UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT PURSUANT TO
SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Date of report (Date of earliest event reported): May 5, 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 May 5, 2021, the Company announced its financial and operating results for the quarter ended March 31, 2021. 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 May 6, 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 3195169. A replay of the call will be available through Thursday, May 13, by dialing 1.855.859.2056, and using conference code 3195169. 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 May 5, 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 in this Item 7.01 by reference.
On May 5, 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 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, 2020 and the Company's other filings with the SEC for a discussion of other risks and uncertainties. The Company disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
In accordance with General Instruction B.2 of Form 8-K, the information furnished under this Item 7.01of this Current Report on Form 8-K and the exhibits attached hereto are deemed to be "furnished" and shall not be deemed "filed" for the purpose of Section 18 of the Exchange Act, or otherwise subject to the liabilities of that section, nor shall such information be deemed incorporated by reference into any filing under the Securities Act or the Exchange Act.
Item 9.01. Financial Statements and Exhibits.
(d) Exhibits.
| Exhibit Number | Description | |||||||
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL). | |||||||
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| LAREDO PETROLEUM, INC. | ||||||||
| Date: May 5, 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 First-Quarter 2021 Financial and Operating Results
TULSA, OK - May 5, 2021 - Laredo Petroleum, Inc. (NYSE: LPI) ("Laredo" or the "Company") today announced its first-quarter 2021 financial and operating results.
First-Quarter 2021 Highlights
•Generated $71 million of cash flows from operating activities and $22 million of Free Cash Flow1
•Sold 723,579 shares at an average price of $38.75 for net proceeds of $26.9 million through the Company's at-the-market equity program ("ATM program")
•Reduced Net Debt1 by $30 million during the quarter
•Produced an average of 24,261 barrels of oil per day ("BOPD"), an increase of 11% from fourth-quarter 2020
•Produced an average of 78,989 barrels of oil equivalent ("BOE") per day, a decrease of 4% from fourth-quarter 2020
•Reduced drilling, completions and equipment costs for a 10,000-foot well to $525 per foot and held costs incurred during first-quarter 2021 to $70 million
•Reduced total lease operating expenses ("LOE") by 3% versus fourth-quarter 2020; unit LOE increased by 4% to $2.66 per BOE, but well below expectations of $3.45 per BOE
"Our results in the first quarter are reflective of the solid, consistent execution that underpins the Company's strategic transformation," stated Jason Pigott, President and Chief Executive Officer. "We maintained a disciplined approach to personnel expenses, continued to drive well costs lower, substantially outperformed our assumptions for lease operating expenses and quickly and safely overcame disruptions that arose from adverse weather in the Permian Basin. We again delivered on our commitment to improve our balance sheet, generating Free Cash Flow1 and opportunistically selling equity through our ATM program to pay down debt. Our transition to Howard County is driving an inflection point in the Company's capital efficiency and we are continuing to optimize our land position and development plan to facilitate further improvements."
First-Quarter 2021 Financial Results
For the first quarter of 2021, the Company reported a net loss attributable to common stockholders of $75.4 million, or $6.33 per diluted share, including a $122.2 million non-cash loss on derivatives. Adjusted Net Income1 for the first quarter of 2021 was $20.3 million, or $1.69 per adjusted diluted share. Adjusted EBITDA1 for the first quarter of 2021 was $93.3 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 first quarter of 2021, Laredo's total production averaged 78,989 BOE per day, including oil production of 24,261 BOPD. Winter storms in the Permian Basin during February 2021 temporarily disrupted both production activities and drilling and completions operations, impacting total and oil production for first-quarter 2021 by an estimated 5,700 BOE per day and 1,700 BOPD, respectively. Despite the weather impact, first-quarter 2021 oil production was positively impacted by the Company's first package of wells in Howard County, the 15-well Gilbert/Passow package, which was the primary driver of oil production growth of 11% from the fourth quarter of 2020.
Unit LOE for the first quarter of 2021 was $2.66 per BOE, an increase of 4% from the fourth quarter of 2020, but below expectations of $3.45 per BOE. The difference versus expectations was a result of reduced activity levels related to winter storms and higher than anticipated production.
Late in first-quarter 2021, Laredo completed the 12-well Trentino/Whitmire package in Howard County, with all wells currently cleaning up or early in their production history. This is the Company's second well package to be completed in Howard County. Oil production in the second quarter of 2021 is expected to be positively impacted by production from the package, resulting in expected 9% - 13% oil production growth versus first-quarter 2021.
The Company is currently operating two drilling rigs and one completions crew in Howard County and expects to complete the 13-well Davis package during the second quarter of 2021. Beginning with the Davis package, Laredo has widened development spacing in the Wolfcamp formation to further enhance the capital efficiency of the Company's Howard County development program. Future development spacing is expected to utilize eight wells per unit in the Wolfcamp formation and four wells per unit in the Lower Spraberry formation.
Costs Incurred
During the first quarter of 2021, total costs incurred were $70 million, comprised of $57 million in drilling and completions activities, $3 million in land, exploration and data related costs, $5 million in infrastructure, including Laredo Midstream Services investments, and $5 million in other capitalized costs.
Laredo continues to drive drilling, completions and equipment costs per well lower through efficiency gains and savings realized by utilizing the Company-owned sand mine in Howard County. Costs for the Company's first two well packages in Howard County were $525 per lateral foot, below initial estimates of $540 per lateral foot.
Environmental, Social, Governance
In February 2021, Laredo further demonstrated the Company's commitment to responsible and sustainable operations, committing to significant reductions in greenhouse gas intensity, methane emissions and the elimination of routine flaring by 2025. Supporting these goals, Laredo's Board of Directors again integrated targets for the reduction of flaring and reportable spills into the Company's executive compensation program, linking 15% of the short-term incentive program payout to these metrics.
2
During the first quarter of 2021, Laredo flared/vented just 0.22% of produced natural gas, down from 1.52% in the first-quarter of 2020 and 0.71% for full-year 2020.
Liquidity
At March 31, 2021, the Company had outstanding borrowings of $220 million on its $725 million senior secured credit facility, resulting in available capacity, after the reduction for outstanding letters of credit, of $461 million. Including cash and cash equivalents of $44 million, total liquidity was $505 million.
At May 3, 2021, the Company had outstanding borrowings of $230 million on its $725 million senior secured credit facility. Available capacity, after the reduction for outstanding letters of credit, was $451 million. Including cash and cash equivalents of $48 million, total liquidity was $499 million.
At March 31, 2021, Laredo had executed $26.9 million of the $75 million authorized under the Company's ATM program. Proceeds from the share sales were utilized to reduce borrowing on the Company's senior secured credit facility.
Second-Quarter and Full-Year 2021 Guidance
The table below reflects the Company's guidance for total and oil production for second-quarter and full-year 2021.
| 2Q-21E | FY-21E | |||||||||||||
| Total production (MBOE per day) | 83.0 - 86.0 | 80.0 - 85.0 | ||||||||||||
| Oil production (MBOPD) | 26.5 - 27.5 | 27.3 - 29.3 | ||||||||||||
The table below reflects the Company's guidance for selected revenue and expense items for the second quarter of 2021.
| 2Q-21E | ||||||||
| Average sales price realizations (excluding derivatives): | ||||||||
| Oil (% of WTI) | 100% | |||||||
| NGL (% of WTI) | 27% | |||||||
| Natural gas (% of Henry Hub) | 71% | |||||||
| Other ($ MM): | ||||||||
| Net income (expense) of purchased oil | ($4.3) | |||||||
| Selected average costs & expenses: | ||||||||
| Lease operating expenses ($/BOE) | $2.85 | |||||||
| Production and ad valorem taxes (% of oil, NGL and natural gas sales revenues) | 7.00% | |||||||
| Transportation and marketing expenses ($/BOE) | $1.55 | |||||||
| General and administrative expenses (excluding LTIP, $/BOE) | $1.50 | |||||||
| General and administrative expenses (LTIP cash and non-cash, $/BOE) | $0.40 | |||||||
| Depletion, depreciation and amortization ($/BOE) | $5.75 | |||||||
3
Conference Call Details
On Thursday, May 6, 2021, at 7:30 a.m. CT, Laredo will host a conference call to discuss its first-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 3195169, 10 minutes prior to the scheduled conference time. A telephonic replay will be available two hours after the call on May 6, 2021 through Thursday, May 13, 2021. Participants may access this replay by dialing 855.859.2056, using conference code 3195169.
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, 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
4
forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.
The SEC generally permits oil and natural gas companies, in filings made with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, and certain probable and possible reserves that meet the SEC's definitions for such terms. In this press release and the conference call, the Company may use the terms "resource potential," "resource play," "estimated ultimate recovery" or "EURs," "type curve" and "standardized measure," each of which the SEC guidelines restrict from being included in filings with the SEC without strict compliance with SEC definitions. These terms refer to the Company’s internal estimates of unbooked hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. "Resource potential" is used by the Company to refer to the estimated quantities of hydrocarbons that may be added to proved reserves, largely from a specified resource play potentially supporting numerous drilling locations. A "resource play" is a term used by the Company to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section potentially supporting numerous drilling locations, which, when compared to a conventional play, typically has a lower geological and/or commercial development risk. "EURs" are based on the Company’s previous operating experience in a given area and publicly available information relating to the operations of producers who are conducting operations in these areas. Unbooked resource potential and "EURs" do not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules and do not include any proved reserves. Actual quantities of reserves that may be ultimately recovered from the Company’s interests may differ substantially from those presented herein. Factors affecting ultimate recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, decreases in oil, natural gas liquids and natural gas prices, well spacing, drilling and production costs, availability and cost of drilling services and equipment, lease expirations, transportation constraints, regulatory approvals, negative revisions to reserve estimates and other factors, as well as actual drilling results, including geological and mechanical factors affecting recovery rates. "EURs" from reserves may change significantly as development of the Company’s core assets provides additional data. In addition, the Company's production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. "Type curve" refers to a production profile of a well, or a particular category of wells, for a specific play and/or area. The "standardized measure" of discounted future new cash flows is calculated in accordance with SEC regulations and a discount rate of 10%. Actual results may vary considerably and should not be considered to represent the fair market value of the Company’s proved reserves.
This press release and any accompanying disclosures include financial measures that are not in accordance with generally accepted accounting principles ("GAAP"), such as Adjusted EBITDA, Adjusted Net Income and Free Cash Flow. While management believes that such measures are useful for investors, they should not be used as a replacement for financial measures that are in accordance with GAAP. For a reconciliation of such non-GAAP financial measures to the nearest comparable measure in accordance with GAAP, please see the supplemental financial information at the end of this press release.
Unless otherwise specified, references to "average sales price" refer to average sales price excluding the effects of the Company's derivative transactions.
All amounts, dollars and percentages presented in this press release are rounded and therefore approximate.
5
Laredo Petroleum, Inc.
Selected operating data
| Three months ended March 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| (unaudited) | ||||||||||||||
| Sales volumes: | ||||||||||||||
| Oil (MBbl) | 2,183 | 2,655 | ||||||||||||
| NGL (MBbl) | 2,321 | 2,467 | ||||||||||||
| Natural gas (MMcf) | 15,630 | 16,512 | ||||||||||||
Oil equivalents (MBOE)(1)(2) | 7,109 | 7,874 | ||||||||||||
Average daily oil equivalent sales volumes (BOE/D)(2) | 78,989 | 86,532 | ||||||||||||
Average daily oil sales volumes (BOPD)(2) | 24,261 | 29,178 | ||||||||||||
Average sales prices(2): | ||||||||||||||
Oil ($/Bbl)(3) | $ | 58.48 | $ | 45.19 | ||||||||||
NGL ($/Bbl)(3) | $ | 17.96 | $ | 4.68 | ||||||||||
Natural gas ($/Mcf)(3) | $ | 2.12 | $ | 0.26 | ||||||||||
Average sales price ($/BOE)(3) | $ | 28.48 | $ | 17.26 | ||||||||||
Oil, with commodity derivatives ($/Bbl)(4) | $ | 45.03 | $ | 56.59 | ||||||||||
NGL, with commodity derivatives ($/Bbl)(4) | $ | 11.25 | $ | 6.85 | ||||||||||
Natural gas, with commodity derivatives ($/Mcf)(4) | $ | 1.66 | $ | 0.94 | ||||||||||
Average sales price, with commodity derivatives ($/BOE)(4) | $ | 21.15 | $ | 23.21 | ||||||||||
Selected average costs and expenses per BOE sold(2): | ||||||||||||||
| Lease operating expenses | $ | 2.66 | $ | 2.80 | ||||||||||
| Production and ad valorem taxes | 1.87 | 1.17 | ||||||||||||
| Transportation and marketing expenses | 1.71 | 1.72 | ||||||||||||
| Midstream service expenses | 0.12 | 0.15 | ||||||||||||
| General and administrative (excluding LTIP) | 1.36 | 1.33 | ||||||||||||
| Total selected operating expenses | $ | 7.72 | $ | 7.17 | ||||||||||
| General and administrative (LTIP): | ||||||||||||||
| LTIP cash | $ | 0.23 | $ | 0.02 | ||||||||||
| LTIP non-cash | $ | 0.26 | $ | 0.25 | ||||||||||
| Depletion, depreciation and amortization | $ | 5.36 | $ | 7.78 | ||||||||||
_______________________________________________________________________________
(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.
6
Laredo Petroleum, Inc.
Consolidated balance sheets
| (in thousands, except share data) | March 31, 2021 | December 31, 2020 | ||||||||||||
| (unaudited) | ||||||||||||||
| Assets | ||||||||||||||
| Current assets: | ||||||||||||||
| Cash and cash equivalents | $ | 44,262 | $ | 48,757 | ||||||||||
| Accounts receivable, net | 67,704 | 63,976 | ||||||||||||
| Derivatives | — | 7,893 | ||||||||||||
| Other current assets | 26,123 | 15,964 | ||||||||||||
| Total current assets | 138,089 | 136,590 | ||||||||||||
| Property and equipment: | ||||||||||||||
| Oil and natural gas properties, full cost method: | ||||||||||||||
| Evaluated properties | 7,953,141 | 7,874,932 | ||||||||||||
| Unevaluated properties not being depleted | 60,260 | 70,020 | ||||||||||||
| Less accumulated depletion and impairment | (6,852,688) | (6,817,949) | ||||||||||||
| Oil and natural gas properties, net | 1,160,713 | 1,127,003 | ||||||||||||
| Midstream service assets, net | 111,083 | 112,697 | ||||||||||||
| Other fixed assets, net | 31,576 | 32,011 | ||||||||||||
| Property and equipment, net | 1,303,372 | 1,271,711 | ||||||||||||
| Operating lease right-of-use assets | 14,955 | 17,973 | ||||||||||||
| Other noncurrent assets, net | 18,487 | 16,336 | ||||||||||||
| Total assets | $ | 1,474,903 | $ | 1,442,610 | ||||||||||
| Liabilities and stockholders' equity | ||||||||||||||
| Current liabilities: | ||||||||||||||
| Accounts payable and accrued liabilities | $ | 49,065 | $ | 38,279 | ||||||||||
| Accrued capital expenditures | 27,924 | 28,275 | ||||||||||||
| Undistributed revenue and royalties | 32,018 | 24,728 | ||||||||||||
| Derivatives | 128,394 | 31,826 | ||||||||||||
| Operating lease liabilities | 11,263 | 11,721 | ||||||||||||
| Other current liabilities | 43,579 | 62,766 | ||||||||||||
| Total current liabilities | 292,243 | 197,595 | ||||||||||||
| Long-term debt, net | 1,145,374 | 1,179,266 | ||||||||||||
| Derivatives | 29,821 | 12,051 | ||||||||||||
| Asset retirement obligations | 66,280 | 64,775 | ||||||||||||
| Operating lease liabilities | 6,459 | 8,918 | ||||||||||||
| Other noncurrent liabilities | 3,294 | 1,448 | ||||||||||||
| Total liabilities | 1,543,471 | 1,464,053 | ||||||||||||
| Commitments and contingencies | ||||||||||||||
| Stockholders' equity: | ||||||||||||||
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of March 31, 2021 and December 31, 2020 | — | — | ||||||||||||
Common stock, $0.01 par value, 22,500,000 shares authorized and 12,899,660 and 12,020,164 issued and outstanding as of March 31, 2021 and December 31, 2020, respectively | 129 | 120 | ||||||||||||
| Additional paid-in capital | 2,426,769 | 2,398,464 | ||||||||||||
| Accumulated deficit | (2,495,466) | (2,420,027) | ||||||||||||
| Total stockholders' equity | (68,568) | (21,443) | ||||||||||||
| Total liabilities and stockholders' equity | $ | 1,474,903 | $ | 1,442,610 | ||||||||||
7
Laredo Petroleum, Inc.
Condensed consolidated statements of operations
| Three months ended March 31, | ||||||||||||||
| (in thousands, except per share data) | 2021 | 2020 | ||||||||||||
| (unaudited) | ||||||||||||||
| Revenues: | ||||||||||||||
| Oil, NGL and natural gas sales | $ | 202,457 | $ | 135,885 | ||||||||||
| Midstream service revenues | 1,296 | 2,683 | ||||||||||||
| Sales of purchased oil | 46,477 | 66,424 | ||||||||||||
| Total revenues | 250,230 | 204,992 | ||||||||||||
| Costs and expenses: | ||||||||||||||
| Lease operating expenses | 18,918 | 22,040 | ||||||||||||
| Production and ad valorem taxes | 13,283 | 9,244 | ||||||||||||
| Transportation and marketing expenses | 12,127 | 13,544 | ||||||||||||
| Midstream service expenses | 858 | 1,170 | ||||||||||||
| Costs of purchased oil | 49,916 | 79,297 | ||||||||||||
| General and administrative | 13,073 | 12,562 | ||||||||||||
| Depletion, depreciation and amortization | 38,109 | 61,302 | ||||||||||||
| Impairment expense | — | 186,699 | ||||||||||||
| Other operating expenses | 1,143 | 1,106 | ||||||||||||
| Total costs and expenses | 147,427 | 386,964 | ||||||||||||
| Operating income (loss) | 102,803 | (181,972) | ||||||||||||
| Non-operating income (expense): | ||||||||||||||
| Gain (loss) on derivatives, net | (154,365) | 297,836 | ||||||||||||
| Interest expense | (25,946) | (24,970) | ||||||||||||
| Loss on extinguishment of debt | — | (13,320) | ||||||||||||
| Other, net | 1,307 | (511) | ||||||||||||
| Total non-operating income (expense), net | (179,004) | 259,035 | ||||||||||||
Income (loss) before income taxes | (76,201) | 77,063 | ||||||||||||
| Income tax benefit (expense): | ||||||||||||||
| Deferred | 762 | (2,417) | ||||||||||||
| Total income tax benefit (expense) | 762 | (2,417) | ||||||||||||
| Net income (loss) | $ | (75,439) | $ | 74,646 | ||||||||||
Net income (loss) per common share(1): | ||||||||||||||
| Basic | $ | (6.33) | $ | 6.43 | ||||||||||
| Diluted | $ | (6.33) | $ | 6.39 | ||||||||||
Weighted-average common shares outstanding(1): | ||||||||||||||
| Basic | 11,918 | 11,618 | ||||||||||||
| Diluted | 11,918 | 11,673 | ||||||||||||
______________________________________________________________________________
(1)For the three months ended March 31, 2020, 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.
8
Laredo Petroleum, Inc.
Condensed consolidated statements of cash flows
| Three months ended March 31, | ||||||||||||||
| (in thousands) | 2021 | 2020 | ||||||||||||
| (unaudited) | ||||||||||||||
| Cash flows from operating activities: | ||||||||||||||
| Net income (loss) | $ | (75,439) | $ | 74,646 | ||||||||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||||
| Share-settled equity-based compensation, net | 2,068 | 2,376 | ||||||||||||
| Depletion, depreciation and amortization | 38,109 | 61,302 | ||||||||||||
| Impairment expense | — | 186,699 | ||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||
| (Gain) loss on derivatives, net | 154,365 | (297,836) | ||||||||||||
| Settlements (paid) received for matured derivatives, net | (41,174) | 47,723 | ||||||||||||
| Premiums received (paid) for commodity derivatives | 9,041 | (477) | ||||||||||||
| Loss on extinguishment of debt | — | 13,320 | ||||||||||||
| Deferred income tax (benefit) expense | (762) | 2,417 | ||||||||||||
| Other, net | 5,477 | 6,921 | ||||||||||||
| Cash flows from operating activities before changes in operating assets and liabilities, net | 91,685 | 97,091 | ||||||||||||
| Change in current assets and liabilities, net | (17,259) | 18,708 | ||||||||||||
| Change in noncurrent assets and liabilities, net | (3,275) | (6,210) | ||||||||||||
| Net cash provided by operating activities | 71,151 | 109,589 | ||||||||||||
| Cash flows from investing activities: | ||||||||||||||
| Acquisitions of oil and natural gas properties, net | — | (22,876) | ||||||||||||
| Capital expenditures: | ||||||||||||||
| Oil and natural gas properties | (68,329) | (135,376) | ||||||||||||
| Midstream service assets | (329) | (761) | ||||||||||||
| Other fixed assets | (551) | (829) | ||||||||||||
| Proceeds from dispositions of capital assets, net of selling costs | 189 | 51 | ||||||||||||
| Net cash used in investing activities | (69,020) | (159,791) | ||||||||||||
| Cash flows from financing activities: | ||||||||||||||
| Borrowings on Senior Secured Credit Facility | 15,000 | — | ||||||||||||
| Payments on Senior Secured Credit Facility | (50,000) | (100,000) | ||||||||||||
| Issuance of January 2025 Notes and January 2028 Notes | — | 1,000,000 | ||||||||||||
| Extinguishment of debt | — | (808,855) | ||||||||||||
| Proceeds from issuance of common stock, net of costs | 26,866 | — | ||||||||||||
| Other, net | 1,508 | (19,023) | ||||||||||||
| Net cash (used in) provided by financing activities | (6,626) | 72,122 | ||||||||||||
| Net (decrease) increase in cash and cash equivalents | (4,495) | 21,920 | ||||||||||||
| Cash and cash equivalents, beginning of period | 48,757 | 40,857 | ||||||||||||
| Cash and cash equivalents, end of period | $ | 44,262 | $ | 62,777 | ||||||||||
9
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 March 31, | ||||||||||||||
| (in thousands) | 2021 | 2020 | ||||||||||||
| (unaudited) | ||||||||||||||
| Oil and natural gas properties | $ | 68,449 | $ | 152,868 | ||||||||||
| Midstream service assets | 876 | 923 | ||||||||||||
| Other fixed assets | 600 | 823 | ||||||||||||
| Total costs incurred, excluding non-budgeted acquisition costs | $ | 69,925 | $ | 154,614 | ||||||||||
10
Laredo Petroleum, Inc.
Supplemental reconciliations of GAAP to non-GAAP financial measures
Non-GAAP financial measures
The non-GAAP financial measures of Free Cash Flow, Adjusted Net Income, Adjusted EBITDA and Net Debt, as defined by the Company, may not be comparable to similarly titled measures used by other companies. Therefore, these non-GAAP financial measures should be considered in conjunction with net income or loss and other performance measures prepared in accordance with GAAP, such as operating income or loss or cash flows from operating activities. Free Cash Flow, Adjusted Net Income, Adjusted EBITDA and Net Debt should not be considered in isolation or as a substitute for GAAP measures, such as net income or loss, operating income or loss or any other GAAP measure of liquidity or financial performance.
Free Cash Flow (Unaudited)
Free Cash Flow is a non-GAAP financial measure that the Company defines as net cash provided by operating activities (GAAP) before changes in operating assets and liabilities, net, less 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 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 March 31, | ||||||||||||||
| (in thousands) | 2021 | 2020 | ||||||||||||
| (unaudited) | ||||||||||||||
| Net cash provided by operating activities | $ | 71,151 | $ | 109,589 | ||||||||||
| Less: | ||||||||||||||
| Change in current assets and liabilities, net | (17,259) | 18,708 | ||||||||||||
| Change in noncurrent assets and liabilities, net | (3,275) | (6,210) | ||||||||||||
| Cash flows from operating activities before changes in operating assets and liabilities, net | 91,685 | 97,091 | ||||||||||||
| Less costs incurred, excluding non-budgeted acquisition costs: | ||||||||||||||
Oil and natural gas properties(1) | 68,449 | 152,868 | ||||||||||||
Midstream service assets(1) | 876 | 923 | ||||||||||||
| Other fixed assets | 600 | 823 | ||||||||||||
| Total costs incurred, excluding non-budgeted acquisition costs | 69,925 | 154,614 | ||||||||||||
| Free Cash Flow (non-GAAP) | $ | 21,760 | $ | (57,523) | ||||||||||
_____________________________________________________________________________
(1)Includes capitalized share-settled equity-based compensation and asset retirement costs.
11
Adjusted Net Income (Unaudited)
Adjusted Net Income is a non-GAAP financial measure that the Company defines as income or loss before income taxes (GAAP) plus adjustments for mark-to-market on derivatives, premiums paid or received for commodity derivatives that matured during the period, impairment expense, gains or losses on disposal of assets, other non-recurring income and expenses and adjusted income tax expense. Management believes Adjusted Net Income helps investors in the oil and natural gas industry to measure and compare the Company's performance to other oil and natural gas companies by excluding from the calculation items that can vary significantly from company to company depending upon accounting methods, the book value of assets and other non-operational factors.
The following table presents a reconciliation of income (loss) before income taxes (GAAP) to Adjusted Net Income (non-GAAP) for the periods presented:
| Three months ended March 31, | ||||||||||||||
| (in thousands, except per share data) | 2021 | 2020 | ||||||||||||
| (unaudited) | ||||||||||||||
Income (loss) before income taxes | $ | (76,201) | $ | 77,063 | ||||||||||
| Plus: | ||||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||
| (Gain) loss on derivatives, net | 154,365 | (297,836) | ||||||||||||
| Settlements (paid) received for matured derivatives, net | (41,174) | 47,723 | ||||||||||||
Net premiums paid for commodity derivatives that matured during the period(1) | (11,005) | (477) | ||||||||||||
| Impairment expense | — | 186,699 | ||||||||||||
| Loss on extinguishment of debt | — | 13,320 | ||||||||||||
| Loss on disposal of assets, net | 72 | 602 | ||||||||||||
| Adjusted income before adjusted income tax expense | 26,057 | 27,094 | ||||||||||||
Adjusted income tax expense(2) | (5,733) | (5,961) | ||||||||||||
| Adjusted Net Income (non-GAAP) | $ | 20,324 | $ | 21,133 | ||||||||||
Net income (loss) per common share(3): | ||||||||||||||
| Basic | $ | (6.33) | $ | 6.43 | ||||||||||
| Diluted | $ | (6.33) | $ | 6.39 | ||||||||||
Adjusted Net Income per common share(3): | ||||||||||||||
| Basic | $ | 1.71 | $ | 1.82 | ||||||||||
| Diluted | $ | 1.71 | $ | 1.81 | ||||||||||
| Adjusted diluted | $ | 1.69 | $ | 1.81 | ||||||||||
Weighted-average common shares outstanding(3): | ||||||||||||||
| Basic | 11,918 | 11,618 | ||||||||||||
| Diluted | 11,918 | 11,673 | ||||||||||||
| Adjusted diluted | 12,040 | 11,673 | ||||||||||||
_______________________________________________________________________________
(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 March 31, 2021 and 2020.
(3)For the three months ended March 31, 2020, net income 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.
12
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 March 31, | ||||||||||||||
| (in thousands) | 2021 | 2020 | ||||||||||||
| (unaudited) | ||||||||||||||
| Net income (loss) | $ | (75,439) | $ | 74,646 | ||||||||||
| Plus: | ||||||||||||||
| Share-settled equity-based compensation, net | 2,068 | 2,376 | ||||||||||||
| Depletion, depreciation and amortization | 38,109 | 61,302 | ||||||||||||
| Impairment expense | — | 186,699 | ||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||
| (Gain) loss on derivatives, net | 154,365 | (297,836) | ||||||||||||
| Settlements (paid) received for matured derivatives, net | (41,174) | 47,723 | ||||||||||||
Net premiums paid for commodity derivatives that matured during the period(1) | (11,005) | (477) | ||||||||||||
| Accretion expense | 1,143 | 1,106 | ||||||||||||
| Loss on disposal of assets, net | 72 | 602 | ||||||||||||
| Interest expense | 25,946 | 24,970 | ||||||||||||
| Loss on extinguishment of debt | — | 13,320 | ||||||||||||
| Income tax (benefit) expense | (762) | 2,417 | ||||||||||||
| Adjusted EBITDA (non-GAAP) | $ | 93,323 | $ | 116,848 | ||||||||||
_____________________________________________________________________________
(1)Reflects net premiums paid previously or upon settlement that are attributable to derivatives settled in the respective periods presented.
13
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 the Company has the ability, and may decide, to use a portion of its cash and cash equivalents to reduce debt. Net Debt as of March 31, 2021 was $1.115 billion.
# # #
Investor Contact:
Ron Hagood
918.858.5504
rhagood@laredopetro.com
14
First-Quarter 2021 Earnings Presentation May 5, 2021 EXHIBIT 99.2
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, 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 “standard ized 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 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 ▪ Generated Free Cash Flow1 of $22 million and limited cost incurred to $70 million ▪ Sold 723,579 shares through ATM equity program at an average price of $38.75 ▪ Reduced net debt1 by $30 million Continuously Improve ▪ Reduced DC&E costs to $525 per foot and increased drilling efficiency while integrating a new drilling rig ▪ Held unit LOE to $2.66 per BOE ▪ Minimized flaring/venting to 0.22% of produced natural gas ▪ New Howard County wells drove 1Q-21 oil production growth of 11% versus prior quarter ▪ Completed Company’s second full-scale development package in Howard County Objectives Principles Successfully Executed Strategy in the First Quarter of 2021 31See Appendix for reconciliations and definitions of non-GAAP measures Improve Oil Cut Decrease Leverage Reduce GHG Emissions Target Free Cash Flow1
$220 $578 $361 $505 $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 ) 78% 64% 53% 0% 20% 40% 60% 80% 100% Bal-21 % Product Hedged4 Actively Managing our Balance Sheet and Commodity Hedges 2.4x Net Debt to Adj. EBITDA1,2 2.6x Net Debt to Consolidated EBITDAX1,2 $44 MM Cash Balance3 4 Credit facility drawn3 Senior unsecured notes Credit facility undrawn3 Oil Natural Gas NGL • Reduced Net Debt1 by $30 million during 1Q-21 • Executed $26.9 million of $75 million ATM program • Reduced credit facility balance by $35 million from 4Q-20 1See Appendix for reconciliations and definitions of non-GAAP measures; 2Includes TTM Adjusted EBITDA/Consolidated EBITDAX and Net Debt as of 3-31-21; 3Amount shown as of 3-31-21; 4Open hedge positions as of 3-31-21; hedges executed through 4-30-21 utilizing midpoint of 2021 production guidance
Ambitious Emissions Reduction Targets 12019 calendar year as baseline; 2As a percentage of natural gas production 20% reduction in GHG intensity1 <0.20% methane emissions1,2 Zero routine flaring Emissions Reductions Targets for 2025 For the second consecutive year, flaring/venting reduction targets are part of executive compensation metrics 0.71% Produced gas flared/vented 1.95% Produced gas flared/vented 5 1.95% 0.71% 0.22% 0.00% 0.50% 1.00% 1.50% 2.00% 2.50% FY-19 FY-20 1Q-21 Percentage of Produced Natural Gas Flared/Vented
0 300 600 900 1,200 1,500 1,800 F e e t p e r D a y Drilling & Completions Efficiencies Drilled Feet/Day/Rig Fractured Feet/Day/Crew $788 $764 $675 $610 $525 $0 $200 $400 $600 $800 FY-17 FY-18 FY-19 FY-20 1Q-21 D & C C o s t ($ /f t) Maintaining Operational & Cost Advantages in Howard County 6 Consistently Reducing DC&E Costs 2017 2018 2019 2020
7 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 truck traffic by 300,000 miles per month Realized savings of $90,0001 per well ▪ Utilized in all 1Q-21 completions, 85% of all sand used ▪ Mine operated by a third party ▪ No additional capital investment beyond surface acreage acquisition 1For Howard County completions
0 20 40 60 80 100 120 140 0 50 100 150 200 250 300 350 400 C u m u la ti v e G ro s s O il 3 P ro d u c ti o n ( M B O ) Production Days Successfully Building Oily, High-Margin Inventory LPI Leasehold (127,345 net acres) 8 W. Glasscock County Total Net Acres 4,351 Targets LS/WC-A/WC-B Locations1 40 Howard County Total Net Acres 12,168 Targets LS/WC-A Locations1 105 - 140 ▪ FY-21 development entirely within Howard and W. Glasscock counties ▪ Company oil cut expected to rise from 30% at beginning of 2021 to almost 40% by year-end 2021 ▪ High oil productivity of acquired acreage drives forecasted oil production growth and Free Cash Flow2 generation in FY-21 1Locations as of January 2021 (adjusted for 2020 completions); 2See Appendix for reconciliations and definitions of non-GAAP measures 3Production data normalized to 10,000’ lateral length, downtime days excluded Map and acreage as of 4-30-21 Cook Wells (W. Glasscock) Gilbert/Passow Wells (Howard) Trentino/Whitmire Wells (Howard)
$325 $375 $425 $40 $45 $50 $55 $60 WTI ($/Bbl) FY-21E Cash Flow1,2 ($ MM) 9 Development of High-Margin Inventory Improves Capital Efficiency 26.8 15 20 25 30 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 Capital and Production Guidance 1Open hedge positions as of 3-31-21; hedges executed through 4-30-21, 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 $351 $360 $0 $100 $200 $300 $400 FY-20A FY-21E T o ta l C a p it a l ($ M M )
10 Second-Quarter and Full-Year 2021 Guidance Production: 2Q-21 FY-21 Total production (MBOE/d) 83.0 - 86.0 80.0 - 85.0 Oil production (MBO/d) 26.5 - 27.5 27.3 - 29.3 Average sales price realizations: (excluding derivatives) 2Q-21 Oil (% of WTI) 100% NGL (% of WTI) 27% Natural gas (% of Henry Hub) 71% Other ($ MM): 2Q-21 Net income / (expense) of purchased oil ($4.3) Operating costs & expenses ($/BOE): 2Q-21 Lease operating expenses $2.85 Production and ad valorem taxes (% of oil, NGL and natural gas revenues) 7.00% Transportation and marketing expenses $1.55 General and administrative expenses (excluding LTIP) $1.50 General and administrative expenses (LTIP cash & non-cash) $0.40 Depletion, depreciation and amortization $5.75
L A R E D O P E T R O L E U M APPENDIX 11
Crude Oil Hedge Book Natural Gas Liquids Hedge Book Natural Gas Hedge Book Bal-2021 FY 2022 Bal-2021 FY 2022 Bal-2021 FY 2022 Brent Swaps (MBbl) 5,651 4,125 Ethane Swaps (MBbl) 688 0 Henry Hub Swaps (MMcf) 32,038 3,650 WTD Price (Bbl) $51.29 $48.34 WTD Price (Bbl) $12.01 $0.00 WTD Price (Mcf) $2.59 $2.73 Brent Collars (MBbl) 440 821 Propane Swaps (MBbl) 1,826 0 Waha Basis Swaps (MMcf) 42,680 18,068 WTD Floor Price (Bbl) $45.00 $53.67 WTD Price (Bbl) $22.90 $0.00 WTD Price (Mcf) ($0.47) ($0.41) WTD Ceiling Price (Bbl) $59.50 $62.40 Butane Swaps (MBbl) 609 0 Total Brent Swaps/Collars (MBbl) 6,091 4,946 WTD Price (Bbl) $25.87 $0.00 WTD Floor Price ($/Bbl) $50.83 $49.22 Isobutane Swaps (MBbl) 166 0 WTD Price (Bbl) $26.55 $0.00 Pentane Swaps (MBbl) 664 0 WTD Price (Bbl) $38.16 $0.00 Oil, NGL & Natural Gas Hedges 12 Bal-2021: April – December 2021, hedges executed through 4-30-21
13 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 Note: As of Feb-21
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 Decline1 Legacy Howard County YE-20 Base Production Decline Expectations 14 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 Decline1 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 & $1.21/MMBtu for natural gas
Commodity Prices Used for 2Q-21 Average Sales Price Realization Guidance 15 Natural Gas: Natural Gas Liquids: Oil: Note: Pricing assumptions as of 5-3-21 WTI NYMEX Brent ICE ($/Bbl) ($/Bbl) Apr-21 $61.70 $65.30 May-21 $63.55 $66.71 Jun-21 $63.39 $66.26 2Q-21 Average $62.89 $66.10 C2 C3 IC4 NC4 C5+ Composite ($/Bbl) ($/Bbl) ($/Bbl) ($/Bbl) ($/Bbl) ($/Bbl) Apr-21 $9.93 $35.11 $35.47 $35.94 $58.50 $27.21 May-21 $10.50 $34.39 $37.28 $37.59 $59.38 $27.54 June-21 $10.50 $34.07 $37.17 $37.43 $58.64 $27.34 2Q-21 Average $10.31 $34.52 $36.65 $37.00 $58.84 $27.37 HH Waha ($/MMBtu) ($/MMBtu) Apr-21 $2.59 $2.37 May-21 $2.93 $2.68 Jun-21 $2.93 $2.84 2Q-21 Average $2.82 $2.63
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): 16 Three months ended, (in thousands, unaudited) 6/30/20 9/30/20 12/31/20 3/31/2021 Net income (loss) ($545,455) ($237,432) ($165,932) ($75,439) Plus: Share-settled equity-based compensation, net 1,694 2,041 2,106 2,068 Depletion, depreciation and amortization 66,574 47,015 42,210 38,109 Impairment expense 406,448 196,088 109,804 — Organizational restructuring expenses 4,200 — — — Mark-to-market on derivatives: (Gain) loss on derivatives, net 90,537 45,250 81,935 154,365 Settlements received (paid) for matured derivatives, net 86,872 51,840 41,786 (41,174) Settlements received for early-terminated commodity derivatives, net — 6,340 — — Net premiums paid for commodity derivatives that matured during the period — — — (11,005) Accretion expense 1,117 1,102 1,105 1,143 (Gain) loss on disposal of assets, net (152) 607 (94) 72 Interest expense 27,072 26,828 26,139 25,946 (Gain) loss on extinguishment of debt, net — — (22,309) — Write-off of debt issuance costs 1,103 — — — Income tax expense (benefit) (7,173) (2,398) 3,208 (762) Adjusted EBITDA $132,837 $137,281 $119,958 $93,323
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): 17 Three months ended, (in thousands, unaudited) 6/30/2020 9/30/2020 12/31/2020 3/31/2021 Net income (loss) ($545,455) ($237,432) ($165,932) ($75,439) Organizational restructuring expenses 4,200 — — — (Gain) loss on extinguishment of debt, net — — (22,309) — (Gain) loss on disposal of assets, net (152) 607 (94) 72 Consolidated Net Income (Loss) (541,407) (236,825) (188,335) (75,367) Mark-to-market on derivatives: (Gain) loss on derivatives, net 90,537 45,250 81,935 154,365 Settlements received (paid) for matured derivatives, net 86,872 51,840 41,786 (41,174) Settlements received for early-terminated commodity derivatives, net — 6,340 — — Mark-to-market (gain) loss on derivatives, net 177,409 103,430 123,721 113,191 Premiums (paid) received for commodity derivatives (50,593) — — 9,041 Non-Cash Charges/Income: Deferred income tax expense (benefit) (7,173) (2,398) 3,208 (762) Depletion, depreciation and amortization 66,574 47,015 42,210 38,109 Share-settled equity-based compensation, net 1,694 2,041 2,106 2,068 Accretion expense 1,117 1,102 1,105 1,143 Impairment expense 406,448 196,088 109,804 — Write-off of debt issuance costs 1,103 — — — Interest Expense 27,072 26,828 26,139 25,946 Consolidated EBITDAX after EBITDAX Adjustments (limited to 15%) $82,244 $137,281 $119,958 $113,369
18 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 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 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 March 31, (in thousands, unaudited) 2021 2020 Net cash provided by operating activities $71,151 $109,589 Less: Change in current assets and liabilities, net (17,259) 18,708 Change in noncurrent assets and liabilities, net (3,275) (6,210) Cash flows from operating activities before changes in operating assets and liabilities, net 91,685 97,091 Less costs incurred, excluding non-budgeted acquisition costs: Oil and natural gas properties(1) 68,449 152,868 Midstream service assets(1) 876 923 Other fixed assets 600 823 Total costs incurred, excluding non-budgeted acquisition costs 69,925 154,614 Free Cash Flow (non-GAAP) $21,760 ($57,523) (1) Includes capitalized share-settled equity-based compensation and asset retirement costs. Supplemental Non-GAAP Financial Measures
Net Debt Net Debt, a non-GAAP financial measure, is calculated as the face value of long-term debt less cash and cash equivalents. Management believes Net Debt is useful to management and investors in determining the Company’s leverage position since the Company has the ability, and may decide, to use a portion of its cash and cash equivalents to reduce debt. Net Debt as of 3-31-21 was $1.115 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) 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. 19 Supplemental Non-GAAP Financial Measures