAX is used by the Company’s management for various purposes, including as a measure of operating performance, in presentations to its board of directors and as a basis for strategic planning and forecasting. Free Cash Flow (Unaudited) Free Cash Flow is a non-GAAP financial measure that the Company defines as net cash provided by operating activities (GAAP) before changes in operating assets and liabilities, net, less incurred capital expenditures, excluding non-budgeted acquisition costs. Free Cash Flow does not represent funds available for future discretionary use because it excludes funds required for future debt service, capital expenditures, acquisitions, working capital, income taxes, franchise taxes and other commitments and obligations. However, management believes Free Cash Flow is useful to management and investors in evaluating operating trends in its 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 Company is unable to provide a reconciliation of the forward-looking Free Cash Flow projection contained in this presentation to net cash provided by operating activities, the most directly comparable GAAP financial measure, because we cannot reliably predict certain of the necessary components of net cash provided by operating activities, such as changes in working capital, without unreasonable efforts. Such unavailable reconciling information may be significant. 21