EOG Resources Reports First Quarter 2026 Results

HOUSTON, May 5, 2026 /PRNewswire/ — EOG Resources, Inc. (EOG) today reported first 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.

First Quarter Highlights

Earned net income of $2.0 billion, or $3.70 per share, and adjusted net income of $1.8 billion, or $3.41 per share
Delivered net cash provided by operating activities of $3.0 billion and Adjusted CFO¹ of $3.1 billion
Generated $1.5 billion of free cash flow
Declared regular quarterly dividend of $1.02 per share
Paid $544 million in regular dividends and repurchased $402 million of shares
Volumes better than guidance midpoints with in-line capital expenditures
Total per-unit cash operating costs and DD&A better than guidance midpoints
Oil and natural gas price realizations better than guidance midpoints
Increasing full year oil and NGL production guidance reflecting reallocation of capital program

CEO Commentary

“EOG delivered exceptional results in the first quarter, with oil, gas, and NGL volumes exceeding the midpoints of guidance while maintaining rigorous cost discipline – total per-unit cash operating costs and DD&A both came in better than guidance midpoints. Operational excellence translated into robust financial performance: we generated $1.5 billion in free cash flow and returned nearly $950 million to shareholders through our regular dividend and share repurchases.

Our first quarter results reflect strong execution and progress towards our full-year objectives. We are reallocating some capital for the remainder of this year to liquids assets while keeping our capital budget unchanged. This drives a modest increase in oil and NGL production this year versus our prior guidance while providing optionality for future growth. This change reflects the flexibility to invest across our high-return, multi-basin portfolio with differentiated exposure to natural gas, liquids, conventionals, and unconventionals.

EOG is well positioned to thrive in the current dynamic macro environment. Our competitive advantages drive differentiated performance: a best-in-class balance sheet providing financial strength and flexibility to invest through cycles; premium pricing exposure in key markets enhancing revenue realizations; differentiated exploration expertise driving low-cost, high-quality inventory across multiple basins; vertical integration and in-house technology strengthening our operational efficiency and cost structure; and a unique culture that empowers our teams to innovate and execute at the highest level.

EOG has never been stronger. Our multi-basin portfolio, operational excellence, and financial strength provide unmatched flexibility to deliver superior returns and significant cash to shareholders across commodity price cycles.”

Return of Capital
The Board of Directors today declared a dividend of $1.02 per share on EOG’s common stock. The dividend will be payable July 31, 2026, to stockholders of record as of July 17, 2026. The indicated annual rate is $4.08 per share.

During the first quarter, the company repurchased 3.2 million shares for $402 million under its share repurchase authorization, at an average purchase price of $125 per share. As of March 31, 2026, EOG had $2.9 billion remaining on its current repurchase authorization.

Key Financial Results
In millions of USD, except per-share, per-Boe and ratio data

GAAP	1Q 2026	4Q 2025	3Q 2025	2Q 2025	1Q 2025
Total Revenue	6,921	5,638	5,847	5,478	5,669
Net Income	1,980	701	1,471	1,345	1,463
Net Income Per Share	3.70	1.30	2.70	2.46	2.65
Net Cash Provided by Operating Activities	2,966	2,612	3,111	2,032	2,289
Total Expenditures	1,768	1,730	8,544	1,883	1,546
Current and Long-Term Debt	7,931	7,936	7,694	4,236	4,744
Cash and Cash Equivalents	3,849	3,396	3,530	5,216	6,599
Debt-to-Total Capitalization	20.4 %	21.0 %	20.3 %	12.7 %	13.8 %
Cash Operating Costs ($/Boe)	10.45	10.28	10.50	10.05	10.31

Non–GAAP
Adjusted Net Income	1,825	1,222	1,472	1,268	1,586
Adjusted Net Income Per Share	3.41	2.27	2.71	2.32	2.87
Adjusted CFO¹	3,129	2,617	3,031	2,496	2,813
Capital Expenditures	1,636	1,639	1,648	1,523	1,484
Free Cash Flow	1,493	978	1,383	973	1,329
Net Debt	4,082	4,540	4,164	(980)	(1,855)
Net Debt-to-Total Capitalization	11.7 %	13.2 %	12.1 %	(3.5 %)	(6.7 %)
Cash Operating Costs ($/Boe)²	10.45	10.22	9.93	9.94	10.31

Key Operational Results

Volumes	1Q 2026	4Q 2025	3Q 2025	2Q 2025	1Q 2025
Crude Oil and Condensate (MBod)	548.5	546.1	534.5	504.2	502.1
Natural Gas Liquids (MBbld)	332.1	342.1	309.3	258.4	241.7
Natural Gas (MMcfd)	3,020	3,065	2,745	2,229	2,080
Total Crude Oil Equivalent (MBoed)	1,383.8	1,399.0	1,301.2	1,134.1	1,090.4

Cash Operating Costs ($/Boe)
Lease & Well	3.71	3.47	3.60	3.84	4.09
Gathering, Processing & Transportation Costs	5.25	5.07	4.90	4.41	4.48
General & Administrative (GAAP)	1.49	1.74	2.00	1.80	1.74
General & Administrative (Non-GAAP) ²	1.49	1.68	1.43	1.69	1.74
Cash Operating Costs (GAAP)	10.45	10.28	10.50	10.05	10.31
Cash Operating Costs (Non-GAAP)²	10.45	10.22	9.93	9.94	10.31

Depreciation, Depletion & Amortization ($/Boe)	9.58	9.53	9.77	10.20	10.32

First Quarter 2026 Results vs Guidance

		1Q 2026
(Unaudited)	1Q 2026	Guidance Midpoint⁴	Variance	4Q 2025	3Q 2025	2Q 2025	1Q 2025
Crude Oil and Condensate Volumes (MBod)
United States	546.5	544.7	1.8	544.5	532.9	503.1	500.9
Trinidad	1.9	1.8	0.1	1.5	1.6	1.1	1.2
Other International⁵	0.1	0.0	0.1	0.1	0.0	0.0	0.0
Total	548.5	546.5	2.0	546.1	534.5	504.2	502.1
Natural Gas Liquids Volumes (MBbld)
Total	332.1	330.0	2.1	342.1	309.3	258.4	241.7
Natural Gas Volumes (MMcfd)
United States	2,769	2,750	19	2,859	2,511	1,977	1,834
Trinidad	239	235	4	195	230	252	246
Other International⁵	12	0	12	11	4	0	0
Total	3,020	2,985	35	3,065	2,745	2,229	2,080

Total Crude Oil Equivalent Volumes (MBoed)	1,383.8	1,374.0	9.8	1,399.0	1,301.2	1,134.1	1,090.4
Total MMBoe	124.5	123.7	0.8	128.7	119.7	103.2	98.1

Benchmark Price
Oil (WTI) ($/Bbl)	72.17			59.17	64.95	63.71	71.42
Natural Gas (HH) ($/Mcf)	4.96			3.55	3.07	3.44	3.66

Crude Oil and Condensate – above (below) WTI⁶($/Bbl)
United States	0.31	(0.25)	0.56	0.37	1.02	1.13	1.48
Trinidad	(3.26)	(4.00)	0.74	(2.10)	(7.21)	(9.21)	(10.30)
Other International⁵	16.95	0.00	16.95	4.81	0.00	0.00	0.00
Natural Gas Liquids – Realizations as % of WTI
Total	30.8 %	31.0 %	(0.2 %)	35.7 %	32.7 %	35.6 %	36.8 %
Natural Gas – above (below) NYMEX Henry Hub⁷($/Mcf)
United States	(1.21)	(1.30)	0.09	(0.61)	(0.36)	(0.57)	(0.30)
Natural Gas Realizations ($/Mcf)
Trinidad	3.91	3.50	0.41	3.94	3.80	3.65	3.78
Other International⁵	3.26	0.00	3.26	3.29	3.27	0.00	0.00

Total Expenditures (GAAP) ($MM)	1,768			1,730	8,544	1,883	1,546
Capital Expenditures (Non-GAAP) ($MM)	1,636	1,625	11	1,639	1,648	1,523	1,484

Operating Unit Costs ($/Boe)
Lease and Well	3.71	3.75	(0.04)	3.47	3.60	3.84	4.09
Gathering, Processing and Transportation Costs	5.25	5.20	0.05	5.07	4.90	4.41	4.48
General & Administrative (GAAP)	1.49			1.74	2.00	1.80	1.74
General & Administrative (Non-GAAP)²	1.49	1.55	(0.06)	1.68	1.43	1.69	1.74
Cash Operating Costs (GAAP)	10.45			10.28	10.50	10.05	10.31
Cash Operating Costs (Non-GAAP)²	10.45	10.50	(0.05)	10.22	9.93	9.94	10.31
Depreciation, Depletion and Amortization	9.58	9.60	(0.02)	9.53	9.77	10.20	10.32

Expenses ($MM)
Exploration and Dry Hole	68	50	18	54	71	85	75
Impairment (GAAP)	39			689	71	39	44
Impairment (excluding certain impairments (Non-GAAP))⁸	39	70	(31)	43	71	28	44
Capitalized Interest	37	37	0	36	27	11	12
Net Interest (GAAP)	66			66	71	51	47
Net Interest (Non-GAAP)⁹	66	67	(1)	66	71	45	47

TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas)
(GAAP)	6.4 %			6.3 %	6.8 %	7.3 %	7.6 %
(Non-GAAP)	6.4 %	7.0 %	(0.6 %)	6.3 %	6.8 %	7.3 %	7.6 %
Income Taxes
Effective Rate	22.5 %	23.0 %	(0.5 %)	22.8 %	19.4 %	23.2 %	22.1 %
Current Tax Expense ($MM)	557	280	277	293	75	301	370

Second Quarter and Full-Year 2026 Guidance¹⁰

(Unaudited)	2Q 2026 Guidance Range			2Q 2026 Midpoint	FY 2026 Guidance Range			FY 2026 Midpoint
Crude Oil and Condensate Volumes (MBod)
United States	544.2	–	548.8	546.5	544.7	–	549.3	547.0
Trinidad	1.8	–	2.2	2.0	1.3	–	1.7	1.5
Total	546.0	–	551.0	548.5	546.0	–	551.0	548.5
Natural Gas Liquids Volumes (MBbld)
Total	327.0	–	347.0	337.0	331.0	–	351.0	341.0
Natural Gas Volumes (MMcfd)
United States	2,735	–	2,835	2,785	2,760	–	2,860	2,810
Trinidad	240	–	260	250	220	–	240	230
Total	2,975	–	3,095	3,035	2,980	–	3,100	3,040
Crude Oil Equivalent Volumes (MBoed)
United States	1,327.0	–	1,368.3	1,347.7	1,335.7	–	1,377.0	1,356.3
Trinidad	41.8	–	45.5	43.7	38.0	–	41.7	39.8
Total	1,368.8	–	1,413.8	1,391.4	1,373.7	–	1,418.7	1,396.1

Crude Oil and Condensate – above (below) WTI⁶($/Bbl)
United States	5.00	–	6.50	5.75	2.25	–	4.25	3.25
Trinidad	(1.75)	–	(0.25)	(1.00)	(1.00)	–	1.00	0.00
Natural Gas Liquids – Realizations as % of WTI
Total	22.0 %	–	32.0 %	27.0 %	24.5 %	–	34.5 %	29.5 %
Natural Gas – above (below) NYMEX Henry Hub⁷ ($/Mcf)
United States	(0.50)	–	0.20	(0.15)	(1.30)	–	0.70	(0.30)
Natural Gas Realizations ($/Mcf)
Trinidad	3.40	–	4.10	3.75	3.25	–	4.25	3.75

Capital Expenditures¹¹ ($MM)	1,575	–	1,675	1,625	6,300	–	6,700	6,500

Operating Unit Costs ($/Boe)
Lease and Well	3.45	–	3.95	3.70	3.45	–	3.95	3.70
Gathering, Processing and Transportation Costs	5.05	–	5.55	5.30	5.05	–	5.55	5.30
General & Administrative	1.35	–	1.65	1.50	1.40	–	1.70	1.55
Cash Operating Costs	9.85	–	11.15	10.50	9.90	–	11.20	10.55
Depreciation, Depletion and Amortization	9.20	–	10.20	9.70	9.35	–	10.35	9.85

Expenses ($MM)
Exploration and Dry Hole	45	–	85	65	205	–	245	225
Impairment (excluding certain impairments)⁸	40	–	120	80	190	–	370	280
Capitalized Interest	35	–	39	37	147	–	151	149
Net Interest	66	–	70	68	267	–	271	269

TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas)	6.0 %	–	8.0 %	7.0 %	5.8 %	–	7.8 %	6.8 %

Income Taxes
Effective Rate	20.0 %	–	25.0 %	22.5 %	20.0 %	–	25.0 %	22.5 %
Current Tax Expense ($MM)	525	–	625	575	2,120	–	2,420	2,270

First Quarter 2026 Results Webcast
Wednesday, May 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, $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 “First 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 first quarter 2026 guidance midpoint disclosures.
5)	Production volumes from Bahrain operations; natural gas realized price represents contract price less partner’s processing and distribution costs.
6)	EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the 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 second 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				3,577
Natural Gas Liquids	572	534	604	666	2,376	664				664
Natural Gas	637	600	707	847	2,791	1,021				1,021
Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net	(191)	107	116	(19)	13	113				113
Gathering, Processing and Marketing	1,340	1,247	1,178	1,149	4,914	1,496				1,496
Gains (Losses) on Asset Dispositions, Net	(1)	—	(18)	(16)	(35)	31				31
Other, Net	19	16	17	20	72	19				19
Total	5,669	5,478	5,847	5,638	22,632	6,921				6,921

Operating Expenses
Lease and Well	401	396	431	447	1,675	462				462
Gathering, Processing and Transportation Costs	440	455	587	652	2,134	654				654
Exploration Costs	41	74	71	50	236	45				45
Dry Hole Costs	34	11	—	4	49	23				23
Impairments	44	39	71	689	843	39				39
Marketing Costs	1,325	1,216	1,134	1,120	4,795	1,384				1,384
Depreciation, Depletion and Amortization	1,013	1,053	1,169	1,226	4,461	1,193				1,193
General and Administrative	171	186	239	224	820	185				185
Taxes Other Than Income	341	301	309	283	1,234	338				338
Total	3,810	3,731	4,011	4,695	16,247	4,323				4,323

Operating Income	1,859	1,747	1,836	943	6,385	2,598				2,598
Other Income, Net	65	55	59	33	212	23				23
Income Before Interest Expense and Income Taxes	1,924	1,802	1,895	976	6,597	2,621				2,621
Interest Expense, Net	47	51	71	66	235	66				66
Income Before Income Taxes	1,877	1,751	1,824	910	6,362	2,555				2,555
Income Tax Provision	414	406	353	209	1,382	575				575
Net Income	1,463	1,345	1,471	701	4,980	1,980				1,980

Dividends Declared per Common Share	0.9750	1.9950	—	1.0200	3.9900	1.0200				1.0200
Net Income Per Share
Basic	2.66	2.48	2.72	1.31	9.17	3.72				3.72
Diluted	2.65	2.46	2.70	1.30	9.12	3.70				3.70
Average Number of Common Shares
Basic	550	543	541	537	543	532				532
Diluted	553	546	544	539	546	535				535

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				546.5
Trinidad	1.2	1.1	1.6	1.5	1.4	1.9				1.9
Other International ^(B)	—	—	—	0.1	—	0.1				0.1
Total	502.1	504.2	534.5	546.1	521.9	548.5				548.5

Average Crude Oil and Condensate Prices ($/Bbl) ^(C)
United States	$ 72.90	$ 64.84	$ 65.97	$ 59.54	$ 65.65	$ 72.48				$ 72.48
Trinidad	61.12	54.50	57.74	57.07	57.59	68.91				68.91
Other International ^(B)	—	—	—	63.98	—	89.12				89.12
Composite	72.87	64.82	65.95	59.54	65.63	72.47				72.47

Natural Gas Liquids Volumes (MBbld) ^(A)
United States	241.7	258.4	309.3	342.1	288.2	332.1				332.1
Total	241.7	258.4	309.3	342.1	288.2	332.1				332.1

Average Natural Gas Liquids Prices ($/Bbl) ^(C)
United States	$ 26.29	$ 22.70	$ 21.25	$ 21.15	$ 22.58	$ 22.20				$ 22.20
Composite	26.29	22.70	21.25	21.15	22.58	22.20				22.20

Natural Gas Volumes (MMcfd) ^(A)
United States	1,834	1,977	2,511	2,859	2,299	2,769				2,769
Trinidad	246	252	230	195	230	239				239
Other International ^(B)	—	—	4	11	4	12				12
Total	2,080	2,229	2,745	3,065	2,533	3,020				3,020

Average Natural Gas Prices ($/Mcf) ^(C)
United States	$ 3.36	$ 2.87	$ 2.71	$ 2.94	$ 2.94	$ 3.75				$ 3.75
Trinidad	3.78	3.65	3.80	3.94	3.78	3.91				3.91
Other International ^(B)	—	—	3.27	3.29	3.28	3.26				3.26
Composite	3.41	2.96	2.80	3.00	3.02	3.76				3.76

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				1,340.1
Trinidad	42.1	43.2	39.8	34.2	39.8	41.7				41.7
Other International ^(B)	—	—	0.7	1.8	0.6	2.0				2.0
Total	1,090.4	1,134.1	1,301.2	1,399.0	1,232.2	1,383.8				1,383.8

Total MMBoe ^(D)	98.1	103.2	119.7	128.7	449.8	124.5				124.5

(A)	Thousand barrels per day or million cubic feet per day, as applicable.
(B)	Production volumes 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 March 31, 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
Accounts Receivable, Net	2,621	2,504	2,680	2,681	3,597
Inventories	897	934	945	1,014	955
Other ^(A)	563	591	665	565	562
Total	10,680	9,245	7,820	7,656	8,963

Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)	78,432	80,139	88,301	89,857	90,786
Other Property, Plant and Equipment	6,510	6,616	6,772	6,832	6,942
Total Property, Plant and Equipment	84,942	86,755	95,073	96,689	97,728
Less: Accumulated Depreciation, Depletion and Amortization	(50,310)	(51,394)	(52,488)	(54,348)	(55,054)
Total Property, Plant and Equipment, Net	34,632	35,361	42,585	42,341	42,674
Deferred Income Taxes	44	39	37	39	30
Other Assets	1,626	1,639	1,757	1,763	1,711
Total Assets	46,982	46,284	52,199	51,799	53,378

Current Liabilities
Accounts Payable	2,353	2,266	2,944	2,904	3,186
Accrued Taxes Payable	668	348	392	299	766
Dividends Payable	534	1,081	550	544	541
Current Portion of Long-Term Debt	1,280	778	27	27	27
Current Portion of Operating Lease Liabilities	318	360	433	472	375
Other ^(A)	566	342	469	445	329
Total	5,719	5,175	4,815	4,691	5,224

Long-Term Debt	3,464	3,458	7,667	7,909	7,904
Other Liabilities	2,368	2,398	2,496	2,512	2,476
Deferred Income Taxes	5,915	6,015	6,936	6,854	6,866
Commitments and Contingencies ^(B)

Stockholders’ Equity
Common Stock, $0.01 Par	206	206	206	206	206
Additional Paid in Capital	6,095	6,153	5,978	6,027	6,026
Accumulated Other Comprehensive Loss	(4)	(7)	(5)	(7)	(6)
Retained Earnings	27,869	28,131	29,603	29,765	31,200
Common Stock Held in Treasury	(4,650)	(5,245)	(5,497)	(6,158)	(6,518)
Total Stockholders’ Equity	29,516	29,238	30,285	29,833	30,908
Total Liabilities and Stockholders’ Equity	46,982	46,284	52,199	51,799	53,378

(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 March 31, 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				1,980
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization	1,013	1,053	1,169	1,226	4,461	1,193				1,193
Impairments	44	39	71	689	843	39				39
Stock-Based Compensation Expenses	50	53	53	60	216	58				58
Deferred Income Taxes	44	105	278	(84)	343	18				18
(Gains) Losses on Asset Dispositions, Net	1	—	18	16	35	(31)				(31)
Other, Net	11	11	2	3	27	15				15
Dry Hole Costs	34	11	—	4	49	23				23
Mark-to-Market Financial Commodity and Other Derivative Contracts (Gains) Losses, Net	191	(107)	(116)	19	(13)	(113)				(113)
Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts	(38)	(24)	27	(21)	(56)	(53)				(53)
Other, Net	—	—	—	(1)	(1)	—				—
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	48	122	133	(3)	300	(907)				(907)
Inventories	76	(45)	4	(84)	(49)	21				21
Accounts Payable	(129)	(107)	5	(40)	(271)	279				279
Accrued Taxes Payable	(339)	(321)	28	(103)	(735)	467				467
Other Assets	(43)	(43)	(28)	97	(17)	55				55
Other Liabilities	(96)	(52)	155	10	17	(123)				(123)
Changes in Components of Working Capital Associated with Investing Activities	(41)	(8)	(159)	123	(85)	45				45
Net Cash Provided by Operating Activities	2,289	2,032	3,111	2,612	10,044	2,966				2,966
Investing Cash Flows
Acquisition of Encino Acquisition Partners, LLC, Net of Cash Acquired	—	—	(4,464)	13	(4,451)	—				—
Additions to Oil and Gas Properties	(1,381)	(1,699)	(1,492)	(1,543)	(6,115)	(1,491)				(1,491)
Additions to Other Property, Plant and Equipment	(102)	(94)	(171)	(112)	(479)	(153)				(153)
Proceeds from Sales of Assets	12	4	5	3	24	144				144
Changes in Components of Working Capital Associated with Investing Activities	41	8	159	(123)	85	(45)				(45)
Net Cash Used in Investing Activities	(1,430)	(1,781)	(5,963)	(1,762)	(10,936)	(1,545)				(1,545)
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)				(544)
Treasury Stock Purchased	(806)	(602)	(479)	(677)	(2,564)	(418)				(418)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan	—	11	—	12	23	1				1
Debt Issuance and Other Financing Costs	—	(7)	(7)	(11)	(25)	—				—
Repayment of Finance Lease Liabilities	(8)	(9)	(8)	(7)	(32)	(7)				(7)
Net Cash Used in Financing Activities	(1,352)	(1,635)	1,167	(984)	(2,804)	(968)				(968)
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				453
Cash and Cash Equivalents at Beginning of Period	7,092	6,599	5,216	3,530	7,092	3,396				3,396
Cash and Cash Equivalents at End of Period	6,599	5,216	3,530	3,396	3,396	3,849				3,849

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.

	1Q 2026
	Before Tax	Income Tax Impact	After Tax	Diluted 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.

Adjusted Net Income (Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)

	4Q 2025
	Before Tax	Income Tax Impact	After Tax	Diluted 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).

	3Q 2025
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share

Reported Net Income (GAAP)	1,824	(353)	1,471	2.70
Adjustments:
Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net	(116)	25	(91)	(0.16)
Net Cash Received from Settlements of Financial Commodity Derivative Contracts ⁽¹⁾	27	(5)	22	0.04
Add: Losses on Asset Dispositions, Net	18	(6)	12	0.02
Add: Acquisition-Related Costs ⁽²⁾	68	(10)	58	0.11
Adjustments to Net Income	(3)	4	1	0.01

Adjusted Net Income (Non-GAAP)	1,821	(349)	1,472	2.71

Average Number of Common Shares
Basic				541
Diluted				544

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

Adjusted Net Income (Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)

	2Q 2025
	Before Tax	Income Tax Impact	After Tax	Diluted 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).

	1Q 2025
	Before Tax	Income Tax Impact	After Tax	Diluted Earnings per Share

Reported Net Income (GAAP)	1,877	(414)	1,463	2.65
Adjustments:
Losses on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net	191	(41)	150	0.26
Net Cash Payments for Settlements of Financial Commodity Derivative Contracts ⁽¹⁾	(38)	8	(30)	(0.05)
Add: Losses on Asset Dispositions, Net	1	2	3	0.01
Adjustments to Net Income	154	(31)	123	0.22

Adjusted Net Income (Non-GAAP)	2,031	(445)	1,586	2.87

Average Number of Common Shares
Basic				550
Diluted				553

(1)

Adjusted Net Income (Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)
	FY 2025
	Before Tax	Income Tax Impact	After Tax	Diluted 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 Tax	Income Tax Impact	After Tax	Diluted 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)

4Q 2025 Net Income per Share (GAAP) – Diluted		1.30

Realized Prices
1Q 2026 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe	42.24
Less: 4Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe	(34.99)
Subtotal	7.25
Multiplied by: 1Q 2026 Crude Oil Equivalent Volumes (MMBoe)	124.5
Total Change in Revenue	903
Add: Income Tax Benefit (Provision) Imputed (based on 22%)	(199)
Change in Net Income	704
Change in Diluted Earnings per Share		1.32

Volumes
1Q 2026 Crude Oil Equivalent Volumes (MMBoe)	124.5
Less: 4Q 2025 Crude Oil Equivalent Volumes (MMBoe)	(128.7)
Subtotal	(4.2)
Multiplied by: 1Q 2026 Composite Average Margin per Boe (GAAP) (Including Total Exploration Costs) (refer to “Revenues, Costs and Margins Per Barrel of Oil Equivalent” schedule below)	18.11
Change in Margin	(76)
Less: Income Tax Benefit (Provision) Imputed (based on 22%)	17
Change in Net Income	(59)
Change in Diluted Earnings per Share		(0.11)

Certain Operating Costs per Boe
4Q 2025 Total Cash Operating Costs (GAAP) and Total DD&A per Boe	19.81
Less: 1Q 2026 Total Cash Operating Costs (GAAP) and Total DD&A per Boe	(20.03)
Subtotal	(0.22)
Multiplied by: 1Q 2026 Crude Oil Equivalent Volumes (MMBoe)	124.5
Change in Before-Tax Net Income	(27)
Add: Income Tax Benefit (Provision) Imputed (based on 22%)	6
Change in Net Income	(21)
Change in Diluted Earnings per Share		(0.04)

Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net
1Q 2026 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts	113
Less: Income Tax Benefit (Provision)	(24)
After Tax – (a)	89
Less: 4Q 2025 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts	(19)
Less: Income Tax Benefit (Provision)	4
After Tax – (b)	(15)
Change in Net Income – (a) – (b)	104
Change in Diluted Earnings per Share		0.19

Other ⁽¹⁾		1.04

1Q 2026 Net Income per Share (GAAP) – Diluted		3.70

1Q 2026 Average Number of Common Shares – Diluted	535

(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)

4Q 2025 Adjusted Net Income per Share (Non-GAAP) – Diluted		2.27

Realized Prices
1Q 2026 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe	42.24
Less: 4Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe	(34.99)
Subtotal	7.25
Multiplied by: 1Q 2026 Crude Oil Equivalent Volumes (MMBoe)	124.5
Total Change in Revenue	903
Add: Income Tax Benefit (Provision) Imputed (based on 22%)	(199)
Change in Net Income	704
Change in Diluted Earnings per Share		1.32

Volumes
1Q 2026 Crude Oil Equivalent Volumes (MMBoe)	124.5
Less: 4Q 2025 Crude Oil Equivalent Volumes (MMBoe)	(128.7)
Subtotal	(4.2)
Multiplied by: 1Q 2026 Composite Average Margin per Boe (Non-GAAP) (Including Total Exploration Costs) (refer to “Revenues, Costs and Margins Per Barrel of Oil Equivalent” schedule below)	18.11
Change in Margin	(76)
Less: Income Tax Benefit (Provision) Imputed (based on 22%)	17
Change in Net Income	(59)
Change in Diluted Earnings per Share		(0.11)

Certain Operating Costs per Boe
4Q 2025 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe	19.75
Less: 1Q 2026 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe	(20.03)
Subtotal	(0.28)
Multiplied by: 1Q 2026 Crude Oil Equivalent Volumes (MMBoe)	124.5
Change in Before-Tax Net Income	(35)
Add: Income Tax Benefit (Provision) Imputed (based on 22%)	8
Change in Net Income	(27)
Change in Diluted Earnings per Share		(0.05)

Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts
1Q 2026 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts	(53)
Less: Income Tax Benefit (Provision)	11
After Tax – (a)	(42)
Less: 4Q 2025 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts	(21)
Less: Income Tax Benefit (Provision)	4
After Tax – (b)	(17)
Change in Net Income – (a) – (b)	(25)
Change in Diluted Earnings per Share		(0.05)

Other ⁽¹⁾		0.03

1Q 2026 Adjusted Net Income per Share (Non-GAAP)		3.41

1Q 2026 Average Number of Common Shares – Diluted	535

(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				2,966

Adjustments:
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	(48)	(122)	(133)	3	(300)	907				907
Inventories	(76)	45	(4)	84	49	(21)				(21)
Accounts Payable	129	107	(5)	40	271	(279)				(279)
Accrued Taxes Payable	339	321	(28)	103	735	(467)				(467)
Other Assets	43	43	28	(97)	17	(55)				(55)
Other Liabilities	96	52	(155)	(10)	(17)	123				123
Changes in Components of Working Capital Associated with Investing Activities	41	8	159	(123)	85	(45)				(45)
Add:
Acquisition-Related Costs ⁽¹⁾, Net of Tax	—	10	58	5	73	—				—
Adjusted Cash Flow from Operations (Non-GAAP)	2,813	2,496	3,031	2,617	10,957	3,129				3,129
Less:
Total Capital Expenditures (Non-GAAP) ⁽²⁾	(1,484)	(1,523)	(1,648)	(1,639)	(6,294)	(1,636)				(1,636)
Free Cash Flow (Non-GAAP)	1,329	973	1,383	978	4,663	1,493				1,493
(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				1,768
Less:
Asset Retirement Costs	(13)	(14)	(86)	(33)	(146)	(12)				(12)
Non-Cash Leasehold Acquisition Costs ⁽³⁾	(9)	(2)	(3)	(10)	(24)	(52)				(52)
Acquisition Costs of Properties ⁽³⁾	1	(270)	(6,736)	2	(7,003)	(23)				(23)
Exploration Costs	(41)	(74)	(71)	(50)	(236)	(45)				(45)
Total Capital Expenditures (Non-GAAP)	1,484	1,523	1,648	1,639	6,294	1,636				1,636

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 Activities	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 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.

	March 31, 2026	December 31, 2025	September 30, 2025	June 30, 2025	March 31, 2025

Total Stockholders’ Equity – (a)	30,908	29,833	30,285	29,238	29,516

Current and Long-Term Debt (GAAP) – (b)	7,931	7,936	7,694	4,236	4,744
Less: Cash	(3,849)	(3,396)	(3,530)	(5,216)	(6,599)
Net Debt (Non-GAAP) – (c)	4,082	4,540	4,164	(980)	(1,855)

Total Capitalization (GAAP) – (a) + (b)	38,839	37,769	37,979	33,474	34,260

Total Capitalization (Non-GAAP) – (a) + (c)	34,990	34,373	34,449	28,258	27,661

Debt-to-Total Capitalization (GAAP) – (b) / [(a) + (b)]	20.4 %	21.0 %	20.3 %	12.7 %	13.8 %

Net Debt-to-Total Capitalization (Non-GAAP) – (c) / [(a) + (c)]	11.7 %	13.2 %	12.1 %	-3.5 %	-6.7 %

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.

	1Q 2026	4Q 2025	3Q 2025	2Q 2025	1Q 2025

Volume – Million Barrels of Oil Equivalent – (a)	124.5	128.7	119.7	103.2	98.1

Total Operating Revenues and Other – (b)	6,921	5,638	5,847	5,478	5,669
Total Operating Expenses – (c)	4,323	4,695	4,011	3,731	3,810
Operating Income – (d)	2,598	943	1,836	1,747	1,859

Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas
Crude Oil and Condensate	3,577	2,991	3,243	2,974	3,293
Natural Gas Liquids	664	666	604	534	572
Natural Gas	1,021	847	707	600	637
Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas – (e)	5,262	4,504	4,554	4,108	4,502

Operating Costs
Lease and Well	462	447	431	396	401
Gathering, Processing and Transportation Costs ⁽¹⁾	654	652	587	455	440
General and Administrative (GAAP)	185	224	239	186	171
Less: Certain Items (see Endnote 2 to 1Q 2026 earnings release)	—	(8)	(68)	(12)	—
General and Administrative (Non-GAAP)⁽²⁾	185	216	171	174	171
Taxes Other Than Income (GAAP)	338	283	309	301	341
Add: Severance Tax Refund	—	—	—	—	—
Taxes Other Than Income (Non-GAAP)⁽³⁾	338	283	309	301	341
Interest Expense, Net	66	66	71	51	47
Less: Acquisition-Related Financing Commitment Costs	—	—	—	(6)	—
Interest Expense, Net (Non-GAAP)⁽⁴⁾	66	66	71	45	47
Total Operating Cost (GAAP) (excluding DD&A and Total Exploration Costs) – (f)	1,705	1,672	1,637	1,389	1,400
Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) – (g)	1,705	1,664	1,569	1,371	1,400

Depreciation, Depletion and Amortization (DD&A)	1,193	1,226	1,169	1,053	1,013

Total Operating Cost (GAAP) (excluding Total Exploration Costs) – (h)	2,898	2,898	2,806	2,442	2,413
Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) – (i)	2,898	2,890	2,738	2,424	2,413

Exploration Costs	45	50	71	74	41
Dry Hole Costs	23	4	—	11	34
Impairments	39	689	71	39	44
Total Exploration Costs (GAAP)	107	743	142	124	119
Less: Certain Impairments ⁽⁵⁾	—	(646)	—	(11)	—
Total Exploration Costs (Non-GAAP)	107	97	142	113	119

Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) – (j)	3,005	3,641	2,948	2,566	2,532
Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP)) – (k)	3,005	2,987	2,880	2,537	2,532

Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas less Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP))	2,257	863	1,606	1,542	1,970
Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas less Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP))	2,257	1,517	1,674	1,571	1,970

Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued)
In millions of USD, except Boe and per Boe amounts (Unaudited)

	1Q 2026	4Q 2025	3Q 2025	2Q 2025	1Q 2025
Per Barrel of Oil Equivalent (Boe) Calculations (GAAP)

Composite Average Operating Revenues and Other per Boe – (b) / (a)	55.59	43.81	48.85	53.08	57.79
Composite Average Operating Expenses per Boe – (c) / (a)	34.72	36.48	33.51	36.15	38.84
Composite Average Operating Income per Boe – (d) / (a)	20.87	7.33	15.34	16.93	18.95

Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe – (e) / (a)	42.24	34.99	38.05	39.80	45.88

Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) – (f) / (a)	13.69	12.99	13.67	13.46	14.26

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) – [(e) / (a) – (f) / (a)]	28.55	22.00	24.38	26.34	31.62

Total Operating Cost per Boe (excluding Total Exploration Costs) – (h) / (a)	23.27	22.52	23.44	23.66	24.58

Composite Average Margin per Boe (excluding Total Exploration Costs) – [(e) / (a) – (h) / (a)]	18.97	12.47	14.61	16.14	21.30

Total Operating Cost per Boe (including Total Exploration Costs) – (j) / (a)	24.13	28.29	24.63	24.86	25.79

Composite Average Margin per Boe (including Total Exploration Costs) – [(e) / (a) – (j) / (a)]	18.11	6.70	13.42	14.94	20.09

Per Barrel of Oil Equivalent (Boe) Calculations (Non-GAAP)

Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) – (g) / (a)	13.69	12.93	13.10	13.30	14.26

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) – [(e) / (a) – (g) / (a)]	28.55	22.06	24.95	26.50	31.62

Total Operating Cost per Boe (excluding Total Exploration Costs) – (i) / (a)	23.27	22.46	22.87	23.50	24.58

Composite Average Margin per Boe (excluding Total Exploration Costs) – [(e) / (a) – (i) / (a)]	18.97	12.53	15.18	16.30	21.30

Total Operating Cost per Boe (including Total Exploration Costs) – (k) / (a)	24.13	23.21	24.06	24.59	25.79

Composite Average Margin per Boe (including Total Exploration Costs) – [(e) / (a) – (k) / (a)]	18.11	11.78	13.99	15.21	20.09

Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued)
In millions of USD, except Boe and per Boe amounts (Unaudited)

	2025	2024	2023	2022	2021

Volume – Million Barrels of Oil Equivalent – (a)	449.8	388.7	359.4	331.5	302.5

Total Operating Revenues and Other – (b)	22,632	23,698	24,186	25,702	18,642
Total Operating Expenses – (c)	16,247	15,616	14,583	15,736	12,540
Operating Income (Loss) – (d)	6,385	8,082	9,603	9,966	6,102

Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas
Crude Oil and Condensate	12,501	13,921	13,748	16,367	11,125
Natural Gas Liquids	2,376	2,106	1,884	2,648	1,812
Natural Gas	2,791	1,551	1,744	3,781	2,444
Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas – (e)	17,668	17,578	17,376	22,796	15,381

Operating Costs
Lease and Well	1,675	1,572	1,454	1,331	1,135
Gathering, Processing and Transportation Costs⁽¹⁾	2,134	1,722	1,620	1,587	1,422
General and Administrative (GAAP)	820	669	640	570	511
Less: Certain Items (see Endnote 7 to Additional Key Financial Information below)	(88)	(10)	—	(16)	—
General and Administrative (Non-GAAP)⁽²⁾	732	659	640	554	511
Taxes Other Than Income (GAAP)	1,234	1,249	1,284	1,585	1,047
Add: Severance Tax Refund	—	31	—	115	—
Taxes Other Than Income (Non-GAAP)⁽³⁾	1,234	1,280	1,284	1,700	1,047
Interest Expense, Net	235	138	148	179	178
Less: Acquisition-Related Financing Commitment Costs	(6)	—	—	—	—
Interest Expense, Net (Non-GAAP)⁽⁴⁾	229	138	148	179	178
Total Operating Cost (GAAP) (excluding DD&A and Total Exploration Costs) – (f)	6,098	5,350	5,146	5,252	4,293
Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) – (g)	6,004	5,371	5,146	5,351	4,293

Depreciation, Depletion and Amortization (DD&A)	4,461	4,108	3,492	3,542	3,651

Total Operating Cost (GAAP) (excluding Total Exploration Costs) – (h)	10,559	9,458	8,638	8,794	7,944
Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) – (i)	10,465	9,479	8,638	8,893	7,944

Exploration Costs	236	174	181	159	154
Dry Hole Costs	49	14	1	45	71
Impairments	843	391	202	382	376
Total Exploration Costs (GAAP)	1,128	579	384	586	601
Less: Certain Impairments ⁽⁵⁾	(657)	(291)	(42)	(113)	(15)
Total Exploration Costs (Non-GAAP)	471	288	342	473	586

Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) – (j)	11,687	10,037	9,022	9,380	8,545
Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP)) – (k)	10,936	9,767	8,980	9,366	8,530

Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas less Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP))	5,981	7,541	8,354	13,416	6,836
Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas less Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP))	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, and Natural Gas per Boe – (e) / (a)	39.28	45.22	48.34	68.77	50.84

Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) – (f) / (a)	13.54	13.76	14.31	15.84	14.19

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) – [(e) / (a) – (f) / (a)]	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) / (a) – (h) / (a)]	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) / (a) – (j) / (a)]	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) – (g) / (a)	13.34	13.82	14.31	16.14	14.19

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) – [(e) / (a) – (g) / (a)]	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) / (a) – (i) / (a)]	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) / (a) – (k) / (a)]	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 International¹	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 ($/Bbl)
United States	0.87	1.70	1.57	2.99	0.58
Trinidad	(7.19)	(11.29)	(9.03)	(8.07)	(11.70)
Other International¹	0.36	—	—	—	—
Natural Gas Liquids – Realizations as % of WTI
Total	34.9 %	30.9 %	29.7 %	39.0 %	50.5 %
Natural Gas – above (below) NYMEX Henry Hub³ ($/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 ($MM)
Exploration and Dry Hole	285	188	182	204	225
Impairment (GAAP)	843	391	202	382	376
Impairment (excluding certain impairments (Non-GAAP))⁸	186	100	160	269	361
Capitalized Interest	86	45	33	36	33
Net Interest	235	138	148	179	178
Net Interest (Non-GAAP)⁹	229	—	—	—	—
TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas)
(GAAP)	7.0 %	7.1 %	7.4 %	7.0 %	6.8 %
(Non-GAAP)⁷	7.0 %	7.3 %	7.4 %	7.5 %	6.8 %
Income Taxes
Effective Rate	21.7 %	22.1 %	21.6 %	21.7 %	21.4 %
Current Tax Expense ($MM)	1,039	1,348	1,415	2,208	1,393

Additional Key Financial Information
(Continued)

Endnotes

1)	2025 production volumes are from Bahrain operations; natural gas realized price represents contract price less partner’s processing and distribution costs.

2)	EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the 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 includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Dry Hole Costs and Other Property, Plant and Equipment. Capital Expenditures excludes Property Acquisitions, Asset Retirement Costs, Non-Cash Exchanges and Transactions and exploration costs incurred as operating expenses.

6)	Effective January 1, 2024, EOG combined Transportation Costs and Gathering and Processing Costs into one line item titled Gathering, Processing and Transportation Costs. This presentation has been conformed for all periods presented and had no impact on previously reported Net Income.

7)	Cash Operating Costs consist of LOE, GP&T and G&A. G&A (Non-GAAP) for fiscal year 2025 excludes costs related to the Encino acquisition, as reflected in the accompanying reconciliation schedules (see “Revenues, Costs and Margins Per Barrel of Oil Equivalent”). In addition, TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas) (Non-GAAP) and G&A (Non-GAAP) for fiscal year 2024 and fiscal year 2022 exclude a state severance tax refund and related consulting fees, respectively, as reflected in the accompanying reconciliation schedules (see “Revenues, Costs and Margins Per Barrel of Oil Equivalent”). The per-Boe impact of such acquisition-related costs and consulting fees on G&A and total Cash Operating Costs for fiscal year 2025, 2024 and 2022 was $(0.19), $(0.02) and $(0.05), respectively.

8)	In general, EOG excludes impairments which are (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG’s oil and gas properties or other assets). EOG believes excluding these impairments from total impairment costs is appropriate and provides useful information to investors, as such impairments were caused by factors outside of EOG’s control (versus, for example, impairments that are due to EOG’s proved oil and gas properties not being as productive as it originally estimated). Impairments (Non-GAAP) for FY 2025 are adjusted from Impairments (GAAP) for FY 2025 by excluding $657 million of impairments, primarily associated with the write-down to fair value of natural gas and crude oil assets in the Barnett Shale and Woodford Oil Window (mainly driven by play-specific economics and resource allocation). Impairments (Non-GAAP) for FY 2024 are adjusted from Impairments (GAAP) for FY 2024 by excluding $291 million of impairments, primarily associated with the write-down to fair value of natural gas and crude oil assets in the Rocky Mountain area.

9)	Net Interest for fiscal year 2025 excludes financing commitment costs related to the Encino acquisition, as reflected in the accompanying reconciliation schedules (see “Revenues, Costs and Margins Per Barrel of Oil Equivalent”). The per-Boe impact of such cost for fiscal year 2025 is $(0.01).

View original content:https://www.prnewswire.com/news-releases/eog-resources-reports-first-quarter-2026-results-302763124.html

SOURCE EOG Resources, Inc.

EOG Resources Reports First Quarter 2026 Results

Cision PR Newswire

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