EOG Resources Reports Fourth Quarter and Full-Year 2025 Results; Announces 2026 Capital Plan

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HOUSTON, Feb. 24, 2026 /PRNewswire/ — EOG Resources, Inc. (EOG) today reported fourth quarter and full-year 2025 results. The attached schedules for the reconciliation of Non-GAAP measures to GAAP measures, along with a related presentation, are also available on EOG’s website at http://investors.eogresources.com/investors.

Fourth Quarter Highlights

Oil, NGLs and natural gas production and total per-unit operating costs better than guidance midpoints
Delivered net cash provided by operating activities of $2.6 billion and Adjusted CFO¹ of $2.6 billion
Generated $1.0 billion of free cash flow
Declared regular quarterly dividend of $1.02 per share and repurchased $675 million of shares
Earned net income of $701 million, or $1.30 per share, and adjusted net income of $1.2 billion, or $2.27 per share

Full-Year 2025 Highlights

Delivered net cash provided by operating activities of $10.0 billion and Adjusted CFO¹ of $11.0 billion
Generated $4.7 billion of free cash flow and returned 100% to shareholders through dividends and share repurchases
Earned net income of $5.0 billion, or $9.12 per share, and adjusted net income of $5.5 billion, or $10.16 per share
Reduced average well costs 7% across multi-basin portfolio

2026 Outlook

Announced $6.5 billion 2026 capital plan, which holds oil production flat to 4Q 2025. The 2026 plan delivers year-over-year oil and total production growth of 5% and 13%, respectively

CEO Commentary
“2025 was a year of exceptional operational execution for EOG. We exceeded our original oil and total volume targets, capital expenditures were on target, and we continued driving down both well costs and cash operating costs. Our differentiated marketing strategy delivered peer-leading U.S. price realizations, further strengthening margins.

Operational excellence drove outstanding financial results and peer-leading cash returns to shareholders. We generated $4.7 billion in free cash flow and returned 100% to shareholders through our sustainable, growing regular dividend, which increased 8%, and $2.5 billion in share repurchases. Since initiating buybacks in 2023, we’ve reduced our share count by approximately 10%. Our robust cash generation and pristine balance sheet position EOG to deliver shareholder value through industry cycles.

2025 was also a year of transformational transactions with the strategic Encino acquisition and our entry into exciting international exploration opportunities in the UAE and Bahrain. EOG’s differentiated portfolio has never been stronger. Looking ahead, we have a disciplined plan for 2026 targeting $4.5 billion in free cash flow using the midpoints of guidance at current strip pricing. Our strategy prioritizes activity in the Delaware Basin, Utica and Eagle Ford while increasing activity in Dorado alongside continued international investment. EOG’s relentless focus on returns, our diverse multi-basin portfolio and industry-leading exploration capabilities provide clear visibility to sustain high returns and robust free cash flow generation for years to come.”

Return of Capital
The Board of Directors today declared a dividend of $1.02 per share on EOG’s common stock. The dividend will be payable April 30, 2026, to stockholders of record as of April 16, 2026. The indicated annual rate is $4.08 per share.

During the fourth quarter, the company repurchased 6.3 million shares for $675 million under its share repurchase authorization, at an average purchase price of $107 per share.

For full-year 2025, the company repurchased 21.7 million shares for $2.5 billion under its share repurchase authorization, at an average purchase price of $115 per share. At December 31, 2025, EOG had $3.3 billion remaining on its current repurchase authorization.

2025 Reserves
Total proved reserves increased 16% in 2025 to 5.5 Billion Boe. Extensions and discoveries added 336 MMBoe of proved reserves in 2025. Revisions other than price increased proved reserves by 65 MMBoe. Net proved reserve additions from all sources, excluding price revisions, replaced 254% of 2025 total production.

2026 Capital Program
Total expenditures for 2026 are expected to range from $6.3 to $6.7 billion, including exploration and development drilling, facilities, leasehold acquisitions, capitalized interest, dry hole costs, and other property, plant and equipment, and excluding property acquisitions, asset retirement costs and non-cash exchanges and transactions. The capital program also excludes certain exploration costs incurred as operating expenses.

The plan holds 4Q 2025 oil production flat through 2026. Under the 2026 program, total oil production growth is 5% and total production growth is 13% year-over-year, inclusive of the Encino acquisition. EOG plans to complete 585 net wells in 2026 across our domestic multi-basin portfolio of high-return inventory.

The 2026 program targets low single-digit percentage average well cost reduction, benefiting from increasing lateral lengths and other sustainable efficiency gains. We expect higher overall activity in the Utica and Dorado, as well as continued advancement of exploration prospects in the UAE and Bahrain.

 Key Financial Results In millions of USD, except per-share, per-Boe and ratio data GAAP 4Q 2025 3Q 2025 2Q 2025 1Q 2025 4Q 2024 FY 2025 FY 2024 Total Revenue 5,638 5,847 5,478 5,669 5,585 22,632 23,698 Net Income 701 1,471 1,345 1,463 1,251 4,980 6,403 Net Income Per Share 1.30 2.70 2.46 2.65 2.23 9.12 11.25 Net Cash Provided by Operating Activities 2,612 3,111 2,032 2,289 2,763 10,044 12,143 Total Expenditures 1,730 8,544 1,883 1,546 1,446 13,703 6,653 Current and Long-Term Debt 7,936 7,694 4,236 4,744 4,752 7,936 4,752 Cash and Cash Equivalents 3,396 3,530 5,216 6,599 7,092 3,396 7,092 Debt-to-Total Capitalization 21.0 % 20.3 % 12.7 % 13.8 % 13.9 % 21.0 % 13.9 % Cash Operating Costs ($/Boe) 10.28 10.50 10.05 10.31 10.15 10.28 10.19 Non-GAAP Adjusted Net Income 1,222 1,472 1,268 1,586 1,535 5,548 6,612 Adjusted Net Income Per Share 2.27 2.71 2.32 2.87 2.74 10.16 11.62 Adjusted CFO(1) 2,617 3,031 2,496 2,813 2,635 10,957 11,593 Capital Expenditures 1,639 1,648 1,523 1,484 1,358 6,294 6,226 Free Cash Flow 978 1,383 973 1,329 1,277 4,663 5,367 Net Debt 4,540 4,164 (980) (1,855) (2,340) 4,540 (2,340) Net Debt-to-Total Capitalization 13.2 % 12.1 % (3.5 %) (6.7 %) (8.7 %) 13.2 % (8.7 %) Cash Operating Costs ($/Boe)(2) 10.22 9.93 9.94 10.31 10.15 10.09 10.17

 Key Operational Results Volumes 4Q 2025 3Q 2025 2Q 2025 1Q 2025 4Q 2024 FY 2025 FY 2024 Crude Oil and Condensate (MBod) 546.1 534.5 504.2 502.1 494.6 521.9 491.4 Natural Gas Liquids (MBbld) 342.1 309.3 258.4 241.7 252.5 288.2 245.9 Natural Gas (MMcfd) 3,065 2,745 2,229 2,080 2,092 2,533 1,948 Total Crude Oil Equivalent (MBoed) 1,399.0 1,301.2 1,134.1 1,090.4 1,095.7 1,232.2 1,062.1 Cash Operating Costs ($/Boe) Lease & Well 3.47 3.60 3.84 4.09 3.91 3.72 4.04 Gathering, Processing & Transportation Costs 5.07 4.90 4.41 4.48 4.37 4.74 4.43 General & Administrative (GAAP) 1.74 2.00 1.80 1.74 1.87 1.82 1.72 General & Administrative (Non-GAAP) (2) 1.68 1.43 1.69 1.74 1.87 1.63 1.70 Cash Operating Costs (GAAP) 10.28 10.50 10.05 10.31 10.15 10.28 10.19 Cash Operating Costs (Non-GAAP)(2) 10.22 9.93 9.94 10.31 10.15 10.09 10.17 Depreciation, Depletion & Amortization ($/Boe) 9.53 9.77 10.20 10.32 10.11 9.92 10.57

 Fourth Quarter 2025 Results vs Guidance 4Q 2025 (Unaudited) Guidance Midpoint 4 4Q 2025 Variance 3Q 2025 2Q 2025 1Q 2025 4Q 2024 Crude Oil and Condensate Volumes (MBod) United States 544.5 543.7 0.8 532.9 503.1 500.9 493.5 Trinidad 1.5 1.3 0.2 1.6 1.1 1.2 1.1 Other International5 0.1 0.0 0.1 0.0 0.0 0.0 0.0 Total 546.1 545.0 1.1 534.5 504.2 502.1 494.6 Natural Gas Liquids Volumes (MBbld) Total 342.1 323.0 19.1 309.3 258.4 241.7 252.5 Natural Gas Volumes (MMcfd) United States 2,859 2,790 69 2,511 1,977 1,834 1,840 Trinidad 195 200 (5) 230 252 246 252 Other International5 11 0 11 4 0 0 0 Total 3,065 2,990 75 2,745 2,229 2,080 2,092 Total Crude Oil Equivalent Volumes (MBoed) 1,399.0 1,366.4 32.6 1,301.2 1,134.1 1,090.4 1,095.7 Total MMBoe 128.7 125.7 3.0 119.7 103.2 98.1 100.8 Benchmark Price Oil (WTI) ($/Bbl) 59.17 64.95 63.71 71.42 70.28 Natural Gas (HH) ($/Mcf) 3.55 3.07 3.44 3.66 2.79 Crude Oil and Condensate -above (below) WTI 6 ($/Bbl) United States 0.37 0.25 0.12 1.02 1.13 1.48 1.40 Trinidad (2.10) (4.00) 1.90 (7.21) (9.21) (10.30) (9.81) Other International5 4.81 0.00 4.81 0.00 0.00 0.00 0.00 Natural Gas Liquids - Realizations as % of WTI Total 35.7 % 33.0 % 2.7 % 32.7 % 35.6 % 36.8 % 33.9 % Natural Gas -above (below) NYMEX Henry Hub 7 ($/Mcf) United States (0.61) (0.45) (0.16) (0.36) (0.57) (0.30) (0.40) Natural Gas Realizations ($/Mcf) Trinidad 3.94 3.60 0.34 3.80 3.65 3.78 3.86 Other International5 3.29 0.00 3.29 3.27 0.00 0.00 0.00 Total Expenditures (GAAP) ($MM) 1,730 8,544 1,883 1,546 1,446 Capital Expenditures (Non-GAAP) ($MM) 1,639 1,650 (11) 1,648 1,523 1,484 1,358 Operating Unit Costs ($/Boe) Lease and Well 3.47 3.75 (0.28) 3.60 3.84 4.09 3.91 Gathering, Processing and Transportation Costs 5.07 5.00 0.07 4.90 4.41 4.48 4.37 General &Administrative (GAAP) 1.74 1.55 0.19 2.00 1.80 1.74 1.87 General & Administrative (Non-GAAP)(2) 1.68 1.55 0.13 1.43 1.69 1.74 1.87 Cash Operating Costs (GAAP) 10.28 10.30 (0.02) 10.50 10.05 10.31 10.15 Cash Operating Costs (Non-GAAP)(2) 10.22 10.30 (0.08) 9.93 9.94 10.31 10.15 Depreciation, Depletion and Amortization 9.53 9.75 (0.22) 9.77 10.20 10.32 10.11 Expenses ($MM) Exploration and Dry Hole 54 60 (6) 71 85 75 60 Impairment (GAAP) 689 71 39 44 276 Impairment (excluding certain impairments (Non-GAAP))8 43 70 (27) 71 28 44 23 Capitalized Interest 36 36 0 27 11 12 13 Net Interest (GAAP) 66 66 0 71 51 47 38 Net Interest (Non-GAAP)9 66 66 0 71 45 47 38 TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas) (GAAP) 6.3 % 7.0 % (0.7 %) 6.8 % 7.3 % 7.6 % 6.8 % (Non-GAAP) 6.3 % 7.0 % (0.7 %) 6.8 % 7.3 % 7.6 % 6.8 % Income Taxes Effective Rate 22.8 % 22.5 % 0.3 % 19.4 % 23.2 % 22.1 % 23.0 % Current Tax Expense ($MM) 293 270 23 75 301 370 454

 First Quarter and Full-Year 2026 Guidance10 (Unaudited) 1Q 2026 1Q 2026 FY 2026 FY 2026 Guidance Range Midpoint Guidance Range Midpoint Crude Oil and Condensate Volumes (MBod) United States 542.4 547.0 544.7 542.7 547.3 545.0 Trinidad 1.6 2.0 1.8 1.3 1.7 1.5 Total 544.0 549.0 546.5 544.0 549.0 546.5 Natural Gas Liquids Volumes (MBbld) 320.0 340.0 330.0 325.0 345.0 335.0 Total Natural Gas Volumes (MMcfd) United States 2,700 2,800 2,750 2,810 2,910 2,860 Trinidad 225 245 235 215 235 225 Total 2,925 3,045 2,985 3,025 3,145 3,085 Crude Oil Equivalent Volumes (MBoed) United States 1,312.4 1,353.7 1,333.1 1,336.0 1,377.3 1,356.7 Trinidad 39.1 42.8 41.0 37.1 40.9 39.0 Total 1,351.5 1,396.5 1,374.0 1,373.1 1,418.2 1,395.7 Crude Oil and Condensate -above (below) WTI 6 ($/Bbl) United States (1.00) 0.50 (0.25) (1.00) 1.00 0.00 Trinidad (4.75) (3.25) (4.00) (3.50) (1.50) (2.50) Natural Gas Liquids - Realizations as % of WTI Total 26.0 % - 31.0 % 26.0 % - 36.0% 36.0% 31.0 % Natural Gas -above (below) NYMEX Henry Hub 7 ($/Mcf) United States (1.65) (0.95) (1.30) (1.60) 0.40 (0.60) Natural Gas Realizations ($/Mcf) Trinidad 3.15 3.85 3.50 3.00 4.00 3.50 Capital Expenditures 11 (Non-GAAP) ($MM) 1,575 1,675 1,625 6,300 6,700 6,500 Operating Unit Costs ($/Boe) Lease and Well 3.50 4.00 3.75 3.50 4.00 3.75 Gathering, Processing and Transportation Costs 4.95 5.45 5.20 4.95 5.45 5.20 General & Administrative 1.40 1.70 1.55 1.40 1.70 1.55 Cash Operating Costs 9.85 11.15 10.50 9.85 11.15 10.50 Depreciation, Depletion and Amortization 9.10 10.10 9.60 9.35 10.35 9.85 Expenses ($MM) Exploration and Dry Hole 30 70 50 195 235 215 Impairment (excluding certain impairments8 30 110 70 190 370 280 Capitalized Interest 35 39 37 147 151 149 Net Interest 65 69 67 267 271 269 TOTI (% of Wellhead Revenue) (GAAP) 6.0 % 8.0 % 7.0 % 5.8 % 7.8 % 6.8 % TOTI (% of Wellhead Revenue) (Non-GAAP) Income Taxes Effective Rate 20.0 % 26.0 % 23.0 % 20.0 % 26.0 % 23.0 % Current Tax Expense ($MM) 230 330 280 925 1,325 1,125

Fourth Quarter and Full-Year 2025 Results Webcast
Wednesday, February 25, 2026, 9:00 a.m. Central time (10:00 a.m. Eastern time) Webcast will be available on EOG’s website for one year. https://investors.eogresources.com/Investors

About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States and Trinidad. To learn more visit https://www.eogresources.com/

Investor Contacts
Pearce Hammond 713-571-4684
Neel Panchal 713-571-4884
Shelby O’Connor 713-571-4560

Media Contact
Kimberly Ehmer 713-571-4676

 Endnotes 1) Cash flow from operations before changes in working capital and certain acquisition-related costs. 2) Cash Operating Costs consist of LOE, GP&T and G&A. Non-GAAP G&A excludes Encino acquisition-related G&A costs of $8 million for 4Q 2025, $68 million for 3Q 2025 and $12 million for 2Q 2025, as reflected in the accompanying reconciliation schedules (see "Revenues, Costs and Margins Per Barrel of Oil Equivalent"). The per-Boe impact of such Encino acquisition-related costs on G&A and total Cash Operating Costs for 4Q 2025 was ($0.06), for 3Q 2025 was ($0.57) and for 2Q 2025 was ($0.11) as set forth in "Fourth Quarter 2025 Results vs Guidance" above. 3) Other includes gathering, processing and marketing revenue, gains (losses) on asset dispositions (for GAAP earnings per share only), other revenue, exploration costs, dry hole costs, impairments, marketing costs, taxes other than income, other income (expense), interest expense, the impact of changes in the effective income tax rate and the impact of share repurchases on diluted shares. 4) GAAP and Non-GAAP distinctions apply solely to actual results and do not pertain to EOG's fourth quarter 2025 guidance midpoint disclosures. 5) Production volumes from Bahrain operations; realized price represents contract price less Bapco's processing and distribution costs. 6) EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. 7) EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the NYMEX Last Day Settle price for each of the applicable months. 8) In general, EOG excludes impairments which are (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG's oil and gas properties or other assets). EOG believes excluding these impairments from total impairment costs is appropriate and provides useful information to investors, as such impairments were caused by factors outside of EOG's control (versus, for example, impairments that are due to EOG's proved oil and gas properties not being as productive as it originally estimated). Impairments (Non-GAAP) for 4Q 2025 are adjusted from Impairments (GAAP) for 4Q 2025 by excluding $646 million of impairments, primarily associated with the write-down to fair value of natural gas and crude oil assets in the Barnett Shale and Woodford Oil Window (mainly driven by play-specific economics and resource allocation). Impairments (Non-GAAP) for 4Q 2024 are adjusted from Impairments (GAAP) for 4Q 2024 by excluding $253 million of impairments, primarily associated with the write- down to fair value of natural gas and crude oil assets in the Rocky Mountain area. 9) Net interest expense (Non-GAAP) excludes Encino acquisition-related financing commitment costs of $6 million in 2Q 2025. 10) The forecast items for the first quarter and full year 2026 set forth above for EOG are based on currently available information and expectations as of the date of this press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with this press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. 11) The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs, Non-Cash Exchanges and Transactions and exploration costs incurred as operating expenses.

Cautionary Notice

This press release and any accompanying disclosures 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 and statements regarding the plans and objectives of EOG’s management for future operations, 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 EOG’s future financial or operating results and returns or 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 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 commodity and other derivative instruments 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 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, EOG’s ability to retain, 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;
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, 2025 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 press release and any accompanying disclosures may include or reference certain forward-looking, non-GAAP financial measures, such as free cash flow, cash flow provided by operating activities before changes in working capital 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 press release or any accompanying disclosures 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, 2025 (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.

 Income Statements In millions of USD, except share data (in millions) and per share data (Unaudited) 2024 2025 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year Operating Revenues and Other Crude Oil and Condensate 3,480 3,692 3,488 3,261 13,921 3,293 2,974 3,243 2,991 12,501 Natural Gas Liquids 513 515 524 554 2,106 572 534 604 666 2,376 Natural Gas 382 303 372 494 1,551 637 600 707 847 2,791 Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net 237 (47) 79 (65) 204 (191) 107 116 (19) 13 Gathering, Processing and Marketing 1,459 1,519 1,481 1,341 5,800 1,340 1,247 1,178 1,149 4,914 Gains (Losses) on Asset Dispositions, Net 26 20 (7) (23) 16 (1) (18) (16) (35) Other, Net 26 23 28 23 100 19 16 17 20 72 Total 6,123 6,025 5,965 5,585 23,698 5,669 5,478 5,847 5,638 22,632 Operating Expenses Lease and Well 396 390 392 394 1,572 401 396 431 447 1,675 Gathering, Processing and Transportation Costs 413 423 445 441 1,722 440 455 587 652 2,134 Exploration Costs 45 34 43 52 174 41 74 71 50 236 Dry Hole Costs 1 5 8 14 34 11 4 49 Impairments 19 81 15 276 391 44 39 71 689 843 Marketing Costs 1,404 1,490 1,500 1,323 5,717 1,325 1,216 1,134 1,120 4,795 Depreciation, Depletion and Amortization 1,074 984 1,031 1,019 4,108 1,013 1,053 1,169 1,226 4,461 General and Administrative 162 151 167 189 669 171 186 239 224 820 Taxes Other Than Income 338 337 283 291 1,249 341 301 309 283 1,234 Total 3,852 3,895 3,876 3,993 15,616 3,810 3,731 4,011 4,695 16,247 Operating Income 2,271 2,130 2,089 1,592 8,082 1,859 1,747 1,836 943 6,385 Other Income, Net 62 66 76 70 274 65 55 59 33 212 Income Before Interest Expense and Income Taxes 2,333 2,196 2,165 1,662 8,356 1,924 1,802 1,895 976 6,597 Interest Expense, Net 33 36 31 38 138 47 51 71 66 235 Income Before Income Taxes 2,300 2,160 2,134 1,624 8,218 1,877 1,751 1,824 910 6,362 Income Tax Provision 511 470 461 373 1,815 414 406 353 209 1,382 Net Income 1,789 1,690 1,673 1,251 6,403 1,463 1,345 1,471 701 4,980 Dividends Declared per Common Share 0.9100 0.9100 0.9100 0.9750 3.7050 0.9750 1.9950 1.0200 3.9900 Net Income Per Share Basic 3.11 2.97 2.97 2.25 11.31 2.66 2.48 2.72 1.31 9.17 Diluted 3.10 2.95 2.95 2.23 11.25 2.65 2.46 2.70 1.30 9.12 Average Number of Common Shares Basic 575 569 564 557 566 550 543 541 537 543 Diluted 577 572 568 561 569 553 546 544 539 546

 Volumes and Prices (Unaudited) 2024 2025 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year Crude Oil and Condensate Volumes (MBbld) (A) United States 486.8 490.1 491.8 493.5 490.6 500.9 503.1 532.9 544.5 520.5 Trinidad 0.6 0.6 1.2 1.1 0.8 1.2 1.1 1.6 1.5 1.4 Other International (C) - 0.1 Total 487.4 490.7 493.0 494.6 491.4 502.1 504.2 534.5 546.1 521.9 Average Crude Oil and Condensate Prices ($/Bbl) (B) United States $78.46 $82.71 $76.95 $71.68 $77.42 $72.90 $64.84 $65.97 $59.54 $65.65 Trinidad 67.50 70.75 63.15 60.47 64.43 61.12 54.50 57.74 57.07 57.59 Other International (C) - 63.98 Composite 78.45 82.69 76.92 71.66 77.40 72.87 64.82 65.95 59.54 65.63 Natural Gas Liquids Volumes (MBbld) (A) United States 231.7 244.8 254.3 252.5 245.9 241.7 258.4 309.3 342.1 288.2 Total 231.7 244.8 254.3 252.5 245.9 241.7 258.4 309.3 342.1 288.2 Average Natural Gas Liquids Prices ($/Bbl) (B) United States $24.32 $23.11 $22.42 $23.85 $23.40 $26.29 $22.70 $21.25 $21.15 $22.58 Composite 24.32 23.11 22.42 23.85 23.40 26.29 22.70 21.25 21.15 22.58 Natural Gas Volumes (MMcfd) (A) United States 1,658 1,668 1,745 1,840 1,728 1,834 1,977 2,511 2,859 2,299 Trinidad 200 204 225 252 220 246 252 230 195 230 Other International (C) - 4 11 4 Total 1,858 1,872 1,970 2,092 1,948 2,080 2,229 2,745 3,065 2,533 Average Natural Gas Prices ($/Mcf) (B) United States $2.10 $1.57 $1.84 $2.39 $1.99 $3.36 $2.87 $2.71 $2.94 $2.94 Trinidad 3.54 3.48 3.68 3.86 3.65 3.78 3.65 3.80 3.94 3.78 Other International (C) - 3.27 3.29 3.28 Composite 2.26 1.78 2.05 2.57 2.17 3.41 2.96 2.80 3.00 3.02 Crude Oil Equivalent Volumes (MBoed) (D) United States 994.7 1,013.0 1,037.1 1,052.7 1,024.5 1,048.3 1,090.9 1,260.7 1,363.0 1,191.8 Trinidad 34.1 34.5 38.6 43.0 37.6 42.1 43.2 39.8 34.2 39.8 Other International (C) - 0.7 1.8 0.6 Total 1,028.8 1,047.5 1,075.7 1,095.7 1,062.1 1,090.4 1,134.1 1,301.2 1,399.0 1,232.2 Total MMBoe (D) 93.6 95.3 99.0 100.8 388.7 98.1 103.2 119.7 128.7 449.8

 (A) Thousand barrels per day or million cubic feet per day, as applicable. (B) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity and other derivative instruments (see Note 12 to the Consolidated Financial Statements in EOG's Annual Report on Form 10-K for the year ended December 31, 2025). (C) Production volumes from Bahrain operations; realized price represents contract price less Bapco's processing and distribution costs. (D) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.

 Balance Sheets In millions of USD (Unaudited) 2024 2025 MAR JUN SEP DEC MAR JUN SEP DEC Current Assets Cash and Cash Equivalents 5,292 5,431 6,122 7,092 6,599 5,216 3,530 3,396 Accounts Receivable, Net 2,688 2,657 2,545 2,650 2,621 2,504 2,680 2,681 Inventories 1,154 1,069 1,038 985 897 934 945 1,014 Assets from Price Risk Management Activities 110 4 19 18 Other (A) 684 642 460 503 563 591 646 547 Total 9,928 9,803 10,165 11,230 10,680 9,245 7,820 7,656 Property, Plant and Equipment Oil and Gas Properties (Successful Efforts Method) 73,356 74,615 75,887 77,091 78,432 80,139 88,301 89,857 Other Property, Plant and Equipment 5,768 6,078 6,314 6,418 6,510 6,616 6,772 6,832 Total Property, Plant and Equipment 79,124 80,693 82,201 83,509 84,942 86,755 95,073 96,689 Less: Accumulated Depreciation, Depletion and (46,047) (47,049) (48,075) (49,297) (50,310) (51,394) (52,488) (54,348) Amortization Total Property, Plant and Equipment, Net 33,077 33,644 34,126 34,212 34,632 35,361 42,585 42,341 Deferred Income Taxes 38 44 42 39 44 39 37 39 Other Assets 1,753 1,733 1,818 1,705 1,626 1,639 1,757 1,763 Total Assets 44,796 45,224 46,151 47,186 46,982 46,284 52,199 51,799 Current Liabilities Accounts Payable 2,389 2,436 2,290 2,464 2,353 2,266 2,944 2,904 Accrued Taxes Payable 786 600 855 1,007 668 348 392 299 Dividends Payable 523 516 513 539 534 1,081 550 544 Liabilities from Price Risk Management Activities - 8 32 116 276 85 17 Current Portion of Long-Term Debt 34 534 34 532 1,280 778 27 27 Current Portion of Operating Lease Liabilities 318 303 338 315 318 360 433 472 Other 223 231 344 381 290 257 452 445 Total 4,273 4,628 4,406 5,354 5,719 5,175 4,815 4,691 Long-Term Debt 3,757 3,250 3,742 4,220 3,464 3,458 7,667 7,909 Other Liabilities 2,533 2,456 2,480 2,395 2,368 2,398 2,496 2,512 Deferred Income Taxes 5,597 5,731 5,949 5,866 5,915 6,015 6,936 6,854 Commitments and Contingencies Stockholders' Equity Common Stock, $0.01 Par 206 206 206 206 206 206 206 206 Additional Paid in Capital 6,188 6,219 6,058 6,090 6,095 6,153 5,978 6,027 Accumulated Other Comprehensive Loss (8) (8) (9) (4) (4) (7) (5) (7) Retained Earnings 23,897 25,071 26,231 26,941 27,869 28,131 29,603 29,765 Common Stock Held in Treasury (1,647) (2,329) (2,912) (3,882) (4,650) (5,245) (5,497) (6,158) Total Stockholders' Equity 28,636 29,159 29,574 29,351 29,516 29,238 30,285 29,833 Total Liabilities and Stockholders' Equity 44,796 45,224 46,151 47,186 46,982 46,284 52,199 51,799

 (A) Effective October 1, 2024, EOG combined Income Taxes Receivable into the Other line item. This presentation has been conformed for all periods presented and had no impact on previously reported Total Assets.

 Cash Flow Statements In millions of USD (Unaudited) 2024 2025 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year Cash Flows from Operating Activities Reconciliation of Net Income to Net Cash Provided by Operating Activities: Net Income 1,789 1,690 1,673 1,251 6,403 1,463 1,345 1,471 701 4,980 Items Not Requiring (Providing) Cash Depreciation, Depletion and Amortization 1,074 984 1,031 1,019 4,108 1,013 1,053 1,169 1,226 4,461 Impairments 19 81 15 276 391 44 39 71 689 843 Stock-Based Compensation Expenses 45 45 58 51 199 50 53 53 60 216 Deferred Income Taxes 199 128 220 (80) 467 44 105 278 (84) 343 (Gains) Losses on Asset Dispositions, Net (26) (20) 7 23 (16) 1 18 16 35 Other, Net 9 3 2 3 17 11 11 2 3 27 Dry Hole Costs 1 5 8 14 34 11 4 49 Mark-to-Market Financial Commodity and Other (237) 47 (79) 65 (204) 191 (107) (116) 19 (13) Derivative Contracts (Gains) Losses, Net Net Cash Received from (Payments for) 55 79 61 19 214 (38) (24) 27 (21) (56) Settlements of Financial Commodity Derivative Contracts Other, Net (1) (1) Changes in Components of Working Capital and Other Assets and Liabilities Accounts Receivable 58 33 109 (99) 101 48 122 133 (3) 300 Inventories 117 75 30 37 259 76 (45) 4 (84) (49) Accounts Payable (58) 29 (159) 152 (36) (129) (107) 5 (40) (271) Accrued Taxes Payable 319 (185) 256 151 541 (339) (321) 28 (103) (735) Other Assets (161) 42 197 (34) 44 (43) (43) (28) 97 (17) Other Liabilities (71) (20) 108 6 23 (96) (52) 155 10 17 Changes in Components of Working Capital (229) (127) 59 (85) (382) (41) (8) (159) 123 (85) Associated with Investing Activities Net Cash Provided by Operating Activities 2,903 2,889 3,588 2,763 12,143 2,289 2,032 3,111 2,612 10,044 Investing Cash Flows Acquisition of Encino Acquisition Partners, LLC, (4,464) 13 (4,451) Net of Cash Acquired Additions to Oil and Gas Properties (1,485) (1,357) (1,263) (1,248) (5,353) (1,381) (1,699) (1,492) (1,543) (6,115) Additions to Other Property, Plant and (350) (313) (239) (117) (1,019) (102) (94) (171) (112) (479) Equipment Proceeds from Sales of Assets 9 10 4 23 12 4 5 3 24 Changes in Components of Working Capital 229 127 (59) 85 382 41 8 159 (123) 85 Associated with Investing Activities Net Cash Used in Investing Activities (1,597) (1,533) (1,561) (1,276) (5,967) (1,430) (1,781) (5,963) (1,762) (10,936) Financing Cash Flows Long-Term Debt Borrowings 985 985 3,472 999 4,471 Long-Term Debt Repayments (500) (1,266) (750) (2,516) Dividends Paid (525) (520) (533) (509) (2,087) (538) (528) (545) (550) (2,161) Treasury Stock Purchased (759) (699) (795) (993) (3,246) (806) (602) (479) (677) (2,564) Proceeds from Stock Options Exercised and 11 11 22 11 12 23 Employee Stock Purchase Plan Debt Issuance and Other Financing Costs (2) (2) (7) (7) (11) (25) Repayment of Finance Lease Liabilities (8) (9) (8) (8) (33) (8) (9) (8) (7) (32) Net Cash Used in Financing Activities (1,292) (1,217) (1,336) (516) (4,361) (1,352) (1,635) 1,167 (984) (2,804) Effect of Exchange Rate Changes on Cash - - (1) (1) 1 (1) - Increase (Decrease) in Cash and Cash Equivalents 14 139 691 970 1,814 (493) (1,383) (1,686) (134) (3,696) Cash and Cash Equivalents at Beginning of Period 5,278 5,292 5,431 6,122 5,278 7,092 6,599 5,216 3,530 7,092 Cash and Cash Equivalents at End of Period 5,292 5,431 6,122 7,092 7,092 6,599 5,216 3,530 3,396 3,396

 Non-GAAP Financial Measures To supplement the presentation of its financial results prepared in accordance with generally accepted accounting principles in the United States of America (GAAP), EOG's quarterly earnings releases and related conference calls, accompanying investor presentation slides and presentation slides for investor conferences contain certain financial measures that are not prepared or presented in accordance with GAAP. These non-GAAP financial measures may include, but are not limited to, Adjusted Net Income (Loss), Adjusted Cash Flow from Operations, Free Cash Flow, Net Debt and related statistics. A reconciliation of each of these measures to their most directly comparable GAAP financial measure and related discussion is included in the tables on the following pages and can also be found in the "Reconciliations & Guidance" section of the "Investors" page of the EOG website at www.eogresources.com. As further discussed in the tables on the following pages, EOG believes these measures may be useful to investors who follow the practice of some industry analysts who make certain adjustments to GAAP measures (for example, to exclude non-recurring items) to facilitate comparisons to others in EOG's industry, and who utilize non-GAAP measures in their calculations of certain statistics (for example, return on capital employed and return on equity) used to evaluate EOG's performance. EOG believes that the non-GAAP measures presented, when viewed in combination with its financial results prepared in accordance with GAAP, provide a more complete understanding of the factors and trends affecting the company's performance. As is discussed in the tables on the following pages, EOG uses these non-GAAP measures for purposes of (i) comparing EOG's financial performance with the financial performance of other companies in the industry and (ii) analyzing EOG's financial performance across periods. The non-GAAP measures presented should not be considered in isolation, and should not be considered as a substitute for, or as an alternative to, EOG's reported Net Income (Loss), Long-Term Debt (including Current Portion of Long-Term Debt), Net Cash Provided by Operating Activities and other financial results calculated in accordance with GAAP. The non-GAAP measures presented should be read in conjunction with EOG's consolidated financial statements prepared in accordance with GAAP. In addition, because not all companies use identical calculations, EOG's presentation of non-GAAP measures may not be comparable to, and may be calculated differently from, similarly titled measures disclosed by other companies, including its peer companies. EOG may also change the calculation of one or more of its non-GAAP measures from time to time - for example, to account for changes in its business and operations or to more closely conform to peer company or industry analysts' practices. Direct ATROR --- The calculation of EOG's direct after-tax rate of return (ATROR) is based on EOG's net estimated recoverable reserves for a particular well(s) or play, the estimated net present value of the future net cash flows from such reserves (for which EOG utilizes certain assumptions regarding future commodity prices and operating costs) and EOG's direct net costs incurred in drilling or acquiring such well(s). As such, EOG's direct ATROR for a particular well(s) or play cannot be calculated from EOG's consolidated financial statements.

 Adjusted Net Income In millions of USD, except share data (in millions) and per share data (Unaudited) The following tables adjust reported Net Income (Loss) (GAAP) to reflect actual net cash received from (payments for) settlements of financial commodity derivative contracts by eliminating the net unrealized mark-to-market (gains) losses from these and other derivative transactions, to eliminate the net (gains) losses on asset dispositions, to add back impairment charges related to certain of EOG's assets (which are generally (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG's oil and gas properties or other assets)), to add back costs associated with the Encino acquisition and to make certain other adjustments to exclude non-recurring and certain other items as further described below. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. 4Q 2025 Before Income Tax After Diluted Tax Impact Tax Earnings per Share Reported Net Income (GAAP) 910 (209) 701 1.30 Adjustments: Losses on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net 19 (4) 15 0.03 Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1) (21) 4 (17) (0.03) Add: Losses on Asset Dispositions, Net 16 (4) 12 0.02 Add: Certain Impairments (2) 646 (140) 506 0.94 Add: Acquisition-related costs (3) 8 (3) 5 0.01 Adjustments to Net Income 668 (147) 521 0.97 Adjusted Net Income (Non-GAAP) 1,578 (356) 1,222 2.27 Average Number of Common Shares Basic 537 Diluted 539

 (1) Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG subtracts from reported Net Income (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the three months ended December 31, 2025, such amount was $21 million. (2) Impairments primarily associated with the write-down to fair value of natural gas and crude oil assets in the Barnett Shale and Woodford Oil Window (mainly driven by play-specific economics and resource allocation). (3) Consists of Encino acquisition-related G&A costs ($8 million).

 Adjusted Net Income (Continued) In millions of USD, except share data (in millions) and per share data (Unaudited) 3Q 2025 Before Income Tax After Diluted Tax Impact Tax Earnings per Share Reported Net Income (GAAP) 1,824 (353) 1,471 2.70 Adjustments: Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net (116) 25 (91) (0.16) Net Cash Received from Settlements of Financial Commodity Derivative Contracts (1) 27 (5) 22 0.04 Add: Losses on Asset Dispositions, Net 18 (6) 12 0.02 Add: Acquisition-related costs (2) 68 (10) 58 0.11 Adjustments to Net Income (3) 4 1 0.01 Adjusted Net Income (Non-GAAP) 1,821 (349) 1,472 2.71 Average Number of Common Shares Basic 541 Diluted 544

 (1) Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the three months ended September 30, 2025, such amount was $27 million. (2) Consists of Encino acquisition-related G&A costs ($68 million).

 2Q 2025 Before Income Tax After Diluted Tax Impact Tax Earnings per Share Reported Net Income (GAAP) 1,751 (406) 1,345 2.46 Adjustments: Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net (107) 23 (84) (0.16) Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1) (24) 5 (19) (0.03) Add: Certain Impairments 11 11 0.02 Add: Acquisition-related costs (2) 18 (3) 15 0.03 Adjustments to Net Income (102) 25 (77) (0.14) Adjusted Net Income (Non-GAAP) 1,649 (381) 1,268 2.32 Average Number of Common Shares Basic 543 Diluted 546

 (1) Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG subtracts from reported Net Income (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the three months ended June 30, 2025, such amount was $24 million. (2) Consists of Encino acquisition-related G&A costs ($12 million) and financing commitment costs ($6 million).

 Adjusted Net Income (Continued) In millions of USD, except share data (in millions) and per share data (Unaudited) 1Q 2025 Before Income Tax After Diluted Tax Impact Tax Earnings per Share Reported Net Income (GAAP) 1,877 (414) 1,463 2.65 Adjustments: Losses on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net 191 (41) 150 0.26 Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1) (38) 8 (30) (0.05) Add: Losses on Asset Dispositions, Net 1 2 3 0.01 Adjustments to Net Income 154 (31) 123 0.22 Adjusted Net Income (Non-GAAP) 2,031 (445) 1,586 2.87 Average Number of Common Shares Basic 550 Diluted 553

 (1) Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG subtracts from reported Net Income (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the three months ended March 31, 2025, such amount was $38 million.

 4Q 2024 Before Income Tax After Diluted Tax Impact Tax Earnings per Share Reported Net Income (GAAP) 1,624 (373) 1,251 2.23 Adjustments: Losses on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net 65 (14) 51 0.10 Net Cash Received from Settlements of Financial Commodity Derivative Contracts (1) 19 (4) 15 0.03 Add: Losses on Asset Dispositions, Net 23 (4) 19 0.03 Add: Certain Impairments (2) 254 (55) 199 0.35 Adjustments to Net Income 361 (77) 284 0.51 Adjusted Net Income (Non-GAAP) 1,985 (450) 1,535 2.74 Average Number of Common Shares Basic 557 Diluted 561

 (1) Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the three months ended December 31, 2024, such amount was $19 million. (2) Impairments primarily associated with the write-down to fair value of natural gas and crude oil assets in the Rocky Mountain area.

 Adjusted Net Income (Continued) In millions of USD, except share data (in millions) and per share data (Unaudited) FY 2025 Before Income Tax After Diluted Tax Impact Tax Earnings per Share Reported Net Income (GAAP) 6,362 (1,382) 4,980 9.12 Adjustments: Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net (13) 3 (10) (0.02) Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1) (56) 12 (44) (0.08) Add: Losses on Asset Dispositions, Net 35 (8) 27 0.05 Add: Certain Impairments (2) 657 (140) 517 0.95 Add: Acquisition-related costs (3) 94 (16) 78 0.14 Adjustments to Net Income 717 (149) 568 1.04 Adjusted Net Income (Non-GAAP) 7,079 (1,531) 5,548 10.16 Average Number of Common Shares Basic 543 Diluted 546

 (1) Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG subtracts from reported Net Income (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the twelve months ended December 31, 2025, such amount was $56 million. (2) Impairments primarily associated with the write-down to fair value of natural gas and crude oil assets in the Barnett Shale and Woodford Oil Window (mainly driven by play-specific economics and resource allocation). (3) Consists of Encino acquisition-related G&A costs ($88 million) and financing commitment costs ($6 million).

 FY 2024 Before Income Tax After Diluted Tax Impact Tax Earnings per Share Reported Net Income (GAAP) 8,218 (1,815) 6,403 11.25 Adjustments: Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net (204) 44 (160) (0.28) Net Cash Received from Settlements of Financial Commodity Derivative Contracts (1) 214 (46) 168 0.30 Less: Gains on Asset Dispositions, Net (16) 3 (13) (0.02) Add: Certain Impairments (2) 291 (57) 234 0.41 Less: Severance Tax Refund (31) 7 (24) (0.04) Add: Severance Tax Consulting Fees 10 (2) 8 0.01 Less: Interest on Severance Tax Refund (5) 1 (4) (0.01) Adjustments to Net Income 259 (50) 209 0.37 Adjusted Net Income (Non-GAAP) 8,477 (1,865) 6,612 11.62 Average Number of Common Shares Basic 566 Diluted 569

 (1) Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the twelve months ended December 31, 2024, such amount was $214 million. (2) Impairments primarily associated with the write-down to fair value of natural gas and crude oil assets in the Rocky Mountain area.

 Net Income Per Share In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited) 3Q 2025 Net Income per Share (GAAP) - Diluted 2.70 Realized Prices 4Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe 34.99 Less: 3Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe (38.05) Subtotal (3.06) Multiplied by: 4Q 2025 Crude Oil Equivalent Volumes (MMBoe) 128.7 Total Change in Revenue (394) Add: Income Tax Benefit (Provision) Imputed (based on 22%) 87 Change in Net Income (307) Change in Diluted Earnings per Share (0.57) Volumes 4Q 2025 Crude Oil Equivalent Volumes (MMBoe) 128.7 Less: 3Q 2025 Crude Oil Equivalent Volumes (MMBoe) (119.7) Subtotal 9.0 Multiplied by: 4Q 2025 Composite Average Margin per Boe (GAAP) (Including Total 6.70 Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule below) Change in Margin 60 Less: Income Tax Benefit (Provision) Imputed (based on 22%) (13) Change in Net Income 47 Change in Diluted Earnings per Share 0.09 Certain Operating Costs per Boe 3Q 2025 Total Cash Operating Costs (GAAP) and Total DD&A per Boe 20.27 Less: 4Q 2025 Total Cash Operating Costs (GAAP) and Total DD&A per Boe (19.81) Subtotal 0.46 Multiplied by: 4Q 2025 Crude Oil Equivalent Volumes (MMBoe) 128.7 Change in Before-Tax Net Income 59 Add: Income Tax Benefit (Provision) Imputed (based on 22%) (13) Change in Net Income 46 Change in Diluted Earnings per Share 0.09 Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net 4Q 2025 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts (19) Less: Income Tax Benefit (Provision) 4 After Tax - (a) (15) Less: 3Q 2025 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts 116 Less: Income Tax Benefit (Provision) (25) After Tax - (b) 91 Change in Net Income - (a) - (b) (106) Change in Diluted Earnings per Share (0.20) Other (1) (0.81) 4Q 2025 Net Income per Share (GAAP) - Diluted 1.30 4Q 2025 Average Number of Common Shares - Diluted 539

 (1) Includes gathering, processing and marketing revenue, gains (losses) on asset dispositions (for GAAP earnings per share only), other revenue, exploration costs, dry hole costs, impairments, marketing costs, taxes other than income, other income (expense), interest expense, the impact of changes in the effective income tax rate and the impact of share repurchases on diluted shares.

 Net Income Per Share (Continued) In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited) FY 2024 Net Income per Share (GAAP) - Diluted 11.25 Realized Prices FY 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe 39.28 Less: FY 2024 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe (45.22) Subtotal (5.94) Multiplied by: FY 2025 Crude Oil Equivalent Volumes (MMBoe) 449.8 Total Change in Revenue (2,672) Add: Income Tax Benefit (Provision) Imputed (based on 22%) 588 Change in Net Income (2,084) Change in Diluted Earnings per Share (3.82) Volumes FY 2025 Crude Oil Equivalent Volumes (MMBoe) 449.8 Less: FY 2024 Crude Oil Equivalent Volumes (MMBoe) (388.7) Subtotal 61.1 Multiplied by: FY 2025 Composite Average Margin per Boe (GAAP) (Including Total 13.31 Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule below) Change in Margin 813 Less: Income Tax Benefit (Provision) Imputed (based on 22%) (179) Change in Net Income 634 Change in Diluted Earnings per Share 1.16 Certain Operating Costs per Boe FY 2024 Total Cash Operating Costs (GAAP) and Total DD&A per Boe 20.76 Less: FY 2025 Total Cash Operating Costs (GAAP) and Total DD&A per Boe (20.20) Subtotal 0.56 Multiplied by: FY 2025 Crude Oil Equivalent Volumes (MMBoe) 449.8 Change in Before-Tax Net Income 252 Add: Income Tax Benefit (Provision) Imputed (based on 22%) (55) Change in Net Income 197 Change in Diluted Earnings per Share 0.36 Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net FY 2025 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts 13 Less: Income Tax Benefit (Provision) (3) After Tax - (a) 10 Less: FY 2024 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts 204 Less: Income Tax Benefit (Provision) (44) After Tax - (b) 160 Change in Net Income - (a) - (b) (150) Change in Diluted Earnings per Share (0.27) Other (1) 0.44 FY 2025 Net Income per Share (GAAP) - Diluted 9.12 FY 2025 Average Number of Common Shares - Diluted 546

 (1) Includes gathering, processing and marketing revenue, gains (losses) on asset dispositions (for GAAP earnings per share only), other revenue, exploration costs, dry hole costs, impairments, marketing costs, taxes other than income, other income (expense), interest expense, the impact of changes in the effective income tax rate and the impact of share repurchases on diluted shares.

 Adjusted Net Income Per Share In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited) 3Q 2025 Adjusted Net Income per Share (Non-GAAP) - Diluted 2.71 Realized Prices 4Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe 34.99 Less: 3Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe (38.05) Subtotal (3.06) Multiplied by: 4Q 2025 Crude Oil Equivalent Volumes (MMBoe) 128.7 Total Change in Revenue (394) Add: Income Tax Benefit (Provision) Imputed (based on 22%) 87 Change in Net Income (307) Change in Diluted Earnings per Share (0.57) Volumes 4Q 2025 Crude Oil Equivalent Volumes (MMBoe) 128.7 Less: 3Q 2025 Crude Oil Equivalent Volumes (MMBoe) (119.7) Subtotal 9.0 Multiplied by: 4Q 2025 Composite Average Margin per Boe (Non-GAAP) (Including Total Exploration Costs) (refer to 11.78 "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule below) Change in Margin 106 Less: Income Tax Benefit (Provision) Imputed (based on 22%) (23) Change in Net Income 83 Change in Diluted Earnings per Share 0.15 Certain Operating Costs per Boe 3Q 2025 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe 19.70 Less: 4Q 2025 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe (19.75) Subtotal (0.05) Multiplied by: 4Q 2025 Crude Oil Equivalent Volumes (MMBoe) 128.7 Change in Before-Tax Net Income (6) Add: Income Tax Benefit (Provision) Imputed (based on 22%) 1 Change in Net Income (5) Change in Diluted Earnings per Share (0.01) Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts 4Q 2025 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts (21) Less: Income Tax Benefit (Provision) 4 After Tax - (a) (17) Less: 3Q 2025 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts 27 Less: Income Tax Benefit (Provision) (5) After Tax - (b) 22 Change in Net Income - (a) - (b) (39) Change in Diluted Earnings per Share (0.07) Other (1) 0.06 4Q 2025 Adjusted Net Income per Share (Non-GAAP) 2.27 4Q 2025 Average Number of Common Shares - Diluted 539

 (1) Includes gathering, processing and marketing revenue, other revenue, exploration costs, dry hole costs, impairments, marketing costs, taxes other than income, other income (expense), interest expense, the impact of changes in the effective income tax rate and the impact of share repurchases on diluted shares.

 Adjusted Net Income Per Share (Continued) In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited) FY 2024 Adjusted Net Income per Share (Non-GAAP) - Diluted 11.62 Realized Prices FY 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe 39.28 Less: FY 2024 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe (45.22) Subtotal (5.94) Multiplied by: FY 2025 Crude Oil Equivalent Volumes (MMBoe) 449.8 Total Change in Revenue (2,672) Add: Income Tax Benefit (Provision) Imputed (based on 22%) 588 Change in Net Income (2,084) Change in Diluted Earnings per Share (3.82) Volumes FY 2025 Crude Oil Equivalent Volumes (MMBoe) 449.8 Less: FY 2024 Crude Oil Equivalent Volumes (MMBoe) (388.7) Subtotal 61.1 Multiplied by: FY 2025 Composite Average Margin per Boe (Non-GAAP) (Including Total Exploration Costs) (refer to 14.97 "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule below) Change in Margin 915 Less: Income Tax Benefit (Provision) Imputed (based on 22%) (201) Change in Net Income 714 Change in Diluted Earnings per Share 1.31 Certain Operating Costs per Boe FY 2024 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe 20.74 Less: FY 2025 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe (20.01) Subtotal 0.73 Multiplied by: FY 2025 Crude Oil Equivalent Volumes (MMBoe) 449.8 Change in Before-Tax Net Income 328 Add: Income Tax Benefit (Provision) Imputed (based on 22%) (72) Change in Net Income 256 Change in Diluted Earnings per Share 0.47 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts FY 2025 Net Cash Received from (Payments for) Settlement of Financial Commodity Derivative Contracts (56) Less: Income Tax Benefit (Provision) 12 After Tax - (a) (44) FY 2024 Net Cash Received from (Payments for) Settlement of Financial Commodity Derivative Contracts 214 Less: Income Tax Benefit (Provision) (46) After Tax - (b) 168 Change in Net Income - (a) - (b) (212) Change in Diluted Earnings per Share (0.39) Other (1) 0.97 FY 2025 Adjusted Net Income per Share (Non-GAAP) 10.16 FY 2025 Average Number of Common Shares - Diluted 546

 (1) Includes gathering, processing and marketing revenue, other revenue, exploration costs, dry hole costs, impairments, marketing costs, taxes other than income, other income (expense), interest expense, the impact of changes in the effective income tax rate and the impact of share repurchases on diluted shares.

 Cash Flow from Operations and Free Cash Flow In millions of USD (Unaudited) The following tables reconcile Net Cash Provided by Operating Activities (GAAP) to Adjusted Cash Flow from Operations (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Changes in Components of Working Capital and Other Assets and Liabilities, Changes in Components of Working Capital Associated with Investing Activities (or Investing and Financing Activities, as applicable) and certain other adjustments to exclude certain non-recurring items and other items as further described below. EOG defines Free Cash Flow (Non-GAAP) for a given period as Adjusted Cash Flow from Operations (Non-GAAP) (see below reconciliation) for such period less the Total Capital Expenditures (Non-GAAP) (see below reconciliation) during such period, as is illustrated below. EOG management uses this information for comparative purposes within the industry. As indicated in the tables below, EOG is (1) in addition to its customary working capital-related adjustments, adjusting Net Cash Provided by Operating Activities (GAAP) to add back certain non-recurring acquisition-related costs incurred during the second, third and fourth quarters of 2025 and (2) now presenting such adjusted measure as "Adjusted Cash Flow from Operations (Non-GAAP)" (instead of "Cash Flow from Operations Before Changes in Working Capital (Non-GAAP)" as reported in prior periods); the presentation below with respect to the second, third and fourth quarters of 2025 and the prior periods shown has been conformed. 2024 2025 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year Net Cash Provided by Operating Activities (GAAP) 2,903 2,889 3,588 2,763 12,143 2,289 2,032 3,111 2,612 10,044 Adjustments: Changes in Components of Working Capital and Other Assets and Liabilities Accounts Receivable (58) (33) (109) 99 (101) (48) (122) (133) 3 (300) Inventories (117) (75) (30) (37) (259) (76) 45 (4) 84 49 Accounts Payable 58 (29) 159 (152) 36 129 107 (5) 40 271 Accrued Taxes Payable (319) 185 (256) (151) (541) 339 321 (28) 103 735 Other Assets 161 (42) (197) 34 (44) 43 43 28 (97) 17 Other Liabilities 71 20 (108) (6) (23) 96 52 (155) (10) (17) Changes in Components of Working Capital 229 127 (59) 85 382 41 8 159 (123) 85 Associated with Investing Activities Add: Acquisition-Related Costs (1), Net of Tax - 10 58 5 73 Adjusted Cash Flow from Operations (Non-GAAP) 2,928 3,042 2,988 2,635 11,593 2,813 2,496 3,031 2,617 10,957 Less: Total Capital Expenditures (Non-GAAP) (2) (1,703) (1,668) (1,497) (1,358) (6,226) (1,484) (1,523) (1,648) (1,639) (6,294) Free Cash Flow (Non-GAAP) 1,225 1,374 1,491 1,277 5,367 1,329 973 1,383 978 4,663 (1) Consists of Encino acquisition-related G&A costs of $12 million, $68 million and $8 million (each before tax) for the three months ended June 30, 2025, three months ended September 30, 2025 and three months ended December 31, 2025, respectively. (2) See below reconciliation of Total Expenditures (GAAP) to Total Capital Expenditures (Non-GAAP): 2024 2025 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year Total Expenditures (GAAP) 1,952 1,682 1,573 1,446 6,653 1,546 1,883 8,544 1,730 13,703 Less: Asset Retirement Costs (21) 60 (11) (26) 2 (13) (14) (86) (33) (146) Non-Cash Leasehold Acquisition Costs (3) (31) (34) (17) (3) (85) (9) (2) (3) (10) (24) Acquisition Costs of Properties (3) (21) (5) (7) (33) 1 (270) (6,736) 2 (7,003) Acquisition Costs of Other Property, Plant and Equipment (131) (1) (5) (137) Exploration Costs (45) (34) (43) (52) (174) (41) (74) (71) (50) (236) Total Capital Expenditures (Non-GAAP) 1,703 1,668 1,497 1,358 6,226 1,484 1,523 1,648 1,639 6,294

 Cash Flow from Operations and Free Cash Flow (Continued) In millions of USD (Unaudited) FY 2023 FY 2022 FY 2021 Net Cash Provided by Operating Activities (GAAP) 11,340 11,093 8,791 Adjustments: Changes in Components of Working Capital and Other Assets and Liabilities Accounts Receivable 38 347 821 Inventories 231 534 13 Accounts Payable 119 (90) (456) Accrued Taxes Payable (61) 113 (312) Other Assets (39) 364 136 Other Liabilities (184) 266 116 Changes in Components of Working Capital Associated with Investing Activities (295) (375) 200 Adjusted Cash Flow from Operations (Non-GAAP) 11,149 12,252 9,309 Less: Total Capital Expenditures (Non-GAAP) (a) (6,041) (4,607) (3,755) Free Cash Flow (Non-GAAP) 5,108 7,645 5,554 (a) See below reconciliation of Total Expenditures (GAAP) to Total Capital Expenditures (Non-GAAP): Total Expenditures (GAAP) 6,818 5,610 4,255 Less: Asset Retirement Costs (257) (298) (127) Non-Cash Development Drilling (90) Non-Cash Leasehold Acquisition Costs (3) (99) (127) (45) Non-Cash Finance Leases (74) Acquisition Costs of Properties (3) (16) (419) (100) Acquisition Costs of Other Property, Plant and Equipment (134) Exploration Costs (181) (159) (154) Total Capital Expenditures (Non-GAAP) 6,041 4,607 3,755

 (3) Line item descriptions revised (from descriptions shown in EOG's previously published tables) to more accurately describe the costs reflected therein; previously reported cost amounts not impacted by such changes in presentation.

 Net Debt-to-Total Capitalization Ratio In millions of USD, except ratio data (Unaudited) The following tables reconcile Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. December 31, September 30, June 30, March 31, December 31, 2025 2025 2025 2025 2024 Total Stockholders' Equity - (a) 29,833 30,285 29,238 29,516 29,351 Current and Long-Term Debt (GAAP) - (b) 7,936 7,694 4,236 4,744 4,752 Less: Cash (3,396) (3,530) (5,216) (6,599) (7,092) Net Debt (Non-GAAP) - (c) 4,540 4,164 (980) (1,855) (2,340) Total Capitalization (GAAP) - (a) + (b) 37,769 37,979 33,474 34,260 34,103 Total Capitalization (Non-GAAP) - (a) + (c) 34,373 34,449 28,258 27,661 27,011 Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] 21.0 % 20.3 % 12.7 % 13.8 % 13.9 % Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + 13.2 % 12.1 % -3.5 % -6.7 % -8.7 % (c)]

 Proved Reserves and Reserve Replacement Data (Unaudited) 2025 Net Proved Reserves Reconciliation Summary United Trinidad Other Total States International Crude Oil and Condensate (MMBbl) Beginning Reserves 1,868 2 1,870 Revisions (10) (10) Purchases in Place 158 158 Extensions, Discoveries and Other Additions 77 1 78 Sales in Place - Production (190) (1) (191) Ending Reserves 1,903 2 1,905 Natural Gas Liquids (MMBbl) Beginning Reserves 1,358 1,358 Revisions 9 9 Purchases in Place 200 200 Extensions, Discoveries and Other Additions 48 48 Sales in Place - Production (105) (105) Ending Reserves 1,510 1,510 Natural Gas (Bcf) Beginning Reserves 8,878 244 9,122 Revisions 798 9 807 Purchases in Place 2,340 2,340 Extensions, Discoveries and Other Additions 1,184 77 1,261 Sales in Place (1) (1) Production (851) (86) (937) Ending Reserves 12,348 244 12,592 Oil Equivalents (MMBoe) Beginning Reserves 4,706 42 4,748 Revisions 131 2 133 Purchases in Place 749 749 Extensions, Discoveries and Other Additions 322 14 336 Sales in Place - Production (437) (15) (452) Ending Reserves 5,471 43 5,514 Net Proved Developed Reserves (MMBoe) At December 31, 2024 2,542 24 2,566 At December 31, 2025 3,317 29 3,346 2025 Exploration and Development Expenditures ($ Millions) Acquisition Cost of Unproved Properties 195 2 197 Exploration Costs 349 79 85 513 Development Costs 5,213 147 5 5,365 Total Drilling 5,757 228 90 6,075 Acquisition Cost of Proved Properties 6,977 26 7,003 Asset Retirement Costs 98 35 13 146 Total Exploration and Development Expenditures 12,832 263 129 13,224 Gathering, Processing and Other 470 5 4 479 Total Expenditures 13,302 268 133 13,703 Proceeds from Sales in Place (24) (24) Net Expenditures 13,278 268 133 13,679 Reserve Replacement Costs ($ / Boe) * All-in Total, Net of Revisions (GAAP) 10.68 16.44 10.86 All-in Total, Net of Revisions (Non-GAAP) 12.29 12.25 12.44 All-in Total, Excluding Revisions Due to Price (GAAP) 11.32 16.44 11.50 All-in Total, Excluding Revisions Due to Price (Non-GAAP) 14.45 12.25 14.54 Reserve Replacement * All-in Total, Net of Revisions and Dispositions 275 % 107 % 0 % 269 % All-in Total, Net of Revisions and Dispositions (Adjusted) 104 % 107 % 0 % 104 % All-in Total, Excluding Revisions Due to Price 259 % 107 % 0 % 254 % All-in Total, Excluding Revisions Due to Price (Adjusted) 88 % 107 % 0 % 89 % * See following reconciliation schedule for calculation methodology

 Reserve Replacement Cost Data (Unaudited; in millions, except ratio data) For the Twelve Months Ended December 31, 2025 United Trinidad Other Total States International Total Costs Incurred in Exploration and Development Activities (GAAP) 12,832 263 129 13,224 Less: Asset Retirement Costs (98) (35) (13) (146) Non-Cash Acquisition Costs of Unproved Properties (24) (24) Total Acquisition Costs of Proved Properties (6,977) (26) (7,003) Exploration Expenses (160) (32) (44) (236) Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) 5,573 196 46 5,815 Total Costs Incurred in Exploration and Development Activities (GAAP) - (a) 12,832 263 129 13,224 Less: Asset Retirement Costs (98) (35) (13) (146) Non-Cash Acquisition Costs of Unproved Properties (24) (24) Non-Cash Acquisition Costs of Proved Properties - Certain Acquisition Costs of Proved Properties (1) (6,972) (6,972) Exploration Expenses (160) (32) (44) (236) Total Exploration and Development Expenditures (Non-GAAP) - (b) 5,578 196 72 5,846 Total Expenditures (GAAP) 13,302 268 133 13,703 Less: Asset Retirement Costs (98) (35) (13) (146) Non-Cash Acquisition Costs of Unproved Properties (24) (24) Non-Cash Acquisition Costs of Proved Properties - Exploration Expenses (160) (32) (44) (236) Total Cash Expenditures (Non-GAAP) 13,020 201 76 13,297 Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe) Revisions Due to Price - (c) 68 68 Revisions Other Than Price 63 2 65 Purchases in Place 749 749 Extensions, Discoveries and Other Additions - (d) 322 14 336 Total Proved Reserve Additions - (e) 1,202 16 1,218 Less: Acquisition Related Purchases 2 (748) (748) Adjusted Total Proved Reserve Additions - (f) 454 16 470 Sales in Place - Net Proved Reserve Additions From All Sources - (g) 1,202 16 1,218 Adjusted Net Proved Reserve Additions From All Sources - (h) 454 16 470 Production - (i) 437 15 452 Reserve Replacement Costs ($ / Boe) All-in Total, Net of Revisions (GAAP) - (a / e) 10.68 16.44 10.86 All-in Total, Net of Revisions (Non-GAAP) - (b / f) 12.29 12.25 12.44 All-in Total, Excluding Revisions Due to Price (GAAP) - (a / (e - c)) 11.32 16.44 11.50 All-in Total, Excluding Revisions Due to Price (Non-GAAP) - (b / (f - c)) 14.45 12.25 14.54 Reserve Replacement All-in Total, Net of Revisions and Dispositions - (g / i) 275 % 107 % 0 % 269 % All-in Total, Net of Revisions and Dispositions (Adjusted) - (h / i) 104 % 107 % 0 % 104 % All-in Total, Excluding Revisions Due to Price - ((g - c) / i) 259 % 107 % 0 % 254 % All-in Total, Excluding Revisions Due to Price (Adjusted) - ((h - c) / i) 88 % 107 % 0 % 89 %

 (1) Includes $6,703 million for the Encino acquisition and $269 million of proved properties adjacent to EOG's core acreage in the Eagle Ford play. (2) Includes 678 MMBoe related to the Encino acquisition and 70 MMBoe related to the acquisition of proved properties adjacent to EOG's core acreage in the Eagle ford play.

 Reserve Replacement Cost Data (Continued) (Unaudited; in millions, except ratio data) For the Twelve Months Ended December 31, 2025 Proved Developed Reserve Replacement Costs ($ / Boe) Total Total Costs Incurred in Exploration and Development Activities (GAAP) - (k) 13,224 Less: Asset Retirement Costs (146) Acquisition Costs of Unproved Properties (197) Acquisition Costs of Proved Properties (7,003) Exploration Expenses (236) Drillbit Exploration and Development Expenditures (Non-GAAP) - (l) 5,642 Total Proved Reserves - Extensions, Discoveries and Other Additions (MMBoe) 336 Add: Conversion of Proved Undeveloped Reserves to Proved Developed 503 Less: Proved Undeveloped Extensions and Discoveries (264) Proved Developed Reserves - Extensions and Discoveries (MMBoe) 575 Total Proved Reserves - Revisions (MMBoe) 133 Less: Proved Undeveloped Reserves - Revisions (21) Proved Developed - Revisions Due to Price (19) Proved Developed Reserves - Revisions Other Than Price (MMBoe) 93 Proved Developed Reserves - Extensions and Discoveries Plus Revisions Other Than Price (MMBoe) - (m) 668 Proved Developed Reserves - Acquisitions (MMBoe) (n) 545 Proved Developed Reserves - Extensions and Discoveries plus Revisions Other Than Price plus Acquisitions (MMBoe) (o) 1,213 Proved Developed Reserve Replacement Costs Excluding Revisions Due to Price ($ / Boe) (GAAP) - (k / o) 10.90 Proved Developed Reserve Replacement Costs Excluding Revisions Due to Price ($ / Boe) (Non-GAAP) - (l / m) 8.45

 Reserve Replacement Cost Data (Continued) In millions of USD, except reserves and ratio data (Unaudited) The following table reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) and Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe. There are numerous ways that industry participants present Reserve Replacement Costs, including "Drilling Only" and "All-In", which reflect total exploration and development expenditures divided by total net proved reserve additions from extensions and discoveries only, or from all sources. Combined with Reserve Replacement, these statistics (and the non-GAAP measures used in calculating such statistics) provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics (and the non-GAAP measures used in calculating such statistics) are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. Please note that the actual cost of adding reserves will vary from the reported statistics due to timing differences in reserve bookings and capital expenditures. Accordingly, some analysts use three or five year averages of reported statistics, while others prefer to estimate future costs. EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures. 2025 2024 2023 2022 2021 Total Costs Incurred in Exploration and Development Activities (GAAP) 13,224 5,634 6,018 5,229 3,969 Less: Asset Retirement Costs (146) 2 (257) (298) (127) Non-Cash Acquisition Costs of Unproved Properties (24) (85) (99) (127) (45) Total Acquisition Costs of Proved Properties (7,003) (33) (16) (419) (100) Non-Cash Development Drilling - (90) Exploration Expenses (236) (174) (181) (159) (154) Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) - (a) 5,815 5,344 5,375 4,226 3,543 Total Costs Incurred in Exploration and Development Activities (GAAP) - (b) 13,224 5,634 6,018 5,229 3,969 Less: Asset Retirement Costs (146) 2 (257) (298) (127) Non-Cash Acquisition Costs of Unproved Properties (24) (85) (99) (127) (45) Non-Cash Acquisition Costs of Proved Properties - (24) (6) (26) (5) Non-Cash Development Drilling - (90) Certain Acquisition Costs of Proved Properties 1 (6,972) Exploration Expenses (236) (174) (181) (159) (154) Total Exploration and Development Expenditures (Non-GAAP) - (c) 5,846 5,353 5,385 4,619 3,638 Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe) Revisions Due to Price - (d) 68 (146) (110) 11 194 Revisions Other Than Price 65 215 139 325 (308) Purchases in Place 749 6 2 16 9 Extensions, Discoveries and Other Additions - (e) 336 580 607 560 952 Total Proved Reserve Additions (GAAP) - (f) 1,218 655 638 912 847 Less: Acquisition Related Purchases (2) (748) Total Proved Reserve Additions (Non-GAAP) - (g) 470 655 638 912 847 Sales in Place - (14) (17) (88) (11) Net Proved Reserve Additions From All Sources (GAAP) 1,218 641 621 824 836 Production 452 391 361 333 309 Reserve Replacement Costs ($ / Boe) All-in Total, Net of Revisions (GAAP) - (b / f) 10.86 8.60 9.43 5.73 4.69 All-in Total, Net of Revisions (Non-GAAP) - (c / g) 12.44 8.17 8.44 5.06 4.30 All-in Total, Excluding Revisions Due to Price (GAAP) - (b / ( f - d)) 11.50 7.03 8.05 5.80 6.08 All-in Total, Excluding Revisions Due to Price (Non-GAAP) - (c / ( g - d)) 14.54 6.68 7.20 5.13 5.57

 (1) Includes $6,703 million for the Encino acquisition and $269 million of proved properties adjacent to EOG's core acreage in the Eagle Ford play. (2) Includes 678 MMBoe related to the Encino acquisition and 70 MMBoe related to the acquisition of proved properties adjacent to EOG's core acreage in the Eagle ford play.

 Definitions $/Boe U.S. Dollars per barrel of oil equivalent MMBoe Million barrels of oil equivalent

 Revenues, Costs and Margins Per Barrel of Oil Equivalent In millions of USD, except Boe and per Boe amounts (Unaudited) EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who review certain components and/or groups of components of revenues, costs and/or margins per barrel of oil equivalent (Boe). Certain of these components are adjusted for non-recurring and certain other items, as further discussed below. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. 4Q 2025 3Q 2025 2Q 2025 1Q 2025 4Q 2024 Volume - Million Barrels of Oil Equivalent - (a) 128.7 119.7 103.2 98.1 100.8 Total Operating Revenues and Other - (b) 5,638 5,847 5,478 5,669 5,585 Total Operating Expenses - (c) 4,695 4,011 3,731 3,810 3,993 Operating Income - (d) 943 1,836 1,747 1,859 1,592 Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas Crude Oil and Condensate 2,991 3,243 2,974 3,293 3,261 Natural Gas Liquids 666 604 534 572 554 Natural Gas 847 707 600 637 494 Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas - (e) 4,504 4,554 4,108 4,502 4,309 Operating Costs Lease and Well 447 431 396 401 394 Gathering, Processing and Transportation Costs (1) 652 587 455 440 441 General and Administrative (GAAP) 224 239 186 171 189 Less: Certain Items (see Endnotes 2 & 3 to 4Q 2025 earnings release) (8) (68) (12) General and Administrative (Non-GAAP) (2) 216 171 174 171 189 Taxes Other Than Income (GAAP) 283 309 301 341 291 Add: Severance Tax Refund - Taxes Other Than Income (Non-GAAP) (3) 283 309 301 341 291 Interest Expense, Net 66 71 51 47 38 Less: Acquisition-Related Financing Commitment Costs - (6) Interest Expense, Net (Non-GAAP) (4) 66 71 45 47 38 Total Operating Cost (GAAP) (excluding DD&A and Total Exploration Costs) - (f) 1,672 1,637 1,389 1,400 1,353 Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (g) 1,664 1,569 1,371 1,400 1,353 Depreciation, Depletion and Amortization (DD&A) 1,226 1,169 1,053 1,013 1,019 Total Operating Cost (GAAP) (excluding Total Exploration Costs) - (h) 2,898 2,806 2,442 2,413 2,372 Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (i) 2,890 2,738 2,424 2,413 2,372 Exploration Costs 50 71 74 41 52 Dry Hole Costs 4 11 34 8 Impairments 689 71 39 44 276 Total Exploration Costs (GAAP) 743 142 124 119 336 Less: Certain Impairments (5) (646) (11) (254) Total Exploration Costs (Non-GAAP) 97 142 113 119 82 Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) - (j) 3,641 2,948 2,566 2,532 2,708 Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP)) - (k) 2,987 2,880 2,537 2,532 2,454 Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural 863 1,606 1,542 1,970 1,601 Gas less Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural 1,517 1,674 1,571 1,970 1,855 Gas less Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP))

 Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued) In millions of USD, except Boe and per Boe amounts (Unaudited) 4Q 2025 3Q 2025 2Q 2025 1Q 2025 4Q 2024 Per Barrel of Oil Equivalent (Boe) Calculations (GAAP) Composite Average Operating Revenues and Other per Boe - (b) / (a) 43.81 48.85 53.08 57.79 55.41 Composite Average Operating Expenses per Boe - (c) / (a) 36.48 33.51 36.15 38.84 39.62 Composite Average Operating Income per Boe - (d) / (a) 7.33 15.34 16.93 18.95 15.79 Composite Average Revenue from Sales of Crude Oil and Condensate, 34.99 38.05 39.80 45.88 42.74 NGLs, and Natural Gas per Boe - (e) / (a) Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (f) / (a) 12.99 13.67 13.46 14.26 13.42 Composite Average Margin per Boe (excluding DD&A and Total Exploration 22.00 24.38 26.34 31.62 29.32 Costs) - [(e) / (a) - (f) / (a)] Total Operating Cost per Boe (excluding Total Exploration Costs) - (h) / (a) 22.52 23.44 23.66 24.58 23.53 Composite Average Margin per Boe (excluding Total Exploration Costs) 12.47 14.61 16.14 21.30 19.21 - [(e) / (a) - (h) / (a)] Total Operating Cost per Boe (including Total Exploration Costs) - (j) / (a) 28.29 24.63 24.86 25.79 26.86 Composite Average Margin per Boe (including Total Exploration 6.70 13.42 14.94 20.09 15.88 Costs) - [(e) / (a) - (j) / (a)] Per Barrel of Oil Equivalent (Boe) Calculations (Non-GAAP) Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (g) / (a) 12.93 13.10 13.30 14.26 13.42 Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - 22.06 24.95 26.50 31.62 29.32 [(e) / (a) - (g) / (a)] Total Operating Cost per Boe (excluding Total Exploration Costs) - (i) / (a) 22.46 22.87 23.50 24.58 23.53 Composite Average Margin per Boe (excluding Total Exploration Costs) - 12.53 15.18 16.30 21.30 19.21 [(e) / (a) - (i) / (a)] Total Operating Cost per Boe (including Total Exploration Costs) - (k) / (a) 23.21 24.06 24.59 25.79 24.34 Composite Average Margin per Boe (including Total Exploration Costs) - 11.78 13.99 15.21 20.09 18.40 [(e) / (a) - (k) / (a)]

 Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued) In millions of USD, except Boe and per Boe amounts (Unaudited) 2025 2024 2023 2022 2021 Volume - Million Barrels of Oil Equivalent - (a) 449.8 388.7 359.4 331.5 302.5 Total Operating Revenues and Other - (b) 22,632 23,698 24,186 25,702 18,642 Total Operating Expenses - (c) 16,247 15,616 14,583 15,736 12,540 Operating Income (Loss) - (d) 6,385 8,082 9,603 9,966 6,102 Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas Crude Oil and Condensate 12,501 13,921 13,748 16,367 11,125 Natural Gas Liquids 2,376 2,106 1,884 2,648 1,812 Natural Gas 2,791 1,551 1,744 3,781 2,444 Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas - (e) 17,668 17,578 17,376 22,796 15,381 Operating Costs Lease and Well 1,675 1,572 1,454 1,331 1,135 Gathering, Processing and Transportation Costs (1) 2,134 1,722 1,620 1,587 1,422 General and Administrative (GAAP) 820 669 640 570 511 Less: Certain Items (see Endnote 7 to Additional Key Financial Information below) (88) (10) (16) General and Administrative (Non-GAAP) (2) 732 659 640 554 511 Taxes Other Than Income (GAAP) 1,234 1,249 1,284 1,585 1,047 Add: Severance Tax Refund - 31 115 Taxes Other Than Income (Non-GAAP) (3) 1,234 1,280 1,284 1,700 1,047 Interest Expense, Net 235 138 148 179 178 Less: Acquisition-Related Financing Commitment Costs (6) Interest Expense, Net (Non-GAAP) (4) 229 138 148 179 178 Total Operating Cost (GAAP) (excluding DD&A and Total Exploration Costs) - (f) 6,098 5,350 5,146 5,252 4,293 Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (g) 6,004 5,371 5,146 5,351 4,293 Depreciation, Depletion and Amortization (DD&A) 4,461 4,108 3,492 3,542 3,651 Total Operating Cost (GAAP) (excluding Total Exploration Costs) - (h) 10,559 9,458 8,638 8,794 7,944 Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (i) 10,465 9,479 8,638 8,893 7,944 Exploration Costs 236 174 181 159 154 Dry Hole Costs 49 14 1 45 71 Impairments 843 391 202 382 376 Total Exploration Costs (GAAP) 1,128 579 384 586 601 Less: Certain Impairments (5) (657) (291) (42) (113) (15) Total Exploration Costs (Non-GAAP) 471 288 342 473 586 Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) - (j) 11,687 10,037 9,022 9,380 8,545 Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP)) - (k) 10,936 9,767 8,980 9,366 8,530 Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural 5,981 7,541 8,354 13,416 6,836 Gas less Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural 6,732 7,811 8,396 13,430 6,851 Gas less Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP))

 Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued) In millions of USD, except Boe and per Boe amounts (Unaudited) 2025 2024 2023 2022 2021 Per Barrel of Oil Equivalent (Boe) Calculations (GAAP) Composite Average Operating Revenues and Other per Boe - (b) / (a) 50.32 60.97 67.30 77.53 61.63 Composite Average Operating Expenses per Boe - (c) / (a) 36.12 40.18 40.58 47.47 41.46 Composite Average Operating Income (Loss) per Boe - (d) / (a) 14.20 20.79 26.72 30.06 20.17 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, 39.28 45.22 48.34 68.77 50.84 and Natural Gas per Boe - (e) / (a) Total Operating Cost per Boe (excluding DD&A and Total Exploration 13.54 13.76 14.31 15.84 14.19 Costs) - (f) / (a) Composite Average Margin per Boe (excluding DD&A and Total Exploration 25.74 31.46 34.03 52.93 36.65 Costs) - [(e) / (a) - (f) / (a)] Total Operating Cost per Boe (excluding Total Exploration Costs) - (h) / (a) 23.46 24.33 24.03 26.53 26.26 Composite Average Margin per Boe (excluding Total Exploration Costs) - 15.82 20.89 24.31 42.24 24.58 [(e) / (a) - (h) / (a)] Total Operating Cost per Boe (including Total Exploration Costs) - (j) / (a) 25.97 25.82 25.10 28.30 28.25 Composite Average Margin per Boe (including Total Exploration Costs) - 13.31 19.40 23.24 40.47 22.59 [(e) / (a) - (j) / (a)] Per Barrel of Oil Equivalent (Boe) Calculations (Non-GAAP) Total Operating Cost per Boe (excluding DD&A and Total Exploration 13.34 13.82 14.31 16.14 14.19 Costs) - (g) / (a) Composite Average Margin per Boe (excluding DD&A and Total Exploration 25.94 31.40 34.03 52.63 36.65 Costs) - [(e) / (a) - (g) / (a)] Total Operating Cost per Boe (excluding Total Exploration Costs) - (i) / (a) 23.26 24.39 24.03 26.83 26.26 Composite Average Margin per Boe (excluding Total Exploration Costs) - 16.02 20.83 24.31 41.94 24.58 [(e) / (a) - (i) / (a)] Total Operating Cost per Boe (including Total Exploration Costs) - (k) / (a) 24.31 25.13 24.98 28.26 28.20 Composite Average Margin per Boe (including Total Exploration Costs) - 14.97 20.09 23.36 40.51 22.64 [(e) / (a) - (k) / (a)]

 (1) 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) EOG believes excluding the above-referenced items from General and Administrative Costs is appropriate and provides useful information to investors, as EOG views such items as non-recurring. (3) EOG believes excluding the above-referenced items from Taxes Other Than Income is appropriate and provides useful information to investors, as EOG views such items as non-recurring. (4) EOG believes excluding the above-referenced items from Interest Expense, Net is appropriate and provides useful information to investors, as EOG views such items as non-recurring. (5) In general, EOG excludes impairments which are (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG's oil and gas properties or other assets). EOG believes excluding these impairments from total exploration costs is appropriate and provides useful information to investors, as such impairments were caused by factors outside of EOG's control (versus, for example, impairments that are due to EOG's proved oil and gas properties not being as productive as it originally estimated).

 Additional Key Financial Information (Unaudited) See "Endnotes" below for related discussion and definitions. 2025 Actual 2024 Actual 2023 Actual 2022 Actual 2021 Actual Crude Oil and Condensate Volumes (MBod) United States 520.5 490.6 475.2 460.7 443.4 Trinidad 1.4 0.8 0.6 0.6 1.5 Other International 0.1 Total 521.9 491.4 475.8 461.3 445.0 Natural Gas Liquids Volumes (MBbld) Total 288.2 245.9 223.8 197.7 144.5 Natural Gas Volumes (MMcfd) United States 2,299 1,728 1,551 1,315 1,210 Trinidad 230 220 160 180 217 Other International(1) 4 9 Total 2,533 1,948 1,711 1,495 1,436 Crude Oil Equivalent Volumes (MBoed) United States 1,191.8 1,024.5 957.5 877.5 789.6 Trinidad 39.8 37.6 27.3 30.7 37.7 Other International(1) 0.6 1.6 Total 1,232.2 1,062.1 984.8 908.2 828.9 Benchmark Price Oil (WTI) ($/Bbl) 64.78 75.72 77.61 94.23 67.96 Natural Gas (HH) ($/Mcf) 3.43 2.27 2.74 6.64 3.85 Crude Oil and Condensate - above (below) WTI(2) ($/Bbl) United States 0.87 1.70 1.57 2.99 0.58 Trinidad (7.19) (11.29) (9.03) (8.07) (11.70) Other International(1) 0.36 Natural Gas Liquids - Realizations as % of WTI Total 34.9 % 30.9 % 29.7 % 39.0 % 50.5 % Natural Gas - above (below) NYMEX Henry Hub(3) ($/Mcf) United States (0.49) (0.28) (0.04) 0.63 1.03 Natural Gas Realizations4 ($/Mcf) Trinidad 3.78 3.65 3.65 4.43 3.40 Other International(1) 3.28 Total Expenditures (GAAP) ($MM) 13,703 6,653 6,818 5,610 4,255 Capital Expenditures5 (non-GAAP) ($MM) 6,294 6,226 6,041 4,607 3,755 Operating Unit Costs ($/Boe) Lease and Well 3.72 4.04 4.05 4.02 3.75 Gathering, Processing and Transportation Costs6 4.74 4.43 4.50 4.78 4.70 General and Administrative (GAAP) 1.82 1.72 1.78 1.72 1.69 General and Administrative (non-GAAP)7 1.63 1.70 1.78 1.67 1.69 Cash Operating Costs (GAAP) 10.28 10.19 10.33 10.52 10.14 Cash Operating Costs (non-GAAP)7 10.09 10.17 10.33 10.47 10.14 Depreciation, Depletion and Amortization 9.92 10.57 9.72 10.69 12.07 Expenses ($MM) Exploration and Dry Hole 285 188 182 204 225 Impairment (GAAP) 843 391 202 382 376 Impairment (excluding certain impairments (non-GAAP))8 186 100 160 269 361 Capitalized Interest 86 45 33 36 33 Net Interest 235 138 148 179 178 Net Interest (non-GAAP)9 229 TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas) (GAAP) 7.0 % 7.1 % 7.4 % 7.0 % 6.8 % (non-GAAP)7 7.0 % 7.3 % 7.4 % 7.5 % 6.8 % Income Taxes Effective Rate 21.7 % 22.1 % 21.6 % 21.7 % 21.4 % Current Tax Expense ($MM) 1,039 1,348 1,415 2,208 1,393

 Additional Key Financial Information (Continued) Endnotes 1) Production volumes from Bahrain operations; realized price represents contract price less Bapco's processing and distribution costs. 2) EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. 3) EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the NYMEX Last Day Settle price for each of the applicable months. 4) The full-year 2022 realized natural gas price for Trinidad includes a one-time pricing adjustment of $0.76/Mcf for prior-period production following a contract amendment with the National Gas Company of Trinidad and Tobago Limited. 5) Capital Expenditures includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Dry Hole Costs and Other Property, Plant and Equipment. Capital Expenditures excludes Property Acquisitions, Asset Retirement Costs, Non- Cash Exchanges and Transactions and exploration costs incurred as operating expenses. 6) 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. 7) Cash Operating Costs consist of LOE, GP&T and G&A. G&A (non-GAAP) for fiscal year 2025 excludes costs related to the Encino acquisition, as reflected in the accompanying reconciliation schedules (see "Revenues, Costs and Margins Per Barrel of Oil Equivalent"). In addition, TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas) (non-GAAP) and G&A (non-GAAP) for fiscal year 2024 and fiscal year 2022 exclude a state severance tax refund and related consulting fees, respectively, as reflected in the accompanying reconciliation schedules (see "Revenues, Costs and Margins Per Barrel of Oil Equivalent"). The per-Boe impact of such acquisition-related costs and consulting fees on G&A and total Cash Operating Costs for fiscal year 2025, 2024 and 2022 was $(0.19), $(0.02) and $(0.05), respectively. 8) In general, EOG excludes impairments which are (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG's oil and gas properties or other assets). EOG believes excluding these impairments from total impairment costs is appropriate and provides useful information to investors, as such impairments were caused by factors outside of EOG's control (versus, for example, impairments that are due to EOG's proved oil and gas properties not being as productive as it originally estimated). Impairments (non-GAAP) for FY 2025 are adjusted from Impairments (GAAP) for FY 2025 by excluding $657 million of impairments, primarily associated with the write-down to fair value of natural gas and crude oil assets in the Barnett Shale and Woodford Oil Window (mainly driven by play-specific economics and resource allocation). Impairments (non-GAAP) for FY 2024 are adjusted from Impairments (GAAP) for FY 2024 by excluding $291 million of impairments, primarily associated with the write-down to fair value of natural gas and crude oil assets in the Rocky Mountain area. 9) Net Interest for fiscal year 2025 excludes financing commitment costs related to the Encino acquisition, as reflected in the accompanying reconciliation schedules (see "Revenues, Costs and Margins Per Barrel of Oil Equivalent"). The per-Boe impact of such cost for fiscal year 2025 is $(0.01).

SOURCE EOG Resources, Inc.