HOUSTON, Nov. 5, 2026 /PRNewswire/ -- EOG Resources, Inc. (EOG) today reported third quarter 2026 results. The attached schedules for the reconciliation of non-GAAP measures to GAAP measures, along with a related presentation, are also available on EOG's website at http://investors.eogresources.com/investors.
Third Quarter Highlights
- Net income of $2.8 billion, or $5.33 per share, and adjusted net income of $2.5 billion, or $4.87 per share
- Net cash provided by operating activities of $3.8 billion and adjusted CFO1 of $3.8 billion
- Generated $2.2 billion of free cash flow
- Paid $544 million in regular dividends and repurchased $1.0 billion of shares
- Record oil, NGL, and natural gas volumes, all better than guidance midpoints
- Total per-unit cash operating costs and DD&A better than guidance midpoints
- Increased regular quarterly dividend by 8 percent to $1.10 per share, a $4.40 per share indicated annual rate
- Entered new long-term gas sales agreement linked to JKM pricing starting by 2030
CEO Commentary
"EOG delivered an outstanding third quarter, achieving record oil, NGL, and natural gas production while maintaining cost discipline as total per-unit cash operating costs and DD&A came in below guidance midpoints. Combined with strong price realizations, these results translated into robust financial performance.
Our focus remains on strengthening our business for the long term, and two recent developments illustrate this commitment. First, we signed a new long-term gas sales agreement expanding our access to premium markets. Linked to JKM pricing, this agreement lifts our premium-priced exposure across LNG feedgas contracts to more than 1 billion cubic feet per day by 2030. Second, we approved the expansion of our Janus gas processing plant in the Delaware Basin. The expansion will provide incremental processing capacity supporting strong netbacks, returns, and long-term value creation.
EOG's business and the outlook for the company have never been stronger. We are pleased to announce an 8% increase in our regular dividend. The increase reflects both the confidence in our business and our ability to support the higher dividend through commodity price cycles. EOG has paid a regular dividend for 28 straight years, a track record that reflects our enduring commitment to returning cash to shareholders.
Underpinning our consistent success is the EOG culture, our core competitive advantage, which empowers our employees to innovate and operate at a high level, supporting efficient operations and high-return investments. We are performing exceptionally well in 2026 and look to finish the year strong and carry significant momentum into 2027."
Return of Capital
The Board of Directors today declared a regular dividend of $1.10 per share on EOG's common stock. The regular dividend will be payable January 29, 2027, to stockholders of record as of January 15, 2027. The indicated annual rate is $4.40 per share.
During the third quarter, the company repurchased 7.0 million shares for $1.0 billion under its share repurchase authorization, at an average purchase price of $143 per share. As of September 30, 2026, EOG had $10.6 billion remaining on its current repurchase authorization.
Key Financial Results | |||||
In millions of USD, except per-share, per-Boe and ratio data | |||||
GAAP | 3Q 2026 | 2Q 2026 | 1Q 2026 | 4Q 2025 | 3Q 2025 |
Total Revenue | 8,549 | 8,620 | 6,921 | 5,638 | 5,847 |
Net Income | 2,781 | 2,724 | 1,980 | 701 | 1,471 |
Net Income Per Share | 5.33 | 5.15 | 3.70 | 1.30 | 2.70 |
Net Cash Provided by Operating Activities | 3,813 | 4,669 | 2,966 | 2,612 | 3,111 |
Total Expenditures | 1,871 | 1,919 | 1,768 | 1,730 | 8,544 |
Current and Long-Term Debt | 7,922 | 7,926 | 7,931 | 7,936 | 7,694 |
Cash and Cash Equivalents | 5,747 | 4,907 | 3,849 | 3,396 | 3,530 |
Debt-to-Total Capitalization | 19.3 % | 19.9 % | 20.4 % | 21.0 % | 20.3 % |
Cash Operating Costs ($/Boe) | 10.49 | 10.57 | 10.45 | 10.28 | 10.50 |
Non–GAAP | |||||
Adjusted Net Income | 2,540 | 2,683 | 1,825 | 1,222 | 1,472 |
Adjusted Net Income Per Share | 4.87 | 5.07 | 3.41 | 2.27 | 2.71 |
Adjusted CFO1 | 3,773 | 4,386 | 3,129 | 2,617 | 3,031 |
Capital Expenditures | 1,597 | 1,587 | 1,636 | 1,639 | 1,648 |
Free Cash Flow | 2,176 | 2,799 | 1,493 | 978 | 1,383 |
Net Debt | 2,175 | 3,019 | 4,082 | 4,540 | 4,164 |
Net Debt-to-Total Capitalization | 6.2 % | 8.7 % | 11.7 % | 13.2 % | 12.1 % |
Cash Operating Costs ($/Boe)2 | 10.49 | 10.57 | 10.45 | 10.22 | 9.93 |
Key Operational Results | |||||
Volumes | 3Q 2026 | 2Q 2026 | 1Q 2026 | 4Q 2025 | 3Q 2025 |
Crude Oil and Condensate (MBod) | 550.4 | 548.8 | 548.5 | 546.1 | 534.5 |
Natural Gas Liquids (MBbld) | 357.1 | 346.8 | 332.1 | 342.1 | 309.3 |
Natural Gas (MMcfd) | 3,153 | 3,089 | 3,020 | 3,065 | 2,745 |
Total Crude Oil Equivalent (MBoed) | 1,433.1 | 1,410.4 | 1,383.8 | 1,399.0 | 1,301.2 |
Cash Operating Costs ($/Boe) | |||||
Lease & Well | 3.74 | 3.64 | 3.71 | 3.47 | 3.60 |
Gathering, Processing & Transportation Costs | 5.26 | 5.27 | 5.25 | 5.07 | 4.90 |
General & Administrative (GAAP) | 1.49 | 1.66 | 1.49 | 1.74 | 2.00 |
General & Administrative (Non-GAAP)2 | 1.49 | 1.66 | 1.49 | 1.68 | 1.43 |
Cash Operating Costs (GAAP) | 10.49 | 10.57 | 10.45 | 10.28 | 10.50 |
Cash Operating Costs (Non-GAAP)2 | 10.49 | 10.57 | 10.45 | 10.22 | 9.93 |
Depreciation, Depletion & Amortization ($/Boe) | 9.80 | 9.81 | 9.58 | 9.53 | 9.77 |
Third Quarter 2026 Results vs Guidance | |||||||
(Unaudited) |
3Q 2026 | 3Q 2026 |
Variance |
2Q 2026 |
1Q 2026 |
4Q 2025 |
3Q 2025 |
Crude Oil and Condensate Volumes (MBod) | |||||||
United States | 547.7 | 546.8 | 0.9 | 546.2 | 546.5 | 544.5 | 532.9 |
Trinidad | 2.0 | 1.7 | 0.3 | 2.1 | 1.9 | 1.5 | 1.6 |
Other International5 | 0.7 | 0.5 | 0.1 | 0.1 | 0.0 | ||
Total | 550.4 | 548.5 | 1.9 | 548.8 | 548.5 | 546.1 | 534.5 |
Natural Gas Liquids Volumes (MBbld) | |||||||
Total | 357.1 | 347.0 | 10.1 | 346.8 | 332.1 | 342.1 | 309.3 |
Natural Gas Volumes (MMcfd) | |||||||
United States | 2,882 | 2,850 | 32 | 2,784 | 2,769 | 2,859 | 2,511 |
Trinidad | 260 | 250 | 10 | 293 | 239 | 195 | 230 |
Other International5 | 11 | 12 | 12 | 11 | 4 | ||
Total | 3,153 | 3,100 | 53 | 3,089 | 3,020 | 3,065 | 2,745 |
Total Crude Oil Equivalent Volumes (MBoed) | 1,433.1 | 1,412.2 | 20.9 | 1,410.4 | 1,383.8 | 1,399.0 | 1,301.2 |
Total MMBoe | 131.8 | 129.9 | 1.9 | 128.3 | 124.5 | 128.7 | 119.7 |
Benchmark Price | |||||||
Oil (WTI) ($/Bbl) | 85.68 | 92.85 | 72.17 | 59.17 | 64.95 | ||
Natural Gas (HH) ($/Mcf) | 2.95 | 2.89 | 4.96 | 3.55 | 3.07 | ||
Crude Oil and Condensate - above (below) WTI6 ($/Bbl) | |||||||
United States | 1.05 | 1.65 | (0.60) | 5.33 | 0.31 | 0.37 | 1.02 |
Trinidad | (1.06) | (2.60) | 1.54 | (3.98) | (3.26) | (2.10) | (7.21) |
Other International | 2.28 | 10.55 | 16.95 | 4.81 | 0.00 | ||
Natural Gas Liquids - Realizations as % of WTI | |||||||
Total | 30.5 % | 28.0 % | 2.5 % | 26.3 % | 30.8 % | 35.7 % | 32.7 % |
Natural Gas - above (below) NYMEX Henry Hub7 ($/Mcf) | |||||||
United States | 0.78 | 0.50 | 0.28 | (0.12) | (1.21) | (0.61) | (0.36) |
Natural Gas Realizations ($/Mcf) | |||||||
Trinidad | 3.92 | 3.80 | 0.12 | 3.99 | 3.91 | 3.94 | 3.80 |
Other International5 | 3.30 | 3.27 | 3.26 | 3.29 | 3.27 | ||
Total Expenditures (GAAP) ($MM) | 1,871 | 1,919 | 1,768 | 1,730 | 8,544 | ||
Capital Expenditures (Non-GAAP) ($MM) | 1,597 | 1,650 | (53) | 1,587 | 1,636 | 1,639 | 1,648 |
Operating Unit Costs ($/Boe) | |||||||
Lease and Well | 3.74 | 3.80 | (0.06) | 3.64 | 3.71 | 3.47 | 3.60 |
Gathering, Processing and Transportation Costs | 5.26 | 5.40 | (0.14) | 5.27 | 5.25 | 5.07 | 4.90 |
General & Administrative (GAAP) | 1.49 | 1.66 | 1.49 | 1.74 | 2.00 | ||
General & Administrative (Non-GAAP)2 | 1.49 | 1.50 | (0.01) | 1.66 | 1.49 | 1.68 | 1.43 |
Cash Operating Costs (GAAP) | 10.49 | 10.57 | 10.45 | 10.28 | 10.50 | ||
Cash Operating Costs (Non-GAAP)2 | 10.49 | 10.70 | (0.21) | 10.57 | 10.45 | 10.22 | 9.93 |
Depreciation, Depletion and Amortization | 9.80 | 10.00 | (0.20) | 9.81 | 9.58 | 9.53 | 9.77 |
Expenses ($MM) | |||||||
Exploration and Dry Hole | 83 | 65 | 18 | 77 | 68 | 54 | 71 |
Impairment (GAAP) | 24 | 19 | 39 | 689 | 71 | ||
Impairment (excluding certain impairments (Non-GAAP))8 | 24 | 110 | (86) | 19 | 39 | 43 | 71 |
Capitalized Interest | 38 | 38 | 38 | 37 | 36 | 27 | |
Net Interest (GAAP) | 67 | 67 | 66 | 66 | 71 | ||
Net Interest (Non-GAAP) | 67 | 66 | 1 | 67 | 66 | 66 | 71 |
TOTI (% of revenues from sales of crude oil and | |||||||
(GAAP) | 6.3 % | 6.6 % | 6.4 % | 6.3 % | 6.8 % | ||
(Non-GAAP) | 6.3 % | 6.8 % | (0.5 %) | 6.6 % | 6.4 % | 6.3 % | 6.8 % |
Income Taxes | |||||||
Effective Rate | 22.0 % | 22.5 % | (0.5 %) | 22.1 % | 22.5 % | 22.8 % | 19.4 % |
Current Tax Expense ($MM) | 889 | 885 | 4 | 429 | 557 | 293 | 75 |
Fourth Quarter and Full-Year 2026 Guidance9 | ||||||||
(Unaudited) | 4Q 2026 | 4Q 2026 | FY 2026 | FY 2026 | ||||
Crude Oil and Condensate Volumes (MBod) | ||||||||
United States | 545.4 | - | 550.0 | 547.7 | 545.1 | - | 548.9 | 547.0 |
Trinidad | 1.8 | - | 2.2 | 2.0 | 1.8 | - | 2.2 | 2.0 |
Other International | 0.5 | - | 0.9 | 0.7 | 0.4 | - | 0.6 | 0.5 |
Total | 547.7 | - | 553.1 | 550.4 | 547.3 | - | 551.7 | 549.5 |
Natural Gas Liquids Volumes (MBbld) | ||||||||
Total | 340.0 | - | 360.0 | 350.0 | 341.6 | - | 351.6 | 346.6 |
Natural Gas Volumes (MMcfd) | ||||||||
United States | 2,780 | - | 2,880 | 2,830 | 2,777 | - | 2,857 | 2,817 |
Trinidad | 200 | - | 220 | 210 | 240 | - | 260 | 250 |
Other International | 7 | - | 13 | 10 | 9 | - | 13 | 11 |
Total | 2,987 | - | 3,113 | 3,050 | 3,026 | - | 3,130 | 3,078 |
Crude Oil Equivalent Volumes (MBoed) | ||||||||
United States | 1,348.7 | - | 1,390.0 | 1,369.4 | 1,349.5 | - | 1,376.7 | 1,363.1 |
Trinidad | 35.1 | - | 38.9 | 37.0 | 41.8 | - | 45.5 | 43.7 |
Other International | 1.7 | - | 3.1 | 2.4 | 1.9 | - | 2.8 | 2.4 |
Total | 1,385.5 | - | 1,432.0 | 1,408.8 | 1,393.2 | - | 1,425.0 | 1,409.2 |
Crude Oil and Condensate - above (below) WTI6 ($/Bbl) | ||||||||
United States | 2.25 | - | 3.75 | 3.00 | 1.90 | - | 2.90 | 2.40 |
Trinidad | 1.25 | - | 2.75 | 2.00 | (2.20) | - | (0.70) | (1.45) |
Natural Gas Liquids - Realizations as % of WTI | ||||||||
Total | 30.0 % | - | 40.0 % | 35.0 % | 28.0 % | - | 33.0 % | 30.5 % |
Natural Gas - above (below) NYMEX Henry Hub7 ($/Mcf) | ||||||||
United States | 1.10 | - | 1.80 | 1.45 | (0.30) | - | 0.70 | 0.20 |
Natural Gas Realizations ($/Mcf) | ||||||||
Trinidad | 3.30 | - | 4.00 | 3.65 | 3.60 | - | 4.10 | 3.85 |
Capital Expenditures10 ($MM) | 1,630 | - | 1,730 | 1,680 | 6,300 | - | 6,700 | 6,500 |
Operating Unit Costs ($/Boe) | ||||||||
Lease and Well | 3.70 | - | 4.20 | 3.95 | 3.60 | - | 3.90 | 3.75 |
Gathering, Processing and Transportation Costs | 5.25 | - | 5.75 | 5.50 | 5.25 | - | 5.45 | 5.35 |
General & Administrative | 1.45 | - | 1.75 | 1.60 | 1.45 | - | 1.65 | 1.55 |
Cash Operating Costs | 10.40 | - | 11.70 | 11.05 | 10.30 | - | 11.00 | 10.65 |
Depreciation, Depletion and Amortization | 9.80 | - | 10.80 | 10.30 | 9.50 | - | 10.30 | 9.90 |
Expenses ($MM) | ||||||||
Exploration and Dry Hole | 50 | - | 90 | 70 | 278 | - | 318 | 298 |
Impairment (excluding certain impairments)8 | 55 | - | 135 | 95 | 87 | - | 267 | 177 |
Capitalized Interest | 36 | - | 40 | 38 | 149 | - | 153 | 151 |
Net Interest | 65 | - | 69 | 67 | 266 | - | 270 | 268 |
TOTI (% of revenues from sales of crude oil and |
5.5 % |
- |
7.5 % |
6.5 % |
5.5 % |
- |
7.5 % |
6.5 % |
Income Taxes | ||||||||
Effective Rate | 18.0 % | - | 24.0 % | 21.0 % | 19.0 % | - | 25.0 % | 22.0 % |
Current Tax Expense ($MM) | 650 | - | 750 | 700 | 2,525 | - | 2,625 | 2,575 |
Third Quarter 2026 Results Webcast
Friday, November 6, 2026, 9:00 a.m. Central time (10:00 a.m. Eastern time) Webcast will be available on EOG's website for one year. https://investors.eogresources.com/Investors
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States and Trinidad. To learn more visit https://www.eogresources.com/
Investor Contacts
Pearce Hammond 713-571-4684
Neel Panchal 713-571-4884
Shelby O'Connor 713-571-4560
Cameron Hughes 713-571-3724
Media Contact
Kimberly Ehmer 713-571-4676
Endnotes | |
1) | Cash flow from operations before changes in working capital and certain acquisition-related costs. |
2) | Cash Operating Costs consist of LOE, GP&T and G&A. Non-GAAP G&A excludes Encino acquisition-related G&A costs of $8 million for 4Q 2025 and $68 million for 3Q 2025, as reflected in the accompanying reconciliation schedules (see "Revenues, Costs and Margins Per Barrel of Oil Equivalent"). The per-Boe impact of such Encino acquisition–related costs on G&A and total Cash Operating Costs for 4Q 2025 was ($0.06) and for 3Q 2025 was ($0.57) as set forth in "Third Quarter 2026 Results vs Guidance" above. |
3) | Other includes gathering, processing and marketing revenue, gains (losses) on asset dispositions (for GAAP earnings per share only), other revenue, exploration costs, dry hole costs, impairments, marketing costs, taxes other than income, other income (expense), interest expense, the impact of changes in the effective income tax rate and the impact of share repurchases on diluted shares. |
4) | GAAP and non-GAAP distinctions apply solely to actual results and do not pertain to EOG's third quarter 2026 guidance midpoint disclosures. |
5) | Crude oil and condensate volumes are from UAE and Bahrain operations. Natural gas volumes are from Bahrain operations; natural gas realized price represents contract price less partner's processing and distribution costs. |
6) | EOG bases United States, Trinidad, and Other International crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the daily settlement prices for the prompt-month NYMEX futures contract for each of the applicable calendar months. |
7) | EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the NYMEX Last Day Settle price for each of the applicable months. |
8) | In general, EOG excludes impairments which are (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG's oil and gas properties or other assets). EOG believes excluding these impairments from total impairment costs is appropriate and provides useful information to investors, as such impairments were caused by factors outside of EOG's control (versus, for example, impairments that are due to EOG's proved oil and gas properties not being as productive as it originally estimated). Impairments (Non-GAAP) for 4Q 2025 are adjusted from Impairments (GAAP) for 4Q 2025 by excluding $646 million of impairments, primarily associated with the write-down to fair value of natural gas and crude oil assets in the Barnett Shale and Woodford Oil Window (mainly driven by play-specific economics and resource allocation). |
9) | The forecast items for the fourth quarter and full year 2026 set forth above for EOG are based on currently available information and expectations as of the date of this press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with this press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. |
10) | The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs, Non-Cash Exchanges and Transactions and exploration costs incurred as operating expenses. |
Cautionary Notice
This press release and any accompanying disclosures may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, goals, returns and rates of return, budgets, reserves, levels of production, capital expenditures, operating costs and asset sales, statements regarding future commodity prices, 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 commodity and other derivative instruments and hedging activities; laws and regulations with respect to the import and export of crude oil, natural gas and related commodities; and trade policies, tariffs, trade agreements and other trade restrictions;
- 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, EOG's ability to retain, and competition in the oil and gas exploration and production industry for, employees, labor and other personnel, facilities, equipment, materials (such as water, sand, fuel and tubulars) and services;
- the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
- weather and natural disasters, including its impact on crude oil and natural gas demand, and related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, liquefaction, compression, storage, transportation, and export facilities;
- the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
- EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;
- the extent to which EOG is successful in its completion of planned asset dispositions;
- the extent and effect of any hedging activities engaged in by EOG;
- the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
- geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, political instability and armed conflicts), including in the areas in which EOG operates;
- the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage; and
- the other factors described under ITEM 1A, Risk Factors of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2025 and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
Historical Non-GAAP Financial Measures:
Reconciliation schedules and definitions for the historical non-GAAP financial measures included or referenced herein as well as related discussion can be found on the EOG website at www.eogresources.com.
Cautionary Notice Regarding Forward-Looking Non-GAAP Financial Measures:
In addition, this press release and any accompanying disclosures may include or reference certain forward-looking, non-GAAP financial measures, such as free cash flow, 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, 2025 (and any updates to such disclosure set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K), available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov.
Income Statements | |||||||||||
In millions of USD, except share data (in millions) and per share data (Unaudited) | |||||||||||
2025 | 2026 | ||||||||||
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 | 3,293 | 2,974 | 3,243 | 2,991 | 12,501 | 3,577 | 4,901 | 4,392 | 12,870 | ||
Natural Gas Liquids | 572 | 534 | 604 | 666 | 2,376 | 664 | 770 | 858 | 2,292 | ||
Natural Gas | 637 | 600 | 707 | 847 | 2,791 | 1,021 | 812 | 1,085 | 2,918 | ||
Gains (Losses) on Mark-to-Market | (191) | 107 | 116 | (19) | 13 | 113 | 40 | 105 | 258 | ||
Gathering, Processing and Marketing | 1,340 | 1,247 | 1,178 | 1,149 | 4,914 | 1,496 | 2,011 | 1,846 | 5,353 | ||
Gains (Losses) on Asset Dispositions, | (1) | — | (18) | (16) | (35) | 31 | 58 | 242 | 331 | ||
Other, Net | 19 | 16 | 17 | 20 | 72 | 19 | 28 | 21 | 68 | ||
Total | 5,669 | 5,478 | 5,847 | 5,638 | 22,632 | 6,921 | 8,620 | 8,549 | 24,090 | ||
Operating Expenses | |||||||||||
Lease and Well | 401 | 396 | 431 | 447 | 1,675 | 462 | 467 | 493 | 1,422 | ||
Gathering, Processing and | 440 | 455 | 587 | 652 | 2,134 | 654 | 676 | 693 | 2,023 | ||
Exploration Costs | 41 | 74 | 71 | 50 | 236 | 45 | 47 | 54 | 146 | ||
Dry Hole Costs | 34 | 11 | — | 4 | 49 | 23 | 30 | 29 | 82 | ||
Impairments | 44 | 39 | 71 | 689 | 843 | 39 | 19 | 24 | 82 | ||
Marketing Costs | 1,325 | 1,216 | 1,134 | 1,120 | 4,795 | 1,384 | 1,950 | 1,781 | 5,115 | ||
Depreciation, Depletion and | 1,013 | 1,053 | 1,169 | 1,226 | 4,461 | 1,193 | 1,259 | 1,292 | 3,744 | ||
General and Administrative | 171 | 186 | 239 | 224 | 820 | 185 | 213 | 196 | 594 | ||
Taxes Other Than Income | 341 | 301 | 309 | 283 | 1,234 | 338 | 431 | 401 | 1,170 | ||
Total | 3,810 | 3,731 | 4,011 | 4,695 | 16,247 | 4,323 | 5,092 | 4,963 | 14,378 | ||
Operating Income | 1,859 | 1,747 | 1,836 | 943 | 6,385 | 2,598 | 3,528 | 3,586 | 9,712 | ||
Other Income, Net | 65 | 55 | 59 | 33 | 212 | 23 | 38 | 45 | 106 | ||
Income Before Interest Expense and | 1,924 | 1,802 | 1,895 | 976 | 6,597 | 2,621 | 3,566 | 3,631 | 9,818 | ||
Interest Expense, Net | 47 | 51 | 71 | 66 | 235 | 66 | 67 | 67 | 200 | ||
Income Before Income Taxes | 1,877 | 1,751 | 1,824 | 910 | 6,362 | 2,555 | 3,499 | 3,564 | 9,618 | ||
Income Tax Provision | 414 | 406 | 353 | 209 | 1,382 | 575 | 775 | 783 | 2,133 | ||
Net Income | 1,463 | 1,345 | 1,471 | 701 | 4,980 | 1,980 | 2,724 | 2,781 | 7,485 | ||
Dividends Declared per Common Share | 0.9750 | 1.9950 | — | 1.0200 | 3.9900 | 1.0200 | 1.0200 | 1.0200 | 3.0600 | ||
Net Income Per Share | |||||||||||
Basic | 2.66 | 2.48 | 2.72 | 1.31 | 9.17 | 3.72 | 5.18 | 5.37 | 14.26 | ||
Diluted | 2.65 | 2.46 | 2.70 | 1.30 | 9.12 | 3.70 | 5.15 | 5.33 | 14.18 | ||
Average Number of Common Shares | |||||||||||
Basic | 550 | 543 | 541 | 537 | 543 | 532 | 526 | 518 | 525 | ||
Diluted | 553 | 546 | 544 | 539 | 546 | 535 | 529 | 522 | 528 | ||
Volumes and Prices | |||||||||||
(Unaudited) | |||||||||||
2025 | 2026 | ||||||||||
1st Qtr | 2nd Qtr | 3rd Qtr | 4th Qtr | Year | 1st Qtr | 2nd Qtr | 3rd Qtr | 4th Qtr | Year | ||
Crude Oil and Condensate Volumes (MBod) (A) | |||||||||||
United States | 500.9 | 503.1 | 532.9 | 544.5 | 520.5 | 546.5 | 546.2 | 547.7 | 546.8 | ||
Trinidad | 1.2 | 1.1 | 1.6 | 1.5 | 1.4 | 1.9 | 2.1 | 2.0 | 2.0 | ||
Other International (B) | — | — | — | 0.1 | — | 0.1 | 0.5 | 0.7 | 0.4 | ||
Total | 502.1 | 504.2 | 534.5 | 546.1 | 521.9 | 548.5 | 548.8 | 550.4 | 549.2 | ||
Average Crude Oil and Condensate Prices ($/Bbl) (C) | |||||||||||
United States | $ 72.90 | $ 64.84 | $ 65.97 | $ 59.54 | $ 65.65 | $ 72.48 | $ 98.18 | $ 86.73 | $ 85.85 | ||
Trinidad | 61.12 | 54.50 | 57.74 | 57.07 | 57.59 | 68.91 | 88.87 | 84.62 | 81.07 | ||
Other International | — | — | — | 63.98 | — | 89.12 | 103.40 | 87.96 | 94.53 | ||
Composite | 72.87 | 64.82 | 65.95 | 59.54 | 65.63 | 72.47 | 98.15 | 86.72 | 85.83 | ||
Natural Gas Liquids Volumes (MBbld) (A) | |||||||||||
United States | 241.7 | 258.4 | 309.3 | 342.1 | 288.2 | 332.1 | 346.8 | 357.1 | 345.4 | ||
Total | 241.7 | 258.4 | 309.3 | 342.1 | 288.2 | 332.1 | 346.8 | 357.1 | 345.4 | ||
Average Natural Gas Liquids Prices ($/Bbl) (C) | |||||||||||
United States | $ 26.29 | $ 22.70 | $ 21.25 | $ 21.15 | $ 22.58 | $ 22.20 | $ 24.41 | $ 26.13 | $ 24.31 | ||
Composite | 26.29 | 22.70 | 21.25 | 21.15 | 22.58 | 22.20 | 24.41 | 26.13 | 24.31 | ||
Natural Gas Volumes (MMcfd) (A) | |||||||||||
United States | 1,834 | 1,977 | 2,511 | 2,859 | 2,299 | 2,769 | 2,784 | 2,882 | 2,812 | ||
Trinidad | 246 | 252 | 230 | 195 | 230 | 239 | 293 | 260 | 265 | ||
Other International (B) | — | — | 4 | 11 | 4 | 12 | 12 | 11 | 11 | ||
Total | 2,080 | 2,229 | 2,745 | 3,065 | 2,533 | 3,020 | 3,089 | 3,153 | 3,088 | ||
Average Natural Gas Prices ($/Mcf) (C) | |||||||||||
United States | $ 3.36 | $ 2.87 | $ 2.71 | $ 2.94 | $ 2.94 | $ 3.75 | $ 2.77 | $ 3.73 | $ 3.42 | ||
Trinidad | 3.78 | 3.65 | 3.80 | 3.94 | 3.78 | 3.91 | 3.99 | 3.92 | 3.94 | ||
Other International (B) | — | — | 3.27 | 3.29 | 3.28 | 3.26 | 3.27 | 3.30 | 3.28 | ||
Composite | 3.41 | 2.96 | 2.80 | 3.00 | 3.02 | 3.76 | 2.89 | 3.74 | 3.46 | ||
Crude Oil Equivalent Volumes (MBoed) (D) | |||||||||||
United States | 1,048.3 | 1,090.9 | 1,260.7 | 1,363.0 | 1,191.8 | 1,340.1 | 1,357.1 | 1,385.1 | 1,360.9 | ||
Trinidad | 42.1 | 43.2 | 39.8 | 34.2 | 39.8 | 41.7 | 50.9 | 45.6 | 46.1 | ||
Other International | — | — | 0.7 | 1.8 | 0.6 | 2.0 | 2.4 | 2.4 | 2.3 | ||
Total | 1,090.4 | 1,134.1 | 1,301.2 | 1,399.0 | 1,232.2 | 1,383.8 | 1,410.4 | 1,433.1 | 1,409.3 | ||
Total MMBoe (D) | 98.1 | 103.2 | 119.7 | 128.7 | 449.8 | 124.5 | 128.3 | 131.8 | 384.7 | ||
(A) | Thousand barrels per day or million cubic feet per day, as applicable. |
(B) | Crude oil and condensate volumes are from UAE and Bahrain operations. Natural gas volumes are from Bahrain operations; natural gas realized price represents contract price less partner's processing and distribution costs. |
(C) | Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity and other derivative instruments (see Note 9 to the Condensed Consolidated Financial Statements in EOG's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2026). |
(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) | |||||||||
2025 | 2026 | ||||||||
MAR | JUN | SEP | DEC | MAR | JUN | SEP | DEC | ||
Current Assets | |||||||||
Cash and Cash Equivalents | 6,599 | 5,216 | 3,530 | 3,396 | 3,849 | 4,907 | 5,747 | ||
Accounts Receivable, Net | 2,621 | 2,504 | 2,680 | 2,681 | 3,597 | 3,529 | 3,955 | ||
Inventories | 897 | 934 | 945 | 1,014 | 955 | 930 | 938 | ||
Other (A) | 563 | 591 | 665 | 565 | 562 | 511 | 607 | ||
Total | 10,680 | 9,245 | 7,820 | 7,656 | 8,963 | 9,877 | 11,247 | ||
Property, Plant and Equipment | |||||||||
Oil and Gas Properties (Successful Efforts Method) | 78,432 | 80,139 | 88,301 | 89,857 | 90,786 | 92,454 | 88,943 | ||
Other Property, Plant and Equipment | 6,510 | 6,616 | 6,772 | 6,832 | 6,942 | 7,064 | 6,757 | ||
Total Property, Plant and Equipment | 84,942 | 86,755 | 95,073 | 96,689 | 97,728 | 99,518 | 95,700 | ||
Less: Accumulated Depreciation, Depletion and | (50,310) | (51,394) | (52,488) | (54,348) | (55,054) | (56,278) | (52,212) | ||
Total Property, Plant and Equipment, Net | 34,632 | 35,361 | 42,585 | 42,341 | 42,674 | 43,240 | 43,488 | ||
Deferred Income Taxes | 44 | 39 | 37 | 39 | 30 | 35 | 31 | ||
Other Assets | 1,626 | 1,639 | 1,757 | 1,763 | 1,711 | 1,631 | 1,702 | ||
Total Assets | 46,982 | 46,284 | 52,199 | 51,799 | 53,378 | 54,783 | 56,468 | ||
Current Liabilities | |||||||||
Accounts Payable | 2,353 | 2,266 | 2,944 | 2,904 | 3,186 | 3,374 | 3,364 | ||
Accrued Taxes Payable | 668 | 348 | 392 | 299 | 766 | 697 | 1,234 | ||
Dividends Payable | 534 | 1,081 | 550 | 544 | 541 | 531 | 525 | ||
Current Portion of Long-Term Debt | 1,280 | 778 | 27 | 27 | 27 | 27 | 28 | ||
Current Portion of Operating Lease Liabilities | 318 | 360 | 433 | 472 | 375 | 324 | 340 | ||
Other (A) | 566 | 342 | 469 | 445 | 329 | 382 | 433 | ||
Total | 5,719 | 5,175 | 4,815 | 4,691 | 5,224 | 5,335 | 5,924 | ||
Long-Term Debt | 3,464 | 3,458 | 7,667 | 7,909 | 7,904 | 7,899 | 7,894 | ||
Other Liabilities | 2,368 | 2,398 | 2,496 | 2,512 | 2,476 | 2,468 | 2,441 | ||
Deferred Income Taxes | 5,915 | 6,015 | 6,936 | 6,854 | 6,866 | 7,217 | 7,108 | ||
Commitments and Contingencies (B) | |||||||||
Stockholders' Equity | |||||||||
Common Stock, $0.01 Par | 206 | 206 | 206 | 206 | 206 | 206 | 206 | ||
Additional Paid-In Capital | 6,095 | 6,153 | 5,978 | 6,027 | 6,026 | 6,072 | 5,899 | ||
Accumulated Other Comprehensive Loss | (4) | (7) | (5) | (7) | (6) | (5) | (5) | ||
Retained Earnings | 27,869 | 28,131 | 29,603 | 29,765 | 31,200 | 33,390 | 35,642 | ||
Common Stock Held in Treasury | (4,650) | (5,245) | (5,497) | (6,158) | (6,518) | (7,799) | (8,641) | ||
Total Stockholders' Equity | 29,516 | 29,238 | 30,285 | 29,833 | 30,908 | 31,864 | 33,101 | ||
Total Liabilities and Stockholders' Equity | 46,982 | 46,284 | 52,199 | 51,799 | 53,378 | 54,783 | 56,468 | ||
(A) | Effective January 1, 2026, EOG combined Price Risk Management Activities into the Other line item. This presentation has been conformed for all periods presented and had no impact on previously reported Total Assets and Total Liabilities and Stockholders' Equity. |
(B) | See Note 5 to the Condensed Consolidated Financial Statements in EOG's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2026. |
Cash Flow Statements | |||||||||||
In millions of USD (Unaudited) | |||||||||||
2025 | 2026 | ||||||||||
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 | |||||||||||
Net Income | 1,463 | 1,345 | 1,471 | 701 | 4,980 | 1,980 | 2,724 | 2,781 | 7,485 | ||
Items Not Requiring (Providing) Cash | |||||||||||
Depreciation, Depletion and Amortization | 1,013 | 1,053 | 1,169 | 1,226 | 4,461 | 1,193 | 1,259 | 1,292 | 3,744 | ||
Impairments | 44 | 39 | 71 | 689 | 843 | 39 | 19 | 24 | 82 | ||
Stock-Based Compensation Expenses | 50 | 53 | 53 | 60 | 216 | 58 | 60 | 55 | 173 | ||
Deferred Income Taxes | 44 | 105 | 278 | (84) | 343 | 18 | 346 | (106) | 258 | ||
(Gains) Losses on Asset Dispositions, Net | 1 | — | 18 | 16 | 35 | (31) | (58) | (242) | (331) | ||
Other, Net | 11 | 11 | 2 | 3 | 27 | 15 | 2 | 6 | 23 | ||
Dry Hole Costs | 34 | 11 | — | 4 | 49 | 23 | 30 | 29 | 82 | ||
Mark-to-Market Financial Commodity and Other | 191 | (107) | (116) | 19 | (13) | (113) | (40) | (105) | (258) | ||
Net Cash Received from (Payments for) | (38) | (24) | 27 | (21) | (56) | (53) | 45 | 40 | 32 | ||
Other, Net | — | — | — | (1) | (1) | — | (1) | (1) | (2) | ||
Changes in Components of Working Capital and | |||||||||||
Accounts Receivable | 48 | 122 | 133 | (3) | 300 | (907) | 60 | (414) | (1,261) | ||
Inventories | 76 | (45) | 4 | (84) | (49) | 21 | 26 | (27) | 20 | ||
Accounts Payable | (129) | (107) | 5 | (40) | (271) | 279 | 176 | (44) | 411 | ||
Accrued Taxes Payable | (339) | (321) | 28 | (103) | (735) | 467 | (69) | 536 | 934 | ||
Other Assets | (43) | (43) | (28) | 97 | (17) | 55 | 47 | (63) | 39 | ||
Other Liabilities | (96) | (52) | 155 | 10 | 17 | (123) | 37 | 47 | (39) | ||
Changes in Components of Working Capital | (41) | (8) | (159) | 123 | (85) | 45 | 6 | 5 | 56 | ||
Net Cash Provided by Operating Activities | 2,289 | 2,032 | 3,111 | 2,612 | 10,044 | 2,966 | 4,669 | 3,813 | 11,448 | ||
Investing Cash Flows | |||||||||||
Acquisition of Encino Acquisition Partners, LLC, | — | — | (4,464) | 13 | (4,451) | — | — | — | — | ||
Additions to Oil and Gas Properties | (1,381) | (1,699) | (1,492) | (1,543) | (6,115) | (1,491) | (1,638) | (1,476) | (4,605) | ||
Additions to Other Property, Plant and Equipment | (102) | (94) | (171) | (112) | (479) | (153) | (144) | (121) | (418) | ||
Proceeds from Sales of Assets | 12 | 4 | 5 | 3 | 24 | 144 | 7 | 243 | 394 | ||
Changes in Components of Working Capital | 41 | 8 | 159 | (123) | 85 | (45) | (6) | (5) | (56) | ||
Net Cash Used in Investing Activities | (1,430) | (1,781) | (5,963) | (1,762) | (10,936) | (1,545) | (1,781) | (1,359) | (4,685) | ||
Financing Cash Flows | |||||||||||
Long-Term Debt Borrowings | — | — | 3,472 | 999 | 4,471 | — | — | — | — | ||
Long-Term Debt Repayments | — | (500) | (1,266) | (750) | (2,516) | — | — | — | — | ||
Dividends Paid | (538) | (528) | (545) | (550) | (2,161) | (544) | (540) | (544) | (1,628) | ||
Treasury Stock Purchased | (806) | (602) | (479) | (677) | (2,564) | (418) | (1,299) | (1,063) | (2,780) | ||
Proceeds from Stock Options Exercised and | — | 11 | — | 12 | 23 | 1 | 15 | — | 16 | ||
Debt Issuance and Other Financing Costs | — | (7) | (7) | (11) | (25) | — | — | — | — | ||
Repayment of Finance Lease Liabilities | (8) | (9) | (8) | (7) | (32) | (7) | (6) | (7) | (20) | ||
Net Cash Provided by (Used in) Financing Activities | (1,352) | (1,635) | 1,167 | (984) | (2,804) | (968) | (1,830) | (1,614) | (4,412) | ||
Effect of Exchange Rate Changes on Cash | — | 1 | (1) | — | — | — | — | — | — | ||
Increase (Decrease) in Cash and Cash Equivalents | (493) | (1,383) | (1,686) | (134) | (3,696) | 453 | 1,058 | 840 | 2,351 | ||
Cash and Cash Equivalents at Beginning of Period | 7,092 | 6,599 | 5,216 | 3,530 | 7,092 | 3,396 | 3,849 | 4,907 | 3,396 | ||
Cash and Cash Equivalents at End of Period | 6,599 | 5,216 | 3,530 | 3,396 | 3,396 | 3,849 | 4,907 | 5,747 | 5,747 | ||
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 earnings 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 | |||||||
3Q 2026 | |||||||
Before | Income Tax | After | Diluted | ||||
Reported Net Income (GAAP) | 3,564 | (783) | 2,781 | 5.33 | |||
Adjustments: | |||||||
Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net | (105) | 23 | (82) | (0.15) | |||
Net Cash Received from Settlements of Financial Commodity Derivative Contracts (1) | 40 | (8) | 32 | 0.06 | |||
Less: Gains on Asset Dispositions, Net | (242) | 51 | (191) | (0.37) | |||
Adjustments to Net Income | (307) | 66 | (241) | (0.46) | |||
Adjusted Net Income (Non-GAAP) | 3,257 | (717) | 2,540 | 4.87 | |||
Average Number of Common Shares | |||||||
Basic | 518 | ||||||
Diluted | 522 | ||||||
(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, 2026, such amount was $40 million. |
Adjusted Net Income (Continued) | |||||||
In millions of USD, except share data (in millions) and per share data (Unaudited) | |||||||
2Q 2026 | |||||||
Before | IncomeTax | After | Diluted | ||||
Reported Net Income (GAAP) | 3,499 | (775) | 2,724 | 5.15 | |||
Adjustments: | |||||||
Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net | (40) | 9 | (31) | (0.06) | |||
Net Cash Received from Settlements of Financial Commodity Derivative Contracts (1) | 45 | (9) | 36 | 0.07 | |||
Less: Gains on Asset Dispositions, Net | (58) | 12 | (46) | (0.09) | |||
Adjustments to Net Income | (53) | 12 | (41) | (0.08) | |||
Adjusted Net Income (Non-GAAP) | 3,446 | (763) | 2,683 | 5.07 | |||
Average Number of Common Shares | |||||||
Basic | 526 | ||||||
Diluted | 529 | ||||||
(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 June 30, 2026, such amount was $45 million. |
1Q 2026 | |||||||
Before | Income Tax | After | Diluted | ||||
Reported Net Income (GAAP) | 2,555 | (575) | 1,980 | 3.70 | |||
Adjustments: | |||||||
Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net | (113) | 24 | (89) | (0.17) | |||
Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1) | (53) | 11 | (42) | (0.08) | |||
Less: Gains on Asset Dispositions, Net | (31) | 7 | (24) | (0.04) | |||
Adjustments to Net Income | (197) | 42 | (155) | (0.29) | |||
Adjusted Net Income (Non-GAAP) | 2,358 | (533) | 1,825 | 3.41 | |||
Average Number of Common Shares | |||||||
Basic | 532 | ||||||
Diluted | 535 | ||||||
(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, 2026, such amount was $53 million. |
Adjusted Net Income (Continued) | |||||||
In millions of USD, except share data (in millions) and per share data (Unaudited) | |||||||
4Q 2025 | |||||||
Before | Income Tax | After | Diluted | ||||
Reported Net Income (GAAP) | 910 | (209) | 701 | 1.30 | |||
Adjustments: | |||||||
Losses on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net | 19 | (4) | 15 | 0.03 | |||
Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1) | (21) | 4 | (17) | (0.03) | |||
Add: Losses on Asset Dispositions, Net | 16 | (4) | 12 | 0.02 | |||
Add: Certain Impairments (2) | 646 | (140) | 506 | 0.94 | |||
Add: Acquisition-Related Costs (3) | 8 | (3) | 5 | 0.01 | |||
Adjustments to Net Income | 668 | (147) | 521 | 0.97 | |||
Adjusted Net Income (Non-GAAP) | 1,578 | (356) | 1,222 | 2.27 | |||
Average Number of Common Shares | |||||||
Basic | 537 | ||||||
Diluted | 539 | ||||||
(1) | Consistent with its customary practice, in calculating Adjusted Net Income (Non-GAAP), EOG subtracts from reported Net Income (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the three months ended December 31, 2025, such amount was $21 million. |
(2) | Impairments primarily associated with the write-down to fair value of natural gas and crude oil assets in the Barnett Shale and Woodford Oil Window (mainly driven by play-specific economics and resource allocation). |
(3) | Consists of Encino acquisition-related G&A costs ($8 million). |
3Q 2025 | |||||||
Before | Income Tax | After | Diluted | ||||
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) | |||||||
FY 2025 | |||||||
Before | Income Tax | After | Diluted | ||||
Reported Net Income (GAAP) | 6,362 | (1,382) | 4,980 | 9.12 | |||
Adjustments: | |||||||
Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net | (13) | 3 | (10) | (0.02) | |||
Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1) | (56) | 12 | (44) | (0.08) | |||
Add: Losses on Asset Dispositions, Net | 35 | (8) | 27 | 0.05 | |||
Add: Certain Impairments (2) | 657 | (140) | 517 | 0.95 | |||
Add: Acquisition-Related Costs (3) | 94 | (16) | 78 | 0.14 | |||
Adjustments to Net Income | 717 | (149) | 568 | 1.04 | |||
Adjusted Net Income (Non-GAAP) | 7,079 | (1,531) | 5,548 | 10.16 | |||
Average Number of Common Shares | |||||||
Basic | 543 | ||||||
Diluted | 546 | ||||||
(1) | Consistent with its customary practice, in calculating Adjusted Net Income (Non-GAAP), EOG subtracts from reported Net Income (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the twelve months ended December 31, 2025, such amount was $56 million. |
(2) | Impairments primarily associated with the write-down to fair value of natural gas and crude oil assets in the Barnett Shale and Woodford Oil Window (mainly driven by play-specific economics and resource allocation). |
(3) | Consists of Encino acquisition-related G&A costs ($88 million) and financing commitment costs ($6 million). |
FY 2024 | |||||||
Before | Income Tax | After | Diluted | ||||
Reported Net Income (GAAP) | 8,218 | (1,815) | 6,403 | 11.25 | |||
Adjustments: | |||||||
Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net | (204) | 44 | (160) | (0.28) | |||
Net Cash Received from Settlements of Financial Commodity Derivative Contracts (1) | 214 | (46) | 168 | 0.30 | |||
Less: Gains on Asset Dispositions, Net | (16) | 3 | (13) | (0.02) | |||
Add: Certain Impairments (2) | 291 | (57) | 234 | 0.41 | |||
Less: Severance Tax Refund | (31) | 7 | (24) | (0.04) | |||
Add: Severance Tax Consulting Fees | 10 | (2) | 8 | 0.01 | |||
Less: Interest on Severance Tax Refund | (5) | 1 | (4) | (0.01) | |||
Adjustments to Net Income | 259 | (50) | 209 | 0.37 | |||
Adjusted Net Income (Non-GAAP) | 8,477 | (1,865) | 6,612 | 11.62 | |||
Average Number of Common Shares | |||||||
Basic | 566 | ||||||
Diluted | 569 | ||||||
(1) | Consistent with its customary practice, in calculating Adjusted Net Income (Non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the twelve months ended December 31, 2024, such amount was $214 million. |
(2) | Impairments primarily associated with the write-down to fair value of natural gas and crude oil assets in the Rocky Mountain area. |
Net Income Per Share | |||
In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited) | |||
2Q 2026 Net Income per Share (GAAP) - Diluted | 5.15 | ||
Realized Prices | |||
3Q 2026 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe | 48.05 | ||
Less: 2Q 2026 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe | (50.52) | ||
Subtotal | (2.47) | ||
Multiplied by: 3Q 2026 Crude Oil Equivalent Volumes (MMBoe) | 131.8 | ||
Total Change in Revenue | (326) | ||
Add: Income Tax Benefit (Provision) Imputed (based on 22%) | 72 | ||
Change in Net Income | (254) | ||
Change in Diluted Earnings per Share | (0.49) | ||
Volumes | |||
3Q 2026 Crude Oil Equivalent Volumes (MMBoe) | 131.8 | ||
Less: 2Q 2026 Crude Oil Equivalent Volumes (MMBoe) | (128.3) | ||
Subtotal | 3.5 | ||
Multiplied by: 3Q 2026 Composite Average Margin per Boe (GAAP) (Including Total | 23.40 | ||
Change in Margin | 82 | ||
Add: Income Tax Benefit (Provision) Imputed (based on 22%) | (18) | ||
Change in Net Income | 64 | ||
Change in Diluted Earnings per Share | 0.12 | ||
Certain Operating Costs per Boe | |||
2Q 2026 Total Cash Operating Costs (GAAP) and Total DD&A per Boe | 20.38 | ||
Less: 3Q 2026 Total Cash Operating Costs (GAAP) and Total DD&A per Boe | (20.29) | ||
Subtotal | 0.09 | ||
Multiplied by: 3Q 2026 Crude Oil Equivalent Volumes (MMBoe) | 131.8 | ||
Change in Before-Tax Net Income | 12 | ||
Add: Income Tax Benefit (Provision) Imputed (based on 22%) | (3) | ||
Change in Net Income | 9 | ||
Change in Diluted Earnings per Share | 0.02 | ||
Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net | |||
3Q 2026 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts | 105 | ||
Add: Income Tax Benefit (Provision) | (23) | ||
After Tax - (a) | 82 | ||
Less: 2Q 2026 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts | 40 | ||
Less: Income Tax Benefit (Provision) | (9) | ||
After Tax - (b) | 31 | ||
Change in Net Income - (a) - (b) | 51 | ||
Change in Diluted Earnings per Share | 0.10 | ||
Other (1) | 0.43 | ||
3Q 2026 Net Income per Share (GAAP) - Diluted | 5.33 | ||
3Q 2026 Average Number of Common Shares - Diluted | 522 | ||
(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 2026 Adjusted Net Income per Share (Non-GAAP) - Diluted | 5.07 | ||
Realized Prices | |||
3Q 2026 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe | 48.05 | ||
Less: 2Q 2026 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe | (50.52) | ||
Subtotal | (2.47) | ||
Multiplied by: 3Q 2026 Crude Oil Equivalent Volumes (MMBoe) | 131.8 | ||
Total Change in Revenue | (326) | ||
Add: Income Tax Benefit (Provision) Imputed (based on 22%) | 72 | ||
Change in Net Income | (254) | ||
Change in Diluted Earnings per Share | (0.49) | ||
Volumes | |||
3Q 2026 Crude Oil Equivalent Volumes (MMBoe) | 131.8 | ||
Less: 2Q 2026 Crude Oil Equivalent Volumes (MMBoe) | (128.3) | ||
Subtotal | 3.5 | ||
Multiplied by: 3Q 2026 Composite Average Margin per Boe (Non-GAAP) (Including Total Exploration Costs) (refer to | 23.40 | ||
Change in Margin | 82 | ||
Less: Income Tax Benefit (Provision) Imputed (based on 22%) | (18) | ||
Change in Net Income | 64 | ||
Change in Diluted Earnings per Share | 0.12 | ||
Certain Operating Costs per Boe | |||
2Q 2026 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe | 20.38 | ||
Less: 3Q 2026 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe | (20.29) | ||
Subtotal | 0.09 | ||
Multiplied by: 3Q 2026 Crude Oil Equivalent Volumes (MMBoe) | 131.8 | ||
Change in Before-Tax Net Income | 12 | ||
Add: Income Tax Benefit (Provision) Imputed (based on 22%) | (3) | ||
Change in Net Income | 9 | ||
Change in Diluted Earnings per Share | 0.02 | ||
Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts | |||
3Q 2026 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts | 40 | ||
Less: Income Tax Benefit (Provision) | (8) | ||
After Tax - (a) | 32 | ||
Less: 2Q 2026 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts | 45 | ||
Add: Income Tax Benefit (Provision) | (9) | ||
After Tax - (b) | 36 | ||
Change in Net Income - (a) - (b) | (4) | ||
Change in Diluted Earnings per Share | (0.01) | ||
Other (1) | 0.16 | ||
3Q 2026 Adjusted Net Income per Share (Non-GAAP) - Diluted | 4.87 | ||
3Q 2026 Average Number of Common Shares - Diluted | 522 | ||
(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 | |||||||||||
2025 | 2026 | ||||||||||
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) | 2,289 | 2,032 | 3,111 | 2,612 | 10,044 | 2,966 | 4,669 | 3,813 | 11,448 | ||
Adjustments: | |||||||||||
Changes in Components of Working Capital | |||||||||||
Accounts Receivable | (48) | (122) | (133) | 3 | (300) | 907 | (60) | 414 | 1,261 | ||
Inventories | (76) | 45 | (4) | 84 | 49 | (21) | (26) | 27 | (20) | ||
Accounts Payable | 129 | 107 | (5) | 40 | 271 | (279) | (176) | 44 | (411) | ||
Accrued Taxes Payable | 339 | 321 | (28) | 103 | 735 | (467) | 69 | (536) | (934) | ||
Other Assets | 43 | 43 | 28 | (97) | 17 | (55) | (47) | 63 | (39) | ||
Other Liabilities | 96 | 52 | (155) | (10) | (17) | 123 | (37) | (47) | 39 | ||
Changes in Components of Working Capital | 41 | 8 | 159 | (123) | 85 | (45) | (6) | (5) | (56) | ||
Add: | |||||||||||
Acquisition-Related Costs (1), Net of Tax | — | 10 | 58 | 5 | 73 | — | — | — | — | ||
Adjusted Cash Flow from Operations (Non- | 2,813 | 2,496 | 3,031 | 2,617 | 10,957 | 3,129 | 4,386 | 3,773 | 11,288 | ||
Less: | |||||||||||
Total Capital Expenditures (Non-GAAP) (2) | (1,484) | (1,523) | (1,648) | (1,639) | (6,294) | (1,636) | (1,587) | (1,597) | (4,820) | ||
Free Cash Flow (Non-GAAP) | 1,329 | 973 | 1,383 | 978 | 4,663 | 1,493 | 2,799 | 2,176 | 6,468 | ||
| |||||||||||
(2) See below reconciliation of Total Expenditures (GAAP) to Total Capital Expenditures (Non-GAAP): | |||||||||||
2025 | 2026 | ||||||||||
1st Qtr | 2nd Qtr | 3rd Qtr | 4th Qtr | Year | 1st Qtr | 2nd Qtr | 3rd Qtr | 4th Qtr | Year | ||
Total Expenditures (GAAP) | 1,546 | 1,883 | 8,544 | 1,730 | 13,703 | 1,768 | 1,919 | 1,871 | 5,558 | ||
Less: | |||||||||||
Asset Retirement Costs | (13) | (14) | (86) | (33) | (146) | (12) | (37) | (12) | (61) | ||
Non-Cash Leasehold Acquisition Costs (3) | (9) | (2) | (3) | (10) | (24) | (52) | (53) | (206) | (311) | ||
Non-Cash Property Acquisition Costs | — | — | — | — | — | — | (2) | — | (2) | ||
Acquisition Costs of Properties (3) | 1 | (270) | (6,736) | 2 | (7,003) | (23) | (193) | (2) | (218) | ||
Exploration Costs | (41) | (74) | (71) | (50) | (236) | (45) | (47) | (54) | (146) | ||
Total Capital Expenditures (Non-GAAP) | 1,484 | 1,523 | 1,648 | 1,639 | 6,294 | 1,636 | 1,587 | 1,597 | 4,820 | ||
Cash Flow from Operations and Free Cash Flow (Continued) | |||||||
In millions of USD (Unaudited) | |||||||
FY 2024 | FY 2023 | FY 2022 | FY 2021 | ||||
Net Cash Provided by Operating Activities (GAAP) | 12,143 | 11,340 | 11,093 | 8,791 | |||
Adjustments: | |||||||
Changes in Components of Working Capital and Other Assets and Liabilities | |||||||
Accounts Receivable | (101) | 38 | 347 | 821 | |||
Inventories | (259) | 231 | 534 | 13 | |||
Accounts Payable | 36 | 119 | (90) | (456) | |||
Accrued Taxes Payable | (541) | (61) | 113 | (312) | |||
Other Assets | (44) | (39) | 364 | 136 | |||
Other Liabilities | (23) | (184) | 266 | 116 | |||
Changes in Components of Working Capital Associated with Investing | 382 | (295) | (375) | 200 | |||
Adjusted Cash Flow from Operations (Non-GAAP) | 11,593 | 11,149 | 12,252 | 9,309 | |||
Less: | |||||||
Total Capital Expenditures (Non-GAAP) (2) | (6,226) | (6,041) | (4,607) | (3,755) | |||
Free Cash Flow (Non-GAAP) | 5,367 | 5,108 | 7,645 | 5,554 | |||
(2) See below reconciliation of Total Expenditures (GAAP) to Total Capital Expenditures (Non-GAAP): | |||||||
Total Expenditures (GAAP) | 6,653 | 6,818 | 5,610 | 4,255 | |||
Less: | |||||||
Asset Retirement Costs | 2 | (257) | (298) | (127) | |||
Non-Cash Development Drilling | — | (90) | — | — | |||
Non-Cash Leasehold Acquisition Costs (3) | (85) | (99) | (127) | (45) | |||
Non-Cash Finance Leases | — | — | — | (74) | |||
Acquisition Costs of Properties (3) | (33) | (16) | (419) | (100) | |||
Acquisition Costs of Other Property, Plant and Equipment | (137) | (134) | — | — | |||
Exploration Costs | (174) | (181) | (159) | (154) | |||
Total Capital Expenditures (Non-GAAP) | 6,226 | 6,041 | 4,607 | 3,755 | |||
(3) | Line item descriptions revised (from descriptions shown in EOG's previously published tables) to more accurately describe the costs reflected therein; previously reported cost amounts not impacted by such changes in presentation. |
Net Debt-to-Total Capitalization Ratio | |||||||||
In millions of USD, except ratio data (Unaudited) | |||||||||
The following tables reconcile Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as | |||||||||
September 30, | June 30, | March 31, | December 31, | September 30, | |||||
Total Stockholders' Equity - (a) | 33,101 | 31,864 | 30,908 | 29,833 | 30,285 | ||||
Current and Long-Term Debt (GAAP) - (b) | 7,922 | 7,926 | 7,931 | 7,936 | 7,694 | ||||
Less: Cash | (5,747) | (4,907) | (3,849) | (3,396) | (3,530) | ||||
Net Debt (Non-GAAP) - (c) | 2,175 | 3,019 | 4,082 | 4,540 | 4,164 | ||||
Total Capitalization (GAAP) - (a) + (b) | 41,023 | 39,790 | 38,839 | 37,769 | 37,979 | ||||
Total Capitalization (Non-GAAP) - (a) + (c) | 35,276 | 34,883 | 34,990 | 34,373 | 34,449 | ||||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] | 19.3 % | 19.9 % | 20.4 % | 21.0 % | 20.3 % | ||||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | 6.2 % | 8.7 % | 11.7 % | 13.2 % | 12.1 % | ||||
Revenues, Costs and Margins Per Barrel of Oil Equivalent | |||||||||
In millions of USD, except Boe and per Boe amounts (Unaudited) | |||||||||
EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who review certain components and/or groups of | |||||||||
3Q 2026 | 2Q 2026 | 1Q 2026 | 4Q 2025 | 3Q 2025 | |||||
Volume - Million Barrels of Oil Equivalent - (a) | 131.8 | 128.3 | 124.5 | 128.7 | 119.7 | ||||
Total Operating Revenues and Other - (b) | 8,549 | 8,620 | 6,921 | 5,638 | 5,847 | ||||
Total Operating Expenses - (c) | 4,963 | 5,092 | 4,323 | 4,695 | 4,011 | ||||
Operating Income - (d) | 3,586 | 3,528 | 2,598 | 943 | 1,836 | ||||
Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas | |||||||||
Crude Oil and Condensate | 4,392 | 4,901 | 3,577 | 2,991 | 3,243 | ||||
Natural Gas Liquids | 858 | 770 | 664 | 666 | 604 | ||||
Natural Gas | 1,085 | 812 | 1,021 | 847 | 707 | ||||
Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural | 6,335 | 6,483 | 5,262 | 4,504 | 4,554 | ||||
Operating Costs | |||||||||
Lease and Well | 493 | 467 | 462 | 447 | 431 | ||||
Gathering, Processing and Transportation Costs (1) | 693 | 676 | 654 | 652 | 587 | ||||
General and Administrative (GAAP) | 196 | 213 | 185 | 224 | 239 | ||||
Less: Certain Items (see Endnote 2 to 3Q 2026 earnings release) | — | — | — | (8) | (68) | ||||
General and Administrative (Non-GAAP) (2) | 196 | 213 | 185 | 216 | 171 | ||||
Taxes Other Than Income (GAAP) | 401 | 431 | 338 | 283 | 309 | ||||
Add: Severance Tax Refund | — | — | — | — | — | ||||
Taxes Other Than Income (Non-GAAP) (3) | 401 | 431 | 338 | 283 | 309 | ||||
Interest Expense, Net | 67 | 67 | 66 | 66 | 71 | ||||
Less: Acquisition-Related Financing Commitment Costs | — | — | — | — | — | ||||
Interest Expense, Net (Non-GAAP) (4) | 67 | 67 | 66 | 66 | 71 | ||||
Total Operating Cost (GAAP) (excluding DD&A and Total Exploration Costs) | 1,850 | 1,854 | 1,705 | 1,672 | 1,637 | ||||
Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration | 1,850 | 1,854 | 1,705 | 1,664 | 1,569 | ||||
Depreciation, Depletion and Amortization (DD&A) | 1,292 | 1,259 | 1,193 | 1,226 | 1,169 | ||||
Total Operating Cost (GAAP) (excluding Total Exploration Costs) - (h) | 3,142 | 3,113 | 2,898 | 2,898 | 2,806 | ||||
Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (i) | 3,142 | 3,113 | 2,898 | 2,890 | 2,738 | ||||
Exploration Costs | 54 | 47 | 45 | 50 | 71 | ||||
Dry Hole Costs | 29 | 30 | 23 | 4 | — | ||||
Impairments | 24 | 19 | 39 | 689 | 71 | ||||
Total Exploration Costs (GAAP) | 107 | 96 | 107 | 743 | 142 | ||||
Less: Certain Impairments (5) | — | — | — | (646) | — | ||||
Total Exploration Costs (Non-GAAP) | 107 | 96 | 107 | 97 | 142 | ||||
Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) - (j) | 3,249 | 3,209 | 3,005 | 3,641 | 2,948 | ||||
Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non- | 3,249 | 3,209 | 3,005 | 2,987 | 2,880 | ||||
Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural (GAAP)) | 3,086 | 3,274 | 2,257 | 863 | 1,606 | ||||
Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural | 3,086 | 3,274 | 2,257 | 1,517 | 1,674 | ||||
Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued) | |||||||||
In millions of USD, except Boe and per Boe amounts (Unaudited) | |||||||||
3Q 2026 | 2Q 2026 | 1Q 2026 | 4Q 2025 | 3Q 2025 | |||||
Per Barrel of Oil Equivalent (Boe) Calculations (GAAP) | |||||||||
Composite Average Operating Revenues and Other per Boe - (b) / (a) | 64.86 | 67.19 | 55.59 | 43.81 | 48.85 | ||||
Composite Average Operating Expenses per Boe - (c) / (a) | 37.65 | 39.69 | 34.72 | 36.48 | 33.51 | ||||
Composite Average Operating Income per Boe - (d) / (a) | 27.21 | 27.50 | 20.87 | 7.33 | 15.34 | ||||
Composite Average Revenue from Sales of Crude Oil and Condensate, | 48.05 | 50.52 | 42.24 | 34.99 | 38.05 | ||||
Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - | 14.04 | 14.45 | 13.69 | 12.99 | 13.67 | ||||
Composite Average Margin per Boe (excluding DD&A and Total Exploration | 34.01 | 36.07 | 28.55 | 22.00 | 24.38 | ||||
Total Operating Cost per Boe (excluding Total Exploration Costs) - (h) / (a) | 23.84 | 24.26 | 23.27 | 22.52 | 23.44 | ||||
Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) | 24.21 | 26.26 | 18.97 | 12.47 | 14.61 | ||||
Total Operating Cost per Boe (including Total Exploration Costs) - | 24.65 | 25.01 | 24.13 | 28.29 | 24.63 | ||||
Composite Average Margin per Boe (including Total Exploration | 23.40 | 25.51 | 18.11 | 6.70 | 13.42 | ||||
Per Barrel of Oil Equivalent (Boe) Calculations (Non-GAAP) | |||||||||
Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (g) / (a) | 14.04 | 14.45 | 13.69 | 12.93 | 13.10 | ||||
Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(e) | 34.01 | 36.07 | 28.55 | 22.06 | 24.95 | ||||
Total Operating Cost per Boe (excluding Total Exploration Costs) - (i) / (a) | 23.84 | 24.26 | 23.27 | 22.46 | 22.87 | ||||
Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) | 24.21 | 26.26 | 18.97 | 12.53 | 15.18 | ||||
Total Operating Cost per Boe (including Total Exploration Costs) - (k) / (a) | 24.65 | 25.01 | 24.13 | 23.21 | 24.06 | ||||
Composite Average Margin per Boe (including Total Exploration Costs) - [(e) | 23.40 | 25.51 | 18.11 | 11.78 | 13.99 | ||||
Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued) | |||||||||
In millions of USD, except Boe and per Boe amounts (Unaudited) | |||||||||
2025 | 2024 | 2023 | 2022 | 2021 | |||||
Volume - Million Barrels of Oil Equivalent - (a) | 449.8 | 388.7 | 359.4 | 331.5 | 302.5 | ||||
Total Operating Revenues and Other - (b) | 22,632 | 23,698 | 24,186 | 25,702 | 18,642 | ||||
Total Operating Expenses - (c) | 16,247 | 15,616 | 14,583 | 15,736 | 12,540 | ||||
Operating Income (Loss) - (d) | 6,385 | 8,082 | 9,603 | 9,966 | 6,102 | ||||
Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas | |||||||||
Crude Oil and Condensate | 12,501 | 13,921 | 13,748 | 16,367 | 11,125 | ||||
Natural Gas Liquids | 2,376 | 2,106 | 1,884 | 2,648 | 1,812 | ||||
Natural Gas | 2,791 | 1,551 | 1,744 | 3,781 | 2,444 | ||||
Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural | 17,668 | 17,578 | 17,376 | 22,796 | 15,381 | ||||
Operating Costs | |||||||||
Lease and Well | 1,675 | 1,572 | 1,454 | 1,331 | 1,135 | ||||
Gathering, Processing and Transportation Costs (1) | 2,134 | 1,722 | 1,620 | 1,587 | 1,422 | ||||
General and Administrative (GAAP) | 820 | 669 | 640 | 570 | 511 | ||||
Less: Certain Items (see Endnote 7 to Additional Key Financial | (88) | (10) | — | (16) | — | ||||
General and Administrative (Non-GAAP) (2) | 732 | 659 | 640 | 554 | 511 | ||||
Taxes Other Than Income (GAAP) | 1,234 | 1,249 | 1,284 | 1,585 | 1,047 | ||||
Add: Severance Tax Refund | — | 31 | — | 115 | — | ||||
Taxes Other Than Income (Non-GAAP) (3) | 1,234 | 1,280 | 1,284 | 1,700 | 1,047 | ||||
Interest Expense, Net | 235 | 138 | 148 | 179 | 178 | ||||
Less: Acquisition-Related Financing Commitment Costs | (6) | — | — | — | — | ||||
Interest Expense, Net (Non-GAAP) (4) | 229 | 138 | 148 | 179 | 178 | ||||
Total Operating Cost (GAAP) (excluding DD&A and Total Exploration Costs) - | 6,098 | 5,350 | 5,146 | 5,252 | 4,293 | ||||
Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration | 6,004 | 5,371 | 5,146 | 5,351 | 4,293 | ||||
Depreciation, Depletion and Amortization (DD&A) | 4,461 | 4,108 | 3,492 | 3,542 | 3,651 | ||||
Total Operating Cost (GAAP) (excluding Total Exploration Costs) - (h) | 10,559 | 9,458 | 8,638 | 8,794 | 7,944 | ||||
Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (i) | 10,465 | 9,479 | 8,638 | 8,893 | 7,944 | ||||
Exploration Costs | 236 | 174 | 181 | 159 | 154 | ||||
Dry Hole Costs | 49 | 14 | 1 | 45 | 71 | ||||
Impairments | 843 | 391 | 202 | 382 | 376 | ||||
Total Exploration Costs (GAAP) | 1,128 | 579 | 384 | 586 | 601 | ||||
Less: Certain Impairments (5) | (657) | (291) | (42) | (113) | (15) | ||||
Total Exploration Costs (Non-GAAP) | 471 | 288 | 342 | 473 | 586 | ||||
Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) - (j) | 11,687 | 10,037 | 9,022 | 9,380 | 8,545 | ||||
Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non- | 10,936 | 9,767 | 8,980 | 9,366 | 8,530 | ||||
Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural | 5,981 | 7,541 | 8,354 | 13,416 | 6,836 | ||||
Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural | 6,732 | 7,811 | 8,396 | 13,430 | 6,851 | ||||
Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued) | |||||||||
In millions of USD, except Boe and per Boe amounts (Unaudited) | |||||||||
2025 | 2024 | 2023 | 2022 | 2021 | |||||
Per Barrel of Oil Equivalent (Boe) Calculations (GAAP) | |||||||||
Composite Average Operating Revenues and Other per Boe - (b) / (a) | 50.32 | 60.97 | 67.30 | 77.53 | 61.63 | ||||
Composite Average Operating Expenses per Boe - (c) / (a) | 36.12 | 40.18 | 40.58 | 47.47 | 41.46 | ||||
Composite Average Operating Income (Loss) per Boe - (d) / (a) | 14.20 | 20.79 | 26.72 | 30.06 | 20.17 | ||||
Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, | 39.28 | 45.22 | 48.34 | 68.77 | 50.84 | ||||
Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (f) | 13.54 | 13.76 | 14.31 | 15.84 | 14.19 | ||||
Composite Average Margin per Boe (excluding DD&A and Total Exploration | 25.74 | 31.46 | 34.03 | 52.93 | 36.65 | ||||
Total Operating Cost per Boe (excluding Total Exploration Costs) - (h) / (a) | 23.46 | 24.33 | 24.03 | 26.53 | 26.26 | ||||
Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / | 15.82 | 20.89 | 24.31 | 42.24 | 24.58 | ||||
Total Operating Cost per Boe (including Total Exploration Costs) - (j) / (a) | 25.97 | 25.82 | 25.10 | 28.30 | 28.25 | ||||
Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / | 13.31 | 19.40 | 23.24 | 40.47 | 22.59 | ||||
Per Barrel of Oil Equivalent (Boe) Calculations (Non-GAAP) | |||||||||
Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - | 13.34 | 13.82 | 14.31 | 16.14 | 14.19 | ||||
Composite Average Margin per Boe (excluding DD&A and Total Exploration | 25.94 | 31.40 | 34.03 | 52.63 | 36.65 | ||||
Total Operating Cost per Boe (excluding Total Exploration Costs) - (i) / (a) | 23.26 | 24.39 | 24.03 | 26.83 | 26.26 | ||||
Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / | 16.02 | 20.83 | 24.31 | 41.94 | 24.58 | ||||
Total Operating Cost per Boe (including Total Exploration Costs) - (k) / (a) | 24.31 | 25.13 | 24.98 | 28.26 | 28.20 | ||||
Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / | 14.97 | 20.09 | 23.36 | 40.51 | 22.64 | ||||
(1) | Effective January 1, 2024, EOG combined Transportation Costs and Gathering and Processing Costs into one line item titled Gathering, Processing and Transportation Costs. This presentation has been conformed for all periods presented and had no impact on previously reported Net Income. |
(2) | EOG believes excluding the above-referenced items from General and Administrative Costs is appropriate and provides useful information to investors, as EOG views such items as non-recurring. |
(3) | EOG believes excluding the above-referenced items from Taxes Other Than Income is appropriate and provides useful information to investors, as EOG views such items as non-recurring. |
(4) | EOG believes excluding the above-referenced items from Interest Expense, Net is appropriate and provides useful information to investors, as EOG views such items as non-recurring. |
(5) | In general, EOG excludes impairments which are (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG's oil and gas properties or other assets). EOG believes excluding these impairments from total exploration costs is appropriate and provides useful information to investors, as such impairments were caused by factors outside of EOG's control (versus, for example, impairments that are due to EOG's proved oil and gas properties not being as productive as it originally estimated). |
Additional Key Financial Information | |||||||||
(Unaudited) | |||||||||
See "Endnotes" below for related discussion and definitions. | 2025 Actual | 2024 Actual | 2023 Actual | 2022 Actual | 2021 Actual | ||||
Crude Oil and Condensate Volumes (MBod) | |||||||||
United States | 520.5 | 490.6 | 475.2 | 460.7 | 443.4 | ||||
Trinidad | 1.4 | 0.8 | 0.6 | 0.6 | 1.5 | ||||
Other International | — | — | — | — | 0.1 | ||||
Total | 521.9 | 491.4 | 475.8 | 461.3 | 445.0 | ||||
Natural Gas Liquids Volumes (MBbld) | |||||||||
Total | 288.2 | 245.9 | 223.8 | 197.7 | 144.5 | ||||
Natural Gas Volumes (MMcfd) | |||||||||
United States | 2,299 | 1,728 | 1,551 | 1,315 | 1,210 | ||||
Trinidad | 230 | 220 | 160 | 180 | 217 | ||||
Other International1 | 4 | — | — | — | 9 | ||||
Total | 2,533 | 1,948 | 1,711 | 1,495 | 1,436 | ||||
Crude Oil Equivalent Volumes (MBoed) | |||||||||
United States | 1,191.8 | 1,024.5 | 957.5 | 877.5 | 789.6 | ||||
Trinidad | 39.8 | 37.6 | 27.3 | 30.7 | 37.7 | ||||
Other International | 0.6 | — | — | — | 1.6 | ||||
Total | 1,232.2 | 1,062.1 | 984.8 | 908.2 | 828.9 | ||||
Benchmark Price | |||||||||
Oil (WTI) ($/Bbl) | 64.78 | 75.72 | 77.61 | 94.23 | 67.96 | ||||
Natural Gas (HH) ($/Mcf) | 3.43 | 2.27 | 2.74 | 6.64 | 3.85 | ||||
Crude Oil and Condensate - above (below) WTI2 ($/Bbl) | |||||||||
United States | 0.87 | 1.70 | 1.57 | 2.99 | 0.58 | ||||
Trinidad | (7.19) | (11.29) | (9.03) | (8.07) | (11.70) | ||||
Other International | 0.36 | — | — | — | — | ||||
Natural Gas Liquids - Realizations as % of WTI | |||||||||
Total | 34.9 % | 30.9 % | 29.7 % | 39.0 % | 50.5 % | ||||
Natural Gas - above (below) NYMEX Henry Hub3 ($/Mcf) | |||||||||
United States | (0.49) | (0.28) | (0.04) | 0.63 | 1.03 | ||||
Natural Gas Realizations4 ($/Mcf) | |||||||||
Trinidad | 3.78 | 3.65 | 3.65 | 4.43 | 3.40 | ||||
Other International1 | 3.28 | — | — | — | — | ||||
Total Expenditures (GAAP) ($MM) | 13,703 | 6,653 | 6,818 | 5,610 | 4,255 | ||||
Capital Expenditures5 (Non-GAAP) ($MM) | 6,294 | 6,226 | 6,041 | 4,607 | 3,755 | ||||
Operating Unit Costs ($/Boe) | |||||||||
Lease and Well | 3.72 | 4.04 | 4.05 | 4.02 | 3.75 | ||||
Gathering, Processing and Transportation Costs6 | 4.74 | 4.43 | 4.50 | 4.78 | 4.70 | ||||
General and Administrative (GAAP) | 1.82 | 1.72 | 1.78 | 1.72 | 1.69 | ||||
General and Administrative (Non-GAAP)7 | 1.63 | 1.70 | 1.78 | 1.67 | 1.69 | ||||
Cash Operating Costs (GAAP) | 10.28 | 10.19 | 10.33 | 10.52 | 10.14 | ||||
Cash Operating Costs (Non-GAAP)7 | 10.09 | 10.17 | 10.33 | 10.47 | 10.14 | ||||
Depreciation, Depletion and Amortization | 9.92 | 10.57 | 9.72 | 10.69 | 12.07 | ||||
Expenses ($MM) | |||||||||
Exploration and Dry Hole | 285 | 188 | 182 | 204 | 225 | ||||
Impairment (GAAP) | 843 | 391 | 202 | 382 | 376 | ||||
Impairment (excluding certain impairments (Non-GAAP))8 | 186 | 100 | 160 | 269 | 361 | ||||
Capitalized Interest | 86 | 45 | 33 | 36 | 33 | ||||
Net Interest | 235 | 138 | 148 | 179 | 178 | ||||
Net Interest (Non-GAAP)9 | 229 | — | — | — | — | ||||
TOTI (% of revenues from sales of crude oil and condensate, NGLs | |||||||||
(GAAP) | 7.0 % | 7.1 % | 7.4 % | 7.0 % | 6.8 % | ||||
(Non-GAAP)7 | 7.0 % | 7.3 % | 7.4 % | 7.5 % | 6.8 % | ||||
Income Taxes | |||||||||
Effective Rate | 21.7 % | 22.1 % | 21.6 % | 21.7 % | 21.4 % | ||||
Current Tax Expense ($MM) | 1,039 | 1,348 | 1,415 | 2,208 | 1,393 | ||||
Additional Key Financial Information | |
(Continued) | |
Endnotes | |
(1) | 2025 volumes are from Bahrain operations; natural gas realized price represents contract price less partner's processing and distribution costs. |
(2) | EOG bases United States, Trinidad and Other International crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the daily settlement prices for the prompt-month NYMEX futures contract for each of the applicable calendar months. |
(3) | EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the NYMEX Last Day Settle price for each of the applicable months. |
(4) | The full-year 2022 realized natural gas price for Trinidad includes a one-time pricing adjustment of $0.76/Mcf for prior-period production following a contract amendment with the National Gas Company of Trinidad and Tobago Limited. |
(5) | Capital Expenditures include expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Dry Hole Costs and Other Property, Plant and Equipment. Capital Expenditures exclude Property Acquisitions, Asset Retirement Costs, Non-Cash Exchanges and Transactions and exploration costs incurred as operating expenses. |
(6) | Effective January 1, 2024, EOG combined Transportation Costs and Gathering and Processing Costs into one line item titled Gathering, Processing and Transportation Costs. This presentation has been conformed for all periods presented and had no impact on previously reported Net Income. |
(7) | Cash Operating Costs consist of LOE, GP&T and G&A. G&A (Non-GAAP) for fiscal year 2025 excludes costs related to the Encino acquisition, as reflected in the accompanying reconciliation schedules (see "Revenues, Costs and Margins Per Barrel of Oil Equivalent"). In addition, TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas) (Non-GAAP) and G&A (Non-GAAP) for fiscal year 2024 and fiscal year 2022 exclude a state severance tax refund and related consulting fees, respectively, as reflected in the accompanying reconciliation schedules (see "Revenues, Costs and Margins Per Barrel of Oil Equivalent"). The per-Boe impact of such acquisition-related costs and consulting fees on G&A and total Cash Operating Costs for fiscal year 2025, 2024 and 2022 was $(0.19), $(0.02) and $(0.05), respectively. |
(8) | In general, EOG excludes impairments which are (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG's oil and gas properties or other assets). EOG believes excluding these impairments from total impairment costs is appropriate and provides useful information to investors, as such impairments were caused by factors outside of EOG's control (versus, for example, impairments that are due to EOG's proved oil and gas properties not being as productive as it originally estimated). Impairments (Non-GAAP) for FY 2025 are adjusted from Impairments (GAAP) for FY 2025 by excluding $657 million of impairments, primarily associated with the write-down to fair value of natural gas and crude oil assets in the Barnett Shale and Woodford Oil Window (mainly driven by play-specific economics and resource allocation). Impairments (Non-GAAP) for FY 2024 are adjusted from Impairments (GAAP) for FY 2024 by excluding $291 million of impairments, primarily associated with the write-down to fair value of natural gas and crude oil assets in the Rocky Mountain area. |
(9) | Net Interest for fiscal year 2025 excludes financing commitment costs related to the Encino acquisition, as reflected in the accompanying reconciliation schedules (see "Revenues, Costs and Margins Per Barrel of Oil Equivalent"). The per-Boe impact of such cost for fiscal year 2025 is $(0.01). |
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SOURCE EOG Resources, Inc.
