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1Q-25 Earnings Presentation May 12, 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 regulatory requirements; 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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1See Appendix for definitions and reconciliations of non-GAAP financial measures. 2As of March 31, 2025. 3Gross operated locations as of January 2025 and excludes upside inventory. Executing on Core Strategic Priorities OPTIMIZE COST STRUCTURE 3 IMPROVE WTI BREAKEVEN MAXIMIZE ADJUSTED FCF1 REDUCE ABSOLUTE DEBT Permian Basin Summary Net Acres2 ~273,000 FY-25E Total Production 135.3 - 139.8 MBOE/d FY-25E % Oil 47% Inventory Locations3 ~925 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 TX
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1Q-25 Guidance 1Q-25 Reported 1Q-25 Guidance 1Q-25 Reported 1Q-25 Guidance 1Q-25 Reported $64 MM Adjusted Free Cash Flow1 Total and Oil Production Above Midpoint of Guidance • Production from recently acquired assets continues to exceed expectations • TIL acceleration in the quarter driven by completions efficiencies Capital Investments Within Guidance • TIL’d two more wells than expected • Reduced cycle times pulled additional drilling activity into the quarter Operating Costs Below Guidance • Operating expenses for Point Energy assets consistently beating expectations • Reduced workover activity in the period Strong Execution Drives Adjusted Free Cash Flow Generation 1 2 3 1See Appendix for definitions and reconciliations of non-GAAP financial measures. 1Q-25 Guidance 1Q-25 Reported 135.0 - 141.0 140.2 Total Production, MBOE/d Oil Production, MBO/d 62.0 - 66.0 64.9 $230 - $260 $253 Capital Investments, $MM $115 - $120 $103 Lease Operating Expense, $MM $360 MM Consolidated EBITDAX1 $351 MM Cash Flows from Operating Activities 1Q-25 Highlights 4
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1 D-Day Delaware Basin 2 Wells 1Q-25 2 Grissom White Delaware Basin 2 Wells 1Q-25 3 Mosaic State Delaware Basin 6 Wells 1Q-25 4 Duiker Lynx Delaware Basin 6 Wells 1Q-25 5 Emily Boss Delaware Basin 3 Wells 1Q-25 6 Scrat Delaware Basin 2 Wells 1Q-25 7 Pinto Delaware Basin 2 Wells 1Q-25 8 Dire Wolf Delaware Basin 3 Wells 2Q-25 9 Durlene Delaware Basin 4 Wells 2Q-25 10 Aloha State Delaware Basin 2 Wells 2Q-25 11 The Colonel Midland Basin 2 Wells 2Q-25 12 Tiger Midland Basin 1 Well 2Q-25 13 Agate Delaware Basin 1 Well 2Q-25 14 Getlo Midland Basin 2 Wells 2Q-25 15 Lil EL Midland Basin 2 Wells 2Q-25 16 Fat Chance Delaware Basin 2 Wells 3Q-25 17 Army South Delaware Basin 6 Wells 3Q-25 18 Cox Midland Basin 8 Wells 3Q-25 19 Navy South Delaware Basin 8 Wells 3Q-25 20 Rambo State Delaware Basin 3 Wells 3Q-25 21 8 Mile Midland Basin 12 Wells 4Q-25 Resilient 2025 Development Program with WTI Breakeven1 of ~$50 per Barrel 1Breakeven based on minimum 10% rate of return. Delaware Basin Midland Basin Combined Rig Count 3.4 1.8 5.2 Frac Crews 0.9 0.4 1.3 Spuds 40 Gross (31.9 Net) 42 Gross (33.9 Net) 82 Gross (65.8 Net) Completions 52 Gross (40.2 Net) 27 Gross (21.6 Net) 79 Gross (61.8 Net) Turn-in-Lines 52 Gross (40.2 Net) 27 Gross (21.3 Net) 79 Gross (61.5 Net) Midland Basin Activity Delaware Basin Activity 5 Reeves Co. Ward Co. Midland Co. Glasscock Co. Howard Co. Pecos Co. Winkler Co. Crane Co. Ector Co. Upton Co. Reagan Co. 2H-25 Program ~$46 WTI Breakeven1 1H-25 Program ~$57 WTI Breakeven1 NM TX
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2025 Capital Program Supports Adjusted Free Cash Flow1 Generation 1See Appendix for definitions and reconciliations of non-GAAP financial measures. 2Assumes May 6, 2025, commodity prices. Bal-25 of $58.70 WTI and $3.92 Henry Hub. 6 64.9 61.0 - 65.0 58.0 - 62.0 68.0 - 72.0 1Q-25A 2Q-25E 3Q-25E 4Q-25E Oil Production, MBO/d 140.2 133.0 - 139.0 128.0 - 134.0 140.0 - 146.0 1Q-25A 2Q-25E 3Q-25E 4Q-25E Total Production, MBOE/d $253 $215 - $245 $260 - $290 $105 - $125 1Q-25A 2Q-25E 3Q-25E 4Q-25E Capital Investments, $MM Reaffirming 2025 Outlook 63.0 - 66.0 Oil Production (MBO/d) 135.3 - 139.8 Total Production (MBOE/d) $835 - $915 MM Capital Investments ~$265 MM Adjusted Free Cash Flow1,2
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$2,440 $21 $112 $2,307 ~$170 ~$2,140 YE-24A Non-Core Divestiture 1Q-25 Paydown 1Q-25A 2Q-4Q Targeted YE-25E • Targeting ~$300 MM1 of debt repayment for FY-25 • Ample liquidity with no term-debt maturities until 2029 • Reduced credit facility balance through $20.5 MM in non-core asset sales Prioritizing Balance Sheet Improvement Through Debt Repayment 1Assumes May 6, 2025, commodity prices. Bal-25 of $58.70 WTI and $3.92 Henry Hub. 2See Appendix for definitions and reconciliations of non-GAAP financial measures. 3As of March 31, 2025. 4Credit Facility further adjusted for redetermination that closed on May 8, 2025. Debt Maturity Profile, $MM3,4 2025E Adjusted Free Cash Flow1,2 Sensitivity, $MM $735 $298 $302 $1,000 $665 $29 Cash Balance 3/31/2025 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 $695 MM Cash Balance Sr. Notes Drawn Credit Facility Undrawn Credit Facility 7 2025E Net Debt Reduction, $MM1 ~$240 ~$265 ~$300 $50 WTI Oil Current Strip WTI Oil $70 WTI Oil
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Peer-Leading Hedge Position Supports 2025 Development Program 1Hedge percentages based on guidance midpoints. 2Sourced from J.P.Morgan E&P Hedging Analyzer Report dated April 22, 2025. Peer group includes (CIVI, CRGY, DVN, FANG, MTDR, OVV, PR, SM, TALO) FY-25 VTLE Hedge Position vs. Peers2Bal-25 Hedge Position as of May 9,20251 Crude Oil ~$71 Avg. WTI per Bbl ~90% Hedged Natural Gas ~79% Hedged ~$2.30 Avg. Waha per MMBtu Natural Gas Liquids ~57% Hedged ~$34 Avg. Propane / $11 Ethane per Bbl 8 0% 25% 50% 75% 100% VTLE Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Hedges as February 19, 2025 Subsequent Hedges Bal-25 Hedge Position MTM Sensitivity as of May 9, 2025 | $MM $50 $60 $70 $0.50 $405 $260 $120 $1.50 $365 $220 $80 $2.50 $330 $185 $40 NYMEX WTI $/Bbl Waha $/MMbtu Crude Oil 0% 25% 50% 75% 100% Peer 1 Peer 2 VTLE Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Natural Gas
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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. Note: Breakeven based on minimum 10% rate of return. Midland Basin Completable Lateral Feet ~8,292,000’ 9 ~250 Upside ~3 Years of Incremental Inventory Economically Viable; Future Evaluation Required ~925 Locations >11 Years of Inventory1 ~$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 +95 ~925 ~250 ~1,175 Jan-23 Inventory 2023 Additions Jan-24 Inventory 2024 Additions Jan-25 Inventory Upside Locations Base + Upside Locations Jan-25 Inventory 11,840,000’ 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%
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$55 $40 Straight LL Development (24 - 5K Wells) Horseshoe Development (12 - 10K Wells) ~$125 ~$90 Straight LL Development (24 - 5K Wells) Horseshoe Development (12 - 10K Wells) $62 $40 Straight LL Development (24 - 5K Wells) Horseshoe Development (12 - 10K Wells) 0 Optimizing Well Design to Enhance Capital Efficiency 1Gross figures represented. 2025 Midland Basin Horseshoe Well Development Improves Capital Efficiency ~30% 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 • Utilizing advanced drilling techniques to expand long-lateral development across the leasehold • Horseshoe wells comprise 14% of total inventory • Successfully drilled and completed Company’s first J-Hook wells • Opportunity to convert 135 straight 10,000’ wells to 90 J-hook 15,000’ laterals, lowering expected WTI breakeven by ~$5/bbl LSS 2 Wells Jo Mill 3 Wells MSS 1 Wells Dean WCA 3 Wells WCB 3 Wells WCD WCC 10 Capital Efficiency ($/1-yr BOE) Capital Savings1 ($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
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Midland Basin Overview 1As of March 31, 2025. 2Gross operated locations as of January 2025 at current activity pace and spacing and excludes upside inventory. Note: Barnett leasehold and inventory included in Midland Basin totals. 11 Midland Basin Program FY-24 FY-25E Delaware Basin Program FY-24 FY-25E $63 $53 $47 $67 Key Stats Net Acres1 ~191,500 Inventory Locations2 ~620 Gross Lateral Length ~13,400’ Completable Lateral Feet 8,292,000’ Avg. WTI Breakeven Oil Price ~$52 Inventory Ownership 86% WI | 65% NRI % of FY-25E Capital Program ~35% 12,500' 12,100' FY-24 FY-25E Upton Co. Reagan Co. Midland Co. Glasscock Co. Howard Co. Crane Co. Ector Co. Midland Basin Completed Lateral Length (ft.) $63 $53 FY-24 FY-25E Capital Efficiency ($/1-yr BOE) $820 $715 FY-24 FY-25E DC&E Capital Cost ($/Ft.) Program Productivity Increase in 2025 versus 2024 0 50 100 150 200 250 - 60 120 180 240 300 360 Cumulative Gross MBOE (Production per Well) Producing Days 12,500’ LL (65% Oil) 12,100’ LL (70% Oil)~2% Increase in Volume; ~3% Decrease in Lateral Length 6 11 12 13 - 7 8 12 - 7 8 12 1Q-25 2Q-25E 3Q-25E 4Q-25E 2025 Development Program Gross Spuds Gross Completions Gross Turn-in-Lines 2025 Program 2024 Program Note: All figures are approximate.
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Pecos Co. Reeves Co. Ward Co. Delaware Basin Winkler Co. Delaware Basin Overview 1As of March 31, 2025. 2Gross operated locations as of January 2025 at current activity pace and spacing and excludes upside inventory. Note: All figures are approximate. 12 Key Stats Net Acres1 ~81,500 Inventory Locations2 ~305 Gross Lateral Length ~11,600’ Completable Lateral Feet 3,548,000’ Avg. WTI Breakeven Oil Price ~$55 Inventory Ownership 72% WI | 55% NRI % of FY-25E Capital Program ~65% 10,750' 13,500' FY-24 FY-25E Completed Lateral Length (ft.) $67 $47 FY-24 FY-25E Capital Efficiency ($/1-yr BOE) $1,000 $890 FY-24 FY-25E DC&E Capital Cost ($/Ft.) Program Productivity Increase in 2025 versus 2024 0 50 100 150 200 250 300 350 - 60 120 180 240 300 360 Cumulative Gross MBOE (Production per Well) Producing Days 10,750’ LL (68% Oil) 13,500’ LL (68% Oil) ~48% Increase in Volume; ~25% Increase in Lateral Length 15 10 8 7 26 7 19 - 23 10 19 - 1Q-25 2Q-25E 3Q-25E 4Q-25E 2025 Development Program Gross Spuds Gross Completions Gross Turn-in-Lines 2025 Program 2024 Program Note: All figures are approximate.
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Optimized 2025 Development Drives Adjusted FCF Generation and Debt Reduction 1 2 3 4 Enhancing capital efficiency through increased productivity and lateral lengths Targeting Net Debt1 reduction of ~$300 MM2 by YE-25 at current commodity prices ~90% of expected Bal-25 oil production hedged at ~$71 per barrel WTI 13 2025 development plan has estimated ~$50 per barrel3 WTI breakeven 1See Appendix for definitions and reconciliations of non-GAAP financial measures. 2Assumes May 6, 2025, commodity prices. Bal-25 of $58.70 WTI and $3.92 Henry Hub. 3Breakeven based on minimum 10% rate of return.
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Appendix
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2Q-25 & FY-25 Guidance 1Current NGL composition C2 (42%), C3 (33%), IC4 (3%), NC4 (11%) and C5+ (11%). Guidance Commodity Prices Used for 2Q-25 Apr-25 May-25 Jun-25 2Q-25 Avg. Crude Oil: WTI NYMEX ($/BBO) $62.96 $58.83 $58.57 $60.10 WTI Midland ($/BBO) $64.06 $59.78 $59.32 $61.03 WTI Houston ($/BBO) $64.33 $60.12 $59.55 $61.31 Natural Gas: Henry Hub ($/MMBTU) $3.95 $3.17 $3.46 $3.52 Waha ($/MMBTU) ($0.94) $0.62 $1.73 $0.47 Natural Gas Liquids: C2 ($/BBL) $10.68 $10.15 $10.45 $10.42 C3 ($/BBL) $35.82 $29.72 $29.61 $31.70 IC4 ($/BBL) $37.38 $38.47 $38.12 $37.99 NC4 ($/BBL) $36.97 $38.40 $36.65 $37.35 C5+ ($/BBL) $56.18 $54.10 $54.39 $54.88 Composite ($/BBL)1 $27.68 $25.40 $25.32 $26.12 2Q-25 FY-25 Production: Total Production (MBOE/D) 133.0 - 139.0 135.3 - 139.8 Crude Oil Production (MBO/D) 61.0 - 65.0 63.0 - 66.0 Capital Expenditures ($MM): $215 - $245 $835 - $915 Average Sales Price Realizations (excluding derivatives): Crude Oil (% of WTI) 101% — Natural Gas Liquids (% of WTI) 24% — Natural Gas (% of Henry Hub) 14% — Net Settlements Received (Paid) for Matured Commodity Derivatives ($MM): Crude Oil ($MM) $69 — Natural Gas Liquids ($MM) $3 — Natural Gas ($MM) $21 — Operating Costs and Expenses ($MM): Lease Operating Expenses $112 - $118 — Production and Ad Valorem Taxes (% of Oil, NGL & Natural Gas Revenues) 6.60% — Oil Transportation and Marketing Expenses $10.7 - $11.7 — Gas Gathering, Processing and Transportation Expenses $6.7 - $7.7 — General and Administrative Expenses (excluding LTIP & Transaction Expense) $21.0 - $22.5 — General and Administrative Expenses (LTIP Cash) $0.6 - $0.7 — General and Administrative Expenses (LTIP Non-Cash) $3.0 - $3.5 — Depletion, Depreciation and Amortization $180 - $190 — 15
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2Q-25 3Q-25 4Q-25 Bal-25 1Q-26 2Q-26 3Q-26 4Q-26 FY-26 FY-27 Crude Oil (MBO) (Price $/BBO) WTI Swaps 4,732 5,226 6,054 16,011 1,530 819 828 828 4,005 - Price $74.85 $70.06 $67.75 $70.61 $71.72 $71.24 $71.24 $71.24 $71.42 - Natural Gas (MMBTU) (Price $/MMBTU) Waha Inside FERC Swaps 12,747,000 17,204,000 15,034,000 44,985,000 12,780,000 12,922,000 13,064,000 13,064,000 51,830,000 43,800,000 Price $2.32 $2.32 $2.32 $2.32 $2.41 $2.41 $2.41 $2.41 $2.41 $2.70 Natural Gas Liquids (MBBL) (Price $/BBL) Propane Swaps 865 874 874 2,613 - - - - - - Price $34.16 $34.16 $34.16 $34.16 - - - - - - Ethane Swaps 1,092 1,104 1,104 3,300 - - - - - - Price $11.04 $11.04 $11.04 $11.04 - - - - - - Active Hedge Program Protecting Adjusted Free Cash Flow and Returns1 1Hedges executed as of May 9, 2025. 16
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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-10 Reserve Value Sensitivity, $MM1 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. 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. This release 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 measure 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 e xcluded 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. 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: Three months ended (in thousands, unaudited) March 31, 2025 Net cash provided by (used in) operating activities $350,985 Less: Net changes in operating assets and liabilities 33,821 Cash flows from operating activities before net changes in operating assets and liabilities and transaction expenses related to non-budgeted acquisitions 317,164 Less capital investments, excluding non-budgeted acquisition costs: Oil and natural gas properties1 251,264 Midstream and other fixed assets1 1,407 Total capital investments, excluding non-budgeted acquisition costs 252,671 Adjusted Free Cash Flow (non-GAAP) $64,493 19
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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, to be filed with the SEC, 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 periods presented: 21 Three months ended (in thousands, unaudited) March 31, 2025 Net income (loss) ($18,837) Plus: Share-settled equity-based compensation 3,604 Depletion, depreciation and amortization 189,900 Impairment expense 158,241 (Gain) loss on disposal of assets, net (110) Mark-to-market on derivatives: (Gain) loss on derivatives, net (44,171) Settlements received (paid) for matured derivatives, net 20,687 Accretion expense 1,034 Interest expense 50,380 Income tax (benefit) expense (1,049) Consolidated EBITDAX (non-GAAP) $359,679
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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 periods presented: 22 Three months ended (in thousands, unaudited) March 31, 2025 Net cash provided by (used in) operating activities $350,985 Plus: Interest expense 50,380 Current income tax (benefit) expense 762 Net changes in operating assets and liabilities (33,821) Other, net (8,627) Consolidated EBITDAX (non-GAAP) $359,679
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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) March 31, 2025 December 31, 2024 Total senior unsecured notes $1,600,578 $1,600,578 Senior Secured Credit Facility 735,000 880,000 Total long-term debt 2,335,578 2,480,578 Less: cash and cash equivalents 28,649 40,179 Net Debt (non-GAAP) $2,306,929 $2,440,399
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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