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): February 22, 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:
| Title of each class | Trading Symbol | Name of each exchange on which registered | ||||||
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:
| Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) | |||||||||||
| Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) | |||||||||||
| 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 2.02. Results of Operations and Financial Condition.
On February 22, 2022, Laredo Petroleum, Inc. (the "Company") announced its financial and operating results for the quarter and year ended December 31, 2021. Copies of the Company's press release and Presentation (as defined below) are furnished as Exhibits 99.1 and 99.2, respectively, to this Current Report on Form 8-K and are incorporated herein by reference. The Company plans to host a teleconference and webcast on February 23, 2022 at 7:30 am Central Time to discuss these results. To access the call, please dial 877.930.8286 or 253.336.8309 for international callers, and use conference code 3342479. A telephonic replay of the call will be available approximately two hours after the call through Wednesday, March 2, 2022 by dialing 855.859.2056, and using conference code 3342479. The webcast may be accessed at the Company's website, www.laredopetro.com, under the tab "Investor Relations."
In accordance with General Instruction B.2 of Form 8-K, the information furnished under this Item 2.02 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 Securities Exchange Act of 1934, as amended (the "Exchange Act"), or otherwise subject to the liabilities of that section, nor shall such information be deemed incorporated by reference into any filing under the Securities Act of 1933, as amended (the "Securities Act"), or the Exchange Act.
Item 7.01. Regulation FD Disclosure.
On February 22, 2022, the Company furnished the press release described above in Item 2.02 of this Current Report on Form 8-K. The press release is attached hereto as Exhibit 99.1 and incorporated into this Item 7.01 by reference.
On February 22, 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.
On February 22, 2022, the Company also furnished a press release announcing its 2022 capital budget and outlook. A copy of the press release is attached hereto as Exhibit 99.3 and incorporated into this Item 7.01 by reference.
All statements in the press releases, teleconference 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 and Section 21E of 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, 2020, its Current Report on Form 8-K, filed on May 11, 2021, its Annual Report on Form 10-K for the year ended December 31, 2021, to be filed with the SEC, 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 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: February 22, 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 Fourth-Quarter and Full-Year 2021 Financial and Operating Results
Updates oil-weighted inventory to ~460 locations, ~8 years of activity
TULSA, OK - February 22, 2022 - 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.
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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
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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
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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 $548 million.
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First-Quarter and Full-Year 2022 Guidance
The table below reflects the Company's guidance for total and oil production for first-quarter and full-year 2022.
| 1Q-22E | FY-22E | |||||||||||||
| Total production (MBOE per day) | 84.0 - 87.0 | 82.0 - 86.0 | ||||||||||||
| Oil production (MBOPD) | 39.5 - 41.5 | 39.5 - 42.5 | ||||||||||||
| Incurred capital expenditures, excluding non-budgeted acquisitions ($ MM) | ~170 | ~520 | ||||||||||||
The table below reflects the Company's guidance for select revenue and expense items for the first quarter of 2022.
| 1Q-22E | ||||||||
| Average sales price realizations (excluding derivatives): | ||||||||
| Oil (% of WTI) | 100% | |||||||
| NGL (% of WTI) | 34% | |||||||
| Natural gas (% of Henry Hub) | 68% | |||||||
| Net settlements received (paid) for matured commodity derivatives ($ MM): | ||||||||
| Oil | ($82) | |||||||
| NGL | ($11) | |||||||
| Natural gas | ($9) | |||||||
| Other ($ MM): | ||||||||
| Net income (expense) of purchased oil | ($3.0) | |||||||
| Selected average costs & expenses: | ||||||||
| Lease operating expenses ($/BOE) | $4.25 | |||||||
| Production and ad valorem taxes (% of oil, NGL and natural gas sales revenues) | 7.00% | |||||||
| Transportation and marketing expenses ($/BOE) | $1.90 | |||||||
| General and administrative expenses (excluding LTIP, $/BOE) | $1.65 | |||||||
| General and administrative expenses (LTIP cash, $/BOE) | $0.30 | |||||||
| General and administrative expenses (LTIP non-cash, $/BOE) | $0.25 | |||||||
| Depletion, depreciation and amortization ($/BOE) | $9.75 | |||||||
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.
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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
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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.
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Laredo Petroleum, Inc.
Selected operating data
| Three months ended December 31, | Year ended December 31, | |||||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | |||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Sales volumes: | ||||||||||||||||||||||||||
| Oil (MBbl) | 3,779 | 2,018 | 11,619 | 9,827 | ||||||||||||||||||||||
| NGL (MBbl) | 1,976 | 2,636 | 8,678 | 10,615 | ||||||||||||||||||||||
| Natural gas (MMcf) | 12,516 | 17,648 | 57,175 | 70,049 | ||||||||||||||||||||||
Oil equivalents (MBOE)(1)(2) | 7,842 | 7,595 | 29,827 | 32,117 | ||||||||||||||||||||||
Average daily oil equivalent sales volumes (BOE/D)(2) | 85,240 | 82,552 | 81,717 | 87,750 | ||||||||||||||||||||||
Average daily oil sales volumes (Bbl/D)(2) | 41,080 | 21,929 | 31,833 | 26,849 | ||||||||||||||||||||||
Average sales prices(2): | ||||||||||||||||||||||||||
Oil ($/Bbl)(3) | $ | 76.92 | $ | 41.82 | $ | 69.32 | $ | 37.43 | ||||||||||||||||||
NGL ($/Bbl)(3)(5) | $ | 29.58 | $ | 10.82 | $ | 22.08 | $ | 7.37 | ||||||||||||||||||
Natural gas ($/Mcf)(3)(5) | $ | 4.15 | $ | 1.19 | $ | 2.63 | $ | 0.72 | ||||||||||||||||||
Average sales price ($/BOE)(3) | $ | 51.15 | $ | 17.63 | $ | 38.46 | $ | 15.45 | ||||||||||||||||||
Oil, with commodity derivatives ($/Bbl)(4) | $ | 57.83 | $ | 60.52 | $ | 52.09 | $ | 56.41 | ||||||||||||||||||
NGL, with commodity derivatives ($/Bbl)(4) | $ | 11.07 | $ | 11.43 | $ | 10.55 | $ | 9.12 | ||||||||||||||||||
Natural gas, with commodity derivatives ($/Mcf)(4) | $ | 1.69 | $ | 1.31 | $ | 1.56 | $ | 1.02 | ||||||||||||||||||
Average sales price, with commodity derivatives ($/BOE)(4) | $ | 33.36 | $ | 23.08 | $ | 26.36 | $ | 22.50 | ||||||||||||||||||
Selected average costs and expenses per BOE sold(2): | ||||||||||||||||||||||||||
| Lease operating expenses | $ | 4.27 | $ | 2.57 | $ | 3.42 | $ | 2.55 | ||||||||||||||||||
| Production and ad valorem taxes | 2.91 | 1.07 | 2.30 | 1.03 | ||||||||||||||||||||||
| Transportation and marketing expenses | 1.71 | 1.59 | 1.61 | 1.55 | ||||||||||||||||||||||
| Midstream service expenses | 0.14 | 0.09 | 0.12 | 0.12 | ||||||||||||||||||||||
| General and administrative (excluding LTIP) | 1.58 | 1.71 | 1.54 | 1.29 | ||||||||||||||||||||||
| Total selected operating expenses | $ | 10.61 | $ | 7.03 | $ | 8.99 | $ | 6.54 | ||||||||||||||||||
| General and administrative (LTIP): | ||||||||||||||||||||||||||
| LTIP cash | $ | (0.08) | $ | 0.12 | $ | 0.35 | $ | 0.06 | ||||||||||||||||||
| LTIP non-cash | $ | 0.23 | $ | 0.25 | $ | 0.22 | $ | 0.22 | ||||||||||||||||||
| Depletion, depreciation and amortization | $ | 9.51 | $ | 5.56 | $ | 7.22 | $ | 6.76 | ||||||||||||||||||
_______________________________________________________________________________
(1)BOE is calculated using a conversion rate of six Mcf per one Bbl.
(2)The numbers presented are calculated based on actual amounts that are not rounded.
(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 the Company's commodity derivative transactions on it's average sales prices. The Company's 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.
(5)Prices presented for the three months ended December 31, 2021 have been updated from preliminary estimates previously provided in the Company's Current Report on Form 8-K dated January 19, 2022. These changes are the result of final accounting presentation requirements which require the Company's contractual minimum volumes to its customers be recorded as a reduction to the transaction price, as these amounts do not represent payments to the customer for distinct goods or services and instead relate specifically to the failure to perform under the specific customer contract. Such amounts are recorded as a reduction to the transaction price when payment is determined as probable, typically when such a deficiency occurs.
9
Laredo Petroleum, Inc.
Consolidated balance sheets
| (in thousands, except share data) | December 31, 2021 | December 31, 2020 | ||||||||||||
| (unaudited) | ||||||||||||||
| Assets | ||||||||||||||
| Current assets: | ||||||||||||||
| Cash and cash equivalents | $ | 56,798 | $ | 48,757 | ||||||||||
| Accounts receivable, net | 151,807 | 63,976 | ||||||||||||
| Derivatives | 4,346 | 7,893 | ||||||||||||
| Other current assets | 22,906 | 15,964 | ||||||||||||
| Total current assets | 235,857 | 136,590 | ||||||||||||
| Property and equipment: | ||||||||||||||
| Oil and natural gas properties, full cost method: | ||||||||||||||
| Evaluated properties | 8,968,668 | 7,874,932 | ||||||||||||
| Unevaluated properties not being depleted | 170,033 | 70,020 | ||||||||||||
| Less: accumulated depletion and impairment | (7,019,670) | (6,817,949) | ||||||||||||
| Oil and natural gas properties, net | 2,119,031 | 1,127,003 | ||||||||||||
| Midstream service assets, net | 96,528 | 112,697 | ||||||||||||
| Other fixed assets, net | 34,590 | 32,011 | ||||||||||||
| Property and equipment, net | 2,250,149 | 1,271,711 | ||||||||||||
| Derivatives | 32,963 | — | ||||||||||||
| Operating lease right-of-use assets | 11,514 | 17,973 | ||||||||||||
| Other noncurrent assets, net | 21,341 | 16,336 | ||||||||||||
| Total assets | $ | 2,551,824 | $ | 1,442,610 | ||||||||||
| Liabilities and stockholders' equity | ||||||||||||||
| Current liabilities: | ||||||||||||||
| Accounts payable and accrued liabilities | $ | 71,386 | $ | 38,279 | ||||||||||
| Accrued capital expenditures | 50,585 | 28,275 | ||||||||||||
| Undistributed revenue and royalties | 117,920 | 24,728 | ||||||||||||
| Derivatives | 179,809 | 31,826 | ||||||||||||
| Operating lease liabilities | 7,742 | 11,721 | ||||||||||||
| Other current liabilities | 99,471 | 62,766 | ||||||||||||
| Total current liabilities | 526,913 | 197,595 | ||||||||||||
| Long-term debt, net | 1,425,858 | 1,179,266 | ||||||||||||
| Derivatives | — | 12,051 | ||||||||||||
| Asset retirement obligations | 69,057 | 64,775 | ||||||||||||
| Operating lease liabilities | 5,726 | 8,918 | ||||||||||||
| Other noncurrent liabilities | 10,490 | 1,448 | ||||||||||||
| Total liabilities | 2,038,044 | 1,464,053 | ||||||||||||
| Commitments and contingencies | ||||||||||||||
| Stockholders' equity: | ||||||||||||||
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of December 31, 2021 and December 31, 2020 | — | — | ||||||||||||
Common stock, $0.01 par value, 22,500,000 shares authorized and 17,074,516 and 12,020,164 issued and outstanding as of December 31, 2021 and December 31, 2020, respectively | 171 | 120 | ||||||||||||
| Additional paid-in capital | 2,788,628 | 2,398,464 | ||||||||||||
| Accumulated deficit | (2,275,019) | (2,420,027) | ||||||||||||
| Total stockholders' equity | 513,780 | (21,443) | ||||||||||||
| Total liabilities and stockholders' equity | $ | 2,551,824 | $ | 1,442,610 | ||||||||||
10
Laredo Petroleum, Inc.
Consolidated statements of operations
| Three months ended December 31, | Year ended December 31, | |||||||||||||||||||||||||
| (in thousands, except per share data) | 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Revenues: | ||||||||||||||||||||||||||
| Oil sales | $ | 290,696 | $ | 84,380 | $ | 805,448 | $ | 367,792 | ||||||||||||||||||
| NGL sales | 58,470 | 28,525 | 191,591 | 78,246 | ||||||||||||||||||||||
| Natural gas sales | 51,918 | 20,960 | 150,104 | 50,317 | ||||||||||||||||||||||
| Midstream service revenues | 2,337 | 1,534 | 6,629 | 8,249 | ||||||||||||||||||||||
| Sales of purchased oil | 66,803 | 52,666 | 240,303 | 172,588 | ||||||||||||||||||||||
| Total revenues | 470,224 | 188,065 | 1,394,075 | 677,192 | ||||||||||||||||||||||
| Costs and expenses: | ||||||||||||||||||||||||||
| Lease operating expenses | 33,468 | 19,549 | 101,994 | 82,020 | ||||||||||||||||||||||
| Production and ad valorem taxes | 22,785 | 8,115 | 68,742 | 33,050 | ||||||||||||||||||||||
| Transportation and marketing expenses | 13,439 | 12,041 | 47,916 | 49,927 | ||||||||||||||||||||||
| Midstream service expenses | 1,135 | 704 | 3,707 | 3,762 | ||||||||||||||||||||||
| Costs of purchased oil | 67,603 | 56,728 | 251,061 | 194,862 | ||||||||||||||||||||||
| General and administrative | 13,619 | 15,840 | 62,801 | 50,534 | ||||||||||||||||||||||
| Organizational restructuring expenses | — | — | 9,800 | 4,200 | ||||||||||||||||||||||
| Depletion, depreciation and amortization | 74,592 | 42,210 | 215,355 | 217,101 | ||||||||||||||||||||||
| Impairment expense | — | 109,804 | 1,613 | 899,039 | ||||||||||||||||||||||
| Other operating expenses | 134 | 1,105 | 4,233 | 4,430 | ||||||||||||||||||||||
| Total costs and expenses | 226,775 | 266,096 | 767,222 | 1,538,925 | ||||||||||||||||||||||
| Gain on sale of oil and natural gas properties, net | — | — | 93,482 | — | ||||||||||||||||||||||
| Operating income (loss) | 243,449 | (78,031) | 720,335 | (861,733) | ||||||||||||||||||||||
| Non-operating income (expense): | ||||||||||||||||||||||||||
| Gain (loss) on derivatives, net | 15,372 | (81,935) | (452,175) | 80,114 | ||||||||||||||||||||||
| Interest expense | (31,163) | (26,139) | (113,385) | (105,009) | ||||||||||||||||||||||
| Gain on extinguishment of debt, net | — | 22,309 | — | 8,989 | ||||||||||||||||||||||
| Gain (loss) on disposal of assets, net | (8,903) | 94 | (8,931) | (963) | ||||||||||||||||||||||
| Write-off of debt issuance costs | — | — | — | (1,103) | ||||||||||||||||||||||
| Other income, net | 573 | 978 | 2,809 | 1,586 | ||||||||||||||||||||||
| Total non-operating income (expense), net | (24,121) | (84,693) | (571,682) | (16,386) | ||||||||||||||||||||||
| Income (loss) before income taxes | 219,328 | (162,724) | 148,653 | (878,119) | ||||||||||||||||||||||
| Income tax (expense) benefit: | ||||||||||||||||||||||||||
| Current | (24) | — | (1,324) | — | ||||||||||||||||||||||
| Deferred | (3,028) | (3,208) | (2,321) | 3,946 | ||||||||||||||||||||||
| Total income tax (expense) benefit | (3,052) | (3,208) | (3,645) | 3,946 | ||||||||||||||||||||||
| Net income (loss) | $ | 216,276 | $ | (165,932) | $ | 145,008 | $ | (874,173) | ||||||||||||||||||
| Net income (loss) per common share: | ||||||||||||||||||||||||||
| Basic | $ | 13.07 | $ | (14.18) | $ | 10.18 | $ | (74.92) | ||||||||||||||||||
| Diluted | $ | 12.84 | $ | (14.18) | $ | 10.03 | $ | (74.92) | ||||||||||||||||||
| Weighted-average common shares outstanding: | ||||||||||||||||||||||||||
| Basic | 16,545 | 11,702 | 14,240 | 11,668 | ||||||||||||||||||||||
| Diluted | 16,846 | 11,702 | 14,464 | 11,668 | ||||||||||||||||||||||
11
Laredo Petroleum, Inc.
Condensed consolidated statements of cash flows
| Three months ended December 31, | Year ended December 31, | |||||||||||||||||||||||||
| (in thousands) | 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Cash flows from operating activities: | ||||||||||||||||||||||||||
Net income (loss) | $ | 216,276 | $ | (165,932) | $ | 145,008 | $ | (874,173) | ||||||||||||||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||||||||||||||||
| Share-settled equity-based compensation, net | 2,066 | 2,106 | 7,675 | 8,217 | ||||||||||||||||||||||
| Depletion, depreciation and amortization | 74,592 | 42,210 | 215,355 | 217,101 | ||||||||||||||||||||||
| Impairment expense | — | 109,804 | 1,613 | 899,039 | ||||||||||||||||||||||
| Gain on sale of oil and natural gas properties, net | — | — | (93,482) | — | ||||||||||||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||||||||||||||
| (Gain) loss on derivatives, net | (15,372) | 81,935 | 452,175 | (80,114) | ||||||||||||||||||||||
Settlements (paid) received for matured derivatives, net | (129,361) | 41,786 | (320,868) | 228,221 | ||||||||||||||||||||||
| Settlements received for early-terminated commodity derivatives, net | — | — | — | 6,340 | ||||||||||||||||||||||
Premiums received (paid) for commodity derivatives | — | — | 9,041 | (51,070) | ||||||||||||||||||||||
| Gain on extinguishment of debt, net | — | (22,309) | — | (8,989) | ||||||||||||||||||||||
| Deferred income tax expense (benefit) | 3,028 | 3,208 | 2,321 | (3,946) | ||||||||||||||||||||||
| Other, net | 15,417 | 4,767 | 32,319 | 22,723 | ||||||||||||||||||||||
| Cash flows from operating activities before changes in operating assets and liabilities, net | 166,646 | 97,575 | 451,157 | 363,349 | ||||||||||||||||||||||
| Change in current assets and liabilities, net | 22,215 | 17,601 | 49,321 | 36,699 | ||||||||||||||||||||||
| Change in noncurrent assets and liabilities, net | 20,698 | (5,406) | (3,807) | (16,658) | ||||||||||||||||||||||
Net cash provided by operating activities | 209,559 | 109,770 | 496,671 | 383,390 | ||||||||||||||||||||||
| Cash flows from investing activities: | ||||||||||||||||||||||||||
| Acquisitions of oil and natural gas properties, net | (136,367) | (12,223) | (763,411) | (35,786) | ||||||||||||||||||||||
| Capital expenditures: | ||||||||||||||||||||||||||
| Oil and natural gas properties | (139,515) | (69,082) | (418,362) | (347,359) | ||||||||||||||||||||||
| Midstream service assets | (474) | (654) | (2,849) | (3,171) | ||||||||||||||||||||||
| Other fixed assets | (2,705) | (1,235) | (5,931) | (4,259) | ||||||||||||||||||||||
| Proceeds from dispositions of capital assets, net of selling costs | — | 95 | 393,742 | 1,337 | ||||||||||||||||||||||
Net cash used in investing activities | (279,061) | (83,099) | (796,811) | (389,238) | ||||||||||||||||||||||
| Cash flows from financing activities: | ||||||||||||||||||||||||||
| Borrowings on Senior Secured Credit Facility | 145,000 | 35,000 | 570,000 | 80,000 | ||||||||||||||||||||||
| Payments on Senior Secured Credit Facility | (70,000) | (15,000) | (720,000) | (200,000) | ||||||||||||||||||||||
| Issuance of January 2025 Notes and January 2028 Notes | — | — | — | 1,000,000 | ||||||||||||||||||||||
| Issuance of July 2029 Notes | — | — | 400,000 | — | ||||||||||||||||||||||
| Extinguishment of debt | — | (38,139) | — | (846,994) | ||||||||||||||||||||||
| Proceeds from issuance of common stock, net of offering costs | — | — | 72,492 | — | ||||||||||||||||||||||
| Payments for debt issuance costs | (89) | (28) | (14,686) | (18,479) | ||||||||||||||||||||||
| Other, net | (7) | (5) | 375 | (779) | ||||||||||||||||||||||
Net cash provided by (used in) financing activities | 74,904 | (18,172) | 308,181 | 13,748 | ||||||||||||||||||||||
| Net increase in cash and cash equivalents | 5,402 | 8,499 | 8,041 | 7,900 | ||||||||||||||||||||||
| Cash and cash equivalents, beginning of period | 51,396 | 40,258 | 48,757 | 40,857 | ||||||||||||||||||||||
| Cash and cash equivalents, end of period | $ | 56,798 | $ | 48,757 | $ | 56,798 | $ | 48,757 | ||||||||||||||||||
12
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:
| Three months ended December 31, | Year ended December 31, | |||||||||||||||||||||||||
| (in thousands) | 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Oil and natural gas properties | $ | 137,892 | $ | 74,223 | $ | 444,337 | $ | 344,160 | ||||||||||||||||||
| Midstream service assets | 420 | 288 | 2,842 | 2,985 | ||||||||||||||||||||||
| Other fixed assets | 3,578 | 1,056 | 6,807 | 4,148 | ||||||||||||||||||||||
| Total incurred capital expenditures, excluding non-budgeted acquisition costs | $ | 141,890 | $ | 75,567 | $ | 453,986 | $ | 351,293 | ||||||||||||||||||
13
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:
| Three months ended December 31, | Year ended December 31, | |||||||||||||||||||||||||
| (in thousands) | 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Net cash provided by operating activities | $ | 209,559 | $ | 109,770 | $ | 496,671 | $ | 383,390 | ||||||||||||||||||
| Less: | ||||||||||||||||||||||||||
| Change in current assets and liabilities, net | 22,215 | 17,601 | 49,321 | 36,699 | ||||||||||||||||||||||
| Change in noncurrent assets and liabilities, net | 20,698 | (5,406) | (3,807) | (16,658) | ||||||||||||||||||||||
| Cash flows from operating activities before changes in operating assets and liabilities, net | 166,646 | 97,575 | 451,157 | 363,349 | ||||||||||||||||||||||
| Less incurred capital expenditures, excluding non-budgeted acquisition costs: | ||||||||||||||||||||||||||
Oil and natural gas properties(1) | 137,892 | 74,223 | 444,337 | 344,160 | ||||||||||||||||||||||
Midstream service assets(1) | 420 | 288 | 2,842 | 2,985 | ||||||||||||||||||||||
| Other fixed assets | 3,578 | 1,056 | 6,807 | 4,148 | ||||||||||||||||||||||
| Total incurred capital expenditures, excluding non-budgeted acquisition costs | 141,890 | 75,567 | 453,986 | 351,293 | ||||||||||||||||||||||
| Free Cash Flow (non-GAAP) | $ | 24,756 | $ | 22,008 | $ | (2,829) | $ | 12,056 | ||||||||||||||||||
_____________________________________________________________________________
(1)Includes capitalized share-settled equity-based compensation and asset retirement costs.
14
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:
| Three months ended December 31, | Year ended December 31, | |||||||||||||||||||||||||
| (in thousands, except per share data) | 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
Income (loss) before income taxes | $ | 219,328 | $ | (162,724) | $ | 148,653 | $ | (878,119) | ||||||||||||||||||
| Plus: | ||||||||||||||||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||||||||||||||
| (Gain) loss on derivatives, net | (15,372) | 81,935 | 452,175 | (80,114) | ||||||||||||||||||||||
Settlements (paid) received for matured derivatives, net | (129,361) | 41,786 | (320,868) | 228,221 | ||||||||||||||||||||||
| Settlements received for early-terminated commodity derivatives, net | — | — | — | 6,340 | ||||||||||||||||||||||
Net premiums paid for commodity derivatives that matured during the period(1) | (10,183) | — | (41,553) | (477) | ||||||||||||||||||||||
| Organizational restructuring expenses | — | — | 9,800 | 4,200 | ||||||||||||||||||||||
| Impairment expense | — | 109,804 | 1,613 | 899,039 | ||||||||||||||||||||||
| Gain on sale of oil and natural gas properties, net | — | — | (93,482) | — | ||||||||||||||||||||||
| Gain on extinguishment of debt, net | — | (22,309) | — | (8,989) | ||||||||||||||||||||||
| (Gain) loss on disposal of assets, net | 8,903 | (94) | 8,931 | 963 | ||||||||||||||||||||||
| Write-off of debt issuance costs | — | — | — | 1,103 | ||||||||||||||||||||||
| Adjusted income before adjusted income tax expense | 73,315 | 48,398 | 165,269 | 172,167 | ||||||||||||||||||||||
Adjusted income tax expense(2) | (16,129) | (10,648) | (36,359) | (37,877) | ||||||||||||||||||||||
| Adjusted Net Income (non-GAAP) | $ | 57,186 | $ | 37,750 | $ | 128,910 | $ | 134,290 | ||||||||||||||||||
| Net income (loss) per common share: | ||||||||||||||||||||||||||
| Basic | $ | 13.07 | $ | (14.18) | $ | 10.18 | $ | (74.92) | ||||||||||||||||||
| Diluted | $ | 12.84 | $ | (14.18) | $ | 10.03 | $ | (74.92) | ||||||||||||||||||
| Adjusted Net Income per common share: | ||||||||||||||||||||||||||
| Basic | $ | 3.46 | $ | 3.23 | $ | 9.05 | $ | 11.51 | ||||||||||||||||||
| Diluted | $ | 3.39 | $ | 3.23 | $ | 8.91 | $ | 11.51 | ||||||||||||||||||
| Adjusted diluted | $ | 3.39 | $ | 3.22 | $ | 8.91 | $ | 11.47 | ||||||||||||||||||
| Weighted-average common shares outstanding: | ||||||||||||||||||||||||||
| Basic | 16,545 | 11,702 | 14,240 | 11,668 | ||||||||||||||||||||||
| Diluted | 16,846 | 11,702 | 14,464 | 11,668 | ||||||||||||||||||||||
| Adjusted diluted | 16,846 | 11,709 | 14,464 | 11,712 | ||||||||||||||||||||||
_______________________________________________________________________________
(1)Reflects net premiums paid previously or upon settlement that are attributable to derivatives settled in the respective periods presented.
(2)Adjusted income tax expense is calculated by applying a statutory tax rate of 22% for each of the periods ended December 31, 2021 and 2020.
15
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:
| Three months ended December 31, | Year ended December 31, | |||||||||||||||||||||||||
| (in thousands) | 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Net income (loss) | $ | 216,276 | $ | (165,932) | $ | 145,008 | $ | (874,173) | ||||||||||||||||||
| Plus: | ||||||||||||||||||||||||||
| Share-settled equity-based compensation, net | 2,066 | 2,106 | 7,675 | 8,217 | ||||||||||||||||||||||
| Depletion, depreciation and amortization | 74,592 | 42,210 | 215,355 | 217,101 | ||||||||||||||||||||||
| Impairment expense | — | 109,804 | 1,613 | 899,039 | ||||||||||||||||||||||
| Gain on sale of oil and natural gas properties, net | — | — | (93,482) | — | ||||||||||||||||||||||
| Organizational restructuring expenses | — | — | 9,800 | 4,200 | ||||||||||||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||||||||||||||
| (Gain) loss on derivatives, net | (15,372) | 81,935 | 452,175 | (80,114) | ||||||||||||||||||||||
Settlements (paid) received for matured derivatives, net | (129,361) | 41,786 | (320,868) | 228,221 | ||||||||||||||||||||||
| Settlements received for early-terminated commodity derivatives, net | — | — | — | 6,340 | ||||||||||||||||||||||
Net premiums paid for commodity derivatives that matured during the period(1) | (10,183) | — | (41,553) | (477) | ||||||||||||||||||||||
| Accretion expense | 1,026 | 1,105 | 4,233 | 4,430 | ||||||||||||||||||||||
| (Gain) loss on disposal of assets, net | 8,903 | (94) | 8,931 | 963 | ||||||||||||||||||||||
| Interest expense | 31,163 | 26,139 | 113,385 | 105,009 | ||||||||||||||||||||||
| Gain on extinguishment of debt, net | — | (22,309) | — | (8,989) | ||||||||||||||||||||||
| Write-off of debt issuance costs | — | — | — | 1,103 | ||||||||||||||||||||||
| Income tax expense (benefit) | 3,052 | 3,208 | 3,645 | (3,946) | ||||||||||||||||||||||
| Adjusted EBITDA (non-GAAP) | $ | 182,162 | $ | 119,958 | $ | 505,917 | $ | 506,924 | ||||||||||||||||||
_____________________________________________________________________________
(1)Reflects net premiums paid previously or upon settlement that are attributable to derivatives settled in the respective periods presented.
16
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.
| (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 | ||||||
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
17
4Q-21 and FY-21 Earnings Presentation EXHIBIT 99.2
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 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 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 Adjusted EBITDA 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
Optimize Capital Structure Targeting leverage of <1.5x5 by 3Q-22 and <1.0x5 by 2H-23 Utilize FCF5 to reduce debt Maintain strong liquidity profile Improve cost of capital Return of capital to shareholders YE-21 Reserves 319 MMBOE (~38% Oil) $3.7B PV-103 Enterprise Value Market Capitalization1 $2.7 Billion $1.2 Billion (17.1mm Shares) Laredo Petroleum (NYSE: LPI) | Pure-Play Permian Energy Producer 1As of market close 2/18/2022; 2Assumes current activity pace; 3Assumes SEC pricing of $63 WTI oil & $3.35 HH gas 4Q4-21 annualized, which includes current Laredo operations, after closing of Pioneer W. Glasscock acquisition; 5See Appendix for definitions of non-GAAP financial measures Acreage FootprintCompany Snapshot Corporate Principles Driving Shareholder Value Net Acres | Years of Inventory2 ~166,000 ~8 Years Q4-21A Production 85.2 MBOE/D ~48% Oil Net Debt to Adjusted EBITDA 1.9x4 <1.5x5 YE-21A 3Q-22E Scope 1 Emissions mtCO2e/MBOE 17.5 12.5 2020A 2025 Target Leasehold Acreage Glasscock Howard Reagan Martin Midland Upton Sterling Irion Mitchell Dawson Borden TX Maximize Free Cash Flow High grade development to maximize capital efficiency Commodity mix improvement Focus on efficiencies and low-cost operations Disciplined hedge program Build scale through accretive transactions Advance Sustainability Formalized Board of Directors ESG oversight Meaningful emissions reduction targets Pay linked to performance ESG reporting aligned to industry- standard frameworks Diversity transparency via EEO-1 data disclosure 3
1See Appendix for definitions of non-GAAP financial measures; 2Assumes WTI oil price of $80 and HH gas price of $4.65 Strong Value Creation Built on Disciplined Execution 4 2022 Plan to Generate Significant Free Cash Flow to Reduce Leverage Free Cash Flow1,2 >$300 million Net Debt to Adjusted EBITDA1 3Q-22 <1.5x “Our outlook for 2022 is strong and our disciplined development plan will build upon our successes of 2021.” — Jason Pigott, President & CEO RETURN OF CAPITAL TO SHAREHOLDERS DISCIPLINED EXECUTION OF STRATEGY UNDERPINS VALUE CREATION FREE CASH FLOW1 EXPANSION 2019 - 2021 2022 2023+ GREW INVENTORY SHIFTED COMMODITY MIX REDUCED LEVERAGE FREE CASH FLOW1 GENERATION ACCELERATE LEVERAGE REDUCTION RETURN OF CAPITAL TO SHAREHOLDERS FREE CASH FLOW1 EXPANSION Acceleration of Value through Accretive Transactions MAINTENANCE CAPITAL
2.4x 1.9x <1.5x YE-20A YE-21A YE-22E 31% 39% ~49% FY-20A FY-21A FY-22E 1YE-20 & YE-21 represent Q4 annualized, which includes current Laredo operations, after closing of Pioneer W. Glasscock acquisition; 2See Appendix for definitions of non-GAAP financial measures Delivered on Value Creation Strategy in 2021 Shifting Production Mix Improving Leverage Ratio1,2 Expanded Oil-Weighted Acreage HOWARD ~33,500 total net acres ~21,000 added in 2021 W. GLASSCOCK ~33,000 total net acres ~20,000 added in 2021Reagan Martin Midland Glasscock Howard Upton Mitchell Sterling Irion2021 Acquisitions Oil Production % of Total Production Net Debt-to-Adjusted EBITDA 5 Inventory Growth through Accretive Transactions Acquired ~41,000 net acres in Howard and W. Glasscock counties ~250 high-margin, oil-weighted locations Incremental Inventory Unlocked with Appraisal Drilling ~125 locations added in Howard and W. Glasscock counties Middle Spraberry (~35 locations) and Wolfcamp D (~90 locations) Strong Oil Production and Reserve Growth Avg. daily oil production increased 19% FY-21 vs. FY-20 Exited 2021 with improved production mix of ~48% oil Grew proved oil reserves by 78% in 2021 Oil reserves now account for 38% of total reserves vs. 24% at YE-20 Improved Leverage through High-Margin Production Reduced leverage ratio by ~0.5x1 vs. YE-20 Enhanced ESG Processes and Transparency Issued two comprehensive ESG and Climate Risk Reports Established goals to reduce greenhouse gas and methane emissions Committed to eliminating routine flaring by 2025
$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 Oil Reserve Growth Driven by Strategic Portfolio Repositioning Highlights Proved reserves PV-10 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-10 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% 6
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 Significant Expansion of Oil-Weighted Inventory in 2021 7 ~405 Howard W. Glasscock Eastern
0 10 20 30 40 50 60 0 15 30 45 60 75 C u m u la ti v e G ro s s O il P ro d u c ti o n p e r W e ll ( M B O ) Producing Days 0 25 50 75 100 125 150 175 200 0 90 180 270 360 C u m u la ti v e G ro s s O il P ro d u c ti o n p e r W e ll (M B O ) Producing Days 1Gross operated location as of January 2022 (adjusted for 2021 completions); 2Production data normalized to 10,000’ lateral length, downtime days excluded Howard County Inventory and Well Performance Avg. LSS/WCA Well Performance2 Howard Borden North Howard Central Howard Middle Spraberry Performance2 Net Acres ~33,500 Q4-21A Net Production (MBOE/D) | % Oil 40.1 | 76% Producing Well Count 178 LSS / WCA Locations1 ~130 MS Locations1 ~35 Total Development Locations1 ~165 Avg. Lateral Length (ft.) ~11,500’ Avg. WI (%) ~92% Highlights Acquisition closed in July 2021 expanded acreage position by ~21,000 contiguous net acres 2022 development program entirely focused on Howard County Consolidated acreage position facilitates drilling of more capital efficient longer laterals Inventory further increased by ~35 locations, driven by appraisal drilling of Middle Spraberry, to which zero value was attributed in acquisition underwriting Thumper D 4MS Thumper B 2MS North Howard Central Howard (Wider-Spacing) Central Howard (Tighter-Spacing) Howard - Key Stats and Acreage Position 8
0 25 50 75 100 125 150 0 90 180 270 360 C u m u la ti v e G ro s s O il P ro d u c ti o n p e r W e ll ( M B O ) Producing Days Cook Package Books Package 0 10 20 30 40 50 60 0 15 30 45 60 75 90 C u m u la ti v e G ro s s O il P ro d u c ti o n p e r W e ll ( M B O ) Producing Days Glasscock Reagan W. Glasscock Eastern W. Glasscock County Inventory and Well Performance Avg. LSS/WCA/WCB Well Performance2 Wolfcamp D Performance2 Net Acres ~33,000 Q4-21A Net Production (MBOE/D) | % Oil 6.8 | 57% Producing Well Count 240 LSS / WCA / WCB Locations1 ~205 WCD Locations1 ~90 Total Development Locations1 ~295 Avg. Lateral Length (ft.) ~10,500’ Avg. WI (%) ~88% Highlights Bolt-on acquisition that closed in October 2021 expanded acreage position by ~20,000 net acres Transaction enabled further expansion of longer lateral development locations Completed a 10-well package in 4Q-21, including two Wolfcamp D appraisal wells Successful Wolfcamp D appraisal drilling unlocked ~90 locations, driven by optimized completion design Optimized Wolfcamp D Completion Design Historical Wolfcamp D Average W. Glasscock - Key Stats and Acreage Position 9 1Gross operated location as of January 2022 (adjusted for 2021 completions); 2Production data normalized to 10,000’ lateral length, downtime days excluded 0 5 10 15 20 25 0 15 30 45 Producing Days 38% Outperformance
Drilling & Completion Efficiencies ~$865 ~$925 ~$975 ~$1,015 $65 $75 $85 $95 80% 9% 7% 4% Disciplined, Efficient Capital Program Maintains Prior Year Activity Levels 2022E Capital Program FY-22 Guidance Capital Expenditures ($MM) ~$520 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 Capital Expenditures by Category DC&E (op) Facilities & Land Corporate DC&E (non-op) 10 Benchmark WTI Oil Price (per BB (Benchmark HH Gas Price assumes $4.65/mcf) 2022E Operated Turn-in-Line Well Count 6 15 15 12 6 18 7 15 15 1Q-22E 2Q-22E 3Q-22E 4Q-22E N. Howard C. Howard 2022E EBITDA Sensitivity - $MM(2) 1,117 1,314 1,439 1,274 1,408 1,653 FY-19A FY-20A FY-21A Drilling Ft./Day/Rig Fractured Ft./Day/Crew 10,750' 9,950' 10,000' 11,800' FY-19A FY-20A FY-21A FY-22E FY-19A FY-20A FY-21A FY-22E Avg. Completed Lateral Length
2022E Total Production, MBOE/d 82.0 – 86.0 2022E Oil Production, MBO/d 39.5 – 42.5 2022E Oil Cut ~49% of total Howard County Completions ~55 wells $6.36 $7.06 $7.82 $8.30 $10.32 $10.59 $16.39 $17.63 $28.48 $29.71 $44.11 $51.34 $41 $43 $58 $66 $71 $77 Q3-20A Q4-20A Q1-21A Q2-21A Q3-21A Q4-21A Cash Costs Cash Margin Realized Price WTI 1Excludes impacts of hedges and interest payments; 2Includes the following charges (LOE, Transportation, Production Taxes, Ad Valorem Taxes, Cash G&A & Cash LTIP) Increased Oil Cut & Margin Improvement Drives Free Cash Flow Generation 11 Net Total Production - MBOE/d vs. Oil Production - MBO/d Production MixCash Margin - $/BOE1,2 25 22 24 26 35 41 41 63 61 55 59 41 44 43 88 83 79 86 77 85 84 Q3-20A Q4-20A Q1-21A Q2-21A Q3-21A Q4-21A 2022E Crude Oil Natural Gas & Natural Gas Liquids 29% 27% 31% 31% 46% 48% 49% 71% 73% 69% 69% 54% 52% 51% Q3-20A Q4-20A Q1-21A Q2-21A Q3-21A Q4-21A 2022E Crude Oil Natural Gas & Natural Gas Liquids FY-22 Mid-Point FY-22 Mid-Point
~70% ~45% ~73% Natural Gas Natural Gas Liquids Crude Oil 2.4x 1.9x <1.5x <1.0x YE-20A YE-21A YE-22E YE-23E $578 $361 $400 $145 $580 2022 2023 2024 2025 2026 2028 2029 1See Appendix for definitions of non-GAAP financial measures; 2Assumes WTI oil price of $80 and HH gas price of $4.65; 3As of 2/18/2022 4YE-20 & YE-21 equals Q4 annualized, represents current Laredo operations, after closing of Pioneer W. Glasscock acquisition; 5Calculated using guidance mid-point Free Cash Flow Supports Debt Reduction Net Debt to Adjusted EBITDA1,4 Current Debt Maturity Profile32022E Volumes Hedged5 Borrowing Base $1,000 MM Elected Commitment $725 MM Cash Balance $13 MM Liquidity ~$550 MM 9.500% Sr. Notes 2025 10.125% Sr. Notes 2028 7.750% Sr. Notes 2029 Drawn Credit Facility Undrawn Credit Facility 12 2022E Free Cash Flow1,2 >$300 million Current Liquidity3 ~$550 million 3Q-22E Net Debt to Adj. EBITDA1 <1.5x Target 2H-23E Net Debt to Adj. EBITDA1 <1.0x Target
Zero routine flaring 13 <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 c o p e 1 E m is s io n s m tC O 2 e / M B O E Defined Scope 1 Emissions Reduction Plan Systematic Plan to Achieve Emissions Reductions Venting Reductions Continuous Monitoring Expanded LDAR Program Flaring Reductions Gas Takeaway Optionality Enhanced Facility Designs Pneumatics Reductions Convert to Non-Vent Devices Combustion Reductions Electrify Compression and Other Field Operations Targets for 2025 12019 calendar year as baseline; 2As a percentage of natural gas production 1.95% 0.71% 0.37% 0.78% 2019A 2020A 2021A Percentage of Produced Natural Gas Flared / Vented Acquisitions Impact eu i
1Data as of 12/31/2021 Corporate and Community Responsibility Local and Impactful Philanthropy >$820,000 Total amount donated since 2019 to improve our local communities1 Diversity and Inclusion Efforts1 EEO-1 Data Disclosed in Company’s 2021 ESG & Climate Risk Report 27% 26% 61% 56% Women in Workforce Minorities in Workforce Women and/or Minorities in Professional-or-higher Roles Female and Minority Directors 14
Appendix
1Q-22 & FY-22 GUIDANCE Guidance Commodity Prices Used for 1Q-22 Jan-22 Feb-22 Mar-22 1Q-22 Avg. Crude Oil: - - - - WTI NYMEX ($/BBO) $82.98 $91.00 $89.48 $87.71 Brent ICE ($/BBO) $85.48 $92.50 $90.74 $89.47 Natural Gas: - - - - Henry Hub ($/MMBTU) $4.02 $6.27 $4.49 $4.88 Waha ($/MMBTU) $4.55 $4.42 $3.93 $4.30 Natural Gas Liquids: - - - - C2 ($/BBL) $15.80 $16.64 $16.01 $16.13 C3 ($/BBL) $48.85 $52.93 $53.18 $51.61 IC4 ($/BBL) $64.16 $63.70 $61.43 $63.07 NC4 ($/BBL) $63.32 $63.50 $61.27 $62.67 C5+ ($/BBL) $81.58 $87.56 $87.05 $85.32 Composite ($/BBL)1 $40.62 $42.98 $42.43 $41.98 1Q-22 FY-22 Production: - - Total Production (MBOE/D) 84.0 – 87.0 82.0 – 86.0 Crude Oil Production (MBO/d) 39.5 – 41.5 39.5 – 42.5 Incurred Capital Expenditures ($MM): ~$170 ~$520 Average Sales Price Realizations (excluding derivatives): - - Crude Oil (% of WTI) 100% - Natural Gas Liquids (% of WTI) 34% - Natural Gas (% of Henry Hub) 68% - Net Settlements Received (Paid) for Matured Commodity Derivatives ($MM): - - Crude Oil ($MM) ($82) - Natural Gas Liquids ($MM) ($11) - Natural Gas ($MM) ($9) - Net Income (Expense) of Purchased Oil ($MM): ($3.0) - Operating Costs & Expenses ($/BOE): - - Lease Operating Expenses $4.25 - Production & Ad Valorem Taxes (% of Oil, NGL & Natural Gas Revenues) 7.0% - Transportation and Marketing Expenses $1.90 - General and Administrative Expenses (excluding LTIP) $1.65 - General and Administrative Expenses (LTIP Cash) $0.30 - General and Administrative Expenses (LTIP Non-Cash) $0.25 - Depletion, Depreciation and Amortization $9.75 - Note: Supports average sales price realization and derivatives guidance 16 1Current NGL composition C2 (42%), C3 (33%), IC4 (3%), NC4 (11%) and C5+ (11%)
Crude Oil Hedge Book (1) (Volume in MBO; Price in $/BBO) Q1-22 Q2-22 Q3-22 Q4-22 FY-22 Q1-23 Q2-23 Q3-23 Q4-23 FY-23 Brent Swaps 1,017 1,028 1,040 1,040 4,125 - - - - - WTD Price $48.34 $48.34 $48.34 $48.34 $48.34 - - - - - Brent Collars 383 387 391 391 1,551 - - - - - WTD Floor Price $56.65 $56.65 $56.65 $56.65 $56.65 - - - - - WTD Ceiling Price $65.44 $65.44 $65.44 $65.44 $65.44 - - - - - WTI Swaps 810 884 92 92 1,878 - - - - - WTD Price $68.91 $85.14 $64.40 $64.40 $76.11 - - - - - WTI Collars 837 846 856 856 3,395 1,260 1,274 184 184 2,902 WTD Floor Price $58.23 $58.23 $58.23 $58.23 $58.23 $65.00 $65.00 $60.00 $60.00 $64.37 WTD Ceiling Price $69.39 $69.39 $69.39 $69.39 $69.39 $78.30 $78.30 $75.66 $75.66 $77.96 Total Swaps/Collars 3,047 3,145 2,378 2,378 10,948 1,260 1,274 184 184 2,902 WTD Floor Price $57.57 $62.36 $53.88 $53.88 $57.34 $65.00 $65.00 $60.00 $60.00 $64.37 Natural Gas Liquids Hedge Book(1) (Volume in MBBL; Price in $/BBL) Q1-22 Q2-22 Q3-22 Q4-22 FY-22 Q1-23 Q2-23 Q3-23 Q4-23 FY-23 Ethane Swaps 378 382 386 386 1,533 - - - - - WTD Price $11.42 $11.42 $11.42 $11.42 $11.42 - - - - - Propane Swaps 288 291 294 294 1,168 - - - - - WTD Price $35.91 $35.91 $35.91 $35.91 $35.91 - - - - - Butane Swaps 90 91 92 92 365 - - - - - WTD Price $41.58 $41.58 $41.58 $41.58 $41.58 - - - - - Isobutane Swaps 27 27 28 28 110 - - - - - WTD Price $42.00 $42.00 $42.00 $42.00 $42.00 - - - - - Pentane Swaps 90 91 92 92 365 - - - - - WTD Price $60.65 $60.65 $60.65 $60.65 $60.65 - - - - - Natural Gas Hedge Book(1) (Volume in MMBTU; Price in $/MMBTU) Q1-22 Q2-22 Q3-22 Q4-22 FY-22 Q1-23 Q2-23 Q3-23 Q4-23 FY-23 Henry Hub Swaps 900,000 910,000 920,000 920,000 3,650,000 - - - - - WTD Price $2.73 $2.73 $2.73 $2.73 $2.73 - - - - - Henry Hub Collars 7,200,000 7,280,000 7,360,000 7,360,000 29,200,000 900,000 910,000 920,000 920,000 3,650,000 WTD Floor Price $3.09 $3.09 $3.09 $3.09 $3.09 $3.00 $3.00 $3.00 $3.00 $3.00 WTD Ceiling Price $3.84 $3.84 $3.84 $3.84 $3.84 $4.45 $4.45 $4.45 $4.45 $4.45 Total Henry Hub Swaps/Collars 8,100,000 8,190,000 8,280,000 8,280,000 32,850,000 900,000 910,000 920,000 920,000 3,650,000 WTD Floor Price $3.05 $3.05 $3.05 $3.05 $3.05 $3.00 $3.00 $3.00 $3.00 $3.00 Waha Basis Swaps 7,155,000 7,234,500 7,314,000 7,314,000 29,017,500 - - - - - WTD Price ($0.36) ($0.36) ($0.36) ($0.36) ($0.36) - - - - - 1Hedges executed as of 2/18/2022 Active Hedge Program to Protect Free Cash Flow 17
(in thousands, unaudited) 3/31/2021 6/30/2021 9/30/2021 12/31/2021 Net Income (loss) ($75,439) ($132,661) $136,832 $216,276 Plus: Share-settled equity-based compensation, net 2,068 1,730 1,811 2,066 Depletion, depreciation and amortization 38,109 39,976 62,678 74,592 Impairment expense — 1,613 — — (Gain) loss on sale of oil and natural gas properties, net — 1,741 (95,223) — Organizational restructuring expenses — 9,800 — — Mark-to-market on derivatives: (Gain) loss on derivatives, net 154,365 216,942 96,240 (15,372) Settlements paid for matured derivatives, net (41,174) (57,607) (92,726) (129,361) Net premiums paid for commodity derivatives that matured during the period(1) (11,005) (10,183) (10,182) (10,183) Accretion expense 1,143 1,158 906 1,026 (Gain) loss on disposal of assets, net 72 (66) 22 8,903 Interest expense 25,946 25,870 30,406 31,163 Income tax (benefit) expense (762) (1,322) 2,677 3,052 Adjusted EBITDA $93,323 $96,991 $133,441 $182,162 Three months ended, Supplemental Non-GAAP Financial Measures Adjusted EBITDA 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 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 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 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. 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): 18
(in thousands, unaudited) 3/31/2021 6/30/2021 9/30/2021 12/31/2021 Net Income (loss) ($75,439) ($132,661) $136,832 $216,276 Organizational restructuring expenses — 9,800 — — (Gain) loss on sale of oil and natural gas properties, net — 1,741 (95,223) — (Gain) loss on disposal of assets, net 72 (66) 22 8,903 Consolidated Net Income (Loss) ($75,367) ($121,186) $41,631 $225,179 Mark-to-market on derivatives: (Gain) loss on derivatives, net 154,365 216,942 96,240 (15,372) Settlements paid for matured derivatives, net (41,174) (57,607) (92,726) (129,361) Mark-to-market loss on derivatives, net $113,191 $159,335 $3,514 ($144,733) Premiums received (paid) for commodity derivatives 9,041 — — — Non-Cash Charges/Income: Deferred income tax (benefit) expense (762) (1,322) 1,377 3,028 Depletion, depreciation and amortization 38,109 39,976 62,678 74,592 Share-settled equity-based compensation, net 2,068 1,730 1,811 2,066 Accretion expense 1,143 1,158 906 1,026 Impairment expense — 1,613 — — Interest expense 25,946 25,870 30,406 31,163 Consolidated EBITDAX after EBITDAX Adjustments (limited to 15%) (non-GAAP) $113,369 $107,174 $142,323 $192,321 Three months ended, Supplemental Non-GAAP Financial Measures Consolidated EBITDAX (Credit Agreement Calculation) “Consolidated EBITDAX” means, for any Person for any period, the Consolidated Net Income of such Person for such period, plus each of the following, to the extent deducted in determining Consolidated Net Income without duplication, determined for such Person and its Consolidated Subsidiaries on a consolidated basis for such period: any provision for (or less any benefit from) income or franchise Taxes; interest expense (as determined under GAAP as in effect as of December 31, 2016), depreciation, depletion and amortization expense; exploration expenses; and other non-cash charges to the extent not already included in the foregoing clauses (ii), (iii) or (iv), plus the aggregate Specified EBITDAX Adjustments during such period; provided that the aggregate Specified EBITDAX Adjustments shall not exceed fifteen percent (15%) of the Consolidated EBITDAX for such period prior to giving effect to any Specified EBITDAX Adjustments for such period, and minus all non-cash income to the extent included in determining Consolidated Net Income. For the purposes of calculating Consolidated EBITDAX for any Rolling Period in connection with any determination of the financial ratio contained in Section 10.1(b), if during such Rolling Period, Borrower or any Consolidated Subsidiary shall have made a Material Disposition or Material Acquisition, the Consolidated EBITDAX for such Rolling Period shall be calculated after giving pro forma effect thereto as if such Material Disposition or Material Acquisition, as applicable, occurred on the first day of such Rolling Period. For additional information, please see the Company's Fifth Amended and Restated Credit Agreement, as amended, dated May 2, 2017 as filed with Securities and Exchange Commission. The following table presents a reconciliation of net income (loss) (GAAP) to Consolidated EBITDAX (Credit Agreement Calculation; non-GAAP): 19
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 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 12-31-2021 was $1.387 B. Net Debt to TTM Adjusted EBITDA 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. Free Cash Flow 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 it 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
EXHIBIT 99.3
15 West 6th Street, Suite 900 · Tulsa, Oklahoma 74119 · (918) 513-4570 · Fax: (918) 513-4571
www.laredopetro.com
Laredo Petroleum Provides 2022 Capital Budget and Outlook
Plan expected to deliver >$300 million of Free Cash Flow1 in 2022
Company expects to achieve deleveraging targets ahead of schedule
TULSA, OK - February 22, 2022 - Laredo Petroleum, Inc. (NYSE: LPI) ("Laredo" or the "Company") today announced its capital budget and production guidance for full-year 2022.
Highlights
•Allocates capital to highest-return opportunities, prioritizing the generation of Free Cash Flow1 and leverage reduction
•Maintains capital discipline with flat activity levels versus 2021, with expected total capital expenditures of ~$520 million, including ~$20 million for non-operated activity and ~$10 million for ESG focused investments
•Generates expected Free Cash Flow1 of >$300 million at $80 WTI and $4.65 Henry Hub
•Accelerates achievement of deleveraging targets by approximately six months. Company expects to achieve 1.5x Net Debt/Adjusted EBITDA1 ratio in third-quarter 2022 and below 1.0x by the second half of 2023
•Holds oil production approximately flat with 4Q-21 levels and generates expected full-year oil production growth of 24 -34% versus prior year, driven primarily by production acquired in the second-half of 2021
•Improves capital efficiency through longer-lateral completions, with average lateral length for 2022 expected to be ~11,800 feet, including 18 15,000-foot wells
"Our 2022 capital budget and expectations are a direct result of the transformational nature of the transactions we executed in 2021," stated Jason Pigott, President and CEO. "The well-timed acquisitions and efficient integration of the properties into our development plan dramatically increased our capital efficiency and oil cut, driving our expected Free Cash Flow1 generation and enabling us to further strengthen our balance sheet. Combined, these important steps are expected to position the Company to return cash to shareholders by early 2023."
Laredo’s 2022 capital budget maintains the Company’s commitment to capital discipline, holding its rig and completions crew count flat with 2021. Activity and capital levels are front-end loaded, with the year’s highest level of investment occurring in the first quarter of 2022, during which the Company is operating three drilling rigs and two completions crews for much of the quarter. Laredo plans to release one drilling rig and one completions crew by
the end of the first quarter and operate a constant two drilling rigs and one completions crew for the balance of 2022.
The Company’s 2022 development plan is focused entirely on capital efficient, oil-weighted Howard County inventory. Efficiencies are expected to further improve with 18 15,000-foot wells in the 2022 plan and average lateral length increasing ~18% to 11,800 feet. Laredo expects to hold full-year 2022 average daily oil production relatively flat with Q4-21 levels.
The primary driver for the expected increase in 2022 capital expenditures versus 2021 is a robust inflationary environment, with Laredo anticipating average inflation of ~15% for 2022. The Company has contracted a significant portion of its services and tangible goods through the first half of 2022. Other significant differences from 2021 investments include ~$20 million for non-operated activities and ~$10 million for facility upgrades to improve emissions on recently acquired properties.
1Non-GAAP financial measure; please see definitions of non-GAAP financial measures at the end of this release.
Full-Year 2022 Guidance
The table below reflects the Company's guidance for total and oil production, incurred capital expenditures and selected activity metrics.
| FY-22E | |||||||||||
| Total production (MBOE per day) | 82.0 - 86.0 | ||||||||||
| Oil production (MBOPD) | 39.5 - 42.5 | ||||||||||
| Incurred capital expenditures, excluding non-budgeted acquisitions ($ MM) | ~520 | ||||||||||
| Average drilling rigs | 2.3 | ||||||||||
| Average completions crews | 1.2 | ||||||||||
| TILs/Completions/Spuds | 55/55/65 | ||||||||||
| Average lateral length (ft.) | 11,800 | ||||||||||
| Average WI% | 97% | ||||||||||
Forward-Looking Statements
This press release and any oral statements made regarding the contents of this release 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
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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.
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.
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;
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•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.
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 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
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