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, 2021
(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, 2021, the Company announced its financial and operating results for the quarter and year ended December 31, 2020. Copies of the Company's press release and Presentation (as defined below) are furnished as Exhibit 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, 2021 at 7:30 am Central Time to discuss these results. To access the call, please dial 1.877.930.8286 or 1.253.336.8309 for international callers, and use conference code 7561618. A replay of the call will be available through Tuesday, March 2, 2021, by dialing 1.855.859.2056, and using conference code 7561618. 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 the 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 and exhibits be deemed incorporated by reference in 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, 2021, 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, 2021, 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, 2021, the Company also issued a press release announcing it had published its 2020 ESG and Climate Risk Report. 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 release, teleconference and the 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, 2019 and the Company's Annual Report on Form 10-K for the year ended December 31, 2020, 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 the Form 8-K, the information furnished under this Item 7.01 of this Current Report on Form 8-K and the exhibits attached hereto are deemed to be "furnished" and shall not be deemed "filed" for the purpose of Section 18 of the Exchange Act, or otherwise subject to the liabilities of that section, nor shall such information and exhibits be deemed incorporate by reference in 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, 2021 | 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 2020 Financial and Operating Results
Provides 2021 Capital Budget and Production Expectations
TULSA, OK - February 22, 2021 - Laredo Petroleum, Inc. (NYSE: LPI) ("Laredo" or the "Company") today announced its fourth-quarter and full-year 2020 financial and operating results.
Full-Year 2020 Highlights
•Fully transitioned development operations to Howard County acreage and successfully completed the Company's first well package
•Added 4,000 net acres in Howard County at an average price of $7,200 per net undeveloped acre
•Produced an average of 87,750 barrels of oil equivalent ("BOE") per day and 26,849 barrels of oil per day ("BOPD"), an increase of 8% and a decrease of 6%, respectively, from full-year 2019, while reducing capital expenditures by 27% over the same period
•Reduced drilling and completions costs during the year by 21%, to $540 per foot from $680 per foot
•Reduced unit lease operating expenses ("LOE") by 17% from full-year 2019
•Reduced unit general and administrative expenses ("G&A"), excluding long-term incentive plan expenses ("LTIP"), by 21% from full-year 2019
•Reduced volume of flared/vented natural gas by 58% from full-year 2019, flaring/venting only 0.71% of the Company's produced natural gas during full-year 2020
•Received $234.1 million from settlements of matured/terminated derivatives
•Extended all term-debt maturities to 2025 and 2028 and repurchased $61 million of term-debt in open market purchases for 62.5% of par
"Despite the unprecedented challenges of COVID and the resulting energy demand and commodity price weakness during 2020, the Laredo team adapted to working remotely and executed on the transformational strategy we communicated in November 2019," stated Jason Pigott, President and Chief Executive Officer. "We continued to deliver by driving down drilling and completions costs, reducing both unit LOE and G&A expenses, adding additional acreage in Howard County and managing financial risk by extending our term-debt maturities and maintaining a robust commodity hedging program."
Full-Year 2021 Outlook and Highlights
•2021 capital budget is expected to generate $25 million to $40 million of Free Cash Flow1 at $52.50 WTI and $2.75 Henry Hub
•2021 capital budget is expected to maximize capital efficiency with consistent activity throughout the year, which, combined with lower costs, results in 25% more completed lateral feet than 2020, with the same drilling and completions budget
•Focus on oily development in Howard County expected to generate consistent oil production growth
•Release of the Company's inaugural ESG and Climate Risk Report, which outlines reduction targets for GHG emissions, methane emissions and flaring and discloses data in alignment with Sustainability Accounting Standards Board ("SASB"), the Task Force on Climate-related Financial Disclosures ("TCFD") and the International Petroleum Industry Environmental Conservation Association ("IPIECA") frameworks
"We are very excited about our budgeted plan for 2021," continued Mr. Pigott. "Our first development package in Howard County continues to perform well and we began completions operations on our second package in the fourth quarter of 2020. Focusing our capital in Howard County during 2021 is expected to result in meaningful capital efficiency gains and Free Cash Flow generation. We have also released our inaugural ESG and Climate Risk Report and are pleased to highlight our successes in all ESG practices and demonstrate our commitment to sustainable development by setting year-end 2025 GHG intensity, flaring and methane emission reduction targets. As we move forward with our plan, we expect the sustainable, highly productive development strategy we have implemented to create value for all of our stakeholders."
2020 Financial Results
For the fourth quarter of 2020, the Company reported a net loss attributable to common stockholders of $165.9 million, or $14.18 per diluted share, which includes a non-cash full cost ceiling impairment charge of $109.8 million. Adjusted Net Income, a non-GAAP financial measure, for the fourth quarter of 2020 was $37.8 million, or $3.22 per adjusted diluted share. Adjusted EBITDA, a non-GAAP financial measure, for the fourth quarter of 2020 was $120.0 million.
For full-year 2020, the Company reported a net loss attributable to common stockholders of $874.2 million, or $74.92 per diluted share, which includes a non-cash full cost ceiling impairment charge of $889.5 million. Adjusted Net Income for full-year 2020 was $134.3 million, or $11.47 per adjusted diluted share, and Adjusted EBITDA was $506.9 million.
Please see supplemental financial information at the end of this release for reconciliations of non-GAAP financial measures, including calculations of Adjusted EBITDA, Adjusted Net Income and Free Cash Flow.
Environmental, Social, Governance
Laredo has consistently demonstrated its commitment to sustainable development, investing in the infrastructure and equipment required to minimize the flaring and venting of produced natural gas and reduce spills of both oil and water. During 2020, Laredo reduced its flared/vented natural gas volumes by 58% from full-year 2019,
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decreasing flared/vented natural gas as a percentage of produced natural gas from 1.95% in 2019 to 0.71% in 2020. Relatedly, in the second half of 2020, the Company flared/vented just 0.12% of its produced natural gas, further demonstrating its position as one of the best operators in the basin. Additionally, Laredo reduced its oil/water spill rate by 29% during 2020, employing improved monitoring technology to quicken response times.
Although Laredo's flaring and venting practices are already among the best in the Permian Basin, the Board furthered the Company's commitment in 2020 by including flaring/venting and oil/water spills metrics in the executive compensation program. These metrics will be further aligned in 2021 with the emission reductions targets announced in our inaugural ESG and Climate Risk Report.
Laredo is determined to maintain its leadership in sustainability practices and, accordingly, today released its inaugural ESG and Climate Risk Report, based on 2019 data. The Company's disclosures are in alignment with SASB, TCFD and IPIECA reporting frameworks and highlight Laredo's Board diversity and women in leadership, as well as the Company's emissions reduction targets. The Company is proud of its commitment to reduce GHG intensity by 20%, reduce methane emissions to less than 0.20% of natural gas production and eliminate routine flaring, all by 2025. Enhancing this commitment, the Board amended the Nominating and Corporate Governance Committee charter to include the monitoring and evaluation of programs and policies relating to ESG matters and has updated the committee name to the Nominating, Corporate Governance, Social and Environmental Committee to reflect these responsibilities.
Additionally, the Company named David Ferris as Vice President and Chief Sustainability Officer. David will join Laredo in late February and brings a wealth of operational and ESG leadership experience. As a consultant, David was instrumental in the completion of the Company's inaugural ESG and Climate Risk Report and will be managing future efforts related to the Company's emissions reduction targets and the implementation of its ESG strategies.
Operations Summary
In the fourth quarter of 2020, Laredo's total production averaged 82,552 BOE per day, including oil production of 21,929 BOPD. During the quarter, the Company completed 15 wells, all in Howard County. Additionally, completions activities on the Company's second well package were ahead of schedule, as work on four wells was accelerated into the fourth quarter of 2020 from the first quarter of 2021.
Laredo's first wells in Howard County, the 15-well Passow/Gilbert package, are expected to reach peak rates during the first quarter of 2021 and have a significant impact on first-quarter 2021 oil production. All wells in the package have begun producing oil and oil production on the four Lower Spraberry wells is still increasing. The package maintained average production of 10,000 gross BOPD for 26 consecutive days prior to the arrival of the winter storms currently impacting the Permian Basin.
Extended freezing temperatures and severe icing have affected the Company's Permian Basin operations for the last 12 days. As always, Laredo's commitment to the safety of its team members and managing its environmental impact is the Company's first priority, and Laredo has experienced zero safety incidents and fluid releases due to the weather.
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Multiple challenges, including lack of field gas and electricity needed for power, shuttered takeaway and processing capacity, access to well sites and facilities, and inoperable vapor recovery units necessary for environmental compliance, have impeded production operations over this 12-day time frame. Additionally, completions operations were unable to proceed, delaying the drilling out of plugs on the Company's 12-well Trentino/Whitmire package in Howard County.
Through the hard work and dedication of our team members, drilling and completions operations have resumed and production is returning to pre-storm levels. The Company currently estimates that the combined impact of shut-in production and completions delays will reduce first-quarter 2021 total production by approximately 8,000 BOE per day and oil production by approximately 3,000 BOPD.
The Company is currently operating two drilling rigs and one completions crew in Howard County. Laredo expects to complete 12 wells in Howard County during the first quarter of 2021, although they will be pushed to the end of the quarter due to weather delays.
2020 Reserves
Laredo grew proved developed reserves by 4% in 2020, an increase of 10.0 million BOE from volumes at year-end 2019. The primary driver of this increase was the shift in development to Howard County, where the Company booked 7.4 million BOE (65% oil) of proved developed reserves, representing 10% of Laredo's proved developed reserves value.
Proved undeveloped reserves ("PUDs") declined by 25.1 million BOE in 2020, primarily as a result of PUD reserves being converted to proved developed reserves and fewer new PUD locations being booked in a low commodity price environment. Laredo has traditionally been conservative in booking PUDs, which now represent only 9% of proved reserves by volume and 5% by value.
Laredo's proved reserves were valued at $1.01 billion at year-end 2020, based on SEC benchmark pricing of $36.04 for oil and $1.21 for natural gas. The PV-10 value, a non-GAAP financial measure, of the Company's proved reserves at year-end 2020 was $1.03 billion, of which $971 million was proved developed reserves. At benchmark prices of $50 WTI and $2.75 Henry Hub, Laredo estimates the PV-10 value of its year-end 2020 proved developed reserves to be $1.76 billion.
Expenses
Laredo substantially reduced both operating and G&A expenses during 2020. Combined unit LOE and G&A, excluding LTIP, were $3.84 per BOE during 2020, a reduction of 18% from $4.71 per BOE in 2019.
In 2021, the Company expects unit LOE to increase from 2020 levels and to average of slightly more than $3.00 per BOE. Utilization of ESPs for artificial lift in Howard County is expected to result in higher operating expenses compared to the Company's established leasehold, but is minimal compared to the higher margins generated in Howard County.
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Total G&A, including LTIP, during 2021 is expected to remain flat on a total dollar basis as the Company remains focused on maintaining current staffing levels, but will likely increase slightly on a unit basis as total production is expected to be lower versus 2020.
Fourth-Quarter and Full-Year 2020 Costs Incurred
During the fourth quarter of 2020, total costs incurred were $76 million, excluding non-budgeted acquisitions, comprised of $66 million in drilling and completions activities, $1 million in land, exploration and data related costs, $2 million in infrastructure, including Laredo Midstream Services investments, and $7 million in other capitalized costs. Costs incurred during the fourth quarter of 2020 slightly exceeded the high end of Company expectations due to completions activity that was planned for first-quarter 2021 being accelerated into fourth-quarter 2020.
Total costs incurred for full-year 2020 were $351 million, a reduction of $131 million from 2019.
2021 Budget and Production Expectations
The Company's capital program for 2021 is almost entirely focused on the development of its highly productive Howard County leasehold. Operations are designed to maximize capital efficiency by consistently running one completions crew for the entire year. Continued improvements in drilled and completed feet per day in the Company's Howard County operations and innovations such as the Company-owned sand mine are driving additional productivity gains and higher activity levels, without adding additional completions crews or drilling rigs.
Laredo expects to invest $360 million in 2021, excluding non-budgeted acquisitions. The components of the capital program include $300 million for drilling, completions and equipment, $30 million for production facilities and equipment and land, and $30 million for other capitalized items.
The Company expects its 2021 development plan to result in a significant improvement in overall capital efficiency with a full-year of operations directed to Howard County. Oil production for full-year 2021 is expected to average 27,250 - 29,250 BOPD, reduced for weather impact of 750 BOPD, with steady growth anticipated throughout the year. Total production is expected to decline to an average of 80,000 - 85,000 BOE per day, reduced for weather impact of 2,000 BOE per day, as the Company moves development from its gassier, established acreage position to its oilier, new acreage position in Howard County.
The 2021 capital plan is supported by a very robust hedging program, with 78% of expected 2021 oil production and 68% of expected 2021 total production hedged, based on the midpoint of guidance. At benchmark pricing of $52.50 WTI and $2.75 Henry Hub, Laredo expects to generate $25 million to $40 million of Free Cash Flow1. The Company remains committed to maintaining a consistent development program and plans to utilize Free Cash Flow to reduce debt.
Please see the table in the appendix of Laredo's Fourth-Quarter 2020 Earnings Presentation posted to the Company's website for the full details of the Company's commodity derivatives.
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Liquidity
At December 31, 2020, the Company had outstanding borrowings of $255 million on its $725 million senior secured credit facility, resulting in available capacity, after the reduction for outstanding letters of credit, of $426 million. Including cash and cash equivalents of $49 million, total liquidity was $475 million.
At February 22, 2021, the Company had outstanding borrowings of $250 million on its $725 million senior secured credit facility, resulting in available capacity, after the reduction for outstanding letters of credit, of $431 million. Including cash and cash equivalents of $47 million, total liquidity was $478 million.
First-Quarter and Full-Year 2021 Guidance
The table below reflects the Company's first-quarter and full-year guidance for total and oil production for 2021. Guidance for first-quarter and full-year 2021 adjusts for recent severe freezing weather in the Permian Basin operating area. The Company estimates total production and oil production for the first quarter of 2021 were reduced by 8,000 BOE per day and 3,000 BOPD, respectively, for weather impact. The Company estimates total production and oil production for full-year 2021 were reduced by 2,000 BOE per day and 750 BOPD, respectively, for weather impact.
| 1Q-21E | FY-21E | |||||||||||||
| Total production (MBOE per day) | 73.0 - 76.0 | 80.0 - 85.0 | ||||||||||||
| Oil production (MBOPD) | 22.0 - 23.0 | 27.3 - 29.3 | ||||||||||||
The table below reflects the Company's guidance for selected revenue and expense items for the first quarter of 2021. Expense items that are guided to on a unit basis have been increased by approximately 10% as a result of the 8,000 BOE per day weather impact to first-quarter 2021 production.
| 1Q-21E | ||||||||
| Average sales price realizations (excluding derivatives): | ||||||||
| Oil (% of WTI) | 100% | |||||||
| NGL (% of WTI) | 32% | |||||||
| Natural gas (% of Henry Hub) | 72% | |||||||
| Other ($ MM): | ||||||||
| Net income (expense) of purchased oil | ($2.6) | |||||||
| Selected average costs & expenses: | ||||||||
| Lease operating expenses ($/BOE) | $3.45 | |||||||
| Production and ad valorem taxes (% of oil, NGL and natural gas sales revenues) | 7.00% | |||||||
| Transportation and marketing expenses ($/BOE) | $1.75 | |||||||
| General and administrative expenses (excluding LTIP, $/BOE) | $1.35 | |||||||
| General and administrative expenses (LTIP cash and non-cash, $/BOE) | $0.50 | |||||||
| Depletion, depreciation and amortization ($/BOE) | $6.10 | |||||||
Conference Call Details
On Tuesday, February 23, 2021, at 7:30 a.m. CT, Laredo will host a conference call to discuss its fourth-quarter and full-year 2020 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
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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 7561618, 10 minutes prior to the scheduled conference time. A telephonic replay will be available two hours after the call on February 23, 2021 through Tuesday, March 2, 2021. Participants may access this replay by dialing 855.859.2056, using conference code 7561618.
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.
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, 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, 2019, Amendment No. 1 to its Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, its Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, its Quarterly Report on Form 10-Q for the quarter ended September 30, 2020 and those set forth from time to time in other filings with the Securities and Exchange Commission ("SEC"). These documents are available through Laredo's website at www.laredopetro.com under the tab "Investor Relations" or through the SEC's Electronic Data Gathering and Analysis Retrieval System at www.sec.gov. Any of these factors could cause Laredo's actual results and plans to differ materially from those in the forward-looking statements. Therefore, Laredo can give no assurance that its future results will be as estimated. Any forward-looking statement speaks only as of the date on which such statement is made. Laredo does not intend to, and disclaims any obligation to, correct update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.
The SEC generally permits oil and natural gas companies, in filings made with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be
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recoverable in future years from known reservoirs under existing economic and operating conditions, and certain probable and possible reserves that meet the SEC's definitions for such terms. In this press release and the conference call, the Company may use the terms "resource potential," "resource play," "estimated ultimate recovery" or "EURs," "type curve" and "standardized measure," each of which the SEC guidelines restrict from being included in filings with the SEC without strict compliance with SEC definitions. These terms refer to the Company’s internal estimates of unbooked hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. "Resource potential" is used by the Company to refer to the estimated quantities of hydrocarbons that may be added to proved reserves, largely from a specified resource play potentially supporting numerous drilling locations. A "resource play" is a term used by the Company to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section potentially supporting numerous drilling locations, which, when compared to a conventional play, typically has a lower geological and/or commercial development risk. "EURs" are based on the Company’s previous operating experience in a given area and publicly available information relating to the operations of producers who are conducting operations in these areas. Unbooked resource potential and "EURs" do not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules and do not include any proved reserves. Actual quantities of reserves that may be ultimately recovered from the Company’s interests may differ substantially from those presented herein. Factors affecting ultimate recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, decreases in oil, natural gas liquids and natural gas prices, well spacing, drilling and production costs, availability and cost of drilling services and equipment, lease expirations, transportation constraints, regulatory approvals, negative revisions to reserve estimates and other factors, as well as actual drilling results, including geological and mechanical factors affecting recovery rates. "EURs" from reserves may change significantly as development of the Company’s core assets provides additional data. In addition, the Company's production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. "Type curve" refers to a production profile of a well, or a particular category of wells, for a specific play and/or area. The "standardized measure" of discounted future new cash flows is calculated in accordance with SEC regulations and a discount rate of 10%. Actual results may vary considerably and should not be considered to represent the fair market value of the Company’s proved reserves.
This press release and any accompanying disclosures include financial measures that are not in accordance with generally accepted accounting principles ("GAAP"), such as Adjusted EBITDA, Adjusted Net Income and Free Cash Flow. While management believes that such measures are useful for investors, they should not be used as a replacement for financial measures that are in accordance with GAAP. For a reconciliation of such non-GAAP financial measures to the nearest comparable measure in accordance with GAAP, please see the supplemental financial information at the end of this press release.
Unless otherwise specified, references to "average sales price" refer to average sales price excluding the effects of the Company's derivative transactions.
All amounts, dollars and percentages presented in this press release are rounded and therefore approximate.
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Laredo Petroleum, Inc.
Selected operating data
| Three months ended December 31, | Years ended December 31, | |||||||||||||||||||||||||
| 2020 | 2019 | 2020 | 2019 | |||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Sales volumes: | ||||||||||||||||||||||||||
| Oil (MBbl) | 2,018 | 2,511 | 9,827 | 10,376 | ||||||||||||||||||||||
| NGL (MBbl) | 2,636 | 2,475 | 10,615 | 9,118 | ||||||||||||||||||||||
| Natural gas (MMcf) | 17,648 | 16,438 | 70,049 | 60,169 | ||||||||||||||||||||||
Oil equivalents (MBOE)(1)(2) | 7,595 | 7,725 | 32,117 | 29,522 | ||||||||||||||||||||||
Average daily oil equivalent sales volumes (BOE/D)(2) | 82,552 | 83,968 | 87,750 | 80,883 | ||||||||||||||||||||||
Average daily oil sales volumes (BOPD)(2) | 21,929 | 27,296 | 26,849 | 28,429 | ||||||||||||||||||||||
Average sales prices(2): | ||||||||||||||||||||||||||
Oil ($/Bbl)(3) | $ | 41.82 | $ | 56.55 | $ | 37.43 | $ | 55.21 | ||||||||||||||||||
NGL ($/Bbl)(3) | $ | 10.82 | $ | 10.26 | $ | 7.37 | $ | 11.00 | ||||||||||||||||||
Natural gas ($/Mcf)(3) | $ | 1.19 | $ | 0.74 | $ | 0.72 | $ | 0.55 | ||||||||||||||||||
Average sales price ($/BOE)(3) | $ | 17.63 | $ | 23.24 | $ | 15.45 | $ | 23.93 | ||||||||||||||||||
Oil, with commodity derivatives ($/Bbl)(4) | $ | 60.52 | $ | 56.79 | $ | 56.41 | $ | 54.37 | ||||||||||||||||||
NGL, with commodity derivatives ($/Bbl)(4) | $ | 11.43 | $ | 13.02 | $ | 9.12 | $ | 13.61 | ||||||||||||||||||
Natural gas, with commodity derivatives ($/Mcf)(4) | $ | 1.31 | $ | 0.94 | $ | 1.02 | $ | 1.05 | ||||||||||||||||||
Average sales price, with commodity derivatives ($/BOE)(4) | $ | 23.08 | $ | 24.62 | $ | 22.50 | $ | 25.45 | ||||||||||||||||||
Selected average costs and expenses per BOE sold(2): | ||||||||||||||||||||||||||
| Lease operating expenses | $ | 2.57 | $ | 2.84 | $ | 2.55 | $ | 3.08 | ||||||||||||||||||
| Production and ad valorem taxes | 1.07 | 1.43 | 1.03 | 1.38 | ||||||||||||||||||||||
| Transportation and marketing expenses | 1.59 | 1.32 | 1.55 | 0.86 | ||||||||||||||||||||||
| Midstream service expenses | 0.09 | 0.14 | 0.12 | 0.15 | ||||||||||||||||||||||
| General and administrative (excluding LTIP) | 1.71 | 1.37 | 1.29 | 1.63 | ||||||||||||||||||||||
| Total selected operating expenses | $ | 7.03 | $ | 7.10 | $ | 6.54 | $ | 7.10 | ||||||||||||||||||
| General and administrative (LTIP): | ||||||||||||||||||||||||||
| LTIP cash | $ | 0.12 | $ | — | $ | 0.06 | $ | — | ||||||||||||||||||
| LTIP non-cash | $ | 0.25 | $ | 0.35 | $ | 0.22 | $ | 0.22 | ||||||||||||||||||
| Depletion, depreciation and amortization | $ | 5.56 | $ | 8.78 | $ | 6.76 | $ | 9.00 | ||||||||||||||||||
_______________________________________________________________________________
(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.
9
Laredo Petroleum, Inc.
Condensed consolidated statements of operations
| Three months ended December 31, | Years ended December 31, | |||||||||||||||||||||||||
| (in thousands, except per share data) | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Revenues: | ||||||||||||||||||||||||||
| Oil, NGL and natural gas sales | $ | 133,865 | $ | 179,558 | $ | 496,355 | $ | 706,548 | ||||||||||||||||||
| Midstream service revenues | 1,534 | 3,356 | 8,249 | 11,928 | ||||||||||||||||||||||
| Sales of purchased oil | 52,666 | 35,208 | 172,588 | 118,805 | ||||||||||||||||||||||
| Total revenues | 188,065 | 218,122 | 677,192 | 837,281 | ||||||||||||||||||||||
| Costs and expenses: | ||||||||||||||||||||||||||
| Lease operating expenses | 19,549 | 21,948 | 82,020 | 90,786 | ||||||||||||||||||||||
| Production and ad valorem taxes | 8,115 | 11,080 | 33,050 | 40,712 | ||||||||||||||||||||||
| Transportation and marketing expenses | 12,041 | 10,164 | 49,927 | 25,397 | ||||||||||||||||||||||
| Midstream service expenses | 704 | 1,085 | 3,762 | 4,486 | ||||||||||||||||||||||
| Costs of purchased oil | 56,728 | 39,034 | 194,862 | 122,638 | ||||||||||||||||||||||
| General and administrative | 15,840 | 13,302 | 50,534 | 54,729 | ||||||||||||||||||||||
| Organizational restructuring expenses | — | — | 4,200 | 16,371 | ||||||||||||||||||||||
| Depletion, depreciation and amortization | 42,210 | 67,846 | 217,101 | 265,746 | ||||||||||||||||||||||
| Impairment expense | 109,804 | 222,999 | 899,039 | 620,889 | ||||||||||||||||||||||
| Other operating expenses | 1,105 | 1,041 | 4,430 | 4,118 | ||||||||||||||||||||||
| Total costs and expenses | 266,096 | 388,499 | 1,538,925 | 1,245,872 | ||||||||||||||||||||||
| Operating loss | (78,031) | (170,377) | (861,733) | (408,591) | ||||||||||||||||||||||
| Non-operating income (expense): | ||||||||||||||||||||||||||
| Gain (loss) on derivatives, net | (81,935) | (57,562) | 80,114 | 79,151 | ||||||||||||||||||||||
| Interest expense | (26,139) | (15,044) | (105,009) | (61,547) | ||||||||||||||||||||||
| Litigation settlement | — | — | — | 42,500 | ||||||||||||||||||||||
| Gain on extinguishment of debt, net | 22,309 | — | 8,989 | — | ||||||||||||||||||||||
| Other, net | 1,072 | (514) | (480) | 3,440 | ||||||||||||||||||||||
| Total non-operating income (expense), net | (84,693) | (73,120) | (16,386) | 63,544 | ||||||||||||||||||||||
Loss before income taxes | (162,724) | (243,497) | (878,119) | (345,047) | ||||||||||||||||||||||
| Income tax (expense) benefit: | ||||||||||||||||||||||||||
| Deferred | (3,208) | 1,776 | 3,946 | 2,588 | ||||||||||||||||||||||
| Total income tax (expense) benefit | (3,208) | 1,776 | 3,946 | 2,588 | ||||||||||||||||||||||
| Net loss | $ | (165,932) | $ | (241,721) | $ | (874,173) | $ | (342,459) | ||||||||||||||||||
Net loss per common share(1): | ||||||||||||||||||||||||||
| Basic | $ | (14.18) | $ | (20.86) | $ | (74.92) | $ | (29.61) | ||||||||||||||||||
| Diluted | $ | (14.18) | $ | (20.86) | $ | (74.92) | $ | (29.61) | ||||||||||||||||||
Weighted-average common shares outstanding(1): | ||||||||||||||||||||||||||
| Basic | 11,702 | 11,586 | 11,668 | 11,565 | ||||||||||||||||||||||
| Diluted | 11,702 | 11,586 | 11,668 | 11,565 | ||||||||||||||||||||||
_______________________________________________________________________________
(1)Net loss per common share and weighted-average common shares outstanding were retroactively adjusted for the Company's 1-for-20 reverse stock split effective June 1, 2020.
10
Laredo Petroleum, Inc.
Condensed consolidated statements of cash flows
| Three months ended December 31, | Years ended December 31, | |||||||||||||||||||||||||
| (in thousands) | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Cash flows from operating activities: | ||||||||||||||||||||||||||
| Net loss | $ | (165,932) | $ | (241,721) | $ | (874,173) | $ | (342,459) | ||||||||||||||||||
| Adjustments to reconcile net loss to net cash provided by operating activities: | ||||||||||||||||||||||||||
| Share-settled equity-based compensation, net | 2,106 | 3,046 | 8,217 | 8,290 | ||||||||||||||||||||||
| Depletion, depreciation and amortization | 42,210 | 67,846 | 217,101 | 265,746 | ||||||||||||||||||||||
| Impairment expense | 109,804 | 222,999 | 899,039 | 620,889 | ||||||||||||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||||||||||||||
| (Gain) loss on derivatives, net | 81,935 | 57,562 | (80,114) | (79,151) | ||||||||||||||||||||||
| Settlements received for matured derivatives, net | 41,786 | 14,394 | 228,221 | 63,221 | ||||||||||||||||||||||
| Settlements received (paid) for early-terminated commodity derivatives, net | — | — | 6,340 | (5,409) | ||||||||||||||||||||||
| Premiums paid for commodity derivatives | — | (1,399) | (51,070) | (9,063) | ||||||||||||||||||||||
| Gain on extinguishment of debt, net | (22,309) | — | (8,989) | — | ||||||||||||||||||||||
| Deferred income tax expense (benefit) | 3,208 | (1,776) | (3,946) | (2,588) | ||||||||||||||||||||||
| Other, net | 4,767 | 6,996 | 22,723 | 21,791 | ||||||||||||||||||||||
| Cash flows from operating activities before changes in operating assets and liabilities, net | 97,575 | 127,947 | 363,349 | 541,267 | ||||||||||||||||||||||
| Change in current assets and liabilities, net | 17,601 | (15,818) | 36,699 | (64,123) | ||||||||||||||||||||||
| Change in noncurrent assets and liabilities, net | (5,406) | (3,923) | (16,658) | (2,070) | ||||||||||||||||||||||
| Net cash provided by operating activities | 109,770 | 108,206 | 383,390 | 475,074 | ||||||||||||||||||||||
| Cash flows from investing activities: | ||||||||||||||||||||||||||
| Acquisitions of oil and natural gas properties | (12,223) | (196,404) | (35,786) | (199,284) | ||||||||||||||||||||||
| Capital expenditures: | ||||||||||||||||||||||||||
| Oil and natural gas properties | (69,082) | (90,803) | (347,359) | (458,985) | ||||||||||||||||||||||
| Midstream service assets | (654) | (1,169) | (3,171) | (7,910) | ||||||||||||||||||||||
| Other fixed assets | (1,235) | (713) | (4,259) | (2,433) | ||||||||||||||||||||||
| Proceeds from dispositions of capital assets, net of selling costs | 95 | 54 | 1,337 | 6,901 | ||||||||||||||||||||||
| Net cash used in investing activities | (83,099) | (289,035) | (389,238) | (661,711) | ||||||||||||||||||||||
| Cash flows from financing activities: | ||||||||||||||||||||||||||
| Borrowings on Senior Secured Credit Facility | 35,000 | 195,000 | 80,000 | 275,000 | ||||||||||||||||||||||
| Payments on Senior Secured Credit Facility | (15,000) | (5,000) | (200,000) | (90,000) | ||||||||||||||||||||||
| Issuance of January 2025 Notes and January 2028 Notes | — | — | 1,000,000 | — | ||||||||||||||||||||||
| Extinguishment of debt | (38,139) | — | (846,994) | — | ||||||||||||||||||||||
| Payments for debt issuance costs | (28) | — | (18,479) | — | ||||||||||||||||||||||
| Other, net | (5) | (7) | (779) | (2,657) | ||||||||||||||||||||||
| Net cash (used in) provided by financing activities | (18,172) | 189,993 | 13,748 | 182,343 | ||||||||||||||||||||||
| Net increase (decrease) in cash and cash equivalents | 8,499 | 9,164 | 7,900 | (4,294) | ||||||||||||||||||||||
| Cash and cash equivalents, beginning of period | 40,258 | 31,693 | 40,857 | 45,151 | ||||||||||||||||||||||
| Cash and cash equivalents, end of period | $ | 48,757 | $ | 40,857 | $ | 48,757 | $ | 40,857 | ||||||||||||||||||
11
Laredo Petroleum, Inc.
Total Costs Incurred
The following table presents the components of the Company's costs incurred, excluding non-budgeted acquisition costs, for the periods presented:
| Three months ended December 31, | Years ended December 31, | |||||||||||||||||||||||||
| (in thousands) | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Oil and natural gas properties | $ | 74,223 | $ | 104,616 | $ | 344,160 | $ | 470,455 | ||||||||||||||||||
| Midstream service assets | 288 | 1,071 | 2,985 | 8,655 | ||||||||||||||||||||||
| Other fixed assets | 1,056 | 504 | 4,148 | 2,470 | ||||||||||||||||||||||
| Total costs incurred, excluding non-budgeted acquisition costs | $ | 75,567 | $ | 106,191 | $ | 351,293 | $ | 481,580 | ||||||||||||||||||
12
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 and Adjusted EBITDA, 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 and Adjusted EBITDA should not be considered in isolation or as a substitute for GAAP measures, such as net income or loss, operating income or loss or any other GAAP measure of liquidity or financial performance.
1Free 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 costs incurred, excluding non-budgeted acquisition costs. Free Cash Flow does not represent funds available for future discretionary use because it excludes funds required for future debt service, capital expenditures, acquisitions, working capital, income taxes, franchise taxes and other commitments and obligations. However, 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 does not provide guidance on the reconciling items between forecasted net cash provided by operating activities and forecasted Free Cash Flow due to the uncertainty regarding timing and estimates of these items. Laredo provides a range for the forecasts of net cash provided by operating activities and Free Cash Flow to allow for the variability in timing and uncertainty of estimates of reconciling items between forecasted net cash provided by operating activities and forecasted Free Cash Flow. Therefore, the Company cannot reconcile forecasted net cash provided by operating activities to forecasted Free Cash Flow without unreasonable effort.
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, | Years ended December 31, | |||||||||||||||||||||||||
| (in thousands) | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Net cash provided by operating activities | $ | 109,770 | $ | 108,206 | $ | 383,390 | $ | 475,074 | ||||||||||||||||||
| Less: | ||||||||||||||||||||||||||
| Change in current assets and liabilities, net | 17,601 | (15,818) | 36,699 | (64,123) | ||||||||||||||||||||||
| Change in noncurrent assets and liabilities, net | (5,406) | (3,923) | (16,658) | (2,070) | ||||||||||||||||||||||
| Cash flows from operating activities before changes in operating assets and liabilities, net | 97,575 | 127,947 | 363,349 | 541,267 | ||||||||||||||||||||||
| Less costs incurred, excluding non-budgeted acquisition costs: | ||||||||||||||||||||||||||
Oil and natural gas properties(1) | $ | 74,223 | $ | 104,616 | $ | 344,160 | $ | 470,455 | ||||||||||||||||||
Midstream service assets(1) | 288 | 1,071 | 2,985 | 8,655 | ||||||||||||||||||||||
| Other fixed assets | 1,056 | 504 | 4,148 | 2,470 | ||||||||||||||||||||||
| Total costs incurred, excluding non-budgeted acquisition costs | $ | 75,567 | $ | 106,191 | $ | 351,293 | $ | 481,580 | ||||||||||||||||||
| Free Cash Flow (non-GAAP) | $ | 22,008 | $ | 21,756 | $ | 12,056 | $ | 59,687 | ||||||||||||||||||
_____________________________________________________________________________
(1)Includes capitalized share-settled equity-based compensation and asset retirement costs.
13
Adjusted Net Income (Unaudited)
Adjusted Net Income is a non-GAAP financial measure that the Company defines as income or loss before income taxes plus adjustments for mark-to-market on derivatives, premiums paid 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 loss before income taxes (GAAP) to Adjusted Net Income (non-GAAP) for the periods presented:
| Three months ended December 31, | Years ended December 31, | |||||||||||||||||||||||||
| (in thousands, except per share data) | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
Loss before income taxes | $ | (162,724) | $ | (243,497) | $ | (878,119) | $ | (345,047) | ||||||||||||||||||
| Plus: | ||||||||||||||||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||||||||||||||
| (Gain) loss on derivatives, net | 81,935 | 57,562 | (80,114) | (79,151) | ||||||||||||||||||||||
| Settlements received for matured derivatives, net | 41,786 | 14,394 | 228,221 | 63,221 | ||||||||||||||||||||||
| Settlements received (paid) for early-terminated commodity derivatives, net | — | — | 6,340 | (5,409) | ||||||||||||||||||||||
Premiums paid for commodity derivatives that matured during the period(1) | — | (1,399) | (477) | (9,063) | ||||||||||||||||||||||
| Organizational restructuring expenses | — | — | 4,200 | 16,371 | ||||||||||||||||||||||
| Impairment expense | 109,804 | 222,999 | 899,039 | 620,889 | ||||||||||||||||||||||
| Gain on extinguishment of debt, net | (22,309) | — | (8,989) | — | ||||||||||||||||||||||
| Litigation settlement | — | — | — | (42,500) | ||||||||||||||||||||||
| (Gain) loss on disposal of assets, net | (94) | (67) | 963 | 248 | ||||||||||||||||||||||
| Write-off of debt issuance costs | — | 935 | 1,103 | 935 | ||||||||||||||||||||||
| Adjusted income before adjusted income tax expense | 48,398 | 50,927 | 172,167 | 220,494 | ||||||||||||||||||||||
Adjusted income tax expense(2) | (10,648) | (11,204) | (37,877) | (48,509) | ||||||||||||||||||||||
| Adjusted Net Income (non-GAAP) | $ | 37,750 | $ | 39,723 | $ | 134,290 | $ | 171,985 | ||||||||||||||||||
Net loss per common share(3): | ||||||||||||||||||||||||||
| Basic | $ | (14.18) | $ | (20.86) | $ | (74.92) | $ | (29.61) | ||||||||||||||||||
| Diluted | $ | (14.18) | $ | (20.86) | $ | (74.92) | $ | (29.61) | ||||||||||||||||||
Adjusted Net Income per common share(3): | ||||||||||||||||||||||||||
| Basic | $ | 3.23 | $ | 3.43 | $ | 11.51 | $ | 14.87 | ||||||||||||||||||
| Diluted | $ | 3.23 | $ | 3.43 | $ | 11.51 | $ | 14.87 | ||||||||||||||||||
| Adjusted diluted | $ | 3.22 | $ | 3.43 | $ | 11.47 | $ | 14.83 | ||||||||||||||||||
Weighted-average common shares outstanding(3): | ||||||||||||||||||||||||||
| Basic | 11,702 | 11,586 | 11,668 | 11,565 | ||||||||||||||||||||||
| Diluted | 11,702 | 11,586 | 11,668 | 11,565 | ||||||||||||||||||||||
| Adjusted diluted | 11,709 | 11,591 | 11,712 | 11,595 | ||||||||||||||||||||||
_______________________________________________________________________________
(1)Reflects premiums incurred previously or upon settlement that are attributable to derivatives settled in the respective periods presented and were not a result of a hedge restructuring.
(2)Adjusted income tax expense is calculated by applying a statutory tax rate of 22% for each of the periods ended December 31, 2020 and 2019.
(3)Net loss per common share, Adjusted Net Income per common share and weighted-average common shares outstanding were retroactively adjusted for the Company's 1-for-20 reverse stock split effective June 1, 2020.
14
Adjusted EBITDA (Unaudited)
Adjusted EBITDA is a non-GAAP financial measure that the Company defines as net income or loss 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 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 loss (GAAP) to Adjusted EBITDA (non-GAAP) for the periods presented:
| Three months ended December 31, | Years ended December 31, | |||||||||||||||||||||||||
| (in thousands) | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Net loss | $ | (165,932) | $ | (241,721) | $ | (874,173) | $ | (342,459) | ||||||||||||||||||
| Plus: | ||||||||||||||||||||||||||
| Share-settled equity-based compensation, net | 2,106 | 3,046 | 8,217 | 8,290 | ||||||||||||||||||||||
| Depletion, depreciation and amortization | 42,210 | 67,846 | 217,101 | 265,746 | ||||||||||||||||||||||
| Impairment expense | 109,804 | 222,999 | 899,039 | 620,889 | ||||||||||||||||||||||
| Organizational restructuring expenses | — | — | 4,200 | 16,371 | ||||||||||||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||||||||||||||
| (Gain) loss on derivatives, net | 81,935 | 57,562 | (80,114) | (79,151) | ||||||||||||||||||||||
| Settlements received for matured derivatives, net | 41,786 | 14,394 | 228,221 | 63,221 | ||||||||||||||||||||||
| Settlements received (paid) for early-terminated commodity derivatives, net | — | — | 6,340 | (5,409) | ||||||||||||||||||||||
Premiums paid for commodity derivatives that matured during the period(1) | — | (1,399) | (477) | (9,063) | ||||||||||||||||||||||
| Accretion expense | 1,105 | 1,041 | 4,430 | 4,118 | ||||||||||||||||||||||
| (Gain) loss on disposal of assets, net | (94) | (67) | 963 | 248 | ||||||||||||||||||||||
| Interest expense | 26,139 | 15,044 | 105,009 | 61,547 | ||||||||||||||||||||||
| Gain on extinguishment of debt, net | (22,309) | — | (8,989) | — | ||||||||||||||||||||||
| Litigation settlement | — | — | — | (42,500) | ||||||||||||||||||||||
| Write-off of debt issuance costs | — | 935 | 1,103 | 935 | ||||||||||||||||||||||
| Income tax expense (benefit) | 3,208 | (1,776) | (3,946) | (2,588) | ||||||||||||||||||||||
| Adjusted EBITDA (non-GAAP) | $ | 119,958 | $ | 137,904 | $ | 506,924 | $ | 560,195 | ||||||||||||||||||
_____________________________________________________________________________
(1)Reflects premiums incurred previously or upon settlement that are attributable to derivatives settled in the respective periods presented and were not a result of a hedge restructuring.
15
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, 2020 | |||||||
| Standardized measure of discounted future net cash flows | $ | 1,015 | ||||||
| Less present value of future income taxes discounted at 10% | (11) | |||||||
| PV-10 (non-GAAP) | $ | 1,026 | ||||||
# # #
Investor Contact:
Ron Hagood
918.858.5504
rhagood@laredopetro.com
16
Fourth-Quarter 2020 Earnings Presentation
Forward-Looking / Cautionary Statements 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. 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, 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, 2019, Amendment No. 1 to its Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, its Quarterly Report on Form 10- Q for the quarter ended June 30, 2020, its Quarterly Report on Form 10-Q for the quarter ended September 30, 2020 and those set forth from time to time in other filings with the Securities and Exchange Commission (“SEC”). These documents are available through Laredo’s website at www.laredopetro.com under the tab “Investor Relations” or through the SEC’s Electronic Data Gathering and Analysis Retrieval System at www.sec.gov. Any of these factors could cause Laredo’s actual results and plans to differ materially from those in the forward-looking statements. Therefore, Laredo can give no assurance that its future results will be as estimated. Any forward-looking statement speaks only as of the date on which such statement is made. Laredo does not intend to, and disclaims any obligation to, correct, update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. The SEC generally permits oil and natural gas companies, in filings made with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, and certain probable and possible reserves that meet the SEC’s definitions for such terms. In this presentation, the Company may use the terms “resource potential,” “resource play,” “estimated ultimate recovery,” or “EURs,” “type curve” and “standardized measure,” each of which the SEC guidelines restrict from being included in filings with the SEC without strict compliance with SEC definitions. These terms refer to the Company’s internal estimates of unbooked hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. “Resource potential” is used by the Company to refer to the estimated quantities of hydrocarbons that may be added to proved reserves, largely from a specified resource play potentially supporting numerous drilling locations. A “resource play” is a term used by the Company to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section potentially supporting numerous drilling locations, which, when compared to a conventional play, typically has a lower geological and/or commercial development risk. “EURs” are based on the Company’s previous operating experience in a given area and publicly available information relating to the operations of producers who are conducting operations in these areas. Unbooked resource potential or “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, Cash Flow 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 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
Expand High-Margin Inventory Manage Risk ▪ Extended term-debt maturities to 2025 and 2028 ▪ Received $234 MM from settlements of matured / terminated derivatives in 2020 ▪ Repurchased $61 MM of debt1 at 62.5% of par value ▪ Hedged 76% of anticipated 2021 oil production Continuously Improve ▪ Reduced volume of flared/vented gas by 58% ▪ Reduced oil/water spills rate by 29% ▪ Reduced D&C cost per foot by 21% ▪ Reduced unit LOE by 17% ▪ Reduced unit G&A expenses by 21% ▪ Fully transitioned development operations to Howard County ▪ Completed Company’s first package of wells in Howard County ▪ Added 4,000 net acres in Howard County at an average price of $7,200 per acre Objectives Principles Successfully Executed Strategy in 2020 Improve Oil Cut Decrease Leverage Reduce GHG Emissions Target Free Cash Flow2 31 In open market purchases 2See Appendix for reconciliations and definitions of non-GAAP measures
15.6 12.5 10 12 14 16 2019 2025 In te n s it y ( m tC O 2 e 3 /M B O E ) GHG Intensity Inaugural ESG & Climate Change Report: Proven Leadership 4 12019 calendar year as baseline; 2As a percentage of natural gas production; 3Metric tons of carbon dioxide equivalent Note: 2019 data. Peers include: APA, BP, COP, CPE, CVX, CXO, DVN, EOG, FANG, MRO, OXY, PDCE, PE, PXD, QEP, RYDAF, SM, XEC and XOM 20% reduction in GHG intensity <0.20% methane emissions2 Zero routine flaring Emissions Reductions Targets for 20251 Laredo has committed to reducing methane emissions and eliminating routine flaring 0 5 10 15 20 25 30 35 40 P e e r P e e r P e e r P e e r P e e r P e e r P e e r P e e r L P I P e e r P e e r P e e r P e e r P e e r P e e r P e e r P e e r P e e r P e e r P e e rG H G I n te n s it y ( m tC O 2 e 3 /M B O E ) Peer GHG Intensity Peer Avg.: 19.5 (20%)
0 500 1,000 1,500 2,000 2,500 FY-19 FY-20 T o ta l F la re & V e n t (M M c f) LPI Annual Flare/Vent Data Flared & Vented Natural Gas 0 50 100 150 FY-19 FY-20 A v g . N e t B b ls o f T o ta l F lu id R e le a s e d P e r M M B b ls H a n d le d LPI Annual Oil/Water Spill Data Net Bbls of Total Fluid Released Per MMBbls Handled Dramatically Exceeded Environmental Targets in 2020 5 58% Volume decrease vs FY-19 29% Decrease vs FY-19 ▪ Optical gas imaging camera (FLIR) inspections for all sites ▪ Utilize sealed frac tanks during flowback ▪ Tank batteries and storage facilities equipped with early warning alarms ▪ All facilities built with impermeable lined containment since 2018 0.71% Produced gas flared/vented 1.95% Produced gas flared/vented
6 Corporate and Community Responsibility >$570,000 Total amount donated since 2019 to improve our local communities Giving Diversity Governance Laredo intends to disclose EEO-1 data by YE-21 Board refresh in last 2 years Independent Directors Female & Minority Directors Separated roles of Chairman and CEO October 2019 55% 91% 45% 27% Women in workforce Minorities in workforce Women in Professional or Higher Roles 25% 38% Safety 0.86 0.74 0.65 0.70 0.75 0.80 0.85 0.90 2019 2020 TRIR1 Laredo had zero at-fault vehicle incidents in 2020 1 Combined employee and contractor Total Recordable Incident Rate
7 Howard County Development Driving Reserves Value 24% 39% 36% Total Proved Oil Natural Gas NGL 278,228 MBOE Total Proved PD PUD 91% PD $1,537 $1,756 $1,975 $2,194 0 500 1,000 1,500 2,000 2,500 $45 $50 $55 $60 $ M M WTI Price PD Reserves PV-101 (Henry Hub - $2.75) 11% 89% PD Howard County Reagan/Glasscock $971 MM PV-10 1Based only on wells categorized as Proved Developed as of YE-20 Note: All reserves as of 12-31-20, based on SEC benchmark pricing of: $36.04/Bbl for oil & $1.21/MMBtu for natural gas; See Appendix for reconciliation of PV-10 to standardized measure
8 FY-20A FY-21E Spuds 55 53 Completions 48 55 Working Interest 98.5% 100% Lateral Length 9,000’ 9,800’ Expect to complete 25% more lateral feet in 2021 vs 2020 for same DC&E expenditures 2020/2021 Capital Budget & Activity $300 $300 $16 $30 $35 $30 $0 $100 $200 $300 $400 FY-20A FY-21E Capital Budget ($ MM) DC&E Infrastructure Other $351 $360
$325 $375 $425 $40 $45 $50 $55 $60 WTI ($/Bbl) FY-21E Cash Flow1,2 ($ MM) 9 Howard County Development Achieves Higher Oil Cut Oil Production (MBO/d) Total Production (MBOE/d) 26.8 15 20 25 30 35 FY-20A FY-21E O il P ro d u c ti o n ( M B O /d ) 27.3 - 29.3 87.8 40 60 80 100 FY-20A FY-21E T o ta l P ro d u c ti o n ( M B O E /d ) 80.0 - 85.0 2021 Production Guidance 1Open hedge positions as of 12-31-20; hedges executed through 2-16-21, utilizing natural gas price held flat at $2.75/Mcf; 2See Appendix for reconciliations and definitions of non-GAAP measures Cash Flow, Including Hedges 2021E Capital Reduce expenditures to operate within cash flow Excess cash flow to reduce net debt
▪ 15-well package fully completed in early December 2020 ▪ Package averaged oil production of 10,000 gross BOPD for 26 consecutive days prior to winter storms in Permian Basin ▪ All four Lower Spraberry wells recently cleaned up and oil production was increasing prior to winter storms 10 LPI Leasehold Passow-Gilbert Package Passow-Gilbert Package Key to 1Q-21E Oil Production Note: Production data normalized to 10,000’ lateral length (average lateral length for package is 9,923’); wells are considered producing when production reaches 200 BOPD; rates are preliminary field measurements and are subject to change; data as of 2-10-2021 0 30 60 90 120 150 180 0 60 120 180 240 300 360 C u m u la ti v e P ro d u c ti o n ( M B O ) Production Days Passow-Gilbert Cumulative Oil Production Passow-Gilbert Wolfcamp Avg. Passow-Gilbert L. Spraberry Avg. Howard County Wolfcamp Budget Howard County L. Spraberry Budget
$0 $5 $10 $15 $20 $25 0 4,000 8,000 12,000 16,000 20,000 Dec-19 Dec-19 Feb-20 Apr-20 Oct-20 Total N e t A c q u is it io n C o s t ($ M / A c ) A c q u ir e d N e t A c re s Closing Date Acquisition Cost per Undeveloped Acre2 Successfully Building Oily, High-Margin Inventory LPI Leasehold (133,199 net acres) 11 W. Glasscock County Total Net Acres 4,352 Targets LS/UWC/MWC Locations1 40 Howard County Total Net Acres 11,555 Targets LS/UWC/MWC Locations1 105 - 140 ▪ Acquisition goal of 6,000+ net acres per year ▪ Targeting areas with high (50%+) oil cut ▪ Focus on contiguous Midland basin acreage that will benefit from LPI’s peer-leading operational costs and efficiencies 1Locations as of January 2021 (adjusted for 2020 completions); 2Net purchase price includes an adjustment for acquired production where applicable 3Subject to a previously disclosed potential contingency payment; Map, acreage as of 12-31-20 Acquired Net Acres Net Acquisition Cost ($M/Ac) 3
$788 $764 $675 $610 $540 $0 $200 $400 $600 $800 FY-17 FY-18 FY-19 FY-20 Current Estimated Cost D & C C o s t ($ /f t) 0 300 600 900 1,200 1,500 1,800 1Q-17 2Q-17 3Q-17 4Q-17 1Q-18 2Q-18 3Q-18 4Q-18 1Q-19 2Q-19 3Q-19 4Q-19 1Q-20 2Q-20 3Q-20 4Q-20 F e e t p e r D a y Drilled Feet/Day/Rig Fractured Feet/Day/Crew Maintaining Operational & Cost Advantages in Howard County 12 Consistently Reducing DC&E Costs Drilling & Completions Efficiencies 1Based on internal estimates as of Feb-20 1 2017 2018 2019 2020
$10.66 $7.60 $6.38 $6.07 $4.65 $3.84 $0 $2 $4 $6 $8 $10 $12 FY-15 FY-16 FY-17 FY-18 FY-19 FY-20 ($ /B O E ) Demonstrated History of Expense Reduction Cash G&A Expense LOE Cost-Control Focus Improves Margins 13 1Excludes long-term incentive plan (“LTIP”) cash & non-cash compensation expenses 1
14 Howard County Sand Mine Drives Additional D&C Cost Reductions LPI Leasehold Mining Area Operated on Laredo-owned surface acreage 5+ years supply of sand Protects against sand cost inflation Reduces truck traffic by 300,000 miles per month Estimated savings of $90,0001 per well ▪ Integrated into operations as of mid-November ▪ Mine operated by a third party ▪ No additional capital investment beyond surface acreage acquisition 1For Howard County completions
15 Intelligent Well - Strategic Approach $1.5MM Business Value Year 1 Level of organizational maturity around technology and corporate data culture L e v e l o f tr u s t in d a ta a s a s tr a te g ic a s s e t Take Action Integrate Generate Deliver Fully understand data 20 IoT + smart devices Streamlining the movement of data from one location to another Mature AWS cloud environment enables ONE Laredo answer Leak prevention leveraging draw down patterns of tanks & low flow pump recirculation patterns Compressor failure prevention leveraging machine learning & anomaly detection Ensuring that reliable data is easily available to decision- makers through many tools Data quality is monitored as part of standard operations Identify potential impacts to production through gas/oil ratio anomalies Enabling cost optimization in the field through the Well Performance Dashboard Transforming data into actionable insights Ensure data is consistent, trustworthy and valid
$250 $578 $361 $475 $0 $200 $400 $600 $800 FY-21 FY-22 FY-23 FY-24 FY-25 FY-26 FY-27 FY-28 D e b t ($ M M ) Actively Managing our Balance Sheet and Commodity Hedges 1See Appendix for reconciliations and definitions of non-GAAP measures 2Includes TTM Adjusted EBITDA/Consolidated EBITDAX as of 12-31-20 and net debt as of 12-31-20 3Amount shown as of 2-22-21 4Open hedge positions as of 12-31-20; hedges executed through 2-16-21 utilizing midpoint of 2021 production guidance 2.3x Net Debt to Adj. EBITDA1,2 2.6x Net Debt to Consolidated EBITDAX1,2 $47 MM Cash Balance3 16 Credit Agreement drawn3Senior unsecured notes Credit Agreement undrawn3 • Repurchased $61.0 MM face value of unsecured notes for $38.1 MM during 4Q-20 • Average purchase price was 62.5% of par • $22.9 MM net debt reduction related to purchase of notes • $4.5 MM annualized interest savings Oil Natural Gas NGL 78% 69% 56% 0% 20% 40% 60% 80% 100% FY-21 % Product Hedged4
Guidance Production: 1Q-21 FY-21 Total production (MBOE/d) 73.0 - 76.0 80.0 - 85.0 Oil production (MBO/d) 22.0 - 23.0 27.3 - 29.3 17 Average sales price realizations: (excluding derivatives) 1Q-21 Oil (% of WTI) 100% NGL (% of WTI) 32% Natural gas (% of Henry Hub) 72% Other ($ MM): 1Q-21 Net income / (expense) of purchased oil ($2.6) Operating costs & expenses ($/BOE): 1Q-21 Lease operating expenses $3.45 Production and ad valorem taxes (% of oil, NGL and natural gas revenues) 7.00% Transportation and marketing expenses $1.75 General and administrative expenses (excluding LTIP) $1.35 General and administrative expenses (LTIP cash & non-cash) $0.50 Depletion, depreciation and amortization $6.10 The table below reflects the Company's first-quarter and full-year guidance for total and oil production for 2021. Guidance for first-quarter and full-year 2021 adjusts for recent severe freezing weather in the Permian Basin operating area. The Company estimates total production and oil production for the first quarter of 2021 were reduced by 8,000 BOE per day and 3,000 BOPD, respectively, for weather impact. The Company estimates total production and oil production for full-year 2021 were reduced by 2,000 BOE per day and 750 BOPD, respectively, for weather impact. The table below reflects the Company's guidance for selected revenue and expense items for the first quarter of 2021. Expense items that are guided to on a unit basis have been increased by approximately 10% as a result of the 8,000 BOE per day weather impact to first-quarter 2021 production.
L A R E D O P E T R O L E U M APPENDIX 18
Oil, Natural Gas & Natural Gas Liquids Hedges Note: Open positions as of 12-31-20, hedges executed through 2-16-21 Natural gas liquids consist of Mt. Belvieu purity ethane and Mt. Belvieu non-TET propane, normal butane, isobutane, and natural gasoline 19 Hedge Product Summary FY-21 FY-22 Oil total volume (Bbl) 8,084,750 3,759,500 Oil wtd-avg price ($/Bbl) - Brent $50.83 $47.05 Nat gas total volume (MMBtu) 42,522,500 3,650,000 Nat gas wtd-avg price ($/MMBtu) - HH $2.59 $2.73 NGL total volume (Bbl) 5,245,050 Natural Gas Liquids Swaps FY-21 FY-22 Ethane Volume (Bbl) 912,500 Wtd-avg price ($/Bbl) $12.01 Propane Volume (Bbl) 2,423,235 Wtd-avg price ($/Bbl) $22.90 Normal Butane Volume (Bbl) 807,745 Wtd-avg price ($/Bbl) $25.87 Isobutane Volume (Bbl) 220,460 Wtd-avg price ($/Bbl) $26.55 Natural Gasoline Volume (Bbl) 881,110 Wtd-avg price ($/Bbl) $38.16 Natural Gas Swaps FY-21 FY-22 HH Volume (MMBtu) 42,522,500 3,650,000 Wtd-avg price ($/MMBtu) $2.59 $2.73 Basis Swaps FY-21 FY-22 Waha/HH Volume (MMBtu) 55,332,300 18,067,500 Wtd-avg price ($/MMBtu) ($0.48) ($0.41) Oil FY-21 FY-22 Brent Swaps Volume (Bbl) 7,291,500 3,759,500 Wtd-avg price ($/Bbl) $51.18 $47.05 Brent Puts Volume (Bbl) 209,250 Wtd-avg floor price ($/Bbl) $55.00 Brent Collars Volume (Bbl) 584,000 Wtd-avg floor price ($/Bbl) $45.00 Wtd-avg ceiling price ($/Bbl) $59.50
79.5 62.3 52.5 45.9 41.0 36.9 81.2 66.6 54.9 47.5 42.1 37.9 0 20 40 60 80 100 Dec-20 Dec-21 Dec-22 Dec-23 Dec-24 Dec-25 M B O E /D Total Production Decline Legacy Howard County YE-20 Base Production Decline Expectations 20 20.4 13.9 10.9 9.1 7.9 7.0 22.1 16.9 12.4 10.1 8.6 7.5 0 5 10 15 20 25 Dec-20 Dec-21 Dec-22 Dec-23 Dec-24 Dec-25 M B O /D Oil Production Decline Legacy Howard County 1Based only on wells categorized as Proved Developed as of YE-20 Note: All reserves as of 12-31-20, based on SEC benchmark pricing of: $36.04/Bbl for oil & $1.21/MMBtu for natural gas; See Appendix for reconciliation of PV-10 to standardized measure
Commodity Prices Used for 1Q-21 Realization Guidance 21 Natural Gas: Natural Gas Liquids: Oil: Note: Pricing assumptions as of 2-19-21 WTI NYMEX Brent ICE ($/Bbl) ($/Bbl) Jan-21 $52.10 $55.28 Feb-21 $58.26 $61.38 Mar-21 $59.20 $62.13 1Q-21 Average $56.46 $59.53 C2 C3 IC4 NC4 C5+ Composite ($/Bbl) ($/Bbl) ($/Bbl) ($/Bbl) ($/Bbl) ($/Bbl) Jan-21 $9.89 $36.40 $36.21 $37.06 $50.56 $26.89 Feb-21 $11.63 $36.89 $39.53 $39.45 $56.03 $28.75 Mar-21 $10.40 $39.64 $39.69 $39.80 $58.33 $29.43 1Q-21 Average $10.61 $37.67 $38.44 $38.75 $54.94 $28.34 HH Waha ($/MMBtu) ($/MMBtu) Jan-21 $2.47 $2.49 Feb-21 $2.76 $2.49 Mar-21 $3.07 $2.80 1Q-21 Average $2.77 $2.60
Supplemental Non-GAAP Financial Measures Adjusted EBITDA Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss 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, our management believes Adjusted EBITDA is useful to an investor in evaluating our operating performance because this measure: is widely used by investors in the oil and natural gas industry to measure a company's operating performance without regard to items that can vary substantially from company to company depending upon accounting methods, the book value of assets, capital structure and the method by which assets were acquired, among other factors; helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and is used by our management for various purposes, including as a measure of operating performance, in presentations to our board of directors and as a basis for strategic planning and forecasting. There are significant limitations to the use of Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss and the lack of comparability of results of operations to different companies due to the different methods of calculating Adjusted EBITDA reported by different companies. Our measurements of Adjusted EBITDA for financial reporting as compared to compliance under our debt agreements differ. The following table presents a reconciliation of net income (loss) (GAAP) to Adjusted EBITDA (non-GAAP): 22 1Reflects revised and restated figures in 1Q-20 10-Q/A Three months ended, (in thousands, unaudited) 3/31/201 6/30/20 9/30/20 12/31/20 Net income (loss) $74,646 ($545,455) ($237,432) ($165,932) Plus: Share-settled equity-based compensation, net 2,376 1,694 2,041 2,106 Depletion, depreciation and amortization 61,302 66,574 47,015 42,210 Impairment expense 186,699 406,448 196,088 109,804 Organizational restructuring expenses — 4,200 — — Mark-to-market on derivatives: (Gain) loss on derivatives, net (297,836) 90,537 45,250 81,935 Settlements received for matured derivatives, net 47,723 86,872 51,840 41,786 Settlements received for early-terminated commodity derivatives, net — — 6,340 — Premiums paid for commodity derivatives that matured during the period (477) — — — Accretion expense 1,106 1,117 1,102 1,105 (Gain) loss on disposal of assets, net 602 (152) 607 (94) Interest expense 24,970 27,072 26,828 26,139 (Gain) loss on extinguishment of debt 13,320 — — (22,309) Write-off of debt issuance costs — 1,103 — — Income tax expense (benefit) 2,417 (7,173) (2,398) 3,208 Adjusted EBITDA $116,848 $132,837 $137,281 $119,958
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 Restricted 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): 23 1Reflects revised and restated figures in 1Q-20 10-Q/A Three months ended, (in thousands, unaudited) 3/31/20201 6/30/2020 9/30/2020 12/31/2020 Net income (loss) $74,646 ($545,455) ($237,432) ($165,932) Organizational restructuring expenses - 4,200 — — (Gain) loss on extinguishment of debt 13,320 - — (22,309) (Gain) loss on disposal of assets, net 602 (152) 607 (94) Consolidated Net Income (Loss) 88,568 (541,407) (236,825) (188,335) Mark-to-market on derivatives: (Gain) loss on derivatives, net (297,836) 90,537 45,250 81,935 Settlements received for matured derivatives, net 47,723 86,872 51,840 41,786 Settlements received for early-terminated commodity derivatives, net - - 6,340 — Mark-to-market (gain) loss on derivatives, net (250,113) 177,409 103,430 123,721 Premiums paid for commodity derivatives (477) (50,593) — — Non-Cash Charges/Income: Deferred income tax expense (benefit) 2,417 (7,173) (2,398) 3,208 Depletion, depreciation and amortization 61,302 66,574 47,015 42,210 Share-settled equity-based compensation, net 2,376 1,694 2,041 2,106 Accretion expense 1,106 1,117 1,102 1,105 Impairment expense 186,699 406,448 196,088 109,804 Write-off of debt issuance costs - 1,103 — — Interest Expense 24,970 27,072 26,828 26,139 Consolidated EBITDAX after EBITDAX Adjustments (limited to 15%) $116,848 $82,244 $137,281 $119,958
Net Debt Net Debt, a non-GAAP financial measure, is calculated as long-term debt less cash. 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 12-31-20 was $1.189 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 is calculated as the face value of debt, reduced by cash and cash equivalents. Net Debt to Adjusted EBITDA is used by our management for various purposes, including as a measure of operating performance, in presentations to our board of directors and as a basis for strategic planning and forecasting. See Appendix slides for a definition of Adjusted EBITDA and for a reconciliation of Net Income to Adjusted EBITDA. Net debt to TTM Consolidated EBITDAX (Credit Agreement Calculation) Net Debt to TTM Consolidated EBITDAX is calculated as net debt divided by trailing twelve-month Consolidated EBITDAX. Net debt is calculated as the face value of debt, reduced by cash and cash equivalents. Net Debt to Consolidated EBITDAX is used by the banks in our Senior Secured Credit Agreement as a measure of indebtedness and as a calculation to measure compliance with the Company’s leverage covenant. See Appendix slides for a definition of Consolidated EBITDAX and for a reconciliation of Net Income to Consolidated EBITDAX. Liquidity Calculated as the Company’s outstanding borrowings on its Senior Secured Credit Agreement, less outstanding letters of credit, plus cash and cash equivalents. Cash Flow Cash flow, a non-GAAP financial measure, represents cash flows from operating activities before changes in operating assets and liabilities, net. Free Cash Flow Free Cash Flow is a non-GAAP financial measure, that we define as net cash provided by operating activites (GAAP) to cash flows from operating activities before changes in operating assets and liabilities, net, less costs incurred, excluding non-budgeted acquisition costs. Free Cash Flow does not represent funds available for future discretionary use because it excludes funds required for future debt service, capital expenditures, acquisitions, working capital, income taxes, franchise taxes and other commitments and obligations. However, management believes Free Cash Flow is useful to management and investors in evaluating operating trends in our business that are affected by production, commodity prices, operating costs and other related factors. There are significant limitations to the use of Free Cash Flow as a measure of performance, including the lack of comparability due to the different methods of calculating Free Cash Flow reported by different companies. 24 Supplemental Non-GAAP Financial Measures
25 PV-10 (Unaudited) PV-10 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. Supplemental Non-GAAP Financial Measures (in millions) December 31,2020 Standardized measure of discounted future net cash flows $1,015 Less present value of future income taxes discounted at 10% (11) PV-10 (non-GAAP) $1,026
Exhibit 99.3
15 West 6th Street, Suite 900 · Tulsa, Oklahoma 74119 · (918) 513-4570 · Fax: (918) 513-4571
www.laredopetro.com
Laredo Petroleum Publishes Inaugural ESG and Climate Risk Report
TULSA, OK - February 22, 2021 - Laredo Petroleum, Inc. (NYSE: LPI) ("Laredo" or the "Company") today published its inaugural ESG and Climate Risk Report, covering data for 2019 operations. The report and data tables are available on the Company’s website at www.laredopetro.com, under the tab for “Sustainability.”
Report Highlights
•Establishment of key emissions reduction targets: a 20% reduction in GHG intensity by 2025, zero routine flaring by 2025 and a reduction of methane emissions to less than 0.20% of produced natural gas by 2025
•Reporting standards and frameworks aligned with the Sustainability Accounting Standards Board ("SASB"), the Task Force on Climate-related Financial Disclosures ("TCFD") and the International Petroleum Industry Environmental Conservation Association ("IPIECA")
•Combined Scope 1 and 2 emissions intensity already below the Oil and Gas Climate Initiative ("OGCI") 2025 carbon intensity targets, which are aligned with Paris Agreement goals
•Demonstrated commitment to Board diversity with women and minority directors comprising 45% of the Board
•Embedded safety culture reflected by 2019 employee total recordable incident rate of 0.37 from one employee recordable incident during the year
"I am extremely proud of Laredo’s inaugural ESG and Climate Risk Report," stated Jason Pigott, President and CEO. "Doing the right thing is deeply ingrained in our culture and this report reflects that philosophy. While we are pleased with our results to date, we are always working to improve. We committed to making further progress on reducing emissions and reporting our results in alignment with leading reporting standards and frameworks. Laredo’s future as an innovative, sustainable energy producer is bright and I look forward to issuing our next ESG and Climate Risk Report by the end of 2021."
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 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. 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, 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, 2019, Amendment No. 1 to its Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, its Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, its Quarterly Report on Form 10-Q for the quarter ended September 30, 2020 and those set forth from time to time in other filings with the Securities and Exchange Commission (“SEC”). These documents are available through Laredo’s website at www.laredopetro.com under the tab “Investor Relations” or through the SEC’s Electronic Data Gathering and Analysis Retrieval System at www.sec.gov. Any of these factors could cause Laredo’s actual results and plans to differ materially from those in the forward-looking statements. Therefore, Laredo can give no assurance that its future results will be as estimated. Any forward-looking statement speaks only as of the date on which such statement is made. Laredo does not intend to, and disclaims any obligation to, correct update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.
Investor Contact:
Ron Hagood
918.858.5504
rhagood@laredopetro.com
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