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Supplemental Presentation 2025 Pearce Hammond, Vice President IR (713) 571-4684, phammond@eogresources.com Neel Panchal, Senior Director IR (713) 571-4884, npanchal@eogresources.com Shelby O’Connor, Manager IR (713) 571-4560, soconnor@eogresources.com
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Supplement - November 2025 Supplemental Presentation Updates As of November 6, 2025 2 • Slide 6: Cash Return Summary Updated for 3Q 2025
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Supplement - November 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 3 Capital Discipline • Returns-Focused Investments Guided by Bottom-Cycle Prices • Pristine Balance Sheet and Significant Free Cash Flow1,2 Generation • Sustainable, Growing Regular Dividend Anchors Commitment to Return Minimum 70% of Annual Free Cash Flow1,2 • 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 accompanying schedules for reconciliations and definitions of non-GAAP measures and other measures. (2) Adjusted cash flow from operations less CAPEX.
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Supplement - November 2025 Sustainable Value Creation Through Industry Cycles • Returns-Focused Investments Guided by Bottom-Cycle Prices • Pristine Balance Sheet and Significant Free Cash Flow1,2 Generation • Sustainable, Growing Regular Dividend Anchors Commitment to Return Minimum 70% of Annual Free Cash Flow1,2 • Reinvestment Pace Supports Continuous Improvement Across Multi-Basin Portfolio Operational Excellence 4 (1) See accompanying schedules for reconciliations and definitions of non-GAAP measures and other measures. (2) Adjusted cash flow from operations less CAPEX. Capital Discipline Operational Excellence Sustainability Culture
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Supplement - November 2025 5 EOG Strategy Delivers Peer Leading Return on Capital Employed 14% 27% 16% 12% 23% 36% 28% 25% 2021 2022 2023 2024 EOG Peer Avg.2 Return on Capital Employed1 (1) Return on Capital Employed calculated using non-GAAP adjusted Net Income. See (1) schedules posted to “Investors” section of EOG website for reconciliations & definitions of non-GAAP and other measures and related discussion and (2) “Supplemental Information” at end of the 3Q 2025 presentation for additional definitions & information, including regarding forward-looking non-GAAP financial measures. (2) Data sourced from Factset, April 2025. Peers include APA, CIVI, CNQ, COP, CTRA, CVX, DVN, FANG, MTDR, OVV, OXY, PR, XOM.
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Cash Return Summary Supplement - November 2025 6 2021 2022 2023 2024 YTD 20253 Regular Dividends, $MM $937 $1,764 $1,925 $2,087 $1,611 Special Dividends, $MM $1,747 $3,384 $1,461 - - Share Repurchases1, MM - - 8.6 25.8 15.4 Share Repurchases1, $MM - - $971 $3,179 $1,828 Total Cash Returns, $MM $2,684 $5,148 $4,357 $5,266 $3,439 Free Cash Flow2, $MM $5,554 $7,645 $5,108 $5,367 $3,685 Free Cash Flow2 Returned, % 48% 67% 85% 98% (1) Share repurchases pursuant to the Board-authorized repurchase program. (2) Adjusted cash flow from operations less CAPEX. See accompanying schedules for reconciliations and definitions of non-GAAP measures and other measures. (3) As of September 30, 2025.
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$2.1 $3.2 Free Cash Flow Regular Dividends Share Repurchases Supplement - November 2025 7 Delivered on 2024 Cash Flow Priorities (1) Cash flow from operations before changes in working capital and certain acquisition-related costs. See (1) schedules posted to “Investors” section of EOG website for reconciliations & definitions of non-GAAP and other measures and related discussion and (2) “Supplemental Information” at end of the 3Q 2025 presentation for additional definitions & information, including regarding forward-looking non-GAAP financial measures. (2) Adjusted cash flow from operations less CAPEX. See accompanying schedules for reconciliations and definitions of non-GAAP measures and other measures. (3) Share repurchases pursuant to the Board-authorized repurchase program. 4% share count reduction assumes basic outstanding share count as of December 31, 2023. 2 $Billion Additional Cash Return 4% Share Count Reduction in ‘24 3 Regular Dividend Primary Mode of Cash Return $5.4 1 2 3 $Billion Adjusted Cash Flow From Operations Capital Program Free Cash Flow $5.4 ($6.2) $11.6 CAPEX 3% Oil Growth 8% BOE Growth $5.3 Bn or 98% of Annual FCF Returned to Shareholders 2 1
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Supplement - November 2025 Sustainable Value Creation Through Industry Cycles • 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 8 Capital Discipline Operational Excellence Sustainability Culture
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Supplement - November 2025 9 Delaware Basin EOG Culture Delivers Sustainable Operational Efficiencies Across Multi-Basin Portfolio Eagle Ford Play Dorado Play Utica Play Powder River Basin 5% Drilled Ft/Day 50%+ Completed Ft/Day 15% Drilled Ft/Day 20% Completed Ft/Day 50% Drilled Ft/Day 5% Completed Ft/Day 15% Drilled Ft/Day 15% Completed Ft/Day 10% Drilled Ft/Day 20% Completed Ft/Day EOG’s decentralized structure provides a broad footprint for learnings, innovation, & technology transfer. Note: Drilled Ft/Day and Completed Ft/Day Represent FY 2024 Performance Compared to FY 2023 Performance.
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Strong Execution Delivers Outstanding 2024 Results Supplement - November 2025 10 Average Well Costs 6% Reduced By Cash Operating Costs1,2 2% Reduced byTotal Production 8% Increased By Operational Excellence Average Payback Period Return on Capital Employed1,3 25% DeliveredCash Recycle Ratio1 4.5x Achieved Outstanding Financial Metrics 1 Year Less Than At $65 Oil (1) See (1) schedules posted to “Investors” section of EOG website for reconciliations & definitions of non-GAAP and other measures and related discussion and (2) “Supplemental Information” at end of the 3Q 2025 presentation posted to EOG website for additional definitions & information, including regarding forward-looking non-GAAP financial measures. (2) Cash operating costs per Boe; include LOE (GAAP), GP&T (GAAP), and G&A expense (non-GAAP). (3) Calculated using non-GAAP adjusted Net Income vs 24% using Net Income (GAAP).
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Lower Costs Drive Higher Margins Supplement - November 2025 11 (1) Increase in Gathering, Processing, and Transportation expenses from 2017 to 2018 is primarily due to the adoption of Accounting Standards Update 2014-09, which required EOG to present certain processing fees as Gathering, Processing, and Transportation costs instead of as a deduction to natural gas revenues. See Note 1 to financial statements in EOG’s 2020 Form 10-K. Effective January 1, 2024, EOG combined Transportation Costs and Gathering and Processing Costs into one line item titled Gathering, Processing, and Transportation Costs. This presentation has been conformed for all periods presented and had no impact on previously reported Net Income. (2) See accompanying schedules for reconciliations and definitions of non-GAAP measures and other measures. (3) Total Exploration Costs includes Exploration, Dry Hole and Impairment Costs. See accompanying schedules for reconciliations and definitions of non-GAAP measures and other measures. 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Composite Avg. Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe $58.01 $30.66 $26.82 $35.58 $45.51 $38.79 $26.42 $50.84 $68.77 $48.34 $45.22 Operating Costs per Boe Lease & Well $6.53 $5.66 $4.53 $4.70 $4.89 $4.58 $3.85 $3.75 $4.02 $4.05 $4.04 Gathering, Processing, and Transportation1 $5.15 $4.77 $4.33 $4.00 $4.51 $4.14 $4.32 $4.70 $4.78 $4.50 $4.43 G&A2 $1.85 $1.66 $1.70 $1.87 $1.63 $1.64 $1.75 $1.69 $1.67 $1.78 $1.70 Taxes Other than Income2 $3.49 $2.02 $1.71 $2.45 $2.94 $2.68 $1.73 $3.46 $5.13 $3.57 $3.29 Interest Expense, Net $0.93 $1.14 $1.37 $1.23 $0.93 $0.62 $0.74 $0.59 $0.54 $0.41 $0.36 Total Operating Cost per Boe $17.95 $15.25 $13.64 $14.25 $14.90 $13.66 $12.39 $14.19 $16.14 $14.31 $13.82(Excluding DD&A and Total Exploration Costs) Composite Average Margin per Boe $40.06 $15.41 $13.18 $21.33 $30.61 $25.13 $14.03 $36.65 $52.63 $34.03 $31.40(Excluding DD&A and Total Exploration Costs) DD&A per Boe $18.43 $15.86 $17.34 $15.34 $13.09 $12.56 $12.32 $12.07 $10.69 $9.72 $10.57 Total Operating Cost per Boe $36.38 $31.11 $30.98 $29.59 $27.99 $26.22 $24.71 $26.26 $26.83 $24.03 $24.39(Excluding Total Exploration Costs) Composite Average Margin per Boe $21.63 ($0.45) ($4.16) $5.99 $17.52 $12.57 $1.71 $24.58 $41.94 $24.31 $20.83(Excluding Total Exploration Costs) Total Exploration Costs3 per Boe $0.70 $2.25 $2.12 $1.65 $1.33 $1.38 $1.42 $1.94 $1.43 $0.95 $0.74 Total Operating Cost per Boe $37.08 $33.36 $33.10 $31.24 $29.32 $27.60 $26.13 $28.20 $28.26 $24.98 $25.13(Including DD&A and Total Exploration Costs) Composite Average Margin per Boe (Including DD&A and Total Exploration Costs) $20.93 ($2.70) ($6.28) $4.34 $16.19 $11.19 $0.29 $22.64 $40.51 $23.36 $20.09
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EOG Marketing Strategy Provides Competitive Advantage Diverse Markets Provide Price Advantage and Flow Assurance Supplement - November 2025 12 ROCKIES PERMIAN GULF COAST CUSHING EXPORTS MIDWEST WEST COAST Clearbrook MEH WTI/Brent CIG Agua Dulce HSC NGPL TXOK Chicago Henry Hub 2025 EOG Estimated Sales Markets • Flexibility: Multiple Transportation Options in Each Basin • Diversification: Access to Multiple Markets to Maximize Margins • Control: Firm Capacity from Wellhead to Sales Point Provides Flow Assurance and Maximum Margins • Duration: Minimize Long-Term, High-Cost Commitments Gas Sales Market NGL Sales Market Oil Sales Market EOG Marketing Strategy 2025U.S. Oil 1U.S. NGLs Mt. Belvieu Conway 1U.S. Gas Exports (USGC/Brent) US Gulf Coast Cushing Rockies & Other Permian US Gulf Coast Southeast Henry Hub Permian JKM LNG Rockies West Coast & Other Northeast Zone 3 St. 65 Mt. Belvieu NORTHEAST SOUTHEAST SoCal Border Guernsey Conway Waha WTL Patoka WTI Eastern Gas South Canton
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Peer Leading 2024 US Price Realizations1 Supplement - November 2025 13 $74.46 $77.42 Peer Average Oil $0.81 $1.99 Peer Average EOG $21.23 $23.40 Peer Average NGL $2.96/Bbl Higher than Peer Avg. EOG EOG EOG $1.18/Mcf Higher than Peer Avg. $2.17/Bbl Higher than Peer Avg. (1) Data sourced from company filings. 2024 peer average includes APA, CIVI, COP, CTRA, CVX, DVN, FANG, MTDR, OXY, PR, and XOM. Oil Price Realization, $/Bbl Gas Price Realization, $/Mcf NGL Price Realization, $/Bbl
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Uniquely Positioned in US Oil Markets Supplement - November 2025 $36.14 $65.95 $94.35 $76.21 $74.46 $2.51 $2.59 $2.87 $2.97 $2.96 2020 2021 2022 2023 2024 US Oil Price Realization vs Peer Average2 EOG Premium to Peers Peer Average (1) Revenue uplift net to EOG calculated based on difference between realized export prices and the comparable local market. (2) Source: Company filings. Peer average for each of 2020-2023 reflect EOG’s then-peer companies as updated for E&P industry M&A activity. 2024 peer average includes APA, CIVI, COP, CTRA, CVX, DVN, FANG, MTDR, OXY, PR, and XOM. 14 EOG Approach to Oil Markets • Export-Linked Capacity of 250,000 Barrels per Day • Low-Cost Pipeline Transportation and Tank Storage in Key Market Segments • Diversified Sales to Domestic Refiners • Control from Wellhead to Sales Point Provides Flow Assurance and Maximum Margins ~$85 MM Revenue Uplift Net to EOG1 Associated with 2024 Crude Oil Export-Linked Sales Volumes $/Bbl
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Supplement - November 2025 Sustainable Value Creation Through Industry Cycles • Committed to Safe Operations, Leading Environmental Performance, and Community Engagement • Strategic Emissions Reduction Pathways 15 Capital Discipline Operational Excellence Sustainability Culture
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New GHG Emissions Intensity Rate Target for 2030 Based on Updated EPA Reporting Requirements Supplement - November 2025 16 Reduce GHG Emissions Intensity Rate1,2 25% from 2019 By 2030 Near-Term Emissions Targets 19.6 14.7 2019 Base Year 2030 Target GHG Intensity Rate metric tons CO2e/MBoe1,2 GHG Reduction Projects • Centralized Compression • Artificial Lift Automation and Optimization • Tank Vapor Capture • Company-Wide Leak Detection and Repair (LDAR) Inspections • Install or Retrofit Pneumatic Pumps to Use Electric and Solar Power Maintain 99%+ Wellhead Gas Capture Rate3 • Plan for and Install Natural Gas Gathering Infrastructure Early in Play Development • Contract Sufficient Pipeline Takeaway Capacity and Secure Ability to Sell to Multiple Markets • Control Centers to Manage Natural Gas Flow in Real Time and Avoid Takeaway Interruptions • Closed Loop Gas Capture Systems to Reduce Flaring and GHG Emissions • Proprietary Applications Monitor Operational Conditions and Lower Potential for Flaring (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) Percentage wellhead natural gas captured upstream of low-pressure separation and/or storage equipment of total gross operated U.S. onshore natural gas production. Note: The data utilized in calculating these metrics is subject to certain reporting rules, regulatory reviews, definitions, calculation methodologies, adjustments and other factors. These metrics are subject to change, if updated data or other information becomes available. Any updates to these metrics will be set forth in materials posted to the Sustainability section of the EOG website. Reaching and maintaining our near-term targets are subject to risks and uncertainties. Please see “Cautionary Notice Regarding Forward-Looking Statements” included herein.
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New Methane Emissions Target for 2025-2030 Based on Updated EPA Reporting Requirements Supplement - November 2025 17 Maintain Near-Zero Methane Emissions1,2 0.20% or less 2025-2030 Near-Term Emissions Targets Methane Reduction Projects • Company-Wide Leak Detection and Repair (LDAR) Inspections Identifies Leaks and Minimizes Emissions • Retrofit or Replace Methane-Emitting Pneumatic Controllers and Pumps • Install Instrument Air Systems to Operate Pneumatic Controllers and Pumps • Reduce Flaring Through Infrastructure, In-Field Practices, and Technologies • EOG Developed Continuous Leak Detection Technology to Reduce Emissions • Real-Time Actionable Alerts Through Continuous Monitoring of Facilities to Detect Methane Leaks • Continue Expanding Across Operations • Enhances Existing Leak Detection Program iSense® Continuous Leak Detection • Integrated with Operational Data and Other Proprietary Applications ✓ Optimize Performance ✓ Reduce Response Time ✓ Enable Data Analytics to Predict Source of Leaks and Potentially Prevent Methane Releases 99% Coverage in Delaware Basin as of YE 20243 (1) Based on methane emissions percentage calculated as thousand cubic feet (Mcf) of gross operated methane emissions per Mcf of total gross operated U.S. onshore and Trinidad natural gas 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 percentage of gross oil production handled at central tank batteries covered by iSense®. Note: Reaching and maintaining our near-term targets are subject to risks and uncertainties. Please see “Cautionary Notice Regarding Forward-Looking Statements” included herein.
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Supplement - November 2025 Sustainable Value Creation Through Industry Cycles • 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 18 Capital Discipline Operational Excellence Sustainability Culture
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Decentralization is Key to EOG’s Culture and Differentiation Supplement - November 2025 19 Multi-Basin Exploration • Active Exploration Across Every Division • Vast Dataset of Play Types • Core Data & Well Performance Models Operational Benefits • Capital Allocation Flexibility • Product & Geographic Diversity • Deep, Play-Specific Expertise EOG Innovations & Core Competencies • Long Lateral Optimization • Premium Motors & Bits • Real-Time Geo-Steering • Super Zipper Stimulation • Continuous Pumping Operations • Real-Time Diversion Technology • Continuous Methane Monitoring • Closed Loop Gas Capture • Infrastructure Optimization to Support Production and Lower Costs • Broad Footprint for Innovation • Knowledge & Technology Transfer • Scale to Self-Source Drilling Fluids and Sand EOG’s decentralized structure provides a broad footprint for learnings, innovation, and technology transfer.
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Data Availability is Critical for a Decentralized Business Real-Time Data & Proprietary Applications Support EOG’s Decentralized Model Supplement - November 2025 20 Division Offices Field Offices Corporate HQ Infrastructure Security Back-Office Real-Time Operations Reservoir & Exploration Planning & Economics Sustainability Accountability Technology Enables Data-Driven, Real-Time Decisions Across Decentralized Structure Transparency Real-Time Operational & Economic Data Available to Employees 24/7 Efficiency Real-Time & Mobile Applications Spur Innovation and Increase Velocity of Business
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Real-Time Facility and Artificial Lift Optimization to Consistently Deliver Base and New Well Production Real-Time Downhole Data to Ensure Effective Rock Stimulation Stage by Stage Real-Time Steering and Motor Data to Stay In Zone, Minimize Trips, and Reduce Time to Drill Comprehensive Log and Map Data Coupled with Proprietary Reservoir Modeling to Optimally Plan Field Development GEOLOGY & RESERVOIR DRILLING COMPLETIONS FACILITIES & PRODUCTION Proprietary Apps Support Innovative, Multi-Disciplinary Execution Connectivity Across All Apps Delivers Fast & Continuous Real-Time Data For High Return Decision Making Supplement - November 2025 21
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Supplement - November 2025 22 Owning Data from Creation to Delivery Integrated Systems Supporting Real-Time Returns-Focused Decision Making
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Play Details Supplement - November 2025 23
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Supplement - November 2025 24 Williston Basin Powder River Basin Wyoming DJ Basin Appalachian Basin Utica Eagle Ford Dorado Columbus Basin Trinidad & Tobago South Texas Delaware Basin Rocky Mountain EOG’s Multi-Basin Portfolio
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Delaware Basin Supplement - November 2025 25 Highlights • Maximized Value Creation Through Stacked Pay Co-Development • Increased Drilled Feet per Day by ~10% in 2024 Through Increased Bottom Hole Assembly Performance Attributed to EOG Motor Program • Increased Completed Lateral Feet per Day by ~20% in 2024 by Applying Super Zipper Completion Method and Continuous Pumping Operations • Increasing Program’s Average Lateral Length by 20%+ in 2025 2024 Activity 2025 Plan Net Completions 385 360 Rigs 16 15 Frac Spreads 4 4 Brushy Canyon Leonard Shale 1st Bone Spring 2nd Bone Spring 3rd Bone Spring Wolfcamp1 Wolfcamp M 4,800’ of Stacked Pay Core Area 395,000 Net Acres Culberson Reeves Eddy Lea Loving Ward Winkler Pecos TEXAS NEW MEXICO (1) Wolfcamp zone inclusive of Wolfcamp Oil and Wolfcamp Combo.
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South Texas Eagle Ford Supplement - November 2025 26 Highlights • 30K Net Acre Bolt-On Acquisition in Atascosa County Completed in 2Q 2025 • Increased Drilled Feet per Day by ~15% in 2024 as a Result of Improved Bottom Hole Assembly Efficiencies • Increased Completed Lateral Feet per Day by ~20% in 2024 by Applying Super Zipper Completion Method and Continuous Pumping Operations • Increasing Program’s Average Lateral Length in 2025 • Leveraging Existing Infrastructure to Minimize Future Capital Expenditures and Lower Cash Operating Costs 2024 Activity 2025 Plan Net Completions 160 110 Rigs 6 4 Frac Spreads 2 1 Core Area 565,000 Net Acres Frio Karnes De WittWilson Gonzales Atascosa McMullenLa Salle Webb TEXAS
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Ohio West Virginia Pennsylvania EOG Acreage Encino Acreage Overlapping Acreage Utica Play Supplement - November 2025 27 Highlights • Closed Encino Acquisition Partners Acquisition on August 1, 2025 • 1.1 MM Net Acres with 2.0+ Bn Boe of Undeveloped Net Resource1 • 90%+ of Acreage Held by Production with Minimal Drilling Commitments • 100% Minerals Ownership Across ~135K Net Acres Enhances Returns • Targeting 3+ Mile Laterals for Capital Efficient Development • EUR Product Mix Averages ~60-70% Liquids Across Volatile Oil Window • Increased Drilled Feet Per Day by ~50% in 2024 Primarily Driven By Consistent Drilling Program 2024 Activity Updated 2025 Plan Net Completions 25 65 Rigs 1 3 Frac Spreads <1 2 OHIO (1) Reflects core net acreage and associated estimated undeveloped net resource potential (not proved reserves). Total acquired acreage of ~1.2 MM net acres.
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Powder River Basin Supplement - November 2025 28 Highlights • Maximized Value Creation Through Development of Stacked Mowry, Turner, Niobrara, and Parkman Reservoirs • Increased Niobrara Well Productivity by 20%+ in 2024 • Reduced Niobrara Days to Drill by ~10% in 2024 as a Result of Improved Bottom Hole Assembly Efficiencies • Leveraging Existing Corridor Infrastructure to Minimize Capital Expenditures and Lower Cash Operating Costs 2024 Activity 2025 Plan Net Completions 27 25 Rigs 1 1 Frac Spreads <1 <1 Parkman Shannon Niobrara Turner Mowry Muddy Dakota 4,800’ of Stacked Pay Core Area 365,000 Net Acres Southern PRB Combo ~155K Net Acres Northern PRB Oil ~110K Net Acres Johnson Converse Campbell WYOMING
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Dorado Supplement - November 2025 29 Highlights • Increased Drilled Feet per Day by ~15% in 2024 Through Increased Bottom Hole Assembly Performance Attributed to EOG Motor Program • Increased Completed Lateral Feet Per Day by ~15% in 2024 by Applying Super Zipper Completion Method and Continuous Pumping Operations • Verde Pipeline in Service Enabling Access to Attractive Natural Gas Markets • Co-Development of Stacked Pay in Austin Chalk and Eagle Ford 2024 Activity 2025 Plan Net Completions 21 25 Rigs 1 1 Frac Spreads <1 <1 La Salle Webb Dimmit TEXAS Core Area 160,000 Net Acres Mexico
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Trinidad & Tobago Supplement - November 2025 30 Overview • 30+ Years Operating in Country • Shallow Water Development Expertise Coupled with Low-Cost Structure Supports Runway for Additional Future Opportunities • Highly Competitive with US Onshore Portfolio • Gas Sold Into Domestic Market 2024 Highlights • Acquired 2 Shallow Water Blocks • Signed New Joint Venture Project for Coconut Area • Completed Construction and Installation of Mento Platform in SMR Area Trinidad Tobago NCMA 4(a) Block Modified U(a) Block Coconut Area TSP Deep Area SMR Area LRL Block SECC Block Pelican Block Sercan Area 605,000 Net Acres Note: TSP Deep Area and Coconut Area include variable depth rights. 2025 Plan • Drill and Complete 4 Net Wells in Mento Field • Commence Construction of Coconut Platform • Conduct 3D Seismic over Newly Acquired LRL Block 4(a) Block
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www.eogresources.com 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. Copying of this presentation is forbidden without the prior written consent of EOG. Information in this presentation is provided “as is” without warranty of any kind, either express or implied, including but not limited to the implied warranties of merchantability, fitness for a particular purpose and the timeliness of the information. You assume all risk in using the information. In no event shall EOG or its representatives be liable for any special, 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 meaning 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, goals, returns and rates of return, budgets, reserves, levels of production, capital expenditures, operating costs and asset sales, statements regarding 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 anticipated benefits of, EOG’s acquisition of Encino Acquisition Partners, LLC (Encino) are forward‐looking 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 "believe" or the negative of those terms or other variations or comparable terminology to identify its forward‐looking 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 increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control drilling, completion and operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, other environmental matters or safety matters, pay and/or increase regular and/or special dividends or repurchase shares or (iii) the successful integration of Encino’s assets and operations or the strategic rationale for, or anticipated benefits of, EOG’s acquisition of Encino, in each case are forward‐looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-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 achieved 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 EOG's forward-looking statements include, among others: • the timing, magnitude and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids (NGLs), natural 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 production levels and rates of return from, (iii) decrease or otherwise control its drilling, completion and operating costs and capital expenditures related to, and (iv) maximize reserve recoveries from, its existing and future crude oil and natural gas exploration and development projects and associated potential and existing drilling locations; • the success of EOG's cost-mitigation initiatives and actions in offsetting the impact of any inflationary or other pressures on EOG's operating costs 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 threats and disruptions to our business and operations from breaches of our information technology systems, physical breaches of our facilities and other infrastructure or breaches of the information technology systems, facilities and infrastructure 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 costs associated with, appropriate gathering, processing, 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 mineral 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 (including, but not limited to, carbon tax or other emissions-related legislation); environmental, health and safety laws and regulations relating to disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and 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 requirements, additional operating restrictions and conditions or restrictions on drilling and completion operations and on the transportation of crude oil, NGLs and natural gas; laws and regulations with respect to financial and other derivatives 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 legislation, policies and initiatives; climate change-related political, social and shareholder activism; and physical, transition and reputational risks and other potential developments related to climate change; • the extent to which EOG is able to successfully and economically develop, implement and carry out its emissions and other environmental or safety-related initiatives and achieve its related targets, goals, ambitions and initiatives; • EOG’s failure to realize, in full or at all, the anticipated benefits of its acquisition of Encino and/or business disruptions resulting from the acquisition (e.g., relating to the integration of Encino’s assets and operations into EOG’s operations) that could harm EOG’s business operations (including current plans and operations and the diversion of management’s attention from EOG’s ongoing business operations); • EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, identify and resolve existing and potential issues with respect to such properties and accurately estimate reserves, production, drilling, completion and operating costs and capital expenditures 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 competition in the oil and gas exploration and production industry for, employees, labor and other personnel, facilities, 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 impact on crude oil and natural gas demand, and related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, liquefaction, compression, storage, transportation, and export facilities; • the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG; • EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital 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, interest rates, inflation rates, global and domestic financial market conditions 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 developments around the world (such as the imposition of tariffs or trade or other economic sanctions, political instability and armed conflicts), including in the areas in which EOG operates; • the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage; and • the other factors described under ITEM 1A, Risk Factors of EOG’s 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 should not place any undue reliance on any of EOG's forward-looking statements. 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 statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. Historical Non-GAAP Financial Measures: Reconciliation schedules and definitions for the historical non‐GAAP 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‐looking, non‐GAAP financial measures, such as free cash flow, adjusted cash flow from operations and return on capital employed, and certain related estimates regarding future performance, commodity prices and operating and financial results. Because we provide these measures on a forward‐looking basis, we cannot reliably or reasonably predict certain of the necessary components of the most directly comparable forward‐looking GAAP measures, such as future changes in working capital and future impairments. Accordingly, we are unable to present a quantitative reconciliation of such forward‐looking, non‐GAAP financial measures to the respective most directly comparable forward‐looking GAAP financial measures without unreasonable efforts. The unavailable information could have a significant impact on our ultimate results. However, management believes these forward‐looking, non‐GAAP measures may be a useful tool for the investment community in comparing EOG’s forecasted financial performance to the forecasted financial performance of other companies in the industry. Any such forward‐looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented; EOG’s 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 gas companies, in their filings with the SEC, to disclose not only “proved” reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also “probable” reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as “possible” reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil 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 “potential” reserves, “resource potential” and/or other estimated reserves or estimated resources not necessarily calculated in accordance with, or contemplated by, the SEC’s latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG’s Annual Report on Form 10‐K for the fiscal year ended December 31, 2024 (and any updates to such disclosure set forth in EOG’s subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K), available from EOG at P.O. Box 4362, Houston, Texas 77210‐4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1‐800‐SEC‐0330 or from the SEC's website at www.sec.gov. Supplement - November 2025 31