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, 2024
 or
 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 Commission file number: 1-9743

 (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, 2024: $ 71,585 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, 553,926,330 shares outstanding as of February 13, 2025.

 Documents incorporated by reference. Portions of the Definitive Proxy Statement for the registrant's 2025 Annual Meeting of Stockholders, to be filed within 120 days after December 31, 2024, are incorporated by reference into Part III of this report.

 Page

 ITEM 1.
 Business

 General

 Exploration and Production

 Marketing

 Volumes and Prices

 Human Capital Management

 Competition

 Regulation

 Other Matters

 Information About Our Executive Officers

 ITEM 1A.
 Risk Factors

 ITEM 1B.
 Unresolved Staff Comments

 ITEM 1C.
 Cybersecurity

 ITEM 2.
 Properties

 Oil and Gas Exploration and Production - Properties and Reserves

 ITEM 3.
 Legal Proceedings

 ITEM 4.
 Mine Safety Disclosures

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

 ITEM 6.
 Reserved

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

 ITEM 7A.
 Quantitative and Qualitative Disclosures About Market Risk

 ITEM 8.
 Financial Statements and Supplementary Data

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

 ITEM 9A.
 Controls and Procedures

 ITEM 9B.
 Other Information

 ITEM 9C.
 Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

 ITEM 10.
 Directors, Executive Officers and Corporate Governance

 ITEM 11.
 Executive Compensation

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

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

 ITEM 14.
 Principal Accountant Fees and Services

 ITEM 15.
 Exhibits and Financial Statement Schedules

 ITEM 16.
 Form 10-K Summary

 SIGNATURES

 (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. 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, 2024, EOG's total estimated net proved reserves were 4,748 million barrels of oil equivalent (MMBoe), of which 1,870 million barrels (MMBbl) were crude oil and condensate reserves, 1,358 MMBbl were NGLs reserves and 9,122 billion cubic feet (Bcf), or 1,520 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, 2024, on a crude oil equivalent basis, 40% of EOG's net proved reserves in the United States were crude oil and condensate, 29% were NGLs and 31% 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, 2024, total net acres at December 31, 2024, and expected net well completions planned for 2025 for certain areas of EOG's United States operations.

 2024
 2025

 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

 309.7
 184.9
 1,039

 South Texas
 124.4
 30.8
 1,272

 Rocky Mountain
 41.7
 14.9

 Other Areas
 14.8
 15.3

 Total
 490.6
 245.9
 1,728
 3,358

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

 In the Delaware Basin, EOG completed 385 net wells in 2024, primarily in the Wolfcamp, Bone Spring and Leonard plays. The Delaware Basin consists of approximately 4,800 feet of liquids-rich stacked pay potential offering EOG multiple co-development opportunities throughout its 395,000 net acre position. Activity in 2025 will remain focused on the Wolfcamp, Bone Spring and Leonard plays, where EOG expects to complete approximately 375 net wells.

 The South Texas area includes the Eagle Ford play and the Dorado gas play. EOG holds approximately 535,000 total net acres in the Eagle Ford play and approximately 160,000 net acres in the Dorado gas play. In 2024, EOG completed 160 net wells in the Eagle Ford play, and 21 net wells in the Dorado gas play. In addition, key gathering, processing and transportation infrastructure was added in order to lower operating costs and increase price realizations. In 2025, EOG expects to complete approximately 120 net Eagle Ford play wells and 25 net Dorado gas play wells, while utilizing new infrastructure that connects the Dorado gas play to the Agua Dulce gas market near Corpus Christi, Texas.

 Activity in the Rocky Mountain area in 2024 was focused on the Wyoming Powder River Basin. In the Powder River Basin, EOG completed 27 net wells in the Niobrara, Mowry, Turner and Parkman formations. In 2025, activity in the Rocky Mountain area is expected to remain flat with plans to complete 30 net wells in the Powder River Basin.

 Activity in the Other Areas includes EOG's newest play, the Utica play. EOG holds approximately 460,000 total net acres, including 135,000 net mineral acres in the Utica. In 2024, EOG completed 25 net Utica wells, collecting data and delineating its acreage. In 2025, EOG expects to complete approximately 30 net Utica wells.

 Operations Outside the United States

 EOG has operations offshore Trinidad and is evaluating additional exploration, development and exploitation opportunities in other select international areas. In addition, EOG is executing an abandonment and reclamation program in Canada.

 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 (SECC) and Pelican Blocks, Banyan and Sercan Areas and each of their related platforms and facilities and the Ska, Mento and Reggae (SMR) and deep Teak, Saaman and Poui (TSP Deep) Areas, all of which are offshore Trinidad and (ii) two production sharing contracts with the Government of Trinidad and Tobago for the Modified U(a) and 4(a) Blocks.

 Several fields in the SECC Block, Modified U(a) Block, 4(a) Block and Banyan and Sercan Areas have been developed and are producing natural gas and crude oil and condensate.

 In 2024, EOG's net production in Trinidad averaged approximately 220 MMcfd of natural gas and approximately 0.8 MBbld of crude oil and condensate. In 2024, EOG completed one net developmental well and one net exploratory well from the Osprey B platform in the Modified U(a) Block. EOG also completed two net exploratory wells from the Oilbird platform in the SECC Block, drilled a TSP Deep exploratory well which allowed EOG to retain a 50% working interest in the TSP Deep Area and recompleted one net well in the Sercan Area. In June 2024, EOG relinquished its rights to a portion of the contract area governed by the Trinidad Northern Area License located offshore the southwest coast of Trinidad. In July 2024, EOG signed a farmout agreement with BP Trinidad and Tobago LLC, which allows EOG to earn a 50% working interest to develop the Coconut field in the Coconut Area located within the East Mayaro and South East Galeota exploration and production licenses. In December 2024, EOG was selected as the preferred bidder in the Lower Reverse L (LRL) and North Coast Marine Area (NCMA) 4(a) Blocks in respect of the 2023 shallow water offshore bid round. Additionally in 2024, EOG completed construction and installation of the Mento platform in the SMR Area and commenced pipeline and associated tie-in installations that will connect the Mento platform to the Pelican platform (Mento Pipeline Installation).

 In 2025, EOG expects to (i) complete the Mento Pipeline Installation; (ii) drill and, if successful, complete two net exploratory wells and drill and complete two net developmental wells, all in the Mento Field located in the SMR Area; (iii) following the execution of the production sharing contracts for the LRL Block, commence an ocean bottom nodal 3D seismic survey over a portion of the LRL Block; and (iv) commence construction of the platform for the Coconut field. The production sharing contracts with the Government of Trinidad and Tobago for the LRL and NCMA 4(a) Blocks were executed on January 29, 2025.

 Bahrain. In February 2025, a subsidiary of EOG signed an exploration participation agreement with Bapco Energies B.S.C. (Closed) to evaluate a gas exploration project in the Kingdom of Bahrain, with drilling anticipated to commence in the second half of 2025. The transaction, which includes a concession agreement with the Kingdom of Bahrain, is subject to further government approvals, which the parties anticipate receiving in the second half of 2025.

 Australia. In April 2021, a subsidiary of EOG entered into a purchase and sale agreement to acquire a 100% interest in the WA-488-P Block, located offshore Western Australia. In November 2021, the petroleum exploration permit for that block was transferred to that subsidiary. The company has deferred drilling plans to further evaluate the prospect.

 Canada. EOG continues the process of exiting its Canada operations in the Horn River area in Northeast British Columbia.

 Marketing

 In 2024, 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, including Houston and Corpus Christi, Texas; Cushing, Oklahoma; the Permian Basin and the Midwest. In 2024, 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 2025, the pricing mechanism for such production is expected to remain the same. At December 31, 2024, EOG was committed to deliver to multiple parties aggregate fixed quantities of crude oil of 2 MMBbls in 2025, all of which is expected to be sourced from future production of available reserves.

 In 2024, 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 2024, 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 2025, the pricing mechanisms for NGL and purity products sales are expected to remain the same. At December 31, 2024, EOG was committed to deliver to multiple parties aggregate fixed quantities of purity products of 15 MMBbls in 2025, all of which is expected to be sourced from future production of available reserves.

 In 2024, consistent with its diversified marketing strategy, the majority of EOG's United States natural gas production was transported by pipeline to various locations, including Katy, Texas; East Texas; the Agua Dulce Hub in South Texas; the Cheyenne Hub in Weld County, Colorado; and Chicago, Illinois. Remaining natural gas production was sold into local markets. In each case, pricing was based on the spot market price at the ultimate sales point. In 2025, the pricing mechanism for such production is expected to remain the same. Additionally, EOG sells natural gas to a liquefaction facility near Corpus Christi, Texas, and receives pricing based on the Platts Japan Korea Marker; such pricing mechanism is expected to remain the same in 2025. At December 31, 2024, EOG was committed to deliver to multiple parties aggregate fixed quantities of natural gas of 342 Bcf in 2025, 318 Bcf in 2026, 359 Bcf in 2027, 328 Bcf in 2028, 328 Bcf in 2029 and 3,474 Bcf thereafter, all of which is expected to be sourced from future production of available reserves.

 In February 2024, EOG entered into a 10-year agreement, commencing in 2027, to sell 180,000 million British thermal units per day (MMBtud) of its domestic natural gas production, with 140,000 MMBtud to be sold at a price indexed to Brent crude oil (Brent) and the remaining volumes to be sold at a price indexed to Brent or a U.S. Gulf Coast gas index.

 In 2024, 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: (i) a fixed price contract and (ii) a contract based on an escalated floor price which further increases if index prices for certain commodities exceed specified levels.

 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 2024, three 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, 2024, 2023 and 2022. 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.

 2024
 2023
 2022

 Crude Oil and Condensate Volumes (MMBbl) (1)

 United States:

 113.3
 110.2
 101.1

 Eagle Ford Play
 45.5
 43.9
 46.6

 Other
 20.8
 19.4
 20.3

 179.6
 173.5
 168.0

 0.3
 0.2
 0.3

 Total
 179.9
 173.7
 168.3

 Natural Gas Liquids Volumes (MMBbl) (1)

 United States:

 67.7
 59.8
 50.7

 Eagle Ford Play
 11.1
 10.5
 10.5

 Other
 11.2
 11.4
 10.9

 90.0
 81.7
 72.1

 Total
 90.0
 81.7
 72.1

 Natural Gas Volumes (Bcf) (1)

 United States:

 Eagle Ford Play

 Other

 Total

 Crude Oil Equivalent Volumes (MMBoe) (2)

 United States:

 244.4
 224.2
 198.3

 Eagle Ford Play
 65.4
 62.7
 65.8

 Other
 65.2
 62.6
 56.0

 375.0
 349.5
 320.1

 13.7
 9.9
 11.4

 Total
 388.7
 359.4
 331.5

 2024
 2023
 2022

 Average Crude Oil and Condensate Prices ($/Bbl) (3)

 $
 77.42
 $
 79.18
 $
 97.22

 64.43
 68.58
 86.16

 77.40
 79.17
 97.21

 Average Natural Gas Liquids Prices ($/Bbl) (3)

 $
 23.40
 $
 23.07
 $
 36.70

 23.40
 23.07
 36.70

 Average Natural Gas Prices ($/Mcf) (3)

 $
 1.99
 $
 2.70
 $
 7.27

 3.65
 3.65
 4.43
 (4)

 2.17
 2.79
 6.93

 (1)Million barrels or billion cubic feet, as applicable.
 (2)Million barrels of oil equivalent; includes crude oil and condensate, NGLs and natural gas.
 (3)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).
 (4)Includes positive revenue adjustment of $0.76 per Mcf ($0.09 per Mcf of EOG's composite natural gas price) for the twelve months ended December 31, 2022, related to a price adjustment per a provision of the natural gas sales contract with NGC amended in July 2022 for natural gas sales during the period from September 2020 through June 2022.

 Human Capital Management

 As of December 31, 2024, EOG employed approximately 3,150 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 and experiences of our employees, as well as an inclusive work environment, promotes collaboration through multiple perspectives, which helps foster 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, management skills, 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, diverse 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 also 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, implement corrective actions as necessary, and enhance our understanding, identification and implementation of proactive safety management practices.

 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 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 proposed, 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, an increase in 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 disbursement 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) requires 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.

 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 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. Conversely, sales of crude oil and condensate and NGLs by EOG 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 Utica in Ohio, the Barnett Shale in the Bend Arch-Fort Worth Basin 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 2024.

 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. Moreover, EOG is subject to the U.S. Environmental Protection Agency's (U.S. EPA) rule requiring annual reporting of GHG emissions and, as discussed further below, is also subject to federal, state and local laws and regulations regarding hydraulic fracturing and other aspects of our operations.

 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 increasingly 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. EPA's GHG reporting program, which program 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, which President Trump is expected to sign into law. 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, capital expenditures 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. In January 2025, President Trump signed executive orders that, among other things, direct federal executive departments and agencies to initiate a regulatory freeze for certain rules that have not taken effect, pending review by the newly appointed agency head, and call upon the U.S. EPA to submit a report on the continuing applicability of its endangerment finding for GHGs under the Clean Air Act.

 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 intends to withdraw from the Paris Agreement. Pursuant to the terms of the Paris Agreement, the withdrawal will take effect on January 27, 2026. Nevertheless, state and local officials may 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 emissions reduction targets and its ambition to reach net zero Scope 1 and Scope 2 GHG emissions by 2040. 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 has created 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 60 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, and 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 (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 2% in 2024, decreased 19% in 2023 and increased 42% in 2022, each as compared to the immediately preceding year. Average NGLs prices received by EOG for production in the United States increased 1% in 2024, decreased 37% in 2023 and increased 7% in 2022, 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 26% decrease in 2024, a 63% decrease in 2023, and a 49% increase in 2022, 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 2025 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 $159 million for net income and $204 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 2025 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 $33 million for net income and $42 million for pretax cash flows from operating activities. For a summary of EOG's financial commodity and other derivative contracts through February 21, 2025, 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, 2024, 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 21, 2025, 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 bodily injury or death claims resulting from an incident involving EOG's operations (subject to policy terms and conditions). Moreover, for any incident involving EOG's operations which results in negative environmental effects, EOG maintains operators extra expense insurance coverage for obligations, expenses or claims that EOG may incur from such an incident, including obligations, expenses or claims in respect of sudden and accidental seepage and pollution, cleanup and containment, evacuation expenses and control of the well (subject to policy terms and conditions). In the event of a well control incident resulting in negative environmental effects, such operators extra expense coverage would be EOG's primary coverage, with the commercial general liability and excess liability coverage also providing certain coverage to EOG. Additionally, subject to policy terms and conditions, EOG also maintains insurance that covers damage to EOG's equipment, facilities and structures due to a physical damage event. All of 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 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 27, 2025) 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, General Counsel and Corporate Secretary

 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, General Counsel and Corporate Secretary in April 2016. Previously, Mr. Donaldson 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 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 other 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, the imposition of tariffs or trade or other economic sanctions and political instability or armed conflict in oil and gas producing regions;
 • the availability, proximity and capacity of appropriate transportation, gathering, processing, compression, storage, 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, such as the COVID-19 pandemic.

 The above-described factors and the volatility of commodity prices make it difficult to predict crude oil, NGLs and natural gas prices in 2025 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.

 Our cost-mitigation initiatives and actions may not offset, largely or at all, the impacts of inflationary pressures on our operating costs and capital expenditures.

 Beginning in the second half of 2021 and continuing, to a lesser degree, through the first quarter of 2023, we, similar to other companies in our industry, experienced inflationary pressures on our operating costs and capital expenditures - namely the costs of fuel, steel (i.e., wellbore tubulars and facilities manufactured using steel), labor and drilling and completion services. Such inflationary pressures on our operating costs and capital expenditures impacted our cash flows and results of operations during these periods. While such inflationary pressures diminished beginning in the second quarter of 2023 and throughout fiscal year 2024 (and, in certain instances, EOG has seen a decline in prices), the market for such materials, services and labor continues to fluctuate and, as a result, the timing and impact of any price changes on our future operating costs and capital expenditures is uncertain.

 We have undertaken, and plan to continue with, certain initiatives and actions (such as agreements with service providers to secure the costs and availability of services) to mitigate any future inflationary pressures (such as from tariffs). However, there can be no assurance that such efforts will offset, largely or at all, the impacts of any future inflationary pressures on our operating costs and capital expenditures and, in turn, 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.

 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 finance 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 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 adversely affect our ability to finance our capital expenditures through debt or equity offerings or other borrowings.

 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 increasing 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 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 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 have a material and adverse effect on our business, financial condition and operations.

 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 level, 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 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, including:

 • cash available for dividends;
 • cash available for 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 required to conduct our operations and carry out our business strategy;
 • our operating costs;
 • any contractual restrictions or statutory/legal restrictions;
 • 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) 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 2025 is subject to fluctuating market prices. To the extent we do not hedge our production volumes for 2025 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 hedging contracts 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 several 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 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. In the future, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums, retentions and deductibles for our insurance policies will change over time and could escalate. 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 adverse effect on our financial condition, results of operations and cash flows.

 If we acquire crude oil, NGLs and 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 seek to acquire crude oil and natural gas properties. Although we perform reviews of properties to be acquired in a manner that we believe is duly 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.

 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 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 increasingly 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 require U.S. public companies to significantly expand the climate-related disclosures in their SEC filings (although the new rules have been stayed pending judicial review and the SEC has requested the court to pause further judicial proceedings, pending the SEC's determination of the appropriate next steps), (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) 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 as 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 proposed, 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, an increase in 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 completion 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 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 completion operations. The U.S. Environmental Protection Agency (U.S. EPA) has issued 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. See also the risk factor below regarding the provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act with respect to regulation of financial derivative transactions and entities (such as EOG) that participate in such transactions.

 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 increasingly focused on GHG emissions and climate change issues in recent years. For example, we are subject to the U.S. EPA's rule requiring annual reporting of GHG emissions which is subject to amendment from time to time. In addition, our oil and gas production and processing operations are subject to the U.S. EPA's new source performance standards applicable to emissions of volatile organic compounds from new, modified and reconstructed crude oil and natural gas wells and equipment located at natural gas production gathering and booster stations and gas processing plants, as well as the U.S. EPA's final new methane rules published in March 2024. Further, our operations are subject to the methane "Waste Emissions Charge" rule, published in November 2024 as part of the Methane Emissions Reduction Program implemented under the Inflation Reduction Act of 2022 (though, in February 2025, such rule was repealed by the U.S. House and Senate under the Congressional Review Act, which President Trump is expected to sign into law).

 At the international level, in December 2015, the U.S. 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 and to which the United States formally rejoined in February 2021. The United States has established an economy-wide target of reducing its net GHG emissions by 50-52 percent below 2005 levels by 2030 and 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 United Nations Climate Change 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 intends to withdraw from the Paris Agreement. Pursuant to the terms of the Paris Agreement, the withdrawal will take effect on January 27, 2026. Nevertheless, many state and local officials may 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 emissions reduction targets and our ambition to reach net-zero Scope 1 and Scope 2 GHG emissions by 2040. 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. For example, we are exploring technology to capture and store carbon dioxide emissions, which includes a pilot carbon capture and storage (CCS) project related to our operations. CCS projects face operational, technological, legal and regulatory risks that could be considerable due to the early-stage nature of such projects and the CCS sector generally. Our ability to successfully develop, implement and carry out our CCS activities will depend on a number of factors that we will not be able to fully control, including timing of regulatory approvals and availability of subsurface pore space. Further, financial or tax incentives in respect of CCS projects could be changed or terminated. In addition, our failure to properly operate a CCS project could put at risk certain governmental tax credits and potentially expose us to commercial, legal, reputational and other risks.

 Further, 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 and net-zero ambition 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. For example, recently adopted U.S. EPA regulations will expand the scope of emissions sources and revise calculation methods. 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 and net-zero ambition, 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, revising our ambition and/or setting new targets, as well as how we define and work to achieve our net-zero ambition. 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, in recent years there has been increased investor and regulatory focus on environmental and social matters. In addition to climate change, there has been increased investor and regulatory focus on topics such as human rights and human capital management in companies' own operations as well as across their supply chains. 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 and contractual, employment and other business relationships may be adversely impacted.

 Lastly, as noted above, the SEC, in March 2024, finalized extensive climate-related disclosure rules that require U.S. public companies to significantly expand the climate-related disclosures in their SEC filings (although the new rules have been stayed pending judicial review and the SEC has requested the court to pause further judicial proceedings, pending the SEC's determination of the appropriate next steps). 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 specific provisions or impact on EOG of any such enacted GMT legislation would be.

 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 or exchange rate fluctuations.

 Our international operations may also be adversely affected by U.S. laws and policies affecting foreign trade and taxation, including tariffs or 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 senior manager, information systems security, who each have over seven years of experience overseeing EOG's cybersecurity processes and strategy.

 Cyber Governance & Oversight

 EOG's cybersecurity team reports to EOG's Senior Vice President and 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, Senior Vice President and 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 normally 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 meaningfulness 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, 2024 (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

 1,770
 1,429
 2,789
 1,929
 4,559
 3,358

 Australia
 —
 —
 1,009
 1,009
 1,009
 1,009

 Total
 1,872
 1,506
 3,989
 3,048
 5,861
 4,554

 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. Approximately 0.1 million net acres will expire in 2025, 0.1 million net acres will expire in 2026 and 0.1 million net acres will expire in 2027 if production is not established or we take no other action to extend the terms of the leases or obtain concessions. As of December 31, 2024, 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 certain geologic trends and prospective economics, 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.

 The agreement governing the acreage associated with our exploration program in offshore Australia is set to expire at various dates through 2026.

 Productive Well Summary. The following table represents EOG's gross and net productive wells at December 31, 2024, including 3,052 wells in which it holds a royalty interest.

 Total

 Gross
 Net
 Gross
 Net
 Gross
 Net

 10,288
 7,111
 3,605
 1,782
 13,893
 8,893

 Total (1)

 10,290
 7,113
 3,647
 1,817
 13,937
 8,930

 (1) EOG operated 9,910 gross and 8,792 net producing crude oil and natural gas wells at December 31, 2024. Gross crude oil and natural gas wells include 55 wells with multiple completions.

 Drilling and Acquisition Activities. During the years ended December 31, 2024, 2023 and 2022, EOG expended $5.6 billion, $6.0 billion and $5.2 billion, respectively, for exploratory and development drilling, facilities and acquisition of leases and producing properties, including asset retirement costs of $(2) million, $257 million and $298 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, 2024, 2023 and 2022:

 Gross Development Wells Completed
 Gross Exploratory Wells Completed

 Dry Hole
 Total
 Dry Hole
 Total

 2024

 —

 —
 —
 —
 —

 Total

 —

 2023

 —

 —
 —
 —
 —

 Total
 —

 2022

 —

 —
 —
 —
 —
 —

 Total

 The following tables set forth the results of the net crude oil and natural gas wells completed for the years ended December 31, 2024, 2023 and 2022:

 Net Development Wells Completed
 Net Exploratory Wells Completed

 Dry Hole
 Total
 Dry Hole
 Total

 2024

 —

 —
 —
 —
 —

 Total

 —

 2023

 —

 —
 —
 —
 —

 Total
 —

 2022

 —

 —
 —
 —
 —
 —

 Total

 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, 2024, 2023 and 2022:

 Wells in Progress at End of Period

 2024
 2023
 2022

 Gross
 Net
 Gross
 Net
 Gross
 Net

 Total

 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, 2024, there were approximately 179 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

 2024
 2023
 2022

 Gross
 Net
 Gross
 Net
 Gross
 Net

 —
 —

 Total

 EOG acquired wells as set forth in the following table (excluding the acquisition of additional interests in 4, 4 and 74 net wells in which EOG previously owned an interest for the years ended December 31, 2024, 2023 and 2022, respectively) for the years ended December 31, 2024, 2023 and 2022:

 Gross Acquired Wells
 Net Acquired Wells

 Crude
Oil
 Natural
Gas
 Total
 Crude
Oil
 Natural
Gas
 Total

 2024

 Total

 2023

 —
 —

 Total
 —
 —

 2022

 Total

 Other Property, Plant and Equipment. EOG's other property, plant and equipment primarily includes gathering, processing and transportation assets, carbon capture and storage 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 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, 2024.

 ITEM 4. Mine Safety Disclosures

 None.

 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, 2025, there were approximately 3,100 record holders and approximately 1,252,000 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:

 (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, 2024 - October 31, 2024

 2,401,712
 $
 126.86
 $
 299,999,895
 $
 1,531,171,168

 November 1, 2024 - November 30, 2024
 1,224,309
 133.70
 157,512,580
 6,373,658,588

 December 1, 2024 - December 31, 2024
 4,241,236
 123.56
 523,698,015
 5,849,960,573

 Total
 7,867,257
 126.15
 981,210,490

 (1)Includes 7,782,416 shares repurchased during the quarter ended December 31, 2024, at an average price of $126.08 per share (inclusive of commissions and transaction fees), pursuant to the Share Repurchase Authorization (as defined below); such repurchases count against the Share Repurchase Authorization. The share repurchases effected during the periods October 1, 2024 through November 8, 2024 and November 11, 2024 through November 20, 2024 were made pursuant to Rule 10b5-1 trading plans entered into by EOG on September 30, 2024 and November 8, 2024 (respectively). Also includes 84,841 total shares that were withheld by or returned to EOG during the quarter ended December 31, 2024, at an average price of $132.23 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, 2024, (i) EOG had repurchased an aggregate 34,462,691 shares at a total cost of $4,150,039,427 (inclusive of commissions and transaction fees) under the Share Repurchase Authorization and (ii) an additional $5,849,960,573 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, and other market and economic conditions. 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 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, 2019 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, 2024)

 2019
 2020
 2021
 2022
 2023
 2024

 EOG
 $
 100.00
 $
 61.36
 $
 115.78
 $
 181.62
 $
 177.98
 $
 185.65

 S&P 500
 $
 100.00
 $
 118.40
 $
 152.39
 $
 124.79
 $
 157.59
 $
 197.02

 S&P O&G E&P
 $
 100.00
 $
 64.58
 $
 120.82
 $
 191.50
 $
 191.57
 $
 181.25

 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 $6,403 million during 2024 as compared to net income of $7,594 million for 2023. At December 31, 2024, EOG's total estimated net proved reserves were 4,748 million barrels of oil equivalent (MMBoe), an increase of 250 MMBoe from December 31, 2023. During 2024, net proved crude oil and condensate and natural gas liquids (NGLs) reserves increased by 218 million barrels (MMBbl), and net proved natural gas reserves increased by 192 billion cubic feet, or 32 MMBoe, in each case from December 31, 2023.

 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 and 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.

 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, 2024, the average U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were $75.72 per barrel and $2.27 per million British thermal units (MMBtu), respectively, representing decreases of 2% and 17%, respectively, from the average NYMEX prices for the year ended December 31, 2023. 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.

 Inflationary Pressures, Operational Efficiencies & Related Initiatives/Actions. During 2024, EOG continued to see diminished inflationary pressures on its operating costs and capital expenditures (e.g., for fuel, wellbore tubulars, facilities manufactured using steel, labor and drilling and completion services) and, in certain circumstances, has seen declines in prices. However, because the market for such materials, services and labor continues to fluctuate, there can be no assurance that the inflationary pressures experienced by EOG in prior periods will not resume. Further, the timing and impact of any future price changes on EOG's operating costs and capital expenditures is uncertain.

 EOG has undertaken (and continues to undertake) initiatives to increase its drilling, completion and operating efficiencies and improve the performance of its wells and, in turn, mitigate the inflationary pressures experienced in prior periods. 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 has resulted in a decrease in cost per foot drilled; and (iv) EOG's self-sourced sand program, which has resulted in cost savings for the sand utilized 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 completion 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 offset, largely or at all, the impacts of any future inflationary pressures (such as from tariffs) on EOG's operating costs and capital expenditures, cash flows and results of operations. Further, there can be no assurance that the factors contributing to any such future inflationary pressures 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.

 Climate Change. For a discussion of climate change matters and related regulatory matters, including potential developments related to climate change and the potential impacts and risks of such developments on EOG, see ITEM 1A, Risk Factors, and the related discussion in ITEM 1, Business – Regulation. EOG will continue to monitor and assess any climate change-related developments that could impact EOG and the oil and gas industry, to determine the impact on its business and operations, and take appropriate actions where necessary.

 Operations

 Several important developments have occurred since January 1, 2024.

 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 2024, EOG continued to focus on initiatives to increase its drilling, completion and operating efficiencies and improve well performance and, in turn, mitigate the inflationary pressures on its operating costs and capital expenditures experienced in prior periods. 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 72% and 73% of EOG's United States production during 2024 and 2023, respectively. During 2024, EOG's drilling and completion activities occurred primarily in the Delaware Basin play, Eagle Ford play and Rocky Mountain area. EOG's major producing areas in the United States are in New Mexico and Texas. See ITEM 1, Business - Exploration and Production for further discussion regarding EOG's 2024 United States operations.

 Trinidad. In Trinidad, EOG continues to deliver natural gas under existing supply contracts. Several fields in the South East Coast Consortium (SECC) Block, Modified U(a) Block, Block 4(a) and Banyan and Sercan Areas have been developed and are producing natural gas which is sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary, and crude oil and condensate which is sold to Heritage Petroleum Company Limited.

 During 2024, EOG completed one net developmental well and one net exploratory well from the Osprey B platform in the Modified U(a) Block. EOG also completed two net exploratory wells from the Oilbird platform in the SECC Block, drilled a deep Teak, Saaman and Poui (TSP Deep) exploratory well which allowed EOG to retain a 50% working interest in the TSP Deep Area and recompleted one net well in the Sercan Area. EOG also completed construction and installation of the Mento platform in the Ska, Mento and Reggae Area and commenced pipeline and associated tie-in installations that will connect the Mento platform to the Pelican platform. In 2024, EOG relinquished its rights to a portion of the contract area governed by the Trinidad Northern Area License located offshore the southwest coast of Trinidad and signed a farmout agreement with BP Trinidad and Tobago LLC, which allows EOG to earn a 50% working interest to develop the Coconut field in the Coconut Area located within the East Mayaro and South East Galeota exploration and production licenses. Additionally, EOG was selected as the preferred bidder in the Lower Reverse L and North Coast Marine Area 4(a) Blocks in respect of the 2023 shallow water offshore bid round.

 Other International. In February 2025, a subsidiary of EOG signed an exploration participation agreement with Bapco Energies B.S.C. (Closed) to evaluate a gas exploration project in the Kingdom of Bahrain, with drilling anticipated to commence in the second half of 2025. The transaction, which includes a concession agreement with the Kingdom of Bahrain, is subject to further government approvals, which the parties anticipate receiving in the second half of 2025.

 In November 2021, a subsidiary of EOG was granted an exploration permit for the WA-488-P Block, located offshore Western Australia. The company has deferred drilling plans to further evaluate the prospect.

 EOG continues to evaluate other select exploration, development and exploitation opportunities outside the United States, primarily by pursuing 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 14% at December 31, 2024 and 12% at December 31, 2023. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

 At December 31, 2024, EOG maintained a strong financial and liquidity position, including $7.1 billion of cash and cash equivalents on hand and $1.9 billion of availability under its senior unsecured revolving credit facility (discussed below).

 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). EOG received net proceeds of $985 million from the issuance of the Notes, which will be used for general corporate purposes, including (i) the repayment of the $500 million aggregate principal amount of 3.15% Senior Notes due 2025 and (ii) the funding of future capital expenditures.

 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.

 During 2024, EOG funded $6.7 billion ($109 million of which was non-cash) in exploration and development and other property, plant and equipment expenditures (excluding asset retirement obligations), paid $2.1 billion in dividends to common stockholders and paid $3.2 billion to repurchase shares of common stock, primarily by utilizing net cash provided by its operating activities and cash on hand.

 Total anticipated 2025 capital expenditures are estimated to range from approximately $6.0 billion to $6.4 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 2025 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 continues to believe 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% of annual net cash provided by operating activities before certain balance sheet-related changes, less total capital expenditures, to stockholders through a combination of quarterly 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 22, 2024, the Board of Directors (Board) declared a quarterly cash dividend on the common stock of $0.91 per share paid on April 30, 2024, to stockholders of record as of April 16, 2024.

 On May 2, 2024, the Board declared a quarterly cash dividend on the common stock of $0.91 per share paid on July 31, 2024, to stockholders of record as of July 17, 2024.

 On August 1, 2024, the Board declared a quarterly cash dividend on the common stock of $0.91 per share paid on October 31, 2024, to stockholders of record as of October 17, 2024.

 On November 7, 2024, the Board increased the quarterly cash dividend on the common stock from the previous $0.91 per share to $0.975 per share, effective beginning with the dividend paid on January 31, 2025, to stockholders of record as of January 17, 2025.

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

 Results of Operations

 This section discusses certain year-to-year comparisons between 2024 and 2023, 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 2023 and 2022, 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, 2023, filed on February 22, 2024, which is incorporated herein by reference.

 Operating Revenues and Other

 During 2024, operating revenues decreased $488 million, or 2%, to $23,698 million from $24,186 million in 2023. Total revenues from sales of EOG's production of crude oil and condensate, NGLs and natural gas, increased $202 million, or 1%, to $17,578 million in 2024 from $17,376 million in 2023. Revenues from the sales of crude oil and condensate and NGLs in 2024 were 91% of total revenues from sales of crude oil and condensate, NGLs and natural gas compared to 90% in 2023. During 2024, EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $204 million compared to net gains of $818 million in 2023. Gathering, processing and marketing revenues decreased $6 million during 2024, to $5,800 million from $5,806 million in 2023. EOG recognized net gains on asset dispositions of $16 million in 2024 compared to net gains on asset dispositions of $95 million in 2023.

 Volume and price statistics for the years ended December 31, 2024, 2023 and 2022 were as follows:

 2024
 2023
 2022

 Crude Oil and Condensate Volumes (MBbld) (1)

 490.6
 475.2
 460.7

 0.8
 0.6
 0.6

 Total
 491.4
 475.8
 461.3

 Average Crude Oil and Condensate Prices ($/Bbl) (2)

 $
 77.42
 $
 79.18
 $
 97.22

 64.43
 68.58
 86.16

 77.40
 79.17
 97.21

 Natural Gas Liquids Volumes (MBbld) (1)

 245.9
 223.8
 197.7

 Total
 245.9
 223.8
 197.7

 Average Natural Gas Liquids Prices ($/Bbl) (2)

 $
 23.40
 $
 23.07
 $
 36.70

 23.40
 23.07
 36.70

 Natural Gas Volumes (MMcfd) (1)

 1,728
 1,551
 1,315

 Total
 1,948
 1,711
 1,495

 Average Natural Gas Prices ($/Mcf) (2)

 $
 1.99
 $
 2.70
 $
 7.27

 3.65
 3.65
 4.43
 (4)

 2.17
 2.79
 6.93

 Crude Oil Equivalent Volumes (MBoed) (3)

 1,024.5
 957.5
 877.5

 37.6
 27.3
 30.7

 Total
 1,062.1
 984.8
 908.2

 Total MMBoe (3)

 388.7
 359.4
 331.5

 (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)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.
 (4)Includes positive revenue adjustment of $0.76 per Mcf ($0.09 per Mcf of EOG's composite natural gas price) for the twelve months ended December 31, 2022, related to a price adjustment per a provision of the natural gas sales contract with NGC amended in July 2022 for natural gas sales during the period from September 2020 through June 2022.

 Crude oil and condensate revenues in 2024 increased $173 million, or 1%, to $13,921 million from $13,748 million in 2023, primarily due to an increase in production ($491 million), partially offset by a lower composite average crude oil and condensate price ($318 million). EOG's composite crude oil and condensate price for 2024 decreased 2% to $77.40 per barrel compared to $79.17 per barrel in 2023. Crude oil and condensate production in 2024 increased 3% to 491 MBbld as compared to 476 MBbld in 2023. The increased production was primarily in the Permian Basin and Utica.

 NGLs revenues in 2024 increased $222 million, or 12%, to $2,106 million from $1,884 million in 2023 primarily due to an increase in production ($192 million) and a higher composite average NGLs price ($30 million). EOG's composite average NGLs price increased 1% to $23.40 per barrel in 2024 compared to $23.07 per barrel in 2023. NGLs production in 2024 increased 10% to 246 MBbld as compared to 224 MBbld in 2023. The increased production was primarily in the Permian Basin.

 Natural gas revenues in 2024 decreased $193 million, or 11%, to $1,551 million from $1,744 million in 2023 primarily due to a lower composite natural gas price ($435 million), partially offset by an increase in natural gas deliveries ($242 million). EOG's composite average natural gas price decreased 22% to $2.17 per Mcf in 2024 compared to $2.79 per Mcf in 2023. Natural gas deliveries in 2024 increased 14% to 1,948 MMcfd as compared to 1,711 MMcfd in 2023. The increase in production was primarily due to increased production of associated natural gas from the Permian Basin and higher natural gas deliveries in Trinidad.

 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. The net gains of $204 million included gains of $110 million related to the Brent crude oil (Brent) linked gas sales contract. During 2023, EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $818 million, which included net cash paid for settlements of crude oil, NGLs and natural gas financial commodity derivative contracts of $112 million.

 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. EOG sells sand primarily in order to balance the timing of firm purchase agreements with completion operations. 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 2024 decreased $14 million compared to 2023, primarily due to lower margins on sand sales and natural gas marketing activities, partially offset by higher margins on crude oil marketing activities.

 Operating and Other Expenses

 During 2024, operating expenses of $15,616 million were $1,033 million higher than the $14,583 million incurred during 2023. The following table presents the costs per barrel of oil equivalent (Boe) for the years ended December 31, 2024 and 2023:

 2024

 2023

 $
 4.04
 $
 4.05

 Gathering, Processing and Transportation Costs (GP&T)
 4.43
 4.50

 Depreciation, Depletion and Amortization (DD&A) -

 Oil and Gas Properties
 10.04
 9.24

 Other Property, Plant and Equipment
 0.53
 0.48

 General and Administrative (G&A)
 1.72
 1.78

 0.36
 0.41

 Total (1)

 $
 21.12
 $
 20.46

 (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 2024 compared to 2023 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 $1,572 million in 2024 increased $118 million from $1,454 million in 2023 primarily due to increased operating and maintenance costs ($81 million), increased lease and well administrative expenses ($27 million) and increased workovers expenditures ($13 million), all in the United States. Lease and well expenses increased in the United States primarily due to increased operating activities resulting from increased production.

 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 $102 million to $1,722 million in 2024 compared to $1,620 million in 2023 primarily due to increased production in the Permian Basin ($91 million) and the Utica ($35 million), partially offset by decreased costs in the Powder River Basin due to reduced operating and maintenance expenses ($17 million), the Eagle Ford play due to lower volumes and reduced third-party fees ($11 million) and the Barnett Shale due to lower gas volumes and operating costs ($5 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 2024 increased $616 million to $4,108 million from $3,492 million in 2023. DD&A expenses associated with oil and gas properties in 2024 were $583 million higher than in 2023. The increase primarily reflects increased production in the United States ($233 million) and Trinidad ($26 million), and increased unit rates in the United States ($166 million) and in Trinidad ($35 million). In addition, the recording of an adjustment to DD&A ($117 million) primarily related to natural gas production used by EOG's domestic gathering systems also contributed to the variance. DD&A expenses associated with other property, plant and equipment in 2024 were $33 million higher than in 2023 primarily due to an increase in expense related to GP&T assets and equipment.

 G&A expenses of $669 million in 2024 increased $29 million from $640 million in 2023 primarily due to a net increase in costs associated with corporate support activities, including employee-related expenses and information systems.

 Interest expense, net of $138 million in 2024 decreased $10 million from $148 million in 2023 primarily due to an increase in capitalized interest ($12 million) and the repayment in March 2023 of the $1,250 million aggregate principal amount of 2.625% Senior Notes due 2023 ($7 million), partially offset by the issuance in November 2024 of the $1,000 million aggregate principal amount of 5.650% Senior Notes due 2054 ($7 million).

 Exploration costs of $174 million in 2024 decreased $7 million from $181 million in 2023 primarily due to decreased geological and geophysical expenditures in the United States ($22 million), partially offset by increased administrative expenses ($9 million) and increased delay rentals ($6 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 FASB's Fair Value Measurement Topic of the 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, 2024 and 2023 (in millions):

 2024

 2023

 Proved properties
 $
 $

 Unproved properties

 Other assets

 Firm commitment contracts

 Total
 $
 $

 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.

 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 2024 decreased $35 million to $1,249 million (7.1% of revenues from sales of crude oil and condensate, NGLs and natural gas) from $1,284 million (7.4% of revenues from sales of crude oil and condensate, NGLs and natural gas) in 2023. The decrease in taxes other than income was primarily due to increased state severance tax refunds ($18 million), decreased ad valorem/property taxes ($14 million) and decreased severance/production taxes ($5 million), all in the United States.

 Other income, net, was $274 million in 2024 compared to other income, net, of $234 million in 2023. The increase of $40 million in 2024 was primarily due to an increase in interest income.

 Income taxes of $1,815 million in 2024 decreased from income taxes of $2,095 million in 2023 primarily due to decreased pretax income. The net effective tax rate for 2024 was unchanged from the prior year rate of 22%.

 Capital Resources and Liquidity

 Cash Flow

 The primary sources of cash for EOG during the three-year period ended December 31, 2024, were funds generated from operations and, to a lesser extent, net proceeds from the issuance of long-term debt and proceeds from asset sales. The primary uses of cash were funds used in operations; exploration and development expenditures; dividend payments to stockholders; purchases of treasury stock; net cash paid for settlements of financial commodity derivative contracts; other property, plant and equipment expenditures; and repayment of debt.

 Net cash provided by operating activities of $12,143 million in 2024 increased $803 million from $11,340 million in 2023 primarily due to a decrease in net cash paid for income taxes ($450 million), an increase in net cash received from settlements of financial commodity derivative contracts ($326 million), an increase in revenues from sales of crude oil and condensate, NGLs and natural gas ($202 million) and a decrease in net cash used in working capital and other assets and liabilities ($197 million), partially offset by the return in 2023 of cash collateral posted for financial commodity derivative contracts ($324 million) and an increase in cash operating expenses ($185 million).

 Net cash used in investing activities of $5,967 million in 2024 decreased by $373 million from $6,340 million in 2023 primarily due to a decrease in net cash used in working capital associated with investing activities ($677 million) and a decrease in additions to oil and gas properties ($32 million); partially offset by an increase in additions to other property, plant and equipment ($219 million) and a decrease in proceeds from the sales of assets ($117 million).

 Net cash used in financing activities of $4,361 million in 2024 included purchases of treasury stock ($3,246 million), cash dividend payments ($2,087 million) and repayment of finance lease liabilities ($33 million). Cash provided by financing activities in 2024 included long-term debt borrowings ($985 million) and proceeds from stock options exercised and employee stock purchase plan activity ($22 million).

 Total Expenditures

 The table below sets out components of total expenditures for the years ended December 31, 2024, 2023 and 2022 (in millions):

 2024
 2023
 2022

 Expenditure Category

 Capital

 Exploration and Development Drilling (1)

 $
 4,534
 $
 4,803
 $
 3,675

 Facilities

 Leasehold Acquisitions (2)

 Property Acquisitions (3)

 Capitalized Interest

 Subtotal
 5,448
 5,579
 4,727

 Exploration and Development Expenditures
 5,636
 5,761
 4,931

 Asset Retirement Costs (4)

 (2)

 Total Exploration and Development Expenditures
 5,634
 6,018
 5,229

 Other Property, Plant and Equipment (5)

 1,019

 Total Expenditures
 $
 6,653
 $
 6,818
 $
 5,610

 (1)Exploration and development drilling included $90 million related to non-cash development drilling in 2023.
 (2)Leasehold acquisitions included $85 million, $99 million and $127 million related to non-cash property exchanges in 2024, 2023 and 2022, respectively.
 (3)Property acquisitions included $24 million, $6 million and $26 million related to non-cash property exchanges in 2024, 2023 and 2022, respectively.
 (4)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 $5,636 million for 2024 were $125 million lower than the prior year primarily due to decreased development drilling expenditures ($249 million), partially offset by increased facility expenditures ($86 million), increased leasehold acquisitions ($23 million) and increased property acquisitions ($17 million). 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 2022 exploration and development expenditures of $4,931 million included $3,962 million in development drilling and facilities, $514 million in exploration, $419 million in property acquisitions and $36 million in capitalized interest.

 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, 2024 (closed) and remaining for 2025, as of February 21, 2025. Natural gas volumes are presented in MMBtu per day (MMBtud) and prices are presented in dollars per MMBtu ($/MMBtu).

 Natural Gas Financial Price Swap Contracts

 Contracts Sold

 Settlement Index
 Volume
(MMBtud in thousands)
 Weighted Average
Price ($/MMBtu)

 January - December 2024 (closed)
 3.07

 January - February 2025 (closed)
 3.07

 March - December 2025
 3.07

 Natural Gas Basis Swap Contracts

 Contracts Sold

 Settlement Index
 Volume
(MMBtud in thousands)
 Weighted Average
Price Differential
($/MMBtu)

 January - December 2024 (closed)
 NYMEX Henry Hub HSC Differential (1)

 0.00

 January - February 2025 (closed)
 NYMEX Henry Hub HSC Differential
 0.00

 March - December 2025
 NYMEX Henry Hub HSC Differential
 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 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 crude oil (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 14% at December 31, 2024, compared to 12% at December 31, 2023. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

 At December 31, 2024 and 2023, respectively, EOG had outstanding $4,640 million and $3,640 million aggregate principal amount of senior notes, which had estimated fair values of $4,441 million and $3,574 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 2024, EOG funded its capital program and operations by utilizing cash provided by operating activities and cash on hand. While EOG maintains a $1.9 billion senior unsecured revolving credit facility to back its commercial paper program, there were no borrowings outstanding at any time during 2024 and the amount outstanding at year-end was zero. EOG considers the availability of its $1.9 billion senior unsecured revolving credit 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 2025 will impact the amount of cash generated from EOG's operating activities, which will in turn impact EOG's financial position. As of February 21, 2025, the average 2025 NYMEX crude oil and natural gas prices were $69.58 per barrel and $4.26 per MMBtu, respectively, representing a decrease of 8% for crude oil and an increase of 88% for natural gas from the average NYMEX prices in 2024. 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 2025 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 $159 million for net income and $204 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 2025 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 $33 million for net income and $42 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 21, 2025, 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 mitigate any future inflationary pressures (such as from tariffs) through efficiency gains and by locking in certain service costs for drilling and completion activities. In addition, EOG expects to spend a portion of its anticipated 2025 capital expenditures on leasing acreage, evaluating new prospects, gathering and processing infrastructure, transportation infrastructure and environmental projects.

 The total anticipated 2025 capital expenditures of approximately $6.0 billion to $6.4 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 $1.9 billion senior unsecured revolving credit facility and equity and debt offerings.

 Operations. In 2025, crude oil and total crude oil equivalent production are expected to increase from 2024 levels. In 2025, EOG expects to continue to focus on mitigating any future inflationary pressures (such as from tariffs) on operating costs through efficiency improvements.

 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 2025, EOG anticipates the following cash requirements under these commitments (in millions):

 Finance Leases (1)

 $

 Operating Leases (1)

 Leases Effective, Not Commenced (1)

 Transportation and Storage Service Commitments (2) (3)

 Purchase and Service Obligations (3)

 Total Cash Requirements
 $
 1,923

 (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, 2024. 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 more information on transportation and storage service commitments and purchase and service obligations, see Note 8 to Consolidated Financial Statements.

 In 2025, EOG has $500 million aggregate principal amount of senior notes maturing, which are expected to be repaid with proceeds from its November 2024 Notes offering discussed above. Additionally in 2025, EOG expects to pay interest of $209 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 and other cash requirements, both in 2025 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 its $1.9 billion senior unsecured revolving credit 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 recoverable 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.

 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 the FASB's Fair Value Measurement Topic of the 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.

 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, 2024, WTI crude oil spot prices have fluctuated from approximately $(36.98) 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 judgement. 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 disclosures of impairments of oil and gas properties and other assets.

 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 and statements regarding the plans and objectives of EOG's management for future operations, 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 EOG's future financial or operating results and returns or 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 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 and other derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;

 • 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 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, 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;
 • the economic and financial impact of epidemics, pandemics or other public health issues;
 • 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, 2024. 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, 2024.

 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 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, 2024, 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, 2024, 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).

 ITEM 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspection

 None.

 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 other information required by this Item is incorporated by reference from (i) EOG's Definitive Proxy Statement with respect to its 2025 Annual Meeting of Stockholders to be filed not later than April 30, 2025 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 2025 Annual Meeting of Stockholders to be filed not later than April 30, 2025. 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 2025 Annual Meeting of Stockholders to be filed not later than April 30, 2025.

 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 from 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) under the Amended and Restated 2008 Plan and the 2021 Plan 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 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, 2024, 461,673 phantom shares had been issued. The Deferral Plan is currently EOG's only stock plan that has not been approved by EOG's stockholders.

 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, 2024.

 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
 2,642,192
 (2)

 $
 79.93
 14,413,459
 (3)

 Equity Compensation Plans Not Approved by EOG Stockholders
 358,846
 (4)

 N/A
 78,327
 (5)

 Total
 3,001,038

 14,491,786

 (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 performance units and restricted stock units with performance-based conditions (collectively, 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) 1,427,293 outstanding stock option and SAR grants, (ii) 655,656 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) 559,243 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 559,243 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 1,118,486 performance units could be outstanding and (B) accordingly, a minimum of 0 and a maximum of 1,118,486 shares of EOG common stock could be issued upon the vesting of such grants.
 (3)Consists of (i) 13,419,099 shares remaining available for issuance under the 2021 Plan and (ii) 994,360 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 from 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 358,846 phantom shares issued and outstanding under the Deferral Plan as of December 31, 2024).
 (5)Represents phantom shares that remain available for issuance under the Deferral Plan.

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

 The information required by this Item is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 2025 Annual Meeting of Stockholders to be filed not later than April 30, 2025.

 ITEM 14. Principal Accountant Fees and Services

 The information required by this Item is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 2025 Annual Meeting of Stockholders to be filed not later than April 30, 2025.

 ITEM 15. Exhibit 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.

 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, 2024
 F- 5

 Consolidated Balance Sheets - December 31, 2024 and 2023
 F- 6

 Consolidated Statements of Stockholders' Equity for Each of the Three Years in the Period Ended December 31, 2024
 F- 7

 Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2024
 F- 8

 Notes to Consolidated Financial Statements
 F- 9

 Supplemental Information to Consolidated Financial Statements
 F- 34

 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, 2024. 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, 2024.

 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 27, 2025

 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, 2024 and 2023, 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, 2024, 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, 2024, 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, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, 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, 2024, 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.

 Critical Audit Matter

 The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

 Proved Oil and Gas Properties and Depletion — 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). The development of the Company's estimated proved reserves volumes requires management to make significant estimates including 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 proved reserves quantities using these estimates along with estimates and assumptions related to engineering data. Changes in these estimates and assumptions could materially affect the estimated quantities of the Company's proved reserves, which in turn could have a significant impact on the amount of depletion expense. The proved oil and gas properties balance, net was $26.2 billion as of December 31, 2024, and depletion expense was $3.8 billion for the year then ended.

 Given the significant judgments made by management, performing audit procedures to evaluate the Company's estimated proved reserve quantities, including management's estimates and assumptions related to 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 proved reserve quantities and 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 proved 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 proved undeveloped reserves to producing properties to evaluate 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
 Comparing the forecasts to information included in Company press releases as well as in analyst and industry reports for the Company and certain of its peer companies
 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.

 /s/ DELOITTE & TOUCHE LLP

 Houston, Texas
 February 27, 2025

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

 CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
 (In Millions, Except Per Share Data)

 2024
 2023
 2022

 Operating Revenues and Other

 Crude Oil and Condensate
 $
 13,921
 $
 13,748
 $
 16,367

 Natural Gas Liquids
 2,106
 1,884
 2,648

 1,551
 1,744
 3,781

 Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net
 ( 3,982)

 Gathering, Processing and Marketing
 5,800
 5,806
 6,696

 Gains on Asset Dispositions, Net

 Total
 23,698
 24,186
 25,702

 Operating Expenses

 1,572
 1,454
 1,331

 1,722
 1,620
 1,587

 Marketing Costs
 5,717
 5,709
 6,535

 4,108
 3,492
 3,542

 Taxes Other Than Income
 1,249
 1,284
 1,585

 Total
 15,616
 14,583
 15,736

 Operating Income
 8,082
 9,603
 9,966

 Other Income, Net

 Income Before Interest Expense and Income Taxes
 8,356
 9,837
 10,080

 Interest Expense

 Incurred

 Capitalized
 ( 45)
 ( 33)
 ( 36)

 Income Before Income Taxes
 8,218
 9,689
 9,901

 1,815
 2,095
 2,142

 $
 6,403
 $
 7,594
 $
 7,759

 Net Income Per Share

 Basic
 $
 11.31
 $
 13.07
 $
 13.31

 Diluted
 $
 11.25
 $
 13.00
 $
 13.22

 Average Number of Common Shares

 Basic

 Diluted

 Comprehensive Income

 $
 6,403
 $
 7,594
 $
 7,759

 Other Comprehensive Income (Loss)

 Foreign Currency Translation Adjustments
 ( 1)

 Deferred Postretirement Plan
 —
 —

 Other Comprehensive Income (Loss)
 ( 1)

 Comprehensive Income
 $
 6,408
 $
 7,593
 $
 7,763

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

 CONSOLIDATED BALANCE SHEETS
 (In Millions, Except Share Data)

 At December 31
 2024
 2023

 ASSETS

 Current Assets

 Cash and Cash Equivalents
 $
 7,092
 $
 5,278

 Accounts Receivable, Net
 2,650
 2,716

 Inventories
 1,275

 Assets from Price Risk Management Activities
 —

 Other

 Total
 11,230
 9,935

 Property, Plant and Equipment

 Oil and Gas Properties (Successful Efforts Method)
 77,091
 72,090

 Other Property, Plant and Equipment
 6,418
 5,497

 Total Property, Plant and Equipment
 83,509
 77,587

 Less: Accumulated Depreciation, Depletion and Amortization
 ( 49,297)
 ( 45,290)

 Total Property, Plant and Equipment, Net
 34,212
 32,297

 Deferred Income Taxes

 Other Assets
 1,705
 1,583

 Total Assets
 $
 47,186
 $
 43,857

 LIABILITIES AND STOCKHOLDERS' EQUITY

 Current Liabilities

 Accounts Payable
 $
 2,464
 $
 2,437

 Accrued Taxes Payable
 1,007

 Dividends Payable

 Liabilities from Price Risk Management Activities
 —

 Current Portion of Long-Term Debt

 Current Portion of Operating Lease Liabilities

 Other

 Total
 5,354
 4,074

 Long-Term Debt
 4,220
 3,765

 Other Liabilities
 2,395
 2,526

 Deferred Income Taxes
 5,866
 5,402

 Commitments and Contingencies (Note 8)

 Stockholders' Equity

 Common Stock, $ 0.01 Par, 1,280,000,000 Shares Authorized and 588,939,584 Shares and 588,748,473 Shares Issued at December 31, 2024 and 2023, respectively

 Additional Paid in Capital
 6,090
 6,166

 Accumulated Other Comprehensive Loss
 ( 4)
 ( 9)

 Retained Earnings
 26,941
 22,634

 Common Stock Held in Treasury, 31,731,107 Shares and 7,888,105 Shares at December 31, 2024 and 2023, respectively

 ( 3,882)
 ( 907)

 Total Stockholders' Equity
 29,351
 28,090

 Total Liabilities and Stockholders' Equity
 $
 47,186
 $
 43,857

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

 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, 2021
 $
 $
 6,087
 $
 ( 12)
 $
 15,919
 $
 ( 20)
 $
 22,180

 —
 —
 —
 7,759
 —
 7,759

 Common Stock Issued Under Stock Plans

 —
 —
 —
 —

 Common Stock Dividends Declared, $ 8.875 Per Share

 —
 —
 —
 ( 5,206)
 —
 ( 5,206)

 Other Comprehensive Income
 —
 —
 —
 —

 Change in Treasury Stock - Stock Compensation Plans, Net

 —
 ( 55)
 —
 —
 ( 61)
 ( 116)

 Restricted Stock and Restricted Stock Units, Net

 —
 ( 2)
 —
 —
 —

 Stock-Based Compensation Expenses
 —
 —
 —
 —

 Treasury Stock Issued as Compensation
 —
 —
 —
 —

 Balance at December 31, 2022
 6,187
 ( 8)
 18,472
 ( 78)
 24,779

 —
 —
 —
 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)
 —
 —
 —

 Stock-Based Compensation Expenses
 —
 —
 —
 —

 Balance at December 31, 2023
 6,166
 ( 9)
 22,634
 ( 907)
 28,090

 —
 —
 —
 6,403
 —
 6,403

 Common Stock Dividends Declared, $ 3.705 Per Share

 —
 —
 —
 ( 2,096)
 —
 ( 2,096)

 Other Comprehensive Income
 —
 —
 —
 —

 Treasury Stock Repurchased
 —
 —
 —
 —
 ( 3,209)
 ( 3,209)

 Change in Treasury Stock - Stock Compensation Plans, Net

 —
 ( 43)
 —
 —
 ( 41)

 Restricted Stock and Restricted Stock Units, Net

 —
 ( 232)
 —
 —
 —

 Stock-Based Compensation Expenses
 —
 —
 —
 —

 Balance at December 31, 2024
 $
 $
 6,090
 $
 ( 4)
 $
 26,941
 $
 ( 3,882)
 $
 29,351

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

 CONSOLIDATED STATEMENTS OF CASH FLOWS
 (In Millions)

 2024
 2023
 2022

 Cash Flows from Operating Activities

 Reconciliation of Net Income to Net Cash Provided by Operating Activities:

 $
 6,403
 $
 7,594
 $
 7,759

 Items Not Requiring (Providing) Cash

 4,108
 3,492
 3,542

 Stock-Based Compensation Expenses

 Deferred Income Taxes
 ( 61)

 Gains on Asset Dispositions, Net
 ( 16)
 ( 95)
 ( 74)

 —

 Mark-to-Market Financial Commodity and Other Derivative Contracts

 (Gains) Losses, Net
 ( 204)
 ( 818)
 3,982

 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts
 ( 112)
 ( 3,501)

 —
 ( 2)

 Changes in Components of Working Capital and Other Assets and Liabilities

 Accounts Receivable
 ( 38)
 ( 347)

 Inventories
 ( 231)
 ( 534)

 Accounts Payable
 ( 36)
 ( 119)

 Accrued Taxes Payable
 ( 113)

 Other Assets
 ( 364)

 Other Liabilities
 ( 266)

 Changes in Components of Working Capital Associated with Investing Activities
 ( 382)

 Net Cash Provided by Operating Activities
 12,143
 11,340
 11,093

 Investing Cash Flows

 Additions to Oil and Gas Properties
 ( 5,353)
 ( 5,385)
 ( 4,619)

 Additions to Other Property, Plant and Equipment
 ( 1,019)
 ( 800)
 ( 381)

 Proceeds from Sales of Assets

 Other Investing Activities
 —
 —
 ( 30)

 Changes in Components of Working Capital Associated with Investing Activities
 ( 295)
 ( 375)

 Net Cash Used in Investing Activities
 ( 5,967)
 ( 6,340)
 ( 5,056)

 Financing Cash Flows

 Long-Term Debt Borrowings
 —
 —

 Long-Term Debt Repayments
 —
 ( 1,250)
 —

 Dividends Paid
 ( 2,087)
 ( 3,386)
 ( 5,148)

 Treasury Stock Purchased
 ( 3,246)
 ( 1,038)
 ( 118)

 Proceeds from Stock Options Exercised and Employee Stock Purchase Plan

 Debt Issuance Costs
 ( 2)
 ( 8)
 —

 Repayment of Finance Lease Liabilities
 ( 33)
 ( 32)
 ( 35)

 Net Cash Used in Financing Activities
 ( 4,361)
 ( 5,694)
 ( 5,273)

 Effect of Exchange Rate Changes on Cash
 ( 1)
 —
 ( 1)

 Increase (Decrease) in Cash and Cash Equivalents
 1,814
 ( 694)

 Cash and Cash Equivalents at Beginning of Year
 5,278
 5,972
 5,209

 Cash and Cash Equivalents at End of Year
 $
 7,092
 $
 5,278
 $
 5,972

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

 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. In addition, EOG is executing an abandonment and reclamation program in Canada. 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.

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

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

 Oil and gas exploration costs, other than the costs of drilling exploratory wells, are expensed as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether EOG has discovered commercial quantities of proved reserves. If commercial quantities of proved reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether commercial quantities of proved reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the estimated reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. The capitalized exploratory well costs that have been capitalized for a period of one year or greater were $ 0 million, $ 3 million and $ 0 million as of December 31, 2024, 2023 and 2022, 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.

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

 Oil and gas properties are grouped in accordance with the provisions of the Extractive Industries - Oil and Gas Topic of the Financial Accounting Standards Board (FASB) 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 FASB's Fair Value Measurement Topic of the 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, 2024 and 2023, were $ 2,184 million and $ 2,237 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.

 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 NGLs 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, 2024, 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 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.

 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.

 Segment Reporting. Effective January 1, 2024, EOG adopted the provisions of Accounting Standards Update (ASU) 2023-07 "Segment Reporting (Topic 820)," which updates reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses.

 Change in Presentation. Effective January 1, 2024, EOG combined Transportation Costs and Gathering and Processing Costs into one line item titled Gathering, Processing and Transportation Costs within the Consolidated Statements of Income and Comprehensive Income. This presentation has been conformed for all periods presented and had no impact on previously reported Net Income.

 Recently Issued Accounting Standards. In October 2023, the FASB issued ASU 2023-06, "Disclosure Improvements." The ASU incorporates several disclosure and presentation requirements currently residing in 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 will adopt ASU 2023-09 on a retrospective basis in the fourth quarter of 2025, and does not expect there to be a material impact on its consolidated financial statements; however, additional income tax disclosures may be required.

 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, however, the SEC voluntarily issued an administrative stay of the implementation of the rules, pending judicial review, and, in February 2025, requested the court to pause further judicial proceedings regarding the rules, pending the SEC's determination of the appropriate next steps.

 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.

 2. Long-Term Debt

 Long-Term Debt at December 31, 2024 and 2023 consisted of the following (in millions):

 2024
 2023

 3.15 % Senior Notes due 2025

 $
 $

 4.15 % Senior Notes due 2026

 6.65 % Senior Notes due 2028

 4.375 % Senior Notes due 2030

 3.90 % Senior Notes due 2035

 5.10 % Senior Notes due 2036

 4.950 % Senior Notes due 2050

 5.650 % Senior Notes due 2054

 1,000
 —

 Long-Term Debt

 4,640
 3,640

 Finance Leases (see Note 17)

 Less: Current Portion of Long-Term Debt

 Unamortized Debt Discount

 Debt Issuance Costs

 Total Long-Term Debt
 $
 4,220
 $
 3,765

 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, 2024, the aggregate annual maturities of current and long-term debt (excluding finance lease obligations) were $ 500 million in 2025, $ 750 million in 2026, zero in 2027, $ 140 million in 2028 and zero in 2029.

 At December 31, 2024 and 2023, EOG had no outstanding commercial paper borrowings and did not utilize any commercial paper borrowings during 2024 or 2023.

 On March 15, 2023, EOG repaid upon maturity the $ 1,250 million aggregate principal amount of its 2.625 % Senior Notes due 2023.

 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 will be used for general corporate purposes, including (i) the repayment of the $ 500 million aggregate principal amount of 3.15 % Senior Notes due 2025 and (ii) the funding of future capital expenditures.

 On June 7, 2023, EOG entered into a new $ 1.9 billion senior unsecured Revolving Credit Agreement (Agreement) with domestic and foreign lenders (Banks). The Agreement replaced EOG's $ 2.0 billion senior unsecured Revolving Credit Agreement, dated as of June 27, 2019, with domestic and foreign lenders, which had a scheduled maturity date of June 27, 2024, and which was terminated by EOG (without penalty), effective as of June 7, 2023, in connection with the completion of the Agreement.

 The Agreement has a scheduled maturity date of June 7, 2028, and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods subject to certain terms and conditions. The Agreement (i) commits the Banks to provide advances up to an aggregate principal amount of $ 1.9 billion at any one time outstanding, with an option for EOG to request increases in the aggregate commitments to an amount not to exceed $ 3.0 billion, subject to certain terms and conditions, and (ii) includes a swingline subfacility and a letter of credit subfacility. Advances under the Agreement will accrue interest based, at EOG's option, on either the Secured Overnight Financing Rate (SOFR) plus 0.1 % plus an applicable margin or the Base Rate (as defined in the Agreement) 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 Agreement 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 Agreement) of no greater than 65 %. At December 31, 2024, EOG was in compliance with this financial covenant. At December 31, 2024 and December 31, 2023, there were no borrowings or letters of credit outstanding under the Agreement. The SOFR and Base Rate (inclusive of the applicable margins), had there been any amounts borrowed under the Agreement at December 31, 2024, would have been 5.33 % and 7.50 %, respectively.

 3. Stockholders' Equity

 Common Stock. In November 2021, EOG's Board of Directors (Board) established a 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, 2024, EOG repurchased 25.8 million shares of common stock for approximately $ 3.2 billion (inclusive of transaction fees and commissions) pursuant to the Share Repurchase Authorization. As of December 31, 2024, approximately $ 5.8 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, 2024, is $ 30 million of estimated federal excise tax.

 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), the vesting of restricted stock, restricted stock unit or performance unit grants 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 27, 2025, the Board declared a quarterly cash dividend on the common stock of $ 0.975 per share to be paid on April 30, 2025, to stockholders of record as of April 16, 2025.

 The following summarizes Common Stock activity for each of the years ended December 31, 2024, 2023 and 2022 (in thousands):

 Common Shares

 Issued
 Treasury
 Outstanding

 Balance at December 31, 2021
 585,522
 ( 257)
 585,265

 Common Stock Issued Under Stock-Based Compensation Plans
 2,674
 —
 2,674

 Treasury Stock Purchased (1)

 —
 ( 997)
 ( 997)

 Common Stock Issued Under Employee Stock Purchase Plan
 —

 Treasury Stock Issued Under Stock-Based Compensation Plans
 —

 Balance at December 31, 2022
 588,397
 ( 700)
 587,697

 Common Stock Issued Under Stock-Based Compensation Plans
 —

 Treasury Stock Purchased (2)

 —
 ( 9,177)
 ( 9,177)

 Common Stock Issued Under Employee Stock Purchase Plan
 —

 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 (2)

 —
 ( 26,350)
 ( 26,350)

 Common Stock Issued Under Employee Stock Purchase Plan
 —

 Treasury Stock Issued Under Stock-Based Compensation Plans
 —
 2,507
 2,507

 Balance at December 31, 2024
 588,940
 ( 31,731)
 557,209

 (1) Represents shares 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.
 (2) 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, 2024, no shares of Series E Preferred Stock have been issued or are outstanding.

 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, 2024 and 2023 consisted of the following (in millions):

 Foreign Currency Translation Adjustment
 Other
 Total

 $
 ( 7)
 $
 ( 1)
 $
 ( 8)

 Other comprehensive loss before taxes
 ( 1)
 —
 ( 1)

 Tax effects
 —
 —
 —

 Other comprehensive loss
 ( 1)
 —
 ( 1)

 ( 8)
 ( 1)
 ( 9)

 Other comprehensive income before taxes

 Tax effects

 —
 —
 —

 Other comprehensive income

 $
 ( 4)
 $
 —
 $
 ( 4)

 No significant amount was reclassified out of Accumulated Other Comprehensive Loss during the years ended December 31, 2024 and 2023.

 5. Other Income, Net

 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). Other income, net for 2022 included interest income ($ 85 million) and equity income from investments in ammonia plants in Trinidad ($ 46 million), partially offset by an upward adjustment to deferred compensation expense ($ 15 million).

 6. Income Taxes

 The principal components of EOG's total net deferred income tax liabilities at December 31, 2024 and 2023 were as follows (in millions):

 2024
 2023

 Deferred Income Tax Assets (Liabilities)

 Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization

 $
 ( 56)
 $
 ( 26)

 Foreign Asset Retirement Obligations

 Foreign Accrued Expenses and Liabilities

 Foreign Net Operating Loss

 Foreign Valuation Allowances
 ( 131)
 ( 126)

 Foreign Other
 —

 Total Net Deferred Income Tax Assets
 $
 $

 Deferred Income Tax (Assets) Liabilities

 Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization

 $
 6,040
 $
 5,778

 Deferred Compensation Plans
 ( 65)
 ( 61)

 Equity Awards
 ( 65)
 ( 59)

 Corporate Alternative Minimum Tax
 —
 ( 212)

 Other
 ( 44)
 ( 44)

 Total Net Deferred Income Tax Liabilities
 $
 5,866
 $
 5,402

 Total Net Deferred Income Tax Liabilities
 $
 5,827
 $
 5,360

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

 2024
 2023
 2022

 $
 8,157
 $
 9,576
 $
 9,752

 Foreign

 Total
 $
 8,218
 $
 9,689
 $
 9,901

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

 2024
 2023
 2022

 Current:

 Federal
 $
 1,244
 $
 1,334
 $
 2,020

 State

 Foreign

 Total
 1,348
 1,415
 2,208

 Deferred:

 Federal
 ( 2)

 State
 ( 37)

 Foreign
 —
 ( 22)

 Total
 ( 61)

 Other Non-Current:

 Foreign
 —
 ( 3)
 ( 5)

 Total

 —
 ( 3)
 ( 5)

 $
 1,815
 $
 2,095
 $
 2,142

 The differences between taxes computed at the U.S. federal statutory tax rate and EOG's effective tax rate for the years indicated below were as follows:

 2024
 2023
 2022

 Statutory Federal Income Tax Rate
 %
 %
 %

 State Income Tax, Net of Federal Benefit

 Effective Income Tax Rate
 %
 %
 %

 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 foreign and state deferred tax assets that management does not believe are more likely than not to be realized.

 The principal components of EOG's rollforward of valuation allowances for deferred income tax assets for the years indicated below were as follows (in millions):

 2024
 2023
 2022

 Beginning Balance
 $
 $
 $

 Increase (1)

 Decrease (2)

 —
 —
 ( 33)

 Other (3)

 ( 30)
 ( 6)

 Ending Balance

 $
 $
 $

 (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, 2024, EOG has state income tax NOLs of approximately $ 1.8 billion. Certain state income tax NOLs have an indefinite carryforward and all others expire between 2025 and 2041. EOG also has foreign income tax NOLs of approximately $ 430 million. Certain foreign income tax NOLs can be carried forward up to 20 years and all others have an indefinite carryforward. 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.

 EOG accrued corporate alternative minimum tax (CAMT) of $ 212 million in 2023 which resulted in a tax credit that could be carried forward indefinitely to offset future regular federal income taxes. Prior to EOG filing its consolidated 2023 U.S. federal income tax return, the Internal Revenue Service issued additional guidance in the form of proposed CAMT regulations. EOG relied on this guidance and, as a result, the 2023 CAMT liability and associated tax credit carryforward decreased by $ 136 million. EOG utilized the remaining $ 76 million of the CAMT credit carryforward to reduce its regular federal income tax liability in 2024.

 The Inflation Reduction Act of 2022, among other things, allows a taxpayer to purchase transferable tax credits. In 2024, EOG purchased approximately $ 200 million of renewable energy tax credits from a third party which were used to offset tax year 2024 estimated tax payments. The cash payments made to the third party were included in income taxes, net of refunds received, as disclosed in Note 10.

 As of December 31, 2024, EOG does not have any unrecognized tax benefits. Consequently, no interest or penalties have been recognized in the Consolidated Statements of Income and Comprehensive Income. EOG does not expect its unrecognized tax benefits to change significantly in the next twelve months. EOG and its subsidiaries file income tax returns and are subject to tax audits in the U.S. and various state, local and foreign jurisdictions. EOG's earliest open tax years in its principal jurisdictions are generally as follows: U.S. federal (2021), Trinidad (2016), Canada (2020), Oman (2021) and Australia (2021).

 EOG's foreign subsidiaries' undistributed earnings are not considered to be permanently reinvested outside of the U.S. 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 U.S. 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 2024, 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.

 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, 2024, 2023 and 2022 was as follows (in millions):

 2024
 2023
 2022

 $
 $
 $

 Total
 $
 $
 $

 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, 2024, approximately 13 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 2024, 2023 and 2022, 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 $ 19 million, $ 32 million and $ 22 million for the years ended December 31, 2024, 2023 and 2022, respectively.

 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 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 10 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 $ 18 million, $ 24 million and $ 34 million for the years ended December 31, 2024, 2023 and 2022, 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 $ 160 million, $ 137 million and $ 88 million for the years ended December 31, 2024, 2023 and 2022, respectively.

 The following table sets forth the restricted stock and restricted stock unit transactions for the years ended December 31, 2024, 2023 and 2022 (shares and units in thousands):

 2024
 2023
 2022

 Number of Shares and Units
 Number of Shares and Units
 Number of Shares and Units

 Outstanding at January 1
 4,364
 $
 111.24
 4,113
 $
 80.77
 4,680
 $
 69.37

 Granted
 1,871
 122.45
 1,680
 131.10
 1,637
 113.21

 Released (1)

 ( 1,343)
 86.27
 ( 1,295)
 42.03
 ( 2,019)
 81.76

 Forfeited
 ( 193)
 116.18
 ( 134)
 93.54
 ( 185)
 68.89

 Outstanding at December 31 (2)

 4,699
 122.64
 4,364
 111.24
 4,113
 80.77

 (1)
 (1)The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2024, 2023 and 2022 was $ 166 million, $ 166 million and $ 223 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, 2024, 2023 and 2022 was $ 576 million, $ 528 million and $ 533 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, 2024, unrecognized compensation expense related to restricted stock and restricted stock units totaled $ 349 million. Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 1.8 years.

 Performance Units. EOG has granted Performance Units to its executive officers annually since 2012. 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 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 three-year performance period, a minimum of 0 % and a maximum of 200 % of the Performance Units granted could be outstanding.

 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 a three-year 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 three-year performance period. At the end of the three-year 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 three-year 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 three-year 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 three-year average ROCE.

 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 $ 12 million, $ 16 million and $ 11 million for the years ended December 31, 2024, 2023 and 2022, respectively.

 Weighted average fair values and valuation assumptions used to value Performance Units during the years ended December 31, 2024, 2023 and 2022 were as follows:

 2024
 2023
 2022

 Weighted Average Fair Value of Grants
 $
 130.31
 $
 142.20
 $
 126.55

 Expected Volatility
 35.20
 %
 44.76
 %
 56.11
 %

 Risk-Free Interest Rate
 3.46
 %
 4.53
 %
 4.01
 %

 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.

 The following table sets forth the Performance Unit transactions for the years ended December 31, 2024, 2023 and 2022 (units in thousands):

 2024
 2023
 2022

 Number of Units
 Number of Units
 Number of Units

 Outstanding at January 1
 $
 95.49
 $
 83.82
 $
 84.97

 Granted
 130.31
 142.20
 126.55

 Released (1)

 ( 45)
 43.33
 ( 86)
 79.98
 ( 57)
 136.74

 Forfeited for Performance Multiple (2)

 ( 135)
 43.33
 ( 86)
 79.98
 ( 56)
 136.74

 Outstanding at December 31 (3)

 (4)
 119.05
 95.49
 83.82

 (1)The total intrinsic value of Performance Units released during the years ended December 31, 2024, 2023 and 2022 was $ 5 million, $ 10 million and $ 7 million, respectively. The intrinsic value is based upon the closing price of the Common Stock on the date the Performance Units are released.
 (2)Upon completion of the Performance Period for the Performance Units granted in 2020, 2019 and 2018, a performance multiple of 25 %, 50 % and 50 %, respectively, was applied to each of the grants resulting in a forfeiture of Performance Units in February 2024, February 2023 and February 2022.
 (3)The total intrinsic value of Performance Units outstanding at December 31, 2024, 2023 and 2022 was $ 69 million, $ 76 million and $ 89 million, respectively.
 (4) 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 1,118 Performance Units could be outstanding.

 At December 31, 2024, unrecognized compensation expense related to Performance Units totaled $ 21 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 1.3 years.

 Upon completion of the Performance Period for the Performance Units granted in September 2021, a performance multiple of 125 % was applied to the grants resulting in an additional grant of 53,410 Performance Units in February 2025.

 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 $ 66 million, $ 61 million and $ 56 million for 2024, 2023 and 2022, 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 2024, 2023 and 2022, respectively.

 For the Trinidadian defined benefit pension plan, the benefit obligation, fair value of plan assets and (prepaid)/accrued benefit cost totaled $ 16 million, $ 17 million and $( 1.4) million, respectively, at December 31, 2024, and $ 16 million, $ 16 million and $( 0.9) million, respectively, at December 31, 2023.

 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.

 8. Commitments and Contingencies

 Letters of Credit and Guarantees. At December 31, 2024 and 2023, respectively, EOG had standby letters of credit and guarantees outstanding totaling $ 825 million and $ 907 million, primarily representing guarantees of payment or performance obligations on behalf of subsidiaries. As of February 21, 2025, EOG had received no demands for payment under these guarantees.

 Minimum Commitments. At December 31, 2024, 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, 2024, were as follows (in millions):

 Total Minimum
Commitments

 2025
 $
 1,520

 2026
 1,062

 2027

 2028

 2029

 2030 and beyond
 1,379

 $
 6,166

 Delivery Commitments. EOG sells crude oil, natural gas and purity products from its producing operations under a variety of contractual arrangements. At December 31, 2024, EOG was committed to deliver to multiple parties aggregate fixed quantities of crude oil of 2 million barrels (MMBbls) in 2025. At December 31, 2024, EOG was committed to deliver to multiple parties aggregate fixed quantities of natural gas of 342 billion cubic feet (Bcf) in 2025, 318 Bcf in 2026, 359 Bcf in 2027, 328 Bcf in 2028, 328 Bcf in 2029 and 3,474 Bcf thereafter. Additionally at December 31, 2024, EOG was committed to deliver to multiple parties aggregate fixed quantities of purity products of 15 MMBbls in 2025. 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.

 9. Net Income Per Share

 The following table sets forth the computation of Net Income Per Share for the years ended December 31, 2024, 2023 and 2022 (in millions, except per share data):

 2024
 2023
 2022

 Numerator for Basic and Diluted Earnings per Share -

 $
 6,403
 $
 7,594
 $
 7,759

 Denominator for Basic Earnings per Share -

 Weighted Average Shares

 Potential Dilutive Common Shares -

 Stock Options/SARs

 Restricted Stock/Units and Performance Units

 Denominator for Diluted Earnings per Share -

 Adjusted Diluted Weighted Average Shares

 Net Income Per Share

 Basic
 $
 11.31
 $
 13.07
 $
 13.31

 Diluted
 $
 11.25
 $
 13.00
 $
 13.22

 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, 1 million and 1 million for the years ended December 31, 2024, 2023 and 2022, respectively.

 10. Supplemental Cash Flow Information

 Net cash paid for interest and income taxes was as follows for the years ended December 31, 2024, 2023 and 2022 (in millions):

 2024
 2023
 2022

 Interest, Net of Capitalized Interest
 $
 $
 $

 Income Taxes, Net of Refunds Received
 $
 $
 1,229
 $
 2,475

 EOG's accrued capital expenditures and amounts recorded within accounts payable at December 31, 2024, 2023 and 2022 were $ 725 million, $ 631 million and $ 713 million, respectively.

 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.

 Non-cash investing activities for the year ended December 31, 2022, included additions of $ 153 million to EOG's oil and gas properties as a result of property exchanges.

 Cash paid for leases for the years ended December 31, 2024, 2023 and 2022, is disclosed in Note 17.

 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, General Counsel and Corporate Secretary, and the Senior Vice Presidents of 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, 2024, 2023 and 2022 (in millions):

 Other

 Total

 2024

 Crude Oil and Condensate
 $
 13,901
 $
 $
 —
 $
 13,921

 Natural Gas Liquids
 2,106
 —
 —
 2,106

 1,256
 —
 1,551

 Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net
 —
 —

 Gathering, Processing and Marketing
 5,799
 —
 5,800

 Gains (Losses) on Asset Dispositions, Net
 ( 5)
 —

 —
 —

 Operating Revenues and Other (2)

 23,387
 —
 23,698

 1,532
 —

 1,722
 —
 —

 Marketing Costs
 5,717
 —
 —

 3,968

 Taxes Other Than Income
 1,245

 Other Segment Items (3) (4)

 Operating Income (Loss)
 8,055
 ( 68)
 8,082

 Other Expense
 ( 3)

 Income Before Income Taxes
 8,218

 Other Segment Disclosures:

 Additions to Oil and Gas Properties, Excluding Dry Hole Costs

 5,213
 5,448

 Total Property, Plant and Equipment, Net
 33,690
 34,212

 Total Assets
 45,776
 1,220
 47,186

 —
 —

 Other

 Total

 2023

 Crude Oil and Condensate
 $
 13,734
 $
 $
 —
 $
 13,748

 Natural Gas Liquids
 1,884
 —
 —
 1,884

 1,530
 —
 1,744

 Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net
 —
 —

 Gathering, Processing and Marketing
 5,806
 —
 —
 5,806

 Gains on Asset Dispositions, Net
 —

 —
 —

 Operating Revenues and Other (5)

 23,916
 —
 24,186

 1,410

 1,620
 —
 —

 Marketing Costs
 5,709
 —
 —

 3,414
 —

 Taxes Other Than Income
 1,278
 —

 Other Segment Items (3) (6)

 Operating Income (Loss)
 9,516
 ( 37)
 9,603

 Other Expense
 ( 6)

 Income Before Income Taxes
 9,689

 Other Segment Disclosures:

 Additions to Oil and Gas Properties, Excluding Dry Hole Costs

 5,413
 5,579

 Total Property, Plant and Equipment, Net
 31,876
 32,297

 Total Assets
 42,674
 1,063
 43,857

 —
 —

 Other

 Total

 2022

 Crude Oil and Condensate
 $
 16,349
 $
 $
 —
 $
 16,367

 Natural Gas Liquids
 2,648
 —
 —
 2,648

 3,489
 —
 3,781

 Losses on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net
 ( 3,982)
 —
 —
 ( 3,982)

 Gathering, Processing and Marketing
 6,695
 —
 6,696

 Gains (Losses) on Asset Dispositions, Net
 ( 4)

 —
 —

 Operating Revenues and Other (7)

 25,394
 25,702

 1,294

 1,587
 —
 —

 Marketing Costs
 6,535
 —
 —

 3,469
 —

 Taxes Other Than Income
 1,575
 —

 Other Segment Items (3) (8)

 Operating Income (Loss)
 9,880
 ( 36)
 9,966

 Other Income

 Income Before Income Taxes
 9,901

 Other Segment Disclosures:

 Additions to Oil and Gas Properties, Excluding Dry Hole Costs
 4,599
 4,727

 Total Property, Plant and Equipment, Net
 29,109
 29,429

 Total Assets
 40,349
 41,371

 —
 —

 (1)Other International primarily consists of EOG's Australia and Canada operations. EOG is continuing the process of exiting its Canada operations. EOG exited Block 36 and Block 49 in Oman in 2023.
 (2)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.
 (3)Other Segment Items includes Exploration Costs, Dry Hole Costs and Impairments.
 (4)EOG recorded pretax impairment charges of $ 31 million in 2024 for proved oil and gas properties and firm commitment contracts related to its decision to exit the Horn River Basin in British Columbia, Canada, in the Other International segment. See Note 14.
 (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)EOG recorded pretax impairment charges of $ 18 million in 2023 for proved oil and gas properties and firm commitment contracts related to its decision to exit the Horn River Basin in British Columbia, Canada, in the Other International segment. See Note 14.
 (7)EOG had sales activity with three significant purchasers in 2022, one totaling $ 3.3 billion, another totaling $ 3.1 billion and a third totaling $ 3.0 billion of consolidated Operating Revenues and Other in the United States segment.
 (8)EOG recorded pretax impairment charges of $ 15 million in 2022 for proved oil and gas properties and firm commitment contracts related to its decision to exit the Horn River Basin in British Columbia, Canada, in the Other International segment. See Note 14.

 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 2024, 2023 and 2022, 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 2024, 2023 and 2022, EOG recognized net gains (losses) on the mark-to-market of financial commodity and other derivative contracts of $ 204 million, $ 818 million and $( 3,982) million, respectively, which included net cash received from (payments for) settlements of crude oil, NGLs and natural gas financial derivative contracts of $ 214 million, $( 112) million and $( 3,501) million, respectively.

 Presented below is a comprehensive summary of EOG's financial commodity derivative contracts settled during the year ended December 31, 2024 (closed) and remaining for 2025 and thereafter, as of December 31, 2024. Natural gas volumes are presented in MMBtu per day (MMBtud) and prices are presented in dollars per MMBtu ($/MMBtu).

 Natural Gas Financial Price Swap Contracts

 Contracts Sold

 Settlement Index
 Volume
(MMBtud in thousands)
 Weighted Average
Price ($/MMBtu)

 January - December 2024 (closed)
 $
 3.07

 January 2025 (closed)
 3.07

 February - December 2025
 3.07

 Natural Gas Basis Swap Contracts

 Contracts Sold

 Settlement Index
 Volume
(MMBtud in thousands)
 Weighted Average Price Differential
($/MMBtu)

 January - December 2024 (closed)
 NYMEX Henry Hub Houston Ship Channel (HSC) Differential (1)

 $
 0.00

 January - December 2025
 NYMEX Henry Hub HSC Differential
 0.00

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

 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, 2024 and 2023, 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,

 Location on Balance Sheet
 2024
 2023

 Asset Derivatives

 Crude oil, NGLs and natural gas financial derivative contracts -

 Current portion
 Assets from Price Risk Management Activities
 $
 —
 $

 Brent Crude Oil (Brent) Linked Gas Sales Contract -

 Noncurrent Portion
 Other Assets (1)

 —

 Liability Derivatives

 Crude oil, NGLs and natural gas financial derivative contracts -

 Current portion
 Liabilities from Price Risk Management Activities (2)

 $
 $
 —

 Noncurrent Portion
 Other Liabilities
 —

 (1) The noncurrent portion related to the Brent Linked Gas Sales Contract consists of gross assets of $ 110 million at December 31, 2024.
 (2) The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $ 117 million, partially offset by gross assets of $ 1 million at December 31, 2024.

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

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

 At December 31, 2024, EOG's net accounts receivable balance related to United States hydrocarbon sales included one receivable balance which accounted for more than 10% of the total balance. The receivable was due from a petroleum refining company. The related amount was collected during early 2025. At December 31, 2023, EOG's net accounts receivable balance related to United States hydrocarbon sales included three receivable balances, each of which accounted for more than 10% of the total balance. The receivables were due from three petroleum refining companies. The related amounts were collected during early 2024.

 In 2024 and 2023, all natural gas from EOG's Trinidad operations was sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary. In 2024 and 2023, all crude oil and condensate from EOG's Trinidad operations was sold to Heritage Petroleum Company Limited.

 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, 2024 and 2023. EOG had no collateral posted and held no collateral at December 31, 2024 and 2023.

 Substantially all of EOG's accounts receivable at December 31, 2024 and 2023 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, 2024, 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, 2024 and 2023 (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, 2024

 Financial Assets:

 Natural Gas Basis Swaps
 $
 —
 $
 $
 —
 $

 Brent Linked Gas Sales Contract
 —
 —

 Financial Liabilities:

 Natural Gas Swaps
 —
 —

 At December 31, 2023

 Financial Assets:

 Natural Gas Swaps
 $
 —
 $
 $
 —
 $

 Natural Gas Basis Swaps
 —
 —

 Financial Liabilities:

 Natural Gas Swaps
 —
 —

 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, 2024 and 2023.

 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 FASB's Fair Value Measurement Topic of the ASC (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.

 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 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.

 During 2022, proved oil and gas properties with a carrying amount of $ 146 million were written down to their fair value of $ 26 million, resulting in pretax impairment charges of $ 120 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, 2024 and 2023, respectively, EOG had outstanding $ 4,640 million and $ 3,640 million aggregate principal amount of senior notes, which had estimated fair values of $ 4,441 million and $ 3,574 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, 2024, 2023 and 2022 (in millions):

 2024
 2023
 2022

 Proved properties (1)

 $
 $
 $

 Unproved properties (2)

 Other assets

 Inventories
 —
 —

 Firm commitment contracts

 Total
 $
 $
 $

 (1) 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.

 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, 2024 and 2023 (in millions):

 2024
 2023

 Carrying Amount at Beginning of Period
 $
 1,506
 $
 1,328

 Liabilities Incurred

 Liabilities Settled (1)

 ( 62)
 ( 114)

 Accretion

 Revisions
 ( 83)

 Foreign Currency Translations
 ( 8)

 Carrying Amount at End of Period
 $
 1,460
 $
 1,506

 Current Portion
 $
 $

 Noncurrent Portion
 $
 1,391
 $
 1,469

 (1) 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 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.

 During 2022, EOG paid cash for property acquisitions of $ 393 million in the United States. Additionally during 2022, EOG recognized net gains on asset dispositions of $ 74 million and received proceeds of $ 349 million primarily due to the sale of certain legacy natural gas assets in the Rocky Mountain area, unproved leasehold in Texas and producing properties in the Mid-Continent area.

 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, 2024, 2023 and 2022 were as follows (in millions):

 2024
 2023
 2022

 Operating Lease Cost
 $
 $
 $

 Finance Lease Cost:

 Amortization of Lease Assets

 Interest on Lease Liabilities

 Variable Lease Cost

 Short-Term Lease Cost

 Total Lease Cost

 $
 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, 2024 and 2023 and supplemental information for the years ended December 31, 2024 and 2023 (in millions, except lease terms and discount rates):

 Location on Balance Sheet
 2024
 2023

 Assets

 Other Assets
 $
 1,005
 $

 Property, Plant and Equipment, Net (1)

 Total

 $
 1,146
 $
 1,144

 Liabilities

 Current

 Current Portion of Operating Lease Liabilities
 $
 $

 Current Portion of Long-Term Debt

 Long-Term

 Other Liabilities

 Long-Term Debt

 Total

 $
 1,190
 $
 1,184

 (1) Finance lease assets are recorded net of accumulated amortization of $ 219 million and $ 190 million at December 31, 2024 and 2023, respectively.

 2024
 2023

 Weighted Average Remaining Lease Term (in years):

 5.0
 5.3

 4.5
 5.5

 Weighted Average Discount Rate:

 4.6
 %
 4.3
 %

 2.6
 %
 2.6
 %

 Cash paid for leases for the years ended December 31, 2024, 2023 and 2022 was as follows (in millions):

 2024
 2023
 2022

 Repayment of Operating Lease Liabilities Associated with Operating Activities
 $
 $
 $

 Repayment of Operating Lease Liabilities Associated with Investing Activities

 Repayment of Finance Lease Liabilities

 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. Non-cash leasing activities for the year ended December 31, 2022, included the additions of $ 511 million of operating leases and no finance leases.

 At December 31, 2024, the future minimum lease payments under non-cancellable leases were as follows (in millions):

 2025
 $
 $

 2026

 2027

 2028

 2029

 2030 and beyond

 Total Lease Payments

 1,166

 Less: Discount to Present Value

 Total Lease Liabilities

 1,040

 Less: Current Portion of Lease Liabilities

 Long-Term Lease Liabilities

 $
 $

 At December 31, 2024, EOG had additional minimum lease payments of $ 117 million, which are expected to commence beginning in 2025 with lease terms of two to ten years.

 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. The proved natural gas reserves reported are inclusive of natural gas consumed in operations.

 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, 2024. 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.

 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, 2024, 2023 and 2022 were based on studies performed by the engineering staff of EOG. The Engineering and Acquisitions 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 five of whom are Registered Professional Engineers. The Vice President, Engineering and Acquisitions is the manager of this department and is the primary technical person responsible for this process. The Vice President, Engineering and Acquisitions holds a Bachelor of Science degree in Petroleum Engineering, has 39 years of experience in reserve evaluations and is a Registered Professional Engineer.

 EOG's reserves estimation process is a collaborative effort coordinated by the Engineering and Acquisitions 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, transportation costs, processing 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.

 Opinions by D&M for the years ended December 31, 2024, 2023 and 2022 covered producing areas containing 85%, 83% and 80%, 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 and Acquisitions 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 and Acquisitions Department of EOG. All reports by D&M were developed utilizing geological and engineering data provided by EOG. The report of D&M dated January 21, 2025, 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, 2024, 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, 2024, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2024, as estimated by the Engineering and Acquisitions Department of EOG:

 NET PROVED RESERVE SUMMARY

 Total

 NET PROVED RESERVES

 Crude Oil (MMBbl) (1)

 Net proved reserves at December 31, 2021
 1,546
 1,548

 —

 —

 —

 (21)
 —
 (21)

 (168)
 —
 (168)

 Net proved reserves at December 31, 2022
 1,659
 1,661

 —

 —

 —

 (7)
 —
 (7)

 (174)
 —
 (174)

 Net proved reserves at December 31, 2023
 1,754
 1,756

 —

 —

 —

 (8)
 —
 (8)

 (180)
 —
 (180)

 Net proved reserves at December 31, 2024
 1,868
 1,870

 Natural Gas Liquids (MMBbl) (1)

 Net proved reserves at December 31, 2021
 —

 —

 —

 —

 (14)
 —
 (14)

 (72)
 —
 (72)

 Net proved reserves at December 31, 2022
 1,145
 —
 1,145

 —

 —

 —

 (5)
 —
 (5)

 (82)
 —
 (82)

 Net proved reserves at December 31, 2023
 1,254
 —
 1,254

 —

 —

 —

 (3)
 —
 (3)

 (90)
 —
 (90)

 Net proved reserves at December 31, 2024
 1,358
 —
 1,358

 Total

 Natural Gas (Bcf) (2)

 Net proved reserves at December 31, 2021
 7,907
 8,222

 (271)
 (253)

 —

 1,414
 1,465

 (316)
 —
 (316)

 (493)
 (66)
 (559)

 Net proved reserves at December 31, 2022
 8,273
 8,591

 (327)
 (315)

 —

 1,287
 1,316

 (28)
 —
 (28)

 (578)
 (59)
 (637)

 Net proved reserves at December 31, 2023
 8,630
 8,930

 (202)
 (200)

 —

 1,098
 1,121

 (14)
 —
 (14)

 (644)
 (81)
 (725)

 Net proved reserves at December 31, 2024
 8,878
 9,122

 Total

 Oil Equivalents (MMBoe) (1)

 Net proved reserves at December 31, 2021
 3,693
 3,747

 Revisions of previous estimates (3)

 —

 Extensions, discoveries and other additions (4)

 (88)
 —
 (88)

 (322)
 (11)
 (333)

 Net proved reserves at December 31, 2022
 4,183
 4,238

 Revisions of previous estimates (3)

 —

 Extensions, discoveries and other additions (5)

 (17)
 —
 (17)

 (351)
 (10)
 (361)

 Net proved reserves at December 31, 2023
 4,447
 4,498

 Revisions of previous estimates (3)

 —

 Extensions, discoveries and other additions (6)

 (14)
 —
 (14)

 (377)
 (14)
 (391)

 Net proved reserves at December 31, 2024
 4,706
 4,748

 (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)See "Reconciliation of Revisions of Previous Estimates" below for additional discussion.
 (4)Change in net proved reserves for the year ended December 31, 2022, attributable to extensions, discoveries and other additions was 150 MMBoe greater than the corresponding change in PUDs for such year. Such difference represents new proved developed reserves attributable to wells drilled during 2022, primarily in the Permian Basin and Gulf Coast Basin, that did not have any associated PUDs recorded at the beginning of 2022. The reserves added as new PUDs for the year ended December 31, 2022, attributable to extensions and discoveries were 410 MMBoe and were primarily in the Permian Basin. See "Net Proved Undeveloped Reserves" below.
 (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.

 During 2024, EOG added 580 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 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.

 During 2022, EOG added 560 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin and Gulf Coast Basin. Approximately 56% of the 2022 reserve additions were crude oil and condensate and NGLs, and substantially all were in the United States. Sales in place of 88 MMBoe were primarily related to the sale of assets in the Rocky Mountain area 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 16 MMBoe were primarily related to the Permian Basin and the purchase or exchange of other producing assets.

 Total

 NET PROVED DEVELOPED RESERVES

 Crude Oil (MMBbl)

 —

 —

 —

 1,033
 —
 1,033

 Natural Gas Liquids (MMBbl)

 —

 —

 —

 —

 Natural Gas (Bcf)

 3,743
 3,874

 3,920
 4,057

 4,283
 4,444

 4,850
 4,994

 Oil Equivalents (MMBoe)

 1,926
 1,948

 2,162
 2,185

 2,322
 2,349

 2,542
 2,566

 NET PROVED UNDEVELOPED RESERVES

 Crude Oil (MMBbl)

 Natural Gas Liquids (MMBbl)

 —

 —

 —

 —

 Natural Gas (Bcf)

 4,164
 4,348

 4,353
 4,534

 4,347
 4,486

 4,028
 4,128

 Oil Equivalents (MMBoe)

 1,767
 1,799

 2,021
 2,053

 2,125
 2,149

 2,164
 2,182

 Net Proved Undeveloped Reserves. The following table presents the changes in EOG's total PUDs during 2024, 2023 and 2022 (in MMBoe):

 2024
 2023
 2022

 Balance at January 1
 2,149
 2,053
 1,799

 Extensions and Discoveries (1)

 Revisions (2)

 (66)
 (51)

 Acquisition of Reserves

 —

 Sale of Reserves

 (13)
 (9)
 (14)

 Conversion to Proved Developed Reserves

 (370)
 (360)
 (293)

 Balance at December 31
 2,182
 2,149
 2,053

 (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, 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 (see discussion of technology employed on pages F-34 - F-36 of this Annual Report on Form 10-K), 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 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, 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 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, 2022, total PUDs increased by 254 MMBoe to 2,053 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 385 MMBoe of PUDs. The PUD additions were primarily in the Permian Basin and 57% of the additions were crude oil and condensate and NGLs. During 2022, EOG drilled and transferred 293 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,286 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.

 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 83 MMBoe of PUD reserves to its net proved reserves for the year ended December 31, 2024 and a net positive revision of 45 MMBoe and 79 MMBoe of PUD reserves from its net proved reserves for the years ended December 31, 2023 and 2022, 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, 2024, 2023 and 2022.

 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
 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)
 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
 Upward revision attributable to decreased gathering, processing and transportation costs, resulting in an increase in reserves that are economically producible.

 Investments
 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

 Total Revisions
 (66)

 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
 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
 (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
 Revisions attributable to ownership interest changes.

 Changes in operating costs
 Upward revision attributable to decreased operating costs, resulting in an increase in reserves that are economically producible.

 Investments
 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
 (51)

 Year Ended December 31, 2022

 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
 See above related discussion.

 Evaluation of Inter-Related Factors

 Prices for crude oil, NGLs and natural gas
 Upward revisions attributable to an increase in the average prices used in EOG's year-end 2022 reserves estimates as compared to the average prices used in EOG's year-end 2021 reserves estimates.

 Well performance forecasts
 (9)
 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
 Upward revisions attributable to EOG's "ethane recovery" elections during 2022 - that is, EOG's elections to increase receipt of ethane (an NGL) from the natural gas stream and reduce the total volume of residue natural gas at the tailgate of the processing plant. The additional NGL reserves attributable to such elections outweigh the lower natural gas reserves.

 Ownership interest changes
 (2)
 Revisions attributable to ownership interest changes.

 Changes in operating costs
 (7)
 —
 Downward revision attributable to increased operating costs, resulting in a decrease in reserves that are economically producible.

 Net Revisions Attributable to Inter-Related Factors

 Total Revisions

 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, 2024 and 2023 (in millions):

 2024
 2023

 Proved properties
 $
 74,789
 $
 69,618

 Unproved properties
 2,302
 2,472

 Total
 77,091
 72,090

 Accumulated depreciation, depletion and amortization
 (47,155)
 (43,323)

 Net capitalized costs
 $
 29,936
 $
 28,767

 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.

 The following table sets forth costs incurred related to EOG's oil and gas activities for the years ended December 31, 2024, 2023 and 2022 (in millions):

 Other

 Total

 2024

 Acquisition Costs of Properties

 Unproved (2)

 $
 $
 —
 $
 $

 Proved (3)

 —
 —

 Subtotal
 —

 Development Costs (4)

 4,783
 4,942

 Total
 $
 5,331
 $
 $
 $
 5,634

 2023

 Acquisition Costs of Properties

 Unproved (5)

 $
 $
 —
 $
 —
 $

 Proved (6)

 —
 —

 Subtotal
 —
 —

 Development Costs (7)

 5,228
 5,358

 Total
 $
 5,821
 $
 $
 $
 6,018

 2022

 Acquisition Costs of Properties

 Unproved (8)

 $
 $
 —
 $
 —
 $

 Proved (9)

 —
 —

 Subtotal
 —
 —

 Development Costs (10)

 4,106
 4,260

 Total
 $
 4,974
 $
 $
 $
 5,229

 (1)Other International primarily consists of EOG's Australia and Canada Operations. EOG is continuing the process of exiting its Canada operations. EOG exited Block 36 and Block 49 in Oman in 2023.
 (2)Includes non-cash unproved leasehold acquisition costs of $85 million related to property exchanges.
 (3)Includes non-cash proved property acquisition costs of $24 million related to property exchanges.
 (4)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.
 (5)Includes non-cash unproved leasehold acquisition costs of $99 million related to property exchanges.
 (6)Includes non-cash proved property acquisition costs of $6 million related to property exchanges.
 (7)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.
 (8)Includes non-cash unproved leasehold acquisition costs of $127 million related to property exchanges.
 (9)Includes non-cash proved property acquisition costs of $26 million related to property exchanges.
 (10)Includes Asset Retirement Costs of $208 million, $81 million and $9 million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment.

 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, 2024, 2023 and 2022 (in millions):

 Other
 International (2)

 Total

 2024

 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues

 $
 17,263
 $
 $
 —
 $
 17,578

 Other
 —
 —

 Total

 17,362
 —
 17,677

 —

 Gathering, Processing and Transportation Costs (3)

 1,722
 —
 —
 1,722

 Production Costs
 2,741
 2,782

 3,765
 3,904

 Income (Loss) Before Income Taxes
 8,625
 (53)
 8,690

 1,887
 (3)
 1,890

 Results of Operations
 $
 6,738
 $
 $
 (50)
 $
 6,800

 2023

 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues

 $
 17,148
 $
 $
 —
 $
 17,376

 Other
 —
 —

 Total

 17,239
 —
 17,467

 —
 —

 Gathering, Processing and Transportation Costs (3)

 1,620
 —
 —
 1,620

 Production Costs
 2,657
 2,703

 —

 3,244
 —
 3,322

 Income (Loss) Before Income Taxes
 9,367
 (30)
 9,438

 2,056
 (2)
 2,062

 Results of Operations
 $
 7,311
 $
 $
 (28)
 $
 7,376

 2022

 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues

 $
 22,486
 $
 $
 —
 $
 22,796

 Other
 —
 —

 Total

 22,604
 —
 22,914

 Gathering, Processing and Transportation Costs (3)

 1,587
 —
 —
 1,587

 Production Costs
 2,833
 2,876

 3,314
 —
 3,386

 Income (Loss) Before Income Taxes
 14,363
 (28)
 14,479

 3,129
 (2)
 3,187

 Results of Operations
 $
 11,234
 $
 $
 (26)
 $
 11,292

 (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, 2024.
 (2)Other International primarily consists of EOG's Australia and Canada Operations. EOG is continuing the process of exiting its Canada operations. EOG exited Block 36 and Block 49 in Oman in 2023.
 (3)Effective January 1, 2024, EOG combined Transportation Costs and Gathering and Processing Costs into one line item titled Gathering, Processing and Transportation Costs.

 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, 2024, 2023 and 2022:

 Year Ended December 31, 2024
 $
 4.06
 $
 2.90
 $
 4.02

 Year Ended December 31, 2023
 $
 4.01
 $
 4.19
 $
 4.02

 Year Ended December 31, 2022
 $
 4.02
 $
 3.11
 $
 3.99

 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 and Acquisitions Department of EOG. The estimates were based on a 12-month average for commodity prices for the years 2024, 2023 and 2022. 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 table 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.

 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, 2024, 2023 and 2022 (in millions):

 Total

 2024

 Future cash inflows (1)

 $
 187,008
 $
 $
 187,949

 Future production costs
 (62,755)
 (269)
 (63,024)

 Future development costs (2)

 (19,228)
 (282)
 (19,510)

 Future income taxes
 (22,137)
 (20)
 (22,157)

 Future net cash flows
 82,888
 83,258

 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
 $
 $
 43,627

 2023

 Future cash inflows (3)

 $
 188,585
 $
 1,101
 $
 189,686

 Future production costs
 (65,349)
 (245)
 (65,594)

 Future development costs (4)

 (20,070)
 (406)
 (20,476)

 Future income taxes
 (21,632)
 (40)
 (21,672)

 Future net cash flows
 81,534
 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
 $
 $
 42,992

 2022

 Future cash inflows (5)

 $
 259,217
 $
 1,189
 $
 260,406

 Future production costs
 (58,021)
 (248)
 (58,269)

 Future development costs (6)

 (17,837)
 (471)
 (18,308)

 Future income taxes
 (39,560)
 (31)
 (39,591)

 Future net cash flows
 143,799
 144,238

 Discount to present value at 10% annual rate
 (69,587)
 (79)
 (69,666)

 Standardized measure of discounted future net cash flows relating to proved oil and gas reserves

 $
 74,212
 $
 $
 74,572

 (1)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.
 (2)Future abandonment costs included in 2024 future development costs for the United States and Trinidad were $1,989 million and $192 million, respectively.
 (3)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 NGL 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.
 (4)Future abandonment costs included in 2023 future development costs for the United States and Trinidad were $2,104 million and $193 million, respectively.
 (5)Estimated crude oil prices used to calculate 2022 future cash inflows for the United States and Trinidad were $96.44 and $85.90, respectively. Estimated NGLs price used to calculate 2022 future cash inflows for the United States was $36.35. Estimated natural gas prices used to calculate 2022 future cash inflows for the United States and Trinidad were $6.96 and $3.28, respectively.
 (6)Future abandonment costs included in 2022 future development costs for the United States and Trinidad were $1,578 million and $188 million, respectively.

 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, 2024 (in millions):

 Other

 Total

 $
 45,861
 $
 $
 —
 $
 46,186

 Sales and transfers of oil and gas produced, net of production costs

 (18,064)
 (269)
 (18,332)

 Net changes in prices and production costs
 30,987
 —
 31,073

 Extensions, discoveries, additions and improved recovery, net of related costs

 10,422
 —
 10,550

 Development costs incurred
 2,286
 —
 —
 2,286

 Revisions of estimated development cost
 (2,290)
 (70)
 —
 (2,360)

 Revisions of previous quantity estimates
 8,324
 —
 8,364

 Accretion of discount
 5,771
 —
 5,809

 Net change in income taxes
 (8,059)
 —
 (8,009)

 Purchases of reserves in place
 —
 —

 Sales of reserves in place
 (760)
 —
 —
 (760)

 Changes in timing and other
 (666)
 (1)
 (635)

 $
 74,212
 $
 $
 —
 $
 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)
 —
 (41,369)

 Extensions, discoveries, additions and improved recovery, net of related costs

 4,825
 —
 4,867

 Development costs incurred
 2,801
 —
 2,849

 Revisions of estimated development cost
 (644)
 —
 (631)

 Revisions of previous quantity estimates
 —

 Accretion of discount
 9,411
 —
 9,448

 Net change in income taxes
 9,250
 (18)
 —
 9,232

 Purchases of reserves in place
 —
 —

 Sales of reserves in place
 (294)
 —
 —
 (294)

 Changes in timing and other
 (3,069)
 —
 (3,067)

 $
 42,655
 $
 $
 —
 $
 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)
 —
 (1,662)

 Extensions, discoveries, additions and improved recovery, net of related costs

 5,442
 —
 5,476

 Development costs incurred
 2,609
 —
 2,637

 Revisions of estimated development cost
 1,197
 —
 1,271

 Revisions of previous quantity estimates
 —

 Accretion of discount
 5,331
 —
 5,367

 Net change in income taxes
 (253)
 —
 (244)

 Purchases of reserves in place
 —
 —

 Sales of reserves in place
 (102)
 —
 —
 (102)

 Changes in timing and other
 (54)
 —
 (16)

 $
 43,304
 $
 $
 —
 $
 43,626

 (1) Other International primarily consists of EOG's Australia and Canada Operations. EOG is continuing the process of exiting its Canada operations. EOG exited Block 36 and Block 49 in Oman in 2023.

 EXHIBITS

 Exhibits not incorporated herein by reference to a prior filing are designated by (i) an asterisk (*) and are filed herewith; or (ii) a pound sign (#) and are not filed herewith, and, 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 United States Securities and Exchange Commission (SEC) upon request.

 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 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 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 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 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 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 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

 #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 3.15% Senior Notes due 2025 of EOG (Exhibit 4.3 to EOG's Current Report on Form 8-K, filed March 19, 2015) (SEC File No. 001-09743).

 4.5(c)
 -
 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)).

 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 Restricted Stock Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made on or after September 28, 2020) (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2020) (SEC File No. 001-09743).

 10.1(c)+
 -
 Form of Restricted Stock Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made on or after September 28, 2020) (Exhibit 10.2 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2020) (SEC File No. 001-09743).

 10.1(d)+
 -
 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(e)+
 -
 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).

 E-2

 10.1(f)+
 -
 Form of Performance Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made on or after September 28, 2020) (Exhibit 10.4 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2020) (SEC File No. 001-09743).

 10.1(g)+
 -
 Form of Performance Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable solely to grant made to Ezra Y. Yacob effective January 4, 2021) (Exhibit 10.1(u) to EOG's Annual Report on Form 10-K for the year ended December 31, 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 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 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 prior to September 29, 2022) (Exhibit 10.4 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2021) (SEC File No. 001-09743).

 10.2(j)+
 -
 Restricted Stock Unit with Performance-Based Conditions ("Performance Unit") Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan, by and between EOG and William R. Thomas, effective September 27, 2021 (Exhibit 10.5 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2021) (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 (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(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 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(m)+
 -
 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 year ended December 31, 2023) (SEC File No. 001-09743).

 E-3

 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 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 year ended December 31, 2023) (SEC File No. 001-09743).

 10.2(o)+
 -
 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(p)+
 -
 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 year ended December 31, 2023) (SEC File No. 001-09743).

 10.2(q)
 -
 Form of Non-Employee Director Restricted Stock Unit Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (applicable to grants made prior to May 28, 2024) (Exhibit 10.6 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2021) (SEC File No. 001-09743).

 10.2(r)
 -
 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 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 year ended December 31, 2011) (originally filed as Exhibit 10.2(b) to EOG's Annual Report on Form 10-K for the 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 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 year ended December 31, 2020) (SEC File No. 001-09743).

 10.4(a)+
 -
 Amended and Restated Change of Control Agreement between EOG and Timothy K. Driggers, effective as of June 15, 2005 (Exhibit 99.11 to EOG's Current Report on Form 8-K, filed June 21, 2005) (SEC File No. 001-09743).

 10.4(b)+
 -
 First Amendment to Amended and Restated Change of Control Agreement between EOG and Timothy K. Driggers, effective as of April 30, 2009 (Exhibit 10.5 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2009) (SEC File No. 001-09743).

 10.4(c)+
 -
 Second Amendment to Amended and Restated Change of Control Agreement between EOG and Timothy K. Driggers, effective as of September 13, 2011 (Exhibit 10.4 to EOG's Current Report on Form 8-K, filed September 13, 2011) (SEC File No. 001-09743).

 10.4(d)+
 -
 Third Amendment to Amended and Restated Change of Control Agreement between EOG and Timothy K. Driggers, effective as of September 4, 2013 (Exhibit 10.6 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013) (SEC File No. 001-09743).

 10.5(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).

 E-4

 10.5(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).

 10.6(a)+
 -
 Change of Control Agreement by and between EOG and Lloyd W. Helms, effective as of June 27, 2013 (Exhibit 10.9 to EOG's Quarterly Report on Form 10-Q for the quarter ended June 30, 2013) (SEC File No. 001-09743).

 10.6(b)+
 -
 First Amendment to Change of Control Agreement between EOG and Lloyd W. Helms, Jr., effective as of September 4, 2013 (Exhibit 10.4 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013) (SEC File No. 001-09743).

 10.7+
 -
 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 year ended December 31, 2017) (SEC File No. 001-09743).

 10.8+
 -
 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).

 10.9+
 -
 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 year ended December 31, 2023) (SEC File No. 001-09743).

 10.10(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).

 10.10(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).

 10.11(a)+
 -
 EOG Resources, Inc. Amended and Restated Annual Bonus Plan (effective as of January 1, 2022) (Exhibit 10.2 to EOG's Current Report on Form 8-K, filed October 4, 2022) (SEC File No. 001-09743).

 10.11(b)+
 -
 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 year ended December 31, 2023) (SEC File No. 001-09743).

 10.12+
 -
 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).

 10.13
 -
 Revolving Credit Agreement, dated as of June 7, 2023, 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 June 12, 2023) (SEC File No. 001-09743).

 *19
 -
 EOG Resources, Inc. Insider Trading Policy (as updated effective February 6, 2025).

 *21
 -
 Subsidiaries of EOG, as of December 31, 2024.

 *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 year ended December 31, 2023) (SEC File No. 001-09743).

 *99.1
 -
 Opinion of DeGolyer and MacNaughton, dated January 21, 2025.

 E-5

 101.INS

 * **101.SCH
 -

 * **101.CAL
 -

 * **101.DEF
 -

 * **101.LAB
 -

 * **101.PRE
 -

 -

 *Exhibits filed herewith

 + Management contract, compensatory plan or arrangement

 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.

 (Registrant)

 Date:
 February 27, 2025
 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 27th day of February, 2025.

 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)

 *

 (Janet F. Clark)

 *

 (Charles R. Crisp)

 *

 (Robert P. Daniels)

 *

 (Lynn A. Dugle)

 *

 (C. Christopher Gaut)

 *

 (Michael T. Kerr)

 *

 (Julie J. Robertson)

 *

 (Donald F. Textor)

 *By:
 /s/ MICHAEL P. DONALDSON

 (Michael P. Donaldson)

 (Attorney-in-fact for persons indicated)