lpi-20211102
0001528129false00015281292021-11-022021-11-02

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): November 2, 2021

LAREDO PETROLEUM, INC.
(Exact name of registrant as specified in charter)
Delaware001-3538045-3007926
(State or other jurisdiction of 
incorporation or organization)
(Commission File Number)(I.R.S. Employer Identification No.)
15 W. Sixth Street Suite 900 
TulsaOklahoma74119
(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 classTrading SymbolName of each exchange on which registered
Common stock, $0.01 par valueLPINew York Stock Exchange

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 November 2, 2021, Laredo Petroleum, Inc. (the "Company") announced its financial and operating results for the quarter ended September 30, 2021. Copies of the Company's press release and Presentation (as defined below) are furnished as Exhibits 99.1 and 99.2, respectively, to this Current Report on Form 8-K and are incorporated herein by reference. The Company plans to host a teleconference and webcast on November 3, 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 4653617. A replay of the call will be available through Wednesday, November 10, by dialing 1.855.859.2056, and using conference code 4653617. The webcast may be accessed at the Company's website, www.laredopetro.com, under the tab "Investor Relations."

In accordance with General Instruction B.2 of Form 8-K, the information furnished under this Item 2.02 of this Current Report on Form 8-K and the exhibits attached hereto are deemed to be "furnished" and shall not be deemed "filed" for the purpose of Section 18 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), or otherwise subject to the liabilities of that section, nor shall such information be deemed incorporated by reference into any filing under the Securities Act of 1933, as amended (the "Securities Act"), or the Exchange Act.

Item 7.01. Regulation FD Disclosure.

On November 2, 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 November 2, 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.

All statements in the press release, teleconference and Presentation, other than historical financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. Although the Company believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance, and actual results or developments may differ materially from those in the forward-looking statements. See the Company's Annual Report on Form 10-K for the year ended December 31, 2020, its Current Report on Form 8-K, filed on May 11, 2021, and the Company's other filings with the U.S. Securities and Exchange Commission for a discussion of other risks and uncertainties. The Company disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

In accordance with General Instruction B.2 of Form 8-K, the information furnished under this Item 7.01 of this Current Report on Form 8-K and the exhibits attached hereto are deemed to be "furnished" and shall not be deemed "filed" for the purpose of Section 18 of the Exchange Act, or otherwise subject to the liabilities of that section, nor shall such information be deemed incorporated by reference into any filing under the Securities Act or the Exchange Act.

Item 9.01. Financial Statements and Exhibits.
 
(d)  Exhibits.
 
Exhibit Number Description
104Cover 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: November 2, 2021
By:/s/ Bryan J. Lemmerman
  Bryan J. Lemmerman
  Senior Vice President and Chief Financial Officer


Document
Exhibit 99.1
https://cdn.kscope.io/544447264fc77a83e37576896b07a65b-g201a09ala10a.jpg

15 West 6th Street, Suite 900 · Tulsa, Oklahoma 74119 · (918) 513-4570 · Fax: (918) 513-4571
www.laredopetro.com
Laredo Petroleum Announces Third-Quarter 2021 Financial and Operating Results
TULSA, OK - November 2, 2021 - Laredo Petroleum, Inc. (NYSE: LPI) ("Laredo" or the "Company") today announced its third-quarter 2021 financial and operating results.
Third-Quarter 2021 Highlights
Announced second significant acquisition of 2021, agreeing to purchase ~20,000 net acres in western Glasscock County, extending the Company's high-margin, oil-weighted development runway to approximately seven years at current activity levels
Closed the purchase of the assets of Sabalo Energy, LLC ("Sabalo") in north Howard County and divestiture of 37.5% of the Company's legacy proved developed reserves on July 1, 2021
Produced an average of 76,703 barrels of oil equivalent ("BOE") per day and 35,329 barrels of oil per day ("BOPD"), a decrease of 13% and an increase of 41%, respectively, versus the third quarter of 2020
Increased oil cut to 46% of total production in third-quarter 2021 versus 29% in third-quarter 2020
Incurred capital expenditures of $137 million, excluding non-budgeted acquisitions and leasehold expenditures, completing 18 wells in Howard County during third-quarter 2021
Initiated the responsibly sourced gas (RSG) certification process and implementation of continuous on-site emissions monitoring of selected facilities
Published the Company's 2021 ESG and Climate Risk Report, which included Scope 3 emissions estimates and full workforce diversity data
Subsequent Highlights
Closed the western Glasscock County acquisition on October 18, 2021
Increased the borrowing base on the Company's senior secured credit facility to $1 billion from $725 million during the facility's semi-annual redetermination
"Over the last two years, we have successfully transformed Laredo by adding oily, high-margin inventory, reducing leverage and continuously improving operational and ESG performance," stated Jason Pigott, President and Chief Executive Officer. "Driven by seven years of high-quality, oil-weighted inventory and our demonstrated development expertise, we are now positioned to deliver sustainable Free Cash Flow1 generation and an even stronger capital structure. Our strategy has clearly created value for our shareholders and we will continue to seek accretive transactions where we can apply our proven development practices and ESG leadership."



Third-Quarter 2021 Financial Results
For the third quarter of 2021, the Company reported net income attributable to common stockholders of $136.8 million, or $8.56 per diluted share, which included a $95.2 million non-cash gain on sale of oil and natural gas properties, net. Adjusted Net Income1 for the third quarter of 2021 was $29.4 million, or $1.84 per adjusted diluted share. Adjusted EBITDA1 for the third quarter of 2021 was $133.4 million.
1Non-GAAP financial measure; please see supplemental reconciliations of GAAP to non-GAAP financial measures at the end of this release.
Operations Summary
In the third quarter of 2021, Laredo's total production averaged 76,703 BOE per day, including oil production of 35,329 BOPD. The Company's oil cut has increased substantially as packages of wells developed on the oil-weighted acreage acquired over the last two years are building Laredo's oil production base.
During third-quarter 2021, Laredo completed 18 wells and turned-in-line 19 wells. Laredo continues to realize a long-term positive trend in drilling and completions efficiencies and maintained an average drilling, completions and equipment cost per well of approximately $525 per foot. Although efficiency gains are currently helping to offset industry-wide service cost inflation, the Company anticipates further inflationary pressure in 2022.
Well performance in third-quarter 2021 was strong as well packages with optimized spacing continued to demonstrate high productivity. The wider-spaced Davis and West/Southwest packages in Central Howard are currently outperforming initial tighter-spaced packages in Central Howard by 24% and 36%, respectively, based on average oil productivity. The Vince Everett and Satnin/Josephine packages in North Howard, both developed by Sabalo prior to the closing of the transaction, are confirming the acreage quality of the North Howard acquisition. The Vince Everett development supports Laredo's assumptions for spacing and productivity for co-developed bounded and semi-bounded wells in North Howard and the Satnin/Josephine package, comprised of unbounded parent wells, is outperforming expectations.
During the third quarter of 2021, Laredo maintained its exemplary flaring/venting performance and began to integrate the recently acquired North Howard assets. Excluding the acquired assets, Laredo flared/vented 0.55% of produced gas during the quarter. Through the first nine months of 2021, excluding North Howard assets, the Company flared 0.37% of produced gas, down from 0.71% during full-year 2020. Including the North Howard assets, during third-quarter 2021, Laredo flared/vented 1.89% of produced gas. The increase is primarily related to third-party takeaway constraints associated with the acquired North Howard production facilities. Beginning in fourth-quarter 2021 and into 2022, Laredo plans to make investments to upgrade the acquired facilities to meet its current environmental standards and work with multiple third-party gathering and processing providers to improve reliability. Once complete, and assuming no third-party takeaway issues, Laredo expects the flaring/venting performance of these assets to be commensurate with the Company's other assets.
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The Company is currently operating two drilling rigs and one completions crew. At the end of the fourth quarter of 2021, Laredo expects to temporarily add a third drilling rig that will be utilized through the end of the first quarter of 2022. The Company expects to complete 18 wells and turn-in-line 24 wells during fourth-quarter 2021.
Operational and General and Administrative Expenses
Unit lease operating expense ("LOE") for the third quarter of 2021 was $4.23 per BOE, reflecting increased diesel costs and increased workover activity and other costs associated with integrating the Sabalo acquisition in north Howard County. Beginning in fourth-quarter 2021, the Company expects unit LOE to be approximately $4.25 per BOE, driven by increased diesel costs and generator usage, anticipated increased workover activity and continued optimization of artificial lift designs associated with the new acquisition areas.
Cash long-term incentive plan ("LTIP") expense of $0.29 per BOE for third-quarter 2021 was higher than forecast and is reflective of the 47% increase in Laredo's stock price from the time of forecast. At a current stock price of approximately $80, the expected expense for fourth-quarter 2021 is $0.35 per BOE.
Incurred Capital Expenditures
During the third quarter of 2021, total incurred capital expenditures were $137 million, excluding non-budgeted acquisitions and leasehold expenditures. Total investments were lower than expected, primarily related to the timing of activities during the period. Total investments were comprised of $115 million in drilling and completions activities, $9 million in land, exploration and data related costs, $7 million in infrastructure, including Laredo Midstream Services investments, and $6 million in other capitalized costs.
The Company expects fourth-quarter 2021 capital investments to be approximately $120 million and is maintaining the previous expectation of $420 million for full-year 2021.
Liquidity
At September 30, 2021, the Company had outstanding borrowings of $30 million on its $725 million senior secured credit facility, resulting in available capacity, after the reduction for outstanding letters of credit, of $651 million. Including cash and cash equivalents of $51 million, total liquidity was $702 million.
On October 20, 2021, as part of the semi-annual borrowing base determination, the Company's borrowing base was increased to $1 billion. Laredo and the member banks maintained the previous elected commitment level of $725 million.
At November 1, 2021, the Company had outstanding borrowings of $160 million on its $725 million senior secured credit facility elected commitment, resulting in available capacity, after the reduction for outstanding letters of credit, of $521 million. Including cash and cash equivalents of $86 million, total liquidity was $607 million. The balance reflects borrowings utilized to close the western Glasscock County acquisition on October 18, 2021.


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Fourth-Quarter 2021 Guidance
The table below reflects the Company's updated guidance for total and oil production for the fourth-quarter and full-year 2021, including volumes from the recently closed western Glasscock County acquisition.
4Q-21EFY-21E
Total production (MBOE per day)80.3 - 83.380.5 - 81.3
Oil production (MBOPD)39.0 - 41.031.3 - 31.8
Incurred capital expenditures, excluding non-budgeted acquisitions ($ MM)$120$420
The table below reflects the Company's guidance for select revenue and expense items for the fourth quarter of 2021.
4Q-21E
Average sales price realizations (excluding derivatives):
Oil (% of WTI)100%
NGL (% of WTI)40%
Natural gas (% of Henry Hub)75%
Net settlements received (paid) for matured commodity derivatives ($ MM):
Oil($72)
NGL($44)
Natural gas($34)
Other ($ MM):
   Net income (expense) of purchased oil($3.5)
Selected average costs & expenses:
Lease operating expenses ($/BOE)$4.25
Production and ad valorem taxes (% of oil, NGL and natural gas sales revenues)6.00%
Transportation and marketing expenses ($/BOE)$1.65
General and administrative expenses (excluding LTIP, $/BOE)$1.70
General and administrative expenses (LTIP cash, $/BOE)$0.35
General and administrative expenses (LTIP non-cash, $/BOE)$0.25
Depletion, depreciation and amortization ($/BOE)$9.50
Conference Call Details
On Wednesday, November 3, 2021, at 7:30 a.m. CT, Laredo will host a conference call to discuss its third-quarter 2021 financial and operating results and management's outlook, the content of which is not part of this earnings release. A slide presentation providing summary financial and statistical information that will be discussed on the call will be posted to the Company's website and available for review. The Company invites interested parties to listen to the call via the Company's website at www.laredopetro.com, under the tab for "Investor Relations." Portfolio managers and analysts who would like to participate on the call should dial 877.930.8286 (international dial-in 253.336.8309), using conference code 4653617, 10 minutes prior to the scheduled conference time. A telephonic replay will be available two hours after the call on November 3, 2021 through Wednesday, November 10, 2021. Participants may access this replay by dialing 855.859.2056, using conference code 4653617.
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About Laredo
Laredo Petroleum, Inc. is an independent energy company with headquarters in Tulsa, Oklahoma. Laredo's business strategy is focused on the acquisition, exploration and development of oil and natural gas properties, primarily in the Permian Basin of West Texas.
Additional information about Laredo may be found on its website at www.laredopetro.com.
Forward-Looking Statements
This press release and any oral statements made regarding the contents of this release, including in the conference call referenced herein, contain forward-looking statements as defined under Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, that address activities that Laredo assumes, plans, expects, believes, intends, projects, indicates, enables, transforms, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. The forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.
General risks relating to Laredo include, but are not limited to, the decline in prices of oil, natural gas liquids and natural gas and the related impact to financial statements as a result of asset impairments and revisions to reserve estimates, the ability of the Company to execute its strategies, including its ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to its financial results and to successfully integrate acquired businesses, assets and properties, oil production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries and other producing countries ("OPEC+"), the outbreak of disease, such as the coronavirus ("COVID-19") pandemic, and any related government policies and actions, changes in domestic and global production, supply and demand for commodities, including as a result of the COVID-19 pandemic and actions by OPEC+, long-term performance of wells, drilling and operating risks, the increase in service and supply costs, tariffs on steel, pipeline transportation and storage constraints in the Permian Basin, the possibility of production curtailment, hedging activities, the impacts of severe weather, including the freezing of wells and pipelines in the Permian Basin due to cold weather, possible impacts of litigation and regulations, the impact of the Company's transactions, if any, with its securities from time to time, the impact of new laws and regulations, including those regarding the use of hydraulic fracturing, the impact of new environmental, health and safety requirements applicable to the Company's business activities, the possibility of the elimination of federal income tax deductions for oil and gas exploration and development and other factors, including those and other risks described in its Annual Report on Form 10-K for the year ended December 31, 2020, Current Report on Form 8-K, filed with the Securities and Exchange Commission ("SEC") on May 11, 2021, and those set forth from time to time in other filings with the SEC. These documents are available through Laredo's website at www.laredopetro.com under the tab "Investor Relations" or through the SEC's Electronic Data Gathering and Analysis Retrieval System at www.sec.gov. Any of these factors could cause Laredo's actual results and plans to differ materially from those in the forward-looking statements. Therefore, Laredo can give no assurance that its future results will be as estimated. Any forward-looking statement speaks only as of the date on which such statement is made. Laredo does not intend to, and disclaims any obligation to, correct update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.
The SEC generally permits oil and natural gas companies, in filings made with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, and certain probable and possible reserves that meet the SEC's definitions for such terms. In this press release and the conference call, the Company may use the terms "resource potential," "resource play," "estimated ultimate recovery" or "EURs," "type curve" and "standardized measure," each of which the SEC guidelines restrict from being included in filings with the SEC without strict compliance with SEC definitions. These terms refer to the Company’s internal estimates of unbooked hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. "Resource potential" is used by the Company to refer to the estimated quantities of hydrocarbons that may be added to proved reserves, largely from a specified resource play potentially supporting numerous drilling locations. A "resource play" is a term used by the Company to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical
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section potentially supporting numerous drilling locations, which, when compared to a conventional play, typically has a lower geological and/or commercial development risk. "EURs" are based on the Company’s previous operating experience in a given area and publicly available information relating to the operations of producers who are conducting operations in these areas. Unbooked resource potential and "EURs" do not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules and do not include any proved reserves. Actual quantities of reserves that may be ultimately recovered from the Company’s interests may differ substantially from those presented herein. Factors affecting ultimate recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, decreases in oil, natural gas liquids and natural gas prices, well spacing, drilling and production costs, availability and cost of drilling services and equipment, lease expirations, transportation constraints, regulatory approvals, negative revisions to reserve estimates and other factors, as well as actual drilling results, including geological and mechanical factors affecting recovery rates. "EURs" from reserves may change significantly as development of the Company’s core assets provides additional data. In addition, the Company's production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. "Type curve" refers to a production profile of a well, or a particular category of wells, for a specific play and/or area. The "standardized measure" of discounted future new cash flows is calculated in accordance with SEC regulations and a discount rate of 10%. Actual results may vary considerably and should not be considered to represent the fair market value of the Company’s proved reserves.
This press release and any accompanying disclosures include financial measures that are not in accordance with generally accepted accounting principles ("GAAP"), such as Adjusted EBITDA, Adjusted Net Income and Free Cash Flow. While management believes that such measures are useful for investors, they should not be used as a replacement for financial measures that are in accordance with GAAP. For a reconciliation of such non-GAAP financial measures to the nearest comparable measure in accordance with GAAP, please see the supplemental financial information at the end of this press release.
Unless otherwise specified, references to "average sales price" refer to average sales price excluding the effects of the Company's derivative transactions.
All amounts, dollars and percentages presented in this press release are rounded and therefore approximate.


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Laredo Petroleum, Inc.
Selected operating data
Three months ended September 30,Nine months ended September 30,
2021202020212020
(unaudited)(unaudited)
Sales volumes:
Oil (MBbl)3,250 2,311 7,840 7,809 
NGL (MBbl)1,830 2,760 6,702 7,979 
Natural gas (MMcf)11,860 18,072 44,659 52,401 
Oil equivalents (MBOE)(1)(2)
7,057 8,083 21,985 24,522 
Average daily oil equivalent sales volumes (BOE/D)(2)
76,703 87,857 80,530 89,496 
Average daily oil sales volumes (Bbl/D)(2)
35,329 25,120 28,717 28,500 
Average sales prices(2):
Oil ($/Bbl)(3)
$70.56 $40.38 $65.66 $36.29 
NGL ($/Bbl)(3)
$26.20 $9.04 $19.86 $6.23 
Natural gas ($/Mcf)(3)
$2.87 $0.79 $2.20 $0.56 
Average sales price ($/BOE)(3)
$44.11 $16.39 $33.94 $14.78 
Oil, with commodity derivatives ($/Bbl)(4)
$53.94 $59.93 $49.33 $55.35 
NGL, with commodity derivatives ($/Bbl)(4)
$9.31 $10.46 $10.40 $8.35 
Natural gas, with commodity derivatives ($/Mcf)(4)
$1.45 $0.92 $1.53 $0.92 
Average sales price, with commodity derivatives ($/BOE)(4)
$29.70 $22.76 $23.86 $22.32 
Selected average costs and expenses per BOE sold(2):
Lease operating expenses$4.23 $2.45 $3.12 $2.55 
Production and ad valorem taxes2.54 1.08 2.09 1.02 
Transportation and marketing expenses1.65 1.63 1.57 1.54 
Midstream service expenses0.14 0.13 0.12 0.12 
General and administrative (excluding LTIP)1.61 1.16 1.52 1.16 
Total selected operating expenses$10.17 $6.45 $8.42 $6.39 
General and administrative (LTIP):
LTIP cash$0.29 $0.03 $0.50 $0.04 
LTIP non-cash$0.23 $0.23 $0.22 $0.22 
Depletion, depreciation and amortization$8.88 $5.82 $6.40 $7.13 
_______________________________________________________________________________
(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.



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Laredo Petroleum, Inc.
Consolidated balance sheets

(in thousands, except share data)September 30, 2021December 31, 2020
(unaudited)
Assets  
Current assets:  
Cash and cash equivalents$51,396 $48,757 
Accounts receivable, net122,657 63,976 
Derivatives3,272 7,893 
Other current assets17,222 15,964 
Total current assets194,547 136,590 
Property and equipment: 
Oil and natural gas properties, full cost method: 
Evaluated properties8,608,464 7,874,932 
Unevaluated properties not being depleted167,219 70,020 
Less: accumulated depletion and impairment(6,948,645)(6,817,949)
Oil and natural gas properties, net1,827,038 1,127,003 
Midstream service assets, net107,863 112,697 
Other fixed assets, net32,192 32,011 
Property and equipment, net1,967,093 1,271,711 
Derivatives35,742 — 
Operating lease right-of-use assets15,236 17,973 
Other noncurrent assets, net46,354 16,336 
Total assets$2,258,972 $1,442,610 
Liabilities and stockholders' equity 
Current liabilities: 
Accounts payable and accrued liabilities$61,341 $38,279 
Accrued capital expenditures53,655 28,275 
Undistributed revenue and royalties85,265 24,728 
Derivatives288,794 31,826 
Operating lease liabilities11,386 11,721 
Other current liabilities74,370 62,766 
Total current liabilities574,811 197,595 
Long-term debt, net1,349,896 1,179,266 
Derivatives37,453 12,051 
Asset retirement obligations55,680 64,775 
Operating lease liabilities6,064 8,918 
Other noncurrent liabilities11,006 1,448 
Total liabilities2,034,910 1,464,053 
Commitments and contingencies
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of September 30, 2021 and December 31, 2020
— — 
Common stock, $0.01 par value, 22,500,000 shares authorized and 16,111,452 and 12,020,164 issued and outstanding as of September 30, 2021 and December 31, 2020, respectively
161 120 
Additional paid-in capital2,715,196 2,398,464 
Accumulated deficit(2,491,295)(2,420,027)
Total stockholders' equity224,062 (21,443)
Total liabilities and stockholders' equity$2,258,972 $1,442,610 








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Laredo Petroleum, Inc.
Consolidated statements of operations
 Three months ended September 30,Nine months ended September 30,
(in thousands, except per share data)2021202020212020
(unaudited)(unaudited)
Revenues:   
Oil sales$229,329 $93,329 $514,752 $283,412 
NGL sales47,949 24,935 133,121 49,721 
Natural gas sales33,998 14,198 98,186 29,357 
Midstream service revenues1,739 1,751 4,292 6,715 
Sales of purchased oil66,235 39,334 173,500 119,922 
Total revenues379,250 173,547 923,851 489,127 
Costs and expenses:
Lease operating expenses29,837 19,840 68,526 62,471 
Production and ad valorem taxes17,937 8,753 45,957 24,935 
Transportation and marketing expenses11,660 13,161 34,477 37,886 
Midstream service expenses1,014 1,073 2,572 3,058 
Costs of purchased oil68,805 42,720 183,458 138,134 
General and administrative15,008 11,473 49,182 34,694 
Organizational restructuring expenses— — 9,800 4,200 
Depletion, depreciation and amortization62,678 47,015 140,763 174,891 
Impairment expense— 196,088 1,613 789,235 
Other operating expenses1,798 1,102 4,099 3,325 
Total costs and expenses208,737 341,225 540,447 1,272,829 
Gain on sale of oil and natural gas properties, net(1)
95,223 — 93,482 — 
Operating income (loss)265,736 (167,678)476,886 (783,702)
Non-operating income (expense):
Gain (loss) on derivatives, net(96,240)(45,250)(467,547)162,049 
Interest expense(30,406)(26,828)(82,222)(78,870)
Loss on extinguishment of debt— — — (13,320)
Loss on disposal of assets, net(22)(607)(28)(1,057)
Write-off of debt issuance costs— — — (1,103)
Other income, net441 533 2,236 608 
Total non-operating income (expense), net(126,227)(72,152)(547,561)68,307 
Income (loss) before income taxes139,509 (239,830)(70,675)(715,395)
Income tax (expense) benefit:
Current(1,300)— (1,300)— 
Deferred(1,377)2,398 707 7,154 
Total income tax (expense) benefit(2,677)2,398 (593)7,154 
Net income (loss)$136,832 $(237,432)$(71,268)$(708,241)
Net income (loss) per common share: 
Basic$8.68 $(20.32)$(5.29)$(60.76)
Diluted$8.56 $(20.32)$(5.29)$(60.76)
Weighted-average common shares outstanding:   
Basic15,756 11,686 13,464 11,657 
Diluted15,993 11,686 13,464 11,657 
_____________________________________________________________________________
(1)In connection with the sale of the Company's working interest in certain oil and natural gas properties, $1.7 million of transaction expenses, which were recorded in the second quarter of 2021, have been reclassified to be presented net with the gain recorded on the sale of oil and natural gas properties for the nine months ended September 30, 2021.




9


Laredo Petroleum, Inc.
Condensed consolidated statements of cash flows
 Three months ended September 30,Nine months ended September 30,
(in thousands)2021202020212020
(unaudited)(unaudited)
Cash flows from operating activities:  
Net income (loss)
$136,832 $(237,432)$(71,268)$(708,241)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Share-settled equity-based compensation, net1,811 2,041 5,609 6,111 
Depletion, depreciation and amortization62,678 47,015 140,763 174,891 
Impairment expense— 196,088 1,613 789,235 
Gain on sale of oil and natural gas properties, net(1)
(95,223)— (93,482)— 
Mark-to-market on derivatives:
(Gain) loss on derivatives, net96,240 45,250 467,547 (162,049)
Settlements (paid) received for matured derivatives, net
(92,726)51,840 (191,507)186,435 
Settlements received for early-terminated commodity derivatives, net— 6,340 — 6,340 
Premiums received (paid) for commodity derivatives
— — 9,041 (51,070)
Loss on extinguishment of debt— — — 13,320 
Deferred income tax expense (benefit)1,377 (2,398)(707)(7,154)
Other, net6,542 5,099 16,902 17,956 
Cash flows from operating activities before changes in operating assets and liabilities, net117,531 113,843 284,511 265,774 
Change in current assets and liabilities, net(3,142)(8,360)27,106 19,098 
Change in noncurrent assets and liabilities, net(16,715)(3,425)(24,505)(11,252)
Net cash provided by operating activities
97,674 102,058 287,112 273,620 
Cash flows from investing activities:
Acquisitions of oil and natural gas properties, net(627,044)— (627,044)(23,563)
Capital expenditures:
Oil and natural gas properties(112,770)(36,338)(278,847)(278,277)
Midstream service assets(814)(756)(2,375)(2,517)
Other fixed assets(1,990)(955)(3,226)(3,024)
Proceeds from dispositions of capital assets, net of selling costs(1)
395,176 514 393,742 1,242 
Net cash used in investing activities
(347,442)(37,535)(517,750)(306,139)
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility180,000 45,000 425,000 45,000 
Payments on Senior Secured Credit Facility(530,000)(85,000)(650,000)(185,000)
Issuance of January 2025 Notes and January 2028 Notes— — — 1,000,000 
Issuance of July 2029 Notes400,000 — 400,000 — 
Extinguishment of debt— — — (808,855)
Proceeds from issuance of common stock, net of costs— — 72,492 — 
Other, net(13,820)(12)(14,215)(19,225)
Net cash provided by (used in) financing activities
36,180 (40,012)233,277 31,920 
Net (decrease) increase in cash and cash equivalents(213,588)24,511 2,639 (599)
Cash, cash equivalents and restricted cash, beginning of period264,984 15,747 48,757 40,857 
Cash and cash equivalents, end of period$51,396 $40,258 $51,396 $40,258 
_____________________________________________________________________________
(1)In connection with the sale of the Company's working interest in certain oil and natural gas properties, $1.7 million of transaction expenses, which were recorded in the second quarter of 2021, have been reclassified to be presented net with the gain recorded on the sale of oil and natural gas properties for the nine months ended September 30, 2021. This resulted in a $1.7 million reclassification between operating cash flows and investing cash flows during the nine months ended September 30, 2021.
10


Laredo Petroleum, Inc.
Total incurred capital expenditures
The following table presents the components of the Company's incurred capital expenditures, excluding non-budgeted acquisition costs, for the periods presented:
Three months ended September 30,Nine months ended September 30,
(in thousands)2021202020212020
(unaudited)(unaudited)
Oil and natural gas properties$135,174 $41,128 $306,445 $269,937 
Midstream service assets567 1,103 2,422 2,697 
Other fixed assets1,685 495 3,229 3,092 
Total incurred capital expenditures, excluding non-budgeted acquisition costs$137,426 $42,726 $312,096 $275,726 


































11


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.
Free Cash Flow (Unaudited)
Free Cash Flow is a non-GAAP financial measure that the Company defines as net cash provided by operating activities (GAAP) before changes in operating assets and liabilities, net, less incurred capital expenditures, excluding non-budgeted acquisition costs. Free Cash Flow does not represent funds available for future discretionary use because it excludes funds required for future debt service, capital expenditures, acquisitions, working capital, income taxes, franchise taxes and other commitments and obligations. However, management believes Free Cash Flow is useful to management and investors in evaluating operating trends in its business that are affected by production, commodity prices, operating costs and other related factors. There are significant limitations to the use of Free Cash Flow as a measure of performance, including the lack of comparability due to the different methods of calculating Free Cash Flow reported by different companies.
The following table presents a reconciliation of net cash provided by operating activities (GAAP) to Free Cash Flow (non-GAAP) for the periods presented:
Three months ended September 30,Nine months ended September 30,
(in thousands)2021202020212020
(unaudited)(unaudited)
Net cash provided by operating activities(1)
$97,674 $102,058 $287,112 $273,620 
Less:
Change in current assets and liabilities, net(3,142)(8,360)27,106 19,098 
Change in noncurrent assets and liabilities, net(16,715)(3,425)(24,505)(11,252)
Cash flows from operating activities before changes in operating assets and liabilities, net(1)
117,531 113,843 284,511 265,774 
Less incurred capital expenditures, excluding non-budgeted acquisition costs:
Oil and natural gas properties(2)
135,174 41,128 306,445 269,937 
Midstream service assets(2)
567 1,103 2,422 2,697 
Other fixed assets1,685 495 3,229 3,092 
Total incurred capital expenditures, excluding non-budgeted acquisition costs 137,426 42,726 312,096 275,726 
Free Cash Flow (non-GAAP) $(19,895)$71,117 $(27,585)$(9,952)
_____________________________________________________________________________
(1)In connection with the sale of the Company's working interest in certain oil and natural gas properties, $1.7 million of transaction expenses, which were recorded in the second quarter of 2021, have been reclassified to be presented net with the gain recorded on the sale of oil and natural gas properties for the nine months ended September 30, 2021. This resulted in a $1.7 million reclassification between operating cash flows and investing cash flows during the nine months ended September 30, 2021.
(2)Includes capitalized share-settled equity-based compensation and asset retirement costs.


12


Adjusted Net Income (Unaudited)
Adjusted Net Income is a non-GAAP financial measure that the Company defines as income or loss before income taxes (GAAP) plus adjustments for mark-to-market on derivatives, premiums paid or received for commodity derivatives that matured during the period, impairment expense, gains or losses on disposal of assets, other non-recurring income and expenses and adjusted income tax expense. Management believes Adjusted Net Income helps investors in the oil and natural gas industry to measure and compare the Company's performance to other oil and natural gas companies by excluding from the calculation items that can vary significantly from company to company depending upon accounting methods, the book value of assets and other non-operational factors.
The following table presents a reconciliation of loss before income taxes (GAAP) to Adjusted Net Income (non-GAAP) for the periods presented:
Three months ended September 30,Nine months ended September 30,
(in thousands, except per share data)2021202020212020
(unaudited)(unaudited)
Income (loss) before income taxes
$139,509 $(239,830)$(70,675)$(715,395)
Plus:
Mark-to-market on derivatives:
(Gain) loss on derivatives, net96,240 45,250 467,547 (162,049)
Settlements (paid) received for matured derivatives, net
(92,726)51,840 (191,507)186,435 
Settlements received for early-terminated commodity derivatives, net— 6,340 — 6,340 
Net premiums paid for commodity derivatives that matured during the period(1)
(10,182)— (31,370)(477)
Organizational restructuring expenses— — 9,800 4,200 
Impairment expense— 196,088 1,613 789,235 
Gain on sale of oil and natural gas properties, net(95,223)— (93,482)— 
Loss on extinguishment of debt— — — 13,320 
Loss on disposal of assets, net22 607 28 1,057 
Write-off of debt issuance costs— — — 1,103 
Adjusted income before adjusted income tax expense37,640 60,295 91,954 123,769 
Adjusted income tax expense(2)
(8,281)(13,265)(20,230)(27,229)
Adjusted Net Income (non-GAAP)$29,359 $47,030 $71,724 $96,540 
Net income (loss) per common share:
Basic$8.68 $(20.32)$(5.29)$(60.76)
Diluted$8.56 $(20.32)$(5.29)$(60.76)
Adjusted Net Income per common share:
Basic$1.86 $4.02 $5.33 $8.28 
Diluted$1.84 $4.02 $5.33 $8.28 
Adjusted diluted$1.84 $4.02 $5.25 $8.25 
Weighted-average common shares outstanding:   
Basic15,756 11,686 13,464 11,657 
Diluted15,993 11,686 13,464 11,657 
Adjusted diluted15,993 11,691 13,661 11,705 
_______________________________________________________________________________
(1)Reflects net premiums paid previously or upon settlement that are attributable to derivatives settled in the respective periods presented.
(2)Adjusted income tax expense is calculated by applying a statutory tax rate of 22% for each of the periods ended September 30, 2021 and 2020.



13


Adjusted EBITDA (Unaudited)
Adjusted EBITDA is a non-GAAP financial measure that the Company defines as net income or loss (GAAP) plus adjustments for share-settled equity-based compensation, depletion, depreciation and amortization, impairment expense, mark-to-market on derivatives, premiums paid or received for commodity derivatives that matured during the period, accretion expense, gains or losses on disposal of assets, interest expense, income taxes and other non-recurring income and expenses. Adjusted EBITDA provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, working capital movement or tax position. Adjusted EBITDA does not represent funds available for future discretionary use because it excludes funds required for debt service, capital expenditures, working capital, income taxes, franchise taxes and other commitments and obligations. However, management believes Adjusted EBITDA is useful to an investor in evaluating the Company's operating performance because this measure:
is widely used by investors in the oil and natural gas industry to measure a company's operating performance without regard to items that can vary substantially from company to company depending upon accounting methods, the book value of assets, capital structure and the method by which assets were acquired, among other factors;
helps investors to more meaningfully evaluate and compare the results of the Company's operations from period to period by removing the effect of its capital structure from its operating structure; and
 is used by management for various purposes, including as a measure of operating performance, in presentations to the Company's board of directors and as a basis for strategic planning and forecasting.
There are significant limitations to the use of Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the Company's net income or loss and the lack of comparability of results of operations to different companies due to the different methods of calculating Adjusted EBITDA reported by different companies. The Company's measurements of Adjusted EBITDA for financial reporting as compared to compliance under its debt agreements differ.
The following table presents a reconciliation of net income (loss) (GAAP) to Adjusted EBITDA (non-GAAP) for the periods presented:
 Three months ended September 30,Nine months ended September 30,
(in thousands)2021202020212020
(unaudited)(unaudited)
Net income (loss)$136,832 $(237,432)$(71,268)$(708,241)
Plus:  
Share-settled equity-based compensation, net1,811 2,041 5,609 6,111 
Depletion, depreciation and amortization62,678 47,015 140,763 174,891 
Impairment expense— 196,088 1,613 789,235 
Gain on sale of oil and natural gas properties, net(95,223)— (93,482)— 
Organizational restructuring expenses— — 9,800 4,200 
Mark-to-market on derivatives:
(Gain) loss on derivatives, net96,240 45,250 467,547 (162,049)
Settlements (paid) received for matured derivatives, net
(92,726)51,840 (191,507)186,435 
Settlements received for early-terminated commodity derivatives, net— 6,340 — 6,340 
Net premiums paid for commodity derivatives that matured during the period(1)
(10,182)— (31,370)(477)
Accretion expense906 1,102 3,207 3,325 
Loss on disposal of assets, net22 607 28 1,057 
Interest expense30,406 26,828 82,222 78,870 
Loss on extinguishment of debt— — — 13,320 
Write-off of debt issuance costs— — — 1,103 
Income tax expense (benefit)2,677 (2,398)593 (7,154)
Adjusted EBITDA (non-GAAP)$133,441 $137,281 $323,755 $386,966 
_____________________________________________________________________________
(1)Reflects net premiums paid previously or upon settlement that are attributable to derivatives settled in the respective periods presented.
14



# # #

Investor Contact:
Ron Hagood
918.858.5504
rhagood@laredopetro.com

15
investorpresentation1122
Third-Quarter 2021 Earnings Presentation Exhibit 99.2


 
Forward-Looking / Cautionary Statements 2 This presentation, including any oral statements made regarding the contents of this presentation, contains forward-looking statements as defined under Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, that address activities that Laredo Petroleum, Inc. (together with its subsidiaries, the “Company”, “Laredo” or “LPI”) assumes, plans, expects, believes, intends, projects, indicates, enables, transforms, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. The forward- looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. General risks relating to Laredo include, but are not limited to, the decline in prices of oil, natural gas liquids and natural gas and the related impact to financial statements as a result of asset impairments and revisions to reserve estimates, the ability of the Company to execute its strategies, including its ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to its financial results and to successfully integrate acquired businesses, assets and properties, oil production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries and other producing countries (“OPEC+”), the outbreak of disease, such as the coronavirus (“COVID-19”) pandemic, and any related government policies and actions, changes in domestic and global production, supply and demand for commodities, including as a result of the COVID-19 pandemic and actions by OPEC+, long-term performance of wells, drilling and operating risks, the increase in service and supply costs, tariffs on steel, pipeline transportation and storage constraints in the Permian Basin, the possibility of production curtailment, hedging activities, the impacts of severe weather, including the freezing of wells and pipelines in the Permian Basin due to cold weather, possible impacts of litigation and regulations, the impact of the Company’s transactions, if any, with its securities from time to time, the impact of new laws and regulations, including those regarding the use of hydraulic fracturing, the impact of new environmental, health and safety requirements applicable to the Company’s business activities, the possibility of the elimination of federal income tax deductions for oil and gas exploration and development and other factors, including those and other risks described in its Annual Report on Form 10-K for the year ended December 31, 2020, Current Report on Form 8-K, filed with the Securities and Exchange Commission ("SEC") on May 11, 2021, and those set forth from time to time in other filings with the SEC. These documents are available through Laredo’s website at www.laredopetro.com under the tab “Investor Relations” or through the SEC’s Electronic Data Gathering and Analysis Retrieval System at www.sec.gov. Any of these factors could cause Laredo’s actual results and plans to differ materially from those in the forward-looking statements. Therefore, Laredo can give no assurance that its future results will be as estimated. Any forward-looking statement speaks only as of the date on which such statement is made. Laredo does not intend to, and disclaims any obligation to, correct, update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. The SEC generally permits oil and natural gas companies, in filings made with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, and certain probable and possible reserves that meet the SEC’s definitions for such terms. In this presentation, the Company may use the terms “resource potential,” “resource play,” “estimated ultimate recovery,” or “EURs,” “type curve” and “standardized measure,” each of which the SEC guidelines restrict from being included in filings with the SEC without strict compliance with SEC definitions. These terms refer to the Company’s internal estimates of unbooked hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. “Resource potential” is used by the Company to refer to the estimated quantities of hydrocarbons that may be added to proved reserves, largely from a specified resource play potentially supporting numerous drilling locations. A “resource play” is a term used by the Company to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section potentially supporting numerous drilling locations, which, when compared to a conventional play, typically has a lower geological and/or commercial development risk. “EURs” are based on the Company’s previous operating experience in a given area and publicly available information relating to the operations of producers who are conducting operations in these areas. Unbooked resource potential and “EURs” do not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules and do not include any proved reserves. Actual quantities of reserves that may be ultimately recovered from the Company’s interests may differ substantially from those presented herein. Factors affecting ultimate recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, decreases in oil, natural gas liquids and natural gas prices, well spacing, drilling and production costs, availability and cost of drilling services and equipment, lease expirations, transportation constraints, regulatory approvals, negative revisions to reserve estimates and other factors, as well as actual drilling results, including geological and mechanical factors affecting recovery rates. “EURs” from reserves may change significantly as development of the Company’s core assets provides additional data. In addition, the Company’s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. “Type curve” refers to a production profile of a well, or a particular category of wells, for a specific play and/or area. The “standardized measure” of discounted future new cash flows is calculated in accordance with SEC regulations and a discount rate of 10%. Actual results may vary considerably and should not be considered to represent the fair market value of the Company’s proved reserves. This presentation includes financial measures that are not in accordance with generally accepted accounting principles (“GAAP”), such as Adjusted EBITDA, 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 definitions of such non-GAAP financial measures, please see the Appendix. Unless otherwise specified, references to “average sales price” refer to average sales price excluding the effects of the Company’s derivative transactions. All amounts, dollars and percentages presented in this presentation are rounded and therefore approximate.


 
3 Laredo Petroleum: Pure-Play Permian Energy Producer Laredo Petroleum (NYSE: LPI) Market Capitalization (Shares Outstanding)1 $1.29 Billion (17.1 Million Shares) Enterprise Value1 $2.70 Billion Net Acres ~166,000 2021E Production2 ~80.8 MBOE/d 2021E Oil Production2 ~31.6 MBO/d Principles Laredo Leasehold Expand High-Margin Inventory  Opportunistically acquire oil-weighted inventory  High-grade development to maximize capital efficiency and increase oil cut Manage Risk  Target Free Cash Flow3 generation and debt reduction  Manage balance sheet and liquidity to facilitate optimal transaction financing  Maintain a consistent commodity hedging program Continuously Improve  Focus on efficiencies and low-cost operations  Reduce GHG emissions intensity and flaring 1As of market close 11/1/2021; 2Utilizes mid-point of FY-21 guidance; 3See Appendix for definitions of non-GAAP financial measures


 
Continuously Improve  Reduced percentage of produced natural gas flared/vented to 0.37% through 3Q-21, excluding recently integrated North Howard assets, from 0.71% for FY-20  Reduced drilling costs by 14% in 2021 versus FY-20 average  Company-owned sand mine protects against sand cost inflation, saving an estimated $250,000 per well  Commitment to eliminate routine flaring by 2025 Manage Risk  No term-debt maturities until 2025  Extended credit facility maturity to 2025  Credit facility borrowing base increased to $1 billion  Active hedge program in 2022 to protect forecasted Free Cash Flow1  Expect to reduce total leverage ratio to ~1.5x by YE-22 Rapid Execution of Transformational Strategy 41See Appendix for reconciliations and definitions of non-GAAP measures Expand High-Margin Inventory  Added ~55,000 net acres of oil-weighted leasehold in six separate transactions  Divested ~94 million BOE of legacy low- margin, gas-weighted reserves  Development focused on recently acquired oil-weighted inventory  Oil cut expected to rise from 31% in 1Q-21 to ~50% by YE-22


 
5 Oil-Weighted Leasehold Built at Lower Oil Prices October 2019 Leasehold YE-2019 Leasehold Pro Forma Current Leasehold Legacy Leasehold Acquired Oil-Weighted Leasehold Acquired approximately 55,000 net acres of highly productive, oil-weighted inventory in Howard and western Glasscock counties in just two years at an average benchmark WTI of ~$63 per barrel Cumulative Oil-Weighted Acquired Inventory vs. Benchmark WTI


 
Wider-Spaced Packages 1Map and acreage as of 10-18-21 2Gross operated locations as of January 2021 (adjusted for 2020 completions), pro forma for all announced acquisitions; 3Flat oil price needed to achieve 10% IRR assuming a $3.00 natural gas price;4Production data normalized to 10,000’ lateral length, downtime days excluded Development Activity Focused on Acquired Acreage 6 W. Glasscock County Howard County Total Net acres1 ~22,200 ~33,400 ~55,600 Target formations LS/WC-A/WC-B LS/WC-A * Locations (gross)2 ~175 ~225 ~400 Avg. breakeven oil price3 <$40 <$35 * Laredo Leasehold North Howard Central Howard W. Glasscock Package Location Tighter-Spaced Packages


 
Est. Cash Margin Increase Attributed to Oil Cut Improvement3 Realized Price 7 Increased Oil Cut and Margin Improvement Drives Free Cash Flow Generation 2 1Excludes impacts of hedges and interest payments; 2Includes the following charges (LOE, Transportation, Production Taxes, Ad Valorem Taxes, Cash G&A & Cash LTIP); 3Estimated using Q2-21 production mix and current quarter realized prices to estimate impact of production mix shift 3 Legacy Leasehold Acquired Oil-Weighted Leasehold Cash Costs1,2 Cash Margin Benchmark WTI 1,2


 
Maintaining Operational & Cost Advantages 8 FY-17 FY-18 FY-19 FY-20 YTD-211 1January through September 2021 1


 
9 Laredo-Owned Sand Mine Saves on Completions Costs LPI Leasehold Mining Area Operated on Laredo-owned surface acreage 5+ years supply of sand Protects against sand cost inflation Reduces emissions >$250,0001 savings per well versus market price  Utilized in all 3Q-21 completions, 100% of all sand used  Mine operated by a third party  No additional capital investment beyond surface acreage acquisition  Elimination of 300,000 miles per month of truck traffic and utilization of wet sand reduces emissions 1For Howard County completions


 
Commitment to Reducing Emissions 12019 calendar year as baseline; 2As a percentage of natural gas production ; 3January through September 2021 <12.5 mtCO2e / MBOE <0.20% methane emissions1,2 Zero routine flaring Emissions Reduction Targets for 2025 For the second consecutive year, flaring/venting reduction targets are part of executive compensation metrics 10 3 3 North Howard Excluded North Howard Included Facility upgrades and increased third-party takeaway reliability expected to improve venting/flaring performance in North Howard


 
11 Corporate and Community Responsibility >$610,000 Total amount donated since 2019 to improve our local communities Giving Diversity1 Governance EEO-1 data disclosed in Company’s 2021 ESG & Climate Risk Report Board refresh in last 2 years Independent Directors Female & Minority Directors Separated roles of Chairman and CEO October 2019 67% 89% 56% 27% Women in workforce Minorities in workforce Women and/or minorities in professional-or- higher roles 25% 61% Safety 0.86 0.74 2019 2020 TRIR2 Laredo had zero at-fault vehicle incidents in 2020 1Data as of 12-31-20; 2Combined employee and contractor Total Recordable Incident Rate


 
Actively Managing our Balance Sheet & Liquidity 12 9.500% Senior Notes 2025 1See Appendix for reconciliations and definitions of non-GAAP measures; 2Balance as of 11-1-21  No term-debt maturities until 2025  Executed “At-the-Market” equity program YTD 2021 resulting in ~$73 million of net proceeds  Extended credit facility maturity until 2025  Active hedge program to protect Free Cash Flow1  Program expected to generate sustainable Free Cash Flow1 used to reduce debt and drive leverage down to 1.5x or less by YE-22 10.125% Senior Notes 2028 Drawn Credit Facility Undrawn Credit Facility Current Maturity Profile $607 MM Liquidity2 $86 MM Cash Balance2 7.750% Senior Notes 2029 Proceeds from issuance of 2029 notes used to pay down credit facility, significantly increasing liquidity Senior secured credit facility borrowing base increased to $1 billion and elected commitment maintained at $725 million


 
Active Hedge Program to Protect Free Cash Flow 13 1Hedge percentage calculated off mid-point guidance Note: NGL barrel composition includes 42% Ethane, 33% Propane, 11% Butane, 3% Isobutane and 11% Pentane


 
14 Guidance Production: 4Q-21 FY-21 Total production (MBOE/d) 80.3 - 83.3 80.5 - 81.3 Oil production (MBO/d) 39.0 - 41.0 31.3 - 31.8 Incurred capital expenditures1 ($ MM) $120 $420 Average sales price realizations: (excluding derivatives) 4Q-21 Oil (% of WTI) 100% NGL (% of WTI) 40% Natural gas (% of Henry Hub) 75% Net settlements received (paid) for matured commodity derivatives ($ MM): 4Q-21 Oil ($72) NGL ($44) Natural Gas ($34) Other ($ MM): 4Q-21 Net income / (expense) of purchased oil ($3.5) Operating costs & expenses ($/BOE): 4Q-21 Lease operating expenses $4.25 Production and ad valorem taxes (% of oil, NGL and natural gas revenues) 6.00% Transportation and marketing expenses $1.65 General and administrative expenses (excluding LTIP) $1.70 General and administrative expenses (LTIP cash) $0.35 General and administrative expenses (LTIP non-cash) $0.25 Depletion, depreciation and amortization $9.50 1Excludes non-budgeted acquisitions and leasehold expenses


 
L A R E D O P E T R O L E U M APPENDIX


 
Commodity Prices Used for 4Q-21 Average Sales Price Realization and Derivatives Guidance 16 Natural Gas: Natural Gas Liquids: Oil: Note: Pricing assumptions as of 10-29-21 WTI NYMEX Brent ICE ($/Bbl) ($/Bbl) Oct-21 $81.22 $83.71 Nov-21 $83.06 $83.67 Dec-21 $81.13 $82.46 4Q-21 Average $81.79 $83.28 C2 C3 IC4 NC4 C5+ Composite ($/Bbl) ($/Bbl) ($/Bbl) ($/Bbl) ($/Bbl) ($/Bbl) Oct-21 $18.24 $60.73 $68.12 $67.93 $80.55 $46.08 Nov-21 $17.64 $58.38 $68.62 $68.88 $80.64 $45.18 Dec-21 $17.69 $58.28 $67.99 $68.09 $80.22 $45.02 4Q-21 Average $17.86 $59.14 $68.24 $68.29 $80.47 $45.43 HH Waha ($/MMBtu) ($/MMBtu) Oct-21 $5.84 $4.92 Nov-21 $6.20 $5.56 Dec-21 $5.43 $5.51 4Q-21 Average $5.82 $5.33


 
Supplemental Non-GAAP Financial Measures Adjusted EBITDA Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss (GAAP) plus adjustments for share-settled equity-based compensation, depletion, depreciation and amortization, impairment expense, mark-to-market on derivatives, premiums paid 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): 17 Three months ended, (in thousands, unaudited) 12/31/2020 3/31/2021 6/30/2021 9/30/2021 Net Income (loss) ($165,932) ($75,439) ($132,661) $136,832 Plus: Share-settled equity-based compensation, net 2,106 2,068 1,730 1,811 Depletion, depreciation and amortization 42,210 38,109 39,976 62,678 Impairment expense 109,804 — 1,613 — (Gain) loss on sale of oil and natural gas properties, net — — 1,741 (95,223) Organizational restructuring expenses — — 9,800 — Mark-to-market on derivatives: Loss on derivatives, net 81,935 154,365 216,942 96,240 Settlements received (paid) for matured derivatives, net 41,786 (41,174) (57,607) (92,726) Net premiums paid for commodity derivatives that matured during the period(1) — (11,005) (10,183) (10,182) Accretion expense 1,105 1,143 1,158 906 (Gain) loss on disposal of assets, net (94) 72 (66) 22 Interest expense 26,139 25,946 25,870 30,406 Gain on extinguishment of debt, net (22,309) — — — Income tax expense (benefit) 3,208 (762) (1,322) 2,677 Adjusted EBITDA $119,958 $93,323 $96,991 $133,441 (1) Reflects net premiums paid previously or upon settlement that are attributable to derivatives settled in the respective periods presented


 
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): 18 Three months ended, (in thousands, unaudited) 12/31/2020 3/31/2021 6/30/2021 9/30/2021 Net Income (loss) ($165,932) ($75,439) ($132,661) $136,832 Organizational restructuring expenses — — 9,800 — (Gain) loss on sale of oil and natural gas properties, net — — 1,741 (95,223) Gain on extinguishment of debt, net (22,309) — — — (Gain) loss on disposal of assets, net (94) 72 (66) 22 Consolidated Net Income (Loss) (188,335) (75,367) (121,186) 41,631 Mark-to-market on derivatives: Loss on derivatives, net 81,935 154,365 216,942 96,240 Settlements received (paid) for matured derivatives, net 41,786 (41,174) (57,607) (92,726) Mark-to-market loss on derivatives, net 123,721 113,191 159,335 3,514 Premiums received (paid) for commodity derivatives — 9,041 — Non-Cash Charges/Income: Deferred income tax expense (benefit) 3,208 (762) (1,322) 1,377 Depletion, depreciation and amortization 42,210 38,109 39,976 62,678 Share-settled equity-based compensation, net 2,106 2,068 1,730 1,811 Accretion expense 1,105 1,143 1,158 906 Impairment expense 109,804 — 1,613 — Interest expense 26,139 25,946 25,870 30,406 Consolidated EBITDAX after EBITDAX Adjustments (limited to 15%) (non-GAAP) $119,958 $113,369 $107,174 $142,322


 
Net Debt Net Debt, a non-GAAP financial measure, is calculated as the face value of long-term debt less cash and cash equivalents. Management believes Net Debt is useful to management and investors in determining the Company’s leverage position since the Company has the ability, and may decide, to use a portion of its cash and cash equivalents to reduce debt. Net Debt as of 9-30-21 was $1.318 B. Net Debt to TTM Adjusted EBITDA Net Debt to TTM Adjusted EBITDA is calculated as Net Debt divided by trailing twelve-month Adjusted EBITDA. Net Debt to Adjusted EBITDA is used by 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. 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 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. 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 activities (GAAP) before changes in operating assets and liabilities, net, less incurred capital expenditures, excluding non-budgeted acquisition costs. Free Cash Flow does not represent funds available for future discretionary use because it excludes funds required for future debt service, capital expenditures, acquisitions, working capital, income taxes, franchise taxes and other commitments and obligations. However, management believes Free Cash Flow is useful to management and investors in evaluating operating trends in 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. We are unable to provide a reconciliation of the forward-looking Free Cash Flow projection contained in this presentation to net cash provided by operating activities, the most directly comparable GAAP financial measure, because we cannot reliably predict certain of the necessary components of net cash provided by operating activities, such as changes in working capital, without unreasonable efforts. Such unavailable reconciling information may be significant. 19 Supplemental Non-GAAP Financial Measures


 
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