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 9, 2023
(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)
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)) | |||||||||||
Securities registered pursuant to Section 12(b) of the Exchange Act:
| Title of each class | Trading Symbol | Name of each exchange on which registered | ||||||
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 9, 2023, Vital Energy, Inc. (the "Company") announced its financial and operating results for the quarter ended March 31, 2023. 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 May 9, 2023, 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 May 9, 2023, the Company also posted to its website, www.vitalenergy.com, an investor presentation (the "Presentation"), which 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, 2022 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.
| VITAL ENERGY, INC. | ||||||||
Date: May 9, 2023 | By: | /s/ Bryan J. Lemmerman | ||||||
| Bryan J. Lemmerman | ||||||||
| Senior Vice President and Chief Financial Officer | ||||||||
EXHIBIT 99.1
Vital Energy Reports First-Quarter 2023 Financial and Operating Results
TULSA, OK - May 9, 2023 - Vital Energy, Inc. (NYSE: VTLE) ("Vital Energy" or the "Company") today reported its first-quarter 2023 financial and operating results. Supplemental slides have been posted to the Company's website and can be found at www.vitalenergy.com. A conference call and webcast to discuss the results is planned for 7:30 a.m. CT, Wednesday, May 10, 2023. Participation details can be found within this release.
Highlights
•Reported 1Q-23 oil and total production that exceeded the high-end of Company guidance, producing 38.5 thousand barrels of oil per day ("MBO/d") and 80.4 thousand barrels of oil equivalent per day ("MBOE/d")
•Reported 1Q-23 incurred capital expenditures below the low-end of guidance, investing $188 million, excluding non-budgeted acquisitions and leasehold expenditures
•Reported 1Q-23 net income of $113.9 million and cash flows from operating activities of $116.1 million
•Generated 1Q-23 Consolidated EBITDAX1 of $214.2 million and Free Cash Flow1 of $(3.9) million
•Announced and recently closed (April 2023) an accretive acquisition of approximately 11,200 net acres in the Midland Basin from Driftwood Energy Operating, LLC ("Driftwood")
•Disclosed preliminary 2022 greenhouse gas intensity and methane intensity levels that demonstrate achievement of 2025 targets
"The benefits of Vital Energy's strategy were evident in our outstanding first quarter results," commented Jason Pigott, President and Chief Executive Officer. "We have a proven track record of successfully acquiring and integrating high-value properties, reducing emissions and using our proprietary technologies to enhance performance and returns. Our results are benefiting from process improvements that increase efficiencies, improve well productivity and increase confidence in our forecasting.
"We are highly confident in our ability to deliver on our 2023 plan," continued Pigott. "Production from base wells and recent completions is performing better than expectations. With increasing operational efficiencies, we are projecting additional completions within our original capital budget expectations. We have successfully integrated the Driftwood acquisition and are currently completing wells on the prolific Upton County acreage. Our outlook for the rest of the year is strong as we remain focused on maintaining capital discipline, generating Free Cash Flow, reducing debt, and creating shareholder value through the capital efficient development of our acquired properties."
1Non-GAAP financial measure; please see supplemental reconciliations of GAAP to non-GAAP financial measures at the end of this release.
First-Quarter 2023 Financial and Operations Summary
Financial Results. The Company reported net income attributable to common stockholders of $113.9 million, or $6.89 per diluted share. Adjusted Net Income1 was $74.4 million, or $4.50 per adjusted diluted share. Cash flows from operating activities was $116.1 million and Consolidated EBITDAX was $214.2 million.
Production. Consistent with preliminary volumes disclosed in April, Vital Energy's oil and total production during the period averaged 38,522 barrels of oil per day and 80,416 barrels of oil equivalent per day, respectively. Results were driven by earlier than expected production from new completions and less than anticipated downtime related to offset completions activity.
Capital Investments. Total incurred capital expenditures were $188 million, excluding non-budgeted acquisitions and leasehold expenditures. Lower than expected investment levels were primarily related to the deferral of facilities investments into second-quarter 2023, moderating inflationary pressures and a brief weather-related deferral of completions activity. Investments included $170 million in drilling and completions, $7 million in infrastructure, including Vital Midstream Services investments, $8 million in other capitalized costs and $3 million in land, exploration and data related costs. Vital Energy completed 21 wells and turned-in-line ("TIL") 18 wells during first-quarter 2023.
Operating Expenses. Lower than expected lease operating expenses ("LOE") during the period were $6.93 per BOE, primarily related to higher production levels.
General and Administrative Expenses. General and administrative ("G&A") expenses, excluding long-term incentive plan ("LTIP") expenses and transaction expenses, for first-quarter 2023 were $3.02 per BOE, higher than guidance, primarily related to timing of accounting for benefits and compensation. Cash and non-cash LTIP expenses were $0.13 per BOE and $0.31 per BOE, respectively. Cash LTIP expense was below guidance due to the decline of the Company's stock price in first-quarter 2023. Transaction expenses related to the Driftwood acquisition were $0.12 per BOE.
Liquidity. At March 31, 2023, the Company had $120 million drawn on its $1.0 billion senior secured credit facility and cash and cash equivalents of $28 million. Through the regular semi-annual redetermination process, the Company's lenders recently have reaffirmed the senior secured credit facility's $1.3 billion borrowing base and $1.0 billion elected commitment
At May 5, 2023, the Company had $255 million drawn on its senior secured credit facility and cash and cash equivalents of $68 million. The drawn amount includes funds utilized to fund closing of the Driftwood acquisition in April 2023.
Achievement of 2025 GHG and Methane Emissions Targets
Operating in a responsible, sustainable manner is a key pillar of Vital Energy's strategy. The Company has instituted a culture that is committed to this mission, set specific emissions targets and made the necessary investments to ensure their attainment.
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Preliminary emissions data for 2022 demonstrates Vital Energy's progress towards its key sustainability commitments. The Company's 2022 Scope 1 greenhouse gas intensity level of approximately 10.7 metric tons of CO2 equivalent per MBOE ("mtCO2/MBOE") is a ~38% reduction from 2021 levels and below Vital Energy's 2025 target of 12.5 mtCO2/MBOE. The Company's 2022 methane intensity level of 0.10% of natural gas produced is down from 0.32% in 2021 and below Vital Energy's 2025 target of 0.20%.
In late 2022, Vital Energy established a combined Scope 1 and 2 emissions intensity target, targeting a level of less than 10 mtCO2/MBOE, a reduction of more than 60% compared to 2019 Company baseline levels.
2023 Outlook, Second Quarter and Full-Year 2023 Guidance
Production. As previously announced, the Company increased full-year 2023 production guidance to incorporate better than expected first-quarter 2023 volumes and the impact of the Driftwood acquisition.
Capital Investments. Vital Energy plans to operate two drilling rigs and one completions crew throughout the remainder of 2023. Gains in completions efficiencies have enabled the expected addition of four additional TIL's late in 2023, increasing expected full-year TIL's to approximately 59 wells. Despite the additional TIL's, the Company reiterated its full-year 2023 capital investment guidance of $625 - $675 million.
The table below reflects the Company's guidance for total and oil production and incurred capital expenditures for second-quarter and full-year 2023. Full-year 2023 production guidance reflects the previously announced increase.
| 2Q-23E | FY-23E | |||||||||||||
| Total production (MBOE/d) | 85.5 - 88.5 | 76.0 - 80.0 | ||||||||||||
| Oil production (MBO/d) | 40.0 - 43.0 | 36.3 - 39.3 | ||||||||||||
| Incurred capital expenditures, excluding non-budgeted acquisitions ($ MM) | $155 - $175 | $625 - $675 | ||||||||||||
The table below reflects the Company's guidance for select revenue and expense items for second-quarter 2023.
| 2Q-23E | ||||||||
| Average sales price realizations (excluding derivatives): | ||||||||
| Oil (% of WTI) | 101% | |||||||
| NGL (% of WTI) | 18% | |||||||
| Natural gas (% of Henry Hub) | 27% | |||||||
| Net settlements received (paid) for matured commodity derivatives ($ MM): | ||||||||
| Oil | $1 | |||||||
| NGL | - | |||||||
| Natural gas | $12 | |||||||
| Selected average costs & expenses: | ||||||||
| Lease operating expenses ($/BOE) | $7.50 | |||||||
| Production and ad valorem taxes (% of oil, NGL and natural gas sales revenues) | 7.00% | |||||||
| Transportation and marketing expenses ($/BOE) | $1.40 | |||||||
| General and administrative expenses (excluding LTIP and transaction expenses, $/BOE) | $2.50 | |||||||
| General and administrative expenses (LTIP cash, $/BOE) | $0.15 | |||||||
| General and administrative expenses (LTIP non-cash, $/BOE) | $0.35 | |||||||
| Depletion, depreciation and amortization ($/BOE) | $12.75 | |||||||
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Conference Call Details
Vital Energy plans to host a conference call at 7:30 a.m. CT on Wednesday, May 10, 2023, to discuss its first-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 will be posted to the Company's website. The Company invites interested parties to listen to the call via the Company's website at www.vitalenergy.com, under the tab for "Investor Relations | News & Presentations." Portfolio managers and analysts who would like to participate on the call should dial 800.715.9871, using conference code 1077806. A replay will be available following the call via the Company's website.
About Vital
Vital Energy, Inc. is an independent energy company with headquarters in Tulsa, Oklahoma. Vital'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 Vital may be found on its website at www.vitalenergy.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 Vital Energy 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 Vital Energy include, but are not limited to, continuing and worsening inflationary pressures and associated changes in monetary policy that may cause costs to rise; changes in domestic and global production, supply and demand for commodities, including as a result of the coronavirus ("COVID-19") pandemic, actions by the Organization of Petroleum Exporting Countries and other producing countries ("OPEC+") and the Russian-Ukrainian military conflict, 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, reduced demand due to shifting market perception towards the oil and gas industry; competition in the oil and gas industry; 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, pipeline transportation and storage constraints in the Permian Basin, the effects and duration of the outbreak of disease, such as the COVID-19 pandemic, and any related government policies and actions, long-term performance of wells, drilling and operating risks, the possibility of production curtailment, the impact of new laws and regulations, including those regarding the use of hydraulic fracturing, the impact of legislation or regulatory initiatives intended to address induced seismicity on our ability to conduct our operations; hedging activities, tariffs on steel, 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 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, 2022 and those set forth from time to time in other filings with the Securities and Exchange Commission ("SEC"). These documents are available through Vital Energy's website at www.vitalenergy.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 Vital Energy's actual results and plans to differ materially from those in the forward-looking statements. Therefore, Vital Energy can give no assurance that its future results will be as estimated. Any forward-looking statement speaks
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only as of the date on which such statement is made. Vital Energy does not intend to, and disclaims any obligation to, correct, update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.
The SEC generally permits oil and natural gas companies, in filings made with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, and certain probable and possible reserves that meet the SEC's definitions for such terms. In this press release and the conference call, the Company may use the terms "resource potential," "resource play," "estimated ultimate recovery" or "EURs," "type curve" and "standardized measure," each of which the SEC guidelines restrict from being included in filings with the SEC without strict compliance with SEC definitions. These terms refer to the Company’s internal estimates of unbooked hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. "Resource potential" is used by the Company to refer to the estimated quantities of hydrocarbons that may be added to proved reserves, largely from a specified resource play potentially supporting numerous drilling locations. A "resource play" is a term used by the Company to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical 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 Free Cash Flow, Adjusted Net Income and Consolidated EBITDAX. 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
Vital Energy, Inc.
Selected operating data
| Three months ended March 31, | ||||||||||||||
| 2023 | 2022 | |||||||||||||
| (unaudited) | ||||||||||||||
| Sales volumes: | ||||||||||||||
| Oil (MBbl) | 3,467 | 3,627 | ||||||||||||
| NGL (MBbl) | 1,849 | 1,994 | ||||||||||||
| Natural gas (MMcf) | 11,529 | 12,243 | ||||||||||||
Oil equivalent (MBOE)(1)(2) | 7,237 | 7,661 | ||||||||||||
Average daily oil equivalent sales volumes (BOE/d)(2) | 80,416 | 85,118 | ||||||||||||
Average daily oil sales volumes (Bbl/d)(2) | 38,522 | 40,295 | ||||||||||||
Average sales prices(2): | ||||||||||||||
Oil ($/Bbl)(3) | $ | 76.94 | $ | 95.81 | ||||||||||
NGL ($/Bbl)(3) | $ | 17.85 | $ | 32.68 | ||||||||||
Natural gas ($/Mcf)(3) | $ | 1.57 | $ | 3.15 | ||||||||||
Average sales price ($/BOE)(3) | $ | 43.91 | $ | 58.90 | ||||||||||
Oil, with commodity derivatives ($/Bbl)(4) | $ | 76.82 | $ | 67.24 | ||||||||||
NGL, with commodity derivatives ($/Bbl)(4) | $ | 17.85 | $ | 26.04 | ||||||||||
Natural gas, with commodity derivatives ($/Mcf)(4) | $ | 1.45 | $ | 2.46 | ||||||||||
Average sales price, with commodity derivatives ($/BOE)(4) | $ | 43.67 | $ | 42.54 | ||||||||||
Selected average costs and expenses per BOE sold(2): | ||||||||||||||
| Lease operating expenses | $ | 6.93 | $ | 5.34 | ||||||||||
| Production and ad valorem taxes | 2.84 | 3.59 | ||||||||||||
| Transportation and marketing expenses | 1.51 | 1.92 | ||||||||||||
| General and administrative (excluding LTIP and transaction expenses) | 3.02 | 1.75 | ||||||||||||
| Total selected operating expenses | $ | 14.30 | $ | 12.60 | ||||||||||
| General and administrative (LTIP): | ||||||||||||||
| LTIP cash | $ | 0.13 | $ | 0.85 | ||||||||||
| LTIP non-cash | $ | 0.31 | $ | 0.27 | ||||||||||
| General and administrative (transaction expenses) | $ | 0.12 | $ | — | ||||||||||
| Depletion, depreciation and amortization | $ | 11.99 | $ | 9.59 | ||||||||||
(1)BOE is calculated using a conversion rate of six Mcf per one Bbl.
(2)The numbers presented are calculated based on actual amounts and may not recalculate using the rounded numbers presented in the table above.
(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.
6
Vital Energy, Inc.
Consolidated balance sheets
| (in thousands, except share data) | March 31, 2023 | December 31, 2022 | ||||||||||||
| (unaudited) | ||||||||||||||
| Assets | ||||||||||||||
| Current assets: | ||||||||||||||
| Cash and cash equivalents | $ | 27,682 | $ | 44,435 | ||||||||||
| Accounts receivable, net | 147,071 | 163,369 | ||||||||||||
| Derivatives | 39,109 | 24,670 | ||||||||||||
| Other current assets | 15,804 | 13,317 | ||||||||||||
| Total current assets | 229,666 | 245,791 | ||||||||||||
| Property and equipment: | ||||||||||||||
| Oil and natural gas properties, full cost method: | ||||||||||||||
| Evaluated properties | 9,735,559 | 9,554,706 | ||||||||||||
| Unevaluated properties not being depleted | 50,142 | 46,430 | ||||||||||||
| Less: accumulated depletion and impairment | (7,401,480) | (7,318,399) | ||||||||||||
| Oil and natural gas properties, net | 2,384,221 | 2,282,737 | ||||||||||||
| Midstream and other fixed assets, net | 128,012 | 127,803 | ||||||||||||
| Property and equipment, net | 2,512,233 | 2,410,540 | ||||||||||||
| Derivatives | 26,448 | 24,363 | ||||||||||||
| Operating lease right-of-use assets | 138,513 | 23,047 | ||||||||||||
| Other noncurrent assets, net | 36,384 | 22,373 | ||||||||||||
| Total assets | $ | 2,943,244 | $ | 2,726,114 | ||||||||||
| Liabilities and stockholders' equity | ||||||||||||||
| Current liabilities: | ||||||||||||||
| Accounts payable and accrued liabilities | $ | 91,688 | $ | 102,516 | ||||||||||
| Accrued capital expenditures | 67,221 | 48,378 | ||||||||||||
| Undistributed revenue and royalties | 148,199 | 160,023 | ||||||||||||
| Derivatives | 1,686 | 5,960 | ||||||||||||
| Operating lease liabilities | 48,434 | 15,449 | ||||||||||||
| Other current liabilities | 34,279 | 82,950 | ||||||||||||
| Total current liabilities | 391,507 | 415,276 | ||||||||||||
| Long-term debt, net | 1,163,807 | 1,113,023 | ||||||||||||
| Asset retirement obligations | 71,308 | 70,366 | ||||||||||||
| Operating lease liabilities | 87,301 | 9,435 | ||||||||||||
| Other noncurrent liabilities | 3,953 | 7,268 | ||||||||||||
| Total liabilities | 1,717,876 | 1,615,368 | ||||||||||||
| Commitments and contingencies | ||||||||||||||
| Stockholders' equity: | ||||||||||||||
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of March 31, 2023 and December 31, 2022 | — | — | ||||||||||||
Common stock, $0.01 par value, 40,000,000 shares authorized, and 17,024,976 and 16,762,127 issued and outstanding as of March 31, 2023 and December 31, 2022, respectively | 170 | 168 | ||||||||||||
| Additional paid-in capital | 2,754,765 | 2,754,085 | ||||||||||||
| Accumulated deficit | (1,529,567) | (1,643,507) | ||||||||||||
| Total stockholders' equity | 1,225,368 | 1,110,746 | ||||||||||||
| Total liabilities and stockholders' equity | $ | 2,943,244 | $ | 2,726,114 | ||||||||||
7
Vital Energy, Inc.
Consolidated statements of operations
| Three months ended March 31, | ||||||||||||||
| (in thousands, except per share data) | 2023 | 2022 | ||||||||||||
| (unaudited) | ||||||||||||||
| Revenues: | ||||||||||||||
| Oil sales | $ | 266,731 | $ | 347,443 | ||||||||||
| NGL sales | 33,006 | 65,155 | ||||||||||||
| Natural gas sales | 18,074 | 38,589 | ||||||||||||
| Sales of purchased oil | 13,851 | 78,864 | ||||||||||||
| Other operating revenues | 845 | 2,344 | ||||||||||||
| Total revenues | 332,507 | 532,395 | ||||||||||||
| Costs and expenses: | ||||||||||||||
| Lease operating expenses | 50,181 | 40,876 | ||||||||||||
| Production and ad valorem taxes | 20,531 | 27,487 | ||||||||||||
| Transportation and marketing expenses | 10,915 | 14,743 | ||||||||||||
| Costs of purchased oil | 14,167 | 82,964 | ||||||||||||
| General and administrative | 25,930 | 21,944 | ||||||||||||
| Depletion, depreciation and amortization | 86,779 | 73,492 | ||||||||||||
| Other operating expenses, net | 1,484 | 138 | ||||||||||||
| Total costs and expenses | 209,987 | 261,644 | ||||||||||||
| Gain (loss) on disposal of assets, net | 237 | (260) | ||||||||||||
| Operating income | 122,757 | 270,491 | ||||||||||||
| Non-operating income (expense): | ||||||||||||||
| Gain (loss) on derivatives, net | 20,490 | (325,816) | ||||||||||||
| Interest expense | (28,554) | (32,477) | ||||||||||||
| Other income, net | 854 | 144 | ||||||||||||
| Total non-operating expense, net | (7,210) | (358,149) | ||||||||||||
| Income (loss) before income taxes | 115,547 | (87,658) | ||||||||||||
| Income tax benefit (expense): | ||||||||||||||
| Current | (1,331) | (1,218) | ||||||||||||
| Deferred | (276) | 2,095 | ||||||||||||
| Total income tax (benefit) expense | (1,607) | 877 | ||||||||||||
| Net income (loss) | $ | 113,940 | $ | (86,781) | ||||||||||
| Net income (loss) per common share: | ||||||||||||||
| Basic | $ | 6.93 | $ | (5.18) | ||||||||||
| Diluted | $ | 6.89 | $ | (5.18) | ||||||||||
| Weighted-average common shares outstanding: | ||||||||||||||
| Basic | 16,431 | 16,767 | ||||||||||||
| Diluted | 16,545 | 16,767 | ||||||||||||
8
Vital Energy, Inc.
Consolidated statements of cash flows
| Three months ended March 31, | ||||||||||||||
| (in thousands) | 2023 | 2022 | ||||||||||||
| (unaudited) | ||||||||||||||
| Cash flows from operating activities: | ||||||||||||||
| Net income (loss) | $ | 113,940 | $ | (86,781) | ||||||||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||||
| Share-settled equity-based compensation, net | 2,572 | 2,053 | ||||||||||||
| Depletion, depreciation and amortization | 86,779 | 73,492 | ||||||||||||
| (Gain) loss on disposal of assets, net | (237) | 260 | ||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||
| (Gain) loss on derivatives, net | (20,490) | 325,816 | ||||||||||||
| Settlements paid for matured derivatives, net | (2,343) | (125,370) | ||||||||||||
| Deferred income tax expense (benefit) | 276 | (2,095) | ||||||||||||
| Other, net | 2,384 | 6,731 | ||||||||||||
| Changes in operating assets and liabilities: | ||||||||||||||
| Accounts receivable, net | 13,961 | (61,742) | ||||||||||||
| Other current assets | (7,464) | 5,092 | ||||||||||||
| Other noncurrent assets, net | 2,345 | (15,227) | ||||||||||||
| Accounts payable and accrued liabilities | (10,693) | 1,842 | ||||||||||||
| Undistributed revenue and royalties | (11,825) | 44,294 | ||||||||||||
| Other current liabilities | (48,650) | (1,471) | ||||||||||||
| Other noncurrent liabilities | (4,430) | 3,988 | ||||||||||||
| Net cash provided by operating activities | 116,125 | 170,882 | ||||||||||||
| Cash flows from investing activities: | ||||||||||||||
| Acquisitions of oil and natural gas properties, net | — | (7,870) | ||||||||||||
| Capital expenditures: | ||||||||||||||
| Oil and natural gas properties | (165,042) | (143,500) | ||||||||||||
| Midstream and other fixed assets | (2,771) | (2,345) | ||||||||||||
| Proceeds from dispositions of capital assets, net of selling costs | 2,175 | 2,019 | ||||||||||||
| Settlements received for contingent consideration | 2,035 | — | ||||||||||||
| Net cash used in investing activities | (163,603) | (151,696) | ||||||||||||
| Cash flows from financing activities: | ||||||||||||||
| Borrowings on Senior Secured Credit Facility | 95,000 | 50,000 | ||||||||||||
| Payments on Senior Secured Credit Facility | (45,000) | (55,000) | ||||||||||||
| Stock exchanged for tax withholding | (2,459) | (5,847) | ||||||||||||
| Other, net | (492) | — | ||||||||||||
| Net cash provided by (used in) financing activities | 47,049 | (10,847) | ||||||||||||
| Net (decrease) increase in cash, cash equivalents and restricted cash | (429) | 8,339 | ||||||||||||
| Cash, cash equivalents and restricted cash, beginning of period | 44,435 | 56,798 | ||||||||||||
| Cash, cash equivalents and restricted cash, end of period | $ | 44,006 | $ | 65,137 | ||||||||||
9
Vital Energy, Inc.
Total Cash, Cash Equivalents and Restricted Cash
The following table presents the Company's cash, cash equivalents and restricted cash as of the dates presented:
| As of March 31, | ||||||||||||||
| (in thousands) | 2023 | 2022 | ||||||||||||
| (unaudited) | ||||||||||||||
| Cash and cash equivalents | $ | 27,682 | $ | 65,137 | ||||||||||
Restricted cash(1) | 16,324 | — | ||||||||||||
| Total cash, cash equivalents and restricted cash | $ | 44,006 | $ | 65,137 | ||||||||||
______________________________________________________________________________
(1)Under the terms of the Driftwood purchase and sale agreement, the Company deposited $16.3 million into a third-party escrow account, which is included in "Other noncurrent assets, net" on the consolidated balance sheets as of March 31, 2023.
10
Vital Energy, 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, 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
Free Cash Flow is a non-GAAP financial measure that the Company defines as net cash provided by operating activities (GAAP) before net changes in operating assets and liabilities and non-budgeted acquisition costs, 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 March 31, | ||||||||||||||
| (in thousands) | 2023 | 2022 | ||||||||||||
| (unaudited) | ||||||||||||||
| Net cash provided by operating activities | $ | 116,125 | $ | 170,882 | ||||||||||
| Less: | ||||||||||||||
| Net changes in operating assets and liabilities | (66,756) | (23,224) | ||||||||||||
| General and administrative (transaction expenses) | (861) | — | ||||||||||||
| Cash flows from operating activities before net changes in operating assets and liabilities and non-budgeted acquisition costs | 183,742 | 194,106 | ||||||||||||
| Less incurred capital expenditures, excluding non-budgeted acquisition costs: | ||||||||||||||
Oil and natural gas properties(1) | 184,114 | 168,368 | ||||||||||||
Midstream and other fixed assets(1) | 3,530 | 2,531 | ||||||||||||
| Total incurred capital expenditures, excluding non-budgeted acquisition costs | 187,644 | 170,899 | ||||||||||||
| Free Cash Flow (non-GAAP) | $ | (3,902) | $ | 23,207 | ||||||||||
_____________________________________________________________________________
(1)Includes capitalized share-settled equity-based compensation and asset retirement costs.
11
Adjusted Net Income
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 March 31, | ||||||||||||||
| (in thousands, except per share data) | 2023 | 2022 | ||||||||||||
| (unaudited) | ||||||||||||||
| Net income (loss) | $ | 113,940 | $ | (86,781) | ||||||||||
| Plus: | ||||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||
| (Gain) loss on derivatives, net | (20,490) | 325,816 | ||||||||||||
| Settlements paid for matured derivatives, net | (1,763) | (125,370) | ||||||||||||
| Settlements received for contingent consideration | 1,455 | — | ||||||||||||
| (Gain) loss on disposal of assets, net | (237) | 260 | ||||||||||||
| Income tax (benefit) expense | 1,607 | (877) | ||||||||||||
| General and administrative (transaction expenses) | 861 | — | ||||||||||||
| Adjusted income before adjusted income tax expense | 95,373 | 113,048 | ||||||||||||
Adjusted income tax expense(1) | (20,982) | (24,871) | ||||||||||||
| Adjusted Net Income (non-GAAP) | $ | 74,391 | $ | 88,177 | ||||||||||
| Net income (loss) per common share: | ||||||||||||||
| Basic | $ | 6.93 | $ | (5.18) | ||||||||||
| Diluted | $ | 6.89 | $ | (5.18) | ||||||||||
| Adjusted Net Income per common share: | ||||||||||||||
| Basic | $ | 4.53 | $ | 5.26 | ||||||||||
| Diluted | $ | 4.50 | $ | 5.26 | ||||||||||
| Adjusted diluted | $ | 4.50 | $ | 5.17 | ||||||||||
| Weighted-average common shares outstanding: | ||||||||||||||
| Basic | 16,431 | 16,767 | ||||||||||||
| Diluted | 16,545 | 16,767 | ||||||||||||
| Adjusted diluted | 16,545 | 17,040 | ||||||||||||
_______________________________________________________________________________
(1)Adjusted income tax expense is calculated by applying a statutory tax rate of 22% for each of the periods ended March 31, 2023 and 2022.
12
Consolidated EBITDAX
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 share-settled equity-based compensation, depletion, depreciation and amortization, impairment expense, gains or losses on disposal of assets, mark-to-market on derivatives, accretion expense, interest expense, income taxes and other non-recurring income and expenses. Consolidated EBITDAX provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, working capital movement or tax position. Consolidated EBITDAX 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 Consolidated EBITDAX is useful to an investor 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 the Company's capital structure from the Company's operating structure; and
•is used by management for various purposes, including (i) as a measure of operating performance, (ii) as a measure of compliance under the Senior Secured Credit Facility, (iii) in presentations to the board of directors and (iv) as a basis for strategic planning and forecasting.
There are significant limitations to the use of Consolidated EBITDAX 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 Consolidated EBITDAX, or similarly titled measures, reported by different companies. The Company is subject to financial covenants under the Senior Secured Credit Facility, one of which establishes a maximum permitted ratio of Net Debt, as defined in the Senior Secured Credit Facility, to Consolidated EBITDAX. See Note 7 in the 2022 Annual Report for additional discussion of the financial covenants under the Senior Secured Credit Facility. Additional information on Consolidated EBITDAX can be found in the Company's Tenth Amendment to the Senior Secured Credit Facility, as filed with the SEC on November 3, 2022.
The following table presents a reconciliation of net income (loss) (GAAP) to Consolidated EBITDAX (non-GAAP) for the periods presented:
| Three months ended March 31, | ||||||||||||||
| (in thousands) | 2023 | 2022 | ||||||||||||
| (unaudited) | ||||||||||||||
| Net income (loss) | $ | 113,940 | $ | (86,781) | ||||||||||
| Plus: | ||||||||||||||
| Share-settled equity-based compensation, net | 2,572 | 2,053 | ||||||||||||
| Depletion, depreciation and amortization | 86,779 | 73,492 | ||||||||||||
| (Gain) loss on disposal of assets, net | (237) | 260 | ||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||
| (Gain) loss on derivatives, net | (20,490) | 325,816 | ||||||||||||
| Settlements paid for matured derivatives, net | (1,763) | (125,370) | ||||||||||||
| Settlements received for contingent consideration | 1,455 | — | ||||||||||||
| Accretion expense | 899 | 1,019 | ||||||||||||
| Interest expense | 28,554 | 32,477 | ||||||||||||
| Income tax (benefit) expense | 1,607 | (877) | ||||||||||||
| General and administrative (transaction expenses) | 861 | — | ||||||||||||
| Consolidated EBITDAX (non-GAAP) | $ | 214,177 | $ | 222,089 | ||||||||||
13
The following table presents a reconciliation of net cash provided by operating activities (GAAP) to Consolidated EBITDAX (non-GAAP) for the periods presented:
| Three months ended March 31, | ||||||||||||||
| (in thousands) | 2023 | 2022 | ||||||||||||
| (unaudited) | ||||||||||||||
| Net cash provided by operating activities | $ | 116,125 | $ | 170,882 | ||||||||||
| Plus: | ||||||||||||||
| Interest expense | 28,554 | 32,477 | ||||||||||||
| Current income tax expense | 1,331 | 1,218 | ||||||||||||
| Net changes in operating assets and liabilities | 66,756 | 23,224 | ||||||||||||
| General and administrative (transaction expenses) | 861 | — | ||||||||||||
| Settlements received for contingent consideration | 1,455 | — | ||||||||||||
| Other, net | (905) | (5,712) | ||||||||||||
| Consolidated EBITDAX (non-GAAP) | $ | 214,177 | $ | 222,089 | ||||||||||
Investor Contact:
Ron Hagood
918.858.5504
ron.hagood@vitalenergy.com
14
1Q-23 Earnings Presentation EXHIBIT 99.2
Forward-Looking / Cautionary Statements 2 This presentation, including any oral statements made regarding the contents of this presentation, contains forward-looking statements as defined under Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, that address activities that Vital Energy, Inc. (together with its subsidiaries, the “Company”, “Vital” or “VTLE”) 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 Vital Energy include, but are not limited to, continuing and worsening inflationary pressures and associated changes in monetary policy that may cause costs to rise; changes in domestic and global production, supply and demand for commodities, including as a result of the coronavirus ("COVID-19") pandemic, actions by the Organization of Petroleum Exporting Countries and other producing countries ("OPEC+") and the Russian-Ukrainian military conflict, 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, reduced demand due to shifting market perception towards the oil and gas industry; competition in the oil and gas industry; 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, pipeline transportation and storage constraints in the Permian Basin, the effects and duration of the outbreak of disease, such as the COVID-19 pandemic, and any related government policies and actions, long-term performance of wells, drilling and operating risks, the possibility of production curtailment, the impact of new laws and regulations, including those regarding the use of hydraulic fracturing, the impact of legislation or regulatory initiatives intended to address induced seismicity on our ability to conduct our operations; hedging activities, tariffs on steel, 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 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, 2022 and those set forth from time to time in other filings with the Securities and Exchange Commission ("SEC"). Any forward-looking statement speaks only as of the date on which such statement is made. Vital 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 Free Cash Flow and Consolidated EBITDAX. While management believes that such measures are useful for investors, they should not be used as a replacement for financial measures that are in accordance with GAAP. For definitions of such non-GAAP financial measures, please see the Appendix. Unless otherwise specified, references to “average sales price” refer to average sales price excluding the effects of the Company’s derivative transactions. All amounts, dollars and percentages presented in this presentation are rounded and therefore approximate.
3 Exceeded high-end of production guidance for both oil and total production • Production from both base and new wells exceeding expectations • Increased full-year 2023 oil and total production guidance in April 2023 • Proprietary digital solutions providing production uplift through ESP and gas lift runtime improvements Reported incurred capital expenditures below guidance • Inflationary pressures moderating for key products and services • Added four TILs to full-year 2023 through completion efficiencies • Expect full-year 2023 capital expenditures to be at midpoint of guidance range Announced accretive Midland Basin acquisition (Closed April 2023) • 11,200 net acres in Upton and South Reagan counties • Added 30 gross locations Achieved 2025 emissions targets • Disclosed preliminary greenhouse gas and methane intensity levels for 2022 • 2022 Scope 1 GHG intensity of 10.7 metric tons of CO2 equivalent/MBOE versus 2025 target of 12.5 • 2022 methane intensity of 0.10% of natural gas produced versus 2025 target of 0.20% Strong First-Quarter 2023 Performance Oil Production | MBO/d 38.51Q-23 Guidance Range 33.0 – 36.0 Total Production | MBOE/d 80.41Q-23 Guidance Range 72.5 – 76.5 Incurred Capital Expenditures | $MM $1881Q-23 Guidance Range $210 – $230
0 25 50 75 100 125 150 175 200 0 60 120 180 240 300 360 C u m u la ti ve G ro ss O il P ro d u ct io n p e r W e ll (M B O ) Producing Days Disciplined Strategy Underpins Long-Term Value Creation 1See Appendix for definitions of non-GAAP financial measures; 2Gross operated locations as of January 2023; 31Q-23 Actuals ; 4FY-23 estimate; not included in 1Q-23 production 5Production data normalized for 10,000’ lateral length and downtime 4 Maintain Capital Discipline Generate Free Cash Flow1 Reduce Debt and Leverage Target Accretive Transactions Advance Sustainability Integrate Digital Solutions Pure-Play Midland Basin Producer Howard Glasscock Reagan Upton Howard ~31,650 net acres ~40.9 MBoe/d3 ~73% oil W. Glasscock ~38,350 net acres ~10.5 MBoe/d3 ~43% oil E. Glasscock ~32,400 net acres ~4.0 MBoe/d3 ~20% oil Reagan ~60,550 net acres ~24.9 MBoe/d3 ~13% oilUpton / S. Reagan ~11,200 net acres ~2.6 MBoe/d4 ~50% oil VTLE Net Acres Inventory Locations2 ~115Howard ~295W. Glasscock ~35E. Glasscock ~30Upton / S. Reagan ~475Total ~185Upside Strong Well Performance5 Across the Portfolio N. Howard C. Howard W. Glasscock Upton / S. Reagan
Initial Howard County (4Q-19) ~7,400 net acres Initial W. Glasscock (4Q-19) ~4,475 net acres Howard Bolt-On (1Q-20) ~1,100 net acres Howard Bolt-On (4Q-20) ~2,750 net acres Howard County (2Q-21) ~21,000 net acres E. Glasscock / Reagan (2Q-21) WI Divestiture W. Glasscock County (3Q-21) ~20,000 net acres Howard Non-Op Divestiture (3Q-22) ~1,650 net acres Upton / S. Reagan (Driftwood) (1Q-23) ~11,200 net acres Accretive Transactions Driving Company Performance 1See Appendix for definitions of non-GAAP financial measures; 2FY-23E assumes $76 oil / $3.42 gas price for 1Q and $75 oil / $2.50 gas price for remaining year and mid-point of capital guidance; 3Calculation conforms to credit facility covenant which requires various treatment of asset transaction impacts 5 Martin Howard Midland Glasscock Upton Reagan Oil Production Growth | MBO/d E. Glasscock/Reagan Net Acres Acquired Net Acres Oil-Weighted Transactions | 4Q-19 - Current Net Debt to Consolidated EBITDAX1,3 | 0.0x 77% 32% 17% 11% 23% 68% 83% 89% 26.8 31.8 37.9 38.5 FY-20A FY-21A FY-22A 1Q-23A Acquisitions E. Glasscock / Reagan 2.61x 2.14x 1.22x 1.30x FY-20A FY-21A FY-22A 1Q-23A 2019 2020 2021 2022 2023
8.79 9.77 9.84 FY-21A FY-22A 1Q-23A Completed Stages Per Day (Primary Crew) 1,430' 1,530' 1,535' FY-21A FY-22A 1Q-23A Drilling Ft. Per Day Per Rig 9,900' 11,900' 11,600' FY-21A FY-22A 1Q-23A Avg. Completed Lateral Length Continuous Improvement Drives Capital Efficient Program DC&E 81% Facilities & Land 12% Corporate 7% Capital Efficient 2023 Development Program 6 Full Year Capital Program FY-23E Guidance $625 - $675Capital Expenditures | $MM ~2.0Avg. Rig Count | Op ~1.3Avg. Frac Crew | Op ~47 Gross (~42.8 Net)Spuds | Op ~60 Gross (~57.2 Net)Completions | Op ~59 Gross (~56.5 Net)Turn-in-Lines | Op 76.0 – 80.0Total Production | MBOE/d 36.3 – 39.3Oil Production | MBO/d Capital Allocation | FY-23E Operated Development Activity 2 2 2 2 1Q-23A 2Q-23E 3Q-23E 4Q-23E Rig Count | # 2 1 1 1 1Q-23A 2Q-23E 3Q-23E 4Q-23E Frac Crews | # 18 23 8 10 1Q-23A 2Q-23E 3Q-23E 4Q-23E Operated Turn-in-Lines | #
77 Leadership in a Low-Carbon Future OUR ENVIRONMENTAL TARGETS <0.20% METHANE EMISSIONS BY 2025 (AS A PERCENT OF NATURAL GAS PRODUCTION) ZERO ROUTINE FLARING BY 2025 <12.5 MTCO2e/MBOE SCOPE 1 GHG EMISSIONS INTENSITY BY 2025 50% RECYCLED WATER FOR COMPLETION OPERATIONS BY 2025 SCOPE 1 AND 2 GHG EMISSIONS INTENSITY < 10 MTCO2e/MBOE BY 2030 ESG PROGRESS 89% REDUCTION IN METHANE INTENSITY SINCE 2019 59% REDUCTION in SCOPE 1 GHG EMISSIONS INTENSITY SINCE 20191 42% REDUCTION IN ROUTINE FLARING SINCE 2019 FOCUSED SHORT-TERM INCENTIVE PROGRAM SO THAT ENVIRONMENTAL GOALS MAKE UP 20% AND IMPLMENTED A LONG-TERM INCENTIVE PROGRAM METRIC TIED TO ACHIEVING 2025 EMISSIONS REDUCTION GOALS FIRST PERMIAN OPERATOR TO ACHIEVE THE TRUSTWELLTM CERTIFICATION FOR RESPONSIBLE OPERATIONS CONDUCTED FIRST SUPPLIER ESG SURVEY TO BETTER UNDERSTAND THE DIVERSITY OF OUR SUPPLY BASE AND THE ESG POLICIES THEY HAVE IN PLACE INCREASED ACTIVE MANAGEMENT AND HIGH GRADING OF OUR VENDORS BASED ON SAFETY METRICS 43% OF 2021 NEW HIRES WERE DIVERSE CONDUCTED COMPANY-WIDE UNCONSCIOUS BIAS TRAINING INCREASED BOARD GENDER AND ETHNIC DIVERSITY TO 60%, A 270% INCREASE SINCE 2019 CH4 1In 2021, we closed on two acquisitions. The 2019 and 2020 emissions data published in this report has been calculated to include emissions for these acquisitions. Achieved target during 2022
Progress Toward Emissions Targets Demonstrates Continued ESG Leadership 1As a percentage of natural gas produced 8 59% Reduction 2022 Scope 1 GHG Intensity vs. 2019 Baseline 89% Reduction 2022 Methane Intensity1 vs. 2019 Baseline 42% Reduction 2022 Routine Flaring vs. 2019 Baseline Zero Incidents 2022 Employee Total Recordable Incident Rate 2022 ESG Highlights • Achieved two of our three 2025 emission reduction targets in 2022 • 58% reduction in absolute emissions driven by pneumatics and monitoring • 53% reduction in combined Scope 1 & Scope 2 GHG emissions intensity • 1st Permian Basin operator with certified responsibly sourced production • Lowest employee and contractor combined TRIR in Company history 2025 Greenhouse Gas Intensity 26.03 23.13 17.29 10.66 12.5 2025 Target G H G In te n si ty (m tC O 2 e/ M B O E) 2025 Methane Intensity1 0.87% 0.60% 0.32% 0.10% 0.20% 2025 Target M et h an e In te n si ty (M et h an e a s % o f N at u ra l G as P ro d u ce d ) 2025 Elimination of Routine Flaring 867 758 945 500 0.00% 2025 Target R o u ti n e Fl ar in g (M M C F p er Y ea r) 42% Reduction to Date 2030 Greenhouse Gas Intensity 10.0 2030 Target 27 24 19 12 G H G In te n si ty (m tC O 2 e/ M B O E) Scope 1 Scope 2 53% Reduction to Date Target Achieved Target Achieved
0.9x 1.4x VTLE Peer Avg. Compelling Investment Opportunity 1Peer group (PDCE, SM, GRNT, CPE, SWN, CHRD, MUR, CIVI, ERF, BRY, NOG, ROCC, AR, APA, OVV, CNX, MRO, MTDR, CRK, CTRA, EQT, CHK, RRC, DVN, EOG, FANG, COP, TXO, OXY, PXD, DEN, HES); 2Source Capital One Research report as of May 3, 2023; 3See Appendix for definitions of non-GAAP financial measures; 4As of May 5, 2023; 5SEC pricing $90.15 benchmark oil and $5.20 benchmark gas; 6Assumes $76 oil / $3.42 gas price for 1Q and various oil benchmarks / $2.50 gas price for remaining year; 9 Enterprise Value to PDP Value Multiple1,2 YE-22 PV-103 Reserve Value Sensitivity | $MM Enterprise Value to 2024 EBITDA Multiple1,2 FY-23E Consolidated EBITDAX3,6 Sensitivity | $MM $2,221 $2,661 $3,094 $4,142 $410 $665 $928 $1,322 $2,631 $3,325 $4,022 $5,464 $65 $75 $85 SEC Benchmark WTI Oil Price $/Bbo (Benchmark HH Gas Price assumes $3.50/mcf) $750 $825 $900 $960 $65 $75 $85 $95 Benchmark WTI Oil Price $/Bbo (Benchmark HH Gas Price assumes $2.50/mcf) 2.0x 3.7x VTLE Peer Avg. Significant Upside Potential Significant Upside Potential PUD PD TEV4 5
Appendix
2Q-23 & FY-23 Guidance 1Current NGL composition C2 (42%), C3 (33%), IC4 (3%), NC4 (11%) and C5+ (11%) 11 Guidance Commodity Prices Used for 2Q-23 2Q-23 Avg.Jun-23May-23Apr-23 Crude Oil: $73.94$71.18$71.28$79.44WTI NYMEX ($/BBO) $77.87$75.08$75.21$83.41Brent ICE ($/BBO) Natural Gas: $2.08$2.14$2.12$1.99Henry Hub ($/MMBTU) $0.70$0.92$1.09$0.09Waha ($/MMBTU) Natural Gas Liquids: $8.44$8.14$8.35$8.84C2 ($/BBL) $30.29$29.09$27.96$33.91C3 ($/BBL) $36.91$34.44$33.23$43.18IC4 ($/BBL) $35.04$32.87$32.17$40.17NC4 ($/BBL) $61.48$58.07$60.10$66.32C5+ ($/BBL) $25.27$24.05$23.88$27.91Composite ($/BBL)1 FY-232Q-23 Production: 76.0 - 80.085.5 - 88.5Total Production (MBOE/D) 36.3 - 39.340.0 - 43.0Crude Oil Production (MBO/D) $625 - $675$155 - $175Incurred Capital Expenditures ($MM): Average Sales Price Realizations (excluding derivatives): -101%Crude Oil (% of WTI) -18%Natural Gas Liquids (% of WTI) -27%Natural Gas (% of Henry Hub) Net Settlements Received (Paid) for Matured Commodity Derivatives ($MM): -$1Crude Oil ($MM) --Natural Gas Liquids ($MM) -$12Natural Gas ($MM) Operating Costs and Expenses ($/BOE): -$7.50Lease Operating Expenses -7.00%Production and Ad Valorem Taxes (% of Oil, NGL & Natural Gas Revenues) -$1.40Transportation and Marketing Expenses -$2.50General and Administrative Expenses (excluding LTIP & Transaction Expense) -$0.15General and Administrative Expenses (LTIP Cash) -$0.35General and Administrative Expenses (LTIP Non-Cash) -$12.75Depletion, Depreciation and Amortization
65% 55% 47% 63% 0% 50% 100% 2H-23 2Q-23 2H-23 2Q-23 Hedge Book Structured to Maintain Exposure to Higher Prices 1Hedges executed as of May 5, 2023; 2Calculated using guidance mid-point 12 FY-244Q-243Q-242Q-241Q-24FY-234Q-233Q-232Q-23 76171819211,287552552183WTI Swaps C ru d e O il (V o lu m e M B O ; P ri ce $ /B B L) $63.75$63.75$63.75$63.75$63.75$74.27$73.39$73.39$79.62Price -----3,8858919032,092WTI Collars -----$68.75 $69.60 $69.55$68.04 Bought Put -----$85.45 $87.04 $86.98 $84.10 Sold Call 2174952566130192100110WTI Three-Way Collars $50.00 $50.00 $50.00 $50.00$50.00$45.58$45.50$45.59$45.64 Sold Put $66.51$66.45$66.47$66.50$66.57$57.71$57.64$57.72$57.76Bought Put $87.09 $87.05 $87.06 $87.09 $87.14$74.45 $74.25 $74.48$74.58 Sold Call 29366707582458154175129WTI Midland Basis Swaps $0.11$0.12$0.11$0.11$0.11$0.18$0.17$0.18$0.18Price 455,700118,250122,600105,350109,500120,50038,00040,10042,400 Henry Hub Swaps N at u ra l G as ( V o lu m e M M B TU ; P ri ce $ /M M B TU ) $3.29$3.28$3.28$3.30$3.30$2.46$2.46$2.46$2.46Price 776,292149,511169,320214,333243,12820,377,996 6,826,5346,858,8736,692,589 Henry Hub Collars $3.40$3.40$3.44$3.36$3.40$4.11$4.11$4.11$4.11WTD Floor Price $6.11$6.12$6.22$6.00$6.11$8.32 $8.34 $8.33$8.31 WTD Ceiling Price -----140,50033,50035,50071,500Henry Hub Three-Way Collars -----$2.00$2.00$2.00$2.00Sold Put -----$2.50$2.50$2.50$2.50Bought Put -----$3.01$3.01$3.01$3.01Sold Call 4,891,9921,187,7611,211,9201,229,6831,262,62831,638,99610,578,03410,614,47310,446,489Waha Basis Swaps ($0.82)($0.81)($0.82)($0.82)($0.83)($1.53)($1.53)($1.53)($1.53)Price Volumes Hedged2 Crude Oil Natural Gas
Free Cash Flow Driving Return of Capital and Debt Reductions 1As of May 5, 2023 13 Current Debt Maturity Profile1 $456 $255 $745 $298$300 2023 2024 2025 2026 2027 2028 2029 $1.3 billion Borrowing Base (Credit Facility) $1.0 billion Elected Commitments (Credit Facility) $68 million Current Cash Balance1 $813 million Current Liquidity1 9.500% Sr. Notes 2025 10.125% Sr. Notes 2028 7.750% Sr. Notes 2029 Drawn Credit Facility Undrawn Credit Facility
0 25 50 75 100 125 150 175 200 0 60 120 180 240 300 360 C u m u la ti ve G ro ss O il P ro d u ct io n p e r W e ll (M B O ) Producing Days 28%, WC-A 74%, WC-A 35%, LSS 26%, LSS 37%, MS 92 23 N. Howard C. Howard Howard County Development Program 1Gross operated locations as of January 2023 ; 2Production data normalized for 10,000’ lateral length and downtime 14 Development Average Well Performance2 Primary Development Targets VTLE Net Acres Howard North Central Inventory Locations1 LS DEAN MS LSS WC-A JO MILL N. Howard (WC-A / LSS / MS) C. Howard (WC-A / LSS) ~85%~95%Avg. WI ~10,250’~11,000’Avg. LL
0 25 50 75 100 125 150 0 60 120 180 240 300 360 C u m u la ti ve G ro ss O il P ro d u ct io n p e r W e ll (M B O ) Producing Days W. Glasscock County Development Program 1Gross operated locations as of January 2023 ; 2Production data normalized for 10,000’ lateral length and downtime 15 Development Area Average Well Performance2 Primary Development Targets Glasscock Inventory Locations1 DEAN WC-B – Potential Upside Target LSS WC-A WC-D WC-C – Potential Upside Target 46%, WC-D 32%, WC-A 22%, LSS ~295 W. Glasscock ~90%Avg. WI ~11,500’Avg. LL W. Glasscock (WC-A / LSS / WC-D) W. Glasscock VTLE Net Acres
0 25 50 75 100 125 150 175 0 60 120 180 240 300 360 C u m u la ti ve G ro ss O il P ro d u ct io n p e r W e ll (M B O ) Producing Days Upton / S. Reagan County Development Program 1Gross operated locations as of January 2023 ; 2Production data normalized for 10,000’ lateral length and downtime 16 Development Area Average Well Performance2 Primary Development Targets Reagan Inventory Locations1 DEAN WC-B 100%, WC-B ~30 Upton / S. Reagan ~75%Avg. WI ~10,000’Avg. LL Upton / S. Reagan (WC-B) LSS – Potential Upside Target WC-A – Potential Upside Target WC-C UPPER LOWER Upton VTLE Net Acres Upton / S. Reagan
0 25 50 75 100 125 150 0 60 120 180 240 300 360 C u m u la ti ve G ro ss O il P ro d u ct io n p e r W e ll (M B O ) Producing Days Wolfcamp D in Glasscock County Extends Oil-Weighted Inventory 1Production data normalized for 10,000’ lateral length, downtime and completion design > 1,500 #/ft 17 Average Well Performance by Completion Design1 Wolfcamp D Producing Wells W. Glasscock E. Glasscock Organically added ~80 oil-weighted Wolfcamp D locations in Glasscock County VTLE W. Glasscock > 1,500 #/ft VTLE E. Glasscock > 1,500 #/ft VTLE < 1,500 #/ft VTLE Leasehold VTLE W. Glasscock > 1,500 #/ft VTLE E. Glasscock > 1,500 #/ft VTLE < 1,500 #/ft Industry Activity
Proved Reserves Underpin Company Value 1Based only on wells categorized as Proved Developed as of YE-22 and decline calculated 4Q to 4Q 18 Proved Reserves Components | YE-22 Annual Base Production Decline Expecatations1 Total Proved Reserves | MMBOE PD 74% PUD 26% FY-25FY-24FY-23 23%33%46% Oil, MBO/d Howard 19%27%41%Total Company 22%31%41% Total Production, MBOE/d Howard 15%20%29%Total Company Oil 39% NGL 31% Natural Gas 30% 319 302 17 (4) (30) YE-21 Revisions & Extensions Sale Of Reserves 2022 Production YE-22
Supplemental Non-GAAP Financial Measures 1Includes capitalized share-settled equity-based compensation and asset retirement costs 19 Free Cash Flow Free Cash Flow is a non-GAAP financial measure that the Company defines as net cash provided by operating activities (GAAP) before net changes in operating assets and liabilities and non-budgeted acquisition costs, 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 March 31, 20222023(in thousands, unaudited) $170,882$116,125Net cash provided by operating activities Less: (23,224)(66,756)Net changes in operating assets and liabilities —(861)General and administrative (transaction expenses) 194,106183,742Cash flows from operating activities before changes in operating assets and liabilities and non-budgeted acquisition costs Less incurred capital expenditures, excluding non-budgeted acquisition costs: 168,368184,114Oil and natural gas properties(1) 2,5313,530Midstream and other fixed assets(1) 170,899187,644Total incurred capital expenditures, excluding non-budgeted acquisition costs $23,207($3,902) Free Cash Flow (non-GAAP)
Supplemental Non-GAAP Financial Measures 20 Consolidated EBITDAX 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 share-settled equity-based compensation, depletion, depreciation and amortization, impairment expense, gains or losses on disposal of assets, mark-to-market on derivatives, accretion expense, interest expense, income taxes and other non-recurring income and expenses. Consolidated EBITDAX provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, working capital movement or tax position. Consolidated EBITDAX 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 Consolidated EBITDAX is useful to an investor 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 the Company's capital structure from the Company's operating structure; and • is used by management for various purposes, including (i) as a measure of operating performance, (ii) as a measure of compliance under the Senior Secured Credit Facility, (iii) in presentations to the board of directors and (iv) as a basis for strategic planning and forecasting. There are significant limitations to the use of Consolidated EBITDAX 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 Consolidated EBITDAX, or similarly titled measures, reported by different companies. The Company is subject to financial covenants under the Senior Secured Credit Facility, one of which establishes a maximum permitted ratio of Net Debt, as defined in the Senior Secured Credit Facility, to Consolidated EBITDAX. See Note 7 in the 2022 Annual Report for additional discussion of the financial covenants under the Senior Secured Credit Facility. Additional information on Consolidated EBITDAX can be found in the Company's Tenth Amendment to the Senior Secured Credit Facility, as filed with the SEC on November 3, 2022.
Supplemental Non-GAAP Financial Measures 1 Calculation conforms to credit facility covenant which requires various treatment of asset transaction impacts 21 Consolidated EBITDAX The following table presents a reconciliation of net income (loss) (GAAP) to Consolidated EBITDAX (non-GAAP) for the periods presented: Trailing Twelve Months ended March 31, Three Months Ended March 31, 202320222023(in thousands, unaudited) $832,233($86,781)$113,940Net income (loss) Plus: 8,9222,0532,572Share-settled equity-based compensation 324,92773,49286,779Depletion, depreciation and amortization 40——Impairment expense 10,420——Organizational restructuring expenses 582260(237)(Gain) loss on disposal of assets, net Mark-to-market on derivatives: (47,583)325,816(20,490)(Gain) loss on derivatives, net (363,146)(125,370)(1,763)Settlements paid for matured derivatives, net 3,912—1,455Settlements received for contingent consideration 3,7591,019899Accretion expense 121,19832,47728,554Interest expense 1,459——Loss on extinguishment of debt, net 7,986(877)1,607Income tax (benefit) expense 861—861General and administrative (transaction expenses) $905,570$222,089$214,177Consolidated EBITDAX (non-GAAP) (21,562)Transaction adjustments (Senior Secured Credit Facility covenant compliance)1 $884,008Consolidated EBITDAX (non-GAAP) (Senior Secured Credit Facility covenant compliance)1
Supplemental Non-GAAP Financial Measures 22 Consolidated EBITDAX The following table presents a reconciliation of net cash provided by operating activities (GAAP) to Consolidated EBITDAX (non-GAAP) for the periods presented: Three Months Ended March 31, 20222023(in thousands, unaudited) $170,882$116,125Net cash provided by operating activities Plus: 32,47728,554Interest expense 1,2181,331Current income tax expense 23,22466,756Net changes in operating assets and liabilities —861General and administrative (transaction expenses) —1,455Settlements received for contingent consideration (5,712)(905)Other, net $222,089$214,177Consolidated EBITDAX (non-GAAP)
Supplemental Non-GAAP Financial Measures 23 Net Debt Net Debt is a non-GAAP financial measure defined in the Company’s Senior Secured Credit Facility as the face value of long-term debt plus any outstanding letters of credit, less cash and cash equivalents, where cash and cash equivalents are capped at $50 million when there are borrowings on the Senior Secured Credit Facility. Management believes Net Debt is useful to management and investors in determining the Company’s leverage position since the Company has the ability, and may decide, to use a portion of its cash and cash equivalents to reduce debt. Net Debt to Consolidated EBITDAX 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. As of March 31, 20222023(in thousands, unaudited) $1,338,957$1,054,151Total senior unsecured notes 100,000120,000Senior Secured Credit Facility 44,115—Letters of credit 1,483,0721,174,151Total long-term debt Less: 50,00027,682Cash and cash equivalents $1,433,072$1,146,469Net Debt (non-GAAP)
Supplemental Non-GAAP Financial Measures 24 PV-10 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. December 31, 2022(in millions) $4,755Standardized measure of discounted future net cash flows (709) Less present value of future income taxes discounted at 10% $5,464 PV-10 (non-GAAP)