EDGAR 10-K Filing

Company CIK: 821189
Filing Year: 2025
Filename: 821189_10-K_2025_0000821189-25-000011.json

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ITEM 1. BUSINESS
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
Delaware Basin 309.7 184.9 1,039 395 385 375
South Texas 124.4 30.8 448 1,272 181 145
Rocky Mountain 41.7 14.9 149 776 42 45
Other Areas 14.8 15.3 92 915 33 40
Total 490.6 245.9 1,728 3,358 641 605
(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.
Year Ended December 31 2024 2023 2022
Crude Oil and Condensate Volumes (MMBbl) (1)
United States:
Delaware Basin 113.3 110.2 101.1
Eagle Ford Play 45.5 43.9 46.6
Other 20.8 19.4 20.3
United States 179.6 173.5 168.0
Trinidad 0.3 0.2 0.3
Total 179.9 173.7 168.3
Natural Gas Liquids Volumes (MMBbl) (1)
United States:
Delaware Basin 67.7 59.8 50.7
Eagle Ford Play 11.1 10.5 10.5
Other 11.2 11.4 10.9
United States 90.0 81.7 72.1
Total 90.0 81.7 72.1
Natural Gas Volumes (Bcf) (1)
United States:
Delaware Basin 380 325 279
Eagle Ford Play 53 50 52
Other 199 191 149
United States 632 566 480
Trinidad 81 59 66
Total 713 625 546
Crude Oil Equivalent Volumes (MMBoe) (2)
United States:
Delaware Basin 244.4 224.2 198.3
Eagle Ford Play 65.4 62.7 65.8
Other 65.2 62.6 56.0
United States 375.0 349.5 320.1
Trinidad 13.7 9.9 11.4
Total 388.7 359.4 331.5
Year Ended December 31 2024 2023 2022
Average Crude Oil and Condensate Prices ($/Bbl) (3)
United States $ 77.42 $ 79.18 $ 97.22
Trinidad 64.43 68.58 86.16
Composite 77.40 79.17 97.21
Average Natural Gas Liquids Prices ($/Bbl) (3)
United States $ 23.40 $ 23.07 $ 36.70
Composite 23.40 23.07 36.70
Average Natural Gas Prices ($/Mcf) (3)
United States $ 1.99 $ 2.70 $ 7.27
Trinidad 3.65 3.65 4.43 (4)
Composite 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 48 Chairman of the Board and Chief Executive Officer
Jeffrey R. Leitzell 45 Executive Vice President and Chief Operating Officer
Ann D. Janssen 60 Executive Vice President and Chief Financial Officer
Michael P. Donaldson 62 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.

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ITEM 1A. RISK FACTORS
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.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. Unresolved Staff Comments
Not applicable.

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ITEM 2. PROPERTIES
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
United States 1,770 1,429 2,789 1,929 4,559 3,358
Trinidad 102 77 191 110 293 187
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.
Crude Oil Natural Gas Total
Gross Net Gross Net Gross Net
United States 10,288 7,111 3,605 1,782 13,893 8,893
Trinidad 2 2 42 35 44 37
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
Crude Oil Natural Gas Dry Hole Total Crude Oil Natural Gas Dry Hole Total
United States
607 117 6 730 8 1 - 9
Trinidad
- 1 - 1 - 3 - 3
Total
607 118 6 731 8 4 - 12
United States 595 152 2 749 9 7 - 16
Trinidad - 2 - 2 - 1 - 1
Total 595 154 2 751 9 8 - 17
United States 462 133 11 606 3 - 8 11
Trinidad - - - - - 2 1 3
Total 462 133 11 606 3 2 9 14
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
Crude Oil Natural Gas Dry Hole Total Crude Oil Natural Gas Dry Hole Total
United States
527 101 5 633 7 1 - 8
Trinidad
- 1 - 1 - 3 - 3
Total
527 102 5 634 7 4 - 11
United States 490 135 2 627 7 6 - 13
Trinidad - 2 - 2 - 1 - 1
Total 490 137 2 629 7 7 - 14
United States 395 117 10 522 3 - 8 11
Trinidad - - - - - 2 1 3
Total 395 117 10 522 3 2 9 14
EOG participated in the drilling of wells that were in the process of being drilled or completed at the end of the period as set out in the table below for the years ended December 31, 2024, 2023 and 2022:
Wells in Progress at End of Period
2024 2023 2022
Gross Net Gross Net Gross Net
United States 243 213 254 212 251 213
Trinidad 2 1 3 3 1 1
Total 245 214 257 215 252 214
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
United States 170 140 156 132 122 98
Trinidad 1 1 1 1 - -
Total 171 141 157 133 122 98
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
United States
21 4 25 19 3 22
Total
21 4 25 19 3 22
United States 5 - 5 5 - 5
Total 5 - 5 5 - 5
United States 25 5 30 19 1 20
Total 25 5 30 19 1 20
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.

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ITEM 3. LEGAL PROCEEDINGS
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.

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. Mine Safety Disclosures
None.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
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:
Period
(a)
Total
Number of
Shares
Purchased (1)
(b)
Average
Price Paid
per Share (c)
Total Number of
Shares or Value of Shares Purchased as
Part of Publicly
Announced Plans or
Programs (2)
(d)
Approximate Dollar Value of Shares
that May Yet Be Purchased Under the Plans or Programs (3)
October 1, 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

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. Reserved

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
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. 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 $95 million in 2023.
Volume and price statistics for the years ended December 31, 2024, 2023 and 2022 were as follows:
Year Ended December 31 2024 2023 2022
Crude Oil and Condensate Volumes (MBbld) (1)
United States 490.6 475.2 460.7
Trinidad 0.8 0.6 0.6
Total 491.4 475.8 461.3
Average Crude Oil and Condensate Prices ($/Bbl) (2)
United States $ 77.42 $ 79.18 $ 97.22
Trinidad 64.43 68.58 86.16
Composite 77.40 79.17 97.21
Natural Gas Liquids Volumes (MBbld) (1)
United States 245.9 223.8 197.7
Total 245.9 223.8 197.7
Average Natural Gas Liquids Prices ($/Bbl) (2)
United States $ 23.40 $ 23.07 $ 36.70
Composite 23.40 23.07 36.70
Natural Gas Volumes (MMcfd) (1)
United States 1,728 1,551 1,315
Trinidad 220 160 180
Total 1,948 1,711 1,495
Average Natural Gas Prices ($/Mcf) (2)
United States $ 1.99 $ 2.70 $ 7.27
Trinidad 3.65 3.65 4.43 (4)
Composite 2.17 2.79 6.93
Crude Oil Equivalent Volumes (MBoed) (3)
United States 1,024.5 957.5 877.5
Trinidad 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:
Lease and Well $ 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
Interest Expense, Net 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):
Proved properties $ 295 $ 44
Unproved properties 63 125
Other assets 31 31
Firm commitment contracts 2 2
Total $ 391 $ 202
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 606 520 411
Leasehold Acquisitions (2)
230 207 186
Property Acquisitions (3)
33 16 419
Capitalized Interest 45 33 36
Subtotal 5,448 5,579 4,727
Exploration Costs 174 181 159
Dry Hole Costs 14 1 45
Exploration and Development Expenditures 5,636 5,761 4,931
Asset Retirement Costs (4)
(2) 257 298
Total Exploration and Development Expenditures 5,634 6,018 5,229
Other Property, Plant and Equipment (5)
1,019 800 381
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
Period Settlement Index Volume
(MMBtud in thousands) Weighted Average
Price ($/MMBtu)
January - December 2024 (closed) NYMEX Henry Hub 725 3.07
January - February 2025 (closed) NYMEX Henry Hub 725 3.07
March - December 2025 NYMEX Henry Hub 725 3.07
Natural Gas Basis Swap Contracts
Contracts Sold
Period Settlement Index Volume
(MMBtud in thousands) Weighted Average
Price Differential
($/MMBtu)
January - December 2024 (closed) NYMEX Henry Hub HSC Differential (1)
10 0.00
January - February 2025 (closed) NYMEX Henry Hub HSC Differential 10 0.00
March - December 2025 NYMEX Henry Hub HSC Differential 10 0.00
_________________
(1) This settlement index is used to fix the differential between pricing at the Houston Ship Channel and NYMEX Henry Hub prices.
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)
$ 35
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.
Impairments
Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties.
When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected undiscounted future cash flows at a DD&A group level to the unamortized capitalized cost of the group. If the expected undiscounted future cash flows, based on EOG's estimate of (and assumptions regarding) future crude oil, NGLs and natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data (all Level 3 inputs as defined by 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.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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."

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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 and is incorporated by reference herein.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.

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ITEM 9A. CONTROLS AND PROCEDURES
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 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 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.

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ITEM 9B. OTHER INFORMATION
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).

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
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.
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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.

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ITEM 11. EXECUTIVE COMPENSATION
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.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
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.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
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.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
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.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
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.
(a)(3), (b) Exhibits
See pages E-1 through E-6 for a listing of the exhibits.