UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT PURSUANT TO
SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Date of report (Date of earliest event reported): February 21, 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 February 21, 2023, Vital Energy, Inc. (the "Company") announced its financial and operating results for the quarter and year ended December 31, 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 February 21, 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 February 21, 2023, the Company also posted to its website an investor presentation (the "Presentation"). The Presentation is available on the Company's website, www.vitalenergy.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, its Annual Report on Form 10-K for the year ended December 31, 2022, to be filed with the SEC, and the Company's other filings with the SEC for a discussion of other risks and uncertainties. The Company disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
In accordance with General Instruction B.2 of 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: February 21, 2023 | By: | /s/ Bryan J. Lemmerman | ||||||
| Bryan J. Lemmerman | ||||||||
| Senior Vice President and Chief Financial Officer | ||||||||
EXHIBIT 99.1
Vital Energy Announces Fourth-Quarter 2022 Financial and Operating Results
Company Issues 2023 Outlook; Plans to Invest $625 - $675 Million
TULSA, OK - February 21, 2023 - Vital Energy, Inc. (NYSE: VTLE) ("Vital Energy" or the "Company") today announced its fourth-quarter 2022 financial and operating results and provided its 2023 outlook. 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, February 22, 2023. Complete details can be found within this release.
Financial Highlights
•Reported 4Q-22 and Company-record FY-22 net income of $118.2 million and $631.5 million, respectively
•Reported 4Q-22 and Company-record FY-22 cash flows from operating activities of $108.9 million and $829.6 million, respectively
•Generated 4Q-22 and Company-record FY-22 Consolidated EBITDAX1 of $191.1 million and $913.5 million, respectively
•Generated 4Q-22 and Company-record FY-22 Free Cash Flow1 of $36.5 million and $219.9 million, respectively
•Divested certain non-operated properties for ~$110 million
•Repurchased $284.8 million face value of term-debt at 99.3% of par value during FY-22
•Repurchased $37.3 million of common stock at an average price of $76.02 per share during FY-22
•Reduced Net Debt1/Consolidated EBITDAX1 ratio to 1.18x from 2.14x at year-end 2021
Operational Highlights
•Produced 35.9 thousand barrels of oil per day ("MBO/d") and 77.9 thousand barrels of oil equivalent per day ("MBOE/d") in 4Q-22, both above the high-end of guidance
•Incurred capital expenditures of $130 million, excluding non-budgeted acquisitions and leasehold expenditures, in 4Q-22, below guidance range
•Grew 2022 oil production 19% over prior year, primarily related to the acquisition and development of oil-weighted properties
•Maintained approximately eight years of oil-weighted inventory at current activity levels, organically adding locations in Glasscock County
•Published 2022 ESG and Climate Risk Report, reporting Scope 1 GHG emissions intensity and methane intensity reductions of 34% and 63%, respectively, compared to 2019 baseline levels
1Non-GAAP financial measure; please see supplemental reconciliations of GAAP to non-GAAP financial measures at the end of this release.
"Our strong financial performance in 2022 was a direct result of the execution of our strategy to create shareholder value by acquiring and developing oil-weighted properties," commented Jason Pigott, President and Chief Executive Officer. "The assets we acquired since 2019 enabled Vital Energy to capitalize on higher oil prices, drive higher margins, and generate $220 million in Free Cash Flow in 2022. We utilized our Free Cash Flow and divestiture proceeds to reduce term-debt by $285 million and repurchase $37 million of common stock while cutting our leverage ratio almost in half."
"We enter 2023 positioned to build on our recent momentum," continued Pigott. "Both production and capital outperformed expectations in the fourth quarter of 2022 and our 2023 development plan is focused on our top-tier assets in northern Howard County. We recently announced an accretive oil-weighted acquisition that expands our Midland Basin footprint into a prolific area of Upton County, adding additional high-margin production and inventory. Our disciplined development and acquisition strategies have delivered improved financial results and a strengthened balance sheet, laying the foundation for sustainable Free Cash Flow generation and shareholder returns."
Fourth-Quarter 2022 Financial and Operations Summary
Financial Results. The Company reported net income attributable to common stockholders of $118.2 million, or $7.13 per diluted share. Adjusted Net Income1 was $57.8 million, or $3.49 per adjusted diluted share. Consolidated EBITDAX was $191.1 million.
Production. Consistent with preliminary volumes disclosed in early January, Vital Energy's oil and total production during the period averaged 35,887 BO/d and 77,947 BOE/d, respectively. Both oil and total production in fourth-quarter 2022 were above the top-end of Company guidance, driven by outperformance from its base production and the productivity of new wells, as well as less than expected downtime related to offset-operator completions.
Capital Investments. Total incurred capital expenditures were $130 million, excluding non-budgeted acquisitions and leasehold expenditures, below the low-end of guidance as inflationary pressures moderated. Investments included $112 million in drilling and completions, $6 million in infrastructure, including Vital Midstream Services investments, $7 million in other capitalized costs and $5 million in land, exploration and data related costs. Non-budgeted acquisitions and leasehold expenditures (including surface land) totaled $2 million. Vital Energy completed and turned-in-line ("TIL") 13 wells during fourth-quarter 2022.
Operating Expenses. Lease operating expenses ("LOE") during the period were $6.53 per BOE, in line with guidance.
General and Administrative Expenses. General and administrative ("G&A") expenses, excluding long-term incentive plan ("LTIP") expenses, for fourth-quarter 2022 were $2.20 per BOE. Cash and non-cash LTIP expenses were $(0.04) per BOE and $0.25 per BOE, respectively. Cash LTIP expense was below guidance due to the stock price decline in fourth-quarter 2022.
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Liquidity. At December 31, 2022, the Company had $70 million drawn on its $1.0 billion senior secured credit facility and cash and cash equivalents of $44 million. At February 17, 2023, the Company had $135 million drawn on its senior secured credit facility and cash and cash equivalents of $16 million.
2023 Outlook
Capital Investments. The 2023 outlook reflects the Company's ongoing focus on capital discipline and maximizing Free Cash Flow. Vital Energy plans to invest $625 - $675 million in 2023, maintaining relatively flat year-over-year activity levels. The Company has estimated cost inflation of approximately 15% over 2022 averages.
Vital Energy expects to operate two drilling rigs throughout the year, two completions crews for the first quarter and one completions crew for the remaining nine months of 2023. The Company's capital plan in 2023 remains focused primarily on high-return projects in Howard County. All ~55 development wells Vital Energy expects to TIL in 2023 are anticipated to be in Howard County.
Production. The Company's activities are expected to result in full-year 2023 oil production of 34.0 - 37.0 MBO/d and total production of 72.0 - 76.0 MBOE/d. Production expectations exclude volumes associated with the Company's recently announced acquisition of producing properties (see below).
Driftwood Acquisition. On February 14, 2023, Vital Energy announced the acquisition of oil-weighted production and inventory from Driftwood Energy for consideration of ~1.58 million shares of Vital Energy common stock and $127.6 million in cash. Upon closing, which is expected in early April 2023, Vital Energy does not anticipate any changes to its activity levels or capital budget. The Company plans to update FY-23 guidance post-closing of the acquisition.
"Our disciplined 2023 investment plan focuses on maximizing Free Cash Flow by concentrating development on our most capital-efficient leasehold," commented Pigott. "This plan holds full-year 2023 average oil production relatively flat with fourth-quarter 2022 levels with no increase in prior-year activity levels. Upon closing of the Driftwood acquisition, we expect to incorporate any activity on the acquired leasehold within our current plan. The Driftwood acquisition furthers our strategy of making accretive acquisitions that extend oil-weighted inventory and grow production without increasing activity levels."
Oil-Weighted Inventory
Vital Energy continues to focus on the strategic acquisition and development of oil-weighted inventory to improve capital efficiency and Free Cash Flow generation. As of year-end 2022, the Company had ~445 high-quality, development ready locations in the Midland Basin with an average breakeven WTI oil price of <$60 per barrel at 2022 average well costs. In 2022, Vital Energy organically replaced a majority of wells developed during the year, adding ~35 oil-weighted locations.
2022 Proved Reserves
Vital Energy's total proved reserves were 302.3 MMBOE (39% oil, 74% developed) at year-end 2022. The standardized measure of discounted net cash flows was $4.8 billion based on SEC benchmark pricing of $90.15 per
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barrel for oil and $5.20 per MMBtu for natural gas. The PV-10 value was $5.5 billion, utilizing the same benchmark prices.
Proved reserves decreased 16.3 MMBOE from year-end 2021. The decrease is primarily related to forecast revisions of producing wells in the Company's legacy acreage, changes in the development schedule and the divestiture of non-operated properties.
Commitment to ESG
A strong commitment to ESG excellence is a core operating principle of Vital Energy. This commitment is reflected in the board of directors' oversight of programs and policies related to ESG matters and the Company's annual publication of its ESG and Climate Risk Report utilizing standards aligned with five different reporting frameworks. In the Company's 2022 ESG and Climate Risk Report, Vital Energy demonstrated substantial progress towards its 2025 emissions intensity goal of 12.5 metric tons of CO2 equivalent per MBOE produced ("mtCO2/MBOE"), reporting 2021 Scope 1 emissions intensity of 17.26 mtCO2/MBOE. The Company also introduced a 2030 combined Scope 1 & 2 emissions intensity goal of 10.0 mtCO2/MBOE.
Additionally, Vital Energy has incorporated a combination of environmental and safety metrics into executive compensation for four consecutive years, demonstrating the importance of operating sustainably and prioritizing the health of our employees and contractors. In 2022, environmental and safety goals comprised 20% of the executive short-term incentive plan goals. Significantly, in 2022, Vital Energy reported zero employee incidents.
First-Quarter and Full-Year 2023 Guidance
The table below reflects the Company's guidance for total and oil production and incurred capital expenditures for first-quarter and full-year 2023. Production guidance does not include volumes associated with the recently announced acquisition.
| 1Q-23E | FY-23E | |||||||||||||
| Total production (MBOE per day) | 72.5 - 76.5 | 72.0 - 76.0 | ||||||||||||
| Oil production (MBOPD) | 33.0 - 36.0 | 34.0 - 37.0 | ||||||||||||
| Incurred capital expenditures, excluding non-budgeted acquisitions ($ MM) | $210 - $230 | $625 - $675 | ||||||||||||
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The table below reflects the Company's guidance for select revenue and expense items for first-quarter 2023.
| 1Q-23E | ||||||||
| Average sales price realizations (excluding derivatives): | ||||||||
| Oil (% of WTI) | 102% | |||||||
| NGL (% of WTI) | 24% | |||||||
| Natural gas (% of Henry Hub) | 51% | |||||||
| Net settlements received (paid) for matured commodity derivatives ($ MM): | ||||||||
| Oil | ($1) | |||||||
| NGL | $0 | |||||||
| Natural gas | ($2) | |||||||
| Selected average costs & expenses: | ||||||||
| Lease operating expenses ($/BOE) | $7.50 | |||||||
| Production and ad valorem taxes (% of oil, NGL and natural gas sales revenues) | 7.50% | |||||||
| Transportation and marketing expenses ($/BOE) | $1.70 | |||||||
| General and administrative expenses (excluding LTIP, $/BOE) | $2.40 | |||||||
| General and administrative expenses (LTIP cash, $/BOE) | $0.25 | |||||||
| General and administrative expenses (LTIP non-cash, $/BOE) | $0.30 | |||||||
| Depletion, depreciation and amortization ($/BOE) | $12.25 | |||||||
Conference Call Details
Vital Energy plans to host a conference call at 7:30 a.m. CT on Wednesday, February 22, 2023, to discuss its fourth-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 5063785. 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
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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 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
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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 Consolidated EBITDAX, 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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Vital Energy, Inc.
Selected operating data
| Three months ended December 31, | Year ended December 31, | |||||||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | |||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Sales volumes: | ||||||||||||||||||||||||||
| Oil (MBbl) | 3,302 | 3,779 | 13,838 | 11,619 | ||||||||||||||||||||||
| NGL (MBbl) | 1,900 | 1,976 | 8,028 | 8,678 | ||||||||||||||||||||||
| Natural gas (MMcf) | 11,812 | 12,516 | 49,259 | 57,175 | ||||||||||||||||||||||
Oil equivalents (MBOE)(1)(2) | 7,171 | 7,842 | 30,076 | 29,827 | ||||||||||||||||||||||
Average daily oil equivalent sales volumes (BOE/D)(2) | 77,947 | 85,240 | 82,400 | 81,717 | ||||||||||||||||||||||
Average daily oil sales volumes (Bbl/D)(2) | 35,887 | 41,080 | 37,912 | 31,833 | ||||||||||||||||||||||
Average sales prices(2): | ||||||||||||||||||||||||||
Oil ($/Bbl)(3) | $ | 85.31 | $ | 76.92 | $ | 97.65 | $ | 69.32 | ||||||||||||||||||
NGL ($/Bbl)(3) | $ | 19.77 | $ | 29.58 | $ | 29.22 | $ | 22.08 | ||||||||||||||||||
Natural gas ($/Mcf)(3) | $ | 2.50 | $ | 4.15 | $ | 4.23 | $ | 2.63 | ||||||||||||||||||
Average sales price ($/BOE)(3) | $ | 48.64 | $ | 51.15 | $ | 59.66 | $ | 38.46 | ||||||||||||||||||
Oil, with commodity derivatives ($/Bbl)(4) | $ | 68.03 | $ | 57.83 | $ | 70.32 | $ | 52.09 | ||||||||||||||||||
NGL, with commodity derivatives ($/Bbl)(4) | $ | 19.01 | $ | 11.07 | $ | 24.29 | $ | 10.55 | ||||||||||||||||||
Natural gas, with commodity derivatives ($/Mcf)(4) | $ | 2.14 | $ | 1.69 | $ | 2.83 | $ | 1.56 | ||||||||||||||||||
Average sales price, with commodity derivatives ($/BOE)(4) | $ | 39.88 | $ | 33.36 | $ | 43.48 | $ | 26.36 | ||||||||||||||||||
Selected average costs and expenses per BOE sold(2): | ||||||||||||||||||||||||||
| Lease operating expenses | $ | 6.53 | $ | 4.27 | $ | 5.78 | $ | 3.42 | ||||||||||||||||||
| Production and ad valorem taxes | 3.00 | 2.91 | 3.69 | 2.30 | ||||||||||||||||||||||
| Transportation and marketing expenses | 2.05 | 1.71 | 1.79 | 1.61 | ||||||||||||||||||||||
| General and administrative (excluding LTIP) | 2.20 | 1.58 | 1.91 | 1.54 | ||||||||||||||||||||||
| Total selected operating expenses | $ | 13.78 | $ | 10.47 | $ | 13.17 | $ | 8.87 | ||||||||||||||||||
| General and administrative (LTIP): | ||||||||||||||||||||||||||
| LTIP cash | $ | (0.04) | $ | (0.08) | $ | 0.11 | $ | 0.35 | ||||||||||||||||||
| LTIP non-cash | $ | 0.25 | $ | 0.23 | $ | 0.24 | $ | 0.22 | ||||||||||||||||||
| Depletion, depreciation and amortization | $ | 11.86 | $ | 9.51 | $ | 10.36 | $ | 7.22 | ||||||||||||||||||
(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 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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Vital Energy, Inc.
Consolidated balance sheets
| (in thousands, except share data) | December 31, 2022 | December 31, 2021 | ||||||||||||
| (unaudited) | ||||||||||||||
| Assets | ||||||||||||||
| Current assets: | ||||||||||||||
| Cash and cash equivalents | $ | 44,435 | $ | 56,798 | ||||||||||
| Accounts receivable, net | 163,369 | 151,807 | ||||||||||||
| Derivatives | 24,670 | 4,346 | ||||||||||||
| Other current assets | 13,317 | 22,906 | ||||||||||||
| Total current assets | 245,791 | 235,857 | ||||||||||||
| Property and equipment: | ||||||||||||||
| Oil and natural gas properties, full cost method: | ||||||||||||||
| Evaluated properties | 9,554,706 | 8,968,668 | ||||||||||||
| Unevaluated properties not being depleted | 46,430 | 170,033 | ||||||||||||
| Less: accumulated depletion and impairment | (7,318,399) | (7,019,670) | ||||||||||||
| Oil and natural gas properties, net | 2,282,737 | 2,119,031 | ||||||||||||
| Midstream service assets, net | 85,156 | 96,528 | ||||||||||||
| Other fixed assets, net | 42,647 | 34,590 | ||||||||||||
| Property and equipment, net | 2,410,540 | 2,250,149 | ||||||||||||
| Derivatives | 24,363 | 32,963 | ||||||||||||
| Operating lease right-of-use assets | 23,047 | 11,514 | ||||||||||||
| Other noncurrent assets, net | 22,373 | 21,341 | ||||||||||||
| Total assets | $ | 2,726,114 | $ | 2,551,824 | ||||||||||
| Liabilities and stockholders' equity | ||||||||||||||
| Current liabilities: | ||||||||||||||
| Accounts payable and accrued liabilities | $ | 102,516 | $ | 71,386 | ||||||||||
| Accrued capital expenditures | 48,378 | 50,585 | ||||||||||||
| Undistributed revenue and royalties | 160,023 | 117,920 | ||||||||||||
| Derivatives | 5,960 | 179,809 | ||||||||||||
| Operating lease liabilities | 15,449 | 7,742 | ||||||||||||
| Other current liabilities | 82,950 | 99,471 | ||||||||||||
| Total current liabilities | 415,276 | 526,913 | ||||||||||||
| Long-term debt, net | 1,113,023 | 1,425,858 | ||||||||||||
| Asset retirement obligations | 70,366 | 69,057 | ||||||||||||
| Operating lease liabilities | 9,435 | 5,726 | ||||||||||||
| Other noncurrent liabilities | 7,268 | 10,490 | ||||||||||||
| Total liabilities | 1,615,368 | 2,038,044 | ||||||||||||
| Commitments and contingencies | ||||||||||||||
| Stockholders' equity: | ||||||||||||||
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of December 31, 2022 and December 31, 2021 | — | — | ||||||||||||
Common stock, $0.01 par value, 40,000,000 and 22,500,000 shares authorized, and 16,762,127 and 17,074,516 issued and outstanding as of December 31, 2022 and December 31, 2021, respectively | 168 | 171 | ||||||||||||
| Additional paid-in capital | 2,754,085 | 2,788,628 | ||||||||||||
| Accumulated deficit | (1,643,507) | (2,275,019) | ||||||||||||
| Total stockholders' equity | 1,110,746 | 513,780 | ||||||||||||
| Total liabilities and stockholders' equity | $ | 2,726,114 | $ | 2,551,824 | ||||||||||
9
Vital Energy, Inc.
Consolidated statements of operations
| Three months ended December 31, | Year ended December 31, | |||||||||||||||||||||||||
| (in thousands, except per share data) | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Revenues: | ||||||||||||||||||||||||||
| Oil sales | $ | 281,665 | $ | 290,696 | $ | 1,351,207 | $ | 805,448 | ||||||||||||||||||
| NGL sales | 37,576 | 58,470 | 234,613 | 191,591 | ||||||||||||||||||||||
| Natural gas sales | 29,528 | 51,918 | 208,554 | 150,104 | ||||||||||||||||||||||
| Sales of purchased oil | 13,378 | 66,803 | 119,408 | 240,303 | ||||||||||||||||||||||
| Other operating revenues | 1,984 | 2,337 | 7,014 | 6,629 | ||||||||||||||||||||||
| Total revenues | 364,131 | 470,224 | 1,920,796 | 1,394,075 | ||||||||||||||||||||||
| Costs and expenses: | ||||||||||||||||||||||||||
| Lease operating expenses | 46,847 | 33,468 | 173,983 | 101,994 | ||||||||||||||||||||||
| Production and ad valorem taxes | 21,485 | 22,785 | 110,997 | 68,742 | ||||||||||||||||||||||
| Transportation and marketing expenses | 14,670 | 13,439 | 53,692 | 47,916 | ||||||||||||||||||||||
| Costs of purchased oil | 13,602 | 67,603 | 122,118 | 251,061 | ||||||||||||||||||||||
| General and administrative | 17,282 | 13,619 | 68,082 | 62,801 | ||||||||||||||||||||||
| Organizational restructuring expenses | — | — | 10,420 | 9,800 | ||||||||||||||||||||||
| Depletion, depreciation and amortization | 85,085 | 74,592 | 311,640 | 215,355 | ||||||||||||||||||||||
| Impairment expense | 40 | — | 40 | 1,613 | ||||||||||||||||||||||
| Other operating expenses, net | 1,829 | 1,341 | 8,583 | 6,381 | ||||||||||||||||||||||
| Total costs and expenses | 200,840 | 226,847 | 859,555 | 765,663 | ||||||||||||||||||||||
| Gain (loss) on disposal of assets, net | (6,031) | (8,903) | (1,079) | 84,551 | ||||||||||||||||||||||
| Operating income | 157,260 | 234,474 | 1,060,162 | 712,963 | ||||||||||||||||||||||
| Non-operating income (expense): | ||||||||||||||||||||||||||
| Gain (loss) on derivatives, net | (7,728) | 15,372 | (298,723) | (452,175) | ||||||||||||||||||||||
| Interest expense | (28,870) | (31,163) | (125,121) | (113,385) | ||||||||||||||||||||||
| Loss extinguishment of debt, net | (1,214) | — | (1,459) | — | ||||||||||||||||||||||
| Other income, net | 1,831 | 645 | 2,155 | 1,250 | ||||||||||||||||||||||
| Total non-operating expense, net | (35,981) | (15,146) | (423,148) | (564,310) | ||||||||||||||||||||||
| Income before income taxes | 121,279 | 219,328 | 637,014 | 148,653 | ||||||||||||||||||||||
| Income tax (expense) benefit: | ||||||||||||||||||||||||||
| Current | (1,350) | (24) | (6,121) | (1,324) | ||||||||||||||||||||||
| Deferred | (1,705) | (3,028) | 619 | (2,321) | ||||||||||||||||||||||
| Total income tax expense | (3,055) | (3,052) | (5,502) | (3,645) | ||||||||||||||||||||||
| Net income | $ | 118,224 | $ | 216,276 | $ | 631,512 | $ | 145,008 | ||||||||||||||||||
| Net income per common share: | ||||||||||||||||||||||||||
| Basic | $ | 7.19 | $ | 13.07 | $ | 37.88 | $ | 10.18 | ||||||||||||||||||
| Diluted | $ | 7.13 | $ | 12.84 | $ | 37.44 | $ | 10.03 | ||||||||||||||||||
| Weighted-average common shares outstanding: | ||||||||||||||||||||||||||
| Basic | 16,441 | 16,545 | 16,672 | 14,240 | ||||||||||||||||||||||
| Diluted | 16,585 | 16,846 | 16,867 | 14,464 | ||||||||||||||||||||||
10
Vital Energy, Inc.
Consolidated statements of cash flows
| Three months ended December 31, | Year ended December 31, | |||||||||||||||||||||||||
| (in thousands) | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Cash flows from operating activities: | ||||||||||||||||||||||||||
| Net income | $ | 118,224 | $ | 216,276 | $ | 631,512 | $ | 145,008 | ||||||||||||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||||||||||||||||
| Share-settled equity-based compensation, net | 2,108 | 2,066 | 8,403 | 7,675 | ||||||||||||||||||||||
| Depletion, depreciation and amortization | 85,085 | 74,592 | 311,640 | 215,355 | ||||||||||||||||||||||
| Impairment expense | 40 | — | 40 | 1,613 | ||||||||||||||||||||||
| (Gain) loss on disposal of assets, net | 6,031 | 8,903 | 1,079 | (84,551) | ||||||||||||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||||||||||||||
| (Gain) loss on derivatives, net | 7,728 | (15,372) | 298,723 | 452,175 | ||||||||||||||||||||||
| Settlements paid for matured derivatives, net | (62,505) | (129,361) | (486,173) | (320,868) | ||||||||||||||||||||||
| Premiums received for commodity derivatives | — | — | — | 9,041 | ||||||||||||||||||||||
| Amortization of debt issuance costs | 1,529 | 1,538 | 6,338 | 5,146 | ||||||||||||||||||||||
| Amortization of operating lease right-of-use assets | 6,098 | 3,702 | 22,621 | 13,609 | ||||||||||||||||||||||
| Loss on extinguishment of debt, net | 1,214 | — | 1,459 | — | ||||||||||||||||||||||
| Deferred income tax expense (benefit) | 1,705 | 3,028 | (619) | 2,321 | ||||||||||||||||||||||
| Other, net | 894 | 1,274 | 5,494 | 4,633 | ||||||||||||||||||||||
| Changes in operating assets and liabilities: | ||||||||||||||||||||||||||
| Accounts receivable, net | 1,843 | (29,150) | (9,226) | (87,831) | ||||||||||||||||||||||
| Other current assets | 796 | (5,741) | 8,370 | (8,767) | ||||||||||||||||||||||
| Other noncurrent assets, net | 387 | 21,503 | 1,837 | (8,782) | ||||||||||||||||||||||
| Accounts payable and accrued liabilities | 16,450 | 10,045 | 31,534 | 31,387 | ||||||||||||||||||||||
| Undistributed revenue and royalties | (89,271) | 24,933 | 42,085 | 81,201 | ||||||||||||||||||||||
| Other current liabilities | 22,859 | 22,128 | (18,503) | 33,331 | ||||||||||||||||||||||
| Other noncurrent liabilities | (12,297) | (805) | (26,994) | 4,975 | ||||||||||||||||||||||
| Net cash provided by operating activities | 108,918 | 209,559 | 829,620 | 496,671 | ||||||||||||||||||||||
| Cash flows from investing activities: | ||||||||||||||||||||||||||
| Acquisitions of oil and natural gas properties, net | — | (136,367) | (5,581) | (763,411) | ||||||||||||||||||||||
| Capital expenditures: | ||||||||||||||||||||||||||
| Oil and natural gas properties | (134,865) | (139,515) | (566,989) | (418,362) | ||||||||||||||||||||||
| Midstream service assets | (273) | (474) | (1,436) | (2,849) | ||||||||||||||||||||||
| Other fixed assets | (3,610) | (2,705) | (12,711) | (5,931) | ||||||||||||||||||||||
| Proceeds from dispositions of capital assets, net of selling costs | 105,949 | — | 108,888 | 393,742 | ||||||||||||||||||||||
| Settlements received for contingent consideration | 322 | — | 1,877 | — | ||||||||||||||||||||||
| Net cash used in investing activities | (32,477) | (279,061) | (475,952) | (796,811) | ||||||||||||||||||||||
| Cash flows from financing activities: | ||||||||||||||||||||||||||
| Borrowings on Senior Secured Credit Facility | 120,000 | 145,000 | 455,000 | 570,000 | ||||||||||||||||||||||
| Payments on Senior Secured Credit Facility | (90,000) | (70,000) | (490,000) | (720,000) | ||||||||||||||||||||||
| Issuance of July 2029 Notes | — | — | — | 400,000 | ||||||||||||||||||||||
| Extinguishment of debt | (100,583) | — | (282,902) | — | ||||||||||||||||||||||
| Proceeds from issuance of common stock, net of offering costs | — | — | — | 72,492 | ||||||||||||||||||||||
| Share repurchases | (10,704) | — | (37,290) | — | ||||||||||||||||||||||
| Stock exchanged for tax withholding | — | (7) | (7,442) | (2,596) | ||||||||||||||||||||||
| Payments for debt issuance costs | (213) | (89) | (1,938) | (14,686) | ||||||||||||||||||||||
| Other, net | (447) | — | (1,459) | 2,971 | ||||||||||||||||||||||
| Net cash (used in) provided by financing activities | (81,947) | 74,904 | (366,031) | 308,181 | ||||||||||||||||||||||
| Net (decrease) increase in cash and cash equivalents | (5,506) | 5,402 | (12,363) | 8,041 | ||||||||||||||||||||||
| Cash and cash equivalents, beginning of period | 49,941 | 51,396 | 56,798 | 48,757 | ||||||||||||||||||||||
| Cash and cash equivalents, end of period | $ | 44,435 | $ | 56,798 | $ | 44,435 | $ | 56,798 | ||||||||||||||||||
11
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, PV-10, 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 December 31, | Year ended December 31, | |||||||||||||||||||||||||
| (in thousands) | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Net cash provided by operating activities | $ | 108,918 | $ | 209,559 | $ | 829,620 | $ | 496,671 | ||||||||||||||||||
| Less: | ||||||||||||||||||||||||||
| Change in current assets and liabilities, net | (47,323) | 22,215 | 54,260 | 49,321 | ||||||||||||||||||||||
| Change in noncurrent assets and liabilities, net | (11,910) | 20,698 | (25,157) | (3,807) | ||||||||||||||||||||||
| Cash flows from operating activities before changes in operating assets and liabilities, net | 168,151 | 166,646 | 800,517 | 451,157 | ||||||||||||||||||||||
| Less incurred capital expenditures, excluding non-budgeted acquisition costs: | ||||||||||||||||||||||||||
Oil and natural gas properties(1) | 127,663 | 137,892 | 566,831 | 444,337 | ||||||||||||||||||||||
Midstream service assets(1) | 363 | 420 | 1,595 | 2,842 | ||||||||||||||||||||||
| Other fixed assets | 3,588 | 3,578 | 12,150 | 6,807 | ||||||||||||||||||||||
| Total incurred capital expenditures, excluding non-budgeted acquisition costs | 131,614 | 141,890 | 580,576 | 453,986 | ||||||||||||||||||||||
| Free Cash Flow (non-GAAP) | $ | 36,537 | $ | 24,756 | $ | 219,941 | $ | (2,829) | ||||||||||||||||||
_____________________________________________________________________________
(1)Includes capitalized share-settled equity-based compensation and asset retirement costs.
12
Adjusted Net Income (Unaudited)
Adjusted Net Income is a non-GAAP financial measure that the Company defines as 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 (GAAP) to Adjusted Net Income (non-GAAP) for the periods presented:
| Three months ended December 31, | Year ended December 31, | |||||||||||||||||||||||||
| (in thousands, except per share data) | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Net income | $ | 118,224 | $ | 216,276 | $ | 631,512 | $ | 145,008 | ||||||||||||||||||
| Plus: | ||||||||||||||||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||||||||||||||
| (Gain) loss on derivatives, net | 7,728 | (15,372) | 298,723 | 452,175 | ||||||||||||||||||||||
| Settlements paid for matured derivatives, net | (62,763) | (129,361) | (486,753) | (320,868) | ||||||||||||||||||||||
| Settlements received for contingent consideration | 580 | — | 2,457 | — | ||||||||||||||||||||||
Net premiums paid for commodity derivatives that matured during the period(1) | — | (10,183) | — | (41,553) | ||||||||||||||||||||||
| Organizational restructuring expenses | — | — | 10,420 | 9,800 | ||||||||||||||||||||||
| Impairment expense | 40 | — | 40 | 1,613 | ||||||||||||||||||||||
| (Gain) loss on disposal of assets, net | 6,031 | 8,903 | 1,079 | (84,551) | ||||||||||||||||||||||
| Loss on extinguishment of debt, net | 1,214 | — | 1,459 | — | ||||||||||||||||||||||
| Income tax expense | 3,055 | 3,052 | 5,502 | 3,645 | ||||||||||||||||||||||
| Adjusted income before adjusted income tax expense | 74,109 | 73,315 | 464,439 | 165,269 | ||||||||||||||||||||||
Adjusted income tax expense(2) | (16,304) | (16,129) | (102,177) | (36,359) | ||||||||||||||||||||||
| Adjusted Net Income (non-GAAP) | $ | 57,805 | $ | 57,186 | $ | 362,262 | $ | 128,910 | ||||||||||||||||||
| Net income per common share: | ||||||||||||||||||||||||||
| Basic | $ | 7.19 | $ | 13.07 | $ | 37.88 | $ | 10.18 | ||||||||||||||||||
| Diluted | $ | 7.13 | $ | 12.84 | $ | 37.44 | $ | 10.03 | ||||||||||||||||||
| Adjusted Net Income per common share: | ||||||||||||||||||||||||||
| Basic | $ | 3.52 | $ | 3.46 | $ | 21.73 | $ | 9.05 | ||||||||||||||||||
| Diluted | $ | 3.49 | $ | 3.39 | $ | 21.48 | $ | 8.91 | ||||||||||||||||||
| Adjusted diluted | $ | 3.49 | $ | 3.39 | $ | 21.48 | $ | 8.91 | ||||||||||||||||||
| Weighted-average common shares outstanding: | ||||||||||||||||||||||||||
| Basic | 16,441 | 16,545 | 16,672 | 14,240 | ||||||||||||||||||||||
| Diluted | 16,585 | 16,846 | 16,867 | 14,464 | ||||||||||||||||||||||
| Adjusted diluted | 16,585 | 16,846 | 16,867 | 14,464 | ||||||||||||||||||||||
_______________________________________________________________________________
(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 December 31, 2022 and 2021.
13
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 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 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 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 | Year ended | |||||||||||||||||||||||||||||||
| (in thousands) | December 31, 2022 | September 30, 2022 | June 30, 2022 | March 31, 2022 | December 31, 2022 | |||||||||||||||||||||||||||
| (unaudited) | ||||||||||||||||||||||||||||||||
| Net income (loss) | $ | 118,224 | $ | 337,523 | $ | 262,546 | $ | (86,781) | $ | 631,512 | ||||||||||||||||||||||
| Plus: | ||||||||||||||||||||||||||||||||
| Share-settled equity-based compensation, net | 2,108 | 1,638 | 2,604 | 2,053 | 8,403 | |||||||||||||||||||||||||||
| Depletion, depreciation and amortization | 85,085 | 74,928 | 78,135 | 73,492 | 311,640 | |||||||||||||||||||||||||||
| Impairment expense | 40 | — | — | — | 40 | |||||||||||||||||||||||||||
| Organizational restructuring expenses | — | 10,420 | — | — | 10,420 | |||||||||||||||||||||||||||
| (Gain) loss on disposal of assets, net | 6,031 | (4,282) | (930) | 260 | 1,079 | |||||||||||||||||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||||||||||||||||||||
| (Gain) loss on derivatives, net | 7,728 | (100,748) | 65,927 | 325,816 | 298,723 | |||||||||||||||||||||||||||
| Settlements paid for matured derivatives, net | (62,763) | (124,611) | (174,009) | (125,370) | (486,753) | |||||||||||||||||||||||||||
| Settlements received for contingent consideration | 580 | 322 | 1,555 | — | 2,457 | |||||||||||||||||||||||||||
| Accretion expense | 933 | 954 | 973 | 1,019 | 3,879 | |||||||||||||||||||||||||||
| Interest expense | 28,870 | 30,967 | 32,807 | 32,477 | 125,121 | |||||||||||||||||||||||||||
| (Gain) loss extinguishment of debt, net | 1,214 | (553) | 798 | — | 1,459 | |||||||||||||||||||||||||||
| Income tax expense (benefit) | 3,055 | (3,768) | 7,092 | (877) | 5,502 | |||||||||||||||||||||||||||
| Consolidated EBITDAX (non-GAAP) | $ | 191,105 | $ | 222,790 | $ | 277,498 | $ | 222,089 | $ | 913,482 | ||||||||||||||||||||||
PV-10 (Unaudited)
PV-10 is a non-GAAP financial measure that is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. Management believes that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to the Company's estimated proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of the Company's proved oil, NGL and natural gas assets. Further, investors may utilize the measure as a basis for comparison of the relative size and value of proved reserves to other companies. The Company uses this measure when assessing the potential return on investment related to proved oil, NGL and natural gas assets. However, PV-10 is not a substitute for the standardized measure of discounted future net cash flows. The PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of the Company's oil, NGL and natural gas reserves of the property.
| (in millions) | December 31, 2022 | |||||||
| Standardized measure of discounted future net cash flows | $ | 4,755 | ||||||
| Less present value of future income taxes discounted at 10% | (709) | |||||||
| PV-10 (non-GAAP) | $ | 5,464 | ||||||
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 December 31, 2022 was $1.08 billion.
14
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
ron.hagood@vitalenergy.com
15
4Q-22 and FY-22 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 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.
Leverage | 0.0x 2.14x 1.18x YE-21A YE-22A Free Cash Flow1 | $MM ($3) $220 FY-21A FY-22A 81.7 82.4 FY-21A FY-22A Oil Production | MBO/d 31.8 37.9 FY-21A FY-22A Total Production | MBOE/d $1,339 $1,054 YE-21A YE-22A Strong 2022 Performance 1See Appendix for definitions of non-GAAP financial measures; 2Includes Sr. Notes 3 Generated Company-Record FCF1 and Consolidated EBITDAX1 • FY-22 FCF of $220 million and FY-22 Consolidated EBITDAX of $913 million • Reinvested 70% of operating cash flow Strong Annual Production Growth • Driven by previous oil-weighted acquisitions • Continuing to optimize production through digital solutions Divested Non-Operated Properties for $110 million • Proceeds used to reduce debt and hi-grade portfolio Reduced Term Debt and Shares Outstanding • Utilized FCF and divestiture proceeds to repurchase – $285 million of term debt – 490,536 common equity shares • Improved year-end leverage by 0.96x to 1.18x at 12/31/2022 Shares Outstanding | millions 17.1 16.8 YE-21A YE-22A Term Debt2 | $MM
Disciplined Strategy Underpins Long-Term Value Creation 1See Appendix for definitions of non-GAAP financial measures; 2Gross operated locations as of January 2023 4 Pure-Play Midland Basin Producer • Maintain Capital Discipline • Generate Free Cash Flow1 • Reduce Debt and Leverage • Target Accretive Transactions • Advance Sustainability and Responsible Production VTLE Leasehold Driftwood Leasehold Howard ~31,750 net acres ~35.9 MBoe/d ~73% oil W. Glasscock ~38,650 net acres ~11.7 MBoe/d ~45% oil E. Glasscock ~32,400 net acres ~4.2 MBoe/d ~20% oil Reagan ~60,450 net acres ~26.1 MBoe/d ~13% oil Howard Glasscock ReaganUpton Inventory Locations2 Howard ~115 W. Glasscock ~295 E. Glasscock ~35 Total ~445 Upside ~185 TX
28%, WC-A 74%, WC-A 35%, LSS 26%, LSS 37%, MS 92 23 N. Howard C. Howard 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 Howard County Activity Driving 2023 Oil Production 1Gross operated locations as of January 2023 ; 2Production data normalized for 10,000’ lateral length and downtime 5 2023 / 2024 Activity Average Well Performance2 Primary Development Targets VTLE Leasehold 2023 Turn-in-Line 2024 Turn-in-Line Howard North Central Inventory Locations1 LS DEAN MS LSS WC-A JO MILL N. Howard (WC-A / LSS / MS) C. Howard (WC-A / LSS) Avg. WI ~95% ~85% Avg. LL ~11,000’ ~10,250’
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 Supports Sustainable FCF Generation 1Gross operated locations as of January 2023 ; 2Production data normalized for 10,000’ lateral length and downtime 6 2023 / 2024 Activity Average Well Performance2 Primary Development Targets VTLE Leasehold 2024 Turn-in-Line 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 Avg. WI ~90% Avg. LL ~11,500’ WC-A LSS WC-D Combined (WC-A / LSS / WC-D)
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 7 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
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 Recently Announced Acquisition Expands Footprint into Upton County 1Production data normalized for 10,000’ lateral length and downtime 8 Acquisition Overview Strong Well Performance1 Enhances Portfolio Depth • Acquiring assets of Driftwood Energy Operating, LLC – Inclusive of all leasehold interest and hedges – Effective Date: January 1, 2023 – Expected Close Date: Early April 2023 – 1,578,948 shares of Vital common stock; $127.6 million of cash Vital Leasehold Driftwood Leasehold Upton Reagan Highlights Gross Acres ~16,500 Net Acres ~11,200 Upton Inventory ~22 Gross / ~18 Net Reagan Inventory ~8 Gross / ~5 Net Current Production ~5.4 MBoe/d % Oil 63% N. Howard C. Howard W. Glasscock Driftwood
Proved Reserves Underpin Company Value 1SEC pricing $90.15 benchmark oil and $5.20 benchmark gas; 2Based only on wells categorized as Proved Developed as of YE-22 and decline calculated 4Q to 4Q; 3As of February 17, 2023 9 Proved Reserves Components | YE-22 PV-10 Reserve Value Sensitivity | $MM1 Annual Base Production Decline Expecatations2 Total Proved Reserves | MMBOE PD 74% PUD 26% $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) FY-23 FY-24 FY-25 Howard Oil, MBO/d 46% 33% 23% Total Company 41% 27% 19% Howard Total Production, MBOE/d 41% 31% 22% Total Company 29% 20% 15% Oil 39% NGL 31% Natural Gas 30% PUD PD TEV3 319 302 17 (4) (30) YE-21 Revisions & Extensions Sale Of Reserves 2022 Production YE-22
FY-23E Consolidated EBITDAX1,2 Sensitivity | $MM Continuous Improvement Drives Capital Efficient Program $695 $805 $920 $1,025 $65 $75 $85 $95 Benchmark WTI Oil Price $/Bbo (Benchmark HH Gas Price assumes $3.05/mcf) DC&E 81% Facilities & Land 12% Corporate 7% Capital Efficient 2023 Development Program 1See Appendix for definitions of non-GAAP financial measures; 2Actualized prices assumed through 1/31/2022 10 Full Year Capital Program Operated Turn-in-Lines | # 18 19 12 6 1Q-23E 2Q-23E 3Q-23E 4Q-23E Guidance FY-23E Capital Expenditures | $MM $625 - $675 Avg. Rig Count | Op ~2.0 Avg. Frac Crew | Op ~1.3 Spuds | Op ~52 Gross (~46.3 Net) Completions | Op ~56 Gross (~53.4 Net) Turn-in-Lines | Op ~55 Gross (~52.8 Net) Total Production | MBOE/d 72.0 - 76.0 Oil Production | MBO/d 34.0 - 37.0 1,430' 1,530' FY-21A FY-22A Drilling Ft. Per Day Per Rig 1,650' 1,625' FY-21A FY-22A Fractured Ft. Per Day Per Crew 9,900' 11,900' 11,800' FY-21A FY-22A FY-23E Avg, Completed Lateral Length Development Operated Activity | # 2 2 2 22 1 1 1 1Q-23E 2Q-23E 3Q-23E 4Q-23E Rig Count Frac Crews
Free Cash Flow Driving Return of Capital and Debt Reductions 1See Appendix for definitions of non-GAAP financial measures; 2Includes Sr. Notes; 3As of February 17, 2023 11 Current Debt Maturity Profile3 $456 $135 $865 $298$300 2023 2024 2025 2026 2027 2028 2029 Borrowing Base $1,300 MM Elected Commitment $1,000 MM Term Debt2 $1,054 MM $220 million FY-22 Free Cash Flow1 1.18x YE-22 Net Debt to Consolidated EBITDAX1 $285 million Term Debt2 Reduced FY-22 ~$880 million Current Liquidity3 $37 million Total Stock Repurchased FY-223 9.500% Sr. Notes 2025 10.125% Sr. Notes 2028 7.750% Sr. Notes 2029 Drawn Credit Facility Undrawn Credit Facility
Hedge Book Structured to Maintain Exposure to Higher Prices 1Hedges executed as of February 17, 2023; 2Calculated using guidance mid-point 12 Current Hedge Book1 62% 60% 25% 62% 0% 50% 100% 2H-23 1H-23 2H-23 1H-23 1Q-23 2Q-23 3Q-23 4Q-23 FY-23 FY-24 Crude Oil (Volume in MBO: Price in $/BBO): WTI Collars 1,949 2,002 828 828 5,607 - WTD Floor Price $68.15 $68.18 $70.00 $70.00 $68.71 - WTD Ceiling Price $83.81 $83.82 $87.47 $87.47 $84.90 - Natural Gas Liquids (Volume in MBBL: Price in $/BBL): Ethane - - - - - - Propane - - - - - - Butane - - - - - - Isobutane - - - - - - Pentane - - - - - - Natural Gas (Volume in MMBTU: Price in $/MMBTU): Henry Hub Collars 6,300,000 6,370,000 6,440,000 6,440,000 25,550,000 - WTD Floor Price $4.14 $4.14 $4.14 $4.14 $4.14 - WTD Ceiling Price $8.43 $8.43 $8.43 $8.43 $8.43 - Waha Basis Swaps 8,100,00 10,010,000 10,120,000 10,120,000 38,350,000 3,660,000 WTD Price ($1.60) ($1.53) ($1.53) ($1.53) ($1.54) ($0.75) Volumes Hedged2 Crude Oil Volumes Natural Gas Volumes
1313 Leadership in a Low-Carbon Future OUR ENVIRONMENTAL TARGETS <12.5 MTCO2e/MBOE SCOPE 1 GHG EMISSIONS INTENSITY BY 2025 ZERO ROUTINE FLARING BY 2025 <0.20% METHANE EMISSIONS BY 2025 (AS A PERCENT OF NATURAL GAS PRODUCTION) SCOPE 1 AND 2 GHG EMISSIONS INTENSITY < 10 MTCO2e/MBOE BY 2030 50% RECYCLED WATER FOR COMPLETION OPERATIONS BY 2025 2021 TO 2022 ESG PROGRESS 62% REDUCTION IN FLARING SINCE 2019 34% REDUCTION in SCOPE 1 GHG EMISSIONS INTENSITY SINCE 20191 63% REDUCTION IN METHANE INTENSITY SINCE 2019 FIRST PERMIAN OPERATOR TO ACHIEVE THE TRUSTWELLTM CERTIFICATION FOR RESPONSIBLE OPERATIONS 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 INCREASED ACTIVE MANAGEMENT AND HIGH GRADING OF OUR VENDORS BASED ON SAFETY METRICS CONDUCTED FIRST SUPPLIER ESG SURVEY TO BETTER UNDERSTAND THE DIVERSITY OF OUR SUPPLY BASE AND THE ESG POLICIES THEY HAVE IN PLACE INCREASED BOARD GENDER AND ETHNIC DIVERSITY TO 60%, A 270% INCREASE SINCE 2019 CONDUCTED COMPANY-WIDE UNCONSCIOUS BIAS TRAINING 43% OF 2021 NEW HIRES WERE DIVERSE 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.
We are Vital Energy 14 Our Company We strive to make energy available, sustainable and abundant to power people’s prosperity, security and dreams for the future. Our Legacy Since our founding we have sought new and better ways to responsibly produce energy to sustain our world. Engaging Communities We are committed to being great neighbors and supporting the communities that surround our operations. Better Decisions We embrace digital transformation like no other company in our space. We believe the potential for profound progress in our industry is limitless. Leading Energy Our executive team and board are committed to setting the standard for the advancement of our industry. We exist to energize human potential.
Appendix
1Q-23 & FY-23 Guidance 1Current NGL composition C2 (42%), C3 (33%), IC4 (3%), NC4 (11%) and C5+ (11%) 16 Guidance Commodity Prices Used for 1Q-23 Jan-23 Feb-23 Mar-23 1Q-23 Avg. Crude Oil: WTI NYMEX ($/BBO) $78.16 $77.10 $76.60 $77.29 Brent ICE ($/BBO) $83.95 $83.60 $82.65 $83.39 Natural Gas: Henry Hub ($/MMBTU) $4.71 $3.11 $2.28 $3.37 Waha ($/MMBTU) $4.78 $2.26 $1.32 $2.80 Natural Gas Liquids: C2 ($/BBL) $10.91 $10.75 $9.87 $10.50 C3 ($/BBL) $35.33 $34.80 $34.55 $34.90 IC4 ($/BBL) $47.77 $51.54 $49.40 $49.51 NC4 ($/BBL) $46.79 $51.21 $47.15 $48.29 C5+ ($/BBL) $70.74 $69.20 $68.15 $69.37 Composite ($/BBL)1 $30.61 $30.79 $29.71 $30.35 1Q-23 FY-23 Production: Total Production (MBOE/D) 72.5 – 76.5 72.0 - 76.0 Crude Oil Production (MBO/D) 33.0 - 36.0 34.0 - 37.0 Incurred Capital Expenditures ($MM): $210 - $230 $625 - $675 Average Sales Price Realizations (excluding derivatives): Crude Oil (% of WTI) 102% - Natural Gas Liquids (% of WTI) 24% - Natural Gas (% of Henry Hub) 51% - Net Settlements Received (Paid) for Matured Commodity Derivatives ($MM): Crude Oil ($MM) ($1) - Natural Gas Liquids ($MM) $0 - Natural Gas ($MM) ($2) - Operating Costs and Expenses ($/BOE): Lease Operating Expenses $7.50 - Production and Ad Valorem Taxes (% of Oil, NGL & Natural Gas Revenues) 7.5% - Transportation and Marketing Expenses $1.70 - General and Administrative Expenses (excluding LTIP) $2.40 - General and Administrative Expenses (LTIP Cash) $0.25 - General and Administrative Expenses (LTIP Non-Cash) $0.30 - Depletion, Depreciation and Amortization $12.25 -
Supplemental Non-GAAP Financial Measures 17 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 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 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 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 Year Ended (in thousands, unaudited) 12/31/2022 9/30/2022 6/30/2022 3/31/2022 12/31/2022 Net Income (loss) $118,224 $337,523 $262,546 ($86,781) $631,512 Plus: Share-settled equity-based compensation, net 2,108 1,638 2,604 2,053 8,403 Depletion, depreciation and amortization 85,085 74,928 78,135 73,492 311,640 Impairment expense 40 - - - 40 Organizational restructuring expenses - 10,420 - - 10,420 (Gain) loss on disposal of assets, net 6,031 (4,282) (930) 260 1,079 Mark-to-market on derivatives: (Gain) loss on derivatives, net 7,728 (100,748) 65,927 325,816 298,723 Settlements paid for matured derivatives, net (62,763) (124,611) (174,009) (125,370) (486,753) Settlements received for contingent consideration 580 322 1,555 - 2,457 Accretion expense 933 954 973 1,019 3,879 Interest expense 28,870 30,967 32,807 32,477 125,121 (Gain) loss on extinguishment of debt, net 1,214 (553) 798 - 1,459 Income tax expense (benefit) 3,055 (3,768) 7,092 (877) 5,502 Consolidated EBITDAX (non-GAAP) $191,105 $222,790 $277,498 $222,089 $913,482
Supplemental Non-GAAP Financial Measures 1Includes capitalized share-settled equity-based compensation and asset retirement costs 18 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. The following table presents a reconciliation of net income (loss) (GAAP) to Consolidated EBITDAX (non-GAAP) for the periods presented: Three Months Ended December 31, Year Ended December 31, (in thousands, unaudited) 2022 2021 2022 2021 Net cash provided by operating activities $108,918 $209,559 $829,620 $496,671 Less: Change in current assets and liabilities, net (47,323) 22,215 54,260 49,321 Change in noncurrent assets and liabilities, net (11,910) 20,698 (25,157) (3,807) Cash flows from operating activities before changes in operating assets and liabilities, net 168,151 166,646 800,517 451,157 Less incurred capital expenditures, excluding non-budgeted acquisition costs: Oil and natural gas properties(1) 127,663 137,892 566,831 444,337 Midstream service assets(1) 363 420 1,595 2,842 Other fixed assets 3,588 3,578 12,150 6,807 Total incurred capital expenditures, excluding non-budgeted acquisition costs 131,614 141,890 580,576 453,986 Free Cash Flow (non-GAAP) $36,537 $24,756 $219,941 ($2,829)
Supplemental Non-GAAP Financial Measures 19 PV-10 (Unaudited) PV-10 is a non-GAAP financial measure that is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. Management believes that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to the Company’s estimated proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of the Company's proved oil, NGL and natural gas assets. Further, investors may utilize the measure as a basis for comparison of the relative size and value of proved reserves to other companies. The Company uses this measure when assessing the potential return on investment related to proved oil, NGL and natural gas assets. However, PV-10 is not a substitute for the standardized measure of discounted future net cash flows. The PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of the Company’s oil, NGL and natural gas reserves of the property. (in millions) December 31, 2022 Standardized measure of discounted future net cash flows $4,755 Less present value of future income taxes discounted at 10% (709) PV-10 (non-GAAP) $5,464
Supplemental Non-GAAP Financial Measures 20 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 December 31, 2022 was $1.08 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.