EOG Resources - 10-K annual report 2025

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2025

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 1-9743

EOG RESOURCES, INC.

(Exact name of registrant as specified in its charter)


Delaware						47-0684736
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)

1111 Bagby, Sky Lobby 2, Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: 713-651-7000

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, par value $0.01 per share	EOG	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐

Smaller reporting company ☐ Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter. Common Stock aggregate market value held by non-affiliates as of June 30, 2025: $65,231 million.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date. Class: Common Stock, par value $0.01 per share, 536,491,493 shares outstanding as of February 13, 2026.

Documents incorporated by reference. Portions of the Definitive Proxy Statement for the registrant's 2026 Annual Meeting of Stockholders, to be filed within 120 days after December 31, 2025, are incorporated by reference into Part III of this report.

TABLE OF CONTENTS


		Page
PART I

ITEM 1.	Business	1
	General	1
	Exploration and Production	1
	Marketing	4
	Volumes and Prices	5
	Human Capital Management	6
	Competition	7
	Regulation	7
	Other Matters	12
	Information About Our Executive Officers	14
ITEM 1A.	Risk Factors	15
ITEM 1B.	Unresolved Staff Comments	28
ITEM 1C.	Cybersecurity	28
ITEM 2.	Properties	30
	Oil and Gas Exploration and Production - Properties and Reserves	30
ITEM 3.	Legal Proceedings	33
ITEM 4.	Mine Safety Disclosures	33

PART II

ITEM 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	34
ITEM 6.	Reserved	36
ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	36
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk	55
ITEM 8.	Financial Statements and Supplementary Data	55
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	55
ITEM 9A.	Controls and Procedures	55
ITEM 9B.	Other Information	55
ITEM 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	55

PART III

ITEM 10.	Directors, Executive Officers and Corporate Governance	56
ITEM 11.	Executive Compensation	56
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	57
ITEM 13.	Certain Relationships and Related Transactions, and Director Independence	58
ITEM 14.	Principal Accountant Fees and Services	58

PART IV

ITEM 15.	Exhibits and Financial Statement Schedules	59

ITEM 16.	Form 10-K Summary	59

SIGNATURES

(i)

PART I

ITEM 1. Business

General

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.), the Republic of Trinidad and Tobago (Trinidad) and, from time to time, select other international areas, including the Kingdom of Bahrain and the United Arab Emirates. EOG's principal producing areas are further described in "Exploration and Production" below. EOG's Annual Reports on Form 10-K, Quarterly Reports on Form 10‑Q, Current Reports on Form 8-K and any amendments to those reports (including related exhibits and supplemental schedules) filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (as amended) are made available, free of charge, through EOG's website, as soon as reasonably practicable after such reports have been filed with, or furnished to, the United States Securities and Exchange Commission (SEC). EOG's website address is www.eogresources.com. Information on our website is not incorporated by reference into, and does not constitute a part of, this report.

At December 31, 2025, EOG's total estimated net proved reserves were 5,514 million barrels of oil equivalent (MMBoe), of which 1,905 million barrels (MMBbl) were crude oil and condensate reserves, 1,510 MMBbl were NGLs reserves and 12,592 billion cubic feet (Bcf), or 2,099 MMBoe, were natural gas reserves (see "Supplemental Information to Consolidated Financial Statements"). At such date, approximately 99% of EOG's net proved reserves, on a crude oil equivalent basis, were located in the United States and 1% in Trinidad. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet (Mcf) of natural gas.

EOG's operations are all crude oil and natural gas exploration and production related. For information regarding the risks associated with EOG's domestic and foreign operations, see ITEM 1A, Risk Factors.

EOG is focused on being among the highest return and lowest cost producers, committed to strong environmental performance and playing a significant role in the long-term future of energy. EOG operates under a consistent business and operational strategy that focuses on a comprehensive approach to developing acreage through industry cycles. EOG evaluates rate of return, net present value, margins, payback period and other key metrics. This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-efficient basis, allowing EOG to maximize long-term growth in shareholder value and maintain a strong balance sheet. EOG is also focused on innovation and cost-effective utilization of advanced technology associated with three-dimensional seismic and microseismic data, the development of reservoir simulation models and the use of improved drilling equipment and completion technologies for horizontal drilling and formation evaluation. These advanced technologies are used, as appropriate, throughout EOG to reduce the risks and costs associated with all aspects of oil and gas exploration, development and exploitation. EOG implements its strategy primarily by emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves. Maintaining the lowest possible operating cost structure, coupled with efficient and safe operations and robust environmental stewardship practices and performance, is integral in the implementation of EOG's strategy.

With respect to information on EOG's working interest in wells or acreage, "net" oil and gas wells or acreage are determined by multiplying "gross" oil and gas wells or acreage by EOG's working interest in the wells or acreage.

Exploration and Production

United States Operations

EOG's operations are located in most of the productive basins in the United States with a focus on crude oil and natural gas plays.

At December 31, 2025, on a crude oil equivalent basis, 35% of EOG's net proved reserves in the United States were crude oil and condensate, 27% were NGLs and 38% were natural gas. The majority of these reserves are in long-lived fields with well-established production characteristics. EOG believes opportunities exist to increase production through continued development in and around many of these fields and through the utilization of applicable technologies. EOG also maintains an active exploration program designed to extend fields and add new trends and resource plays to its already broad portfolio.

The following is a summary of volume statistics and net well completions for the year ended December 31, 2025, total net acres at December 31, 2025, and expected net well completions planned for 2026 for certain areas of EOG's United States operations.


2025						2026
Area of Operation	Crude Oil & Condensate Volumes (MBbld) (1)	Natural Gas Liquids Volumes (MBbld) (1)	Natural Gas Volumes (MMcfd) (1)	Total Net Acres (in thousands)	Net Well Completions	Expected Net Well Completions
Delaware Basin	318.7	199.4	1,179	395	393	300
South Texas	121.3	32.3	581	1,313	149	155
Appalachian Basin	32.4	32.7	340	1,736	55	85
Rocky Mountain	40.7	14.0	143	748	34	45
Other Areas	7.4	9.8	56	474	10	—
Total	520.5	288.2	2,299	4,666	641	585

(1)Thousand barrels per day or million cubic feet per day, as applicable.

In the Delaware Basin, EOG completed 393 net wells in 2025, primarily in the Wolfcamp, Bone Spring and Leonard plays. Activity in 2026 will remain focused on the Wolfcamp, Bone Spring and Leonard plays, where EOG expects to complete approximately 300 net wells.

The South Texas area includes the Eagle Ford play and the Dorado gas play. EOG holds approximately 565,000 net acres in the Eagle Ford play and approximately 160,000 net acres in the Dorado gas play. In 2025, EOG completed 122 net wells in the Eagle Ford play and 27 net wells in the Dorado gas play. In 2026, EOG expects to complete approximately 115 net Eagle Ford play wells and 40 net Dorado gas play wells.

The Appalachian Basin includes the Utica play where EOG holds approximately 1,100,000 net acres, including 135,000 net mineral acres. In 2025, EOG completed 55 net wells in the Utica play. In 2026, EOG expects to complete approximately 85 net wells in the Utica play. For discussion regarding EOG's August 2025 acquisition of Encino Acquisition Partners, LLC, see ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations – Overview – Operations and Note 16 to Consolidated Financial Statements.

In the Rocky Mountain area, EOG completed 22 net wells in 2025 in the Powder River Basin and 12 net wells in the Williston Basin. In 2026, EOG expects to complete approximately 45 net wells across the Powder River Basin and the Williston Basin.

Operations Outside the United States

EOG has operations offshore Trinidad, onshore Bahrain, and onshore United Arab Emirates, and is evaluating additional exploration, development and exploitation opportunities in those jurisdictions and other select international areas.

Trinidad. EOG, through its subsidiaries, including EOG Resources Trinidad Limited, holds interests in (i) the exploration and production licenses covering the South East Coast Consortium and Pelican Blocks, Banyan and Sercan Areas and each of their related platforms and facilities, the Ska, Mento and Reggae and Deep Teak, Saaman and Poui (TSP Deep) Areas and Coconut Field, all of which are offshore Trinidad; and (ii) four production sharing contracts with the Government of Trinidad and Tobago for the Modified U(a), 4(a), Lower Reverse L and North Coast Marine Area 4(a) Blocks.

Several of the fields listed above have been developed and produce natural gas and crude oil and condensate. In 2025, EOG's net production in Trinidad averaged approximately 230 MMcfd of natural gas and approximately 1.4 MBbld of crude oil and condensate.

In 2025, EOG completed three gross developmental wells and one gross exploratory well from the Mento platform in the Mento Area as part of an ongoing drilling program. EOG also continues to move forward on the design and construction of the Coconut Platform in accordance with the farmout agreement signed in 2024 with BP Trinidad and Tobago LLC.

In 2026, EOG expects to (i) complete the Mento drilling program; (ii) complete and install the Coconut Platform along with supporting pipelines; and (iii) continue to make progress on various opportunities, which include a new drilling program to drill exploration, appraisal and development wells.

Bahrain. In February 2025, a subsidiary of EOG signed an exploration participation agreement with Bapco Energies B.S.C. (Closed) (Bapco) to evaluate a gas exploration prospect in the Kingdom of Bahrain. In August 2025, the government of the Kingdom of Bahrain approved the related concession agreement. As part of the transaction, EOG has a working interest in several producing legacy wells. EOG has commenced drilling of exploratory wells, which are expected to be completed in 2026.

United Arab Emirates. In May 2025, a subsidiary of EOG was awarded a new oil exploration concession for Unconventional Onshore Block 3 (UCO3) by Abu Dhabi's Supreme Council for Financial and Economic Affairs. EOG holds a 100 percent equity interest and operatorship and, in coordination with Abu Dhabi National Oil Company (ADNOC), has commenced drilling operations to explore and appraise unconventional oil potential in the concession area. Following a three-year appraisal period, EOG may enter into a production concession in which ADNOC has the option to participate.

Marketing

In 2025, EOG continued its diversified approach to marketing its crude oil and condensate. The majority of EOG's United States crude oil and condensate production was transported by pipeline to downstream markets with the remainder sold into local markets. Major U.S. sales areas accessed by EOG were at various locations along the U.S. Gulf Coast; Cushing, Oklahoma; the Permian Basin; the Northeast; and the Midwest. In 2025, EOG also sold crude oil at the Port of Corpus Christi for export to foreign destinations. In each case, the price received was based on market prices at that specific sales point or based on the price index applicable for that location. In 2026, the pricing mechanism for such production is expected to remain the same. At December 31, 2025, EOG was committed to deliver to multiple parties aggregate fixed quantities of crude oil of 24 MMBbls in 2026, 11 MMBbls in 2027 and 4 MMBbls in 2028, all of which is expected to be sourced from future production of available reserves.

In 2025, EOG processed certain of its United States natural gas production, either at EOG-owned facilities or at third-party facilities, extracting NGLs. NGLs were sold at prevailing market prices, into either local markets or downstream locations. In certain instances, EOG exchanged its NGLs production for purity products received downstream, which were sold at prevailing market prices. In 2025, EOG also sold purity products at the Houston Ship Channel. In each case, the price received was based on market prices for that location and purity product. In 2026, the pricing mechanisms for NGL and purity products sales are expected to remain the same. At December 31, 2025, EOG was committed to deliver to multiple parties aggregate fixed quantities of purity products of 24 MMBbls in 2026, all of which is expected to be sourced from future production of available reserves.

In 2025, consistent with its diversified marketing strategy, the majority of EOG's United States natural gas production was transported by pipeline to various locations throughout the United States and the Dawn Hub in Ontario. Remaining natural gas production was sold into local markets. Pricing was primarily based on the spot market price at the ultimate sales point. In 2026, the pricing mechanism for such production is expected to generally remain the same. Additionally, EOG sells natural gas to a liquefaction facility near Corpus Christi, Texas, and may receive pricing based on the Platts Japan Korea Marker (or the NYMEX Henry Hub price, at EOG's election); such pricing mechanism is expected to remain the same in 2026. At December 31, 2025, EOG was committed to deliver to multiple parties aggregate fixed quantities of natural gas of 573 Bcf in 2026, 370 Bcf in 2027, 338 Bcf in 2028, 336 Bcf in 2029, 331 Bcf in 2030 and 3,020 Bcf thereafter, all of which is expected to be sourced from future production of available reserves.

In 2025, natural gas volumes from Trinidad were sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary under two natural gas sales arrangements. Crude oil and condensate are sold to both Heritage Petroleum Company Limited and BP Trinidad and Tobago LLC.

In certain instances, EOG purchases and sells third-party crude oil and natural gas in order to balance firm capacity at third-party facilities with production in certain areas and to utilize excess capacity at EOG-owned facilities.

During 2025, two purchasers each accounted for more than 10% of EOG's total crude oil and condensate, NGLs and natural gas revenues and gathering, processing and marketing revenues. The purchasers are in the crude oil refining industry. EOG does not believe that the loss of any single purchaser would have a material adverse effect on its financial condition or results of operations.

Volumes and Prices

The following table sets forth certain information regarding EOG's volumes of, and average prices for, crude oil and condensate, NGLs and natural gas. The table also presents crude oil equivalent volumes which are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 Mcf of natural gas for each of the years ended December 31, 2025, 2024 and 2023. See ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations, for volumes on a per-day basis.


Year Ended December 31	2025	2024	2023

Crude Oil and Condensate Volumes (MMBbl) (1)
United States:
Delaware Basin	116.7	113.3	110.2
Eagle Ford Play	44.2	45.5	43.9
Other	29.1	20.8	19.4
United States	190.0	179.6	173.5
Trinidad	0.5	0.3	0.2
Total	190.5	179.9	173.7
Natural Gas Liquids Volumes (MMBbl) (1)
United States:
Delaware Basin	73.0	67.7	59.8
Eagle Ford Play	11.7	11.1	10.5
Other	20.5	11.2	11.4
United States	105.2	90.0	81.7
Total	105.2	90.0	81.7
Natural Gas Volumes (Bcf) (1)
United States:
Delaware Basin	431	380	325
Eagle Ford Play	56	53	50
Other	352	199	191
United States	839	632	566
Trinidad	84	81	59
Other International (2)	1	—	—
Total	924	713	625
Crude Oil Equivalent Volumes (MMBoe) (3)
United States:
Delaware Basin	261.5	244.4	224.2
Eagle Ford Play	65.3	65.4	62.7
Other	108.2	65.2	62.6
United States	435.0	375.0	349.5
Trinidad	14.6	13.7	9.9
Other International (2)	0.2	—	—
Total	449.8	388.7	359.4


Year Ended December 31	2025		2024		2023

Average Crude Oil and Condensate Prices ($/Bbl) (4)
United States	$	65.65	$	77.42	$	79.18
Trinidad	57.59		64.43		68.58
Composite	65.63		77.40		79.17
Average Natural Gas Liquids Prices ($/Bbl) (4)
United States	$	22.58	$	23.40	$	23.07
Composite	22.58		23.40		23.07
Average Natural Gas Prices ($/Mcf) (4)
United States	$	2.94	$	1.99	$	2.70
Trinidad	3.78		3.65		3.65
Other International (2)	3.28		—		—
Composite	3.02		2.17		2.79

(1)Million barrels or billion cubic feet, as applicable.

(2)Production volumes from Bahrain operations; realized price represents contract price less Bapco's processing and distribution costs.

(3)Million barrels of oil equivalent; includes crude oil and condensate, NGLs and natural gas.

(4)Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity and other derivative instruments (see Note 12 to Consolidated Financial Statements).

Human Capital Management

As of December 31, 2025, EOG employed approximately 3,400 persons, including foreign national employees. EOG's approach to human capital management includes oversight by the Board of Directors (Board) and the Compensation and Human Resources Committee of the Board and focuses on various areas, including the following:

Culture; Recruiting; Retention. EOG's culture is key to its sustainable success. By providing employees with a quality work environment and maintaining a consistent college recruiting and internship program and experienced talent recruiting program, EOG is able to attract and retain many of the industry's best and brightest. To help assess the effectiveness of its approach to human capital management, EOG conducts an annual employee engagement and satisfaction survey. Based on the results of the survey, EOG has received "top workplace" recognition in various office locations as well as several "culture excellence" awards.

EOG values the gender, racial, ethnic and cultural backgrounds of our employees and works to foster a collaborative work environment of different talents, perspectives and experiences. EOG believes the backgrounds, viewpoints and experiences of our employees, as well as an inclusive work environment, promotes collaboration through multiple perspectives, which helps enhance creativity and drive innovation. Further, as reflected in its Code of Business Conduct and Ethics for Directors, Officers and Employees, EOG is committed to providing equal opportunity in all aspects of employment and to hiring, evaluating and promoting employees based on skills and performance.

Compensation, Benefits, Health & Wellness. EOG values attracting and retaining talent, and so it provides competitive salaries, bonuses and a subsidized, comprehensive benefits package. EOG also offers a holistic wellness program, a matching gifts program, a flexible work schedule, paid family care leave, paid leave for illness or injury, paid volunteer time and an employee assistance program to support the mental well-being of employees and their dependents. In addition, new-hire stock grants, annual stock grants and an employee stock purchase plan give every employee the opportunity to be a participant in EOG's success.

Training and Development. EOG supports employees' professional development and provides training in leadership, communication, team effectiveness, technical skills and use of EOG systems and applications. EOG's leadership training, in particular, is focused on providing continuity of leadership at EOG by further enhancing the skills needed to lead a multi-disciplined and decentralized workforce. In addition, EOG holds several internal technical conferences each year designed to share best practices and technical advances across the company, including safety and environmental topics. EOG also offers its employees a tuition reimbursement program as well as reimbursement for the costs of professional certifications.

Safety. EOG's safety management programs and processes provide a framework for assessing safety performance in a systematic way. To foster accountability for conducting operations in a safe manner, EOG's safety performance is considered in evaluating employee performance and compensation. EOG provides initial, periodic and refresher safety training to employees and contractors. These training programs address various topics, including operating procedures, safe work practices and emergency and incident response procedures. EOG also collects and tracks incident data and metrics to identify trends and implement corrective actions as necessary.

Competition

EOG competes with major integrated oil and gas companies, government-affiliated oil and gas companies and other independent oil and gas companies for the acquisition of licenses, concessions and leases, properties and reserves and access to the facilities, equipment, materials, services, and employees and other personnel (including geologists, geophysicists, engineers and other specialists) necessary to explore for, develop, produce, market and transport crude oil, NGLs and natural gas. Certain of EOG's competitors have financial and other resources substantially greater than those EOG possesses and have established strategic long-term positions or strong governmental relationships in countries or areas in which EOG may seek new or expanded entry. As a consequence, EOG may be at a competitive disadvantage in certain respects, such as in bidding for drilling rights or in accessing and retaining necessary services, facilities, equipment, materials and personnel. In addition, EOG's larger competitors may have a competitive advantage when responding to factors that affect demand for crude oil, NGLs and natural gas, such as changing worldwide prices and levels of production and the cost and availability of alternative fuels. EOG also faces competition from alternative energy sources, such as renewable energy sources. See ITEM 1A, Risk Factors.

Regulation

General. New or revised rules, regulations and policies may be issued, and new legislation may be enacted, that could impact the oil and gas exploration and production industry. Such rules, regulations, policies and legislation may affect, among other things, (i) permitting for oil and gas drilling on state, tribal and federal lands, (ii) the leasing of state, tribal and federal lands for oil and gas development, (iii) the regulation and disclosure of greenhouse gas (GHG) emissions and/or other climate change-related matters associated with oil and gas operations (e.g., the development, implementation and carrying out of carbon capture and storage activities, including associated financial or tax incentives), (iv) the use of hydraulic fracturing on state, tribal and federal lands, (v) the calculation of royalty payments in respect of oil and gas production from state, tribal and federal lands (including, but not limited to, applicable royalty percentages), (vi) U.S. federal income tax laws applicable to oil and gas exploration and production companies and (vii) the use of financial derivative instruments to hedge the financial impact of fluctuations in crude oil, NGLs and natural gas prices. For additional discussion regarding the regulatory-related risks to which EOG's operations, financial condition and results of operations are or may be subject, see the below discussion and ITEM 1A, Risk Factors.

United States Regulation of Crude Oil and Natural Gas Production. Crude oil and natural gas production operations are subject to various types of regulation, including regulation by federal and state agencies.

United States legislation affecting the oil and gas industry is regularly reviewed, expanded and/or revised by lawmakers. In addition, numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations applicable to the oil and gas industry. Such rules and regulations, among other things, require permits for the drilling of wells, regulate the spacing of wells, prevent the waste of natural gas through restrictions on flaring, require surety bonds for various exploration and production operations and regulate the calculation and payment of royalty payments (for federal and state leases), production taxes and ad valorem taxes.

A portion of EOG's oil and gas leases in New Mexico, North Dakota and Wyoming, as well as in other areas, are granted by the federal government and administered by the Bureau of Land Management (BLM) and/or the Bureau of Indian Affairs (BIA), both federal agencies. Operations conducted by EOG on federal oil and gas leases must comply with numerous additional statutory and regulatory restrictions and, in the case of leases relating to tribal lands, certain tribal environmental and permitting requirements and employment rights regulations. In addition, the U.S. Department of the Interior (via various of its agencies, including the BLM, the BIA and the Office of Natural Resources Revenue) has certain authority over our calculation and payment of royalties, bonuses, fines, penalties, assessments and other revenues related to federal and tribal oil and gas leases. In addition, the Inflation Reduction Act of 2022 (IRA) required that all leases granted and administered by the BLM and entered into on or after August 16, 2022 include a royalty rate of 16.67 percent in respect of the associated oil and gas production. Regulations implementing the new royalty rate were finalized in April 2024. However, the July 2025 One Big Beautiful Bill Act (OBBBA) reversed the royalty increase enacted under the IRA to the previous rate of 12.5 percent and repealed a royalty imposed on methane produced from federal oil and gas leases.

BLM and BIA leases contain relatively standardized terms requiring compliance with detailed regulations. Under certain circumstances, the BLM or BIA may require operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect EOG's interests on federal lands. From time to time, the U.S. Department of the Interior has also considered limiting or pausing new oil and natural gas leases on federal lands. Any limitation or ban on permitting for oil and gas exploration and production activities on federal lands could have a material and adverse effect on EOG's operations, financial condition and results of operations. EOG's interests in offshore United States leases are de minimis.

The transportation and sale for resale of natural gas in interstate commerce are regulated pursuant to the Natural Gas Act of 1938, as amended (NGA), and the Natural Gas Policy Act of 1978. These statutes are administered by the Federal Energy Regulatory Commission (FERC). Effective January 1993, the Natural Gas Wellhead Decontrol Act of 1989 deregulated natural gas prices for all "first sales" of natural gas, which includes all sales by EOG of its own production. All other sales of natural gas by EOG, such as those of natural gas purchased from third parties, remain jurisdictional sales subject to a blanket sales certificate under the NGA, which has flexible terms and conditions. Consequently, all of EOG's sales of natural gas currently may be made at unregulated market prices, subject to applicable contract provisions. EOG's jurisdictional sales, however, may be subject in the future to greater federal oversight, including the possibility that the FERC might prospectively impose more restrictive conditions on such sales. EOG's sales of crude oil and condensate and NGLs are made at unregulated market prices.

EOG owns certain gathering and/or processing facilities and systems in the Permian Basin in West Texas and New Mexico, the Anadarko Basin in Oklahoma, the Powder River Basin in Wyoming, the Appalachian Basin in Ohio, the Barnett Shale in North Texas, the Bakken and Three Forks plays in the Williston Basin in North Dakota, and the Eagle Ford play and Dorado gas play in South Texas. State regulation of gathering and processing facilities generally includes various safety, environmental and, in some circumstances, nondiscrimination requirements with respect to the provision of gathering and processing services, but does not generally entail rate regulation. EOG's gathering and processing operations could be materially and adversely affected should they be subject in the future to the application of state or federal regulation of rates and services.

EOG's gathering and processing operations also may be, or become, subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of such facilities. Additional rules and legislation pertaining to these matters are considered and/or adopted from time to time. Although EOG cannot predict what effect, if any, such legislation might have on its operations and financial condition, EOG could be required to incur additional capital expenditures and increased compliance and operating costs depending on the nature and extent of such future legislative and regulatory changes.

EOG also owns crude oil truck unloading facilities in certain of its U.S. plays. Regulation of such facilities is conducted at the state and federal levels and generally includes various safety, environmental and permitting requirements. Additional regulation pertaining to these matters is considered and/or adopted from time to time. Although EOG cannot predict what effect, if any, any such new regulations might have on the transportation of its crude oil production by truck, EOG could be required to incur additional capital expenditures and increased compliance and operating costs depending on the nature and extent of such future regulatory changes. EOG did not transport any crude oil by rail during 2025.

Proposals and proceedings that might affect the oil and gas industry are considered from time to time by Congress, the state legislatures, the FERC and other federal, state and local regulatory commissions, agencies, councils and courts. EOG cannot predict when or whether any such proposals or proceedings may become effective. It should also be noted that the oil and gas industry historically has been very heavily regulated; therefore, there is no assurance that the approach currently being followed by such legislative bodies and regulatory commissions, agencies, councils and courts will remain unchanged.

Environmental Regulation Generally - United States. EOG is subject to various federal, state and local laws and regulations covering the discharge or release of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations affect EOG's operations and costs as a result of their effect on crude oil and natural gas exploration, development and production operations and related activities (e.g., carbon capture and storage). Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, including the assessment of monetary penalties, the imposition of investigatory and remedial obligations, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and the issuance of orders enjoining future operations or imposing additional compliance requirements.

In addition, EOG has acquired certain oil and gas properties from third parties whose actions with respect to the management and disposal or release of hydrocarbons or other wastes were not under EOG's control. Under environmental laws and regulations, EOG could be required to remove or remediate wastes disposed of or released by prior owners or operators. EOG also could incur costs related to the clean-up of third-party sites to which it sent regulated substances for disposal or to which it sent equipment for cleaning, and for damages to natural resources or other claims related to releases of regulated substances at such third-party sites. In addition, EOG could be responsible under environmental laws and regulations for oil and gas properties in which EOG previously owned or currently owns an interest, but was or is not the operator.

Compliance with environmental laws and regulations increases EOG's overall cost of business, but has not had, to date, a material adverse effect on EOG's operations, financial condition, results of operations or capital expenditures (for environmental control facilities or otherwise). In addition, it is not anticipated, based on current laws and regulations, that EOG will be required in the near future to expend amounts (whether for environmental control facilities or otherwise) that are material in relation to its total exploration and development expenditure program in order to comply with such laws and regulations. However, EOG is unable to predict (i) the timing, scope and effect of any currently proposed or future laws or regulations regarding the environment and (ii) the ultimate cost of compliance or the ultimate effect on EOG's operations, financial condition, results of operations and capital expenditures relating to such future laws and regulations. The direct and indirect cost of such laws and regulations (if enacted) could materially and adversely affect EOG's operations, financial condition, results of operations and capital expenditures.

Climate Change - United States. Local, state, federal and international regulatory bodies have been focused on GHG emissions and climate change issues in recent years. The U.S. Congress has, from time to time, proposed legislation for imposing restrictions on, or requiring fees or carbon taxes in respect of, GHG emissions. Further, the IRA imposes a methane emissions charge on certain oil and gas facilities, including onshore and offshore petroleum and natural gas production facilities, that exceed certain emissions thresholds. The charge will be levied annually based on emissions reported under the U.S. Environmental Protection Agency's (U.S. EPA) GHG Reporting Program, which was amended in May 2024, impacting how emissions are reported under the program. The U.S. EPA published final regulations specific to the calculation of such annual charge in November 2024. In February 2025, however, the U.S. House and Senate approved a joint resolution of disapproval under the Congressional Review Act to repeal the methane emissions charge regulations, which was signed into law, and the OBBBA postponed the imposition of the IRA's methane emissions charge to 2034. In any event, EOG does not expect such annual methane emissions charge would have a material impact on EOG's financial condition, results of operations or operations.

In addition to the U.S. EPA's rule requiring annual reporting of GHG emissions from covered facilities (which is amended from time to time and under which EOG reports), the U.S. EPA has adopted regulations for certain large sources regulating GHG emissions as pollutants under the federal Clean Air Act. Further, the U.S. EPA, in May 2016, issued regulations that require operators to reduce methane emissions and emissions of volatile organic compounds (VOC) from new, modified and reconstructed crude oil and natural gas wells and equipment located at natural gas production gathering and boosting stations, gas processing plants and natural gas transmission compressor stations. In November 2021, the U.S. EPA proposed a rule to further reduce methane and VOC emissions from new and existing sources in the oil and natural gas sector and, in November 2022, the U.S. EPA issued a supplemental proposal to expand its November 2021 proposed rule, including proposed regulation of additional sources of methane and VOC emissions, such as abandoned and unplugged wells. In addition, in March 2024, the U.S. EPA published its final methane rules, which impose new methane emission requirements on the oil and gas industry, including our operations. Further, in April 2024, the BLM published its final Waste Prevention Rule, which requires operators of oil and gas leases to take reasonable steps to avoid natural gas waste, as well as develop leak detection, repair and waste minimization plans.

However, in September 2025, the U.S. EPA announced a proposal to end the GHG Reporting Program for all sectors except petroleum and natural gas systems (excluding reporting for natural gas distribution, which would also be eliminated under the proposal) and defer reporting for petroleum and natural gas systems until 2034. In addition, in December 2025, the U.S. EPA issued a final rule extending several compliance deadlines and timeframes associated with its 2024 methane rules, and the BLM announced it would delay enforcement of two provisions of the Waste Prevention Rule scheduled to take effect in December 2025 as it reconsiders revisions to the 2024 regulations. Further, on February 12, 2026, the U.S. EPA announced the rescission of its 2009 "Endangerment Finding" under the Clean Air Act, which found that GHGs endanger the public health and welfare of current and future generations and emissions of GHGs from motor vehicles contribute to GHG pollution. The rescission impacts the U.S. EPA's authority to regulate GHGs, as well as the U.S. EPA's prior scientific assessment of climate change risks. Litigation challenging the rescission is anticipated which may influence the rescission and the U.S. EPA's regulation of GHG emissions going forward.

At the international level, the U.S., in December 2015, participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement (adopted at the conference) calls for nations to undertake efforts with respect to global temperatures and GHG emissions. The Paris Agreement went into effect in November 2016. The United States formally rejoined the Paris Conference in February 2021 and established economy-wide targets of (i) reducing its net GHG emissions by 50-52 percent below 2005 levels by 2030 and (ii) achieving net zero GHG emissions economy-wide by no later than 2050. In December 2023, the first global stocktake, also known as the “UAE Consensus,” was issued at the COP 28 Conference. The UAE Consensus is an assessment of members’ collective efforts and achievements to reduce GHG emissions and adapt to the impacts of climate change. The UAE Consensus calls on parties, including the U.S., to contribute to the transitioning away from fossil fuels, reduce methane emissions, and increase renewable energy capacity, among other things, to achieve net zero emissions by 2050. In January 2025, the United States submitted formal notification to the United Nations that it intended to withdraw from the Paris Agreement; pursuant to the terms of the Paris Agreement, such withdrawal took effect on January 27, 2026. On January 7, 2026, it was announced that the United States will also withdraw from the United Nations Framework Convention on Climate Change. State and local officials may, however, continue efforts to uphold the commitments set forth in the international accord.

EOG believes that its strategy to continue to improve its emissions performance is important for environmental, operational and economic reasons. EOG’s approach to reducing emissions from its operations remains operationally focused. For example, EOG has developed an environmental data collection and analysis system that is utilized in calculating GHG emissions from the facilities it operates. This system calculates emissions based on recognized regulatory methodologies, where applicable, and on commonly accepted engineering practices.

In addition, EOG has developed, and will continue to develop, targets and ambitions related to its environmental initiatives, including, but not limited to, its current emissions targets. See ITEM 1A, Risk Factors, for additional discussion regarding EOG’s initiatives, targets and ambitions related to emissions and other environmental matters.

EOG is unable to predict the timing, scope and effect of any currently proposed or future investigations, laws, regulations, treaties or policies regarding climate change and GHG emissions (including any laws and regulations that may be enacted in the U.S.), but the direct and indirect costs of such investigations, laws, regulations, treaties or policies (if enacted, issued or applied) could materially and adversely affect EOG's operations, financial condition, results of operations and capital expenditures. The potential increase in the costs of our operations could include costs to operate and maintain our facilities, install new emissions controls on our facilities, acquire allowances or credits to cover our GHG emissions, pay taxes, charges or fees related to our GHG emissions, or administer and manage a GHG emissions program. In addition, changes in regulatory policies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to GHG emissions, or restrictions on their use, could also adversely affect market demand for, and in turn the prices we receive for our production of, crude oil, NGLs and natural gas. Further, the increasing attention to global climate change risks may create the potential for a greater likelihood of governmental investigations and private and public litigation, which could increase our costs or otherwise adversely affect our business. See ITEM 1A, Risk Factors, for additional discussion regarding climate change-related developments.

Regulation of Hydraulic Fracturing and Other Operations - United States. Substantially all of the onshore crude oil and natural gas wells drilled by EOG are completed and stimulated through the use of hydraulic fracturing. Hydraulic fracturing technology, which has been used by the oil and gas industry for more than 70 years and is constantly being enhanced, enables EOG to produce crude oil and natural gas that otherwise would not be recovered. Specifically, hydraulic fracturing is a process in which pressurized fluid is pumped into underground formations to create tiny fractures or spaces that allow crude oil and natural gas to flow from the reservoir into the well so that it can be brought to the surface. Hydraulic fracturing generally takes place thousands of feet underground, a considerable distance below any drinking water aquifers; further, there are impermeable layers of rock between the area fractured and the water aquifers. The makeup of the fluid used in EOG’s hydraulic fracturing process includes water and sand, and typically less than 0.5% of highly diluted chemical additives; lists of the chemical additives used in fracturing fluids are available to the public via internet websites and in other publications sponsored by industry trade associations and through state agencies in those states that require the reporting of the components of fracturing fluids. While the majority of the sand remains underground to hold open the fractures, a significant amount of the water and chemical additives flow back and are then either reused or safely disposed of at sites that are approved and permitted by the appropriate regulatory authorities. EOG periodically conducts regulatory assessments of these disposal facilities to monitor compliance with applicable regulations.

The regulation of hydraulic fracturing is primarily conducted at the state and local level through permitting and other compliance requirements. In April 2012, however, the U.S. EPA issued regulations specifically applicable to the oil and gas industry that require operators to significantly reduce VOC emissions from natural gas wells that are hydraulically fractured through the use of "green completions" to capture natural gas that would otherwise escape into the air. The U.S. EPA has also issued regulations that establish standards for VOC emissions from several types of equipment, including storage tanks, compressors, dehydrators, and valves and sweetening units at gas processing plants. In addition, and as further discussed above under “Climate Change – United States,” the U.S. EPA has issued regulations with respect to the reduction of methane and VOC emissions, including its final methane rules published in March 2024. From time to time, there have been various other proposals to regulate hydraulic fracturing at the federal level.

In addition to the above-described federal regulations, some state and local governments have imposed, or have considered imposing, various conditions and restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water; disclosure of the chemical additives used in hydraulic fracturing operations; restrictions on the type of chemical additives that may be used in hydraulic fracturing operations; and restrictions on drilling or injection activities on certain lands lying within wilderness wetlands, ecologically or seismically sensitive areas, and other protected areas. Such federal, state and local permitting and disclosure requirements, operating restrictions, conditions or prohibitions could lead to operational delays and increased operating and compliance costs and, moreover, could delay or effectively prevent the development of crude oil and natural gas from formations which would not be economically viable without the use of hydraulic fracturing.

Compliance with laws and regulations relating to hydraulic fracturing and other aspects of our operations increases EOG's overall cost of business, but has not had, to date, a material adverse effect on EOG's operations, financial condition, results of operations or capital expenditures (whether for environmental control facilities or otherwise). In addition, it is not anticipated, based on current laws and regulations, that EOG will be required in the near future to expend amounts that are material in relation to its total exploration and development expenditure program in order to comply with such laws and regulations. However, EOG is unable to predict (i) the timing, scope and effect of any currently proposed or future laws or regulations regarding hydraulic fracturing in the United States or other aspects of our operations and (ii) the ultimate cost of compliance or the ultimate effect on EOG's operations, financial condition, results of operations and capital expenditures relating to such future laws and regulations. The direct and indirect costs of such laws and regulations (if enacted) could materially and adversely affect EOG's operations, financial condition, results of operations and capital expenditures.

Other International Regulation. EOG's exploration and production operations outside the United States are subject to various types of regulations, including environmental regulations, imposed by the respective governments of the countries in which EOG's operations are conducted, and may affect EOG's operations and costs of compliance within those countries. EOG is unable to predict the timing, scope and effect of any currently proposed or future laws, regulations or treaties, including those regarding climate change and hydraulic fracturing, but the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely affect EOG's operations, financial condition, results of operations and capital expenditures. EOG will continue to review the risks to its existing business and operations, as well as any potential business and operations, outside the United States associated with all environmental matters, including climate change and hydraulic fracturing regulation. In addition, EOG will continue to monitor and assess any new policies, legislation, regulations and treaties in the areas outside the United States where it operates, to determine the impact on its operations and take appropriate actions, where necessary.

Further, EOG will continue to monitor and assess the impact on its business of any environmental, climate change or other policies, legislation and regulations enacted by foreign governments – for example, the European Union’s November 2023 approval of methane emissions limits on crude oil and natural gas imports beginning in 2030.

Other Matters

Energy Prices. EOG is a crude oil and natural gas producer and is impacted by changes in the prices for crude oil and condensate, NGLs and natural gas. During the last three years, average United States commodity prices have fluctuated, at times rather dramatically. Average crude oil and condensate prices received by EOG for production in the United States decreased 15% in 2025, decreased 2% in 2024 and decreased 19% in 2023, each as compared to the immediately preceding year. Average NGLs prices received by EOG for production in the United States decreased 4% in 2025, increased 1% in 2024 and decreased 37% in 2023, each as compared to the immediately preceding year. Fluctuations in average natural gas prices received by EOG for production in the United States resulted in a 48% increase in 2025, a 26% decrease in 2024, and a 63% decrease in 2023, each as compared to the immediately preceding year.

Due to the many uncertainties associated with the world political and economic environment (for example, the actions of other crude oil exporting nations, including the Organization of Petroleum Exporting Countries, or the global impacts of wars or military conflicts involving such nations or regions), the global supply of, and demand for, crude oil, NGLs and natural gas and the availability of other energy supplies, the relative competitive relationships of the various energy sources in the view of consumers and other factors, EOG is unable to predict what changes may occur in the prices of crude oil and condensate, NGLs and natural gas in the future. For additional discussion regarding changes in crude oil and condensate, NGLs and natural gas prices, the potential impacts on EOG and the risks that such changes may present to EOG, see ITEM 1A, Risk Factors.

Based on EOG's tax position, EOG's price sensitivity in 2026 for each $1.00 per barrel increase or decrease in crude oil and condensate price, combined with the estimated change in NGLs price, is approximately $174 million for net income and $223 million for pretax cash flows from operating activities. Including the impact of EOG's natural gas financial derivative contracts and based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2026 for which prices have not been determined under long-term marketing contracts, EOG's price sensitivity for each $0.10 per Mcf increase or decrease in natural gas price is approximately $64 million for net income and $83 million for pretax cash flows from operating activities. For a summary of EOG's financial commodity and other derivative contracts through February 18, 2026, see ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Financial Commodity and Other Derivative Transactions. For a summary of EOG's financial commodity and other derivative contracts for the year ended December 31, 2025, see Note 12 to Consolidated Financial Statements.

Risk Management. EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in prices of 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. See Note 12 to Consolidated Financial Statements. For a summary of EOG's financial commodity and other derivative contracts through February 18, 2026, see ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations ‑ Capital Resources and Liquidity - Financial Commodity and Other Derivative Transactions.

All of EOG's crude oil, NGLs and natural gas activities are subject to the risks normally incident to the exploration for, and development, production and transportation of, crude oil, NGLs and natural gas, including rig and well explosions, cratering, fires, loss of well control and leaks and spills, each of which could result in damage to life, property and/or the environment. EOG's operations are also subject to certain perils, including hurricanes, tropical storms, flooding, winter storms and other adverse weather events. Moreover, EOG's activities are subject to governmental regulations as well as interruption or termination by governmental authorities based on environmental and other considerations. Losses and liabilities arising from such events could reduce EOG's revenues and increase costs to EOG to the extent not covered by insurance.

Insurance is maintained by EOG against many, but not all, of these risks in accordance with what EOG believes are customary industry practices and in amounts and at costs that EOG believes to be prudent and commercially practicable. Specifically, EOG maintains commercial general liability and excess liability insurance coverage for third party property damage, bodily injury or death claims resulting from an incident involving EOG's operations, including a sudden and accidental pollution event (subject to policy terms and conditions). EOG also maintains first party property damage insurance that covers damage to EOG's equipment, facilities and structures due to a physical damage event and maintains operators extra expense (OEE) coverage for obligations, expenses or claims that EOG may incur from a control of well incident, including obligations, expenses or claims with respect to a resulting pollution event, including coverage for cleanup and containment (subject to policy terms and conditions). EOG's drilling activities are conducted on a contractual basis with independent drilling contractors and other third-party service contractors. The indemnification and other risk allocation provisions included in such contracts are negotiated on a contract-by-contract basis and are each based on the particular circumstances of the services being provided and the anticipated operations.

In addition to the above-described risks, EOG's operations outside the United States are subject to certain additional risks, including:

•increases in taxes and governmental royalties;

•additional and potentially unfamiliar laws and policies governing the operations of foreign-based companies and changes in such laws and policies;

•expropriation of assets;

•unilateral or forced renegotiation, modification or nullification of existing contracts with governmental entities; and

•currency restrictions and exchange rate fluctuations.

Please refer to ITEM 1A, Risk Factors, for further discussion of the risks to which EOG is subject with respect to its operations outside the United States.

Information About Our Executive Officers

The current executive officers of EOG and their names and ages (as of February 24, 2026) are as follows:

Name

Age

Position

Ezra Y. Yacob

Chairman of the Board and Chief Executive Officer

Jeffrey R. Leitzell

Executive Vice President and Chief Operating Officer

Ann D. Janssen

Executive Vice President and Chief Financial Officer

Michael P. Donaldson

Executive Vice President and Chief Legal Officer

Ezra Y. Yacob was appointed Chairman of the Board, effective October 2022, and elected Chief Executive Officer and appointed as a Director effective October 2021. Prior to that, he served as President from January 2021 through September 2021; Executive Vice President, Exploration and Production from December 2017 to January 2021; and Vice President and General Manager of EOG's Midland, Texas office from May 2014 to December 2017. He also previously served as Manager, Division Exploration in EOG's Fort Worth, Texas, and Midland, Texas, offices from March 2012 to May 2014 as well as in various geoscience and leadership positions. Mr. Yacob joined EOG in August 2005.

Jeffrey R. Leitzell was elected Executive Vice President and Chief Operating Officer in December 2023. Mr. Leitzell previously served as Executive Vice President, Exploration and Production from May 2021 to December 2023, Vice President and General Manager of EOG's Midland, Texas office from December 2017 to May 2021 and as Operations Manager in Midland from August 2015 to December 2017. Prior to that, Mr. Leitzell held various engineering roles of increasing responsibility in multiple offices and functional areas within EOG. Mr. Leitzell joined EOG in October 2008.

Ann D. Janssen was elected Executive Vice President and Chief Financial Officer effective January 2024. Previously, Ms. Janssen served as Senior Vice President and Chief Accounting Officer from February 2018 through December 2023 and as EOG's principal accounting officer from September 2010 through December 2023. Prior to that, Ms. Janssen held various accounting and finance roles of increasing responsibilities. Ms. Janssen joined a predecessor of EOG in October 1995.

Michael P. Donaldson was elected Executive Vice President and Chief Legal Officer in September 2025. Previously, Mr. Donaldson served as Executive Vice President, General Counsel and Corporate Secretary from April 2016 to September 2025 and served as Vice President, General Counsel and Corporate Secretary from May 2012 to April 2016. He was elected Corporate Secretary in May 2008, and was appointed Deputy General Counsel and Corporate Secretary in July 2010. Mr. Donaldson joined EOG in September 2007.

ITEM 1A. Risk Factors

Our business and operations are subject to many risks. The risks described below may not be the only risks we face, as our business and operations may also be subject to risks that we do not yet know of, or that we currently believe are immaterial. If any of the events or circumstances described below actually occurs, our business, financial condition, results of operations and/or cash flows could be materially and adversely affected and the trading price of our common stock could decline. The following risk factors should be read in conjunction with the other information contained herein, including the consolidated financial statements and the related notes. Unless the context requires otherwise, "we," "us," "our" and "EOG" refer to EOG Resources, Inc. and its subsidiaries.

Risks Related to our Financial Condition, Results of Operations and Cash Flows

Crude oil, NGLs and natural gas prices are volatile, and a substantial and extended decline in commodity prices can have a material and adverse effect on us.

Prices for crude oil and natural gas (including prices for natural gas liquids (NGLs) and condensate) fluctuate widely. Among the interrelated factors that can or could cause these price fluctuations are:

•domestic and worldwide supplies of, and consumer and industrial/commercial demand for, crude oil, NGLs and natural gas;

•domestic and international drilling activity;

•the actions of crude oil producing and exporting nations, including the Organization of Petroleum Exporting Countries;

•worldwide economic conditions, geopolitical factors and political conditions, including, but not limited to, tariffs; trade policies, trade agreements and trade restrictions; other economic sanctions or barriers; and political instability or armed conflicts in oil and gas producing regions;

•the availability, proximity and capacity of appropriate gathering, processing, compression, storage, transportation, refining, liquefaction and export facilities;

•the price and availability of, and demand for, competing energy sources, including alternative energy sources;

•the effect of worldwide energy conservation measures, alternative fuel requirements and climate change-related legislation, policies, initiatives and developments;

•technological advances and consumer and industrial/commercial behavior, preferences and attitudes, in each case affecting energy generation, transmission, storage and consumption;

•the nature and extent of governmental regulation, including environmental and other climate change-related regulation, regulation of financial and other derivative transactions and hedging activities, tax laws and regulations and laws and regulations with respect to the import and export of crude oil, NGLs, and natural gas and related commodities;

•the level and effect of trading in commodity futures markets, including trading by commodity price speculators and others;

•natural disasters, weather conditions and changes in weather patterns, each of which may be exacerbated by climate change; and

•the economic and financial impact of epidemics, pandemics or other public health issues.

The above-described factors and the volatility of commodity prices make it difficult to predict crude oil, NGLs and natural gas prices in 2026 and thereafter. As a result, there can be no assurance that the prices for crude oil, NGLs and/or natural gas will sustain, or increase from, their current levels, nor can there be any assurance that the prices for crude oil, NGLs and/or natural gas will not decline.

Our cash flows, financial condition and results of operations depend to a great extent on prevailing commodity prices. Accordingly, substantial and extended declines in commodity prices can materially and adversely affect the amount of cash flows we have available for our capital expenditures and operating costs; the terms on which we can access the credit and capital markets; our results of operations; and our financial condition, including (but not limited to) our ability to pay regular and special dividends on our common stock or repurchase shares of our common stock under the share repurchase authorization established by our Board of Directors (Board). As a result, the trading price of our common stock may be materially and adversely affected.

Lower commodity prices can also reduce the amount of crude oil, NGLs and natural gas that we can produce economically. Substantial and extended declines in the prices of these commodities can render uneconomic a portion of our exploration, development and exploitation projects, resulting in our having to make downward adjustments (“write-downs”) to our estimated reserves and also possibly shut in, or plug and abandon, certain wells. In addition, significant prolonged decreases in commodity prices may cause the expected future cash flows from our properties to fall below their respective net book values, which would require us to recognize an impairment expense in respect of the value of our properties. Such reserve write-downs and asset impairments can materially and adversely affect our results of operations and financial position and, in turn, the trading price of our common stock.

We have substantial capital requirements, and we may be unable to obtain needed financing on satisfactory terms, if at all.

We make, and expect to continue to make, substantial capital expenditures for the acquisition, exploration, development and production of crude oil, NGLs and natural gas reserves as well as for the gathering, processing and transportation of our production volumes. We intend to fund our capital expenditures primarily through our cash flows from operations and cash on hand and, if and as necessary, commercial paper borrowings, bank borrowings, borrowings under our revolving credit facility and public and private debt and equity offerings.

Lower crude oil, NGLs and natural gas prices, however, reduce our cash flows and could also delay or impair our ability to consummate any planned acquisitions or divestitures. Further, if the condition of the credit and capital markets materially declines, we might not be able to obtain financing on terms we consider acceptable, if at all. In addition, weakness and/or volatility in domestic and global financial markets or economic conditions or a depressed commodity price environment may increase the interest rates that lenders and commercial paper investors require us to pay or otherwise adversely affect our ability to finance our capital expenditures through debt or equity offerings or other financing transactions.

Similarly, a reduction in our cash flows (for example, as a result of lower crude oil, NGLs and/or natural gas prices or unanticipated well shut-ins) and the corresponding adverse effect on our financial condition and results of operations may also increase the interest rates that lenders and commercial paper investors require us to pay. A substantial increase in interest rates would decrease our net cash flows available for reinvestment (and, as noted above, for the payment of regular and special dividends on our common stock and for the repurchase of shares of our common stock). Any of these factors could have a material and adverse effect on our business, financial condition and results of operations and, in turn, the trading price of our common stock.

Further, our ability to obtain financings, our borrowing costs and the terms of any financings are, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. The interrelated factors that may impact our credit ratings include our debt levels; planned capital expenditures and sales of assets; near-term and long-term production growth opportunities; liquidity; asset quality; cost structure; product mix; and commodity pricing levels (including, but not limited to, the estimates and assumptions of credit rating agencies with respect to future commodity prices). We cannot provide any assurance that our current credit ratings will remain in effect for any given period of time or that our credit ratings will be raised in the future, nor can we provide any assurance that any of our credit ratings will not be lowered.

In addition, companies in the oil and gas sector may be exposed to reputational risks and, in turn, certain financial risks. For example, certain financial institutions, investment advisors and sovereign wealth, pension and endowment funds, in response to concerns related to climate change and the requests and other influence of environmental groups and similar stakeholders, have from time to time elected to shift some or all of their investments and financing away from oil and gas-related sectors. Additional financial institutions and other investors may, in the future, elect to do likewise or may impose more stringent conditions with respect to investments in, and financing of, oil and gas-related sectors. As a result, fewer financial institutions and other investors may be willing to invest in, and provide capital to, companies in the oil and gas sector.

A material reduction in capital available to the oil and gas sector could make it more difficult (e.g., due to a lack of investor interest in our debt or equity securities) and/or more costly (e.g., due to higher interest rates on our debt securities or other borrowings) to secure funding for our operations, which, in turn, could adversely affect our ability to successfully carry out our business strategy and could have a material and adverse effect on our business, financial condition and operations.

Our continued initiatives to increase operating efficiencies may not be successful in offsetting any future inflationary pressures on our operating costs and capital expenditures.

We have undertaken (and continue to undertake) initiatives to increase our drilling, completions and operating efficiencies and improve the performance of our wells. Such initiatives include (among others): (i) our downhole drilling motor program; (ii) enhanced techniques for completing our wells; (iii) drilling extended laterals; and (iv) our self-sourced sand program. In addition, from time to time (when available and advantageous), we enter into agreements with service providers to secure the costs and availability of certain drilling and completions services we utilize as part of our operations.

We plan to continue these initiatives and actions. However, such efforts may not be successful or may not be sufficient to offset the impacts of any future inflationary pressures (such as from tariffs, other trade barriers or other macroeconomic factors) on our operating costs and capital expenditures and, in turn, on our cash flows and results of operations. For additional discussion, see ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations – Overview – Recent Developments.

Reserve estimates depend on many interpretations and assumptions. Any significant inaccuracies in these interpretations and assumptions could cause the reported quantities of our reserves to be materially misstated.

Estimating quantities of crude oil, NGLs and natural gas reserves and the future net cash flows from such reserves is a complex, inexact process. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors, made by our management. Any significant inaccuracies in these interpretations or assumptions could cause the reported quantities of our reserves and future net cash flows from such reserves to be overstated or understated. Also, 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.

To prepare estimates of our economically recoverable crude oil, NGLs and natural gas reserves and future net cash flows from our reserves, we analyze many variable factors, such as historical production from the area compared with production rates from other producing areas. We also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also involves economic assumptions relating to commodity prices, production costs, gathering, processing, compression, storage and transportation costs, severance, ad valorem and other applicable taxes, capital expenditures and workover and remedial costs. Many of these factors are or may be beyond our control. The quantities of reserves ultimately recovered and the future net cash flows from such reserves most likely will vary from our estimates. Any significant variance, including any significant downward revisions (“write-downs”) to our existing reserve estimates, could materially and adversely affect our business, financial condition and results of operations and, in turn, the trading price of our common stock. For related discussion, see ITEM 2, Properties - Oil and Gas Exploration and Production - Properties and Reserves and Supplemental Information to Consolidated Financial Statements.

If we fail to acquire or find sufficient additional reserves over time, our reserves and production will decline from their current levels.

The rate of production from crude oil and natural gas properties generally declines as reserves are produced. Except to the extent that we conduct successful exploration, exploitation and development activities resulting in additional reserves, acquire additional properties containing reserves or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our reserves will decline as they are produced. Maintaining our production of crude oil, NGLs and natural gas at, or increasing our production from, current levels, is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves, which may be adversely impacted by bans or restrictions on leasing and/or drilling. To the extent we are unsuccessful in acquiring or finding additional reserves, our future cash flows and results of operations and, in turn, the trading price of our common stock could be materially and adversely affected.

Our ability to declare and pay regular or special dividends on our common stock and repurchase shares of our common stock is subject to certain factors and considerations.

Regular and special dividends on our common stock and repurchases of our common stock are authorized and determined by our Board in its sole discretion and depend upon a number of factors and considerations, including:

•cash available for dividends or share repurchases;

•our results of operations and anticipated future results of operations;

•our financial condition, especially in relation to the anticipated future capital expenditures and other commitments requiring cash necessary to conduct our operations and carry out our business strategy;

•our operating costs;

•the levels of dividends paid by comparable companies; and

•other factors our Board deems relevant.

We expect to continue to pay dividends to our stockholders; however, our payment of dividends in the future is solely within the discretion of our Board. Accordingly, our Board may reduce our dividends or cease declaring dividends at any time, including if it determines that our current or forecasted future cash flows provided by our operating activities (after deducting our capital expenditures and other commitments requiring cash) are not sufficient to pay our desired levels of dividends to our stockholders or to pay dividends to our stockholders at all. Any reduction in the amount of dividends we pay to stockholders could have an adverse effect on the trading price of our common stock.

In November 2021, our Board established a share repurchase authorization allowing for the repurchase by us of up to $5 billion of our common stock, which was subsequently increased by the Board, from $5 billion to $10 billion, in November 2024 (Share Repurchase Authorization). Beginning in March 2023, we have repurchased shares from time to time under the Share Repurchase Authorization. The timing and amount of repurchases is at the discretion of our management and depends on a variety of factors, including the trading price of our common stock, corporate and regulatory requirements, other market and economic conditions, the availability of cash to effect repurchases and our anticipated future capital expenditures and other commitments requiring cash. For further discussion regarding the Share Repurchase Authorization and our share repurchases thereunder, see ITEM 5, “Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” below.

Our hedging activities may prevent us from fully benefiting from increases in crude oil, NGLs and natural gas prices and may expose us to other risks, including counterparty risk, and our future production may not be sufficiently protected from any declines in commodity prices by our existing or future hedging arrangements.

We use financial derivative instruments (primarily financial basis swap, price swap, option, swaption and collar contracts) and, in certain cases, fixed price physical sales contracts to hedge the impact of fluctuations in crude oil, NGLs and natural gas prices on our results of operations and cash flows. To the extent that we engage in hedging activities to protect ourselves against commodity price declines, we may be prevented from fully realizing the benefits of increases in crude oil, NGLs and natural gas prices above the prices established by our hedging contracts. Further, a majority of our forecasted production for 2026 is subject to fluctuating market prices. To the extent we do not hedge our production volumes for 2026 and beyond, we may be materially and adversely impacted by any declines in commodity prices, which may result in lower net cash provided by our operating activities. In addition, our hedging activities may expose us to the risk of financial loss in certain circumstances, including instances in which the counterparties to our financial derivative instruments fail to perform under the contracts.

The inability of our customers and other contractual counterparties to satisfy their obligations to us may have a material and adverse effect on us.

We have various customers for the crude oil, natural gas and related commodities that we produce as well as various other contractual counterparties, including financial institutions and affiliates of financial institutions. Domestic and global economic conditions, including the financial condition of financial institutions generally, may adversely affect the ability of our customers and other contractual counterparties to pay amounts owed to us from time to time and to otherwise satisfy their contractual obligations to us, as well as their ability to access the credit and capital markets for such purposes.

Moreover, our customers and other contractual counterparties may be unable to satisfy their contractual obligations to us for reasons unrelated to these conditions and factors, such as (i) the unavailability of required facilities or equipment due to mechanical failure or market conditions or (ii) financial, operational or strategic actions taken by the customer or counterparty that adversely impact its financial condition, results of operations and cash flows and, in turn, its ability to satisfy its contractual obligations to us. Furthermore, if a customer is unable to satisfy its contractual obligation to purchase crude oil, natural gas or related commodities from us, we may be unable to sell such production to another customer on terms we consider acceptable, if at all, due to the geographic location of such production; the availability, proximity and capacity of appropriate gathering, processing, compression, storage, transportation, export, liquefaction and refining facilities; or market or other factors and conditions.

The inability of our customers and other contractual counterparties to pay amounts owed to us and/or to otherwise satisfy their contractual obligations to us may materially and adversely affect our business, financial condition, results of operations and cash flows.

Risks Related to our Operations

Drilling crude oil and natural gas wells is a high-risk activity and subjects us to a variety of risks that we cannot control.

Drilling crude oil and natural gas wells involves numerous risks, including the risk that we may not encounter commercially productive crude oil, NGLs and/or natural gas reserves. As a result, we may not recover all or any portion of our investment in new wells.

Specifically, we often are uncertain as to the future cost or timing of drilling, completing and operating wells, and our drilling and completions operations and those of our third-party operators may be curtailed, delayed or canceled, the cost of such operations may increase and/or our results of operations and cash flows from such operations may be impacted, as a result of a variety of factors, including:

•unexpected drilling conditions;

•leasehold title problems;

•pressure or irregularities in formations;

•equipment failures or accidents;

•adverse weather events, such as winter storms, flooding, wildfires, tropical storms and hurricanes, and other natural disasters, which may be exacerbated by climate change;

•compliance with, or changes in (including the adoption of new), environmental, health and safety laws and regulations relating to air emissions, hydraulic fracturing, access to and use of water, disposal or other discharge (e.g., into injection wells) of produced water, drilling fluids and other wastes, laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil, NGLs and natural gas, and other laws and regulations, such as tax laws and regulations;

•the availability and timely issuance of required federal, state, tribal and other permits and licenses, which may be adversely affected by (among other things) bans or restrictions on drilling, government shutdowns or other suspensions of, or delays in, government services;

•the availability of, costs associated with, and terms of contractual arrangements for properties, including mineral licenses and leases, pipelines, crude oil hauling trucks and qualified drivers and facilities and equipment to gather, process, compress, store, transport, market and export crude oil, NGLs and natural gas and related commodities; and

•the costs of, or shortages or delays in the availability of, drilling rigs, hydraulic fracturing services, pressure pumping equipment and supplies, tubular materials, water, sand, disposal facilities, qualified personnel and other necessary facilities, equipment, materials, supplies and services.

Our failure to recover our investment in wells, increases in the costs of our drilling and completions operations or those of our third-party operators, and/or curtailments, delays or cancellations of our drilling and completions operations or those of our third-party operators, in each case, due to any of the above factors or other factors, may materially and adversely affect our business, financial condition and results of operations. For related discussion of the risks and potential losses and liabilities inherent in our crude oil and natural gas operations generally, see the immediately following risk factor.

Our crude oil, NGLs and natural gas operations and supporting activities and operations involve many risks and expose us to potential losses and liabilities, and insurance may not fully protect us against these risks and potential losses and liabilities.

Our crude oil, NGLs and natural gas operations and supporting activities and operations are subject to all of the risks associated with exploring and drilling for, and producing, gathering, processing, compressing, storing, transporting and exporting crude oil, NGLs and natural gas, including the risks of:

•well blowouts and cratering;

•loss of well control;

•crude oil spills, natural gas leaks, formation water (i.e., produced water) spills and pipeline ruptures;

•pipe failures and casing collapses;

•uncontrollable flows of crude oil, natural gas, formation water or drilling fluids;

•releases of chemicals, wastes or pollutants;

•adverse weather events, such as winter storms, flooding, wildfires, tropical storms and hurricanes, and other natural disasters, which may be exacerbated by climate change;

•fires and explosions;

•terrorism, vandalism and physical, electronic and cyber breaches and related threats;

•formations with abnormal or unexpected pressures;

•leaks or spills in connection with, or associated with, the gathering, processing, compression, storage, transportation and export of crude oil, NGLs and natural gas; and

•malfunctions of, or damage to, gathering, processing, compression, storage, transportation and export facilities and equipment and other facilities and equipment utilized in support of our crude oil and natural gas operations.

If any of these events occur, we could incur losses, liabilities and other costs as a result of:

•injury or loss of life;

•damage to, or destruction of, property, facilities, equipment and crude oil and natural gas reservoirs;

•pollution or other environmental damage;

•regulatory investigations, penalties and injunctions as well as cleanup and remediation responsibilities and costs;

•the lack of availability of, or access to, necessary third-party services and facilities, such as gathering, processing, compression, storage, transportation and export services and facilities;

•loss of production due to temporary cessation of our operations (for example, to conduct repairs necessary to resume operations) or damage to necessary facilities and equipment; and

•compliance with laws and regulations enacted as a result of such events.

We maintain insurance against many, but not all, such losses and liabilities in accordance with what we believe are customary industry practices and in amounts and at costs that we believe to be prudent and commercially practicable. However, the occurrence of any of these events and any losses or liabilities incurred as a result of such events, if uninsured or in excess of our insurance coverage, would reduce the funds available to us for our operations and could, in turn, have a material and adverse effect on our business, financial condition and results of operations. Further, in the future, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates or at all. As a result of market conditions, premiums, retentions and deductibles for our insurance policies will change over time and could increase. In addition, some forms of insurance may become unavailable or unavailable on economically acceptable terms.

Our ability to sell and deliver our crude oil, NGLs and natural gas production could be materially and adversely affected if adequate gathering, processing, compression, storage, transportation, refining, liquefaction and export facilities and equipment are unavailable.

The sale of our crude oil, NGLs and natural gas production depends on a number of factors beyond our control, including the availability, proximity and capacity of, and costs associated with, gathering, processing, compression, storage, transportation, refining, liquefaction and export facilities and equipment owned by third parties. These facilities and equipment may be temporarily unavailable to us due to market conditions, supply chain disruptions, regulatory reasons, mechanical reasons or other factors or conditions, and may not be available to us in the future on terms we consider acceptable, if at all. In particular, in certain newer plays, the capacity of gathering, processing, compression, storage, transportation, refining, liquefaction and export facilities and equipment may not be sufficient to accommodate potential production from existing and new wells. In addition, lack of financing, construction and permitting delays, permitting costs and regulatory or other constraints could limit or delay the construction, manufacture or other acquisition of new gathering, processing, compression, storage, transportation, refining, liquefaction and export facilities and equipment by third parties or us, and we may experience delays or increased costs in accessing the pipelines, gathering systems or transportation systems necessary to transport our production to points of sale or delivery.

Any significant change in market or other conditions affecting gathering, processing, compression, storage, transportation, refining, liquefaction and export facilities and equipment or the availability of these facilities and equipment, including due to our failure or inability to obtain access to these facilities and equipment on terms acceptable to us or at all, could materially and adversely affect our business and, in turn, our financial condition and results of operations.

A portion of our crude oil, NGLs and natural gas production may be subject to interruptions that could have a material and adverse effect on us.

A portion of our crude oil, NGLs and natural gas production may be interrupted, or shut in, from time to time for various reasons, including, but not limited to, as a result of accidents, weather conditions or natural disasters, the unavailability of gathering, processing, compression, storage, transportation, refining, liquefaction or export facilities or equipment or field labor issues, or intentionally as a result of market conditions such as crude oil, NGLs or natural gas prices that we deem uneconomic. If a substantial amount of our production is interrupted or shut in, our cash flows and, in turn, our financial condition and results of operations could be materially and adversely affected.

Our operations are substantially dependent upon the availability of water. Restrictions or limitations on our ability to obtain water may have a material and adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of our operations, both during drilling operations and completions operations. Limitations or restrictions on our ability to secure sufficient amounts of water (including limitations resulting from natural causes such as drought) could materially and adversely impact our operations. Further, severe drought conditions can result in local authorities taking steps to restrict the use of water in their jurisdiction for drilling and completions in order to protect the local water supply. If we are unable to obtain water to use in our operations from local sources, we may need to obtain water from sources that are more distant from our drilling sites, resulting in increased costs, which could have a material and adverse effect on our financial condition, results of operations and cash flows.

If we acquire crude oil, NGLs or natural gas properties, our failure to fully identify existing and potential issues, to accurately estimate reserves, production rates or costs, or to effectively integrate the acquired properties into our operations could materially and adversely affect our business, financial condition and results of operations.

From time to time, we acquire crude oil and natural gas properties. Although we perform reviews of properties to be acquired in a manner that we believe are diligent and consistent with industry practices, reviews of records and properties may not necessarily reveal existing or potential issues (such as title defects or environmental issues), nor may they permit us to become sufficiently familiar with the properties in order to fully assess their deficiencies and potential. Even when issues with a property are identified, we often may assume environmental and other risks and liabilities in connection with acquired properties pursuant to the acquisition agreements.

In addition, there are numerous uncertainties inherent in estimating quantities of crude oil, NGLs and natural gas reserves (as discussed further above), actual future production rates and associated costs with respect to acquired properties. Actual reserves, production rates and costs may vary substantially from those assumed in our estimates. In addition, an acquisition may have a material and adverse effect on our financial condition and results of operations, particularly during the periods in which the operations of the acquired properties are being integrated into our ongoing operations or if we are unable to effectively integrate the acquired properties into our ongoing operations or achieve anticipated synergies.

Competition in the oil and gas exploration and production industry is intense, and some of our competitors have greater resources than we have.

We compete with major integrated oil and gas companies, government-affiliated oil and gas companies and other independent oil and gas companies for the acquisition of licenses, concessions and leases, properties and reserves and access to the facilities, equipment, materials, services and employees and other personnel (including geologists, geophysicists, engineers and other specialists) necessary to explore for, develop, produce, market and transport crude oil, NGLs and natural gas. Certain of our competitors have financial and other resources substantially greater than those we possess and have established strategic long-term positions or strong governmental relationships in countries or areas in which we may seek new or expanded entry. As a consequence, we may be at a competitive disadvantage in certain respects, such as in bidding for drilling rights or in accessing and retaining necessary services, facilities, equipment, materials and personnel. In addition, our larger competitors may have a competitive advantage when responding to factors that affect demand for crude oil, NGLs and natural gas, such as changing worldwide prices and levels of production and the cost and availability of alternative fuels. We also face competition from alternative energy sources, such as renewable energy sources.

Risks Related to Sustainability, Regulatory and Legal Matters

Developments and concerns related to climate change may have a material and adverse effect on us.

Governmental and regulatory bodies, investors, consumers, industry and other stakeholders have been focused on climate change matters in recent years. For example, (i) in March 2024, the U.S. Securities and Exchange Commission (SEC) finalized extensive climate-related disclosure rules that would require U.S. public companies to significantly expand the climate-related disclosures in their SEC filings (although these rules have 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), (ii) in September 2023, California passed climate-related disclosure mandates which are broader than the SEC's final rules and (iii) in November 2023, the European Union approved methane emissions limits on crude oil and natural gas imports beginning in 2030. This focus, together with changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy, the use of crude oil, NGLs and natural gas and the use of products manufactured with, or powered by, crude oil, NGLs and natural gas, may result in (i) the enactment of climate change-related regulations, policies and initiatives (at the government, corporate and/or investor community levels), including alternative energy requirements, energy conservation measures and emissions-related legislation, (ii) technological advances with respect to the generation, transmission, storage and consumption of energy (e.g., wind, solar and hydrogen power, smart grid technology and battery technology) and (iii) increased availability of, and increased consumer and industrial/commercial demand for, non-hydrocarbon energy sources (e.g., alternative energy sources. such as renewable energy sources) and products manufactured with, or powered by, non-hydrocarbon sources (e.g., electric vehicles and renewable residential and commercial power supplies). These developments may adversely affect the demand for products manufactured with, or powered by, crude oil, NGLs and natural gas and the demand for, and in turn the prices of, the crude oil, NGLs and natural gas that we sell. See the risk factors above for a discussion of the impact of commodity prices (including fluctuations in commodity prices) on our financial condition, cash flows and results of operations.

In addition to potentially adversely affecting the demand for, and prices of, the crude oil, NGLs and natural gas that we produce and sell, such developments may also adversely impact, among other things, the availability to us of necessary third-party services and facilities that we rely on, which may increase our operational costs and adversely affect our ability to explore for, produce, transport and process crude oil, NGLs and natural gas and successfully carry out our business strategy. For further discussion of the potential impact of such availability-related risks on our financial condition and results of operations, see the discussion in the section above entitled "Risks Related to our Operations."

Further, climate change-related developments (such as the climate-related disclosure mandates referenced above) may result in negative perceptions of the oil and gas industry and, in turn, reputational risks associated with the exploration for, and production of, hydrocarbons. Such negative perceptions and reputational risks may adversely affect our ability to successfully carry out our business strategy, for example, by adversely affecting the availability and cost of capital to us. For further discussion of the potential impact of such risks on our financial condition, cash flows and results of operations, see the discussion below in this section and in the section above entitled "Risks Related to Our Operations."

In addition, the enactment of climate change-related regulations, policies and initiatives (at the government, corporate and/or investor community levels) may also result in increases in our compliance costs and other operating costs. For further discussion regarding the risks to us of climate change-related regulations, policies and initiatives, see the discussion in this section. Also, continuing political and social concerns relating to climate change may have adverse effects on our business and operations, such as a greater potential for shareholder activism, governmental inquiries and enforcement actions and litigation (including, but not limited to, litigation brought by governmental entities and shareholder litigation) and resulting expenses and potential disruption to our day-to-day operations.

Regulatory, legislative and policy changes may materially and adversely affect the oil and gas exploration and production industry.

New or revised rules, regulations and policies may be issued, and new legislation may be enacted, that could impact the oil and gas exploration and production industry. Such rules, regulations, policies and legislation may affect, among other things, (i) permitting for oil and gas drilling on state, tribal and federal lands, (ii) the leasing of state, tribal and federal lands for oil and gas development, (iii) the regulation and disclosure of greenhouse gas (GHG) emissions and/or other climate change-related matters associated with oil and gas operations, (iv) the use of hydraulic fracturing on state, tribal and federal lands, (v) the calculation of royalty payments in respect of oil and gas production from state, tribal and federal lands (including, but not limited to, applicable royalty percentages), (vi) U.S. federal income tax laws applicable to oil and gas exploration and production companies and (vii) the use of financial derivative instruments to hedge the financial impact of fluctuations in crude oil, NGLs and natural gas prices.

Further, such regulatory, legislative and policy changes may, among other things, result in additional permitting and disclosure requirements, additional operating restrictions and/or the imposition of various conditions and restrictions on drilling and completions operations or other aspects of our business, any of which could lead to operational delays, increased operating and compliance costs and/or other impacts on our business and operations and could materially and adversely affect our business, results of operations, financial condition and capital expenditures.

For related discussion, see the below risk factors regarding legislative and regulatory matters impacting the oil and gas exploration and production industry and the discussion in ITEM 1, Business - Regulation.

We incur certain costs to comply with government regulations, particularly regulations relating to environmental protection and safety, and could incur even greater costs in the future.

Our crude oil, NGLs and natural gas operations and supporting activities are regulated extensively by federal, state, tribal and local governments and regulatory agencies, both domestically and in the foreign countries in which we do business, and are subject to interruption or termination by governmental and regulatory authorities based on environmental, health, safety or other considerations. Moreover, we have incurred and will continue to incur costs in our efforts to comply with the requirements of environmental, health, safety and other regulations. Further, the regulatory environment could change in ways that we cannot predict and that might substantially increase our costs of compliance and/or adversely affect our business and operations and, in turn, materially and adversely affect our results of operations, financial condition, cash flows and capital expenditures.

Specifically, as a current or past owner or lessee and operator of crude oil and natural gas properties, we are subject to various federal, state, tribal, local and foreign regulations relating to the discharge of materials into, and the protection of, the environment. These regulations may, among other things, impose liability on us for the cost of pollution cleanup resulting from current or past operations, subject us to liability for pollution damages and require suspension or cessation of operations in affected areas. Changes in, or additions to, these regulations, could lead to increased operating and compliance costs and, in turn, materially and adversely affect our business, results of operations, financial condition and capital expenditures.

The regulation of hydraulic fracturing is primarily conducted at the state and local level through permitting and other compliance requirements and, further, some state and local governments have imposed or have considered imposing various conditions and restrictions on drilling and completions operations. The U.S. Environmental Protection Agency (U.S. EPA) has, however, issued certain regulations relating to hydraulic fracturing and there have been various other proposals to regulate hydraulic fracturing at the federal level.

Any new requirements, restrictions, conditions or prohibitions could lead to operational delays and increased operating and compliance costs and, further, could delay or effectively prevent the development of crude oil and natural gas from formations which would not be economically viable without the use of hydraulic fracturing. Accordingly, our production of crude oil and natural gas could be materially and adversely affected. For additional discussion regarding hydraulic fracturing regulation, see Regulation of Hydraulic Fracturing and Other Operations - United States under ITEM 1, Business - Regulation.

We will continue to monitor and assess any proposed or new policies, legislation, regulations and treaties in the areas where we operate to determine the impact on our operations and take appropriate actions, where necessary. We are unable to predict the timing, scope and effect of any currently proposed or future laws, regulations or treaties, but the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely affect our business, results of operations, financial condition and capital expenditures.

Regulations, government policies and government and corporate initiatives relating to greenhouse gas emissions and climate change could have a significant impact on our operations and we could incur significant cost in the future to comply.

Local, state, federal and international regulatory bodies have been focused on GHG emissions and climate change issues in recent years. For discussion of the rules and regulations adopted by the U.S. EPA and the Bureau of Land Management with respect to GHG emissions and related matters and the related actions taken by the U.S. Congress, see ITEM 1, Business – Regulation – Climate Change – United States.

At the international level, the Paris Agreement calls for nations to undertake efforts with respect to global temperatures and GHG emissions and the UAE Consensus calls on parties, including the U.S., to contribute to the transitioning away from fossil fuels, reduce methane emissions, and increase renewable energy capacity, among other things, to achieve net zero emissions by 2050. The U.S. withdrew from the Paris Agreement effective January 27, 2026 and, on January 7, 2026, it was announced that the U.S. will also withdraw from the United Nations Framework Convention on Climate Change. For further discussion regarding the Paris Agreement, the UAE Consensus and related matters, see ITEM 1, Business – Regulation – Climate Change – United States. State and local officials may, however, continue efforts to uphold the commitments set forth in the international accord.

It is possible that the Paris Agreement, the related UAE Consensus, and subsequent domestic and international regulations and government policies related to climate change and GHG emissions will have adverse effects on the market for crude oil, NGLs and natural gas as well as adverse effects on the business and operations of companies engaged in the exploration for, and production of, crude oil, NGLs and natural gas.

We are unable to predict the timing, scope and effect of any currently proposed or future investigations, laws, regulations, treaties or policies regarding climate change and GHG emissions (including any laws and regulations that may be enacted in the U.S.), but the direct and indirect costs of such developments (if enacted, issued or applied) could materially and adversely affect our operations, financial condition, results of operations and capital expenditures. The potential increase in the costs of our operations could include costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay taxes or fees related to our GHG emissions, or administer and manage a GHG emissions program. In addition, changes in regulatory policies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to GHG emissions, or restrictions on their use, could also adversely affect market demand for, and in turn the prices we receive for our production of, crude oil, NGLs and natural gas. For additional discussion regarding the regulation of GHG emissions and climate change generally, see ITEM 1, Business – Regulation.

Our initiatives, targets and ambitions related to emissions and other environmental or safety-related matters, including our related public statements and disclosures, are subject to various factors, contingencies and uncertainties and may expose us to certain risks.

We have developed, and will continue to develop, targets and ambitions related to our environmental and safety initiatives, including, but not limited to, our current emissions targets. Our public disclosures and other statements related to these initiatives, targets and ambitions reflect our plans and expectations at the time such disclosures and statements are made and are not a guarantee the initiatives will be successfully developed, implemented and carried out or that the targets or ambitions will be achieved or achieved on the anticipated timelines or that, if achieved, will be sustained.

Our ability to achieve and, if achieved, sustain these targets and ambitions is subject to numerous factors and contingencies, some of which are outside of our control and include (among other commercial, operational, technological, financial, legal and regulatory factors and contingencies) evolving government regulation, the pace of changes in technology, the successful development and deployment of existing or new technologies and business solutions on a commercial scale, the availability, timing and cost of necessary equipment, goods, services and personnel, and the availability of requisite financing and federal and state incentive programs.

As both emissions sources and emissions measurements and related technologies, regulations, protocols and methodologies continue to evolve, the emissions that will be included in our emissions inventory may change. This means our current targets using calculations and forecasts of our current emissions inventory could be more challenging to meet and sustain if our emissions inventory expands due to evolving practices and/or new regulations. This means a target that we have achieved and maintained in the past could be more challenging to meet and sustain if our emissions inventory changes. Also, while there is rapid evolution taking place in the technologies we may be able to use to reduce emissions and achieve and maintain our targets, the timing, cost and anticipated success of these technologies may change.

These uncertainties, evolving practices and regulations and challenges around emissions measurement and reporting and emissions reduction technologies may result in our revising our existing targets and/or setting new targets. In addition, the pursuit and achievement of our current or future initiatives, targets and ambitions relating to the reduction of GHG emissions and other environmental or safety-related initiatives may increase our costs – for example, by requiring us to purchase emissions credits or offsets, the availability and price of which are outside of our control - and may impact or otherwise limit our ability to execute on our business strategy. Also, our continuing efforts to research, establish, accomplish and accurately report on our emissions and other environmental or safety-related initiatives, targets and ambitions may create additional operational risks and expenses and expose us to reputational, legal and other risks.

In addition, from time to time there has been particular investor and regulatory focus on environmental and social matters, including, in addition to climate change, human rights and human capital management matters. If our related initiatives, targets and ambitions do not meet our investors' or other stakeholders' evolving expectations and standards, investment in our stock may be viewed as less attractive and our reputation, relationships with investors and other business relationships may be adversely impacted.

Lastly, as noted above, the SEC, in March 2024, finalized extensive climate-related disclosure rules that would require U.S. public companies to significantly expand the climate-related disclosures in their SEC filings (although these rules have 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). To the extent the rules are implemented, we could incur increased costs related to the assessment and disclosure of climate-related information.

Tax laws and regulations, including those applicable specifically to crude oil and natural gas exploration and production companies, may change over time, and such changes could materially and adversely affect our business, cash flows, results of operations and financial condition.

From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws, including laws specifically applicable to crude oil and natural gas exploration and production companies - such as eliminating the immediate deduction for intangible drilling and development costs. No accurate prediction can be made as to whether any such legislative changes or similar or other tax law changes will be proposed or enacted. Further, no accurate prediction can be made as to what the specific provisions or impact on EOG of any such enacted legislation would be.

In addition, certain countries, including countries where EOG currently has operations or may in the future have operations, have implemented (via legislation), or may implement, a global minimum tax (GMT). While such GMT legislation has had, to date, no material impact on EOG, no accurate prediction can be made as to (i) which additional countries or jurisdictions will participate and enact GMT legislation and (ii) what the impact on EOG of any such enacted GMT legislation would be. Recent changes to the GMT rules would exempt U.S. multinationals (like EOG) from certain of its provisions after 2025, if ultimately legislated into law in the countries where EOG has current or may have future operations.

The elimination or postponement of certain U.S. federal income tax deductions currently available to crude oil and natural gas exploration and production companies, as well as any other changes to, or the imposition of new, U.S. federal, state, local or non-U.S. (i.e., foreign) taxes (including the imposition of, or increases in, production, severance or similar taxes or the enactment of a GMT or similar tax), could materially and adversely affect our business, cash flows, results of operations and financial condition.

In addition, legislation may be proposed with respect to the enactment of a tax levied on the carbon content of fuels based on the GHG emissions associated with such fuels. A carbon tax, whether imposed on producers or consumers, would generally increase the prices for crude oil, NGLs and natural gas. Such price increases may, in turn, reduce demand for crude oil, NGLs and natural gas and materially and adversely affect our cash flows, results of operations and financial condition.

We are unable to predict the timing, scope and effect of any proposed or enacted tax law changes, but any such changes (if enacted) may materially and adversely affect our business. We will continue to monitor and assess any proposed or enacted tax law changes to determine the impact on our business, cash flows, results of operations and financial condition and take appropriate actions, where necessary.

Risks Related to Our International Operations

We operate in other countries and, as a result, are subject to certain political, economic, competitive and other risks.

Our operations in jurisdictions outside the U.S. are subject to various risks inherent in foreign operations. These risks include, among other risks:

•increases in taxes and governmental royalties;

•additional and potentially unfamiliar laws and policies governing the operations of foreign-based companies and changes in such laws and policies;

•loss of revenue, loss of or damage to equipment, property and other assets and interruption of operations as a result of expropriation, nationalization, acts of terrorism, war, civil unrest and other political risks;

•unilateral or forced renegotiation, modification or nullification of existing contracts with governmental entities;

•difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations;

•competition from companies that have established strategic long-term positions or have strong governmental relationships in the foreign jurisdictions in which we operate; and

•currency restrictions and exchange rate fluctuations.

Our international operations may also be adversely affected by U.S. laws and policies affecting foreign trade and taxation, including tariffs and trade or other economic sanctions; modifications to, or withdrawal from, international trade treaties; and U.S. laws with respect to participation in boycotts that are not supported by the U.S. government. The realization of any of these factors could materially and adversely affect our business, financial condition and results of operations.

Risks Related to Cybersecurity and Other External Factors

Our business could be materially and adversely affected by security threats, including cyber threats and cyber attacks, and other disruptions.

As an oil and gas producer, we face various security threats, including (i) cyber threats to gain unauthorized access to, or control of, our sensitive information or to render our data or systems corrupted or unusable; (ii) threats to the security of our facilities and infrastructure or to the security of third-party facilities and infrastructure, such as gathering, transportation, processing, fractionation, refining, liquefaction and export facilities; and (iii) threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material and adverse effect on our business.

We rely extensively on information technology systems, including internally developed software, data hosting platforms, real-time data acquisition systems, third-party software, cloud services and other internally or externally hosted hardware and software platforms, to (i) estimate our oil and gas reserves, (ii) process and record financial and operating data, (iii) process and analyze all stages of our business operations, including exploration, drilling, completions, production, gathering and processing, transportation, pipelines and other related activities and (iv) communicate with, and make payments to, our employees and vendors, suppliers and other third parties. Further, our reliance on technology has increased due to the increased use of personal devices and remote communications. Although we have implemented and invested in, and will continue to implement and invest in, controls, procedures and protections (including internal and external personnel) that are designed to protect our systems, identify and remediate on a regular basis vulnerabilities in our systems and related infrastructure and monitor and mitigate the risk of data loss and other cyber threats, such measures cannot entirely eliminate cyber threats and the controls, procedures and protections we have implemented and invested in may prove to be ineffective.

Our systems and networks, and those of our business associates, may become the target of cyber attacks, including, without limitation, denial-of-service attacks; malicious software; data privacy breaches by employees, insiders or others with authorized access; phishing attacks; ransomware; attempts to gain unauthorized access to our data and systems; and other electronic security breaches. Security incidents can also occur as a result of non-technical issues, such as physical theft. More recently, advancements in artificial intelligence (AI) may pose serious risks for many of the traditional tools used to identify individuals, including voice recognition (whether by machine or the human ear), facial recognition or screening questions to confirm identities. In addition, generative AI systems may also be used by malicious actors to create more sophisticated cyber attacks (i.e., more realistic phishing or other attacks). The advancements in AI could also lead to an increase in the frequency of identity fraud or cyber attacks (whether successful or unsuccessful), which could cause us to incur increasing costs, including costs to deploy additional personnel, protection technologies and policies and procedures, train employees, and engage third-party experts and consultants.

If any of these security breaches were to occur, we could suffer disruptions to our normal operations, including our drilling, completion, production and corporate functions, which could materially and adversely affect us in a variety of ways, including, but not limited to, the following:

•unauthorized access to, and release of, our business data, reserves information, strategic information or other sensitive or proprietary information, which could have a material and adverse effect on our ability to compete for oil and gas resources, or reduce our competitive advantage over other companies;

•data corruption, communication interruption, or other operational disruptions during our drilling activities, which could result in our failure to reach the intended target or a drilling incident;

•data corruption or operational disruptions of our production-related infrastructure, which could result in loss of production or accidental discharges;

•unauthorized access to, and release of, personal information of our royalty owners, employees and vendors, which could expose us to allegations that we did not sufficiently protect such information;

•a cyber attack on a vendor or service provider, which could result in supply chain disruptions and could delay or halt our operations;

•a cyber attack on third-party gathering, transportation, processing, fractionation, refining, liquefaction or export facilities, which could result in reduced demand for our production or delay or prevent us from transporting and marketing our production, in either case resulting in a loss of revenues;

•a cyber attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues;

•a deliberate corruption of our financial or operating data could result in events of non-compliance which could then lead to regulatory fines or penalties;

•a cyber attack on a communications network or power grid, which could cause operational disruptions resulting in a loss of revenues; and

•a cyber attack on our automated and surveillance systems, which could cause a loss of production and potential environmental hazards.

Further, strategic targets, such as energy-related assets, may be at a greater risk of terrorist attacks or cyber attacks than other targets in the United States. Moreover, external digital technologies control nearly all of the crude oil and natural gas distribution systems in the U.S. and abroad, which are necessary to transport and market our production. A cyber attack directed at, for example, crude oil, NGLs and natural gas distribution systems could (i) damage critical distribution and storage assets or the environment; (ii) disrupt energy supplies and markets, by delaying or preventing delivery of production to markets; and (iii) make it difficult or impossible to accurately account for production and settle transactions.

Any such terrorist attack or cyber attack that affects us, our customers, suppliers, or others with whom we do business and/or energy-related assets could have a material adverse effect on our business, including disruption of our operations, damage to our reputation, a loss of counterparty trust, reimbursement or other costs, increased compliance costs, significant litigation exposure and legal liability or regulatory fines, penalties or intervention. Although we have business continuity plans in place, our operations may be adversely affected by significant and widespread disruption to our systems and the infrastructure that supports our business. While we continue to evolve and modify our business continuity plans as well as our cyber threat detection and mitigation systems, there can be no assurance that they will be effective in avoiding disruption and business impacts. Further, our insurance may not be adequate to compensate us for all resulting losses, and the cost to obtain adequate coverage may increase for us in the future and some insurance coverage may become more difficult to obtain, if available at all.

While we have experienced limited cyber incidents in the past, we have not had, to date, any business interruptions or material losses from breaches of our information technology systems and related infrastructure. However, there is no assurance that we will not suffer any such interruptions or losses in the future. Further, as technologies evolve and cyber threats become more sophisticated, we are continually expending additional resources to modify or enhance our security measures to protect against such threats and to identify and remediate on a regular basis any vulnerabilities in our information systems and related infrastructure that may be detected, and these expenditures in the future may be significant. Additionally, the continuing and evolving threat of cyber attacks has resulted in evolving legal and compliance matters, including increased regulatory focus on prevention and new disclosure requirements recently enacted by the SEC with respect to material cyber incidents and cyber risk management, strategy and governance, which could require us to expend significant additional resources to meet such requirements.

Terrorist activities and military and other actions could materially and adversely affect us.

Terrorist attacks and the threat of terrorist attacks (including cyber-related attacks), whether domestic or foreign, as well as military or other actions taken in response to these acts, could cause instability in the global financial and energy markets. The U.S. government has from time to time issued public warnings that indicate that energy-related assets, such as transportation and refining facilities, might be specific targets of terrorist organizations.

Any such actions and the threat of such actions, including any resulting political instability or societal disruption, could materially and adversely affect us in unpredictable ways, including, but not limited to, the disruption of energy supplies and markets, the reduction of overall demand for crude oil, NGLs and natural gas, increased volatility in crude oil, NGLs and natural gas prices or the possibility that the facilities and other infrastructure on which we rely could be a direct target or an indirect casualty of an act of terrorism, and, in turn, could materially and adversely affect our business, financial condition and results of operations.

ITEM 1B. Unresolved Staff Comments

Not applicable.

ITEM 1C. Cybersecurity

EOG relies on information technology systems across its business. As its reliance on data and information technology systems has increased, EOG has continued to evolve and modify its cybersecurity processes and strategy and related governance and oversight practices as well as enhance the expertise of its cybersecurity team.

Cyber Risk Management & Strategy

As part of its overall risk management system, EOG regularly assesses its processes and practices for managing and mitigating cybersecurity risks and determines whether such risks are being effectively managed and mitigated.

EOG has invested in and implemented multiple technologies, controls, and procedures designed to protect its information systems and related infrastructure; identify, assess and remediate vulnerabilities; and monitor and mitigate the risk of data loss and other cybersecurity threats and intrusions.

EOG focuses on building cybersecurity awareness with its employees and other end-users through training and security exercises and communicates EOG's expectations of employees and contractors with respect to cybersecurity matters via EOG's Codes of Business Conduct and Ethics.

EOG's dedicated, in-house cybersecurity team, which is responsible for EOG's cybersecurity strategy and planning, oversees such efforts, with assistance from external threat analysts, consultants and service providers. As part of these efforts, such team seeks to identify potential cyber vulnerabilities and opportunities for improvement and then evaluates and implements different cybersecurity technologies to address any identified vulnerabilities and opportunities.

In addition, EOG's internal audit team, in conjunction with third-party experts, plays an important role in reviewing and assessing EOG's cybersecurity technologies, controls and procedures, including conducting penetration testing and vulnerability assessments.

In the event of an incident, EOG has a designated response team and written response plan in place with predefined escalation and response procedures. EOG also has processes in place to monitor the cybersecurity risk exposure and security practices of key service providers to assess their cyber preparedness.

While such technologies, controls, and procedures cannot entirely eliminate cybersecurity threats, EOG believes the risks from cybersecurity threats (including as a result of previous cybersecurity incidents) have been effectively managed and contained, and have not materially affected, and are not reasonably likely to materially affect, EOG and its business strategy, results of operations or financial condition. See ITEM 1A, Risk Factors, for related discussion.

As technology and potential cybersecurity threats evolve, EOG intends to continue to adapt and enhance its cybersecurity controls, procedures, and protections.

Cyber Expertise & Experience

As discussed above, EOG's cybersecurity team consists of in-house cybersecurity professionals and external threat analysts, consultants and service providers. EOG's in-house professionals and external threat analysts possess various cybersecurity certifications.

EOG's cybersecurity team is led by EOG's group director, information systems and director, information systems operations, who each have over eight years of experience overseeing EOG's cybersecurity processes and strategy.

Cyber Governance & Oversight

EOG's cybersecurity team reports to EOG's Chief Information and Technology Officer, who has served as EOG's Chief Technology Officer since 2017 and as EOG's Chief Information Officer for over 25 years.

EOG's cybersecurity team leadership, Chief Information and Technology Officer and other members of senior management are responsible for the day-to-day management of cybersecurity risks and cybersecurity leadership. Such senior management team regularly reports to EOG's Audit Committee and Board of Directors (Board) regarding cybersecurity matters, including the assessments performed regarding EOG's cybersecurity technologies, controls and procedures.

As part of its risk oversight responsibility and pursuant to its charter, the Audit Committee, in consultation with the Board and the Board's other committees, oversees EOG’s policies, strategies, and initiatives for mitigating cybersecurity and information technology risks.

ITEM 2. Properties

Oil and Gas Exploration and Production - Properties and Reserves

Reserve Information. For estimates and discussions of EOG's net proved reserves of crude oil and condensate, natural gas liquids (NGLs) and natural gas, the qualifications of the preparers of EOG's reserve estimates, EOG's independent petroleum consultants and EOG's processes and controls with respect to its reserve estimates, see "Supplemental Information to Consolidated Financial Statements."

There are numerous uncertainties inherent in estimating quantities of reserves and in projecting future rates of production and the timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth in "Supplemental Information to Consolidated Financial Statements" represent only estimates. Reserve engineering is a complex, subjective process of estimating underground accumulations of crude oil and condensate, NGLs and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the amount and quality of available data and of engineering and geological interpretation and judgment. As a result, estimates by different engineers typically vary. In addition, results of drilling, testing and production or fluctuations in commodity prices subsequent to the date of an estimate may justify revision of such estimate (upward or downward). Accordingly, reserve estimates are often different from the quantities ultimately recovered. Further, the validity of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. For related discussion, see ITEM 1A, Risk Factors, and "Supplemental Information to Consolidated Financial Statements."

In general, the rate of production from crude oil and natural gas properties declines as reserves are produced. Except to the extent EOG acquires additional properties containing reserves, conducts successful exploration, exploitation and development activities resulting in additional reserves or, through engineering studies, identifies additional behind-pipe zones or secondary recovery reserves, the reserves of EOG will decline as reserves are produced. Future production is, therefore, highly dependent upon the level of success of these activities. For related discussion, see ITEM 1A, Risk Factors. EOG's estimates of reserves filed with other federal agencies are consistent with the information set forth in "Supplemental Information to Consolidated Financial Statements."

Acreage. The following table summarizes EOG's gross and net developed and undeveloped acreage at December 31, 2025 (in thousands of acres). Excluded is acreage in which EOG's interest is limited to owned royalty, overriding royalty and other similar interests.


	Developed		Undeveloped		Total
	Gross	Net	Gross	Net	Gross	Net

United States	2,175	1,778	3,847	2,888	6,022	4,666
Trinidad	102	78	611	530	713	608
Other International	—	—	1,940	1,920	1,940	1,920
Total	2,277	1,856	6,398	5,338	8,675	7,194

Most of EOG's undeveloped oil and gas leases, particularly in the United States, are subject to lease expiration if initial wells are not drilled within a specified period, generally between three to five years. Within the United States, approximately 0.1 million net acres will expire in 2026, 0.1 million net acres will expire in 2027 and 0.1 million net acres will expire in 2028 if production is not established or EOG takes no other action to extend the terms of the leases or obtain concessions. As of December 31, 2025, there were no proved undeveloped reserves (PUDs) associated with undeveloped leases on which drilling was planned after the expiration dates of such leases. In the ordinary course of business, based on its evaluations of geologic trends, prospective economics, and other factors, EOG has allowed certain lease acreage to expire and may allow additional acreage to expire in the future.

Many of EOG's oil and gas leases are large enough to accommodate more than one producing unit. Included in undeveloped acreage is non-producing acreage within such larger producing leases.

Productive Well Summary. The following table summarizes EOG's gross and net productive wells at December 31, 2025, including 4,189 wells in which it holds a royalty interest.


	Crude Oil		Natural Gas		Total
	Gross	Net	Gross	Net	Gross	Net

United States	11,791	7,870	5,286	2,456	17,077	10,326
Trinidad	2	2	46	37	48	39
Other International	—	—	4	2	4	2
Total (1)	11,793	7,872	5,336	2,495	17,129	10,367

(1)EOG operated 11,573 gross and 10,185 net producing crude oil and natural gas wells at December 31, 2025. Gross crude oil and natural gas wells include 53 wells with multiple completions.

Drilling and Acquisition Activities. During the years ended December 31, 2025, 2024 and 2023, EOG expended $13.2 billion, $5.6 billion and $6.0 billion, respectively, for exploratory and development drilling, facilities and acquisition of leases and producing properties, including asset retirement costs of $146 million, $(2) million and $257 million, respectively. The following tables set forth the results of the gross crude oil and natural gas wells completed for the years ended December 31, 2025, 2024 and 2023:


	Gross Development Wells Completed				Gross Exploratory Wells Completed
	Crude Oil	Natural Gas	Dry Hole	Total	Crude Oil	Natural Gas	Dry Hole	Total
2025
United States	542	154	3	699	5	5	2	12
Trinidad	—	3	—	3	—	1	1	2
Total	542	157	3	702	5	6	3	14
2024
United States	607	117	6	730	8	1	—	9
Trinidad	—	1	—	1	—	3	—	3
Total	607	118	6	731	8	4	—	12
2023
United States	595	152	2	749	9	7	—	16
Trinidad	—	2	—	2	—	1	—	1
Total	595	154	2	751	9	8	—	17

The following tables set forth the results of the net crude oil and natural gas wells completed for the years ended December 31, 2025, 2024 and 2023:


	Net Development Wells Completed				Net Exploratory Wells Completed
	Crude Oil	Natural Gas	Dry Hole	Total	Crude Oil	Natural Gas	Dry Hole	Total
2025
United States	495	132	3	630	4	5	2	11
Trinidad	—	2	—	2	—	1	1	2
Total	495	134	3	632	4	6	3	13
2024
United States	527	101	5	633	7	1	—	8
Trinidad	—	1	—	1	—	3	—	3
Total	527	102	5	634	7	4	—	11
2023
United States	490	135	2	627	7	6	—	13
Trinidad	—	2	—	2	—	1	—	1
Total	490	137	2	629	7	7	—	14

EOG participated in the drilling of wells that were in the process of being drilled or completed at the end of the period as set out in the table below for the years ended December 31, 2025, 2024 and 2023:


	Wells in Progress at End of Period
	2025		2024		2023
	Gross	Net	Gross	Net	Gross	Net

United States	263	222	243	213	254	212
Trinidad	4	2	2	1	3	3
Other International	6	4	—	—	—	—
Total	273	228	245	214	257	215

Included in the above table of wells in progress at the end of the period were wells which had been drilled, but were not completed (DUCs). In order to effectively manage its capital expenditures and to provide flexibility in managing its drilling rig and well completion schedules, EOG, from time to time, will have an inventory of DUCs. At December 31, 2025, there were approximately 121 MMBoe of net PUDs associated with EOG's inventory of DUCs. Under EOG's current drilling plan, all such DUCs are expected to be completed within five years from the original booking date of such reserves. The following table sets forth EOG's DUCs, for which PUDs had been booked, as of the end of each period.


	Drilled Uncompleted Wells at End of Period
	2025		2024		2023
	Gross	Net	Gross	Net	Gross	Net

United States	167	119	170	140	156	132
Trinidad	—	—	1	1	1	1
Total	167	119	171	141	157	133

EOG acquired wells as set forth in the following table (excluding the acquisition of additional interests of 23, 4 and 4 net wells in which EOG previously owned an interest for the years ended December 31, 2025, 2024 and 2023, respectively) for the years ended December 31, 2025, 2024 and 2023:


	Gross Acquired Wells			Net Acquired Wells
	Crude Oil	Natural Gas	Total	Crude Oil	Natural Gas	Total
2025
United States	462	1,206	1,668	355	601	956
Other International	—	4	4	—	2	2
Total	462	1,210	1,672	355	603	958
2024
United States	21	4	25	19	3	22
Total	21	4	25	19	3	22
2023
United States	5	—	5	5	—	5
Total	5	—	5	5	—	5

Other Property, Plant and Equipment. EOG's other property, plant and equipment primarily includes gathering, processing and transportation assets and buildings. EOG does not own drilling rigs or hydraulic fracturing equipment. All of EOG's drilling and completion activities are conducted on a contractual basis with independent drilling contractors and other third-party service contractors.

ITEM 3. Legal Proceedings

See the information set forth under the "Contingencies" caption in Note 8 of the Notes to Consolidated Financial Statements, which is incorporated by reference herein.

Item 103 of Regulation S-K promulgated under the Securities Exchange Act of 1934, as amended, requires disclosure regarding certain proceedings arising under federal, state or local environmental laws when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that EOG reasonably believes will exceed a specified threshold. Pursuant to this item, EOG uses a threshold of $1 million for purposes of determining whether disclosure of any such proceedings is required; EOG believes proceedings under this threshold are not material to EOG's business and financial condition (the choice of this threshold does not, however, imply that matters with potential monetary sanctions in excess of $1 million are necessarily material to EOG's business or financial condition). Applying this threshold, there are no environmental proceedings to disclose for the quarter and year ended December 31, 2025.

ITEM 4. Mine Safety Disclosures

None.

PART II

ITEM 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

EOG's common stock is traded on the New York Stock Exchange under the ticker symbol "EOG."

As of February 13, 2026, there were approximately 3,400 record holders and approximately 1,271,000 beneficial owners of EOG's common stock.

EOG expects to continue to pay dividends to its stockholders; however, EOG's Board may reduce the dividend or cease declaring dividends at any time, including if it determines that EOG's current or forecasted future cash flows provided by its operating activities (after deducting capital expenditures and other commitments requiring cash) are not sufficient to pay EOG's desired levels of dividends to its stockholders or to pay dividends to its stockholders at all. For additional discussion, see ITEM 1A. Risk Factors.

The following table sets forth, for the periods indicated, EOG's share repurchase activity:


Period	(a) Total Number of Shares Purchased (1)	(b) Average Price Paid per Share		(c) Total Number of Shares or Value of Shares Purchased as Part of Publicly Announced Plans or Programs (2)		(d) Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (3)

October 1, 2025 - October 31, 2025	1,335,450	$	108.28	$	143,748,309	$	3,878,171,155
November 1, 2025 - November 30, 2025	1,808,125	107.35		193,248,798		3,684,922,357
December 1, 2025 - December 31, 2025	3,164,582	106.90		337,998,278		3,346,924,079
Total	6,308,157	107.32		$	674,995,385

(1)Includes 6,289,876 shares repurchased during the quarter ended December 31, 2025, at an average price of $107.31 per share (inclusive of commissions and transaction fees), pursuant to the Share Repurchase Authorization (as defined and further discussed below); such repurchases count against the Share Repurchase Authorization. The share repurchases effected during the period October 1, 2025 through November 7, 2025 were made pursuant to a Rule 10b5-1 trading plan entered into by EOG on September 29, 2025. Also includes 18,281 total shares that were withheld by or returned to EOG during the quarter ended December 31, 2025, at an average price of $109.09 per share, (i) in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or stock-settled stock appreciation rights 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; such shares do not count against the Share Repurchase Authorization.

(2)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). As of December 31, 2025, (i) EOG had repurchased an aggregate 56,166,452 shares at a total cost of $6,653,075,921 (inclusive of commissions and transaction fees) under the Share Repurchase Authorization and (ii) an additional $3,346,924,079 of shares remained available for repurchases under the Share Repurchase Authorization.

(3)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.

Comparative Stock Performance

The following performance graph and related information shall not be deemed "soliciting material" or to be "filed" with the United States Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that EOG specifically requests that such information be treated as "soliciting material" or specifically incorporates such information by reference into such a filing.

The performance graph shown below compares the cumulative five-year total return to stockholders of EOG's common stock as compared to the cumulative five-year total returns of the Standard and Poor's 500 Index (S&P 500) and the Standard and Poor's 500 Oil & Gas Exploration & Production Index (S&P O&G E&P). The comparison was prepared based upon the following assumptions:

1.$100 was invested on December 31, 2020 in each of the following: common stock of EOG, the S&P 500 and the S&P O&G E&P.

2. Dividends are reinvested.

Comparison of Five-Year Cumulative Total Returns

EOG, S&P 500 and S&P O&G E&P

(Performance Results Through December 31, 2025)


	2020		2021		2022		2023		2024		2025
EOG	$	100.00	$	188.69	$	295.99	$	290.06	$	302.55	$	268.07
S&P 500	$	100.00	$	128.71	$	105.40	$	133.10	$	166.40	$	196.16
S&P O&G E&P	$	100.00	$	187.09	$	296.53	$	296.63	$	280.65	$	282.89

ITEM 6. Reserved

ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

Overview

EOG Resources, Inc., together with its subsidiaries (collectively, EOG), is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States of America (United States) with proved reserves in the United States and the Republic of Trinidad and Tobago (Trinidad). EOG is focused on being among the highest return and lowest cost producers, committed to strong environmental performance and playing a significant role in the long-term future of energy. EOG operates under a consistent business and operational strategy that focuses on a comprehensive approach to developing acreage through industry cycles. EOG evaluates rate of return, net present value, margins, payback period and other key metrics. This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-efficient basis, allowing EOG to maximize long-term growth in shareholder value and maintain a strong balance sheet. EOG implements its strategy primarily by emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves. Maintaining the lowest possible operating cost structure, coupled with efficient and safe operations and robust environmental stewardship practices and performance, is integral in the implementation of EOG's strategy.

EOG realized net income of $4,980 million for 2025 as compared to net income of $6,403 million for 2024. At December 31, 2025, EOG's total estimated net proved reserves were 5,514 million barrels of oil equivalent (MMBoe), an increase of 766 MMBoe from December 31, 2024. During 2025, net proved crude oil and condensate and natural gas liquids (NGLs) reserves increased by 187 million barrels (MMBbl), and net proved natural gas reserves increased by 3,470 billion cubic feet, or 579 MMBoe, in each case from December 31, 2024.

Recent Developments

Commodity Prices. Prices for crude oil and condensate, NGLs and natural gas have historically been volatile. This volatility is expected to continue due to the many uncertainties associated with the world political and economic environment, the global supply of, and demand for, crude oil, NGLs and natural gas, the availability of other energy supplies and other factors, including tariffs, trade policies and agreements and trade barriers or other restrictions imposed by the U.S. government or other governments and the related impact of such measures on commodity and financial markets.

The market prices of crude oil and condensate, NGLs and natural gas impact the amount of cash generated from EOG's operating activities, which, in turn, impact EOG's financial position and results of operations.

For the year ended December 31, 2025, the average U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were $64.78 per barrel and $3.43 per million British thermal units (MMBtu), respectively, representing a decrease of 14% and an increase of 51%, respectively, from the average NYMEX prices for the year ended December 31, 2024. Market prices for NGLs are influenced by the components extracted, including ethane, propane and butane and natural gasoline, among others, and the respective market pricing for each component.

Operating Efficiencies. EOG has undertaken (and continues to undertake) initiatives to increase its drilling, completions and operating efficiencies and improve the performance of its wells. Such initiatives include (among others): (i) EOG's downhole drilling motor program, which has resulted in increased footage drilled per day and, in turn, reduced drilling times; (ii) enhanced techniques for completing its wells, which has resulted in increased footage completed per day and pumping hours per day; (iii) drilling extended laterals, which have resulted in a decrease in cost per foot drilled; and (iv) EOG's self-sourced sand program, which has provided supply certainty and resulted in operational efficiencies in its well completion operations. In addition, EOG has entered into agreements with its service providers from time to time, when available and advantageous, to secure the costs and availability of certain drilling and completions services it utilizes as part of its operations.

EOG plans to continue with these initiatives and actions, though there can be no assurance that such efforts will be successful and sufficient to offset the impacts of any future inflationary pressures (such as from tariffs, other trade barriers or other macroeconomic factors) on EOG's operating costs and capital expenditures, cash flows and results of operations. Further, there can be no assurance that any such pressures or factors will not impact EOG's ability to conduct its future day-to-day drilling, completion and production operations. See ITEM 1A. Risk Factors, for related discussion.

Operations

Several important developments have occurred since January 1, 2025.

United States. EOG's efforts to identify plays with large reserve potential have proven to be successful. EOG continues to drill numerous wells in large acreage plays, which in the aggregate have contributed substantially to, and are expected to continue to contribute substantially to, EOG's crude oil and condensate, NGLs and natural gas production. EOG has placed an emphasis on applying its horizontal drilling and completion expertise to unconventional crude oil and natural gas plays.

In 2025, EOG continued to focus on initiatives to increase its drilling, completion and operating efficiencies and improve well performance. In addition, EOG continued to evaluate certain potential crude oil and condensate, NGLs and natural gas exploration and development prospects and to look for opportunities to add drilling inventory through leasehold acquisitions, farm-ins, exchanges or tactical or bolt-on acquisitions. On a volumetric basis, as calculated using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas, crude oil and condensate and NGLs production accounted for approximately 68% and 72% of EOG's United States production during 2025 and 2024, respectively. During 2025, EOG's drilling and completion activities occurred primarily in the Delaware Basin play, Eagle Ford play and Utica play. EOG's major producing areas in the United States are in New Mexico, Texas and Ohio. See ITEM 1, Business - Exploration and Production for further discussion regarding EOG's 2025 United States operations.

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.

On August 1, 2025, EOG completed its acquisition of Encino Acquisition Partners, LLC (Encino) for $5.7 billion, inclusive of Encino's net debt. The assets of Encino include 675,000 core net acres in the Utica play. The financial results of Encino have been included in EOG's consolidated financial statements beginning August 1, 2025. This acquisition impacted revenues and operating and other expenses as described in the Results of Operations section below. Additionally, see Note 16 to the Consolidated Financial Statements for further discussion of the acquisition.

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. Crude oil production attributable to EOG's interest was approximately 4 MBbld for the quarter ended December 31, 2025.

Trinidad. In Trinidad, EOG continues to produce natural gas which is sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary under existing supply contracts. Crude oil and condensate are sold to both Heritage Petroleum Company Limited and BP Trinidad and Tobago LLC. In January 2025, EOG executed two production sharing contracts with the Government of Trinidad and Tobago for the Lower Reverse L and North Coast Marine Area 4(a) Blocks.

Other International. In February 2025, a subsidiary of EOG signed an exploration participation agreement with Bapco Energies B.S.C. (Closed) (Bapco) to evaluate a gas exploration prospect in the Kingdom of Bahrain. In August 2025, the government of the Kingdom of Bahrain approved the related concession agreement. As part of the transaction, EOG has a working interest in several producing legacy wells. EOG has commenced drilling of exploratory wells, which are expected to be completed in 2026.

In May 2025, a subsidiary of EOG was awarded a new oil exploration concession for Unconventional Onshore Block 3 (UCO3) by Abu Dhabi's Supreme Council for Financial and Economic Affairs. EOG holds a 100 percent equity interest and operatorship and, in coordination with Abu Dhabi National Oil Company (ADNOC), has commenced drilling operations to explore and appraise unconventional oil potential in the concession area. Following a three-year appraisal period, EOG may enter into a production concession in which ADNOC has the option to participate.

EOG continues to evaluate other select crude oil and natural gas opportunities outside the United States, primarily by pursuing exploration opportunities in countries where crude oil and natural gas reserves have been identified.

Capital Structure

One of management's key strategies is to maintain a strong balance sheet with a consistently below average debt-to-total capitalization ratio as compared to those in EOG's peer group. EOG's debt-to-total capitalization ratio was 21% at December 31, 2025 and 14% at December 31, 2024. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

At December 31, 2025, EOG maintained a strong financial and liquidity position, including $3.4 billion of cash and cash equivalents on hand and $3.0 billion of availability under its senior unsecured revolving credit facility (discussed below).

The Internal Revenue Service previously announced tax relief related to 2024 severe weather events occurring in various Texas counties, including Harris County, where EOG's corporate offices are located. The tax relief permitted eligible taxpayers to postpone certain tax filings and payments. In February 2025, EOG paid approximately $700 million of such federal tax payments related to the 2024 tax year.

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.

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 discussed below.

On December 3, 2025, EOG entered into a new $3.0 billion senior unsecured Revolving Credit Agreement (New Facility) with domestic and foreign lenders, which has a scheduled maturity date of December 3, 2030. The New Facility replaced EOG's $1.9 billion senior unsecured Revolving Credit Agreement, dated as of June 7, 2023, 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.

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

During 2025, EOG funded $13.6 billion in exploration and development and other property, plant and equipment expenditures (excluding asset retirement obligations), paid $2.2 billion in dividends to common stockholders and paid $2.6 billion to repurchase shares of common stock, primarily by utilizing net cash provided by its operating activities, issuances of senior notes and cash on hand.

Total anticipated 2026 capital expenditures are estimated to range from approximately $6.3 billion to $6.7 billion, including exploration and development drilling, facilities, leasehold acquisitions, capitalized interest, dry hole costs and other property, plant and equipment and excluding property acquisitions, asset retirement costs, non-cash exchanges and transactions and exploration costs incurred as operating expenses. The majority of 2026 expenditures will be focused on United States crude oil drilling activities. EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program, bank borrowings, borrowings under its senior unsecured revolving credit facility, joint development agreements and similar agreements and equity and debt offerings.

Management believes that EOG has one of the strongest prospect inventories in EOG's history. When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer incremental exploration and/or production opportunities.

Cash Return Framework. In November 2023, EOG announced an increase in its cash return commitment - specifically, a commitment, effective beginning with fiscal year 2024, to return a minimum of 70 percent of annual net cash provided by operating activities before certain balance sheet-related changes, less total capital expenditures, to stockholders through a combination of regular dividends, special dividends and share repurchases. For discussion regarding EOG's payment of dividends and share repurchases, see ITEM 1A, Risk Factors, and ITEM 5, Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Dividend Declarations. On February 27, 2025, the Board of Directors (Board) declared a quarterly cash dividend on the common stock of $0.975 per share paid on April 30, 2025, to stockholders of record as of April 16, 2025.

On May 1, 2025, the Board declared a quarterly cash dividend on the common stock of $0.975 per share paid on July 31, 2025, to stockholders of record as of July 17, 2025.

On May 30, 2025, the Board declared a quarterly cash dividend on the common stock of $1.02 per share paid on October 31, 2025, to stockholders of record as of October 17, 2025. This represented an increase from the previous quarterly cash dividend which was $0.975 per share.

On November 6, 2025, the Board declared a quarterly cash dividend on the common stock of $1.02 per share paid on January 30, 2026, to stockholders of record as of January 16, 2026.

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.

Results of Operations

This section discusses certain year-to-year comparisons between 2025 and 2024, which should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning on page F-1. For discussion of certain year-to-year comparisons between 2024 and 2023, see "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, ITEM 7 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2024, filed on February 27, 2025, which is incorporated herein by reference.

Operating Revenues and Other

During 2025, total operating revenues decreased $1,066 million, or 4%, to $22,632 million from $23,698 million in 2024. Total revenues from sales of EOG's production of crude oil and condensate, NGLs and natural gas, increased $90 million, or 1%, to $17,668 million in 2025 from $17,578 million in 2024. Revenues from the sales of crude oil and condensate and NGLs in 2025 were 84% of total revenues from sales of crude oil and condensate, NGLs and natural gas compared to 91% in 2024. During 2025, EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $13 million compared to net gains of $204 million in 2024. Gathering, processing and marketing revenues decreased $886 million during 2025, to $4,914 million from $5,800 million in 2024. EOG recognized net losses on asset dispositions of $35 million in 2025 compared to net gains on asset dispositions of $16 million in 2024.

Volume and price statistics for the years ended December 31, 2025, 2024 and 2023 were as follows (see Note 11 for segment financial information):


Year Ended December 31	2025		2024		2023

Crude Oil and Condensate Volumes (MBbld) (1)
United States	520.5		490.6		475.2
Trinidad	1.4		0.8		0.6
Total	521.9		491.4		475.8
Average Crude Oil and Condensate Prices ($/Bbl) (2)
United States	$	65.65	$	77.42	$	79.18
Trinidad	57.59		64.43		68.58
Composite	65.63		77.40		79.17
Natural Gas Liquids Volumes (MBbld) (1)
United States	288.2		245.9		223.8
Total	288.2		245.9		223.8
Average Natural Gas Liquids Prices ($/Bbl) (2)
United States	$	22.58	$	23.40	$	23.07
Composite	22.58		23.40		23.07
Natural Gas Volumes (MMcfd) (1)
United States	2,299		1,728		1,551
Trinidad	230		220		160
Other International (3)	4		—		—
Total	2,533		1,948		1,711
Average Natural Gas Prices ($/Mcf) (2)
United States	$	2.94	$	1.99	$	2.70
Trinidad	3.78		3.65		3.65
Other International (3)	3.28		—		—
Composite	3.02		2.17		2.79
Crude Oil Equivalent Volumes (MBoed) (4)
United States	1,191.8		1,024.5		957.5
Trinidad	39.8		37.6		27.3
Other International (3)	0.6		—		—
Total	1,232.2		1,062.1		984.8

Total MMBoe (4)	449.8		388.7		359.4

(1) Thousand barrels per day or million cubic feet per day, as applicable.

(2)Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity and other derivative instruments (see Note 12 to Consolidated Financial Statements).

(3)Production volumes from Bahrain operations; realized price represents contract price less Bapco's processing and distribution costs.

(4)Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.

Crude oil and condensate revenues in 2025 decreased $1,420 million, or 10%, to $12,501 million from $13,921 million in 2024, primarily due to a lower composite average crude oil and condensate price ($2,239 million), partially offset by an increase in production ($819 million). EOG's composite crude oil and condensate price for 2025 decreased 15% to $65.63 per barrel compared to $77.40 per barrel in 2024. Crude oil and condensate production in 2025 increased 6% to 522 MBbld as compared to 491 MBbld in 2024. The increased production was primarily in the Utica and the Permian Basin.

NGLs revenues in 2025 increased $270 million, or 13%, to $2,376 million from $2,106 million in 2024 primarily due to an increase in production ($356 million), partially offset by a lower composite average NGLs price ($86 million). EOG's composite average NGLs price decreased 4% to $22.58 per barrel in 2025 compared to $23.40 per barrel in 2024. NGLs production in 2025 increased 17% to 288 MBbld as compared to 246 MBbld in 2024. The increased production was primarily in the Utica and the Permian Basin.

Natural gas revenues in 2025 increased $1,240 million, or 80%, to $2,791 million from $1,551 million in 2024 primarily due to a higher composite natural gas price ($783 million) and an increase in natural gas deliveries ($457 million). EOG's composite average natural gas price increased 39% to $3.02 per Mcf in 2025 compared to $2.17 per Mcf in 2024. Natural gas deliveries in 2025 increased 30% to 2,533 MMcfd as compared to 1,948 MMcfd in 2024. The increase in production was primarily due to increased production of associated natural gas from the Permian Basin and higher natural gas deliveries in the Utica and Dorado.

During 2025, EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $13 million, which included net cash paid for settlements of NGLs and natural gas financial commodity derivative contracts of $56 million and losses of $79 million related to the Brent crude oil (Brent) linked gas sales contract. During 2024, EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $204 million, which included net cash received from settlements of natural gas financial commodity derivative contracts of $214 million and gains of $110 million related to the Brent linked gas sales contract.

Gathering, processing and marketing revenues are revenues generated from sales of third-party crude oil, NGLs and natural gas, as well as fees associated with gathering third-party natural gas and revenues from sales of EOG-owned sand. Purchases and sales of third-party crude oil and natural gas may be utilized in order to balance firm capacity at third-party facilities with production in certain areas and to utilize excess capacity at EOG-owned facilities. Marketing costs represent the costs to purchase third-party crude oil, natural gas and sand and the associated transportation costs, as well as costs associated with EOG-owned sand sold to third parties.

Gathering, processing and marketing revenues less marketing costs in 2025 increased $36 million compared to 2024, primarily due to higher margins on natural gas marketing activities and sand sales, partially offset by lower margins on crude oil marketing activities.

Operating and Other Expenses

During 2025, operating expenses of $16,247 million were $631 million higher than the $15,616 million incurred during 2024. The following table presents the costs per barrel of oil equivalent (Boe) for the years ended December 31, 2025 and 2024:


	2025		2024

Lease and Well	$	3.72	$	4.04
Gathering, Processing and Transportation Costs (GP&T)	4.74		4.43
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties	9.34		10.04
Other Property, Plant and Equipment	0.58		0.53
General and Administrative (G&A)	1.82		1.72
Interest Expense, Net	0.52		0.36
Total (1)	$	20.72	$	21.12

(1)Total excludes exploration costs, dry hole costs, impairments, marketing costs and taxes other than income.

The primary factors impacting the cost components of per-unit rates of lease and well, GP&T, DD&A, G&A and interest expense, net for 2025 compared to 2024 are set forth below. See "Operating Revenues and Other" above for a discussion of volumes.

Lease and well expenses include expenses for EOG-operated properties, as well as expenses billed to EOG from other operators where EOG is not the operator of a property. Lease and well expenses can be divided into the following categories: costs to operate and maintain crude oil and natural gas wells, the cost of workovers and lease and well administrative expenses. Operating and maintenance costs include, among other things, pumping services, produced water disposal, equipment repair and maintenance, compression expense, lease upkeep and fuel and power. Workovers are operations to restore or maintain production from existing wells.

Each of these categories of costs individually fluctuates from time to time as EOG attempts to maintain and increase production while maintaining efficient, safe and environmentally responsible operations. EOG continues to increase its operating activities by drilling new wells in existing and new areas. Operating and maintenance costs within these existing and new areas, as well as the costs of services charged to EOG by vendors, fluctuate over time.

Lease and well expenses of $1,675 million in 2025 increased $103 million from $1,572 million in 2024 primarily due to increased operating and maintenance costs ($89 million) in the United States and increased lease and well administrative expenses ($42 million), partially offset by decreased workovers expenditures ($38 million) in the United States.

GP&T costs represent costs to process and deliver hydrocarbon products from the lease to a downstream point of sale. GP&T costs include operating and maintenance expenses from EOG-owned assets, fees paid to third-party operators and administrative expenses associated with operating EOG's GP&T assets. EOG pays third parties to process the majority of its natural gas production to extract NGLs.

GP&T costs increased $412 million to $2,134 million in 2025 compared to $1,722 million in 2024 primarily due to increased production in the Utica ($375 million) and the Permian Basin ($93 million), partially offset by decreased costs in the Eagle Ford play ($45 million) and the Powder River Basin ($14 million).

DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method. EOG's DD&A rate and expense are the composite of numerous individual DD&A group calculations. There are several factors that can impact EOG's composite DD&A rate and expense, such as field production profiles, drilling or acquisition of new wells, disposition of existing wells and reserve revisions (upward or downward) primarily related to well performance, economic factors and impairments. Changes to these factors may cause EOG's composite DD&A rate and expense to fluctuate from period to period. DD&A of the cost of other property, plant and equipment is generally calculated using the straight-line depreciation method over the useful lives of the assets.

DD&A expenses in 2025 increased $353 million to $4,461 million from $4,108 million in 2024. DD&A expenses associated with oil and gas properties in 2025 were $298 million higher than in 2024. The increase primarily reflects increased production in the United States ($596 million) and Trinidad ($7 million), and increased unit rates in Trinidad ($8 million). This was partially offset by decreased unit rates in the United States ($197 million) and an adjustment to DD&A recorded in 2024 ($117 million) related to natural gas production used by EOG's domestic gathering systems. DD&A expenses associated with other property, plant and equipment in 2025 were $55 million higher than in 2024 primarily due to an increase in expense related to GP&T assets and equipment.

G&A expenses of $820 million in 2025 increased $151 million from $669 million in 2024 primarily due to increased professional services and other costs, including Encino acquisition-related costs ($100 million), employee-related costs ($47 million) and information systems costs ($10 million).

Interest expense, net of $235 million in 2025 increased $97 million from $138 million in 2024 primarily due to the issuance of the July Notes and the November Notes ($95 million), the issuance in November 2024 of the $1,000 million aggregate principal amount of 5.650% Senior Notes due 2054 ($50 million) and financing commitment costs related to the Encino acquisition ($6.5 million), partially offset by increased capitalized interest primarily related to the unproved leasehold acquired through the Encino acquisition ($40 million) and the maturity in April 2025 of the $500 million aggregate principal amount of 3.15% Senior Notes due 2025 ($12 million).

Exploration costs of $236 million in 2025 increased $62 million from $174 million in 2024 primarily due to increased geological and geophysical expenditures in Trinidad ($27 million), the United Arab Emirates ($23 million) and the United States ($7 million) as well as increased administrative expenses ($11 million), partially offset by decreased delay rentals ($8 million).

Impairments include: amortization of individually insignificant unproved oil and gas property costs as well as impairments of proved oil and gas properties; other property, plant and equipment; individually significant unproved oil and gas property costs; and other assets. 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. When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected undiscounted future cash flows at a DD&A 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 Financial Accounting Standards Board's (FASB) Accounting Standards Codification (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.

The following table represents impairments for the years ended December 31, 2025 and 2024 (in millions):


	2025		2024

Proved properties	$	709	$	295
Unproved properties	61		63
Other assets	72		31
Firm commitment contracts	1		2
Total	$	843	$	391

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.

Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes. Severance/production taxes are generally determined based on revenues from sales of crude oil and condensate, NGLs and natural gas, and ad valorem/property taxes are generally determined based on the valuation of the underlying assets.

Taxes other than income in 2025 decreased $15 million to $1,234 million (7.0% of revenues from sales of crude oil and condensate, NGLs and natural gas) from $1,249 million (7.1% of revenues from sales of crude oil and condensate, NGLs and natural gas) in 2024. The decrease in taxes other than income was primarily due to decreased severance/production taxes ($60 million), partially offset by decreased state severance tax refunds ($30 million) and increased ad valorem/property taxes ($10 million), all in the United States.

Other income, net, was $212 million in 2025 compared to other income, net, of $274 million in 2024. The decrease of $62 million in 2025 was primarily due to a decrease in interest income.

Income taxes of $1,382 million in 2025 decreased from income taxes of $1,815 million in 2024 primarily due to decreased pretax income. The net effective tax rate for 2025 was unchanged from the prior year rate of 22%.

Capital Resources and Liquidity

Liquidity Overview. At December 31, 2025, EOG maintained a strong financial and liquidity position, including $3.4 billion of cash and cash equivalents on hand and $3.0 billion of availability under the New Facility (which remains undrawn).

The primary sources of cash for EOG during the three-year period ended December 31, 2025, were funds generated from operations and net proceeds from the issuance of long-term debt. The primary uses of cash were exploration and development expenditures; funds used in operations; dividend payments to stockholders; share repurchases and other purchases of treasury stock; the acquisition of Encino; repayment of long-term debt; and other property, plant, and equipment expenditures.

See Notes 2 and 13 to the Consolidated Financial Statements for further discussion on our debt obligations, including the fair value of our senior notes.

Cash Flow. Net cash provided by operating activities of $10,044 million in 2025 decreased $2,099 million from $12,143 million in 2024 primarily due to an increase in net cash paid for income taxes and tax credit purchases ($1,090 million), an increase in cash operating expenses ($696 million), net cash paid for settlements of financial commodity derivative contracts of $56 million compared to net cash received of $214 million in 2024, an increase in net cash used in working capital and other assets and liabilities ($178 million), partially offset by an increase in revenues from sales of crude oil and condensate, NGLs and natural gas ($90 million).

Net cash used in investing activities of $10,936 million in 2025 increased by $4,969 million from $5,967 million in 2024 primarily due to the acquisition of Encino ($4,451 million), an increase in additions to oil and gas properties ($762 million) and a decrease in cash provided by working capital associated with investing activities ($297 million), partially offset by a decrease in additions to other property, plant and equipment ($540 million).

Net cash used in financing activities of $2,804 million in 2025 included share repurchases and other purchases of treasury stock ($2,564 million), repayments of long-term debt ($2,516 million) and dividend payments to stockholders ($2,161 million). Cash provided by financing activities in 2025 included long-term debt borrowings ($4,471 million). Net cash used in financing activities of $4,361 million in 2024 included share repurchases and other purchases of treasury stock ($3,246 million) and cash dividend payments ($2,087 million). Cash provided by financing activities in 2024 included long-term debt borrowings ($985 million).

Total Expenditures

The table below sets out the components of total expenditures for the years ended December 31, 2025, 2024 and 2023 (in millions):


	2025		2024		2023
Expenditure Category
Capital
Exploration and Development Drilling (1)	$	4,885	$	4,534	$	4,803
Facilities	622		606		520
Leasehold Acquisitions (2)	197		230		207
Property Acquisitions (3)	7,003		33		16
Capitalized Interest	86		45		33
Subtotal	12,793		5,448		5,579
Exploration Costs	236		174		181
Dry Hole Costs	49		14		1
Exploration and Development Expenditures	13,078		5,636		5,761
Asset Retirement Costs (4)	146		(2)		257
Total Exploration and Development Expenditures	13,224		5,634		6,018
Other Property, Plant and Equipment (5)	479		1,019		800
Total Expenditures	$	13,703	$	6,653	$	6,818

(1)Exploration and development drilling included $90 million related to non-cash development drilling in 2023.

(2)Leasehold acquisitions included $24 million, $85 million and $99 million related to non-cash property exchanges in 2025, 2024 and 2023, respectively.

(3)Property acquisitions for the year ended December 31, 2025, included $6,703 million related to the Encino acquisition. Property acquisitions included $24 million and $6 million related to non-cash property exchanges in 2024 and 2023, respectively.

(4)Asset retirement costs for the year ended December 31, 2025, included $52 million related to the Encino acquisition. Asset Retirement Costs for 2024 included a downward revision to asset retirement obligations of $83 million.

(5)Other property, plant and equipment included $137 million related to the acquisition of a gathering and processing system in South Texas and $134 million related to the acquisition of a gathering and processing system in the Powder River Basin in 2024 and 2023, respectively.

Exploration and development expenditures of $13,078 million for 2025 were $7,442 million higher than the prior year primarily due to increased property acquisitions (including Encino) ($6,970 million), increased development drilling expenditures ($405 million), increased exploration expenses ($62 million), increased capitalized interest ($41 million), increased dry hole costs ($35 million) and increased facility expenditures ($16 million), partially offset by decreased exploration drilling expenditures ($54 million) and decreased leasehold acquisitions ($33 million). The 2025 exploration and development expenditures of $13,078 million included $7,003 million in property acquisitions, $5,365 million in development drilling and facilities, $624 million in exploration and $86 million in capitalized interest. The 2024 exploration and development expenditures of $5,636 million included $4,944 million in development drilling and facilities, $614 million in exploration, $45 million in capitalized interest and $33 million in property acquisitions. The 2023 exploration and development expenditures of $5,761 million included $5,101 million in development drilling and facilities, $611 million in exploration, $33 million in capitalized interest and $16 million in property acquisitions.

The level of exploration and development expenditures, including acquisitions, will vary in future periods depending on energy market conditions and other economic factors. EOG believes it has significant flexibility and availability with respect to financing alternatives and the ability to adjust its exploration and development expenditure budget as circumstances warrant. While EOG has certain continuing commitments associated with expenditure plans related to its operations, such commitments are not expected to be material when considered in relation to the total financial capacity of EOG. Further, EOG believes that its sources of liquidity are adequate for other near-term and long-term funding requirements, including its cash return commitment, debt service obligations, repayments of debt maturities and other commitment and contingencies. However, the adequacy of liquidity sources could be impacted by various factors, including general economic and market conditions, volatility in commodity prices or financial and capital markets and regulatory and other factors discussed in this report under ITEM 1A, Risk Factors.

Financial Commodity and Other Derivative Transactions

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 February 18, 2026 (inclusive of the contracts assumed, via novation, from Encino). Natural gas volumes are presented in MMBtu per day (MMBtud) and prices are presented in dollars per MMBtu ($/MMBtu). NGL volumes are presented in MBbld and prices are presented in $/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 - February 2026 (closed)	NYMEX Henry Hub	460	3.78
March - 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)

0.00

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


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 - February 2026 (closed)	NYMEX Henry Hub	80	4.28		3.72
March - 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)

10.46

January 2026 (closed)

Mont Belvieu Ethane (non-Tet)

10.94

February - December 2026

Mont Belvieu Ethane (non-Tet)

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)

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)

30.82

January 2026 (closed)

Mont Belvieu Propane (Tet)

30.24

February - December 2026

Mont Belvieu Propane (Tet)

30.24

In connection with its financial commodity derivative contracts, EOG had no collateral posted and no collateral held at February 18, 2026. The amount of posted collateral will increase or decrease based on fluctuations in forward NYMEX Henry Hub prices.

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.

Financing

EOG's debt-to-total capitalization ratio was 21% at December 31, 2025, compared to 14% at December 31, 2024. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

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 inputs regarding interest rates available to EOG at year-end. EOG's debt is at fixed interest rates. While changes in interest rates affect the fair value of EOG's senior notes, such changes do not expose EOG to material fluctuations in earnings or cash flow.

During 2025, EOG funded its capital program and operations by utilizing cash provided by operating activities, proceeds from the issuances of senior notes and cash on hand. While EOG maintains the New Facility to back its commercial paper program (which replaced its prior $1.9 billion revolving credit facility), there were no borrowings outstanding at any time during 2025 under either facility and the amount outstanding at year-end was zero. EOG considers the availability of the New Facility, as described in Note 2 to Consolidated Financial Statements, to be sufficient to meet its ongoing operating needs.

Outlook

Pricing. Crude oil, NGLs and natural gas prices have been volatile, and this volatility is expected to continue. As a result of the many uncertainties associated with the world economic and political environment, worldwide supplies of, and demand for, crude oil and condensate, NGLs and natural gas, the availability of other energy supplies, the relative competitive relationships of the various energy sources in the view of consumers and other factors, EOG is unable to predict what changes may occur in crude oil and condensate, NGLs, natural gas, ammonia and methanol prices in the future. The market price of crude oil and condensate, NGLs and natural gas in 2026 will impact the amount of cash generated from EOG's operating activities, which will in turn impact EOG's financial position. As of February 18, 2026, the average 2026 NYMEX crude oil and natural gas prices were $63.23 per barrel and $3.84 per MMBtu, respectively, representing a decrease of 2% for crude oil and an increase of 12% for natural gas from the average NYMEX prices in 2025. See ITEM 1A, Risk Factors for additional discussion of the impact of commodity prices (including fluctuations in commodity prices) on our financial condition, cash flows and results of operations.

Based on EOG's tax position, EOG's price sensitivity in 2026 for each $1.00 per barrel increase or decrease in crude oil and condensate price, combined with the estimated change in NGLs price, is approximately $174 million for net income and $223 million for pretax cash flows from operating activities. Including the impact of EOG's natural gas financial derivative contracts and based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2026 for which prices have not been determined under long-term marketing contracts, EOG's price sensitivity for each $0.10 per Mcf increase or decrease in natural gas price is approximately $64 million for net income and $83 million for pretax cash flows from operating activities. For information regarding EOG's crude oil, NGLs and natural gas financial commodity derivative contracts through February 18, 2026, see "Financial Commodity and Other Derivative Transactions" above.

Capital. EOG plans to continue to focus a substantial portion of its exploration and development expenditures in its major producing areas in the United States. In particular, EOG will be focused on United States drilling activity in the Delaware Basin play, Eagle Ford play, Dorado gas play and Utica play where it generates its highest rates-of-return. To further enhance the economics of these plays, EOG expects to continue to improve well performance and to focus on improving operating efficiencies. In addition, EOG expects to spend a portion of its anticipated 2026 capital expenditures on leasing acreage, evaluating new prospects, gathering and processing infrastructure, transportation infrastructure and environmental projects.

The total anticipated 2026 capital expenditures of approximately $6.3 billion to $6.7 billion, including exploration and development drilling, facilities, leasehold acquisitions, capitalized interest, dry hole costs and other property, plant and equipment and excluding property acquisitions, asset retirement costs, non-cash exchanges and transactions and exploration costs incurred as operating expenses, is structured to maintain EOG's strategy of capital discipline by funding its exploration, development and exploitation activities primarily from available internally generated cash flows and cash on hand. EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program, bank borrowings, borrowings under its $3.0 billion senior unsecured revolving credit facility and equity and debt offerings.

Operations. In 2026, crude oil and total crude oil equivalent production are expected to increase from 2025 levels. In addition, in 2026 EOG expects to (i) continue to undertake initiatives to increase its drilling, completion and operating efficiencies and improve the performance of its wells and (ii) when available and advantageous, enter into agreements with its service providers to secure the costs and availability of certain drilling and completions services it utilizes as part of its operations.

Cash Requirements. Certain of EOG's capital expenditures and operating costs are subject to contracts with minimum commitments, including those that meet the definition of a lease under ASC "Leases (Topic 842)". In 2026, EOG anticipates the following cash requirements under these commitments (in millions):


Finance Leases (1)	$	30
Operating Leases (1)	515
Leases Effective, Not Commenced (1)	30
Transportation and Storage Service Commitments (2) (3)	1,031
Purchase and Service Obligations (3)	640
Total Cash Requirements	$	2,246

(1) For more information on contracts that meet the definition of a lease under ASC "Leases (Topic 842)," see Note 17 to Consolidated Financial Statements.

(2) Amounts exclude transportation and storage service commitments that meet the definition of a lease. Amounts shown are 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. Management does not believe that any future changes in these rates before the expiration dates of these commitments will have a material adverse effect on the financial condition or results of operations of EOG.

(3) For years 2026 and beyond, $65 million of capital commitments have been made. For more information on transportation and storage service commitments and purchase and service obligations, see Note 8 to Consolidated Financial Statements.

In 2026, EOG has no senior notes maturing and EOG expects to pay interest of $393 million on senior notes. For more information on EOG's current and long-term debt, see Note 2 to Consolidated Financial Statements.

Cash requirements to settle the liability for EOG's pension and postretirement benefit obligations and the liability for dismantlement, abandonment and asset retirement obligations (see Notes 7 and 15, respectively, to Consolidated Financial Statements) are excluded because they are subject to estimates and the timing of settlement is unknown.

EOG expects to fund its exploration, development and exploitation activities, its cash return commitment, its debt service obligations and other cash requirements, both in 2026 and in future years, primarily from internally generated cash flows and cash on hand. As discussed above, EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program, bank borrowings, borrowings under the New Facility and equity and debt offerings.

Summary of Critical Accounting Policies and Estimates

EOG prepares its financial statements and the accompanying notes in conformity with accounting principles generally accepted in the United States, which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. EOG identifies certain accounting policies and estimates as critical based on, among other things, their impact on EOG's financial condition, results of operations or liquidity, and the degree of difficulty, subjectivity and complexity in their application. Critical accounting policies and estimates cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection and disclosure of each of the critical accounting policies and estimates. Following is a discussion of EOG's most critical accounting policies and estimates:

Proved Oil and Gas Reserves

EOG's engineers estimate proved oil and gas reserves in accordance with United States Securities and Exchange Commission (SEC) regulations, which directly impact financial accounting estimates, including depreciation, depletion and amortization and impairments of proved properties and related assets. Proved reserves represent estimated quantities of crude oil and condensate, NGLs and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be economically producible in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made.

The process of estimating quantities of proved oil and 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. Proved reserves are estimated using a trailing 12-month average price, in accordance with SEC rules. Crude oil, NGLs and natural gas prices have exhibited significant volatility in the past, and EOG expects that volatility to continue in the future. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. For related discussion, see ITEM 1A, Risk Factors, and "Supplemental Information to Consolidated Financial Statements."

Depreciation, Depletion and Amortization for Oil and Gas Properties

The quantities of estimated proved oil and gas reserves are a significant component of EOG's calculation of depreciation, depletion and amortization expense, and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves are revised upward or downward, earnings will increase or decrease, respectively.

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.

Impairments

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.

When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected undiscounted future cash flows at a DD&A 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.

Crude oil, NGLs and natural gas prices have exhibited significant volatility in the past, and EOG expects that volatility to continue in the future. During the five years ended December 31, 2025, WTI crude oil spot prices have fluctuated from approximately $47.47 per barrel to $123.64 per barrel, and Henry Hub natural gas spot prices have ranged from approximately $1.21 per MMBtu to $23.86 per MMBtu. Market prices for NGLs are influenced by the components extracted, including ethane, propane, butane and natural gasoline, among others, and the respective market pricing for each component.

EOG uses the five-year NYMEX futures strip for WTI crude oil and Henry Hub natural gas and the five-year Oil Price Information Services futures strip for NGLs components (in each case as of the applicable balance sheet date) as a basis to estimate future crude oil, NGLs and natural gas prices. EOG's proved reserves estimates, including the timing of future production, are also subject to significant assumptions and judgment, and are frequently revised (upwards and downwards) as more information becomes available. In the future, if any combination of crude oil prices, NGLs prices, natural gas prices or estimated proved reserves diverge negatively from EOG's current estimates, impairment charges may be necessary.

These estimates, which factor into EOG's unproved and proved property impairment calculations, involve the use of various assumptions and judgment. Differing assumptions could impact the timing and amount of an impairment in any given period. Any impairment will decrease earnings in the period in which it is recognized. See Notes 13 and 14 to Consolidated Financial Statements for further discussion of impairments of oil and gas properties and other assets.

Business Combinations

EOG accounts for business combinations under the Business Combinations Topic of the ASC, which requires identifiable assets acquired and liabilities assumed to be recognized at their acquisition date fair values. In estimating the fair values of assets acquired and liabilities assumed, various assumptions are applied.

The most significant assumptions relate to the estimated fair values of proved and unproved crude oil and natural gas properties for which EOG utilized the Income Approach described in ASC 820. The assumptions made in performing the valuation under the Income Approach include future crude oil, NGLs and natural gas prices, future operating and development costs, anticipated production from reserves, a weighted average cost of capital rate and risk adjustment factors for proved undeveloped, probable and possible reserves.

The assumptions and inputs used in determining fair value estimates involve significant management judgment and are based on industry, market and economic conditions at the time of the acquisition. While these estimates are based on assumptions considered reasonable, they are inherently uncertain and actual results may differ.

Information Regarding Forward-Looking Statements

This Annual Report on Form 10-K includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, goals, returns and rates of return, budgets, reserves, levels of production, capital expenditures, operating costs and asset sales, statements regarding future commodity prices, statements regarding the plans and objectives of EOG's management for future operations and statements and projections regarding the strategic rationale for, and anticipated benefits of, EOG's acquisition of Encino Acquisition Partners, LLC (Encino) are forward‐looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "aims," "ambition," "initiative," "goal," "may," "will," "focused on," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward‐looking statements. In particular, statements, express or implied, concerning (i) EOG's future financial or operating results and returns, (ii) EOG's ability to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control drilling, completion and operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, other environmental matters or safety matters, pay and/or increase regular and/or special dividends or repurchase shares or (iii) the successful integration of Encino's assets and operations or the strategic rationale for, or anticipated benefits of, EOG's acquisition of Encino, in each case are forward‐looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that such assumptions are accurate or will prove to have been correct or that any of such expectations will be achieved (in full or at all) or will be achieved on the expected or anticipated timelines. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:

•the timing, magnitude and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids (NGLs), natural gas and related commodities;

•the extent to which EOG is successful in its efforts to acquire or discover additional reserves;

•the extent to which EOG is successful in its efforts to (i) economically develop its acreage in, (ii) produce reserves and achieve anticipated production levels and rates of return from, (iii) decrease or otherwise control its drilling, completion and operating costs and capital expenditures related to, and (iv) maximize reserve recoveries from, its existing and future crude oil and natural gas exploration and development projects and associated potential and existing drilling locations;

•the success of EOG's cost-mitigation initiatives and actions in offsetting the impact of any inflationary or other pressures on EOG's operating costs and capital expenditures;

•the extent to which EOG is successful in its efforts to market its production of crude oil and condensate, NGLs and natural gas;

•security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, physical breaches of our facilities and other infrastructure or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business, and enhanced regulatory focus on the prevention of, and disclosure requirements relating to, cyber incidents;

•the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation, refining, liquefaction and export facilities and equipment;

•the availability, cost, terms and timing of issuance or execution of mineral licenses, concessions and leases and governmental and other permits and rights-of-way, and EOG's ability to retain mineral licenses, concessions and leases;

•the impact of, and changes in, government policies, laws and regulations, including climate change-related regulations, policies and initiatives (for example, with respect to air emissions); tax laws and regulations (including, but not limited to, carbon tax or other emissions-related legislation); environmental, health and safety laws and regulations relating to disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations affecting the leasing of acreage and permitting for oil and gas drilling and the calculation of royalty payments in respect of oil and gas production; laws and regulations imposing additional permitting and disclosure requirements, additional operating restrictions and conditions or restrictions on drilling and completion operations and on the transportation of crude oil, NGLs and natural gas; laws and regulations with respect to financial commodity and other derivative instruments and hedging activities; laws and regulations with respect to the import and export of crude oil, natural gas and related commodities; and trade policies, tariffs, trade agreements and other trade restrictions;

•the impact of climate change-related legislation, policies and initiatives; climate change-related political, social and shareholder activism; and physical, transition and reputational risks and other potential developments related to climate change;

•the extent to which EOG is able to successfully and economically develop, implement and carry out its emissions and other environmental or safety-related initiatives and achieve its related targets, goals, ambitions and initiatives;

•EOG's failure to realize, in full or at all, the anticipated benefits of its acquisition of Encino and/or business disruptions resulting from the acquisition (e.g., relating to the integration of Encino's assets and operations into EOG's operations) that could harm EOG's business operations (including current plans and operations and the diversion of management's attention from EOG's ongoing business operations);

•EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, identify and resolve existing and potential issues with respect to such properties and accurately estimate reserves, production, drilling, completion and operating costs and capital expenditures with respect to such properties;

•the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully, economically and in compliance with applicable laws and regulations;

•competition in the oil and gas exploration and production industry for the acquisition of licenses, concessions, leases and properties;

•the availability and cost of, EOG's ability to retain, and competition in the oil and gas exploration and production industry for, employees, labor and other personnel, facilities, equipment, materials (such as water, sand, fuel and tubulars) and services;

•the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;

•weather and natural disasters, including its impact on crude oil and natural gas demand, and related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, liquefaction, compression, storage, transportation, and export facilities;

•the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;

•EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;

•the extent to which EOG is successful in its completion of planned asset dispositions;

•the extent and effect of any hedging activities engaged in by EOG;

•the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;

•geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, political instability and armed conflicts), including in the areas in which EOG operates;

•the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage; and

•the other factors described under ITEM 1A, Risk Factors of this Annual Report on Form 10-K and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk

The information required by this Item is incorporated by reference from ITEM 7 of this report, specifically the information set forth under the captions "Recent Developments," "Financial Commodity and Other Derivative Transactions," "Financing" and "Outlook" in "Management's Discussion and Analysis of Financial Condition and Results of Operations."

ITEM 8. Financial Statements and Supplementary Data

The information required by this Item is included in this report as set forth in the "Index to Financial Statements" on page F-1 and is incorporated by reference herein.

ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

ITEM 9A. Controls and Procedures

Disclosure Controls and Procedures. EOG's management, with the participation of EOG's principal executive officer and principal financial officer, evaluated the effectiveness of EOG's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (Exchange Act)) as of December 31, 2025. EOG's disclosure controls and procedures are designed to provide reasonable assurance that information that is required to be disclosed in the reports EOG files or submits under the Exchange Act is accumulated and communicated to EOG's management, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the United States Securities and Exchange Commission. Based on that evaluation, EOG's principal executive officer and principal financial officer have concluded that EOG's disclosure controls and procedures were effective as of December 31, 2025.

Management's Annual Report on Internal Control over Financial Reporting. EOG's management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act). Even an effective system of internal control over financial reporting, 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. See "Management's Responsibility for Financial Reporting" appearing on page F-2 of this report, which is incorporated herein by reference. The report of EOG's independent registered public accounting firm relating to the consolidated financial statements and effectiveness of internal control over financial reporting is set forth beginning on page F-3 of this report. There were no changes in EOG's internal control over financial reporting that occurred during the quarter ended December 31, 2025, that have materially affected, or are reasonably likely to materially affect, EOG's internal control over financial reporting.

ITEM 9B. Other Information

Trading Plans/Arrangements. During the quarter ended December 31, 2025, no Section 16 officer of EOG, and no director of EOG, adopted or terminated any Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (in each case, as defined in Item 408(a) of Regulation S-K).

Retention Stock Award for Named Executive Officer. On February 20, 2026, the Compensation and Human Resources Committee of the Board of Directors of EOG approved an award of restricted stock to Jeffrey R. Leitzell, EOG's Executive Vice President and Chief Operating Officer. This one-time award of 32,499 shares of restricted stock, which is intended to support the long-term retention of Mr. Leitzell due to his critical role within the organization, was made (i) under the terms of the EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan and (ii) subject to a five-year "cliff" vesting period and EOG's standard termination provisions for restricted stock grants. The form of award agreement that will govern Mr. Leitzell's grant will be filed as an exhibit to EOG’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2026.

ITEM 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspection

None.

PART III

ITEM 10. Directors, Executive Officers and Corporate Governance

Insider Trading Policies. EOG has insider trading policies and procedures governing the purchase, sale and other disposition of EOG securities by EOG’s directors, officers and employees, and by EOG itself (e.g., EOG's periodic repurchases of its common stock). EOG believes such policies and procedures are reasonably designed to promote compliance with insider trading laws, rules and regulations and the listing standards of the New York Stock Exchange (NYSE) (on which EOG's common stock is listed).

EOG's policies and procedures, which are set forth in the EOG Resources, Inc. Code of Business Conduct and Ethics for Directors, Officers and Employees (Code of Conduct) and EOG's Insider Trading Policy, are attached as Exhibit 19 to this Annual Report on Form 10-K and incorporated herein by reference.

_______________

The information required by this Item and not otherwise included in this report is incorporated by reference from (i) EOG's Definitive Proxy Statement with respect to its 2026 Annual Meeting of Stockholders to be filed not later than April 30, 2026 and (ii) ITEM 1 of this report, specifically the information therein set forth under the caption "Information About Our Executive Officers."

Pursuant to Rule 303A.10 of the NYSE and Item 406 of Regulation S-K promulgated under the Securities Exchange Act of 1934, as amended, EOG has adopted the Code of Conduct, which applies to all EOG directors, officers and employees, including EOG's principal executive officer, principal financial officer and principal accounting officer. EOG has also adopted a Code of Ethics for Senior Financial Officers (Code of Ethics) that, along with EOG's Code of Conduct, applies to EOG's principal executive officer, principal financial officer, principal accounting officer and controllers.

You can access the Code of Conduct and Code of Ethics on the "Governance" page under "Investors" on EOG's website at www.eogresources.com, and any EOG stockholder who so requests may obtain a printed copy of the Code of Conduct and Code of Ethics by submitting a written request to EOG's Corporate Secretary.

EOG intends to disclose any amendments to the Code of Conduct or Code of Ethics, and any waivers with respect to the Code of Conduct or Code of Ethics granted to EOG's principal executive officer, principal financial officer, principal accounting officer, any of our controllers or any of our other employees performing similar functions, on its website at www.eogresources.com within four business days after the amendment or waiver. In such case, the disclosure regarding the amendment or waiver will remain available on EOG's website for at least 12 months after the initial disclosure. There have been no waivers granted with respect to EOG's Code of Conduct or Code of Ethics.

ITEM 11. Executive Compensation

The information required by this Item is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 2026 Annual Meeting of Stockholders to be filed not later than April 30, 2026. The Compensation and Human Resources Committee Report and related information incorporated by reference herein shall not be deemed "soliciting material" or to be "filed" with the United States Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended, except to the extent that EOG specifically incorporates such information by reference into such a filing.

ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required by this Item with respect to security ownership of certain beneficial owners and management is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 2026 Annual Meeting of Stockholders to be filed not later than April 30, 2026.

Equity Compensation Plan Information

Stock Plans Approved by EOG Stockholders. EOG's stockholders approved the EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (2021 Plan) at the 2021 Annual Meeting of Stockholders in April 2021. From and after the April 29, 2021 effective date of the 2021 Plan, no further grants have been (or will be) made under the Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Amended and Restated 2008 Plan). The Amended and Restated 2008 Plan was approved by EOG's stockholders at the 2013 Annual Meeting of Stockholders in May 2013.

The 2021 Plan provides for grants of stock options, stock appreciation rights (SARs), restricted stock, restricted stock units (which may include performance-based conditions) and other stock-based awards, up to an aggregate maximum of 20 million shares of EOG common stock, plus any shares that were subject to outstanding awards under the Amended and Restated 2008 Plan as of April 29, 2021 that subsequently are 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 of Directors (Board).

At the 2018 Annual Meeting of Stockholders in April 2018, stockholders approved an amendment and restatement of the EOG Resources, Inc. Employee Stock Purchase Plan (ESPP) to (among other changes) increase the number of shares available for grant by 2.5 million shares and further extend the term of the ESPP to December 31, 2027, unless terminated earlier by its terms or by EOG.

Stock Plans Not Approved by EOG Stockholders. In December 2008, the Board approved the amendment and continuation of the 1996 Deferral Plan as the "EOG Resources, Inc. 409A Deferred Compensation Plan" (Deferral Plan). Under the Deferral Plan (as subsequently amended), payment of up to 50% of base salary and 100% of annual cash bonus, director's fees, vestings of restricted stock units granted to non-employee directors (and dividends credited thereon) and 401(k) refunds (as defined in the Deferral Plan) may be deferred into a phantom stock account. In the phantom stock account, deferrals are treated as if shares of EOG common stock were purchased at the closing stock price on the date of deferral. Dividends paid on EOG common stock are credited quarterly and treated as if reinvested in EOG common stock. Payment of the phantom stock account is made in actual shares of EOG common stock in accordance with the Deferral Plan and the individual's deferral election. A total of 540,000 shares of EOG common stock have been authorized by the Board and registered for issuance under the Deferral Plan. As of December 31, 2025, 478,678 phantom shares had been issued.

The following table sets forth data for EOG's equity compensation plans aggregated by the various plans approved by EOG's stockholders and those plans not approved by EOG's stockholders, in each case as of December 31, 2025.


Plan Category	(a) Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights		(b) Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (1)		(c) Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a))

Equity Compensation Plans Approved by EOG Stockholders	1,986,971	(2)	$	66.72	12,242,898	(3)
Equity Compensation Plans Not Approved by EOG Stockholders	295,322	(4)	N/A		61,322	(5)
Total	2,282,293				12,304,220

(1)The weighted-average exercise price is calculated based solely on the exercise prices of the outstanding stock option and SAR grants and does not reflect (i) shares that will be issued upon the vesting of outstanding grants of restricted stock units or the vesting of outstanding grants of restricted stock units with performance-based conditions (performance units) or (ii) shares that will be issued in respect of issued and outstanding Deferral Plan phantom shares, all of which have no exercise price.

(2)Amount includes (i) 808,918 outstanding stock option and SAR grants, (ii) 684,885 outstanding restricted stock units, for which shares of EOG common stock will be issued, on a one-for-one basis, upon the vesting of such grants, and (iii) 493,168 outstanding performance units and assumes, for purposes of this table, (A) the application of a 100% performance multiple upon the completion of each of the remaining performance periods in respect of such grants and (B) accordingly, the issuance, on a one-for-one basis, of an aggregate 493,168 shares of EOG common stock upon the vesting of such grants. As more fully discussed in Note 7 to Consolidated Financial Statements, upon the application of the relevant performance multiple at the completion of each of the remaining performance periods in respect of such grants, (A) a minimum of 0 and a maximum of 986,336 performance units could be outstanding and (B) accordingly, a minimum of 0 and a maximum of 986,336 shares of EOG common stock could be issued upon the vesting of such grants.

(3)Consists of (i) 11,488,226 shares remaining available for issuance under the 2021 Plan and (ii) 754,672 shares remaining available for purchase under the ESPP. As noted above, from and after the April 29, 2021 effective date of the 2021 Plan, no further grants have been (or will be) made under the Amended and Restated 2008 Plan.

(4)Consists of shares of EOG common stock to be issued in accordance with the Deferral Plan and participant deferral elections (i.e., in respect of the 295,322 phantom shares issued and outstanding under the Deferral Plan as of December 31, 2025).

(5)Represents phantom shares that remain available for issuance under the Deferral Plan.

ITEM 13. Certain Relationships and Related Transactions, and Director Independence

ITEM 14. Principal Accountant Fees and Services

PART IV

ITEM 15. Exhibits and Financial Statement Schedules

(a)(1) and (a)(2) Financial Statements and Financial Statement Schedule

See "Index to Financial Statements" set forth on page F-1.

(a)(3), (b) Exhibits

See pages E-1 through E-6 for a listing of the exhibits.

ITEM 16. Form 10-K Summary

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 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

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.

F-15

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.

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)

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)

10.46

January - December 2026

Mont Belvieu Ethane (non-Tet)

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)

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)

30.82

January - December 2026

Mont Belvieu Propane (Tet)

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.

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.

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 EO G (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. Employe e 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)

EOG Resources - 10-K annual report 2025

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