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EOG Resources Reports Third Quarter 2025 Results

1. EOG reported $5.847 billion in total revenue for Q3 2025. 2. Adjusted net income was $1.472 billion, or $2.71 per share. 3. EOG generated $1.4 billion in free cash flow, supporting shareholder returns. 4. Production rates exceeded guidance in crude oil, NGL, and natural gas. 5. Acquisition of Encino showed strong integration and operational efficiency gains.

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Why Bullish?

Recent performance includes higher revenues and free cash flow, alongside effective management strategies. This reflects strong operational health, akin to other companies in the sector that saw improved stock prices following similar performance analytics.

How important is it?

The quarterly earnings report includes significant revenue growth, shareholder returns, and successful integration of the Encino acquisition, contributing strong insights into EOG's operational capabilities and future performance outlook.

Why Short Term?

The strong quarterly results will likely influence market sentiment in the near term as investors react to EOG's successful performance and cash returns.

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, /PRNewswire/ -- 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 data GAAP  3Q 2025 2Q 2025 1Q 2025 4Q 2024 3Q 2024 Total Revenue 5,847 5,478 5,669 5,585 5,965 Net Income 1,471 1,345 1,463 1,251 1,673 Net Income Per Share 2.70 2.46 2.65 2.23 2.95 Net Cash Provided by Operating Activities 3,111 2,032 2,289 2,763 3,588 Total Expenditures 8,544 1,883 1,546 1,446 1,573 Current and Long–Term Debt 7,694 4,236 4,744 4,752 3,776 Cash and Cash Equivalents 3,530 5,216 6,599 7,092 6,122 Debt–to–Total Capitalization 20.3 % 12.7 % 13.8 % 13.9 % 11.3 % Cash Operating Costs ($/Boe) 10.50 10.05 10.31 10.15 10.15 Non–GAAP Adjusted Net Income 1,472 1,268 1,586 1,535 1,644 Adjusted Net Income Per Share 2.71 2.32 2.87 2.74 2.89 Adjusted CFO1 3,031 2,496 2,813 2,635 2,988 Capital Expenditures 1,648 1,523 1,484 1,358 1,497 Free Cash Flow 1,383 973 1,329 1,277 1,491 Net Debt 4,164 (980) (1,855) (2,340) (2,346) Net Debt–to–Total Capitalization 12.1 % (3.5 %) (6.7 %) (8.7 %) (8.6 %) Cash Operating Costs ($/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 $440 million of shares Oil, NGLs and natural gas production above guidance midpoints Capital expenditures and per–unit operating costs better than guidance midpoints Closed on the acquisition of Encino Acquisition Partners (Encino) Third Quarter 2025 Highlights and Cash Return Volumes and Capital Expenditures Volumes 3Q 2025 3Q 2025Guidance Midpoint  2Q 2025  1Q 2025  4Q 2024  3Q 2024 Crude Oil and Condensate (MBod) 534.5 532.4 504.2 502.1 494.6 493.0 Natural Gas Liquids (MBbld) 309.3 305.0 258.4 241.7 252.5 254.3 Natural Gas (MMcfd) 2,745 2,735 2,229 2,080 2,092 1,970 Total Crude Oil Equivalent (MBoed) 1,301.2 1,293.3 1,134.1 1,090.4 1,095.7 1,075.7 Capital Expenditures ($MM) 1,648 1,650 1,523 1,484 1,358 1,497 From Ezra Yacob, 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 the UAE. 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 RepurchasesThe 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 guidance range Natural gas production of 2,745 MMcfd was above the midpoint of the guidance range Total company equivalent production of 1,301.2 MBoed 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 to 2Q 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 of Encino for $5.7 billion, subject to post–closing adjustments Issued $3.5 billion of senior notes in conjunction with the Encino acquisition Third Quarter 2025 Operating Performance Lease and Well QoQ: Decreased primarily due to the impact of higher production, primarily in the Utica from the integration of Encino operations, and lower workover expenses Guidance Midpoint: Lower primarily due to lower workover expenses and operating and maintenance costs General and Administrative (Non–GAAP) QoQ: Decreased primarily due to the impact of higher production, primarily in the Utica from the integration of Encino operations, and lower employee–related expenses Guidance Midpoint: Lower primarily due to lower employee–related expenses Gathering, Processing and Transportation Costs QoQ: Increased primarily due to the impact of higher Utica production from the integration of Encino operations Guidance Midpoint: Lower primarily due to lower natural gas gathering and processing fees Depreciation, Depletion and Amortization QoQ: Decreased primarily due to the impact of higher Utica production and well mix Guidance Midpoint: Lower primarily due to the addition of lower–cost reserves Third Quarter 2025 Results vs Guidance (Unaudited) See "Endnotes" below for related discussion and definitions.      3Q 2025 3Q 2025 Guidance Midpoint 6 Variance 2Q 2025 1Q 2025 4Q 2024 3Q 2024 Crude Oil and Condensate Volumes (MBod) United States 532.9 531.0 1.9 503.1 500.9 493.5 491.8 Trinidad 1.6 1.4 0.2 1.1 1.2 1.1 1.2 Total 534.5 532.4 2.1 504.2 502.1 494.6 493.0 Natural Gas Liquids Volumes (MBbld) Total 309.3 305.0 4.3 258.4 241.7 252.5 254.3 Natural Gas Volumes (MMcfd) United States 2,511 2,525 (14) 1,977 1,834 1,840 1,745 Trinidad 230 210 20 252 246 252 225 Other International7 4 0 4 0 0 0 0 Total 2,745 2,735 10 2,229 2,080 2,092 1,970 Total Crude Oil Equivalent Volumes (MBoed) 1,301.2 1,293.3 7.9 1,134.1 1,090.4 1,095.7 1,075.7 Total MMBoe 119.7 119.0 0.7 103.2 98.1 100.8 99.0 Benchmark Price Oil (WTI) ($/Bbl) 64.95 63.71 71.42 70.28 75.16 Natural Gas (HH) ($/Mcf) 3.07 3.44 3.66 2.79 2.16 Crude Oil and Condensate – above (below) WTI 8 ($/Bbl) United States 1.02 0.80 0.22 1.13 1.48 1.40 1.79 Trinidad (7.21) (5.00) (2.21) (9.21) (10.30) (9.81) (12.01) Natural Gas Liquids – Realizations as % of WTI Total 32.7 % 34.0 % (1.3 %) 35.6 % 36.8 % 33.9 % 29.8 % Natural Gas – above (below) NYMEX Henry Hub 9 ($/Mcf) United States (0.36) (0.40) 0.04 (0.57) (0.30) (0.40) (0.32) Natural Gas Realizations ($/Mcf) Trinidad 3.80 3.60 0.20 3.65 3.78 3.86 3.68 Other International7 3.27 0.00 3.27 0.00 0.00 0.00 0.00 Total Expenditures (GAAP) ($MM) 8,544 1,883 1,546 1,446 1,573 Capital Expenditures (non–GAAP) ($MM) 1,648 1,650 (2) 1,523 1,484 1,358 1,497 Operating Unit Costs ($/Boe) Lease and Well 3.60 3.70 (0.10) 3.84 4.09 3.91 3.96 Gathering, Processing and Transportation Costs5 4.90 5.10 (0.20) 4.41 4.48 4.37 4.50 General and Administrative (GAAP) 2.00 1.50 0.50 1.80 1.74 1.87 1.69 General and Administrative (non–GAAP)2,3 1.43 1.50 (0.07) 1.69 1.74 1.87 1.59 Cash Operating Costs (GAAP) 10.50 10.30 0.20 10.05 10.31 10.15 10.15 Cash Operating Costs (non–GAAP)2,3 9.93 10.30 (0.37) 9.94 10.31 10.15 10.05 Depreciation, Depletion and Amortization 9.77 9.85 (0.08) 10.20 10.32 10.11 10.42 Expenses ($MM) Exploration and Dry Hole 71 75 (4) 85 75 60 43 Impairment (GAAP) 71 39 44 276 15 Impairment (excluding certain impairments (non–GAAP))10 71 70 1 28 44 23 15 Capitalized Interest 27 21 6 11 12 13 12 Net Interest (GAAP) 71 83 (12) 51 47 38 31 Net Interest (non–GAAP)11 71 83 (12) 45 47 38 31 TOTI (% of revenues from sales of crude oil and condensate, 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 Taxes Effective Rate 19.4 % 20.5 % (1.1 %) 23.2 % 22.1 % 23.0 % 21.6 % Current Tax Expense ($MM) 75 180 (105) 301 370 454 240 Fourth Quarter and Full‐Year 2025 Guidance12 (Unaudited) See "Endnotes" below for related discussion and definitions. 4Q 2025 Guidance Range 4Q 2025 Midpoint FY 2025 Guidance Range FY 2025Midpoint Crude Oil and Condensate Volumes (MBod) United States 541.4 – 546.0 543.7 518.7 – 521.9 520.3 Trinidad 1.1 – 1.5 1.3 1.1 – 1.5 1.3 Total 542.5 – 547.5 545.0 519.8 – 523.4 521.6 Natural Gas Liquids Volumes (MBbld) Total 315.5 – 330.5 323.0 280.0 – 286.0 283.0  Natural Gas Volumes (MMcfd) United States 2,740 – 2,840 2,790 2,250 – 2,310 2,280 Trinidad 190 – 210 200 220 – 240 230 Total 2,930 – 3,050 2,990 2,470 – 2,550 2,510 Crude Oil Equivalent Volumes (MBoed) United States 1,313.6 – 1,349.8 1,331.7 1,173.7 – 1,192.9 1,183.3 Trinidad 32.8 – 36.5 34.7 37.8 – 41.5 39.7 Total 1,346.4 – 1,386.3 1,366.4 1,211.5 – 1,234.4 1,223.0 Crude Oil and Condensate – above (below) WTI 8 ($/Bbl) United States (0.50) – 1.00 0.25 0.35 – 1.35 0.85 Trinidad (5.25) – (2.75) (4.00) (8.40) – (6.90) (7.65) Natural Gas Liquids – Realizations as % of WTI Total 28.0 % – 38.0 % 33.0 % 31.5 % – 36.5 % 34.0 % Natural Gas – above (below) NYMEX Henry Hub 9 ($/Mcf) United States (0.80) – (0.10) (0.45) (0.95) – 0.05 (0.45) Natural Gas Realizations ($/Mcf) Trinidad 3.00 – 4.20 3.60 3.40 – 3.90 3.65 Capital Expenditures 13 ($MM) 1,600 – 1,700 1,650 6,200 – 6,400 6,300 Operating Unit Costs ($/Boe) Lease and Well 3.50 – 4.00 3.75 3.70 – 3.90 3.80 Gathering, Processing and Transportation Costs5 4.75 – 5.25 5.00 4.65 – 4.85 4.75 General and Administrative 1.40 – 1.70 1.55 1.45 – 1.65 1.55 Cash Operating Costs 9.65 – 10.95 10.30 9.80 – 10.40 10.10 Depreciation, Depletion and Amortization 9.25 – 10.25 9.75 9.70 – 10.30 10.00 Expenses ($MM) Exploration and Dry Hole 40 – 80 60 270 – 310 290 Impairment (excluding certain impairments)10 30 – 110 70 180 – 260 220 Capitalized Interest 34 – 38 36 85 – 89 87 Net Interest 64 – 68 66 228 – 232 230 TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas) 6.0 % – 8.0 % 7.0 % 6.5 % – 8.5 % 7.5 % Income Taxes Effective Rate 20.0 % – 25.0 % 22.5 % 19.0 % – 24.0 % 21.5 % Current Tax Expense ($MM) 220 – 320 270 970 – 1,070 1,020 Third Quarter 2025 Results WebcastFriday, 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 EOGEOG 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 www.eogresources.com. Investor ContactsPearce Hammond 713–571–4684Neel Panchal 713–571–4884Shelby O'Connor 713–571–4560 Media ContactKimberly 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. Excludes Encino acquisition–related G&A costs of $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 3Q 2025 was ($0.57) and for 2Q 2025 was ($0.11) as set forth in "Third Quarter 2025 Results vs Guidance" above. G&A per Boe (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 to EOG's third quarter 2025 guidance midpoint disclosures. 7) Other International represents EOG's Kingdom of Bahrain operations. Realized price represents contract price less Bapco's processing and distribution costs. 8) 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. 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 applicable months. 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 originally estimated). 11) Net interest expense (non–GAAP) excludes Encino acquisition–related financing commitment costs of $6 million in 2Q 2025. 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 or forecast. 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.  Glossary Acq Acquisitions Adjusted CFO Cash flow from operations before changes in working capital and certain acquisition–related costs  ATROR After–tax rate of return Bbl Barrel Bn Billion Boe Barrels of oil equivalent Bopd Barrels of oil per day CAGR Compound annual growth rate Capex Capital expenditures CO2e Carbon dioxide equivalent DD&A Depreciation, Depletion and Amortization Disc Discoveries Divest Divestitures EPS Earnings per share Ext Extensions GAAP Generally Accepted Accounting Principles G&A General and administrative expense G&P Gathering and processing GHG Greenhouse gas GP&T Gathering, processing & transportation expense HH Henry Hub LOE Lease operating expense, or lease and well expense MBbld Thousand barrels of liquids per day MBod Thousand barrels of oil per day MBoe Thousand barrels of oil equivalent MBoed Thousand barrels of oil equivalent per day Mcf Thousand cubic feet of natural gas MMBoe Million barrels of oil equivalent MMcfd Million cubic feet of natural gas per day NGLs Natural gas liquids NYMEX U.S. New York Mercantile Exchange OTP Other than price QoQ Quarter over quarter TOTI Taxes other than income USD United States dollar WTI West Texas Intermediate YoY 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. Although EOG believes the expectations reflected in its forward–looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that such assumptions are accurate or will prove to have been correct or that any of such expectations will be achieved (in full or at all) or will be achieved on the expected or anticipated timelines. Moreover, EOG's forward–looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward–looking statements include, among others: the timing, magnitude and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids (NGLs), natural gas and related commodities; the extent to which EOG is successful in its efforts to acquire or discover additional reserves; the extent to which EOG is successful in its efforts to (i) economically develop its acreage in, (ii) produce reserves and achieve anticipated production levels and rates of return from, (iii) decrease or otherwise control its drilling, completion and operating costs and capital expenditures related to, and (iv) maximize reserve recoveries from, its existing and future crude oil and natural gas exploration and development projects and associated potential and existing drilling locations; the success of EOG's cost–mitigation initiatives and actions in offsetting the impact of any inflationary or other pressures on EOG's operating costs and capital expenditures; the extent to which EOG is successful in its efforts to market its production of crude oil and condensate, NGLs and natural gas; security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, physical breaches of our facilities and other infrastructure or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business, and enhanced regulatory focus on the prevention of, and disclosure requirements relating to, cyber incidents; the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation, refining, liquefaction and export facilities and equipment; the availability, cost, terms and timing of issuance or execution of mineral licenses, concessions and leases and governmental and other permits and rights–of–way, and EOG's ability to retain mineral licenses, concessions and leases; the impact of, and changes in, government policies, laws and regulations, including climate change–related regulations, policies and initiatives (for example, with respect to air emissions); tax laws and regulations (including, but not limited to, carbon tax or other emissions–related legislation); environmental, health and safety laws and regulations relating to disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations affecting the leasing of acreage and permitting for oil and gas drilling and the calculation of royalty payments in respect of oil and gas production; laws and regulations imposing additional permitting and disclosure requirements, additional operating restrictions and conditions or restrictions on drilling and completion operations and on the transportation of crude oil, NGLs and natural gas; laws and regulations with respect to financial and other derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities; the impact of climate change–related legislation, policies and initiatives; climate change–related political, social and shareholder activism; and physical, transition and reputational risks and other potential developments related to climate change; the extent to which EOG is able to successfully and economically develop, implement and carry out its emissions and other environmental or safety–related initiatives and achieve its related targets, goals, ambitions and initiatives; EOG's failure to realize, in full or at all, the anticipated benefits of its acquisition of Encino and/or business disruptions resulting from the acquisition (e.g., relating to the integration of Encino's assets and operations into EOG's operations) that could harm EOG's business operations (including current plans and operations and the diversion of management's attention from EOG's ongoing business operations); EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, identify and resolve existing and potential issues with respect to such properties and accurately estimate reserves, production, drilling, completion and operating costs and capital expenditures with respect to such properties; the extent to which EOG's third–party–operated crude oil and natural gas properties are operated successfully, economically and in compliance with applicable laws and regulations; competition in the oil and gas exploration and production industry for the acquisition of licenses, concessions, leases and properties; the availability and cost of, and competition in the oil and gas exploration and production industry for, employees, labor and other personnel, facilities, equipment, materials (such as water, sand, fuel and tubulars) and services; the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise; weather and natural disasters, including its impact on crude oil and natural gas demand, and related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, liquefaction, compression, storage, transportation, and export facilities; the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG; EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements; the extent to which EOG is successful in its completion of planned asset dispositions; the extent and effect of any hedging activities engaged in by EOG; the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions; the economic and financial impact of epidemics, pandemics or other public health issues; geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, political instability and armed conflicts), including in the areas in which EOG operates; the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage; and the other factors described under ITEM 1A, Risk Factors of EOG's Annual Report on Form 10–K for the fiscal year ended December 31, 2024, and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10–Q or Current Reports on Form 8–K. In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward–looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward–looking statements. EOG's forward–looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward–looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. Historical Non–GAAP Financial Measures:Reconciliation schedules and definitions for the historical non–GAAP financial measures included or referenced herein as well as related discussion can be found on the EOG website at www.eogresources.com. Cautionary Notice Regarding Forward–Looking Non–GAAP Financial Measures:In addition, this 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 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, 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 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 9,510 Natural Gas Liquids 513 515 524 554 2,106 572 534 604 1,710 Natural Gas 382 303 372 494 1,551 637 600 707 1,944 Gains (Losses) on Mark-to-Market      Financial Commodity and Other      Derivative Contracts, Net 237 (47) 79 (65) 204 (191) 107 116 32 Gathering, Processing and Marketing 1,459 1,519 1,481 1,341 5,800 1,340 1,247 1,178 3,765 Gains (Losses) on Asset Dispositions,      Net 26 20 (7) (23) 16 (1) — (18) (19) Other, Net 26 23 28 23 100 19 16 17 52 Total 6,123 6,025 5,965 5,585 23,698 5,669 5,478 5,847 16,994 Operating Expenses Lease and Well 396 390 392 394 1,572 401 396 431 1,228 Gathering, Processing and      Transportation Costs 413 423 445 441 1,722 440 455 587 1,482 Exploration Costs 45 34 43 52 174 41 74 71 186 Dry Hole Costs 1 5 — 8 14 34 11 — 45 Impairments 19 81 15 276 391 44 39 71 154 Marketing Costs 1,404 1,490 1,500 1,323 5,717 1,325 1,216 1,134 3,675 Depreciation, Depletion and      Amortization 1,074 984 1,031 1,019 4,108 1,013 1,053 1,169 3,235 General and Administrative 162 151 167 189 669 171 186 239 596 Taxes Other Than Income 338 337 283 291 1,249 341 301 309 951 Total 3,852 3,895 3,876 3,993 15,616 3,810 3,731 4,011 11,552 Operating Income 2,271 2,130 2,089 1,592 8,082 1,859 1,747 1,836 5,442 Other Income, Net 62 66 76 70 274 65 55 59 179 Income Before Interest Expense and      Income Taxes 2,333 2,196 2,165 1,662 8,356 1,924 1,802 1,895 5,621 Interest Expense, Net 33 36 31 38 138 47 51 71 169 Income Before Income Taxes 2,300 2,160 2,134 1,624 8,218 1,877 1,751 1,824 5,452 Income Tax Provision 511 470 461 373 1,815 414 406 353 1,173 Net Income 1,789 1,690 1,673 1,251 6,403 1,463 1,345 1,471 4,279 Dividends Declared per Common Share 0.9100 0.9100 0.9100 0.9750 3.7050 0.9750 1.9950 — 2.9700 Net Income Per Share Basic 3.11 2.97 2.97 2.25 11.31 2.66 2.48 2.72 7.85 Diluted 3.10 2.95 2.95 2.23 11.25 2.65 2.46 2.70 7.81 Average Number of Common Shares Basic 575 569 564 557 566 550 543 541 545 Diluted 577 572 568 561 569 553 546 544 548 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 486.8 490.1 491.8 493.5 490.6 500.9 503.1 532.9 512.4 Trinidad 0.6 0.6 1.2 1.1 0.8 1.2 1.1 1.6 1.3 Total 487.4 490.7 493.0 494.6 491.4 502.1 504.2 534.5 513.7 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 $   67.83 Trinidad 67.50 70.75 63.15 60.47 64.43 61.12 54.50 57.74 57.80 Composite 78.45 82.69 76.92 71.66 77.40 72.87 64.82 65.95 67.81 Natural Gas Liquids Volumes (MBbld) (A) United States 231.7 244.8 254.3 252.5 245.9 241.7 258.4 309.3 270.0 Total 231.7 244.8 254.3 252.5 245.9 241.7 258.4 309.3 270.0 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 $   23.20 Composite 24.32 23.11 22.42 23.85 23.40 26.29 22.70 21.25 23.20 Natural Gas Volumes (MMcfd) (A) United States 1,658 1,668 1,745 1,840 1,728 1,834 1,977 2,511 2,110 Trinidad 200 204 225 252 220 246 252 230 243 Other International (C) — — — — — — — 4 1 Total 1,858 1,872 1,970 2,092 1,948 2,080 2,229 2,745 2,354 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 Trinidad 3.54 3.48 3.68 3.86 3.65 3.78 3.65 3.80 3.74 Other International (C) — — — — — — — 3.27 3.27 Composite 2.26 1.78 2.05 2.57 2.17 3.41 2.96 2.80 3.03 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 1,134.1 Trinidad 34.1 34.5 38.6 43.0 37.6 42.1 43.2 39.8 41.7 Other International — — — — — — — 0.7 0.2 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 1,176.0 Total 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 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 Accounts Receivable, Net 2,688 2,657 2,545 2,650 2,621 2,504 2,680 Inventories 1,154 1,069 1,038 985 897 934 945 Assets from Price Risk Management Activities 110 4 — — — — 19 Other (A) 684 642 460 503 563 591 646 Total 9,928 9,803 10,165 11,230 10,680 9,245 7,820 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 Other Property, Plant and Equipment 5,768 6,078 6,314 6,418 6,510 6,616 6,772 Total Property, Plant and Equipment 79,124 80,693 82,201 83,509 84,942 86,755 95,073 Less:  Accumulated Depreciation, Depletion and Amortization (46,047) (47,049) (48,075) (49,297) (50,310) (51,394) (52,488) Total Property, Plant and Equipment, Net 33,077 33,644 34,126 34,212 34,632 35,361 42,585 Deferred Income Taxes 38 44 42 39 44 39 37 Other Assets 1,753 1,733 1,818 1,705 1,626 1,639 1,757 Total Assets 44,796 45,224 46,151 47,186 46,982 46,284 52,199 Current Liabilities Accounts Payable 2,389 2,436 2,290 2,464 2,353 2,266 2,944 Accrued Taxes Payable 786 600 855 1,007 668 348 392 Dividends Payable 523 516 513 539 534 1,081 550 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 Current Portion of Operating Lease Liabilities 318 303 338 315 318 360 433 Other 223 231 344 381 290 257 452 Total 4,273 4,628 4,406 5,354 5,719 5,175 4,815 Long-Term Debt 3,757 3,250 3,742 4,220 3,464 3,458 7,667 Other Liabilities 2,533 2,456 2,480 2,395 2,368 2,398 2,496 Deferred Income Taxes 5,597 5,731 5,949 5,866 5,915 6,015 6,936 Commitments and Contingencies Stockholders' Equity Common Stock, $0.01 Par 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 Accumulated Other Comprehensive Loss (8) (8) (9) (4) (4) (7) (5) Retained Earnings 23,897 25,071 26,231 26,941 27,869 28,131 29,603 Common 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 30,285 Total 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 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 4,279 Items Not Requiring (Providing) Cash Depreciation, Depletion and Amortization 1,074 984 1,031 1,019 4,108 1,013 1,053 1,169 3,235 Impairments 19 81 15 276 391 44 39 71 154 Stock-Based Compensation Expenses 45 45 58 51 199 50 53 53 156 Deferred Income Taxes 199 128 220 (80) 467 44 105 278 427 (Gains) Losses on Asset Dispositions, Net (26) (20) 7 23 (16) 1 — 18 19 Other, Net 9 3 2 3 17 11 11 2 24 Dry Hole Costs 1 5 — 8 14 34 11 — 45 Mark-to-Market Financial Commodity and Other      Derivative Contracts (Gains) Losses, Net (237) 47 (79) 65 (204) 191 (107) (116) (32) Net Cash Received from (Payments for)      Settlements of Financial Commodity      Derivative Contracts 55 79 61 19 214 (38) (24) 27 (35) Changes in Components of Working Capital and      Other Assets and Liabilities Accounts 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 (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 7 Changes in Components of Working Capital      Associated with Investing Activities (229) (127) 59 (85) (382) (41) (8) (159) (208) Net Cash Provided by Operating Activities 2,903 2,889 3,588 2,763 12,143 2,289 2,032 3,111 7,432 Investing Cash Flows Acquisition of Encino Acquisition Partners, LLC,      Net of Cash Acquired — — — — — — — (4,464) (4,464) Additions 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      Equipment (350) (313) (239) (117) (1,019) (102) (94) (171) (367) Proceeds from Sales of Assets 9 10 — 4 23 12 4 5 21 Changes in Components of Working Capital      Associated with Investing Activities 229 127 (59) 85 382 41 8 159 208 Net 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 Flows Long-Term Debt Borrowings — — — 985 985 — — 3,472 3,472 Long-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      Employee Stock Purchase Plan — 11 — 11 22 — 11 — 11 Debt 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 7,092 Cash and Cash Equivalents at End of Period 5,292 5,431 6,122 7,092 7,092 6,599 5,216 3,530 3,530 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 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 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 associatedwith 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. 3Q 2025 Before Tax Income Tax Impact After Tax Diluted 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). Adjusted Net Income (Continued) In millions of USD, except share data (in millions) and per share data (Unaudited) 2Q 2025 Before Tax Income Tax Impact After Tax DilutedEarnings 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 Tax Income TaxImpact After Tax Diluted 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. Adjusted Net Income (Continued) In millions of USD, except share data (in millions) and per share data (Unaudited) 4Q 2024 Before Tax Income TaxImpact After Tax Diluted Earningsper 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 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. Adjusted Net Income (Continued) In millions of USD, except share data (in millions) and per share data (Unaudited) 3Q 2024 Before Tax Income Tax Impact After Tax DilutedEarningsper Share Reported Net Income (GAAP) 2,134 (461) 1,673 2.95 Adjustments: Gains on Mark-to-Market Financial Commodity and Other Derivative      Contracts, Net (79) 17 (62) (0.11) Net Cash Received from Settlements of Financial Commodity Derivative      Contracts (1) 61 (13) 48 0.08 Add: Losses on Asset Dispositions, Net 7 (2) 5 0.01 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 (37) 8 (29) (0.06) Adjusted Net Income (Non-GAAP) 2,097 (453) 1,644 2.89 Average Number of Common Shares Basic 564 Diluted 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 Tax Income TaxImpact After Tax DilutedEarnings 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 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. Adjusted Net Income (Continued) In millions of USD, except share data (in millions) and per share data (Unaudited) FY 2023 Before Tax Income Tax Impact After Tax DilutedEarnings perShare Reported Net Income (GAAP) 9,689 (2,095) 7,594 13.00 Adjustments: Gains on Mark-to-Market Financial Commodity Derivative      Contracts, Net (818) 176 (642) (1.09) Net Cash Payments for Settlements of Financial Commodity      Derivative Contracts (1) (112) 24 (88) (0.15) Less: Gains on Asset Dispositions, Net (95) 20 (75) (0.13) Add: Certain Impairments 42 (6) 36 0.06 Adjustments to Net Income (983) 214 (769) (1.31) Adjusted Net Income (Non-GAAP) 8,706 (1,881) 6,825 11.69 Average Number of Common Shares Basic 581 Diluted 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 Share In 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 2.46 Realized Prices 3Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and      Natural Gas per Boe 38.05 Less:  2Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and      Natural Gas per Boe (39.80) Subtotal (1.75) Multiplied by: 3Q 2025 Crude Oil Equivalent Volumes (MMBoe) 119.7 Total Change in Revenue (209) Add: Income Tax Benefit (Provision) Imputed (based on 22%) 46 Change in Net Income (163) Change in Diluted Earnings per Share (0.30) Volumes 3Q 2025 Crude Oil Equivalent Volumes (MMBoe) 119.7 Less:  2Q 2025 Crude Oil Equivalent Volumes (MMBoe) (103.2) Subtotal 16.5 Multiplied by:  3Q 2025 Composite Average Margin per Boe (GAAP) (Including Total     Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent"      schedule below) 13.42 Change in Margin 221 Less:  Income Tax Benefit (Provision) Imputed (based on 22%) (49) Change in Net Income 172 Change in Diluted Earnings per Share 0.32 Certain Operating Costs per Boe 2Q 2025 Total Cash Operating Costs (GAAP) and Total DD&A per Boe 20.25 Less:  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) 119.7 Change in Before-Tax Net Income (2) Add:  Income Tax Benefit (Provision) Imputed (based on 22%) 1 Change in Net Income (1) Change in Diluted Earnings per Share 0.00 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) Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net 3Q 2025 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative      Contracts 116 Less:  Income Tax Benefit (Provision) (25) After Tax - (a) 91 Less: 2Q 2025 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts 107 Less:  Income Tax Benefit (Provision) (23) After Tax - (b) 84 Change in Net Income - (a) - (b) 7 Change in Diluted Earnings per Share 0.01 Other (1) 0.21 3Q 2025 Net Income per Share (GAAP) - Diluted 2.70 3Q 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 Share In 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 2.32 Realized Prices 3Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and      Natural Gas per Boe 38.05 Less:  2Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and      Natural Gas per Boe (39.80) Subtotal (1.75) Multiplied by: 3Q 2025 Crude Oil Equivalent Volumes (MMBoe) 119.7 Total Change in Revenue (209) Add: Income Tax Benefit (Provision) Imputed (based on 22%) 46 Change in Net Income (163) Change in Diluted Earnings per Share (0.30) Volumes 3Q 2025 Crude Oil Equivalent Volumes (MMBoe) 119.7 Less:  2Q 2025 Crude Oil Equivalent Volumes (MMBoe) (103.2) Subtotal 16.5 Multiplied by:  3Q 2025 Composite Average Margin per Boe (Non-GAAP) (Including Total      Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent"      schedule below) 13.99 Change in Margin 231 Less:  Income Tax Benefit (Provision) Imputed (based on 22%) (51) Change in Net Income 180 Change in Diluted Earnings per Share 0.33 Certain Operating Costs per Boe 2Q 2025 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe 20.14 Less:  3Q 2025 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe (19.70) Subtotal 0.44 Multiplied by:  3Q 2025 Crude Oil Equivalent Volumes (MMBoe) 119.7 Change in Before-Tax Net Income 53 Add:  Income Tax Benefit (Provision) Imputed (based on 22%) (12) Change in Net Income 41 Change in Diluted Earnings per Share 0.08 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) Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts 3Q 2025 Net Cash Received from (Payments for)  Settlements of Financial Commodity Derivative      Contracts 27 Less:  Income Tax Benefit (Provision) (5) After Tax - (a) 22 Less: 2Q 2025 Net Cash Received from (Payments for) Settlements of Financial Commodity      Derivative Contracts (24) Less:  Income Tax Benefit (Provision) 5 After Tax - (b) (19) Change in Net Income - (a) - (b) 41 Change in Diluted Earnings per Share 0.08 Other (1) 0.20 3Q 2025 Adjusted Net Income per Share (Non-GAAP) 2.71 3Q 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 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 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-related costs 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 presentation below 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 Year Net Cash Provided by Operating Activities (GAAP) 2,903 2,889 3,588 2,763 12,143 2,289 2,032 3,111 7,432 Adjustments: Changes in Components of Working Capital      and Other Assets and Liabilities Accounts 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) 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) (7) Changes in Components of Working Capital      Associated with Investing Activities 229 127 (59) 85 382 41 8 159 208 Add: Acquisition-Related Costs (1), Net of Tax — — — — — — 10 58 68 Adjusted Cash Flow from Operations (Non-     GAAP) 2,928 3,042 2,988 2,635 11,593 2,813 2,496 3,031 8,340 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 and three 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 Year Total Expenditures (GAAP) 1,952 1,682 1,573 1,446 6,653 1,546 1,883 8,544 11,973 Less: 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,      Plant and Equipment (131) (1) (5) — (137) — — — — Exploration 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 4,655 Cash Flow from Operations and Free Cash Flow (Continued)    In millions of USD (Unaudited) FY 2023 FY 2022 Net Cash Provided by Operating Activities (GAAP) 11,340 11,093 Adjustments: Changes in Components of Working Capital and Other Assets and Liabilities Accounts Receivable 38 347 Inventories 231 534 Accounts Payable 119 (90) Accrued Taxes Payable (61) 113 Other Assets (39) 364 Other Liabilities (184) 266 Changes in Components of Working Capital Associated with Investing Activities (295) (375) Adjusted Cash Flow from Operations (Non-GAAP) 11,149 12,252 Less: 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 5,610 Less: 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 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 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-Total Capitalization ratio calculation.  EOG management uses this information for comparative purposes within the industry. September 30, 2025 June 30, 2025 March 31, 2025 December 31,2024 September 30, 2024 Total Stockholders' Equity - (a) 30,285 29,238 29,516 29,351 29,574 Current and Long-Term Debt (GAAP) - (b) 7,694 4,236 4,744 4,752 3,776 Less: 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 33,350 Total Capitalization (Non-GAAP) - (a) + (c) 34,449 28,258 27,661 27,011 27,228 Debt-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) /      [(a) + (c)] 12.1 % -3.5 % -6.7 % -8.7 % -8.6 % 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 groupsof 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 thefinancial performance of other companies in the industry. 3Q 2025 2Q 2025 1Q 2025 4Q 2024 3Q 2024 Volume - Million Barrels of Oil Equivalent - (a) 119.7 103.2 98.1 100.8 99.0 Total Operating Revenues and Other - (b) 5,847 5,478 5,669 5,585 5,965 Total Operating Expenses - (c) 4,011 3,731 3,810 3,993 3,876 Operating Income - (d) 1,836 1,747 1,859 1,592 2,089 Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas Crude Oil and Condensate 3,243 2,974 3,293 3,261 3,488 Natural Gas Liquids 604 534 572 554 524 Natural Gas 707 600 637 494 372 Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural      Gas  - (e) 4,554 4,108 4,502 4,309 4,384 Operating Costs Lease and Well 431 396 401 394 392 Gathering, Processing and Transportation Costs (1) 587 455 440 441 445 General and Administrative (GAAP) 239 186 171 189 167 Less:  Certain Items (see Endnotes 2 & 3 to 3Q 2025 earnings release) (68) (12) — — (10) General and Administrative (Non-GAAP) (2) 171 174 171 189 157 Taxes Other Than Income (GAAP) 309 301 341 291 283 Add:  Severance Tax Refund — — — — 31 Taxes Other Than Income (Non-GAAP) (3) 309 301 341 291 314 Interest Expense, Net 71 51 47 38 31 Less:  Acquisition-Related Financing Commitment Costs — (6) — — — Interest Expense, Net  (Non-GAAP) (4) 71 45 47 38 31 Total Operating Cost (GAAP)  (excluding DD&A and Total Exploration Costs)      - (f) 1,637 1,389 1,400 1,353 1,318 Total Operating Cost (Non-GAAP)  (excluding DD&A and Total Exploration      Costs) - (g) 1,569 1,371 1,400 1,353 1,339 Depreciation, Depletion and Amortization (DD&A) 1,169 1,053 1,013 1,019 1,031 Total Operating Cost (GAAP) (excluding Total Exploration Costs) - (h) 2,806 2,442 2,413 2,372 2,349 Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (i) 2,738 2,424 2,413 2,372 2,370 Exploration Costs 71 74 41 52 43 Dry Hole Costs — 11 34 8 — Impairments 71 39 44 276 15 Total Exploration Costs (GAAP) 142 124 119 336 58 Less:  Certain Impairments (5) — (11) — (254) — Total Exploration Costs (Non-GAAP) 142 113 119 82 58 Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) - (j) 2,948 2,566 2,532 2,708 2,407 Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-     GAAP)) - (k) 2,880 2,537 2,532 2,454 2,428 Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural      Gas less Total Operating Cost (GAAP) (including Total Exploration Costs      (GAAP)) 1,606 1,542 1,970 1,601 1,977 Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural      Gas less Total Operating Cost (Non-GAAP) (including Total Exploration      Costs (Non-GAAP)) 1,674 1,571 1,970 1,855 1,956 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 2024 Per 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 60.25 Composite Average Operating Expenses per Boe - (c) / (a) 33.51 36.15 38.84 39.62 39.15 Composite Average Operating Income per Boe  - (d) / (a) 15.34 16.93 18.95 15.79 21.10 Composite Average Revenue from Sales of Crude Oil and Condensate,     NGLs, and Natural Gas per Boe - (e) / (a) 38.05 39.80 45.88 42.74 44.31 Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) -      (f) / (a) 13.67 13.46 14.26 13.42 13.32 Composite Average Margin per Boe (excluding DD&A and Total Exploration      Costs) - [(e) / (a) - (f) / (a)] 24.38 26.34 31.62 29.32 30.99 Total Operating Cost per Boe (excluding Total Exploration Costs) - (h) / (a) 23.44 23.66 24.58 23.53 23.74 Composite Average Margin per Boe (excluding Total Exploration Costs) -      [(e) / (a) - (h) / (a)] 14.61 16.14 21.30 19.21 20.57 Total Operating Cost per Boe (including Total Exploration Costs) - (j) / (a) 24.63 24.86 25.79 26.86 24.33 Composite Average Margin per Boe (including Total Exploration Costs) -      [(e) / (a) - (j) / (a)] 13.42 14.94 20.09 15.88 19.98 Per Barrel of Oil Equivalent (Boe) Calculations (Non-GAAP) Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) -      (g) / (a) 13.10 13.30 14.26 13.42 13.53 Composite Average Margin per Boe (excluding DD&A and Total Exploration      Costs) - [(e) / (a) - (g) / (a)] 24.95 26.50 31.62 29.32 30.78 Total Operating Cost per Boe (excluding Total Exploration Costs) - (i) / (a) 22.87 23.50 24.58 23.53 23.95 Composite Average Margin per Boe (excluding Total Exploration Costs) -      [(e) / (a) - (i) / (a)] 15.18 16.30 21.30 19.21 20.36 Total Operating Cost per Boe (including Total Exploration Costs) - (k) / (a) 24.06 24.59 25.79 24.34 24.54 Composite Average Margin per Boe (including Total Exploration Costs) -      [(e) / (a) - (k) / (a)] 13.99 15.21 20.09 18.40 19.77 Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued) In millions of USD, except Boe and per Boe amounts (Unaudited) 2024 2023 2022 Volume - Million Barrels of Oil Equivalent - (a) 388.7 359.4 331.5 Total Operating Revenues and Other - (b) 23,698 24,186 25,702 Total Operating Expenses - (c) 15,616 14,583 15,736 Operating Income (Loss) - (d) 8,082 9,603 9,966 Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas Crude Oil and Condensate 13,921 13,748 16,367 Natural Gas Liquids 2,106 1,884 2,648 Natural Gas 1,551 1,744 3,781 Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural      Gas - (e) 17,578 17,376 22,796 Operating Costs Lease and Well 1,572 1,454 1,331 Gathering, Processing and Transportation Costs (1) 1,722 1,620 1,587 General and Administrative (GAAP) 669 640 570 Less:  Severance Tax Consulting Fees (10) — (16) General and Administrative (Non-GAAP) (2) 659 640 554 Taxes Other Than Income (GAAP) 1,249 1,284 1,585 Add:  Severance Tax Refund 31 — 115 Taxes Other Than Income (Non-GAAP) (3) 1,280 1,284 1,700 Interest Expense, Net 138 148 179 Total Operating Cost (GAAP) (excluding DD&A and Total Exploration Costs) -      (f) 5,350 5,146 5,252 Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration      Costs) - (g) 5,371 5,146 5,351 Depreciation, Depletion and Amortization (DD&A) 4,108 3,492 3,542 Total Operating Cost (GAAP) (excluding Total Exploration Costs) - (h) 9,458 8,638 8,794 Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (i) 9,479 8,638 8,893 Exploration Costs 174 181 159 Dry Hole Costs 14 1 45 Impairments 391 202 382 Total Exploration Costs (GAAP) 579 384 586 Less:  Certain Impairments (5) (291) (42) (113) Total Exploration Costs (Non-GAAP) 288 342 473 Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) - (j) 10,037 9,022 9,380 Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-     GAAP)) - (k) 9,767 8,980 9,366 Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural      Gas less Total Operating Cost (GAAP) (including Total  Exploration Costs      (GAAP)) 7,541 8,354 13,416 Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural      Gas less Total Operating Cost (Non-GAAP) (including Total Exploration      Costs (Non-GAAP)) 7,811 8,396 13,430 Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued) In millions of USD, except Boe and per Boe amounts (Unaudited) 2024 2023 2022 Per Barrel of Oil Equivalent (Boe) Calculations (GAAP) Composite Average Operating Revenues and Other per Boe - (b) / (a) 60.97 67.30 77.53 Composite Average Operating Expenses per Boe - (c) / (a) 40.18 40.58 47.47 Composite Average Operating Income (Loss) per Boe - (d) / (a) 20.79 26.72 30.06 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs,      and Natural Gas per Boe - (e) / (a) 45.22 48.34 68.77 Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) -  (f) / (a) 13.76 14.31 15.84 Composite Average Margin per Boe (excluding DD&A and Total Exploration      Costs) - [(e) / (a) - (f) / (a)] 31.46 34.03 52.93 Total Operating Cost per Boe (excluding Total Exploration Costs) - (h) / (a) 24.33 24.03 26.53 Composite Average Margin per Boe (excluding Total Exploration Costs) -      [(e) / (a) - (h) / (a)] 20.89 24.31 42.24 Total Operating Cost per Boe (including Total Exploration Costs) - (j) / (a) 25.82 25.10 28.30 Composite Average Margin per Boe (including Total Exploration Costs) - [(e) /      (a) - (j) / (a)] 19.40 23.24 40.47 Per Barrel of Oil Equivalent (Boe) Calculations (Non-GAAP) Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) -        (g) / (a) 13.82 14.31 16.14 Composite Average Margin per Boe (excluding DD&A and Total Exploration      Costs) - [(e) / (a) - (g) / (a)] 31.40 34.03 52.63 Total Operating Cost per Boe (excluding Total Exploration Costs) - (i) / (a) 24.39 24.03 26.83 Composite Average Margin per Boe (excluding Total Exploration Costs) -      [(e) / (a) - (i) / (a)] 20.83 24.31 41.94 Total Operating Cost per Boe (including Total Exploration Costs) - (k) / (a) 25.13 24.98 28.26 Composite Average Margin per Boe (including Total Exploration Costs) - [(e) /      (a) - (k) / (a)] 20.09 23.36 40.51 (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 Actual Crude Oil and Condensate Volumes (MBod) United States 490.6 475.2 460.7 Trinidad 0.8 0.6 0.6 Total 491.4 475.8 461.3 Natural Gas Liquids Volumes (MBbld) Total 245.9 223.8 197.7 Natural Gas Volumes (MMcfd) United States 1,728 1,551 1,315 Trinidad 220 160 180 Total 1,948 1,711 1,495 Crude Oil Equivalent Volumes (MBoed) United States 1,024.5 957.5 877.5 Trinidad 37.6 27.3 30.7 Total 1,062.1 984.8 908.2 Benchmark Price Oil (WTI) ($/Bbl) 75.72 77.61 94.23 Natural Gas (HH) ($/Mcf) 2.27 2.74 6.64 Crude Oil and Condensate - above (below) WTI1 ($/Bbl) United States 1.70 1.57 2.99 Trinidad (11.29) (9.03) (8.07) Natural Gas Liquids - Realizations as % of WTI Total 30.9 % 29.7 % 39.0 % Natural Gas - above (below) NYMEX Henry Hub2 ($/Mcf) United States (0.28) (0.04) 0.63 Natural Gas Realizations3 ($/Mcf) Trinidad 3.65 3.65 4.43 Total Expenditures (GAAP) ($MM) 6,653 6,818 5,610 Capital Expenditures4 (non-GAAP) ($MM) 6,226 6,041 4,607 Operating Unit Costs ($/Boe) Lease and Well 4.04 4.05 4.02 Gathering, Processing and Transportation Costs5 4.43 4.50 4.78 General and Administrative (GAAP) 1.72 1.78 1.72 General and Administrative (non-GAAP)6 1.70 1.78 1.67 Cash Operating Costs (GAAP) 10.19 10.33 10.52 Cash Operating Costs (non-GAAP)6 10.17 10.33 10.47 Depreciation, Depletion and Amortization 10.57 9.72 10.69 Expenses ($MM) Exploration and Dry Hole 188 182 204 Impairment (GAAP) 391 202 382 Impairment (excluding certain impairments (non-GAAP))7 100 160 269 Capitalized Interest 45 33 36 Net Interest 138 148 179 TOTI (% 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 Taxes Effective Rate 22.1 % 21.6 % 21.7 % Current Tax Expense ($MM) 1,348 1,415 2,208 Additional Key Information (Continued) Endnotes 1) 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). SOURCE EOG Resources, Inc.

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