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): August 3, 2022
(Exact name of registrant as specified in charter)
| (State or other jurisdiction of incorporation or organization) | (Commission File Number) | (I.R.S. Employer Identification No.) | ||||||
| (Address of principal executive offices) | (Zip code) | |||||||
Registrant’s telephone number, including area code: (918 ) 513-4570
Not Applicable
(Former name or former address, if changed since last report)
Securities registered pursuant to Section 12(b) of the Exchange Act:
| Title of each class | Trading Symbol | Name of each exchange on which registered | ||||||
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
| Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) | |||||||||||
| Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) | |||||||||||
| Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) | |||||||||||
| Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) | |||||||||||
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter). | |||||||||||
Emerging Growth Company | |||||||||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ | |||||||||||
Item 2.02. Results of Operations and Financial Condition.
On August 3, 2022, Laredo Petroleum, Inc. (the "Company") announced its financial and operating results for the quarter ended June 30, 2022. 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.
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 August 3, 2022, the Company furnished the press release described above in Item 2.02 of this Current Report on Form 8-K. The press release is attached hereto as Exhibit 99.1 and incorporated into this Item 7.01 by reference.
On August 3, 2022, the Company also posted to its website a corporate presentation (the "Presentation"). The Presentation is available on the Company's website, www.laredopetro.com, and is attached hereto as Exhibit 99.2 and incorporated into this Item 7.01 by reference.
All statements in the press release 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, 2021 and the Company's other filings with the SEC for a discussion of other risks and uncertainties. The Company disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
In accordance with General Instruction B.2 of Form 8-K, the information furnished under this Item 7.01 of this Current Report on Form 8-K and the exhibits attached hereto are deemed to be "furnished" and shall not be deemed "filed" for the purpose of Section 18 of the Exchange Act, or otherwise subject to the liabilities of that section, nor shall such information be deemed incorporated by reference into any filing under the Securities Act or the Exchange Act.
Item 9.01. Financial Statements and Exhibits.
(d) Exhibits.
| Exhibit Number | Description | |||||||
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL). | |||||||
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| LAREDO PETROLEUM, INC. | ||||||||
Date: August 3, 2022 | By: | /s/ Bryan J. Lemmerman | ||||||
| Bryan J. Lemmerman | ||||||||
| Senior Vice President and Chief Financial Officer | ||||||||
EXHIBIT 99.1
15 West 6th Street, Suite 900 · Tulsa, Oklahoma 74119 · (918) 513-4570 · Fax: (918) 513-4571
www.laredopetro.com
Laredo Petroleum Announces Second-Quarter 2022 Financial and Operating Results
Updates Full-Year 2022 Outlook and Issues Preliminary 2023 Outlook
TULSA, OK - August 3, 2022 - Laredo Petroleum, Inc. (NYSE: LPI) ("Laredo" or the "Company") today announced its second-quarter 2022 financial and operating results. Supplemental slides have been posted to the Company's website and can be found at www.laredopetro.com. A conference call and webcast to discuss the results is planned for 7:30 a.m. CT, Thursday, August 4, 2022. Complete details can be found within this release.
Highlights
•Reported net income of $262.5 million and cash flows from operating activities of $368.1 million, generating Adjusted EBITDA1 of $278.4 million and Free Cash Flow1 of $110.5 million
•Produced 40,553 barrels of oil per day ("BOPD") and 87,032 barrels of oil equivalent per day ("BOEPD"), increases of 53% and 1%, respectively, compared to second-quarter 2021
•Incurred capital expenditures of $138 million, excluding non-budgeted acquisitions and leasehold expenditures
•Increased total liquidity to $1.148 billion from $646 million in first-quarter 2022
•Reduced Net Debt1/Consolidated EBITDAX1 ratio to 1.4x from 1.9x in first-quarter 2022
•Repurchased 184,173 shares for $16.1 million and $91.4 million face value of term-debt at 98% of par value, year to date, of which 85,161 shares and $32.0 million face value of term-debt repurchases were executed during the second quarter
"Our strong financial results in the second quarter are a direct result of our multi-year strategic transformation," stated Jason Pigott, President and Chief Executive Officer. "We delivered record Adjusted EBITDA and Free Cash Flow, introduced a plan to return capital to shareholders through a $200 million equity repurchase program and repurchased more than $40 million of equity and debt. At $100 oil for the remainder of 2022 and $90 oil for 2023, we expect to deliver approximately $840 million of Free Cash Flow for full-year 2022 and 2023 combined and to continue repurchasing our equity and debt."
Second-Quarter 2022 Financial and Operations Summary
Financial Results. For the second quarter of 2022, the Company reported net income attributable to common stockholders of $262.5 million, or $15.41 per diluted share. Adjusted Net Income1 for the second quarter of 2022 was $127.8 million, or $7.50 per adjusted diluted share. Adjusted EBITDA for the second quarter of 2022 was $278.4 million.
1Non-GAAP financial measure; please see supplemental reconciliations of GAAP to non-GAAP financial measures at the end of this release.
Production. In the second quarter of 2022, the Company's total and oil production averaged 87,032 BOEPD and 40,553 BOPD, respectively. Total and oil production for the second quarter were reduced by 937 BOEPD and 672 BOPD, respectively, for working interest adjustments to wells that reached payout prior to second-quarter 2022 for non-leased mineral owners.
Operating Expenses. Lease operating expenses ("LOE") in second-quarter 2022 were $5.30 per BOE. Total LOE is expected to remain relatively flat for the remainder of the year, with unit LOE increasing slightly as total volumes are expected to decline.
Capital Investments. During the second quarter of 2022, Laredo completed 11 wells and turned-in-line ("TIL") seven wells. Total incurred capital expenditures were $138 million, excluding non-budgeted acquisitions and leasehold expenditures. Total investments included $112 million in drilling and completions activities, including $12 million of non-operated capital, $6 million in land, exploration and data related costs, $13 million in infrastructure, including Laredo Midstream Services investments, and $7 million in other capitalized costs.
Equity and Debt Repurchases. During the second quarter of 2022, Laredo purchased 85,161 shares for $9.1 million at an average price of $106.50 per share. The Company purchased $32.0 million face value of term debt at 101% of par value.
Liquidity. At June 30, 2022, the Company had no outstanding borrowings on its $1.0 billion senior secured credit facility. Including cash and cash equivalents of $148 million, total liquidity was $1.148 billion.
2022 Outlook
Late in the second quarter of 2022, Laredo TIL'd the six-well Leech package, developed in the Company's most southeastern unit of its Howard County leasehold. The package has been producing for approximately 60 days, with the expected increase in oil production slower than expected. Production guidance for the remainder of 2022 has been adjusted to reflect the current range of outcomes for the Leech wells. No additional completions are planned in the area until 2024 and the Company will adjust development strategies based on the longer-term performance of the package. Full-year 2022 total and oil production was revised from a range of 82.0 - 86.0 MBOEPD and 39.5 - 42.5 MBOPD, respectively, to 82.0 - 83.5 MBOEPD and 38.0 - 39.0 MBOPD, respectively. Free Cash Flow for full-year 2022 is projected to be approximately $280 million at $100 WTI for the remainder of the year versus previous projections of $350 million.
The Company is currently operating two drilling rigs and one completions crew and expects to complete 11 wells and TIL 13 wells during the third quarter of 2022 and to complete 13 - 15 wells and TIL 12 - 17 wells during the fourth quarter of 2022. Laredo expects incurred capital expenditures for full-year 2022 to be in-line with its previously updated capital budget of $550 million.
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2023 Preliminary Outlook
Laredo anticipates operated activity levels in 2023 will be comparable to 2022 with an annual average of approximately two drilling rigs and 1.4 completions crews. Total capital expenditures, based on current service costs and anticipated activity levels, are expected to be approximately $585 million.
At this time, the Company expects that its planned investments in 2023 will result in low single-digit oil growth. At $90 WTI for full-year 2023, Free Cash Flow is expected to be approximately $560 million.
Updated 2022 Projections
The table below reflects the Company's guidance for total and oil production and incurred capital expenditures for third-quarter, fourth-quarter and full-year 2022.
| 3Q-22E | 4Q-22E | FY-22E | |||||||||||||||
| Total production (MBOE per day) | 78.5 - 81.5 | 77.5 - 80.5 | 82.0 - 83.5 | ||||||||||||||
| Oil production (MBOPD) | 35.5 - 37.5 | 35.5 - 37.5 | 38.0 - 39.0 | ||||||||||||||
| Incurred capital expenditures, excluding non-budgeted acquisitions ($ MM) | ~$120 | ~$120 | ~$550 | ||||||||||||||
The table below reflects the Company's guidance for select revenue and expense items for the third quarter of 2022.
| 3Q-22E | ||||||||
| Average sales price realizations (excluding derivatives): | ||||||||
| Oil (% of WTI) | 103% | |||||||
| NGL (% of WTI) | 31% | |||||||
| Natural gas (% of Henry Hub) | 72% | |||||||
| Net settlements received (paid) for matured commodity derivatives ($ MM): | ||||||||
| Oil | ($100) | |||||||
| NGL | ($12) | |||||||
| Natural gas | ($30) | |||||||
| Selected average costs & expenses: | ||||||||
| Lease operating expenses ($/BOE) | $5.70 | |||||||
| Production and ad valorem taxes (% of oil, NGL and natural gas sales revenues) | 7.00% | |||||||
| Transportation and marketing expenses ($/BOE) | $1.75 | |||||||
| General and administrative expenses (excluding LTIP, $/BOE) | $1.80 | |||||||
| General and administrative expenses (LTIP cash, $/BOE) | $0.40 | |||||||
| General and administrative expenses (LTIP non-cash, $/BOE) | $0.30 | |||||||
| Depletion, depreciation and amortization ($/BOE) | $10.25 | |||||||
Conference Call Details
On Thursday, August 4, 2022, at 7:30 a.m. CT, Laredo will host a conference call to discuss its second-quarter 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."
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Portfolio managers and analysts who would like to participate on the call should dial 800.715.9871, using conference code 6923767. A replay will be available following the call via the Company's website.
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 in the Permian Basin of West Texas.
Additional information about Laredo may be found on its website at www.laredopetro.com.
Forward-Looking Statements
This press release and any oral statements made regarding the contents of this release, including in the conference call referenced herein, contain forward-looking statements as defined under Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, that address activities that Laredo assumes, plans, expects, believes, intends, projects, indicates, enables, transforms, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. The forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Such statements are not guarantees of future performance and involve risks, assumptions and uncertainties.
General risks relating to Laredo include, but are not limited to, the decline in prices of oil, natural gas liquids and natural gas and the related impact to financial statements as a result of asset impairments and revisions to reserve estimates, the ability of the Company to execute its strategies, including its ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to its financial results and to successfully integrate acquired businesses, assets and properties, oil production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries and other producing countries ("OPEC+"), the outbreak of disease, such as the coronavirus ("COVID-19") pandemic, and any related government policies and actions, changes in domestic and global production, supply and demand for commodities, including as a result of the COVID-19 pandemic, actions by OPEC+ and the Russian-Ukrainian military conflict, long-term performance of wells, drilling and operating risks, the increase in service and supply costs, including as a result of inflationary pressures, 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, 2021 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 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
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drilling or recovered with additional drilling or recovery techniques. "Resource potential" is used by the Company to refer to the estimated quantities of hydrocarbons that may be added to proved reserves, largely from a specified resource play potentially supporting numerous drilling locations. A "resource play" is a term used by the Company to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section potentially supporting numerous drilling locations, which, when compared to a conventional play, typically has a lower geological and/or commercial development risk. "EURs" are based on the Company’s previous operating experience in a given area and publicly available information relating to the operations of producers who are conducting operations in these areas. Unbooked resource potential and "EURs" do not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules and do not include any proved reserves. Actual quantities of reserves that may be ultimately recovered from the Company’s interests may differ substantially from those presented herein. Factors affecting ultimate recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, decreases in oil, natural gas liquids and natural gas prices, well spacing, drilling and production costs, availability and cost of drilling services and equipment, lease expirations, transportation constraints, regulatory approvals, negative revisions to reserve estimates and other factors, as well as actual drilling results, including geological and mechanical factors affecting recovery rates. "EURs" from reserves may change significantly as development of the Company’s core assets provides additional data. In addition, the Company's production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. "Type curve" refers to a production profile of a well, or a particular category of wells, for a specific play and/or area. The "standardized measure" of discounted future new cash flows is calculated in accordance with SEC regulations and a discount rate of 10%. Actual results may vary considerably and should not be considered to represent the fair market value of the Company’s proved reserves.
This press release and any accompanying disclosures include financial measures that are not in accordance with generally accepted accounting principles ("GAAP"), such as Adjusted EBITDA, Adjusted Net Income and Free Cash Flow. While management believes that such measures are useful for investors, they should not be used as a replacement for financial measures that are in accordance with GAAP. For a reconciliation of such non-GAAP financial measures to the nearest comparable measure in accordance with GAAP, please see the supplemental financial information at the end of this press release.
Unless otherwise specified, references to "average sales price" refer to average sales price excluding the effects of the Company's derivative transactions.
All amounts, dollars and percentages presented in this press release are rounded and therefore approximate.
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Laredo Petroleum, Inc.
Selected operating data
| Three months ended June 30, | Six months ended June 30, | |||||||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | |||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Sales volumes: | ||||||||||||||||||||||||||
| Oil (MBbl) | 3,690 | 2,406 | 7,317 | 4,590 | ||||||||||||||||||||||
| NGL (MBbl) | 2,100 | 2,551 | 4,094 | 4,872 | ||||||||||||||||||||||
| Natural gas (MMcf) | 12,774 | 17,169 | 25,017 | 32,799 | ||||||||||||||||||||||
Oil equivalents (MBOE)(1)(2) | 7,920 | 7,819 | 15,581 | 14,928 | ||||||||||||||||||||||
Average daily oil equivalent sales volumes (BOE/D)(2) | 87,032 | 85,924 | 86,080 | 82,475 | ||||||||||||||||||||||
Average daily oil sales volumes (Bbl/D)(2) | 40,553 | 26,440 | 40,424 | 25,357 | ||||||||||||||||||||||
Average sales prices(2): | ||||||||||||||||||||||||||
Oil ($/Bbl)(3) | $ | 111.20 | $ | 65.55 | $ | 103.57 | $ | 62.19 | ||||||||||||||||||
NGL ($/Bbl)(3) | $ | 34.52 | $ | 17.05 | $ | 33.62 | $ | 17.48 | ||||||||||||||||||
Natural gas ($/Mcf)(3) | $ | 5.21 | $ | 1.81 | $ | 4.20 | $ | 1.96 | ||||||||||||||||||
Average sales price ($/BOE)(3) | $ | 69.38 | $ | 29.71 | $ | 64.22 | $ | 29.13 | ||||||||||||||||||
Oil, with commodity derivatives ($/Bbl)(4) | $ | 74.72 | $ | 47.00 | $ | 71.01 | $ | 46.06 | ||||||||||||||||||
NGL, with commodity derivatives ($/Bbl)(4) | $ | 27.24 | $ | 10.40 | $ | 26.65 | $ | 10.81 | ||||||||||||||||||
Natural gas, with commodity derivatives ($/Mcf)(4) | $ | 3.33 | $ | 1.46 | $ | 2.90 | $ | 1.55 | ||||||||||||||||||
Average sales price, with commodity derivatives ($/BOE)(4) | $ | 47.41 | $ | 21.05 | $ | 45.01 | $ | 21.10 | ||||||||||||||||||
| Selected average costs and expenses per BOE sold: | ||||||||||||||||||||||||||
| Lease operating expenses | $ | 5.30 | $ | 2.53 | $ | 5.32 | $ | 2.59 | ||||||||||||||||||
| Production and ad valorem taxes | 4.17 | 1.88 | 3.88 | 1.88 | ||||||||||||||||||||||
| Transportation and marketing expenses | 1.39 | 1.37 | 1.65 | 1.53 | ||||||||||||||||||||||
| Midstream service expenses | 0.22 | 0.09 | 0.20 | 0.10 | ||||||||||||||||||||||
| General and administrative (excluding LTIP) | 1.71 | 1.60 | 1.73 | 1.48 | ||||||||||||||||||||||
| Total selected operating expenses | $ | 12.79 | $ | 7.47 | $ | 12.78 | $ | 7.58 | ||||||||||||||||||
| General and administrative (LTIP): | ||||||||||||||||||||||||||
| LTIP cash | $ | 0.11 | $ | 0.92 | $ | 0.47 | $ | 0.59 | ||||||||||||||||||
| LTIP non-cash | $ | 0.33 | $ | 0.18 | $ | 0.30 | $ | 0.21 | ||||||||||||||||||
| Depletion, depreciation and amortization | $ | 9.87 | $ | 5.11 | $ | 9.73 | $ | 5.23 | ||||||||||||||||||
(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 its 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) | June 30, 2022 | December 31, 2021 | ||||||||||||
| (unaudited) | ||||||||||||||
| Assets | ||||||||||||||
| Current assets: | ||||||||||||||
| Cash and cash equivalents | $ | 147,546 | $ | 56,798 | ||||||||||
| Accounts receivable, net | 205,767 | 151,807 | ||||||||||||
| Derivatives | 5,174 | 4,346 | ||||||||||||
| Other current assets | 15,476 | 22,906 | ||||||||||||
| Total current assets | 373,963 | 235,857 | ||||||||||||
| Property and equipment: | ||||||||||||||
| Oil and natural gas properties, full cost method: | ||||||||||||||
| Evaluated properties | 9,318,212 | 8,968,668 | ||||||||||||
| Unevaluated properties not being depleted | 124,182 | 170,033 | ||||||||||||
| Less: accumulated depletion and impairment | (7,164,277) | (7,019,670) | ||||||||||||
| Oil and natural gas properties, net | 2,278,117 | 2,119,031 | ||||||||||||
| Midstream service assets, net | 92,690 | 96,528 | ||||||||||||
| Other fixed assets, net | 36,761 | 34,590 | ||||||||||||
| Property and equipment, net | 2,407,568 | 2,250,149 | ||||||||||||
| Derivatives | 34,905 | 32,963 | ||||||||||||
| Other noncurrent assets, net | 56,573 | 32,855 | ||||||||||||
| Total assets | $ | 2,873,009 | $ | 2,551,824 | ||||||||||
| Liabilities and stockholders' equity | ||||||||||||||
| Current liabilities: | ||||||||||||||
| Accounts payable and accrued liabilities | $ | 62,752 | $ | 71,386 | ||||||||||
| Accrued capital expenditures | 64,758 | 50,585 | ||||||||||||
| Undistributed revenue and royalties | 257,398 | 117,920 | ||||||||||||
| Derivatives | 274,409 | 179,809 | ||||||||||||
| Other current liabilities | 140,059 | 107,213 | ||||||||||||
| Total current liabilities | 799,376 | 526,913 | ||||||||||||
| Long-term debt, net | 1,291,242 | 1,425,858 | ||||||||||||
| Derivatives | 2,089 | — | ||||||||||||
| Asset retirement obligations | 70,254 | 69,057 | ||||||||||||
| Other noncurrent liabilities | 30,592 | 16,216 | ||||||||||||
| Total liabilities | 2,193,553 | 2,038,044 | ||||||||||||
| Commitments and contingencies | ||||||||||||||
| Stockholders' equity: | ||||||||||||||
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of June 30, 2022 and December 31, 2021 | — | — | ||||||||||||
Common stock, $0.01 par value, 40,000,000 and 22,500,000 shares authorized, and 17,212,383 and 17,074,516 issued and outstanding as of June 30, 2022 and December 31, 2021, respectively | 172 | 171 | ||||||||||||
| Additional paid-in capital | 2,778,538 | 2,788,628 | ||||||||||||
| Accumulated deficit | (2,099,254) | (2,275,019) | ||||||||||||
| Total stockholders' equity | 679,456 | 513,780 | ||||||||||||
| Total liabilities and stockholders' equity | $ | 2,873,009 | $ | 2,551,824 | ||||||||||
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Laredo Petroleum, Inc.
Consolidated statements of operations
| Three months ended June 30, | Six months ended June 30, | |||||||||||||||||||||||||
| (in thousands, except per share data) | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Revenues: | ||||||||||||||||||||||||||
| Oil sales | $ | 410,359 | $ | 157,722 | $ | 757,802 | $ | 285,423 | ||||||||||||||||||
| NGL sales | 72,505 | 43,494 | 137,660 | 85,172 | ||||||||||||||||||||||
| Natural gas sales | 66,606 | 31,110 | 105,195 | 64,188 | ||||||||||||||||||||||
| Midstream service revenues | 1,891 | 1,257 | 4,235 | 2,553 | ||||||||||||||||||||||
| Sales of purchased oil | 8,795 | 60,788 | 87,659 | 107,265 | ||||||||||||||||||||||
| Total revenues | 560,156 | 294,371 | 1,092,551 | 544,601 | ||||||||||||||||||||||
| Costs and expenses: | ||||||||||||||||||||||||||
| Lease operating expenses | 42,014 | 19,771 | 82,890 | 38,689 | ||||||||||||||||||||||
| Production and ad valorem taxes | 33,001 | 14,737 | 60,488 | 28,020 | ||||||||||||||||||||||
| Transportation and marketing expenses | 10,994 | 10,690 | 25,737 | 22,817 | ||||||||||||||||||||||
| Midstream service expenses | 1,733 | 700 | 3,147 | 1,558 | ||||||||||||||||||||||
| Costs of purchased oil | 6,780 | 64,737 | 89,744 | 114,653 | ||||||||||||||||||||||
| General and administrative | 16,999 | 21,101 | 38,943 | 34,174 | ||||||||||||||||||||||
| Organizational restructuring expenses | — | 9,800 | — | 9,800 | ||||||||||||||||||||||
| Depletion, depreciation and amortization | 78,135 | 39,976 | 151,627 | 78,085 | ||||||||||||||||||||||
| Impairment expense | — | 1,613 | — | 1,613 | ||||||||||||||||||||||
| Other operating (income) expense, net | (736) | 2,899 | 283 | 4,042 | ||||||||||||||||||||||
| Total costs and expenses | 188,920 | 186,024 | 452,859 | 333,451 | ||||||||||||||||||||||
| Operating income | 371,236 | 108,347 | 639,692 | 211,150 | ||||||||||||||||||||||
| Non-operating income (expense): | ||||||||||||||||||||||||||
| Loss on derivatives, net | (65,927) | (216,942) | (391,743) | (371,307) | ||||||||||||||||||||||
| Interest expense | (32,807) | (25,870) | (65,284) | (51,816) | ||||||||||||||||||||||
| Loss on extinguishment of debt, net | (798) | — | (798) | — | ||||||||||||||||||||||
| Gain (loss) on disposal of assets, net | 38 | 66 | (222) | (6) | ||||||||||||||||||||||
| Other income (expense), net | (2,104) | 416 | 335 | 1,795 | ||||||||||||||||||||||
| Total non-operating expense, net | (101,598) | (242,330) | (457,712) | (421,334) | ||||||||||||||||||||||
| Income (loss) before income taxes | 269,638 | (133,983) | 181,980 | (210,184) | ||||||||||||||||||||||
| Income tax (expense) benefit: | ||||||||||||||||||||||||||
| Current | (4,513) | — | (5,731) | — | ||||||||||||||||||||||
| Deferred | (2,579) | 1,322 | (484) | 2,084 | ||||||||||||||||||||||
| Total income tax (expense) benefit | (7,092) | 1,322 | (6,215) | 2,084 | ||||||||||||||||||||||
| Net income (loss) | $ | 262,546 | $ | (132,661) | $ | 175,765 | $ | (208,100) | ||||||||||||||||||
| Net income (loss) per common share: | ||||||||||||||||||||||||||
| Basic | $ | 15.60 | $ | (10.47) | $ | 10.46 | $ | (16.92) | ||||||||||||||||||
| Diluted | $ | 15.41 | $ | (10.47) | $ | 10.31 | $ | (16.92) | ||||||||||||||||||
| Weighted-average common shares outstanding: | ||||||||||||||||||||||||||
| Basic | 16,834 | 12,674 | 16,800 | 12,298 | ||||||||||||||||||||||
| Diluted | 17,039 | 12,674 | 17,040 | 12,298 | ||||||||||||||||||||||
8
Laredo Petroleum, Inc.
Consolidated statements of cash flows
| Three months ended June 30, | Six months ended June 30, | |||||||||||||||||||||||||
| (in thousands) | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Cash flows from operating activities: | ||||||||||||||||||||||||||
| Net income (loss) | $ | 262,546 | $ | (132,661) | $ | 175,765 | $ | (208,100) | ||||||||||||||||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||||||||||||||||
| Share-settled equity-based compensation, net | 2,604 | 1,730 | 4,657 | 3,798 | ||||||||||||||||||||||
| Depletion, depreciation and amortization | 78,135 | 39,976 | 151,627 | 78,085 | ||||||||||||||||||||||
| Impairment expense | — | 1,613 | — | 1,613 | ||||||||||||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||||||||||||||
| Loss on derivatives, net | 65,927 | 216,942 | 391,743 | 371,307 | ||||||||||||||||||||||
| Settlements paid for matured derivatives, net | (172,454) | (57,607) | (297,824) | (98,781) | ||||||||||||||||||||||
| Premiums received for commodity derivatives | — | — | — | 9,041 | ||||||||||||||||||||||
| Amortization of debt issuance costs | 1,673 | 1,110 | 3,214 | 2,099 | ||||||||||||||||||||||
| Amortization of operating lease right-of-use assets | 5,710 | 2,767 | 10,735 | 5,764 | ||||||||||||||||||||||
| Loss on extinguishment of debt, net | 798 | — | 798 | — | ||||||||||||||||||||||
| Deferred income tax benefit (expense) | 2,579 | (1,322) | 484 | (2,084) | ||||||||||||||||||||||
| Other, net | 920 | 1,006 | 1,345 | 2,497 | ||||||||||||||||||||||
| Changes in operating assets and liabilities: | ||||||||||||||||||||||||||
| Accounts receivable, net | 7,782 | (22,905) | (53,960) | (26,633) | ||||||||||||||||||||||
| Other current assets | 1,752 | 5,852 | 6,844 | (4,412) | ||||||||||||||||||||||
| Other noncurrent assets, net | (18,830) | (11,013) | (34,057) | (12,649) | ||||||||||||||||||||||
| Accounts payable and accrued liabilities | (10,476) | 719 | (8,634) | 9,784 | ||||||||||||||||||||||
| Undistributed revenue and royalties | 95,166 | 14,267 | 139,460 | 21,557 | ||||||||||||||||||||||
| Other current liabilities | 34,290 | 49,574 | 32,819 | 29,952 | ||||||||||||||||||||||
| Other noncurrent liabilities | 10,003 | 6,498 | 13,991 | 4,859 | ||||||||||||||||||||||
| Net cash provided by operating activities | 368,125 | 116,546 | 539,007 | 187,697 | ||||||||||||||||||||||
| Cash flows from investing activities: | ||||||||||||||||||||||||||
| Acquisitions of oil and natural gas properties, net | (17) | — | (7,887) | — | ||||||||||||||||||||||
| Capital expenditures: | ||||||||||||||||||||||||||
| Oil and natural gas properties | (139,250) | (97,748) | (282,750) | (166,077) | ||||||||||||||||||||||
| Midstream service assets | (396) | (1,232) | (689) | (1,561) | ||||||||||||||||||||||
| Other fixed assets | (2,211) | (685) | (4,263) | (1,236) | ||||||||||||||||||||||
| Proceeds from dispositions of capital assets, net of selling costs | 30 | 118 | 2,049 | 307 | ||||||||||||||||||||||
| Net cash used in investing activities | (141,844) | (99,547) | (293,540) | (168,567) | ||||||||||||||||||||||
| Cash flows from financing activities: | ||||||||||||||||||||||||||
| Borrowings on Senior Secured Credit Facility | 85,000 | 230,000 | 135,000 | 245,000 | ||||||||||||||||||||||
| Payments on Senior Secured Credit Facility | (185,000) | (70,000) | (240,000) | (120,000) | ||||||||||||||||||||||
| Extinguishment of debt | (32,334) | — | (32,334) | — | ||||||||||||||||||||||
| Proceeds from issuance of common stock, net of offering costs | — | 45,626 | — | 72,492 | ||||||||||||||||||||||
| Share repurchases | (9,071) | — | (9,071) | — | ||||||||||||||||||||||
| Stock exchanged for tax withholding | (742) | (451) | (6,589) | (1,741) | ||||||||||||||||||||||
| Payments for debt issuance costs | (1,725) | (1,452) | (1,725) | (1,452) | ||||||||||||||||||||||
| Other | — | — | — | 2,798 | ||||||||||||||||||||||
| Net cash (used in) provided by financing activities | (143,872) | 203,723 | (154,719) | 197,097 | ||||||||||||||||||||||
| Net increase in cash, cash equivalents and restricted cash | 82,409 | 220,722 | 90,748 | 216,227 | ||||||||||||||||||||||
| Cash, cash equivalents and restricted cash, beginning of period | 65,137 | 44,262 | 56,798 | 48,757 | ||||||||||||||||||||||
| Cash, cash equivalents and restricted cash, end of period | $ | 147,546 | $ | 264,984 | $ | 147,546 | $ | 264,984 | ||||||||||||||||||
9
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, Consolidated EBITDAX, Net Debt and Net Debt to Consolidated EBITDAX, as defined by the Company, may not be comparable to similarly titled measures used by other companies. Furthermore, these non-GAAP financial measures should not be considered in isolation or as a substitute for GAAP measures of liquidity or financial performance, but rather should be considered in conjunction with GAAP measures, such as net income or loss, operating income or loss or cash flows from operating activities.
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. 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 June 30, | Six months ended June 30, | |||||||||||||||||||||||||
| (in thousands) | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Net cash provided by operating activities | $ | 368,125 | $ | 116,546 | $ | 539,007 | $ | 187,697 | ||||||||||||||||||
| Less: | ||||||||||||||||||||||||||
| Change in current assets and liabilities, net | 128,514 | 47,507 | 116,529 | 30,248 | ||||||||||||||||||||||
| Change in noncurrent assets and liabilities, net | (8,827) | (4,515) | (20,066) | (7,790) | ||||||||||||||||||||||
| Cash flows from operating activities before changes in operating assets and liabilities, net | 248,438 | 73,554 | 442,544 | 165,239 | ||||||||||||||||||||||
| Less incurred capital expenditures, excluding non-budgeted acquisition costs: | ||||||||||||||||||||||||||
Oil and natural gas properties(1) | 135,496 | 102,822 | 303,864 | 171,271 | ||||||||||||||||||||||
Midstream service assets(1) | 267 | 979 | 726 | 1,855 | ||||||||||||||||||||||
| Other fixed assets | 2,200 | 944 | 4,272 | 1,544 | ||||||||||||||||||||||
| Total incurred capital expenditures, excluding non-budgeted acquisition costs | 137,963 | 104,745 | 308,862 | 174,670 | ||||||||||||||||||||||
| Free Cash Flow (non-GAAP) | $ | 110,475 | $ | (31,191) | $ | 133,682 | $ | (9,431) | ||||||||||||||||||
_____________________________________________________________________________
(1)Includes capitalized share-settled equity-based compensation and asset retirement costs.
10
Adjusted Net Income (Unaudited)
Adjusted Net Income is a non-GAAP financial measure that the Company defines as net income or loss (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, income taxes, 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 net income (loss) (GAAP) to Adjusted Net Income (non-GAAP) for the periods presented:
| Three months ended June 30, | Six months ended June 30, | |||||||||||||||||||||||||
| (in thousands, except per share data) | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Net income (loss) | $ | 262,546 | $ | (132,661) | $ | 175,765 | $ | (208,100) | ||||||||||||||||||
| Plus: | ||||||||||||||||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||||||||||||||
| Loss on derivatives, net | 65,927 | 216,942 | 391,743 | 371,307 | ||||||||||||||||||||||
| Settlements paid for matured derivatives, net | (172,454) | (57,607) | (297,824) | (98,781) | ||||||||||||||||||||||
Net premiums paid for commodity derivatives that matured during the period(1) | — | (10,183) | — | (21,188) | ||||||||||||||||||||||
| Organizational restructuring expenses | — | 9,800 | — | 9,800 | ||||||||||||||||||||||
| Transaction expenses | — | 1,741 | — | 1,741 | ||||||||||||||||||||||
| Impairment expense | — | 1,613 | — | 1,613 | ||||||||||||||||||||||
| Loss on extinguishment of debt, net | 798 | — | 798 | — | ||||||||||||||||||||||
| (Gain) loss on disposal of assets, net | (38) | (66) | 222 | 6 | ||||||||||||||||||||||
| Income tax expense (benefit) | 7,092 | (1,322) | 6,215 | (2,084) | ||||||||||||||||||||||
| Adjusted income before adjusted income tax expense | 163,871 | 28,257 | 276,919 | 54,314 | ||||||||||||||||||||||
Adjusted income tax expense(2) | (36,052) | (6,217) | (60,922) | (11,949) | ||||||||||||||||||||||
| Adjusted Net Income (non-GAAP) | $ | 127,819 | $ | 22,040 | $ | 215,997 | $ | 42,365 | ||||||||||||||||||
| Net income (loss) per common share: | ||||||||||||||||||||||||||
| Basic | $ | 15.60 | $ | (10.47) | $ | 10.46 | $ | (16.92) | ||||||||||||||||||
| Diluted | $ | 15.41 | $ | (10.47) | $ | 10.31 | $ | (16.92) | ||||||||||||||||||
| Adjusted Net Income per common share: | ||||||||||||||||||||||||||
| Basic | $ | 7.59 | $ | 1.74 | $ | 12.86 | $ | 3.44 | ||||||||||||||||||
| Diluted | $ | 7.50 | $ | 1.74 | $ | 12.68 | $ | 3.44 | ||||||||||||||||||
| Adjusted diluted | $ | 7.50 | $ | 1.71 | $ | 12.68 | $ | 3.40 | ||||||||||||||||||
| Weighted-average common shares outstanding: | ||||||||||||||||||||||||||
| Basic | 16,834 | 12,674 | 16,800 | 12,298 | ||||||||||||||||||||||
| Diluted | 17,039 | 12,674 | 17,040 | 12,298 | ||||||||||||||||||||||
| Adjusted diluted | 17,039 | 12,886 | 17,040 | 12,476 | ||||||||||||||||||||||
_______________________________________________________________________________
(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 June 30, 2022 and 2021.
11
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 June 30, | Six months ended June 30, | |||||||||||||||||||||||||
| (in thousands) | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Net income (loss) | $ | 262,546 | $ | (132,661) | $ | 175,765 | $ | (208,100) | ||||||||||||||||||
| Plus: | ||||||||||||||||||||||||||
| Share-settled equity-based compensation, net | 2,604 | 1,730 | 4,657 | 3,798 | ||||||||||||||||||||||
| Depletion, depreciation and amortization | 78,135 | 39,976 | 151,627 | 78,085 | ||||||||||||||||||||||
| Impairment expense | — | 1,613 | — | 1,613 | ||||||||||||||||||||||
| Organizational restructuring expenses | — | 9,800 | — | 9,800 | ||||||||||||||||||||||
| Transaction expenses | — | 1,741 | — | 1,741 | ||||||||||||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||||||||||||||
| Loss on derivatives, net | 65,927 | 216,942 | 391,743 | 371,307 | ||||||||||||||||||||||
| Settlements paid for matured derivatives, net | (172,454) | (57,607) | (297,824) | (98,781) | ||||||||||||||||||||||
Net premiums paid for commodity derivatives that matured during the period(1) | — | (10,183) | — | (21,188) | ||||||||||||||||||||||
| Accretion expense | 973 | 1,158 | 1,992 | 2,301 | ||||||||||||||||||||||
| (Gain) loss on disposal of assets, net | (38) | (66) | 222 | 6 | ||||||||||||||||||||||
| Interest expense | 32,807 | 25,870 | 65,284 | 51,816 | ||||||||||||||||||||||
| Loss on extinguishment of debt, net | 798 | — | 798 | — | ||||||||||||||||||||||
| Income tax expense (benefit) | 7,092 | (1,322) | 6,215 | (2,084) | ||||||||||||||||||||||
| Adjusted EBITDA (non-GAAP) | $ | 278,390 | $ | 96,991 | $ | 500,479 | $ | 190,314 | ||||||||||||||||||
_____________________________________________________________________________
(1)Reflects net premiums paid previously or upon settlement that are attributable to derivatives settled in the respective periods presented.
12
Consolidated EBITDAX (Unaudited)
Consolidated EBITDAX is a non-GAAP financial measure defined in the Company's Senior Secured Credit Facility as net income or loss (GAAP) plus adjustments for extraordinary gains (or losses), non-cash recurring gains (or losses), depletion, depreciation and amortization expense, interest expense, any provisions for (or benefit from) income or franchise taxes, exploration expenses and other non-cash charges. Consolidated EBITDAX is used by the Company’s management for various purposes, including as a measure of operating performance and compliance under the Company's Senior Secured Credit Facility. Additional information on the calculation of Consolidated EBITDAX can be found in the Company's Eighth Amendment to the Senior Secured Credit Facility as filed with the SEC on April 19, 2022.
The following table presents a reconciliation of net income (loss) (GAAP) to Consolidated EBITDAX (non-GAAP) for the periods presented:
| Three months ended | ||||||||||||||||||||||||||
| (in thousands) | June 30, 2022 | March 31, 2022 | December 31, 2021 | September 30, 2021 | ||||||||||||||||||||||
| (unaudited) | ||||||||||||||||||||||||||
| Net income (loss) | $ | 262,546 | $ | (86,781) | $ | 216,276 | $ | 136,832 | ||||||||||||||||||
| Plus: | ||||||||||||||||||||||||||
| Share-settled equity-based compensation, net | 2,604 | 2,053 | 2,066 | 1,811 | ||||||||||||||||||||||
| Depletion, depreciation and amortization | 78,135 | 73,492 | 74,592 | 62,678 | ||||||||||||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||||||||||||||
| (Gain) loss on derivatives, net | 65,927 | 325,816 | (15,372) | 96,240 | ||||||||||||||||||||||
| Settlements paid for matured derivatives, net | (172,454) | (125,370) | (129,361) | (92,726) | ||||||||||||||||||||||
| Accretion expense | 973 | 1,019 | 1,026 | 906 | ||||||||||||||||||||||
| Gain on sale of oil and natural gas properties, net | — | — | — | (95,223) | ||||||||||||||||||||||
| (Gain) loss on disposal of assets, net | (38) | 260 | 8,903 | 22 | ||||||||||||||||||||||
| Interest expense | 32,807 | 32,477 | 31,163 | 30,406 | ||||||||||||||||||||||
| Loss on extinguishment of debt, net | 798 | — | — | — | ||||||||||||||||||||||
| Income tax expense (benefit) | 7,092 | (877) | 3,052 | 2,677 | ||||||||||||||||||||||
| Consolidated EBITDAX (non-GAAP) | $ | 278,390 | $ | 222,089 | $ | 192,345 | $ | 143,623 | ||||||||||||||||||
Net Debt (Unaudited)
Net Debt, a non-GAAP financial measure, is calculated as the face value of long-term debt plus any outstanding letters of credit, 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 June 30, 2022 $1.159 billion.
Net Debt to Consolidated EBITDAX (Unaudited)
Net Debt to Consolidated EBITDAX, a non-GAAP financial measure, is calculated as Net Debt divided by Consolidated EBITDAX for the previous four quarters, as defined in the Company's Senior Secured Credit Facility. Net Debt to Consolidated EBITDAX is used by the Company’s management for various purposes, including as a measure of operating performance, in presentations to its board of directors and as a basis for strategic planning and forecasting.
# # #
Investor Contact:
Ron Hagood
918.858.5504
rhagood@laredopetro.com
13
2Q-2022 Earnings Presentation EXHIBIT 99.2
This presentation, including any oral statements made regarding the contents of this presentation, contains forward-looking statements as defined under Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, that address activities that Laredo Petroleum, Inc. (together with its subsidiaries, the “Company”, “Laredo” or “LPI”) assumes, plans, expects, believes, intends, projects, indicates, enables, transforms, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. The forward- looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Such statements are not guarantees of future performance and involve risks, assumptions and uncertainties. General risks relating to Laredo include, but are not limited to, the decline in prices of oil, natural gas liquids and natural gas and the related impact to financial statements as a result of asset impairments and revisions to reserve estimates, the ability of the Company to execute its strategies, including its ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to its financial results and to successfully integrate acquired businesses, assets and properties, oil production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries and other producing countries (“OPEC+”), the outbreak of disease, such as the coronavirus (“COVID-19”) pandemic, and any related government policies and actions, changes in domestic and global production, supply and demand for commodities, including as a result of the COVID-19 pandemic, actions by OPEC+ and the Russian-Ukrainian military conflict, long-term performance of wells, drilling and operating risks, the increase in service and supply costs, including as a result of inflationary pressures, 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, 2021, and those set forth from time to time in other filings with the Securities and Exchange Commission (“SEC”). These documents are available through Laredo’s website at www.laredopetro.com under the tab “Investor Relations” or through the SEC’s Electronic Data Gathering and Analysis Retrieval System at www.sec.gov. Any of these factors could cause Laredo’s actual results and plans to differ materially from those in the forward-looking statements. Therefore, Laredo can give no assurance that its future results will be as estimated. Any forward-looking statement speaks only as of the date on which such statement is made. Laredo does not intend to, and disclaims any obligation to, correct, update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. The SEC generally permits oil and natural gas companies, in filings made with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, and certain probable and possible reserves that meet the SEC’s definitions for such terms. In this presentation, the Company may use the terms “resource potential,” “resource play,” “estimated ultimate recovery,” or “EURs,” “type curve” and “standardized measure,” each of which the SEC guidelines restrict from being included in filings with the SEC without strict compliance with SEC definitions. These terms refer to the Company’s internal estimates of unbooked hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. “Resource potential” is used by the Company to refer to the estimated quantities of hydrocarbons that may be added to proved reserves, largely from a specified resource play potentially supporting numerous drilling locations. A “resource play” is a term used by the Company to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section potentially supporting numerous drilling locations, which, when compared to a conventional play, typically has a lower geological and/or commercial development risk. “EURs” are based on the Company’s previous operating experience in a given area and publicly available information relating to the operations of producers who are conducting operations in these areas. Unbooked resource potential 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 Consolidated EBITDAX and Free Cash Flow. While management believes that such measures are useful for investors, they should not be used as a replacement for financial measures that are in accordance with GAAP. For definitions of such non-GAAP financial measures, please see the Appendix. Unless otherwise specified, references to “average sales price” refer to average sales price excluding the effects of the Company’s derivative transactions. All amounts, dollars and percentages presented in this presentation are rounded and therefore approximate. 2 Forward-Looking / Cautionary Statements
35% 47% 28.4 38.5 FY-19A FY-22E ($624) ($644) ($482) ($351) ($454) ~($550) ~($585) ($246) ($106) $60 $12 ($3) ~$280 ~$560 FY-17A FY-18A FY-19A FY-20A FY-21A FY-22E FY-23E Multi-Year Strategic Transformation Yields a “New” Laredo 3 Low-cost, efficient and safe operations Optimizing production through digital and innovative solutions Reducing emissions and flaring Local philanthropy and community engagement Committed to diversity and inclusion Added ~57,000 oil-weighted net acres in the Midland Basin ~8 years of inventory primarily across Howard County and western Glasscock County Strong proved reserve base Broad portfolio of digital solutions Hired key leadership roles including CEO, CFO, Chief Sustainability Officer and Chief Technology Officer Refreshed 80% of Board over the past three years Board is 60% diverse based on race/gender Separated Chairman and CEO roles Maximize Free Cash Flow1 Optimize capital structure through debt and leverage reductions Return of capital to shareholders Advance sustainability New Leadership New Strategy New Assets New Capabilities Expanded Inventory Shifted Commodity Mix Reduced Leverage Balanced Investment & Capital Discipline Generating Free Cash Flow1 Outspending Cash Flow Capital Discipline & Portfolio Repositioning FCF Generation2 ~$200MM Stock Repurchase Target ~$700MM Debt Reduction Target 2022-2023 Capital Expenditures $MM Free Cash Flow $MM 1See Appendix for definitions of non-GAAP financial measures; 2Assumes 2022 WTI oil price / HH gas price of $100 / $7.00 (1H-22 actualized) and 2023 WTI oil price / HH gas price of $90 / $5.65 Oil Production MBo/d & Oil % Portfolio Repositioning 2019 - 2021 Return of Capital 2022+ Net Acres Oil-Weighted ~66,000 Eastern ~100,000
$1.48 Equity $1.48 Equity $1.48 Equity $0.61 Equity Uplift $0.61 Equity Uplift $0.73 Equity Uplift $1.13 Net Debt $0.52 Net Debt $0.52 Net Debt$2.6 $2.6 $3.3 Current $700 MM Debt Reduction 3.5x EV / '22E EBITDA 0.0x 1.0x 2.0x 3.0x 4.0x 5.0x 6.0x LPI Reducing Debt and Leverage Absolute net debt target of $700 to $750 million Achieving leverage target of <1.0x in 2Q-23 Repurchasing Shares Opportunistically Two-year program authorized through May 27, 2024 $200 million stock repurchase target 1See Appendix for definitions of non-GAAP financial measures; 2Assumes 2022 WTI oil price / HH gas price of $100 / $7.00 (1H-22 actualized) and 2023 WTI oil price / HH gas price of $90 / $5.65 3Less than or equal to $55 breakeven oil price; 4Source JP Morgan Research as of 7/28/2022 5Peer Group (PXD, CTRA, DVN, EOG, HES, CPE, SM, MRO, RRC, CLR, FANG, MTDR, AR, CNX, EQT, PDCE, APA, CHK, MUR, SWN, OVV) “New” Laredo Focused on Driving Shareholder Value Enterprise Value / 2022E EBITDA - Peer Comparison4,5 4 Equitizing Enterprise Value - $B Avg. Multiple 3.5x Maintaining Capital Discipline Strong asset performance supports steady reinvestment rate Ability to maintain current oil production at ~60% reinvestment rate Generating Free Cash Flow1 Two-year projected total of ~$840 million (2022-23)2 Sustainable Free Cash Flow supported by eight years of oil-weighted inventory3 Expanding Value Trading at a discount to Proved Developed Reserves value Highest 2022-23 Free Cash Flow yield in peer group5 Peer Group Debt Reduction Multiple Expansion Illustrative Value
2.14x 1.93x 1.39x 4Q-21A 1Q-22A 2Q-22A $9 $7 4Q-21A 1Q-22A 2Q-22A 3Q-22A (QTD) $32 $59 4Q-21A 1Q-22A 2Q-22A 3Q-22A (QTD) Deleveraging 1Incurred capital expenditures; 2See Appendix for definitions of non-GAAP financial measures; 33Q-22A QTD as of August 2, 2022 Executing the Plan | Q2 2022 Results 5 Oil Production Capital Discipline1 Free Cash Flow2 Repurchasing Debt3 Repurchasing Shares3 41.1 40.3 40.6 4Q-21A 1Q-22A 2Q-22A $142 $171 $138 4Q-21A 1Q-22A 2Q-22A $25 $23 $110 4Q-21A 1Q-22A 2Q-22A (Units in MBo/d) (Units in $ millions) (Units in $ millions) (Net Debt to Consolidated EBITDAX2 Multiple) (Units in $ millions) (Units in $ millions) Program Initiated 2Q-22 Program Initiated 2Q-22
0 25 50 75 100 125 150 175 200 0 90 180 270 360 C u m u la ti v e G ro s s O il P ro d u c ti o n p e r W e ll ( M B O ) Producing Days 1Timing based on estimated flowback date; 2Production data normalized to 10,000’ lateral length, downtime days Development Program in 2H-22 & FY-23 Primarily Focused on North Howard Howard Strong Performance in North Howard Driving 2H-22 and FY-23 Expectations 6 North Howard Development 100% of 2H-22 and 92% of FY-23 TIL’s Oil production outperforming Central Howard by ~25% Expected to generate ~60% of FY-23 oil production Middle Sprayberry continuing to outperform expectations with nine wells set to turn-in-line during 2023 Central Howard Development ~80% of Central Howard developed; 23 remaining locations in three DSUs Scheduled TIL’s: Five in FY-23 and 18 in FY-24 North Howard Central Howard Average Well Performance2 LPI Producing 2H ‘2022 TIL 2023 TIL 2024 TIL LPI OBO Net Acres North Howard Middle Spraberry (North Howard) Central Howard (2Q-21+) Central Howard (4Q-20 to 1Q-21) Leech (2Q-22) Leech DSU
100 125 130 165 165 60 195 275 295 295 ≤$40 ≤$45 ≤$50 ≤$55 Inventory Upside Near-term Development Focus 1Gross operated location as of January 2022 (adjusted for 2021 completions) 2Locations may require the formation of drilling units to develop 3Flat oil price needed to achieve 10% IRR assuming gas price at 20:1 ratio Development Focus Areas ~460 ~320 ~1502 Avg. Breakeven Oil Price3 ~8 Years of Inventory1 Assumes: Current activity pace Low-risk, operated only Current development spacing <$55 breakeven oil price Howard Glasscock Howard W. Glasscock Eastern Reagan Midland Martin Sterling Mitchell ~160 Low Breakeven Oil Inventory Underpins Sustainable Free Cash Flow Generation 7 ~405 Howard W. Glasscock Eastern
1,117' 1,314' 1,439' 1,577' FY-19A FY-20A FY-21A YTD-22A 10,750' 9,950' 10,000' 12,653' FY-19A FY-20A FY-21A YTD-22A 1,274' 1,408' 1,653' 1,584' FY-19A FY-20A FY-21A YTD-22A ~4 Yrs. Current Sand Inventory2 Drilling Ft. Per Day Per Rig Disciplined, Efficient Capital Program Maintains Prior Year Activity Levels 2022E Capital Program FY-22 Guidance Capital Expenditures ($MM) ~$550 Avg. Rig Count (Op) ~2.3 Avg. Frac Crews (Op) ~1.2 Spuds 65 Gross (62.9 Net) Completions 55 Gross (53.1 Net) Turn-in-Lines 55 Gross (53.1 Net) Production (MBOE/d) 82.0 – 83.5 Oil Production (MBO/d) 38.0 – 39.0 81% 8% 7% 4% Capital Expenditures by Category DC&E (op) Facilities & Land Corporate DC&E (non-op) 8 Continuous Improvement Drives Capital Efficient Drilling and Completion Program Company Owned Sand Mine Reduces Well Costs and Protects Against Inflation Avg. Completed Lateral Length 1Based on Howard County 10,000’ lateral length completions; 2Based on current pace of development Fractured Ft. Per Day Per Crew Located on Laredo owned surface acreage Operated by a third party Reduces emissions by: − Elimination of truck traffic − Utilization of wet sand >$400K Per Well Savings1
$567 $332 $348 $1,000 2022 2023 2024 2025 2026 2028 2029 2.61x 2.14x 1.93x 1.39x <1.35x <1.25x <1.15 <1.00 FY-20A FY-21A 1Q-22A 2Q-22A 3Q-22E 4Q-22E 1Q-23E 2Q-23E ~$245 ~$260 ~$280 ~$310 ~$420 ~$560 ~$685 ~$810 $80 $90 $100 $110 $80 $90 $100 $110 1See Appendix for definitions of non-GAAP financial measures; 2Assumes 2022 WTI oil price / HH gas price of $100 / $7.00 (1H-22 actualized) and 2023 WTI oil price / HH gas price of $90 / $5.65; 3As of 8/2/2022 41H-22 pricing actualized Free Cash Flow Driving Return of Capital and Debt Reductions 9 Rapidly Deleveraging through Free Cash Flow1 Generation Current Debt Maturity Profile3Free Cash Flow1 Sensitivities - $MM Net Debt to Consolidated EBITDAX1,2 Borrowing Base $1,250 MM Elected Commitment $1,000 MM Cash Balance $114 MM Liquidity ~$1,114 MM 9.500% Sr. Notes 2025 10.125% Sr. Notes 2028 7.750% Sr. Notes 2029 Drawn Credit Facility Undrawn Credit Facility 2022-23 Debt Reduction Target ~$700 million Current Liquidity3 ~$1.1 billion Two-Year Stock Repurchase Program through May 27, 2024 ~$200 million 2Q-23E Net Debt to Consolidated EBITDAX1,2 <1.0x Target Benchmark WTI Oil Price (per BBL) (Benchmark HH Gas Price assumes $7.00/mcf) Benchmark WTI Oil Price (per BBL) (Benchmark HH Gas Price assumes $5.65/mcf) 2022E Free Cash Flow1,4 (~$550 million capex) 2023E Free Cash Flow1 (~$585 million capex)
$2,798 $2,463 $2,922 $3,380 $3,840 SEC Pricing $55 $65 $75 $85 2.8x 2.3x 2.1x 2.0x 2.0x 1.9x 1.9x 1.8x 1.8x 1.7x 1.6x Average 1.6x 1.6x 1.5x 1.3x 1.2x 1.2x 1.2x 1.1x 1.1x 1.1x 1.1x 1.0x LPI 10 Significant Upside Potential Supported by Strong Reserves and Cash Flow 1See Appendix for definitions of non-GAAP financial measures; 2SEC pricing $63 benchmark oil and $3.35 benchmark gas / YE-21 reserves; 3Source Capital One Research as of 7/27/2022 4Source JP Morgan Research as of 7/28/2022; 5Peer Group (PXD, CTRA, DVN, EOG, HES, CPE, SM, MRO, RRC, CLR, FANG, MTDR, AR, CNX, EQT, PDCE, APA, CHK, MUR, SWN, OVV) PV-101,2 Proven Developed Producing Reserve Value Sensitivity - $MM Current Adj. Enterprise Value / PDP – Peer Comparison3,5 P e e r G ro u p EV / EBITDA vs. 2-Year FCF Yield – Peer Comparison4,5 0.0x 2.0x 4.0x 6.0x 8.0x 0% 20% 40% 60% 80% LPI Average
Generating Significant Free Cash Flow1 Returning Capital to Shareholders Reducing Debt and Improving Leverage Equity Upside Potential vs. Peer Group2 1See Appendix for definitions of non-GAAP financial measures 2Peer Group (PXD, CTRA, DVN, EOG, HES, CPE, SM, MRO, RRC, CLR, FANG, MTDR, AR, CNX, EQT, PDCE, APA, CHK, MUR, SWN, OVV) Compelling Investment Opportunity 11
Appendix
2H-22 & FY-22 GUIDANCE Guidance Commodity Prices Used for 3Q-22 Jul-22 Aug-22 Sep-22 3Q-22 Avg. Crude Oil: - - - - WTI NYMEX ($/BBO) $99.39 $98.05 $96.20 $97.90 Brent ICE ($/BBO) $104.84 $103.86 $101.36 $103.38 Natural Gas: - - - - Henry Hub ($/MMBTU) $6.55 $8.69 $8.23 $7.82 Waha ($/MMBTU) $5.62 $7.92 $7.34 $6.96 Natural Gas Liquids: - - - - C2 ($/BBL) $24.15 $24.99 $24.57 $24.57 C3 ($/BBL) $48.09 $48.56 $48.35 $48.34 IC4 ($/BBL) $64.43 $57.80 $57.44 $59.92 NC4 ($/BBL) $53.89 $54.39 $54.50 $54.25 C5+ ($/BBL) $79.10 $77.81 $77.86 $78.26 Composite ($/BBL)1 $42.57 $42.80 $42.56 $42.64 3Q-22 4Q-22 FY-22 Production: - - Total Production (MBOE/D) 78.5 – 81.5 77.5 – 80.5 82.0 – 83.5 Crude Oil Production (MBO/d) 35.5 – 37.5 35.5 – 37.5 38.0 – 39.0 Incurred Capital Expenditures ($MM): ~$120 ~$120 ~$550 Average Sales Price Realizations (excluding derivatives): - - - Crude Oil (% of WTI) 103% - - Natural Gas Liquids (% of WTI) 31% - - Natural Gas (% of Henry Hub) 72% - - Net Settlements Received (Paid) for Matured Commodity Derivatives ($MM): - - - Crude Oil ($MM) ($100) - - Natural Gas Liquids ($MM) ($12) - - Natural Gas ($MM) ($30) - - Operating Costs & Expenses ($/BOE): - - - Lease Operating Expenses $5.70 - - Production & Ad Valorem Taxes (% of Oil, NGL & Natural Gas Revenues) 7.0% - - Transportation and Marketing Expenses $1.75 - - General and Administrative Expenses (excluding LTIP) $1.80 - - General and Administrative Expenses (LTIP Cash) $0.40 - - General and Administrative Expenses (LTIP Non-Cash) $0.30 - - Depletion, Depreciation and Amortization $10.25 - - Note: Supports average sales price realization and derivatives guidance 13 1Current NGL composition C2 (42%), C3 (33%), IC4 (3%), NC4 (11%) and C5+ (11%)
1Hedges executed as of 7/31/2022 Active Hedge Program to Protect Free Cash Flow 14 (Volume in MBO; Price in $/BBO) Q3-22 Q4-22 2H-22 Q1-23 Q2-23 Q3-23 Q4-23 FY-23 Brent Swaps 1,040 1,040 2,079 - - - - - WTD Price $48.34 $48.34 $48.34 - - - - - Brent Collars 391 391 782 - - - - - WTD Floor Price $56.65 $56.65 $56.65 - - - - - WTD Ceiling Price $65.44 $65.44 $65.44 - - - - - WTI Swaps 92 92 184 - - - - - WTD Price $64.40 $64.40 $64.40 - - - - - WTI Collars 1,408 1,408 2,815 1,620 1,638 552 552 4,362 WTD Floor Price $72.65 $72.65 $72.65 $67.22 $67.22 $70.00 $70.00 $67.93 WTD Ceiling Price $86.54 $86.54 $86.54 $81.50 $81.50 $87.02 $87.02 $82.89 Total Swaps/Collars 2,930 2,930 5,860 1,620 1,638 552 552 4,362 WTD Floor Price $61.63 $61.63 $61.63 $67.22 $67.22 $70.00 $70.00 $67.93 (Volume in MBBL; Price in $/BBL) Q3-22 Q4-22 2H-22 Q1-23 Q2-23 Q3-23 Q4-23 FY-23 Ethane Swaps 386 386 773 - - - - - WTD Price $11.42 $11.42 $11.42 - - - - - Propane Swaps 294 294 589 - - - - - WTD Price $35.91 $35.91 $35.91 - - - - - Butane Swaps 92 92 184 - - - - - WTD Price $41.58 $41.58 $41.58 - - - - - Isobutane Swaps 28 28 55 - - - - - WTD Price $42.00 $42.00 $42.00 - - - - - Pentane Swaps 92 92 184 - - - - - WTD Price $60.65 $60.65 $60.65 - - - - - (Volume in MMBTU; Price in $/MMBTU) Q3-22 Q4-22 2H-22 Q1-23 Q2-23 Q3-23 Q4-23 FY-23 Henry Hub Swaps 920,000 920,000 1,840,000 - - - - - WTD Price $2.73 $2.73 $2.73 - - - - - Henry Hub Collars 7,360,000 7,360,000 14,720,000 4,500,000 4,550,000 4,600,000 4,600,000 18,250,000 WTD Floor Price $3.09 $3.09 $3.09 $3.90 $3.90 $3.90 $3.90 $3.90 WTD Ceiling Price $3.84 $3.84 $3.84 $8.31 $8.31 $8.31 $8.31 $8.31 Total Henry Hub Swaps/Collars 8,280,000 8,280,000 16,560,000 4,500,000 4,550,000 4,600,000 4,600,000 18,250,000 WTD Floor Price $3.05 $3.05 $3.05 $3.90 $3.90 $3.90 $3.90 $3.90 Waha Basis Swaps 7,314,000 7,314,000 14,628,000 4,500,000 4,550,000 4,600,000 4,600,000 18,250,000 WTD Price ($0.36) ($0.36) ($0.36) ($1.58) ($1.58) ($1.58) ($1.58) ($1.58)
1.95% 0.71% 0.37% 0.73% 0.78% FY-19A FY-20A FY-21A YTD-22A Zero routine flaring 15 <12.5 mtCO2e / MBOE <0.20% methane emissions1,2 18.08 17.54 12.50 2019 Baseline 2020 Performance Venting Reductions Flaring Reductions Pnuematics Reductions Combustion Reductions 2025 Target S c o p e 1 E m is s io n s m tC O 2 e / M B O E Defined Scope 1 Emissions Reduction Plan Systematic Plan to Achieve Emissions Reductions TrustWellTM Certification First Permian operator to receive TrustWellTM responsibly sourced certification Gold certification awarded for production from 73 horizontal wells representing ~31,500 BOEPD of gross operated production in the certification area Uniquely positioned among Permian Basin operators to benefit as premium markets are developed for certified responsibly sourced production Targets for 2025 12019 calendar year as baseline; 2As a percentage of natural gas production Percentage of Produced Natural Gas Flared / Vented Acquisitions Impact eu i
1Data as of 12/31/2021; 2Data as of 7/31/2022 Corporate and Community Responsibility Local and Impactful Philanthropy >$820,000 Total amount donated since 2019 to improve our local communities1 Diversity and Inclusion Efforts1 EEO-1 Data Disclosed in Company’s 2021 ESG & Climate Risk Report 27% 26% 61% 60% Women in Workforce Minorities in Workforce Women and/or Minorities in Professional-or-higher Roles Female and Minority Directors2 16
Supplemental Non-GAAP Financial Measures Consolidated EBITDAX (Credit Agreement Calculation Unaudited) Consolidated EBITDAX is a non-GAAP financial measure defined in the Company’s Senior Secured Credit Facility as net income or loss (GAAP) plus adjustments for extraordinary gains (or losses), non-cash recurring gains (or losses), depletion, depreciation and amortization expense, interest expense, any provisions for (or benefit from) income or franchise taxes, exploration expenses and other non-cash charges. Consolidated EBITDAX is used by the Company’s management for various purposes, including as a measure of operating performance and compliance under the Company’s Senior Secured Credit Facility. Additional information on the calculation of Consolidate EBITDAX can be found in the Company’s Eighth Amendment to the Senior Secured Credit Facility as filed with the SEC on April 19, 2022. The following table presents a reconciliation of net income (loss) (GAAP) to Consolidated EBITDAX (non-GAAP) for the periods presented: 17 (in thousands, unaudited) 6/30/2022 3/31/2022 12/31/2021 9/30/2021 Net Income (loss) $262,546 ($86,781) $216,276 $136,832 Plus: Share-settled equity-based compensation, net 2,604 2,053 2,066 1,811 Depletion, depreciation and amortization 78,135 73,492 74,592 62,678 Mark-to-market on derivatives: (Gain) loss on derivatives, net 65,927 325,816 (15,372) 96,240 Settlements paid for matured derivatives, net (172,454) (125,370) (129,361) (92,726) Accretion expense 973 1,019 1,026 906 (Gain) loss on sale of oil and natural gas properties, net - - - (95,223) (Gain) loss on disposal of assets, net (38) 260 8,903 22 Interest expense 32,807 32,477 31,163 30,406 Loss on extinguished of debt, net 798 - - - Income tax (benefit) expense 7,092 (877) 3,052 2,677 Consolidated EBITDAX (non-GAAP) $278,390 $222,089 $192,345 $143,623 Three months ended,
Supplemental Non-GAAP Financial Measures PV-10 (Unaudited) PV-10 is a non-GAAP financial measure that is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. Management believes that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to the Company's estimated proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of the Company's proved oil, NGL and natural gas assets. Further, investors may utilize the measure as a basis for comparison of the relative size and value of proved reserves to other companies. The Company uses this measure when assessing the potential return on investment related to proved oil, NGL and natural gas assets. However, PV-10 is not a substitute for the standardized measure of discounted future net cash flows. The PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of the Company's oil, NGL and natural gas reserves of the property. 18 (in millions) December 31, 2021 Standardized measure of discounted future net cash flows $3,425 Less present value of future income taxes discounted at 10% (291) PV-10 (non-GAAP) $3,716
Supplemental Non-GAAP Financial Measures Net Debt (Unaudited) Net Debt, a non-GAAP financial measure, is calculated as the face value of long-term debt plus any outstanding letters of credit, 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 June 30, 2022 was $1.159 billion. Net Debt to Consolidated EBITDAX (Unaudited) Net Debt to Consolidated EBITDAX, a non-GAAP financial measure, is calculated as Net Debt divided by Consolidated EBITDAX, for the previous four quarters, as defined in the Company's Senior Secured Credit Facility. Net Debt to Consolidated EBITDAX is used by the Company’s management for various purposes, including as a measure of operating performance, in presentations to its board of directors and as a basis for strategic planning and forecasting Free Cash Flow (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. Management believes Free Cash Flow is useful to management and investors in evaluating operating trends in its business that are affected by production, commodity prices, operating costs and other related factors. There are significant limitations to the use of Free Cash Flow as a measure of performance, including the lack of comparability due to the different methods of calculating Free Cash Flow reported by different companies. The Company is unable to provide a reconciliation of the forward-looking Free Cash Flow projection contained in this presentation to net cash provided by operating activities, the most directly comparable GAAP financial measure, because 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