None.

EOG RESOURCES, INC.

INDEX TO FINANCIAL STATEMENTS

			Page
Consolidated Financial Statements:
Management's Responsibility for Financial Reporting			F-2
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)			F-3
Consolidated Statements of Income and Comprehensive Income for Each of the Three Years in the Period Ended December 31, 2025			F-7
Consolidated Balance Sheets - December 31, 2025 and 2024			F-8
Consolidated Statements of Stockholders' Equity for Each of the Three Years in the Period Ended December 31, 2025			F-9
Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2025			F-10
Notes to Consolidated Financial Statements			F-11
Supplemental Information to Consolidated Financial Statements			F-41

F-1

MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING

The following consolidated financial statements of EOG Resources, Inc., together with its subsidiaries (collectively, EOG), were prepared by management, which is responsible for the integrity, objectivity and fair presentation of such financial statements. The statements have been prepared in conformity with generally accepted accounting principles in the United States of America and, accordingly, include some amounts that are based on the best estimates and judgments of management.

EOG's management is also responsible for establishing and maintaining adequate internal control over financial reporting as well as designing and implementing programs and controls to prevent and detect fraud. The system of internal control of EOG is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America. This system consists of 1) entity level controls, including written policies and guidelines relating to the ethical conduct of business affairs, 2) general computer controls and 3) process controls over initiating, authorizing, recording, processing and reporting transactions. Even an effective internal control system, no matter how well designed, has inherent limitations, including the possibility of human error, circumvention of controls or overriding of controls and, therefore, can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, the effectiveness of a system of internal control over financial reporting in future periods can change as conditions change.

The adequacy of EOG's financial controls and the accounting principles employed by EOG in its financial reporting are under the general oversight of the Audit Committee of the Board of Directors. No member of this committee is an officer or employee of EOG. Moreover, EOG's independent registered public accounting firm and internal auditors have full, free, separate and direct access to the Audit Committee and meet with the committee periodically to discuss accounting, auditing and financial reporting matters.

EOG's management assessed the effectiveness of EOG's internal control over financial reporting as of December 31, 2025. In making this assessment, EOG used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (2013). These criteria cover the control environment, risk assessment process, control activities, information and communication systems, and monitoring activities. Based on this assessment and those criteria, management believes that EOG maintained effective internal control over financial reporting as of December 31, 2025.

Deloitte & Touche LLP, independent registered public accounting firm, was engaged to audit the consolidated financial statements of EOG and audit EOG's internal control over financial reporting and issue a report thereon. In the conduct of the audits, Deloitte & Touche LLP was given unrestricted access to all financial records and related data, including all minutes of meetings of stockholders, the Board of Directors and committees of the Board of Directors. Management believes that all representations made to Deloitte & Touche LLP during the audits were valid and appropriate. Their audits were made in accordance with the standards of the Public Company Accounting Oversight Board (United States). Their report appears on page F-3.

EZRA Y. YACOB						ANN D. JANSSEN
Chairman of the Board and Chief Executive Officer						Executive Vice President and Chief Financial Officer
Houston, Texas
February 24, 2026

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholders and the Board of Directors of EOG Resources, Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of EOG Resources, Inc. and subsidiaries (the "Company") as of December 31, 2025 and 2024, the related consolidated statements of income and comprehensive income, stockholders' equity, and cash flows, for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the "financial statements"). We also have audited the Company's internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

Basis for Opinions

The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Responsibility for Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

F-3

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Proved Oil and Gas Properties — Crude Oil, NGL and Natural Gas Reserves — Refer to Note 1 to the Financial Statements

Critical Audit Matter Description

The Company’s proved oil and gas properties are depleted using the units of production method based on estimated proved crude oil, natural gas liquids (NGLs), and natural gas reserves (proved reserves) and reviewed for impairment whenever events and circumstances indicate a possible decline in the recoverability of the carrying amount may have occurred, by comparing the carrying amount of the proved oil and natural gas properties to the estimated undiscounted future net cash flows, derived in part from the underlying proved reserves. The development of the Company’s estimated reserves volumes requires management to make significant estimates including calculating the best estimate of future production, and the Company’s ability to convert proved undeveloped reserves to producing properties within five years of their initial reporting to the Securities and Exchange Commission.

The Company’s reserve engineers estimate reserves quantities using geological, engineering and economic data for each reservoir. Changes in these estimates and assumptions could materially affect the amount of depletion expense and the proved oil and natural gas properties impairment evaluations.

Given the significant judgments made by management, performing audit procedures to evaluate the Company’s estimated reserve quantities, including management’s estimates and assumptions related to the best estimate of future production and converting proved undeveloped reserves to producing properties within five years, required a high degree of auditor judgment and an increased extent of effort.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to management’s significant judgments and assumptions related to reserve quantities, including converting proved undeveloped reserves to producing properties within five years included the following, among others:

• We tested the design, implementation, and operating effectiveness of controls related to the Company’s estimation of proved reserves, including controls relating to the five-year development plan.

• We evaluated the Company’s estimated reserves and reasonableness of management’s five-year development plan by:

◦Comparing the Company’s estimated future production to historical production volumes

◦Assessing the reasonableness of the production volume decline curves by comparing to historical decline curve estimates

◦Comparing the forecasts for converting proved undeveloped reserves to producing properties to historical conversion rates

◦Comparing the conversion plan for proved undeveloped reserves to the Company’s drill plan and the availability of capital relative to the drill plan

◦Reviewing internal communications to management and the Board of Directors

◦Considering information included in Company press releases as well as in analyst and industry reports for the Company

◦Comparing the Company’s proved reserve volumes to those independently developed by management’s expert, an independent reserve engineering firm

• We evaluated the experience, qualifications and objectivity of management’s expert, an independent reserve engineering firm, including the methodologies used to independently audit the proved reserve quantities of the Company.

F-4

Management’s Determination of Fair Value — Valuation of Oil and Gas Properties — Refer to Notes 1, 13, 14 and 16 to the Financial Statements

Critical Audit Matter Description

The Company’s determination of the fair value of their oil and gas properties, inclusive of acquired oil and natural gas properties, requires management to make significant estimates and apply a high level of judgement. In doing so, management has utilized the income valuation technique which incorporates several business and market assumptions which are highly subjective and require a high level of judgement and estimation. As described in Note 16 to the financial statements, on August 1, 2025 the Company acquired Encino Acquisition Partners, LLC (“Encino”) in an acquisition accounted for as a business combination, and as described in Notes 13 and 14 to the financial statements the Company recorded impairments of certain proved oil and gas properties which had an impairment indicator at year end, which required the applicable oil and gas properties to be measured at their fair values as of the respective measurement dates.

Management applied significant judgment in estimating the fair value of oil and gas properties acquired in the acquisition of Encino, which involved the use of discounted cash flow models that incorporated estimates of future production volumes from the related estimates of reserves, future oil, NGL and natural gas prices, reserve adjustment factors and a weighted average cost of capital rate.

At December 31, 2025, certain of the Company's proved oil and natural gas properties were reduced to their respective fair value, resulting in an impairment to their respective carrying value, which was included in impairments within the consolidated statements of income and comprehensive income. When an impairment indicator is identified, the Company compares the estimated undiscounted future net cash flows from the applicable oil, NGL and natural gas reserves to the carrying amount of the proved oil and natural gas properties at a depletion group level to determine if the carrying amount is recoverable. If the carrying amount of the proved oil and natural gas properties exceeds the undiscounted future net cash flows, the Company will adjust the carrying value to fair value. Management estimated the fair value of the certain proved oil and natural gas properties which had an impairment indicator at year end using discounted cash flow models which incorporates estimates of future production volumes from the related estimates of proved reserves, future oil, NGL and natural gas prices and the application of a weighted average cost of capital.

The principal considerations for our determination that performing procedures relating to the valuation of certain crude oil and natural gas assets in the acquisition of Encino, and certain oil and gas properties which had an impairment indicator at year end, is a critical audit matter are (i) the significant judgments made by management, including estimated oil and gas reserves as discussed in the previous Critical Audit Matter, as well the estimates of future oil, NGL and natural gas prices, reserve adjustment factors and the weighted average cost of capital rate; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating significant assumptions of the nature discussed in the previous Critical Audit Matter, as well as assumptions used in the discounted cash flow model related to estimated future oil, NGL and natural gas prices, reserve adjustment factors and the weighted average cost of capital rate; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

How the Critical Audit Matter Was Addressed in the Audit

In addition to the procedures specified in the previous Critical Audit Matter, our audit procedures related to management’s significant judgments and assumptions related to future oil, NGL and natural gas prices, reserve adjustment factors and the weighted average cost of capital rate included the following, among others:

• We tested the design, implementation, and operating effectiveness of controls related to the Company’s assumptions related to estimates of future oil, NGL and natural gas prices, reserve adjustment factors and the weighted average cost of capital rate used to estimate the value of the applicable oil and gas properties

• We evaluated the appropriateness of the business assumptions and accounting assumptions in line with the applicable financial reporting framework, as well as assessed the acceptability of the underlying data

F-5

• We evaluated the appropriateness of the discounted cash flow models by:

◦Testing the completeness and accuracy of underlying data used in the discounted cash flow models

◦Evaluating the reasonableness of significant assumptions used by management related to estimates of future oil, NGL and natural gas prices, reserve adjustment factors and the weighted average cost of capital rate

◦Utilizing professionals with specialized skill and knowledge to assist in the evaluation of the discounted cash flow models, including future oil, NGL and natural gas prices, reserve adjustment factors and the weighted average cost of capital rate used

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 24, 2026

We have served as the Company's auditor since 2002.

F-6

EOG RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(In Millions, Except Per Share Data)

Year Ended December 31			2025						2024						2023
Operating Revenues and Other
Crude Oil and Condensate			$	12,501					$	13,921					$	13,748
Natural Gas Liquids			2,376						2,106						1,884
Natural Gas			2,791						1,551						1,744
Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net			13						204						818
Gathering, Processing and Marketing			4,914						5,800						5,806
Gains (Losses) on Asset Dispositions, Net			(35)						16						95
Other, Net			72						100						91
Total			22,632						23,698						24,186
Operating Expenses
Lease and Well			1,675						1,572						1,454
Gathering, Processing and Transportation Costs			2,134						1,722						1,620
Exploration Costs			236						174						181
Dry Hole Costs			49						14						1
Impairments			843						391						202
Marketing Costs			4,795						5,717						5,709
Depreciation, Depletion and Amortization			4,461						4,108						3,492
General and Administrative			820						669						640
Taxes Other Than Income			1,234						1,249						1,284
Total			16,247						15,616						14,583
Operating Income			6,385						8,082						9,603
Other Income, Net			212						274						234
Income Before Interest Expense and Income Taxes			6,597						8,356						9,837
Interest Expense
Incurred			321						183						181
Capitalized			(86)						(45)						(33)
Interest Expense, Net			235						138						148
Income Before Income Taxes			6,362						8,218						9,689
Income Tax Provision			1,382						1,815						2,095
Net Income			$	4,980					$	6,403					$	7,594
Net Income Per Share
Basic			$	9.17					$	11.31					$	13.07
Diluted			$	9.12					$	11.25					$	13.00
Average Number of Common Shares
Basic			543						566						581
Diluted			546						569						584
Comprehensive Income
Net Income			$	4,980					$	6,403					$	7,594
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments			(2)						4						(1)
Deferred Postretirement Plan			(1)						1						—
Other Comprehensive Income (Loss)			(3)						5						(1)
Comprehensive Income			$	4,977					$	6,408					$	7,593

The accompanying notes are an integral part of these consolidated financial statements.

F-7

EOG RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(In Millions, Except Share Data)

At December 31			2025						2024
ASSETS
Current Assets
Cash and Cash Equivalents			$	3,396					$	7,092
Accounts Receivable, Net			2,681						2,650
Inventories			1,014						985
Assets from Price Risk Management Activities			18						—
Other			547						503
Total			7,656						11,230
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)			89,857						77,091
Other Property, Plant and Equipment			6,832						6,418
Total Property, Plant and Equipment			96,689						83,509
Less: Accumulated Depreciation, Depletion and Amortization			(54,348)						(49,297)
Total Property, Plant and Equipment, Net			42,341						34,212
Deferred Income Taxes			39						39
Other Assets			1,763						1,705
Total Assets			$	51,799					$	47,186
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable			$	2,904					$	2,464
Accrued Taxes Payable			299						1,007
Dividends Payable			544						539
Liabilities from Price Risk Management Activities			—						116
Current Portion of Long-Term Debt			27						532
Current Portion of Operating Lease Liabilities			472						315
Other			445						381
Total			4,691						5,354
Long-Term Debt			7,909						4,220
Other Liabilities			2,512						2,395
Deferred Income Taxes			6,854						5,866
Commitments and Contingencies (Note 8)
Stockholders' Equity
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 589,044,385 Shares and 588,939,584 Shares Issued at December 31, 2025 and 2024, respectively			206						206
Additional Paid in Capital			6,027						6,090
Accumulated Other Comprehensive Loss			(7)						(4)
Retained Earnings			29,765						26,941
Common Stock Held in Treasury, 51,374,169 Shares and 31,731,107 Shares at December 31, 2025 and 2024, respectively			(6,158)						(3,882)
Total Stockholders' Equity			29,833						29,351
Total Liabilities and Stockholders' Equity			$	51,799					$	47,186

The accompanying notes are an integral part of these consolidated financial statements.

F-8

EOG RESOURCES, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(In Millions, Except Per Share Data)

			Common Stock						Additional Paid In Capital						Accumulated Other Comprehensive Loss						Retained Earnings						Common Stock Held In Treasury						Total Stockholders' Equity
Balance at December 31, 2022			$	206					$	6,187					$	(8)					$	18,472					$	(78)					$	24,779
Net Income			—						—						—						7,594						—						7,594
Common Stock Dividends Declared, $5.885 Per Share			—						—						—						(3,432)						—						(3,432)
Other Comprehensive Loss			—						—						(1)						—						—						(1)
Treasury Stock Repurchased			—						—						—						—						(979)						(979)
Change in Treasury Stock - Stock Compensation Plans, Net			—						(36)						—						—						(12)						(48)
Restricted Stock and Restricted Stock Units, Net			—						(162)						—						—						162						—
Stock-Based Compensation Expenses			—						177						—						—						—						177
Balance at December 31, 2023			206						6,166						(9)						22,634						(907)						28,090
Net Income			—						—						—						6,403						—						6,403
Common Stock Dividends Declared, $3.705 Per Share			—						—						—						(2,096)						—						(2,096)
Other Comprehensive Income			—						—						5						—						—						5
Treasury Stock Repurchased			—						—						—						—						(3,209)						(3,209)
Change in Treasury Stock - Stock Compensation Plans, Net			—						(43)						—						—						2						(41)
Restricted Stock and Restricted Stock Units, Net			—						(232)						—						—						232						—
Stock-Based Compensation Expenses			—						199						—						—						—						199
Balance at December 31, 2024			206						6,090						(4)						26,941						(3,882)						29,351
Net Income			—						—						—						4,980						—						4,980
Common Stock Dividends Declared, $3.990 Per Share			—						—						—						(2,156)						—						(2,156)
Other Comprehensive Loss			—						—						(3)						—						—						(3)
Treasury Stock Repurchased			—						—						—						—						(2,526)						(2,526)
Change in Treasury Stock - Stock Compensation Plans, Net			—						(11)						—						—						(18)						(29)
Restricted Stock and Restricted Stock Units, Net			—						(268)						—						—						268						—
Stock-Based Compensation Expenses			—						216						—						—						—						216
Balance at December 31, 2025			$	206					$	6,027					$	(7)					$	29,765					$	(6,158)					$	29,833

The accompanying notes are an integral part of these consolidated financial statements.

F-9

EOG RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Millions)

Year Ended December 31			2025						2024						2023
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
Net Income			$	4,980					$	6,403					$	7,594
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization			4,461						4,108						3,492
Impairments			843						391						202
Stock-Based Compensation Expenses			216						199						177
Deferred Income Taxes			343						467						683
(Gains) Losses on Asset Dispositions, Net			35						(16)						(95)
Other, Net			27						17						27
Dry Hole Costs			49						14						1
Mark-to-Market Financial Commodity and Other Derivative Contracts
Gains, Net			(13)						(204)						(818)
Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts			(56)						214						(112)
Other, Net			(1)						—						(2)
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable			300						101						(38)
Inventories			(49)						259						(231)
Accounts Payable			(271)						(36)						(119)
Accrued Taxes Payable			(735)						541						61
Other Assets			(17)						44						39
Other Liabilities			17						23						184
Changes in Components of Working Capital Associated with Investing Activities			(85)						(382)						295
Net Cash Provided by Operating Activities			10,044						12,143						11,340
Investing Cash Flows
Acquisition of Encino Acquisition Partners, LLC, Net of Cash Acquired			(4,451)						—						—
Additions to Oil and Gas Properties			(6,115)						(5,353)						(5,385)
Additions to Other Property, Plant and Equipment			(479)						(1,019)						(800)
Proceeds from Sales of Assets			24						23						140
Changes in Components of Working Capital Associated with Investing Activities			85						382						(295)
Net Cash Used in Investing Activities			(10,936)						(5,967)						(6,340)
Financing Cash Flows
Long-Term Debt Borrowings			4,471						985						—
Long-Term Debt Repayments			(2,516)						—						(1,250)
Dividends Paid			(2,161)						(2,087)						(3,386)
Treasury Stock Purchased			(2,564)						(3,246)						(1,038)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan			23						22						20
Debt Issuance and Other Financing Costs			(25)						(2)						(8)
Repayment of Finance Lease Liabilities			(32)						(33)						(32)
Net Cash Used in Financing Activities			(2,804)						(4,361)						(5,694)
Effect of Exchange Rate Changes on Cash			—						(1)						—
Increase (Decrease) in Cash and Cash Equivalents			(3,696)						1,814						(694)
Cash and Cash Equivalents at Beginning of Year			7,092						5,278						5,972
Cash and Cash Equivalents at End of Year			$	3,396					$	7,092					$	5,278

The accompanying notes are an integral part of these consolidated financial statements.

F-10

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Nature of Business. EOG Resources, Inc., a Delaware corporation organized in 1985, together with its subsidiaries (collectively, EOG), explores for, develops, produces and markets crude oil, natural gas liquids (NGLs) and natural gas primarily in major producing basins in the United States of America (United States or U.S.) and the Republic of Trinidad and Tobago (Trinidad). EOG is evaluating additional exploration, development and exploitation opportunities in other select international areas, including the Kingdom of Bahrain and the United Arab Emirates. EOG completed the exit of Block 36 and Block 49 located in the Sultanate of Oman (Oman) in 2023.

Principles of Consolidation. The consolidated financial statements of EOG include the accounts of all domestic and foreign subsidiaries. Any investments in unconsolidated affiliates, in which EOG is able to exercise significant influence, are accounted for using the equity method. All intercompany accounts and transactions have been eliminated.

The preparation of financial statements in conformity with accounting principles generally accepted in the U.S. (U.S. GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Financial Instruments. EOG's financial instruments consist of cash and cash equivalents, financial commodity and other derivative contracts, accounts receivable, accounts payable and current and long-term debt. The carrying values of cash and cash equivalents, financial commodity and other derivative contracts, accounts receivable and accounts payable approximate fair value. See Notes 2, 12 and 13.

Cash and Cash Equivalents. EOG records as cash equivalents all highly liquid short-term investments with original maturities of three months or less.

Business Combinations. EOG accounts for business combinations under the Business Combinations Topic of the Financial Accounting Standards Board's (FASB) Accounting Standards Codification (ASC 805), which requires identifiable assets acquired and liabilities assumed to be recognized at their acquisition date fair values. See Note 16 for further discussion of the Encino Acquisition Partners, LLC (Encino) acquisition.

Oil and Gas Operations. EOG accounts for its crude oil and natural gas exploration and production activities under the successful efforts method of accounting.

Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties.

Oil and gas exploration costs, other than the costs of drilling exploratory wells, are expensed as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether EOG has discovered commercial quantities of proved reserves. If commercial quantities of proved reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether commercial quantities of proved reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the estimated reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. The capitalized exploratory well costs that have been capitalized for a period of one year or greater were $0 million, $0 million and $3 million as of December 31, 2025, 2024 and 2023, respectively. In 2023, such costs related to two projects in the United States. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized.

F-11

Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base used includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.

Oil and gas properties are grouped in accordance with the provisions of the Extractive Industries - Oil and Gas Topic of the FASB's Accounting Standards Codification (ASC). The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.

Amortization rates are updated quarterly to reflect: 1) the addition of capital expenditures, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions and/or property dispositions and 4) impairments.

When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the group. If the expected undiscounted future cash flows, based on EOG's estimate of (and assumptions regarding) future crude oil, NGLs and natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data (all Level 3 inputs as defined by the Fair Value Measurement Topic of the FASB's ASC (ASC 820)), are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach described in ASC 820. In certain instances, EOG utilizes accepted offers from third-party purchasers as the basis for determining fair value.

Other Property, Plant and Equipment. Other property, plant and equipment consists of gathering and processing assets, compressors, carbon capture and storage assets, buildings and leasehold improvements, computer hardware and software, vehicles, and furniture and fixtures. Other property, plant and equipment is generally depreciated on a straight-line basis over the estimated useful lives of the property, plant and equipment, which range from 3 years to 45 years.

Inventories. Inventories consist primarily of tubular goods, materials for completion operations, well equipment and gathering lines held for use in the exploration for, and development and production of, crude oil, NGLs and natural gas reserves. EOG accounts for inventories at the lower of cost and net realizable value with adjustments made, as appropriate, to recognize any reductions in value.

Revenue Recognition. EOG presents disaggregated revenues by type of commodity within its Consolidated Statements of Income and Comprehensive Income and by geographic areas defined as operating segments. See Note 11.

Revenues are recognized for the sale of crude oil and condensate, NGLs and natural gas at the point control of the product is transferred to the customer, typically when production is delivered and title or risk of loss transfers to the customer. Arrangements for such sales are evidenced by signed contracts with prices typically based on stated market indices, with certain adjustments for product quality and geographic location. As EOG transfers control of the product shortly after production and after performance obligations have been fulfilled, contract assets and contract liabilities are not recognized. The balances of accounts receivable from contracts with customers as of December 31, 2025 and 2024, were $2,289 million and $2,184 million, respectively, and are included in Accounts Receivable, Net on the Consolidated Balance Sheets. Losses incurred on receivables from contracts with customers are infrequent and have been immaterial. Certain arrangements provide for the sale of fixed quantities of commodities in future years with pricing mechanisms based on future market prices of the commodity at time of delivery. EOG does not disclose the value of these obligations given the uncertainty of the future realized transaction price.

Crude Oil and Condensate. EOG sells its crude oil and condensate production at the wellhead or further downstream at a contractually-specified delivery point. Revenue is recognized when control transfers to the customer based on contract terms which reflect prevailing market prices. Any costs incurred prior to the transfer of control, such as gathering and transportation, are recognized as Gathering, Processing and Transportation Costs.

F-12

Natural Gas Liquids. EOG delivers certain of its natural gas production to either EOG-owned processing facilities or third-party processing facilities, where extraction of NGLs occurs. For EOG-owned facilities, revenue is recognized after processing upon transfer of control to the customer. For third-party facilities, extracted NGLs are sold to the owner of the processing facility at the tailgate, or EOG takes possession and sells the extracted NGLs at the tailgate or exercises its option to sell further downstream to various customers. Under typical arrangements for third-party facilities, revenue is recognized after processing upon the transfer of control of the NGLs to the customer, either at the tailgate of the processing plant or further downstream. EOG recognizes revenues based on contract terms which reflect prevailing market prices, with any costs incurred prior to the transfer of control, such as processing, transportation and fractionation fees, recognized as Gathering, Processing and Transportation Costs.

Natural Gas. EOG sells its natural gas production either at the wellhead or further downstream at a contractually-specified delivery point. In connection with the extraction of NGLs, EOG sells residue gas under separate agreements. Typically, EOG takes possession of the natural gas at the tailgate of the processing facility and sells it at the tailgate or further downstream. In each case, EOG recognizes revenues when control transfers to the customer, based on contract terms which reflect prevailing market prices.

Gathering, Processing and Marketing. Gathering, processing and marketing revenues represent sales of third-party crude oil and condensate, NGLs and natural gas, as well as fees associated with gathering and processing third-party natural gas and revenues from sales of EOG-owned sand. EOG evaluates whether it is the principal or agent under these transactions. As control of the underlying commodity is transferred to EOG prior to the gathering, processing and marketing activities, EOG considers itself the principal of these arrangements. Accordingly, EOG recognizes these transactions on a gross basis. Purchases of third-party commodities are recorded as Marketing Costs, with sales of third-party commodities and fees received for gathering and processing recorded as Gathering, Processing and Marketing revenues.

Capitalized Interest Costs. Interest costs have been capitalized as a part of the historical cost of unproved oil and gas properties. The amount capitalized is an allocation of the interest cost incurred during the reporting period. Capitalized interest is computed only during the exploration and development phases and ceases once production begins. The interest rate used for capitalization purposes is based on the interest rates on EOG's outstanding borrowings.

Accounting for Risk Management Activities. Financial commodity and other derivative instruments are recorded on the balance sheet as either an asset or liability measured at fair value, and changes in the instrument's fair value are recognized currently in earnings unless specific hedge accounting criteria are met. During the three-year period ended December 31, 2025, EOG elected not to designate any of its financial commodity and other derivative instruments as accounting hedges and, accordingly, changes in the fair value of these outstanding derivative instruments are recognized as gains or losses in the period of change. The gains or losses are recorded as Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net on the Consolidated Statements of Income and Comprehensive Income. The related cash flow impact of settled contracts is reflected as cash flows from operating activities. EOG employs net presentation of financial commodity and other derivative assets and liabilities for financial reporting purposes when such assets and liabilities are with the same counterparty and subject to a master netting arrangement. See Note 12.

Income Taxes. Income taxes are accounted for using the asset and liability approach. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. EOG assesses the realizability of deferred tax assets and recognizes valuation allowances as appropriate. See Note 6.

Foreign Currency Translation. The United States dollar is the functional currency for all of EOG's consolidated subsidiaries except for its Canadian subsidiaries, for which the functional currency is the Canadian dollar. For its Canadian subsidiaries, asset and liability accounts are translated at year-end exchange rates and revenues and expenses are translated at average exchange rates prevailing during the year. Translation adjustments are included in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets. Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period. See Note 4.

Net Income Per Share. Basic net income per share is computed on the basis of the weighted-average number of common shares outstanding during the period. Diluted net income per share is computed based upon the weighted-average number of common shares outstanding during the period plus the assumed issuance of common shares for all potentially dilutive securities. See Note 9.

Stock-Based Compensation. EOG measures the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. See Note 7.

F-13

Leases. In the ordinary course of business, EOG enters into contracts for drilling, fracturing, compression, real estate and other services which contain equipment and other assets and that meet the definition of a lease under ASC "Leases (Topic 842)." The lease term for these contracts, which includes the noncancellable period of the lease plus any renewals at EOG's option that are reasonably certain to be exercised, ranges from one month to 30 years.

Right of use (ROU) assets and related liabilities are recognized on the commencement date on the Consolidated Balance Sheets based on future lease payments, discounted based on the rate implicit in the contract, if readily determinable, or EOG's incremental borrowing rate commensurate with the lease term of the contract. EOG estimates its incremental borrowing rate based on the approximate rate required to borrow on a collateralized basis. Contracts with lease terms of 12 months or less are not recorded on the Consolidated Balance Sheets, but instead are disclosed as short-term lease cost. EOG has elected not to separate non-lease components for most asset classes, except for those asset classes where the non-lease (i.e., service) components comprise a material amount of the minimum lease payments. See Note 17.

Recently Issued Accounting Standards. In October 2023, the FASB issued Accounting Standards Update (ASU) 2023-06, "Disclosure Improvements." The ASU incorporates several disclosure and presentation requirements currently residing in United States Securities and Exchange Commission (SEC) Regulations S-X and S-K. The amendments will be applied prospectively and are effective when the SEC removes the related requirements from Regulations S-X or S-K (as the case may be). Any amendments the SEC does not remove by June 30, 2027, will not be effective. As EOG is currently subject to these SEC requirements, this ASU is not expected to have a material impact on EOG's consolidated financial statements or related disclosures.

In December 2023, the FASB issued ASU 2023-09, "Income Taxes (Topic 740): Improvements to Income Tax Disclosures" (ASU 2023-09). ASU 2023-09 requires companies to disclose, on an annual basis, specific categories in the effective tax rate reconciliation and provide additional information for reconciling items that meet a quantitative threshold. In addition, ASU 2023-09 requires companies to disclose additional information about income taxes paid. The new standard is effective for annual periods beginning after December 15, 2024. EOG adopted ASU 2023-09 on a retrospective basis in the fourth quarter of 2025, which did not have a material impact on its consolidated financial statements; however, additional income tax disclosures are required. See Note 6.

In March 2024, the SEC adopted final rules under SEC Release No. 33-11275, The Enhancement and Standardization of Climate-Related Disclosures for Investors. The rules amending Regulation S-X will require public entities to provide certain climate-related information in their annual reports and registration statements. The rules were scheduled to be effective for large accelerated filers commencing with the fiscal period beginning January 1, 2025. In April 2024, the SEC voluntarily stayed the rules pending judicial review. The rules have since been stayed in abeyance by the U.S. Court of Appeals for the Eighth Circuit until such time as the SEC reconsiders the challenged rules by notice-and-comment rulemaking or renews its defense of the rules. EOG will continue to monitor these developments.

In November 2024, the FASB issued ASU 2024-03, "Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses" (ASU 2024-03), which requires disaggregated disclosure of income statement expenses for public business entities (PBEs). ASU 2024-03 requires PBEs to disaggregate certain expense captions from the face of the income statement. The ASU does not change or remove any existing expense disclosure requirements. The ASU is effective for PBEs for fiscal years beginning after December 15, 2026 and interim periods within fiscal years beginning after December 15, 2027. Although permitted, EOG does not intend to early adopt. EOG is currently evaluating the impact of the standard on its financial statement disclosures.

F-14

2. Long-Term Debt

Long-Term Debt at December 31, 2025 and 2024 consisted of the following (in millions):

			2025						2024
3.15% Senior Notes due 2025			$	—					$	500
4.15% Senior Notes due 2026			—						750
6.65% Senior Notes due 2028			140						140
4.400% Senior Notes due 2028			500						—
4.375% Senior Notes due 2030			750						750
4.400% Senior Notes due 2031			750						—
5.000% Senior Notes due 2032			1,250						—
3.90% Senior Notes due 2035			500						500
5.10% Senior Notes due 2036			250						250
5.350% Senior Notes due 2036			1,250						—
4.950% Senior Notes due 2050			750						750
5.650% Senior Notes due 2054			1,000						1,000
5.950% Senior Notes due 2055			750						—
Long-Term Debt			7,890						4,640
Finance Leases (see Note 17)			117						150
Less: Current Portion of Long-Term Debt			27						532
Unamortized Debt Discount			57						33
Debt Issuance Costs			14						5
Total Long-Term Debt			$	7,909					$	4,220

The senior notes in the table above are senior, unsecured obligations that rank equally in right of payment with all of EOG's other unsecured and unsubordinated outstanding debt. At December 31, 2025, the aggregate annual maturities of current and long-term debt (excluding finance lease obligations) were zero in 2026, zero in 2027, $640 million in 2028, zero in 2029 and $750 million in 2030.

At December 31, 2025 and 2024, EOG had no outstanding commercial paper borrowings and did not utilize any commercial paper borrowings during 2025 or 2024.

On November 21, 2024, EOG closed on its offering of $1.0 billion aggregate principal amount of its 5.650% Senior Notes due 2054 (the Notes). Interest on the Notes is payable semi-annually in arrears on June 1 and December 1 of each year, beginning on June 1, 2025. EOG received net proceeds of $985 million from the issuance of the Notes, which were used for general corporate purposes, including (i) the repayment of the $500 million aggregate principal amount of its 3.15% Senior Notes due 2025 and (ii) the funding of future capital expenditures.

On April 1, 2025, EOG repaid upon maturity the $500 million aggregate principal amount of its 3.15% Senior Notes due 2025.

On July 1, 2025, EOG closed on its offering of $500 million aggregate principal amount of its 4.400% Senior Notes due 2028, $1.25 billion aggregate principal amount of its 5.000% Senior Notes due 2032, $1.25 billion aggregate principal amount of its 5.350% Senior Notes due 2036 and $500 million aggregate principal amount of its 5.950% Senior Notes due 2055 (collectively, the July Notes). Interest on the July Notes is payable semi-annually in arrears on January 15 and July 15 of each year, beginning on January 15, 2026. EOG received net proceeds of $3.47 billion from the issuance of the July Notes, which were used for general corporate purposes, including the payment of a portion of the consideration for the acquisition of Encino and related fees, costs and expenses.

F-15

On November 24, 2025, EOG closed on its offering of $750 million aggregate principal amount of its 4.400% Senior Notes due 2031 and $250 million aggregate principal amount of its 5.950% Senior Notes due 2055 (collectively, the November Notes). Interest on the November Notes is payable semi-annually in arrears on January 15 and July 15 of each year, beginning on January 15, 2026. EOG received net proceeds of $996 million from the issuance of the November Notes, which were used for general corporate purposes, including the repayment of the $750 million aggregate principal amount of its 4.15% Senior Notes due 2026.

On December 24, 2025, EOG redeemed the $750 million aggregate principal amount of its 4.15% Senior Notes prior to their maturity in 2026.

On December 3, 2025, EOG entered into a new $3.0 billion senior unsecured Revolving Credit Agreement (New Facility) with domestic and foreign lenders (Banks). The New Facility replaced EOG's $1.9 billion senior unsecured Revolving Credit Agreement, dated as of June 7, 2023 (2023 Facility), with domestic and foreign lenders, which had a scheduled maturity date of June 7, 2028, and which was terminated by EOG (without penalty), effective as of December 3, 2025, in connection with the completion of the New Facility.

The New Facility has a scheduled maturity date of December 3, 2030 and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods, subject to, among certain other terms and conditions, the consent of the Banks holding greater than 50% of the commitments then outstanding under the New Facility. The New Facility commits the Banks to provide advances up to an aggregate principal amount of $3.0 billion outstanding at any given time, with an option for EOG to request increases in the aggregate commitments to an amount not to exceed $4.0 billion, subject to certain terms and conditions. The New Facility also includes a swingline subfacility and a letter of credit subfacility.

Advances under the New Facility will accrue interest based, at EOG’s option, on either the Secured Overnight Financing Rate (SOFR) plus an applicable margin, or the Base Rate (as defined in the New Facility) plus an applicable margin. The applicable margin used in connection with interest rates and fees will be based on EOG’s credit rating for its senior unsecured long-term debt at the applicable time.

The New Facility contains representations, warranties, covenants and events of default that EOG believes are customary for investment grade, senior unsecured commercial bank credit agreements, including a financial covenant for the maintenance of a ratio of Total Debt to Total Capitalization (as such terms are defined in the New Facility) of no greater than 65%.

There were no borrowings or letters of credit outstanding under the 2023 Facility as of (i) December 31, 2024 or (ii) the December 3, 2025 effective date of the closing of the New Facility and termination of the 2023 Facility. Further, at December 31, 2025, there were no borrowings or letters of credit outstanding under the New Facility. The SOFR and Base Rate (inclusive of the applicable margins), had there been any amounts borrowed under the New Facility at December 31, 2025, would have been 4.59% and 6.75%, respectively.

3. Stockholders' Equity

Common Stock. In November 2021, EOG's Board of Directors (Board) established a new share repurchase authorization allowing for the repurchase by EOG of up to $5 billion of its common stock and, in November 2024, increased such share repurchase authorization from $5 billion to $10 billion, effective November 7, 2024 (Share Repurchase Authorization).

Under the Share Repurchase Authorization, EOG may repurchase shares from time to time, at management's discretion, in accordance with applicable securities laws, including through open market transactions, privately negotiated transactions or any combination thereof. The timing and amount of repurchases is at the discretion of EOG's management and depends on a variety of factors, including the trading price of EOG's common stock, corporate and regulatory requirements, other market and economic conditions, the availability of cash to effect repurchases and EOG's anticipated future capital expenditures and other commitments requiring cash. Repurchased shares are held as treasury shares and are available for general corporate purposes. The Share Repurchase Authorization has no time limit, does not require EOG to repurchase a specific number of shares and may be modified, suspended, or terminated by the Board at any time. During the year ended December 31, 2025, EOG repurchased 21.7 million shares of common stock for approximately $2.5 billion (inclusive of transaction fees and commissions) pursuant to the Share Repurchase Authorization. As of December 31, 2025, approximately $3.3 billion remained available for repurchases under the Share Repurchase Authorization. Included in the Treasury Stock Repurchased amounts on the Consolidated Statements of Stockholders' Equity for the year ended December 31, 2025, is $23.2 million of estimated federal excise tax.

F-16

Shares of common stock are from time to time withheld by, or returned to, EOG in satisfaction of tax withholding obligations arising upon the exercise of employee stock options or stock-settled stock appreciation rights (SARs), as well as the vesting of restricted stock, restricted stock units or restricted stock units with performance-based conditions (performance units), or in payment of the exercise price of employee stock options. Such shares withheld or returned have not counted, and will not count, against the Share Repurchase Authorization. Shares purchased, withheld and returned are held in treasury for, among other purposes, fulfilling any obligations arising under EOG's stock-based compensation plans and any other approved transactions or activities for which such shares of common stock may be required.

On February 24, 2026, the Board declared a quarterly cash dividend on the common stock of $1.02 per share to be paid on April 30, 2026, to stockholders of record as of April 16, 2026.

The following summarizes Common Stock activity for each of the years ended December 31, 2025, 2024 and 2023 (in thousands):

			Common Shares
			Issued						Treasury						Outstanding
Balance at December 31, 2022			588,397						(700)						587,697
Common Stock Issued Under Stock-Based Compensation Plans			159						—						159
Treasury Stock Purchased (1)			—						(9,177)						(9,177)
Common Stock Issued Under Employee Stock Purchase Plan			193						—						193
Treasury Stock Issued Under Stock-Based Compensation Plans			—						1,989						1,989
Balance at December 31, 2023			588,749						(7,888)						580,861
Common Stock Issued Under Stock-Based Compensation Plans			—						—						—
Treasury Stock Purchased (1)			—						(26,350)						(26,350)
Common Stock Issued Under Employee Stock Purchase Plan			191						—						191
Treasury Stock Issued Under Stock-Based Compensation Plans			—						2,507						2,507
Balance at December 31, 2024			588,940						(31,731)						557,209
Common Stock Issued Under Stock-Based Compensation Plans			—						—						—
Treasury Stock Purchased (1)			—						(22,219)						(22,219)
Common Stock Issued Under Employee Stock Purchase Plan			104						—						104
Treasury Stock Issued Under Stock-Based Compensation Plans			—						2,576						2,576
Balance at December 31, 2025			589,044						(51,374)						537,670

(1) Represents shares that were repurchased under the Share Repurchase Authorization and/or that were withheld by or returned to EOG (i) in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or SARs or the vesting of restricted stock, restricted stock unit or performance unit grants or (ii) in payment of the exercise price of employee stock options.

Preferred Stock. EOG currently has one authorized series of preferred stock - its Series E junior participating preferred stock (Series E Preferred Stock), of which 3,000,000 shares have been designated and authorized. As of December 31, 2025, no shares of Series E Preferred Stock have been issued or are outstanding.

F-17

4. Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss includes certain transactions that have been reported in the Consolidated Statements of Stockholders' Equity. The components of Accumulated Other Comprehensive Loss at December 31, 2025 and 2024 consisted of the following (in millions):

			Foreign Currency Translation Adjustment						Other						Total
December 31, 2023			$	(8)					$	(1)					$	(9)
Other comprehensive income before taxes			4						1						5
Tax effects			—						—						—
Other comprehensive income			4						1						5
December 31, 2024			(4)						—						(4)
Other comprehensive loss before taxes			(2)						(1)						(3)
Tax effects			—						—						—
Other comprehensive loss			(2)						(1)						(3)
December 31, 2025			$	(6)					$	(1)					$	(7)

No significant amount was reclassified out of Accumulated Other Comprehensive Loss during the years ended December 31, 2025 and 2024.

5. Other Income, Net

Other income, net for 2025 was primarily interest income ($210 million). Other income, net for 2024 included interest income ($277 million), partially offset by an upward adjustment to deferred compensation expense ($5 million). Other income, net for 2023 included interest income ($240 million), partially offset by an upward adjustment to deferred compensation expense ($7 million).

F-18

6. Income Taxes

The components of EOG's Net Deferred Income Tax Liabilities at December 31, 2025 and 2024 were as follows (in millions):

			2025						2024
Deferred Income Tax Assets (Liabilities)
Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization			$	(54)					$	(56)
Foreign Asset Retirement Obligations			108						89
Foreign Accrued Expenses and Liabilities			10						10
Foreign Net Operating Losses			130						127
Foreign Valuation Allowances			(155)						(131)
Total Net Deferred Income Tax Assets			$	39					$	39
Deferred Income Tax (Assets) Liabilities
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization			$	7,055					$	6,040
Deferred Compensation Plans			(73)						(65)
Equity Awards			(68)						(65)
Other			(60)						(44)
Total Net Deferred Income Tax Liabilities			$	6,854					$	5,866
Net Deferred Income Tax Liabilities			$	6,815					$	5,827

The components of EOG's Income Before Income Taxes for the years indicated below were as follows (in millions):

			2025						2024						2023
United States			$	6,366					$	8,157					$	9,576
Foreign			(4)						61						113
Income Before Income Taxes			$	6,362					$	8,218					$	9,689

The components of EOG's Income Tax Provision for the years indicated below were as follows (in millions):

			2025						2024						2023
Current:
Federal			$	988					$	1,244					$	1,334
State			43						102						76
Foreign			8						2						5
Total			1,039						1,348						1,415
Deferred:
Federal			341						425						628
State			3						40						55
Foreign			(1)						2						—
Total			343						467						683
Other Non-Current:
Foreign			—						—						(3)
Total			—						—						(3)
Income Tax Provision			$	1,382					$	1,815					$	2,095

F-19

The differences between taxes computed at the United States federal statutory tax rate and EOG's Effective Income Tax Rate for the years indicated below were as follows (in millions, except percentages):

			2025												2024												2023
			Amount						Percent						Amount						Percent						Amount						Percent
Statutory Federal Income Tax Rate			$	1,336					21		%				$	1,726					21		%				$	2,035					21		%
State and Local Income Taxes, Net of Federal Benefit (1)			37						1		%				112						1		%				104						1		%
Foreign Tax Effects			7						0		%				(9)						0		%				(17)						0		%
Effects of Cross-Border Tax Laws			16						0		%				21						0		%				9						0		%
Tax Credits			(23)						0		%				(12)						0		%				—						0		%
Changes in Valuation Allowances			5						0		%				1						0		%				—						0		%
Nontaxable or Nondeductible Items			12						0		%				6						0		%				9						0		%
Changes in Unrecognized Tax Benefits			—						0		%				—						0		%				(4)						0		%
Other Adjustments			(8)						0		%				(30)						0		%				(41)						0		%
Effective Income Tax Rate			$	1,382					22		%				$	1,815					22		%				$	2,095					22		%

(1) New Mexico made up the majority (greater than 50%) of the state tax effect for the years ended December 31, 2025 and December 31, 2024. Texas made up the majority (greater than 50%) of the state tax effect for the year ended December 31, 2023.

The components of EOG’s Total Income Taxes Paid (Net of Refunds) for the years indicated below were as follows (in millions):

			2025						2024						2023
Federal (1)			$	1,758					$	701					$	1,110
State
Texas (2)			—						45						69
Other			105						28						45
Foreign			6						5						5
Total Income Taxes Paid (Net of Refunds)			$	1,869					$	779					$	1,229

(1) The year ended December 31, 2025 includes cash payments related to the purchase of tax credits and certain postponed 2024 tax year payments related to tax relief for severe weather events which occurred in 2024. The year ended December 31, 2024 includes cash payments related to the purchase of tax credits.

(2) The amount of income taxes paid during the year does not meet the 5% disaggregation threshold for the year ended December 31, 2025.

Deferred tax assets are recorded for future deductible amounts and certain other tax benefits, such as tax net operating losses (NOLs) and tax credit carryforwards, provided that management assesses the utilization of such assets to be "more likely than not." Management assesses the available positive and negative evidence to estimate if sufficient future taxable income will be generated to use the existing deferred tax assets. On the basis of this evaluation, EOG has recorded valuation allowances for the portion of certain deferred tax assets that management does not believe are more likely than not to be realized.

F-20

The components of the change in EOG's Valuation Allowances for deferred income tax assets for the years indicated below were as follows (in millions):

			2025						2024						2023
Beginning Balance			$	201					$	216					$	207
Increase (1)			30						15						8
Decrease (2)			(17)						—						—
Other (3)			5						(30)						1
Ending Balance			$	219					$	201					$	216

(1) Increase in valuation allowance related to the generation of tax NOLs and other deferred tax assets.

(2) Decrease in valuation allowance associated with adjustments to certain deferred tax assets and their related allowances.

(3) Represents dispositions, revisions and/or foreign exchange rate variances and the effect of statutory income tax rate changes.

As of December 31, 2025, EOG has NOL carryforwards of approximately $400 million (federal), $1.8 billion (state) and $454 million (foreign). The federal NOL, as well as certain state and foreign NOLs, have indefinite carryforward periods. All other state NOLs expire between 2026 and 2040 and the other foreign NOLs can be carried forward, some up to 20 years. The ability to utilize these NOLs, in any jurisdiction, depends on sufficient future taxable income and whether there are any statutory limitations. Certain limitations related to ownership changes, among others, may apply to the federal and state NOLs acquired from Encino in 2025. As described previously, these NOLs and other less significant tax benefits have been evaluated for the likelihood of utilization, and valuation allowances have been established for the portion of these deferred income tax assets that do not meet the “more likely than not” threshold.

In 2025, EOG purchased approximately $440 million of energy-related tax credits from a third-party seller(s) which were used to reduce tax year 2025 estimated tax payments. The cash payments made to the third-party seller(s) are included in income taxes, net of refunds received, disclosed in Note 10.

As of December 31, 2025, EOG does not have any unrecognized tax benefits. Consequently, no interest or penalties have been recognized in the Consolidated Statement of Income and Comprehensive Income. When applicable, EOG's accounting policy is to record interest and penalties to the income tax provision. EOG and its subsidiaries file income tax returns and are subject to tax audits in the United States and various state, local and foreign jurisdictions. Generally, EOG's earliest open tax year in its principal jurisdiction, the United States, is 2022.

EOG's foreign subsidiaries' undistributed earnings are not considered to be permanently reinvested outside of the United States and when appropriate, deferred income taxes have been accrued on any such outside basis differences. Additionally, EOG's foreign earnings may be subject to the United States federal "Global Intangible Low-Taxed Income" (GILTI) inclusion. EOG records any GILTI tax as a period expense.

On July 4, 2025, the One Big Beautiful Bill Act was signed into law, which primarily made permanent (generally with amendments) certain tax provisions of the 2017 Tax Cuts and Jobs Act. Included, among others, were changes to business tax provisions such as permanently restoring 100% bonus depreciation and full domestic research expensing. While the legislation reduced EOG's 2025 cash tax payments, it did not have a material impact on EOG's earnings.

7. Employee Benefit Plans

Stock-Based Compensation

During 2025, EOG maintained various stock-based compensation plans as discussed below. EOG recognizes compensation expense on grants of stock options, SARs, restricted stock, restricted stock units and restricted stock units with performance-based conditions (together with the performance units granted under the 2008 Plan (as defined below), Performance Units) and grants made under the EOG Resources, Inc. Employee Stock Purchase Plan (ESPP). Stock-based compensation expense is calculated based upon the grant date estimated fair value of the awards, net of forfeitures, based upon EOG's historical employee turnover rate. Compensation expense is amortized over the shorter of the vesting period or the period from the grant date to the date the employee becomes eligible for retirement without requiring company approval, with a minimum amortization period of one year.

F-21

Stock-based compensation expense is included on the Consolidated Statements of Income and Comprehensive Income based upon the job functions of the employees receiving the grants. Compensation expense related to EOG's stock-based compensation plans for the years ended December 31, 2025, 2024 and 2023 was as follows (in millions):

			2025						2024						2023
Lease and Well			$	76					$	68					$	54
Gathering, Processing and Transportation Costs			6						6						4
Exploration Costs			28						27						24
General and Administrative			106						98						95
Total			$	216					$	199					$	177

The Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (2008 Plan) provided for grants of stock options, SARs, restricted stock and restricted stock units, Performance Units, and other stock-based awards.

EOG's stockholders approved the EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (2021 Plan) at the 2021 Annual Meeting of Stockholders. Therefore, no further grants were made from the 2008 Plan from and after the April 29, 2021 effective date of the 2021 Plan. The 2021 Plan provides for grants of stock options, SARs, restricted stock and restricted stock units, Performance Units and other stock-based awards, up to an aggregate maximum of 20 million shares of common stock, plus any shares that were subject to outstanding awards under the 2008 Plan as of April 29, 2021, that are subsequently canceled or forfeited, expire or are otherwise not issued or are settled in cash. Under the 2021 Plan, grants may be made to employees and non-employee members of EOG's Board.

The vesting schedules for grants of stock options, SARs, restricted stock and restricted stock units, and Performance Units are generally as follows:

Grant Type						Vesting Schedule
Stock Options/SARs						Vesting in increments of one-third on each of the first three anniversaries, respectively, of the date of grant
Restricted Stock/Restricted Stock Units						"Cliff" vesting three years from the date of grant
Performance Units						"Cliff" vesting on the February 28th following the three-year performance period and the Compensation and Human Resources Committee's certification of the applicable performance multiple

At December 31, 2025, approximately 11 million common shares remained available for grant under the 2021 Plan. EOG's policy is to issue shares related to the 2021 Plan from previously authorized unissued shares or treasury shares to the extent treasury shares are available.

During 2025, 2024 and 2023, EOG issued shares in connection with stock option/SAR exercises, restricted stock grants, restricted stock unit and Performance Unit releases and ESPP purchases. Excess net tax benefits / (deficiencies) recognized within the income tax provision were $2 million, $19 million and $32 million for the years ended December 31, 2025, 2024 and 2023, respectively.

F-22

Stock Options and Stock-Settled Stock Appreciation Rights and Employee Stock Purchase Plan. Participants in EOG's stock-based compensation plans (including the 2008 Plan and 2021 Plan) have been or may be granted options to purchase shares of Common Stock. In addition, participants in EOG's stock-based compensation plans (including the 2008 Plan and 2021 Plan) have been or may be granted SARs, representing the right to receive shares of Common Stock based on the appreciation in the stock price from the date of grant on the number of SARs granted. EOG did not grant any stock options or SARs in 2025, 2024 and 2023. EOG's ESPP allows eligible employees to semi-annually purchase, through payroll deductions, shares of Common Stock at 85 percent of the fair market value at specified dates. Contributions to the ESPP are limited to 15 percent of the employee's pay (subject to certain ESPP limits) during each of the two six-month offering periods each year. Stock-based compensation expense related to stock option, SAR and ESPP grants totaled $6 million, $18 million and $24 million for the years ended December 31, 2025, 2024 and 2023, respectively.

Restricted Stock and Restricted Stock Units. Employees may be granted restricted (non-vested) stock and/or restricted stock units without cost to them. Upon vesting of restricted stock, shares of Common Stock are released to the employee. Upon vesting, restricted stock units are converted into shares of Common Stock and released to the employee. Stock-based compensation expense related to restricted stock and restricted stock units totaled $199 million, $160 million and $137 million for the years ended December 31, 2025, 2024 and 2023, respectively.

The following table sets forth the restricted stock and restricted stock unit transactions for the years ended December 31, 2025, 2024 and 2023 (shares and units in thousands):

			2025												2024												2023
			Number of Shares and Units						Weighted Average Grant Date Fair Value						Number of Shares and Units						Weighted Average Grant Date Fair Value						Number of Shares and Units						Weighted Average Grant Date Fair Value
Outstanding at January 1			4,699						$	122.64					4,364						$	111.24					4,113						$	80.77
Granted			2,155						117.29						1,871						122.45						1,680						131.10
Released (1)			(1,394)						113.93						(1,343)						86.27						(1,295)						42.03
Forfeited			(179)						123.21						(193)						116.18						(134)						93.54
Outstanding at December 31 (2)			5,281						122.73						4,699						122.64						4,364						111.24

(1)

(1)The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2025, 2024 and 2023 was $159 million, $166 million and $166 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date restricted stock and restricted stock units are released.

(2)

(2)The total intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2025, 2024 and 2023 was $555 million, $576 million and $528 million, respectively. The intrinsic value is based on the closing market price of the Common Stock on the last trading day of the year.

At December 31, 2025, unrecognized compensation expense related to restricted stock and restricted stock units totaled $383 million. Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 1.8 years.

Performance Units. EOG grants Performance Units annually to its executive officers and from time to time to other officers, without cost to them. For the grants made prior to September 2022, as more fully discussed in the grant agreements, the applicable performance metric is EOG's total shareholder return (TSR) over a three-year performance period (Performance Period) relative to the TSR over the same period of a designated group of peer companies. Upon the application of the applicable performance multiple at the completion of the Performance Period, a minimum of 0% and a maximum of 200% of the Performance Units granted could be outstanding.

F-23

For the grants made beginning in September 2022, as more fully discussed in the grant agreements, the applicable performance metrics are 1) EOG's TSR over the Performance Period relative to the TSR over the same period of a designated group of peer companies and 2) EOG's average return on capital employed (ROCE) over the Performance Period. At the end of the Performance Period, a performance multiple based on EOG's relative TSR ranking will be determined, with a minimum performance multiple of 0% and a maximum performance multiple of 200%. A specified modifier ranging from -70% to +70% will then be applied to the performance multiple based on EOG's average ROCE over the Performance Period, provided that in no event shall the performance multiple, after applying the ROCE modifier, be less than 0% or exceed 200%. Furthermore, if EOG's TSR over the Performance Period is negative (i.e., less than 0%), the performance multiple will be capped at 100%, regardless of EOG's relative TSR ranking or average ROCE over the Performance Period.

The fair value of the Performance Units is estimated using a Monte Carlo simulation. Stock-based compensation expense related to the Performance Unit grants totaled $11 million, $12 million and $16 million for the years ended December 31, 2025, 2024 and 2023, respectively.

Weighted average fair values and valuation assumptions used to value Performance Units during the years ended December 31, 2025, 2024 and 2023 were as follows:

			2025						2024						2023
Weighted Average Fair Value of Grants			$	122.70					$	130.31					$	142.20
Expected Volatility			30.93		%				35.20		%				44.76		%
Risk-Free Interest Rate			3.62		%				3.46		%				4.53		%

Expected volatility is based on the term-matched historical volatility over the simulated term, which is calculated as the time between the grant date and the end of the performance period. The risk-free interest rate is derived from the Treasury Constant Maturities yield curve on the grant date.

F-24

The following table sets forth the Performance Unit transactions for the years ended December 31, 2025, 2024 and 2023 (units in thousands):

			2025												2024												2023
			Number of Units						Weighted Average Grant Date Fair Value						Number of Units						Weighted Average Grant Date Fair Value						Number of Units						Weighted Average Grant Date Fair Value
Outstanding at January 1			559						$	119.05					630						$	95.49					688						$	83.82
Granted			148						122.70						109						130.31						114						142.20
Granted for Performance Multiple (1)			53						96.61						—						—						—						—
Released (2)			(267)						96.61						(45)						43.33						(86)						79.98
Forfeited for Performance Multiple (3)			—						—						(135)						43.33						(86)						79.98
Outstanding at December 31 (4)			493			(5)			129.87						559						119.05						630						95.49

(1)Upon completion of the Performance Period for the Performance Units granted in 2021, a performance multiple of 125% was applied to each of the grants resulting in additional grants of Performance Units in February 2025.

(2)The total intrinsic value of Performance Units released during the years ended December 31, 2025, 2024 and 2023 was $34 million, $5 million and $10 million, respectively. The intrinsic value is based upon the closing price of the Common Stock on the date the Performance Units are released.

(3)Upon completion of the Performance Period for the Performance Units granted in 2020 and 2019, a performance multiple of 25% and 50%, respectively, was applied to each of the grants resulting in a forfeiture of Performance Units in February 2024 and February 2023.

(4)The total intrinsic value of Performance Units outstanding at December 31, 2025, 2024 and 2023 was $52 million, $69 million and $76 million, respectively.

(5)Upon the application of the relevant performance multiple at the completion of each of the remaining Performance Periods, a minimum of zero and a maximum of 986 Performance Units could be outstanding.

At December 31, 2025, unrecognized compensation expense related to Performance Units totaled $28 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 1.7 years.

Upon completion of the Performance Period for the Performance Units granted in September 2022, a performance multiple of 100% was applied to the grants resulting in no additional grant of Performance Units in February 2026.

Other Stock Awards. In August 2024, and in recognition of EOG's 25th anniversary as an independent public company, EOG awarded 25 shares of EOG common stock to each of its non-executive officer employees. Stock-based compensation expense related to the awards totaled $9 million for the year ended December 31, 2024, and the intrinsic value of the awards was $9 million (based upon the closing price of EOG's common stock on the August 16, 2024 award date). A gross-up to account for income taxes was also recognized.

Pension Plans. EOG has a defined contribution pension plan in place for most of its employees in the United States. EOG's contributions to the pension plan are based on various percentages of compensation and, in some instances, are based upon the amount of the employees' contributions. EOG's total costs recognized for the plan were $76 million, $66 million and $61 million for 2025, 2024 and 2023, respectively.

In addition, EOG's Trinidadian subsidiary maintains a contributory defined benefit pension plan and a matched savings plan. These pension plans are available to most employees of the Trinidadian subsidiary. EOG's combined contributions to these plans were $1 million, for each of 2025, 2024 and 2023, respectively.

For the Trinidadian defined benefit pension plan, the benefit obligation, fair value of plan assets and (prepaid)/accrued benefit cost totaled $17 million, $18 million and $(1.9) million, respectively, at December 31, 2025, and $16 million, $17 million and $(1.4) million, respectively, at December 31, 2024.

Postretirement Health Care. EOG has postretirement medical and dental benefits in place for eligible United States and Trinidad employees and their eligible dependents, the costs of which are not material.

F-25

8. Commitments and Contingencies

Letters of Credit and Guarantees. At December 31, 2025 and 2024, respectively, EOG had standby letters of credit and guarantees outstanding totaling $768 million and $825 million, primarily representing guarantees of payment or performance obligations on behalf of subsidiaries. As of February 18, 2026, EOG had received no demands for payment under these guarantees.

Minimum Commitments. At December 31, 2025, total minimum commitments from purchase and service obligations and transportation and storage service commitments not qualifying as leases, based on current transportation and storage rates and the foreign currency exchange rates used to convert Canadian dollars into United States dollars at December 31, 2025, were as follows (in millions):

			Total Minimum Commitments
2026			$	1,671
2027			1,344
2028			1,074
2029			970
2030			773
2031 and beyond			2,235
			$	8,067

Delivery Commitments. EOG sells crude oil, natural gas and purity products from its producing operations under a variety of contractual arrangements. At December 31, 2025, EOG was committed to deliver to multiple parties aggregate fixed quantities of crude oil of 24 million barrels (MMBbls) in 2026, 11 MMBbls in 2027 and 4 MMBbls in 2028. At December 31, 2025, EOG was committed to deliver to multiple parties aggregate fixed quantities of natural gas of 573 billion cubic feet (Bcf) in 2026, 370 Bcf in 2027, 338 Bcf in 2028, 336 Bcf in 2029, 331 Bcf in 2030 and 3,020 Bcf thereafter. Additionally at December 31, 2025, EOG was committed to deliver to multiple parties aggregate fixed quantities of purity products of 24 MMBbls in 2026. All delivery commitments are expected to be sourced from future production of available reserves.

Contingencies. There are currently various suits and claims pending against EOG that have arisen in the ordinary course of EOG's business, including contract disputes, personal injury and property damage claims and title disputes. While the ultimate outcome and impact on EOG cannot be predicted, management believes that the resolution of these suits and claims will not, individually or in the aggregate, have a material adverse effect on EOG's consolidated financial position, results of operations or cash flow. EOG records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

F-26

9. Net Income Per Share

The following table sets forth the computation of Net Income Per Share for the years ended December 31, 2025, 2024 and 2023 (in millions, except per share data):

			2025						2024						2023
Numerator for Basic and Diluted Earnings per Share -
Net Income			$	4,980					$	6,403					$	7,594
Denominator for Basic Earnings per Share -
Weighted Average Shares			543						566						581
Potential Dilutive Common Shares -
Stock Options/SARs			—						1						1
Restricted Stock/Units and Performance Units			3						2						2
Denominator for Diluted Earnings per Share -
Adjusted Diluted Weighted Average Shares			546						569						584
Net Income Per Share
Basic			$	9.17					$	11.31					$	13.07
Diluted			$	9.12					$	11.25					$	13.00

The diluted earnings per share calculation excludes stock option, SAR, restricted stock, restricted stock unit, Performance Unit and ESPP grants that were anti-dilutive. Shares underlying the excluded stock option, SAR and ESPP grants were zero, zero and 1 million for the years ended December 31, 2025, 2024 and 2023, respectively.

10. Supplemental Cash Flow Information

Net cash paid for interest and income taxes was as follows for the years ended December 31, 2025, 2024 and 2023 (in millions):

			2025						2024						2023
Interest, Net of Capitalized Interest			$	185					$	140					$	161
Income Taxes, Net of Refunds Received (1)			$	1,869					$	779					$	1,229

(1)Includes cash paid for the purchase of energy-related tax credits from a third-party seller(s) for the years ended December 31, 2025 and 2024. See Note 6.

EOG's accrued capital expenditures and amounts recorded within accounts payable at December 31, 2025, 2024 and 2023 were $878 million, $725 million and $631 million, respectively.

Non-cash investing activities for the year ended December 31, 2025, included additions of $24 million to EOG's oil and gas properties as a result of property exchanges.

Non-cash investing activities for the year ended December 31, 2024, included additions of $109 million to EOG's oil and gas properties as a result of property exchanges.

Non-cash investing activities for the year ended December 31, 2023, included additions of $195 million to EOG's oil and gas properties as a result of property exchanges.

Cash paid for leases for the years ended December 31, 2025, 2024 and 2023, is disclosed in Note 17.

F-27

11. Business Segment Information

EOG's operations are all crude oil, NGLs and natural gas exploration and production-related. The Segment Reporting Topic of the ASC establishes standards for reporting information about operating segments in annual and interim financial statements. Operating segments are defined as components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker, or decision-making group, in deciding how to allocate resources and in assessing performance. EOG's chief operating decision makers (CODM) are the Chairman of the Board and Chief Executive Officer, the Executive Vice President and Chief Operating Officer, the Executive Vice President and Chief Financial Officer, the Executive Vice President and Chief Legal Officer, and the Senior Vice Presidents, Exploration and Production.

The CODM routinely review and make operating decisions related to significant issues associated with each of EOG's major producing areas (including in the United States and in Trinidad) and its exploration programs both inside and outside the United States. For segment reporting purposes, the CODM consider the major United States producing areas to be one operating segment. The CODM use operating income (loss) to assess performance and allocate resources.

Financial information by reportable segment is presented below as of and for the years ended December 31, 2025, 2024 and 2023 (in millions):

			United States						Trinidad						Other International						Total
2025
Crude Oil and Condensate			$	12,472					$	29					$	—					$	12,501
Natural Gas Liquids			2,376						—						—						2,376
Natural Gas			2,468						318						5						2,791
Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net			13						—						—						13
Gathering, Processing and Marketing			4,908						6						—						4,914
Gains (Losses) on Asset Dispositions, Net			(40)						6						(1)						(35)
Other, Net			72						—						—						72
Operating Revenues and Other (1)			22,269						359						4						22,632
Lease and Well			1,611						49						15
Gathering, Processing and Transportation Costs			2,133						1						—
Marketing Costs			4,795						—						—
Depreciation, Depletion and Amortization			4,305						155						1
General and Administrative			787						16						17
Taxes Other Than Income			1,227						6						1
Other Segment Items (2) (3)			988						84						56
Operating Income (Loss)			6,423						48						(86)						6,385
Interest Income																					210
Other Income																					2
Interest Expense, Net																					235
Income Before Income Taxes																					6,362
Other Segment Disclosures:
Additions to Oil and Gas Properties, Excluding Dry Hole Costs(6)			12,510						158						73						12,741
Total Property, Plant and Equipment, Net			41,700						539						102						42,341
Total Assets			50,309						1,192						298						51,799
Interest Expense, Net			235						—						—						235
Interest Income			195						10						5						210

F-28

			United States						Trinidad						Other International						Total
2024
Crude Oil and Condensate			$	13,901					$	20					$	—					$	13,921
Natural Gas Liquids			2,106						—						—						2,106
Natural Gas			1,256						295						—						1,551
Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net			204						—						—						204
Gathering, Processing and Marketing			5,799						1						—						5,800
Gains (Losses) on Asset Dispositions, Net			21						(5)						—						16
Other, Net			100						—						—						100
Operating Revenues and Other (4)			23,387						311						—						23,698
Lease and Well			1,532						40						—
Gathering, Processing and Transportation Costs			1,722						—						—
Marketing Costs			5,717						—						—
Depreciation, Depletion and Amortization			3,968						139						1
General and Administrative			639						15						15
Taxes Other Than Income			1,245						3						1
Other Segment Items (2)			509						19						51
Operating Income (Loss)			8,055						95						(68)						8,082
Interest Income																					277
Other Expense																					(3)
Interest Expense, Net																					138
Income Before Income Taxes																					8,218
Other Segment Disclosures:
Additions to Oil and Gas Properties, Excluding Dry Hole Costs			5,213						223						12						5,448
Total Property, Plant and Equipment, Net			33,690						497						25						34,212
Total Assets			45,776						1,220						190						47,186
Interest Expense, Net			138						—						—						138
Interest Income			257						15						5						277

F-29

			United States						Trinidad						Other International						Total
2023
Crude Oil and Condensate			$	13,734					$	14					$	—					$	13,748
Natural Gas Liquids			1,884						—						—						1,884
Natural Gas			1,530						214						—						1,744
Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net			818						—						—						818
Gathering, Processing and Marketing			5,806						—						—						5,806
Gains on Asset Dispositions, Net			53						42						—						95
Other, Net			91						—						—						91
Operating Revenues and Other (5)			23,916						270						—						24,186
Lease and Well			1,410						43						1
Gathering, Processing and Transportation Costs			1,620						—						—
Marketing Costs			5,709						—						—
Depreciation, Depletion and Amortization			3,414						78						—
General and Administrative			618						15						7
Taxes Other Than Income			1,278						6						—
Other Segment Items (2)			351						4						29
Operating Income (Loss)			9,516						124						(37)						9,603
Interest Income																					240
Other Expense																					(6)
Interest Expense, Net																					148
Income Before Income Taxes																					9,689
Other Segment Disclosures:
Additions to Oil and Gas Properties, Excluding Dry Hole Costs			5,413						162						4						5,579
Total Property, Plant and Equipment, Net			31,876						404						17						32,297
Total Assets			42,674						1,063						120						43,857
Interest Expense, Net			148						—						—						148
Interest Income			223						12						5						240

(1)EOG had sales activity with two significant purchasers in 2025, one totaling $2.8 billion and the other totaling $2.3 billion of consolidated Operating Revenues and Other in the United States segment.

(2)Other Segment Items include Exploration Costs, Dry Hole Costs and Impairments. For 2025, Other Segment Items primarily consisted of exploration costs and impairments in the United States, exploration and dry hole costs in Trinidad and exploration costs in Other International. For 2024, Other Segment Items primarily consisted of exploration costs and impairments in the United States, dry hole costs in Trinidad and impairment and exploration costs in Other International. For 2023, Other Segment Items primarily consisted of exploration costs and impairments in the United States, exploration costs in Trinidad and impairment and exploration costs in Other International.

(3)EOG recorded pretax impairment charges of $816 million in the United States for proved and unproved oil and gas properties and other assets. See Note 14.

(4)EOG had sales activity with three significant purchasers in 2024, one totaling $2.9 billion, another totaling $2.6 billion and a third totaling $2.5 billion of consolidated Operating Revenues and Other in the United States segment.

(5)EOG had sales activity with three significant purchasers in 2023, one totaling $3.3 billion and two others totaling $2.6 billion each of consolidated Operating Revenues and Other in the United States segment.

(6)Includes oil and gas properties from the Encino acquisition of $6,651 million.

F-30

12. Risk Management Activities

Commodity Price Transactions. EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for crude oil, NGLs and natural gas. EOG utilizes financial commodity derivative instruments, primarily price swap, option, swaption, collar and basis swap contracts, as a means to manage this price risk.

During 2025, 2024 and 2023, EOG elected not to designate any of its financial commodity and other derivative contracts as accounting hedges and, accordingly, accounted for these financial commodity and other derivative contracts using the mark-to-market accounting method. Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net on the Consolidated Statements of Income and Comprehensive Income. The related cash flow impact is reflected in Cash Flows from Operating Activities. During 2025, 2024 and 2023, EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $13 million, $204 million and $818 million, respectively, which included net cash received from (payments for) settlements of crude oil, NGLs and natural gas financial derivative contracts of $(56) million, $214 million and $(112) million, respectively.

Presented below is a comprehensive summary of EOG's financial commodity derivative contracts settled during the year ended December 31, 2025 (closed) and remaining for 2026 and thereafter, as of December 31, 2025 (inclusive of the contracts assumed via novation, from Encino). Natural gas volumes are presented in million British thermal units per day (MMBtud) and prices are presented in dollars per million British Thermal Units ($/MMBtu). NGL volumes are presented in thousand barrels per day (MBbld) and prices are presented in dollars per barrel ($/Bbl).

Natural Gas Financial Price Swap Contracts
												Contracts Sold
Period						Settlement Index						Volume (MMBtud in thousands)						Weighted Average Price ($/MMBtu)
February - July 2025 (closed)						NYMEX Henry Hub						725						$	3.07
August - December 2025 (closed)						NYMEX Henry Hub						1,225						3.32
January 2026 (closed)						NYMEX Henry Hub						460						3.78
February - June 2026						NYMEX Henry Hub						460						3.78
July - December 2026						NYMEX Henry Hub						450						3.79

Natural Gas Basis Swap Contracts
												Contracts Sold
Period						Settlement Index						Volume (MMBtud in thousands)						Weighted Average Price Differential ($/MMBtu)
January - December 2025 (closed)						NYMEX Henry Hub Houston Ship Channel (HSC) Differential (1)						10						$	0.00

(1) This settlement index is used to fix the differential between pricing at the Houston Ship Channel and NYMEX Henry Hub prices.

F-31

Natural Gas Collar Contracts
												Contracts Sold
																		Weighted Average Price ($/MMBtu)
Period						Settlement Index						Volume (MMBtud in thousands)						Ceiling Price						Floor Price
September 2025 (closed)						NYMEX Henry Hub						50						$	4.65					$	3.81
October - December 2025 (closed)						NYMEX Henry Hub						60						4.63						3.76
January 2026 (closed)						NYMEX Henry Hub						80						4.28						3.72
February - June 2026						NYMEX Henry Hub						80						4.28						3.72
July - December 2026						NYMEX Henry Hub						70						4.23						3.71
January - December 2027						NYMEX Henry Hub						120						4.41						3.42

Ethane Financial Price Swap Contracts
												Contracts Sold
Period						Settlement Index						Volume (MBbld)						Weighted Average Price ($/Bbl)
August - December 2025 (closed)						Mont Belvieu Ethane (non-Tet)						11						$	10.46
January - December 2026						Mont Belvieu Ethane (non-Tet)						11						10.94

Butane Financial Price Swap Contracts
												Contracts Sold
Period						Settlement Index						Volume (MBbld)						Weighted Average Price ($/Bbl)
August - December 2025 (closed)						Mont Belvieu Butane (non-Tet)						7						$	36.28

Propane Financial Price Swap Contracts
												Contracts Sold
Period						Settlement Index						Volume (MBbld)						Weighted Average Price ($/Bbl)
August - December 2025 (closed)						Mont Belvieu Propane (Tet)						13						$	30.82
January - December 2026						Mont Belvieu Propane (Tet)						1						30.24

F-32

Financial Commodity and Other Derivatives Location on Balance Sheet. The following table sets forth the amounts and classification of EOG's outstanding financial commodity and other derivative instruments at December 31, 2025 and 2024, respectively. Certain amounts may be presented on a net basis on the consolidated financial statements when such amounts are with the same counterparty and subject to a master netting arrangement (in millions):

												Fair Value at December 31,
Description						Location on Balance Sheet						2025						2024
Asset Derivatives
NGLs and natural gas financial derivative contracts -
Current portion						Assets from Price Risk Management Activities						$	18					$	—
Brent Crude Oil (Brent) Linked Gas Sales Contract -
Noncurrent Portion						Other Assets						31						110
Liability Derivatives
NGLs and natural gas financial derivative contracts -
Current portion						Liabilities from Price Risk Management Activities (1)						$	—					$	116
Noncurrent Portion						Other Liabilities						2						—

(1) The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $117 million, partially offset by gross assets of $1 million at December 31, 2024.

Natural Gas Sales Linked to Brent Crude Oil. In February 2024, EOG entered into a 10-year agreement, commencing in 2027, to sell 180,000 MMBtud of its domestic natural gas production, with 140,000 MMBtud to be sold at a price indexed to Brent and the remaining volumes to be sold at a price indexed to Brent or a U.S. Gulf Coast gas index. It was determined that this agreement meets the definition of a derivative under the Derivatives and Hedging Topic of the ASC and does not qualify for the normal purchases and normal sales scope exception. As such, this agreement is accounted for as a derivative using the mark-to-market accounting method. Changes in the fair value are recognized as gains or losses in the period of change on the Consolidated Statements of Income and Comprehensive Income.

Credit Risk. Notional contract amounts are used to express the magnitude of a derivative. The amounts potentially subject to credit risk, in the event of nonperformance by the counterparties, are equal to the fair value of such contracts (see Note 13). EOG evaluates its exposure to significant counterparties on an ongoing basis, including those arising from physical and financial transactions. In some instances, EOG renegotiates payment terms and/or requires collateral, parent guarantees or letters of credit to minimize credit risk.

In 2025 and 2024, all natural gas from EOG's Trinidad operations was sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary. In 2025 and 2024, all crude oil and condensate from EOG's Trinidad operations was sold to Heritage Petroleum Company Limited and/or BP Trinidad and Tobago LLC.

All of EOG's financial commodity derivative instruments are covered by International Swap Dealers Association Master Agreements (ISDAs) with counterparties. The ISDAs may contain provisions that (i) require EOG, if it is the party in a net liability position, to post collateral with the counterparty when the amount of the net liability exceeds the threshold level specified for EOG's then-current credit ratings or (ii) require the counterparty, if it is in a net liability position, to post collateral with EOG when the amount of the net liability exceeds the threshold level specified for the counterparty's then-current credit ratings. In addition, the ISDAs may also provide that as a result of certain circumstances, including certain events that cause EOG's credit ratings to become materially weaker than its then-current ratings, the counterparty may require all outstanding financial derivatives under the ISDA to be settled immediately. See Note 13 for the aggregate fair value of all financial derivative instruments that were in a net liability position at December 31, 2025 and 2024. EOG had no collateral posted and held no collateral at December 31, 2025 and 2024.

F-33

Substantially all of EOG's accounts receivable at December 31, 2025 and 2024 resulted from hydrocarbon sales and/or joint interest billings to third-party companies, including foreign state-owned entities in the oil and gas industry. This concentration of customers and joint interest owners may impact EOG's overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. In determining whether or not to require collateral or other credit enhancements from a customer, EOG typically analyzes the entity's net worth, cash flows, earnings and credit ratings. Receivables are generally not collateralized. During the three-year period ended December 31, 2025, credit losses incurred on receivables by EOG have been immaterial.

13. Fair Value Measurements

Certain of EOG's financial and nonfinancial assets and liabilities are reported at fair value on the Consolidated Balance Sheets. An established fair value hierarchy prioritizes the relative reliability of inputs used in fair value measurements. The hierarchy gives highest priority to Level 1 inputs that represent unadjusted quoted market prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are directly or indirectly observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs and have the lowest priority in the hierarchy. EOG gives consideration to the credit risk of its counterparties, as well as its own credit risk, when measuring financial assets and liabilities at fair value.

Recurring Fair Value Measurements. The following table provides fair value measurement information within the fair value hierarchy for certain of EOG's financial assets and liabilities carried at fair value on a recurring basis at December 31, 2025 and 2024 (in millions):

			Fair Value Measurements Using:
			Quoted Prices in Active Markets (Level 1)						Significant Other Observable Inputs (Level 2)						Significant Unobservable Inputs (Level 3)						Total
At December 31, 2025
Financial Assets:
Natural Gas Swaps			$	—					$	12					$	—					$	12
Natural Gas Collars			—						4						—						4
NGL Swaps			—						2						—						2
Brent Linked Gas Sales Contract			—						—						31						31
Financial Liabilities:
Natural Gas Swaps			—						1						—						1
Natural Gas Collars			—						1						—						1
At December 31, 2024
Financial Assets:
Natural Gas Basis Swaps			$	—					$	1					$	—					$	1
Brent Linked Gas Sales Contract			—						—						110						110
Financial Liabilities:
Natural Gas Swaps			—						117						—						117

See Note 12 for a description of the Brent Linked Gas Sales Contract and for the balance sheet amounts and classification of EOG's financial commodity and other derivative instruments at December 31, 2025 and 2024.

The estimated fair value of financial commodity and other derivative contracts was based upon forward commodity price curves based on quoted market prices. For the Brent Linked Gas Sales Contract, the estimated fair value was based on EOG's estimates of (and assumptions regarding) significant Level 3 inputs, as defined by ASC 820, including future crude oil and natural gas prices. These Level 3 inputs are immaterial to the financial statements. Financial commodity and other derivative contracts were valued by utilizing an independent third-party derivative valuation provider who uses various types of valuation models, as applicable.

F-34

Non-Recurring Fair Value Measurements. The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs and reserve lives. A reconciliation of EOG's asset retirement obligations is presented in Note 15.

When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the group. If the expected undiscounted future cash flows, based on EOG's estimate of (and assumptions regarding) future crude oil, NGLs and natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data (all Level 3 inputs as defined by ASC 820) are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach described in ASC 820. In certain instances, EOG utilizes accepted offers from third-party purchasers as the basis for determining fair value.

During 2025, proved oil and gas properties with a carrying amount of $1,163 million were written down to their fair value of $454 million, resulting in pretax impairment charges of $709 million.

During 2024, proved oil and gas properties with a carrying amount of $619 million were written down to their fair value of $324 million, resulting in pretax impairment charges of $295 million.

During 2023, proved oil and gas properties with a carrying amount of $59 million were written down to their fair value of $15 million, resulting in pretax impairment charges of $44 million.

EOG utilized average prices per acre from comparable market transactions and estimated discounted cash flows as the basis for determining the fair value of unproved and proved properties, respectively, received in non-cash property exchanges. See Note 10.

Fair Value of Debt. At December 31, 2025 and 2024, respectively, EOG had outstanding $7,890 million and $4,640 million aggregate principal amount of senior notes, which had estimated fair values of $7,849 million and $4,441 million, respectively. The estimated fair value of debt was based upon quoted market prices and, where such prices were not available, other observable (Level 2) inputs regarding interest rates available to EOG at year-end.

14. Impairment Expense

Impairment expense was as follows for the years ended December 31, 2025, 2024 and 2023 (in millions):

			2025						2024						2023
Proved properties (1)			$	709					$	295					$	44
Unproved properties (2)			61						63						125
Other assets			72						31						31
Firm commitment contracts			1						2						2
Total			$	843					$	391					$	202

(1)Impairments of proved properties for the year ended December 31, 2025, were primarily due to 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 of proved properties for the year ended December 31, 2024, were primarily due to the write-down to fair value of natural gas and crude oil assets in the Rocky Mountain area.

(2)Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. See Note 1.

F-35

15. Asset Retirement Obligations

The following table presents the reconciliation of the beginning and ending aggregate carrying amounts of short-term and long-term legal obligations associated with the retirement of property, plant and equipment for the years ended December 31, 2025 and 2024 (in millions):

			2025						2024
Carrying Amount at Beginning of Period			$	1,460					$	1,506
Liabilities Incurred (1)			91						48
Liabilities Settled (2)			(75)						(62)
Accretion			60						59
Revisions			33						(83)
Foreign Currency Translations			1						(8)
Carrying Amount at End of Period			$	1,570					$	1,460
Current Portion			$	49					$	69
Noncurrent Portion			$	1,521					$	1,391

(1)Liabilities incurred for the year ended December 31, 2025, include $52 million related to the Encino acquisition.

(2)Includes settlements related to asset sales and property exchanges.

The current and noncurrent portions of EOG's asset retirement obligations are included in Current Liabilities - Other and Other Liabilities, respectively, on the Consolidated Balance Sheets.

16. Acquisitions and Divestitures

During 2025, EOG purchased proved properties adjacent to its core acreage in the Eagle Ford play for $269 million. Additionally during 2025, EOG recognized net losses on asset dispositions of $35 million and received proceeds of $24 million primarily due to lease exchanges and dispositions in the Delaware Basin and the Eagle Ford as well as the sale of certain other assets.

In January 2026, EOG signed a purchase and sale agreement for the sale of its entire interest and related fixed assets in the northern Midland Basin for $165 million, subject to customary closing adjustments. The transaction closed on February 18, 2026.

During 2024, EOG paid cash for property acquisitions of $146 million, primarily to acquire a gathering system in South Texas, as well as producing properties in the Utica. Additionally during 2024, EOG recognized net gains on asset dispositions of $16 million and received proceeds of $23 million primarily due to lease exchanges and dispositions in the Delaware Basin and the Eagle Ford as well as the sale of certain other assets.

During 2023, EOG paid cash for property acquisitions of $144 million, primarily to acquire a gathering and processing system in the Powder River Basin. Additionally during 2023, EOG recognized net gains on asset dispositions of $95 million and received proceeds of $140 million primarily due to the sale of EOG's equity interest in ammonia plant investments in Trinidad, the sale of certain legacy assets in the Texas Panhandle, the sale of certain gathering and processing assets and the sale of certain other assets.

Encino Acquisition. On August 1, 2025, EOG acquired all of the outstanding equity interest in Encino, an independent oil and gas exploration and production company with operations in the Utica play, for cash consideration of $4,471 million and the assumption of Encino's senior notes in an aggregate principal amount of $1,200 million. The cash consideration included $392 million to repay Encino's revolving credit facility. In connection with the completion of the acquisition, EOG repaid and redeemed the senior notes in full, utilizing aggregate cash of approximately $1,292 million (inclusive of applicable redemption premiums and accrued and unpaid interest). In connection with the acquisition, EOG issued the July Notes incurring $8 million of debt issuance costs. See Note 2.

The assets of Encino principally include producing wells and developed and undeveloped acreage in the Utica play.

F-36

In connection with this transaction, EOG incurred acquisition-related costs of approximately $58 million, of which $52 million were recorded as General and Administrative Expense and $6.5 million were recorded as Interest Expense.

EOG accounted for this transaction as a business combination under ASC 805 using the acquisition method with EOG as the acquirer. Under the acquisition method, the consideration transferred is allocated to the identifiable assets acquired and liabilities assumed based on their estimated fair values, with any excess of the consideration transferred over the estimated fair value of the identifiable net assets acquired recorded as goodwill. EOG did not record goodwill in connection with this transaction.

Certain data necessary to complete the purchase price allocation is preliminary including the valuations of oil and gas properties and the calculation of deferred taxes based upon the underlying tax basis of assets acquired and liabilities assumed. EOG believes the estimates used are reasonable, but are subject to change as additional information becomes available. Fair value measurements were applied to the acquired assets and liabilities. These measurements may be adjusted up to one year from the acquisition date if new information becomes available regarding facts and circumstances that existed as of such date.

The fair value measurements of Oil and Gas Properties and Asset Retirement Obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs as defined by ASC 820. The fair values of Proved Oil and Gas Properties and the majority of Unproved Oil and Gas Properties were measured using the Income Approach. Significant inputs to the valuation of Proved and Unproved Oil and Gas Properties included EOG's estimate of future crude oil, NGLs and natural gas prices, anticipated production from reserves, a weighted average cost of capital rate, and risk adjustment factors for proved undeveloped, probable and possible reserves. The valuation of a portion of the Unproved Oil and Gas Properties were valued using the Market Approach using prices per acre of comparable transactions as inputs. These inputs required significant judgments, assumptions and estimates by management at the time of the valuation, are the most sensitive and may be subject to change. The senior notes assumed were measured using observable market prices. The fair values of working capital items were determined to be equivalent to the carrying value as they are short-term in nature.

F-37

The following table summarizes the preliminary allocation of the consideration to the fair values of the assets acquired and liabilities assumed from the Encino acquisition (in millions):

Total Consideration			$	4,471
Fair Value of Assets Acquired:
Cash and Cash Equivalents			$	20
Accounts Receivable, Net			326
Inventories			9
Assets from Price Risk Management Activities			26
Other Current Assets			23
Oil and Gas Properties (Successful Efforts Method)			6,703
Other Property, Plant and Equipment			52
Other Assets			68
Amount Attributable to Assets Acquired			$	7,227
Fair Value of Liabilities Assumed:
Accounts Payable			$	614
Accrued Taxes Payable			22
Liabilities from Price Risk Management Activities			15
Current Portion of Operating Lease Liabilities			23
Other Current Liabilities			47
Senior Notes			1,266
Asset Retirement Obligations			52
Other Liabilities			72
Deferred Income Taxes			645
Amount Attributable to Liabilities Assumed			$	2,756
Net Assets Acquired and Liabilities Assumed			$	4,471

The following table details revenues and net income for Encino from the acquisition date, August 1, 2025, for the period presented (in millions):

			Year Ended December 31, 2025
Operating Revenues and Other			$	874
Net Income			246

The following table details unaudited supplemental pro forma financial information as if EOG had completed the acquisition on January 1, 2024 (in millions):

			Year Ended December 31,
			2025						2024
Operating Revenues and Other			$	24,053					$	25,495
Net Income			5,405						6,556

F-38

17. Leases

Lease costs are classified by the function of the ROU asset. The lease costs related to exploration and development activities are initially included in the Oil and Gas Properties line on the Consolidated Balance Sheets and subsequently accounted for in accordance with the Extractive Industries - Oil and Gas Topic of the ASC. Variable lease cost represents costs incurred above the contractual minimum payments and other charges associated with leased equipment, primarily for drilling and fracturing contracts classified as operating leases. The components of lease cost for the years ended December 31, 2025, 2024 and 2023 were as follows (in millions):

			2025						2024						2023
Operating Lease Cost			$	467					$	419					$	387
Finance Lease Cost:
Amortization of Lease Assets			31						33						33
Interest on Lease Liabilities			3						4						5
Variable Lease Cost			165						122						91
Short-Term Lease Cost			334						535						567
Total Lease Cost			$	1,000					$	1,113					$	1,083

The following table sets forth the amounts and classification of EOG's outstanding ROU assets and related lease liabilities at December 31, 2025 and 2024 and supplemental information for the years ended December 31, 2025 and 2024 (in millions, except lease terms and discount rates):

Description						Location on Balance Sheet						2025						2024
Assets
Operating Leases						Other Assets						$	1,176					$	1,005
Finance Leases						Property, Plant and Equipment, Net (1)						110						141
Total												$	1,286					$	1,146
Liabilities
Current
Operating Leases						Current Portion of Operating Lease Liabilities						$	472					$	315
Finance Leases						Current Portion of Long-Term Debt						27						32
Long-Term
Operating Leases						Other Liabilities						727						725
Finance Leases						Long-Term Debt						90						118
Total												$	1,316					$	1,190

(1) Finance lease assets are recorded net of accumulated amortization of $251 million and $219 million at December 31, 2025 and 2024, respectively.

			2025						2024
Weighted Average Remaining Lease Term (in years):
Operating Leases			4.2						5.0
Finance Leases			4.2						4.5
Weighted Average Discount Rate:
Operating Leases			4.4		%				4.6		%
Finance Leases			2.6		%				2.6		%

F-39

Cash paid for leases for the years ended December 31, 2025, 2024 and 2023 was as follows (in millions):

			2025						2024						2023
Repayment of Operating Lease Liabilities Associated with Operating Activities			$	241					$	226					$	226
Repayment of Operating Lease Liabilities Associated with Investing Activities			234						202						172
Repayment of Finance Lease Liabilities			32						33						32

Non-cash leasing activities for the year ended December 31, 2025, included the additions of $587 million of operating leases and no finance leases. Non-cash leasing activities for the year ended December 31, 2024, included the additions of $403 million of operating leases and no finance leases. Non-cash leasing activities for the year ended December 31, 2023, included the additions of $727 million of operating leases and no finance leases.

At December 31, 2025, the future minimum lease payments under non-cancellable leases were as follows (in millions):

			Operating Leases						Finance Leases
2026			$	515					$	30
2027			254						30
2028			180						30
2029			142						30
2030			93						4
2031 and beyond			143						—
Total Lease Payments			1,327						124
Less: Discount to Present Value			128						7
Total Lease Liabilities			1,199						117
Less: Current Portion of Lease Liabilities			472						27
Long-Term Lease Liabilities			$	727					$	90

At December 31, 2025, EOG had additional minimum lease payments of $254 million, which are expected to commence beginning in 2026 with lease terms of two to seventeen years.

F-40

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS

(In Millions, Except Per Share Data, Unless Otherwise Indicated)

(Unaudited)

Oil and Gas Producing Activities

The following disclosures are made in accordance with Financial Accounting Standards Board Accounting Standards Update No. 2010-03 "Oil and Gas Reserve Estimation and Disclosures" and the United States Securities and Exchange Commission's (SEC) final rule on "Modernization of Oil and Gas Reporting."

Oil and Gas Reserves. Users of this information should be aware that the process of estimating quantities of "proved," "proved developed" and "proved undeveloped" crude oil, natural gas liquids (NGLs) and natural gas reserves is complex, requiring significant subjective decisions in the evaluation of available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including, but not limited to, additional development activity; evolving production history; crude oil and condensate, NGLs and natural gas prices; continual reassessment of the viability of production under varying economic conditions; and improvements and other changes in geological, geophysical and engineering evaluation methods. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. Although reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.

Proved reserves represent estimated quantities of crude oil, NGLs and natural gas, which, by analysis of geoscience and engineering data, can be estimated, with reasonable certainty, to be economically producible from a given date forward from known reservoirs under then-existing economic conditions, operating methods and government regulations before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

Proved developed reserves are proved reserves expected to be recovered under operating methods being utilized at the time the estimates were made, through wells and equipment in place or if the cost of any required equipment is relatively minor compared to the cost of a new well.

Proved undeveloped reserves (PUDs) are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion or recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. PUDs can be recorded in respect of a particular undeveloped undrilled location only if the location is scheduled, under the then-current drilling and development plan, to be drilled within five years from the date that the PUDs were recorded, unless specific factors (such as those described in interpretative guidance issued by the Staff of the SEC) justify a longer timeframe. Likewise, absent any such specific factors, PUDs associated with a particular undeveloped drilling location shall be removed from the estimates of proved reserves if the location is scheduled, under the then-current drilling and development plan, to be drilled on a date that is beyond five years from the date that the PUDs were recorded. EOG has formulated development plans for all drilling locations associated with its PUDs at December 31, 2025. Under these plans, each location will be drilled within five years from the date the associated PUDs were recorded. Estimates for PUDs are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

F-41

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

To generate PUD estimates, EOG technical staff, including engineering and geological staff, perform a detailed technical analysis of each potential drilling location within its inventory of prospects. To determine which of these locations would penetrate undrained portions of the reservoir that can be judged, with reasonable certainty, to be continuous and contain economically producible crude oil, NGLs, and natural gas, studies are conducted using numerous analysis techniques containing both static and dynamic data. The geoscientists map the entire reservoir in question employing two-dimensional and three-dimensional seismic along with well logs and core data of existing penetrations. The maps are integrated with other static data, including, but not limited to, petrophysical and mechanical properties of the formation plus thermal maturity indicators. Often, highly specialized equipment is utilized to prepare and evaluate rock samples in assessing microstructures which contribute to porosity and permeability. In addition, analysis of dynamic data is incorporated from offsets and analog wells to arrive at recoverable hydrocarbons. Dynamic analysis methods employed include, but are not limited to, proprietary rate transient and pressure transient analysis techniques incorporating static and flowing pressures and production data. These proprietary techniques in low permeability reservoirs quantify estimates of production contribution from hydraulic fractures, natural fractures, and rock matrix.

The impact of optimal completion techniques is a key factor in determining if the PUDs reflected in prospective locations are reasonably certain of being economically producible. EOG's technical staff estimates the recovery improvement that might be achieved when completing horizontal wells with multi-stage fracture stimulation. In the early stages of development of a play, EOG determines the optimal horizontal lateral spacing and multi-stage fracture stimulation using the aforementioned analysis techniques along with pilot drilling programs and gathering of microseismic data.

The process of analyzing static and dynamic data, well completion optimization data and the results of early development activities provides the appropriate level of certainty as well as support for the economic producibility of the plays in which PUDs are reflected. EOG has found this approach to be effective based on successful application in analogous reservoirs in low permeability resource plays.

Certain of EOG's Trinidad reserves are held under production sharing contracts where EOG's interest varies with prices and production volumes. Trinidad reserves, as presented on a net basis, assume prices in existence at the time the estimates were made and EOG's estimate of future production volumes. Future fluctuations in prices, production rates or changes in political or regulatory environments could cause EOG's share of future production from Trinidadian reserves to be materially different from that presented.

Estimates of proved reserves at December 31, 2025, 2024 and 2023 were based on studies performed by the engineering staff of EOG. The Engineering Department is directly responsible for EOG's reserve evaluation process and consists of 17 engineers, all of whom hold, at a minimum, bachelor's degrees in engineering, and four of whom are Registered Professional Engineers. The Vice President, Engineering is the manager of this department and is the primary technical person responsible for this process. The Vice President, Engineering holds a Bachelor of Science degree in Mechanical Engineering and has 14 years of experience in reserve evaluations.

EOG's reserves estimation process is a collaborative effort coordinated by the Engineering Department in compliance with EOG's internal controls for such process. Reserve information as well as models used to estimate such reserves are stored on secured databases. Non-technical inputs used in reserve estimation models, including crude oil, NGLs and natural gas prices, production costs, gathering, processing and transportation costs, and applicable fractionation costs, future capital expenditures and EOG's net ownership percentages, are obtained from other departments within EOG. EOG's Internal Audit Department conducts testing with respect to such non-technical inputs. Additionally, EOG engages DeGolyer and MacNaughton (D&M), independent petroleum consultants, to perform independent reserves evaluation of select EOG properties comprising not less than 75% of EOG's estimates of proved reserves. Pursuant to EOG's internal controls applicable to its reserves estimation process, EOG's reserve values for the properties evaluated must be within 5% of the values calculated by D&M in the aggregate. Once completed, EOG's year-end reserves are presented to senior management, including the Chairman of the Board and Chief Executive Officer; the Executive Vice President and Chief Operating Officer; and the Executive Vice President and Chief Financial Officer, for approval.

F-42

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Opinions by D&M for the years ended December 31, 2025, 2024 and 2023 covered producing areas containing 84%, 85% and 83%, respectively, of proved reserves of EOG on a net-equivalent-barrel-of-oil basis. D&M's opinions indicate that the estimates of proved reserves prepared by EOG's Engineering Department for the properties reviewed by D&M, when compared in total on a net-equivalent-barrel-of-oil basis, do not differ materially from the estimates prepared by D&M. Specifically, such estimates by D&M in the aggregate varied by not more than 5% from those prepared by the Engineering Department of EOG. All reports by D&M were developed utilizing geological and engineering data provided by EOG. The report of D&M dated February 4, 2026, which contains further discussion of the reserve estimates and evaluations prepared by D&M, as well as the qualifications of D&M's technical person primarily responsible for overseeing such estimates and evaluations, is attached as Exhibit 99.1 to this Annual Report on Form 10-K and incorporated herein by reference.

No major discovery or other favorable or adverse event subsequent to December 31, 2025, is believed to have caused a material change in the estimates of net proved reserves as of that date.

The following tables set forth EOG's net proved reserves at December 31 for each of the four years in the period ended December 31, 2025, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2025, as estimated by the Engineering Department of EOG:

F-43

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NET PROVED RESERVE SUMMARY

			United States						Trinidad						Total
NET PROVED RESERVES
Crude Oil (MMBbl) (1)
Net proved reserves at December 31, 2022			1,659						2						1,661
Revisions of previous estimates			56						—						56
Purchases in place			1						—						1
Extensions, discoveries and other additions			219						—						219
Sales in place			(7)						—						(7)
Production			(174)						—						(174)
Net proved reserves at December 31, 2023			1,754						2						1,756
Revisions of previous estimates			71						—						71
Purchases in place			3						—						3
Extensions, discoveries and other additions			228						—						228
Sales in place			(8)						—						(8)
Production			(180)						—						(180)
Net proved reserves at December 31, 2024			1,868						2						1,870
Revisions of previous estimates			(10)						—						(10)
Purchases in place			158						—						158
Extensions, discoveries and other additions			77						1						78
Sales in place			—						—						—
Production			(190)						(1)						(191)
Net proved reserves at December 31, 2025			1,903						2						1,905
Natural Gas Liquids (MMBbl) (1)
Net proved reserves at December 31, 2022			1,145						—						1,145
Revisions of previous estimates			26						—						26
Purchases in place			1						—						1
Extensions, discoveries and other additions			169						—						169
Sales in place			(5)						—						(5)
Production			(82)						—						(82)
Net proved reserves at December 31, 2023			1,254						—						1,254
Revisions of previous estimates			31						—						31
Purchases in place			2						—						2
Extensions, discoveries and other additions			164						—						164
Sales in place			(3)						—						(3)
Production			(90)						—						(90)
Net proved reserves at December 31, 2024			1,358						—						1,358
Revisions of previous estimates			9						—						9
Purchases in place			200						—						200
Extensions, discoveries and other additions			48						—						48
Sales in place			—						—						—
Production			(105)						—						(105)
Net proved reserves at December 31, 2025			1,510						—						1,510

F-44

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

			United States						Trinidad						Total
Natural Gas (Bcf) (2) (3)
Net proved reserves at December 31, 2022			8,273						318						8,591
Revisions of previous estimates			(327)						12						(315)
Purchases in place			3						—						3
Extensions, discoveries and other additions			1,287						29						1,316
Sales in place			(28)						—						(28)
Production			(578)						(59)						(637)
Net proved reserves at December 31, 2023			8,630						300						8,930
Revisions of previous estimates			(202)						2						(200)
Purchases in place			10						—						10
Extensions, discoveries and other additions			1,098						23						1,121
Sales in place			(14)						—						(14)
Production			(644)						(81)						(725)
Net proved reserves at December 31, 2024			8,878						244						9,122
Revisions of previous estimates			798						9						807
Purchases in place			2,340						—						2,340
Extensions, discoveries and other additions			1,184						77						1,261
Sales in place			(1)						—						(1)
Production			(851)						(86)						(937)
Net proved reserves at December 31, 2025			12,348						244						12,592

F-45

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

			United States						Trinidad						Total
Oil Equivalents (MMBoe) (1) (3)
Net proved reserves at December 31, 2022			4,183						55						4,238
Revisions of previous estimates (4)			28						1						29
Purchases in place			2						—						2
Extensions, discoveries and other additions (5)			602						5						607
Sales in place			(17)						—						(17)
Production			(351)						(10)						(361)
Net proved reserves at December 31, 2023			4,447						51						4,498
Revisions of previous estimates (4)			68						1						69
Purchases in place			6						—						6
Extensions, discoveries and other additions (6)			576						4						580
Sales in place			(14)						—						(14)
Production			(377)						(14)						(391)
Net proved reserves at December 31, 2024			4,706						42						4,748
Revisions of previous estimates (4)			131						2						133
Purchases in place			749						—						749
Extensions, discoveries and other additions (7)			322						14						336
Sales in place			—						—						—
Production			(437)						(15)						(452)
Net proved reserves at December 31, 2025			5,471						43						5,514

(1)Million barrels or million barrels of oil equivalent, as applicable; oil equivalents include crude oil and condensate, NGLs and natural gas. Oil equivalents 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.

(2)Billion cubic feet.

(3)Natural gas to be consumed in operations represents less than 3% of total net proved reserves on a barrel of oil equivalent basis at December 31, 2025, 2024 and 2023. These volumes are not included in the calculation of our standardized measure of discounted future net cash flows from projected production of EOG's oil and gas reserves.

(4)See "Reconciliation of Revisions of Previous Estimates" below for additional discussion.

(5)Change in net proved reserves for the year ended December 31, 2023, attributable to extensions, discoveries and other additions was 91 MMBoe greater than the corresponding change in PUDs for such year. Such difference represents new proved developed reserves attributable to wells drilled during 2023, primarily in the Permian Basin, that did not have any associated PUDs recorded at the beginning of 2023. The reserves added as new PUDs for the year ended December 31, 2023, attributable to extensions and discoveries were 516 MMBoe and were primarily in the Permian Basin. See "Net Proved Undeveloped Reserves" below.

(6)Change in net proved reserves for the year ended December 31, 2024, attributable to extensions, discoveries and other additions was 101 MMBoe greater than the corresponding change in PUDs for such year. Such difference represents new proved developed reserves attributable to wells drilled during 2024, primarily in the Permian Basin, that did not have any associated PUDs recorded at the beginning of 2024. The reserves added as new PUDs for the year ended December 31, 2024, attributable to extensions and discoveries were 479 MMBoe and were primarily in the Permian Basin. See "Net Proved Undeveloped Reserves" below.

(7)Change in net proved reserves for the year ended December 31, 2025, attributable to extensions, discoveries and other additions was 72 MMBoe greater than the corresponding change in PUDs for such year. Such difference represents new proved developed reserves attributable to wells drilled during 2025, primarily in South Texas and the Permian Basin, that did not have any associated PUDs recorded at the beginning of 2025. The reserves added as new PUDs for the year ended December 31, 2025, attributable to extensions and discoveries were 264 MMBoe and were primarily in the Permian Basin. See "Net Proved Undeveloped Reserves" below.

F-46

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

During 2025, EOG added 336 million barrels of oil equivalent (MMBoe) of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin and South Texas. Approximately 38% of the 2025 reserve additions were crude oil and condensate and NGLs, and substantially all were in the United States. Refer to "Reconciliation of Revisions of Previous Estimates" below for factors impacting revisions of previous estimates. Purchases in place of 749 MMBoe were primarily related to the acquisition of Encino Acquisition Partners, LLC (Encino) and the purchase of proved properties adjacent to EOG's core acreage in the Eagle Ford play.

During 2024, EOG added 580 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin and Utica. Approximately 68% of the 2024 reserve additions were crude oil and condensate and NGLs, and substantially all were in the United States. Sales in place of 14 MMBoe were primarily related to the exchange of assets in the Gulf Coast Basin. Refer to "Reconciliation of Revisions of Previous Estimates" below for factors impacting revisions of previous estimates. Purchases in place of 6 MMBoe were primarily related to the Permian Basin and the purchase or exchange of other assets.

During 2023, EOG added 607 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin and Gulf Coast Basin. Approximately 64% of the 2023 reserve additions were crude oil and condensate and NGLs, and substantially all were in the United States. Sales in place of 17 MMBoe were primarily related to the sale of assets in the Permian Basin and the Anadarko Basin and the sale or exchange of other producing assets. Refer to "Reconciliation of Revisions of Previous Estimates" below for factors impacting revisions of previous estimates. Purchases in place of 2 MMBoe were primarily related to the Permian Basin and the purchase or exchange of other producing assets.

F-47

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

			United States						Trinidad						Total
NET PROVED DEVELOPED RESERVES
Crude Oil (MMBbl)
December 31, 2022			948						—						948
December 31, 2023			983						—						983
December 31, 2024			1,033						—						1,033
December 31, 2025			1,132						1						1,133
Natural Gas Liquids (MMBbl)
December 31, 2022			561						—						561
December 31, 2023			625						—						625
December 31, 2024			700						—						700
December 31, 2025			933						—						933
Natural Gas (Bcf)
December 31, 2022			3,920						137						4,057
December 31, 2023			4,283						161						4,444
December 31, 2024			4,850						144						4,994
December 31, 2025			7,515						165						7,680
Oil Equivalents (MMBoe)
December 31, 2022			2,162						23						2,185
December 31, 2023			2,322						27						2,349
December 31, 2024			2,542						24						2,566
December 31, 2025			3,317						29						3,346
NET PROVED UNDEVELOPED RESERVES
Crude Oil (MMBbl)
December 31, 2022			711						2						713
December 31, 2023			771						2						773
December 31, 2024			835						2						837
December 31, 2025			771						1						772
Natural Gas Liquids (MMBbl)
December 31, 2022			584						—						584
December 31, 2023			629						—						629
December 31, 2024			658						—						658
December 31, 2025			577						—						577
Natural Gas (Bcf)
December 31, 2022			4,353						181						4,534
December 31, 2023			4,347						139						4,486
December 31, 2024			4,028						100						4,128
December 31, 2025			4,833						79						4,912
Oil Equivalents (MMBoe)
December 31, 2022			2,021						32						2,053
December 31, 2023			2,125						24						2,149
December 31, 2024			2,164						18						2,182
December 31, 2025			2,154						14						2,168

F-48

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Net Proved Undeveloped Reserves. The following table presents the changes in EOG's total PUDs during 2025, 2024 and 2023 (in MMBoe):

			2025						2024						2023
Balance at January 1			2,182						2,149						2,053
Extensions and Discoveries (1)			264						479						516
Revisions (2)			21						(66)						(51)
Acquisition of Reserves			204						3						—
Sale of Reserves			—						(13)						(9)
Conversion to Proved Developed Reserves			(503)						(370)						(360)
Balance at December 31			2,168						2,182						2,149

(1)See "Net Proved Reserves" table and accompanying notes above for additional discussion regarding changes in reserves attributable to extensions, discoveries and other additions.

(2)See "Reconciliation of Revisions of Previous Estimates" below for additional discussion.

For the twelve-month period ended December 31, 2025, total PUDs decreased by 14 MMBoe to 2,168 MMBoe. EOG added approximately 18 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion. Based on the technology employed by EOG to identify and record PUDs (see discussion of technology employed on pages F-41 - F-43 of this Annual Report on Form 10-K), EOG added 246 MMBoe of PUDs. The PUD additions were primarily in the Permian Basin and South Texas and 33% of the additions were crude oil and condensate and NGLs. During 2025, EOG drilled and transferred 503 MMBoe of PUDs to proved developed reserves at a total capital cost of $3,483 million. Refer to "Reconciliation of Revisions of Previous Estimates" below for factors impacting revisions of previous estimates. All PUDs, including drilled but uncompleted wells (DUCs), are scheduled for completion within five years of the original reserve booking.

For the twelve-month period ended December 31, 2024, total PUDs increased by 33 MMBoe to 2,182 MMBoe. EOG added approximately 25 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion. Based on the technology employed by EOG to identify and record PUDs, EOG added 454 MMBoe of PUDs. The PUD additions were primarily in the Permian Basin and 68% of the additions were crude oil and condensate and NGLs. During 2024, EOG drilled and transferred 370 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,609 million. Refer to "Reconciliation of Revisions of Previous Estimates" below for factors impacting revisions of previous estimates. All PUDs, including DUCs, are scheduled for completion within five years of the original reserve booking.

For the twelve-month period ended December 31, 2023, total PUDs increased by 96 MMBoe to 2,149 MMBoe. EOG added approximately 44 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion. Based on the technology employed by EOG to identify and record PUDs, EOG added 472 MMBoe of PUDs. The PUD additions were primarily in the Permian Basin and 65% of the additions were crude oil and condensate and NGLs. During 2023, EOG drilled and transferred 360 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,801 million. Refer to "Reconciliation of Revisions of Previous Estimates" below for factors impacting revisions of previous estimates. All PUDs, including DUCs, are scheduled for completion within five years of the original reserve booking.

F-49

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Reconciliation of Revisions of Previous Estimates. As an initial step in determining the revisions to be made to EOG's net proved reserves estimates for the prior year-end, EOG's technical staff reviews its updated drilling and development plan. As discussed above, if under such plan an undeveloped drilling location for which PUD reserves were previously recorded will not be drilled within five years from the date that the PUD reserves were recorded, such PUD reserves are removed from EOG's estimates of net proved reserves. To the extent EOG's updated drilling and development plan includes new proved locations, the proved reserves associated with such locations are incorporated into EOG's estimates of net proved reserves.

Pursuant to such process, EOG's technical staff included a net negative revision of 13 MMBoe of PUD reserves to its net proved reserves for the year ended December 31, 2025 and a net negative revision of 83 MMBoe and a net positive revision of 45 MMBoe of PUD reserves from its net proved reserves for the years ended December 31, 2024 and 2023, respectively.

EOG's technical staff then evaluates the following six inter-related factors (in the order indicated below) in respect of the net proved reserves associated with each of its well locations:

• crude oil, NGLs and natural gas prices;

• EOG's well performance forecasts;

• marketing-related changes (i.e., relating to the sale of EOG's production);

• changes in EOG's ownership interests (in its well locations);

• production costs, gathering, processing and transportation costs (collectively, operating costs) and changes therein; and

• investments in future wells and/or recompletions and changes therein.

EOG's evaluation of such inter-related factors resulted in the following revisions to its net proved reserves and net PUD reserves for the years ended December 31, 2025, 2024 and 2023.

F-50

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Year Ended December 31, 2025
Review of Updated Plan						Revision to Net Proved Reserves (MMBoe)									Revision to Net PUD Reserves (MMBoe)						Explanation
Revision related to addition of PUD reserves pursuant to review of updated drilling and development plan						(13)									(13)						See above related discussion.
Evaluation of Inter-Related Factors
Prices for crude oil, NGLs and natural gas			68									49									Positive revisions attributable to an increase in the average prices used in EOG's year-end 2025 reserves estimates as compared to the average prices used in EOG's year-end 2024 reserves estimates.
Well performance forecasts			85									(35)									Upward revisions in total proved attributable to EOG's forecast adjustments in certain locations and infill drilling. Downward revisions in PUDs attributable to forecast adjustments on EOG's existing PUDs.
Marketing-related changes (e.g., ethane recovery elections) relating to the sale of production			(10)									11									Downward revisions in total proved attributable to changes in production mix processed in 2025 vs 2024. Upward revisions in PUDs attributable to improved recoveries in certain locations.
Ownership interest changes			(1)									(1)									Revisions attributable to ownership interest changes.
Changes in operating costs			—									10									Upward revision in PUDs attributable to decreased lease operating costs, resulting in an increase in reserves that are economically producible.
Investments			4									—									Reduced investments for certain PUDs transfers and proved developed non-producing reserves that resulted in them becoming economic for 2025 compared to 2024 investments.
Net Revisions Attributable to Inter-Related Factors						146									34
Total Revisions						133									21

F-51

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Year Ended December 31, 2024
Review of Updated Plan						Revision to Net Proved Reserves (MMBoe)									Revision to Net PUD Reserves (MMBoe)						Explanation
Revision related to addition of PUD reserves pursuant to review of updated drilling and development plan						(83)									(83)						See above related discussion.
Evaluation of Inter-Related Factors
Prices for crude oil, NGLs and natural gas			(146)									(105)									Downward revisions attributable to a decrease in the average prices used in EOG's year-end 2024 reserves estimates as compared to the average prices used in EOG's year-end 2023 reserves estimates.
Well performance forecasts			248									93									Revisions attributable to EOG's forecasted changes in well performance in certain locations, including the increase in lateral lengths in the 2024 development program and on existing PUDs.
Marketing-related changes (e.g., ethane recovery elections) relating to the sale of production			(2)									2									Revisions attributable to changes in production mix processed in 2024 vs 2023.
Ownership interest changes			(6)									(4)									Revisions attributable to ownership interest changes.
Changes in operating costs			32									16									Upward revision attributable to decreased gathering, processing and transportation costs, resulting in an increase in reserves that are economically producible.
Investments			26									15									Reduced investments for certain PUDs and proved developed non-producing reserves that resulted in them becoming economic for 2024 compared to 2023 investments.
Net Revisions Attributable to Inter-Related Factors						152									17
Total Revisions						69									(66)

F-52

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Year Ended December 31, 2023
Review of Updated Plan						Revision to Net Proved Reserves (MMBoe)									Revision to Net PUD Reserves (MMBoe)						Explanation
Revision related to addition of PUD reserves pursuant to review of updated drilling and development plan						45									45						See above related discussion.
Evaluation of Inter-Related Factors
Prices for crude oil, NGLs and natural gas			(110)									(68)									Downward revisions attributable to a decrease in the average prices used in EOG's year-end 2023 reserves estimates as compared to the average prices used in EOG's year-end 2022 reserves estimates.
Well performance forecasts			12									(97)									Revisions attributable to EOG's forecasted changes in well performance in certain locations.
Marketing-related changes (e.g., ethane recovery elections) relating to the sale of production			—									—									Immaterial
Ownership interest changes			4									8									Revisions attributable to ownership interest changes.
Changes in operating costs			66									50									Upward revision attributable to decreased operating costs, resulting in an increase in reserves that are economically producible.
Investments			12									11									Reduced investments for certain PUDs and proved developed non-producing reserves that resulted in them becoming economic for 2023 compared to 2022 investments
Net Revisions Attributable to Inter-Related Factors						(16)									(96)
Total Revisions						29									(51)

F-53

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Capitalized Costs Relating to Oil and Gas Producing Activities. The following table sets forth the capitalized costs relating to EOG's crude oil, NGLs and natural gas producing activities at December 31, 2025 and 2024 (in millions):

			2025						2024
Proved properties			$	85,570					$	74,789
Unproved properties			4,287						2,302
Total			89,857						77,091
Accumulated depreciation, depletion and amortization			(51,917)						(47,155)
Net capitalized costs			$	37,940					$	29,936

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities. The acquisition, exploration and development costs disclosed in the following tables are in accordance with definitions in the Extractive Industries - Oil and Gas Topic of the Accounting Standards Codification (ASC).

Acquisition costs include costs incurred to purchase, lease or otherwise acquire property.

Exploration costs include additions to exploratory wells, including those in progress, and exploration expenses.

Development costs include additions to production facilities and equipment and additions to development wells, including those in progress.

F-54

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table sets forth costs incurred related to EOG's oil and gas activities for the years ended December 31, 2025, 2024 and 2023 (in millions):

			United States						Trinidad						Other International						Total
2025
Acquisition Costs of Properties
Unproved (1) (2)			$	2,274					$	2					$	—					$	2,276
Proved (2)			4,846						—						26						4,872
Subtotal			7,120						2						26						7,148
Exploration Costs			349						79						85						513
Development Costs (3)			5,311						182						18						5,511
Total			$	12,780					$	263					$	129					$	13,172
2024
Acquisition Costs of Properties
Unproved (4)			$	229					$	—					$	1					$	230
Proved (5)			33						—						—						33
Subtotal			262						—						1						263
Exploration Costs			286						115						28						429
Development Costs (6)			4,783						132						27						4,942
Total			$	5,331					$	247					$	56					$	5,634
2023
Acquisition Costs of Properties
Unproved (7)			$	207					$	—					$	—					$	207
Proved (8)			16						—						—						16
Subtotal			223						—						—						223
Exploration Costs			370						53						14						437
Development Costs (9)			5,228						117						13						5,358
Total			$	5,821					$	170					$	27					$	6,018

(1)Includes non-cash unproved leasehold acquisition costs of $24 million related to property exchanges.

(2)Unproved and proved property acquisition costs for the year ended December 31, 2025, includes $6,651 million related to the Encino acquisition.

(3)Includes Asset Retirement Costs of $98 million, $35 million and $13 million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment.

(4)Includes non-cash unproved leasehold acquisition costs of $85 million related to property exchanges.

(5)Includes non-cash proved property acquisition costs of $24 million related to property exchanges.

(6)Includes Asset Retirement Costs of $(37) million, $8 million and $27 million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment.

(7)Includes non-cash unproved leasehold acquisition costs of $99 million related to property exchanges.

(8)Includes non-cash proved property acquisition costs of $6 million related to property exchanges.

(9)Includes Asset Retirement Costs of $241 million, $3 million and $13 million for the United States, Trinidad and Other International, respectively. Includes non-cash development drilling costs of $90 million. Excludes other property, plant and equipment.

F-55

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Results of Operations for Oil and Gas Producing Activities (1). The following table sets forth results of operations for oil and gas producing activities for the years ended December 31, 2025, 2024 and 2023 (in millions):

			United States						Trinidad						Other International						Total
2025
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues			$	17,316					$	347					$	5					$	17,668
Other			71						—						—						71
Total			17,387						347						5						17,739
Exploration Costs			159						32						45						236
Dry Hole Costs			12						37						—						49
Gathering, Processing and Transportation Costs			2,133						1						—						2,134
Production Costs			2,800						53						15						2,868
Impairments			816						15						12						843
Depreciation, Depletion and Amortization			4,048						153						1						4,202
Income (Loss) Before Income Taxes			7,419						56						(68)						7,407
Income Tax Provision (Benefit)			1,612						10						(4)						1,618
Results of Operations			$	5,807					$	46					$	(64)					$	5,789
2024
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues			$	17,263					$	315					$	—					$	17,578
Other			99						—						—						99
Total			17,362						315						—						17,677
Exploration Costs			154						4						16						174
Dry Hole Costs			1						13						—						14
Gathering, Processing and Transportation Costs			1,722						—						—						1,722
Production Costs			2,741						40						1						2,782
Impairments			354						2						35						391
Depreciation, Depletion and Amortization			3,765						138						1						3,904
Income (Loss) Before Income Taxes			8,625						118						(53)						8,690
Income Tax Provision (Benefit)			1,887						6						(3)						1,890
Results of Operations			$	6,738					$	112					$	(50)					$	6,800
2023
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues			$	17,148					$	228					$	—					$	17,376
Other			91						—						—						91
Total			17,239						228						—						17,467
Exploration Costs			166						4						11						181
Dry Hole Costs			1						—						—						1
Gathering, Processing and Transportation Costs			1,620						—						—						1,620
Production Costs			2,657						45						1						2,703
Impairments			184						—						18						202
Depreciation, Depletion and Amortization			3,244						78						—						3,322
Income (Loss) Before Income Taxes			9,367						101						(30)						9,438
Income Tax Provision (Benefit)			2,056						8						(2)						2,062
Results of Operations			$	7,311					$	93					$	(28)					$	7,376

(1)Excludes gains or losses on the mark-to-market of financial commodity and other derivative contracts, gains or losses on sales of reserves and related assets, interest charges and general corporate expenses for each of the three years in the period ended December 31, 2025.

F-56

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table sets forth production costs per barrel of oil equivalent, excluding severance/production and ad valorem taxes, for the years ended December 31, 2025, 2024 and 2023:

			United States						Trinidad			Other International						Composite
Year Ended December 31, 2025			$	3.69					$	3.36		$	65.22					$	3.71
Year Ended December 31, 2024			$	4.06					$	2.90		$	—					$	4.02
Year Ended December 31, 2023			$	4.01					$	4.19		$	—					$	4.02

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves. The following information has been developed utilizing procedures prescribed by the Extractive Industries - Oil and Gas Topic of the ASC and based on crude oil, NGL and natural gas reserves and production volumes estimated by the Engineering Department of EOG. The estimates were based on a 12-month average for commodity prices for the years 2025, 2024 and 2023. The following information may be useful for certain comparative purposes, but should not be solely relied upon in evaluating EOG or its performance. Further, information contained in the following tables should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of EOG.

The future cash flows presented below are based on sales prices, cost rates and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil, NGL and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.

Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible reserves as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

F-57

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table sets forth the standardized measure of discounted future net cash flows from projected production of EOG's oil and gas reserves for the years ended December 31, 2025, 2024 and 2023 (in millions):

			United States						Trinidad						Total
2025
Future cash inflows (1)			$	192,046					$	1,032					$	193,078
Future production costs			(74,233)						(200)						(74,433)
Future development costs (2)			(18,981)						(218)						(19,199)
Future income taxes			(19,997)						(113)						(20,110)
Future net cash flows			78,835						501						79,336
Discount to present value at 10% annual rate			(37,958)						(61)						(38,019)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves			$	40,877					$	440					$	41,317
2024
Future cash inflows (3)			$	187,008					$	940					$	187,948
Future production costs			(62,755)						(269)						(63,024)
Future development costs (4)			(19,228)						(282)						(19,510)
Future income taxes			(22,137)						(20)						(22,157)
Future net cash flows			82,888						369						83,257
Discount to present value at 10% annual rate			(39,584)						(47)						(39,631)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves			$	43,304					$	322					$	43,626
2023
Future cash inflows (5)			$	188,585					$	1,101					$	189,686
Future production costs			(65,349)						(245)						(65,594)
Future development costs (6)			(20,070)						(406)						(20,476)
Future income taxes			(21,632)						(40)						(21,672)
Future net cash flows			81,534						410						81,944
Discount to present value at 10% annual rate			(38,879)						(73)						(38,952)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves			$	42,655					$	337					$	42,992

(1)Estimated crude oil prices used to calculate 2025 future cash inflows for the United States and Trinidad were $66.37 and $62.23, respectively. Estimated NGL price used to calculate 2025 future cash inflows for the United States was $20.87. Estimated natural gas prices used to calculate 2025 future cash inflows for the United States and Trinidad were $2.77 and $3.70, respectively.

(2)Future abandonment costs included in 2025 future development costs for the United States and Trinidad were $2,243 million and $193 million, respectively.

(3)Estimated crude oil prices used to calculate 2024 future cash inflows for the United States and Trinidad were $77.37 and $63.95, respectively. Estimated NGL price used to calculate 2024 future cash inflows for the United States was $20.24. Estimated natural gas prices used to calculate 2024 future cash inflows for the United States and Trinidad were $1.69 and $3.41, respectively.

(4)Future abandonment costs included in 2024 future development costs for the United States and Trinidad were $1,989 million and $192 million, respectively.

(5)Estimated crude oil prices used to calculate 2023 future cash inflows for the United States and Trinidad were $80.00 and $68.59, respectively. Estimated NGLs price used to calculate 2023 future cash inflows for the United States was $19.94. Estimated natural gas prices used to calculate 2023 future cash inflows for the United States and Trinidad were $2.69 and $3.33, respectively.

(6)Future abandonment costs included in 2023 future development costs for the United States and Trinidad were $2,104 million and $193 million, respectively.

F-58

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

Changes in Standardized Measure of Discounted Future Net Cash Flows. The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for each of the three years in the period ended December 31, 2025 (in millions):

			United States						Trinidad						Other International						Total
December 31, 2022			$	74,212					$	360					$	—					$	74,572
Sales and transfers of oil and gas produced, net of production costs			(12,872)						(182)						—						(13,054)
Net changes in prices and production costs			(41,377)						8						—						(41,369)
Extensions, discoveries, additions and improved recovery, net of related costs			4,825						42						—						4,867
Development costs incurred			2,801						48						—						2,849
Revisions of estimated development cost			(644)						13						—						(631)
Revisions of previous quantity estimates			381						27						—						408
Accretion of discount			9,411						37						—						9,448
Net change in income taxes			9,250						(18)						—						9,232
Purchases of reserves in place			31						—						—						31
Sales of reserves in place			(294)						—						—						(294)
Changes in timing and other			(3,069)						2						—						(3,067)
December 31, 2023			$	42,655					$	337					$	—					$	42,992
Sales and transfers of oil and gas produced, net of production costs			(12,800)						(274)						—						(13,074)
Net changes in prices and production costs			(1,695)						33						—						(1,662)
Extensions, discoveries, additions and improved recovery, net of related costs			5,442						34						—						5,476
Development costs incurred			2,609						28						—						2,637
Revisions of estimated development cost			1,197						74						—						1,271
Revisions of previous quantity estimates			899						7						—						906
Accretion of discount			5,331						36						—						5,367
Net change in income taxes			(253)						9						—						(244)
Purchases of reserves in place			75						—						—						75
Sales of reserves in place			(102)						—						—						(102)
Changes in timing and other			(54)						38						—						(16)
December 31, 2024			$	43,304					$	322					$	—					$	43,626
Sales and transfers of oil and gas produced, net of production costs			(12,383)						(293)						10						(12,666)
Net changes in prices and production costs			(7,324)						207						—						(7,117)
Extensions, discoveries, additions and improved recovery, net of related costs			1,997						112						—						2,109
Development costs incurred			3,329						154						—						3,483
Revisions of estimated development cost			400						(81)						—						319
Revisions of previous quantity estimates			1,519						20						—						1,539
Accretion of discount			5,421						34						—						5,455
Net change in income taxes			1,630						(31)						—						1,599
Purchases of reserves in place			4,502						—						—						4,502
Sales of reserves in place			(3)						—						—						(3)
Changes in timing and other			(1,515)						(4)						(10)						(1,529)
December 31, 2025			$	40,877					$	440					$	—					$	41,317

F-59

EXHIBITS

Exhibit Number						Description
**2			-			Equity Interest Purchase Agreement, dated as of May 30, 2025, by and among EOG, Encino Acquisition Partners, LLC, CPPIB EAP US Inc., CPPIB EAP Canada, Inc., the other seller parties thereto and Encino Energy, LLC (Exhibit 2.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended June 30, 2025) (SEC File No. 001-09743).
3.1(a)			-			Restated Certificate of Incorporation, dated September 3, 1987 (Exhibit 3.1(a) to EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2008) (SEC File No. 001-09743).
3.1(b)			-			Certificate of Amendment of Restated Certificate of Incorporation, dated May 5, 1993 (Exhibit 4.1(b) to EOG's Registration Statement on Form S-8, SEC File No. 33-52201, filed February 8, 1994).
3.1(c)			-			Certificate of Amendment of Restated Certificate of Incorporation, dated June 14, 1994 (Exhibit 4.1(c) to EOG's Registration Statement on Form S-8, SEC File No. 33-58103, filed March 15, 1995).
3.1(d)			-			Certificate of Amendment of Restated Certificate of Incorporation, dated June 11, 1996 (Exhibit 3(d) to EOG's Registration Statement on Form S-3, SEC File No. 333-09919, filed August 9, 1996).
3.1(e)			-			Certificate of Amendment of Restated Certificate of Incorporation, dated May 7, 1997 (Exhibit 3(e) to EOG's Registration Statement on Form S-3, SEC File No. 333-44785, filed January 23, 1998).
3.1(f)			-			Certificate of Ownership and Merger Merging EOG Resources, Inc. into Enron Oil & Gas Company, dated August 26, 1999 (Exhibit 3.1(f) to EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 1999) (SEC File No. 001-09743).
3.1(g)			-			Certificate of Designations of Series E Junior Participating Preferred Stock, dated February 14, 2000 (Exhibit 2 to EOG's Registration Statement on Form 8-A, SEC File No. 001-09743, filed February 18, 2000).
3.1(h)			-			Certificate of Elimination of the Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series A, dated September 13, 2000 (Exhibit 3.1(j) to EOG's Registration Statement on Form S-3, SEC File No. 333-46858, filed September 28, 2000).
3.1(i)			-			Certificate of Elimination of the Flexible Money Market Cumulative Preferred Stock, Series C, dated September 13, 2000 (Exhibit 3.1(k) to EOG's Registration Statement on Form S-3, SEC File No. 333-46858, filed September 28, 2000).
3.1(j)			-			Certificate of Elimination of the Flexible Money Market Cumulative Preferred Stock, Series D, dated February 24, 2005 (Exhibit 3.1(k) to EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2004) (SEC File No. 001-09743).
3.1(k)			-			Amended Certificate of Designations of Series E Junior Participating Preferred Stock, dated March 7, 2005 (Exhibit 3.1(m) to EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2007) (SEC File No. 001-09743).
3.1(l)			-			Certificate of Amendment of Restated Certificate of Incorporation, dated May 3, 2005 (Exhibit 3.1(l) to EOG's Quarterly Report on Form 10-Q for the quarter ended June 30, 2005) (SEC File No. 001-09743).
3.1(m)			-			Certificate of Elimination of Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B, dated March 6, 2008 (Exhibit 3.1 to EOG's Current Report on Form 8-K, filed March 6, 2008) (SEC File No. 001-09743).
3.1(n)			-			Certificate of Amendment of Restated Certificate of Incorporation, dated April 28, 2017 (Exhibit 3.1 to EOG's Current Report on Form 8-K, filed May 2, 2017) (SEC File No. 001-09743).
3.2			-			Bylaws, dated August 23, 1989, as amended and restated effective as of February 23, 2023 (Exhibit 3.2(b) to EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2022) (SEC File No. 001-09743).
4.1			-			Description of Securities Registered Under Section 12 of the Securities Exchange Act of 1934 (Exhibit 4.1 to EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2019) (SEC File No. 001-09743).
4.2			-			Indenture, dated as of September 1, 1991, between Enron Oil & Gas Company (predecessor to EOG) and The Bank of New York Mellon Trust Company, N.A. (as successor in interest to JPMorgan Chase Bank, N.A. (formerly, Texas Commerce Bank National Association)), as Trustee (Exhibit 4(a) to EOG's Registration Statement on Form S-3, SEC File No. 33-42640, filed in paper format on September 6, 1991).

E-1

Exhibit Number						Description
#4.3(a)			-			Certificate, dated April 3, 1998, of the Senior Vice President and Chief Financial Officer of Enron Oil & Gas Company (predecessor to EOG) establishing the terms of the 6.65% Notes due April 1, 2028 of Enron Oil & Gas Company.
#4.3(b)			-			Global Note with respect to the 6.65% Notes due April 1, 2028 of Enron Oil & Gas Company (predecessor to EOG).
4.4			-			Indenture, dated as of May 18, 2009, between EOG and Computershare Trust Company, N.A. (as successor to Wells Fargo Bank, National Association), as Trustee (Exhibit 4.9 to EOG's Registration Statement on Form S-3, SEC File No. 333-159301, filed May 18, 2009).
4.5(a)			-			Officers' Certificate Establishing 3.15% Senior Notes due 2025 and 3.90% Senior Notes due 2035 of EOG, dated March 17, 2015 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed March 19, 2015) (SEC File No. 001-09743).
4.5(b)			-			Form of Global Note with respect to the 3.90% Senior Notes due 2035 of EOG (Exhibit 4.4 to EOG's Current Report on Form 8-K, filed March 19, 2015) (SEC File No. 001-09743).
4.6(a)			-			Officers' Certificate Establishing 4.15% Senior Notes due 2026 and 5.10% Senior Notes due 2036 of EOG, dated January 14, 2016 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed January 15, 2016) (SEC File No. 001-09743).
4.6(b)			-			Form of Global Note with respect to the 4.15% Senior Notes due 2026 of EOG (Exhibit 4.3 to EOG's Current Report on Form 8-K, filed January 15, 2016) (SEC File No. 001-09743).
4.6(c)			-			Form of Global Note with respect to the 5.10% Senior Notes due 2036 of EOG (Exhibit 4.4 to EOG's Current Report on Form 8-K, filed January 15, 2016) (SEC File No. 001-09743).
4.7(a)			-			Officers' Certificate Establishing 4.375% Senior Notes due 2030 and 4.950% Senior Notes due 2050 of EOG, dated April 14, 2020 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed April 14, 2020) (SEC File No. 001-09743).
4.7(b)			-			Form of Global Note with respect to the 4.375% Senior Notes due 2030 of EOG (included in Exhibit 4.7(a)).
4.7(c)			-			Form of Global Note with respect to the 4.950% Senior Notes due 2050 of EOG (included in Exhibit 4.7(a)).
4.8(a)			-			Officers' Certificate Establishing 5.650% Senior Notes due 2054 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed November 21, 2024) (SEC File No. 001-09743).
4.8(b)			-			Form of Global Note with respect to the 5.650% Senior Notes due 2054 (included in Exhibit 4.8(a)).
4.9(a)			-			Officers' Certificate Establishing 4.400% Senior Notes due 2028 of EOG, 5.000% Senior Notes due 2032 of EOG, 5.350% Senior Notes due 2036 of EOG and 5.950% Senior Notes due 2055 of EOG, dated July 1, 2025 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed July 1, 2025) (SEC File No. 001-09743).
4.9(b)			-			Form of Global Note with respect to the 4.400% Senior Notes due 2028 of EOG (included in Exhibit 4.9(a)).
4.9(c)			-			Form of Global Note with respect to the 5.000% Senior Notes due 2032 of EOG (included in Exhibit 4.9(a)).
4.9(d)			-			Form of Global Note with respect to the 5.350% Senior Notes due 2036 of EOG (included in Exhibit 4.9(a)).
4.9(e)			-			Form of Global Note with respect to the 5.950% Senior Notes due 2055 of EOG (included in Exhibit 4.9(a)).
4.10(a)			-			Officers' Certificate Establishing 4.400% Senior Notes due 2031 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed November 24, 2025) (SEC File No. 001-09743).
4.10(b)			-			Form of Global Note with respect to the 4.400% Senior Notes due 2031 (included in Exhibit 4.10(a)).
4.11(a)			-			Officers' Certificate Establishing New 5.950% Senior Notes due 2055 (Exhibit 4.4 to EOG's Current Report on Form 8-K, filed November 24, 2025) (SEC File No. 001-09743).
4.11(b)			-			Form of Global Note with respect to the New 5.950% Senior Notes due 2055 (included in Exhibit 4.11(a)).

E-2

Exhibit Number						Description
10.1(a)+			-			Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan, effective as of May 2, 2013 (Exhibit 4.4 to EOG's Registration Statement on Form S-8, SEC File No. 333-188352, filed May 3, 2013).
10.1(b)+			-			Form of Stock-Settled Stock Appreciation Right Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made on or after September 25, 2017 and prior to September 28, 2020) (Exhibit 10.4 to EOG's Current Report on Form 8-K, filed September 29, 2017) (SEC File No. 001-09743).
10.1(c)+			-			Form of Stock-Settled Stock Appreciation Right Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made on or after September 28, 2020) (Exhibit 10.3 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2020) (SEC File No. 001-09743).
10.2(a)+			-			EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan, dated effective as of April 29, 2021 (Exhibit 4.4 to EOG's Registration Statement on Form S-8, SEC File No. 333-255691, filed April 30, 2021).
10.2(b)+			-			Form of Restricted Stock Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (applicable to grants made prior to September 15, 2023) (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2021) (SEC File No. 001-09743).
10.2(c)+			-			Form of Restricted Stock Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (applicable to grants made on or after September 15, 2023 and prior to December 18, 2023) (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2023 (SEC File No. 001-09743).
10.2(d)+			-			Form of Restricted Stock Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (applicable to grants made on or after December 18, 2023) (Exhibit 10.2(d) to EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2023) (SEC File No. 001-09743).
10.2(e)+			-			Form of Restricted Stock Unit Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (applicable to grants made prior to September 15, 2023) (Exhibit 10.2 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2021) (SEC File No. 001-09743).
10.2(f)+			-			Form of Restricted Stock Unit Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (applicable to grants made on or after September 15, 2023 and prior to December 18, 2023) (Exhibit 10.2 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2023) (SEC File No. 001-09743).
10.2(g)+			-			Form of Restricted Stock Unit Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (applicable to grants made on or after December 18, 2023) (Exhibit 10.2(g) to EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2023) (SEC File No. 001-09743).
10.2(h)+			-			Form of Stock-Settled Stock Appreciation Right Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (Exhibit 10.3 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2021) (SEC File No. 001-09743).
10.2(i)+			-			Form of Restricted Stock Unit with Performance-Based Conditions ("Performance Unit") Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (applicable to grants made on or after September 29, 2022 and prior to September 15, 2023) (Exhibit 10.1 to EOG's Current Report on Form 8-K, filed October 4, 2022) (SEC File No. 001-09743).
10.2(j)+			-			Form of Restricted Stock Unit with Performance-Based Conditions ("Performance Unit") Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (applicable to grants made on or after September 15, 2023 and prior to December 18, 2023) (Exhibit 10.3 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2023) (SEC File No. 001-09743).
10.2(k)+			-			Form of Restricted Stock Unit with Performance-Based Conditions ("Performance Unit") Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (amended and restated award agreement applicable solely to grants made effective September 15, 2023) (Exhibit 10.2(m) to EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2023) (SEC File No. 001-09743).
10.2(l)+			-			Form of Restricted Stock Unit with Performance-Based Conditions ("Performance Unit") Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (applicable to grants made on or after December 18, 2023 and prior to September 27, 2024) (Exhibit 10.2(n) to EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2023) (SEC File No. 001-09743).

E-3

Exhibit Number						Description
10.2(m)+			-			Form of Restricted Stock Unit with Performance-Based Conditions ("Performance Unit") Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (applicable to grants made on or after September 27, 2024) (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2024) (SEC File No. 001-09743).
10.2(n)+			-			Form of Restricted Stock Unit with Performance-Based Conditions ("Performance Unit") Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (applicable solely to grant made to Ann D. Janssen effective January 2, 2024) (Exhibit 10.2(o) to EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2023) (SEC File No. 001-09743).
10.2(o)			-			Form of Non-Employee Director Restricted Stock Unit Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (applicable to grants made on or after May 28, 2024) (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended June 30, 2024) (SEC File No. 001-09743).
10.3(a)+			-			EOG Resources, Inc. 409A Deferred Compensation Plan - Nonqualified Supplemental Deferred Compensation Plan - Plan Document, effective as of December 16, 2008 (Exhibit 10.2(a) to EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2008) (SEC File No. 001-09743).
10.3(b)+			-			EOG Resources, Inc. 409A Deferred Compensation Plan - Nonqualified Supplemental Deferred Compensation Plan - Adoption Agreement, originally dated as of December 16, 2008 (and as amended through February 24, 2012 (including an amendment to Item 7 thereof, effective January 1, 2012, with respect to the deferral of restricted stock units)) (Exhibit 10.2(b) to EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2011) (originally filed as Exhibit 10.2(b) to EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2008) (SEC File No. 001-09743).
10.3(c)+			-			First Amendment to the EOG Resources, Inc. 409A Deferred Compensation Plan, effective as of January 1, 2013 (Exhibit 10.8 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013) (SEC File No. 001-09743).
10.3(d)+			-			Amendment 2 to the EOG Resources, Inc. 409A Deferred Compensation Plan, effective as of January 1, 2018 (Exhibit 10.3(d) to EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2018) (SEC File No. 001-09743).
10.3(e)+			-			Third Amendment to the EOG Resources, Inc. 409A Deferred Compensation Plan, effective as of December 17, 2020 (Exhibit 10.2(e) to EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2020) (SEC File No. 001-09743).
10.4(a)+			-			Change of Control Agreement by and between EOG and Michael P. Donaldson, effective as of May 3, 2012 (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended June 30, 2012) (SEC File No. 001-09743).
10.4(b)+			-			First Amendment to Change of Control Agreement between EOG and Michael P. Donaldson, effective as of September 4, 2013 (Exhibit 10.7 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013) (SEC File No. 001-09743).
10.5+			-			Change of Control Agreement by and between EOG and Ezra Y. Yacob, effective as of January 26, 2018 (Exhibit 10.10 to EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2017) (SEC File No. 001-09743).
10.6+			-			Change of Control Agreement by and between EOG and Jeffrey R. Leitzell, effective as of June 17, 2021 (Exhibit 10.2 to EOG's Quarterly Report on Form 10-Q for the quarter ended June 30, 2021 (SEC File No. 001-09743).
10.7+			-			Change of Control Agreement by and between EOG and Ann D. Janssen, effective as of February 2, 2024 (Exhibit 10.10 to EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2023) (SEC File No. 001-09743).
10.8(a)+			-			EOG Resources, Inc. Change of Control Severance Plan, as amended and restated effective as of June 15, 2005 (Exhibit 99.12 to EOG's Current Report on Form 8-K, filed June 21, 2005) (SEC File No. 001-09743).
10.8(b)+			-			First Amendment to the EOG Resources, Inc. Change of Control Severance Plan, effective as of April 30, 2009 (Exhibit 10.6 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2009) (SEC File No. 001-09743).
10.9+			-			EOG Resources, Inc. Second Amended and Restated Annual Bonus Plan (effective as of January 1, 2024) (Exhibit 10.12(c) to EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2023) (SEC File No. 001-09743).

E-4

Exhibit Number						Description
10.10(a)+			-			EOG Resources, Inc. Employee Stock Purchase Plan (As Amended and Restated Effective January 1, 2018) (Exhibit 4.4(a) to EOG's Registration Statement on Form S-8, SEC File No. 333-224466, filed April 26, 2018).
10.10(b)+			-			EOG Resources, Inc. Employee Stock Purchase Plan (As Initially Amended and Restated Effective January 1, 2018 and As Further Amended and Restated Effective June 1, 2025) (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended June 30, 2025) (SEC File No. 001-09743).
10.11			-			Revolving Credit Agreement, dated as of December 3, 2025, among EOG, JPMorgan Chase Bank, N.A., as Administrative Agent, the financial institutions as bank parties thereto, and the other parties thereto (Exhibit 10.1 to EOG's Current Report on Form 8-K, filed December 8, 2025) (SEC File No. 001-09743).
19			-			EOG Resources, Inc. Insider Trading Policy (as updated effective February 6, 2025) (Exhibit 19 to EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2024) (SEC File No. 001-09743).
*21			-			Subsidiaries of EOG, as of December 31, 2025.
*23.1			-			Consent of DeGolyer and MacNaughton.
*23.2			-			Consent of Deloitte & Touche LLP.
*24			-			Powers of Attorney.
*31.1			-			Section 302 Certification of Annual Report of Principal Executive Officer.
*31.2			-			Section 302 Certification of Annual Report of Principal Financial Officer.
*32.1##			-			Section 906 Certification of Annual Report of Principal Executive Officer.
*32.2##			-			Section 906 Certification of Annual Report of Principal Financial Officer.
97+			-			EOG Resources, Inc. Policy for the Recovery of Erroneously Awarded Compensation, adopted September 13, 2023 (Exhibit 97 to EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2023) (SEC File No. 001-09743).
*99.1			-			Opinion of DeGolyer and MacNaughton, dated February 4, 2026.
101.INS						Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
* ***101.SCH			-			Inline XBRL Schema Document.
* ***101.CAL			-			Inline XBRL Calculation Linkbase Document.
* ***101.DEF			-			Inline XBRL Definition Linkbase Document.
* ***101.LAB			-			Inline XBRL Label Linkbase Document.
* ***101.PRE			-			Inline XBRL Presentation Linkbase Document.
104			-			Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

*Exhibits filed herewith.

**Certain schedules and exhibits (and similar attachments) have been omitted pursuant to Item 601(a)(5) of Regulation S-K and will be provided to the SEC upon request.

***Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Statements of Income and Comprehensive Income for Each of the Three Years in the Period Ended December 31, 2025, (ii) the Consolidated Balance Sheets - December 31, 2025 and 2024, (iii) the Consolidated Statements of Stockholders' Equity for Each of the Three Years in the Period Ended December 31, 2025, (iv) the Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2025 and (v) the Notes to Consolidated Financial Statements.

+ Management contract, compensatory plan or arrangement.

E-5

Exhibits not filed herewith. Pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, the registrant hereby agrees to furnish a copy of such exhibit to the SEC upon request.

The certifications attached as Exhibit 32.1 and Exhibit 32.2 accompany this report pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed "filed" by the registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

E-6

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

									EOG RESOURCES, INC.
									(Registrant)
Date:			February 24, 2026			By:			/s/ ANN D. JANSSEN Ann D. Janssen Executive Vice President and Chief Financial Officer (Principal Financial Officer and Duly Authorized Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the registrant and in the capacities with EOG Resources, Inc. indicated and on the 24th day of February, 2026.

			Signature			Title
			/s/ EZRA Y. YACOB			Chairman of the Board and Chief Executive Officer and Director
			(Ezra Y. Yacob)			(Principal Executive Officer)
			/s/ ANN D. JANSSEN			Executive Vice President and Chief Financial Officer
			(Ann D. Janssen)			(Principal Financial Officer)
			/s/ LAURA B. DISTEFANO			Vice President and Chief Accounting Officer
			(Laura B. Distefano)			(Principal Accounting Officer)
			*
			(John D. Chandler)			Director
			*			Director
			(Janet F. Clark)
			*			Director
			(Charles R. Crisp)
			*			Director
			(Robert P. Daniels)
			*			Director
			(Lynn A. Dugle)
			*			Director
			(C. Christopher Gaut)
			*			Director
			(Michael T. Kerr)
			*			Director
			(Julie J. Robertson)
*By:			/s/ MICHAEL P. DONALDSON
			(Michael P. Donaldson)
			(Attorney-in-fact for persons indicated)