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2Q-25 Earnings Presentation August 6, 2025
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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 Energy” 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: the volatility of oil, NGL and natural gas prices, including the Company’s area of operation in the Permian Basin; changes, uncertainty and instability in domestic and global production, supply and demand for oil, NGL and natural gas, and actions by the Organization of the Petroleum Exporting Countries members and other oil exporting nations ("OPEC+"); changes in general economic, business or industry conditions and market volatility, including as a result of slowing growth, inflationary pressures, monetary policy, tariffs, trade barriers, price and exchange controls and other regulatory requirements, including such changes that may be implemented by the United States ("U.S.") and foreign governments; the Company’s ability 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; the Company’s ability to optimize spacing, drilling and completions techniques in order to maximize its rate of return, cash flows from operations and stockholder value; the ongoing instability and uncertainty in the U.S. and international energy, financial and consumer markets that could adversely affect the liquidity available to the Company and its customers and the demand for commodities, including oil, NGL and natural gas; competition in the oil and gas industry; the Company’s ability to discover, estimate, develop and replace oil, NGL and natural gas reserves and inventory; insufficient transportation capacity in the Permian Basin and challenges associated with such constraint, and the availability and costs of sufficient gathering, processing, storage and export capacity; a decrease in production levels which may impair the Company’s ability to meet its contractual obligations and ability to retain its leases; risks associated with the uncertainty of potential drilling locations and plans to drill in the future; the inability of significant customers to meet their obligations; revisions to the Company’s reserve estimates as a result of changes in commodity prices, decline curves and other uncertainties; the availability and costs of drilling and production equipment, supplies, labor and oil and natural gas processing and other services; ongoing war and political instability in Ukraine, Israel and the Middle East and the effects of such conflicts on the global hydrocarbon market and supply chains; risks related to the geographic concentration of the Company’s assets; the Company’s ability to hedge commercial risk, including commodity price volatility, and regulations that affect the Company’s ability to hedge such risks; the Company’s ability to continue to maintain the borrowing capacity under its Senior Secured Credit Facility or access other means of obtaining capital and liquidity, especially during periods of sustained low commodity prices; the Company’s ability to comply with restrictions contained in its debt agreements, including its Senior Secured Credit Facility and the indentures governing its senior unsecured notes, as well as debt that could be incurred in the future; the Company’s ability to generate sufficient cash to service its indebtedness, fund its capital requirements and generate future profits; drilling and operating risks, including but not limited to, risks related to hydraulic fracturing, securing sufficient electricity to produce its wells without limitation, natural disasters and other matters beyond the Company’s control; U.S. and international economic conditions and legal, tax, political and administrative developments, including the effects of energy, trade and environmental policies and existing and future laws and government regulations; the Company’s ability to comply with federal, state and local legal, tax and regulatory requirements, including the One Big Beautiful Bill Act (“OBBB Act”), and any impact thereof on taxes, tariffs and international trade; the impact of repurchases, if any, of securities from time to time; the Company’s ability to maintain the health and safety of, as well as recruit and retain, qualified personnel, including senior management or other key personnel, necessary to operate its business; evolving cybersecurity risks such as those involving unauthorized access, denial-of-service attacks, third-party service provider failures, malicious software, data privacy breaches by employees, insiders or others with authorized access, cyber or phishing attacks, ransomware, social engineering, physical breaches or other actions; and the Company’s belief that the outcome of any current legal proceedings will not materially affect its financial results and operations 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. This presentation includes financial measures that are not in accordance with generally accepted accounting principles (“GAAP”), such as Adjusted Free Cash Flow, Net Debt, PV-10 and Consolidated EBITDAX. While management believes that such measures are useful for investors, they should not be used as a replacement for financial measures that are in accordance with GAAP. For definitions of such non-GAAP financial measures and their reconciliations to the most comparable GAAP measures, please see the Appendix. This presentation also includes certain forward-looking non-GAAP measures. Due to the forward-looking nature of such measures, no reconciliations of these non-GAAP measures to their respective most directly comparable GAAP measures are available without unreasonable efforts. This is due to the inherent difficulty of forecasting the timing or amount of various reconciling items that would impact the most directly comparable forward-looking GAAP financial measure, that have not yet occurred, are out of the Company’s control and/or cannot be reasonably predicted. Accordingly, such reconciliations are excluded from this presentation. Forward-looking non-GAAP financial measures provided without the most directly comparable GAAP financial measures may vary from the corresponding GAAP financial measures. 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.
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~4,962,000 ~9,172,000 ~11,780,000 Jan-23 Jan-24 Jan-25 217.0 233.0 305.0 $217 $233 ~$305 FY-23 FY-24 FY-25E 46.3 61.7 65.3 46.3 61.7 63.3 - 65.3 FY-23 FY-24 FY-25E 1See Appendix for definitions and reconciliations of non-GAAP financial measures. 2As of June 30, 2025 further adjusted for subsequent non-core asset sale in Crane and Upton counties. 3Gross operated locations as of January 2025 and excludes upside inventory further adjusted for subsequent non-core asset sale in Crane and Upton counties. Creating Value from High-Quality Permian Basin Position OPTIMIZE COST STRUCTURE 3 IMPROVE WTI BREAKEVEN MAXIMIZE ADJUSTED FCF1 Permian Basin Summary Net Acres2 ~267,300 FY-25E Total Production 136.5 - 139.5 MBOE/d FY-25E % Oil 47% Inventory Locations3 ~920 VTLE Acreage Reeves Co. Pecos Co. Ward Co. Winkler Co. Crane Co. Ector Co. Reagan Co. Upton Co. Midland Co. Glasscock Co. Howard Co. NM TX REDUCE ABSOLUTE DEBT TX Oil Production, MBo/d Adjusted Free Cash Flow1,2, $MM Inventory Completable Lateral Feet
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2Q-25 Guidance 2Q-25 Reported 2Q-25 Guidance 2Q-25 Reported $215 - $245 $257 Capital Investments, $MM $112 - $118 $108 Lease Operating Expense, $MM 2Q-25 Guidance 2Q-25 Reported $36 MM Adjusted Free Cash Flow1 In-Line Production • Total production above midpoint with gas production in the Delaware Basin and Howard County consistently beating expectations • Weather downtime and production curtailments reduced quarterly average production by 780 BOE/d, 500 BO/d of which was oil Capital Investments Reflect Activity Acceleration • Accelerated $11 MM of activity into the second quarter to solidify timing for large packages to be TIL’d in late third quarter/early fourth quarter • Drilling costs higher than anticipated due to one-time drilling cost overruns Expenses Below Guidance • Operating expenses on Point Energy assets beat expectations • G&A expenses lower due to reduced employee and professional costs Sustainably Lower Expenses Drive Adjusted Free Cash Flow1 Generation 1 2 3 1See Appendix for definitions and reconciliations of non-GAAP financial measures. 2Inclusive of Oil Transportation and Marketing Expenses and Gas Gathering, Processing and Transportation Expenses 2Q-25 Guidance 2Q-25 Reported 133.0 - 139.0 137.9 Total Production, MBOE/d Oil Production, MBO/d 61.0 - 65.0 62.1 $338 MM Consolidated EBITDAX1 $252 MM Cash Flows from Operating Activities 2Q-25 Highlights 4 2Q-25 Guidance 2Q-25 Reported 2Q-25 Guidance 2Q-25 Reported $24.6 - $26.7 $23.8 Total G&A Expense, $MM $17.4 - $19.4 $16.0 Transportation & Marketing Expense2, $MM
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4Q-24 to 2Q-25 Quarterly Average Guidance 4Q-24 to 2Q-25 Quarterly Average Actual 3Q-25 Guidance 4Q-25 Guidance 4Q-24 to 2Q-25 Quarterly Average Guidance 4Q-24 to 2Q-25 Quarterly Average Actual 3Q-25 Guidance 4Q-25 Guidance Successful Optimization Efforts Driving Improved Cost Outlook 1General and administrative expenses includes LTIP cash/non-cash and excludes transaction expenses. 5 Lease Operating Expenses, $MM $110.7 $107.0 - $113.0 General and Administrative Expenses1, $MM $20.0 - $22.0 $20.0 - $22.0 • Optimized cost structure reduces ongoing expenses by ~6% versus initial expectations – Renegotiated service contracts inherited from acquisitions to better terms and lower costs – Savings from conversion to high-line power and lease gas to fuel generators – Consolidation of lease operator routes – Optimization of chemical treatment parameters • Reduced G&A expense outlook nearly 20% versus expectations since Point Energy acquisition – Reduced employee/contractor headcount by ~10% in June 2025 – Rationalized corporate expenses to reflect pivot from acquisition strategy to asset optimization $109.0 - $115.0 $25.0 - $26.7 $115.0 - $120.0 $24.4
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253.0 257.0 265.0 125.0 $253 $257 $235 - $265 $105 - $125 1Q-25 2Q-25 3Q-25E 4Q-25E 140.2 137.9 134.0 146.0 140.2 137.9 128.0 - 134.0 140.0 - 146.0 1Q-25 2Q-25 3Q-25E 4Q-25E Disciplined 2025 Capital Program Supports Adjusted Free Cash Flow1 Outlook 1See Appendix for definitions and reconciliations of non-GAAP financial measures. 2Assumes July 31, 2025 commodity prices. Bal-25 of $67.30 WTI and $3.40 Henry Hub. 6 64.9 62.1 62.0 72.0 64.9 62.1 58.0 - 62.0 68.0 - 72.0 1Q-25 2Q-25 3Q-25E 4Q-25E Oil Production, MBO/d Total Production, MBOE/dCapital Investments, $MM Reaffirming 2025 Outlook 63.3 - 65.3 Oil Production (MBO/d) 136.5 - 139.5 Total Production (MBOE/d) $850 - $900 MM Capital Investments ~$305 MM Adjusted Free Cash Flow1,2 3Q-25 Guidance Reduced by $25 MM
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$990 $865 $735 1H-25 2H-25E 10,050' 12,400' 1H-25 2H-25E $785 $720 $670 1H-25 2H-25E DC&E Capital Cost ($/Ft.) Capital Efficiency Improving in 2H-25 7 Delaware Basin Program Productivity 0 100 200 300 400 500 - 60 120 180 240 300 360 Cumulative Gross MBOE (Production per Well) Producing Days 12,100’ LL (62% Oil) 15,400’ LL (67% Oil) 2H-25 Program 1H-25 Program Midland Basin Program Productivity 0 100 200 300 - 60 120 180 240 300 360 Cumulative Gross MBOE (Production per Well) Producing Days 10,050’ LL (78% Oil) 12,400’ LL (69% Oil) 2H-25 Program 1H-25 Program ~23% (~8%) Note: All figures are approximate. Lateral Length (ft.) 12,100' 15,400' 1H-25 2H-25E DC&E Capital Cost ($/Ft.) ~27% (~13%) Lateral Length (ft.) Average Pacesetter Well Average Pacesetter Well
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Jul-25 Aug-25 Sep-25 Oct-25 Nov-25 8 Mile Package (4Q-25) Rambo State Package (3Q-25) Cox Package (3Q-25) Army & Navy South Package (3Q-25) Fat Chance Package (3Q-25) Fat Chance Package (3Q-25) Army/Navy South Package (3Q-25) Cox Package (3Q-25) Rambo State Package (3Q-25) 8 Mile Package (4Q-25) 2H-25 Development Program On Schedule Midland Basin Activity Delaware Basin Activity 8 Reeves Co. Ward Co. Midland Co. Glasscock Co. Howard Co. Pecos Co. Winkler Co. Crane Co. Ector Co. Upton Co. Reagan Co. NM TX Army/Navy South Package (13 Wells) Fat Chance (2 Wells) Rambo State (3 Wells) 8 Mile Package (12 Wells) Cox Package (8 Wells) Midland Basin Delaware Basin 2H-25 Turn-in-Line Program Producing Completed; Commencing Flowback Drilled; Waiting on Completion Drilling Drilling
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$2,440 $125 ~$185 ~$2,130 YE-24 1H-25 Paydown 2H-25E Paydown YE-25E • Targeting ~$310 MM1 of debt repayment for FY-25, including $27 MM of non-core asset sales • Ample liquidity with no term-debt maturities until 2029 • Expect credit facility to be reduced to ~40% drawn at YE-25 Prioritizing Balance Sheet Improvement Through Debt Repayment 1Assumes July 31, 2025 commodity prices. Bal-25 of $67.30 WTI and $3.40 Henry Hub. 2See Appendix for definitions and reconciliations of non-GAAP financial measures. 3As of June 30, 2025. 4Includes non-core asset sales located in Reagan, Crane, and Upton counties. Debt Maturity Profile, $MM3 2025E Adjusted Free Cash Flow1,2 Sensitivity, $MM $745 $298 $302 $1,000 $655 $30 Cash Balance 6/30/2025 2025 2026 2027 2028 2029 (7.750%) 2030 (9.750%) 2031 2032 (7.875%) Credit Facility Current Borrowing Base $1.40 B Elected Commitment $1.40 B Total Liquidity $685 MM Cash Balance Sr. Notes Drawn Credit Facility Undrawn Credit Facility 9 2025E Net Debt1,2 Reduction, $MM ~$285 ~$305 ~$325 $55 WTI Oil Current Strip WTI Oil $75 WTI Oil 4 4
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3Q-25 4Q-25 2H-25 1Q-26 2Q-26 3Q-26 4Q-26 FY-26 FY-27 Crude Oil (MBO) (Price $/BBO) WTI Swaps 5,226 6,054 11,279 3,825 3,686 2,898 2,898 13,307 3,285 Price $70.06 $67.75 $68.82 $65.09 $63.70 $63.52 $63.52 $64.02 $61.07 WTI Collars - - - 540 546 - - 1,086 - Put Price - - - $60.00 $60.00 - - $60.00 - Call Price - - - $71.02 $71.02 - - $71.02 - Natural Gas (MMBTU) (Price $/MMBTU) Waha Inside FERC Swaps 17,204,000 15,034,000 32,238,000 13,680,000 13,832,000 13,984,000 13,984,000 55,480,000 43,800,000 Price $2.32 $2.32 $2.32 $2.41 $2.41 $2.41 $2.41 $2.41 $2.70 Waha Basis Swaps - - - - - - - - 14,600,000 Price - - - - - - - - ($0.97) Natural Gas Liquids (MBBL) (Price $/BBL) Propane Swaps 874 874 1,748 - - - - - - Price $34.16 $34.16 $34.16 - - - - - - Ethane Swaps 1,104 1,104 2,208 - - - - - - Price $11.04 $11.04 $11.04 - - - - - - Active Hedging Program Underpins Cash Flow 1Hedges executed as of August 5, 2025. 2Excludes Waha basis hedges. 10 Crude Oil Hedge Position, MBO1 Natural Gas Hedge Position, MMBTU1,2 Natural Gas Liquids Hedge Position, MBBL1 11,279 14,393 3,285 2H-25 FY-26 FY-27 32,238,000 51,830,000 43,800,000 3,650,000 2H-25 FY-26 FY-27 3,956 0 0 2H-25 FY-26 FY-27 Hedges as June 17, 2025 Subsequent Hedges Hedges as June 17, 2025 Subsequent Hedges Hedges as June 17, 2025 Subsequent Hedges
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$55 $43 Straight LL Development (24 - 5K Wells) Horseshoe Development (12 - 10K Wells) ~$125 ~$95 Straight LL Development (24 - 5K Wells) Horseshoe Development (12 - 10K Wells) $62 $41 Straight LL Development (24 - 5K Wells) Horseshoe Development (12 - 10K Wells) 0 Optimized Well Designs Extend and Improve Inventory 1Gross figures represented. 2025 Midland County Horseshoe Well Development 2025 Delaware Basin J-Hook Well Development Midland Basin Midland Co. Upton Co. Reagan Co. Glasscock Co. Howard Co. Midland Co. VTLE Acreage Illustrative Horseshoe Design - WCA • Established core competencies in advanced drilling techniques to expand long-lateral development • 125 horseshoe wells in current inventory represents around 1.5 years of development • Commenced production from first two J-Hook wells • Opportunity to convert 135 straight 10,000’ wells to 90 J-Hook 15,000’ laterals, lowering expected WTI breakeven by ~$5/bbl LSS 2 Wells Jo Mill 3 Wells MSS 1 Wells Dean WCA 3 Wells WCB 3 Wells WCD WCC 11 Capital Efficiency ($/1-yr BOE) Development Capital1 ($MM) Avg. WTI Breakeven (Oil $/Bbl) Delaware Basin Reeves Co. Pecos Co. Ward Co. Winkler Co. VTLE Acreage J-Hook Design - WCB VTLE Acreage J-Hook Design - WCB 2025 Midland County Horseshoe Development Comparison
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11 Years of High-Quality Permian Basin Inventory 1Gross operated locations as of January 2025 at current activity pace and spacing and excludes upside inventory. 2Adjusted for non-core asset sales in Crane and Upton counties. Note: Breakeven based on minimum 10% rate of return. Midland Basin Completable Lateral Feet ~8,232,000’ 12 ~245 Upside ~3 Years of Incremental Inventory2 Economically Viable; Future Evaluation Required ~920 Locations >11 Years of Inventory1,2 ~$53 Avg. WTI Breakeven Oil Price ~25% ~35% ~45% ~40% ~40% ~40% ~35% ~25% ~15% Jan-23 Inventory Jan-24 Inventory Jan-25 Inventory ~300% Increase in Sub-$50 WTI Breakeven Total Completable Lateral Feet vs. 2023 ~445 +385 ~830 +90 ~920 ~245 ~1,165 Jan-23 Inventory 2023 Additions Jan-24 Inventory 2024 Additions Jan-25 Inventory Upside Locations Base + Upside Locations Jan-25 Inventory 11,780,000’ 9,172,000’ 4,962,000’ Sub-$50 WTI Breakeven $50-$60 WTI Breakeven $60-$75 WTI Breakeven Illustrative 5% DC&E Savings ~50% ~15% ~60% ~35% ~5% ~35% Delaware Basin Completable Lateral Feet ~3,548,000’ Jan-25 Inventory Illustrative 5% DC&E Savings ~35% ~20% ~45% ~40% ~15% ~45% 2 2 2
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Maximizing Adjusted Free Cash Flow1 Generation and Reducing Debt 1 2 3 4 Enhancing capital efficiency with Horseshoe and J-Hook well designs Targeting Net Debt1 reduction of ~$310 MM2 by YE-25 at current commodity prices ~95% of expected 2H-25 oil production hedged at ~$69 per barrel WTI 13 Sustainable LOE and G&A savings enhancing cash flow and debt repayment 1See Appendix for definitions and reconciliations of non-GAAP financial measures. 2Assumes July 31, 2025 commodity prices. Bal-25 of $67.30 WTI and $3.40 Henry Hub. 3Breakeven based on minimum 10% rate of return.
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Appendix
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3Q-25 & FY-25 Guidance 1Current NGL composition C2 (42%), C3 (33%), IC4 (3%), NC4 (11%) and C5+ (11%). Guidance Commodity Prices Used for 3Q-25 Jul-25 Aug-25 Sep-25 3Q-25 Avg. Crude Oil: WTI NYMEX ($/BBO) $67.24 $68.91 $67.95 $68.03 WTI Midland ($/BBO) $67.62 $69.23 $68.35 $68.40 WTI Houston ($/BBO) $67.76 $69.48 $68.63 $68.62 Natural Gas: Henry Hub ($/MMBTU) $3.26 $3.08 $3.11 $3.15 Waha ($/MMBTU) $1.58 $1.05 $0.76 $1.13 Natural Gas Liquids: C2 ($/BBL) $9.72 $8.98 $9.08 $9.26 C3 ($/BBL) $29.70 $30.66 $30.82 $30.39 IC4 ($/BBL) $39.59 $40.06 $40.01 $39.88 NC4 ($/BBL) $36.08 $37.59 $37.75 $37.13 C5+ ($/BBL) $55.69 $57.96 $57.91 $57.18 Composite ($/BBL)1 $25.17 $25.60 $25.71 $25.49 3Q-25 FY-25 Production: Total Production (MBOE/D) 128.0 - 134.0 136.5 - 139.5 Crude Oil Production (MBO/D) 58.0 - 62.0 63.3 - 65.3 Capital Expenditures ($MM): $235 - $265 $850 - $900 Average Sales Price Realizations (excluding derivatives): Crude Oil (% of WTI) 101% — Natural Gas Liquids (% of WTI) 21% — Natural Gas (% of Henry Hub) 23% — Net Settlements Received (Paid) for Matured Commodity Derivatives ($MM): Crude Oil ($MM) $11 — Natural Gas Liquids ($MM) $5 — Natural Gas ($MM) $20 — Operating Costs and Expenses ($MM): Lease Operating Expenses $109 - $115 — Production and Ad Valorem Taxes (% of Oil, NGL & Natural Gas Revenues) 6.40% — Oil Transportation and Marketing Expenses $10.7 - $11.7 — Gas Gathering, Processing and Transportation Expenses $5.5 - $6.5 — General and Administrative Expenses (excluding LTIP & Transaction Expense) $16.9 - $18.4 — General and Administrative Expenses (LTIP Cash) $0.4 - $0.5 — General and Administrative Expenses (LTIP Non-Cash) $2.7 - $3.1 — Depletion, Depreciation and Amortization $168 - $178 — 15
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1As of June 30, 2025 further adjusted for subsequent non-core asset sales in Crane, Ector and Upton counties. 2Gross operated locations as of January 2025 and excludes upside inventory further adjusted for subsequent non-core asset sales in Crane and Upton counties. Asset Overview 16 VTLE Acreage Reeves Co. Pecos Co. Ward Co. Winkler Co. Crane Co. Ector Co. Reagan Co. Upton Co. Midland Co. Glasscock Co. Howard Co. NM TX Delaware Basin Midland Basin Net Acres1 ~81,200 ~186,100 Inventory Locations2 ~305 Gross ~615 Gross Lateral Length ~11,600’ ~13,400’ Completable Lateral Feet 3,548,000’ 8,232,000’ Avg. WTI Breakeven Oil Price ~$55 ~$52 Inventory Ownership 72% WI | 55% NRI 86% WI | 65% NRI % of FY-25E Capital Program ~65% ~35% TX Delaware Basin Midland Basin
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Oil 37% NGL 32% Natural Gas 31% Proved Reserves Growth in 2024 1See Appendix for definitions and reconciliations of non-GAAP financial measures. 2Based only on wells categorized as Proved Developed as of YE-24 and decline calculated Dec to Dec. Note: SEC pricing $75.48 benchmark oil and $2.13 benchmark gas. Total Proved Reserves, MMBOE PV-101 Reserve Value Sensitivity, $MM Proved Reserves Components, YE-24 YE-24 PDP Base Production Decline Expectations2 $3,718 $2,813 $3,489 $4,174 $792 $318 $644 $1,005 $4,510 $3,131 $4,133 $5,179 SEC $60 $70 $80 Oil 47% NGL 28% Natural Gas 25% 71% 70% 29% 30% 405 (49) 69 30 455 YE-23 2024 Production Purchase of Reserves Price & Other Revisions plus Additions YE-24 PUD PD Proved Developed Proved Undeveloped PUD PD Benchmark WTI Oil Price $/bbl (Benchmark HH Gas Price assumes $3.00/mcf) 42% 27% 20% 16% 14% FY-25 FY-26 FY-27 FY-28 FY-29 36% 21% 17% 14% 12% FY-25 FY-26 FY-27 FY-28 FY-29 Oil Production, MBO/D Total Production, MBOE/D 12% Total Proved Reserves Increase ~22% of Inventory Currently Booked as PUDs 17 Oil Price $75.48/bbl (Gas Price $2.13/mcf)
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CATEGORY TARGET 2023 PERFORMANCE3 TARGET PROGRESS by 2025 Scope 1 GHG emissions intensity1 Below 12.5 mtCO2e/MBOE 2019 baseline of 26.03 mtCO2e/MBOE 9.14 mtCO2e / MBOE Achieved 65% reduction from baseline Methane Emissions2 Below 0.20% 2019 baseline of 0.87% 0.08% Achieved 90% reduction from baseline Recycled water 50% used for completion operations 2019 baseline of 35% water recycling rate (8 million bbls recycled) 57% water recycling rate Achieved More then 20.5 million bbls recycled Routine flaring Zero 2019 baseline of 867 MMCF/year 366 MMCF/year 58% reduction to date by 2030 Combined Scope 1 and 2 GHG emissions intensity Below 10 mtCO2e/MBOE 2019 baseline of 26.53 mtCO2e/MBOE 11.94 mtCO2e/MBOE 55% reduction to date 2024 Sustainability Report Highlights 1Scope 1 GHG metrics are based on EPA Subpart W reporting; all performance is as of December 31, 2023. 2As a percentage of natural gas produced. 32023 performance is inclusive of acquisitions closed in the 2023 calendar year. Continued Progress Toward Sustainability Targets 18
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Supplemental Non-GAAP Financial Measures 1Includes capitalized share-settled equity-based compensation and asset retirement costs. This release includes certain forward-looking non-GAAP measures. Due to the forward-looking nature of such measures, no reconciliations of these non-GAAP measures to their respective most directly comparable GAAP measure are available without unreasonable efforts. This is due to the inherent difficulty of forecasting the timing or amount of various reconcili ng items that would impact the most directly comparable forward-looking GAAP financial measure, that have not yet occurred, are out of the Company’s control and/or cannot be reasonably predicted. Accordingly, such reconciliations are exclu ded from this release. Forward-looking non-GAAP financial measures provided without the most directly comparable GAAP financial measures may vary materially from the corresponding GAAP financial measures. Adjusted Free Cash Flow Free Cash Flow is a non-GAAP financial measure that the Company defines as net cash provided by (used in) operating activities ( GAAP) before net changes in operating assets and liabilities and transaction expenses related to non -budgeted acquisitions, less capital investments, excluding non-budgeted acquisition costs. Management believes Adjusted 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 Adju sted Free Cash Flow as a measure of performance, including the lack of comparability due to the different methods of calculating Adjusted Free Cash Flow reported by different companies. The following table presents a reconciliation of net cash provided by (used in) operating activities (GAAP) to Adjusted Free Cash Flow (non-GAAP) for the periods presented: 19 Three months ended Year ended (in thousands, unaudited) June 30, 2025 December 31, 2024 December 31, 2023 Net cash provided by (used in) operating activities $252,341 $1,000,330 $812,956 Less: Net changes in operating assets and liabilities (40,774) (127,830) (71,444) General and administrative (transaction expenses) — (548) (11,341) Cash flows from operating activities before net changes in operating assets and liabilities and transaction expenses related to non-budgeted acquisitions 293,115 1,128,708 895,741 Less capital investments, excluding non-budgeted acquisition costs: Oil and natural gas properties1 254,195 873,637 663,025 Midstream and other fixed assets1 2,830 22,276 15,601 Total capital investments, excluding non-budgeted acquisition costs 257,025 895,913 678,626 Adjusted Free Cash Flow (non-GAAP) $36,090 $232,795 $217,115
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Supplemental Non-GAAP Financial Measures Consolidated EBITDAX Consolidated EBITDAX is a non-GAAP financial measure defined in the Company's Senior Secured Credit Facility as net income or loss (GAAP) plus adjustments for share-settled equity-based compensation, depletion, depreciation and amortization, impairment expense, organizational restructuring expenses, gains or losses on dispo sal of assets, mark-to-market on derivatives, accretion expense, interest expense, income taxes and other non-recurring income and expenses. Consolidated EBITDAX provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, working capital movement or tax position. Consolidated EBITDAX does not represent funds available for future discretionary us e because it excludes funds required for debt service, capital expenditures, working capital, income taxes, franchise taxes and other commitments and obligations. However, management believes Consolidated EBITDAX is useful to an investor because this measure: • is used by investors in the oil and natural gas industry to measure a company's operating performance without regard to items that can vary substantially from company to company depending upon accounting methods, the book value of assets, capital structure and the method by which assets were acquired, among other fac tors; • helps investors to more meaningfully evaluate and compare the results of the Company's operations from period to period by re moving the effect of the Company's capital structure from the Company's operating structure; and • is used by management for various purposes, including (i) as a measure of operating performance, (ii) as a measure of compliance under the Senior Secured Credit Facility, (iii) in p resentations to the board of directors and (iv) as a basis for strategic planning and forecasting. There are significant limitations to the use of Consolidated EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the Company's net income or loss and the lack of comparability of results of operations to different companies due to the different methods of calculating Consolidated EBITDAX, or similarly titled measures, reported by different companies. The Company is subject to financial covenants under the Senior Secured Credit Faci lity, one of which establishes a maximum permitted ratio of Net Debt, as defined in the Senior Secured Credit Facility, to Consolidated EBITDAX. See Note 7 in the 2024 Annual Report for additional discussion of the financial covenants under the Senior Secured Credit Facility. Additional information on Consolidated EBITDAX can be found in the Company's Eleventh Amendment to the Senior Secured Credit Facility, as filed with the SEC on September 13, 2023. 20
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Supplemental Non-GAAP Financial Measures Consolidated EBITDAX The following table presents a reconciliation of net income (loss) (GAAP) to Consolidated EBITDAX (non-GAAP) for the period presented: 21 Three months ended (in thousands, unaudited) June 30, 2025 Net income (loss) ($582,572) Plus: Share-settled equity-based compensation 3,233 Depletion, depreciation and amortization 186,424 Impairment expense 427,046 Organizational restructuring expenses 4,627 (Gain) loss on disposal of assets, net (1,255) Mark-to-market on derivatives: (Gain) loss on derivatives, net (68,993) Settlements received (paid) for matured derivatives, net 79,558 Accretion expense 977 Interest expense 49,854 Income tax (benefit) expense 239,170 Consolidated EBITDAX (non-GAAP) $338,069
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Supplemental Non-GAAP Financial Measures Consolidated EBITDAX The following table presents a reconciliation of net cash provided by (used in) operating activities (GAAP) to Consolidated E BITDAX (non-GAAP) for the period presented: 22 Three months ended (in thousands, unaudited) June 30, 2025 Net cash provided by (used in) operating activities $252,341 Plus: Interest expense 49,854 Organizational restructuring expenses 4,627 Current income tax (benefit) expense 1,070 Net changes in operating assets and liabilities 40,774 Other, net (10,597) Consolidated EBITDAX (non-GAAP) $338,069
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Supplemental Non-GAAP Financial Measures Net Debt Net Debt is a non-GAAP financial measure defined in the Company's Senior Secured Credit Facility as the face value of long-term debt plus any outstanding letters of credit, less cash and cash equivalents, where cash and cash equivalents are capped at $100 million when there are borrowings on the Senior Secured Credit Facility. Management believes Net Debt is useful to management and investors in determining the Company's leverage position since the Company has the ability, and may decide, to use a portion of its cash and cash equivalents to reduce debt. 23 (in thousands, unaudited) June 30, 2025 December 31, 2024 Total senior unsecured notes $1,600,578 $1,600,578 Senior Secured Credit Facility 745,000 880,000 Total long-term debt 2,345,578 2,480,578 Less: cash and cash equivalents 30,194 40,179 Net Debt (non-GAAP) $2,315,384 $2,440,399 Net Debt to Consolidated EBITDAX Net Debt to Consolidated EBITDAX is a non-GAAP financial measure defined in the Company's Senior Secured Credit Facility as Net Debt divided by Consolidated EBITDAX for the previous four quarters, which requires various treatment of asset transaction impacts. 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.
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Supplemental Non-GAAP Financial Measures PV-10 PV-10 is a non-GAAP financial measure that is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. Management believes that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to the Company's estimated proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of the Company's proved oil, NGL and natural gas assets. Further, investors may utilize the measure as a basis for comparison of the relative size and value of proved reserves to other companies. The Company uses this measure when assessing the potential return on investment related to proved oil, NGL and natural gas assets. However, PV-10 is not a substitute for the standardized measure of discounted future net cash flows. The PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of the Company's oil, NGL and natural gas reserves of the property. 24 (in millions, unaudited) December 31, 2024 Standardized measure of discounted future net cash flows $4,215 Less: present value of future income taxes discounted at 10% (295) PV-10 (non-GAAP) $4,510