Press Release

Updates oil-weighted inventory to ~460 locations, ~8 years of activity

TULSA, OK, Feb. 22, 2022 (GLOBE NEWSWIRE) -- Laredo Petroleum, Inc. (NYSE: LPI) ("Laredo" or the "Company") today announced its fourth-quarter and full-year 2021 financial and operating results. Under a separate press release, the Company today also issued its 2022 outlook. A conference call and webcast to discuss the Company's financial and operating results and its 2022 outlook is planned for 7:30 a.m. CT, Wednesday, February, 23, 2022. Complete details can be found within this release.

2021 Highlights

• Grew development inventory through acquisition of ~41,000 net acres in Howard and western Glasscock counties, adding ~250 high-margin, oil-weighted locations
• Added an additional ~125 oil-weighted locations in the Middle Spraberry formation in Howard County and the Wolfcamp D formation in western Glasscock County following recent appraisal success
• Increased average daily oil production by 19% versus full-year 2020
• Increased total proved reserves by 15% in 2021, including a 78% increase in proved oil reserves. Oil now comprises 38% of total proved reserves versus 24% at year-end 2020
• Accelerated transition to oil-weighted assets through sale of ~94 million BOE of lower-margin gas-weighted reserves, primarily in Glasscock and Reagan counties
• Increased liquidity through the sale of 1.4 million shares of common stock for net proceeds of $72.5 million through the Company's at-the-market equity program and issuance of $400 million of senior notes maturing in 2029
• Reduced Net Debt/Adjusted EBITDA ratio (fourth quarter annualized)¹ to 1.9x at fourth-quarter 2021 from 2.4x at fourth-quarter 2020
• Issued two comprehensive ESG and Climate Risk Reports with data through year-end 2020, establishing goals for reducing greenhouse gas and methane emissions, as well as the elimination of routine flaring by 2025

Fourth-Quarter 2021 Highlights

• Closed acquisition of ~20,000 net acres in western Glasscock County for ~$203 million, net of customary closing price adjustments
• Generated Adjusted EBITDA¹ of $182.2 million and Free Cash Flow¹ of $24.8 million
• Produced 41,080 barrels of oil per day ("BOPD") and 85,240 barrels of oil equivalent per day ("BOEPD"), an increase of 87% and 3%, respectively, versus fourth-quarter 2020, exceeding guidance ranges for both metrics
• Increased oil cut as a percentage of total production to 48% in fourth-quarter 2021 versus 27% in fourth-quarter 2020
• Incurred capital expenditures of $142 million, excluding non-budgeted acquisitions and leasehold expenditures, completing 18 wells with 26 turn-in lines ("TIL") during the quarter

"We posted exceptional results in 2021 and enter 2022 with strong momentum and a clearly defined strategy to add value for shareholders," stated Jason Pigott, President and Chief Executive Officer. "Our team identified and closed two acquisitions that significantly expanded our oil-weighted leasehold in Howard and western Glasscock counties and extended our runway of high-margin drilling locations. We strengthened our balance sheet, purposefully funding portions of the acquisitions with equity and proceeds from the divestiture of lower-margin gas-weighted reserves. Our capital today is being allocated to our highest return opportunities in Howard and western Glasscock counties. We also furthered our commitment to sustainable development, setting meaningful emissions reduction goals and allocating necessary capital to ensure their attainment."

"Our outlook for 2022 is strong and our disciplined development plan will build upon our successes from 2021," continued Mr. Pigott. "We are focused on capital efficient development, generation of Free Cash Flow¹ and leverage reduction. We expect to achieve our initial leverage target of 1.5x Net Debt/Adjusted EBITDA¹ in the third quarter of 2022 and to be below 1.0x by the second half of 2023. As we further strengthen our capital structure, we expect to be in a position to return cash to shareholders in early 2023."

Fourth-Quarter and Full-Year 2021 Financial Results

For the fourth quarter of 2021, the Company reported net income attributable to common stockholders of $216.3 million, or $12.84 per diluted share. Adjusted Net Income¹ for the fourth quarter of 2021 was $57.2 million, or $3.39 per adjusted diluted share. Adjusted EBITDA¹ for the fourth quarter of 2021 was $182.2 million.

For full-year 2021, the Company reported net income attributable to common stockholders of $145.0 million, or $10.03 per diluted share. Adjusted Net Income¹ for full-year 2021 was $128.9 million, or $8.91 per adjusted diluted share. Adjusted EBITDA¹ for full-year 2021 was $505.9 million.

¹Non-GAAP financial measure; please see supplemental reconciliations of GAAP to non-GAAP financial measures at the end of this release.

Oil-Weighted Inventory Update

A key pillar of Laredo's strategy since 2019 has been the acquisition and development of oil-weighted, high-margin inventory. During 2021, the Company sourced and closed two transformational transactions, one in Howard County and one in western Glasscock County, significantly expanding Laredo's oil-weighted inventory.

In Howard County, pro-forma for the acquisition closed in July 2021, the Company had an estimated 225 Lower Spraberry and Wolfcamp A locations, 61 of which were developed in 2021. In late 2021, the Company drilled two appraisal wells in the Middle Spraberry with initial oil productivity far exceeding initial expectations. Based on these results, Laredo has incorporated ~35 Middle Spraberry wells, with an estimated breakeven WTI oil price of <$55 per barrel, into the Company's development inventory.

Laredo is focused on further enhancing capital efficiency in Howard County with extended-reach laterals. The Company has successfully combined 52 10,000-foot and shorter laterals into 26 highly capital efficient 15,000-foot locations. Laredo estimates current development inventory in Howard County to be ~165 locations with an average lateral length of ~11,500 feet.

In western Glasscock County, pro-forma for the acquisition closed in October 2021, the Company had an estimated 175 Lower Spraberry, Wolfcamp A and Wolfcamp B locations, eight of which were developed in 2021. As part of the western Glasscock County development package completed in the fourth quarter of 2021, Laredo developed two Wolfcamp D appraisal wells. The Company has significant experience developing the Wolfcamp D and, based on prior production data, optimized the completion of these two appraisal wells. Initial oil productivity is outperforming expectations, driving an estimated breakeven WTI oil price for Wolfcamp D wells in western Glasscock of $45 - $50 per barrel. The Company has incorporated ~90 Wolfcamp D wells into its western Glasscock inventory.

At the time of the announcement of the western Glasscock acquisition that closed in October 2021, Laredo estimated ~135 oil-weighted locations associated with the acquisition. After further evaluation, the Company now estimates ~150 locations on the acquired properties. Combining existing western Glasscock holdings with the acquired properties, Laredo now estimates an inventory of ~205 Lower Spraberry, Wolfcamp A and Wolfcamp B locations in western Glasscock County. Combined with the Wolfcamp D inventory, Laredo estimates a total of ~295 oil-weighted locations in western Glasscock County.

Laredo estimates combined Howard and western Glasscock County oil-weighted inventory of ~460 locations, with breakeven WTI oil prices ranging from <$40 to <$55 per barrel. At a current development cadence of 55 - 60 wells per year, the Company has an approximately eight-year runway of oil-weighted inventory. Laredo remains committed to a returns-focused development strategy and expects to focus primarily on higher-margin Howard County development in 2022 and 2023.

In the Company's eastern (legacy) acreage, Laredo estimates another ~150 locations with a potential WTI breakeven of <$55 per barrel. Adding these locations into inventory will require additional technical evaluation and, in many cases, the formation of drilling units to optimize returns by extending laterals.

Operations Summary

In the fourth quarter of 2021, the Company's total and oil production averaged 85,240 BOEPD and 41,080 BOPD, respectively. Both metrics exceeded the high-end of guidance, driven by strong well performance in Howard and western Glasscock counties, including the test of the Middle Spraberry in Howard County. Total and oil production for full-year 2021 averaged 81,717 BOEPD and 31,833 BOPD, respectively, with both metrics above the high-end of guidance.

Lease operating expenses ("LOE") for fourth-quarter 2021 were $4.27 per BOE, relatively flat from $4.23 in third-quarter 2021 and in-line with expectations. For full-year 2021, LOE increased to $3.42 versus $2.55 for full-year 2020 as the Company transitioned operations to higher-margin properties in Howard County. Operating expenses in Howard County are higher than the Company's gas-weighted eastern acreage because the oilier properties require different methods of artificial lift that are higher-cost, however, such costs are more than overcome by the higher-margins in Howard County.

During fourth-quarter 2021, Laredo maintained its best-in-class venting/flaring performance and made significant strides reducing venting/flaring on its acquired properties in Howard County. Excluding recently acquired assets in Howard County, Laredo vented/flared 0.38% of produced gas during the fourth-quarter 2021, down from 0.55% during the prior quarter. The Company reduced vented/flared volumes on the acquired properties in Howard County by 81% versus third-quarter 2021, and reduced total Company vented/flared volumes to 0.61% of produced gas during fourth-quarter 2021, down from 1.89% in the prior quarter. For full-year 2021, excluding acquired assets, Laredo vented/flared 0.37% of produced gas, down from 0.71% in full-year 2020.

In the fourth quarter of 2021, the Company completed 18 wells, including 26 TILs, with capital expenditures of $142 million, excluding non-budgeted and leasehold acquisitions. Capital expenditures were higher than expectations, primarily related to inflationary pressures on steel and additional non-operated investments in the recent acquisition areas. For full-year 2021, Laredo completed 67 wells, including 71 TILs, with total capital expenditures of $444 million, excluding non-budgeted acquisitions and leasehold expenditures.

Laredo is currently operating three drilling rigs and two completions crews and expects to complete and TIL 18 wells during the first quarter of 2022. Laredo expects to release one drilling rig and one completions crew by the end of the first-quarter of 2022 and to maintain a two rig/one crew cadence for the remainder of 2022.

2021 Proved Reserves

The Company's total proved reserves increased 15% in 2021, with proved oil reserves increasing 78%, benefiting from Laredo's strategy of acquiring and developing high-return oil-weighted assets. The Company's reserves were valued at $3.4 billion at year-end 2021, based on SEC benchmark pricing of $63.04 per barrel for oil and $3.35 per MMBtu for natural gas. The PV-10 value was $3.7 billion, utilizing the same benchmark prices.

The divestiture of gas-weighted reserves during 2021, combined with the oil-weighted acquisitions, contributed to the increase of oil reserves as a percentage of total reserves to 38% versus 24% the previous year, driving a significant increase in reserve value at higher oil prices. At benchmark prices of $75 WTI and $3.50 NYMEX Henry Hub, the Company estimates the PV-10 value of its year-end 2021 reserves to be $4.6 billion.

Environmental, Social, Governance

Throughout 2021, Laredo made significant strides furthering its already robust environmental, social and governance ("ESG") commitments. The Company's board of directors amended the Nominating and Corporate Governance Committee's charter to include monitoring and evaluation of programs and policies related to ESG matters. The Company established goals for meaningful reductions of greenhouse gas and methane emissions and the elimination of routine flaring by 2025. Additionally, Laredo announced the appointment of a Chief Sustainability Officer and issued two comprehensive ESG and Climate Risk Reports, utilizing reporting standards and frameworks aligned with the Sustainability Accounting Standards Board and the Task Force on Climate-related Financial Disclosures. These reports are available on the Company's website at www.laredopetro.com, under the tab for "Sustainability."

In 2022, for the third consecutive year, Laredo has incorporated environmental metrics into the Company's executive compensation program. For the 2022 short-term incentive program, the metrics have been broadened to include a safety goal, in addition to the spills and flaring goals from the previous two years. Further emphasizing the Company's commitment to sustainable development, three-year emissions reductions targets were incorporated into the long-term incentive plan portion of executive compensation.

Additionally, Laredo increased the transparency of its diversity practices, including disclosure of EEO-1 data in Laredo's 2021 ESG and Climate Risk Report and, in responding to shareholder input, implemented a majority voting standard for director elections and an executive clawback plan.

Incurred Capital Expenditures

During the fourth quarter of 2021, total incurred capital expenditures were $142 million, excluding non-budgeted acquisitions and leasehold expenditures. Investments were higher than expectations due to industry-wide oil field service inflation and non-operated investments. Total investments were comprised of $117 million in drilling and completions activities, including $8 million of non-operated capital, $7 million in land, exploration and data related costs, $10 million in infrastructure, including Laredo Midstream Services investments, and $8 million in other capitalized costs.

For full-year 2021, total incurred capital expenditures were $444 million, excluding non-budgeted acquisitions and leasehold expenditures. Total investments were comprised of $368 million in drilling and completions activities, including $9 million of non-operated capital, $23 million in land, exploration and data related costs, $28 million in infrastructure, including Laredo Midstream Services investments, and $25 million in other capitalized costs.

Liquidity

At December 31, 2021, the Company had outstanding borrowings of $105 million on its $725 million senior secured credit facility, resulting in available capacity, after the reduction for outstanding letters of credit, of $576 million. Including cash and cash equivalents of $57 million, total liquidity was $633 million.

At February 21, 2022, the Company had outstanding borrowings of $145 million on its $725 million senior secured credit facility, resulting in available capacity, after the reduction for outstanding letters of credit, of $536 million. Including cash and cash equivalents of $12 million, total liquidity was $548 million.

First-Quarter and Full-Year 2022 Guidance

The table below reflects the Company's guidance for total and oil production for first-quarter and full-year 2022.

The table below reflects the Company's guidance for select revenue and expense items for the first quarter of 2022.

Conference Call Details

On Wednesday, February 23, 2022, at 7:30 a.m. CT, Laredo will host a conference call to discuss its fourth-quarter and full-year 2021 financial and operating results and management's outlook, the content of which is not part of this earnings release. A slide presentation providing summary financial and statistical information that will be discussed on the call will be posted to the Company's website and available for review. The Company invites interested parties to listen to the call via the Company's website at www.laredopetro.com, under the tab for "Investor Relations." Portfolio managers and analysts who would like to participate on the call should dial 877.930.8286 (international dial-in 253.336.8309), using conference code 3342479, 10 minutes prior to the scheduled conference time. A telephonic replay will be available two hours after the call through Wednesday, March 2, 2022. Participants may access this replay by dialing 855.859.2056, using conference code 3342479.

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 and actions by OPEC+, long-term performance of wells, drilling and operating risks, the increase in service and supply costs, 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, 2020, Current Report on Form 8-K, filed with the Securities and Exchange Commission ("SEC") on May 11, 2021, and those set forth from time to time in other filings with the 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 press release and the conference call, 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 press release and any accompanying disclosures include financial measures that are not in accordance with generally accepted accounting principles ("GAAP"), such as Adjusted EBITDA, Adjusted Net Income 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 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.

Laredo Petroleum, Inc.
Selected operating data

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Laredo Petroleum, Inc.
Consolidated balance sheets

Laredo Petroleum, Inc.
Consolidated statements of operations

Laredo Petroleum, Inc.
Condensed consolidated statements of cash flows

Laredo Petroleum, Inc.
Total incurred capital expenditures

The following table presents the components of the Company's incurred capital expenditures, excluding non-budgeted acquisition costs, for the periods presented:

Laredo Petroleum, Inc.
Supplemental reconciliations of GAAP to non-GAAP financial measures

Non-GAAP financial measures

The non-GAAP financial measures of Free Cash Flow, Adjusted Net Income, Adjusted EBITDA, PV-10 and Net Debt, as defined by the Company, 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, Adjusted Net Income, Adjusted EBITDA, PV-10 and Net Debt 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 (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 following table presents a reconciliation of net cash provided by operating activities (GAAP) to Free Cash Flow (non-GAAP) for the periods presented:

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

Adjusted Net Income (Unaudited)

Adjusted Net Income is a non-GAAP financial measure that the Company defines as income or loss before income taxes (GAAP) plus adjustments for mark-to-market on derivatives, premiums paid or received for commodity derivatives that matured during the period, impairment expense, gains or losses on disposal of assets, other non-recurring income and expenses and adjusted income tax expense. Management believes Adjusted Net Income helps investors in the oil and natural gas industry to measure and compare the Company's performance to other oil and natural gas companies by excluding from the calculation items that can vary significantly from company to company depending upon accounting methods, the book value of assets and other non-operational factors.

The following table presents a reconciliation of income (loss) before income taxes (GAAP) to Adjusted Net Income (non-GAAP) for the periods presented:

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Adjusted EBITDA (Unaudited)

Adjusted EBITDA is a non-GAAP financial measure that the Company defines 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, management believes Adjusted EBITDA is useful to an investor in evaluating the Company's 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 the Company's operations from period to period by removing the effect of its capital structure from its operating structure; and
•  is used by management for various purposes, including as a measure of operating performance, in presentations to the Company's 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 the Company's 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. The Company's measurements of Adjusted EBITDA for financial reporting as compared to compliance under its debt agreements differ.

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

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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.

Net Debt (Unaudited)

Net Debt, a non-GAAP financial measure, is calculated as the face value of long-term debt 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 December 31, 2021 was $1.387 billion.

Net Debt to TTM Adjusted EBITDA (Unaudited)

Net Debt to TTM Adjusted EBITDA is calculated as Net Debt divided by trailing twelve-month Adjusted EBITDA. Net Debt to Adjusted EBITDA 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

Source: Laredo Petroleum, Inc.