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INFINITY Second Quarter 2026 Earnings Call Presentation August 2026
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2 Forward-Looking Statements. This presentation contains “forward-looking statements” that express the Company’s opinions, expectations, beliefs, plans, objectives, assumptions or projections regarding future events or future results, in contrast with statements that reflect historical facts. All statements, other than statements of historical fact, included in this presentation regarding the Company’s strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management, future commodity prices, future production targets, leverage targets or debt repayment, hedging strategy, future capital spending plans, capital efficiency, our ability to pay future dividends and make share repurchases, expected drilling and completions plans and projected well costs, among other similar statements, are forward-looking statements. When used in this presentation, words such as “may,” “assume,” “forecast,” “could,” “should,” “will,” “plan,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “target,” “outlook,” “guidance,” “budget” and similar expressions are used to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current beliefs, based on currently available information, as to the outcome and timing of future events at the time such statements were made. Such statements are subject to a number of assumptions, risks and uncertainties, including those incident to the development, production, gathering and sale of oil, natural gas and NGLs, most of which are difficult to predict and many of which are beyond the control of the Company. These include, but are not limited to, our failure to realize, in full or at all, the anticipated benefits of capital raising transactions and acquisitions, including synergies; commodity price volatility; inflation; lack of availability and cost of drilling, completion and production equipment and services; supply chain disruption; project construction delays; environmental risks; drilling, completion and other operating risks; lack of availability or capacity of midstream gathering and transportation infrastructure; regulatory changes; the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital; the timing of development expenditures; the concentration of the Company’s operations in the Appalachian Basin; difficult and adverse conditions in the domestic and global capital and credit markets; impacts of geopolitical events and world health events, including trade wars; the impacts of recently enacted legislation; lack of transportation and storage capacity as a result of oversupply, government regulations or other factors; potential financial losses or earnings reductions resulting from the Company’s commodity price risk management program or any inability to manage its commodity risks; failure to realize expected value creation from property acquisitions and trades; weather related risks; competition in the oil and natural gas industry; loss of production and leasehold rights due to mechanical failure or depletion of wells and the Company’s inability to re-establish production; the Company’s ability to service its indebtedness; political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, armed conflict, political instability and civil unrest, including instability in the Middle East, Venezuela and Mexico and other sustained military campaigns, the armed conflict in Ukraine and associated economic sanctions on Russia, conditions in South America, Central America, China and Russia, and acts of terrorism or sabotage; 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; technological advancements, including artificial intelligence and its application in our industry; risks related to the Company’s ability to expand its business, including through the recruitment and retention of qualified personnel; and the other risks described under the heading “Risk Factors” in the Company’s filings with the U.S. Securities and Exchange Commission (the “SEC”), including its most recent Annual Report on Form 10-K and any subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K. As a result, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Therefore, these forward-looking statements are not a guarantee of the Company’s performance, and you should not place undue reliance on such statements. All forward-looking statements, expressed or implied, included in this presentation are expressly qualified in their entirety by this cautionary statement. Any forward-looking statement speaks only as of the date on which such statement is made, and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except to the extent required by law. Reserves. The Company’s proved reserves are reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expires, unless evidence indicates that renewal is reasonably certain. Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, the Company’s reserve and PV-10 estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered. You should not assume that the present values referred to in this presentation represent the actual current market value of our oil, natural gas and NGL reserves. You are urged to consider closely the oil and natural gas disclosures in the Company’s filings with the SEC, including its most recent Annual Report on Form 10-K. Non-GAAP Measures. This presentation includes certain non-GAAP financial measures, such as Adjusted EBITDAX, Adjusted EBITDAX Margin, PV-10, Capital Efficiency Ratio, F&D, DROI, Net Leverage and Net Debt. Because not all companies calculate non-GAAP financial measures identically (or at all), the non-GAAP financial measures included herein may not be comparable to other similarly titled measures used by other companies. Further, such non-GAAP financial information should not be considered as a substitute for the historical financial information prepared in accordance with GAAP included herein or provided in connection herewith. Please see the appendix of this presentation for definitions and reconciliations of such non-GAAP financial measures. 2 Disclaimer
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3 1. Equity market capitalization and enterprise value based on August 7, 2026 share price of $12.98 and 63.4 million total shares outstanding. Enterprise value calculation uses total debt and preferred balances excluding the impact of issuance fees and asso ciated expenses. 2. Net leverage is defined as total debt outstanding less cash and cash equivalents outstanding as of June 30, 2026 divided by a nnualized Adjusted EBITDAX for the quarter ending June 30, 2026. 3. Liquidity is defined as borrowing base availability plus cash and cash equivalents as of June 30, 2026. 4. Net leverage, Adjusted EBITDAX, Adjusted EBITDAX Margin and Capital efficiency are Non-GAAP measures. See appendix for additional details. 5. Based on a 2-rig pace. 6. Annual production growth is calculated based on the midpoint of INR’s production guidance for the year ending 2026. 7. Development capex is defined as the combination of drilling and completion capital expenditures and midstream capital expendi tures. Infinity Natural Resources (NYSE: INR) High growth, low cost, vertically integrated E&P focused on the development of balanced inventory OH Utica Shale: ~108k net acres Market Capitalization(1) $823 million Enterprise Value(1) $1.7 billion Net Leverage(2)(4) 1.1x Liquidity(3) $901 million Operating / Financial Statistics Net Horizon Acreage ~177,000 Inventory (#) / Inventory Life (yrs)(5) 400+ / ~12 years 2Q 2026 Production 348 MMcfe/d 2Q 2026 Adj. EBITDAX Margin(4) $3.62/mcfe 2025 Capital Efficiency / Peer Avg.(4) 3.5x / 1.6x Midstream Capacity ~1.0 Bcf/d 2026E Guidance Net Production (MMcfe/d) 345 – 375 Net Liquids Production (Mbbls/d) 18 – 20 Annual Production Growth(6) 70% Development CapEx ($MM)(7) $450 - $500 Operated Rigs 2 INR Midstream (OH & PA) • ~1 Bcf/d of throughput capacity • ~150 miles of gathering lines • ~100 miles of water lines • ~83,000 hp compression PA Marcellus Shale: ~35k net acres PA Deep Dry Gas Utica Shale: ~34k net acres INR AOI INR Acreage County INR Midstream Infinity Natural Resources Overview
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4 1. DROI is a non-GAAP measure. See appendix for additional details. Balanced High-Quality Portfolio ▪ $3.4 Billion Economic Projects >2.0x DROI(1) ▪ Ohio Utica assets with exposure to oil-weighted, liquids-rich, and dry gas inventory ▪ Pennsylvania assets with exposure to stacked-pay Marcellus and Deep Utica inventory Operational Flexibility ▪ Flexibility to allocate capital across oil, liquids-rich, and dry gas to the highest return opportunities ▪ Deep inventory enables cycle-driven capital allocation ▪ Enhances returns through commodity cycles Expansive Midstream System ▪ Upstream & Midstream integration in PA and acquired OH assets ▪ Control over gathering, processing, and marketing ▪ Structurally competitive cost advantages ▪ Lower breakevens through scale and integrated midstream Basin-Leading Profitability ▪ Basin-leading Appalachian EBITDA margins per Mcfe ▪ Low F&D costs drive best-in-class capital efficiency ▪ High-margin resource base across the Utica and Marcellus “A differentiated Appalachian E&P combining rare production growth with an integrated, high-margin operating platform.” Why Own Infinity Natural Resources
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5 Best in Basin Growth, Margin and Capital Efficiency Note: Diamonds represent Appalachian peers’ average, with peers being AR, CNX, EQT, GPOR, and RRC. 1. Net production for 2026 and annual production growth are calculated based on the midpoint of INR’s production guidance for th e year ending 2026. 2. Adjusted EBITDAX margin is a non-GAAP measure. For a reconciliation, please see the appendix. Peer average statistics were $1.5 2/mcfe, $1.54/mcfe, $1.93/mcfe for 2023, 2024, and 2025, respectively. 3. Capital Efficiency is a non-GAAP measure. Capital efficiency is calculated as the Adjusted EBITDAX margin for a period divided b y the all-in F&D ($/mcfe) for a period. For a reconciliation, please see the appendix. Peer average statistics were 1.1x, 1.4x, 2.8x and 1.7x for 20 23, 2024, 2025 and 3-year average, respectively. Net Production Growth (MMcfe/d)(1) Adj. EBITDAX Margin(2) ($/Mcfe) Capital Efficiency(3) (x) $3.05 $3.70 $3.38 $3.62 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 2023 2024 2025 YTD'26 3.0x 3.0x 4.2x 3.5x 0.0x 1.0x 2.0x 3.0x 4.0x 5.0x 2023 2024 2025 3Yr Avg Peer Average INR Peer Average INR114% 27% 46% 78% 0% 25% 50% 75% 100% 125% 2023 2024 2025 2026 % Growth 70%+
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6 1. Operating costs exclude the impact of firm transportation costs. See management’s discussion and analysis of financial condi tion and results of operations in the Company’s Quarterly Report on Form 10-Q for further detail. 2. Adjusted EBITDAX and net leverage are non-GAAP measures. See appendix for additional details. Key Highlights ▪ Increased net production and Adjusted EBITDAX by 75% and 131% year over year, respectively ▪ Turned in Line 10 wells in Ohio during the second quarter ▪ 7 volatile oil Utica wells (3 TIL in late June) ▪ 3 rich gas Utica wells (TIL in late June) ▪ Spudded 9 wells ▪ 1 deep dry gas Utica well, 2 dry gas Marcellus wells ▪ 2 rich gas Utica wells ▪ 4 volatile oil Utica wells ▪ Completed 10 wells ▪ 7 volatile oil Utica wells, 3 dry gas Marcellus wells ▪ Added ~1,100 net horizon acres during 2Q26 ▪ Midstream expansion continuing as planned in Pennsylvania and on acquired Ohio assets ▪ Strong balance sheet supported by $901 million of liquidity Total Production Volumes Net Revenues Operating Costs(1) Adjusted EBITDAX(2) Incurred Development Capital Expenditures Net Leverage(2) (Net Debt / LQA Adj. EBITDAX) $129.1 million $73.1 million 2Q26 2Q25 $114.7 million $49.6 million $36.2 million $23.9 million $171.0 million $74.5 million 348 MMcfe/d 199 MMcfe/d 1.1x 0.1x Continued Execution: Second Quarter 2026 Results
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7 $50 $115 $97 $115 2Q25 2Q26 1Q26 2Q26 $1.32 $1.14 $1.14 $1.14 2Q25 2Q26 1Q26 2Q26 199 348 299 348 2Q25 2Q26 1Q26 2Q26 6.1 9.5 7.8 9.5 2Q25 2Q26 1Q26 2Q26 6.1 12.4 9.6 12.4 2Q25 2Q26 1Q26 2Q26 125 217 194 217 2Q25 2Q26 1Q26 2Q26 1. Operating expenses include LOE, GP&T, midstream opex, and production taxes. GP&T excludes firm transportation costs of approximately $7.5 million, or $0.24/Mcfe. 2. Adjusted EBITDAX and GP&T excluding firm transportation costs are non-GAAP measures. See appendix for additional details. Oil Production (Mbbls/d) NGL Production (Mbbls/d) Nat. Gas Production (MMcfe/d) Total Production (MMcfe/d) Operating Expenses ($/Mcfe)(1)(2) Adjusted EBITDAX ($MM)(2) Increasing Production While Driving Costs Lower
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8 255 93 21% 62% 16% 236 180 132 112 68 60 44 108 69 108 35 34 Location Count by State(1) Assets are uniquely positioned providing high return resource exposure to oil, rich gas, and dry gas drilling inventory 1. Location counts include all wells in process (“WIPs”) and undeveloped locations 2Q26 Net Production (MMcfe/d) Net Horizon Acres by State (000’s) 2Q26 Production Mix (%) Location Count by Operating Area(1) Net Horizon Acres by Reservoir (000’s) ~177,000 Net Acres 400+ Locations 348 MMcfe/d OH PA OH PA OH PA Oil Dry Gas NGL OH Utica Oil PA Marcellus PA Utica OH Utica Dry Gas OH Utica Rich Gas OH Utica PA Marcellus PA Utica Balanced High Return Development Across All Hydrocarbons
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1.3x-1.5x 1.5x-2.5x >2.5x >1.3x INR Total Note: All type curves reflect internal forecasts. Well costs and operating costs are internal projections. Revenue is based o n $65/bbl WTI and $4.00/MMBtu Henry Hub 1. DROI is a non-GAAP measure. See appendix for additional details.9 Economic Capital Projects by DROI(1) Total Inventory Lateral Footage by Area $4.8Bn $3.4 Billion Economic Projects >2.0x DROI INR’s highly economic inventory base spans across dry gas, rich gas, and oil phase windows Expansive High DROI(x) Inventory Across Operating Areas Volatile Oil OH Gas Weighted PA Marcellus PA Utica
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▪ ~1 Bcf/d of throughput capacity capable of supporting INR growth thru end of decade ▪ 70% of INR gross operated natural gas volumes flowing through owned system ▪ Increased system utilization by 30% since end of 1Q ▪ Vast operational reach supporting operating flexibility and development ▪ Significantly reduces well breakeven levels in Ohio and Pennsylvania 10 Key Highlights Southeastern Ohio Midstream System Waiting on final numbers Ohio Compressor Station – Noble County Processing Plant Black Oil Dry Gas Expansive Company Owned Midstream System
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Volatile Oil Utica (OH) Rich Gas Utica (OH) Dry Gas Marcellus (PA) Deep Dry Gas Utica (PA) Total Company 2Q26 YTD 3Q26 2026E 2Q26 YTD 3Q26 2026E 2Q26 YTD 3Q26 2026E 2Q26 YTD 3Q26 2026E 2Q26 YTD 3Q26 2026E Wells Spud Gross Wells 4.0 7.0 4.0 18.0 2.0 2.0 6.0 14.0 2.0 6.0 - 6.0 1.0 1.0 - 1.0 9.0 16.0 10.0 39.0 Net Wells 3.7 5.7 3.4 14.0 1.2 1.2 2.3 6.6 2.0 6.0 - 6.0 1.0 1.0 - 1.0 7.9 13.9 5.7 27.6 Gross Lateral Footage (Mft) 46.0 89.0 87.0 311.0 19.0 19.0 79.0 159.0 28.0 91.0 - 91.0 10.0 10.0 - 10.0 103.0 209.0 166.0 571.0 Avg. Lateral Length (Mft) 11.5 12.7 21.8 17.3 9.5 9.5 13.2 11.4 14.0 15.2 - 15.2 10.0 10.0 - 10.0 11.4 13.1 16.6 14.6 Wells Completed Gross Wells 7.0 15.0 - 19.0 - 3.0 3.0 11.0 3.0 3.0 3.0 6.0 - - 1.0 1.0 10.0 21.0 7.0 37.0 Net Wells 5.7 13.5 - 16.9 - 1.7 1.8 5.2 3.0 3.0 3.0 6.0 - - 1.0 1.0 8.7 18.2 5.8 29.1 Gross Lateral Footage (Mft) 89.0 199.0 - 286.0 - 53.0 30.0 152.0 47.0 47.0 44.0 91.0 - - 10.0 10.0 136.0 299.0 84.0 539.0 Avg. Lateral Length (Mft) 12.7 13.3 - 15.1 - 17.7 10.0 13.8 15.7 15.7 14.7 15.2 - - 10.0 10.0 13.6 14.2 12.0 14.6 Wells Turned-in-Line ("TIL") Gross Wells 7.0 11.0 4.0 15.0 3.0 3.0 - 6.0 - - 3.0 6.0 - - - 1.0 10.0 14.0 7.0 28.0 Net Wells 5.9 9.8 3.7 13.5 1.7 1.7 - 3.5 - - 3.0 6.0 - - - 1.0 7.5 11.5 6.7 24.0 Gross Lateral Footage (Mft) 99.0 153.0 46.0 199.0 53.0 53.0 - 83.0 - - 47.0 91.0 - - - 10.0 152.0 206.0 93.0 383.0 Avg. Lateral Length (Mft) 14.1 13.9 11.5 13.3 17.7 17.7 - 13.8 - - 15.7 15.2 - - - 10.0 15.2 14.7 13.3 13.7 11 Developing Assets Across Our Portfolio 2026 program weighted towards Ohio development with near term focus on liquids-weighted projects Note: Rich Gas Utica (OH) reflects the assets acquired from Antero.
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12 1. Net leverage is defined as total debt outstanding less cash and cash equivalents outstanding as of June 30, 2026 divided by a nnualized Adjusted EBITDAX for the quarter ending June 30, 2026. Net leverage is a Non -GAAP measure. See appendix for additional details. Significant Liquidity with no Near-Term Maturities ▪ Net leverage of 1.1x(1) ▪ Target long term net leverage of less than 1.0x (1) ▪ No near-term debt maturities ▪ No borrowings outstanding under revolving credit facility ▪ Active hedge program moderates forecasted cash flow Senior Unsecured Outstanding Liquidity under credit facility $550 $875 $- $200 $400 $600 $800 $1,000 2025 2026 2027 2028 2029 2031 Financial Strength Provides Strategic Flexibility Key Points
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13 Appendix
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14 1. Incurred Development Capital Expenditures includes well development and midstream capital. 14 2026 Outlook and Guidance Net Production Total Net Production (Mmcfe/d) 345 – 375 Total Natural Gas Net Production (Mmcf/d) 235 – 255 Total Liquids Net Production (Mbbls/d) 18 – 20 Incurred Development Capital Expenditures(1) $450 – $500 Operated Rigs ~ 2 Rigs TILs (Gross) ~30 Wells
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15 INR seeks to mitigate commodity fluctuations by actively hedging its anticipated PDP and near-term development production to support cash management and leverage. $3.87 $4.17 $4.43 $3.47 $3.70 $4.02 0 5,000 10,000 15,000 20,000 25,000 30,000 Q3 2026 Q4 2026 Q1 2027 Q2 2027 Q3 2027 Q4 2027 Gas Volumes (BBtu) INR Hedge Position and Philosophy 15 Note: Hedge positions as of 6-Aug-26. (1) Natural gas hedges represent Henry Hub trades volumes and price Hedging Overview Oil Hedges Natural Gas Hedges(1) Natural Gas Liquids Hedges ▪ INR actively hedges within its bank group to secure DROIs and maintain balance sheet strength ▪ INR is hedged approximately 78% on an equivalent basis for the remainder of 2026 at the midpoint of our guidance ▪ Recent hedging activity has focused on oil and C3+ trades for 2026 and 2027 tracking price increases following start of Iran conflict ▪ Primarily targeting swaps and collars $63.87 $64.50 $66.54 $65.63 $65.49 $65.85 0 300 600 900 1,200 Q3 2026 Q4 2026 Q1 2027 Q2 2027 Q3 2027 Q4 2027 Oil Volumes (MBbl) $36.36 $35.89 $35.91 $33.06 $32.63 $32.89 0 200 400 600 800 1,000 Q3 2026 Q4 2026 Q1 2027 Q2 2027 Q3 2027 Q4 2027 NGL Volumes (MBbl)
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16 Hedge Book Overview – As of 6 -Aug -26 16 FY 2026 FY 2027 FY 2028 FY 2029 Q1 Q2 Q3 Q4 2026 Q1 Q2 Q3 Q4 2027 Q1 Q2 Q3 Q4 2028 WTI Fixed Swaps Total Volume (MBbl) 634 613 679 801 2,726 458 454 411 387 1,710 249 227 211 197 884 Daily Volume (Bbl/d) 7,039 6,734 7,383 8,701 7,468 5,089 4,992 4,465 4,204 4,684 2,736 2,495 2,293 2,141 2,415 WAVG Swap Price ($ / Bbl) $63.92 $63.71 $63.26 $63.71 $63.65 $65.39 $64.67 $64.78 $65.51 $65.08 $71.78 $71.09 $70.43 $69.91 $70.87 WTI Fixed Collars Total Volume (MBbl) - 72 67 115 254 153 100 65 32 350 - - - - - Daily Volume (Bbl/d) - 791 728 1,250 696 1,700 1,099 707 348 959 - - - - - WAVG Ceiling Price ($ / Bbl) - $78.00 $78.00 $78.00 $78.00 $84.60 $84.60 $84.60 $84.60 $84.60 - - - - - WAVG Floor Price ($ / Bbl) - $70.00 $70.00 $70.00 $70.00 $70.00 $70.00 $70.00 $70.00 $70.00 - - - - - Henry Hub Fixed Swaps Total Volume (BBtu) 16,061 16,040 15,230 13,644 60,975 12,167 11,390 10,688 10,089 44,334 9,450 8,990 8,670 8,260 35,370 Daily Volume (MMBtu/d) 178,456 176,264 165,543 148,304 167,055 135,189 125,165 116,174 109,663 121,463 103,846 98,791 94,239 89,783 96,639 WAVG Swap Price ($ / MMBtu) $4.31 $3.62 $3.87 $4.17 $3.99 $4.43 $3.47 $3.70 $4.02 $3.91 $4.26 $3.29 $3.56 $3.90 $3.76 Dom South Basis Swaps Total Volume (BBtu) 12,276 11,347 10,137 9,065 42,825 7,131 3,140 3,320 3,280 16,871 2,940 2,780 2,670 2,540 10,930 Daily Volume (MMBtu/d) 136,400 124,692 110,185 98,533 117,329 79,233 34,505 36,087 35,652 46,222 32,308 30,549 29,022 27,609 29,863 WAVG Swap Price ($ / MMBtu) ($0.77) ($0.90) ($1.21) ($1.25) ($1.01) ($0.76) ($0.73) ($1.06) ($1.05) ($0.87) ($0.64) ($0.82) ($1.11) ($1.07) ($0.90) Dom South Fixed Swaps Total Volume (BBtu) 795 2,001 4,544 4,296 11,636 3,220 2,696 2,360 2,096 10,372 - - - - - Daily Volume (MMBtu/d) 8,833 21,989 49,391 46,696 31,879 35,778 29,626 25,652 22,783 28,416 - - - - - WAVG Swap Price ($ / MMBtu) $3.70 $2.83 $2.99 $3.12 $3.06 $3.60 $2.62 $2.60 $2.84 $2.96 - - - - - Tetco M2 Basis Swaps Total Volume (BBtu) 473 461 451 436 1,821 366 413 403 385 1,566 1,280 1,228 1,210 1,155 4,873 Daily Volume (MMBtu/d) 5,256 5,066 4,902 4,739 4,989 4,067 4,533 4,375 4,185 4,290 14,066 13,489 13,152 12,554 13,313 WAVG Swap Price ($ / MMBtu) ($0.58) ($0.96) ($1.19) ($1.25) ($0.99) ($0.58) ($0.85) ($1.09) ($1.08) ($0.90) ($0.51) ($0.83) ($1.09) ($1.06) ($0.86) REX Zone 3 Basis Swaps Total Volume (BBtu) - 4,230 4,640 4,140 13,010 2,775 2,775 2,775 2,775 11,100 4,490 4,366 4,270 4,158 17,284 Daily Volume (MMBtu/d) - 46,484 50,435 45,000 35,644 30,833 30,495 30,163 30,163 30,411 49,341 47,981 46,413 45,190 47,223 WAVG Swap Price ($ / MMBtu) - ($0.41) ($0.48) ($0.31) ($0.40) $0.13 ($0.35) ($0.35) ($0.24) ($0.20) $0.18 ($0.28) ($0.33) ($0.21) ($0.16)
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17 Hedge Book Overview – As of 6 -Aug -26 17 FY 2029 FY 2030 FY 2031 Q1 Q2 Q3 Q4 2029 Q1 Q2 Q3 Q4 2030 Q1 Q2 Q3 Q4 2031 WTI Fixed Swaps Total Volume (MBbl) - - - - - - - - - - - - - - - Daily Volume (Bbl/d) - - - - - - - - - - - - - - - WAVG Swap Price ($ / Bbl) - - - - - - - - - - - - - - - WTI Fixed Collars Total Volume (MBbl) - - - - - - - - - - - - - - - Daily Volume (Bbl/d) - - - - - - - - - - - - - - - WAVG Ceiling Price ($ / Bbl) - - - - - - - - - - - - - - - WAVG Floor Price ($ / Bbl) - - - - - - - - - - - - - - - Henry Hub Fixed Swaps Total Volume (BBtu) 7,780 7,600 7,420 7,170 29,970 6,800 6,630 6,530 6,350 26,310 - - - - - Daily Volume (MMBtu/d) 86,444 83,516 80,652 77,935 82,110 75,556 72,857 70,978 69,022 72,082 - - - - - WAVG Swap Price ($ / MMBtu) $4.06 $3.14 $3.44 $3.80 $3.61 $4.02 $3.10 $3.37 $3.73 $3.56 - - - - - Dom South Basis Swaps Total Volume (BBtu) - - - - - - - - - - - - - - - Daily Volume (MMBtu/d) - - - - - - - - - - - - - - - WAVG Swap Price ($ / MMBtu) - - - - - - - - - - - - - - - Dom South Fixed Swaps Total Volume (BBtu) - - - - - - - - - - - - - - - Daily Volume (MMBtu/d) - - - - - - - - - - - - - - - WAVG Swap Price ($ / MMBtu) - - - - - - - - - - - - - - - Tetco M2 Basis Swaps Total Volume (BBtu) - - - - - - - - - - - - - - - Daily Volume (MMBtu/d) - - - - - - - - - - - - - - - WAVG Swap Price ($ / MMBtu) - - - - - - - - - - - - - - - REX Zone 3 Basis Swaps Total Volume (BBtu) - - - - - - - - - - - - - - - Daily Volume (MMBtu/d) - - - - - - - - - - - - - - - WAVG Swap Price ($ / MMBtu) - - - - - - - - - - - - - - -
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18 Hedge Book Overview – As of 6 -Aug -26 18 FY 2026 FY 2027 FY 2028 FY 2029 Q1 Q2 Q3 Q4 2026 Q1 Q2 Q3 Q4 2027 Q1 Q2 Q3 Q4 2028 Ethane Fixed Swaps Total Volume (MGal) 2,441 2,440 2,294 2,137 9,312 1,902 1,854 1,750 1,610 7,116 - - - - - Daily Volume (Gal/d) 27,122 26,813 24,935 23,228 25,512 21,133 20,374 19,022 17,500 19,496 - - - - - WAVG Swap Price ($ / Gal) $0.28 $0.27 $0.28 $0.29 $0.28 $0.27 $0.23 $0.23 $0.24 $0.24 - - - - - Propane Fixed Swaps Total Volume (MGal) 5,259 9,696 13,976 13,832 42,763 9,619 9,415 8,725 7,747 35,506 - - - - - Daily Volume (Gal/d) 58,433 106,549 151,913 150,348 117,159 106,878 103,462 94,837 84,207 97,277 - - - - - WAVG Swap Price ($ / Gal) $0.76 $0.74 $0.76 $0.76 $0.75 $0.77 $0.70 $0.70 $0.71 $0.72 - - - - - Normal Butane Fixed Swaps Total Volume (MGal) 1,547 2,809 3,879 3,773 12,008 2,571 2,597 2,435 2,161 9,764 - - - - - Daily Volume (Gal/d) 17,189 30,868 42,163 41,011 32,899 28,567 28,538 26,467 23,489 26,751 - - - - - WAVG Swap Price ($ / Gal) $0.87 $0.91 $0.93 $0.92 $0.91 $0.94 $0.84 $0.83 $0.84 $0.86 - - - - - IsoButane Fixed Swaps Total Volume (MGal) 951 1,976 2,893 2,944 8,764 2,092 2,027 1,872 1,657 7,648 - - - - - Daily Volume (Gal/d) 10,567 21,714 31,446 32,000 24,011 23,244 22,275 20,348 18,011 20,953 - - - - - WAVG Swap Price ($ / Gal) $0.89 $0.95 $0.98 $0.94 $0.95 $0.97 $0.89 $0.87 $0.88 $0.91 - - - - - Natural Gasoline Fixed Swaps Total Volume (MGal) 772 2,472 3,411 3,346 10,001 2,354 2,415 2,276 2,005 9,050 1,010 900 830 770 3,510 Daily Volume (Gal/d) 8,578 27,165 37,076 36,370 27,400 26,156 26,538 24,739 21,793 24,795 11,099 9,890 9,022 8,370 9,590 WAVG Swap Price ($ / Gal) $1.40 $1.59 $1.54 $1.47 $1.52 $1.47 $1.39 $1.36 $1.35 $1.39 $1.42 $1.38 $1.36 $1.35 $1.38
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19 Three Months Ended Twelve Months Ended, ($ in thousands) 06/30/25 03/31/26 06/30/26 12/31/24 12/31/25 Net Income $71,954 ($6,343) $112,909 $49,286 $63,959 Add: Interest expense, net $1,360 $5,789 $14,733 $21,529 $9,667 Provision / (benefit) for income taxes ($604) ($348) $548 $0 ($4,858) Depreciation, depletion and amortization $23,652 $35,660 $44,414 $73,726 $103,750 Net cash settlements received / (paid) on deriv. $2,778 ($17,992) ($6,427) $28,360 $12,214 Non-recurring transaction expenses $331 $13,452 $3,035 $771 $1,601 Non-cash compensation expenses1 $2,293 $1,912 $3,003 $0 $133,053 Less: $331 (Gain) / loss on derivative instruments ($52,121) $65,134 ($57,542) $22,047 ($58,407) Adjusted EBITDAX 49,641$ 97,264$ 114,673$ 195,719$ 260,978$ 19 Adjusted EBITDAX Reconciliation 1. Represents adjusted EBITDAX for the three months shown on an annualized basis Adjusted EBITDAX Adjusted EBITDAX is defined as net income plus interest expense, other expense, income tax expense and benefit, depreciation, depletion, and amortization, unrealized gain (loss) on derivative instruments, net cash settlements received (paid) on derivatives, non-cash compensation expense and non-recurring transaction expenses. Adjusted EBITDAX is presented on our management’s belief that this non-GAAP measure is useful information to investors when comparing our operating performance, our ability to fund development activities and to service our incurred debt without regard to our financing methods, corporate form or capital structure. Our computations of Adjusted EBITDAX may differ from and may not be comparable to similarly titled measures of other companies. Adjusted EBITDAX Margin is defined as Adjusted EBITDAX divided by total production. Net Debt and Net Debt to Adjusted EBITDAX (or Net Leverage) Net Debt is calculated by subtracting cash and cash equivalents from total debt. Net Debt is a non-GAAP measures which our management believes are also useful to investors when assessing our leverage since we have the ability to and may decide to use a portion of our cash and cash equivalents to retire debt. Our management uses this measures for that purpose. Net Leverage (x) Note: Adjusted EBITDAX is a non-GAAP financial measure. 1. Includes stock-based compensation expense for equity awards related to general and administrative employees only. Three Months Ending ($ in thousands) 06/30/25 09/30/25 12/31/25 03/31/26 06/30/26 Total debt outstanding 34,378$ 75,363$ 150,847$ 537,648$ 538,150$ Plus: Unamortized Issuance Fees -$ -$ -$ 12,352$ 11,850$ Less: Cash and cash equivalents (6,282)$ (4,572)$ (64,049)$ (72,983)$ (25,883)$ Net debt outstanding 28,096$ 70,791$ 86,798$ 477,017$ 524,117$ Quarter Ending Adjusted EBITDAX 49,641$ 60,049$ 94,042$ 97,264$ 114,673$ Last Quarter Annualized Adjusted EBITDAX1 198,564$ 240,196$ 376,169$ 389,056$ 458,692$ Net debt to LQA EBITDAX 0.1x 0.3x 0.2x 1.2x 1.1x Non -GAAP Reconciliations and Definitions
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20 Fiscal Year Ending December 31, ($ in thousands) 2023 2024 2025 Future cash inflows 3,865,302$ 4,181,440$ 5,511,802$ Future development costs1 (545,803) (652,135) (764,219) Future production costs (1,281,802) (1,548,957) (1,824,402) Future net cash flow 2,037,697$ 1,980,348$ 2,923,181$ Discounted future income tax expense - - (531,583) 10% discount to reflect timing of cash flows (1,099,313) (1,007,830) (1,310,404) Standardized measure of disc. net cash flows 938,384$ 972,518$ 1,081,193$ Pre-Tax PV - 10 938,384$ 972,518$ 1,332,993$ Proved Reserves Pre-Tax PV-10 Proved Reserves SEC PV-10 represents the estimated present value of the future cash flows less future development and production costs from our proved and probable reserves before income taxes discounted using a 10% discount rate. PV- 10 of proved reserves generally differs from the standardized measure of discounted future net cash flows from production of proved oil and natural gas reserves (the “Standardized Measure”), the most directly comparable GAAP financial measure, because it does not include the effects of future income taxes, as is required under GAAP in computing the Standardized Measure. We believe that the presentation of a pre-tax PV-10 value provides relevant and useful information because it is widely used by investors and analysts as a basis for comparing the relative size and value of our proved reserves to other oil and natural gas companies. Because many factors that are unique to each company may impact the amount and timing of future income taxes, the use of PV-10 value provides greater comparability when evaluating oil and natural gas companies. The PV-10 value is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of proved oil and gas reserves. However, the definition of PV-10 value as defined above may differ significantly from the definitions used by other companies to compute similar measures. As a result, the PV-10 value as defined may not be comparable to similar measures provided by other companies. All-In Finding & Development Costs (“F&D”) All-In F&D is calculated by dividing total costs incurred (which includes the total acquisition, exploration and development costs incurred during the period related to the specified property or group of properties) by the sum of the extensions, discoveries, additions, revisions, and purchases during that period. All-in F&D ($ / mcfe) Proved Reserves Pre-Tax PV-10 ($mm) Fiscal Year Ending December 31, ($ in thousands) 2023 2024 2025 Acquisition Costs: Proved properties 274,732$ 19,172$ 44,585$ Unproved properties 1,047 89,174 5,236 Development Costs 144,121 165,795 274,723 Exploration Costs - - - Total Acquisition and Development Costs 419,900$ 274,143$ 324,544$ Reserve Additions: Extensions 267,450 216,108 402,953 Revisions to previous estimates (144,414) 9,354 2,198 Purchases of reserves in place 289,164 - - Total Reserve Additions 412,200 225,462 405,150 All-In F&D ($ / mcfe) $1.02 $1.22 $0.80 Non -GAAP Reconciliations and Definitions
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21 Capital Efficiency Capital Efficiency Ratio means Adjusted EBITDAX per unit of production divided by finding and development costs (“F&D”) per mcfe. F&D is calculated by dividing total costs incurred (which includes the total acquisition, exploration and development costs incurred during the period related to the specified property or group of properties) by the sum of the extensions, discoveries, additions, revisions, and purchases during that period. DROI DROI refers to Discounted Return on Investment, which is defined as the present value at a 10% discount rate of future net cashflows excluding capital expenditures divided by the net capital expenditures associated with the development of a horizontal well. Capital Efficiency (x) Fiscal Year Ending December 31, ($ in thousands) 2023 2024 2025 Adjusted EBITDAX 126,494$ 195,719$ 260,978$ Total Net Production (MMcfe) 41,406 52,908 77,292 Adjusted EBITDA Margin ($ / mcfe) 3.05$ 3.70$ 3.38$ All-In F&D ($ / mcfe) 1.02$ 1.22$ 0.80$ Capital Efficiency 3.00x 3.04x 4.22x Non -GAAP Reconciliations and Definitions