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.