HOUSTON, Aug. 4, 2026 /PRNewswire/ -- EOG Resources, Inc. (EOG) today reported second 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.
Second Quarter Highlights
- Earned net income of $2.72 billion, or $5.15 per share, and adjusted net income of $2.68 billion, or $5.07 per share
- Delivered net cash provided by operating activities of $4.7 billion and adjusted CFO1 of $4.4 billion
- Generated $2.8 billion of free cash flow
- Declared regular quarterly dividend of $1.02 per share
- Paid $540 million in regular dividends and repurchased $1.3 billion of shares
- Quarterly oil volumes of 548.8 MBod and total volumes of 1,410.4 MBoed
- Delivered lease & well and gathering, processing & transportation costs better than guidance midpoints
- Established UAE oil production with successful initial test
CEO Commentary
"EOG delivered outstanding second quarter results, including record financial performance. Strong operational execution highlighted by LOE and GP&T costs below guidance midpoints coupled with higher oil prices drove this robust financial performance. In the second quarter, we generated $2.8 billion of free cash flow and returned $1.8 billion to shareholders through our regular dividend and share repurchases. Our cash return reflects the significant cash generation capacity of our business, the strength of our balance sheet, and confidence in our ability to drive further value creation.
We are well positioned to capture opportunities across commodity cycles. Our diversified asset portfolio spans oil, NGLs, and natural gas across unconventional and conventional resources, which we continue to strengthen through organic exploration. On that front, during the quarter, we established UAE oil production with successful test results from two one-mile lateral wells that averaged over 25,000 barrels of cumulative oil production per well for the first 30 days.
Our operating model maximizes the value of our low-cost, high-return inventory across multiple basins. Vertical integration and in-house technology support repeatable cost discipline, and our pricing exposure to premium markets drives strong realizations. Most importantly, our core competitive advantage, the unique EOG culture, allows our employees to innovate and operate at a high level, supporting efficient operations and long-term returns.
We executed strongly in the first half of 2026 and enter the second half with positive momentum. Based on current guidance, we expect to deliver 5% oil production growth and 14% total production growth this year. At the current forward strip, this performance is expected to drive substantial free cash flow for the full-year 2026, supporting opportunistic and disciplined cash returns to shareholders. We remain focused on sustainable value creation through industry cycles by being among the highest return and lowest cost producers."
Return of Capital
The Board of Directors today declared a regular dividend of $1.02 per share on EOG's common stock. The regular dividend will be payable October 30, 2026, to stockholders of record as of October 16, 2026. The indicated annual rate is $4.08 per share.
During the second quarter, the company repurchased 9.6 million shares for $1,294 million under its share repurchase authorization, at an average purchase price of $135 per share. As of June 30, 2026, EOG had $11.7 billion remaining on its current repurchase authorization.
Key Financial Results
In millions of USD, except per-share, per-Boe and ratio data
GAAP 2Q 2026 1Q 2026 4Q 2025 3Q 2025 2Q 2025
Total Revenue 8,620 6,921 5,638 5,847 5,478
Net Income 2,724 1,980 701 1,471 1,345
Net Income Per Share 5.15 3.70 1.30 2.70 2.46
Net Cash Provided by Operating Activities 4,669 2,966 2,612 3,111 2,032
Total Expenditures 1,919 1,768 1,730 8,544 1,883
Current and Long-Term Debt 7,926 7,931 7,936 7,694 4,236
Cash and Cash Equivalents 4,907 3,849 3,396 3,530 5,216
Debt-to-Total Capitalization 19.9 % 20.4 % 21.0 % 20.3 % 12.7 %
Cash Operating Costs ($/Boe) 10.57 10.45 10.28 10.50 10.05
Non-GAAP
Adjusted Net Income 2,683 1,825 1,222 1,472 1,268
Adjusted Net Income Per Share 5.07 3.41 2.27 2.71 2.32
Adjusted CFO1 4,386 3,129 2,617 3,031 2,496
Capital Expenditures 1,587 1,636 1,639 1,648 1,523
Free Cash Flow 2,799 1,493 978 1,383 973
Net Debt 3,019 4,082 4,540 4,164 (980)
Net Debt-to-Total Capitalization 8.7 % 11.7 % 13.2 % 12.1 % (3.5 %)
Cash Operating Costs ($/Boe)2 10.57 10.45 10.22 9.93 9.94
Key Operational Results
Volumes 2Q 2026 1Q 2026 4Q 2025 3Q 2025 2Q 2025
Crude Oil and Condensate (MBod) 548.8 548.5 546.1 534.5 504.2
Natural Gas Liquids (MBbld) 346.8 332.1 342.1 309.3 258.4
Natural Gas (MMcfd) 3,089 3,020 3,065 2,745 2,229
Total Crude Oil Equivalent (MBoed) 1,410.4 1,383.8 1,399.0 1,301.2 1,134.1
Cash Operating Costs ($/Boe)
Lease & Well 3.64 3.71 3.47 3.60 3.84
Gathering, Processing & Transportation Costs 5.27 5.25 5.07 4.90 4.41
General & Administrative (GAAP) 1.66 1.49 1.74 2.00 1.80
General & Administrative (Non-GAAP)2 1.66 1.49 1.68 1.43 1.69
Cash Operating Costs (GAAP) 10.57 10.45 10.28 10.50 10.05
Cash Operating Costs (Non-GAAP)2 10.57 10.45 10.22 9.93 9.94
Depreciation, Depletion & Amortization ($/Boe) 9.81 9.58 9.53 9.77 10.20
Second Quarter 2026 Results vs Guidance
(Unaudited) 2Q 2026 2Q 2026 Variance 1Q 2026 4Q 2025 3Q 2025 2Q 2025
Guidance
Midpoint
4
Crude Oil and Condensate Volumes (MBod)
United States 546.2 546.5 (0.3) 546.5 544.5 532.9 503.1
Trinidad 2.1 2.0 0.1 1.9 1.5 1.6 1.1
Other International5 0.5 0.1 0.1 0.0 0.0
Total 548.8 548.5 0.3 548.5 546.1 534.5 504.2
Natural Gas Liquids Volumes (MBbld)
Total 346.8 337.0 9.8 332.1 342.1 309.3 258.4
Natural Gas Volumes (MMcfd)
United States 2,784 2,785 (1) 2,769 2,859 2,511 1,977
Trinidad 293 250 43 239 195 230 252
Other International5 12 12 11 4 0
Total 3,089 3,035 54 3,020 3,065 2,745 2,229
Total Crude Oil Equivalent Volumes (MBoed) 1,410.4 1,391.4 19.0 1,383.8 1,399.0 1,301.2 1,134.1
Total MMBoe 128.3 126.6 1.7 124.5 128.7 119.7 103.2
Benchmark Price
Oil (WTI) ($/Bbl) 92.85 72.17 59.17 64.95 63.71
Natural Gas (HH) ($/Mcf) 2.89 4.96 3.55 3.07 3.44
Crude Oil and Condensate -above (below) WTI
6
($/Bbl)
United States 5.33 5.75 (0.42) 0.31 0.37 1.02 1.13
Trinidad (3.98) (1.00) (2.98) (3.26) (2.10) (7.21) (9.21)
Other International 10.55 16.95 4.81 0.00 0.00
Natural Gas Liquids - Realizations as % of WTI
Total 26.3 % 27.0 % (0.7 %) 30.8 % 35.7 % 32.7 % 35.6 %
Natural Gas -above (below) NYMEX Henry Hub
7
($/Mcf)
United States (0.12) (0.15) 0.03 (1.21) (0.61) (0.36) (0.57)
Natural Gas Realizations ($/Mcf)
Trinidad 3.99 3.75 0.24 3.91 3.94 3.80 3.65
Other International5 3.27 3.26 3.29 3.27 0.00
Total Expenditures (GAAP) ($MM) 1,919 1,768 1,730 8,544 1,883
Capital Expenditures (Non-GAAP) ($MM) 1,587 1,625 (38) 1,636 1,639 1,648 1,523
Operating Unit Costs ($/Boe)
Lease and Well 3.64 3.70 (0.06) 3.71 3.47 3.60 3.84
Gathering, Processing and Transportation Costs 5.27 5.30 (0.03) 5.25 5.07 4.90 4.41
General & Administrative (GAAP) 1.66 1.49 1.74 2.00 1.80
General & Administrative (Non-GAAP)(2) 1.66 1.50 0.16 1.49 1.68 1.43 1.69
Cash Operating Costs (GAAP) 10.57 10.45 10.28 10.50 10.05
Cash Operating Costs (Non-GAAP)(2) 10.57 10.50 0.07 10.45 10.22 9.93 9.94
Depreciation, Depletion and Amortization 9.81 9.70 0.11 9.58 9.53 9.77 10.20
Expenses ($MM)
Exploration and Dry Hole 77 65 12 68 54 71 85
Impairment (GAAP) 19 39 689 71 39
Impairment (excluding certain impairments (Non-GAAP))8 19 80 (61) 39 43 71 28
Capitalized Interest 38 37 1 37 36 27 11
Net Interest (GAAP) 67 66 66 71 51
Net Interest (Non-GAAP)9 67 68 (1) 66 66 71 45
TOTI (% of revenues from sales of crude oil and
condensate, NGLs and natural gas)
(GAAP) 6.6 % 6.4 % 6.3 % 6.8 % 7.3 %
(Non-GAAP) 6.6 % 7.0 % (0.4 %) 6.4 % 6.3 % 6.8 % 7.3 %
Income Taxes
Effective Rate 22.1 % 22.5 % (0.4 %) 22.5 % 22.8 % 19.4 % 23.2 %
Current Tax Expense ($MM) 429 575 (146) 557 293 75 301
Third Quarter and Full-Year 2026 Guidance
10
3Q 2026 3Q 2026 FY 2026 FY 2026
(Unaudited) Guidance Range Midpoint Guidance Range Midpoint
Crude Oil and Condensate Volumes (MBod)
United States 544.5 549.1 546.8 544.8 549.2 547.0
Trinidad 1.5 1.9 1.7 1.5 1.9 1.7
Total 546.0 551.0 548.5 546.3 551.1 548.7
Natural Gas Liquids Volumes (MBbld)
Total 337.0 357.0 347.0 332.0 352.0 342.0
Natural Gas Volumes (MMcfd)
United States 2,800 2,900 2,850 2,760 2,860 2,810
Trinidad 240 260 250 240 260 250
Total 3,040 3,160 3,100 3,000 3,120 3,060
Crude Oil Equivalent Volumes (MBoed)
United States 1,348.2 1,389.4 1,368.8 1,336.8 1,377.9 1,357.3
Trinidad 41.5 45.2 43.4 41.5 45.2 43.4
Total 1,389.7 1,434.7 1,412.2 1,378.3 1,423.1 1,400.7
Crude Oil and Condensate -above (below) WTI
6
($/Bbl)
United States 0.90 2.40 1.65 1.25 3.25 2.25
Trinidad (3.35) (1.85) (2.60) (3.40) (1.40) (2.40)
Natural Gas Liquids - Realizations as % of WTI
Total 23.0 % - 33.0% 28.0 % 23.0 % - 33.0% 28.0 %
Natural Gas - above (below) NYMEX Henry Hub
7
($/Mcf)
United States 0.15 0.85 0.50 (1.10) 0.90 (0.10)
Natural Gas Realizations ($/Mcf)
Trinidad 3.45 4.15 3.80 3.25 4.25 3.75
Capital Expenditures
11
($MM) 1,600 1,700 1,650 6,300 6,700 6,500
Operating Unit Costs ($/Boe)
Lease and Well 3.55 4.05 3.80 3.55 4.05 3.80
Gathering, Processing and Transportation Costs 5.15 5.65 5.40 5.10 5.60 5.35
General & Administrative 1.35 1.65 1.50 1.40 1.70 1.55
Cash Operating Costs 10.05 11.35 10.70 10.05 11.35 10.70
Depreciation, Depletion and Amortization 9.50 10.50 10.00 9.40 10.40 9.90
Expenses ($MM)
Exploration and Dry Hole 45 85 65 235 275 255
Impairment (excluding certain impairments)8 70 150 110 190 370 280
Capitalized Interest 36 40 38 147 151 149
Net Interest 64 68 66 267 271 269
TOTI (% of revenues from sales of crude oil and 5.8 % 7.8 % 6.8 % 5.8 % 7.8 % 6.8 %
condensate, NGLs and natural gas)
Income Taxes
Effective Rate 20.0 % 25.0 % 22.5 % 20.0 % 25.0 % 22.5 %
Current Tax Expense ($MM) 545 645 595 2,015 2,215 2,115
Second Quarter 2026 Results Webcast
Wednesday, August 5, 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, $68 million
for 3Q 2025 and $12 million for 2Q 2025, as reflected in the accompanying reconciliation schedules (see "Revenues, Costs and Margins Per Barrel of Oil
Equivalent"). The per-Boe impact of such Encino acquisition-related costs on G&A and total Cash Operating Costs for 4Q 2025 was ($0.06), for 3Q 2025
was ($0.57) and for 2Q 2025 was ($0.11) as set forth in "Second 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 second 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)
Net interest expense (Non-GAAP) excludes Encino acquisition-related financing commitment costs of $6 million in 2Q 2025.
10) The forecast items for the third quarter and full year 2026 set forth above for EOG are based on currently available information and expectations as of
the date of this press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a
result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in
conjunction with this press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or
forecast.
11) The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Dry Hole Costs and
Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs, Non-Cash Exchanges and Transactions and
exploration costs incurred as operating expenses.
Cautionary Notice
This press release and any accompanying disclosures may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, goals, returns and rates of return, budgets, reserves, levels of production, capital expenditures, operating costs and asset sales, statements regarding future commodity prices, 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 8,478
Natural Gas Liquids 572 534 604 666 2,376 664 770 1,434
Natural Gas 637 600 707 847 2,791 1,021 812 1,833
Gains (Losses) on Mark-to-Market (191) 107 116 (19) 13 113 40 153
Financial Commodity and Other
Derivative Contracts, Net
Gathering, Processing and Marketing 1,340 1,247 1,178 1,149 4,914 1,496 2,011 3,507
Gains (Losses) on Asset Dispositions, (1) (18) (16) (35) 31 58 89
Net
Other, Net 19 16 17 20 72 19 28 47
Total 5,669 5,478 5,847 5,638 22,632 6,921 8,620 15,541
Operating Expenses
Lease and Well 401 396 431 447 1,675 462 467 929
Gathering, Processing and 440 455 587 652 2,134 654 676 1,330
Transportation Costs
Exploration Costs 41 74 71 50 236 45 47 92
Dry Hole Costs 34 11 4 49 23 30 53
Impairments 44 39 71 689 843 39 19 58
Marketing Costs 1,325 1,216 1,134 1,120 4,795 1,384 1,950 3,334
Depreciation, Depletion and 1,013 1,053 1,169 1,226 4,461 1,193 1,259 2,452
Amortization
General and Administrative 171 186 239 224 820 185 213 398
Taxes Other Than Income 341 301 309 283 1,234 338 431 769
Total 3,810 3,731 4,011 4,695 16,247 4,323 5,092 9,415
Operating Income 1,859 1,747 1,836 943 6,385 2,598 3,528 6,126
Other Income, Net 65 55 59 33 212 23 38 61
Income Before Interest Expense and 1,924 1,802 1,895 976 6,597 2,621 3,566 6,187
Income Taxes
Interest Expense, Net 47 51 71 66 235 66 67 133
Income Before Income Taxes 1,877 1,751 1,824 910 6,362 2,555 3,499 6,054
Income Tax Provision 414 406 353 209 1,382 575 775 1,350
Net Income 1,463 1,345 1,471 701 4,980 1,980 2,724 4,704
Dividends Declared per Common Share 0.9750 1.9950 1.0200 3.9900 1.0200 1.0200 2.0400
Net Income Per Share
Basic 2.66 2.48 2.72 1.31 9.17 3.72 5.18 8.89
Diluted 2.65 2.46 2.70 1.30 9.12 3.70 5.15 8.84
Average Number of Common Shares
Basic 550 543 541 537 543 532 526 529
Diluted 553 546 544 539 546 535 529 532
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 (MBbld) (A)
United States 500.9 503.1 532.9 544.5 520.5 546.5 546.2 546.3
Trinidad 1.2 1.1 1.6 1.5 1.4 1.9 2.1 2.0
Other International (B) - 0.1 0.1 0.5 0.3
Total 502.1 504.2 534.5 546.1 521.9 548.5 548.8 548.6
Average Crude Oil and Condensate Prices
($/Bbl) (C)
United States $72.90 $64.84 $65.97 $59.54 $65.65 $72.48 $98.18 $85.40
Trinidad 61.12 54.50 57.74 57.07 57.59 68.91 88.87 79.20
Other International - 63.98 89.12 103.40 101.81
Composite 72.87 64.82 65.95 59.54 65.63 72.47 98.15 85.38
Natural Gas Liquids Volumes (MBbld) (A)
United States 241.7 258.4 309.3 342.1 288.2 332.1 346.8 339.5
Total 241.7 258.4 309.3 342.1 288.2 332.1 346.8 339.5
Average Natural Gas Liquids Prices ($/Bbl) (C)
United States $26.29 $22.70 $21.25 $21.15 $22.58 $22.20 $24.41 $23.34
Composite 26.29 22.70 21.25 21.15 22.58 22.20 24.41 23.34
Natural Gas Volumes (MMcfd) (A)
United States 1,834 1,977 2,511 2,859 2,299 2,769 2,784 2,777
Trinidad 246 252 230 195 230 239 293 266
Other International (B) - 4 11 4 12 12 12
Total 2,080 2,229 2,745 3,065 2,533 3,020 3,089 3,055
Average Natural Gas Prices ($/Mcf) (C)
United States $3.36 $2.87 $2.71 $2.94 $2.94 $3.75 $2.77 $3.25
Trinidad 3.78 3.65 3.80 3.94 3.78 3.91 3.99 3.95
Other International (B) - 3.27 3.29 3.28 3.26 3.27 3.27
Composite 3.41 2.96 2.80 3.00 3.02 3.76 2.89 3.32
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 1,348.6
Trinidad 42.1 43.2 39.8 34.2 39.8 41.7 50.9 46.4
Other International - 0.7 1.8 0.6 2.0 2.4 2.2
Total 1,090.4 1,134.1 1,301.2 1,399.0 1,232.2 1,383.8 1,410.4 1,397.2
Total MMBoe (D) 98.1 103.2 119.7 128.7 449.8 124.5 128.3 252.9
(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 June 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
Accounts Receivable, Net 2,621 2,504 2,680 2,681 3,597 3,529
Inventories 897 934 945 1,014 955 930
Other (A) 563 591 665 565 562 511
Total 10,680 9,245 7,820 7,656 8,963 9,877
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method) 78,432 80,139 88,301 89,857 90,786 92,454
Other Property, Plant and Equipment 6,510 6,616 6,772 6,832 6,942 7,064
Total Property, Plant and Equipment 84,942 86,755 95,073 96,689 97,728 99,518
Less: Accumulated Depreciation, Depletion and (50,310) (51,394) (52,488) (54,348) (55,054) (56,278)
Amortization
Total Property, Plant and Equipment, Net 34,632 35,361 42,585 42,341 42,674 43,240
Deferred Income Taxes 44 39 37 39 30 35
Other Assets 1,626 1,639 1,757 1,763 1,711 1,631
Total Assets 46,982 46,284 52,199 51,799 53,378 54,783
Current Liabilities
Accounts Payable 2,353 2,266 2,944 2,904 3,186 3,374
Accrued Taxes Payable 668 348 392 299 766 697
Dividends Payable 534 1,081 550 544 541 531
Current Portion of Long-Term Debt 1,280 778 27 27 27 27
Current Portion of Operating Lease Liabilities 318 360 433 472 375 324
Other (A) 566 342 469 445 329 382
Total 5,719 5,175 4,815 4,691 5,224 5,335
Long-Term Debt 3,464 3,458 7,667 7,909 7,904 7,899
Other Liabilities 2,368 2,398 2,496 2,512 2,476 2,468
Deferred Income Taxes 5,915 6,015 6,936 6,854 6,866 7,217
Commitments and Contingencies (B)
Stockholders' Equity
Common Stock, $0.01 Par 206 206 206 206 206 206
Additional Paid in Capital 6,095 6,153 5,978 6,027 6,026 6,072
Accumulated Other Comprehensive Loss (4) (7) (5) (7) (6) (5)
Retained Earnings 27,869 28,131 29,603 29,765 31,200 33,390
Common Stock Held in Treasury (4,650) (5,245) (5,497) (6,158) (6,518) (7,799)
Total Stockholders' Equity 29,516 29,238 30,285 29,833 30,908 31,864
Total Liabilities and Stockholders' Equity 46,982 46,284 52,199 51,799 53,378 54,783
(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's 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 June 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
Provided by Operating Activities:
Net Income 1,463 1,345 1,471 701 4,980 1,980 2,724 4,704
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization 1,013 1,053 1,169 1,226 4,461 1,193 1,259 2,452
Impairments 44 39 71 689 843 39 19 58
Stock-Based Compensation Expenses 50 53 53 60 216 58 60 118
Deferred Income Taxes 44 105 278 (84) 343 18 346 364
(Gains) Losses on Asset Dispositions, Net 1 18 16 35 (31) (58) (89)
Other, Net 11 11 2 3 27 15 2 17
Dry Hole Costs 34 11 4 49 23 30 53
Mark-to-Market Financial Commodity and Other 191 (107) (116) 19 (13) (113) (40) (153)
Derivative Contracts (Gains) Losses, Net
Net Cash Received from (Payments for) (38) (24) 27 (21) (56) (53) 45 (8)
Settlements of Financial Commodity
Derivative Contracts
Other, Net (1) (1) (1) (1)
Changes in Components of Working Capital and
Other Assets and Liabilities
Accounts Receivable 48 122 133 (3) 300 (907) 60 (847)
Inventories 76 (45) 4 (84) (49) 21 26 47
Accounts Payable (129) (107) 5 (40) (271) 279 176 455
Accrued Taxes Payable (339) (321) 28 (103) (735) 467 (69) 398
Other Assets (43) (43) (28) 97 (17) 55 47 102
Other Liabilities (96) (52) 155 10 17 (123) 37 (86)
Changes in Components of Working Capital (41) (8) (159) 123 (85) 45 6 51
Associated with Investing Activities
Net Cash Provided by Operating Activities 2,289 2,032 3,111 2,612 10,044 2,966 4,669 7,635
Investing Cash Flows
Acquisition of Encino Acquisition Partners, LLC, (4,464) 13 (4,451)
Net of Cash Acquired
Additions to Oil and Gas Properties (1,381) (1,699) (1,492) (1,543) (6,115) (1,491) (1,638) (3,129)
Additions to Other Property, Plant and Equipment (102) (94) (171) (112) (479) (153) (144) (297)
Proceeds from Sales of Assets 12 4 5 3 24 144 7 151
Changes in Components of Working Capital 41 8 159 (123) 85 (45) (6) (51)
Associated with Investing Activities
Net Cash Used in Investing Activities (1,430) (1,781) (5,963) (1,762) (10,936) (1,545) (1,781) (3,326)
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) (1,084)
Treasury Stock Purchased (806) (602) (479) (677) (2,564) (418) (1,299) (1,717)
Proceeds from Stock Options Exercised and 11 12 23 1 15 16
Employee Stock Purchase Plan
Debt Issuance and Other Financing Costs (7) (7) (11) (25)
Repayment of Finance Lease Liabilities (8) (9) (8) (7) (32) (7) (6) (13)
Net Cash Used in Financing Activities (1,352) (1,635) 1,167 (984) (2,804) (968) (1,830) (2,798)
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 1,511
Cash and Cash Equivalents at Beginning of Period 7,092 6,599 5,216 3,530 7,092 3,396 3,849 3,396
Cash and Cash Equivalents at End of Period 6,599 5,216 3,530 3,396 3,396 3,849 4,907 4,907
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 contracts by eliminating the net unrealized mark-to-market (gains) losses from these and other derivative transactions, to eliminate the net (gains) losses on asset dispositions, to add back impairment charges
related to certain of EOG's assets (which are generally (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG's oil and gas properties or other assets)), to add back costs associated with the Encino acquisition and to make certain
other adjustments to exclude non-recurring and certain other items as further described below. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain
other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.
2Q 2026
Before Income Tax After Diluted
Tax Impact Tax Earnings per
Share
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.
Adjusted Net Income
(Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)
1Q 2026
Before Income After Diluted
Tax Tax Impact Tax Earnings per
Share
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.
4Q 2025
Before Income Tax After Diluted
Tax Impact Tax Earnings per
Share
Reported Net Income (GAAP) 910 (209) 701 1.30
Adjustments:
Losses on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net 19 (4) 15 0.03
Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1) (21) 4 (17) (0.03)
Add: Losses on Asset Dispositions, Net 16 (4) 12 0.02
Add: Certain Impairments (2) 646 (140) 506 0.94
Add: Acquisition-Related Costs (3) 8 (3) 5 0.01
Adjustments to Net Income 668 (147) 521 0.97
Adjusted Net Income (Non-GAAP) 1,578 (356) 1,222 2.27
Average Number of Common Shares
Basic 537
Diluted 539
(1) Consistent with its customary practice, in calculating Adjusted Net Income (Non-GAAP), EOG subtracts from reported Net Income (GAAP) the total net cash
paid for settlements of financial commodity derivative contracts during such period. For the three months ended December 31, 2025, such amount was $21
million.
(2) Impairments primarily associated with the write-down to fair value of natural gas and crude oil assets in the Barnett Shale and Woodford Oil Window
(mainly driven by play-specific economics and resource allocation).
(3)
Consists of Encino acquisition-related G&A costs ($8 million).
Adjusted Net Income
(Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)
3Q 2025
Before Income After Diluted
Tax Tax Impact Tax Earnings per
Share
Reported Net Income (GAAP) 1,824 (353) 1,471 2.70
Adjustments:
Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net (116) 25 (91) (0.16)
Net Cash Received from Settlements of Financial Commodity Derivative Contracts (1) 27 (5) 22 0.04
Add: Losses on Asset Dispositions, Net 18 (6) 12 0.02
Add: Acquisition-Related Costs (2) 68 (10) 58 0.11
Adjustments to Net Income (3) 4 1 0.01
Adjusted Net Income (Non-GAAP) 1,821 (349) 1,472 2.71
Average Number of Common Shares
Basic 541
Diluted 544
(1) Consistent with its customary practice, in calculating Adjusted Net Income (Non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash
received from settlements of financial commodity derivative contracts during such period. For the three months ended September 30, 2025, such amount was
$27 million.
(2)
Consists of Encino acquisition-related G&A costs ($68 million).
2Q 2025
Before Income Tax After Diluted
Tax Impact Tax Earnings per
Share
Reported Net Income (GAAP) 1,751 (406) 1,345 2.46
Adjustments:
Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net (107) 23 (84) (0.16)
Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1) (24) 5 (19) (0.03)
Add: Certain Impairments 11 11 0.02
Add: Acquisition-Related Costs (2) 18 (3) 15 0.03
Adjustments to Net Income (102) 25 (77) (0.14)
Adjusted Net Income (Non-GAAP) 1,649 (381) 1,268 2.32
Average Number of Common Shares
Basic 543
Diluted 546
(1) Consistent with its customary practice, in calculating Adjusted Net Income (Non-GAAP), EOG subtracts from reported Net Income (GAAP) the total net cash
paid for settlements of financial commodity derivative contracts during such period. For the three months ended June 30, 2025, such amount was $24
million.
(2)
Consists of Encino acquisition-related G&A costs ($12 million) and financing commitment costs ($6 million).
Adjusted Net Income
(Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)
FY 2025
Before Income Tax After Diluted
Tax Impact Tax Earnings per
Share
Reported Net Income (GAAP) 6,362 (1,382) 4,980 9.12
Adjustments:
Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net (13) 3 (10) (0.02)
Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1) (56) 12 (44) (0.08)
Add: Losses on Asset Dispositions, Net 35 (8) 27 0.05
Add: Certain Impairments (2) 657 (140) 517 0.95
Add: Acquisition-Related Costs (3) 94 (16) 78 0.14
Adjustments to Net Income 717 (149) 568 1.04
Adjusted Net Income (Non-GAAP) 7,079 (1,531) 5,548 10.16
Average Number of Common Shares
Basic 543
Diluted 546
(1) Consistent with its customary practice, in calculating Adjusted Net Income (Non-GAAP), EOG subtracts from reported Net Income (GAAP) the total net cash
paid for settlements of financial commodity derivative contracts during such period. For the twelve months ended December 31, 2025, such amount was $56
million.
(2) Impairments primarily associated with the write-down to fair value of natural gas and crude oil assets in the Barnett Shale and Woodford Oil Window
(mainly driven by play-specific economics and resource allocation).
(3)
Consists of Encino acquisition-related G&A costs ($88 million) and financing commitment costs ($6 million).
FY 2024
Before Income Tax After Diluted
Tax Impact Tax Earnings per
Share
Reported Net Income (GAAP) 8,218 (1,815) 6,403 11.25
Adjustments:
Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net (204) 44 (160) (0.28)
Net Cash Received from Settlements of Financial Commodity Derivative Contracts (1) 214 (46) 168 0.30
Less: Gains on Asset Dispositions, Net (16) 3 (13) (0.02)
Add: Certain Impairments (2) 291 (57) 234 0.41
Less: Severance Tax Refund (31) 7 (24) (0.04)
Add: Severance Tax Consulting Fees 10 (2) 8 0.01
Less: Interest on Severance Tax Refund (5) 1 (4) (0.01)
Adjustments to Net Income 259 (50) 209 0.37
Adjusted Net Income (Non-GAAP) 8,477 (1,865) 6,612 11.62
Average Number of Common Shares
Basic 566
Diluted 569
(1) Consistent with its customary practice, in calculating Adjusted Net Income (Non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash
received from settlements of financial commodity derivative contracts during such period. For the twelve months ended December 31, 2024, such amount was
$214 million.
(2)
Impairments primarily associated with the write-down to fair value of natural gas and crude oil assets in the Rocky Mountain area.
Net Income Per Share
In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)
1Q 2026 Net Income per Share (GAAP) - Diluted 3.70
Realized Prices
2Q 2026 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe 50.52
Less: 1Q 2026 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe (42.24)
Subtotal 8.28
Multiplied by: 2Q 2026 Crude Oil Equivalent Volumes (MMBoe) 128.3
Total Change in Revenue 1,062
Add: Income Tax Benefit (Provision) Imputed (based on 22%) (234)
Change in Net Income 828
Change in Diluted Earnings per Share 1.57
Volumes
2Q 2026 Crude Oil Equivalent Volumes (MMBoe) 128.3
Less: 1Q 2026 Crude Oil Equivalent Volumes (MMBoe) (124.5)
Subtotal 3.8
Multiplied by: 2Q 2026 Composite Average Margin per Boe (GAAP) (Including Total 25.51
Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule below)
Change in Margin 97
Less: Income Tax Benefit (Provision) Imputed (based on 22%) (21)
Change in Net Income 76
Change in Diluted Earnings per Share 0.14
Certain Operating Costs per Boe
1Q 2026 Total Cash Operating Costs (GAAP) and Total DD&A per Boe 20.03
Less: 2Q 2026 Total Cash Operating Costs (GAAP) and Total DD&A per Boe (20.38)
Subtotal (0.35)
Multiplied by: 2Q 2026 Crude Oil Equivalent Volumes (MMBoe) 128.3
Change in Before-Tax Net Income (45)
Add: Income Tax Benefit (Provision) Imputed (based on 22%) 10
Change in Net Income (35)
Change in Diluted Earnings per Share (0.07)
Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net
2Q 2026 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts 40
Less: Income Tax Benefit (Provision) (9)
After Tax - (a) 31
Less: 1Q 2026 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts 113
Less: Income Tax Benefit (Provision) (24)
After Tax - (b) 89
Change in Net Income - (a) - (b) (58)
Change in Diluted Earnings per Share (0.11)
Other (1) (0.08)
2Q 2026 Net Income per Share (GAAP) - Diluted 5.15
2Q 2026 Average Number of Common Shares - Diluted 529
(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)
1Q 2026 Adjusted Net Income per Share (Non-GAAP) - Diluted 3.41
Realized Prices
2Q 2026 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe 50.52
Less: 1Q 2026 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe (42.24)
Subtotal 8.28
Multiplied by: 2Q 2026 Crude Oil Equivalent Volumes (MMBoe) 128.3
Total Change in Revenue 1,062
Add: Income Tax Benefit (Provision) Imputed (based on 22%) (234)
Change in Net Income 828
Change in Diluted Earnings per Share 1.57
Volumes
2Q 2026 Crude Oil Equivalent Volumes (MMBoe) 128.3
Less: 1Q 2026 Crude Oil Equivalent Volumes (MMBoe) (124.5)
Subtotal 3.8
Multiplied by: 2Q 2026 Composite Average Margin per Boe (Non-GAAP) (Including Total Exploration Costs) (refer to 25.51
"Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule below)
Change in Margin 97
Less: Income Tax Benefit (Provision) Imputed (based on 22%) (21)
Change in Net Income 76
Change in Diluted Earnings per Share 0.14
Certain Operating Costs per Boe
1Q 2026 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe 20.03
Less: 2Q 2026 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe (20.38)
Subtotal (0.35)
Multiplied by: 2Q 2026 Crude Oil Equivalent Volumes (MMBoe) 128.3
Change in Before-Tax Net Income (45)
Add: Income Tax Benefit (Provision) Imputed (based on 22%) 10
Change in Net Income (35)
Change in Diluted Earnings per Share (0.07)
Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts
2Q 2026 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts 45
Less: Income Tax Benefit (Provision) (9)
After Tax - (a) 36
Less: 1Q 2026 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts (53)
Less: Income Tax Benefit (Provision) 11
After Tax - (b) (42)
Change in Net Income - (a) - (b) 78
Change in Diluted Earnings per Share 0.15
Other (1) (0.13)
2Q 2026 Adjusted Net Income per Share (Non-GAAP) 5.07
2Q 2026 Average Number of Common Shares - Diluted 529
(1) Includes gathering, processing and marketing revenue, other revenue, exploration costs, dry hole costs, impairments, marketing costs, taxes other than
income, other income (expense), interest expense, the impact of changes in the effective income tax rate and the impact of share repurchases on diluted
shares.
Cash Flow from Operations and Free Cash Flow
In millions of USD (Unaudited)
The following tables reconcile Net Cash Provided by Operating Activities (GAAP) to Adjusted Cash Flow from Operations (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Changes in Components of Working Capital and Other Assets and Liabilities,
Changes in Components of Working Capital Associated with Investing Activities (or Investing and Financing Activities, as applicable) and certain other adjustments to exclude certain non-recurring items and other items as further described below. EOG defines Free Cash Flow (Non-GAAP) for a given period as Adjusted Cash Flow from Operations (Non-GAAP) (see below
reconciliation) for such period less the Total Capital Expenditures (Non-GAAP) (see below reconciliation) during such period, as is illustrated below. EOG management uses this information for comparative purposes within the industry. As indicated in the tables below, EOG is (1) in addition to its customary working capital-related adjustments, adjusting Net Cash Provided
by Operating Activities (GAAP) to add back certain non-recurring acquisition-related costs incurred during the second, third and fourth quarters of 2025 and (2) now presenting such adjusted measure as "Adjusted Cash Flow from Operations (Non-GAAP)" (instead of "Cash Flow from Operations Before Changes in Working Capital (Non-GAAP)" as reported in prior periods); the
presentation below with respect to the second, third and fourth quarters of 2025 and the prior periods shown has been conformed.
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 7,635
Adjustments:
Changes in Components of Working Capital
and Other Assets and Liabilities
Accounts Receivable (48) (122) (133) 3 (300) 907 (60) 847
Inventories (76) 45 (4) 84 49 (21) (26) (47)
Accounts Payable 129 107 (5) 40 271 (279) (176) (455)
Accrued Taxes Payable 339 321 (28) 103 735 (467) 69 (398)
Other Assets 43 43 28 (97) 17 (55) (47) (102)
Other Liabilities 96 52 (155) (10) (17) 123 (37) 86
Changes in Components of Working Capital 41 8 159 (123) 85 (45) (6) (51)
Associated with Investing Activities
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 7,515
GAAP)
Less:
Total Capital Expenditures (Non-GAAP) (2) (1,484) (1,523) (1,648) (1,639) (6,294) (1,636) (1,587) (3,223)
Free Cash Flow (Non-GAAP) 1,329 973 1,383 978 4,663 1,493 2,799 4,292
(1) Consists of Encino acquisition-related G&A costs of $12 million, $68 million and $8 million (each before tax) for the three months ended June 30, 2025, three months ended September 30, 2025 and three months ended December 31, 2025, respectively.
(2) See below reconciliation of Total Expenditures (GAAP) to Total Capital Expenditures (Non-GAAP):
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 3,687
Less:
Asset Retirement Costs (13) (14) (86) (33) (146) (12) (37) (49)
Non-Cash Leasehold Acquisition Costs (3) (9) (2) (3) (10) (24) (52) (53) (105)
Non-Cash Property Acquisition Costs - (2) (2)
Acquisition Costs of Properties (3) 1 (270) (6,736) 2 (7,003) (23) (193) (216)
Exploration Costs (41) (74) (71) (50) (236) (45) (47) (92)
Total Capital Expenditures (Non-GAAP) 1,484 1,523 1,648 1,639 6,294 1,636 1,587 3,223
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
Activities
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 used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may
be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry.
June 30, March 31, December 31, September 30, June 30,
2026 2026 2025 2025 2025
Total Stockholders' Equity - (a) 31,864 30,908 29,833 30,285 29,238
Current and Long-Term Debt (GAAP) - (b) 7,926 7,931 7,936 7,694 4,236
Less: Cash (4,907) (3,849) (3,396) (3,530) (5,216)
Net Debt (Non-GAAP) - (c) 3,019 4,082 4,540 4,164 (980)
Total Capitalization (GAAP) - (a) + (b) 39,790 38,839 37,769 37,979 33,474
Total Capitalization (Non-GAAP) - (a) + (c) 34,883 34,990 34,373 34,449 28,258
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] 19.9 % 20.4 % 21.0 % 20.3 % 12.7 %
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + 8.7 % 11.7 % 13.2 % 12.1 % -3.5 %
(c)]
Revenues, Costs and Margins Per Barrel of Oil Equivalent
In millions of USD, except Boe and per Boe amounts (Unaudited)
EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who review certain components and/or groups of components of revenues, costs and/or margins per barrel of oil equivalent (Boe). Certain of these components are adjusted for non-recurring and certain other items, as further discussed below. EOG management uses this
information for purposes of comparing its financial performance with the financial performance of other companies in the industry.
2Q 2026 1Q 2026 4Q 2025 3Q 2025 2Q 2025
Volume - Million Barrels of Oil Equivalent - (a) 128.3 124.5 128.7 119.7 103.2
Total Operating Revenues and Other - (b) 8,620 6,921 5,638 5,847 5,478
Total Operating Expenses - (c) 5,092 4,323 4,695 4,011 3,731
Operating Income - (d) 3,528 2,598 943 1,836 1,747
Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas
Crude Oil and Condensate 4,901 3,577 2,991 3,243 2,974
Natural Gas Liquids 770 664 666 604 534
Natural Gas 812 1,021 847 707 600
Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural 6,483 5,262 4,504 4,554 4,108
Gas - (e)
Operating Costs
Lease and Well 467 462 447 431 396
Gathering, Processing and Transportation Costs (1) 676 654 652 587 455
General and Administrative (GAAP) 213 185 224 239 186
Less: Certain Items (see Endnote 2 to 2Q 2026 earnings release) - (8) (68) (12)
General and Administrative (Non-GAAP) (2) 213 185 216 171 174
Taxes Other Than Income (GAAP) 431 338 283 309 301
Add: Severance Tax Refund -
Taxes Other Than Income (Non-GAAP) (3) 431 338 283 309 301
Interest Expense, Net 67 66 66 71 51
Less: Acquisition-Related Financing Commitment Costs - (6)
Interest Expense, Net (Non-GAAP) (4) 67 66 66 71 45
Total Operating Cost (GAAP) (excluding DD&A and Total Exploration Costs) 1,854 1,705 1,672 1,637 1,389
- (f)
Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration 1,854 1,705 1,664 1,569 1,371
Costs) - (g)
Depreciation, Depletion and Amortization (DD&A) 1,259 1,193 1,226 1,169 1,053
Total Operating Cost (GAAP) (excluding Total Exploration Costs) - (h) 3,113 2,898 2,898 2,806 2,442
Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (i) 3,113 2,898 2,890 2,738 2,424
Exploration Costs 47 45 50 71 74
Dry Hole Costs 30 23 4 11
Impairments 19 39 689 71 39
Total Exploration Costs (GAAP) 96 107 743 142 124
Less: Certain Impairments (5) - (646) (11)
Total Exploration Costs (Non-GAAP) 96 107 97 142 113
Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) - (j) 3,209 3,005 3,641 2,948 2,566
Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non- 3,209 3,005 2,987 2,880 2,537
GAAP)) - (k)
Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural 3,274 2,257 863 1,606 1,542
Gas less Total Operating Cost (GAAP) (including Total Exploration Costs
(GAAP))
Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural 3,274 2,257 1,517 1,674 1,571
Gas less Total Operating Cost (Non-GAAP) (including Total Exploration
Costs (Non-GAAP))
Revenues, Costs and Margins Per Barrel of Oil Equivalent
(Continued)
In millions of USD, except Boe and per Boe amounts (Unaudited)
2Q 2026 1Q 2026 4Q 2025 3Q 2025 2Q 2025
Per Barrel of Oil Equivalent (Boe) Calculations (GAAP)
Composite Average Operating Revenues and Other per Boe - (b) / (a) 67.19 55.59 43.81 48.85 53.08
Composite Average Operating Expenses per Boe - (c) / (a) 39.69 34.72 36.48 33.51 36.15
Composite Average Operating Income per Boe - (d) / (a) 27.50 20.87 7.33 15.34 16.93
Composite Average Revenue from Sales of Crude Oil and Condensate, 50.52 42.24 34.99 38.05 39.80
NGLs, and Natural Gas per Boe - (e) / (a)
Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - 14.45 13.69 12.99 13.67 13.46
(f) / (a)
Composite Average Margin per Boe (excluding DD&A and Total Exploration 36.07 28.55 22.00 24.38 26.34
Costs) - [(e) / (a) - (f) / (a)]
Total Operating Cost per Boe (excluding Total Exploration Costs) - (h) / (a) 24.26 23.27 22.52 23.44 23.66
Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) 26.26 18.97 12.47 14.61 16.14
/ (a) - (h) / (a)]
Total Operating Cost per Boe (including Total Exploration Costs) - (j) / (a) 25.01 24.13 28.29 24.63 24.86
Composite Average Margin per Boe (including Total Exploration Costs) - [(e) 25.51 18.11 6.70 13.42 14.94
/ (a) - (j) / (a)]
Per Barrel of Oil Equivalent (Boe) Calculations (Non-GAAP)
Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - 14.45 13.69 12.93 13.10 13.30
(g) / (a)
Composite Average Margin per Boe (excluding DD&A and Total Exploration 36.07 28.55 22.06 24.95 26.50
Costs) - [(e) / (a) - (g) / (a)]
Total Operating Cost per Boe (excluding Total Exploration Costs) - (i) / (a) 24.26 23.27 22.46 22.87 23.50
Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) 26.26 18.97 12.53 15.18 16.30
/ (a) - (i) / (a)]
Total Operating Cost per Boe (including Total Exploration Costs) - (k) / (a) 25.01 24.13 23.21 24.06 24.59
Composite Average Margin per Boe (including Total Exploration Costs) - [(e) 25.51 18.11 11.78 13.99 15.21
/ (a) - (k) / (a)]
Revenues, Costs and Margins Per Barrel of Oil Equivalent
(Continued)
In millions of USD, except Boe and per Boe amounts (Unaudited)
2025 2024 2023 2022 2021
Volume - Million Barrels of Oil Equivalent - (a) 449.8 388.7 359.4 331.5 302.5
Total Operating Revenues and Other - (b) 22,632 23,698 24,186 25,702 18,642
Total Operating Expenses - (c) 16,247 15,616 14,583 15,736 12,540
Operating Income (Loss) - (d) 6,385 8,082 9,603 9,966 6,102
Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas
Crude Oil and Condensate 12,501 13,921 13,748 16,367 11,125
Natural Gas Liquids 2,376 2,106 1,884 2,648 1,812
Natural Gas 2,791 1,551 1,744 3,781 2,444
Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural 17,668 17,578 17,376 22,796 15,381
Gas - (e)
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)
Information below)
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
(f)
Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration 6,004 5,371 5,146 5,351 4,293
Costs) - (g)
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
GAAP)) - (k)
Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural 5,981 7,541 8,354 13,416 6,836
Gas less Total Operating Cost (GAAP) (including Total Exploration Costs
(GAAP))
Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural 6,732 7,811 8,396 13,430 6,851
Gas less Total Operating Cost (Non-GAAP) (including Total Exploration
Costs (Non-GAAP))
Revenues, Costs and Margins Per Barrel of Oil Equivalent
(Continued)
In millions of USD, except Boe and per Boe amounts (Unaudited)
2025 2024 2023 2022 2021
Per Barrel of Oil Equivalent (Boe) Calculations (GAAP)
Composite Average Operating Revenues and Other per Boe - (b) / (a) 50.32 60.97 67.30 77.53 61.63
Composite Average Operating Expenses per Boe - (c) / (a) 36.12 40.18 40.58 47.47 41.46
Composite Average Operating Income (Loss) per Boe - (d) / (a) 14.20 20.79 26.72 30.06 20.17
Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, 39.28 45.22 48.34 68.77 50.84
and Natural Gas per Boe - (e) / (a)
Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (f) 13.54 13.76 14.31 15.84 14.19
/ (a)
Composite Average Margin per Boe (excluding DD&A and Total Exploration 25.74 31.46 34.03 52.93 36.65
Costs) - [(e) / (a) - (f) / (a)]
Total Operating Cost per Boe (excluding Total Exploration Costs) - (h) / (a) 23.46 24.33 24.03 26.53 26.26
Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / 15.82 20.89 24.31 42.24 24.58
(a) - (h) / (a)]
Total Operating Cost per Boe (including Total Exploration Costs) - (j) / (a) 25.97 25.82 25.10 28.30 28.25
Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / 13.31 19.40 23.24 40.47 22.59
(a) - (j) / (a)]
Per Barrel of Oil Equivalent (Boe) Calculations (Non-GAAP)
Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - 13.34 13.82 14.31 16.14 14.19
(g) / (a)
Composite Average Margin per Boe (excluding DD&A and Total Exploration 25.94 31.40 34.03 52.63 36.65
Costs) - [(e) / (a) - (g) / (a)]
Total Operating Cost per Boe (excluding Total Exploration Costs) - (i) / (a) 23.26 24.39 24.03 26.83 26.26
Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / 16.02 20.83 24.31 41.94 24.58
(a) - (i) / (a)]
Total Operating Cost per Boe (including Total Exploration Costs) - (k) / (a) 24.31 25.13 24.98 28.26 28.20
Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / 14.97 20.09 23.36 40.51 22.64
(a) - (k) / (a)]
(1) Effective January 1, 2024, EOG combined Transportation Costs and Gathering and Processing Costs into one line item titled Gathering, Processing and
Transportation Costs. This presentation has been conformed for all periods presented and had no impact on previously reported Net Income.
(2) EOG believes excluding the above-referenced items from General and Administrative Costs is appropriate and provides useful information to investors, as
EOG views such items as non-recurring.
(3) EOG believes excluding the above-referenced items from Taxes Other Than Income is appropriate and provides useful information to investors, as EOG views
such items as non-recurring.
(4) EOG believes excluding the above-referenced items from Interest Expense, Net is appropriate and provides useful information to investors, as EOG views
such items as non-recurring.
(5) In general, EOG excludes impairments which are (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties
or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG's oil and gas properties or other assets). EOG believes
excluding these impairments from total exploration costs is appropriate and provides useful information to investors, as such impairments were caused by
factors outside of EOG's control (versus, for example, impairments that are due to EOG's proved oil and gas properties not being as productive as it
originally estimated).
Additional Key Financial Information
(Unaudited)
See "Endnotes" below for related discussion and definitions. 2025 Actual 2024 Actual 2023 Actual 2022 Actual 2021 Actual
Crude Oil and Condensate Volumes (MBod)
United States 520.5 490.6 475.2 460.7 443.4
Trinidad 1.4 0.8 0.6 0.6 1.5
Other International 0.1
Total 521.9 491.4 475.8 461.3 445.0
Natural Gas Liquids Volumes (MBbld)
Total 288.2 245.9 223.8 197.7 144.5
Natural Gas Volumes (MMcfd)
United States 2,299 1,728 1,551 1,315 1,210
Trinidad 230 220 160 180 217
Other International(1) 4 9
Total 2,533 1,948 1,711 1,495 1,436
Crude Oil Equivalent Volumes (MBoed)
United States 1,191.8 1,024.5 957.5 877.5 789.6
Trinidad 39.8 37.6 27.3 30.7 37.7
Other International 0.6 1.6
Total 1,232.2 1,062.1 984.8 908.2 828.9
Benchmark Price
Oil (WTI) ($/Bbl) 64.78 75.72 77.61 94.23 67.96
Natural Gas (HH) ($/Mcf) 3.43 2.27 2.74 6.64 3.85
Crude Oil and Condensate - above (below) WTI(2) ($/Bbl)
United States 0.87 1.70 1.57 2.99 0.58
Trinidad (7.19) (11.29) (9.03) (8.07) (11.70)
Other International 0.36
Natural Gas Liquids - Realizations as % of WTI
Total 34.9 % 30.9 % 29.7 % 39.0 % 50.5 %
Natural Gas - above (below) NYMEX Henry Hub(3) ($/Mcf)
United States (0.49) (0.28) (0.04) 0.63 1.03
Natural Gas Realizations4 ($/Mcf)
Trinidad 3.78 3.65 3.65 4.43 3.40
Other International(1) 3.28
Total Expenditures (GAAP) ($MM) 13,703 6,653 6,818 5,610 4,255
Capital Expenditures5 (Non-GAAP) ($MM) 6,294 6,226 6,041 4,607 3,755
Operating Unit Costs ($/Boe)
Lease and Well 3.72 4.04 4.05 4.02 3.75
Gathering, Processing and Transportation Costs6 4.74 4.43 4.50 4.78 4.70
General and Administrative (GAAP) 1.82 1.72 1.78 1.72 1.69
General and Administrative (Non-GAAP)7 1.63 1.70 1.78 1.67 1.69
Cash Operating Costs (GAAP) 10.28 10.19 10.33 10.52 10.14
Cash Operating Costs (Non-GAAP)7 10.09 10.17 10.33 10.47 10.14
Depreciation, Depletion and Amortization 9.92 10.57 9.72 10.69 12.07
Expenses ($MM)
Exploration and Dry Hole 285 188 182 204 225
Impairment (GAAP) 843 391 202 382 376
Impairment (excluding certain impairments (Non-GAAP))8 186 100 160 269 361
Capitalized Interest 86 45 33 36 33
Net Interest 235 138 148 179 178
Net Interest (Non-GAAP)9 229
TOTI (% of revenues from sales of crude oil and condensate, NGLs
and natural gas)
(GAAP) 7.0 % 7.1 % 7.4 % 7.0 % 6.8 %
(Non-GAAP)7 7.0 % 7.3 % 7.4 % 7.5 % 6.8 %
Income Taxes
Effective Rate 21.7 % 22.1 % 21.6 % 21.7 % 21.4 %
Current Tax Expense ($MM) 1,039 1,348 1,415 2,208 1,393
Additional Key Financial Information
(Continued)
Endnotes
1) 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).
View original content:https://www.prnewswire.com/news-releases/eog-resources-reports-second-quarter-2026-results-302842953.html
SOURCE EOG Resources, Inc.
