EOG Resources Reports Third Quarter 2025 Results

EOG Resources, Inc. (EOG) today reported third quarter 2025 results. The attached supplemental financial tables and schedules for the reconciliation of non-GAAP measures to GAAP measures and related definitions and discussion, along with a related presentation, are also available on EOG's website at http://investors.eogresources.com/investors.

Key Financial ResultsIn millions of USD, except per-share, per-Boe and ratio dataGAAP 3Q2025 2Q 2025 1Q 2025 4Q 2024 3Q 2024Total Revenue 5,847 5,478 5,669 5,585 5,965Net Income 1,471 1,345 1,463 1,251 1,673Net Income Per Share 2.70 2.46 2.65 2.23 2.95Net Cash Provided by Operating Activities 3,111 2,032 2,289 2,763 3,588Total Expenditures 8,544 1,883 1,546 1,446 1,573Current and Long-Term Debt 7,694 4,236 4,744 4,752 3,776Cash and Cash Equivalents 3,530 5,216 6,599 7,092 6,122Debt-to-Total Capitalization 20.3% 12.7% 13.8% 13.9% 11.3%Cash Operating Costs ($/Boe) 10.50 10.05 10.31 10.15 10.15Non-GAAPAdjusted Net Income 1,472 1,268 1,586 1,535 1,644Adjusted Net Income Per Share 2.71 2.32 2.87 2.74 2.89Adjusted CFO1 3,031 2,496 2,813 2,635 2,988Capital Expenditures 1,648 1,523 1,484 1,358 1,497Free Cash Flow 1,383 973 1,329 1,277 1,491Net Debt 4,164 (980) (1,855) (2,340) (2,346)Net Debt-to-Total Capitalization 12.1% (3.5%) (6.7%) (8.7%) (8.6%)Cash Operating Costs ($/Boe) 2,3 9.93 9.94 10.31 10.15 10.05

Third Quarter Highlights

— Earned adjusted net income of $1.5 billion, or $2.71 per share

— Generated $1.4 billion of free cash flow

— Paid $545 million in regular dividends and repurchased $440 million of shares

— Oil, NGLs and natural gas production above guidance midpoints

— Capital expenditures and per-unit operating costs better than guidance midpoints

— Closed on the acquisition of Encino Acquisition Partners(Encino)

Third Quarter 2025 Highlights and Cash Return

Volumes and Capital Expenditures

Volumes 3Q 2025 3Q 2025 2Q 2025 1Q 2025 4Q 2024 3Q 2024 Guidance MidpointCrude Oil and Condensate (MBod) 534.5 532.4 504.2 502.1 494.6 493.0Natural Gas Liquids (MBbld) 309.3 305.0 258.4 241.7 252.5 254.3Natural Gas (MMcfd) 2,745 2,735 2,229 2,080 2,092 1,970Total Crude Oil Equivalent (MBoed) 1,301.2 1,293.3 1,134.1 1,090.4 1,095.7 1,075.7Capital Expenditures ($MM) 1,648 1,650 1,523 1,484 1,358 1,497

From EzraYacob, Chairman and Chief Executive Officer “EOG delivered another quarter of strong operational performance. Third quarter oil, gas, and NGL volumes exceeded the midpoints of our guidance. Higher volumes, combined with lower-than-expected per-unit cash operating costs and DD&A, helped drive outstanding financial results.

We generated substantial free cash flow of $1.4 billion, which helped support nearly $1.0 billion of cash return to shareholders, including $440 million of opportunistic share repurchases. As of quarter-end, we have committed to return 89% of our estimated annual free cash flow to shareholders, with the potential to return additional cash over the balance of the year.

Our ability to deliver operational excellence quarter after quarter is the result of EOG's unique culture and the quality of our multi-basin portfolio. EOG's foundational assets, the Delaware Basin, Eagle Ford, and Utica, are delivering strong returns, exceeding our expectations. In the Utica, the integration of the Encino assets is proceeding exceptionally well, with continued incremental efficiency gains. Our emerging and international assets are also performing well, with strong well results in Dorado, the Powder River Basin, and Trinidad, along with continued progress in our exploration prospects in Bahrain and theUAE.

Our business has never been stronger. Our pristine balance sheet provides unmatched flexibility to continue to improve our high-return, long-duration asset base while delivering significant cash returns through commodity price cycles. EOG has never been better positioned to create long-term value for our shareholders.”

Regular Dividend and Third Quarter Share Repurchases The Board of Directors today declared a dividend of $1.02 per share on EOG's common stock. The dividend will be payable January 30, 2026, to shareholders of record as of January 16, 2026. This dividend represents an indicated annual rate of $4.08 per share. EOG has never suspended or reduced its regular dividend.

During the third quarter, the company repurchased 3.8 million shares for $440 million under its share repurchase authorization. EOG has $4.0 billion remaining on its current share buyback authorization.

Third Quarter 2025 Financial Performance

Prices

— NGL and natural gas prices decreased in 3Q compared with 2Q, partially offset by higher crude oil & condensate prices

Volumes

— Oil production of 534.5 MBod was above the midpoint of the guidance range

— NGL production of 309.3 MBbld was above the midpoint of the guidancerange

— Natural gas production of 2,745MMcfd was above the midpoint of the guidancerange

— Total company equivalent production of 1,301.2MBoed was above the midpoint of the guidance range

Per-Unit Costs

— LOE, non-GAAP G&A and DD&A costs decreased in 3Q compared to 2Q, while GP&T costs increased. Encino acquisition-related costs increased GAAP G&A costs in 3Q compared to2Q

Hedges

— Mark-to-market hedge gains increased GAAP earnings per share in 3Q compared with 2Q

— Cash received to settle hedges increased adjusted non-GAAP earnings per share in 3Q compared with 2Q

Free Cash Flow

— Adjusted cash flow from operations was $3.0 billion

— Incurred $1.6 billion of capital expenditures

— Generated $1.4 billion of free cash flow

Cash Return and Working Capital

— Paid $545 million in regular dividends

— Repurchased $440 million of stock

— Closed on the acquisition ofEncino for $5.7 billion, subject to post-closingadjustments

— Issued $3.5 billion of senior notes in conjunction with theEncinoacquisition

Third Quarter 2025 Operating Performance

Lease and Well

— QoQ: Decreased primarily due to the impact of higher production, primarily in the Utica from the integration of Encino operations, and lower workover expenses

— Guidance Midpoint: Lower primarily due to lower workover expenses and operating and maintenancecosts

General and Administrative (Non-GAAP)

— QoQ: Decreased primarily due to the impact of higher production, primarily in the Utica from the integration of Encino operations, and lower employee-related expenses

— Guidance Midpoint: Lower primarily due to lower employee-relatedexpenses

Gathering, Processing and Transportation Costs

— QoQ: Increased primarily due to the impact of higher Utica production from the integration of Encino operations

— Guidance Midpoint: Lower primarily due to lower natural gas gathering and processing fees

Depreciation, Depletion and Amortization

— QoQ: Decreased primarily due to the impact of higher Utica production and wellmix

— Guidance Midpoint: Lower primarily due to the addition of lower-costreserves

Third Quarter 2025 Results vs Guidance(Unaudited)See “Endnotes” below for related discussion and definitions. 3Q 2025 3Q 2025 Guidance Variance 2Q 2025 1Q 2025 4Q 2024 3Q 2024 Midpoint6Crude Oil and Condensate Volumes (MBod)United States 532.9 531.0 1.9 503.1 500.9 493.5 491.8Trinidad 1.6 1.4 0.2 1.1 1.2 1.1 1.2Total 534.5 532.4 2.1 504.2 502.1 494.6 493.0Natural Gas Liquids Volumes (MBbld)Total 309.3 305.0 4.3 258.4 241.7 252.5 254.3Natural Gas Volumes (MMcfd)United States 2,511 2,525 (14) 1,977 1,834 1,840 1,745Trinidad 230 210 20 252 246 252 225Other International7 4 0 4 0 0 0 0Total 2,745 2,735 10 2,229 2,080 2,092 1,970Total Crude Oil Equivalent Volumes (MBoed) 1,301.2 1,293.3 7.9 1,134.1 1,090.4 1,095.7 1,075.7Total MMBoe 119.7 119.0 0.7 103.2 98.1 100.8 99.0Benchmark PriceOil (WTI) ($/Bbl) 64.95 63.71 71.42 70.28 75.16Natural Gas (HH) ($/Mcf) 3.07 3.44 3.66 2.79 2.16Crude Oil and Condensate – above (below) WTI8 ($/Bbl)United States 1.02 0.80 0.22 1.13 1.48 1.40 1.79Trinidad (7.21) (5.00) (2.21) (9.21) (10.30) (9.81) (12.01)Natural Gas Liquids – Realizations as % of WTITotal 32.7% 34.0% (1.3%) 35.6% 36.8% 33.9% 29.8%Natural Gas – above (below) NYMEX Henry Hub9 ($/Mcf)United States (0.36) (0.40) 0.04 (0.57) (0.30) (0.40) (0.32)Natural Gas Realizations ($/Mcf)Trinidad 3.80 3.60 0.20 3.65 3.78 3.86 3.68Other International7 3.27 0.00 3.27 0.00 0.00 0.00 0.00Total Expenditures (GAAP) ($MM) 8,544 1,883 1,546 1,446 1,573Capital Expenditures (non-GAAP) ($MM) 1,648 1,650 (2) 1,523 1,484 1,358 1,497Operating Unit Costs ($/Boe)Lease and Well 3.60 3.70 (0.10) 3.84 4.09 3.91 3.96Gathering, Processing and Transportation Costs5 4.90 5.10 (0.20) 4.41 4.48 4.37 4.50General and Administrative (GAAP) 2.00 1.50 0.50 1.80 1.74 1.87 1.69General and Administrative (non-GAAP)2,3 1.43 1.50 (0.07) 1.69 1.74 1.87 1.59Cash Operating Costs (GAAP) 10.50 10.30 0.20 10.05 10.31 10.15 10.15Cash Operating Costs (non-GAAP)2,3 9.93 10.30 (0.37) 9.94 10.31 10.15 10.05Depreciation, Depletion and Amortization 9.77 9.85 (0.08) 10.20 10.32 10.11 10.42Expenses ($MM)Exploration and Dry Hole 71 75 (4) 85 75 60 43Impairment (GAAP) 71 39 44 276 15Impairment(excludingcertainimpairments(non-GAAP))10 71 70 1 28 44 23 15Capitalized Interest 27 21 6 11 12 13 12Net Interest (GAAP) 71 83 (12) 51 47 38 31Net Interest (non-GAAP)11 71 83 (12) 45 47 38 31TOTI (% of revenues from sales of crude oil andcondensate, NGLs and natural gas)(GAAP) 6.8% 7.5% (0.7%) 7.3% 7.6% 6.8% 6.5%(non-GAAP)3 6.8% 7.5% (0.7%) 7.3% 7.6% 6.8% 7.2%Income TaxesEffective Rate 19.4% 20.5% (1.1%) 23.2% 22.1% 23.0% 21.6%Current Tax Expense ($MM) 75 180 (105) 301 370 454 240Fourth Quarter and Full-Year 2025 Guidance12(Unaudited)See “Endnotes” below for related discussion and definitions 4Q 2025 4Q 2025 FY 2025 FY 2025. Guidance Range Midpoint Guidance Range MidpointCrude Oil and Condensate Volumes (MBod)United States 541.4 – 546.0 543.7 518.7 – 521.9 520.3Trinidad 1.1 – 1.5 1.3 1.1 – 1.5 1.3Total 542.5 – 547.5 545.0 519.8 – 523.4 521.6Natural Gas Liquids Volumes (MBbld)Total 315.5 – 330.5 323.0 280.0 – 286.0 283.0Natural Gas Volumes (MMcfd)United States 2,740 – 2,840 2,790 2,250 – 2,310 2,280Trinidad 190 – 210 200 220 – 240 230Total 2,930 – 3,050 2,990 2,470 – 2,550 2,510Crude Oil Equivalent Volumes (MBoed)United States 1,313.6 – 1,349.8 1,331.7 1,173.7 – 1,192.9 1,183.3Trinidad 32.8 – 36.5 34.7 37.8 – 41.5 39.7Total 1,346.4 – 1,386.3 1,366.4 1,211.5 – 1,234.4 1,223.0Crude Oil and Condensate – above (below) WTI8 ($/Bbl)United States (0.50) – 1.00 0.25 0.35 – 1.35 0.85Trinidad (5.25) – (2.75) (4.00) (8.40) – (6.90) (7.65)Natural Gas Liquids – Realizations as % of WTITotal 28.0% – 38.0% 33.0% 31.5% – 36.5% 34.0%Natural Gas – above (below) NYMEX Henry Hub9 ($/Mcf)United States (0.80) – (0.10) (0.45) (0.95) – 0.05 (0.45)Natural Gas Realizations ($/Mcf)Trinidad 3.00 – 4.20 3.60 3.40 – 3.90 3.65Capital Expenditures13 ($MM) 1,600 – 1,700 1,650 6,200 – 6,400 6,300Operating Unit Costs ($/Boe)Lease and Well 3.50 – 4.00 3.75 3.70 – 3.90 3.80Gathering, Processing and Transportation Costs5 4.75 – 5.25 5.00 4.65 – 4.85 4.75General and Administrative 1.40 – 1.70 1.55 1.45 – 1.65 1.55Cash Operating Costs 9.65 – 10.95 10.30 9.80 – 10.40 10.10Depreciation, Depletion and Amortization 9.25 – 10.25 9.75 9.70 – 10.30 10.00Expenses ($MM)Exploration and Dry Hole 40 – 80 60 270 – 310 290Impairment (excluding certain impairments)10 30 – 110 70 180 – 260 220Capitalized Interest 34 – 38 36 85 – 89 87Net Interest 64 – 68 66 228 – 232 230TOTI (% of revenues from sales of crude oil andcondensate, NGLs and natural gas) 6.0% – 8.0% 7.0% 6.5% – 8.5% 7.5%Income TaxesEffective Rate 20.0% – 25.0% 22.5% 19.0% – 24.0% 21.5%Current Tax Expense ($MM) 220 – 320 270 970 – 1,070 1,020

Third Quarter 2025 Results Webcast Friday, November 7, 2025, 9:00 a.m. Central time (10:00 a.m. Eastern time) Webcast will be available on EOG's website for one year. http://investors.eogresources.com/investors

About EOG EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and productioncompanies in the United States with proved reserves in the United States and Trinidad. To learn more visitwww.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

Endnotes1) Cash flow from operations before changes in working capital and certain acquisition-related costs.2) Cash Operating Costs consist ofLOE,GP&TandG&A. ExcludesEncinoacquisition-relatedG&A costsof$68millionfor3Q2025and$12million for 2Q 2025, as reflected in the accompanying reconciliation schedules (see “Revenues, Costs and Margins Per Barrel of Oil Equivalent”). The per-BoeimpactofsuchEncinoacquisition-relatedcostsonG&A andtotalCashOperatingCostsfor3Q2025was($0.57)andfor2Q2025was ($0.11)assetforthin”ThirdQuarter2025ResultsvsGuidance”above.G&AperBoe (GAAP) for 3Q 2025 was $2.00 and for 2Q 2025 was $1.80.3) Cash Operating Costs consist of LOE, GP&T and G&A. TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas) (non-GAAP) and G&A (non-GAAP) for 3Q 2024 exclude a state severance tax refund and related consulting fees, as reflected in the accompanying reconciliation schedules (see “Revenues, Costs and Margins Per Barrel of Oil Equivalent”). The per-Boe impact of such consulting fees on G&A and total Cash Operating Costs for 3Q 2024 was $(0.10) as set forth in “Third Quarter 2025 Results vs Guidance” above.4) 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.5) 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.6) GAAP and non-GAAP distinctions apply solely to actual results and do not pertain toEOG'sthirdquarter 2025guidancemidpoint disclosures.7) Other International represents EOG's Kingdom of Bahrain operations. Realized price represents contract price less Bapco's processing and distributioncosts.8) EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing,Oklahoma,usingthesimple averageoftheNYMEXsettlementpricesforeachtradingdaywithintheapplicablecalendar month.9) 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 applicablemonths.10) 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 originallyestimated).11) Net interest expense (non-GAAP) excludesEncinoacquisition-relatedfinancingcommitmentcostsof$6million in2Q2025.12) The forecast items for the fourth quarter and full year 2025 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 orforecast.13) 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.GlossaryAcq AcquisitionsAdjusted CFO Cash flow from operations before changes in working capital and certain acquisition-related costsATROR After-tax rate of returnBbl BarrelBn BillionBoe Barrels of oil equivalentBopd Barrels of oil per dayCAGR Compound annual growth rateCapex Capital expendituresCO2e Carbon dioxide equivalentDD&A Depreciation, Depletion and AmortizationDisc DiscoveriesDivest DivestituresEPS Earnings per shareExt ExtensionsGAAP Generally Accepted Accounting PrinciplesG&A General and administrative expenseG&P Gathering and processingGHG Greenhouse gasGP&T Gathering, processing & transportation expenseHH Henry HubLOE Lease operating expense, or lease and well expenseMBbld Thousand barrels of liquids per dayMBod Thousand barrels of oil per dayMBoe Thousand barrels of oil equivalentMBoed Thousand barrels of oil equivalent per dayMcf Thousand cubic feet of natural gasMMBoe Million barrels of oil equivalentMMcfd Million cubic feet of natural gas per dayNGLs Natural gas liquidsNYMEX U.S. New York Mercantile ExchangeOTP Other than priceQoQ Quarter over quarterTOTI Taxes other than incomeUSD United States dollarWTI West Texas IntermediateYoY Year over year$MM Million United States dollars$/Bbl U.S. Dollars per barrel$/Boe U.S. Dollars per barrel of oil equivalent$/Mcf U.S. Dollars per thousand cubic feet

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, statements regarding the plans and objectives of EOG's management for future operations and statements and projections regarding the strategic rationale for, and anticipated benefits of, EOG's acquisition of Encino Acquisition Partners, LLC (Encino) are forward-looking statements. EOG typically uses words such as “expect,” “anticipate,” “estimate,” “project,” “strategy,” “intend,” “plan,” “target,” “aims,” “ambition,” “initiative,” “goal,” “may,” “will,” “focused on,” “should” and “believe” or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning (i) EOG's future financial or operating results and returns, (ii) EOG's ability to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control drilling, completion and operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, other environmental matters or safety matters, pay and/or increase regular and/or special dividends or repurchase shares or (iii) the successful integration of Encino's assets and operations or the strategic rationale for, or anticipated benefits of, EOG's acquisition of Encino, in each case are forward-looking statements. Forward-looking statements are not guarantees of performance. AlthoughEOGbelievestheexpectationsreflectedinitsforward-lookingstatementsarereasonableandarebased onreasonableassumptions,noassurance can be given that such assumptions are accurate or will prove to have been correct or that any of such expectations will be achieved (in full or at all) or will be achieved on the expected or anticipated timelines. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:

— the timing, magnitude and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids (NGLs),

— natural gas and related commodities;

— the extent to which EOG is successful in its efforts to acquire or discover additional reserves;

— the extent to which EOG is successful in its efforts to (i) economically develop its acreage in, (ii) produce reserves and achieve anticipated production levels and rates of return from, (iii) decrease or otherwise control its drilling, completion and operating costs and capital expenditures related to, and (iv) maximize reserve recoveries from, its existing and future crude oil and natural gas exploration and development projects and associated potential and existing drilling locations;

— the success of EOG's cost-mitigation initiatives and actions in offsetting the impact of any inflationary or other pressures on EOG's operating costs and capital expenditures;

— the extent to which EOG is successful in its efforts to market its production of crude oil and condensate, NGLs and natural gas;

— security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, physical breaches of our facilities and other infrastructure or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business, and enhanced regulatory focus on the prevention of, and disclosure requirements relating to, cyber incidents;

— the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation, refining, liquefaction and export facilities and equipment;

— the availability, cost, terms and timing of issuance or execution of mineral licenses, concessions and leases and governmental and other permits and rights-of-way, and EOG's ability to retain mineral licenses, concessions and leases;

— the impact of, and changes in, government policies, laws and regulations, including climate change-related regulations, policies and initiatives (for example, with respect to air emissions); tax laws and regulations (including, but not limited to, carbon tax or other emissions-related legislation); environmental, health and safety laws and regulations relating to disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations affecting the leasing of acreage and permitting for oil and gas drilling and the calculation of royalty payments in respect of oil and gas production; laws and regulations imposing additional permitting and disclosure requirements, additional operating restrictions and conditions or restrictions on drilling and completion operations and on the transportation of crude oil, NGLs and natural gas; laws and regulations with respect to financial and other derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;

— the impact of climate change-related legislation, policies and initiatives; climate change-related political, social and shareholder activism; and physical, transition and reputational risks and other potential developments related to climate change;

— the extent to which EOG is able to successfully and economically develop, implement and carry out its emissions and other environmental or safety-related initiatives and achieve its related targets, goals, ambitions and initiatives;

— EOG's failure to realize, in full or at all, the anticipated benefits of its acquisition of Encino and/or business disruptions resulting from the acquisition (e.g., relating to the integration of Encino's assets and operations into EOG's operations) that could harm EOG's business operations (including current plans and operations and the diversion of management's attention from EOG's ongoing business operations);

— EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, identify and resolve existing and potential issues with respect to such properties and accurately estimate reserves, production, drilling, completion and operating costs and capital expenditures with respect to such properties;

— the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully, economically and in compliance with applicable laws and regulations;

— competition in the oil and gas exploration and production industry for the acquisition of licenses, concessions, leases and properties;

— the availability and cost of, and competition in the oil and gas exploration and production industry for, employees, labor and other personnel, facilities, equipment, materials (such as water, sand, fuel and tubulars) and services;

— the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;

— weather and natural disasters, including its impact on crude oil and natural gas demand, and related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, liquefaction, compression, storage, transportation, and export facilities;

— the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;

— EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;

— the extent to which EOG is successful in its completion of planned asset dispositions;

— the extent and effect of any hedging activities engaged in by EOG;

— the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;

— the economic and financial impact of epidemics, pandemics or other public health issues;

— geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, political instability and armed conflicts), including in the areas in which EOG operates;

— the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage; and

— the other factors described under ITEM 1A, Risk Factors of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2024, and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

In light of these risks, uncertainties and assumptions, the events anticipated byEOG'sforward-lookingstatementsmaynotoccur,and,ifanyofsuchevents 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, adjusted cash flow from operations and return on capital employed, and certain related estimates regarding future performance, commodity prices and operating and financial results. Because we provide these measures on a forward-looking basis, we cannot reliably or reasonably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures, such as future changes in working capital and future impairments. Accordingly, we are unable to present a quantitative reconciliation of such forward-looking, non-GAAP financial measures to the respective most directly comparable forward-looking GAAP financial measures without unreasonable efforts. The unavailable information could have a significant impact on our ultimate results. However, management believes these forward-looking, non-GAAP measures may be a useful tool for the investment community in comparingEOG'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 thatEOGwillnecessarilyachieve 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, 2024 (and any updates to such disclosure set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K), available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov.

Income StatementsIn 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 YearOperating Revenues and OtherCrude Oil and Condensate 3,480 3,692 3,488 3,261 13,921 3,293 2,974 3,243 9,510Natural Gas Liquids 513 515 524 554 2,106 572 534 604 1,710Natural Gas 382 303 372 494 1,551 637 600 707 1,944Gains (Losses) on Mark-to-Market 237 (47) 79 (65) 204 (191) 107 116 32Financial Commodity and OtherDerivative Contracts, NetGathering, Processing and Marketing 1,459 1,519 1,481 1,341 5,800 1,340 1,247 1,178 3,765Gains (Losses) on Asset Dispositions, 26 20 (7) (23) 16 (1) – (18) (19)NetOther, Net 26 23 28 23 100 19 16 17 52Total 6,123 6,025 5,965 5,585 23,698 5,669 5,478 5,847 16,994Operating ExpensesLease and Well 396 390 392 394 1,572 401 396 431 1,228Gathering, Processing and 413 423 445 441 1,722 440 455 587 1,482Transportation CostsExploration Costs 45 34 43 52 174 41 74 71 186Dry Hole Costs 1 5 – 8 14 34 11 – 45Impairments 19 81 15 276 391 44 39 71 154Marketing Costs 1,404 1,490 1,500 1,323 5,717 1,325 1,216 1,134 3,675Depreciation, Depletion and 1,074 984 1,031 1,019 4,108 1,013 1,053 1,169 3,235AmortizationGeneral and Administrative 162 151 167 189 669 171 186 239 596Taxes Other Than Income 338 337 283 291 1,249 341 301 309 951Total 3,852 3,895 3,876 3,993 15,616 3,810 3,731 4,011 11,552Operating Income 2,271 2,130 2,089 1,592 8,082 1,859 1,747 1,836 5,442Other Income, Net 62 66 76 70 274 65 55 59 179Income Before Interest Expense and 2,333 2,196 2,165 1,662 8,356 1,924 1,802 1,895 5,621Income TaxesInterest Expense, Net 33 36 31 38 138 47 51 71 169Income Before Income Taxes 2,300 2,160 2,134 1,624 8,218 1,877 1,751 1,824 5,452Income Tax Provision 511 470 461 373 1,815 414 406 353 1,173Net Income 1,789 1,690 1,673 1,251 6,403 1,463 1,345 1,471 4,279Dividends Declared per Common Share 0.9100 0.9100 0.9100 0.9750 3.7050 0.9750 1.9950 – 2.9700Net Income Per ShareBasic 3.11 2.97 2.97 2.25 11.31 2.66 2.48 2.72 7.85Diluted 3.10 2.95 2.95 2.23 11.25 2.65 2.46 2.70 7.81Average Number of Common SharesBasic 575 569 564 557 566 550 543 541 545Diluted 577 572 568 561 569 553 546 544 548Volumes and Prices(Unaudited) 2024 2025 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr YearCrude Oil and Condensate Volumes (MBbld) (A)United States 486.8 490.1 491.8 493.5 490.6 500.9 503.1 532.9 512.4Trinidad 0.6 0.6 1.2 1.1 0.8 1.2 1.1 1.6 1.3Total 487.4 490.7 493.0 494.6 491.4 502.1 504.2 534.5 513.7Average 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 $ 67.83Trinidad 67.50 70.75 63.15 60.47 64.43 61.12 54.50 57.74 57.80Composite 78.45 82.69 76.92 71.66 77.40 72.87 64.82 65.95 67.81Natural Gas Liquids Volumes (MBbld) (A)United States 231.7 244.8 254.3 252.5 245.9 241.7 258.4 309.3 270.0Total 231.7 244.8 254.3 252.5 245.9 241.7 258.4 309.3 270.0Average Natural Gas Liquids Prices ($/Bbl) (B)United States $ 24.32 $ 23.11 $ 22.42 $ 23.85 $ 23.40 $ 26.29 $ 22.70 $ 21.25 $ 23.20Composite 24.32 23.11 22.42 23.85 23.40 26.29 22.70 21.25 23.20Natural Gas Volumes (MMcfd) (A)United States 1,658 1,668 1,745 1,840 1,728 1,834 1,977 2,511 2,110Trinidad 200 204 225 252 220 246 252 230 243Other International (C) – – – – – – – 4 1Total 1,858 1,872 1,970 2,092 1,948 2,080 2,229 2,745 2,354Average Natural Gas Prices ($/Mcf) (B)United States $ 2.10 $ 1.57 $ 1.84 $ 2.39 $ 1.99 $ 3.36 $ 2.87 $ 2.71 $ 2.94Trinidad 3.54 3.48 3.68 3.86 3.65 3.78 3.65 3.80 3.74Other International (C) – – – – – – – 3.27 3.27Composite 2.26 1.78 2.05 2.57 2.17 3.41 2.96 2.80 3.03Crude 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 1,134.1Trinidad 34.1 34.5 38.6 43.0 37.6 42.1 43.2 39.8 41.7Other International – – – – – – – 0.7 0.2Total 1,028.8 1,047.5 1,075.7 1,095.7 1,062.1 1,090.4 1,134.1 1,301.2 1,176.0Total MMBoe (D) 93.6 95.3 99.0 100.8 388.7 98.1 103.2 119.7 321.0(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 10 to the Condensed Consolidated Financial Statements in EOG's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2025).(C) Other International represents EOG's Kingdom of 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 SheetsIn millions of USD (Unaudited) 2024 2025 MAR JUN SEP DEC MAR JUN SEP DECCurrent AssetsCash and Cash Equivalents 5,292 5,431 6,122 7,092 6,599 5,216 3,530Accounts Receivable, Net 2,688 2,657 2,545 2,650 2,621 2,504 2,680Inventories 1,154 1,069 1,038 985 897 934 945Assets from Price Risk Management Activities 110 4 – – – – 19Other (A) 684 642 460 503 563 591 646Total 9,928 9,803 10,165 11,230 10,680 9,245 7,820Property, Plant and EquipmentOil and Gas Properties (Successful Efforts Method) 73,356 74,615 75,887 77,091 78,432 80,139 88,301Other Property, Plant and Equipment 5,768 6,078 6,314 6,418 6,510 6,616 6,772Total Property, Plant and Equipment 79,124 80,693 82,201 83,509 84,942 86,755 95,073Less: Accumulated Depreciation, Depletion and (46,047) (47,049) (48,075) (49,297) (50,310) (51,394) (52,488)AmortizationTotal Property, Plant and Equipment, Net 33,077 33,644 34,126 34,212 34,632 35,361 42,585Deferred Income Taxes 38 44 42 39 44 39 37Other Assets 1,753 1,733 1,818 1,705 1,626 1,639 1,757Total Assets 44,796 45,224 46,151 47,186 46,982 46,284 52,199Current LiabilitiesAccounts Payable 2,389 2,436 2,290 2,464 2,353 2,266 2,944Accrued Taxes Payable 786 600 855 1,007 668 348 392Dividends Payable 523 516 513 539 534 1,081 550Liabilities from Price Risk Management Activities – 8 32 116 276 85 17Current Portion of Long-Term Debt 34 534 34 532 1,280 778 27Current Portion of Operating Lease Liabilities 318 303 338 315 318 360 433Other 223 231 344 381 290 257 452Total 4,273 4,628 4,406 5,354 5,719 5,175 4,815Long-Term Debt 3,757 3,250 3,742 4,220 3,464 3,458 7,667Other Liabilities 2,533 2,456 2,480 2,395 2,368 2,398 2,496Deferred Income Taxes 5,597 5,731 5,949 5,866 5,915 6,015 6,936Commitments and ContingenciesStockholders' EquityCommon Stock, $0.01 Par 206 206 206 206 206 206 206Additional Paid in Capital 6,188 6,219 6,058 6,090 6,095 6,153 5,978Accumulated Other Comprehensive Loss (8) (8) (9) (4) (4) (7) (5)Retained Earnings 23,897 25,071 26,231 26,941 27,869 28,131 29,603Common Stock Held in Treasury (1,647) (2,329) (2,912) (3,882) (4,650) (5,245) (5,497)Total Stockholders' Equity 28,636 29,159 29,574 29,351 29,516 29,238 30,285Total Liabilities and Stockholders' Equity 44,796 45,224 46,151 47,186 46,982 46,284 52,199(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 StatementsIn millions of USD (Unaudited) 2024 2025 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr YearCash Flows from Operating ActivitiesReconciliation of Net Income to Net CashProvided by Operating Activities:Net Income 1,789 1,690 1,673 1,251 6,403 1,463 1,345 1,471 4,279Items Not Requiring (Providing) CashDepreciation, Depletion and Amortization 1,074 984 1,031 1,019 4,108 1,013 1,053 1,169 3,235Impairments 19 81 15 276 391 44 39 71 154Stock-Based Compensation Expenses 45 45 58 51 199 50 53 53 156Deferred Income Taxes 199 128 220 (80) 467 44 105 278 427(Gains) Losses on Asset Dispositions, Net (26) (20) 7 23 (16) 1 – 18 19Other, Net 9 3 2 3 17 11 11 2 24Dry Hole Costs 1 5 – 8 14 34 11 – 45Mark-to-Market Financial Commodity and Other (237) 47 (79) 65 (204) 191 (107) (116) (32)Derivative Contracts (Gains) Losses, NetNet Cash Received from (Payments for) 55 79 61 19 214 (38) (24) 27 (35)Settlements of Financial CommodityDerivative ContractsChanges in Components of Working Capital andOther Assets and LiabilitiesAccounts Receivable 58 33 109 (99) 101 48 122 133 303Inventories 117 75 30 37 259 76 (45) 4 35Accounts Payable (58) 29 (159) 152 (36) (129) (107) 5 (231)Accrued Taxes Payable 319 (185) 256 151 541 (339) (321) 28 (632)Other Assets (161) 42 197 (34) 44 (43) (43) (28) (114)Other Liabilities (71) (20) 108 6 23 (96) (52) 155 7Changes in Components of Working Capital (229) (127) 59 (85) (382) (41) (8) (159) (208)Associated with Investing ActivitiesNet Cash Provided by Operating Activities 2,903 2,889 3,588 2,763 12,143 2,289 2,032 3,111 7,432Investing Cash FlowsAcquisition of Encino Acquisition Partners, LLC, – – – – – – – (4,464) (4,464)Net of Cash AcquiredAdditions to Oil and Gas Properties (1,485) (1,357) (1,263) (1,248) (5,353) (1,381) (1,699) (1,492) (4,572)Additions to Other Property, Plant and (350) (313) (239) (117) (1,019) (102) (94) (171) (367)EquipmentProceeds from Sales of Assets 9 10 – 4 23 12 4 5 21Changes in Components of Working Capital 229 127 (59) 85 382 41 8 159 208Associated with Investing ActivitiesNet Cash Used in Investing Activities (1,597) (1,533) (1,561) (1,276) (5,967) (1,430) (1,781) (5,963) (9,174)Financing Cash FlowsLong-Term Debt Borrowings – – – 985 985 – – 3,472 3,472Long-Term Debt Repayments – – – – – – (500) (1,266) (1,766)Dividends Paid (525) (520) (533) (509) (2,087) (538) (528) (545) (1,611)Treasury Stock Purchased (759) (699) (795) (993) (3,246) (806) (602) (479) (1,887)Proceeds from Stock Options Exercised and – 11 – 11 22 – 11 – 11Employee Stock Purchase PlanDebt Issuance and Other Financing Costs – – – (2) (2) – (7) (7) (14)Repayment of Finance Lease Liabilities (8) (9) (8) (8) (33) (8) (9) (8) (25)Net Cash Used in Financing Activities (1,292) (1,217) (1,336) (516) (4,361) (1,352) (1,635) 1,167 (1,820)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) (3,562)Cash and Cash Equivalents at Beginning of Period 5,278 5,292 5,431 6,122 5,278 7,092 6,599 5,216 7,092Cash and Cash Equivalents at End of Period 5,292 5,431 6,122 7,092 7,092 6,599 5,216 3,530 3,530Non-GAAP Financial MeasuresTo 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.DirectATRORThe 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 IncomeIn 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 offinancial commodity derivative contracts by eliminating the net unrealized mark-to-market (gains) losses from these and other derivativetransactions, 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 resultof certain other events or decisions (e.g., a periodic review of EOG's oil and gas properties or other assets)), to add back costs associatedwith the Encino acquisition and to make certain other adjustments to exclude non-recurring and certain other items as further describedbelow. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reportedcompany 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 thefinancial performance of other companies in the industry. 3Q 2025 Before Income Tax After Diluted Tax Impact Tax Earnings per ShareReported Net Income (GAAP) 1,824 (353) 1,471 2.70Adjustments:Gains on Mark-to-Market Financial Commodity and Other Derivative (116) 25 (91) (0.16)Contracts, NetNet Cash Received from Settlements of Financial Commodity Derivative 27 (5) 22 0.04Contracts (1)Add: Losses on Asset Dispositions, Net 18 (6) 12 0.02Add: Acquisition-related costs (2) 68 (10) 58 0.11Adjustments to Net Income (3) 4 1 0.01Adjusted Net Income (Non-GAAP) 1,821 (349) 1,472 2.71Average Number of Common SharesBasic 541Diluted 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).Adjusted Net Income(Continued)In millions of USD, except share data (in millions) and per share data (Unaudited) 2Q 2025 Before Income Tax After Diluted Tax Impact Tax Earnings per ShareReported Net Income (GAAP) 1,751 (406) 1,345 2.46Adjustments:Gains on Mark-to-Market Financial Commodity and Other Derivative (107) 23 (84) (0.16)Contracts, NetNet Cash Payments for Settlements of Financial Commodity Derivative (24) 5 (19) (0.03)Contracts (1)Add: Certain Impairments 11 – 11 0.02Add: Acquisition-related costs (2) 18 (3) 15 0.03Adjustments to Net Income (102) 25 (77) (0.14)Adjusted Net Income (Non-GAAP) 1,649 (381) 1,268 2.32Average Number of Common SharesBasic 543Diluted 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 ShareReported Net Income (GAAP) 1,877 (414) 1,463 2.65Adjustments:Losses on Mark-to-Market Financial Commodity and Other Derivative 191 (41) 150 0.26Contracts, NetNet Cash Payments for Settlements of Financial Commodity Derivative (38) 8 (30) (0.05)Contracts (1)Add: Losses on Asset Dispositions, Net 1 2 3 0.01Adjustments to Net Income 154 (31) 123 0.22Adjusted Net Income (Non-GAAP) 2,031 (445) 1,586 2.87Average Number of Common SharesBasic 550Diluted 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.Adjusted Net Income(Continued)In millions of USD, except share data (in millions) and per share data (Unaudited) 4Q 2024 Before Income Tax After Diluted Tax Impact Tax Earnings per ShareReported Net Income (GAAP) 1,624 (373) 1,251 2.23Adjustments:Losses on Mark-to-Market Financial Commodity and Other Derivative 65 (14) 51 0.10Contracts, NetNet Cash Received from Settlements of Financial Commodity Derivative 19 (4) 15 0.03Contracts (1)Add: Losses on Asset Dispositions, Net 23 (4) 19 0.03Add: Certain Impairments 254 (55) 199 0.35Adjustments to Net Income 361 (77) 284 0.51Adjusted Net Income (Non-GAAP) 1,985 (450) 1,535 2.74Average Number of Common SharesBasic 557Diluted 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.Adjusted Net Income(Continued)In millions of USD, except share data (in millions) and per share data (Unaudited) 3Q 2024 Before Income Tax After Diluted Tax Impact Tax Earnings per ShareReported Net Income (GAAP) 2,134 (461) 1,673 2.95Adjustments:Gains on Mark-to-Market Financial Commodity and Other Derivative (79) 17 (62) (0.11)Contracts, NetNet Cash Received from Settlements of Financial Commodity Derivative 61 (13) 48 0.08Contracts (1)Add: Losses on Asset Dispositions, Net 7 (2) 5 0.01Less: Severance Tax Refund (31) 7 (24) (0.04)Add: Severance Tax Consulting Fees 10 (2) 8 0.01Less: Interest on Severance Tax Refund (5) 1 (4) (0.01)Adjustments to Net Income (37) 8 (29) (0.06)Adjusted Net Income (Non-GAAP) 2,097 (453) 1,644 2.89Average Number of Common SharesBasic 564Diluted 568(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, 2024, such amount was $61 million.Adjusted Net Income(Continued)In millions of USD, except share data (in millions) and per share data (Unaudited) FY 2024 Before Income Tax After Diluted Tax Impact Tax Earnings per ShareReported Net Income (GAAP) 8,218 (1,815) 6,403 11.25Adjustments:Gains on Mark-to-Market Financial Commodity and Other Derivative (204) 44 (160) (0.28)Contracts, NetNet Cash Received from Settlements of Financial Commodity 214 (46) 168 0.30Derivative Contracts (1)Less: Gains on Asset Dispositions, Net (16) 3 (13) (0.02)Add: Certain Impairments 291 (57) 234 0.41Less: Severance Tax Refund (31) 7 (24) (0.04)Add: Severance Tax Consulting Fees 10 (2) 8 0.01Less: Interest on Severance Tax Refund (5) 1 (4) (0.01)Adjustments to Net Income 259 (50) 209 0.37Adjusted Net Income (Non-GAAP) 8,477 (1,865) 6,612 11.62Average Number of Common SharesBasic 566Diluted 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.Adjusted Net Income(Continued)In millions of USD, except share data (in millions) and per share data (Unaudited) FY 2023 Before Income Tax After Diluted Tax Impact Tax Earnings per ShareReported Net Income (GAAP) 9,689 (2,095) 7,594 13.00Adjustments:Gains on Mark-to-Market Financial Commodity Derivative (818) 176 (642) (1.09)Contracts, NetNet Cash Payments for Settlements of Financial Commodity (112) 24 (88) (0.15)Derivative Contracts (1)Less: Gains on Asset Dispositions, Net (95) 20 (75) (0.13)Add: Certain Impairments 42 (6) 36 0.06Adjustments to Net Income (983) 214 (769) (1.31)Adjusted Net Income (Non-GAAP) 8,706 (1,881) 6,825 11.69Average Number of Common SharesBasic 581Diluted 584(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, 2023, such amount was $112 million.Net Income per ShareIn millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)2Q 2025 Net Income per Share (GAAP) – Diluted 2.46Realized Prices3Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and 38.05Natural Gas per BoeLess: 2Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and (39.80)Natural Gas per BoeSubtotal (1.75)Multiplied by: 3Q 2025 Crude Oil Equivalent Volumes (MMBoe) 119.7Total Change in Revenue (209)Add: Income Tax Benefit (Provision) Imputed (based on 22%) 46Change in Net Income (163)Change in Diluted Earnings per Share (0.30)Volumes3Q 2025 Crude Oil Equivalent Volumes (MMBoe) 119.7Less: 2Q 2025 Crude Oil Equivalent Volumes (MMBoe) (103.2)Subtotal 16.5Multiplied by: 3Q 2025 Composite Average Margin per Boe (GAAP) (Including Total 13.42Exploration Costs) (refer to “Revenues, Costs and Margins Per Barrel of Oil Equivalent”schedule below)Change in Margin 221Less: Income Tax Benefit (Provision) Imputed (based on 22%) (49)Change in Net Income 172Change in Diluted Earnings per Share 0.32Certain Operating Costs per Boe2Q 2025 Total Cash Operating Costs (GAAP) and Total DD&A per Boe 20.25Less: 3Q 2025 Total Cash Operating Costs (GAAP) and Total DD&A per Boe (20.27)Subtotal (0.02)Multiplied by: 3Q 2025 Crude Oil Equivalent Volumes (MMBoe) 119.7Change in Before-Tax Net Income (2)Add: Income Tax Benefit (Provision) Imputed (based on 22%) 1Change in Net Income (1)Change in Diluted Earnings per Share 0.00Net Income Per Share(Continued)In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net3Q 2025 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative 116ContractsLess: Income Tax Benefit (Provision) (25)After Tax – (a) 91Less: 2Q 2025 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative 107ContractsLess: Income Tax Benefit (Provision) (23)After Tax – (b) 84Change in Net Income – (a) – (b) 7Change in Diluted Earnings per Share 0.01Other (1) 0.213Q 2025 Net Income per Share (GAAP) – Diluted 2.703Q 2025 Average Number of Common Shares – Diluted 544(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 ShareIn millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)2Q 2025 Adjusted Net Income per Share (Non-GAAP) – Diluted 2.32Realized Prices3Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and 38.05Natural Gas per BoeLess: 2Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and (39.80)Natural Gas per BoeSubtotal (1.75)Multiplied by: 3Q 2025 Crude Oil Equivalent Volumes (MMBoe) 119.7Total Change in Revenue (209)Add: Income Tax Benefit (Provision) Imputed (based on 22%) 46Change in Net Income (163)Change in Diluted Earnings per Share (0.30)Volumes3Q 2025 Crude Oil Equivalent Volumes (MMBoe) 119.7Less: 2Q 2025 Crude Oil Equivalent Volumes (MMBoe) (103.2)Subtotal 16.5Multiplied by: 3Q 2025 Composite Average Margin per Boe (Non-GAAP) (Including Total 13.99Exploration Costs) (refer to “Revenues, Costs and Margins Per Barrel of Oil Equivalent”schedule below)Change in Margin 231Less: Income Tax Benefit (Provision) Imputed (based on 22%) (51)Change in Net Income 180Change in Diluted Earnings per Share 0.33Certain Operating Costs per Boe2Q 2025 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe 20.14Less: 3Q 2025 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe (19.70)Subtotal 0.44Multiplied by: 3Q 2025 Crude Oil Equivalent Volumes (MMBoe) 119.7Change in Before-Tax Net Income 53Add: Income Tax Benefit (Provision) Imputed (based on 22%) (12)Change in Net Income 41Change in Diluted Earnings per Share 0.08Adjusted 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)Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts3Q 2025 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative 27ContractsLess: Income Tax Benefit (Provision) (5)After Tax – (a) 22Less: 2Q 2025 Net Cash Received from (Payments for) Settlements of Financial Commodity (24)Derivative ContractsLess: Income Tax Benefit (Provision) 5After Tax – (b) (19)Change in Net Income – (a) – (b) 41Change in Diluted Earnings per Share 0.08Other (1) 0.203Q 2025 Adjusted Net Income per Share (Non-GAAP) 2.713Q 2025 Average Number of Common Shares – Diluted 544(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 FlowIn 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 thispresentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities forChanges in Components of Working Capital and Other Assets and Liabilities, Changes in Components of Working Capital Associated with InvestingActivities (or Investing and Financing Activities, as applicable) and certain other adjustments to exclude certain non-recurring items and other items asfurther described below. EOG defines Free Cash Flow (Non-GAAP) for a given period as Adjusted Cash Flow from Operations (Non-GAAP) (see belowreconciliation) for such period less the Total Capital Expenditures (Non-GAAP) (see below reconciliation) during such period, as is illustrated below. EOGmanagement uses this information for comparative purposes within the industry. As indicated in the tables below, EOG is (1) in addition to its customaryworking capital-related adjustments, adjusting Net Cash Provided by Operating Activities (GAAP) to add back certain non-recurring acquisition-relatedcosts incurred during the second and third 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 presentationbelow with respect to the second and third 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 YearNet Cash Provided by Operating Activities (GAAP) 2,903 2,889 3,588 2,763 12,143 2,289 2,032 3,111 7,432Adjustments:Changes in Components of Working Capitaland Other Assets and LiabilitiesAccounts Receivable (58) (33) (109) 99 (101) (48) (122) (133) (303)Inventories (117) (75) (30) (37) (259) (76) 45 (4) (35)Accounts Payable 58 (29) 159 (152) 36 129 107 (5) 231Accrued Taxes Payable (319) 185 (256) (151) (541) 339 321 (28) 632Other Assets 161 (42) (197) 34 (44) 43 43 28 114Other Liabilities 71 20 (108) (6) (23) 96 52 (155) (7)Changes in Components of Working Capital 229 127 (59) 85 382 41 8 159 208Associated with Investing ActivitiesAdd:Acquisition-Related Costs (1), Net of Tax – – – – – – 10 58 68Adjusted Cash Flow from Operations (Non- 2,928 3,042 2,988 2,635 11,593 2,813 2,496 3,031 8,340GAAP)Less:Total Capital Expenditures (Non-GAAP) (2) (1,703) (1,668) (1,497) (1,358) (6,226) (1,484) (1,523) (1,648) (4,655)Free Cash Flow (Non-GAAP) 1,225 1,374 1,491 1,277 5,367 1,329 973 1,383 3,685(1) Consists of Encino acquisition-related G&A costs of $12 million and $68 million (each before tax) for the three months ended June 30, 2025 andthree months ended September 30, 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 YearTotal Expenditures (GAAP) 1,952 1,682 1,573 1,446 6,653 1,546 1,883 8,544 11,973Less:Asset Retirement Costs (21) 60 (11) (26) 2 (13) (14) (86) (113)Non-Cash Leasehold Acquisition Costs (3) (31) (34) (17) (3) (85) (9) (2) (3) (14)Acquisition Costs of Properties (3) (21) (5) – (7) (33) 1 (270) (6,736) (7,005)Acquisition Costs of Other Property, (131) (1) (5) – (137) – – – -Plant and EquipmentExploration Costs (45) (34) (43) (52) (174) (41) (74) (71) (186)Total Capital Expenditures (Non-GAAP) 1,703 1,668 1,497 1,358 6,226 1,484 1,523 1,648 4,655Cash Flow from Operations and Free Cash Flow (Continued)In millions of USD (Unaudited) FY 2023 FY 2022Net Cash Provided by Operating Activities (GAAP) 11,340 11,093Adjustments:Changes in Components of Working Capital and Other Assets and LiabilitiesAccounts Receivable 38 347Inventories 231 534Accounts Payable 119 (90)Accrued Taxes Payable (61) 113Other Assets (39) 364Other Liabilities (184) 266Changes in Components of Working Capital Associated with Investing Activities (295) (375)Adjusted Cash Flow from Operations (Non-GAAP) 11,149 12,252Less:Total Capital Expenditures (Non-GAAP) (a) (6,041) (4,607)Free Cash Flow (Non-GAAP) 5,108 7,645(a) See below reconciliation of Total Expenditures (GAAP) to Total Capital Expenditures (Non-GAAP):Total Expenditures (GAAP) 6,818 5,610Less:Asset Retirement Costs (257) (298)Non-Cash Development Drilling (90) -Non-Cash Leasehold Acquisition Costs (3) (99) (127)Acquisition Costs of Properties (3) (16) (419)Acquisition Costs of Other Property, Plant and Equipment (134) -Exploration Costs (181) (159)Total Capital Expenditures (Non-GAAP) 6,041 4,607(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 RatioIn 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 TotalCapitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated withinternational subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors whofollow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-TotalCapitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. September 30, June 30, March 31, December 31, September 30, 2025 2025 2025 2024 2024Total Stockholders' Equity – (a) 30,285 29,238 29,516 29,351 29,574Current and Long-Term Debt (GAAP) – (b) 7,694 4,236 4,744 4,752 3,776Less: Cash (3,530) (5,216) (6,599) (7,092) (6,122)Net Debt (Non-GAAP) – (c) 4,164 (980) (1,855) (2,340) (2,346)Total Capitalization (GAAP) – (a) + (b) 37,979 33,474 34,260 34,103 33,350Total Capitalization (Non-GAAP) – (a) + (c) 34,449 28,258 27,661 27,011 27,228Debt-to-Total Capitalization (GAAP) – (b) / [(a) + (b)] 20.3% 12.7% 13.8% 13.9% 11.3%Net Debt-to-Total Capitalization (Non-GAAP) – (c) / 12.1% -3.5% -6.7% -8.7% -8.6%[(a) + (c)]Revenues, Costs and Margins Per Barrel of Oil EquivalentIn 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 groupsof components of revenues, costs and/or margins per barrel of oil equivalent (Boe). Certain of these components are adjusted for non-recurring andcertain other items, as further discussed below. EOG management uses this information for purposes of comparing its financial performance with thefinancial performance of other companies in the industry. 3Q 2025 2Q 2025 1Q 2025 4Q 2024 3Q 2024Volume – Million Barrels of Oil Equivalent – (a) 119.7 103.2 98.1 100.8 99.0Total Operating Revenues and Other – (b) 5,847 5,478 5,669 5,585 5,965Total Operating Expenses – (c) 4,011 3,731 3,810 3,993 3,876Operating Income – (d) 1,836 1,747 1,859 1,592 2,089Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural GasCrude Oil and Condensate 3,243 2,974 3,293 3,261 3,488Natural Gas Liquids 604 534 572 554 524Natural Gas 707 600 637 494 372Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural 4,554 4,108 4,502 4,309 4,384Gas – (e)Operating CostsLease and Well 431 396 401 394 392Gathering, Processing and Transportation Costs (1) 587 455 440 441 445General and Administrative (GAAP) 239 186 171 189 167Less: Certain Items (see Endnotes 2 & 3 to 3Q 2025 earnings release) (68) (12) – – (10)General and Administrative (Non-GAAP) (2) 171 174 171 189 157Taxes Other Than Income (GAAP) 309 301 341 291 283Add: Severance Tax Refund – – – – 31Taxes Other Than Income (Non-GAAP) (3) 309 301 341 291 314Interest Expense, Net 71 51 47 38 31Less: Acquisition-Related Financing Commitment Costs – (6) – – -Interest Expense, Net (Non-GAAP) (4) 71 45 47 38 31Total Operating Cost (GAAP) (excluding DD&A and Total Exploration Costs) 1,637 1,389 1,400 1,353 1,318- (f)Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration 1,569 1,371 1,400 1,353 1,339Costs) – (g)Depreciation, Depletion and Amortization (DD&A) 1,169 1,053 1,013 1,019 1,031Total Operating Cost (GAAP) (excluding Total Exploration Costs) – (h) 2,806 2,442 2,413 2,372 2,349Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) – (i) 2,738 2,424 2,413 2,372 2,370Exploration Costs 71 74 41 52 43Dry Hole Costs – 11 34 8 -Impairments 71 39 44 276 15Total Exploration Costs (GAAP) 142 124 119 336 58Less: Certain Impairments (5) – (11) – (254) -Total Exploration Costs (Non-GAAP) 142 113 119 82 58Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) – (j) 2,948 2,566 2,532 2,708 2,407Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non- 2,880 2,537 2,532 2,454 2,428GAAP)) – (k)Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural 1,606 1,542 1,970 1,601 1,977Gas less Total Operating Cost (GAAP) (including Total Exploration Costs(GAAP))Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural 1,674 1,571 1,970 1,855 1,956Gas less Total Operating Cost (Non-GAAP) (including Total ExplorationCosts (Non-GAAP))Revenues, Costs and Margins Per Barrel of Oil Equivalent(Continued)In millions of USD, except Boe and per Boe amounts (Unaudited) 3Q 2025 2Q 2025 1Q 2025 4Q 2024 3Q 2024Per Barrel of Oil Equivalent (Boe) Calculations (GAAP)Composite Average Operating Revenues and Other per Boe – (b) / (a) 48.85 53.08 57.79 55.41 60.25Composite Average Operating Expenses per Boe – (c) / (a) 33.51 36.15 38.84 39.62 39.15Composite Average Operating Income per Boe – (d) / (a) 15.34 16.93 18.95 15.79 21.10Composite Average Revenue from Sales of Crude Oil and Condensate, 38.05 39.80 45.88 42.74 44.31NGLs, and Natural Gas per Boe – (e) / (a)Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) – 13.67 13.46 14.26 13.42 13.32(f) / (a)Composite Average Margin per Boe (excluding DD&A and Total Exploration 24.38 26.34 31.62 29.32 30.99Costs) – [(e) / (a) – (f) / (a)]Total Operating Cost per Boe (excluding Total Exploration Costs) – (h) / (a) 23.44 23.66 24.58 23.53 23.74Composite Average Margin per Boe (excluding Total Exploration Costs) – 14.61 16.14 21.30 19.21 20.57[(e) / (a) – (h) / (a)]Total Operating Cost per Boe (including Total Exploration Costs) – (j) / (a) 24.63 24.86 25.79 26.86 24.33Composite Average Margin per Boe (including Total Exploration Costs) – 13.42 14.94 20.09 15.88 19.98[(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) – 13.10 13.30 14.26 13.42 13.53(g) / (a)Composite Average Margin per Boe (excluding DD&A and Total Exploration 24.95 26.50 31.62 29.32 30.78Costs) – [(e) / (a) – (g) / (a)]Total Operating Cost per Boe (excluding Total Exploration Costs) – (i) / (a) 22.87 23.50 24.58 23.53 23.95Composite Average Margin per Boe (excluding Total Exploration Costs) – 15.18 16.30 21.30 19.21 20.36[(e) / (a) – (i) / (a)]Total Operating Cost per Boe (including Total Exploration Costs) – (k) / (a) 24.06 24.59 25.79 24.34 24.54Composite Average Margin per Boe (including Total Exploration Costs) – 13.99 15.21 20.09 18.40 19.77[(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) 2024 2023 2022Volume – Million Barrels of Oil Equivalent – (a) 388.7 359.4 331.5Total Operating Revenues and Other – (b) 23,698 24,186 25,702Total Operating Expenses – (c) 15,616 14,583 15,736Operating Income (Loss) – (d) 8,082 9,603 9,966Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural GasCrude Oil and Condensate 13,921 13,748 16,367Natural Gas Liquids 2,106 1,884 2,648Natural Gas 1,551 1,744 3,781Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural 17,578 17,376 22,796Gas – (e)Operating CostsLease and Well 1,572 1,454 1,331Gathering, Processing and Transportation Costs (1) 1,722 1,620 1,587General and Administrative (GAAP) 669 640 570Less: Severance Tax Consulting Fees (10) – (16)General and Administrative (Non-GAAP) (2) 659 640 554Taxes Other Than Income (GAAP) 1,249 1,284 1,585Add: Severance Tax Refund 31 – 115Taxes Other Than Income (Non-GAAP) (3) 1,280 1,284 1,700Interest Expense, Net 138 148 179Total Operating Cost (GAAP) (excluding DD&A and Total Exploration Costs) – 5,350 5,146 5,252(f)Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration 5,371 5,146 5,351Costs) – (g)Depreciation, Depletion and Amortization (DD&A) 4,108 3,492 3,542Total Operating Cost (GAAP) (excluding Total Exploration Costs) – (h) 9,458 8,638 8,794Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) – (i) 9,479 8,638 8,893Exploration Costs 174 181 159Dry Hole Costs 14 1 45Impairments 391 202 382Total Exploration Costs (GAAP) 579 384 586Less: Certain Impairments (5) (291) (42) (113)Total Exploration Costs (Non-GAAP) 288 342 473Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) – (j) 10,037 9,022 9,380Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non- 9,767 8,980 9,366GAAP)) – (k)Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural 7,541 8,354 13,416Gas less Total Operating Cost (GAAP) (including Total Exploration Costs(GAAP))Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural 7,811 8,396 13,430Gas less Total Operating Cost (Non-GAAP) (including Total ExplorationCosts (Non-GAAP))Revenues, Costs and Margins Per Barrel of Oil Equivalent(Continued)In millions of USD, except Boe and per Boe amounts (Unaudited) 2024 2023 2022Per Barrel of Oil Equivalent (Boe) Calculations (GAAP)Composite Average Operating Revenues and Other per Boe – (b) / (a) 60.97 67.30 77.53Composite Average Operating Expenses per Boe – (c) / (a) 40.18 40.58 47.47Composite Average Operating Income (Loss) per Boe – (d) / (a) 20.79 26.72 30.06Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, 45.22 48.34 68.77and Natural Gas per Boe – (e) / (a)Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) – 13.76 14.31 15.84(f) / (a)Composite Average Margin per Boe (excluding DD&A and Total Exploration 31.46 34.03 52.93Costs) – [(e) / (a) – (f) / (a)]Total Operating Cost per Boe (excluding Total Exploration Costs) – (h) / (a) 24.33 24.03 26.53Composite Average Margin per Boe (excluding Total Exploration Costs) – 20.89 24.31 42.24[(e) / (a) – (h) / (a)]Total Operating Cost per Boe (including Total Exploration Costs) – (j) / (a) 25.82 25.10 28.30Composite Average Margin per Boe (including Total Exploration Costs) – [(e) / 19.40 23.24 40.47(a) – (j) / (a)]Per Barrel of Oil Equivalent (Boe) Calculations (Non-GAAP)Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) – 13.82 14.31 16.14(g) / (a)Composite Average Margin per Boe (excluding DD&A and Total Exploration 31.40 34.03 52.63Costs) – [(e) / (a) – (g) / (a)]Total Operating Cost per Boe (excluding Total Exploration Costs) – (i) / (a) 24.39 24.03 26.83Composite Average Margin per Boe (excluding Total Exploration Costs) – 20.83 24.31 41.94[(e) / (a) – (i) / (a)]Total Operating Cost per Boe (including Total Exploration Costs) – (k) / (a) 25.13 24.98 28.26Composite Average Margin per Boe (including Total Exploration Costs) – [(e) / 20.09 23.36 40.51(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. 2024 Actual 2023 Actual 2022 ActualCrude Oil and Condensate Volumes (MBod)United States 490.6 475.2 460.7Trinidad 0.8 0.6 0.6Total 491.4 475.8 461.3Natural Gas Liquids Volumes (MBbld)Total 245.9 223.8 197.7Natural Gas Volumes (MMcfd)United States 1,728 1,551 1,315Trinidad 220 160 180Total 1,948 1,711 1,495Crude Oil Equivalent Volumes (MBoed)United States 1,024.5 957.5 877.5Trinidad 37.6 27.3 30.7Total 1,062.1 984.8 908.2Benchmark PriceOil (WTI) ($/Bbl) 75.72 77.61 94.23Natural Gas (HH) ($/Mcf) 2.27 2.74 6.64Crude Oil and Condensate – above (below) WTI1 ($/Bbl)United States 1.70 1.57 2.99Trinidad (11.29) (9.03) (8.07)Natural Gas Liquids – Realizations as % of WTITotal 30.9% 29.7% 39.0%Natural Gas – above (below) NYMEX Henry Hub2 ($/Mcf)United States (0.28) (0.04) 0.63Natural Gas Realizations3 ($/Mcf)Trinidad 3.65 3.65 4.43Total Expenditures (GAAP) ($MM) 6,653 6,818 5,610Capital Expenditures4 (non-GAAP) ($MM) 6,226 6,041 4,607Operating Unit Costs ($/Boe)Lease and Well 4.04 4.05 4.02Gathering, Processing and Transportation Costs5 4.43 4.50 4.78General and Administrative (GAAP) 1.72 1.78 1.72General and Administrative (non-GAAP)6 1.70 1.78 1.67Cash Operating Costs (GAAP) 10.19 10.33 10.52Cash Operating Costs (non-GAAP)6 10.17 10.33 10.47Depreciation, Depletion and Amortization 10.57 9.72 10.69Expenses ($MM)Exploration and Dry Hole 188 182 204Impairment (GAAP) 391 202 382Impairment (excluding certain impairments (non-GAAP))7 100 160 269Capitalized Interest 45 33 36Net Interest 138 148 179TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas)(GAAP) 7.1% 7.4% 7.0%(non-GAAP)6 7.3% 7.4% 7.5%Income TaxesEffective Rate 22.1% 21.6% 21.7%Current Tax Expense ($MM) 1,348 1,415 2,208Additional Key Information(Continued)Endnotes1) 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.2) 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.3) 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.4) 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.5) 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.6) Cash Operating Costs consist of LOE, GP&T and G&A. 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 consulting fees on G&A and total Cash Operating Costs for fiscal year 2024 and fiscal year 2022 was $(0.02) and $(0.05), respectively.7) 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).

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SOURCE EOG Resources, Inc.

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