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2Q 2025 Earnings Presentation Pearce Hammond, Vice President IR (713) 571-4684, phammond@eogresources.com Neel Panchal, Senior Director IR (713) 571-4884, npanchal@eogresources.com Shelby OâConnor, Manager IR (713) 571-4560, soconnor@eogresources.com
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2Q 2025 Sustainable Value Creation Through Industry Cycles EOG is focused on being among the highest return and lowest cost producers, committed to strong environmental performance and playing a significant role in the long-term future of energy Capital Discipline ⢠Returns-Focused Investments Guided by Bottom-Cycle Prices ⢠Pristine Balance Sheet and Significant Free Cash Flow1 Generation ⢠Sustainable, Growing Regular Dividend Anchors Commitment to Return Minimum 70% of Annual Free Cash Flow1 ⢠Reinvestment Pace Supports Continuous Improvement Across Multi-Basin Portfolio Operational Excellence ⢠Organic Exploration Maintains Low Cost, High Quality, Multi-Basin Inventory ⢠Superior In-House Technical Expertise, Proprietary Information Technology, and Self- Sourced Materials Support Well Performance & Cost Control ⢠Product, Geographic, and Pricing Diversification Enhances Margins Sustainability ⢠Committed to Safe Operations, Leading Environmental Performance, and Community Engagement ⢠Strategic Emissions Reduction Pathways Culture ⢠Decentralized, Non-Bureaucratic Structure Enables Value Creation in the Field, at the Asset Level ⢠Collaborative, Multi-Disciplinary Teams Drive Innovation ⢠Technology Leadership and Real-Time, Data-Driven Decision Making (1) See (1) schedules posted to âInvestorsâ section of EOG website for reconciliations & definitions of non-GAAP and other measures and related discussion and (2) âSupplemental Informationâ at end of this presentation for additional definitions & information, including regarding forward-looking non-GAAP financial measures. 2
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Outstanding Operational Execution ⢠Volumes, Capital Expenditures, and Per-Unit Operating Costs Better Than Targets1 ⢠Updated Full-Year Guidance After Encino Acquisition ⢠Peer Leading US Price Realizations 2Q 2025 Results & Highlights 2Q 2025 Strong Financial Results ⢠$1.3 Bn Adjusted Net Income2 ⢠$2.32 Adjusted EPS2 and $4.57 Adjusted CFPS2 ⢠$1.0 Bn Free Cash Flow2 Delivering on Cash Return Commitment ⢠Increased Regular Quarterly Dividend Rate 5%4 ⢠Returned $1.1 Bn to Shareholders ⢠Paid $0.5 Bn in Regular Dividends ⢠Executed $0.6 Bn of Share Repurchases2 Continuing to Improve Multi-Basin Portfolio ⢠Acquired Encino Creating Premier Utica Asset Position Totaling 1.1 MM Net Acres3 ⢠Awarded Onshore Concession in the UAE to Explore and Appraise ~900K Acre Unconventional Oil Prospect (1) Based on midpoints of 2Q 2025 guidance, as of May 1, 2025. (2) See (1) schedules posted to âInvestorsâ section of EOG website for reconciliations & definitions of non-GAAP and other measures and related discussion and (2) âSupplemental Informationâ at end of this presentation for additional definitions & information, including regarding forward-looking non-GAAP financial measures. (3) Reflects core net acreage. Total acquired acreage of ~1.2 MM net acres. Definitive acquisition agreement dated May 30, 2025 and closed August 1, 2025. (4) Effective beginning with regular dividend payable October 31, 2025. 3
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Updated 2025 Guidance After Encino Acquisition Focus on Capital Discipline Delivers Significant Free Cash Flow & Shareholder Returns (1) Based on midpoints of full-year 2025 guidance, as of August 7, 2025. (2) See (1) schedules posted to âInvestorsâ section of EOG website for reconciliations & definitions of non-GAAP and other measures and related discussion and (2) âSupplemental Informationâ at end of this presentation for additional definitions & information, including regarding forward-looking non-GAAP financial me asures. 2Q 2025 G&P, Environmental, Other Facilities Strategic Infrastructure International Exploration Domestic Capital Program ⢠Updated Plan Delivers ~$4.3 Bn Free Cash Flow1,2 at $65 WTI and $3.50 HH ⢠Reflects Integration of Encino Acquisition ⢠Maintains Capital Efficient Program in Delaware Basin and Eagle Ford ⢠Continued Investments in Emerging Plays, Exploration & International Opportunities ⢠Targets Low Single-Digit Percentage Reduction for Well Costs in 2025 ⢠Committed $3.5 Bn of Cash Return YTD Through Regular Dividend and Share Repurchases 1,224 MBOED Average Total Production1 521 MBOD Average Oil Production1 Cash Operating Costs DD&A $10.351 G&A LOE GP&T $10.051 $6.3 Bn1 4
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Cash Flow Priorities Support Sustainable Value Creation 2Q 2025 Regular Dividend ⢠Sustainable and Growing Regular Dividend ⢠Primary Mode of Cash Return to Shareholders ⢠Competitive Across Peer Group & Broader Market Capital Investment ⢠Investment Pace in Each Asset to Optimize Returns & NPV ⢠Align Investment with Short- & Long-Term Supply and Demand Fundamentals ⢠Multi-Basin Portfolio of Oil and Gas Assets Balance Sheet ⢠Industry Leading Balance Sheet ⢠Ability to Invest in Low-Cost Property Bolt-Ons and Other Counter-Cyclical Opportunities Cash Return ⢠Regular Dividend Complemented by Opportunistic Share Repurchases and Special Dividends ⢠Balance Sheet Supports Ability to Return 100% of Annual Free Cash Flow1 in Near-Term Increased Regular Dividend 8% For 20251 (1) See (1) schedules posted to âInvestorsâ section of EOG website for reconciliations & definitions of non-GAAP and other measures and related discussion and (2) âSupplemental Informationâ at end of this presentation for additional definitions & information, including regarding forward-looking non-GAAP financial measures. (2) Based on midpoints of full-year 2025 guidance, as of August 7, 2025. (3) At $45 WTI and $2.50 HH. Cash Flow Priorities Share Repurchases1 $1.4 Bn Executed 1H 2025 Target Total Debt to EBITDA 1,3 <1.0x 5 Oil (MBOD) 5212025 Average Production2 Total (MBOED) 1,224
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Multi-Basin Portfolio of Long Duration, High Return Inventory 12+ Billion Boe of Resource1 Across Portfolio 2Q 2025 Average Direct After-Tax Rate of Return1 For 12+ Bn Boe of Resource1 55% 100% 200% $45 & $2.50 $55 & $3.00 $65 & $3.50 Comprehensive Approach to Developing Acreage for Value Creation Through Industry Cycles ⢠Delivers Double Digit ROCE1 at Bottom-Cycle Pricing ⢠Evaluate Rate of Return, Net Present Value, Margins, Payback Period, and Other Key Metrics Organic Exploration Expertise & Strategic Acquisitions Unlock Low-Cost, High-Quality Resource ⢠Continue to Improve Inventory Quality and Duration Through Improved Productivity and Lowering Costs ⢠Resource Estimate Does Not Include Trinidad and Other Exploration Opportunities >55% >100% >200% (1) See (1) schedules posted to âInvestorsâ section of EOG website for reconciliations & definitions of non-GAAP and other measures and related discussion and (2) âSupplemental Informationâ at end of this presentation for additional definitions & information, including regarding forward-looking non-GAAP financial measures. 6
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2Q 2025 7 Encino Acquisition Creates Premier Utica Asset Position Returns-Focused Acquisition Transitions Utica to a Foundational Play (1) Reflects core net acreage and associated estimated undevelope d net resource potential (not proved reserves). Total acquired acreage of ~1.2 MM net acres. Strong Strategic Fit ⢠Expands Asset to 1.1 Million Net Acres & 2.0+ Bn Boe of Undeveloped Net Resource1 ⢠Enhances Liquids Acreage Footprint with Addition of 235K Net Acres in Volatile Oil Window ⢠Adds Premium Gas Exposure with Addition of 330K Net Acres Across Wet and Dry Gas Windows ⢠Increases Average Working Interest in Northern Acreage Returns Focused Acquisition ⢠Immediately Accretive Across Multiple Financial Metrics ⢠Estimate $150MM of Synergies to be Realized in First Year ⢠EOG Technical Expertise Enhances Returns 2025 Plan Update ⢠2025 Plan Integrates Encino Scheduled Activity ⢠5 Rigs and 3 Completion Crews Through Year-End ⢠65 Net Completions Ohio West Virginia Pennsylvania EOG Acreage Encino Acreage Overlapping Acreage
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2Q 2025 Net Wells Developed to Date Direct Well Cost ($/ft) 1 Payback Period2 (Months) Finding Cost ($/boe) (1) Direct Well Costs = Drilling, Completion, Well-Site Facilities, and Flowback. (2) Average payback period of wells completed year-to-date, calculated at $65 WTI and $3.50 HH. Utica is leveraging learnings from existing plays to improve economics and margins faster than ever. Premier Utica Asset Moves to Foundational Play Highly Competitive in Differentiated Multi-Basin Portfolio Utica Delaware EFUtica Delaware Basin Eagle Ford 50+ 2,500+ 3,600+ Utica Delaware EFUtica Delaware Basin Eagle Ford <$650/ft <$750/ft <$550/ft Utica Delaware EFUtica Delaware Basin Eagle Ford 9.3 9.3 7.5 Utica Delaware EFUtica Delaware Basin Eagle Ford <$7.00 <$6.00 <$10.00 8
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2Q 2025 9 EOG A B C D E F Peer Avg GH I J K Differentiated Approach to Delaware Basin Development Leveraging Core Competencies to Drive Industry Leading Results Extensive Subsurface Expertise Drives Optimal, High-Return Codevelopment ⢠Uniquely Defined & Highly Productive Targets ⢠Shallow and Deep Zones Deliver Comparable Returns of >55% at Bottom-Cycle Pricing2 ⢠9 Distinct Targets Added to Development Program Over Last 5 Years Operational Excellence Compounds Benefits of Extended Laterals ⢠In-House Motor Program Reduces Trips Downhole and Total Time to Drill ⢠Consistent EUR/ft Delivered by Proprietary High-Intensity Completion Design ⢠Smaller Surface Footprint and Less Infrastructure Per Acre Peer Leading Breakeven Price1 Oil Price Required for NPV10 EOG ~20% Lower than Peer Avg. EOG Increasing Avg. Lateral Length 20%+ For 2025 Program (1) Peers include APA, CIVI, COP, CTRA, CVX, DVN, Mewbourne, MTDR , OXY, PR, XOM. Data sourced from Rystad Energy (ShaleWellCube, February 2025). (2) Direct after-tax rate of return. SUBSURFACE EXPERTISE OPERATIONAL EXCELLENCE LEADING ECONOMICS Leonard Bone Spring Wolfcamp TEXAS NEW MEXICO
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2Q 2025 10 Improving Economics and Adding Resource in the Eagle Ford Long Runway for Additional Value Creation After 15+ Years of Development ⢠30K Net Acre Bolt-On in Atascosa County Completed in 2Q ⢠Started Drilling Operations on Acquired Acreage with 8-Well Package Adding Competitive, High-Return Resource Core Area 565,000 Net Acres Frio Karnes De WittWilson Gonzales Atascosa McMullenLa Salle Webb Improving Economics Through Efficiencies Increase in Average Lateral Length5%+ Target Maximum Lateral Length (Ft)24.5K Direct Well Cost Reduction6% Wells Exceeding 3+ Mile Laterals15% TEXAS Whistler E #5H Longest Lateral in Texas - 24,128 ft 2025 Program
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2Q 2025 11 La SalleWebb Dimmit Agua Dulce Dorado Asset Encinal Agua Dulce Provides Access to: ⢠Corpus Christi, Freeport, and Brownsville LNG Terminals ⢠Premium Markets: ⢠Zone 3 St. 65 Serving Southeast Power Demand Growth ⢠Henry Hub ⢠Mexico Exports Dorado: Lowest Cost Dry Gas Play in North America Highly Prolific Wells with Access to Premium Markets TEXAS Breakeven Price1 $1.40 $1.55 $1.90 Dorado Haynesville Marcellus (1) Breakeven price includes Direct F&D, LOE, GP&T, G&A, and Production Tax. Dorado data sourced from internal EOG data. Haynesville and Marcellus data sourced from Rystad Energy (ShaleWellCube, April 2025) and IHS. (2) Per well production data averaged and normalized to 11,000 ft, the average lateral length of the 2024 and 2025 Dorado progra ms. Core Area 160,000 Net Acres TEXAS 2023 2024 2025 0 10 20 03 0 6 0 9 0 Average Production Rates2 $/mcf MMcfd
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Gulf States Exploration Opportunities Leveraging Core Competencies to Improve Multi-Basin Portfolio UAE Bahrain Saudi Arabia Oman Qatar Saudi Arabia Oman UAE Bahrain Gulf of Oman Arabian Gulf Arabian Gulf Gulf of Aden Abu Dhabi Dubai Manama EOG Gas Exploration Prospect EOG Exploration and Technical Expertise ⢠Apply Proprietary Horizontal Drilling and Completions Technologies to Unlock High-Return Unconventional Resource ⢠Target Formations with Positive Production Results from Prior Horizontal Development Tests UAE: Exploration Concession Awarded by Abu Dhabi Government in Partnership with ADNOC ⢠Unconventional Onshore Oil Prospect ⢠~900K Acres in Concession Area ⢠Planned Drilling Activity in 2025 Bahrain: JV Partnership with Bapco ⢠Unconventional Onshore Gas Prospect ⢠Planned Drilling Activity in 2025 ⢠Production to be Sold Into Local Market 2Q 2025 EOG Oil Exploration Prospect 12
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2Q 2025 13 Marketing Strategy Captures Premium Gas Markets Strategic Infrastructure and Transport Agreements Support Margin Enhancement and Peer Leading Price Realizations Delaware Basin â Janus Gas Processing Plant ⢠Janus Gas Processing Plant to Matterhorn Pipeline to Multiple Premium Gulf Coast Markets ⢠300 MMcfd Plant Supports Permian Operations ⢠Phase 1 Completed 2025; Phase 2 Optionality South Texas Dorado â Verde Pipeline ⢠Verde Pipeline to Transco TLEP1 to LNG and Premium Southeast (SE) Markets ⢠1 Bcf Per Day Pipeline Supports Dorado Operations ⢠Phase 1 Completed 2023; Phase 2 Completed 2024 Henry Hub Waha NTX/ETX HSC/Katy Wharton West Coast EOG Connectivity to Improved Pricing EOG Supply Basins EOG Janus Plant EOG Verde Pipeline LNG Terminals Gas Markets Existing Transport Capacity New Transport Capacity MEXICO TEXAS LOUISIANA NEW MEXICO SE Power Demand Agua Dulce Zone 3 St. 65 Pool Dorado Eagle Ford Delaware Basin (1) Transco TLEP (Texas to Louisiana Energy Pathway) owned and operated by The Williams Companies (WMB).
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2Q 2025 Gas Sales Agreements Provide Pricing Diversification (1) Contractual sales volume increase contingent upo n startup of Cheniere Corpus Christi Stage III project. (2) EOG revenue net of working interest owner sales volumes and royalty payments, as of December 31, 2024. (3) Brent-linked gas sales 10-year agreement starting January 2027. (4) JKM-linked gas sales and HH-linked gas sales 15-year agreements starting upon completion of Cheniere Corpus Christi Stage III project. Brent-Linked Gas Sales Agreement ⢠Sales Volumes of 140K MMBtu Per Day Linked to Brent ⢠Additional 40K MMBtu Per Day Linked to Brent or US Gulf Coast Gas Index ⢠10-Year Agreement with Firm January 2027 Start Date ⢠First Mover on US Sales Volumes Linked to Historically More Stable Oil Index Japan Korea Marker-Linked Gas Sales Agreement ⢠Sales Volumes Grow from 140K MMBtu Per Day to 420K MMBtu Per Day Under 15-Year Agreements1 ⢠JKM Average Market Price of ~$16/Mcf from Contract Inception ⢠~$1.3 BN Cumulative Revenue Uplift Net to EOG from Contract Inception2 Henry Hub-Linked Gas Sales Agreement ⢠Sales Volumes of 300K MMBtu Per Day Under 15-Year Agreements1 ⢠Henry Hub-Linked Pricing Removes Basis Differential Adjustments Flexibility to Source Contract Volumes from Several Basins Within EOGâs Multi-Basin Portfolio 140 140 420 420 420 420 420 300 300 300 300 300 300 140 140 140 140 40 40 40 40 2024 2025 2026 2027 2028 2029 2030 Gross Sales Volumes3,4 K MMBtu per day Linked to Brent Linked to Henry Hub 1 Linked to JKM or Henry Hub 3,4 900 900 900 900 720 Linked to Brent or US Gulf Coast Gas 32020-2024 Significant Uplift Potential ~$1.3 Bn Cumulative Revenue Uplift2 440 14
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2Q 2025 15 Peer Leading 2Q 2025 US Price Realizations1 $63.08 $64.84 Peer Average Oil $1.48 $2.87 Peer Average EOG $18.57 $22.70 Peer Average NGL ~$1.76/Bbl. Higher than Peer Avg. EOG EOG EOG ~$1.39/Mcf Higher than Peer Avg. ~$4.13/Bbl. Higher than Peer Avg. (1) Data sourced from company filings. 2Q 2025 peer average include s only peer companies that have reported 2Q 2025 results on or prior to August 6, 2025 (APA, CIVI, CTRA, CVX, DVN, FANG, MTDR, OXY, OVV, PR, and XOM). Oil Price Realization, $/Bbl. Gas Price Realization, $/Mcf NGL Price Realization, $/Bbl.
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1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025E 27 Years of Sustainable, Growing Regular Dividend Regular Dividend is a $2.1 Bn Cash Return Commitment for 20251 2Q 2025 (1) See (1) schedules posted to âInvestorsâ section of EOG website for reconciliations & definitions of non-GAAP and other measures and related discussion and (2) âSupplemental Informationâ at end of this presentation for additional definitions & information, including regarding forward-looking non-GAAP financial measures. Note: Dividends adjusted for 2-for-1 stock splits effective March 1, 2005 and March 31, 2014. 1 $3.95 Increased Regular Dividend 8% For 20251 16
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2020 2021 2022 2023 2024 2025 YTD Strong Cash Return Delivers Shareholder Value Committed YTD 81% of 2025E Annual Free Cash Flow1 2Q 2025 17 Cash Return to Shareholders Share Repurchases1 Special Dividends Regular Dividends $2.7 Bn $5.1 Bn $4.4 Bn $5.3 Bn $5.6 Bn FCF1 at $68 WTI & $3.85 HH $7.6 Bn FCF1 at $94 WTI & $6.64 HH $5.1 Bn FCF1 at $78 WTI & $2.74 HH $5.4 Bn FCF1 at $76 WTI & $2.27 HH $1.8 Bn $0.9 Bn $3.3 Bn $1.8 Bn $1.5 Bn $1.9 Bn $1.0 Bn $2.1 Bn $3.2 Bn $0.8 Bn $1.6 Bn FCF1 at $39 WTI & $2.08 HH $0.8 Bn (1) See (1) schedules posted to âInvestorsâ section of EOG website for reconciliations & definitions of non-GAAP and other measures and related discussion and (2) âSupplemental Informationâ at end of this presentation for additional definitions & information, including regarding forward-looking non-GAAP financial measures. Committed YTD $4.3 Bn FCF1 FY Estimate at $65 WTI & $3.50 HH $3.5 Bn $2.1 Bn $1.4 Bn
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Environmental Targets, Ambition, & Strategy Announcing New Emissions Targets 2Q 2025 REDUCE ⢠Optimizing wellhead and facility gas capture systems ⢠Expanding continuous leak detection (iSenseÂŽ) and aerial-based survey technologies ⢠Centralizing compression and optimizing artificial lift systems CAPTURE ⢠Operating carbon capture & storage (CCS) pilot project ⢠Prioritizing pure stream CO 2 emissions sources ⢠Evaluating additional CCS opportunities OFFSET ⢠Evaluating projects and other options to offset remaining emissions (1) Metric tons of gross operated GHG emissions (Scope 1), on a CO2e basis, per Mboe of total gross operated U.S. onshore and Trinidad production. (2) Includes Scope 1 emissions (i) reported to the EPA pursuant to the EPA Greenhouse Gas Reporting Program (GHGRP) and emissions that are subject to the EPA GHGRP but are below the basin reporting threshold and would otherwise go unreported calculated using the GHGRP methodology as adopted in 2024 and (ii) from our Trinidad operations calculated using the GHGRP methodology as adopted in 2024. (3) Based on methane emissions percentage calculated as thous and cubic feet (Mcf) of gross operated methane emissions per Mcf of total gross operated U.S. onshore and Trinidad natural gas production. (4) Net zero Scope 1 and Scope 2 GHG emissions by 2040. See EO Gâs 2023 Sustainability Report for definitions, formulas, and additional information. Note: Reaching and maintaining our near-term targets and net zero ambition are subject to risks and uncertainties. Please see âCautionary Notice Regarding Forward-Looking Statementsâ included herein. Net Zero Ambition4 Emissions Reduction Pathways Reduce GHG Emissions Intensity Rate1,2 25% from 2019 By 2030 Maintain Near-Zero Methane Emissions 2,3 0.20% or less 2025-2030 Near-Term Emissions Targets Maintain Zero Routine Flaring ZERO routine flaring 2025-2030 18
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Sustainable Value Creation Through Industry Cycles 2Q 2025 Capital Discipline Operational Excellence Sustainability EOG Culture At the foundation of EOGâs historical and future success are the employees who embrace and embody the EOG culture. The companyâs decentralized, non-bureaucratic structure enables value creation in the field, at the asset level. Every employee is a businessperson first and remains committed to returns, best-in-class exploration, technology leadership, collaborative, multi-disciplinary innovation, and responsible operations. EOGâs culture continues to be the most valuable asset driving a sustainable competitive advantage. 19
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Supplemental Information 2Q 2025 Adjusted Cash Flow from Operations: cash flow from operations before changes in working capital and certain acquisition-related costs. Adjusted Cash Flow Per Share (CFPS): adjusted cash flow from operations divided by average diluted shares. Cash Recycle Ratio: calculated as full-year 2024 cash flow from operations before cha nges in working capital (non-GAAP) ($11,593 MM) divided by full- year 2024 total production (389 MMBoe), with such r esulting quotient divided by full-year 2024 all-in total finding and development cost, excluding revisions due to price (non-GAAP) ($6.68 / Boe). See schedules posted to âInvestorsâ section of EOG website for corresponding GAAP measures and related reconciliations. Commodity Price Sensitivities : each $1 per bbl increase or decrease in crude oil and condensate price, combined with the estimated change in NGLs price, is approximately $214 million for pretax cash flows from operating activities. Each $0.10 per thousand cubic feet increase or decrease in natural gas price is approximately $46 million for pretax cash flows from operating activities. Includes impact of associated financial commodity derivative c ontracts. Dividends: 8% increase in regular dividend for 2025 reflec ts aggregate quarterly dividends paid/declared for 2025 ($3.945 per share) versus aggregate quarterly dividends paid for 2024 ($3.64 per share). $2.1 billion annual c ommitment is based on regular dividends paid in 1H 2025 plus (1) regular dividend of $0.975 per share paid on July 31, 2025 and (2) regular dividend of $1.02 per share payable on October 31, 2025. Forward-Looking Non-GAAP Financial Measures: see âCautionary Notice Regarding Forward-Looking Non-GAAP Financial Measuresâ on following slide. Free Cash Flow (FCF) (non-GAAP measure): adjusted cash flow from operations less CAPEX. Resource: resource potential net to EOG, not proved reserves. See related discussion under âOil and Gas Reservesâ on following slide. Return on Capital Employed (ROCE) (non-GAAP measure): does not include the impact of derivative contracts. Share Repurchases : data included in this presentation and related references represent repurchases pursuant to the Board-authorized repurchase program. 20
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Copyright; Assumption of Risk: Copyright 2025. This presentation and the contents of this presentation have been copyrighted by EOG Resources, Inc. (EOG). All rights reserved. Cop ying of this presentation is forbidden without the prior written consent of EOG. Information in this presentation is provided âas isâ without warranty of any kind, either express or implied, including but not limited to the implied warranties of mercha ntability, fitness for a particular pur pose and the timeliness of the information. You assume all risk in using the i nformation. In no event shall EOG or its representatives be liable for any s pecial, indirect or consequential damages resulting from the use of the information. Cautionary Notice Regarding Forward-Looking Statements: This presentation may include forward-looking statements within the me aning of 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, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, goa ls, returns and rates of return, budgets, reserves, levels of production, ca pital expenditures, operating costs and asset sales, statements regard ing future commodity prices, statements regarding the plans and objectives of EOG's management for future operations and statements and projections regarding the strategic rationale for, and antici pated benefits of, EOGâs acquisition of Encino Acquisition Partners, LLC (Encino) are forward âlooking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "aims," "ambition," "initiative," "goal," "may," "will," "focused on," "should" and "believ e" or the negative of those terms or other variations or comparable terminology to identify its forward âlooking statements. In particular, statements, express or implied, concerning (i) EOG's future financial or operating results and returns, (ii) EOG's ability to replace or i ncrease reserves, increase production, generate returns and rates of r eturn, replace or increase drilling locations, reduce or otherwise contro l drilling, completion and operating costs and capital expenditures, gen erate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet in itiatives, plans, goals, ambitions or targets with respect to emissions, other environmental mat ters or safety matters, pay and/or increase regular and/or special dividends or repurchase shares or (iii) the successful integration of Encinoâs as sets and operations or the strategic rationale for, or anticipated benefits of, EOGâs acquisition of Encino, in each case are forward âlooking statements. Forward-looking statements are not guarantees of pe rformance. Although EOG believes the expectations reflected in its forwar d-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that such assumptions are accurate or will prove to have been correct or that any of such expectations will be achieved (in full or at all) or will be achie ved on the expected or anticipated timelines. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG' s actual results to differ materially from the expectations reflected in EO G's forward-looking statements include, among others: ⢠the timing, magnitude and duration of changes in pri ces for, supplies of, and demand for, crude oil and condensate, natural gas liquids (NGLs), natura l gas and related commodities; ⢠the extent to which EOG is successful in its efforts to acquire or discover additional reserves; ⢠the extent to which EOG is successful in its efforts to (i) economically develop its acreage in, (ii) produce reserves and achieve anticipated product ion levels and rates of return from, (iii) decrease or otherwise control its drilling, completion and operating costs and capital expenditures relat ed to, and (iv) maximize reserve recoveries from, its existing and future crude oil and natural gas exploratio n and development projects and asso ciated potential and existing drill ing locations; ⢠the success of EOG's cost-mitigation i nitiatives and actions in offsetting the impact of any i nflationary or other pressures on EOG's operating cost s and capital expenditures; ⢠the extent to which EOG is successful in its efforts to market its production of crude oil and condensate, NGLs and natural gas; ⢠security threats, including cybersecurity thre ats and disruptions to our business and operations from breaches of our information technology syst ems, physical breaches of our facilities and other infrastructure or breach es of the information technology sy stems, facilities and infrastructur e of third parties with which we transact business, and enhanced regulatory focus on the prevention of, and disclosure requirements relating to, cyber incidents; ⢠the availability, proximity and capacity of, and co sts associated with, appropriate gathering, proc essing, compression, storage, transportation, refining, liquefaction and export facilities and equipment; ⢠the availability, cost, terms and timing of issuance or execution of mineral licenses, concessions and leases and governmental and other permits and rights-of-way, and EOG's ability to retain mi neral licenses, concessions and leases; ⢠the impact of, and changes in, government policies, laws and regulations, including climate change-related regulations, policies and initiatives (for example, with respect to air emissions); tax laws and regulations (inc luding, but not limited to, carbon tax or other emissions-related legisla tion); environmental, health and safety laws and regulations relating to disposal of produced water, drilling fluids and o ther wastes, hydraulic fracturing and access to and use of water; laws an d regulations affecting the leasing of acreage and permitting for oil and gas drilling and the calculation of royalty payments in respect of oil and gas production; laws and regulations imposing additional permitting and disclosure re quirements, additional operating restrictions and conditions or restrictions on drilling and co mpletion operations and on the transportation of crude oil, NGLs and natural gas; laws and regulations with respect to financial and other derivative s and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities; ⢠the impact of climate change-related legislati on, policies and initiatives; climate change-relate d political, social and shareholder activism; and physical, transition and reputational risks and oth er potential developments related to climate change; ⢠the extent to which EOG is able to successfully and economically develop, im plement and carry out its emissions and other environmental or safety-rel ated initiatives and achieve its related tar gets, goals, ambitions and initiatives; ⢠EOGâs failure to realize, in full or at all, the anticipated benefits of its ac quisition of Encino and/or business disruptions resulting from the acqu isition (e.g., relating to the integration of Encinoâs assets and operation s into EOGâs operations) that could harm EOGâs business operations (including current plans and operations and the diversion of managementâs attention from EOGâs ongoing business operations); ⢠EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, iden tify and resolve existing and potenti al issues with respect to such properties and accurately estimate reserve s, production, drilling, completion an d operating costs and capital expen ditures with respect to such properties; ⢠the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully, economically and in compliance with applicable laws and regulations; ⢠competition in the oil and gas exploration and production industry for the acquisition of licenses, concessions, leases and properties; ⢠the availability and cost of, and compe tition in the oil and gas exploration and production industr y for, employees, labor and other personnel, facil ities, equipment, materials (such as water, sand, fuel and tubulars) and services; ⢠the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise; ⢠weather and natural disasters, including its im pact on crude oil and natural gas demand, and related delays in drilling and in the installation and ope ration (by EOG or third parties) of production, gathering, processing, re fining, liquefaction, compression, storage, transportation, and export facilities; ⢠the ability of EOG's customers and other contractual counterparties to sa tisfy their obligations to EOG and, related thereto, to access the credit an d capital markets to obtain financing need ed to satisfy their obligations to EOG; ⢠EOG's ability to access the commercial paper market an d other credit and capital markets to obtain fin ancing on terms it deems acceptable, if at all, an d to otherwise satisfy its capita l expenditure requirements; ⢠the extent to which EOG is successful in its completion of planned asset dispositions; ⢠the extent and effect of any hedging activities engaged in by EOG; ⢠the timing and extent of changes in foreign currency exchange rates, intere st rates, inflation rates, global and domestic financial market conditio ns and global and domestic general economic conditions; ⢠the economic and financial impact of epidemics, pandemics or other public health issues; ⢠geopolitical factors and political conditions and dev elopments around the world (such as the imposition of tariffs or trade or other economic sancti ons, political instability and armed conflicts), i ncluding in the areas in which EOG operates; ⢠the extent to which EOG incurs uninsured losses and liabilities or losses and liabilitie s in excess of its insurance coverage; and ⢠the other factors described under ITEM 1A, Risk Factors of EOGâs Annual Report on Form 10-K for the fiscal year ended December 31, 2024 and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K. In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you s hould not place any undue reliance on any of EOG's forward-looking statem ents. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking s tatements, whether as a result of new information, subsequent events, an ticipated or unanticipated circumstances or otherwise. Historical Non-GAAP Financial Measures: Reconciliation schedules and definitions for the historical non âGAAP financial measures included or referenced herein as well as related discussion can be found on the EOG website at www.eogresources.com. Cautionary Notice Regarding Forward-Looking Non-GAAP Financial Measures: In addition, this presentation may include or reference certain forward âlooking, nonâGAAP financial measures, such as free cash flow, adjusted cash flow from operations and return on capital employed, and certain related estimates reg arding future performance, commodity prices and operating and financial results. Because we provide these measures on a forward âlooking basis, we cannot reliably or reasonably predict certain of the necessary components of the most directly comparable forward âlooking GAAP measures, such as future changes in working capital and future impairments. Accordingly, we are unable to present a quantitative reconciliation of such forward âlooking, nonâGAAP financial measures to the respective most directly comparable forward âlooking GAAP financial measures without unreasonable efforts. The una vailable information could have a significant impact on our ultimate results. However, management believes these forward âlooking, nonâGAAP measures may be a useful tool for the investment community in comparing EOGâs forecasted financial performance to the forecasted financial perf ormance of other companies in the industry. Any such forward âlooking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for t he period(s) presented; EOGâs actual results may differ materially from such measures and estimates. Oil and Gas Reserves: The United States Securities and Exchange Commission (SEC) permits oil and ga s companies, in their filings with the SEC, to disclose not only âprovedâ reserves (i.e., quantities of oil and gas that are estimated to be recoverabl e with a high degree of confidence), but also âprobableâ reserves (i.e., q uantities of oil and gas that are as likely as not to be recovered) as well as âpossibleâ reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reser ves are only estimates and may not correspond to the ultimate quantities of o il and gas recovered. Any reserve or resource estimates provided in this presentation that are not specifically designated as being estimates of proved reserves may include âpotential â reserves, âresource potentialâ and/or other estimated reserves or estimated resources not necessarily calculated in accordance with, or contemp lated by, the SECâs latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOGâs Annual Report on Form 10 âK for the fiscal year ended December 31, 2024 (and any updates to such disclosure set forth in EOGâs subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K), available from EOG at P.O. Box 4362, Houston, Texas 77210â4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1 â800âSECâ0330 or from the SEC's website at www.sec.gov. 2Q 2025 21