10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2023

or

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

Commission file number: 1-9743

EOG RESOURCES, INC.

(Exact name of registrant as specified in its charter)

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

1111 Bagby, Sky Lobby 2, Houston, Texas   77002

(Address of principal executive offices)     (Zip Code)

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

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

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

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

None.

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

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

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

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

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

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

Smaller reporting company ☐    Emerging growth company ☐

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

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

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

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

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

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter.  Common Stock aggregate market value held by non-affiliates as of June 30, 2023: $66,533 million.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.  Class: Common Stock, par value $0.01 per share, 580,001,872 shares outstanding as of February 15, 2024.

Documents incorporated by reference.  Portions of the Definitive Proxy Statement for the registrant's 2024 Annual Meeting of Stockholders, to be filed within 120 days after December 31, 2023, are incorporated by reference into Part III of this report.

TABLE OF CONTENTS

		Page
PART I
ITEM 1.	Business	1
	General	1
	Exploration and Production	1
	Marketing	4
	Wellhead Volumes and Prices	5
	Human Capital Management	6
	Competition	7
	Regulation	7
	Other Matters	12
	Information About Our Executive Officers	13
ITEM 1A.	Risk Factors	15
ITEM 1B.	Unresolved Staff Comments	29
ITEM 1C.	Cybersecurity	29
ITEM 2.	Properties	30
	Oil and Gas Exploration and Production - Properties and Reserves	30
ITEM 3.	Legal Proceedings	33
ITEM 4.	Mine Safety Disclosures	33
PART II
ITEM 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	34
ITEM 6.	Reserved	36
ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	36
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk	53
ITEM 8.	Financial Statements and Supplementary Data	53
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	53
ITEM 9A.	Controls and Procedures	53
ITEM 9B.	Other Information	53
ITEM 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	53
PART III
ITEM 10.	Directors, Executive Officers and Corporate Governance	54
ITEM 11.	Executive Compensation	54
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	54
ITEM 13.	Certain Relationships and Related Transactions, and Director Independence	56
ITEM 14.	Principal Accounting Fees and Services	56
PART IV
ITEM 15.	Exhibit and Financial Statement Schedules	56
ITEM 16.	Form 10-K Summary	56
SIGNATURES

(i)

PART I

ITEM 1.  Business

General

EOG Resources, Inc., a Delaware corporation organized in 1985, together with its subsidiaries (collectively, EOG), explores for, develops, produces and markets crude oil, natural gas liquids (NGLs) and natural gas primarily in major producing basins in the United States of America (United States or U.S.), the Republic of Trinidad and Tobago (Trinidad) and, from time to time, select other international areas.  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, 2023, EOG's total estimated net proved reserves were 4,498 million barrels of oil equivalent (MMBoe), of which 1,756 million barrels (MMBbl) were crude oil and condensate reserves, 1,254 MMBbl were NGLs reserves and 8,930 billion cubic feet (Bcf), or 1,488 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 lowest-cost, highest-return and lowest-emissions producers, playing a significant role in the long-term future of energy. EOG operates under a consistent business and operational strategy that focuses predominantly on maximizing the rate of return on investment of capital by controlling operating costs and capital expenditures and maximizing reserve recoveries. Pursuant to this strategy, each prospective drilling location is evaluated by its estimated rate of return. This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-effective 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, to a lesser extent, natural gas plays.

At December 31, 2023, on a crude oil equivalent basis, 39% of EOG's net proved reserves in the United States were crude oil and condensate, 28% were NGLs and 33% were natural gas. The majority of these reserves are in long-lived fields with well-established production characteristics. EOG believes that 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.

1

The following is a summary of wellhead volume statistics and net well completions for the year ended December 31, 2023, total net acres at December 31, 2023, and expected net well completions planned for 2024 for certain areas of EOG's United States operations.

2023						2024
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	301.9	164.0	890	395	370	360
South Texas	126.0	32.4	436	1,155	200	170
Rocky Mountain	39.4	15.3	149	801	54	40
Other Areas	7.9	12.1	76	1,015	16	30
Total	475.2	223.8	1,551	3,366	640	600

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

In the Delaware Basin, EOG completed 370 net wells in 2023, primarily in the Wolfcamp, Bone Spring and Leonard plays. The Delaware Basin consists of approximately 4,800 feet of oil-rich stacked pay potential offering EOG multiple co-development opportunities throughout its 395,000 net acre position.

In the Wolfcamp play, EOG completed 188 net wells in 2023. EOG continued to focus on co-development of multiple Wolfcamp targets to maximize the value of the acreage. In 2024, the Wolfcamp play will continue to be a primary area of focus.

In the Bone Spring play, EOG has three main sub-plays: the First, Second and Third Bone Spring. In 2023, EOG completed 140 total net Bone Spring wells within the three sub-plays. Of the three sub-plays, the Second Bone Spring had the majority of the activity in 2023 with EOG completing 89 net wells. The Bone Spring play continues to be an integral part of EOG's Delaware Basin plans and portfolio.

In the Leonard play, EOG executed its development plan with 42 net wells completed in 2023. EOG continued co-development of multiple Leonard zones simultaneously, and expects the Leonard play to become a more active part of EOG's program in the next several years.

Activity in 2024 will remain focused on the Wolfcamp, Bone Spring, and Leonard plays, where EOG expects to complete approximately 360 net wells.

The South Texas area includes our Eagle Ford play and our 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 the Dorado gas play, EOG has continued to delineate the Eagle Ford and Austin Chalk formations with excellent results. In 2023, EOG completed 172 net wells in the Eagle Ford play, and 28 net wells in the Dorado gas play. In addition, key infrastructure was added in order to lower operating costs and increase price realizations. In 2024, EOG expects to complete approximately 145 net Eagle Ford play wells and 25 net Dorado wells, as well as completing major infrastructure projects to connect the Dorado gas play to the Agua Dulce gas market near Corpus Christi, Texas.

Activity in the Rocky Mountain area in 2023 was focused on the Wyoming Powder River Basin. In the Powder River Basin, EOG operated a two-rig program and completed 35 net wells in the Niobrara, Mowry, Turner and Parkman formations. In addition, key infrastructure was added in order to lower operating costs and increase price realizations. In addition, in the DJ Basin, EOG completed eight net wells in the Codell formation and, in the Williston Basin, EOG completed 11 net wells in the Bakken and Three Forks formations. In 2024, activity in the Rockies is expected to decrease. EOG plans to complete approximately 10 net Williston Basin wells, five net DJ Basin wells and 25 net wells in the Powder River Basin.

Activity in the Other Areas include EOG's newest play, the Utica play. EOG holds approximately 435,000 total net acres, including 135,000 net mineral acres in the Utica. In the Utica play, EOG has continued to test with excellent results. In 2023, EOG completed six net Utica wells. In 2024, EOG expects to complete approximately 20 net Utica wells.

2

Operations Outside the United States

EOG has operations offshore Trinidad and is making preparations to drill offshore Australia, as well as evaluating additional exploration, development and exploitation opportunities in these and other select international areas. In addition, EOG exited Block 36 and Block 49 in the Sultanate of Oman (Oman) and 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) Block, Pelican and Banyan Fields, Sercan Area and each of their related platforms and facilities and the Ska, Mento and Reggae and deep Teak, Saaman and Poui (TSP) 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, Modified U(a) Block, 4(a) Block, Banyan Field and Sercan Area have been developed and are producing natural gas and crude oil and condensate.

In March 2021, EOG signed a farmout agreement with Heritage Petroleum Company Limited (Heritage), which allows EOG to earn a 65% working interest in a portion of the contract area (EOG Area) governed by the Trinidad Northern Area License. The EOG Area is located offshore the southwest coast of Trinidad.

In 2023, EOG's net production in Trinidad averaged approximately 160 MMcfd of natural gas and approximately 0.6 MBbld of crude oil and condensate. In 2023, EOG successfully drilled and completed two developmental wells and one exploratory well in the Modified U(a) Block from the recently installed Osprey B platform. Additionally, EOG completed the design phase and commenced construction of the platform and related facilities in the Mento Area. Also, EOG sold its equity interest in its ammonia plant investments in the first quarter of 2023.

In 2024, EOG plans to complete the remaining wells in the current drilling program in the Modified U(a) Block. EOG also expects to drill and, if successful, complete two exploratory wells in the SECC Block. Additionally, EOG expects to recomplete two wells in the Sercan Area and drill one exploratory well in the TSP Area. Also, EOG plans to complete construction and installation of the platform and related facilities in the Mento Area.

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.

In 2023, EOG continued preparing for the drilling of an exploration well, the timing of which will depend on obtaining regulatory approvals and subsequent equipment availability.

Oman. In 2023, EOG completed the exit of Block 36 and Block 49 located in Oman.

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

3

Marketing

In 2023, EOG continued its diversified approach to marketing its wellhead crude oil and condensate production. The majority of EOG's United States wellhead 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 2023, 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 2024, the pricing mechanism for such production is expected to remain the same. At December 31, 2023, EOG was committed to deliver to multiple parties fixed quantities of crude oil of 7 MMBbls in 2024 and 1 MMBbls in 2025, all of which is expected to be sourced from future production of available reserves.

In 2023, EOG processed certain of its United States wellhead 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, such pricing mechanisms are expected to remain the same. In 2023, 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 2024, such pricing mechanism is expected to remain the same. At December 31, 2023, EOG was not committed to deliver fixed quantities of NGLs in 2024.

In 2023, consistent with its diversified marketing strategy, the majority of EOG's United States wellhead 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 2024, 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 2024. At December 31, 2023, EOG was committed to deliver to multiple parties fixed quantities of natural gas of 371 Bcf in 2024, 282 Bcf in 2025, 297 Bcf in 2026, 293 Bcf in 2027, 263 Bcf in 2028 and 3,277 Bcf thereafter, all of which is expected to be sourced from future production of available reserves.

In 2023, natural gas volumes from Trinidad were sold under a fixed price contract. In July 2022, EOG amended the natural gas sales contract with the National Gas Company of Trinidad and Tobago Limited and its subsidiary (NGC) to (i) extend the term to 2026 and (ii) effective September 1, 2020, provide for an increase in price realization if index prices for certain commodities exceed specified levels. Additionally in 2023, EOG entered into a separate fixed price contract with NGC to cover the volumes associated with an exploratory well to be drilled in 2024.

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 2023, three purchasers each accounted for more than 10% of EOG's total wellhead 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 materially adverse effect on its financial condition or results of operations.

4

Wellhead Volumes and Prices

The following table sets forth certain information regarding EOG's wellhead 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, 2023, 2022 and 2021. See ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations, for wellhead volumes on a per-day basis.

Year Ended December 31	2023	2022	2021
Crude Oil and Condensate Volumes (MMBbl) (1)
United States:
Delaware Basin	110.2	101.1	84.3
Eagle Ford Play	43.9	46.6	51.8
Other	19.4	20.3	25.7
United States	173.5	168.0	161.8
Trinidad	0.2	0.3	0.5
Other International (2)	—	—	—
Total	173.7	168.3	162.3
Natural Gas Liquids Volumes (MMBbl) (1)
United States:
Delaware Basin	59.8	50.7	30.9
Eagle Ford Play	10.5	10.5	9.0
Other	11.4	10.9	12.8
United States	81.7	72.1	52.7
Total	81.7	72.1	52.7
Natural Gas Volumes (Bcf) (1)
United States:
Delaware Basin	325	279	238
Eagle Ford Play	50	52	55
Other	191	149	149
United States	566	480	442
Trinidad	59	66	79
Other International (2)	—	—	3
Total	625	546	524
Crude Oil Equivalent Volumes (MMBoe) (3)
United States:
Delaware Basin	224.2	198.3	154.9
Eagle Ford Play	62.7	65.8	70.0
Other	62.6	56.0	63.3
United States	349.5	320.1	288.2
Trinidad	9.9	11.4	13.7
Other International (2)	—	—	0.6
Total	359.4	331.5	302.5

5

Year Ended December 31	2023		2022			2021
Average Crude Oil and Condensate Prices ($/Bbl) (4)
United States	$	79.18	$	97.22		$	68.54
Trinidad	68.58		86.16			56.26
Other International (2)	—		—			42.36
Composite	79.17		97.21			68.50
Average Natural Gas Liquids Prices ($/Bbl) (4)
United States	$	23.07	$	36.70		$	34.35
Composite	23.07		36.70			34.35
Average Natural Gas Prices ($/Mcf) (4)
United States	$	2.70	$	7.27		$	4.88
Trinidad	3.65		4.43		(5)	3.40
Other International (2)	—		—			5.67
Composite	2.79		6.93			4.66

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

(2)Other International includes EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. EOG is continuing the process of exiting its Canada operations.

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

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

(5)Includes positive revenue adjustment of $0.76 per Mcf ($0.09 per Mcf of EOG's composite wellhead 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, 2023, EOG employed approximately 3,050 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.

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 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 developing 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.

6

Diversity, Equity and Inclusion. EOG values gender, racial, ethnic and cultural diversity and works to foster a collaborative work environment of different talents, perspectives and experiences. EOG believes such diversity in background and experience, as well as an inclusive work environment, promotes diversity of thought, which helps foster creativity and drive innovation. EOG continues to raise employee awareness and provide leadership support to help advance diversity, equity and inclusion efforts within EOG. 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.

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 safety data and metrics to identify trends 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 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) required 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 competing 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 under constant review for amendment or expansion. 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.

7

A portion of EOG's oil and gas leases in New Mexico, North Dakota, Utah 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 our 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.

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 supporting EOG's operations in the Permian Basin in West Texas and New Mexico, the Powder River Basin in Wyoming, the Utica Shale in Ohio, the Fort Worth Basin Barnett Shale in North Texas, the Williston Basin Bakken and Three Forks plays 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 2023.

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.

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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. The U.S. EPA published proposed regulations specific to the calculation of such annual charge in January 2024. EOG does not currently expect such annual methane emissions charges to have a material impact on its 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 booster 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 December 2023, during the United Nations Climate Change Conference (COP 28 Conference), the U.S. EPA announced its final methane rules, which impose new methane emission requirements on the oil and gas industry, including our operations.

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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. The United States has 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 addition, many state and local officials have stated their intent to intensify 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, social and governance (ESG) 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 ESG 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.

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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 announced in December 2023. 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 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.

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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 19% in 2023, increased 42% in 2022 and increased 77% in 2021, each as compared to the immediately preceding year. Average NGLs prices received by EOG for production in the United States decreased 37% in 2023, increased 7% in 2022 and increased 156% in 2021, 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 63% decrease in 2023, a 49% increase in 2022, and a 203% increase in 2021, 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 2024 for each $1.00 per barrel increase or decrease in wellhead crude oil and condensate price, combined with the estimated change in NGLs price, is approximately $151 million for net income and $193 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 2024 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 wellhead natural gas price is approximately $27 million for net income and $35 million for pretax cash flows from operating activities. For a summary of EOG's financial commodity derivative contracts through February 16, 2024, see ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Financial Commodity Derivative Transactions. For a summary of EOG's financial commodity derivative contracts for the year ended December 31, 2023, 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 derivative contracts through February 16, 2024, see ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations ‑ Capital Resources and Liquidity - Financial Commodity 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.

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Insurance is maintained by EOG against some, 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 coverage provided by third-party insurers 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 coverage provided by third-party insurers 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 referenced above also providing certain coverage to EOG. 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 the risk of increases in taxes and governmental royalties, changes in laws and policies governing the operations of foreign-based companies, expropriation of assets, unilateral or forced renegotiation, modification or nullification of existing contracts with governmental entities, 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 22, 2024) are as follows:

Name	Age	Position
Ezra Y. Yacob	47	Chairman of the Board and Chief Executive Officer
Lloyd W. Helms, Jr.	66	President
Jeffrey R. Leitzell	44	Executive Vice President and Chief Operating Officer
Ann D. Janssen	59	Executive Vice President and Chief Financial Officer
Michael P. Donaldson	61	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.

Lloyd W. Helms, Jr. was elected President in October 2021. He served as President and Chief Operating Officer from October 2021 to December 2023. Mr. Helms served as Chief Operating Officer from December 2017 to December 2023 and as Executive Vice President, Exploration and Production from August 2013 to December 2017. He was elected Vice President, Engineering and Acquisitions in September 2006, Vice President and General Manager of EOG's Calgary, Alberta, Canada office in March 2008, and served as Executive Vice President, Operations from February 2012 to August 2013. Mr. Helms joined a predecessor of EOG in February 1981.

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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

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, political instability or armed conflict in oil and gas producing regions;

•the duration and economic and financial impact of epidemics, pandemics or other public health issues, such as the COVID-19 pandemic;

•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 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; and

•natural disasters, weather conditions and changes in weather patterns.

The above-described factors and the volatility of commodity prices make it difficult to predict crude oil, NGLs and natural gas prices in 2024 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.

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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 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 write down 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 three months 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 in 2023, 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 such inflationary pressures. 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. 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. Any of these factors could have a material and adverse effect on our business, financial condition and results of operations.

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.

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In addition, companies in the oil and gas sector may be exposed to increasing reputational risks and, in turn, certain financial risks. Specifically, certain financial institutions (including certain 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; such trend may be accelerated by the extensive climate-related disclosure requirements discussed below. Further, additional financial institutions and other investors may elect to do likewise in the future 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 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, 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. Our actual reserves and future net cash flows from such reserves most likely will vary from our estimates. Any significant variance, including any significant downward revisions to our existing reserve estimates, could materially and adversely affect our business, financial condition and results of operations and, in turn, the trading price of our common stock. For related discussion, see ITEM 2, Properties - Oil and Gas Exploration and Production - Properties and Reserves and Supplemental Information to Consolidated Financial Statements.

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

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

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

Regular and special dividends on 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;

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

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•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 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 that allows for the repurchase by us of up to $5 billion of our common stock (November 2021 Authorization). Beginning in March 2023, we have repurchased shares from time to time under the November 2021 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 November 2021 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 2024 is subject to fluctuating market prices. To the extent we do not hedge our production volumes for 2024 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.

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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, including development 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 conditions, such as winter storms, flooding, tropical storms and hurricanes, and changes in weather patterns, 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, tropical storms and hurricanes, and other natural disasters, which may be exacerbated by climate change;

•fires and explosions;

•terrorism, vandalism and physical, electronic and cybersecurity breaches;

•formations with abnormal or unexpected pressures;

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•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 additional 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 and penalties as well as cleanup and remediation responsibilities and costs;

•suspension or interruption of our operations, including due to injunction;

•repairs necessary to resume operations; 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, 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.

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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.

We have limited control over the activities on properties that we do not operate.

Some of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. In addition, a third-party operator could also decide to shut-in or curtail production from wells, or plug and abandon marginal wells, on properties owned by that operator during periods of lower crude oil, NGLs or natural gas prices. These limitations and our dependence on the operator and third-party working interest owners for these projects could cause us to incur unexpected future costs, lower production and materially and adversely affect 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 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 competing energy sources, such as renewable energy sources.

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Risks Related to ESG/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 2022, the U.S. Securities and Exchange Commission (SEC) proposed extensive climate-related disclosure requirements that, if adopted, would require U.S. public companies to significantly expand the climate-related disclosures in their SEC filings, (ii) in September 2023, California passed climate-related disclosure mandates which are broader than the SEC’s proposed 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 extensive climate-related disclosure requirements 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.

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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 announced in December 2023. Further, our operations are subject to the proposed methane “Waste Emissions Charge” rule, published in January 2024 as part of the Methane Emissions Reduction Program implemented under the Inflation Reduction Act of 2022.

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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 addition, many state and local officials have stated their intent to intensify 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 ESG matters, including our related public statements and disclosures, may expose us to certain risks.

We have developed, and will continue to develop, targets and ambitions related to our environmental, social and governance (ESG) 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.

Our ability to achieve our ESG-related targets and ambitions is subject to numerous factors and conditions, some of which are outside of our control and include evolving government regulation, potential revisions to emissions estimates as measurement technologies advance or due to changes in protocol or methodologies, 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.

In addition, the pursuit and achievement of our current or future initiatives, targets and ambitions relating to the reduction of GHG emissions may increase our costs, including 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. Such initiatives, targets and ambitions are also subject to business, regulatory, economic and competitive uncertainties and contingencies, and required advancements in technology. Also, our continuing efforts to research, establish, accomplish and accurately report on our emissions and other ESG-related initiatives, targets and ambitions may create additional operational risks and expenses and expose us to reputational, legal and other risks.

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Further, investor and regulatory focus on ESG matters continues to increase. In addition to climate change, there is increasing investor and regulatory attention and focus on topics such as diversity and inclusion, human rights and human capital management, in companies’ own operations as well as across their supply chains. If our ESG-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.

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. In addition, certain countries, including countries where EOG is currently conducting business or may in the future conduct business, have advocated for the implementation (via legislation) of a global minimum tax.

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 (i) what the specific provisions or the effective date of any such enacted legislation would be or (ii) in the case of a global minimum tax or similar tax, which countries or other jurisdictions would participate and enact applicable legislation.

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 global minimum tax or similar tax), could, if adopted, 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.

In August 2022, President Biden signed into law the Inflation Reduction Act (IRA), which, among other changes, imposes a 15% corporate alternative minimum tax (CAMT) on the "adjusted financial statement income" of certain large corporations (generally, corporations reporting at least $1 billion average adjusted financial statement net income). To the extent we are subject to the CAMT, our cash obligations for U.S. federal income taxes could be accelerated. The U.S. Treasury Department, the Internal Revenue Service and other standard-setting bodies are expected to continue to issue guidance on how the CAMT and other provisions of the IRA will be applied or otherwise administered which may differ from our interpretations. We continue to evaluate the IRA and its effect on our financial condition and cash flows.

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;

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•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.

Unfavorable currency exchange rate fluctuations could materially and adversely affect our results of operations.

The reporting currency for our consolidated financial statements is the U.S. dollar. However, certain of our subsidiaries are located in countries other than the U.S. and have functional currencies other than the U.S. dollar. The assets, liabilities, revenues and expenses of certain of these foreign subsidiaries are denominated in currencies other than the U.S. dollar. To prepare our consolidated financial statements, we must translate those assets, liabilities, revenues and expenses into U.S. dollars at then-applicable exchange rates. Consequently, increases and decreases in the value of the U.S. dollar versus other currencies will affect the amount of these items in our consolidated financial statements, even if the amount has not changed in the original currency. These translations could result in changes to our results of operations from period to period. For the fiscal year ended December 31, 2023, EOG had no net operating revenues related to operations of our foreign subsidiaries whose functional currency was not the U.S. dollar.

Risks Related to Cybersecurity, Outbreaks/Pandemics and Other External Factors

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

As an oil and gas producer, we face various security threats, including (i) cybersecurity 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 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 cybersecurity threats, such measures cannot entirely eliminate cybersecurity 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 cybersecurity attacks, including, without limitation, denial-of-service attacks; malicious software; data privacy breaches by employees, insiders or others with authorized access; cyber or phishing-attacks; ransomware; attempts to gain unauthorized access to our data and systems; and other electronic security breaches. 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:

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

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

•a cybersecurity 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 cybersecurity 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 cybersecurity 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 cybersecurity 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 cybersecurity incidents in the past, we have not had, to date, any business interruptions or material losses from breaches of cybersecurity. However, there is no assurance that we will not suffer any such interruptions or losses in the future. Further, as technologies evolve and cybersecurity 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 cybersecurity 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 cybersecurity incidents and cybersecurity risk management, strategy and governance, which could require us to expend significant additional resources to meet such requirements.

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Outbreaks of communicable diseases can adversely affect our business, financial condition and results of operations.

Global or national health concerns, including a widespread outbreak of contagious disease, can, among other impacts, negatively impact the global economy, reduce demand and pricing for crude oil, NGLs and natural gas, lead to operational disruptions and limit our ability to execute on our business plan, any of which could materially and adversely affect our business, financial condition and results of operations. Furthermore, uncertainty regarding the impact of any outbreak of contagious disease could lead to increased volatility in crude oil, NGLs and natural gas prices.

In the event of a future outbreak or pandemic, we may experience disruptions to commodities markets, equipment supply chains and the availability of our workforce, which could materially and adversely affect our ability to conduct our business and operations. In addition, if such a future outbreak or pandemic results in an economic downturn, our customers and other contractual parties may be unable to pay amounts owed to us from time to time and to otherwise satisfy their contractual obligations to us, and may be unable to access the credit and capital markets for such purposes. Such inability of our customers and other contractual counterparties may materially and adversely affect our business, financial condition, results of operations and cash flows.

There would be many variables and uncertainties associated with any future outbreak or pandemic, including (but not limited to) the duration and severity of the outbreak; the extent of travel restrictions, business closures and other measures imposed by governmental authorities; increased risk of cyberattacks on information technology systems used in remote working arrangements; absence of employees due to illness; the impact of the pandemic on EOG's customers and contractual counterparties; and other factors that may be currently unknown or considered immaterial, to fully assess the potential impact on our business, financial condition and results of operations.

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.

Weather and climate may have a significant and adverse impact on us.

Demand for crude oil and natural gas is, to a degree, dependent on weather and climate, which impacts, among other things, the price we receive for the commodities that we produce and, in turn, our cash flows and results of operations. For example, relatively warm temperatures during a winter season generally result in relatively lower demand for natural gas (as less natural gas is used to heat residences and businesses) and, as a result, lower prices for natural gas production during that season.

In addition, there has been public discussion that climate change may be associated with more frequent or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other related phenomena, which could affect some, or all, of our operations. Our exploration, exploitation and development activities and equipment could be adversely affected by extreme weather events, such as winter storms, flooding and tropical storms and hurricanes, which may cause a loss of production from temporary cessation of activity or damaged facilities and equipment. Such extreme weather events could also impact other areas of our operations, including access to our drilling and production facilities for routine operations, maintenance and repairs, the installation and operation of gathering, processing, compression, storage and/or transportation facilities and the availability of, and our access to, necessary third-party services and facilities, such as gathering, processing, compression, storage, transportation and export services and facilities. Such extreme weather events and changes in weather patterns may materially and adversely affect our business and, in turn, our financial condition and results of operations.

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ITEM 1B.  Unresolved Staff Comments

Not applicable.

ITEM 1C. Cybersecurity

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

Cyber Risk Management & Strategy

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

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

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

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

In addition, EOG's internal audit function, in conjunction with third-party experts, play a key role in reviewing and assessing EOG's cybersecurity technologies, controls and procedures, including conducting penetration testing and vulnerability assessments.

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

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

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

Cyber Expertise & Experience

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

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

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Cyber Governance & Oversight

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

EOG's cybersecurity team leadership, Senior Vice President and Chief Information and Technology Officer and other members of senior management regularly report to EOG's Audit Committee and Board of Directors (Board) regarding cybersecurity matters, including the assessments performed regarding EOG's cybersecurity technologies, controls and procedures.

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

ITEM 2.  Properties

Oil and Gas Exploration and Production - Properties and Reserves

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

There are numerous uncertainties inherent in estimating quantities of reserves and in projecting future rates of production and 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, 2023 (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	1,869	1,500	2,747	1,866	4,616	3,366
Trinidad	77	65	238	139	315	204
Australia	—	—	1,009	1,009	1,009	1,009
Total	1,946	1,565	3,994	3,014	5,940	4,579

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Most of our 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 2024, 0.1 million net acres will expire in 2025 and 1.1 million net acres will expire in 2026 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, 2023, 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 our evaluations of certain geologic trends and prospective economics, we have allowed certain lease acreage to expire and may allow additional acreage to expire in the future.

Many of our oil and gas leases are large enough to accommodate more than one producing unit. Included in our 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 depending on EOG's decision to move forward with its defined work program or unless EOG is either granted a production license or an extension of the permit.

Productive Well Summary. The following table represents EOG's gross and net productive wells at December 31, 2023, including 2,868 wells in which we hold a royalty interest.

	Crude Oil		Natural Gas		Total
	Gross	Net	Gross	Net	Gross	Net
United States	9,475	6,652	3,595	1,772	13,070	8,424
Trinidad	2	2	38	32	40	34
Total (1)	9,477	6,654	3,633	1,804	13,110	8,458

(1)    EOG operated 9,304 gross and 8,291 net producing crude oil and natural gas wells at December 31, 2023. Gross crude oil and natural gas wells include 58 wells with multiple completions.

Drilling and Acquisition Activities.  During the years ended December 31, 2023, 2022 and 2021, EOG expended $6.0 billion, $5.2 billion and $4.0 billion, respectively, for exploratory and development drilling, facilities and acquisition of leases and producing properties, including asset retirement costs of $257 million, $298 million and $127 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, 2023, 2022 and 2021:

	Gross Development Wells Completed				Gross Exploratory Wells Completed
	Crude Oil	Natural Gas	Dry Hole	Total	Crude Oil	Natural Gas	Dry Hole	Total
2023
United States	595	152	2	749	9	7	—	16
Trinidad	—	2	—	2	—	1	—	1
Total	595	154	2	751	9	8	—	17
2022
United States	462	133	11	606	3	—	8	11
Trinidad	—	—	—	—	—	2	1	3
Total	462	133	11	606	3	2	9	14
2021
United States	474	72	5	551	10	1	1	12
Trinidad	—	—	—	—	—	—	—	—
Oman	—	—	—	—	—	—	3	3
Total	474	72	5	551	10	1	4	15

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The following tables set forth the results of the net crude oil and natural gas wells completed for the years ended December 31, 2023, 2022 and 2021:

	Net Development Wells Completed				Net Exploratory Wells Completed
	Crude Oil	Natural Gas	Dry Hole	Total	Crude Oil	Natural Gas	Dry Hole	Total
2023
United States	490	135	2	627	7	6	—	13
Trinidad	—	2	—	2	—	1	—	1
Total	490	137	2	629	7	7	—	14
2022
United States	395	117	10	522	3	—	8	11
Trinidad	—	—	—	—	—	2	1	3
Total	395	117	10	522	3	2	9	14
2021
United States	434	66	4	504	10	1	1	12
Trinidad	—	—	—	—	—	—	—	—
Oman	—	—	—	—	—	—	3	3
Total	434	66	4	504	10	1	4	15

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, 2023, 2022 and 2021:

	Wells in Progress at End of Period
	2023		2022		2021
	Gross	Net	Gross	Net	Gross	Net
United States	254	212	251	213	191	167
Trinidad	3	3	1	1	1	1
Total	257	215	252	214	192	168

Included in the previous 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, 2023, there were approximately 134 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
	2023		2022		2021
	Gross	Net	Gross	Net	Gross	Net
United States	156	132	122	98	121	105
Trinidad	1	1	—	—	—	—
Total	157	133	122	98	121	105

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EOG acquired wells as set forth in the following table (excluding the acquisition of additional interests in 4, 74 and 5 net wells in which EOG previously owned an interest for the years ended December 31, 2023, 2022 and 2021, respectively) for the years ended December 31, 2023, 2022 and 2021:

	Gross Acquired Wells			Net Acquired Wells
	Crude Oil	Natural Gas	Total	Crude Oil	Natural Gas	Total
2023
United States	5	—	5	5	—	5
Total	5	—	5	5	—	5
2022
United States	25	5	30	19	1	20
Total	25	5	30	19	1	20
2021
United States	2	14	16	1	13	14
Total	2	14	16	1	13	14

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

ITEM 3.  Legal Proceedings

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

Item 103 of Regulation S-K promulgated under the Securities Exchange Act of 1934, as amended, requires disclosure regarding certain proceedings arising under federal, state or local environmental laws when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that EOG reasonably believes will exceed a specified threshold. Pursuant to this item, EOG uses a threshold of $1 million for purposes of determining whether disclosure of any such proceedings is required; EOG believes proceedings under this threshold are not material to EOG's business and financial condition (the choice of this threshold does not imply that matters with potential monetary sanctions in excess of $1 million are necessarily material to EOG's business or financial condition). Applying this threshold, there are no environmental proceedings to disclose for the quarter and year ended December 31, 2023.

ITEM 4.  Mine Safety Disclosures

None.

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PART II

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

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

As of February 15, 2024, there were approximately 3,000 record holders and approximately 1,093,000 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, 2023 - October 31, 2023	59,602	$	129.19	$	—	$	4,328,867,620
November 1, 2023 - November 30, 2023	1,198,980	122.96		145,760,313		4,183,107,307
December 1, 2023 - December 31, 2023	1,269,005	122.49		154,239,583		4,028,867,724
Total	2,527,587	122.87		299,999,896

(1)Includes 2,444,880 shares repurchased during the quarter ended December 31, 2023, at an average price of $122.71 per share (inclusive of commissions and transaction fees), pursuant to the November 2021 Authorization (as defined and further discussed below); such repurchases count against the November 2021 Authorization. The share repurchases during December 2023 were made pursuant to a Rule 10b5-1 trading plan entered into by EOG on December 1, 2023 (prior to the opening of trading on such day).

Also includes 82,707 total shares that were withheld by or returned to EOG during the quarter ended December 31, 2023, at an average price of $127.66 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 November 2021 Authorization).

(2)Effective November 4, 2021, EOG's Board of Directors (Board) established a new share repurchase authorization that allows for the repurchase by EOG of up to $5 billion of its common stock (November 2021 Authorization). As of the date of this filing, (i) EOG has repurchased an aggregate 8,648,918 shares at a total cost of $971,132,276 (inclusive of commissions and transaction fees) under the November 2021 Authorization and (ii) an additional $4,028,867,724 of shares may be purchased under the November 2021 Authorization.

(3)Under the November 2021 Authorization, EOG may repurchase shares from time to time, at management's discretion, in accordance with applicable securities laws, including through open market transactions, privately negotiated transactions or any combination thereof. The timing and amount of repurchases is at the discretion of EOG's management and depends on a variety of factors, including the trading price of EOG's common stock, corporate and regulatory requirements, other market and economic conditions, the availability of cash to effect repurchases and EOG's anticipated future capital expenditures and other commitments requiring cash. Repurchased shares are held as treasury shares and are available for general corporate purposes. The November 2021 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.

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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, 2018 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, 2023)

	2018		2019		2020		2021		2022		2023
EOG	$	100.00	$	97.18	$	59.63	$	112.52	$	176.50	$	172.96
S&P 500	$	100.00	$	131.49	$	155.68	$	200.37	$	164.08	$	207.21
S&P O&G E&P	$	100.00	$	112.02	$	72.35	$	135.35	$	214.52	$	214.60

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ITEM 6.  Reserved

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

Overview

EOG Resources, Inc., together with its subsidiaries (collectively, EOG), is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States of America (United States) with proved reserves in the United States and the Republic of Trinidad and Tobago (Trinidad).  EOG is focused on being among the lowest-cost, highest-return and lowest-emissions producers, playing a significant role in the long-term future of energy. EOG operates under a consistent business and operational strategy that focuses predominantly on maximizing the rate of return on investment of capital by controlling operating costs and capital expenditures and maximizing reserve recoveries.  Pursuant to this strategy, each prospective drilling location is evaluated by its estimated rate of return. This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-effective basis, allowing EOG to maximize long-term 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 $7,594 million during 2023 as compared to net income of $7,759 million for 2022. At December 31, 2023, EOG's total estimated net proved reserves were 4,498 million barrels of oil equivalent (MMBoe), an increase of 260 MMBoe from December 31, 2022.  During 2023, net proved crude oil and condensate and natural gas liquids (NGLs) reserves increased by 204 million barrels (MMBbl), and net proved natural gas reserves increased by 339 billion cubic feet or 57 MMBoe, in each case from December 31, 2022.

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, 2023, the average U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were $77.61 per barrel and $2.74 per million British thermal units (MMBtu), respectively, representing decreases of 18% and 59%, respectively, from the average NYMEX prices for the year ended December 31, 2022. 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.

Inflation Considerations; Availability of Materials, Labor & Services. Beginning in the second half of 2021 and continuing, to a lesser degree, through the first three months of 2023, EOG, similar to other companies in its industry, experienced inflationary pressures on its 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 resulted from (i) supply chain disruptions caused by the COVID-19 pandemic and the resulting limited availability of certain materials and products manufactured using such materials; (ii) increased demand for fuel and steel; (iii) increased demand for drilling and completion services coupled with a limited number of available service providers, resulting in increased competition for such services among EOG and other companies in its industry; (iv) labor shortages; and (v) other factors, including the ongoing conflict between Russia and the Ukraine which began in late February 2022. Beginning in the second quarter of 2023, EOG has seen these inflationary pressures diminish and, in certain circumstances, seen a decline in prices. However, the market for such materials, services and labor continues to fluctuate and, as a result, the timing and impact of any price changes on EOG's future operating costs and capital expenditures is uncertain.

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Such inflationary pressures on EOG's operating costs and capital expenditures have, in turn, impacted its cash flows and results of operations. However, by virtue of its continued focus on increasing its drilling, completion and operating efficiencies and improving the performance of its wells, as well as the flexibility provided by its multi-basin drilling portfolio, EOG has, to date, been able to largely offset such impacts. Such inflationary pressures resulted in an increase of less than 10 percent in its fiscal year 2023 well costs (i.e., its costs for drilling, completions and well-site facilities) versus fiscal year 2022. Accordingly, such increase in EOG's fiscal year 2023 well costs did not have a material impact on EOG's full-year 2023 cash flows. Further, such inflationary pressures and the factors contributing to such inflationary pressures (described above) have not, to date, impacted EOG's liquidity, capital resources, cash requirements or financial position or its ability to conduct its day-to-day drilling, completion and production operations.

The initiatives EOG has undertaken (and continues to undertake) to increase its drilling, completion and operating efficiencies and improve the performance of its wells and, in turn, mitigate such inflationary pressures, 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; and (iii) EOG's self-sourced sand program, which has resulted in continued cost savings for the sand utilized in its well completion operations. In addition, EOG enters 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 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 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, 2023.

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 2023, EOG continued to focus on increasing drilling, completion and operating efficiencies, to improve well performance and, as is further discussed above, to mitigate inflationary pressures on its operating costs and capital expenditures. 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 73% and 75% of EOG's United States production during 2023 and 2022, respectively. During 2023, 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 2023 United States operations.

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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), the Banyan Field and the Sercan Area have been developed and are producing natural gas which is sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary (NGC), and crude oil and condensate which is sold to Heritage Petroleum Company Limited.

In the fourth quarter of 2023, EOG completed two net developmental wells and one net exploratory well from the recently installed Osprey B platform in the Modified U(a) Block. Additionally, in 2023, EOG completed the design phase for the platform and related facilities in the Mento Area and commenced construction of such platform and related facilities.

Also, EOG sold its equity interest in its ammonia plant investments in the first quarter of 2023.

Other International. In November 2021, a subsidiary of EOG was granted an exploration permit for the WA-488-P Block, located offshore Western Australia. In 2023, EOG continued to prepare for the drilling of an exploration well subject to regulatory approvals and equipment availability.

EOG continues to evaluate other select crude oil and natural gas opportunities outside the United States, primarily by pursuing exploration opportunities in countries where indigenous 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 12% at December 31, 2023 and 17% at December 31, 2022.  As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

At December 31, 2023, EOG maintained a strong financial and liquidity position, including $5.3 billion of cash and cash equivalents on hand and $1.9 billion of availability under its senior unsecured revolving credit facility (discussed below).

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

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

During 2023, EOG funded $6.6 billion ($195 million of which was non-cash) in exploration and development and other property, plant and equipment expenditures (excluding asset retirement obligations), paid $3.4 billion in dividends to common stockholders, repaid the 2023 Notes and paid $1.0 billion to repurchase shares of common stock, primarily by utilizing net cash provided by its operating activities and cash on hand.

Total anticipated 2024 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 2024 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.

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Cash Return Framework. In May 2022, EOG announced the addition of quantitative guidance to its cash return framework - specifically, a commitment to return a minimum of 60% 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. On November 2, 2023, EOG announced an increase in such 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 related discussion regarding our 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 23, 2023, EOG's Board of Directors (Board) declared a quarterly cash dividend on the common stock of $0.825 per share paid on April 28, 2023, to stockholders of record as of April 14, 2023. The Board also declared on such date a special dividend on the common stock of $1.00 per share paid on March 30, 2023, to stockholders of record as of March 16, 2023.

On May 4, 2023, the Board declared a quarterly cash dividend on the common stock of $0.825 per share paid on July 31, 2023, to stockholders of record as of July 17, 2023.

On August 3, 2023, the Board declared a quarterly cash dividend on the common stock of $0.825 per share paid on October 31, 2023, to stockholders of record as of October 17, 2023.

On November 2, 2023, the Board (i) increased the quarterly cash dividend on the common stock from the previous $0.825 per share to $0.91 per share, effective beginning with the dividend paid on January 31, 2024, to stockholders of record as of January 17, 2024, and (ii) declared a special cash dividend on the common stock of $1.50 per share, paid on December 29, 2023, to stockholders of record as of December 15, 2023.

On February 22, 2024, the Board declared a quarterly cash dividend on the common stock of $0.91 per share to be paid on April 30, 2024, to stockholders of record as of April 16, 2024.

Results of Operations

This section discusses certain year-to-year comparisons between 2023 and 2022, which should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning on page F-1. For discussion of certain year-to-year comparisons between 2022 and 2021, 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, 2022, filed on February 23, 2023, which is incorporated herein by reference.

Operating Revenues and Other

During 2023, operating revenues decreased $1,516 million, or 6%, to $24,186 million from $25,702 million in 2022. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, decreased $5,420 million, or 24%, to $17,376 million in 2023 from $22,796 million in 2022. Revenues from the sales of crude oil and condensate and NGLs in 2023 were 90% of total wellhead revenues compared to 83% in 2022. During 2023, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $818 million compared to net losses of $3,982 million in 2022. Gathering, processing and marketing revenues decreased $890 million during 2023, to $5,806 million from $6,696 million in 2022. EOG recognized net gains on asset dispositions of $95 million in 2023 compared to net gains on asset dispositions of $74 million in 2022.

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Wellhead volume and price statistics for the years ended December 31, 2023, 2022 and 2021 were as follows:

Year Ended December 31	2023		2022			2021
Crude Oil and Condensate Volumes (MBbld) (1)
United States	475.2		460.7			443.4
Trinidad	0.6		0.6			1.5
Other International (2)	—		—			0.1
Total	475.8		461.3			445.0
Average Crude Oil and Condensate Prices ($/Bbl) (3)
United States	$	79.18	$	97.22		$	68.54
Trinidad	68.58		86.16			56.26
Other International (2)	—		—			42.36
Composite	79.17		97.21			68.50
Natural Gas Liquids Volumes (MBbld) (1)
United States	223.8		197.7			144.5
Total	223.8		197.7			144.5
Average Natural Gas Liquids Prices ($/Bbl) (3)
United States	$	23.07	$	36.70		$	34.35
Composite	23.07		36.70			34.35
Natural Gas Volumes (MMcfd) (1)
United States	1,551		1,315			1,210
Trinidad	160		180			217
Other International (2)	—		—			9
Total	1,711		1,495			1,436
Average Natural Gas Prices ($/Mcf) (3)
United States	$	2.70	$	7.27		$	4.88
Trinidad	3.65		4.43		(5)	3.40
Other International (2)	—		—			5.67
Composite	2.79		6.93			4.66
Crude Oil Equivalent Volumes (MBoed) (4)
United States	957.5		877.5			789.6
Trinidad	27.3		30.7			37.7
Other International (2)	—		—			1.6
Total	984.8		908.2			828.9
Total MMBoe (4)	359.4		331.5			302.5

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

(2)Other International includes EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. EOG is continuing the process of exiting its Canada operations.

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

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

(5)Includes positive revenue adjustment of $0.76 per Mcf ($0.09 per Mcf of EOG's composite wellhead 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.

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Wellhead crude oil and condensate revenues in 2023 decreased $2,619 million, or 16%, to $13,748 million from $16,367 million in 2022, due primarily to a lower composite average wellhead crude oil and condensate price ($3,134 million), partially offset by an increase in production ($515 million). EOG's composite wellhead crude oil and condensate price for 2023 decreased 19% to $79.17 per barrel compared to $97.21 per barrel in 2022. Wellhead crude oil and condensate production in 2023 increased 3% to 476 MBbld as compared to 461 MBbld in 2022. The increased production was primarily in the Permian Basin, partially offset by decreased production in the Eagle Ford play.

NGLs revenues in 2023 decreased $764 million, or 29%, to $1,884 million from $2,648 million in 2022 primarily due to a lower composite average wellhead NGLs price ($1,117 million), partially offset by an increase in production ($353 million). EOG's composite average wellhead NGLs price decreased 37% to $23.07 per barrel in 2023 compared to $36.70 per barrel in 2022. NGLs production in 2023 increased 13% to 224 MBbld as compared to 198 MBbld in 2022. The increased production was primarily in the Permian Basin.

Wellhead natural gas revenues in 2023 decreased $2,037 million, or 54%, to $1,744 million from $3,781 million in 2022 primarily due to a lower composite wellhead natural gas price ($2,583 million), partially offset by an increase in natural gas deliveries ($546 million). EOG's composite average wellhead natural gas price decreased 60% to $2.79 per Mcf in 2023 compared to $6.93 per Mcf in 2022. Natural gas deliveries in 2023 increased 14% to 1,711 MMcfd as compared to 1,495 MMcfd in 2022. The increase in production was primarily due to increased production of associated natural gas from the Permian Basin and higher deliveries in the Dorado gas play, partially offset by lower natural gas deliveries in Trinidad and decreased production of associated natural gas from the Eagle Ford play.

During 2023, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $818 million, which included net cash paid for settlements of crude oil, NGLs and natural gas financial derivative contracts of $112 million. During 2022, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $3,982 million, which included net cash paid for settlements of crude oil, NGLs and natural gas financial derivative contracts of $3,501 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 2023 decreased $64 million compared to 2022, primarily due to lower margins on natural gas marketing activities.

Operating and Other Expenses

During 2023, operating expenses of $14,583 million were $1,153 million lower than the $15,736 million incurred during 2022.  The following table presents the costs per barrel of oil equivalent (Boe) for the years ended December 31, 2023 and 2022:

	2023		2022
Lease and Well	$	4.05	$	4.02
Transportation Costs	2.66		2.91
Gathering and Processing Costs	1.84		1.87
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties	9.24		10.21
Other Property, Plant and Equipment	0.48		0.48
General and Administrative (G&A)	1.78		1.72
Interest Expense, Net	0.41		0.54
Total (1)	$	20.46	$	21.75

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

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The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, gathering and processing costs, DD&A, G&A and interest expense, net for 2023 compared to 2022 are set forth below.  See "Operating Revenues and Other" above for a discussion of production 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 $1,454 million in 2023 increased $123 million from $1,331 million in 2022 primarily due to higher operating and maintenance costs in the United States ($65 million) and in Trinidad ($8 million), higher lease and well administrative expenses in the United States ($43 million), and higher workovers expenditures in the United States ($8 million). Lease and well expenses increased in the United States primarily due to increased operating activities resulting from increased production.

Transportation costs represent costs associated with the delivery of hydrocarbon products from the lease or an aggregation point on EOG's gathering system to a downstream point of sale.  Transportation costs include transportation fees, storage and terminal fees, the cost of compression (the cost of compressing natural gas to meet pipeline pressure requirements), the cost of dehydration (the cost associated with removing water from natural gas to meet pipeline requirements), gathering fees and fuel costs. Transportation costs also include operating and maintenance expenses associated with EOG-owned transportation assets.

Transportation costs of $957 million in 2023 decreased $9 million from $966 million in 2022 primarily due to decreased transportation costs related to production from the Eagle Ford play ($37 million) and the Rocky Mountain area ($6 million), partially offset by increased transportation costs related to production from the Permian Basin ($20 million), the Dorado gas play ($9 million) and the Mid-Continent area ($5 million).

Gathering and processing costs represent operating and maintenance expenses and administrative expenses associated with operating EOG's gathering and processing assets as well as natural gas processing fees and certain NGLs fractionation fees paid to third parties. EOG pays third parties to process the majority of its natural gas production to extract NGLs.

Gathering and processing costs increased $42 million to $663 million in 2023 compared to $621 million in 2022 primarily due to increased gathering and processing fees related to production from the Permian Basin ($33 million) and increased operating and maintenance expenses related to production from the Rocky Mountain area ($14 million) and the Permian Basin ($10 million), partially offset by decreased operating and maintenance expenses related to production from the Eagle Ford play ($14 million) and decreased gathering and processing fees related to production from the Rocky Mountain area ($13 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. 

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DD&A expenses in 2023 decreased $50 million to $3,492 million from $3,542 million in 2022.  DD&A expenses associated with oil and gas properties in 2023 were $64 million lower than in 2022 primarily due to lower unit rates in the United States ($373 million), partially offset by an increase in production in the United States ($299 million). Unit rates in the United States decreased primarily due to upward reserve revisions related to favorable well performance, lower expected future operating costs and reserve additions at lower costs per Boe. DD&A expenses associated with other property, plant and equipment in 2023 were $14 million higher than in 2022 primarily due to an increase in expense related to gathering assets and equipment.

G&A expenses of $640 million in 2023 increased $70 million from $570 million in 2022 primarily due to a net increase in costs associated with corporate support activities, including employee-related expenses and information systems and other services.

Interest expense, net of $148 million in 2023 decreased $31 million from $179 million in 2022 primarily due to the repayment in March 2023 of the $1,250 million aggregate principal amount of the 2023 Notes.

Exploration costs of $181 million in 2023 increased $22 million from $159 million in 2022 primarily due to increased administrative expenses ($10 million) and increased geological and geophysical expenditures ($8 million), both in the United States.

Impairments include: amortization of unproved oil and gas property costs as well as impairments of proved oil and gas properties; other property, plant and equipment; 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 a proved property 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 estimates 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, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value.  Fair value is generally calculated by using the Income Approach described in the Fair Value Measurement Topic of the Financial Accounting Standards Board's Accounting Standards Codification (ASC).  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, 2023 and 2022 (in millions):

	2023		2022
Proved properties	$	44	$	120
Unproved properties	125		206
Other assets	31		29
Inventories	—		25
Firm commitment contracts	2		2
Total	$	202	$	382

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 wellhead revenues, and ad valorem/property taxes are generally determined based on the valuation of the underlying assets.

Taxes other than income in 2023 decreased $301 million to $1,284 million (7.4% of wellhead revenues) from $1,585 million (7.0% of wellhead revenues) in 2022. The decrease in taxes other than income was primarily due to decreased severance/production taxes ($357 million) and decreased ad valorem/property taxes ($34 million), partially offset by decreased state severance tax refunds ($99 million), all in the United States.

Other income, net, was $234 million in 2023 compared to other income, net, of $114 million in 2022. The increase of $120 million in 2023 was primarily due to an increase in interest income ($155 million), partially offset by the absence of equity income due to the sale of EOG's equity interest in ammonia plant investments in Trinidad in the first quarter of 2023 ($46 million).

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EOG recognized an income tax provision of $2,095 million in 2023 compared to an income tax provision of $2,142 million in 2022 primarily due to decreased pretax income. The net effective tax rate for 2023 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, 2023, were funds generated from operations and, to a lesser extent, proceeds from asset sales.  The primary uses of cash were funds used in operations; exploration and development expenditures; dividend payments to stockholders; net cash paid for settlements of financial commodity derivative contracts; repayment of debt; other property, plant and equipment expenditures; and purchases of treasury stock.

Net cash provided by operating activities of $11,340 million in 2023 increased $247 million from $11,093 million in 2022 primarily due to a decrease in net cash paid for settlements of financial commodity derivative contracts ($3,389 million), a decrease in net cash paid for income taxes ($1,246 million), a decrease in net cash used in working capital and other assets and liabilities ($590 million) and net cash provided by a change in collateral posted for financial commodity derivative contracts ($508 million), partially offset by a decrease in wellhead revenues ($5,420 million).

Net cash used in investing activities of $6,340 million in 2023 increased by $1,284 million from $5,056 million in 2022 primarily due to an increase in additions to oil and gas properties ($766 million); an increase in additions to other property, plant and equipment ($419 million) and a decrease in proceeds from the sales of assets ($209 million); partially offset by a decrease in net cash used in working capital associated with investing activities ($80 million) and a decrease in other investing activities ($30 million).

Net cash used in financing activities of $5,694 million in 2023 included cash dividend payments ($3,386 million), a repayment of long-term debt ($1,250 million), purchases of treasury stock ($1,038 million) and repayment of finance lease liabilities ($32 million). Cash provided by financing activities in 2023 included proceeds from stock options exercised and employee stock purchase plan activity ($20 million). 

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Total Expenditures

The table below sets out components of total expenditures for the years ended December 31, 2023, 2022 and 2021 (in millions):

	2023		2022		2021
Expenditure Category
Capital
Exploration and Development Drilling (1)	$	4,803	$	3,675	$	2,864
Facilities	520		411		405
Leasehold Acquisitions (2)	207		186		215
Property Acquisitions (3)	16		419		100
Capitalized Interest	33		36		33
Subtotal	5,579		4,727		3,617
Exploration Costs	181		159		154
Dry Hole Costs	1		45		71
Exploration and Development Expenditures	5,761		4,931		3,842
Asset Retirement Costs	257		298		127
Total Exploration and Development Expenditures	6,018		5,229		3,969
Other Property, Plant and Equipment (4)	800		381		286
Total Expenditures	$	6,818	$	5,610	$	4,255

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

(2)Leasehold acquisitions included $99 million, $127 million and $45 million related to non-cash property exchanges in 2023, 2022 and 2021, respectively.

(3)Property acquisitions included $6 million, $26 million and $5 million related to non-cash property exchanges in 2023, 2022 and 2021, respectively.

(4)Other property, plant and equipment in 2023 included $134 million related to the acquisition of a gathering and processing system in the Powder River Basin. Other property, plant and equipment in 2021 included non-cash additions of $74 million, primarily related to finance lease transactions for storage facilities.

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Exploration and development expenditures of $5,761 million for 2023 were $830 million higher than the prior year. The increase was primarily due to increased exploration and development drilling expenditures in the United States ($1,079 million), increased facility expenditures ($109 million) and increased exploration and development drilling expenditures in Trinidad ($51 million), partially offset by decreased property acquisitions ($403 million). 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 2021 exploration and development expenditures of $3,842 million included $3,172 million in development drilling and facilities, $537 million in exploration, $100 million in property acquisitions and $33 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.

Financial Commodity Derivative Transactions

Presented below is a comprehensive summary of EOG's financial commodity derivative contracts settled during the year ended December 31, 2023 (closed) and remaining for 2024 and thereafter, as of February 16, 2024. Crude oil volumes are presented in MBbld and prices are presented in $/Bbl. Natural gas volumes are presented in MMBtu per day (MMBtud) and prices are presented in dollars per MMBtu ($/MMBtu).

Crude Oil Financial Price Swap Contracts
		Contracts Sold			Contracts Purchased
Period	Settlement Index	Volume (MBbld)	Weighted Average Price ($/Bbl)		Volume (MBbld)	Weighted Average Price ($/Bbl)
January - March 2023 (closed)	NYMEX WTI	95	$	67.90	6	$	102.26
April - May 2023 (closed)	NYMEX WTI	91	67.63		2	98.15
June 2023 (closed)	NYMEX WTI	2	69.10		2	98.15

Natural Gas Financial Price Swap Contracts
		Contracts Sold
Period	Settlement Index	Volume (MMBtud in thousands)	Weighted Average Price ($/MMBtu)
January - December 2023 (closed)	NYMEX Henry Hub	300	$	3.36
January - February 2024 (closed)	NYMEX Henry Hub	725	3.07
March - December 2024	NYMEX Henry Hub	725	3.07
January - December 2025	NYMEX Henry Hub	725	3.07

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Natural Gas Basis Swap Contracts
		Contracts Sold
Period	Settlement Index	Volume (MMBtud in thousands)	Weighted Average Price Differential ($/MMBtu)
January - December 2023 (closed)	NYMEX Henry Hub HSC Differential (1)	135	$	0.01
January - February 2024 (closed)	NYMEX Henry Hub HSC Differential	10	0.00
March - December 2024	NYMEX Henry Hub HSC Differential	10	0.00
January - 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.

Financing

EOG's debt-to-total capitalization ratio was 12% at December 31, 2023, compared to 17% at December 31, 2022.  As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

At December 31, 2023 and 2022, respectively, EOG had outstanding $3,640 million and $4,890 million aggregate principal amount of senior notes, which had estimated fair values of $3,574 million and $4,740 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 2023, 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 2023 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 and the relative competitive relationships of the various energy sources in the view of consumers, 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 2024 will impact the amount of cash generated from EOG's operating activities, which will in turn impact EOG's financial position. As of February 16, 2024, the average 2024 NYMEX crude oil and natural gas prices were $75.81 per barrel and $2.28 per MMBtu, respectively, representing a decrease of 2% for crude oil and a decrease of 17% for natural gas from the average NYMEX prices in 2023. 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.

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Based on EOG's tax position, EOG's price sensitivity in 2024 for each $1.00 per barrel increase or decrease in wellhead crude oil and condensate price, combined with the estimated change in NGLs price, is approximately $151 million for net income and $193 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 2024 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 wellhead natural gas price is approximately $27 million for net income and $35 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 16, 2024, see "Financial Commodity 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 its Delaware Basin, 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 lessen inflationary pressure 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 2024 capital expenditures on leasing acreage, evaluating new prospects, gathering and processing infrastructure, transportation infrastructure and environmental projects.

The total anticipated 2024 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 2024, crude oil and total crude oil equivalent production are expected to increase from 2023 levels. In 2024, EOG expects to continue to focus on mitigating inflationary pressure 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 2024, EOG anticipates the following cash requirements under these commitments (in millions):

Finance Leases (1)	$	37
Operating Leases (1)	363
Leases Effective, Not Commenced (1)	55
Transportation and Storage Service Commitments (2) (3)	878
Purchase and Service Obligations (3)	873
Total Cash Requirements	$	2,206

(1)    For more information on contracts that meet the definition of a lease under ASC "Leases (Topic 842)," see Note 18 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, 2023. 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 2024, EOG has no senior notes maturing and EOG expects to pay interest of $158 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 any unrecognized tax benefits, EOG's pension and postretirement benefit obligations and the liability for dismantlement, abandonment and asset retirement obligations (see Notes 6, 7, and 15, respectively, to Consolidated Financial Statements) are excluded because they are subject to estimates and the timing of settlement is unknown.

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EOG expects to fund its exploration, development and exploitation activities and other cash requirements, both in 2024 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 and continual reassessment of the viability of production under varying economic conditions.  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 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.  Lease rentals are expensed as incurred.

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When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the group.  If the expected undiscounted future cash flows, based on EOG's estimates of (and assumptions regarding) future crude oil and natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data, 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 the Fair Value Measurement Topic of the ASC.  In certain instances, EOG utilizes accepted offers from third-party purchasers as the basis for determining fair value.  Estimates of undiscounted future cash flows require significant judgment, and the assumptions used in preparing such estimates are inherently uncertain. In addition, such assumptions and estimates are reasonably likely to change in the future. 

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, 2023, 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 $1.33 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.

See Notes 13 and 14 to Consolidated Financial Statements for further disclosures of impairments of oil and gas properties and other assets.

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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, safety matters or other ESG (environmental/social/governance) 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, extent 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 recovery 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 inflationary 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 prevention 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;

•the availability, cost, terms and timing of issuance or execution of mineral licenses and leases and governmental and other permits and rights-of-way, and EOG's ability to retain mineral licenses 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 and 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 derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;

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•the impact of climate change-related policies and initiatives at the corporate and/or investor community levels and other potential developments related to climate change, such as (but not limited to) changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy; increased availability of, and increased consumer and industrial/commercial demand for, competing energy sources (including alternative energy sources); technological advances with respect to the generation, transmission, storage and consumption of energy; alternative fuel requirements; energy conservation measures and emissions-related legislation; decreased demand for, and availability of, services and facilities related to the exploration for, and production of, crude oil, NGLs and natural gas; and negative perceptions of the oil and gas industry and, in turn, reputational risks associated with the exploration for, and production of, crude oil, NGLs and natural gas;

•continuing political and social concerns relating to climate change and the greater potential for shareholder activism, governmental inquiries and enforcement actions and litigation and the resulting expenses and potential disruption to EOG's day-to-day operations;

•the extent to which EOG is able to successfully and economically develop, implement and carry out its emissions and other ESG-related initiatives and achieve its related targets, 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, 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, including its impact on crude oil and natural gas demand, and weather-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 duration and 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;

•acts of war and terrorism and responses to these acts; 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

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

ITEM 8.  Financial Statements and Supplementary Data

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

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

None.

ITEM 9A.  Controls and Procedures

Disclosure Controls and Procedures. EOG's management, with the participation of EOG's principal executive officer and principal financial officer, evaluated the effectiveness of EOG's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (Exchange Act)) as of December 31, 2023. 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, 2023.

Management's Annual Report on Internal Control over Financial Reporting. EOG's management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act). Even an effective system of internal control over financial reporting, no matter how well designed, has inherent limitations, including the possibility of human error, circumvention of controls or overriding of controls and, therefore, can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, the effectiveness of a system of internal control over financial reporting in future periods can change as conditions change. See "Management's Responsibility for Financial Reporting" appearing on page F-2 of this report, which is incorporated herein by reference.

The report of EOG's independent registered public accounting firm relating to the consolidated financial statements and effectiveness of internal control over financial reporting is set forth on page F-3 of this report.

There were no changes in EOG's internal control over financial reporting that occurred during the quarter ended December 31, 2023, that have materially affected, or are reasonably likely to materially affect, EOG's internal control over financial reporting.

ITEM 9B.  Other Information

Trading Plans/Arrangements. During the quarter ended December 31, 2023, no director or Section 16 officer of EOG adopted or terminated any Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (in each case, as defined in Item 408(a) of Regulation S-K).

ITEM 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspection

None.

53

PART III

ITEM 10.  Directors, Executive Officers and Corporate Governance

The information required by this Item is incorporated by reference from (i) EOG's Definitive Proxy Statement with respect to its 2024 Annual Meeting of Stockholders to be filed not later than April 29, 2024 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 New York Stock Exchange and Item 406 of Regulation S-K promulgated under the Securities Exchange Act of 1934, as amended, EOG has adopted a Code of Business Conduct and Ethics for Directors, Officers and Employees (Code of Conduct) that 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 of the amendment or waiver. In such case, the disclosure regarding the amendment or waiver will remain available on EOG's website for at least 12 months after the initial disclosure. There have been no waivers granted with respect to EOG's Code of Conduct or Code of Ethics.

ITEM 11.  Executive Compensation

The information required by this Item is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 2024 Annual Meeting of Stockholders to be filed not later than April 29, 2024. The Compensation and Human Resources Committee Report and related information incorporated by reference herein shall not be deemed "soliciting material" or to be "filed" with the United States Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended, except to the extent that EOG specifically incorporates such information by reference into such a filing.

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

The information required by this Item with respect to security ownership of certain beneficial owners and management is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 2024 Annual Meeting of Stockholders to be filed not later than April 29, 2024.

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 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).

54

The Amended and Restated 2008 Plan was approved by EOG's stockholders at the 2013 Annual Meeting of Stockholders in May 2013. The Amended and Restated 2008 Plan authorized an additional 31.0 million shares of EOG common stock for grant under the plan and extended the expiration date of the plan to May 2023.

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, 2023, 455,545 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, 2023.

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	4,257,571	(2)	$	79.22	16,284,804	(3)
Equity Compensation Plans Not Approved by EOG Stockholders	359,181	(4)	N/A		84,455	(5)
Total	4,616,752				16,369,259

(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) 2,842,973 outstanding stock option and SAR grants, (ii) 784,210 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) 630,388 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 630,388 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 1,260,776 performance units could be outstanding and (B) accordingly, a minimum of 0 and a maximum of 1,260,776 shares of EOG common stock could be issued upon the vesting of such grants.

(3)Consists of (i) 15,099,333 shares remaining available for issuance under the 2021 Plan and (ii) 1,185,471 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 359,181 phantom shares issued and outstanding under the Deferral Plan as of December 31, 2023).

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

55

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 2024 Annual Meeting of Stockholders to be filed not later than April 29, 2024.

ITEM 14.  Principal Accounting Fees and Services

The information required by this Item is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 2024 Annual Meeting of Stockholders to be filed not later than April 29, 2024.

PART IV

ITEM 15.  Exhibit and Financial Statement Schedules

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

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

(a)(3), (b)      Exhibits

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

ITEM 16. Form 10-K Summary

None.

56

EOG RESOURCES, INC.

INDEX TO FINANCIAL STATEMENTS

	Page
Consolidated Financial Statements:
Management's Responsibility for Financial Reporting	F-2
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)	F-3
Consolidated Statements of Income and Comprehensive Income for Each of the Three Years in the Period Ended December 31, 2023	F-6
Consolidated Balance Sheets - December 31, 2023 and 2022	F-7
Consolidated Statements of Stockholders' Equity for Each of the Three Years in the Period Ended December 31, 2023	F-8
Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2023	F-9
Notes to Consolidated Financial Statements	F-10
Supplemental Information to Consolidated Financial Statements	F-37

F-1

MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING

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

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

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

EOG's management assessed the effectiveness of EOG's internal control over financial reporting as of December 31, 2023.  In making this assessment, EOG used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (2013).  These criteria cover the control environment, risk assessment process, control activities, information and communication systems, and monitoring activities.  Based on this assessment and those criteria, management believes that EOG maintained effective internal control over financial reporting as of December 31, 2023.

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

EZRA Y. YACOB	ANN D. JANSSEN
Chairman of the Board and Chief Executive Officer	Executive Vice President and Chief Financial Officer
Houston, Texas
February 22, 2024

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of EOG Resources, Inc. and subsidiaries (the "Company") as of December 31, 2023 and 2022, the related consolidated statements of income and comprehensive income, stockholders' equity, and cash flows, for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the "financial statements"). We also have audited the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

Basis for Opinions

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

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

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

Definition and Limitations of Internal Control over Financial Reporting

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

F-3

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

Critical Audit Matter

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

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

Critical Audit Matter Description

The Company’s proved oil and gas properties are depleted using the units of production method based on estimated proved crude oil, natural gas liquids (NGLs), and natural gas reserves (proved reserves). The development of the Company’s estimated proved reserves volumes requires management to make significant estimates including the Company’s ability to convert proved undeveloped reserves to producing properties within five years of their initial reporting to the Securities and Exchange Commission. The Company’s reserve engineers estimate proved reserves quantities using these estimates along with estimates and assumptions related to engineering data. Changes in these estimates and assumptions could materially affect the estimated quantities of the Company’s proved reserves, which in turn could have a significant impact on the amount of depletion expense. The proved oil and gas properties balance, net was $24.8 billion as of December 31, 2023, and depletion expense was $3.2 billion for the year then ended.

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

How the Critical Audit Matter Was Addressed in the Audit

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

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

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

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

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

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

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

◦Reviewing internal communications to management and the Board of Directors

◦Comparing the forecasts to information included in Company press releases as well as in analyst and industry reports for the Company and certain of its peer companies

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

F-4

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

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 22, 2024

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

F-5

EOG RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(In Millions, Except Per Share Data)

Year Ended December 31	2023		2022		2021
Operating Revenues and Other
Crude Oil and Condensate	$	13,748	$	16,367	$	11,125
Natural Gas Liquids	1,884		2,648		1,812
Natural Gas	1,744		3,781		2,444
Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts, Net	818		(3,982)		(1,152)
Gathering, Processing and Marketing	5,806		6,696		4,288
Gains on Asset Dispositions, Net	95		74		17
Other, Net	91		118		108
Total	24,186		25,702		18,642
Operating Expenses
Lease and Well	1,454		1,331		1,135
Transportation Costs	957		966		863
Gathering and Processing Costs	663		621		559
Exploration Costs	181		159		154
Dry Hole Costs	1		45		71
Impairments	202		382		376
Marketing Costs	5,709		6,535		4,173
Depreciation, Depletion and Amortization	3,492		3,542		3,651
General and Administrative	640		570		511
Taxes Other Than Income	1,284		1,585		1,047
Total	14,583		15,736		12,540
Operating Income	9,603		9,966		6,102
Other Income, Net	234		114		9
Income Before Interest Expense and Income Taxes	9,837		10,080		6,111
Interest Expense
Incurred	181		215		211
Capitalized	(33)		(36)		(33)
Interest Expense, Net	148		179		178
Income Before Income Taxes	9,689		9,901		5,933
Income Tax Provision	2,095		2,142		1,269
Net Income	$	7,594	$	7,759	$	4,664
Net Income Per Share
Basic	$	13.07	$	13.31	$	8.03
Diluted	$	13.00	$	13.22	$	7.99
Average Number of Common Shares
Basic	581		583		581
Diluted	584		587		584
Comprehensive Income
Net Income	$	7,594	$	7,759	$	4,664
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments	(1)		4		(1)
Other, Net of Tax	—		—		1
Other Comprehensive Income (Loss)	(1)		4		—
Comprehensive Income	$	7,593	$	7,763	$	4,664

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

F-6

EOG RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(In Millions, Except Share Data)

At December 31	2023		2022
ASSETS
Current Assets
Cash and Cash Equivalents	$	5,278	$	5,972
Accounts Receivable, Net	2,716		2,774
Inventories	1,275		1,058
Assets from Price Risk Management Activities	106		—
Income Taxes Receivable	—		97
Other	560		574
Total	9,935		10,475
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)	72,090		67,322
Other Property, Plant and Equipment	5,497		4,786
Total Property, Plant and Equipment	77,587		72,108
Less: Accumulated Depreciation, Depletion and Amortization	(45,290)		(42,679)
Total Property, Plant and Equipment, Net	32,297		29,429
Deferred Income Taxes	42		33
Other Assets	1,583		1,434
Total Assets	$	43,857	$	41,371
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable	$	2,437	$	2,532
Accrued Taxes Payable	466		405
Dividends Payable	526		482
Liabilities from Price Risk Management Activities	—		169
Current Portion of Long-Term Debt	34		1,283
Current Portion of Operating Lease Liabilities	325		296
Other	286		346
Total	4,074		5,513
Long-Term Debt	3,765		3,795
Other Liabilities	2,526		2,574
Deferred Income Taxes	5,402		4,710
Commitments and Contingencies (Note 8)
Stockholders' Equity
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 588,748,473 Shares and 588,396,757 Shares Issued at December 31, 2023 and 2022, respectively	206		206
Additional Paid in Capital	6,166		6,187
Accumulated Other Comprehensive Loss	(9)		(8)
Retained Earnings	22,634		18,472
Common Stock Held in Treasury, 7,888,105 Shares and 700,281 Shares at December 31, 2023 and 2022, respectively	(907)		(78)
Total Stockholders' Equity	28,090		24,779
Total Liabilities and Stockholders' Equity	$	43,857	$	41,371

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

F-7

EOG RESOURCES, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(In Millions, Except Per Share Data)

	Common Stock		Additional Paid In Capital		Accumulated Other Comprehensive Loss		Retained Earnings		Common Stock Held In Treasury		Total Stockholders' Equity
Balance at December 31, 2020	$	206	$	5,945	$	(12)	$	14,170	$	(7)	$	20,302
Net Income	—		—		—		4,664		—		4,664
Common Stock Issued Under Stock Plans	—		17		—		—		—		17
Common Stock Dividends Declared, $4.9875 Per Share	—		—		—		(2,915)		—		(2,915)
Other Comprehensive Loss	—		—		—		—		—		—
Change in Treasury Stock - Stock Compensation Plans, Net	—		(22)		—		—		(18)		(40)
Restricted Stock and Restricted Stock Units, Net	—		(5)		—		—		5		—
Stock-Based Compensation Expenses	—		152		—		—		—		152
Treasury Stock Issued as Compensation	—		—		—		—		—		—
Balance at December 31, 2021	206		6,087		(12)		15,919		(20)		22,180
Net Income	—		—		—		7,759		—		7,759
Common Stock Issued Under Stock Plans	—		24		—		—		—		24
Common Stock Dividends Declared, $8.8750 Per Share	—		—		—		(5,206)		—		(5,206)
Other Comprehensive Income	—		—		4		—		—		4
Change in Treasury Stock - Stock Compensation Plans, Net	—		(55)		—		—		(61)		(116)
Restricted Stock and Restricted Stock Units, Net	—		(2)		—		—		2		—
Stock-Based Compensation Expenses	—		133		—		—		—		133
Treasury Stock Issued as Compensation	—		—		—		—		1		1
Balance at December 31, 2022	206		6,187		(8)		18,472		(78)		24,779
Net Income	—		—		—		7,594		—		7,594
Common Stock Dividends Declared, $5.8850 Per Share	—		—		—		(3,432)		—		(3,432)
Other Comprehensive Loss	—		—		(1)		—		—		(1)
Treasury Stock Repurchased	—		—		—		—		(979)		(979)
Change in Treasury Stock - Stock Compensation Plans, Net	—		(36)		—		—		(12)		(48)
Restricted Stock and Restricted Stock Units, Net	—		(162)		—		—		162		—
Stock-Based Compensation Expenses	—		177		—		—		—		177
Balance at December 31, 2023	$	206	$	6,166	$	(9)	$	22,634	$	(907)	$	28,090

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

F-8

EOG RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Millions)

Year Ended December 31	2023		2022		2021
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
Net Income	$	7,594	$	7,759	$	4,664
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization	3,492		3,542		3,651
Impairments	202		382		376
Stock-Based Compensation Expenses	177		133		152
Deferred Income Taxes	683		(61)		(122)
Gains on Asset Dispositions, Net	(95)		(74)		(17)
Other, Net	27		—		13
Dry Hole Costs	1		45		71
Mark-to-Market Financial Commodity Derivative Contracts
(Gains) Losses, Net	(818)		3,982		1,152
Net Cash Payments for Settlements of Financial Commodity Derivative Contracts	(112)		(3,501)		(638)
Other, Net	(2)		45		7
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	(38)		(347)		(821)
Inventories	(231)		(534)		(13)
Accounts Payable	(119)		90		456
Accrued Taxes Payable	61		(113)		312
Other Assets	39		(364)		(136)
Other Liabilities	184		(266)		(116)
Changes in Components of Working Capital Associated with Investing Activities	295		375		(200)
Net Cash Provided by Operating Activities	11,340		11,093		8,791
Investing Cash Flows
Additions to Oil and Gas Properties	(5,385)		(4,619)		(3,638)
Additions to Other Property, Plant and Equipment	(800)		(381)		(212)
Proceeds from Sales of Assets	140		349		231
Other Investing Activities	—		(30)		—
Changes in Components of Working Capital Associated with Investing Activities	(295)		(375)		200
Net Cash Used in Investing Activities	(6,340)		(5,056)		(3,419)
Financing Cash Flows
Long-Term Debt Repayments	(1,250)		—		(750)
Dividends Paid	(3,386)		(5,148)		(2,684)
Treasury Stock Purchased	(1,038)		(118)		(41)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan	20		28		19
Debt Issuance Costs	(8)		—		—
Repayment of Finance Lease Liabilities	(32)		(35)		(37)
Net Cash Used in Financing Activities	(5,694)		(5,273)		(3,493)
Effect of Exchange Rate Changes on Cash	—		(1)		1
Increase (Decrease) in Cash and Cash Equivalents	(694)		763		1,880
Cash and Cash Equivalents at Beginning of Year	5,972		5,209		3,329
Cash and Cash Equivalents at End of Year	$	5,278	$	5,972	$	5,209

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

F-9

EOG RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  Summary of Significant Accounting Policies

Nature of Business. EOG Resources, Inc., a Delaware corporation organized in 1985, together with its subsidiaries (collectively, EOG), explores for, develops, produces and markets crude oil, natural gas liquids (NGLs) and natural gas primarily in major producing basins in the United States of America (United States or U.S.) and the Republic of Trinidad and Tobago (Trinidad). EOG is making preparations to drill offshore Australia, as well as evaluating additional exploration, development and exploitation opportunities in these and other select international areas. In addition, EOG is executing an abandonment and reclamation program in Canada. EOG completed the exit of Block 36 and Block 49 located in the Sultanate of Oman (Oman) in 2023. EOG sold its operations in the China Sichuan Basin (China) in the second quarter of 2021.

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

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

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

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

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

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

Oil and gas exploration costs, other than the costs of drilling exploratory wells, are expensed as incurred.  The costs of drilling exploratory wells are capitalized pending determination of whether EOG has discovered commercial quantities of proved reserves.  If commercial quantities of proved reserves are not discovered, such drilling costs are expensed.  In some circumstances, it may be uncertain whether commercial quantities of proved reserves have been discovered when drilling has been completed.  Such exploratory well drilling costs may continue to be capitalized if the estimated reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made (see Note 16).  Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized.

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

F-10

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

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

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

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

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

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

Revenues are recognized for the sale of crude oil and condensate, NGLs and natural gas at the point control of the product is transferred to the customer, typically when production is delivered and title or risk of loss transfers to the customer. Arrangements for such sales are evidenced by signed contracts with prices typically based on stated market indices, with certain adjustments for product quality and geographic location. As EOG typically invoices customers shortly after performance obligations have been fulfilled, contract assets and contract liabilities are not recognized. The balances of accounts receivable from contracts with customers as of December 31, 2023 and 2022, were $2,237 million and $2,340 million, respectively, and are included in Accounts Receivable, Net on the Consolidated Balance Sheets. Losses incurred on receivables from contracts with customers are infrequent and have been immaterial. Certain arrangements provide for the sale of fixed quantities of commodities in future years with pricing mechanisms based on future market prices of the commodity at time of delivery. EOG does not disclose the value of these obligations given the uncertainty of the future realized transaction price.

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

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

F-11

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

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

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

Accounting for Risk Management Activities.  Financial commodity derivative instruments are recorded on the balance sheet as either an asset or liability measured at fair value, and changes in the instrument's fair value are recognized currently in earnings unless specific hedge accounting criteria are met.  During the three-year period ended December 31, 2023, EOG elected not to designate any of its financial commodity derivative instruments as accounting hedges and, accordingly, changes in the fair value of these outstanding derivative instruments are recognized as gains or losses in the period of change.  The gains or losses are recorded as Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts on the Consolidated Statements of Income and Comprehensive Income.  The related cash flow impact of settled contracts is reflected as cash flows from operating activities.  EOG employs net presentation of financial commodity derivative assets and liabilities for financial reporting purposes when such assets and liabilities are with the same counterparty and subject to a master netting arrangement.  See Note 12.

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

Effective January 1, 2021, EOG adopted the provisions of ASU 2019-12, "Income Taxes (Topic 740) Simplifying the Accounting for Income Taxes" (ASU 2019-12). There was no impact upon adoption of ASU 2019-12 to EOG's consolidated financial statements or related disclosures.

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

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

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

F-12

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

Right of Use (ROU) assets and related liabilities are recognized on the commencement date on the Consolidated Balance Sheets based on future lease payments, discounted based on the rate implicit in the contract, if readily determinable, or EOG's incremental borrowing rate commensurate with the lease term of the contract. EOG estimates its incremental borrowing rate based on the approximate rate required to borrow on a collateralized basis. Contracts with lease terms of less than 12 months are not recorded on the Consolidated Balance Sheets, but instead are disclosed as short-term lease cost. EOG has elected not to separate non-lease components for most asset classes, except for those asset classes where the non-lease (i.e. service) components comprise a material amount of the minimum lease payments. See Note 18.

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

In November 2023, the FASB issued ASU 2023-07 "Segment Reporting (Topic 820)," which updates reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. In addition, the amendment prescribes interim disclosure requirements, clarifies circumstances in which an entity can disclose multiple segment measures of profit or loss, provides new segment disclosure requirements for entities with a single reportable segment, and contains other disclosure requirements. The ASU is effective for public companies with annual periods beginning after December 15, 2023, and interim periods within annual periods beginning after December 15, 2024, with early adoption permitted. EOG is currently evaluating the impact of the standard on our segment reporting disclosures.

In December 2023, the FASB issued ASU 2023-09, "Income Taxes (Topic 740): Improvements to Income Tax Disclosures" (ASU 2023-09). ASU 2023-09 requires companies to disclose, on an annual basis, specific categories in the effective tax rate reconciliation and provide additional information for reconciling items that meet a quantitative threshold. In addition, ASU 2023-09 requires companies to disclose additional information about income taxes paid. ASU 2023-09 will be effective for annual periods beginning after December 15, 2024, and although permitted, EOG does not intend to early adopt. EOG is continuing to evaluate the provisions of ASU 2023-09 and does not anticipate a material impact on its consolidated financial statements and related disclosures upon adoption.

F-13

2.  Long-Term Debt

Long-Term Debt at December 31, 2023 and 2022 consisted of the following (in millions):

	2023		2022
2.625% Senior Notes due 2023	$	—	$	1,250
3.15% Senior Notes due 2025	500		500
4.15% Senior Notes due 2026	750		750
6.65% Senior Notes due 2028	140		140
4.375% Senior Notes due 2030	750		750
3.90% Senior Notes due 2035	500		500
5.10% Senior Notes due 2036	250		250
4.950% Senior Notes due 2050	750		750
Long-Term Debt	3,640		4,890
Finance Leases (see Note 18)	183		215
Less: Current Portion of Long-Term Debt	34		1,283
Unamortized Debt Discount	21		23
Debt Issuance Costs	3		4
Total Long-Term Debt	$	3,765	$	3,795

The senior notes in the table above are senior, unsecured obligations that rank equally in right of payment with all of our other unsecured and unsubordinated outstanding debt. At December 31, 2023, the aggregate annual maturities of current and long-term debt (excluding finance lease obligations) were zero in 2024, $500 million in 2025, $750 million in 2026, zero in 2027 and $140 million in 2028.

At December 31, 2023 and 2022, EOG had no outstanding commercial paper borrowings and did not utilize any commercial paper borrowings during 2023 or 2022.

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

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

The New Facility has a scheduled maturity date of June 7, 2028 and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods, subject to, among certain other terms and conditions, the consent of the Banks holding greater than 50% of the commitments then outstanding under the New Facility. The New Facility commits the Banks to provide advances up to an aggregate principal amount of $1.9 billion outstanding at any given time, with an option for EOG to request increases in the aggregate commitments to an amount not to exceed $3.0 billion, subject to certain terms and conditions. The New Facility also includes a swingline subfacility and a letter of credit subfacility. Advances under the New Facility will accrue interest based, at EOG's option, on either the Secured Overnight Financing Rate (SOFR) plus 0.1% plus an applicable margin, or the Base Rate (as defined in the New Facility) plus an applicable margin. The applicable margin used in connection with interest rates and fees will be based on EOG's credit rating for its senior unsecured long-term debt at the applicable time.

Consistent with the terms of the 2019 Facility, the New Facility contains representations, warranties, covenants and events of default that EOG believes are customary for investment grade, senior unsecured commercial bank credit agreements, including a financial covenant for the maintenance of a ratio of Total Debt to Total Capitalization (as such terms are defined in the New Facility) of no greater than 65%. At December 31, 2023, EOG was in compliance with this financial covenant.

F-14

There were no borrowings or letters of credit outstanding under the 2019 Facility as of (i) December 31, 2022 or (ii) the June 7, 2023 effective date of the closing of the New Facility and termination of the 2019 Facility. Further, at December 31, 2023, there were no borrowings or letters of credit outstanding under the New Facility. The SOFR and Base Rate (inclusive of the applicable margins), had there been any amounts borrowed under the New Facility at December 31, 2023, would have been 6.35% and 8.50%, respectively.

3.  Stockholders' Equity

Common Stock.  In September 2001, EOG's Board of Directors (Board) authorized the repurchase of an aggregate maximum of 10 million shares of common stock that superseded all previous authorizations (September 2001 Authorization). EOG last repurchased shares under the September 2001 Authorization in March 2003.  Effective November 4, 2021, the Board (i) established a new share repurchase authorization to allow for the repurchase by EOG of up to $5 billion of common stock (November 2021 Authorization) and (ii) revoked and terminated the September 2001 Authorization.

Under the November 2021 Authorization, EOG may repurchase shares from time to time, at management's discretion, in accordance with applicable securities laws, including through open market transactions, privately negotiated transactions or any combination thereof. The timing and amount of repurchases is at the discretion of EOG's management and depends on a variety of factors, including the trading price of EOG's common stock, corporate and regulatory requirements, other market and economic conditions, the availability of cash to effect repurchases and EOG's anticipated future capital expenditures and other commitments requiring cash. Repurchased shares are held as treasury shares and are available for general corporate purposes. The November 2021 Authorization has no time limit, does not require EOG to repurchase a specific number of shares and may be modified, suspended, or terminated by the Board at any time. During year ended December 31, 2023, EOG repurchased 8.6 million shares of common stock for approximately $971 million (inclusive of transaction fees and commissions) pursuant to the November 2021 Authorization. As of December 31, 2023, approximately $4 billion remained available for repurchases under the November 2021 Authorization. Included in the Treasury Stock Repurchased amounts on the Consolidated Statements of Stockholders' Equity for the year ended December 31, 2023, is $8 million of estimated federal excise tax.

Shares of common stock are from time to time withheld by, or returned to, EOG in satisfaction of tax withholding obligations arising upon the exercise of employee stock options or stock-settled stock appreciation rights (SARs), the vesting of restricted stock, restricted stock unit or performance unit grants or in payment of the exercise price of employee stock options. Such shares withheld or returned prior to November 4, 2021 did not count against the September 2001 Authorization, and such shares withheld or returned on or subsequent to November 4, 2021 have not counted, and will not count, against the November 2021 Authorization. Shares purchased, withheld and returned are held in treasury for, among other purposes, fulfilling any obligations arising under EOG's stock-based compensation plans and any other approved transactions or activities for which such shares of common stock may be required.

On February 22, 2024, the Board declared a quarterly cash dividend on the common stock of $0.91 per share to be paid on April 30, 2024, to stockholders of record as of April 16, 2024.

F-15

The following summarizes Common Stock activity for each of the years ended December 31, 2023, 2022 and 2021 (in thousands):

	Common Shares
	Issued	Treasury	Outstanding
Balance at December 31, 2020	583,695	(124)	583,571
Common Stock Issued Under Stock-Based Compensation Plans	1,511	—	1,511
Treasury Stock Purchased (1)	—	(504)	(504)
Common Stock Issued Under Employee Stock Purchase Plan	316	—	316
Treasury Stock Issued Under Stock-Based Compensation Plans	—	371	371
Balance at December 31, 2021	585,522	(257)	585,265
Common Stock Issued Under Stock-Based Compensation Plans	2,674	—	2,674
Treasury Stock Purchased (1)	—	(997)	(997)
Common Stock Issued Under Employee Stock Purchase Plan	201	—	201
Treasury Stock Issued Under Stock-Based Compensation Plans	—	554	554
Balance at December 31, 2022	588,397	(700)	587,697
Common Stock Issued Under Stock-Based Compensation Plans	159	—	159
Treasury Stock Purchased (2)	—	(9,177)	(9,177)
Common Stock Issued Under Employee Stock Purchase Plan	193	—	193
Treasury Stock Issued Under Stock-Based Compensation Plans	—	1,989	1,989
Balance at December 31, 2023	588,749	(7,888)	580,861

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

(2)    Represents shares that were repurchased under the November 2021 Authorization and/or that were withheld by or returned to EOG (i) in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or SARs or the vesting of restricted stock, restricted stock unit or performance unit grants or (ii) in payment of the exercise price of employee stock options.

Preferred Stock.  EOG currently has one authorized series of preferred stock - its Series E junior participating preferred stock (Series E Preferred Stock), of which 3,000,000 shares have been designated and authorized.  As of December 31, 2023, no shares of Series E Preferred Stock have been issued or are outstanding.

4.  Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss includes certain transactions that have been reported in the Consolidated Statements of Stockholders' Equity. The components of Accumulated Other Comprehensive Loss at December 31, 2023 and 2022 consisted of the following (in millions):

F-16

	Foreign Currency Translation Adjustment		Other		Total
December 31, 2021	$	(11)	$	(1)	$	(12)
Other comprehensive income before taxes	4		—		4
Tax effects	—		—		—
Other comprehensive income	4		—		4
December 31, 2022	(7)		(1)		(8)
Other comprehensive loss before taxes	(1)		—		(1)
Tax effects	—		—		—
Other comprehensive loss	(1)		—		(1)
December 31, 2023	$	(8)	$	(1)	$	(9)

No significant amount was reclassified out of Accumulated Other Comprehensive Loss during the years ended December 31, 2023 and 2022.

5.  Other Income, Net

Other income, net for 2023 included interest income ($240 million), partially offset by an upward adjustment to deferred compensation expense ($7 million). Other income, net for 2022 included interest income ($85 million) and equity income from investments in ammonia plants in Trinidad ($46 million), partially offset by an upward adjustment to deferred compensation expense ($15 million). Other income, net for 2021 included equity income from investments in ammonia plants in Trinidad ($18 million) and interest income ($3 million), partially offset by an upward adjustment to deferred compensation expense ($13 million).

6.  Income Taxes

The principal components of EOG's total net deferred income tax liabilities at December 31, 2023 and 2022 were as follows (in millions):

	2023		2022
Deferred Income Tax Assets (Liabilities)
Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization	$	(26)	$	(18)
Foreign Asset Retirement Obligations	84		81
Foreign Accrued Expenses and Liabilities	12		13
Foreign Net Operating Loss	97		82
Foreign Valuation Allowances	(126)		(116)
Foreign Other	1		(9)
Total Net Deferred Income Tax Assets	$	42	$	33
Deferred Income Tax (Assets) Liabilities
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization	$	5,778	$	5,291
Financial Commodity Derivative Contracts	—		(421)
Deferred Compensation Plans	(61)		(58)
Equity Awards	(59)		(60)
Corporate Alternative Minimum Tax	(212)		—
Other	(44)		(42)
Total Net Deferred Income Tax Liabilities	$	5,402	$	4,710
Total Net Deferred Income Tax Liabilities	$	5,360	$	4,677

F-17

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

	2023		2022		2021
United States	$	9,576	$	9,752	$	5,787
Foreign	113		149		146
Total	$	9,689	$	9,901	$	5,933

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

	2023		2022		2021
Current:
Federal	$	1,334	$	2,020	$	1,203
State	76		126		85
Foreign	5		62		105
Total	1,415		2,208		1,393
Deferred:
Federal	628		(2)		(41)
State	55		(37)		(62)
Foreign	—		(22)		(19)
Total	683		(61)		(122)
Other Non-Current:
Foreign	(3)		(5)		(2)
Total	(3)		(5)		(2)
Income Tax Provision	$	2,095	$	2,142	$	1,269

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

	2023		2022		2021
Statutory Federal Income Tax Rate	21.0	%	21.0	%	21.0	%
State Income Tax, Net of Federal Benefit	1.0		0.7		0.3
Income Tax Provision Related to Foreign Operations	(0.2)		—		0.9
Stock-Based Compensation	—		—		0.2
Other	(0.2)		—		(1.0)
Effective Income Tax Rate	21.6	%	21.7	%	21.4	%

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

F-18

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

	2023		2022		2021
Beginning Balance	$	207	$	219	$	219
Increase (1)	8		27		15
Decrease (2)	—		(33)		(14)
Other (3)	1		(6)		(1)
Ending Balance	$	216	$	207	$	219

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

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

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

As of December 31, 2023, EOG has state income tax NOLs of approximately $1.9 billion. Certain state NOLs have an indefinite carryforward and all others expire between 2024 and 2040. EOG also has Canadian NOLs of $333 million, some of which can be carried forward up to 20 years. In 2023, EOG accrued corporate alternative minimum tax (CAMT) of $212 million which resulted in a credit that can be carried forward indefinitely to offset regular federal income taxes in subsequent years. As described previously, these NOLs and other tax benefits have been evaluated for the likelihood of utilization, and valuation allowances have been established for the portion of these deferred income tax assets that do not meet the "more likely than not" threshold.

The ability of EOG to utilize CAMT credit carryforwards may be subject to various limitations under the Internal Revenue Code. Such limitations may arise if certain ownership changes (as defined for federal income tax purposes) were to occur.

As of December 31, 2023, EOG does not have any unrecognized tax benefits. Consequently, no interest or penalties have been recognized in the Consolidated Statements of Income and Comprehensive Income. EOG does not expect its unrecognized tax benefits to change significantly in the next twelve months. EOG and its subsidiaries file income tax returns and are subject to tax audits in the U.S. and various state, local and foreign jurisdictions. EOG's earliest open tax years in its principal jurisdictions are as follows: U.S. federal (2020), Trinidad (2015), Canada (2019), Oman (2020) and Australia (2021).

EOG's foreign subsidiaries' undistributed earnings are not considered to be permanently reinvested outside of the U.S. and, when appropriate, deferred income taxes have been accrued on any such outside basis differences. Additionally, EOG’s foreign earnings may be subject to the U.S. federal "global intangible low-taxed income" (GILTI) inclusion. EOG records any GILTI tax as a period expense.

7.  Employee Benefit Plans

Stock-Based Compensation

During 2023, EOG maintained various stock-based compensation plans as discussed below.  EOG recognizes compensation expense on grants of stock options, SARs, restricted stock, restricted stock units and restricted stock units with performance-based conditions (together with the performance units granted under the 2008 Plan (as defined below), Performance Units) and grants made under the EOG Resources, Inc. Employee Stock Purchase Plan (ESPP).  Stock-based compensation expense is calculated based upon the grant date estimated fair value of the awards, net of forfeitures, based upon EOG's historical employee turnover rate.  Compensation expense is amortized over the shorter of the vesting period or the period from date of grant until the date the employee becomes eligible to retire without company approval.

F-19

Stock-based compensation expense is included on the Consolidated Statements of Income and Comprehensive Income based upon the job functions of the employees receiving the grants.  Compensation expense related to EOG's stock-based compensation plans for the years ended December 31, 2023, 2022 and 2021 was as follows (in millions):

	2023		2022		2021
Lease and Well	$	54	$	40	$	49
Gathering and Processing Costs	4		4		3
Exploration Costs	24		15		20
General and Administrative	95		74		80
Total	$	177	$	133	$	152

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

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

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

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

At December 31, 2023, approximately 15 million common shares remained available for grant under the 2021 Plan.  EOG's policy is to issue shares related to the 2021 Plan from previously authorized unissued shares or treasury shares to the extent treasury shares are available.

During 2023, 2022 and 2021, EOG issued shares in connection with stock option/SAR exercises, restricted stock grants, restricted stock unit and Performance Unit releases and ESPP purchases.  Excess net tax benefits / (deficiencies) recognized within the income tax provision were $32 million, $22 million and $(11) million for the years ended December 31, 2023, 2022 and 2021, respectively.

F-20

Stock Options and Stock-Settled Stock Appreciation Rights and Employee Stock Purchase Plan.  Participants in EOG's stock-based compensation plans (including the 2008 Plan and 2021 Plan) have been or may be granted options to purchase shares of Common Stock.  In addition, participants in EOG's stock-based compensation plans (including the 2008 Plan and 2021 Plan) have been or may be granted SARs, representing the right to receive shares of Common Stock based on the appreciation in the stock price from the date of grant on the number of SARs granted.  Stock options and SARs are granted at a price not less than the market price of the Common Stock on the date of grant.  Terms for stock options and SARs granted have generally not exceeded a maximum term of seven years.  EOG did not grant any stock options or SARs in 2023. EOG's ESPP allows eligible employees to semi-annually purchase, through payroll deductions, shares of Common Stock at 85 percent of the fair market value at specified dates.  Contributions to the ESPP are limited to 10 percent of the employee's pay (subject to certain ESPP limits) during each of the two six-month offering periods each year.

The fair value of stock option grants and SAR grants is estimated using the Hull-White II binomial option pricing model.  The fair value of ESPP grants is estimated using the Black-Scholes-Merton model.  Stock-based compensation expense related to stock option, SAR and ESPP grants totaled $24 million, $34 million and $48 million for the years ended December 31, 2023, 2022 and 2021, respectively.

Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants for the years ended December 31, 2023, 2022 and 2021 were as follows:

	Stock Options/SARs							ESPP
		2022			2021			2023			2022			2021
Weighted Average Fair Value of Grants		$	28.30		$	24.92		$	29.35		$	26.62		$	18.12
Expected Volatility		42.20		%	42.24		%	38.01		%	43.00		%	51.27		%
Risk-Free Interest Rate		0.89		%	0.50		%	5.02		%	1.30		%	0.07		%
Dividend Yield		3.28		%	2.26		%	2.68		%	2.89		%	2.89		%
Expected Life		5.3 years			5.2 years			0.5 years			0.5 years			0.5 years

Expected volatility is based on an equal weighting of historical volatility and implied volatility from traded options in EOG's Common Stock.  The risk-free interest rate is based upon United States Treasury yields in effect at the time of grant.  The expected life is based upon historical experience and contractual terms of stock option, SAR and ESPP grants.

The following table sets forth the stock option and SAR transactions for the years ended December 31, 2023, 2022 and 2021 (stock options and SARs in thousands):

	2023			2022			2021
	Number of Stock Options/ SARs	Weighted Average Grant Price		Number of Stock Options/ SARs	Weighted Average Grant Price		Number of Stock Options/ SARs	Weighted Average Grant Price
Outstanding at January 1	4,225	$	77.49	9,969	$	84.37	10,186	$	84.08
Granted	—	—		2	97.64		1,982	81.68
Exercised (1)	(1,294)	73.01		(5,526)	89.70		(1,130)	63.98
Forfeited	(88)	87.74		(220)	82.74		(1,069)	98.15
Outstanding at December 31	2,843	79.22		4,225	77.49		9,969	84.37
Stock Options/SARs Exercisable at December 31	2,282	78.60		2,462	84.53		6,197	95.33

(1)The total intrinsic value of stock options/SARs exercised during the years 2023, 2022 and 2021 was $70 million, $190 million and $27 million, respectively.  The intrinsic value is based upon the difference between the market price of the Common Stock on the date of exercise and the grant price of the stock options/SARs.

At December 31, 2023, there were 2.8 million stock options/SARs vested or expected to vest with a weighted average grant price of $79.17 per share, an intrinsic value of $119 million and a weighted average remaining contractual life of 3.3 years.

F-21

The following table summarizes certain information for the stock options and SARs outstanding and exercisable at December 31, 2023 (stock options and SARs in thousands):

Stock Options/SARs Outstanding							Stock Options/SARs Exercisable
Range of Grant Prices	Stock Options/ SARs	Weighted Average Remaining Life (Years)	Weighted Average Grant Price		Aggregate Intrinsic Value(1)		Stock Options/ SARs	Weighted Average Remaining Life (Years)	Weighted Average Grant Price		Aggregate Intrinsic Value (1)
$ 34.00 to $ 52.99	634	3	$	37.49			633	3	$	37.46
53.00 to     80.99	380	3	74.99				376	3	75.03
81.00 to     81.99	1,140	5	81.81				588	4	81.81
82.00 to     96.99	246	1	95.97				242	1	96.09
97.00 to   129.99	443	2	126.57				443	2	126.58
	2,843	3	79.22		$	121	2,282	3	78.60		$	99

(1)Based upon the difference between the closing market price of the Common Stock on the last trading day of the year and the grant price of in-the-money stock options and SARs, in millions.

At December 31, 2023, unrecognized compensation expense related to non-vested stock option and SAR grants totaled $13 million.  This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 0.7 years.

At the 2018 Annual Meeting of Stockholders, EOG stockholders approved an amendment and restatement of the ESPP to (among other changes) increase the number of shares available for grant. At December 31, 2023, approximately 1.2 million shares of Common Stock remained available for grant under the ESPP.  The following table summarizes ESPP activity for the years ended December 31, 2023, 2022 and 2021 (in thousands, except number of participants):

	2023		2022		2021
Approximate Number of Participants	2,015		1,969		2,036
Shares Purchased	193		201		316
Aggregate Purchase Price	$	18,759	$	17,250	$	17,224

Restricted Stock and Restricted Stock Units.  Employees may be granted restricted (non-vested) stock and/or restricted stock units without cost to them.  Upon vesting of restricted stock, shares of Common Stock are released to the employee.  Upon vesting, restricted stock units are converted into shares of Common Stock and released to the employee.  Stock-based compensation expense related to restricted stock and restricted stock units totaled $137 million, $88 million and $89 million for the years ended December 31, 2023, 2022 and 2021, respectively.

F-22

The following table sets forth the restricted stock and restricted stock unit transactions for the years ended December 31, 2023, 2022 and 2021 (shares and units in thousands):

	2023			2022			2021
	Number of Shares and Units	Weighted Average Grant Date Fair Value		Number of Shares and Units	Weighted Average Grant Date Fair Value		Number of Shares and Units	Weighted Average Grant Date Fair Value
Outstanding at January 1	4,113	$	80.77	4,680	$	69.37	4,742	$	74.97
Granted	1,680	131.10		1,637	113.21		1,422	81.50
Released (1)	(1,295)	42.03		(2,019)	81.76		(1,388)	101.00
Forfeited	(134)	93.54		(185)	68.89		(96)	68.26
Outstanding at December 31 (2)	4,364	111.24		4,113	80.77		4,680	69.37

(1)

(1)The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2023, 2022 and 2021 was $166 million, $223 million and $110 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date restricted stock and restricted stock units are released.

(2)

(2)The total intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2023, 2022 and 2021 was $528 million, $533 million and $416 million, respectively. The intrinsic value is based on the closing market price of the Common Stock on the last trading day of the year.

At December 31, 2023, unrecognized compensation expense related to restricted stock and restricted stock units totaled $357 million. Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 1.8 years.

Performance Units.  EOG has granted Performance Units to its executive officers annually since 2012. For the grants made prior to September 2022, as more fully discussed in the grant agreements, the applicable performance metric is EOG's total shareholder return (TSR) over a three-year performance period relative to the TSR over the same period of a designated group of peer companies. Upon the application of the applicable performance multiple at the completion of the three-year performance period, a minimum of 0% and a maximum of 200% of the Performance Units granted could be outstanding.

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

The fair value of the Performance Units is estimated using a Monte Carlo simulation. Stock-based compensation expense related to the Performance Unit grants totaled $16 million, $11 million and $15 million for the years ended December 31, 2023, 2022 and 2021, respectively.

  Weighted average fair values and valuation assumptions used to value Performance Units during the years ended December 31, 2023, 2022 and 2021 were as follows:

	2023			2022			2021
Weighted Average Fair Value of Grants	$	142.20		$	126.55		$	95.16
Expected Volatility	44.76		%	56.11		%	53.80		%
Risk-Free Interest Rate	4.53		%	4.01		%	0.59		%

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

F-23

The following table sets forth the Performance Unit transactions for the years ended December 31, 2023, 2022 and 2021 (units in thousands):

	2023				2022			2021
	Number of Units		Weighted Average Grant Date Fair Value		Number of Units	Weighted Average Grant Date Fair Value		Number of Units	Weighted Average Grant Date Fair Value
Outstanding at January 1	688		$	83.82	679	$	84.97	613	$	88.38
Granted	114		142.20		122	126.55		222	95.16
Granted for Performance Multiple (1)	—		—		—	—		19	113.81
Released (2)	(86)		79.98		(57)	136.74		(175)	113.06
Forfeited for Performance Multiple (3)	(86)		79.98		(56)	136.74		—	—
Outstanding at December 31 (4)	630	(5)	95.49		688	83.82		679	84.97

(1)Upon completion of the performance period for the Performance Units granted in 2017, a performance multiple of 125% was applied to the grants resulting in additional grants of Performance Units in February 2021.

(2)The total intrinsic value of Performance Units released during the years ended December 31, 2023, 2022 and 2021 was $10 million, $7 million and $13 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date Performance Units are released.

(3)Upon completion of the performance period for the Performance Units granted in 2019 and 2018, a performance multiple of 50% was applied to each of the grants resulting in a forfeiture of Performance Units in both February 2023 and February 2022.

(4)The total intrinsic value of Performance Units outstanding at December 31, 2023, 2022 and 2021 was $76 million, $89 million and $60 million, respectively. The intrinsic value is based on the closing market price of the Common Stock on the last trading day of the year.

(5)Upon the application of the relevant performance multiple at the completion of each of the remaining performance periods, a minimum of zero and a maximum of 1,261 Performance Units could be outstanding.

At December 31, 2023, unrecognized compensation expense related to Performance Units totaled $18 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 1.7 years.

Upon completion of the performance period for the Performance Units granted in September 2020, a performance multiple of 25% was applied to the grants resulting in a forfeiture of 134,981 Performance Units in February 2024.

Pension Plans.  EOG has a defined contribution pension plan in place for most of its employees in the United States.  EOG's contributions to the pension plan are based on various percentages of compensation and, in some instances, are based upon the amount of the employees' contributions.  EOG's total costs recognized for the plan were $61 million, $56 million and $52 million for 2023, 2022 and 2021, respectively.

In addition, EOG's Trinidadian subsidiary maintains a contributory defined benefit pension plan and a matched savings plan.  These pension plans are available to most employees of the Trinidadian subsidiary. EOG's combined contributions to these plans were $1 million, for each of 2023, 2022 and 2021, respectively.

For the Trinidadian defined benefit pension plan, the benefit obligation, fair value of plan assets and (prepaid)/accrued benefit cost totaled $16 million, $16 million and $(0.9) million, respectively, at December 31, 2023, and $14 million, $15 million and $(0.5) million, respectively, at December 31, 2022.

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

F-24

8.  Commitments and Contingencies

Letters of Credit and Guarantees.  At December 31, 2023 and 2022, respectively, EOG had standby letters of credit and guarantees outstanding totaling approximately $907 million and $776 million, primarily representing guarantees of payment or performance obligations on behalf of subsidiaries. As of February 16, 2024, EOG had received no demands for payment under these guarantees.

Minimum Commitments. At December 31, 2023, total minimum commitments from purchase and service obligations and transportation and storage service commitments not qualifying as leases, based on current transportation and storage rates and the foreign currency exchange rates used to convert Canadian dollars into United States dollars at December 31, 2023, were as follows (in millions):

	Total Minimum Commitments
2024	$	1,751
2025	1,201
2026	983
2027	829
2028	545
2029 and beyond	1,375
	$	6,684

Delivery Commitments. EOG sells crude oil and natural gas from its producing operations under a variety of contractual arrangements. At December 31, 2023, EOG was committed to deliver to multiple parties fixed quantities of crude oil of 7 million barrels (MMBbls) in 2024 and 1 MMBbls in 2025. Additionally at December 31, 2023, EOG was committed to deliver to multiple parties fixed quantities of natural gas of 371 billion cubic feet (Bcf) in 2024, 282 Bcf in 2025, 297 Bcf in 2026, 293 Bcf in 2027, 263 Bcf in 2028 and 3,277 Bcf thereafter. All delivery commitments are expected to be sourced from future production of available reserves.

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

9.  Net Income Per Share

The following table sets forth the computation of Net Income Per Share for the years ended December 31, 2023, 2022 and 2021 (in millions, except per share data):

	2023		2022		2021
Numerator for Basic and Diluted Earnings per Share -
Net Income	$	7,594	$	7,759	$	4,664
Denominator for Basic Earnings per Share -
Weighted Average Shares	581		583		581
Potential Dilutive Common Shares -
Stock Options/SARs	1		2		—
Restricted Stock/Units and Performance Units	2		2		3
Denominator for Diluted Earnings per Share -
Adjusted Diluted Weighted Average Shares	584		587		584
Net Income Per Share
Basic	$	13.07	$	13.31	$	8.03
Diluted	$	13.00	$	13.22	$	7.99

F-25

The diluted earnings per share calculation excludes stock option, SAR, restricted stock, restricted stock unit, Performance Unit and ESPP grants that were anti-dilutive.  Shares underlying the excluded stock option, SAR and ESPP grants were 1 million, 1 million and 6 million for the years ended December 31, 2023, 2022 and 2021, respectively.

10.  Supplemental Cash Flow Information

Net cash paid for interest and income taxes was as follows for the years ended December 31, 2023, 2022 and 2021 (in millions):

	2023		2022		2021
Interest, Net of Capitalized Interest	$	161	$	173	$	185
Income Taxes, Net of Refunds Received	$	1,229	$	2,475	$	1,114

EOG's accrued capital expenditures and amounts recorded within accounts payable at December 31, 2023, 2022 and 2021 were $631 million, $713 million and $592 million, respectively.

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

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

Non-cash investing activities for the year ended December 31, 2021, included additions of $50 million to EOG's oil and gas properties as a result of property exchanges and an addition of $74 million to EOG's other property, plant and equipment made in connection with finance lease transactions for storage facilities.

Cash paid for leases for the years ended December 31, 2023, 2022 and 2021, is disclosed in Note 18.

11.  Business Segment Information

EOG's operations are all crude oil, NGLs and natural gas exploration and production-related. The Segment Reporting Topic of the ASC establishes standards for reporting information about operating segments in annual financial statements.  Operating segments are defined as components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker, or decision-making group, in deciding how to allocate resources and in assessing performance.  EOG's chief operating decision-making process is informal and involves the Chairman of the Board and Chief Executive Officer and other key officers.  This group routinely reviews and makes operating decisions related to significant issues associated with each of EOG's major producing areas (including in the United States and in Trinidad) and its exploration programs both inside and outside the United States.  For segment reporting purposes, the chief operating decision makers consider the major United States producing areas to be one operating segment.

F-26

Financial information by reportable segment is presented below as of and for the years ended December 31, 2023, 2022 and 2021 (in millions):

	United States		Trinidad		Other International (1)		Total
2023
Crude Oil and Condensate	$	13,734	$	14	$	—	$	13,748
Natural Gas Liquids	1,884		—		—		1,884
Natural Gas	1,530		214		—		1,744
Gains on Mark-to-Market Financial Commodity Derivative Contracts, Net	818		—		—		818
Gathering, Processing and Marketing	5,806		—		—		5,806
Gains on Asset Dispositions, Net	53		42		—		95
Other, Net	91		—		—		91
Operating Revenues and Other (2)	23,916		270		—		24,186
Depreciation, Depletion and Amortization	3,414		78		—		3,492
Operating Income (Loss) (3)	9,516		124		(37)		9,603
Interest Income	223		12		5		240
Other Income (Expense)	(6)		1		(1)		(6)
Interest Expense, Net	148		—		—		148
Income (Loss) Before Income Taxes	9,585		137		(33)		9,689
Income Tax Provision	2,093		2		—		2,095
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	5,413		162		4		5,579
Total Property, Plant and Equipment, Net	31,876		404		17		32,297
Total Assets	42,674		1,063		120		43,857

2022
Crude Oil and Condensate	$	16,349	$	18	$	—	$	16,367
Natural Gas Liquids	2,648		—		—		2,648
Natural Gas	3,489		292		—		3,781
Losses on Mark-to-Market Financial Commodity Derivative Contracts, Net	(3,982)		—		—		(3,982)
Gathering, Processing and Marketing	6,695		1		—		6,696
Gains (Losses) on Asset Dispositions, Net	77		(4)		1		74
Other, Net	118		—		—		118
Operating Revenues and Other (4)	25,394		307		1		25,702
Depreciation, Depletion and Amortization	3,469		73		—		3,542
Operating Income (Loss) (5)	9,880		122		(36)		9,966
Interest Income	81		2		2		85
Other Income (Expense)	(17)		46		—		29
Interest Expense, Net	179		—		—		179
Income (Loss) Before Income Taxes	9,765		170		(34)		9,901
Income Tax Provision	2,106		35		1		2,142
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	4,599		122		6		4,727
Total Property, Plant and Equipment, Net	29,109		307		13		29,429
Total Assets	40,349		879		143		41,371

F-27

	United States		Trinidad		Other International (1)		Total
2021
Crude Oil and Condensate	$	11,094	$	31	$	—	$	11,125
Natural Gas Liquids	1,812		—		—		1,812
Natural Gas	2,156		270		18		2,444
Losses on Mark-to-Market Financial Commodity Derivative Contracts, Net	(1,152)		—		—		(1,152)
Gathering, Processing and Marketing	4,287		1		—		4,288
Gains (Losses) on Asset Dispositions, Net	(40)		(2)		59		17
Other, Net	108		—		—		108
Operating Revenues and Other (6)	18,265		300		77		18,642
Depreciation, Depletion and Amortization	3,558		87		6		3,651
Operating Income (Loss) (7)	6,013		151		(62)		6,102
Interest Income	3		—		—		3
Other Income (Expense)	(14)		8		12		6
Interest Expense, Net	178		—		—		178
Income (Loss) Before Income Taxes	5,824		159		(50)		5,933
Income Tax Provision (Benefit)	1,247		66		(44)		1,269
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	3,557		55		5		3,617
Total Property, Plant and Equipment, Net	28,213		204		9		28,426
Total Assets	37,436		637		163		38,236

(1)Other International primarily consists of EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. EOG is continuing the process of exiting its Canada operations. EOG began exploration programs in Australia in the third quarter of 2021 and in Oman in the third quarter of 2020. The decision was reached in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman.

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

(3)EOG recorded pretax impairment charges of $18 million in 2023 for proved oil and gas properties and firm commitment contracts related to its decision to exit the Horn River Basin in British Columbia, Canada, in the Other International segment. See Note 14.

(4)EOG had sales activity with three significant purchasers in 2022, one totaling $3.3 billion, another totaling $3.1 billion and a third totaling $3.0 billion of consolidated Operating Revenues and Other in the United States segment.

(5)EOG recorded pretax impairment charges of $15 million in 2022 for proved oil and gas properties and firm commitment contracts related to its decision to exit the Horn River Basin in British Columbia, Canada, in the Other International segment. See Note 14.

(6)EOG had sales activity with two significant purchasers in 2021, one totaling $2.7 billion and the other totaling $2.6 billion of consolidated Operating Revenues and Other in the United States segment.

(7)EOG recorded pretax impairment charges of $45 million and dry hole costs of $42 million in 2021 in the Other International segment related to its decision in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman. In addition, EOG recorded net gains of asset dispositions of $58 million in 2021 in the Other International segment during the second quarter of 2021 due to the sale of its China operations. See Notes 14 and 17, respectively.

F-28

12.  Risk Management Activities

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

During 2023, 2022 and 2021, EOG elected not to designate any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounted for these financial commodity derivative contracts using the mark-to-market accounting method.  Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts, Net on the Consolidated Statements of Income and Comprehensive Income.  The related cash flow impact is reflected in Cash Flows from Operating Activities.  During 2023, 2022 and 2021, EOG recognized net gains (losses) on the mark-to-market of financial commodity derivative contracts of $818 million, $(3,982) million and $(1,152) million, respectively, which included net cash payments for settlements of crude oil, NGLs and natural gas financial derivative contracts of $(112) million, $(3,501) million and $(638) million, respectively.

Presented below is a comprehensive summary of EOG's financial commodity derivative contracts settled during the year ended December 31, 2023 (closed) and remaining for 2024 and thereafter, as of December 31, 2023. Crude oil volumes are presented in MBbld and prices are presented in $/Bbl. Natural gas volumes are presented in MMBtu per day (MMBtud) and prices are presented in dollars per MMBtu ($/MMBtu).

Crude Oil Financial Price Swap Contracts
		Contracts Sold			Contracts Purchased
Period	Settlement Index	Volume (MBbld)	Weighted Average Price ($/Bbl)		Volume (MBbld)	Weighted Average Price ($/Bbl)
January - March 2023 (closed)	NYMEX WTI	95	$	67.90	6	$	102.26
April - May 2023 (closed)	NYMEX WTI	91	67.63		2	98.15
June 2023 (closed)	NYMEX WTI	2	69.10		2	98.15

Natural Gas Financial Price Swap Contracts
		Contracts Sold
Period	Settlement Index	Volume (MMBtud in thousands)	Weighted Average Price ($/MMBtu)
January 2023 - December 2023 (closed)	NYMEX Henry Hub	300	$	3.36
January 2024 (closed)	NYMEX Henry Hub	725	3.07
February - December 2024	NYMEX Henry Hub	725	3.07
January - December 2025	NYMEX Henry Hub	725	3.07

F-29

Natural Gas Basis Swap Contracts
		Contracts Sold
Period	Settlement Index	Volume (MMBtud in thousands)	Weighted Average Price Differential ($/MMBtu)
January - December 2023 (closed)	NYMEX Henry Hub Houston Ship Channel (HSC) Differential (1)	135	$	0.01
January - December 2024	NYMEX Henry Hub HSC Differential	10	0.00
January - 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.

Financial Commodity Derivatives Location on Balance Sheet. The following table sets forth the amounts and classification of EOG's outstanding derivative financial instruments at December 31, 2023 and 2022, respectively.  Certain amounts may be presented on a net basis on the consolidated financial statements when such amounts are with the same counterparty and subject to a master netting arrangement (in millions):

		Fair Value at December 31,
Description	Location on Balance Sheet	2023		2022
Asset Derivatives
Crude oil, NGLs and natural gas financial derivative contracts -
Current portion	Assets from Price Risk Management (1)	$	106	$	—
Liability Derivatives
Crude oil, NGLs and natural gas financial derivative contracts -
Current portion	Liabilities from Price Risk Management Activities	$	—	$	169
Noncurrent Portion	Other Liabilities (2)	103		371

(1)    The current portion of Assets from Price Risk Management Activities consists of gross assets of $106 million at December 31, 2023.

(2)    The noncurrent portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $104 million, partially offset by gross assets of $1 million, at December 31, 2023.

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

At December 31, 2023, EOG's net accounts receivable balance related to United States hydrocarbon sales included three receivable balances, each of which accounted for more than 10% of the total balance.  The receivables were due from three petroleum refinery companies. The related amounts were collected during early 2024. At December 31, 2022, EOG's net accounts receivable balance related to United States hydrocarbon sales included one receivable balance which accounted for more than 10% of the total balance.  The receivable was due from a petroleum refinery company.  The related amount was collected during early 2023.

In 2023 and 2022, all natural gas from EOG's Trinidad operations was sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary. In 2023 and 2022, all crude oil and condensate from EOG's Trinidad operations was sold to Heritage Petroleum Company Limited.

F-30

All of EOG's financial derivative instruments are covered by International Swap Dealers Association Master Agreements (ISDAs) with counterparties.  The ISDAs may contain provisions that (i) require EOG, if it is the party in a net liability position, to post collateral with the counterparty when the amount of the net liability exceeds the threshold level specified for EOG's then-current credit ratings or (ii) require the counterparty, if it is in a net liability position, to post collateral with EOG when the amount of the net liability exceeds the threshold level specified for the counterparty's then-current credit ratings. In addition, the ISDAs may also provide that as a result of certain circumstances, including certain events that cause EOG's credit ratings to become materially weaker than its then-current ratings, the counterparty may require all outstanding financial derivatives under the ISDA to be settled immediately.  See Note 13 for the aggregate fair value of all financial derivative instruments that were in a net liability position at December 31, 2023 and 2022.  EOG had no collateral posted or held at December 31, 2023 and had $324 million of collateral posted and no collateral held at December 31, 2022.

Substantially all of EOG's accounts receivable at December 31, 2023 and 2022 resulted from hydrocarbon sales and/or joint interest billings to third-party companies, including foreign state-owned entities in the oil and gas industry.  This concentration of customers and joint interest owners may impact EOG's overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions.  In determining whether or not to require collateral or other credit enhancements from a customer, EOG typically analyzes the entity's net worth, cash flows, earnings and credit ratings.  Receivables are generally not collateralized.  During the three-year period ended December 31, 2023, credit losses incurred on receivables by EOG have been immaterial.

13.  Fair Value Measurements

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

Recurring Fair Value Measurements. The following table provides fair value measurement information within the fair value hierarchy for certain of EOG's financial assets and liabilities carried at fair value on a recurring basis at December 31, 2023 and 2022 (in millions):

	Fair Value Measurements Using:
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
At December 31, 2023
Financial Assets:
Natural Gas Swaps	$	—	$	105	$	—	$	105
Natural Gas Basis Swaps	—		2		—		2
Financial Liabilities:
Natural Gas Swaps	—		104		—		104
At December 31, 2022
Financial Assets:
Natural Gas Basis Swaps	$	—	$	29	$	—	$	29
Financial Liabilities:
Natural Gas Swaps	—		703		—		703
Crude Oil Swaps	—		190		—		190

See Note 12 for the balance sheet amounts and classification of EOG's financial derivative instruments at December 31, 2023 and 2022.

F-31

The estimated fair value of crude oil, NGLs and natural gas financial derivative contracts (including options/collars) was based upon forward commodity price curves based on quoted market prices.  Financial commodity derivative contracts were valued by utilizing an independent third-party derivative valuation provider who uses various types of valuation models, as applicable.

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

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

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

During 2022, proved oil and gas properties with a carrying amount of $146 million were written down to their fair value of $26 million, resulting in pretax impairment charges of $120 million

During 2021, proved oil and gas properties with a carrying amount of $27 million were written down to their fair value of $7 million, resulting in pretax impairment charges of $20 million.

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

Fair Value of Debt. At December 31, 2023 and 2022, respectively, EOG had outstanding $3,640 million and $4,890 million aggregate principal amount of senior notes, which had estimated fair values of $3,574 million and $4,740 million, respectively. The estimated fair value of debt was based upon quoted market prices and, where such prices were not available, other observable (Level 2) inputs regarding interest rates available to EOG at year-end.

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 will be accounted for as a derivative beginning in the first quarter of 2024 (effective upon the execution of the agreement) using the mark-to-market accounting method. Changes in the fair value will be recognized as gains or losses in the period of change on the Consolidated Statements of Income and Comprehensive Income.

F-32

14.  Impairment Expense

Impairment expense was as follows for the years ended December 31, 2023, 2022 and 2021 (in millions):

	2023		2022		2021
Proved properties	$	44	$	120	$	20
Unproved properties (1)	125		206		310
Other assets	31		29		28
Inventories	—		25		13
Firm commitment contracts	2		2		5
Total	$	202	$	382	$	376

(1)    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. Impairments of unproved oil and gas properties included $38 million in 2021 for the decision in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman. See Note 1.

15.  Asset Retirement Obligations

The following table presents the reconciliation of the beginning and ending aggregate carrying amounts of short-term and long-term legal obligations associated with the retirement of property, plant and equipment for the years ended December 31, 2023 and 2022 (in millions):

	2023		2022
Carrying Amount at Beginning of Period	$	1,328	$	1,231
Liabilities Incurred	71		100
Liabilities Settled (1)	(114)		(215)
Accretion	53		43
Revisions	166		173
Foreign Currency Translations	2		(4)
Carrying Amount at End of Period	$	1,506	$	1,328
Current Portion	$	37	$	38
Noncurrent Portion	$	1,469	$	1,290

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

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

F-33

16.  Exploratory Well Costs

EOG's net changes in capitalized exploratory well costs for the years ended December 31, 2023, 2022 and 2021 are presented below (in millions):

	2023		2022		2021
Balance at January 1	$	15	$	7	$	29
Additions Pending the Determination of Proved Reserves	195		135		73
Reclassifications to Proved Properties	(133)		(88)		(41)
Costs Charged to Expense (1)	(1)		(39)		(54)
Balance at December 31	$	76	$	15	$	7

(1)    Includes capitalized exploratory well costs charged to either dry hole costs or impairments.

	2023		2022		2021
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	73	$	15	$	7
Capitalized exploratory well costs that have been capitalized for a period greater than one year (1)	3		—		—
Balance at December 31	$	76	$	15	$	7
Number of exploratory wells that have been capitalized for a period greater than one year	2		—		—

(1)    Consists of costs related to two projects in the United States at December 31, 2023.

17.  Acquisitions and Divestitures

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

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

During 2021, EOG paid cash for property acquisitions of $95 million in the United States. Additionally during 2021, EOG recognized net gains on asset dispositions of $17 million and received proceeds of $231 million primarily due to the sale of the China assets and the disposition of the Northwest Shelf assets in New Mexico. Additionally, in the fourth quarter of 2021, EOG signed a purchase and sale agreement for the sale of primarily producing properties in the Rocky Mountain area. At December 31, 2021, the book value of these assets and their related asset retirement obligations were $99 million and $105 million, respectively.

F-34

18. Leases

Lease costs are classified by the function of the ROU asset. The lease costs related to exploration and development activities are initially included in the Oil and Gas Properties line on the Consolidated Balance Sheets and subsequently accounted for in accordance with the Extractive Industries - Oil and Gas Topic of the ASC. Variable lease cost represents costs incurred above the contractual minimum payments and other charges associated with leased equipment, primarily for drilling and fracturing contracts classified as operating leases. The components of lease cost for the years ended December 31, 2023, 2022 and 2021 were as follows (in millions):

	2023		2022		2021
Operating Lease Cost	$	387	$	282	$	295
Finance Lease Cost:
Amortization of Lease Assets	33		36		39
Interest on Lease Liabilities	5		6		7
Variable Lease Cost	91		71		63
Short-Term Lease Cost	567		425		257
Total Lease Cost	$	1,083	$	820	$	661

The following table sets forth the amounts and classification of EOG's outstanding ROU assets and related lease liabilities at December 31, 2023 and 2022 and supplemental information for the years ended December 31, 2023 and 2022 (in millions, except lease terms and discount rates):

Description	Location on Balance Sheet	2023		2022
Assets
Operating Leases	Other Assets	$	974	$	846
Finance Leases	Property, Plant and Equipment, Net (1)	170		203
Total		$	1,144	$	1,049
Liabilities
Current
Operating Leases	Current Portion of Operating Lease Liabilities	$	325	$	296
Finance Leases	Current Portion of Long-Term Debt	34		33
Long-Term
Operating Leases	Other Liabilities	676		584
Finance Leases	Long-Term Debt	149		182
Total		$	1,184	$	1,095

(1)    Finance lease assets are recorded net of accumulated amortization of $190 million and $157 million at December 31, 2023 and 2022, respectively.

	2023		2022
Weighted Average Remaining Lease Term (in years):
Operating Leases	5.3		4.9
Finance Leases	5.5		6.5
Weighted Average Discount Rate:
Operating Leases	4.3	%	3.4	%
Finance Leases	2.6	%	2.6	%

F-35

Cash paid for leases for the years ended December 31, 2023, 2022 and 2021 was as follows (in millions):

	2023		2022		2021
Repayment of Operating Lease Liabilities Associated with Operating Activities	$	226	$	199	$	207
Repayment of Operating Lease Liabilities Associated with Investing Activities	172		95		98
Repayment of Finance Lease Liabilities	32		35		37

Non-cash leasing activities for the year ended December 31, 2023, included the additions of $727 million of operating leases and no finance leases. Non-cash leasing activities for the year ended December 31, 2022, included the additions of $511 million of operating leases and no finance leases. Non-cash leasing activities for the year ended December 31, 2021, included the additions of $333 million of operating leases and $74 million of finance leases.

At December 31, 2023, the future minimum lease payments under non-cancellable leases were as follows (in millions):

	Operating Leases		Finance Leases
2024	$	363	$	37
2025	213		35
2026	129		30
2027	100		30
2028	99		30
2029 and beyond	222		35
Total Lease Payments	1,126		197
Less: Discount to Present Value	125		14
Total Lease Liabilities	1,001		183
Less: Current Portion of Lease Liabilities	325		34
Long-Term Lease Liabilities	$	676	$	149

At December 31, 2023, EOG had additional minimum lease payments of $350 million, which are expected to commence beginning in 2024 with lease terms of two to ten years.

F-36

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

Oil and Gas Producing Activities

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

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

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

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

Proved undeveloped reserves (PUDs) are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion or recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. PUDs can be recorded in respect of a particular undeveloped undrilled location only if the location is scheduled, under the then-current drilling and development plan, to be drilled within five years from the date that the PUDs were recorded, unless specific factors (such as those described in interpretative guidance issued by the Staff of the SEC) justify a longer timeframe.  Likewise, absent any such specific factors, PUDs associated with a particular undeveloped drilling location shall be removed from the estimates of proved reserves if the location is scheduled, under the then-current drilling and development plan, to be drilled on a date that is beyond five years from the date that the PUDs were recorded.  EOG has formulated development plans for all drilling locations associated with its PUDs at December 31, 2023.  Under these plans, each location will be drilled within five years from the date the associated PUDs were recorded.  Estimates for PUDs are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

In making estimates of PUDs, EOG's technical staff, including engineers and geoscientists, perform detailed technical analysis of each potential drilling location within its inventory of prospects.  In making a determination as to which of these locations would penetrate undrilled portions of the formation that can be judged, with reasonable certainty, to be continuous and contain economically producible crude oil, NGLs and natural gas, studies are conducted using numerous data elements and analysis techniques.  EOG's technical staff estimates the hydrocarbons in place by mapping the entirety of the play in question using seismic techniques, typically employing two-dimensional and three-dimensional data.  This analysis is integrated with other static data, including, but not limited to, core analysis, mechanical properties of the formation, thermal maturity indicators, and well logs of existing penetrations.  Highly specialized equipment is utilized to prepare rock samples in assessing microstructures which contribute to porosity and permeability.

Analysis of dynamic data is then incorporated to arrive at the estimated fractional recovery of hydrocarbons in place.  Data analysis techniques employed include, but are not limited to, well testing analysis, static bottom hole pressure analysis, flowing bottom hole pressure analysis, analysis of historical production trends, pressure transient analysis and rate transient analysis.  Application of proprietary rate transient analysis techniques in low permeability rocks allow for quantification of estimates of contribution to production from both fractures and rock matrix.

F-37

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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

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

Estimates of proved reserves at December 31, 2023, 2022 and 2021 were based on studies performed by the engineering staff of EOG.  The Engineering and Acquisitions Department is directly responsible for EOG's reserve evaluation process and consists of 16 engineers, all of whom hold, at a minimum, bachelor's degrees in engineering, and four of whom are Registered Professional Engineers.  The Vice President, Engineering and Acquisitions is the manager of this department and is the primary technical person responsible for this process.  The Vice President, Engineering and Acquisitions holds a Bachelor of Science degree in Petroleum Engineering, has 37 years of experience in reserve evaluations and is a Registered Professional Engineer.

EOG's reserves estimation process is a collaborative effort coordinated by the Engineering and Acquisitions Department in compliance with EOG's internal controls for such process.  Reserve information as well as models used to estimate such reserves are stored on secured databases.  Non-technical inputs used in reserve estimation models, including crude oil, NGLs and natural gas prices, production costs, transportation costs, processing and applicable fractionation costs, future capital expenditures and EOG's net ownership percentages, are obtained from other departments within EOG.  EOG's Internal Audit Department conducts testing with respect to such non-technical inputs.  Additionally, EOG engages DeGolyer and MacNaughton (D&M), independent petroleum consultants, to perform independent reserves evaluation of select EOG properties comprising not less than 75% of EOG's estimates of proved reserves.  EOG's Board of Directors requires that D&M's and EOG's reserve quantities for the properties evaluated by D&M vary by no more than 5% in the aggregate.  Once completed, EOG's year-end reserves are presented to senior management, including the Chairman of the Board and Chief Executive Officer; the President; and the Executive Vice President and Chief Financial Officer, for approval.

Opinions by D&M for the years ended December 31, 2023, 2022 and 2021 covered producing areas containing 83%, 80% and 78%, respectively, of proved reserves of EOG on a net-equivalent-barrel-of-oil basis.  D&M's opinions indicate that the estimates of proved reserves prepared by EOG's Engineering and Acquisitions Department for the properties reviewed by D&M, when compared in total on a net-equivalent-barrel-of-oil basis, do not differ materially from the estimates prepared by D&M.  Specifically, such estimates by D&M in the aggregate varied by not more than 5% from those prepared by the Engineering and Acquisitions Department of EOG.  All reports by D&M were developed utilizing geological and engineering data provided by EOG.  The report of D&M dated January 26, 2024, which contains further discussion of the reserve estimates and evaluations prepared by D&M, as well as the qualifications of D&M's technical person primarily responsible for overseeing such estimates and evaluations, is attached as Exhibit 99.1 to this Annual Report on Form 10-K and incorporated herein by reference.

No major discovery or other favorable or adverse event subsequent to December 31, 2023, is believed to have caused a material change in the estimates of net proved reserves as of that date.

The following tables set forth EOG's net proved reserves at December 31 for each of the four years in the period ended December 31, 2023, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2023, as estimated by the Engineering and Acquisitions Department of EOG:

F-38

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NET PROVED RESERVE SUMMARY

	United States	Trinidad	Other International (1)	Total
NET PROVED RESERVES
Crude Oil (MMBbl) (2)
Net proved reserves at December 31, 2020	1,513	1	—	1,514
Revisions of previous estimates	(116)	—	—	(116)
Purchases in place	2	—	—	2
Extensions, discoveries and other additions	311	1	—	312
Sales in place	(2)	—	—	(2)
Production	(162)	—	—	(162)
Net proved reserves at December 31, 2021	1,546	2	—	1,548
Revisions of previous estimates	120	—	—	120
Purchases in place	7	—	—	7
Extensions, discoveries and other additions	175	—	—	175
Sales in place	(21)	—	—	(21)
Production	(168)	—	—	(168)
Net proved reserves at December 31, 2022	1,659	2	—	1,661
Revisions of previous estimates	56	—	—	56
Purchases in place	1	—	—	1
Extensions, discoveries and other additions	219	—	—	219
Sales in place	(7)	—	—	(7)
Production	(174)	—	—	(174)
Net proved reserves at December 31, 2023	1,754	2	—	1,756
Natural Gas Liquids (MMBbl) (2)
Net proved reserves at December 31, 2020	813	—	—	813
Revisions of previous estimates	(128)	—	—	(128)
Purchases in place	3	—	—	3
Extensions, discoveries and other additions	194	—	—	194
Sales in place	—	—	—	—
Production	(53)	—	—	(53)
Net proved reserves at December 31, 2021	829	—	—	829
Revisions of previous estimates	258	—	—	258
Purchases in place	4	—	—	4
Extensions, discoveries and other additions	140	—	—	140
Sales in place	(14)	—	—	(14)
Production	(72)	—	—	(72)
Net proved reserves at December 31, 2022	1,145	—	—	1,145
Revisions of previous estimates	26	—	—	26
Purchases in place	1	—	—	1
Extensions, discoveries and other additions	169	—	—	169
Sales in place	(5)	—	—	(5)
Production	(82)	—	—	(82)
Net proved reserves at December 31, 2023	1,254	—	—	1,254

F-39

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	United States	Trinidad	Other International (1)	Total
Natural Gas (Bcf) (3)
Net proved reserves at December 31, 2020	5,043	269	48	5,360
Revisions of previous estimates	754	26	3	783
Purchases in place	23	—	—	23
Extensions, discoveries and other additions	2,574	100	—	2,674
Sales in place	(4)	—	(48)	(52)
Production	(483)	(80)	(3)	(566)
Net proved reserves at December 31, 2021	7,907	315	—	8,222
Revisions of previous estimates	(271)	18	—	(253)
Purchases in place	32	—	—	32
Extensions, discoveries and other additions	1,414	51	—	1,465
Sales in place	(316)	—	—	(316)
Production	(493)	(66)	—	(559)
Net proved reserves at December 31, 2022	8,273	318	—	8,591
Revisions of previous estimates	(327)	12	—	(315)
Purchases in place	3	—	—	3
Extensions, discoveries and other additions	1,287	29	—	1,316
Sales in place	(28)	—	—	(28)
Production	(578)	(59)	—	(637)
Net proved reserves at December 31, 2023	8,630	300	—	8,930

F-40

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	United States	Trinidad	Other International (1)	Total
Oil Equivalents (MMBoe) (2)
Net proved reserves at December 31, 2020	3,166	46	8	3,220
Revisions of previous estimates (4)	(118)	4	—	(114)
Purchases in place	9	—	—	9
Extensions, discoveries and other additions (5)	934	18	—	952
Sales in place	(3)	—	(8)	(11)
Production	(295)	(14)	—	(309)
Net proved reserves at December 31, 2021	3,693	54	—	3,747
Revisions of previous estimates (4)	333	3	—	336
Purchases in place	16	—	—	16
Extensions, discoveries and other additions (6)	551	9	—	560
Sales in place	(88)	—	—	(88)
Production	(322)	(11)	—	(333)
Net proved reserves at December 31, 2022	4,183	55	—	4,238
Revisions of previous estimates (4)	28	1	—	29
Purchases in place	2	—	—	2
Extensions, discoveries and other additions (7)	602	5	—	607
Sales in place	(17)	—	—	(17)
Production	(351)	(10)	—	(361)
Net proved reserves at December 31, 2023	4,447	51	—	4,498

(1)Other International includes EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. EOG is continuing the process of exiting its Canada operations.

(2)Million barrels or million barrels of oil equivalent, as applicable; oil equivalents include crude oil and condensate, NGLs and natural gas. Oil equivalents are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas.

(3)Billion cubic feet.

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

(5)Change in net proved reserves for the year ended December 31, 2021, attributable to extensions, discoveries and other additions was 173 MMBoe greater than the corresponding change in PUDs for such year. Such difference represents new proved developed reserves attributable to wells drilled during 2021, primarily in the Permian Basin, that did not have any associated PUDs recorded at the beginning of 2021. The reserves added as new PUDs for the year ended December 31, 2021, attributable to extensions and discoveries were 779 MMBoe and were primarily in the Permian Basin. See "Net Proved Undeveloped Reserves" below.

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

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

F-41

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

During 2022, EOG added 560 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin and Gulf Coast Basin.  Approximately 56% of the 2022 reserve additions were crude oil and condensate and NGLs, and substantially all were in the United States.  Sales in place of 88 MMBoe were primarily related to the sale of assets in the Rocky Mountain area and the Anadarko Basin and the sale or exchange of other producing assets. Refer to "Reconciliation of Revisions of Previous Estimates" below for factors impacting revisions of previous estimates. Purchases in place of 16 MMBoe were primarily related to the Permian Basin and the purchase or exchange of other producing assets.

During 2021, EOG added 952 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin. Approximately 53% of the 2021 reserve additions were crude oil and condensate and NGLs, and substantially all were in the United States. Sales in place of 11 MMBoe were primarily related to the sale of the China assets and the sale or exchange of other producing assets. Refer to "Reconciliation of Revisions of Previous Estimates" below for factors impacting revisions of previous estimates. Purchases in place of 9 MMBoe were primarily related to the Permian Basin and the purchase or exchange of other producing assets.

F-42

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	United States	Trinidad	Other International (1)	Total
NET PROVED DEVELOPED RESERVES
Crude Oil (MMBbl)
December 31, 2020	792	1	—	793
December 31, 2021	886	—	—	886
December 31, 2022	948	—	—	948
December 31, 2023	983	—	—	983
Natural Gas Liquids (MMBbl)
December 31, 2020	392	—	—	392
December 31, 2021	416	—	—	416
December 31, 2022	561	—	—	561
December 31, 2023	625	—	—	625
Natural Gas (Bcf)
December 31, 2020	2,586	171	32	2,789
December 31, 2021	3,743	131	—	3,874
December 31, 2022	3,920	137	—	4,057
December 31, 2023	4,283	161	—	4,444
Oil Equivalents (MMBoe)
December 31, 2020	1,614	30	5	1,649
December 31, 2021	1,926	22	—	1,948
December 31, 2022	2,162	23	—	2,185
December 31, 2023	2,322	27	—	2,349
NET PROVED UNDEVELOPED RESERVES
Crude Oil (MMBbl)
December 31, 2020	721	—	—	721
December 31, 2021	660	2	—	662
December 31, 2022	711	2	—	713
December 31, 2023	771	2	—	773
Natural Gas Liquids (MMBbl)
December 31, 2020	421	—	—	421
December 31, 2021	413	—	—	413
December 31, 2022	584	—	—	584
December 31, 2023	629	—	—	629
Natural Gas (Bcf)
December 31, 2020	2,457	98	16	2,571
December 31, 2021	4,164	184	—	4,348
December 31, 2022	4,353	181	—	4,534
December 31, 2023	4,347	139	—	4,486
Oil Equivalents (MMBoe)
December 31, 2020	1,552	16	3	1,571
December 31, 2021	1,767	32	—	1,799
December 31, 2022	2,021	32	—	2,053
December 31, 2023	2,125	24	—	2,149

(1)Other International includes EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. EOG is continuing the process of exiting its Canada operations.

F-43

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Net Proved Undeveloped Reserves. The following table presents the changes in EOG's total PUDs during 2023, 2022 and 2021 (in MMBoe):

	2023	2022	2021
Balance at January 1	2,053	1,799	1,571
Extensions and Discoveries (1)	516	410	779
Revisions (2)	(51)	141	(305)
Acquisition of Reserves	—	10	—
Sale of Reserves	(9)	(14)	(3)
Conversion to Proved Developed Reserves	(360)	(293)	(243)
Balance at December 31	2,149	2,053	1,799

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

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

For the twelve-month period ended December 31, 2023, total PUDs increased by 96 MMBoe to 2,149 MMBoe.  EOG added approximately 44 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion.  Based on the technology employed by EOG to identify and record PUDs (see discussion of technology employed on pages F-37 and F-38 of this Annual Report on Form 10-K), EOG added 472 MMBoe of PUDs.  The PUD additions were primarily in the Permian Basin and 65% of the additions were crude oil and condensate and NGLs.  During 2023, EOG drilled and transferred 360 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,801 million. Refer to "Reconciliation of Revisions of Previous Estimates" below for factors impacting revisions of previous estimates. All PUDs, including drilled but uncompleted wells (DUCs), are scheduled for completion within five years of the original reserve booking.

For the twelve-month period ended December 31, 2022, total PUDs increased by 254 MMBoe to 2,053 MMBoe.  EOG added approximately 25 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion.  Based on the technology employed by EOG to identify and record PUDs, EOG added 385 MMBoe of PUDs.  The PUD additions were primarily in the Permian Basin and 57% of the additions were crude oil and condensate and NGLs.  During 2022, EOG drilled and transferred 293 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,286 million. Refer to "Reconciliation of Revisions of Previous Estimates" below for factors impacting revisions of previous estimates. All PUDs, including DUCs, are scheduled for completion within five years of the original reserve booking.

For the twelve-month period ended December 31, 2021, total PUDs increased by 228 MMBoe to 1,799 MMBoe.  EOG added approximately 40 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion.  Based on the technology employed by EOG to identify and record PUDs, EOG added 739 MMBoe of PUDs.  The PUD additions were primarily in the Permian Basin and 52% of the additions were crude oil and condensate and NGLs.  During 2021, EOG drilled and transferred 243 MMBoe of PUDs to proved developed reserves at a total capital cost of $1,619 million. Refer to "Reconciliation of Revisions of Previous Estimates" below for factors impacting revisions of previous estimates. All PUDs, including DUCs, are scheduled for completion within five years of the original reserve booking.

F-44

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

Pursuant to such process, EOG's technical staff included a net positive revision of 45 MMBoe of PUD reserves to its net proved reserves for the year ended December 31, 2023 and a net positive revision of 79 MMBoe and a negative revision of 250 MMBoe of PUD reserves from its net proved reserves for the years ended December 31, 2022 and 2021, respectively.

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

•crude oil, NGLs and natural gas prices;

•EOG's well performance forecasts;

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

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

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

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

EOG's evaluation of such inter-related factors resulted in the following revisions to its net proved reserves and net PUD reserves for the years ended December 31, 2023, 2022 and 2021.

F-45

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

F-46

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Year Ended December 31, 2022
Review of Updated Plan		Revision to Net Proved Reserves (MMBoe)		Revision to Net PUD Reserves (MMBoe)	Explanation
Revision related to addition of PUD reserves pursuant to review of updated drilling and development plan		79		79	See above related discussion.
Evaluation of Inter-Related Factors
Prices for crude oil, NGLs and natural gas	11		2		Upward revisions attributable to an increase in the average prices used in EOG's year-end 2022 reserves estimates as compared to the average prices used in EOG's year-end 2021 reserves estimates.
Well performance forecasts	104		(9)		Revisions attributable to EOG's forecasted changes in well performance in certain locations.
Marketing-related changes (e.g., ethane recovery elections) relating to the sale of production	151		68		Upward revisions attributable to EOG's "ethane recovery" elections during 2022 - that is, EOG's elections to increase receipt of ethane (an NGL) from the natural gas stream and reduce the total volume of residue natural gas at the tailgate of the processing plant. The additional NGL reserves attributable to such elections outweigh the lower natural gas reserves.
Ownership interest changes	(2)		1		Revisions attributable to ownership interest changes.
Changes in operating costs	(7)		—		Downward revision attributable to increased operating costs, resulting in a decrease in reserves that are economically producible.
Net Revisions Attributable to Inter-Related Factors		257		62
Total Revisions		336		141

F-47

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Year Ended December 31, 2021
Review of Updated Plan		Revision to Net Proved Reserves (MMBoe)		Revision to Net PUD Reserves (MMBoe)	Explanation
Revision related to removal of PUD reserves pursuant to review of updated drilling and development plan		(250)		(250)	See above related discussion.
Evaluation of Inter-Related Factors
Prices for crude oil, NGLs and natural gas	194		29		Upward revisions attributable to an increase in the average prices used in EOG's year-end 2021 reserves estimates as compared to the average prices used in EOG's year-end 2020 reserves estimates.
Well performance forecasts	(13)		(51)		Downward revisions attributable to EOG's forecasted decrease in well performance in certain locations.
Marketing-related changes (e.g., ethane rejection elections) relating to the sale of production	(69)		(38)		Downward revisions attributable to EOG's "ethane rejection" elections during 2021 - that is, EOG's elections to reduce receipt of ethane (an NGL) from the natural gas stream and instead receive residue natural gas (that includes ethane) at the tailgate of the processing plant. The additional natural gas reserves attributable to such elections are outweighed by lower NGLs reserves.
Ownership interest changes	8		—		Upward revision attributable to ownership interest changes.
Changes in operating costs	16		5		Upward revisions attributable to improved/lower operating costs, resulting in an increase in reserves that are economically producible.
Net Revisions Attributable to Inter-Related Factors		136		(55)
Total Revisions		(114)		(305)

F-48

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Capitalized Costs Relating to Oil and Gas Producing Activities.  The following table sets forth the capitalized costs relating to EOG's crude oil, NGLs and natural gas producing activities at December 31, 2023 and 2022 (in millions):

	2023		2022
Proved properties	$	69,618	$	64,657
Unproved properties	2,472		2,665
Total	72,090		67,322
Accumulated depreciation, depletion and amortization	(43,323)		(40,791)
Net capitalized costs	$	28,767	$	26,531

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

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

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

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

F-49

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table sets forth costs incurred related to EOG's oil and gas activities for the years ended December 31, 2023, 2022 and 2021 (in millions):

	United States		Trinidad		Other International (1)		Total
2023
Acquisition Costs of Properties
Unproved (2)	$	207	$	—	$	—	$	207
Proved (3)	16		—		—		16
Subtotal	223		—		—		223
Exploration Costs	370		53		14		437
Development Costs (4)	5,228		117		13		5,358
Total	$	5,821	$	170	$	27	$	6,018
2022
Acquisition Costs of Properties
Unproved (5)	$	186	$	—	$	—	$	186
Proved (6)	419		—		—		419
Subtotal	605		—		—		605
Exploration Costs	263		84		17		364
Development Costs (7)	4,106		145		9		4,260
Total	$	4,974	$	229	$	26	$	5,229
2021
Acquisition Costs of Properties
Unproved (8)	$	207	$	—	$	8	$	215
Proved (9)	100		—		—		100
Subtotal	307		—		8		315
Exploration Costs	296		7		51		354
Development Costs (10)	3,206		77		17		3,300
Total	$	3,809	$	84	$	76	$	3,969

(1)Other International primarily consists of EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. EOG is continuing the process of exiting its Canada operations. EOG began exploration programs in Australia in the third quarter of 2021 and in Oman in the third quarter of 2020. The decision was reached in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman.

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

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

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

(5)Includes non-cash unproved leasehold acquisition costs of $127 million related to property exchanges.

(6)Includes non-cash proved property acquisition costs of $26 million related to property exchanges.

(7)Includes Asset Retirement Costs of $208 million, $81 million and $9 million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment.

(8)Includes non-cash unproved leasehold acquisition costs of $45 million related to property exchanges.

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

(10)Includes Asset Retirement Costs of $86 million, $24 million and $17 million for the United States, Trinidad and Other International, respectively.  Excludes other property, plant and equipment.

F-50

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Results of Operations for Oil and Gas Producing Activities (1). The following table sets forth results of operations for oil and gas producing activities for the years ended December 31, 2023, 2022 and 2021 (in millions):

	United States		Trinidad		Other International (2)		Total
2023
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	17,148	$	228	$	—	$	17,376
Other	91		—		—		91
Total	17,239		228		—		17,467
Exploration Costs	166		4		11		181
Dry Hole Costs	1		—		—		1
Transportation Costs	957		—		—		957
Gathering and Processing Costs	663		—		—		663
Production Costs	2,657		45		1		2,703
Impairments	184		—		18		202
Depreciation, Depletion and Amortization	3,244		78		—		3,322
Income (Loss) Before Income Taxes	9,367		101		(30)		9,438
Income Tax Provision	2,056		8		(2)		2,062
Results of Operations	$	7,311	$	93	$	(28)	$	7,376
2022
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	22,486	$	310	$	—	$	22,796
Other	118		—		—		118
Total	22,604		310		—		22,914
Exploration Costs	145		4		10		159
Dry Hole Costs	22		21		2		45
Transportation Costs	966		—		—		966
Gathering and Processing Costs	621		—		—		621
Production Costs	2,833		41		2		2,876
Impairments	340		28		14		382
Depreciation, Depletion and Amortization	3,314		72		—		3,386
Income (Loss) Before Income Taxes	14,363		144		(28)		14,479
Income Tax Provision	3,129		60		(2)		3,187
Results of Operations	$	11,234	$	84	$	(26)	$	11,292
2021
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	15,062	$	301	$	18	$	15,381
Other	108		—		—		108
Total	15,170		301		18		15,489
Exploration Costs	137		5		12		154
Dry Hole Costs	29		—		42		71
Transportation Costs	863		—		—		863
Gathering and Processing Costs	559		—		—		559
Production Costs	2,108		39		8		2,155
Impairments	312		3		61		376
Depreciation, Depletion and Amortization	3,411		87		6		3,504
Income (Loss) Before Income Taxes	7,751		167		(111)		7,807
Income Tax Provision	1,690		73		(1)		1,762
Results of Operations	$	6,061	$	94	$	(110)	$	6,045

(1)Excludes gains or losses on the mark-to-market of financial commodity derivative contracts, gains or losses on sales of reserves and related assets, interest charges and general corporate expenses for each of the three years in the period ended December 31, 2023.

(2)Other International primarily consists of EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. EOG is continuing the process of exiting its Canada operations. EOG began exploration programs in Australia in the third quarter of 2021 and in Oman in the third quarter of 2020. The decision was reached in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman.

F-51

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table sets forth production costs per barrel of oil equivalent, excluding severance/production and ad valorem taxes, for the years ended December 31, 2023, 2022 and 2021:

	United States		Trinidad		Other International (1)		Composite
Year Ended December 31, 2023	$	4.01	$	4.19	$	—	$	4.02
Year Ended December 31, 2022	$	4.02	$	3.11	$	—	$	3.99
Year Ended December 31, 2021	$	3.71	$	2.32	$	16.13	$	3.67

(1)    Other International primarily consists of EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. EOG is continuing the process of exiting its Canada operations.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves.  The following information has been developed utilizing procedures prescribed by the Extractive Industries - Oil and Gas Topic of the ASC and based on crude oil, NGL and natural gas reserves and production volumes estimated by the Engineering and Acquisitions Department of EOG.  The estimates were based on a 12-month average for commodity prices for the years 2023, 2022 and 2021.  The following information may be useful for certain comparative purposes, but should not be solely relied upon in evaluating EOG or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of EOG.

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

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

F-52

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table sets forth the standardized measure of discounted future net cash flows from projected production of EOG's oil and gas reserves for the years ended December 31, 2023, 2022 and 2021 (in millions):

	United States		Trinidad		Other International (1)		Total
2023
Future cash inflows (2)	$	188,585	$	1,101	$	—	$	189,686
Future production costs	(65,349)		(245)		—		(65,594)
Future development costs (3)	(20,070)		(406)		—		(20,476)
Future income taxes	(21,632)		(40)		—		(21,672)
Future net cash flows	81,534		410		—		81,944
Discount to present value at 10% annual rate	(38,879)		(73)		—		(38,952)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	42,655	$	337	$	—	$	42,992
2022
Future cash inflows (4)	$	259,217	$	1,189	$	—	$	260,406
Future production costs	(58,021)		(248)		—		(58,269)
Future development costs (5)	(17,837)		(471)		—		(18,308)
Future income taxes	(39,560)		(31)		—		(39,591)
Future net cash flows	143,799		439		—		144,238
Discount to present value at 10% annual rate	(69,587)		(79)		—		(69,666)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	74,212	$	360	$	—	$	74,572
2021
Future cash inflows (6)	$	166,316	$	1,135	$	—	$	167,451
Future production costs	(44,905)		(258)		—		(45,163)
Future development costs (7)	(13,885)		(380)		—		(14,265)
Future income taxes	(22,831)		(84)		—		(22,915)
Future net cash flows	84,695		413		—		85,108
Discount to present value at 10% annual rate	(38,834)		(88)		—		(38,922)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	45,861	$	325	$	—	$	46,186

(1)Other International includes EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. EOG is continuing the process of exiting its Canada operations.

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

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

(4)Estimated crude oil prices used to calculate 2022 future cash inflows for the United States and Trinidad were $96.44 and $85.90, respectively. Estimated NGL price used to calculate 2022 future cash inflows for the United States was $36.35. Estimated natural gas prices used to calculate 2022 future cash inflows for the United States and Trinidad were $6.96 and $3.28, respectively.

(5)Future abandonment costs included in 2022 future development costs for the United States and Trinidad were $1,578 million and $188 million, respectively.

(6)Estimated crude oil prices used to calculate 2021 future cash inflows for the United States and Trinidad were $67.79 and $58.32, respectively. Estimated NGLs price used to calculate 2021 future cash inflows for the United States was $30.28. Estimated natural gas prices used to calculate 2021 future cash inflows for the United States and Trinidad were $4.61 and $3.28, respectively.

(7)Future abandonment costs included in 2021 future development costs for the United States and Trinidad were $2,586 million and $102 million, respectively.

F-53

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

Changes in Standardized Measure of Discounted Future Net Cash Flows. The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for each of the three years in the period ended December 31, 2023 (in millions):

	United States		Trinidad		Other International (1)		Total
December 31, 2020	$	11,202	$	339	$	149	$	11,690
Sales and transfers of oil and gas produced, net of production costs	(11,532)		(261)		(16)		(11,809)
Net changes in prices and production costs	37,088		133		(1)		37,220
Extensions, discoveries, additions and improved recovery, net of related costs	12,154		71		—		12,225
Development costs incurred	1,619		16		—		1,635
Revisions of estimated development cost	2,773		(133)		—		2,640
Revisions of previous quantity estimates	(1,789)		73		—		(1,716)
Accretion of discount	1,313		42		17		1,372
Net change in income taxes	(9,914)		27		17		(9,870)
Purchases of reserves in place	151		—		—		151
Sales of reserves in place	(19)		—		(151)		(170)
Changes in timing and other	2,815		18		(15)		2,818
December 31, 2021	$	45,861	$	325	$	—	$	46,186
Sales and transfers of oil and gas produced, net of production costs	(18,064)		(269)		1		(18,332)
Net changes in prices and production costs	30,987		86		—		31,073
Extensions, discoveries, additions and improved recovery, net of related costs	10,422		128		—		10,550
Development costs incurred	2,286		—		—		2,286
Revisions of estimated development cost	(2,290)		(70)		—		(2,360)
Revisions of previous quantity estimates	8,324		40		—		8,364
Accretion of discount	5,771		38		—		5,809
Net change in income taxes	(8,059)		50		—		(8,009)
Purchases of reserves in place	400		—		—		400
Sales of reserves in place	(760)		—		—		(760)
Changes in timing and other	(666)		32		(1)		(635)
December 31, 2022	$	74,212	$	360	$	—	$	74,572
Sales and transfers of oil and gas produced, net of production costs	(12,872)		(182)		—		(13,054)
Net changes in prices and production costs	(41,377)		8		—		(41,369)
Extensions, discoveries, additions and improved recovery, net of related costs	4,825		42		—		4,867
Development costs incurred	2,801		48		—		2,849
Revisions of estimated development cost	(644)		13		—		(631)
Revisions of previous quantity estimates	381		27		—		408
Accretion of discount	9,411		37		—		9,448
Net change in income taxes	9,250		(18)		—		9,232
Purchases of reserves in place	31		—		—		31
Sales of reserves in place	(294)		—		—		(294)
Changes in timing and other	(3,069)		2		—		(3,067)
December 31, 2023	$	42,655	$	337	$	—	$	42,992

(1)    Other International includes EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. EOG is continuing the process of exiting its Canada operations.

F-54

EXHIBITS

Exhibits not incorporated herein by reference to a prior filing are designated by (i) an asterisk (*) and are filed herewith; or (ii) a pound sign (#) and are not filed herewith, and, pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, the registrant hereby agrees to furnish a copy of such exhibit to the United States Securities and Exchange Commission (SEC) upon request.

Exhibit Number		Description
3.1(a)	-	Restated Certificate of Incorporation, dated September 3, 1987 (Exhibit 3.1(a) to EOG's Annual Report on Form 10-K for the year ended December 31, 2008) (SEC File No. 001-09743).
3.1(b)	-	Certificate of Amendment of Restated Certificate of Incorporation, dated May 5, 1993 (Exhibit 4.1(b) to EOG's Registration Statement on Form S-8, SEC File No. 33-52201, filed February 8, 1994).
3.1(c)	-	Certificate of Amendment of Restated Certificate of Incorporation, dated June 14, 1994 (Exhibit 4.1(c) to EOG's Registration Statement on Form S-8, SEC File No. 33-58103, filed March 15, 1995).
3.1(d)	-	Certificate of Amendment of Restated Certificate of Incorporation, dated June 11, 1996 (Exhibit 3(d) to EOG's Registration Statement on Form S-3, SEC File No. 333-09919, filed August 9, 1996).
3.1(e)	-	Certificate of Amendment of Restated Certificate of Incorporation, dated May 7, 1997 (Exhibit 3(e) to EOG's Registration Statement on Form S-3, SEC File No. 333-44785, filed January 23, 1998).
3.1(f)	-	Certificate of Ownership and Merger Merging EOG Resources, Inc. into Enron Oil & Gas Company, dated August 26, 1999 (Exhibit 3.1(f) to EOG's Annual Report on Form 10-K for the year ended December 31, 1999) (SEC File No. 001-09743).
3.1(g)	-	Certificate of Designations of Series E Junior Participating Preferred Stock, dated February 14, 2000 (Exhibit 2 to EOG's Registration Statement on Form 8-A, SEC File No. 001-09743, filed February 18, 2000).
3.1(h)	-	Certificate of Elimination of the Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series A, dated September 13, 2000 (Exhibit 3.1(j) to EOG's Registration Statement on Form S-3, SEC File No. 333-46858, filed September 28, 2000).
3.1(i)	-	Certificate of Elimination of the Flexible Money Market Cumulative Preferred Stock, Series C, dated September 13, 2000 (Exhibit 3.1(k) to EOG's Registration Statement on Form S-3, SEC File No. 333-46858, filed September 28, 2000).
3.1(j)	-	Certificate of Elimination of the Flexible Money Market Cumulative Preferred Stock, Series D, dated February 24, 2005 (Exhibit 3.1(k) to EOG's Annual Report on Form 10-K for the year ended December 31, 2004) (SEC File No. 001-09743).
3.1(k)	-	Amended Certificate of Designations of Series E Junior Participating Preferred Stock, dated March 7, 2005 (Exhibit 3.1(m) to EOG's Annual Report on Form 10-K for the year ended December 31, 2007) (SEC File No. 001-09743).
3.1(l)	-	Certificate of Amendment of Restated Certificate of Incorporation, dated May 3, 2005 (Exhibit 3.1(l) to EOG's Quarterly Report on Form 10-Q for the quarter ended June 30, 2005) (SEC File No. 001-09743).
3.1(m)	-	Certificate of Elimination of Fixed Rate Cumulative Perpetual Senior Preferred Stock, Series B, dated March 6, 2008 (Exhibit 3.1 to EOG's Current Report on Form 8-K, filed March 6, 2008) (SEC File No. 001-09743).
3.1(n)	-	Certificate of Amendment of Restated Certificate of Incorporation, dated April 28, 2017 (Exhibit 3.1 to EOG's Current Report on Form 8-K, filed May 2, 2017) (SEC File No. 001-09743).
3.2(a)	-	Bylaws, dated August 23, 1989, as amended and restated effective as of September 22, 2015 (Exhibit 3.1 to EOG's Current Report on Form 8-K, filed September 28, 2015) (SEC File No. 001-09743).
3.2(b)	-	Bylaws, dated August 23, 1989, as amended and restated effective as of February 23, 2023 (Exhibit 3.2(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 2022) (SEC File No. 001-09743).
4.1	-	Description of Securities Registered Under Section 12 of the Securities Exchange Act of 1934 (Exhibit 4.1 to EOG's Annual Report on Form 10-K for the year ended December 31, 2019) (SEC File No. 001-09743).
4.2	-	Indenture, dated as of September 1, 1991, between Enron Oil & Gas Company (predecessor to EOG) and The Bank of New York Mellon Trust Company, N.A. (as successor in interest to JPMorgan Chase Bank, N.A. (formerly, Texas Commerce Bank National Association)), as Trustee (Exhibit 4(a) to EOG's Registration Statement on Form S-3, SEC File No. 33-42640, filed in paper format on September 6, 1991).

E-1

Exhibit Number		Description
#4.3(a)	-	Certificate, dated April 3, 1998, of the Senior Vice President and Chief Financial Officer of Enron Oil & Gas Company (predecessor to EOG) establishing the terms of the 6.65% Notes due April 1, 2028 of Enron Oil & Gas Company.
#4.3(b)	-	Global Note with respect to the 6.65% Notes due April 1, 2028 of Enron Oil & Gas Company (predecessor to EOG).
4.4	-	Indenture, dated as of May 18, 2009, between EOG and Computershare Trust Company, N.A. (as successor to Wells Fargo Bank, National Association), as Trustee (Exhibit 4.9 to EOG's Registration Statement on Form S-3, SEC File No. 333-159301, filed May 18, 2009).
4.5(a)	-	Officers' Certificate Establishing 3.15% Senior Notes due 2025 and 3.90% Senior Notes due 2035 of EOG, dated March 17, 2015 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed March 19, 2015) (SEC File No. 001-09743).
4.5(b)	-	Form of Global Note with respect to the 3.15% Senior Notes due 2025 of EOG (Exhibit 4.3 to EOG's Current Report on Form 8-K, filed March 19, 2015) (SEC File No. 001-09743).
4.5(c)	-	Form of Global Note with respect to the 3.90% Senior Notes due 2035 of EOG (Exhibit 4.4 to EOG's Current Report on Form 8-K, filed March 19, 2015) (SEC File No. 001-09743).
4.6(a)	-	Officers' Certificate Establishing 4.15% Senior Notes due 2026 and 5.10% Senior Notes due 2036 of EOG, dated January 14, 2016 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed January 15, 2016) (SEC File No. 001-09743).
4.6(b)	-	Form of Global Note with respect to the 4.15% Senior Notes due 2026 of EOG (Exhibit 4.3 to EOG's Current Report on Form 8-K, filed January 15, 2016) (SEC File No. 001-09743).
4.6(c)	-	Form of Global Note with respect to the 5.10% Senior Notes due 2036 of EOG (Exhibit 4.4 to EOG's Current Report on Form 8-K, filed January 15, 2016) (SEC File No. 001-09743).
4.7(a)	-	Officers' Certificate Establishing 4.375% Senior Notes due 2030 and 4.950% Senior Notes due 2050 of EOG, dated April 14, 2020 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed April 14, 2020) (SEC File No. 001-09743).
4.7(b)	-	Form of Global Note with respect to the 4.375% Senior Notes due 2030 of EOG (included in Exhibit 4.10(a)).
4.7(c)	-	Form of Global Note with respect to the 4.950% Senior Notes due 2050 of EOG (included in Exhibit 4.10(a)).
10.1(a)+	-	Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan, effective as of May 2, 2013 (Exhibit 4.4 to EOG's Registration Statement on Form S-8, SEC File No. 333-188352, filed May 3, 2013).
10.1(b)+	-	Form of Restricted Stock Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made on or after September 28, 2020) (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2020) (SEC File No. 001-09743).
10.1(c)+	-	Form of Restricted Stock Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made on or after September 28, 2020) (Exhibit 10.2 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2020) (SEC File No. 001-09743).
10.1(d)+	-	Form of Stock-Settled Stock Appreciation Right Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made on or after September 25, 2017 and prior to September 28, 2020) (Exhibit 10.4 to EOG's Current Report on Form 8-K, filed September 29, 2017) (SEC File No. 001-09743).
10.1(e)+	-	Form of Stock-Settled Stock Appreciation Right Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made on or after September 28, 2020) (Exhibit 10.3 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2020) (SEC File No. 001-09743).
10.1(f)+	-	Form of Performance Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made on or after September 28, 2020) (Exhibit 10.4 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2020) (SEC File No. 001-09743).

E-2

Exhibit Number		Description
10.1(g)+	-	Form of Performance Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable solely to grant made to Ezra Y. Yacob effective January 4, 2021) (Exhibit 10.1(u) to EOG's Annual Report on Form 10-K for the year ended December 31, 2020) (SEC File No. 001-09743).
10.1(h)	-	Form of Non-Employee Director Restricted Stock Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made on or after May 6, 2019) (Exhibit 10.2 to EOG's Quarterly Report on Form 10-Q for the quarter ended June 30, 2019) (SEC File No. 001-09743).
10.2(a)+	-	EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan, dated effective as of April 29, 2021 (Exhibit 4.4 to EOG's Registration Statement on Form S-8, SEC File No. 333-255691, filed April 30, 2021).
10.2(b)+	-	Form of Restricted Stock Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (applicable to grants made prior to September 15, 2023) (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2021) (SEC File No. 001-09743).
10.2(c)+	-	Form of Restricted Stock Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (applicable to grants made on or after September 15, 2023 and prior to December 18, 2023) (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2023 (SEC File No. 001-09743).
*10.2(d)+	-	Form of Restricted Stock Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (applicable to grants made on or after December 18, 2023).
10.2(e)+	-	Form of Restricted Stock Unit Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (applicable to grants made prior to September 15, 2023) (Exhibit 10.2 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2021) (SEC File No. 001-09743).
10.2(f)+	-	Form of Restricted Stock Unit Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (applicable to grants made on or after September 15, 2023 and prior to December 18, 2023) (Exhibit 10.2 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2023) (SEC File No. 001-09743).
*10.2(g)+	-	Form of Restricted Stock Unit Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (applicable to grants made on or after December 18, 2023).
10.2(h)+	-	Form of Stock-Settled Stock Appreciation Right Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (Exhibit 10.3 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2021) (SEC File No. 001-09743).
10.2(i)+	-	Form of Restricted Stock Unit with Performance-Based Conditions ("Performance Unit") Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (applicable to grants made prior to September 29, 2022) (Exhibit 10.4 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2021) (SEC File No. 001-09743).
10.2(j)+	-	Restricted Stock Unit with Performance-Based Conditions ("Performance Unit") Award Agreement under EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan, by and between EOG and William R. Thomas, effective September 27, 2021 (Exhibit 10.5 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2021) (SEC File No. 001-09743).
10.2(k)+	-	Form of Restricted Stock Unit with Performance-Based Conditions ("Performance Unit") Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (applicable to grants made on or after September 29, 2022 and prior to September 15, 2023) (Exhibit 10.1 to EOG's Current Report on Form 8-K, filed October 4, 2022) (SEC File No. 001-09743).
10.2(l)+	-	Form of Restricted Stock Unit with Performance-Based Conditions ("Performance Unit") Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (applicable to grants made on or after September 15, 2023 and prior to December 18, 2023) (Exhibit 10.3 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2023) (SEC File No. 001-09743).
*10.2(m)+	-	Form of Restricted Stock Unit with Performance-Based Conditions ("Performance Unit") Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (amended and restated award agreement applicable solely to grants made effective September 15, 2023).
*10.2(n)+	-	Form of Restricted Stock Unit with Performance-Based Conditions ("Performance Unit") Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (applicable to grants made on or after December 18, 2023).

E-3

Exhibit Number		Description
*10.2(o)+	-	Form of Restricted Stock Unit with Performance-Based Conditions ("Performance Unit") Award Agreement for EOG Resources, Inc. Omnibus Equity Compensation Plan (applicable solely to grant made to Ann D. Janssen effective January 2, 2023).
10.2(p)	-	Form of Non-Employee Director Restricted Stock Unit Award Agreement for EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (Exhibit 10.6 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2021) (SEC File No. 001-09743).
10.3(a)+	-	EOG Resources, Inc. 409A Deferred Compensation Plan - Nonqualified Supplemental Deferred Compensation Plan - Plan Document, effective as of December 16, 2008 (Exhibit 10.2(a) to EOG's Annual Report on Form 10-K for the year ended December 31, 2008) (SEC File No. 001-09743).
10.3(b)+	-	EOG Resources, Inc. 409A Deferred Compensation Plan - Nonqualified Supplemental Deferred Compensation Plan - Adoption Agreement, originally dated as of December 16, 2008 (and as amended through February 24, 2012 (including an amendment to Item 7 thereof, effective January 1, 2012, with respect to the deferral of restricted stock units)) (Exhibit 10.2(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 2011) (originally filed as Exhibit 10.2(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 2008) (SEC File No. 001-09743).
10.3(c)+	-	First Amendment to the EOG Resources, Inc. 409A Deferred Compensation Plan, effective as of January 1, 2013 (Exhibit 10.8 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013) (SEC File No. 001-09743).
10.3(d)+	-	Amendment 2 to the EOG Resources, Inc. 409A Deferred Compensation Plan, effective as of January 1, 2018 (Exhibit 10.3(d) to EOG's Annual Report on Form 10-K for the year ended December 31, 2018) (SEC File No. 001-09743).
10.3(e)+	-	Third Amendment to the EOG Resources, Inc. 409A Deferred Compensation Plan, effective as of December 17, 2020 (Exhibit 10.2(e) to EOG's Annual Report on Form 10-K for the year ended December 31, 2020) (SEC File No. 001-09743).
10.4(a)+	-	Amended and Restated Change of Control Agreement between EOG and Timothy K. Driggers, effective as of June 15, 2005 (Exhibit 99.11 to EOG's Current Report on Form 8-K, filed June 21, 2005) (SEC File No. 001-09743).
10.4(b)+	-	First Amendment to Amended and Restated Change of Control Agreement between EOG and Timothy K. Driggers, effective as of April 30, 2009 (Exhibit 10.5 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2009) (SEC File No. 001-09743).
10.4(c)+	-	Second Amendment to Amended and Restated Change of Control Agreement between EOG and Timothy K. Driggers, effective as of September 13, 2011 (Exhibit 10.4 to EOG's Current Report on Form 8-K, filed September 13, 2011) (SEC File No. 001-09743).
10.5(a)+	-	Change of Control Agreement by and between EOG and Michael P. Donaldson, effective as of May 3, 2012 (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended June 30, 2012) (SEC File No. 001-09743).
10.5(b)+	-	First Amendment to Change of Control Agreement between EOG and Michael P. Donaldson, effective as of September 4, 2013 (Exhibit 10.7 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013) (SEC File No. 001-09743).
10.6(a)+	-	Change of Control Agreement by and between EOG and Lloyd W. Helms, effective as of June 27, 2013 (Exhibit 10.9 to EOG's Quarterly Report on Form 10-Q for the quarter ended June 30, 2013) (SEC File No. 001-09743).
10.6(b)+	-	First Amendment to Change of Control Agreement between EOG and Lloyd W. Helms, Jr., effective as of September 4, 2013 (Exhibit 10.4 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013) (SEC File No. 001-09743).
10.7+	-	Change of Control Agreement by and between EOG and Ezra Y. Yacob, effective as of January 26, 2018 (Exhibit 10.10 to EOG's Annual Report on Form 10-K for the year ended December 31, 2017) (SEC File No. 001-09743).
10.8(a)+	-	Change of Control Agreement by and between EOG and Kenneth W. Boedeker, effective as of December 19, 2018 (Exhibit 10.11 to EOG's Annual Report on Form 10-K for the year ended December 31, 2018) (SEC File No. 001-09743).

E-4

Exhibit Number		Description
10.8(b)+	-	Retirement Notice and Letter, dated September 11, 2023, by and between EOG and Kenneth W. Boedeker (Exhibit 10.4 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2023) (SEC File No. 001-09743).
10.9+	-	Change of Control Agreement by and between EOG and Jeffrey R. Leitzell, effective as of June 17, 2021 (Exhibit 10.2 to EOG's Quarterly Report on Form 10-Q for the quarter ended June 30, 2021 (SEC File No. 001-09743).
*10.10+	-	Change of Control Agreement by and between EOG and Ann D. Janssen, effective as of February 2, 2024.
10.11(a)+	-	EOG Resources, Inc. Change of Control Severance Plan, as amended and restated effective as of June 15, 2005 (Exhibit 99.12 to EOG's Current Report on Form 8-K, filed June 21, 2005) (SEC File No. 001-09743).
10.11(b)+	-	First Amendment to the EOG Resources, Inc. Change of Control Severance Plan, effective as of April 30, 2009 (Exhibit 10.6 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2009) (SEC File No. 001-09743).
10.12(a)+	-	EOG Resources, Inc. Annual Bonus Plan (effective January 1, 2019) (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2019) (SEC File No. 001-09743).
10.12(b)+	-	EOG Resources, Inc. Amended and Restated Annual Bonus Plan (effective as of January 1, 2022) (Exhibit 10.2 to EOG's Current Report on Form 8-K, filed October 4, 2022) (SEC File No. 001-09743).
*10.12(c)+	-	EOG Resources, Inc. Second Amended and Restated Annual Bonus Plan (effective as of January 1, 2024).
10.13+	-	EOG Resources, Inc. Employee Stock Purchase Plan (As Amended and Restated Effective January 1, 2018) (Exhibit 4.4(a) to EOG's Registration Statement on Form S-8, SEC File No. 333-224466, filed April 26, 2018).
10.14	-	Revolving Credit Agreement, dated as of June 7, 2023, among EOG, JPMorgan Chase Bank, N.A., as Administrative Agent, the financial institutions as bank parties thereto, and the other parties thereto (Exhibit 10.1 to EOG's Current Report on Form 8-K, filed June 12, 2023) (SEC File No. 001-09743).
*21	-	Subsidiaries of EOG, as of December 31, 2023.
*23.1	-	Consent of DeGolyer and MacNaughton.
*23.2	-	Consent of Deloitte & Touche LLP.
*24	-	Powers of Attorney.
*31.1	-	Section 302 Certification of Annual Report of Principal Executive Officer.
*31.2	-	Section 302 Certification of Annual Report of Principal Financial Officer.
*32.1	-	Section 906 Certification of Annual Report of Principal Executive Officer.
*32.2	-	Section 906 Certification of Annual Report of Principal Financial Officer.
*97+	-	EOG Resources, Inc. Policy for the Recovery of Erroneously Awarded Compensation, adopted September 13, 2023.
*99.1	-	Opinion of DeGolyer and MacNaughton, dated January 26, 2024.
101.INS	-	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
*  **101.SCH	-	Inline XBRL Schema Document.
*  **101.CAL	-	Inline XBRL Calculation Linkbase Document.
*  **101.DEF	-	Inline XBRL Definition Linkbase Document.
*  **101.LAB	-	Inline XBRL Label Linkbase Document.
*  **101.PRE	-	Inline XBRL Presentation Linkbase Document.
104	-	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

E-5

*Exhibits filed herewith

**Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Statements of Income and Comprehensive Income for Each of the Three Years in the Period Ended December 31, 2023, (ii) the Consolidated Balance Sheets - December 31, 2023 and 2022, (iii) the Consolidated Statements of Stockholders' Equity for Each of the Three Years in the Period Ended December 31, 2023, (iv) the Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2023 and (v) the Notes to Consolidated Financial Statements.

+ Management contract, compensatory plan or arrangement

E-6

SIGNATURES

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

			EOG RESOURCES, INC.
			(Registrant)
Date:	February 22, 2024	By:	/s/ ANN D. JANSSEN                                                                        Ann D. Janssen Executive Vice President and Chief Financial Officer (Principal Financial Officer and Duly Authorized Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the registrant and in the capacities with EOG Resources, Inc. indicated and on the 22nd day of February, 2024.

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

EX-10.2D

Exhibit 10.2(d)

This document constitutes part of a prospectus covering securities

that have been registered under the Securities Act of 1933.

EOG RESOURCES, INC.

RESTRICTED STOCK AWARD AGREEMENT

GRANTEE: [Participant Name: First Name Middle Name Last Name] [Participant ID: Participant ID]

Congratulations! If you accept the terms of this Agreement, you will be granted an Award of EOG Resources, Inc. Restricted Stock as follows:

Date of Grant	[Grant Date: Month DD, YYYY]
Shares of Restricted Stock granted under this Award	[Granted: Shares Granted]
Vesting Date	Third anniversary of Date of Grant

If you accept the terms of this Agreement, the Compensation and Human Resources Committee of the Board of EOG Resources, Inc. (the “Company”) hereby grants to you, the above-named Grantee, effective as of the Date of Grant set forth above, a Restricted Stock Award (the “Award”) in accordance with the terms set forth below.

General. This Restricted Stock Award Agreement (this “Agreement”) is governed by the terms and conditions of the EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (as may be amended from time to time, the “Plan”), which is hereby made a part of this Agreement. All capitalized terms that are not defined in this Agreement have the meanings ascribed to them under the Plan. Under the terms of this Agreement and the Plan, a Restricted Stock book entry will be maintained by the Company (or its agent) until you become vested in the shares of Restricted Stock. You will have voting rights with respect to the shares of Restricted Stock.

Vesting. Subject to your continuous employment with the Company or an Affiliate, this Award shall vest on the Vesting Date and the shares of Restricted Stock shall be released on the first business day following the Vesting Date (or as soon as administratively practicable thereafter, but no later than 60 days following such date).

Termination of Employment. In the event of Involuntary Termination for performance reasons, Termination for Cause, or voluntary termination prior to the Vesting Date, all shares of Restricted Stock awarded hereunder shall be forfeited and canceled. Further, if your employment with the Company or an Affiliate is otherwise terminated prior to the Vesting Date, this Award shall terminate and all shares of Restricted Stock awarded hereunder shall be forfeited and canceled, except as provided below.

Due to Death or Disability. If your employment with the Company or an Affiliate terminates due to death or Disability prior to the Vesting Date, all forfeiture restrictions on the shares of Restricted Stock awarded hereunder shall lapse and all shares shall be released to your beneficiary or you as soon as administratively practicable following the effective date of such termination (but no later than 60 days following such date).

Due to Retirement After Age 62. If your employment with the Company or an Affiliate terminates prior to the Vesting Date due to Retirement after attaining age 62 with at least five years of service with the Company and the effective date of your Retirement is at least one whole year after the Date of Grant, then, subject to your compliance with a post-employment non-competition agreement between you and the Company providing for (among other terms, conditions and restrictions) a restricted period expiring on the Vesting Date, (i) all forfeiture restrictions on the shares of Restricted Stock awarded hereunder shall lapse on the Vesting Date to the same extent as if your employment had not terminated; and (ii) such shares shall be released to you as soon as administratively practicable following the Vesting Date (but no later than 60 days following such date). For the avoidance of doubt, if (A) you do not comply with the terms of the post-employment non-competition agreement through the Vesting Date or (B) the effective date of your Retirement is less than one whole year after the Date of Grant, all shares of Restricted Stock awarded hereunder shall be forfeited and canceled.

Due to Retirement Prior to Age 62. If your employment with the Company or an Affiliate terminates prior to the Vesting Date and your termination is designated in writing by the Company as a Company-approved Retirement prior to age 62 with at least five years of service with the Company, then, subject to such restrictions as the Company may impose (including, but not limited to, a post-employment non-competition agreement between you and the Company providing for (among other terms, conditions and restrictions) a restricted period expiring on the Vesting Date), (i) for each whole year that has passed since the Date of Grant up to and

including the effective date of your Retirement, all forfeiture restrictions on 33% of the shares of Restricted Stock awarded hereunder (rounded down to the next whole share) shall lapse on the Vesting Date to the same extent as if your employment had not terminated and (ii) such shares shall be released to you as soon as administratively practicable following the Vesting Date (but no later than 60 days following such date). For the avoidance of doubt, if you do not comply with the terms of the post-employment non-competition agreement or any other restrictive covenants to which you are subject through the Vesting Date, all shares of Restricted Stock awarded hereunder shall be forfeited and canceled.

Due to Involuntary Termination Other than for Cause or Performance Reasons. In the event of Involuntary Termination for any reason other than for Cause or performance reasons prior to the Vesting Date, for each whole year that has passed prior to the effective date of your Involuntary Termination since the Date of Grant set forth above, 33% of the shares of Restricted Stock awarded hereunder (rounded down to the next whole share) shall be released to you as soon as administratively practicable following the effective date of such Involuntary Termination (but no later than 60 days following such date).

Due to a Change in Control of the Company. Upon the termination of your employment by the Company or an Affiliate without Cause or by you for Good Reason during the two-year period following a Change in Control of the Company prior to the Vesting Date, all forfeiture restrictions on the shares of Restricted Stock awarded hereunder shall lapse as of the date of your termination and such shares shall be released to you as soon as administratively practicable following the date of your termination (but no later than 60 days following such date).

Dividends. Pursuant to Section 7.5 of the Plan, (i) dividends on unvested shares of Restricted Stock shall accrue and be credited by the Company for your benefit; and (ii) such dividends shall not be paid to you until (and to the extent) you become vested in such shares of Restricted Stock and shall be forfeited in the event of (and to the extent of) the forfeiture and cancellation of such shares of Restricted Stock pursuant to this Agreement.

Delivery of Documents. By accepting the terms of this Agreement, you consent to the electronic delivery of documents related to your current or future participation in the Plan (including the Plan documents; this Agreement; any other prospectus or other documents describing the terms and conditions of the Plan and this Award; and the Company’s then-most recent annual report to stockholders, Annual Report on Form 10-K and definitive proxy statement), and you acknowledge that such electronic delivery may be made by the Company, in its sole discretion, by one or more of the following methods: (i) the posting of such documents on the Company’s intranet website or external website; (ii) the posting of such documents on the Fidelity Brokerage Services LLC (FMR LLC) website; (iii) the delivery of such documents via the Fidelity Brokerage Services LLC (FMR LLC) website; (iv) the posting of such documents to another Company intranet website or third party internet website accessible by you; or (v) delivery via electronic mail, by attaching such documents to such electronic email and/or including a link to such documents on a Company intranet website or external website or third party internet website accessible by you. Notwithstanding the foregoing, you also acknowledge that the Company may, in its sole discretion (and as an alternative to, or in addition to, electronic delivery) deliver a paper copy of any such documents to you. You further acknowledge that you may receive from the Company a paper copy of any documents delivered electronically at no cost to you by contacting the Company (Attention: Human Resources Department) by telephone or in writing.

Notice of Termination of Employment.By accepting the terms of this Agreement, you agree that your employment with the Company may be terminated at any time either by you or the Company, at will and with or without cause. However, you agree that you will provide the Company with advance written notice (“Written Notice”) of your departure from the Company. The Written Notice must be provided at least 14 days prior to terminating your employment with the Company unless the reason for the termination of your employment is Retirement, in which case the Written Notice must be provided at least 60 days prior to terminating your employment with the Company (such advance period, in either case, the “Notice Period”).

Written Notice Requirements. If you have accepted an offer of employment or offer to associate with any business or venture or have received such an offer that you may accept, your Written Notice must provide the name of such business or venture, your new position’s job title, and a description of your duties in the new position. If in the opinion of the Company, in its sole discretion, your work for such business or venture may result in your use of the Company’s confidential or proprietary information; if your Written Notice does not provide the name of the business or venture with which you have accepted an offer of employment or offer to associate or from which you have received such an offer that you plan to accept; or if an extension is necessary to ensure business continuity; the Company may give you written notice requiring that the Notice Period be extended to a maximum of 60 days. The Company has a Written Notice form that you must complete and return to the Company’s Chief Human Resources Officer, the Vice President or General Manager to whom you report, or any executive officer of the Company. The Company will mail or deliver any Notice Period extension to your last known address within 14 days of receipt of your Written Notice.

Continued Employment During the Notice Period.During the Notice Period, you will remain an employee of the Company, and you may be required to continue the duties of your employment or assist the Company in transferring your responsibilities to an employee or other person designated by the Company. You shall remain available to meet with Company representatives. Further, you agree that during the Notice Period, the Company may, in its sole discretion, (a) limit you from your active duties and responsibilities, in whole or in part; (b) limit your access to the Company’s facilities; (c) limit your communications with the Company’s other employees, vendors, customers, or competitors; and (d) limit your access to the Company’s information systems and documents.

Compensation and Benefits During the Notice Period. During the Notice Period, the Company will continue to pay you your regular salary, less any applicable withholdings, and you may continue to participate in benefits in which you are enrolled.

Full Time and Attention. You agree to devote your full time and attention during normal working hours to the service of the Company. You shall not engage in any business or secondary employment that interferes with your obligations and responsibilities to the Company. Outside work must not be done on Company time and must not involve the use of Company resources. You further agree that during your employment with the Company you will not (1) engage in any business competitive with the business conducted by the Company; (2) render advice or services to, or otherwise assist, any other person, association, or entity who is engaged, directly or indirectly, in any business competitive with the business conducted by the Company; or (3) induce any employee of the Company to terminate employment with the Company or hire or assist in the hiring of any such employee by any person, association, or entity not affiliated with the Company.

Confidentiality. You agree to maintain the confidentiality of confidential or proprietary information entrusted to you by the Company or others with whom the Company does business, both during and after the termination of your employment with the Company. Confidential information includes all non-public information that might be of use to competitors, or harmful to the Company or others with whom the Company does business, if disclosed. It also includes non-public information that vendors, customers and other companies have entrusted to the Company. Proprietary information includes seismic, geological and geophysical data, prospect and trend information, intellectual property such as trade secrets, patents, trademarks, and copyrights, as well as exploration, production and marketing plans, engineering and manufacturing ideas, designs, databases, records, salary and employee performance information and any unpublished financial data and reports. Unauthorized use or distribution of this information is a violation of Company policy. Such information is to be used solely for Company purposes and never for the private gain of a director, officer or employee (or any member of his or her family), or any third party.

Non-Solicitation Following Termination of Employment. You agree that if your employment with the Company terminates for any reason, for 365 days following your termination of employment, you will not hire, attempt to hire, or knowingly solicit for employment any person (1) who is employed at the Company or (2) who was employed by the Company during the 60 days prior to the termination of your employment.

Material Terms. You understand and agree that the provisions of this Agreement titled Notice of Termination of Employment, Continued Employment During the Notice Period, Full Time and Attention, Confidentiality, and Non-Solicitation Following Termination of Employment are material provisions of this Agreement, without which EOG would not have made the Award, and that a breach of the terms and conditions of any of those provisions will be considered a material breach of this Agreement, entitling the Company to the return of the consideration given to you for entering into this Agreement, and that the Company would be irreparably harmed by your failure to fully comply with these provisions.

Choice-of-law.The validity, interpretation, performance and enforcement of this Agreement shall be governed by, and shall be construed and interpreted according to, the laws of the State of Texas, without reference to any conflicts of law principles that would operate to make the internal laws of any other jurisdiction applicable.

Exclusive Venue. You further agree that the exclusive venues for any dispute arising out of or related to this Agreement are the state courts in Harris County, Texasand you further agree to submit to the jurisdiction of those courts in any such dispute.

Except as provided herein, this Agreement does not amend the terms and conditions of your current employment. To read and print the following documents, refer to the “Accounts & Benefits – Stock Plans – Plan & Grant Documents” section of the Fidelity Brokerage Services LLC (FMR LLC) website.

Current Annual Report
Current Proxy Statement
EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan 

As part of your acceptance of this Agreement, you also agree to adhere to Company policies, including those listed below, some of which have terms or provisions that apply beyond the term of your employment with the Company.

Code of Business Conduct and Ethics, effective February 2022
Conflicts of Interest Policy, effective January 2020
Policy on Confidential Information, effective December 2016
Policy on Inventions, effective August 2008
Information Systems Security Policy, effective April 2020
Harassment Prevention Policy, effective July 2022
Equal Employment Opportunity Policy, effective July 2022 

By accepting this Agreement, you acknowledge that you have read and agree to all of the terms and conditions set forth above. If you decide to reject the terms and conditions of this Agreement, you will decline your right to the Award, and it may be cancelled. 

You are advised to print a copy of this Agreement for your records and reference.

EX-10.2G

Exhibit 10.2(g)

This document constitutes part of a prospectus covering securities
that have been registered under the Securities Act of 1933.

EOG RESOURCES, INC.
RESTRICTED STOCK UNIT AWARD AGREEMENT

GRANTEE: [Participant Name: First Name Middle Name Last Name] [Participant ID: Participant ID]

Congratulations! You have been granted an Award of EOG Resources, Inc. Restricted Stock Units as follows:

Date of Grant	[Grant Date: Month DD, YYYY]
Restricted Stock Units granted under this Award	[Granted: Shares Granted]
Vesting Date	Third anniversary of Date of Grant

The Compensation and Human Resources Committee of the Board of EOG Resources, Inc. (the “Company”) hereby grants to you, the above-named Grantee, effective as of the Date of Grant set forth above, a Restricted Stock Unit Award (the “Award”) in accordance with the terms set forth below.

General. This Restricted Stock Unit Award Agreement (this “Agreement”) is governed by the terms and conditions of the EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (as may be amended from time to time, the “Plan”), which is hereby made a part of this Agreement. All capitalized terms that are not defined in this Agreement have the meanings ascribed to them under the Plan. Under the terms of this Agreement and the Plan, a Restricted Stock Unit ledger account will be maintained by the Company (or its agent) until you become vested in the Restricted Stock Units and the Company common stock represented by such Restricted Stock Units is distributed to you. You will have no voting rights with respect to the Company common stock represented by such Restricted Stock Units until such time as the Company common stock is issued to you.

Vesting. Subject to your continuous employment with the Company or an Affiliate, this Award shall vest on the Vesting Date and the shares of Company common stock represented by the Restricted Stock Units awarded hereunder shall be distributed on the first business day following the Vesting Date (or as soon as administratively practicable thereafter, but no later than 60 days after such date).

Termination of Employment. Except as provided below, if your employment with the Company or an Affiliate does not continue until the Vesting Date, this Award shall terminate and all Restricted Stock Units awarded hereunder shall be forfeited and canceled.

Due to Death. If your employment with the Company or an Affiliate terminates due to death prior to the Vesting Date, all forfeiture restrictions on the Restricted Stock Units awarded hereunder shall lapse immediately and all shares of Company common stock represented by the Restricted Stock Units shall be distributed to your beneficiary as soon as administratively practicable following your date of death, but no later than 60 days after such date.

Due to Disability. If your employment with the Company or an Affiliate terminates due to Disability prior to the Vesting Date, all forfeiture restrictions on the Restricted Stock Units awarded hereunder shall lapse immediately. All shares of Company common stock represented by the Restricted Stock Units that vest hereunder shall be distributed to you according to the schedule specified under “Distribution of Shares” below.

Due to Retirement After Age 62. If your employment with the Company or an Affiliate terminates prior to the Vesting Date due to Retirement after attaining age 62 with at least five years of service with the Company and the effective date of your Retirement is at least one whole year

after the Date of Grant, then, subject to your compliance with a post-employment non-competition agreement between you and the Company providing for (among other terms, conditions and restrictions) a restricted period expiring on the Vesting Date, all forfeiture restrictions on the Restricted Stock Units awarded hereunder shall lapse on the Vesting Date to the same extent as if your employment had not terminated. All shares of Company common stock represented by the Restricted Stock Units that vest hereunder shall be distributed to you according to the schedule specified under “Distribution of Shares” below. For the avoidance of doubt, if you do not comply with the terms of the post-employment non-competition agreement or any other restrictive covenants to which you are subject through the Vesting Date, all Restricted Stock Units awarded hereunder shall be forfeited and canceled or, if settled prior to the Vesting Date, any shares of Company common stock distributed to you hereunder shall be subject to recoupment. For clarity, the forfeiture and recoupment provisions contemplated by the immediately preceding sentence shall lapse as of the Vesting Date. In addition, if the effective date of your Retirement is less than one whole year after the Date of Grant, all Restricted Stock Units awarded hereunder shall be forfeited and canceled.

Due to Retirement Prior to Age 62. If your employment with the Company or an Affiliate terminates prior to the Vesting Date and your termination is designated in writing by the Company as a Company-approved Retirement prior to age 62 with at least five years of service with the Company, then, subject to such restrictions as the Company may impose (including, but not limited to, a post-employment non-competition agreement between you and the Company providing for (among other terms, conditions and restrictions) a restricted period expiring on the Vesting Date), for each whole year that has passed since the Date of Grant up to and including the effective date of your Retirement, all forfeiture restrictions on 33% of the shares of Company common stock represented by the Restricted Stock Units awarded hereunder (rounded down to the next whole share) shall lapse on the Vesting Date to the same extent as if your employment had not terminated. All shares of Company common stock represented by the Restricted Stock Units that vest hereunder shall be distributed to you according to the schedule specified under “Distribution of Shares” below. For the avoidance of doubt, if you do not comply with the terms of the post-employment non-competition agreement or any other restrictive covenants to which you are subject through the Vesting Date, all Restricted Stock Units awarded hereunder shall be forfeited and canceled or, if settled prior to the Vesting Date, any shares of Company common stock distributed to you hereunder shall be subject to recoupment.

Due to Involuntary Termination Other than for Cause or Performance Reasons. If your employment with the Company or an Affiliate terminates prior to the Vesting Date due to Involuntary Termination for any reason other than for Cause or performance reasons, for each whole year that has passed since the Date of Grant up to and including the effective date of your Involuntary Termination, all forfeiture restrictions on 33% of the shares of Company common stock represented by the Restricted Stock Units awarded hereunder (rounded down to the next whole share) shall lapse on the effective date of your Involuntary Termination. All shares of Company common stock represented by the Restricted Stock Units that vest hereunder shall be distributed to you according to the schedule specified under “Distribution of Shares” below.

Due to Performance Reasons, Cause or Voluntary Termination. In the event of Involuntary Termination for performance reasons, Termination for Cause, or voluntary termination, in any case, prior to the Vesting Date, all Restricted Stock Units awarded hereunder shall be forfeited and canceled.

Due to a Change in Control of the Company. If your employment with the Company or an Affiliate is terminated prior to the Vesting Date involuntarily without Cause or by you for Good Reason during the two-year period following a Change in Control of the Company, all forfeiture restrictions on the Restricted Stock Units awarded hereunder shall lapse as of the date of your termination. All shares of Company common stock represented by the Restricted Stock Units that vest hereunder shall be distributed to you according to the schedule specified under “Distribution of Shares” below.

2

Distribution of Shares. Other than as specified under “Due to Death” above, all shares of Company common stock represented by the Restricted Stock Units awarded hereunder that vest pursuant to this “Termination of Employment” section shall be distributed to you on the first business day following the Vesting Date (or as soon as administratively practicable thereafter, but no later than 60 days after such date); provided, however, if your termination of employment with the Company or an Affiliate occurs within two years following a Change in Control of the Company that constitutes an event described in Section 409A(a)(2)(v) of the Code (or any successor provision) and the regulations thereto, such shares instead shall be distributed to you as soon as administratively practicable (and not later than 60 days) following the effective date of your termination of employment notwithstanding any continuing obligations you might have under the post-employment non-competition agreement contemplated by the “Due to Retirement After Age 62” or “Due to Retirement Prior to Age 62” sections above (which obligations shall continue to apply to you to the extent provided in such non-competition agreement, as shall the related recoupment provisions referenced in such sections), subject to any six-month delay applicable to specified employees described under “Section 409A” below.

Dividend Equivalents. Pursuant to Section 8.6 of the Plan, (i) dividend equivalents on unvested Restricted Stock Units shall accrue and be credited by the Company for your benefit, and (ii) such dividend equivalents shall vest and be paid to you according to the same schedule as the corresponding shares of Company common stock represented by the Restricted Stock Units are distributed to you. If a Restricted Stock Unit is forfeited, the corresponding dividend equivalents also shall be forfeited.

Section 409A. The Plan and this Agreement are intended to meet the requirements of Section 409A, and shall be administered such that any payment, settlement, or deferrals of amounts hereunder shall not be subject to any excise penalty tax that may be imposed thereunder. All payments to be made upon a termination of employment under this Agreement may only be made upon a Separation from Service to the extent necessary in order to avoid the imposition of penalty taxes on you pursuant to Section 409A. Notwithstanding any other provision of this Agreement to the contrary, if you are considered a “specified employee” of the Company for purposes of Section 409A (as determined in accordance with the methodology established by the Company as in effect on the date of your Separation from Service), to the extent required by Section 409A, any payment that constitutes nonqualified deferred compensation within the meaning of Section 409A that is otherwise due to you under this Agreement during the six-month period immediately following your Separation from Service on account of your Separation from Service shall be accumulated and paid to you on the first business day of the seventh month following your Separation from Service (the “Delayed Payment Date”). If you die during the postponement period, the amounts and entitlements delayed on account of Section 409A shall be paid to the personal representative of your estate on the first to occur of the Delayed Payment Date or 30 calendar days after the date of your death. The Company, in its sole discretion, shall determine if you are a “specified employee” on the date of your Separation from Service and whether you are subject to any six-month delay in distribution of amounts due to you under this Agreement.

Delivery of Documents. By accepting the terms of this Agreement, you consent to the electronic delivery of documents related to your current or future participation in the Plan (including the Plan documents; this Agreement; any other prospectus or other documents describing the terms and conditions of the Plan and this Award; and the Company’s then-most recent annual report to stockholders, Annual Report on Form 10-K and definitive proxy statement), and you acknowledge that such electronic delivery may be made by the Company, in its sole discretion, by one or more of the following methods: (i) the posting of such documents on the Company’s intranet website or external website; (ii) the posting of such documents on the Fidelity Brokerage Services LLC (FMR LLC) website; (iii) the delivery of such documents via the Fidelity Brokerage Services LLC (FMR LLC) website; (iv) the posting of such documents to another Company intranet website or third party internet website accessible by you; or (v) delivery via electronic mail, by attaching such documents to such electronic email and/or including a link to such documents on a Company intranet website or external website or third-party internet website accessible by you. Notwithstanding the foregoing, you also acknowledge that the Company may, in its sole discretion (and as an alternative to, or in addition to, electronic delivery) deliver a paper copy of any such documents to you. You further acknowledge that you may receive from the Company a paper copy

3

of any documents delivered electronically at no cost to you by contacting the Company (Attention: Human Resources Department) by telephone or in writing.

Confidentiality. You agree to maintain the confidentiality of confidential or proprietary information entrusted to you by the Company or others with whom the Company does business, both during and after the termination of your employment with the Company. Confidential information includes all non-public information that might be of use to competitors, or harmful to the Company or others with whom the Company does business, if disclosed. It also includes non-public information that vendors, customers and other companies have entrusted to the Company. Proprietary information includes seismic, geological and geophysical data, prospect and trend information, intellectual property such as trade secrets, patents, trademarks, and copyrights, as well as exploration, production and marketing plans, engineering and manufacturing ideas, designs, databases, records, salary and employee performance information and any unpublished financial data and reports. Unauthorized use or distribution of this information is a violation of Company policy. Such information is to be used solely for Company purposes and never for the private gain of a director, officer or employee (or any member of his or her family), or any third party.

Non-Solicitation Following Termination of Employment. You agree that if your employment with the Company terminates for any reason, for 365 days following your termination of employment, you will not hire, attempt to hire, or knowingly solicit for employment any person (1) who is employed at the Company or (2) who was employed by the Company during the 60 days prior to the termination of your employment.

Material Terms. You understand and agree that the provisions of this Agreement titled Confidentiality and Non-Solicitation Following Termination of Employment are material provisions of this Agreement, without which EOG would not have made the Award, and that a breach of the terms and conditions of any of those provisions will be considered a material breach of this Agreement, entitling the Company to the return of the consideration given to you for entering into this Agreement, and that the Company would be irreparably harmed by your failure to fully comply with these provisions.

Choice-of-law.The validity, interpretation, performance and enforcement of this Agreement shall be governed by, and shall be construed and interpreted according to, the laws of the State of Texas, without reference to any conflicts of law principles that would operate to make the internal laws of any other jurisdiction applicable.

Exclusive Venue. You further agree that the exclusive venues for any dispute arising out of or related to this Agreement are the state courts in Harris County, Texasand you further agree to submit to the jurisdiction of those courts in any such dispute.

Except as provided herein, this Agreement does not amend the terms and conditions of your current employment. To read and print the following documents, refer to the “Accounts & Benefits – Stock Plans – Plan & Grant Documents” section of the Fidelity Brokerage Services LLC (FMR LLC) website.

Current Annual Report
Current Proxy Statement
EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan

4

As part of your acceptance of this Agreement, you also agree to adhere to Company policies, including those listed below, some of which have terms or provisions that apply beyond the term of your employment with the Company.

Code of Business Conduct and Ethics, effective February 2022
Conflicts of Interest Policy, effective January 2020
Policy on Confidential Information, effective December 2016
Policy on Inventions, effective August 2008
Information Systems Security Policy, effective April 2020
Harassment Prevention Policy, effective July 2022
Equal Employment Opportunity Policy, effective July 2022 

By accepting this Agreement, you acknowledge that you have read and agree to all of the terms and conditions set forth above. If you decide to reject the terms and conditions of this Agreement, you will decline your right to the Award, and it may be cancelled. 

You are advised to print a copy of this Agreement for your records and reference.

5

EX-10.2M

Exhibit 10.2(m)

This document constitutes part of a prospectus covering securities

that have been registered under the Securities Act of 1933.

EOG RESOURCES, INC.

RESTRICTED STOCK UNIT WITH PERFORMANCE-BASED CONDITIONS

(“PERFORMANCE UNIT”) AWARD AGREEMENT

GRANTEE: [Participant Name: First Name Middle Name Last Name] [Participant ID: Participant ID]

Congratulations! You have been granted an Award of EOG Resources, Inc. Performance Units as follows:

Date of Grant:	[Grant Date: Month DD, YYYY]
Performance Units granted under this Award (subject to adjustment as set forth below):	[Granted: Shares Granted]
Vesting Date:	The February 28th immediately following the Certification Date (as defined below)

The Compensation and Human Resources Committee of the Board of EOG Resources, Inc. (the “Company”) hereby grants to you, the above-named Grantee, effective as of the Date of Grant set forth above, a Performance Unit Award (the “Award”) in accordance with the terms set forth below.

General. This Performance Unit Award Agreement (this “Agreement”) is governed by the terms and conditions of the EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (as may be amended from time to time, the “Plan”), which is hereby made a part of this Agreement.

This Agreement amends and restates, and replaces in its entirety, that certain Performance Unit Award Agreement heretofore entered into between you and the Company in respect of that certain Award with a Date of Grant of September 15, 2023.

All capitalized terms that are not defined in this Agreement have the meanings ascribed to them under the Plan. Under the terms of this Agreement and the Plan, a Performance Unit ledger account will be maintained by the Company (or its agent) until you become vested in the Performance Units. You will have no voting rights with respect to the Company common stock represented by such Performance Units (including any additional Performance Units which may be credited to you upon the completion of the Performance Period based on the applicable Performance Multiple) until such time as the Company common stock is issued to you.

Performance Period; TSR Rank; Performance Multiple. Upon the completion of the Performance Period (as defined on Annex A) and the certification (in writing) by the Committee of

(i)the Total Shareholder Return (as defined on Annex A) over the Performance Period of the Company and each Peer Company (as defined on Annex A),

(ii)the Company’s corresponding TSR Rank (see table on Annex A) for the Performance Period, and

(iii)the applicable Performance Multiple (determined in accordance with the “Pre-Adjustment Performance Multiple” table on Annex A and the “Absolute ROCE Modifier” and “Negative TSR Cap” adjustment provisions set forth on Annex A) (the date of such certification by the Committee, the “Certification Date”),

such Performance Multiple shall be applied to the number of Performance Units awarded hereunder and, except in the case of an applicable Performance Multiple of 100% or an applicable Performance Multiple of 0% (in which case all Performance Units awarded hereunder shall be deemed forfeited and canceled), your Performance Unit ledger account shall be adjusted to reflect (A) the additional Performance Units credited to you (in the case of a Performance Multiple greater than 100%) or (B) your decreased Performance Units (in the case of a Performance Multiple less than 100% but greater than 0%).

Vesting. Subject to your continuous employment with the Company or an Affiliate, this Award shall vest on the Vesting Date and the shares of Company common stock represented by the Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple) shall be distributed on the first business day following the Vesting Date (or as soon as administratively practicable thereafter, but no later than 60 days after such date).

Termination of Employment. Except as provided below, if your employment with the Company or an Affiliate does not continue until the Vesting Date, this Award shall terminate and all Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple) shall be forfeited and canceled.

Due to Death. If your employment with the Company or an Affiliate terminates due to death on or prior to the end date of the Performance Period, (i) all forfeiture restrictions on the Performance Units awarded hereunder shall lapse effective as of the date of your death; (ii) the Performance Multiple to be applied to the number of Performance Units awarded hereunder shall be 100%; and (iii) all shares of Company common stock represented by the Performance Units awarded hereunder shall be distributed to your beneficiary as soon as administratively practicable following your date of death, but no later than 60 days after such date. If your employment with the Company or an Affiliate terminates due to death subsequent to the end date of the Performance Period, but prior to the Vesting Date, (i) all forfeiture restrictions on the Performance Units awarded hereunder shall lapse effective as of the date of your death; (ii) the Performance Multiple to be applied to the number of Performance Units awarded hereunder shall be the Performance Multiple for the Performance Period as certified by the Committee; and (iii) all shares of Company common stock represented by the Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple) shall be distributed to your beneficiary as soon as administratively practicable following the Vesting Date, but no later than 60 days after such date.

Due to Disability. If your employment with the Company or an Affiliate terminates due to Disability prior to the Vesting Date, (i) all forfeiture restrictions on the Performance Units awarded hereunder shall lapse effective as of the date of such termination; (ii) the Performance Multiple to be applied to the number of Performance Units awarded hereunder shall be the Performance Multiple for the Performance Period as certified by the Committee; and (iii) all shares of Company common stock represented by the Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple) shall be distributed to you as soon as administratively practicable following the Vesting Date, but no later than 60 days after such date, subject to the six-month delay applicable to specified employees described under “Section 409A” below.

Due to Retirement After Age 62. If your employment with the Company or an Affiliate terminates prior to the Vesting Date due to Retirement after attaining age 62 with at least five years of service with the Company, (i) all forfeiture restrictions on the Performance Units awarded hereunder shall lapse effective as of the date of such termination; (ii) the Performance Multiple to be applied to the number of Performance Units awarded hereunder shall be the Performance Multiple for the Performance Period as certified by the Committee; and (iii) all shares of Company common stock represented by the Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple) shall be distributed to you as soon as administratively practicable following the Vesting Date, but no later than 60 days after such date, subject to the six-month delay applicable to specified employees described under “Section 409A” below.

Due to Retirement Prior to Age 62. If your employment with the Company or an Affiliate terminates prior to the Vesting Date and your termination is designated in writing by the Company as a Company-approved Retirement prior to age 62 with at least five years of service with the Company, subject to such restrictions as the Company may impose (including, but not limited to, a six-month post-employment non-competition agreement), (i) the Performance Multiple to be applied to the number of Performance Units awarded hereunder shall be the Performance Multiple for the Performance Period as certified by the Committee; and (ii) for each whole year that has passed since the Date of Grant set forth above up to and including the effective date of such Retirement, you shall be eligible to receive a distribution of 33% of the shares of Company common stock represented by the Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple and rounded down to the next whole share). Such shares of Company common stock shall be distributed to you as soon as administratively practicable following the Vesting Date, but no later than 60 days after such date, subject to the six-month delay applicable to specified employees described under “Section 409A” below, providedthat you do not violate the provisions of any restrictive covenants to which you are subject (including those set forth in any post-employment non-competition agreement between you and the Company), in which case, under the terms of this Agreement, all Performance Units (including any additional Performance Units which may have been credited to you upon the completion of the Performance Period based on the applicable Performance Multiple) shall be forfeited and canceled.

Due to Involuntary Termination Other than for Cause or Performance Reasons. If the termination of your employment with the Company or an Affiliate is an Involuntary Termination for any reason other than for Cause or performance reasons prior to the Vesting Date, (i) the Performance Multiple to be applied to the number of Performance Units awarded hereunder shall be the Performance Multiple for the Performance Period as certified by the Committee; (ii) for each whole year that has passed prior to the effective date of your Involuntary Termination since the Date of Grant set forth above, you shall be eligible to receive a distribution of 33% of the

shares of Company common stock represented by the Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple and rounded down to the next whole share); and (iii) such shares of Company common stock shall be distributed to you as soon as administratively practicable following the Vesting Date, but no later than 60 days after such date, subject to the six-month delay applicable to specified employees described under “Section 409A” below.

Due to Performance Reasons, Cause or Voluntary Termination. If the termination of your employment with the Company or an Affiliate is an Involuntary Termination for performance reasons, a Termination for Cause, or a voluntary termination, in any case prior to the Vesting Date, all Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple) shall be forfeited and canceled.

Due to a Change in Control of the Company. If the termination of your employment with the Company or an Affiliate is by the Company or such Affiliate (as the case may be) without Cause or by you for Good Reason, in either case during the two-year period following a Change in Control of the Company with an effective date prior to the end date of the Performance Period, (i) all forfeiture restrictions on the Performance Units awarded hereunder shall lapse as of the date of your termination; and (ii) the Performance Multiple to be applied to the number of Performance Units awarded hereunder shall be the Performance Multiple for the Performance Period as certified by the Committee (or its successor) (using, for purposes of the Total Shareholder Return calculations for the Company and each of the Peer Companies, the 30 calendar day period immediately preceding the effective date of the Change in Control of the Company (such effective date, the “COC Effective Date”) as the end month of the Performance Period); provided, that the calculation of Average ROCE (as defined on Annex A) (for purposes of determining the applicable “Absolute ROCE Modifier”) shall (A) be based solely on the ROCE (as defined on Annex A) measure for each of the completed fiscal years (if any) of the Performance Period occurring prior to the COC Effective Date and (B) disregard the fiscal year which includes the COC Effective Date; and providedfurther, that, if the COC Effective Date occurs in the first fiscal year of the Performance Period or prior to the commencement of the Performance Period, the “Absolute ROCE Modifier” shall not apply in determining the applicable Performance Multiple. For the avoidance of doubt (and for illustrative purposes), (1) if the COC Effective Date occurs in the third fiscal year of the Performance Period, Average ROCE shall be calculated based on the ROCE measure for each of the first and second fiscal years of the Performance Period and (2) if the COC Effective Date occurs in the second fiscal year of the Performance Period, Average ROCE shall be equal to the ROCE measure for the first fiscal year of the Performance Period.

If the termination of your employment with the Company or an Affiliate is by the Company or such Affiliate (as the case may be) without Cause or by you for Good Reason, in either case during the two-year period following a Change in Control of the Company with an effective date on or subsequent to the end date of the Performance Period, but prior to the Vesting Date, (i) all forfeiture restrictions on the Performance Units awarded hereunder shall lapse as of the date of your termination; and (ii) the Performance Multiple to be applied to the number of Performance Units awarded hereunder shall be the Performance Multiple for the Performance Period as certified by the Committee (or its successor).

All shares of Company common stock represented by the Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple) shall be distributed to you as soon as administratively practicable following the date of your termination, but no later than 60 days after such date, subject to the six-month delay applicable to specified employees described under “Section 409A” below; provided, however, that if the event constituting the Change in Control of the Company does not qualify as a change in effective ownership or control of the Company for purposes of Section 409A, then, pursuant to Section 12.2 of the Plan, such distribution shall be delayed until the earliest time that such distribution would be Permissible under Section 409A.

Dividend Equivalents. Pursuant to Section 8.6 of the Plan, (i) dividend equivalents on unvested Performance Units (as adjusted for the applicable Performance Multiple) shall accrue and be credited by the Company for your benefit; and (ii) such dividend equivalents shall not be paid to you until (and to the extent) you become vested in the related Performance Units and shall be forfeited in the event of (and to the extent of) the forfeiture and cancellation of the Performance Units pursuant to this Agreement.

Section 409A. The Plan and this Agreement are intended to meet the requirements of Section 409A, and shall be administered such that any payment, settlement, or deferrals of amounts hereunder shall not be subject to any excise penalty tax that may be imposed thereunder. All payments to be made upon a termination of employment under this Agreement may only be made upon a Separation from Service to the extent necessary in order to avoid the imposition of penalty taxes on you pursuant to Section 409A. Notwithstanding any other provision of this Agreement to the contrary, if you are considered a “specified employee” of the Company for purposes of Section 409A (as determined in accordance with the methodology established by the Company as in effect on the date of your

Separation from Service), to the extent required by Section 409A, any payment that constitutes nonqualified deferred compensation within the meaning of Section 409A that is otherwise due to you under this Agreement during the six-month period immediately following your Separation from Service on account of your Separation from Service shall be accumulated and paid to you on the first business day of the seventh month following your Separation from Service (the “Delayed Payment Date”). If you die during the postponement period, the amounts and entitlements delayed on account of Section 409A shall be paid to the personal representative of your estate on the first to occur of the Delayed Payment Date or 30 calendar days after the date of your death. The Company, in its sole discretion, shall determine if you are a “specified employee” on the date of your Separation from Service and whether you are subject to any six-month delay in distribution of amounts due to you under this Agreement.

Delivery of Documents. By accepting the terms of this Agreement, you consent to the electronic delivery of documents related to your current or future participation in the Plan (including the Plan documents; this Agreement; any other prospectus or other documents describing the terms and conditions of the Plan and this Award; and the Company’s then-most recent annual report to stockholders, Annual Report on Form 10-K and definitive proxy statement), and you acknowledge that such electronic delivery may be made by the Company, in its sole discretion, by one or more of the following methods: (i) the posting of such documents on the Company’s intranet website or external website; (ii) the posting of such documents on the Fidelity Brokerage Services, LLC (FMR LLC) website; (iii) the delivery of such documents via the Fidelity Brokerage Services LLC (FMR LLC) website; (iv) the posting of such documents to another Company intranet website or third party internet website accessible by you; or (v) delivery via electronic mail, by attaching such documents to such electronic email and/or including a link to such documents on a Company intranet website or external website or third party internet website accessible by you. Notwithstanding the foregoing, you also acknowledge that the Company may, in its sole discretion (and as an alternative to, or in addition to, electronic delivery) deliver a paper copy of any such documents to you. You further acknowledge that you may receive from the Company a paper copy of any documents delivered electronically at no cost to you by contacting the Company (Attention: Human Resources Department) by telephone or in writing.

Except as provided herein, this Agreement does not amend the terms and conditions of your current employment. To read and print the following documents, refer to the “Accounts & Benefits – Stock Plans – Plan & Grant Documents” section of the Fidelity Brokerage Services LLC (FMR LLC) website.

Current Annual Report Current Proxy Statement

EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan

As part of your acceptance of this Agreement, you also agree to adhere to Company policies, including those listed below, some of which have terms or provisions that apply beyond the term of your employment with the Company.

Code of Business Conduct and Ethics, effective February 2022 Conflicts of Interest Policy, effective January 2020

Policy on Confidential Information, effective December 2016 Policy on Inventions, effective August 2008

Information Systems Security Policy, effective April 2020 Harassment Prevention Policy, effective July 2022

Equal Employment Opportunity Policy, effective July 2022

By accepting this Agreement, you acknowledge that you have read and agree to all of the terms and conditions set forth above. If you decide to reject the terms and conditions of this Agreement, you will decline your right to the Award, and it may be cancelled.

In addition, in consideration of the Award, you hereby agree, by accepting this Agreement, to be subject to the Company’s Policy for the Recovery of Erroneously Awarded Compensation (as the same may be amended from time to time, and including any successor policy), to the extent you are, or become subject to, such Policy.

You are advised to print a copy of this Agreement for your records and reference.

Annex A

Definitions of Certain Terms

“Peer Company” shall mean each of (i) APA Corporation (ticker symbol: APA); (ii) ConocoPhillips (ticker symbol: COP); (iii) Coterra Energy Inc. (ticker symbol: CTRA); (iv) Devon Energy Corporation (ticker symbol: DVN); (v) Diamondback Energy, Inc. (ticker symbol: FANG); (vi) Marathon Oil Corporation (ticker symbol: MRO); (vii) Occidental Petroleum Corporation (ticker symbol: OXY); (viii) Ovintiv Inc. (ticker symbol: OVV); and (ix) S&P 500 (collectively, and including any Replaced Peer Company, the “Peer Companies”); provided, however, that in the event of a public announcement or other public disclosure during the Performance Period regarding the execution of a definitive agreement with respect to a merger, acquisition, consolidation or similar transaction upon the consummation of which a Peer Company will cease to be a publicly traded company (a “Corporate Transaction”), then such Peer Company (a “Replaced Peer Company”) shall, for purposes of the Committee’s certification referenced above and as set forth in the “Total Shareholder Return – Replaced Peer Company” definition below and without regard to whether the Corporate Transaction is ultimately consummated, be replaced by S5OILP for the remainder of the Performance Period beginning on the date that the Replaced Peer Company or its counterparty first issues such a public announcement or other public disclosure regarding the Corporate Transaction (such date, the “Announcement Date”); and providedfurther, should any Peer Company, due to its financial performance or financial condition (e.g., bankruptcy), cease to have its voting stock be publicly traded (either temporarily or permanently), such Peer Company shall nevertheless continue to be a Peer Company for purposes of the Committee’s certification referenced above.

“Performance Period”shall mean the three-year period from and including January 1 of the year immediately following the year of the Date of Grant through December 31 of the third year immediately following the year of the Date of Grant (except as provided above under “Termination of Employment – Due to a Change in Control”).

“Replaced Peer Company’s Total Shareholder Return” shall mean the Replaced Peer Company’s average daily closing stock price for December of the year of the Date of Grant as compared to the Replaced Peer Company’s closing stock price on the trading day immediately preceding the Announcement Date, assuming the reinvestment of dividends and as adjusted for stock splits, recapitalizations, reorganizations or other similar adjustments or changes in the Replaced Peer Company’s capital structure, and expressed as a positive or negative percentage (as the case may be).

“S5OILP Total Shareholder Return” shall mean the S5OILP’s closing index value on the trading day immediately preceding the Announcement Date as compared to the S5OILP’s average daily closing index value for December of the third year immediately following the year of the Date of Grant, except as provided above under “Termination of Employment – Due to a Change in Control”), as adjusted for the reinvestment of dividends, and expressed as a positive or negative percentage (as the case may be); provided, however, that in the event the Announcement Date is a date in December of the third year immediately following the year of the Date of Grant, then the S5OILP’s closing index value on the trading day immediately preceding the Announcement Date shall be compared to the S5OILP’s average daily closing index value for the subsequent remaining trading days of December of the third year immediately following the year of the Date of Grant.

“S&P 500” shall mean the Standard & Poor’s 500 index (or any successor index thereto).

“Total Shareholder Return” for a company (i.e., for the Company or a Peer Company) shall mean such company’s average daily closing stock price (or average daily closing index value, in the case of S&P 500 or S5OILP) for December of the year of the Date of Grant as compared to the average daily closing stock price (or average daily closing index value, in the case of S&P 500 or S5OILP) for December of the third year immediately following the year of the Date of Grant, except as provided above under “Termination of Employment – Due to a Change in Control”), assuming the reinvestment of dividends and as adjusted for stock splits, recapitalizations, reorganizations or other similar adjustments or changes in the company’s capital structure, and expressed as a percentage (positive or negative (as the case may be)). Notwithstanding the foregoing, the Total Shareholder Return for a Replaced Peer Company shall be determined as set forth in the “Total Shareholder Return – Replaced Peer Company” definition below.

“Total Shareholder Return – Replaced Peer Company”for a Replaced Peer Company shall mean the percentage (positive or negative (as the case may be)) equal to the product of (A) multiplied by (B), minus 100%, where:

“(A)” is equal to 100% plus the Replaced Peer Company’s Total Shareholder Return, and

“(B)” is equal to 100% plus the S&P 500 Oil & Gas E&P Sub Industry Index (or any successor index thereto) (“S5OILP”) Total Shareholder Return.

Pre-Adjustment Performance Multiple

“TSR Rank”of the Company among the 10 Total Companies (i.e., the Company and Nine (9) Peer Companies)	Performance Multiple (Subject to adjustment in accordance with the “Absolute ROCE Modifier” and “Negative TSR Cap” provisions below)
1	200%
2	175%
3	150%
4	125%
5	100%
6	75%
7	50%
8	25%
9	0%
10	0%

Adjustments to Performance Multiple

Absolute ROCE Modifier. The Performance Multiple (as specified in the table above) shall be adjusted by applying the modifier set forth opposite the Average ROCE (as defined below) of the Company in the table below; provided, however, that in no event shall the Performance Multiple, after giving effect to such adjustment, exceed 200% or be less than 0%; and, providedfurther, that under the circumstances described in the first paragraph of “Termination of Employment - Due to a Change in Control” above, the Absolute ROCE Modifier shall not apply in determining the applicable Performance Multiple.

Average ROCE (as defined below)	Performance Multiple Modifier
≤ 0%	-70%
1%	-65%
2%	-60%
3%	-55%
4%	-50%
5%	-45%
6%	-40%
7%	-35%
8%	-30%
9%	-25%
10%	-20%
11%	0%
12%	0%
13%	0%
14%	0%
15%	+20%
16%	+25%
17%	+30%
18%	+35%
19%	+40%
20%	+45%
21%	+50%
22%	+55%
23%	+60%
24%	+65%
≥ 25%	+70%

“Average ROCE” shall mean the simple average of the return on capital employed (“ROCE”) measure of the Company for each of the three fiscal years comprising the Performance Period (calculated and rounded as provided below), with such resulting average rounded to the nearest whole number percentage point, with five tenths or more of a percentage point (i.e., ≥ 0.5) rounded upwards and less than five tenths of a percentage point (i.e., < 0.5) rounded downwards (e.g., 12.5% rounded to 13% and 12.4% rounded to 12%), except to the extent otherwise provided in the first paragraph of “Termination of Employment - Due to a Change in Control” above.

For purposes of the “Average ROCE” calculation described above, ROCE for a fiscal year shall be calculated, as a percentage, as the sum of the Company’s non-GAAP after-tax net interest expense for such fiscal year and non-GAAP adjusted net income (loss) for such fiscal year, divided by the average of the Company’s non-GAAP total capitalization (calculated as the sum of total stockholders’ equity and current and long-term debt, less cash, in each case as of December 31st of the applicable fiscal year) for such fiscal year and the immediately preceding fiscal year, with such resulting percentage rounded to the nearest tenth of a percentage point, with five hundredths or more of a percentage point (i.e., ≥ 0.05) rounded upwards and less than five hundredths of a percentage point (i.e., < 0.05) rounded downwards (e.g., 12.05% rounded to 12.1% and 12.04% rounded to 12.0%).

Negative TSR Cap. Notwithstanding any of the above provisions to the contrary (including the “Absolute ROCE Modifier” provision), in the event the Total Shareholder Return of the Company shall be negative (i.e., less than 0%), the Performance Multiple shall not exceed, and shall be capped at, 100%.

EX-10.2N

Exhibit 10.2(n)

This document constitutes part of a prospectus covering securities

that have been registered under the Securities Act of 1933.

EOG RESOURCES, INC.

RESTRICTED STOCK UNIT WITH PERFORMANCE-BASED CONDITIONS

(“PERFORMANCE UNIT”) AWARD AGREEMENT

GRANTEE: [Participant Name: First Name Middle Name Last Name] [Participant ID: Participant ID]

Congratulations! You have been granted an Award of EOG Resources, Inc. Performance Units as follows:

Date of Grant:	[Grant Date: Month DD, YYYY]
Performance Units granted under this Award (subject to adjustment as set forth below):	[Granted: Shares Granted]
Vesting Date:	The February 28th immediately following the Certification Date (as defined below)

The Compensation and Human Resources Committee of the Board of EOG Resources, Inc. (the “Company”) hereby grants to you, the above-named Grantee, effective as of the Date of Grant set forth above, a Performance Unit Award (the “Award”) in accordance with the terms set forth below.

General. This Performance Unit Award Agreement (this “Agreement”) is governed by the terms and conditions of the EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (as may be amended from time to time, the “Plan”), which is hereby made a part of this Agreement. All capitalized terms that are not defined in this Agreement have the meanings ascribed to them under the Plan. Under the terms of this Agreement and the Plan, a Performance Unit ledger account will be maintained by the Company (or its agent) until you become vested in the Performance Units. You will have no voting rights with respect to the Company common stock represented by such Performance Units (including any additional Performance Units which may be credited to you upon the completion of the Performance Period based on the applicable Performance Multiple) until such time as the Company common stock is issued to you.

Performance Period; TSR Rank; Performance Multiple. Upon the completion of the Performance Period (as defined on Annex A) and the certification (in writing) by the Committee of

(i)the Total Shareholder Return (as defined on Annex A) over the Performance Period of the Company and each Peer Company (as defined on Annex A),

(ii)the Company’s corresponding TSR Rank (see table on Annex A) for the Performance Period, and

(iii)the applicable Performance Multiple (determined in accordance with the “Pre-Adjustment Performance Multiple” table on Annex A and the “Absolute ROCE Modifier” and “Negative TSR Cap” adjustment provisions set forth on Annex A) (the date of such certification by the Committee, the “Certification Date”),

such Performance Multiple shall be applied to the number of Performance Units awarded hereunder and, except in the case of an applicable Performance Multiple of 100% or an applicable Performance Multiple of 0% (in which case all Performance Units awarded hereunder shall be deemed forfeited and canceled), your Performance Unit ledger account shall be adjusted to reflect (A) the additional Performance Units credited to you (in the case of a Performance Multiple greater than 100%) or (B) your decreased Performance Units (in the case of a Performance Multiple less than 100% but greater than 0%).

Vesting. Subject to your continuous employment with the Company or an Affiliate, this Award shall vest on the Vesting Date and the shares of Company common stock represented by the Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple) shall be distributed on the first business day following the Vesting Date (or as soon as administratively practicable thereafter, but no later than 60 days after such date).

Termination of Employment. Except as provided below, if your employment with the Company or an Affiliate does not continue until the Vesting Date, this Award shall terminate and all Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple) shall be forfeited and canceled.

Due to Death. If your employment with the Company or an Affiliate terminates due to death on or prior to the end date of the Performance Period, (i) all forfeiture restrictions on the Performance Units awarded hereunder shall lapse effective as of the date of your death; (ii) the Performance Multiple to be applied to the number of Performance Units awarded hereunder shall be 100%; and (iii) all shares of Company common stock represented by the Performance Units awarded hereunder shall be distributed to your beneficiary as soon as administratively practicable following your date of death, but no later than 60 days after such date. If your employment with the Company or an Affiliate terminates due to death subsequent to the end date of the Performance Period, but prior to the Vesting Date, (i) all forfeiture restrictions on the Performance Units awarded hereunder shall lapse effective as of the date of your death; (ii) the Performance Multiple to be applied to the number of Performance Units awarded hereunder shall be the Performance Multiple for the Performance Period as certified by the Committee; and (iii) all shares of Company common stock represented by the Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple) shall be distributed to your beneficiary as soon as administratively practicable following the Vesting Date, but no later than 60 days after such date.

Due to Disability. If your employment with the Company or an Affiliate terminates due to Disability prior to the Vesting Date, (i) all forfeiture restrictions on the Performance Units awarded hereunder shall lapse effective as of the date of such termination; (ii) the Performance Multiple to be applied to the number of Performance Units awarded hereunder shall be the Performance Multiple for the Performance Period as certified by the Committee; and (iii) all shares of Company common stock represented by the Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple) shall be distributed to you as soon as administratively practicable following the Vesting Date, but no later than 60 days after such date, subject to the six-month delay applicable to specified employees described under “Section 409A” below.

Due to Retirement After Age 62. If your employment with the Company or an Affiliate terminates prior to the Vesting Date due to Retirement after attaining age 62 with at least five years of service with the Company and the effective date of your Retirement is at least one whole year after the Date of Grant, then, subject to your compliance with a post-employment non-competition agreement between you and the Company providing for (among other terms, conditions and restrictions) a restricted period expiring on the Vesting Date, (i) all forfeiture restrictions on the Performance Units awarded hereunder shall lapse on the Vesting Date to the same extent as if your employment had not terminated; (ii) the Performance Multiple to be applied to the number of Performance Units awarded hereunder shall be the Performance Multiple for the Performance Period as certified by the Committee; and (iii) all shares of Company common stock represented by the Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple) shall be distributed to you as soon as administratively practicable following the Vesting Date, but no later than 60 days after such date, subject to the six-month delay applicable to specified employees described under “Section 409A” below, provided that if (A) you do not comply with the terms of the post-employment non-competition agreement through the Vesting Date or (B) the effective date of your Retirement is less than one whole year after the Date of Grant, all Performance Units (including any additional Performance Units which may have been credited to you upon the completion of the Performance Period based on the applicable Performance Multiple) shall be forfeited and canceled.

Due to Retirement Prior to Age 62. If your employment with the Company or an Affiliate terminates prior to the Vesting Date and your termination is designated in writing by the Company as a Company-approved Retirement prior to age 62 with at least five years of service with the Company, then, subject to such restrictions as the Company may impose (including, but not limited to, a post-employment non-competition agreement between you and the Company providing for (among other terms, conditions and restrictions) a restricted period expiring on the Vesting Date), (i) all forfeiture restrictions on the Performance Units awarded hereunder shall lapse on the Vesting Date to the same extent as if your employment had not terminated; (ii) the Performance Multiple to be applied to the number of Performance Units awarded hereunder shall be the Performance Multiple for the Performance Period as certified by the Committee; and (iii) for each whole year that has passed since the Date of Grant up to and including the effective date of your Retirement, you shall be eligible to receive a distribution of 33% of the shares of Company common stock represented by the Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple and rounded down to the next whole share). Such shares of Company common stock shall be distributed to you as soon as administratively practicable following the Vesting Date, but no later than 60 days after such date, subject to the six-month delay applicable to specified employees described under “Section 409A” below, provided that if you do not comply with the terms of the post-employment non-competition agreement or any other restrictive covenants to which you are subject through the Vesting Date, all Performance Units (including any additional Performance Units which may have been credited to you upon the completion of the Performance Period based on the applicable Performance Multiple) shall be forfeited and canceled.

Due to Involuntary Termination Other than for Cause or Performance Reasons. If the termination of your employment with the Company or an Affiliate is an Involuntary Termination for any reason other than for Cause or performance reasons prior to the Vesting Date, (i) the Performance Multiple to be applied to the number of

Performance Units awarded hereunder shall be the Performance Multiple for the Performance Period as certified by the Committee; (ii) for each whole year that has passed prior to the effective date of your Involuntary Termination since the Date of Grant set forth above, you shall be eligible to receive a distribution of 33% of the shares of Company common stock represented by the Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple and rounded down to the next whole share); and (iii) such shares of Company common stock shall be distributed to you as soon as administratively practicable following the Vesting Date, but no later than 60 days after such date, subject to the six-month delay applicable to specified employees described under “Section 409A” below.

Due to Performance Reasons, Cause or Voluntary Termination. If the termination of your employment with the Company or an Affiliate is an Involuntary Termination for performance reasons, a Termination for Cause, or a voluntary termination, in any case prior to the Vesting Date, all Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple) shall be forfeited and canceled.

Due to a Change in Control of the Company.If the termination of your employment with the Company or an Affiliate is by the Company or such Affiliate (as the case may be) without Cause or by you for Good Reason, in either case during the two-year period following a Change in Control of the Company with an effective date prior to the end date of the Performance Period, (i) all forfeiture restrictions on the Performance Units awarded hereunder shall lapse as of the date of your termination; and (ii) the Performance Multiple to be applied to the number of Performance Units awarded hereunder shall be the Performance Multiple for the Performance Period as certified by the Committee (or its successor) (using, for purposes of the Total Shareholder Return calculations for the Company and each of the Peer Companies, the 30 calendar day period immediately preceding the effective date of the Change in Control of the Company (such effective date, the “COC Effective Date”) as the end month of the Performance Period); provided, that the calculation of Average ROCE (as defined on Annex A) (for purposes of determining the applicable “Absolute ROCE Modifier”) shall (A) be based solely on the ROCE (as defined on Annex A) measure for each of the completed fiscal years (if any) of the Performance Period occurring prior to the COC Effective Date and (B) disregard the fiscal year which includes the COC Effective Date; and providedfurther, that, if the COC Effective Date occurs in the first fiscal year of the Performance Period or prior to the commencement of the Performance Period, the “Absolute ROCE Modifier” shall not apply in determining the applicable Performance Multiple. For the avoidance of doubt (and for illustrative purposes), (1) if the COC Effective Date occurs in the third fiscal year of the Performance Period, Average ROCE shall be calculated based on the ROCE measure for each of the first and second fiscal years of the Performance Period and (2) if the COC Effective Date occurs in the second fiscal year of the Performance Period, Average ROCE shall be equal to the ROCE measure for the first fiscal year of the Performance Period.

If the termination of your employment with the Company or an Affiliate is by the Company or such Affiliate (as the case may be) without Cause or by you for Good Reason, in either case during the two-year period following a Change in Control of the Company with an effective date on or subsequent to the end date of the Performance Period, but prior to the Vesting Date, (i) all forfeiture restrictions on the Performance Units awarded hereunder shall lapse as of the date of your termination; and (ii) the Performance Multiple to be applied to the number of Performance Units awarded hereunder shall be the Performance Multiple for the Performance Period as certified by the Committee (or its successor).

All shares of Company common stock represented by the Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple) shall be distributed to you as soon as administratively practicable following the date of your termination, but no later than 60 days after such date, subject to the six-month delay applicable to specified employees described under “Section 409A” below; provided, however, that if the event constituting the Change in Control of the Company does not qualify as a change in effective ownership or control of the Company for purposes of Section 409A, then, pursuant to Section 12.2 of the Plan, such distribution shall be delayed until the earliest time that such distribution would be Permissible under Section 409A.

Dividend Equivalents. Pursuant to Section 8.6 of the Plan, (i) dividend equivalents on unvested Performance Units (as adjusted for the applicable Performance Multiple) shall accrue and be credited by the Company for your benefit; and (ii) such dividend equivalents shall not be paid to you until (and to the extent) you become vested in the related Performance Units and shall be forfeited in the event of (and to the extent of) the forfeiture and cancellation of the Performance Units pursuant to this Agreement.

Section 409A. The Plan and this Agreement are intended to meet the requirements of Section 409A, and shall be administered such that any payment, settlement, or deferrals of amounts hereunder shall not be subject to any excise penalty tax that may be imposed thereunder. All payments to be made upon a termination of employment under this Agreement may only be made upon a Separation from Service to the extent necessary in order to avoid the imposition of penalty taxes on you pursuant to Section 409A. Notwithstanding any other provision of this Agreement to the contrary, if you are considered a “specified employee” of the Company for purposes of Section 409A (as determined in accordance with the methodology established by the Company as in effect on the date of your Separation from Service), to the extent required by Section 409A, any payment that constitutes nonqualified deferred

compensation within the meaning of Section 409A that is otherwise due to you under this Agreement during the six-month period immediately following your Separation from Service on account of your Separation from Service shall be accumulated and paid to you on the first business day of the seventh month following your Separation from Service (the “Delayed Payment Date”). If you die during the postponement period, the amounts and entitlements delayed on account of Section 409A shall be paid to the personal representative of your estate on the first to occur of the Delayed Payment Date or 30 calendar days after the date of your death. The Company, in its sole discretion, shall determine if you are a “specified employee” on the date of your Separation from Service and whether you are subject to any six-month delay in distribution of amounts due to you under this Agreement.

Delivery of Documents. By accepting the terms of this Agreement, you consent to the electronic delivery of documents related to your current or future participation in the Plan (including the Plan documents; this Agreement; any other prospectus or other documents describing the terms and conditions of the Plan and this Award; and the Company’s then-most recent annual report to stockholders, Annual Report on Form 10-K and definitive proxy statement), and you acknowledge that such electronic delivery may be made by the Company, in its sole discretion, by one or more of the following methods: (i) the posting of such documents on the Company’s intranet website or external website; (ii) the posting of such documents on the Fidelity Brokerage Services, LLC (FMR LLC) website; (iii) the delivery of such documents via the Fidelity Brokerage Services LLC (FMR LLC) website; (iv) the posting of such documents to another Company intranet website or third party internet website accessible by you; or (v) delivery via electronic mail, by attaching such documents to such electronic email and/or including a link to such documents on a Company intranet website or external website or third party internet website accessible by you. Notwithstanding the foregoing, you also acknowledge that the Company may, in its sole discretion (and as an alternative to, or in addition to, electronic delivery) deliver a paper copy of any such documents to you. You further acknowledge that you may receive from the Company a paper copy of any documents delivered electronically at no cost to you by contacting the Company (Attention: Human Resources Department) by telephone or in writing.

Except as provided herein, this Agreement does not amend the terms and conditions of your current employment. To read and print the following documents, refer to the “Accounts & Benefits – Stock Plans – Plan & Grant Documents” section of the Fidelity Brokerage Services LLC (FMR LLC) website.

Current Annual Report Current Proxy Statement

EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan

As part of your acceptance of this Agreement, you also agree to adhere to Company policies, including those listed below, some of which have terms or provisions that apply beyond the term of your employment with the Company.

Code of Business Conduct and Ethics, effective February 2022 Conflicts of Interest Policy, effective January 2020

Policy on Confidential Information, effective December 2016 Policy on Inventions, effective August 2008

Information Systems Security Policy, effective April 2020 Harassment Prevention Policy, effective July 2022

Equal Employment Opportunity Policy, effective July 2022

By accepting this Agreement, you acknowledge that you have read and agree to all of the terms and conditions set forth above. If you decide to reject the terms and conditions of this Agreement, you will decline your right to the Award, and it may be cancelled.

In addition, in consideration of the Award, you hereby agree, by accepting this Agreement, to be subject to the Company’s Policy for the Recovery of Erroneously Awarded Compensation (as the same may be amended from time to time, and including any successor policy), to the extent you are, or become subject to, such Policy.

You are advised to print a copy of this Agreement for your records and reference.

Annex A

Definitions of Certain Terms

“Peer Company” shall mean each of (i) APA Corporation (ticker symbol: APA); (ii) ConocoPhillips (ticker symbol: COP); (iii) Coterra Energy Inc. (ticker symbol: CTRA); (iv) Devon Energy Corporation (ticker symbol: DVN); (v) Diamondback Energy, Inc. (ticker symbol: FANG); (vi) Marathon Oil Corporation (ticker symbol: MRO); (vii) Occidental Petroleum Corporation (ticker symbol: OXY); (viii) Ovintiv Inc. (ticker symbol: OVV); and (ix) S&P 500 (collectively, and including any Replaced Peer Company, the “Peer Companies”); provided, however, that in the event of a public announcement or other public disclosure during the Performance Period regarding the execution of a definitive agreement with respect to a merger, acquisition, consolidation or similar transaction upon the consummation of which a Peer Company will cease to be a publicly traded company (a “Corporate Transaction”), then such Peer Company (a “Replaced Peer Company”) shall, for purposes of the Committee’s certification referenced above and as set forth in the “Total Shareholder Return – Replaced Peer Company” definition below and without regard to whether the Corporate Transaction is ultimately consummated, be replaced by S5OILP for the remainder of the Performance Period beginning on the date that the Replaced Peer Company or its counterparty first issues such a public announcement or other public disclosure regarding the Corporate Transaction (such date, the “Announcement Date”); and providedfurther, should any Peer Company, due to its financial performance or financial condition (e.g., bankruptcy), cease to have its voting stock be publicly traded (either temporarily or permanently), such Peer Company shall nevertheless continue to be a Peer Company for purposes of the Committee’s certification referenced above.

“Performance Period”shall mean the three-year period from and including January 1 of the year immediately following the year of the Date of Grant through December 31 of the third year immediately following the year of the Date of Grant (except as provided above under “Termination of Employment – Due to a Change in Control of the Company”).

“Replaced Peer Company’s Total Shareholder Return” shall mean the Replaced Peer Company’s average daily closing stock price for December of the year of the Date of Grant as compared to the Replaced Peer Company’s closing stock price on the trading day immediately preceding the Announcement Date, assuming the reinvestment of dividends and as adjusted for stock splits, recapitalizations, reorganizations or other similar adjustments or changes in the Replaced Peer Company’s capital structure, and expressed as a positive or negative percentage (as the case may be).

“S5OILP Total Shareholder Return” shall mean the S5OILP’s closing index value on the trading day immediately preceding the Announcement Date as compared to the S5OILP’s average daily closing index value for December of the third year immediately following the year of the Date of Grant, except as provided above under “Termination of Employment – Due to a Change in Control”), as adjusted for the reinvestment of dividends, and expressed as a positive or negative percentage (as the case may be); provided, however, that in the event the Announcement Date is a date in December of the third year immediately following the year of the Date of Grant, then the S5OILP’s closing index value on the trading day immediately preceding the Announcement Date shall be compared to the S5OILP’s average daily closing index value for the subsequent remaining trading days of December of the third year immediately following the year of the Date of Grant.

“S&P 500” shall mean the Standard & Poor’s 500 index (or any successor index thereto).

“Total Shareholder Return” for a company (i.e., for the Company or a Peer Company) shall mean such company’s average daily closing stock price (or average daily closing index value, in the case of S&P 500 or S5OILP) for December of the year of the Date of Grant as compared to the average daily closing stock price (or average daily closing index value, in the case of S&P 500 or S5OILP) for December of the third year immediately following the year of the Date of Grant, except as provided above under “Termination of Employment – Due to a Change in Control”), assuming the reinvestment of dividends and as adjusted for stock splits, recapitalizations, reorganizations or other similar adjustments or changes in the company’s capital structure, and expressed as a percentage (positive or negative (as the case may be)). Notwithstanding the foregoing, the Total Shareholder Return for a Replaced Peer Company shall be determined as set forth in the “Total Shareholder Return – Replaced Peer Company” definition below.

“Total Shareholder Return – Replaced Peer Company”for a Replaced Peer Company shall mean the percentage (positive or negative (as the case may be)) equal to the product of (A) multiplied by (B), minus 100%, where:

“(A)” is equal to 100% plus the Replaced Peer Company’s Total Shareholder Return, and

“(B)” is equal to 100% plus the S&P 500 Oil & Gas E&P Sub Industry Index (or any successor index thereto) (“S5OILP”) Total Shareholder Return.

Pre-Adjustment Performance Multiple

“TSR Rank”of the Company among the 10 Total Companies (i.e., the Company and Nine (9) Peer Companies)	Performance Multiple (Subject to adjustment in accordance with the “Absolute ROCE Modifier” and “Negative TSR Cap” provisions below)
1	200%
2	175%
3	150%
4	125%
5	100%
6	75%
7	50%
8	25%
9	0%
10	0%

Adjustments to Performance Multiple

Absolute ROCE Modifier. The Performance Multiple (as specified in the table above) shall be adjusted by applying the modifier set forth opposite the Average ROCE (as defined below) of the Company in the table below; provided, however, that in no event shall the Performance Multiple, after giving effect to such adjustment, exceed 200% or be less than 0%; and, providedfurther, that under the circumstances described in the first paragraph of “Termination of Employment - Due to a Change in Control” above, the Absolute ROCE Modifier shall not apply in determining the applicable Performance Multiple.

Average ROCE (as defined below)	Performance Multiple Modifier
≤ 0%	-70%
1%	-65%
2%	-60%
3%	-55%
4%	-50%
5%	-45%
6%	-40%
7%	-35%
8%	-30%
9%	-25%
10%	-20%
11%	0%
12%	0%
13%	0%
14%	0%
15%	+20%
16%	+25%
17%	+30%
18%	+35%
19%	+40%
20%	+45%
21%	+50%
22%	+55%
23%	+60%
24%	+65%
≥ 25%	+70%

“Average ROCE” shall mean the simple average of the return on capital employed (“ROCE”) measure of the Company for each of the three fiscal years comprising the Performance Period (calculated and rounded as provided below), with such resulting average rounded to the nearest whole number percentage point, with five tenths or more of a percentage point (i.e., ≥ 0.5) rounded upwards and less than five tenths of a percentage point (i.e., < 0.5) rounded downwards (e.g., 12.5% rounded to 13% and 12.4% rounded to 12%), except to the extent otherwise provided in the first paragraph of “Termination of Employment - Due to a Change in Control” above.

For purposes of the “Average ROCE” calculation described above, ROCE for a fiscal year shall be calculated, as a percentage, as the sum of the Company’s non-GAAP after-tax net interest expense for such fiscal year and non-GAAP adjusted net income (loss) for such fiscal year, divided by the average of the Company’s non-GAAP total capitalization (calculated as the sum of total stockholders’ equity and current and long-term debt, less cash, in each case as of December 31st of the applicable fiscal year) for such fiscal year and the immediately preceding fiscal year, with such resulting percentage rounded to the nearest tenth of a percentage point, with five hundredths or more of a percentage point (i.e., ≥ 0.05) rounded upwards and less than five hundredths of a percentage point (i.e., < 0.05) rounded downwards (e.g., 12.05% rounded to 12.1% and 12.04% rounded to 12.0%).

Negative TSR Cap. Notwithstanding any of the above provisions to the contrary (including the “Absolute ROCE Modifier” provision), in the event the Total Shareholder Return of the Company shall be negative (i.e., less than 0%), the Performance Multiple shall not exceed, and shall be capped at, 100%.

EX-10.2O

Exhibit 10.2(o)

This document constitutes part of a prospectus covering securities

that have been registered under the Securities Act of 1933.

EOG RESOURCES, INC.

RESTRICTED STOCK UNIT WITH PERFORMANCE-BASED CONDITIONS

(“PERFORMANCE UNIT”) AWARD AGREEMENT

GRANTEE: [Participant Name: First Name Middle Name Last Name] [Participant ID: Participant ID]

Congratulations! You have been granted an Award of EOG Resources, Inc. Performance Units as follows:

Date of Grant:	[Grant Date: Month DD, YYYY]
Performance Units granted under this Award (subject to adjustment as set forth below):	[Granted: Shares Granted]
Vesting Date:	The February 28th immediately following the Certification Date (as defined below)

The Compensation and Human Resources Committee of the Board of EOG Resources, Inc. (the “Company”) hereby grants to you, the above-named Grantee, effective as of the Date of Grant set forth above, a Performance Unit Award (the “Award”) in accordance with the terms set forth below.

General. This Performance Unit Award Agreement (this “Agreement”) is governed by the terms and conditions of the EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (as may be amended from time to time, the “Plan”), which is hereby made a part of this Agreement. All capitalized terms that are not defined in this Agreement have the meanings ascribed to them under the Plan. Under the terms of this Agreement and the Plan, a Performance Unit ledger account will be maintained by the Company (or its agent) until you become vested in the Performance Units. You will have no voting rights with respect to the Company common stock represented by such Performance Units (including any additional Performance Units which may be credited to you upon the completion of the Performance Period based on the applicable Performance Multiple) until such time as the Company common stock is issued to you.

Performance Period; TSR Rank; Performance Multiple. Upon the completion of the Performance Period (as defined on Annex A) and the certification (in writing) by the Committee of

(i)the Total Shareholder Return (as defined on Annex A) over the Performance Period of the Company and each Peer Company (as defined on Annex A),

(ii)the Company’s corresponding TSR Rank (see table on Annex A) for the Performance Period, and

(iii)the applicable Performance Multiple (determined in accordance with the “Pre-Adjustment Performance Multiple” table on Annex A and the “Absolute ROCE Modifier” and “Negative TSR Cap” adjustment provisions set forth on Annex A) (the date of such certification by the Committee, the “Certification Date”),

such Performance Multiple shall be applied to the number of Performance Units awarded hereunder and, except in the case of an applicable Performance Multiple of 100% or an applicable Performance Multiple of 0% (in which case all Performance Units awarded hereunder shall be deemed forfeited and canceled), your Performance Unit ledger account shall be adjusted to reflect (A) the additional Performance Units credited to you (in the case of a Performance Multiple greater than 100%) or (B) your decreased Performance Units (in the case of a Performance Multiple less than 100% but greater than 0%).

Vesting. Subject to your continuous employment with the Company or an Affiliate, this Award shall vest on the Vesting Date and the shares of Company common stock represented by the Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple) shall be distributed on the first business day following the Vesting Date (or as soon as administratively practicable thereafter, but no later than 60 days after such date).

Termination of Employment. Except as provided below, if your employment with the Company or an Affiliate does not continue until the Vesting Date, this Award shall terminate and all Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple) shall be forfeited and canceled.

Due to Death. If your employment with the Company or an Affiliate terminates due to death on or prior to the end date of the Performance Period, (i) all forfeiture restrictions on the Performance Units awarded hereunder shall lapse effective as of the date of your death; (ii) the Performance Multiple to be applied to the number of Performance Units awarded hereunder shall be 100%; and (iii) all shares of Company common stock represented by the Performance Units awarded hereunder shall be distributed to your beneficiary as soon as administratively practicable following your date of death, but no later than 60 days after such date. If your employment with the Company or an Affiliate terminates due to death subsequent to the end date of the Performance Period, but prior to the Vesting Date, (i) all forfeiture restrictions on the Performance Units awarded hereunder shall lapse effective as of the date of your death; (ii) the Performance Multiple to be applied to the number of Performance Units awarded hereunder shall be the Performance Multiple for the Performance Period as certified by the Committee; and (iii) all shares of Company common stock represented by the Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple) shall be distributed to your beneficiary as soon as administratively practicable following the Vesting Date, but no later than 60 days after such date.

Due to Disability. If your employment with the Company or an Affiliate terminates due to Disability prior to the Vesting Date, (i) all forfeiture restrictions on the Performance Units awarded hereunder shall lapse effective as of the date of such termination; (ii) the Performance Multiple to be applied to the number of Performance Units awarded hereunder shall be the Performance Multiple for the Performance Period as certified by the Committee; and (iii) all shares of Company common stock represented by the Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple) shall be distributed to you as soon as administratively practicable following the Vesting Date, but no later than 60 days after such date, subject to the six-month delay applicable to specified employees described under “Section 409A” below.

Due to Retirement After Age 62. If your employment with the Company or an Affiliate terminates prior to the Vesting Date due to Retirement after attaining age 62 with at least five years of service with the Company and the effective date of your Retirement is at least one whole year after the Date of Grant, then, subject to your compliance with a post-employment non-competition agreement between you and the Company providing for (among other terms, conditions and restrictions) a restricted period expiring on the Vesting Date, (i) all forfeiture restrictions on the Performance Units awarded hereunder shall lapse on the Vesting Date to the same extent as if your employment had not terminated; (ii) the Performance Multiple to be applied to the number of Performance Units awarded hereunder shall be the Performance Multiple for the Performance Period as certified by the Committee; and (iii) all shares of Company common stock represented by the Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple) shall be distributed to you as soon as administratively practicable following the Vesting Date, but no later than 60 days after such date, subject to the six-month delay applicable to specified employees described under “Section 409A” below, provided that if (A) you do not comply with the terms of the post-employment non-competition agreement through the Vesting Date or (B) the effective date of your Retirement is less than one whole year after the Date of Grant, all Performance Units (including any additional Performance Units which may have been credited to you upon the completion of the Performance Period based on the applicable Performance Multiple) shall be forfeited and canceled.

Due to Retirement Prior to Age 62. If your employment with the Company or an Affiliate terminates prior to the Vesting Date and your termination is designated in writing by the Company as a Company-approved Retirement prior to age 62 with at least five years of service with the Company, then, subject to such restrictions as the Company may impose (including, but not limited to, a post-employment non-competition agreement between you and the Company providing for (among other terms, conditions and restrictions) a restricted period expiring on the Vesting Date), (i) all forfeiture restrictions on the Performance Units awarded hereunder shall lapse on the Vesting Date to the same extent as if your employment had not terminated; (ii) the Performance Multiple to be applied to the number of Performance Units awarded hereunder shall be the Performance Multiple for the Performance Period as certified by the Committee; and (iii) for each whole year that has passed since the Date of Grant up to and including the effective date of your Retirement, you shall be eligible to receive a distribution of 33% of the shares of Company common stock represented by the Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple and rounded down to the next whole share). Such shares of Company common stock shall be distributed to you as soon as administratively practicable following the Vesting Date, but no later than 60 days after such date, subject to the six-month delay applicable to specified employees described under “Section 409A” below, provided that if you do not comply with the terms of the post-employment non-competition agreement or any other restrictive covenants to which you are subject through the Vesting Date, all Performance Units (including any additional Performance Units which may have been credited to you upon the completion of the Performance Period based on the applicable Performance Multiple) shall be forfeited and canceled.

Due to Involuntary Termination Other than for Cause or Performance Reasons. If the termination of your employment with the Company or an Affiliate is an Involuntary Termination for any reason other than for Cause or performance reasons prior to the Vesting Date, (i) the Performance Multiple to be applied to the number of

Performance Units awarded hereunder shall be the Performance Multiple for the Performance Period as certified by the Committee; (ii) for each whole year that has passed prior to the effective date of your Involuntary Termination since the Date of Grant set forth above, you shall be eligible to receive a distribution of 33% of the shares of Company common stock represented by the Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple and rounded down to the next whole share); and (iii) such shares of Company common stock shall be distributed to you as soon as administratively practicable following the Vesting Date, but no later than 60 days after such date, subject to the six-month delay applicable to specified employees described under “Section 409A” below.

Due to Performance Reasons, Cause or Voluntary Termination. If the termination of your employment with the Company or an Affiliate is an Involuntary Termination for performance reasons, a Termination for Cause, or a voluntary termination, in any case prior to the Vesting Date, all Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple) shall be forfeited and canceled.

Due to a Change in Control of the Company.If the termination of your employment with the Company or an Affiliate is by the Company or such Affiliate (as the case may be) without Cause or by you for Good Reason, in either case during the two-year period following a Change in Control of the Company with an effective date prior to the end date of the Performance Period, (i) all forfeiture restrictions on the Performance Units awarded hereunder shall lapse as of the date of your termination; and (ii) the Performance Multiple to be applied to the number of Performance Units awarded hereunder shall be the Performance Multiple for the Performance Period as certified by the Committee (or its successor) (using, for purposes of the Total Shareholder Return calculations for the Company and each of the Peer Companies, the 30 calendar day period immediately preceding the effective date of the Change in Control of the Company (such effective date, the “COC Effective Date”) as the end month of the Performance Period); provided, that the calculation of Average ROCE (as defined on Annex A) (for purposes of determining the applicable “Absolute ROCE Modifier”) shall (A) be based solely on the ROCE (as defined on Annex A) measure for each of the completed fiscal years (if any) of the Performance Period occurring prior to the COC Effective Date and (B) disregard the fiscal year which includes the COC Effective Date; and providedfurther, that, if the COC Effective Date occurs in the first fiscal year of the Performance Period or prior to the commencement of the Performance Period, the “Absolute ROCE Modifier” shall not apply in determining the applicable Performance Multiple. For the avoidance of doubt (and for illustrative purposes), (1) if the COC Effective Date occurs in the third fiscal year of the Performance Period, Average ROCE shall be calculated based on the ROCE measure for each of the first and second fiscal years of the Performance Period and (2) if the COC Effective Date occurs in the second fiscal year of the Performance Period, Average ROCE shall be equal to the ROCE measure for the first fiscal year of the Performance Period.

If the termination of your employment with the Company or an Affiliate is by the Company or such Affiliate (as the case may be) without Cause or by you for Good Reason, in either case during the two-year period following a Change in Control of the Company with an effective date on or subsequent to the end date of the Performance Period, but prior to the Vesting Date, (i) all forfeiture restrictions on the Performance Units awarded hereunder shall lapse as of the date of your termination; and (ii) the Performance Multiple to be applied to the number of Performance Units awarded hereunder shall be the Performance Multiple for the Performance Period as certified by the Committee (or its successor).

All shares of Company common stock represented by the Performance Units awarded hereunder (as adjusted for the applicable Performance Multiple) shall be distributed to you as soon as administratively practicable following the date of your termination, but no later than 60 days after such date, subject to the six-month delay applicable to specified employees described under “Section 409A” below; provided, however, that if the event constituting the Change in Control of the Company does not qualify as a change in effective ownership or control of the Company for purposes of Section 409A, then, pursuant to Section 12.2 of the Plan, such distribution shall be delayed until the earliest time that such distribution would be Permissible under Section 409A.

Dividend Equivalents. Pursuant to Section 8.6 of the Plan, (i) dividend equivalents on unvested Performance Units (as adjusted for the applicable Performance Multiple) shall accrue and be credited by the Company for your benefit; and (ii) such dividend equivalents shall not be paid to you until (and to the extent) you become vested in the related Performance Units and shall be forfeited in the event of (and to the extent of) the forfeiture and cancellation of the Performance Units pursuant to this Agreement.

Section 409A. The Plan and this Agreement are intended to meet the requirements of Section 409A, and shall be administered such that any payment, settlement, or deferrals of amounts hereunder shall not be subject to any excise penalty tax that may be imposed thereunder. All payments to be made upon a termination of employment under this Agreement may only be made upon a Separation from Service to the extent necessary in order to avoid the imposition of penalty taxes on you pursuant to Section 409A. Notwithstanding any other provision of this Agreement to the contrary, if you are considered a “specified employee” of the Company for purposes of Section 409A (as determined in accordance with the methodology established by the Company as in effect on the date of your Separation from Service), to the extent required by Section 409A, any payment that constitutes nonqualified deferred

compensation within the meaning of Section 409A that is otherwise due to you under this Agreement during the six-month period immediately following your Separation from Service on account of your Separation from Service shall be accumulated and paid to you on the first business day of the seventh month following your Separation from Service (the “Delayed Payment Date”). If you die during the postponement period, the amounts and entitlements delayed on account of Section 409A shall be paid to the personal representative of your estate on the first to occur of the Delayed Payment Date or 30 calendar days after the date of your death. The Company, in its sole discretion, shall determine if you are a “specified employee” on the date of your Separation from Service and whether you are subject to any six-month delay in distribution of amounts due to you under this Agreement.

Delivery of Documents. By accepting the terms of this Agreement, you consent to the electronic delivery of documents related to your current or future participation in the Plan (including the Plan documents; this Agreement; any other prospectus or other documents describing the terms and conditions of the Plan and this Award; and the Company’s then-most recent annual report to stockholders, Annual Report on Form 10-K and definitive proxy statement), and you acknowledge that such electronic delivery may be made by the Company, in its sole discretion, by one or more of the following methods: (i) the posting of such documents on the Company’s intranet website or external website; (ii) the posting of such documents on the Fidelity Brokerage Services, LLC (FMR LLC) website; (iii) the delivery of such documents via the Fidelity Brokerage Services LLC (FMR LLC) website; (iv) the posting of such documents to another Company intranet website or third party internet website accessible by you; or (v) delivery via electronic mail, by attaching such documents to such electronic email and/or including a link to such documents on a Company intranet website or external website or third party internet website accessible by you. Notwithstanding the foregoing, you also acknowledge that the Company may, in its sole discretion (and as an alternative to, or in addition to, electronic delivery) deliver a paper copy of any such documents to you. You further acknowledge that you may receive from the Company a paper copy of any documents delivered electronically at no cost to you by contacting the Company (Attention: Human Resources Department) by telephone or in writing.

Except as provided herein, this Agreement does not amend the terms and conditions of your current employment. To read and print the following documents, refer to the “Accounts & Benefits – Stock Plans – Plan & Grant Documents” section of the Fidelity Brokerage Services LLC (FMR LLC) website.

Current Annual Report Current Proxy Statement

EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan

As part of your acceptance of this Agreement, you also agree to adhere to Company policies, including those listed below, some of which have terms or provisions that apply beyond the term of your employment with the Company.

Code of Business Conduct and Ethics, effective February 2022 Conflicts of Interest Policy, effective January 2020

Policy on Confidential Information, effective December 2016 Policy on Inventions, effective August 2008

Information Systems Security Policy, effective April 2020 Harassment Prevention Policy, effective July 2022

Equal Employment Opportunity Policy, effective July 2022

By accepting this Agreement, you acknowledge that you have read and agree to all of the terms and conditions set forth above. If you decide to reject the terms and conditions of this Agreement, you will decline your right to the Award, and it may be cancelled.

In addition, in consideration of the Award, you hereby agree, by accepting this Agreement, to be subject to the Company’s Policy for the Recovery of Erroneously Awarded Compensation (as the same may be amended from time to time, and including any successor policy), to the extent you are, or become subject to, such Policy.

You are advised to print a copy of this Agreement for your records and reference.

Annex A

Definitions of Certain Terms

“Peer Company” shall mean each of (i) APA Corporation (ticker symbol: APA); (ii) ConocoPhillips (ticker symbol: COP); (iii) Coterra Energy Inc. (ticker symbol: CTRA); (iv) Devon Energy Corporation (ticker symbol: DVN); (v) Diamondback Energy, Inc. (ticker symbol: FANG); (vi) Marathon Oil Corporation (ticker symbol: MRO); (vii) Occidental Petroleum Corporation (ticker symbol: OXY); (viii) Ovintiv Inc. (ticker symbol: OVV); and (ix) S&P 500 (collectively, and including any Replaced Peer Company, the “Peer Companies”); provided, however, that in the event of a public announcement or other public disclosure during the Performance Period regarding the execution of a definitive agreement with respect to a merger, acquisition, consolidation or similar transaction upon the consummation of which a Peer Company will cease to be a publicly traded company (a “Corporate Transaction”), then such Peer Company (a “Replaced Peer Company”) shall, for purposes of the Committee’s certification referenced above and as set forth in the “Total Shareholder Return – Replaced Peer Company” definition below and without regard to whether the Corporate Transaction is ultimately consummated, be replaced by S5OILP for the remainder of the Performance Period beginning on the date that the Replaced Peer Company or its counterparty first issues such a public announcement or other public disclosure regarding the Corporate Transaction (such date, the “Announcement Date”); and providedfurther, should any Peer Company, due to its financial performance or financial condition (e.g., bankruptcy), cease to have its voting stock be publicly traded (either temporarily or permanently), such Peer Company shall nevertheless continue to be a Peer Company for purposes of the Committee’s certification referenced above.

“Performance Period”shall mean January 1, 2024 through December 31, 2026 (except as provided above under “Termination of Employment – Due to a Change in Control of the Company”).

“Replaced Peer Company’s Total Shareholder Return” shall mean the Replaced Peer Company’s average daily closing stock price for December of the year of the Date of Grant as compared to the Replaced Peer Company’s closing stock price on the trading day immediately preceding the Announcement Date, assuming the reinvestment of dividends and as adjusted for stock splits, recapitalizations, reorganizations or other similar adjustments or changes in the Replaced Peer Company’s capital structure, and expressed as a positive or negative percentage (as the case may be).

“S5OILP Total Shareholder Return” shall mean the S5OILP’s closing index value on the trading day immediately preceding the Announcement Date as compared to the S5OILP’s average daily closing index value for December of the third year immediately following the year of the Date of Grant, except as provided above under “Termination of Employment – Due to a Change in Control”), as adjusted for the reinvestment of dividends, and expressed as a positive or negative percentage (as the case may be); provided, however, that in the event the Announcement Date is a date in December of the third year immediately following the year of the Date of Grant, then the S5OILP’s closing index value on the trading day immediately preceding the Announcement Date shall be compared to the S5OILP’s average daily closing index value for the subsequent remaining trading days of December of the third year immediately following the year of the Date of Grant.

“S&P 500” shall mean the Standard & Poor’s 500 index (or any successor index thereto).

“Total Shareholder Return” for a company (i.e., for the Company or a Peer Company) shall mean such company’s average daily closing stock price (or average daily closing index value, in the case of S&P 500 or S5OILP) for December of the year of the Date of Grant as compared to the average daily closing stock price (or average daily closing index value, in the case of S&P 500 or S5OILP) for December of the third year immediately following the year of the Date of Grant, except as provided above under “Termination of Employment – Due to a Change in Control”), assuming the reinvestment of dividends and as adjusted for stock splits, recapitalizations, reorganizations or other similar adjustments or changes in the company’s capital structure, and expressed as a percentage (positive or negative (as the case may be)). Notwithstanding the foregoing, the Total Shareholder Return for a Replaced Peer Company shall be determined as set forth in the “Total Shareholder Return – Replaced Peer Company” definition below.

“Total Shareholder Return – Replaced Peer Company”for a Replaced Peer Company shall mean the percentage (positive or negative (as the case may be)) equal to the product of (A) multiplied by (B), minus 100%, where:

“(A)” is equal to 100% plus the Replaced Peer Company’s Total Shareholder Return, and

“(B)” is equal to 100% plus the S&P 500 Oil & Gas E&P Sub Industry Index (or any successor index thereto) (“S5OILP”) Total Shareholder Return.

Pre-Adjustment Performance Multiple

“TSR Rank”of the Company among the 10 Total Companies (i.e., the Company and Nine (9) Peer Companies)	Performance Multiple (Subject to adjustment in accordance with the “Absolute ROCE Modifier” and “Negative TSR Cap” provisions below)
1	200%
2	175%
3	150%
4	125%
5	100%
6	75%
7	50%
8	25%
9	0%
10	0%

Adjustments to Performance Multiple

Absolute ROCE Modifier. The Performance Multiple (as specified in the table above) shall be adjusted by applying the modifier set forth opposite the Average ROCE (as defined below) of the Company in the table below; provided, however, that in no event shall the Performance Multiple, after giving effect to such adjustment, exceed 200% or be less than 0%; and, providedfurther, that under the circumstances described in the first paragraph of “Termination of Employment - Due to a Change in Control” above, the Absolute ROCE Modifier shall not apply in determining the applicable Performance Multiple.

Average ROCE (as defined below)	Performance Multiple Modifier
≤ 0%	-70%
1%	-65%
2%	-60%
3%	-55%
4%	-50%
5%	-45%
6%	-40%
7%	-35%
8%	-30%
9%	-25%
10%	-20%
11%	0%
12%	0%
13%	0%
14%	0%
15%	+20%
16%	+25%
17%	+30%
18%	+35%
19%	+40%
20%	+45%
21%	+50%
22%	+55%
23%	+60%
24%	+65%
≥ 25%	+70%

“Average ROCE” shall mean the simple average of the return on capital employed (“ROCE”) measure of the Company for each of the three fiscal years comprising the Performance Period (calculated and rounded as provided below), with such resulting average rounded to the nearest whole number percentage point, with five tenths or more of a percentage point (i.e., ≥ 0.5) rounded upwards and less than five tenths of a percentage point (i.e., < 0.5) rounded downwards (e.g., 12.5% rounded to 13% and 12.4% rounded to 12%), except to the extent otherwise provided in the first paragraph of “Termination of Employment - Due to a Change in Control” above.

For purposes of the “Average ROCE” calculation described above, ROCE for a fiscal year shall be calculated, as a percentage, as the sum of the Company’s non-GAAP after-tax net interest expense for such fiscal year and non-GAAP adjusted net income (loss) for such fiscal year, divided by the average of the Company’s non-GAAP total capitalization (calculated as the sum of total stockholders’ equity and current and long-term debt, less cash, in each case as of December 31st of the applicable fiscal year) for such fiscal year and the immediately preceding fiscal year, with such resulting percentage rounded to the nearest tenth of a percentage point, with five hundredths or more of a percentage point (i.e., ≥ 0.05) rounded upwards and less than five hundredths of a percentage point (i.e., < 0.05) rounded downwards (e.g., 12.05% rounded to 12.1% and 12.04% rounded to 12.0%).

Negative TSR Cap. Notwithstanding any of the above provisions to the contrary (including the “Absolute ROCE Modifier” provision), in the event the Total Shareholder Return of the Company shall be negative (i.e., less than 0%), the Performance Multiple shall not exceed, and shall be capped at, 100%.

EX-10.10

Exhibit 10.10

CHANGE OF CONTROL AGREEMENT

This Change of Control Agreement (“Agreement”) between EOG Resources, Inc., a Delaware corporation (the “Company”), and Ann D. Janssen (the “Employee”) is effective as of this 2nd day of February, 2024 (the “Effective Date”). Certain capitalized terms used herein are defined in Section 21.

WITNESSETH:

Whereas, the Company considers it to be in the best interests of its stockholders to encourage the continued employment of certain key employees of the Company notwithstanding the possibility, threat or occurrence of a Change of Control of the Company; and

Whereas, the Employee is a key employee of the Company; and

Whereas, the Company believes that the possibility of the occurrence of a Change of Control of the Company may result in the termination by the Employee of the Employee’s employment by the Company or in the distraction of the Employee from the performance of Employee’s duties to the Company, in either case to the detriment of the Company and its stockholders; and

Whereas, the Company recognizes that the Employee could suffer adverse financial and professional consequences if a Change of Control of the Company were to occur; and

Whereas, the Company wishes to continue to protect the Employee if a Change of Control of the Company occurs, thereby encouraging the Employee to remain in the employ of the Company and not to be distracted from the performance of Employee’s duties to the Company by the possibility of a Change of Control of the Company; and

Now, Therefore, the parties agree as follows:

SECTION 1.    OTHER EMPLOYMENT ARRANGEMENTS.

    (a)    This Agreement does not affect the Employee’s existing or future employment arrangements with the Company unless a Change of Control of the Company shall have occurred before the expiration of the term of this Agreement. The Employee’s employment with the Company shall continue to be governed by the Employee’s existing or future employment agreements with the Company, if any, or, in the absence of any employment agreement, shall continue to be at the will of the Company, except that if a Change of Control of the Company shall have occurred before the expiration of the term of this Agreement and the Employee’s employment with the Company is terminated (whether by the Employee or the Company or automatically as provided in Section 3) after the occurrence of that Change of Control of the Company, then the Employee shall be entitled to receive certain benefits as provided in this Agreement.

    (b)    Nothing in this Agreement shall prevent or limit the Employee’s continuing or future participation in any plan, program, policy or practice of or provided by the Company or any of its Affiliates and for which the Employee may qualify, nor shall anything herein limit or otherwise affect such rights as the Employee may have under any contract or agreement with the Company or any of its Affiliates. Amounts which are vested benefits or which the Employee is otherwise entitled to receive under any plan, program, policy or practice of or provided by, or any contract or agreement with, the Company or any of its Affiliates at or subsequent to the date of termination of the Employee’s employment with the Company shall be payable or otherwise provided in accordance with such plan, program, policy or practice or contract or agreement except as explicitly modified by this Agreement.

SECTION 2.    CHANGE OF CONTROL OF THE COMPANY.

    A “Change of Control of the Company” shall mean the occurrence of any of the following events:

(a)    The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) (an “Exchange Act Person”) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20% or more of either the then-outstanding shares of common stock of the Company (the “Outstanding Company Common Stock”) or the combined voting power of the then-outstanding voting securities of the Company entitled to vote generally in the election of directors (the “Outstanding Company Voting Securities”); provided, however, that, for purposes of this clause (a), the following acquisitions shall not constitute a Change of Control of the Company: (i) any acquisition directly from the Company, (ii) any acquisition by the Company, (iii) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any Affiliated Company, (iv) any acquisition by any corporation pursuant to a transaction that complies with subclauses (i), (ii) and (iii) of clause (c) of this Section 2 or (v) an acquisition by a Qualified Institutional Investor, but only for so long as such investor remains a Qualified Institutional Investor;

(b)    Individuals who, as of May 3, 2005, constitute the Board of Directors (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Board of Directors; provided, however, that any individual becoming a director subsequent to May 3, 2005, whose election, or nomination for election by the Company’s stockholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of an Exchange Act Person other than the Board of Directors;

(c)    Consummation of a reorganization, merger, consolidation or sale or other disposition of all or substantially all of the assets of the Company or the acquisition of the assets or stock of another entity (a “Business Combination”), in each case, unless, following such

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Business Combination, (i) all or substantially all of the individuals and entities that were the beneficial owners of the Outstanding Company Common Stock and the Outstanding Company Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 60% of the then-outstanding shares of common stock and the combined voting power of the then-outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination (including, without limitation, a corporation that, as a result of such transaction, owns the Company or all or substantially all of the Company’s assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership immediately prior to such Business Combination of the Outstanding Company Common Stock and the Outstanding Company Voting Securities, as the case may be, (ii) no Exchange Act Person (excluding any corporation resulting from such Business Combination or any employee benefit plan (or related trust) of the Company or such corporation resulting from such Business Combination) beneficially owns, directly or indirectly, 20% or more of, respectively, the then-outstanding shares of common stock of the corporation resulting from such Business Combination or the combined voting power of the then-outstanding voting securities of such corporation, except to the extent that such ownership existed prior to the Business Combination, and (iii) at least a majority of the members of the board of directors of the corporation resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement or of the action of the Board of Directors providing for such Business Combination; or

(d)Approval by the stockholdersof the Company of a complete liquidation or dissolution of the Company.

Notwithstanding anything contained in this Agreement to the contrary, if (i) the Employee’s employment with the Company is terminated, or (ii) an event occurs which, had it occurred after a Change of Control of the Company, would with proper notice from Employee constitute an Event of Termination for Good Reason, and if it is reasonably demonstrated by the Employee that such action (A) was taken at the request of a third party that has taken steps reasonably calculated to effect a Change of Control of the Company or (B) otherwise arose in connection with or anticipation of a Change of Control of the Company, then for all purposes of this Agreement, such Change of Control of the Company shall be deemed to have occurred on the date immediately prior to the date of such termination or event.

SECTION 3.    TERM OF THIS AGREEMENT.

The term of this Agreement shall begin on the Effective Date and shall expire on the first to occur of:

        (a)    the Employee’s death, the Employee’s Disability or the Employee’s Retirement, which events shall also be deemed automatically to terminate the Employee’s employment by the Company; or

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        (b)    the termination by the Employee or the Company of the Employee’s employment by the Company.

The expiration of the term of this Agreement shall not terminate this Agreement itself or affect the right of the Employee or the Employee’s legal representatives to enforce the payment of any amount or other benefit to which the Employee was entitled before the expiration of the term of this Agreement or to which the Employee became entitled as a result of the event that caused the term of this Agreement to expire.

SECTION 4.    EVENT OF TERMINATION FOR CAUSE.

(a)An “Event of Termination for Cause” shall mean the Employee's (i) conviction of a felony involving moral turpitude (which, through lapse of time or otherwise, is not subject to appeal), (ii) willful refusal without proper legal cause to perform employee's duties and responsibilities which remains uncorrected for thirty (30) daysfollowing written notice to the Employee by the Company of such event, or (iii) willfully engaging in conduct which the Employee has, or reasonably should have, reason to know is materially injurious to the Company.

(b)For purposes of this Section 4, no act, or failure to act, on the part of the Employee shall be considered “willful” unless it is done, or omitted to be done, by the Employee in bad faith or without reasonable belief that the Employee’s action or omission was in the best interests of the Company. Any act, or failure to act, based upon authority given pursuant to a resolution duly adopted by the Board of Directors or upon the instructions of the Chief Executive Officer of the Company or a senior officer of the Company or based upon the advice of counsel for the Company shall be conclusively presumed to be done, or omitted to be done, by the Employee in good faith and in the best interests of the Company.

(c)The cessation of employment of the Employee as a result of the alleged occurrence of an event referred to in clause (ii) or (iii) of the definition of “Event of Termination for Cause” shall not be deemed to be as a result of an Event of Termination for Cause unless and until there shall have been delivered to the Employee a copy of a resolution duly adopted by the affirmative vote of not less than three-quarters of the entire membership of the Board of Directors (excluding the Employee, if the Employee is a member of the Board of Directors) at a meeting of the Board of Directors called and held for such purpose (after reasonable notice is provided to the Employee and the Employee is given an opportunity, together with counsel for the Employee, to be heard before the Board of Directors), finding that, in the good faith opinion of the Board of Directors, the Employee is guilty of the conduct described in clause (ii) or (iii) of such definition and specifying the particulars thereof in detail. Any determination of the Board of Directors under this clause (c) shall not be binding on the Employee, shall not be conclusive as to whether an Event of Termination for Cause has occurred, and shall not affect Employee’s right to contest whether an Event of Termination for Cause has occurred.

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SECTION 5.    EVENT OF TERMINATION FOR GOOD REASON.

An “Event of Termination for Good Reason” shall mean, after a Change of Control of the Company, the occurrence of any of the following events, provided Employee serves written notice of termination in connection with or based upon any such event within ninety (90) days of the Employee’s knowledge of the occurrence of such event:

(a)    a reduction in the Employee's authority and/or responsibilities (whether or not occurring solely as a result of the Company’s ceasing to be a publicly traded entity); or

(b)    a reduction in Employee's Annual Base Salary as in effect immediately prior to the Change of Control of the Company or a reduction in Employee’s target annual bonus as in effect immediately prior to the Change of Control of the Company, or the failure to continue the Employee's full participation in any employee benefit plan or program (unless replaced by a substantially comparable plan or program) in which Employee is eligible to participate immediately prior to the Change of Control of the Company (other than as a result of the normal expiration of such plan or program), in each case other than as a part of a general program to reduce compensation or benefits on a proportional basis relative to all other employees of the Company; or

(c)    a relocation of the Employee's primary place of work to a location more than 50 miles away from the Employee's primary place of work immediately prior to the Change of Control of the Company (provided, however, this clause (c) shall no longer apply to an employee after he has accepted any such relocation after a Change of Control of the Company has occurred and the above referenced ninety (90) day period has passed), or

(d)    the failure of the Company to obtain the assumption in writing of its obligation to perform this Agreement by any successor to the Company prior to a merger, consolidation, sale or similar transaction.

For the avoidance of doubt, any action referred to in clause (a), (b), (c) or (d) above shall constitute an Event of Termination for Good Reason under the foregoing definition regardless of whether the Company is permitted to take such action under any employment contract with the Employee.

SECTION 6.    NOTICE OF TERMINATION.

If a Change of Control of the Company shall have occurred before the expiration of the term of this Agreement, any termination by the Employee or the Company of the Employee’s employment by the Company, or any determination of the Employee’s Disability, that occurs within two (2) years of such Change of Control shall be communicated by notice to the other party that shall indicate the specific paragraph of Section 7 pursuant to which the Employee is to receive benefits as a result of the termination. If the notice states that the Employee’s employment by the Company has been automatically terminated as a result of the Employee’s Disability, the notice shall specifically describe the basis for the determination of the Employee’s

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Disability and shall state the date of the determination of the Employee’s Disability, which date shall be not more than ten (10) days before the date such notice is given. If the notice is from the Company and states that the Employee’s employment by the Company is terminated by the Company as a result of the occurrence of an Event of Termination for Cause, the notice shall specifically describe the action or inaction of the Employee that the Company believes constitutes an Event of Termination for Cause, and in the case of a termination under clause (ii) or (iii) of the definition of Event of Termination for Cause, shall include the resolution of the Board of Directors referred to in Section 4(c). If the notice is from the Employee and states that the Employee’s employment by the Company is terminated by the Employee as a result of the occurrence of an Event of Termination for Good Reason, the notice shall specifically describe the action or inaction of the Company that the Employee believes constitutes an Event of Termination for Good Reason. Each notice given pursuant to this Section 6 (other than a notice stating that the Employee’s employment by the Company has been automatically terminated as a result of the Employee’s Disability) shall state a date, which shall be not fewer than thirty (30) days nor more than sixty (60) days after the date such notice is given, on which the termination of the Employee’s employment by the Company is effective. The date so stated in accordance with this Section 6 shall be the “Termination Date”. If a Change of Control of the Company shall have occurred before the expiration of the term of this Agreement, any subsequent purported termination by the Company of the Employee’s employment by the Company, or any subsequent purported determination by the Company of the Employee’s Disability, within two (2) years of such Change of Control shall be ineffective unless that termination or determination shall have been communicated by the Company to the Employee by notice that meets the requirements of the foregoing provisions of this Section 6 and the provisions of Section 9.

SECTION 7.    BENEFITS PAYABLE ON CHANGE OF CONTROL AND TERMINATION.

    If a Change of Control of the Company shall have occurred before the expiration of the term of this Agreement, and the Employee’s employment by the Company is terminated (whether by the Employee or the Company or automatically as provided in Section 3) within two (2) years after the occurrence of that Change of Control of the Company, the Employee shall be entitled to the following benefits:

    (a)    If the Employee’s employment by the Company is terminated by the Company as a result of the occurrence of an Event of Termination for Cause, or by the Employee before the occurrence of an Event of Termination for Good Reason, then the Company shall pay to the Employee the Base Salary accrued through the Termination Date but not previously paid to the Employee, and the Employee shall be entitled to any other amounts or benefits provided under any plan, policy, practice, program, contract or arrangement of or with the Company, which shall be governed by the terms thereof (except as explicitly modified by this Agreement).

    (b)    If the Employee’s employment by the Company is automatically terminated as a result of the Employee’s death, the Employee’s Disability or the Employee’s Retirement, then the Company shall pay to the Employee the Base Salary accrued through the date of the occurrence of that event but not previously paid to the Employee, and the Employee shall be

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entitled to any other amounts or benefits provided under any plan, policy, practice, program, contract or arrangement of or with the Company, which shall be governed by the terms thereof (except as explicitly modified by this Agreement).

    (c)    If the Employee’s employment by the Company is terminated (x) by the Company, other than as a result of the occurrence of an Event of Termination for Cause, or (y) by the Employee after the occurrence of an Event of Termination for Good Reason, then the Employee shall be entitled to the following:

        (i)    the Company shall pay to the Employee the Base Salary and compensation for earned but unused vacation time accrued through the Termination Date but not previously paid to the Employee;

        (ii)    the Company shall pay to the Employee, as a lump sum, an amount equal to the total of the following amounts:

(A)    2.99 times the amount of the Employee’s Annual Base Salary as in effect immediately prior to the Change of Control (or if increased, immediately prior to the Termination Date); plus

(B)    two (2) times the amount of the Employee’s target annual bonus as in effect immediately prior to the Change of Control (or if no target annual bonus for the year in which the Change of Control occurs has been set, the target annual bonus for the immediately prior year) (or if increased, immediately prior to the Termination Date); plus

(C)    the amount of the retirement contributions that would have been made by the Company on behalf of the Employee to the Company’s Savings and Retirement Plan (as amended, supplemented, modified and/or restated from time to time, and including any replacement or successor plan) if the Employee had continued to be employed by the Company at the Employee’s Annual Base Salary and target annual bonus as in effect immediately prior to the Change of Control (or if increased, immediately prior to the Termination Date) for three (3) years following the Termination Date; and plus

(D)    the amount of the matching contributions that would have been made by the Company on behalf of the Employee to the Company’s Savings and Retirement Plan (as amended, supplemented, modified and/or restated from time to time, and including any replacement or successor plan) if the Employee had continued to be employed by the Company at the Employee’s Annual Base Salary and target annual bonus as in effect immediately prior to the Change of Control (or if increased, immediately prior to the Termination Date) for three (3) years following the Termination Date and had continued to contribute to the Company’s Savings and Retirement Plan (as amended, supplemented, modified and/or restated from time to time, and including any replacement or successor plan) during such three (3) year period at the Employee’s then-current contribution level.

        (iii)    the Company shall arrange for the Employee’s uninterrupted participation for three (3) years after the Termination Date in the Company’s major medical/dental insurance

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plan, which participation shall cease upon Employee’s eligibility for participation in a major medical/dental insurance plan of another employer;

        (iv)    the Company shall cause the Employee to receive three (3) years age and service credit for eligibility for the Company’s retiree medical insurance coverage; and

        (v)    the Company shall provide outplacement services at a cost not to exceed $50,000.00.

Each payment required to be made to the Employee pursuant to the foregoing provisions of this Section 7 shall be made by check drawn on an account of the Company at a bank located in the United States of America (unless the Employee has elected to have salary payments deposited directly by the Company to a bank account maintained by the Employee, in which event the Company shall make a direct deposit of the payment to that account), and shall be paid (x) if the Employee’s employment by the Company was terminated as a result of the Employee’s death, the Employee’s Disability or the Employee’s Retirement, not more than thirty (30) days immediately following the date of the occurrence of that event, and (y) if the Employee’s employment by the Company was terminated for any other reason, not more than ten (10) days immediately following the Termination Date.

SECTION 8.    SUCCESSORS.

If a Change of Control of the Company shall have occurred before the expiration of the term of this Agreement,

    (a)    the Company shall not, directly or indirectly, consolidate with, merge into or sell or otherwise transfer its assets as an entirety or substantially as an entirety to, any person, or permit any person to consolidate with or merge into the Company, unless immediately after such consolidation, merger, sale or transfer, the Successor shall have assumed in writing the Company’s obligations under this Agreement and agreed to perform this Agreement in the same manner and to the same extent that the Company would be required to perform it if no such succession had taken place; and

    (b)    not fewer than ten (10) days before the consummation of any consolidation of the Company with, merger by the Company into, or sale or other transfer by the Company of its assets as an entirety or substantially as an entirety to, any person, the Company shall give the Employee notice of that proposed transaction.

SECTION 9.    NOTICE.

Notices required or permitted to be given by either party pursuant to this Agreement shall be in writing and shall be deemed to have been given when delivered personally to the other party or when deposited with the United States Postal Service as certified or registered mail with postage prepaid and addressed:

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    (a)    if to the Employee, at the Employee’s address last shown on the Company’s records, and

    (b)    if to the Company, at 1111 Bagby, Sky Lobby 2, Houston, Texas 77002, directed to the attention of the Company’s Chairman of the Board,

or, in either case, to such other address as the party to whom such notice is to be given shall have specified by notice given to the other party.

SECTION 10.    WITHHOLDING TAXES.

The Company may withhold from all payments to be paid to the Employee pursuant to this Agreement all taxes that, by applicable federal or state law, the Company is required to so withhold.

SECTION 11.    U.S. EXCISE TAXES.

If any payment or right accruing to the Employee from the Company or an Affiliate under this Agreement without the application of this Section 11 (“Total Payments”), would constitute a “parachute payment” (as defined in Section 280G of the Code (as defined in Section 20) and regulations thereunder), the severance benefit payable under this Agreement shall be reduced to the largest amount that will result in no portion of the amounts payable or rights accruing being subject to an excise tax under Section 4999 of the Code or being disallowed as a deduction under Section 280G of the Code. The determination of whether any reduction in the severance benefit payable is to apply shall be made by a public accounting firm chosen by the Company, at the expense of the Company. Such determination shall be made in good faith after consultation with the Employee and shall be conclusive and binding on the Employee. The Employee shall cooperate in good faith with said accounting firm in making such determination and providing the necessary information for this purpose. The foregoing provisions of this Section 11 shall apply only if after reduction for any applicable federal excise tax imposed by Section 4999 of the Code and federal, state or local income or employment taxes, the Total Payments accruing to the Employee would be less than the amount of the Total Payments as reduced under the foregoing provisions of this Section 11 and after reduction for only federal, state or local income or employment taxes. For the avoidance of doubt, the parties to this Agreement agree that this Section 11 explicitly modifies the U.S. Excise Tax treatment of benefits which may be payable or otherwise provided under any plan, program, policy, or practice of the Company or an Affiliate and any agreement or understanding that the Employee may have with the Company or an Affiliate.

SECTION 12.    EXPENSES OF ENFORCEMENT.

The Company agrees to pay as incurred (within ten (10) days following the Company’s receipt of an invoice from the Employee), to the full extent permitted by law, all legal fees and expenses that the Employee may reasonably incur as a result of any contest (regardless of the outcome thereof) by the Company, the Employee or others of the validity, interpretation or enforceability of, or liability under, any provision of this Agreement (including as a result of any

9

contest by the Employee about the amount of any payment pursuant to this Agreement), plus, in each case, interest on any delayed payment at the applicable federal rate provided for in Section 7872(f)(2)(A) of the Code.

SECTION 13.    EMPLOYMENT BY WHOLLY OWNED ENTITIES.

If, at or after the Effective Date, the Employee is or becomes an employee of one or more corporations, partnerships, limited liability companies or other entities that are, directly or indirectly, wholly owned by the Company, references in this Agreement to the Employee’s employment by the Company shall include the Employee’s employment by any such wholly owned entity.

SECTION 14.    NO OBLIGATION TO MITIGATE; NO RIGHTS OF OFFSET.

    (a)    The Employee shall not be required to mitigate the amount of any payment or other benefit required to be paid to the Employee pursuant to this Agreement, whether by seeking other employment or otherwise, nor shall the amount of any such payment or other benefit be reduced on account of any compensation earned or benefits received by the Employee as a result of employment by another person.

    (b)    The Company’s obligation to make the payments provided for in this Agreement and otherwise to perform its obligations hereunder shall not be affected by any set-off, counterclaim, recoupment, defense or other claim, right or action which the Company may have against the Employee or others.

SECTION 15.    AMENDMENT AND WAIVER.

No provision of this Agreement may be amended or waived (whether by act or course of conduct or omission or otherwise) unless that amendment or waiver is by written instrument signed by the parties hereto. No waiver by either party of any breach of this Agreement shall be deemed a waiver of any other or subsequent breach.

SECTION 16.    GOVERNING LAW.

The validity, interpretation, construction and enforceability of this Agreement shall be governed by the laws of the State of Texas.

SECTION 17.    VALIDITY.

The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement, which shall remain in full force and effect.

SECTION 18.    COUNTERPARTS.

This Agreement may be executed in counterparts, each of which shall be deemed an original but all of which together will constitute the same instrument.

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SECTION 19.    ASSIGNMENT.

This Agreement shall inure to the benefit of and be enforceable by the Employee’s legal representative. The Company may not assign any of its obligations under this Agreement unless (i) such assignment is to a Successor and (ii) the requirements of Section 8 are fulfilled.

SECTION 20.    CODE SECTION 409A.

The parties hereto will act in good faith to equitably restructure any payments and benefits provided for in this Agreement to the extent necessary to comply with Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”). Any such restructuring shall not reduce the value of such benefits and payments. Upon the Employee’s termination of employment with the Company, in no event shall any payment or provision of benefits be made prior to the date that is six (6) months after the Employee’s termination of employment to the extent such payment delay is required under Section 409A(a)(2)(B)(i) of the Code. For purposes of any payments or provision of benefits under this Agreement, the Employee shall not be considered to have terminated employment unless the Employee incurs a “separation from service” with the Company within the meaning of Section 409A(a)(2)(A)(i) of the Code and applicable guidance issued thereunder.

SECTION 21.    MISCELLANEOUS.

    (a)    As used in this Agreement, the following terms and phrases have the indicated meanings:

        (i)    “Affiliate” and “Affiliates” mean, when used with respect to any entity, individual, or other person, any other entity, individual, or other person which, directly or indirectly, through one or more intermediaries controls, or is controlled by, or is under common control with such entity, individual or person. “Affiliated Company” means any entity that is an Affiliate of the Company.

        (ii)    “Annual Base Salary” means, at any point in time, the regular rate of wages payable to the Employee, expressed on an annualized basis, including any base salary that has been earned but deferred.

(iii)    “Board of Directors” means the Board of Directors of the Company.

        (iv)    “Change of Control of the Company” has the meaning assigned to that phrase in Section 2.

        (v)     “Company” has the meaning assigned to that term in the preamble to this Agreement. The term “Company” shall also include any Successor, whether the liability of such Successor under this Agreement is established by contract or occurs by operation of law.

        (vi)    “Effective Date” has the meaning assigned to that term in the preamble to this Agreement.

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        (vii)    “Employee” has the meaning assigned to such term in the preamble to this Agreement.

        (viii)     “Employee’s Disability” means:

            (A)    if no Change of Control of the Company shall have occurred before the date of determination, the physical or mental disability of the Employee determined in accordance with the disability policy of the Company at the time in effect and generally applicable to its salaried employees; and

            (B)    if a Change of Control of the Company shall have occurred before the date of determination, the physical or mental disability of the Employee determined in accordance with the disability policy of the Company in effect immediately before the occurrence of the first Change of Control of the Company and generally applicable to its salaried employees.

        (ix)    “Employee’s Retirement” means (x) if no Change of Control of the Company shall have occurred before the date of the Employee’s proposed retirement, the retirement of the Employee in accordance with the retirement policy of the Company at the time in effect and generally applicable to its salaried employees, and (y) if a Change of Control of the Company shall have occurred before the date of the Employee’s proposed retirement, the retirement of the Employee from the employ of the Company in accordance with the retirement policy of the Company in effect immediately before the occurrence of the first Change of Control of the Company and generally applicable to its salaried employees.

        (x)    “Event of Termination for Good Reason” has the meaning assigned to that phrase in Section 5.

        (xi)    “Event of Termination for Cause” has the meaning assigned to that phrase in Section 4.

        (xii)    “Expiration Date” has the meaning assigned to that term in Section 3.

        (xiii)     “Person” means any individual, corporation, partnership, joint venture, association, joint-stock company, limited partnership, limited liability company, trust, unincorporated organization, government, or agency or political subdivision of any government.

(xiv)    “Qualified Institutional Investor” shall mean, as of any time of determination, a Person that is described in Rule 13d-l(b)(1) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) (as such Rule is in effect on the date hereof) and is eligible to report (and, if such Person is the Beneficial Owner of greater than 5% of the shares of common stock of the Company (“Common Shares”), does in fact report) beneficial ownership of Common Shares on Schedule 13G, and such Person (i) is not required to file a Schedule 13D (or any successor or comparable report) with respect to its beneficial ownership of Common Shares, and (ii) shall be the Beneficial Owner of less than 15% of the Common Shares then outstanding; provided, however, that a Person which would constitute a

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Qualified Institutional Investor except for its failure to satisfy clause (ii) of this definition shall nonetheless constitute a Qualified Institutional Investor if (A) such Person or an Affiliate of such Person shall have, as of December 31, 2004, reported beneficial ownership of greater than 5% of the Common Shares for a period of two consecutive years and shall thereafter continuously beneficially own greater than 5% of the Common Shares then outstanding prior to the time of determination, (B) shall be the Beneficial Owner of less than 15% of the Common Shares then outstanding (including in such calculation the holdings of all of such Person’s Affiliates and Associates other than those which, under published interpretations of the SEC or its Staff, are eligible to file separate reports on Schedule 13G with respect to their beneficial ownership of the Common Shares), and (C) such Person shall be the Beneficial Owner of less than 30% of the Common Shares then outstanding.

    Solely for the purposes of the above definition of “Qualified Institutional Investor”, a person shall be deemed to be the “Beneficial Owner” of and shall be deemed to “beneficially own” any securities (i) which such Person or any of such Person's Affiliates or Associates (as defined in Rule 12b-2 of the Exchange Act) beneficially owns, directly or indirectly; (ii) which such Person or any of such Person's Affiliates or Associates has (A) the right to acquire (whether such right is exercisable immediately or only after the passage of time) pursuant to any agreement, arrangement or understanding (other than customary agreements with and between underwriters and selling group members with respect to a bona fide public offering of securities), or upon the exercise of conversion rights, exchange rights, rights, warrants or options, or otherwise; provided, however, that a Person shall not be deemed the Beneficial Owner of, or to beneficially own, securities tendered pursuant to a tender or exchange offer made by or on behalf of such Person or any of such Person's Affiliates or Associates until such tendered securities are accepted for purchase or exchange; or (B) the right to vote pursuant to any agreement, arrangement or understanding; provided, however, that a Person shall not be deemed the Beneficial Owner of, or to beneficially own, any security if the agreement, arrangement or understanding to vote such security (1) arises solely from a revocable proxy or consent given to such Person in response to a public proxy or consent solicitation made pursuant to, and in accordance with, the applicable rules and regulations promulgated under the Exchange Act and (2) is not also then reportable on Schedule 13D under the Exchange Act (or any comparable or successor report); or (iii) which are beneficially owned, directly or indirectly, by any other Person with which such Person or any of such Person's Affiliates or Associates has any agreement, arrangement or understanding (other than customary agreements with and between underwriters and selling group members with respect to a bona fide public offering of securities) for the purpose of acquiring, holding, voting (except to the extent contemplated by the proviso to (ii)(B) above) or disposing of any securities of the Company.

        (xv)     “Successor” means a person with or into which the Company shall have been merged or consolidated or to which the Company shall have transferred its assets as an entirety or substantially as an entirety.

        (xvi)    “Termination Date” has the meaning assigned to that term in Section 6.

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        (xvii)    “This Agreement” means this Change of Control Agreement as it may be amended from time to time.

    (b)    In the event of the enactment of any successor provision to any statute or rule cited in this Agreement, references in this Agreement to such statute or rule shall be to such successor provision.

    (c)    The headings of Sections of this Agreement shall not control the meaning or interpretation of this Agreement.

    (d)    References in this Agreement to any Section are to the corresponding Section of this Agreement unless the context otherwise indicates.

In Witness Whereof, the Company and the Employee have executed this Agreement as of the Effective Date.

EOG RESOURCES, INC.

By: /s/ MICHELE L. HATZ

Name: Michele L. Hatz

Title: Vice President and Chief Human Resources Officer

ANN D. JANSSEN

/s/ ANN D. JANSSEN

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EX-10.12C

Exhibit 10.12(c)

EOG Resources, Inc.

Second Amended and Restated Annual Bonus Plan

1. Purpose of the Plan. The Second Amended and Restated Annual Bonus Plan (the “Plan”) of EOG Resources, Inc. (the “Company”) is designed to enhance the Company’s ability to attract, reward and retain highly qualified employees and provide additional financial incentives to employees to promote the success of the Company.

2. Eligibility. Eligibility under the Plan is limited to (i) active regular full-time and active regular part-time employees of the Company who are on the Company’s payroll when bonus payments for a calendar year are made, (ii) certain terminated employees of the Company (regular full-time or regular part-time) as provided in Section 6 and (iii) employees of the Company (regular full-time or regular part-time) whose unpaid leave of absenceor absence treated as “paid hours not worked” (or similar treatment/coding) includes the payment date for bonuses for a calendar year as provided in Section 7 (each, a “Participant” and, collectively, “Participants”).

3. Administration. The Plan shall be administered by the Compensation and Human Resources Committee of the Board of Directors of the Company (the “Plan Administrator”), which shall have the exclusive right, power and authority, in its sole and absolute discretion, to administer the Plan and all related Plan documents. The Plan Administrator is fully authorized and empowered to take any and all actions which it deems necessary or appropriate to administer the Plan, including, without limitation, the authority to (i) interpret the Plan, (ii) determine the applicable performance goals and bonus opportunities for each Participant and (iii) determine bonus awards for each Participant. The Plan Administrator may, however, delegate to any of the executive officers of the Company (as determined by the Board of Directors of the Company for purposes of Regulation S-K) the authority to determine the applicable performance goals, bonus opportunities and bonus awards in accordance with the terms of the Plan for, and make related interpretations of the Plan in respect of, Participants who are not executive officers of the Company. Additionally, the Plan Administrator may, from time to time, adopt (or cause to be adopted) such rules, regulations, definitions and forms consistent with the provisions of the Plan as they may deem advisable to carry out and administer the Plan. All interpretations and actions taken by the Plan Administrator (or by an executive officer pursuant to a delegation of authority from the Plan Administrator as contemplated by this Section 3) in connection with the administration of the Plan shall be final, conclusive and binding on all persons having an interest in the Plan.

4. Performance Goals, Bonus Opportunities and Bonus Awards. Performance goals, bonus opportunities and bonus awards for a calendar year shall be determined in the sole discretion of the Plan Administrator (subject to the authority of the Plan Administrator, pursuant to Section 3, to delegate to any of the executive officers of the Company the authority to determine (in accordance with the terms of the Plan) the applicable performance goals, bonus opportunities and bonus awards for Participants who are not executive officers of the Company). Performance goals may be based on

Company-wide financial, operational and/or strategic performance measures; financial, operational and/or strategic performance of one or more business units of the Company; personal performance goals for a Participant; and/or such other goals as may be determined by the Plan Administrator. The applicable performance goals for a calendar year may differ among Participants. Except as is provided in Section 6 in respect of the eligibility of certain terminated employees to receive a prorated bonus for a calendar year, the awarding of bonuses for a calendar year under the Plan shall be in the sole discretion of the Plan Administrator based on the attainment of the applicable performance goals for the year and other factors as they may determine in their sole discretion. Notwithstanding any provision of the Plan to the contrary, in no event shall the annual bonus awarded to an executive officer of the Company for a calendar year, inclusive of individual performance considerations, exceed 200% of such executive officer’s then-applicable bonus target percentage (as previously determined by the Plan Administrator).

5. Form and Timing of Payment. Bonuses awarded pursuant to the Plan to any Participant shall be paid on or before March 15 of the year following the end of the applicable calendar year for which the applicable performance goals were measured. Bonuses awarded shall be paid in cash or, at the discretion of the Plan Administrator, in the form of restricted stock or restricted stock units (collectively, “Stock”) awarded under the terms of the Company’s 2021 Omnibus Equity Compensation Plan (or a successor plan), or in any combination of cash and Stock. In addition, the Plan Administrator may permit Participants who are eligible to participate in the Company’s 409A Deferred Compensation Plan (or a successor or similar deferral plan sponsored by the Company, if any) the option to defer the receipt of a cash bonus awarded pursuant to the Plan in accordance with the terms of such deferral plan. Bonuses under the Plan are discretionary, not guaranteed wages, and shall not be considered vested or determinable until paid. Nothing under the Plan shall be construed to create an enforceable right to payment of a bonus.

6. Termination of Employment. Notwithstanding any other provision of the Plan and for the avoidance of doubt, in the event that a Participant’s employment with the Company terminates due to voluntary termination or involuntary termination for performance reasons or for cause prior to the payment date for bonuses for a calendar year, the Participant shall not be eligible to receive a bonus for such calendar year. In the event that a Participant’s employment with the Company is terminated due to involuntary termination for any reason other than for cause or performance reasons, death, disability, or Company-approved retirement prior to the payment date for bonuses for a calendar year, such Participant shall be eligible (subject to the other provisions of this Section 6) to receive a prorated bonus, payable in cash, based on the number of days of active employment in the calendar year and the Participant’s base pay and bonus target percentage as of the date of such termination. The payment of such a prorated bonus shall (i) not require the approval of the Plan Administrator (contemplated by Section 4), (ii) be in the sole discretion of the principal executive officer of the Company (or, in his absence, the principal operating officer of the Company) (including

2

the option for the Participant to defer the receipt of such prorated bonus in accordance with a Company deferral plan), (iii) require acceptance and execution by the Participant of such form of waiver and release as may be deemed appropriate by the Company in its sole discretion and (iv) if so approved, be made not later than two and one-half months from the effective date of such termination; provided, however, as contemplated by Section 4, that if the Participant is an executive officer of the Company, such payment shall require the approval of, and shall be in the sole discretion of, the Plan Administrator. For the avoidance of doubt, and as is provided in Section 5, nothing in this Section 6 shall be construed to create an enforceable right to payment of such a prorated bonus; prorated bonuses pursuant to this Section 6 shall be discretionary, not guaranteed wages, and shall not be considered vested or determinable until paid.

7. Active Employment;Unpaid Leaves of Absence; Other Absence. Notwithstanding any other provision of the Plan, a Participant’s bonus in respect of a calendar year shall be based on his/her number of days of active employment in such calendar year. For the avoidance of doubt, an unpaid leave of absence or absence treated as “paid hours not worked” (or similar treatment/coding) does not constitute “active employment” for purposes of the Plan. Accordingly, any days during a calendar year during which a Participant is on an unpaid leave of absence or an absence treated as “paid hours not worked” (or similar treatment/coding) shall be taken into account (and shall not be counted) in determining the amount of such Participant’s bonus for such calendar year.

Further, if a Participant is an active employee of the Company (regular full-time or regular part-time) for all or part of a calendar year and, subsequent to such calendar year-end, commences an unpaid leave of absence or absence treated as “paid hours not worked” (or similar treatment/coding) that includes the payment date for bonuses for such calendar year, the Participant shall nevertheless be eligible to receive a bonus for such calendar year based on his/her number of days of active employment in such calendar year.

8. Unfunded Nature of the Plan. The Plan shall constitute an unfunded, unsecured obligation of the Company to make bonus payments from its general assets in accordance with the provisions of the Plan. The establishment of the Plan shall not be deemed to create a trust. No Participant shall have any security or other interest in any assets of the Company.

9. Prohibition Against Assignment or Encumbrance. No right, title, interest or benefit hereunder shall ever be liable for, or charged with, any of the torts or obligations of a Participant, or be subject to seizure by any creditor of a Participant or any person claiming under a Participant. No Participant, nor any person claiming under a Participant, shall have the power to sell, transfer, pledge, anticipate or dispose of any right, title, interest or benefit hereunder in any manner until the same shall have been actually distributed free and clear of the terms of the Plan.

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10. Plan Not an Employment Contract. Nothing in the adoption, implementation or provisions of the Plan shall confer on any Participant any right to continued employment by the Company or affect in any way the right of the Company to terminate a Participant’s employment.

11. Relationship to Other Benefits. No payment pursuant to the Plan shall be taken into account in determining any benefits pursuant to any pension, retirement, savings, profit sharing, group insurance, termination and/or indemnities or severance payments, welfare or other benefit plan of the Company or of any subsidiary or affiliate of the Company, except to the extent otherwise expressly provided in writing in such other plan or an agreement thereunder.

12. Clawback Policy. Bonus payments received by a Participant under the Plan shall be subject to the Company’s Policy for the Recovery of Erroneously Awarded Compensation (effective October 2, 2023) (as the same may be amended from time to time, and including any successor policy), to the extent the Participant is or becomes subject to such policy.

13. Severability. In the event any provision of the Plan shall be held invalid or illegal for any reason, any illegality or invalidity shall not affect the remaining parts of the Plan, but the Plan shall be construed and enforced as if the illegal or invalid provision had never been inserted, and the Company shall have the privilege and opportunity to correct and remedy such questions of illegality or invalidity by amendment as provided in the Plan.

14. Withholding of Taxes. The Company shall have the right to deduct from any payment made under the Plan any foreign, federal, state or local taxes required by law to be withheld with respect to such payments.

15. Applicable Law. The Plan shall be governed and construed in accordance with the laws of the State of Texas, except to the extent such laws are preempted by an applicable federal law.

16. Rights of Company. Nothing contained in the Plan shall prevent the Company from adopting or continuing in effect other compensation arrangements, which arrangements may be either generally applicable or applicable only in specific cases.

17. Effective Date. The Plan is adopted and effective as of January 1, 2024 and supersedes and replaces, in its entirety and with effect from January 1, 2024, that certain Amended and Restated Annual Bonus Plan of the Company adopted and effective as of January 1, 2022. The Plan shall apply to, and be effective beginning with, the bonus awards paid in respect of fiscal year 2024 performance.

18. Amendment and Termination of the Plan. The Plan Administrator may modify or terminate the Plan at any time without prior notice to, or the consent of, Participants.

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EX-21

EXHIBIT 21

EOG Resources, Inc.

Subsidiaries

As of December 31, 2023

EOG Resources, Inc., a Delaware corporation, had the U.S. and international subsidiaries shown below as of December 31, 2023.

Name of Subsidiary	Jurisdiction of Organization/Incorporation
EOG Expat Services, Inc.	Delaware
EOG Resources Australia Block NT-P87 Pty Ltd.	Western Australia
EOG Resources Australia Block WA-488 Pty Ltd.	Western Australia
EOG Resources Australia Block WA-544 Pty Ltd.	Western Australia
EOG – Canada, Inc.	Delaware
EOG Canada Oil & Gas Inc.	Alberta
EOG Resources Australia Pty Ltd.	Western Australia
EOG Resources Block 4(a) Company	Cayman Islands
EOG Resources China LLC	Delaware
EOG Resources (Nevis) Block 4 (a) Limited	Nevis
EOG Resources International, Inc.	Delaware
EOG Resources Marketing LLC	Delaware
EOG Resources Muscat Block 49 SPC	Oman
EOG Resources Muscat SPC	Oman
EOG Resources Nevis U (b) Block Limited	Nevis
EOG Resources Nitro2000 Company	Cayman Islands
EOG Resources Oman Block 49 Limited	Cayman Islands
EOG Resources Oman Limited	Cayman Islands
EOG Resources Trinidad – U(a) Block Limited	Cayman Islands
EOG Resources Trinidad Block 4(a) Unlimited	Trinidad
EOG Resources Trinidad Limited	Trinidad
EOG Resources Trinidad Nitro Unlimited	Trinidad
EOG Resources Trinidad U(b) Block Unlimited	Trinidad
EOG Resources U(b) Block Company	Cayman Islands
EOG SPG Holdings, Inc.	Delaware
SPG Dorado Injection LLC	Delaware
SPG Dorado Transportation LLC	Delaware
EOGI International Company	Cayman Islands
EOGI International, Inc.	Delaware
EOGI Oman International Block 49 Ltd.	Cayman Islands
EOGI Oman International Ltd.	Cayman Islands
EOGI Trinidad – U(a) Block Company	Cayman Islands
Murrott Capital Ltd.	Nevis
Nilo Operating Company	Delaware
Pecan Pipeline Company	Delaware

Name of Subsidiary	Jurisdiction of Organization/Incorporation
Pecan Pipeline (Wyoming) LLC	Delaware
Pecan Pipeline (North Dakota), Inc.	Delaware
Rockies Holdings LLC	Wyoming

EX-23.1

EXHIBIT 23.1

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

February 16, 2024

EOG Resources, Inc.

1111 Bagby, Sky Lobby 2

Houston, Texas 77002

Ladies and Gentlemen:

We hereby consent to the inclusion of references to our firm and to the opinions as mentioned below delivered to EOG Resources, Inc. (EOG) regarding our comparison of estimates prepared by us with those provided to us by EOG of the proved crude oil, condensate, natural gas liquids, and natural gas reserves of certain selected properties in which EOG has represented it holds an interest in the section entitled “Supplemental Information to Consolidated Financial Statements - Oil and Gas Producing Activities” in EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023, to be filed with the United States Securities and Exchange Commission on or about February 22, 2024. The opinions are contained in our reports of third party dated January 27, 2022, February 1, 2023 and January 26, 2024, with respect to the reserves estimates as of December 31, 2021, December 31, 2022, and December 31, 2023, respectively. Additionally, we hereby consent to the incorporation by reference of such references to our firm and to our opinions in EOG’s previously filed Registration Statements (File Nos. 333-261702, 333-255691, 333-150791, 333-62256, 333-84014, 333-166517, 333-166518, 333-179884, 333-188352, and 333-224466).

Very truly yours,

/s/ DeGOLYER and MacNAUGHTON

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

EX-23.2

EXHIBIT 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-261702 on Form S-3 and Registration Statement Nos. 333-255691, 333-150791, 333-62256, 333-84014, 333-166517, 333-166518, 333-179884, 333-188352, and 333-224466 on Form S-8, of our report dated February 22, 2024, relating to the financial statements of EOG Resources, Inc. and the effectiveness of EOG Resources, Inc.’s internal control over financial reporting, appearing in this Annual Report on Form 10-K for the year ended December 31, 2023.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 22, 2024

EX-24

EXHIBIT 24

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that in connection with the filing by EOG Resources, Inc., a Delaware corporation (the “Company”), of its Annual Report on Form 10-K for the fiscal year ended December 31, 2023 with the United States Securities and Exchange Commission, the undersigned director of the Company hereby constitutes and appoints Ann D. Janssen and Michael P. Donaldson, and each of them (with full power to each of them to act alone), her true and lawful attorney-in-fact and agent, for her and on her behalf and in her name, place and stead, in any and all capacities, to sign, execute and file such Annual Report on Form 10-K, together with any amendments or supplements thereto and with all exhibits and any and all documents required to be filed with respect thereto with any regulatory authority, granting unto said attorneys, and each of them, full power and authority to do and perform each and every act and action requisite and necessary to be done in and about the premises in order to effectuate the same as fully to all intents and purposes as the undersigned might or could do if personally present, with full power of substitution, hereby ratifying and confirming all the said attorneys-in-fact and agents, or either of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has hereto set her hand this 21st day of February 2024.

/s/ JANET F. CLARK

JANET F. CLARK

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that in connection with the filing by EOG Resources, Inc., a Delaware corporation (the “Company”), of its Annual Report on Form 10-K for the fiscal year ended December 31, 2023 with the United States Securities and Exchange Commission, the undersigned director of the Company hereby constitutes and appoints Ann D. Janssen and Michael P. Donaldson, and each of them (with full power to each of them to act alone), his true and lawful attorney-in-fact and agent, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file such Annual Report on Form 10-K, together with any amendments or supplements thereto and with all exhibits and any and all documents required to be filed with respect thereto with any regulatory authority, granting unto said attorneys, and each of them, full power and authority to do and perform each and every act and action requisite and necessary to be done in and about the premises in order to effectuate the same as fully to all intents and purposes as the undersigned might or could do if personally present, with full power of substitution, hereby ratifying and confirming all the said attorneys-in-fact and agents, or either of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has hereto set his hand this 16th day of February 2024.

/s/ CHARLES R. CRISP

CHARLES R. CRISP

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that in connection with the filing by EOG Resources, Inc., a Delaware corporation (the “Company”), of its Annual Report on Form 10-K for the fiscal year ended December 31, 2023 with the United States Securities and Exchange Commission, the undersigned director of the Company hereby constitutes and appoints Ann D. Janssen and Michael P. Donaldson, and each of them (with full power to each of them to act alone), his true and lawful attorney-in-fact and agent, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file such Annual Report on Form 10-K, together with any amendments or supplements thereto and with all exhibits and any and all documents required to be filed with respect thereto with any regulatory authority, granting unto said attorneys, and each of them, full power and authority to do and perform each and every act and action requisite and necessary to be done in and about the premises in order to effectuate the same as fully to all intents and purposes as the undersigned might or could do if personally present, with full power of substitution, hereby ratifying and confirming all the said attorneys-in-fact and agents, or either of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has hereto set his hand this 21st day of February 2024.

/s/ ROBERT P. DANIELS

ROBERT P. DANIELS

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that in connection with the filing by EOG Resources, Inc., a Delaware corporation (the “Company”), of its Annual Report on Form 10-K for the fiscal year ended December 31, 2023 with the United States Securities and Exchange Commission, the undersigned director of the Company hereby constitutes and appoints Ann D. Janssen and Michael P. Donaldson, and each of them (with full power to each of them to act alone), her true and lawful attorney-in-fact and agent, for her and on her behalf and in her name, place and stead, in any and all capacities, to sign, execute and file such Annual Report on Form 10-K, together with any amendments or supplements thereto and with all exhibits and any and all documents required to be filed with respect thereto with any regulatory authority, granting unto said attorneys, and each of them, full power and authority to do and perform each and every act and action requisite and necessary to be done in and about the premises in order to effectuate the same as fully to all intents and purposes as the undersigned might or could do if personally present, with full power of substitution, hereby ratifying and confirming all the said attorneys-in-fact and agents, or either of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has hereto set his hand this 21st day of February 2024.

/s/ LYNN A. DUGLE

LYNN A. DUGLE

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that in connection with the filing by EOG Resources, Inc., a Delaware corporation (the “Company”), of its Annual Report on Form 10-K for the fiscal year ended December 31, 2023 with the United States Securities and Exchange Commission, the undersigned director of the Company hereby constitutes and appoints Ann D. Janssen and Michael P. Donaldson, and each of them (with full power to each of them to act alone), his true and lawful attorney-in-fact and agent, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file such Annual Report on Form 10-K, together with any amendments or supplements thereto and with all exhibits and any and all documents required to be filed with respect thereto with any regulatory authority, granting unto said attorneys, and each of them, full power and authority to do and perform each and every act and action requisite and necessary to be done in and about the premises in order to effectuate the same as fully to all intents and purposes as the undersigned might or could do if personally present, with full power of substitution, hereby ratifying and confirming all the said attorneys-in-fact and agents, or either of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has hereto set his hand this 21st day of February 2024.

/s/ C. CHRISTOPHER GAUT

C. CHRISTOPHER GAUT

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that in connection with the filing by EOG Resources, Inc., a Delaware corporation (the “Company”), of its Annual Report on Form 10-K for the fiscal year ended December 31, 2023 with the United States Securities and Exchange Commission, the undersigned director of the Company hereby constitutes and appoints Ann D. Janssen and Michael P. Donaldson, and each of them (with full power to each of them to act alone), his true and lawful attorney-in-fact and agent, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file such Annual Report on Form 10-K, together with any amendments or supplements thereto and with all exhibits and any and all documents required to be filed with respect thereto with any regulatory authority, granting unto said attorneys, and each of them, full power and authority to do and perform each and every act and action requisite and necessary to be done in and about the premises in order to effectuate the same as fully to all intents and purposes as the undersigned might or could do if personally present, with full power of substitution, hereby ratifying and confirming all the said attorneys-in-fact and agents, or either of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has hereto set his hand this 21st day of February 2024.

/s/ MICHAEL T. KERR

MICHAEL T. KERR

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that in connection with the filing by EOG Resources, Inc., a Delaware corporation (the “Company”), of its Annual Report on Form 10-K for the fiscal year ended December 31, 2023 with the United States Securities and Exchange Commission, the undersigned director of the Company hereby constitutes and appoints Ann D. Janssen and Michael P. Donaldson, and each of them (with full power to each of them to act alone), his true and lawful attorney-in-fact and agent, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file such Annual Report on Form 10-K, together with any amendments or supplements thereto and with all exhibits and any and all documents required to be filed with respect thereto with any regulatory authority, granting unto said attorneys, and each of them, full power and authority to do and perform each and every act and action requisite and necessary to be done in and about the premises in order to effectuate the same as fully to all intents and purposes as the undersigned might or could do if personally present, with full power of substitution, hereby ratifying and confirming all the said attorneys-in-fact and agents, or either of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has hereto set his hand this 17th day of February 2024.

/s/ JULIE J. ROBERTSON

JULIE J. ROBERTSON

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that in connection with the filing by EOG Resources, Inc., a Delaware corporation (the “Company”), of its Annual Report on Form 10-K for the fiscal year ended December 31, 2023 with the United States Securities and Exchange Commission, the undersigned director of the Company hereby constitutes and appoints Ann D. Janssen and Michael P. Donaldson, and each of them (with full power to each of them to act alone), his true and lawful attorney-in-fact and agent, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file such Annual Report on Form 10-K, together with any amendments or supplements thereto and with all exhibits and any and all documents required to be filed with respect thereto with any regulatory authority, granting unto said attorneys, and each of them, full power and authority to do and perform each and every act and action requisite and necessary to be done in and about the premises in order to effectuate the same as fully to all intents and purposes as the undersigned might or could do if personally present, with full power of substitution, hereby ratifying and confirming all the said attorneys-in-fact and agents, or either of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, the undersigned has hereto set his hand this 21st day of February 2024.

/s/ DONALD F. TEXTOR

DONALD F. TEXTOR

EX-31.1

EXHIBIT 31.1

CERTIFICATIONS

I, Ezra Y. Yacob, certify that:

1.I have reviewed this Annual Report on Form 10-K of EOG Resources, Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  February 22, 2024

/s/ EZRA Y. YACOB

Ezra Y. Yacob

Chairman of the Board and Chief Executive Officer

(Principal Executive Officer)

EX-31.2

EXHIBIT 31.2

CERTIFICATIONS

I, Ann D. Janssen, certify that:

1.I have reviewed this Annual Report on Form 10-K of EOG Resources, Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  February 22, 2024

/s/ ANN D. JANSSEN

Ann D. Janssen

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF PERIODIC REPORT

I, Ezra Y. Yacob, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that:

(1)The Annual Report on Form 10-K of the Company for the year ended December 31, 2023 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:  February 22, 2024

/s/ EZRA Y. YACOB

Ezra Y. Yacob

Chairman of the Board and Chief Executive Officer

(Principal Executive Officer)

EX-32.2

EXHIBIT 32.2

CERTIFICATION OF PERIODIC REPORT

I, Ann D. Janssen, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that:

(1)The Annual Report on Form 10-K of the Company for the year ended December 31, 2023 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:  February 22, 2024

/s/ ANN D. JANSSEN

Ann D. Janssen

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-97

Exhibit 97

EOG RESOURCES, INC.

POLICY FOR THE RECOVERY OF ERRONEOUSLY AWARDED COMPENSATION

1.Purpose. The purpose of this Policy is to describe circumstances in which the Company will recover Erroneously Awarded Compensation and the process for such recovery. This Policy is intended to comply with (a) Section 954 of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010, as codified in Section 10D of the Exchange Act, and implemented by Rule 10D-1 thereunder adopted by the Commission and (b) Section 303A.14 of the Listed Company Manual of the NYSE.

2.Administration. This Policy shall be administered by the Compensation Committee. Any determinations made by the Compensation Committee shall be final and binding on all affected individuals.

3.Definitions. For purposes of this Policy, the following capitalized terms shall have the meanings set forth below.

a.“Audit Committee” means the Audit Committee of the Board.

b.“Board” means the Board of Directors of the Company.

c.“Commission” means the United States Securities and Exchange Commission.

d.“Company” means EOG Resources, Inc.

e.“Compensation Committee” means the Compensation and Human Resources Committee of the Board.

f.“Compensation Eligible for Recovery” means Incentive-based Compensation received by an individual:

i.after beginning service as an Executive Officer,

ii.who served as an Executive Officer at any time during the performance period for the applicable Incentive-based Compensation (regardless of whether such individual is serving as an Executive Officer at the time the Erroneously Awarded Compensation is required to be repaid to the Company),

iii.while the Company had a class of securities listed on a national securities exchange or a national securities association,

Active 105419053.2

iv.during the applicable Recovery Period, and

v.on or after the Effective Date.

g.“Effective Date” means October 2, 2023.

h.“Erroneously Awarded Compensation” means the Compensation Eligible for Recovery less the amount of such compensation as it would have been determined based on the restated amounts, computed without regard to any taxes paid.

i.“Exchange Act” means the Securities Exchange Act of 1934, as amended.

j.“Executive Officer” shall mean, for purposes of this Policy, (i) each of the “executive officers” of the Company identified from time to time by the Board pursuant to 17 C.F.R. 240.3b-7 and 17 C.F.R. 229.401(b), together with (ii) the Company’s principal financial officer and the Company’s principal accounting officer (to the extent either such officer has not been identified by the Board as an “executive officer” pursuant to 17 C.F.R. 240.3b-7 and 17 C.F.R. 229.401(b)).

k.“Financial Reporting Measure” means measures that are determined and presented in accordance with the accounting principles used in preparing the Company’s financial statements, and any measures that are derived wholly or in part from such measures. Stock price and total shareholder return are considered Financial Reporting Measures. For the avoidance of doubt, a Financial Reporting Measure need not be presented within the financial statements or included in a filing with the Commission.

l.“Incentive-based Compensation” means any compensation that is granted, earned, or vested based wholly or in part upon the attainment of a Financial Reporting Measure.

m. “NYSE” means the New York Stock Exchange LLC.

n.“Policy” means this Policy for the Recovery of Erroneously Awarded Compensation, as the same may be amended or amended and restated from time to time.

o.“Recovery Period” means the three completed fiscal years immediately preceding the Restatement Date and any transition period (that results from a change in the Company’s fiscal year) of less than nine months within or immediately following those three completed fiscal years.

p.“Restatement” means an accounting restatement:

i.due to material noncompliance of the Company with any financial reporting requirement under the securities laws, including any required accounting restatement to correct an error in previously issued financial statements that is material to the previously issued financial statements, or

2

ii.that would result in a material misstatement if the error were corrected in the current period or left uncorrected in the current period.

q.“Restatement Date” means the earlier of:

i.the date the Audit Committee concludes, or reasonably should have concluded, that the Company is required to prepare a Restatement, or

ii.the date a court, regulator, or other legally authorized body directs the Company to prepare a Restatement.

4.Recovery of Erroneously Awarded Compensation.

a.The Chief Financial Officer or Chief Accounting Officer of the Company shall promptly report to the Audit Committee any instance in which the Company is required to prepare a Restatement.

b.Upon learning of a required Restatement, the Audit Committee shall determine the Restatement Date and shall promptly report to the Compensation Committee such determination.

c.As soon as administratively practicable following the Restatement, the Chief Financial Officer or the Chief Accounting Officer (or another appropriate officer or third party designated by the Compensation Committee, which may include the Company’s Chief Human Resources Officer) shall calculate the Erroneously Awarded Compensation for each affected individual, which calculation shall be subject to Compensation Committee approval. For purposes of calculating Erroneously Awarded Compensation:

i.Incentive-based Compensation shall be deemed received in the Company’s fiscal period during which the Financial Reporting Measure specified in the Incentive-based Compensation award is attained, even if the payment or grant of the Incentive-based Compensation occurs after the end of that period.

ii.Incentive-based Compensation based on (or derived from) stock price or total shareholder return, where the amount of Erroneously Awarded Compensation is not subject to mathematical recalculation directly from the information in a Restatement, shall be based on a reasonable estimate of the effect of the Restatement on the stock price or total shareholder return upon which the Incentive-based Compensation was received. The Company shall maintain documentation of the determination of such reasonable estimate and provide such documentation to the NYSE.

d.Promptly following the Compensation Committee’s approval of the Erroneously Awarded Compensation calculated by the Chief Financial Officer or the Chief Accounting Officer (or another appropriate officer or third party designated by the Compensation Committee, which may include the Company’s Chief Human Resources Officer), the Company shall notify in writing each individual who received Erroneously Awarded Compensation of the amount of

3

Erroneously Awarded Compensation received by such individual and shall demand payment or return, as applicable, of such Erroneously Award Compensation.

e.The Company shall demand recovery and recover Erroneously Awarded Compensation in compliance with this Policy except to the extent that the Compensation Committee determines that (I) recovery of the Erroneously Awarded Compensation would be duplicative of compensation recovered by the Company from the individual pursuant to Section 304 of the Sarbanes-Oxley Act of 2002 or pursuant to other recovery obligations (in which case, the amount of Erroneously Awarded Compensation may be appropriately reduced to avoid such duplication), or (II) recovery would be impracticable and one of the following conditions applies:

i.the direct expense paid to a third party to assist in enforcing this Policy would exceed the amount to be recovered. Before concluding that it would be impracticable to recover any amount of Erroneously Awarded Compensation based on expense of enforcement, the Company must make a reasonable attempt to recover such Erroneously Awarded Compensation, document such reasonable attempt(s) to recover, and provide that documentation to the NYSE;

ii.recovery would violate home country law where that law was adopted prior to November 28, 2022. Before concluding that it would be impracticable to recover any amount of Erroneously Awarded Compensation based on violation of home country law, the Company must obtain an opinion of home country counsel, acceptable to the NYSE, that recovery would result in such a violation, and must provide such opinion to the NYSE; or

iii.recovery would likely cause an otherwise tax-qualified retirement plan, under which benefits are broadly available to employees of the Company, to fail to meet the requirements of 26 U.S.C. 401(a)(13) or 26 U.S.C. 411(a) and regulations thereunder.

f.Except as provided in Section 4(e), in no event may the Company accept repayment from the affected individual of less than the full amount of the Erroneously Awarded Compensation received by such individual.

g.The Compensation Committee shall determine, in its sole discretion, the method of recovering any Erroneously Awarded Compensation pursuant to this Policy, taking into account all facts and circumstances (including the time value of money and the cost to shareholders of delayed recovery), so long as such method complies with the terms of Section 303A.14 of the NYSE Listing Standards. If the Compensation Committee determines that an appropriate method of recovery is one other than the prompt repayment by the affected individual in cash or property, the Company may offer to enter into a repayment agreement with the affected individual (in a form and with terms reasonably acceptable to the Compensation Committee); provided, however, that if the affected individual does not sign and return the repayment agreement within thirty (30) days after the Company extends such offer, the affected individual will be required to repay the Erroneously Awarded Compensation received by such

4

individual in a lump sum on or prior to the one hundred twentieth (120th) day following the Restatement.

h.If the affected individual fails to repay to the Company when due the full amount of the Erroneously Awarded Compensation received by such affected individual, the Company shall take all actions reasonable and appropriate to recover the full amount of the Erroneously Awarded Compensation from the affected individual.

5.Disclosure. The Company shall file all disclosures with respect to this Policy in accordance with the requirements of the securities laws, including the disclosure required by the applicable Commission filings.

6.No Indemnification. The Company shall not indemnify any current or former Executive Officer against the loss of Erroneously Awarded Compensation, and shall not pay, or reimburse any current or former Executive Officers for, premiums for any insurance policy to fund such Executive Officer’s potential recovery obligations.

7.Effective Date. This Policy shall be effective as of the Effective Date.

8.Amendment and Interpretation. The Compensation Committee may amend this Policy from time to time in its discretion and shall amend this Policy as it deems necessary or advisable to reflect the regulations adopted by the Commission and to comply with any rules or standards adopted by the NYSE. The Compensation Committee may at any time, in its sole discretion, supplement, amend or terminate any provision of this Policy in any respect as the Compensation Committee determines to be necessary or appropriate. The Compensation Committee shall interpret and construe this Policy and make all determinations necessary or advisable for the administration of this Policy. It is intended that this Policy be interpreted in a manner that is consistent with the requirements of Section 10D of the Exchange Act and Rule 10D-1 thereunder and Section 303A.14 of the NYSE Listed Company Manual and any other applicable rules adopted by the Commission.

9.Other Recoupment Rights. The Compensation Committee intends that this Policy will be applied to the fullest extent of the law. The Compensation Committee may require that any employment agreement, equity award agreement or similar agreement entered into on or after the Effective Date shall, as a condition to the grant of any benefit thereunder, require the party thereto to agree to abide by the terms of this Policy or implement arrangements designed to facilitate the administration hereof. Any right of recovery under this Policy is in addition to, and not in lieu of, any other remedies or rights of recovery that may be available to the Company pursuant to the terms of any employment agreement, equity award agreement, or similar agreement and any other legal remedies available to the Company.

10.Successors. This Policy shall be binding and enforceable against all current and former Executive Officers and their beneficiaries, heirs, executors, administrators or other legal representatives.

5

EX-99.1

EXHIBIT 99.1

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

January 26, 2024

EOG Resources, Inc.

1111 Bagby Street, Sky Lobby 2

Houston, Texas 77002

Ladies and Gentlemen:

Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2023, of the estimated net proved oil, condensate, natural gas liquids (NGL), and gas reserves of certain properties in which EOG Resources, Inc. (EOG) has represented it holds an interest. This evaluation was completed on January 26, 2024. The properties evaluated consist of working and royalty interests located in the States of New Mexico and Texas and offshore from Trinidad. EOG has represented that these properties account for 82.7 percent on a net equivalent barrel basis of EOG’s net proved reserves as of December 31, 2023, and that the net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the United States Securities and Exchange Commission (SEC). It is our opinion that the procedures and methodologies employed by EOG for the preparation of its proved reserves estimates as of December 31, 2023, comply with the current requirements of the SEC. We have reviewed information provided by EOG that it represents to be EOG’s estimates of the net reserves, as of December 31, 2023, for the same properties as those which we evaluated. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S–K and is to be used for inclusion in certain SEC filings by EOG.

Reserves estimates included herein are expressed as net reserves as represented by EOG. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2023. Net reserves are defined as that portion of the gross reserves attributable to the interests held by EOG after deducting all interests held by others.

Estimates of reserves should be regarded only as estimates that may change as further production history and additional information become available. Not only

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are such estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Information used in the preparation of this report was obtained from EOG and from public sources. In the preparation of this report we have relied, without independent verification, upon information furnished by EOG with respect to the property interests being evaluated, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination was not considered necessary for the purposes of this report.

Definition of Reserves

Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

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(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells

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on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019” and, for properties in the United States, in Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

Based on the current stage of field development, production performance, the development plans provided by EOG, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.

The proved undeveloped reserves estimates were based on opportunities in the plan of development provided by EOG.

EOG has represented that its senior management is committed to the development plan provided by EOG and that EOG has the financial capability to execute the development

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plan, including the drilling and completion of wells and the installation of equipment and facilities.

For the evaluation of unconventional reservoirs, a performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized for this report. Performance-based methodology primarily includes (1) production diagnostics, (2) decline-curve analysis, and (3) model-based analysis (if necessary, based on availability of data). Production diagnostics include data quality control, identification of flow regimes, and characteristic well performance behavior. These analyses were performed for all well groupings (or type-curve areas).

Characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate profiles, including one or multiple b-exponent values followed by an exponential decline. Based on the availability of data, model-based analysis may be integrated to evaluate long-term decline behavior, the effect of dynamic reservoir and fracture parameters on well performance, and complex situations sourced by the nature of unconventional reservoirs.

For properties offshore from Trinidad, when applicable, the volumetric method was used to estimate the original gas in place (OGIP). Structure maps were prepared to delineate selected reservoirs, and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material-balance methods were used to estimate OGIP.

Estimates of ultimate recovery were obtained after applying recovery factors to OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material-balance and other engineering methods were used to estimate recovery factors based on an analysis of reservoir performance, including production rate, reservoir pressure, and reservoir fluid properties.

For properties offshore from Trinidad, reserves for depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production as defined under the Definition of Reserves heading of this report, contract expiration, or technical well abandonment rate, whichever occurs first.

In the evaluation of undeveloped reserves, type-well analysis was performed using well data from analogous reservoirs for which more complete historical performance data were available.

Data provided by EOG from wells drilled through December 31, 2023, and made available for this evaluation were used to prepare the reserves estimates herein. The reserves estimates for the properties offshore from Trinidad were based on consideration

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of monthly production data available only through September 2023. The reserves estimates for the properties in the States of New Mexico and Texas were based on consideration of daily and monthly production data through December 2023. Estimated cumulative production, as of December 31, 2023, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 3 months for the properties offshore from Trinidad.

Oil and condensate reserves estimated herein are those to be recovered by normal field separation. NGL reserves estimated herein include pentanes and heavier fractions (C5+) and liquefied petroleum gas (LPG), which consists primarily of propane and butane fractions, and are the result of low-temperature plant processing. Oil, condensate, and NGL reserves included in this report are expressed in thousands of barrels (Mbbl). In these estimates, 1 barrel equals 42 United States gallons. For reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity.

Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Gas reserves estimated herein are reported as sales gas. Gas quantities are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at the pressure base of the state or area in which the quantities are located. Gas quantities included in this report are expressed in millions of cubic feet (MMcf).

Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas is both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil at initial reservoir conditions. Gas quantities estimated herein include both associated and nonassociated gas.

At the request of EOG, sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.

Primary Economic Assumptions

This report has been prepared using initial prices, expenses, and costs provided by EOG. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the reserves reported herein:

Oil, Condensate, and NGL Prices

EOG has represented that the oil, condensate, and NGL prices were based on a reference price, calculated as the unweighted arithmetic

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average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. EOG supplied differentials to a West Texas Intermediate (WTI) reference price of $78.22 per barrel and the prices were held constant thereafter. The volume-weighted average prices attributable to the estimated proved reserves over the lives of the properties were $80.05 per barrel of oil and condensate and $18.94 per barrel of NGL.

Gas Prices

EOG has represented that the gas prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. EOG supplied differentials to a Henry Hub reference price of $2.64 per million Btu ($/MMBtu) and the prices were held constant thereafter. Btu factors provided by EOG were used to convert prices from dollars per million Btu to dollars per thousand cubic feet of gas. The volume-weighted average price attributable to the estimated proved reserves over the lives of the properties was $2.869 per thousand cubic feet of gas.

Production and Ad Valorem Taxes

For properties in the United States, production taxes were calculated using the tax rates for each state in which the reserves are locatedincluding, where appropriate, abatements for enhanced recovery programs, and ad valorem taxes were estimated using rates provided by EOG based on recent payments.

Operating Expenses, Capital Costs, and Abandonment Costs

Estimates of operating expenses and future capital expenditures, provided by EOG and based on existing economic conditions, were held constant for the lives of the properties. In certain cases, future expenditures, either higher or lower than current expenditures, may have been used because of anticipated changes in operating conditions, but no general escalation that might result from inflation was applied. Abandonment costs, which are those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment, were provided by EOG for all properties and were not adjusted for inflation. Operating expenses, capital costs, and abandonment costs were considered, as appropriate, in determining the economic viability of the undeveloped reserves estimated herein.

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In our opinion, the information relating to estimated proved reserves of oil, condensate, NGL, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the FASB and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the SEC; provided, however, that estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

Summary of Conclusions

DeGolyer and MacNaughton has performed an independent evaluation of the extent of the estimated net proved oil, condensate, NGL, and gas reserves of certain properties in which EOG has represented it holds an interest. EOG has represented that its estimated net proved reserves attributable to the properties evaluated herein were based on the definitions of proved reserves of the SEC. EOG’s estimates of the net proved reserves, as of December 31, 2023, attributable to these properties, which represent 82.7 percent of EOG’s total proved reserves on a net equivalent basis, are summarized as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and thousands of barrels of oil equivalent (Mboe):

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	Estimated by EOG Net Proved Reserves as of December 31, 2023
Properties Evaluated by DeGolyer and MacNaughton	Oil and Condensate (Mbbl)	NGL (Mbbl)	Sales Gas (MMcf)	Oil Equivalent (Mboe)
Proved Developed	809,504	505,867	2,945,453	1,806,280
Proved Undeveloped	732,419	597,648	3,495,841	1,912,707
Total Proved	1,541,923	1,103,515	6,441,294	3,718,987
Note: Sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.

DeGolyer and MacNaughton’s estimates of EOG’s net proved reserves, as of December 31, 2023, attributable to the properties evaluated herein were based on the definition of proved reserves of the SEC and are summarized as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and thousands of barrels of oil equivalent (Mboe):

	Estimated by DeGolyer and MacNaughton Net Proved Reserves as of December 31, 2023
Properties Evaluated by DeGolyer and MacNaughton	Oil and Condensate (Mbbl)	NGL (Mbbl)	Sales Gas (MMcf)	Oil Equivalent (Mboe)
Proved Developed	805,244	483,261	2,831,058	1,760,348
Proved Undeveloped	760,067	587,055	3,445,230	1,921,327
Total Proved	1,565,311	1,070,316	6,276,288	3,681,675
Note: Sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.

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In comparing the detailed net proved reserves estimates prepared by DeGolyer and MacNaughton and by EOG of the properties evaluated herein, differences have been found, both positive and negative, resulting in an aggregate difference of 1.0 percent when compared on the basis of net oil equivalent. It is DeGolyer and MacNaughton’s opinion that there is no material difference between the net proved reserves estimates prepared by EOG and those prepared by DeGolyer and MacNaughton for those properties DeGolyer and MacNaughton evaluated.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2023, estimated reserves.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in EOG. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of EOG. DeGolyer and MacNaughton has used all data, assumptions, procedures, and methods that it considers necessary to prepare this report.

Submitted,

/s/ DeGOLYER and MacNAUGHTON

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

/s/ Dilhan Ilk

Dilhan Ilk, P.E.

Executive Vice President

DeGolyer and MacNaughton

[SEAL]

[SEAL]

DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

I, Dilhan Ilk, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

1.That I am a Executive Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to EOG dated January 26, 2024, and that I, as Executive Vice President, was responsible for the preparation of this report of third party.

2.That I attended Istanbul Technical University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 2003, a Master of Science degree from Texas A&M University in 2005, and a Doctor in Philosophy degree from Texas A&M University in 2010; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers; and that I have in excess of 13 years of experience in oil and gas reservoir studies and reserves evaluations.

/s/ Dilhan Ilk

Dilhan Ilk, P.E.

Executive Vice President

DeGolyer and MacNaughton

[SEAL]

[SEAL]

XML

Cover - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2023

Feb. 15, 2024

Jun. 30, 2023

Cover [Abstract]

Document Type

10-K

Document Annual Report

true

Document Period End Date

Dec. 31, 2023

Current Fiscal Year End Date

--12-31

Document Transition Report

false

Entity File Number

1-9743

Entity Registrant Name

EOG RESOURCES, INC.

Entity Incorporation, State or Country Code

DE

Entity Tax Identification Number

47-0684736

Entity Address, Address Line One

1111 Bagby

Entity Address, Address Line Two

Sky Lobby 2

Entity Address, City or Town

Houston

Entity Address, State or Province

TX

Entity Address, Postal Zip Code

77002

City Area Code

713

Local Phone Number

651-7000

Title of 12(b) Security

Common Stock, par value $0.01 per share

Trading Symbol

EOG

Security Exchange Name

NYSE

Entity Well-known Seasoned Issuer

Yes

Entity Voluntary Filers

No

Entity Current Reporting Status

Yes

Entity Interactive Data Current

Yes

Entity Filer Category

Large Accelerated Filer

Entity Small Business

false

Entity Emerging Growth Company

false

ICFR Auditor Attestation Flag

true

Document Financial Statement Error Correction [Flag]

false

Entity Shell Company

false

Entity Public Float

$ 66,533

Entity Common Stock, Shares Outstanding

580,001,872

Documents Incorporated by Reference

Documents incorporated by reference.  Portions of the Definitive Proxy Statement for the registrant's 2024 Annual Meeting of Stockholders, to be filed within 120 days after December 31, 2023, are incorporated by reference into Part III of this report.

Entity Central Index Key

0000821189

Document Fiscal Year Focus

2023

Document Fiscal Period Focus

FY

Amendment Flag

false

XML

Audit Information	12 Months Ended
	Dec. 31, 2023
Auditor Information [Abstract]
Auditor Name	DELOITTE & TOUCHE LLP
Auditor Location	Houston, Texas
Auditor Firm ID	34

XML

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating Revenues and Other
Gains on Asset Dispositions, Net	$ 95	$ 74	$ 17
Total	24,186	25,702	18,642
Operating Expenses
Lease and Well	1,454	1,331	1,135
Transportation Costs	957	966	863
Gathering and Processing Costs	663	621	559
Exploration Costs	181	159	154
Dry Hole Costs	1	45	71
Impairments	202	382	376
Marketing Costs	5,709	6,535	4,173
Depreciation, Depletion and Amortization	3,492	3,542	3,651
General and Administrative	640	570	511
Taxes Other Than Income	1,284	1,585	1,047
Total	14,583	15,736	12,540
Operating Income	9,603	9,966	6,102
Other Income, Net	234	114	9
Income Before Interest Expense and Income Taxes	9,837	10,080	6,111
Interest Expense
Incurred	181	215	211
Capitalized	(33)	(36)	(33)
Interest Expense, Net	148	179	178
Income Before Income Taxes	9,689	9,901	5,933
Income Tax Provision	2,095	2,142	1,269
Net Income	$ 7,594	$ 7,759	$ 4,664
Net Income Per Share
Basic ( in usd per share)	$ 13.07	$ 13.31	$ 8.03
Diluted (in usd per share)	$ 13.00	$ 13.22	$ 7.99
Average Number of Common Shares
Basic (in shares)	581	583	581
Diluted (in shares)	584	587	584
Comprehensive Income
Net Income	$ 7,594	$ 7,759	$ 4,664
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments	(1)	4	(1)
Other, Net of Tax	0	0	1
Other Comprehensive Income (Loss)	(1)	4	0
Comprehensive Income	7,593	7,763	4,664
Crude Oil and Condensate
Operating Revenues and Other
Revenue from contract with customer	13,748	16,367	11,125
Natural Gas Liquids
Operating Revenues and Other
Revenue from contract with customer	1,884	2,648	1,812
Natural Gas
Operating Revenues and Other
Revenue from contract with customer	1,744	3,781	2,444
Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts, Net
Operating Revenues and Other
Revenue not from contract with customer	818	(3,982)	(1,152)
Gathering, Processing and Marketing
Operating Revenues and Other
Revenue from contract with customer	5,806	6,696	4,288
Other, Net
Operating Revenues and Other
Revenue not from contract with customer	$ 91	$ 118	$ 108

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Current Assets
Cash and Cash Equivalents	$ 5,278	$ 5,972
Accounts Receivable, Net	2,716	2,774
Inventories	1,275	1,058
Assets from Price Risk Management Activities	106	0
Income Taxes Receivable	0	97
Other	560	574
Total	9,935	10,475
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)	72,090	67,322
Other Property, Plant and Equipment	5,497	4,786
Total Property, Plant and Equipment	77,587	72,108
Less: Accumulated Depreciation, Depletion and Amortization	(45,290)	(42,679)
Total Property, Plant and Equipment, Net	32,297	29,429
Deferred Income Taxes	42	33
Other Assets	1,583	1,434
Total Assets	43,857	41,371
Current Liabilities
Accounts Payable	2,437	2,532
Accrued Taxes Payable	466	405
Dividends Payable	526	482
Liabilities from Price Risk Management Activities	0	169
Current Portion of Long-Term Debt	34	1,283
Current Portion of Operating Lease Liabilities	325	296
Other	286	346
Total	4,074	5,513
Long-Term Debt	3,765	3,795
Other Liabilities	2,526	2,574
Deferred Income Taxes	5,402	4,710
Commitments and Contingencies (Note 8)
Stockholders' Equity
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 588,748,473 Shares and 588,396,757 Shares Issued at December 31, 2023 and 2022, respectively	206	206
Additional Paid in Capital	6,166	6,187
Accumulated Other Comprehensive Loss	(9)	(8)
Retained Earnings	22,634	18,472
Common Stock Held in Treasury, 7,888,105 Shares and 700,281 Shares at December 31, 2023 and 2022, respectively	(907)	(78)
Total Stockholders' Equity	28,090	24,779
Total Liabilities and Stockholders' Equity	$ 43,857	$ 41,371

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	1,280,000,000	1,280,000,000
Common stock, shares issued (in shares)	588,748,473	588,396,757
Common stock held in treasury (in shares)	7,888,105	700,281

XML

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) $ in Millions	Total	Common Stock	Additional Paid In Capital	Accumulated Other Comprehensive Loss	Retained Earnings	Common Stock Held In Treasury
Beginning balance at Dec. 31, 2020	$ 20,302	$ 206	$ 5,945	$ (12)	$ 14,170	$ (7)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	4,664				4,664
Common Stock Issued Under Stock Plans	17		17
Common Stock Dividends Declared	(2,915)				(2,915)
Other Comprehensive Income (Loss)	0			0
Change in Treasury Stock - Stock Compensation Plans, Net	(40)		(22)			(18)
Restricted Stock and Restricted Stock Units, Net	0		(5)			5
Stock-Based Compensation Expenses	152		152
Treasury Stock Issued as Compensation	0					0
Ending balance at Dec. 31, 2021	22,180	206	6,087	(12)	15,919	(20)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	7,759				7,759
Common Stock Issued Under Stock Plans	24		24
Common Stock Dividends Declared	(5,206)				(5,206)
Other Comprehensive Income (Loss)	4			4
Change in Treasury Stock - Stock Compensation Plans, Net	(116)		(55)			(61)
Restricted Stock and Restricted Stock Units, Net	0		(2)			2
Stock-Based Compensation Expenses	133		133
Treasury Stock Issued as Compensation	1					1
Ending balance at Dec. 31, 2022	24,779	206	6,187	(8)	18,472	(78)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	7,594				7,594
Common Stock Dividends Declared	(3,432)				(3,432)
Other Comprehensive Income (Loss)	(1)			(1)
Treasury Stock Repurchased	(979)					(979)
Change in Treasury Stock - Stock Compensation Plans, Net	(48)		(36)			(12)
Restricted Stock and Restricted Stock Units, Net	0		(162)			162
Stock-Based Compensation Expenses	177		177
Ending balance at Dec. 31, 2023	$ 28,090	$ 206	$ 6,166	$ (9)	$ 22,634	$ (907)

XML

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of Stockholders' Equity [Abstract]
Common stock dividends declared (in USD per share)	$ 5.8850	$ 8.8750	$ 4.9875

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Cash Flows from Operating Activities
Net Income	$ 7,594	$ 7,759	$ 4,664
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization	3,492	3,542	3,651
Impairments	202	382	376
Stock-Based Compensation Expenses	177	133	152
Deferred Income Taxes	683	(61)	(122)
Gains on Asset Dispositions, Net	(95)	(74)	(17)
Other, Net	27	0	13
Dry Hole Costs	1	45	71
Mark-to-Market Financial Commodity Derivative Contracts
(Gains) Losses, Net	(818)	3,982	1,152
Net Cash Payments for Settlements of Financial Commodity Derivative Contracts	(112)	(3,501)	(638)
Other, Net	(2)	45	7
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	(38)	(347)	(821)
Inventories	(231)	(534)	(13)
Accounts Payable	(119)	90	456
Accrued Taxes Payable	61	(113)	312
Other Assets	39	(364)	(136)
Other Liabilities	184	(266)	(116)
Changes in Components of Working Capital Associated with Investing Activities	295	375	(200)
Net Cash Provided by Operating Activities	11,340	11,093	8,791
Investing Cash Flows
Additions to Oil and Gas Properties	(5,385)	(4,619)	(3,638)
Additions to Other Property, Plant and Equipment	(800)	(381)	(212)
Proceeds from Sales of Assets	140	349	231
Other Investing Activities	0	(30)	0
Changes in Components of Working Capital Associated with Investing Activities	(295)	(375)	200
Net Cash Used in Investing Activities	(6,340)	(5,056)	(3,419)
Financing Cash Flows
Long-Term Debt Repayments	(1,250)	0	(750)
Dividends Paid	(3,386)	(5,148)	(2,684)
Treasury Stock Purchased	(1,038)	(118)	(41)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan	20	28	19
Debt Issuance Costs	(8)	0	0
Repayment of Finance Lease Liabilities	(32)	(35)	(37)
Net Cash Used in Financing Activities	(5,694)	(5,273)	(3,493)
Effect of Exchange Rate Changes on Cash	0	(1)	1
Increase (Decrease) in Cash and Cash Equivalents	(694)	763	1,880
Cash and Cash Equivalents at Beginning of Year	5,972	5,209	3,329
Cash and Cash Equivalents at End of Year	$ 5,278	$ 5,972	$ 5,209

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Nature of Business. EOG Resources, Inc., a Delaware corporation organized in 1985, together with its subsidiaries (collectively, EOG), explores for, develops, produces and markets crude oil, natural gas liquids (NGLs) and natural gas primarily in major producing basins in the United States of America (United States or U.S.) and the Republic of Trinidad and Tobago (Trinidad). EOG is making preparations to drill offshore Australia, as well as evaluating additional exploration, development and exploitation opportunities in these and other select international areas. In addition, EOG is executing an abandonment and reclamation program in Canada. EOG completed the exit of Block 36 and Block 49 located in the Sultanate of Oman (Oman) in 2023. EOG sold its operations in the China Sichuan Basin (China) in the second quarter of 2021.

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

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

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

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

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

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

Oil and gas exploration costs, other than the costs of drilling exploratory wells, are expensed as incurred.  The costs of drilling exploratory wells are capitalized pending determination of whether EOG has discovered commercial quantities of proved reserves.  If commercial quantities of proved reserves are not discovered, such drilling costs are expensed.  In some circumstances, it may be uncertain whether commercial quantities of proved reserves have been discovered when drilling has been completed.  Such exploratory well drilling costs may continue to be capitalized if the estimated reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made (see Note 16).  Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized.

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

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

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

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

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

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

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

Revenues are recognized for the sale of crude oil and condensate, NGLs and natural gas at the point control of the product is transferred to the customer, typically when production is delivered and title or risk of loss transfers to the customer. Arrangements for such sales are evidenced by signed contracts with prices typically based on stated market indices, with certain adjustments for product quality and geographic location. As EOG typically invoices customers shortly after performance obligations have been fulfilled, contract assets and contract liabilities are not recognized. The balances of accounts receivable from contracts with customers as of December 31, 2023 and 2022, were $2,237 million and $2,340 million, respectively, and are included in Accounts Receivable, Net on the Consolidated Balance Sheets. Losses incurred on receivables from contracts with customers are infrequent and have been immaterial. Certain arrangements provide for the sale of fixed quantities of commodities in future years with pricing mechanisms based on future market prices of the commodity at time of delivery. EOG does not disclose the value of these obligations given the uncertainty of the future realized transaction price.

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

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

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

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

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

Accounting for Risk Management Activities.  Financial commodity derivative instruments are recorded on the balance sheet as either an asset or liability measured at fair value, and changes in the instrument's fair value are recognized currently in earnings unless specific hedge accounting criteria are met.  During the three-year period ended December 31, 2023, EOG elected not to designate any of its financial commodity derivative instruments as accounting hedges and, accordingly, changes in the fair value of these outstanding derivative instruments are recognized as gains or losses in the period of change.  The gains or losses are recorded as Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts on the Consolidated Statements of Income and Comprehensive Income.  The related cash flow impact of settled contracts is reflected as cash flows from operating activities.  EOG employs net presentation of financial commodity derivative assets and liabilities for financial reporting purposes when such assets and liabilities are with the same counterparty and subject to a master netting arrangement.  See Note 12.

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

Effective January 1, 2021, EOG adopted the provisions of ASU 2019-12, "Income Taxes (Topic 740) Simplifying the Accounting for Income Taxes" (ASU 2019-12). There was no impact upon adoption of ASU 2019-12 to EOG's consolidated financial statements or related disclosures.

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

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

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

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

Right of Use (ROU) assets and related liabilities are recognized on the commencement date on the Consolidated Balance Sheets based on future lease payments, discounted based on the rate implicit in the contract, if readily determinable, or EOG's incremental borrowing rate commensurate with the lease term of the contract. EOG estimates its incremental borrowing rate based on the approximate rate required to borrow on a collateralized basis. Contracts with lease terms of less than 12 months are not recorded on the Consolidated Balance Sheets, but instead are disclosed as short-term lease cost. EOG has elected not to separate non-lease components for most asset classes, except for those asset classes where the non-lease (i.e. service) components comprise a material amount of the minimum lease payments. See Note 18.

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

In November 2023, the FASB issued ASU 2023-07 "Segment Reporting (Topic 820)," which updates reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. In addition, the amendment prescribes interim disclosure requirements, clarifies circumstances in which an entity can disclose multiple segment measures of profit or loss, provides new segment disclosure requirements for entities with a single reportable segment, and contains other disclosure requirements. The ASU is effective for public companies with annual periods beginning after December 15, 2023, and interim periods within annual periods beginning after December 15, 2024, with early adoption permitted. EOG is currently evaluating the impact of the standard on our segment reporting disclosures.

In December 2023, the FASB issued ASU 2023-09, "Income Taxes (Topic 740): Improvements to Income Tax Disclosures" (ASU 2023-09). ASU 2023-09 requires companies to disclose, on an annual basis, specific categories in the effective tax rate reconciliation and provide additional information for reconciling items that meet a quantitative threshold. In addition, ASU 2023-09 requires companies to disclose additional information about income taxes paid. ASU 2023-09 will be effective for annual periods beginning after December 15, 2024, and although permitted, EOG does not intend to early adopt. EOG is continuing to evaluate the provisions of ASU 2023-09 and does not anticipate a material impact on its consolidated financial statements and related disclosures upon adoption.

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Long-Term Debt

12 Months Ended

Dec. 31, 2023

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

Long-Term Debt at December 31, 2023 and 2022 consisted of the following (in millions):

	2023		2022
2.625% Senior Notes due 2023	$	—	$	1,250
3.15% Senior Notes due 2025	500		500
4.15% Senior Notes due 2026	750		750
6.65% Senior Notes due 2028	140		140
4.375% Senior Notes due 2030	750		750
3.90% Senior Notes due 2035	500		500
5.10% Senior Notes due 2036	250		250
4.950% Senior Notes due 2050	750		750
Long-Term Debt	3,640		4,890
Finance Leases (see Note 18)	183		215
Less: Current Portion of Long-Term Debt	34		1,283
Unamortized Debt Discount	21		23
Debt Issuance Costs	3		4
Total Long-Term Debt	$	3,765	$	3,795

The senior notes in the table above are senior, unsecured obligations that rank equally in right of payment with all of our other unsecured and unsubordinated outstanding debt. At December 31, 2023, the aggregate annual maturities of current and long-term debt (excluding finance lease obligations) were zero in 2024, $500 million in 2025, $750 million in 2026, zero in 2027 and $140 million in 2028.

At December 31, 2023 and 2022, EOG had no outstanding commercial paper borrowings and did not utilize any commercial paper borrowings during 2023 or 2022.

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

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

The New Facility has a scheduled maturity date of June 7, 2028 and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods, subject to, among certain other terms and conditions, the consent of the Banks holding greater than 50% of the commitments then outstanding under the New Facility. The New Facility commits the Banks to provide advances up to an aggregate principal amount of $1.9 billion outstanding at any given time, with an option for EOG to request increases in the aggregate commitments to an amount not to exceed $3.0 billion, subject to certain terms and conditions. The New Facility also includes a swingline subfacility and a letter of credit subfacility. Advances under the New Facility will accrue interest based, at EOG's option, on either the Secured Overnight Financing Rate (SOFR) plus 0.1% plus an applicable margin, or the Base Rate (as defined in the New Facility) plus an applicable margin. The applicable margin used in connection with interest rates and fees will be based on EOG's credit rating for its senior unsecured long-term debt at the applicable time.

Consistent with the terms of the 2019 Facility, the New Facility contains representations, warranties, covenants and events of default that EOG believes are customary for investment grade, senior unsecured commercial bank credit agreements, including a financial covenant for the maintenance of a ratio of Total Debt to Total Capitalization (as such terms are defined in the New Facility) of no greater than 65%. At December 31, 2023, EOG was in compliance with this financial covenant.

There were no borrowings or letters of credit outstanding under the 2019 Facility as of (i) December 31, 2022 or (ii) the June 7, 2023 effective date of the closing of the New Facility and termination of the 2019 Facility. Further, at December 31, 2023, there were no borrowings or letters of credit outstanding under the New Facility. The SOFR and Base Rate (inclusive of the applicable margins), had there been any amounts borrowed under the New Facility at December 31, 2023, would have been 6.35% and 8.50%, respectively.

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Stockholder's Equity

12 Months Ended

Dec. 31, 2023

Stockholders' Equity Note [Abstract]

Stockholder's Equity

Stockholders' Equity

Common Stock.  In September 2001, EOG's Board of Directors (Board) authorized the repurchase of an aggregate maximum of 10 million shares of common stock that superseded all previous authorizations (September 2001 Authorization). EOG last repurchased shares under the September 2001 Authorization in March 2003.  Effective November 4, 2021, the Board (i) established a new share repurchase authorization to allow for the repurchase by EOG of up to $5 billion of common stock (November 2021 Authorization) and (ii) revoked and terminated the September 2001 Authorization.

Under the November 2021 Authorization, EOG may repurchase shares from time to time, at management's discretion, in accordance with applicable securities laws, including through open market transactions, privately negotiated transactions or any combination thereof. The timing and amount of repurchases is at the discretion of EOG's management and depends on a variety of factors, including the trading price of EOG's common stock, corporate and regulatory requirements, other market and economic conditions, the availability of cash to effect repurchases and EOG's anticipated future capital expenditures and other commitments requiring cash. Repurchased shares are held as treasury shares and are available for general corporate purposes. The November 2021 Authorization has no time limit, does not require EOG to repurchase a specific number of shares and may be modified, suspended, or terminated by the Board at any time. During year ended December 31, 2023, EOG repurchased 8.6 million shares of common stock for approximately $971 million (inclusive of transaction fees and commissions) pursuant to the November 2021 Authorization. As of December 31, 2023, approximately $4 billion remained available for repurchases under the November 2021 Authorization. Included in the Treasury Stock Repurchased amounts on the Consolidated Statements of Stockholders' Equity for the year ended December 31, 2023, is $8 million of estimated federal excise tax.

Shares of common stock are from time to time withheld by, or returned to, EOG in satisfaction of tax withholding obligations arising upon the exercise of employee stock options or stock-settled stock appreciation rights (SARs), the vesting of restricted stock, restricted stock unit or performance unit grants or in payment of the exercise price of employee stock options. Such shares withheld or returned prior to November 4, 2021 did not count against the September 2001 Authorization, and such shares withheld or returned on or subsequent to November 4, 2021 have not counted, and will not count, against the November 2021 Authorization. Shares purchased, withheld and returned are held in treasury for, among other purposes, fulfilling any obligations arising under EOG's stock-based compensation plans and any other approved transactions or activities for which such shares of common stock may be required.

On February 22, 2024, the Board declared a quarterly cash dividend on the common stock of $0.91 per share to be paid on April 30, 2024, to stockholders of record as of April 16, 2024.

The following summarizes Common Stock activity for each of the years ended December 31, 2023, 2022 and 2021 (in thousands):

	Common Shares
	Issued	Treasury	Outstanding
Balance at December 31, 2020	583,695	(124)	583,571
Common Stock Issued Under Stock-Based Compensation Plans	1,511	—	1,511
Treasury Stock Purchased (1)	—	(504)	(504)
Common Stock Issued Under Employee Stock Purchase Plan	316	—	316
Treasury Stock Issued Under Stock-Based Compensation Plans	—	371	371
Balance at December 31, 2021	585,522	(257)	585,265
Common Stock Issued Under Stock-Based Compensation Plans	2,674	—	2,674
Treasury Stock Purchased (1)	—	(997)	(997)
Common Stock Issued Under Employee Stock Purchase Plan	201	—	201
Treasury Stock Issued Under Stock-Based Compensation Plans	—	554	554
Balance at December 31, 2022	588,397	(700)	587,697
Common Stock Issued Under Stock-Based Compensation Plans	159	—	159
Treasury Stock Purchased (2)	—	(9,177)	(9,177)
Common Stock Issued Under Employee Stock Purchase Plan	193	—	193
Treasury Stock Issued Under Stock-Based Compensation Plans	—	1,989	1,989
Balance at December 31, 2023	588,749	(7,888)	580,861

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

(2)    Represents shares that were repurchased under the November 2021 Authorization and/or that were withheld by or returned to EOG (i) in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or SARs or the vesting of restricted stock, restricted stock unit or performance unit grants or (ii) in payment of the exercise price of employee stock options.

Preferred Stock.  EOG currently has one authorized series of preferred stock - its Series E junior participating preferred stock (Series E Preferred Stock), of which 3,000,000 shares have been designated and authorized.  As of December 31, 2023, no shares of Series E Preferred Stock have been issued or are outstanding.

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Accumulated Other Comprehensive Loss

12 Months Ended

Dec. 31, 2023

Equity [Abstract]

Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss includes certain transactions that have been reported in the Consolidated Statements of Stockholders' Equity. The components of Accumulated Other Comprehensive Loss at December 31, 2023 and 2022 consisted of the following (in millions):

	Foreign Currency Translation Adjustment		Other		Total
December 31, 2021	$	(11)	$	(1)	$	(12)
Other comprehensive income before taxes	4		—		4
Tax effects	—		—		—
Other comprehensive income	4		—		4
December 31, 2022	(7)		(1)		(8)
Other comprehensive loss before taxes	(1)		—		(1)
Tax effects	—		—		—
Other comprehensive loss	(1)		—		(1)
December 31, 2023	$	(8)	$	(1)	$	(9)

No significant amount was reclassified out of Accumulated Other Comprehensive Loss during the years ended December 31, 2023 and 2022.

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Other Income, Net	12 Months Ended
	Dec. 31, 2023
Other Income and Expenses [Abstract]
Other Income, Net	Other Income, NetOther income, net for 2023 included interest income ($240 million), partially offset by an upward adjustment to deferred compensation expense ($7 million). Other income, net for 2022 included interest income ($85 million) and equity income from investments in ammonia plants in Trinidad ($46 million), partially offset by an upward adjustment to deferred compensation expense ($15 million). Other income, net for 2021 included equity income from investments in ammonia plants in Trinidad ($18 million) and interest income ($3 million), partially offset by an upward adjustment to deferred compensation expense ($13 million).

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Income Taxes

12 Months Ended

Dec. 31, 2023

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The principal components of EOG's total net deferred income tax liabilities at December 31, 2023 and 2022 were as follows (in millions):

	2023		2022
Deferred Income Tax Assets (Liabilities)
Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization	$	(26)	$	(18)
Foreign Asset Retirement Obligations	84		81
Foreign Accrued Expenses and Liabilities	12		13
Foreign Net Operating Loss	97		82
Foreign Valuation Allowances	(126)		(116)
Foreign Other	1		(9)
Total Net Deferred Income Tax Assets	$	42	$	33
Deferred Income Tax (Assets) Liabilities
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization	$	5,778	$	5,291
Financial Commodity Derivative Contracts	—		(421)
Deferred Compensation Plans	(61)		(58)
Equity Awards	(59)		(60)
Corporate Alternative Minimum Tax	(212)		—
Other	(44)		(42)
Total Net Deferred Income Tax Liabilities	$	5,402	$	4,710
Total Net Deferred Income Tax Liabilities	$	5,360	$	4,677

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

	2023		2022		2021
United States	$	9,576	$	9,752	$	5,787
Foreign	113		149		146
Total	$	9,689	$	9,901	$	5,933

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

	2023		2022		2021
Current:
Federal	$	1,334	$	2,020	$	1,203
State	76		126		85
Foreign	5		62		105
Total	1,415		2,208		1,393
Deferred:
Federal	628		(2)		(41)
State	55		(37)		(62)
Foreign	—		(22)		(19)
Total	683		(61)		(122)
Other Non-Current:
Foreign	(3)		(5)		(2)
Total	(3)		(5)		(2)
Income Tax Provision	$	2,095	$	2,142	$	1,269

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

	2023		2022		2021
Statutory Federal Income Tax Rate	21.0	%	21.0	%	21.0	%
State Income Tax, Net of Federal Benefit	1.0		0.7		0.3
Income Tax Provision Related to Foreign Operations	(0.2)		—		0.9
Stock-Based Compensation	—		—		0.2
Other	(0.2)		—		(1.0)
Effective Income Tax Rate	21.6	%	21.7	%	21.4	%

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

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

	2023		2022		2021
Beginning Balance	$	207	$	219	$	219
Increase (1)	8		27		15
Decrease (2)	—		(33)		(14)
Other (3)	1		(6)		(1)
Ending Balance	$	216	$	207	$	219

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

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

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

As of December 31, 2023, EOG has state income tax NOLs of approximately $1.9 billion. Certain state NOLs have an indefinite carryforward and all others expire between 2024 and 2040. EOG also has Canadian NOLs of $333 million, some of which can be carried forward up to 20 years. In 2023, EOG accrued corporate alternative minimum tax (CAMT) of $212 million which resulted in a credit that can be carried forward indefinitely to offset regular federal income taxes in subsequent years. As described previously, these NOLs and other tax benefits have been evaluated for the likelihood of utilization, and valuation allowances have been established for the portion of these deferred income tax assets that do not meet the "more likely than not" threshold.

The ability of EOG to utilize CAMT credit carryforwards may be subject to various limitations under the Internal Revenue Code. Such limitations may arise if certain ownership changes (as defined for federal income tax purposes) were to occur.

As of December 31, 2023, EOG does not have any unrecognized tax benefits. Consequently, no interest or penalties have been recognized in the Consolidated Statements of Income and Comprehensive Income. EOG does not expect its unrecognized tax benefits to change significantly in the next twelve months. EOG and its subsidiaries file income tax returns and are subject to tax audits in the U.S. and various state, local and foreign jurisdictions. EOG's earliest open tax years in its principal jurisdictions are as follows: U.S. federal (2020), Trinidad (2015), Canada (2019), Oman (2020) and Australia (2021).

EOG's foreign subsidiaries' undistributed earnings are not considered to be permanently reinvested outside of the U.S. and, when appropriate, deferred income taxes have been accrued on any such outside basis differences. Additionally, EOG’s foreign earnings may be subject to the U.S. federal "global intangible low-taxed income" (GILTI) inclusion. EOG records any GILTI tax as a period expense.

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Employee Benefit Plans

12 Months Ended

Dec. 31, 2023

Share-Based Payment Arrangement [Abstract]

Employee Benefit Plans

Employee Benefit Plans

Stock-Based Compensation

During 2023, EOG maintained various stock-based compensation plans as discussed below.  EOG recognizes compensation expense on grants of stock options, SARs, restricted stock, restricted stock units and restricted stock units with performance-based conditions (together with the performance units granted under the 2008 Plan (as defined below), Performance Units) and grants made under the EOG Resources, Inc. Employee Stock Purchase Plan (ESPP).  Stock-based compensation expense is calculated based upon the grant date estimated fair value of the awards, net of forfeitures, based upon EOG's historical employee turnover rate.  Compensation expense is amortized over the shorter of the vesting period or the period from date of grant until the date the employee becomes eligible to retire without company approval.

Stock-based compensation expense is included on the Consolidated Statements of Income and Comprehensive Income based upon the job functions of the employees receiving the grants.  Compensation expense related to EOG's stock-based compensation plans for the years ended December 31, 2023, 2022 and 2021 was as follows (in millions):

	2023		2022		2021
Lease and Well	$	54	$	40	$	49
Gathering and Processing Costs	4		4		3
Exploration Costs	24		15		20
General and Administrative	95		74		80
Total	$	177	$	133	$	152

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

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

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

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

At December 31, 2023, approximately 15 million common shares remained available for grant under the 2021 Plan.  EOG's policy is to issue shares related to the 2021 Plan from previously authorized unissued shares or treasury shares to the extent treasury shares are available.

During 2023, 2022 and 2021, EOG issued shares in connection with stock option/SAR exercises, restricted stock grants, restricted stock unit and Performance Unit releases and ESPP purchases.  Excess net tax benefits / (deficiencies) recognized within the income tax provision were $32 million, $22 million and $(11) million for the years ended December 31, 2023, 2022 and 2021, respectively.

Stock Options and Stock-Settled Stock Appreciation Rights and Employee Stock Purchase Plan.  Participants in EOG's stock-based compensation plans (including the 2008 Plan and 2021 Plan) have been or may be granted options to purchase shares of Common Stock.  In addition, participants in EOG's stock-based compensation plans (including the 2008 Plan and 2021 Plan) have been or may be granted SARs, representing the right to receive shares of Common Stock based on the appreciation in the stock price from the date of grant on the number of SARs granted.  Stock options and SARs are granted at a price not less than the market price of the Common Stock on the date of grant.  Terms for stock options and SARs granted have generally not exceeded a maximum term of seven years.  EOG did not grant any stock options or SARs in 2023. EOG's ESPP allows eligible employees to semi-annually purchase, through payroll deductions, shares of Common Stock at 85 percent of the fair market value at specified dates.  Contributions to the ESPP are limited to 10 percent of the employee's pay (subject to certain ESPP limits) during each of the two six-month offering periods each year.

The fair value of stock option grants and SAR grants is estimated using the Hull-White II binomial option pricing model.  The fair value of ESPP grants is estimated using the Black-Scholes-Merton model.  Stock-based compensation expense related to stock option, SAR and ESPP grants totaled $24 million, $34 million and $48 million for the years ended December 31, 2023, 2022 and 2021, respectively.

Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants for the years ended December 31, 2023, 2022 and 2021 were as follows:

	Stock Options/SARs							ESPP
		2022			2021			2023			2022			2021
Weighted Average Fair Value of Grants		$	28.30		$	24.92		$	29.35		$	26.62		$	18.12
Expected Volatility		42.20		%	42.24		%	38.01		%	43.00		%	51.27		%
Risk-Free Interest Rate		0.89		%	0.50		%	5.02		%	1.30		%	0.07		%
Dividend Yield		3.28		%	2.26		%	2.68		%	2.89		%	2.89		%
Expected Life		5.3 years			5.2 years			0.5 years			0.5 years			0.5 years

Expected volatility is based on an equal weighting of historical volatility and implied volatility from traded options in EOG's Common Stock.  The risk-free interest rate is based upon United States Treasury yields in effect at the time of grant.  The expected life is based upon historical experience and contractual terms of stock option, SAR and ESPP grants.

The following table sets forth the stock option and SAR transactions for the years ended December 31, 2023, 2022 and 2021 (stock options and SARs in thousands):

	2023			2022			2021
	Number of Stock Options/ SARs	Weighted Average Grant Price		Number of Stock Options/ SARs	Weighted Average Grant Price		Number of Stock Options/ SARs	Weighted Average Grant Price
Outstanding at January 1	4,225	$	77.49	9,969	$	84.37	10,186	$	84.08
Granted	—	—		2	97.64		1,982	81.68
Exercised (1)	(1,294)	73.01		(5,526)	89.70		(1,130)	63.98
Forfeited	(88)	87.74		(220)	82.74		(1,069)	98.15
Outstanding at December 31	2,843	79.22		4,225	77.49		9,969	84.37
Stock Options/SARs Exercisable at December 31	2,282	78.60		2,462	84.53		6,197	95.33

(1)The total intrinsic value of stock options/SARs exercised during the years 2023, 2022 and 2021 was $70 million, $190 million and $27 million, respectively.  The intrinsic value is based upon the difference between the market price of the Common Stock on the date of exercise and the grant price of the stock options/SARs.

At December 31, 2023, there were 2.8 million stock options/SARs vested or expected to vest with a weighted average grant price of $79.17 per share, an intrinsic value of $119 million and a weighted average remaining contractual life of 3.3 years.

The following table summarizes certain information for the stock options and SARs outstanding and exercisable at December 31, 2023 (stock options and SARs in thousands):

Stock Options/SARs Outstanding							Stock Options/SARs Exercisable
Range of Grant Prices	Stock Options/ SARs	Weighted Average Remaining Life (Years)	Weighted Average Grant Price		Aggregate Intrinsic Value(1)		Stock Options/ SARs	Weighted Average Remaining Life (Years)	Weighted Average Grant Price		Aggregate Intrinsic Value (1)
$ 34.00 to $ 52.99	634	3	$	37.49			633	3	$	37.46
53.00 to     80.99	380	3	74.99				376	3	75.03
81.00 to     81.99	1,140	5	81.81				588	4	81.81
82.00 to     96.99	246	1	95.97				242	1	96.09
97.00 to   129.99	443	2	126.57				443	2	126.58
	2,843	3	79.22		$	121	2,282	3	78.60		$	99

(1)Based upon the difference between the closing market price of the Common Stock on the last trading day of the year and the grant price of in-the-money stock options and SARs, in millions.

At December 31, 2023, unrecognized compensation expense related to non-vested stock option and SAR grants totaled $13 million.  This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 0.7 years.

At the 2018 Annual Meeting of Stockholders, EOG stockholders approved an amendment and restatement of the ESPP to (among other changes) increase the number of shares available for grant. At December 31, 2023, approximately 1.2 million shares of Common Stock remained available for grant under the ESPP.  The following table summarizes ESPP activity for the years ended December 31, 2023, 2022 and 2021 (in thousands, except number of participants):

	2023		2022		2021
Approximate Number of Participants	2,015		1,969		2,036
Shares Purchased	193		201		316
Aggregate Purchase Price	$	18,759	$	17,250	$	17,224

Restricted Stock and Restricted Stock Units.  Employees may be granted restricted (non-vested) stock and/or restricted stock units without cost to them.  Upon vesting of restricted stock, shares of Common Stock are released to the employee.  Upon vesting, restricted stock units are converted into shares of Common Stock and released to the employee.  Stock-based compensation expense related to restricted stock and restricted stock units totaled $137 million, $88 million and $89 million for the years ended December 31, 2023, 2022 and 2021, respectively.

The following table sets forth the restricted stock and restricted stock unit transactions for the years ended December 31, 2023, 2022 and 2021 (shares and units in thousands):

	2023			2022			2021
	Number of Shares and Units	Weighted Average Grant Date Fair Value		Number of Shares and Units	Weighted Average Grant Date Fair Value		Number of Shares and Units	Weighted Average Grant Date Fair Value
Outstanding at January 1	4,113	$	80.77	4,680	$	69.37	4,742	$	74.97
Granted	1,680	131.10		1,637	113.21		1,422	81.50
Released (1)	(1,295)	42.03		(2,019)	81.76		(1,388)	101.00
Forfeited	(134)	93.54		(185)	68.89		(96)	68.26
Outstanding at December 31 (2)	4,364	111.24		4,113	80.77		4,680	69.37

(1)

(1)The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2023, 2022 and 2021 was $166 million, $223 million and $110 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date restricted stock and restricted stock units are released.

(2)

(2)The total intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2023, 2022 and 2021 was $528 million, $533 million and $416 million, respectively. The intrinsic value is based on the closing market price of the Common Stock on the last trading day of the year.

At December 31, 2023, unrecognized compensation expense related to restricted stock and restricted stock units totaled $357 million. Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 1.8 years.

Performance Units.  EOG has granted Performance Units to its executive officers annually since 2012. For the grants made prior to September 2022, as more fully discussed in the grant agreements, the applicable performance metric is EOG's total shareholder return (TSR) over a three-year performance period relative to the TSR over the same period of a designated group of peer companies. Upon the application of the applicable performance multiple at the completion of the three-year performance period, a minimum of 0% and a maximum of 200% of the Performance Units granted could be outstanding.

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

The fair value of the Performance Units is estimated using a Monte Carlo simulation. Stock-based compensation expense related to the Performance Unit grants totaled $16 million, $11 million and $15 million for the years ended December 31, 2023, 2022 and 2021, respectively.

  Weighted average fair values and valuation assumptions used to value Performance Units during the years ended December 31, 2023, 2022 and 2021 were as follows:

	2023			2022			2021
Weighted Average Fair Value of Grants	$	142.20		$	126.55		$	95.16
Expected Volatility	44.76		%	56.11		%	53.80		%
Risk-Free Interest Rate	4.53		%	4.01		%	0.59		%

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

The following table sets forth the Performance Unit transactions for the years ended December 31, 2023, 2022 and 2021 (units in thousands):

	2023				2022			2021
	Number of Units		Weighted Average Grant Date Fair Value		Number of Units	Weighted Average Grant Date Fair Value		Number of Units	Weighted Average Grant Date Fair Value
Outstanding at January 1	688		$	83.82	679	$	84.97	613	$	88.38
Granted	114		142.20		122	126.55		222	95.16
Granted for Performance Multiple (1)	—		—		—	—		19	113.81
Released (2)	(86)		79.98		(57)	136.74		(175)	113.06
Forfeited for Performance Multiple (3)	(86)		79.98		(56)	136.74		—	—
Outstanding at December 31 (4)	630	(5)	95.49		688	83.82		679	84.97

(1)Upon completion of the performance period for the Performance Units granted in 2017, a performance multiple of 125% was applied to the grants resulting in additional grants of Performance Units in February 2021.

(2)The total intrinsic value of Performance Units released during the years ended December 31, 2023, 2022 and 2021 was $10 million, $7 million and $13 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date Performance Units are released.

(3)Upon completion of the performance period for the Performance Units granted in 2019 and 2018, a performance multiple of 50% was applied to each of the grants resulting in a forfeiture of Performance Units in both February 2023 and February 2022.

(4)The total intrinsic value of Performance Units outstanding at December 31, 2023, 2022 and 2021 was $76 million, $89 million and $60 million, respectively. The intrinsic value is based on the closing market price of the Common Stock on the last trading day of the year.

(5)Upon the application of the relevant performance multiple at the completion of each of the remaining performance periods, a minimum of zero and a maximum of 1,261 Performance Units could be outstanding.

At December 31, 2023, unrecognized compensation expense related to Performance Units totaled $18 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 1.7 years.

Upon completion of the performance period for the Performance Units granted in September 2020, a performance multiple of 25% was applied to the grants resulting in a forfeiture of 134,981 Performance Units in February 2024.

Pension Plans.  EOG has a defined contribution pension plan in place for most of its employees in the United States.  EOG's contributions to the pension plan are based on various percentages of compensation and, in some instances, are based upon the amount of the employees' contributions.  EOG's total costs recognized for the plan were $61 million, $56 million and $52 million for 2023, 2022 and 2021, respectively.

In addition, EOG's Trinidadian subsidiary maintains a contributory defined benefit pension plan and a matched savings plan.  These pension plans are available to most employees of the Trinidadian subsidiary. EOG's combined contributions to these plans were $1 million, for each of 2023, 2022 and 2021, respectively.

For the Trinidadian defined benefit pension plan, the benefit obligation, fair value of plan assets and (prepaid)/accrued benefit cost totaled $16 million, $16 million and $(0.9) million, respectively, at December 31, 2023, and $14 million, $15 million and $(0.5) million, respectively, at December 31, 2022.

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

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2023

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Letters of Credit and Guarantees.  At December 31, 2023 and 2022, respectively, EOG had standby letters of credit and guarantees outstanding totaling approximately $907 million and $776 million, primarily representing guarantees of payment or performance obligations on behalf of subsidiaries. As of February 16, 2024, EOG had received no demands for payment under these guarantees.

Minimum Commitments. At December 31, 2023, total minimum commitments from purchase and service obligations and transportation and storage service commitments not qualifying as leases, based on current transportation and storage rates and the foreign currency exchange rates used to convert Canadian dollars into United States dollars at December 31, 2023, were as follows (in millions):

	Total Minimum Commitments
2024	$	1,751
2025	1,201
2026	983
2027	829
2028	545
2029 and beyond	1,375
	$	6,684

Delivery Commitments. EOG sells crude oil and natural gas from its producing operations under a variety of contractual arrangements. At December 31, 2023, EOG was committed to deliver to multiple parties fixed quantities of crude oil of 7 million barrels (MMBbls) in 2024 and 1 MMBbls in 2025. Additionally at December 31, 2023, EOG was committed to deliver to multiple parties fixed quantities of natural gas of 371 billion cubic feet (Bcf) in 2024, 282 Bcf in 2025, 297 Bcf in 2026, 293 Bcf in 2027, 263 Bcf in 2028 and 3,277 Bcf thereafter. All delivery commitments are expected to be sourced from future production of available reserves.

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

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Net Income Per Share

12 Months Ended

Dec. 31, 2023

Earnings Per Share [Abstract]

Net Income Per Share

Net Income Per Share

The following table sets forth the computation of Net Income Per Share for the years ended December 31, 2023, 2022 and 2021 (in millions, except per share data):

	2023		2022		2021
Numerator for Basic and Diluted Earnings per Share -
Net Income	$	7,594	$	7,759	$	4,664
Denominator for Basic Earnings per Share -
Weighted Average Shares	581		583		581
Potential Dilutive Common Shares -
Stock Options/SARs	1		2		—
Restricted Stock/Units and Performance Units	2		2		3
Denominator for Diluted Earnings per Share -
Adjusted Diluted Weighted Average Shares	584		587		584
Net Income Per Share
Basic	$	13.07	$	13.31	$	8.03
Diluted	$	13.00	$	13.22	$	7.99

The diluted earnings per share calculation excludes stock option, SAR, restricted stock, restricted stock unit, Performance Unit and ESPP grants that were anti-dilutive.  Shares underlying the excluded stock option, SAR and ESPP grants were 1 million, 1 million and 6 million for the years ended December 31, 2023, 2022 and 2021, respectively.

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2023

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

Supplemental Cash Flow Information

Net cash paid for interest and income taxes was as follows for the years ended December 31, 2023, 2022 and 2021 (in millions):

	2023		2022		2021
Interest, Net of Capitalized Interest	$	161	$	173	$	185
Income Taxes, Net of Refunds Received	$	1,229	$	2,475	$	1,114

EOG's accrued capital expenditures and amounts recorded within accounts payable at December 31, 2023, 2022 and 2021 were $631 million, $713 million and $592 million, respectively.

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

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

Non-cash investing activities for the year ended December 31, 2021, included additions of $50 million to EOG's oil and gas properties as a result of property exchanges and an addition of $74 million to EOG's other property, plant and equipment made in connection with finance lease transactions for storage facilities.

Cash paid for leases for the years ended December 31, 2023, 2022 and 2021, is disclosed in Note 18.

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Business Segment Information

12 Months Ended

Dec. 31, 2023

Segment Reporting [Abstract]

Business Segment Information

Business Segment Information

EOG's operations are all crude oil, NGLs and natural gas exploration and production-related. The Segment Reporting Topic of the ASC establishes standards for reporting information about operating segments in annual financial statements.  Operating segments are defined as components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker, or decision-making group, in deciding how to allocate resources and in assessing performance.  EOG's chief operating decision-making process is informal and involves the Chairman of the Board and Chief Executive Officer and other key officers.  This group routinely reviews and makes operating decisions related to significant issues associated with each of EOG's major producing areas (including in the United States and in Trinidad) and its exploration programs both inside and outside the United States.  For segment reporting purposes, the chief operating decision makers consider the major United States producing areas to be one operating segment.

Financial information by reportable segment is presented below as of and for the years ended December 31, 2023, 2022 and 2021 (in millions):

	United States		Trinidad		Other International (1)		Total
2023
Crude Oil and Condensate	$	13,734	$	14	$	—	$	13,748
Natural Gas Liquids	1,884		—		—		1,884
Natural Gas	1,530		214		—		1,744
Gains on Mark-to-Market Financial Commodity Derivative Contracts, Net	818		—		—		818
Gathering, Processing and Marketing	5,806		—		—		5,806
Gains on Asset Dispositions, Net	53		42		—		95
Other, Net	91		—		—		91
Operating Revenues and Other (2)	23,916		270		—		24,186
Depreciation, Depletion and Amortization	3,414		78		—		3,492
Operating Income (Loss) (3)	9,516		124		(37)		9,603
Interest Income	223		12		5		240
Other Income (Expense)	(6)		1		(1)		(6)
Interest Expense, Net	148		—		—		148
Income (Loss) Before Income Taxes	9,585		137		(33)		9,689
Income Tax Provision	2,093		2		—		2,095
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	5,413		162		4		5,579
Total Property, Plant and Equipment, Net	31,876		404		17		32,297
Total Assets	42,674		1,063		120		43,857

2022
Crude Oil and Condensate	$	16,349	$	18	$	—	$	16,367
Natural Gas Liquids	2,648		—		—		2,648
Natural Gas	3,489		292		—		3,781
Losses on Mark-to-Market Financial Commodity Derivative Contracts, Net	(3,982)		—		—		(3,982)
Gathering, Processing and Marketing	6,695		1		—		6,696
Gains (Losses) on Asset Dispositions, Net	77		(4)		1		74
Other, Net	118		—		—		118
Operating Revenues and Other (4)	25,394		307		1		25,702
Depreciation, Depletion and Amortization	3,469		73		—		3,542
Operating Income (Loss) (5)	9,880		122		(36)		9,966
Interest Income	81		2		2		85
Other Income (Expense)	(17)		46		—		29
Interest Expense, Net	179		—		—		179
Income (Loss) Before Income Taxes	9,765		170		(34)		9,901
Income Tax Provision	2,106		35		1		2,142
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	4,599		122		6		4,727
Total Property, Plant and Equipment, Net	29,109		307		13		29,429
Total Assets	40,349		879		143		41,371

	United States		Trinidad		Other International (1)		Total
2021
Crude Oil and Condensate	$	11,094	$	31	$	—	$	11,125
Natural Gas Liquids	1,812		—		—		1,812
Natural Gas	2,156		270		18		2,444
Losses on Mark-to-Market Financial Commodity Derivative Contracts, Net	(1,152)		—		—		(1,152)
Gathering, Processing and Marketing	4,287		1		—		4,288
Gains (Losses) on Asset Dispositions, Net	(40)		(2)		59		17
Other, Net	108		—		—		108
Operating Revenues and Other (6)	18,265		300		77		18,642
Depreciation, Depletion and Amortization	3,558		87		6		3,651
Operating Income (Loss) (7)	6,013		151		(62)		6,102
Interest Income	3		—		—		3
Other Income (Expense)	(14)		8		12		6
Interest Expense, Net	178		—		—		178
Income (Loss) Before Income Taxes	5,824		159		(50)		5,933
Income Tax Provision (Benefit)	1,247		66		(44)		1,269
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	3,557		55		5		3,617
Total Property, Plant and Equipment, Net	28,213		204		9		28,426
Total Assets	37,436		637		163		38,236

(1)Other International primarily consists of EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. EOG is continuing the process of exiting its Canada operations. EOG began exploration programs in Australia in the third quarter of 2021 and in Oman in the third quarter of 2020. The decision was reached in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman.

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

(3)EOG recorded pretax impairment charges of $18 million in 2023 for proved oil and gas properties and firm commitment contracts related to its decision to exit the Horn River Basin in British Columbia, Canada, in the Other International segment. See Note 14.

(4)EOG had sales activity with three significant purchasers in 2022, one totaling $3.3 billion, another totaling $3.1 billion and a third totaling $3.0 billion of consolidated Operating Revenues and Other in the United States segment.

(5)EOG recorded pretax impairment charges of $15 million in 2022 for proved oil and gas properties and firm commitment contracts related to its decision to exit the Horn River Basin in British Columbia, Canada, in the Other International segment. See Note 14.

(6)EOG had sales activity with two significant purchasers in 2021, one totaling $2.7 billion and the other totaling $2.6 billion of consolidated Operating Revenues and Other in the United States segment.

(7)EOG recorded pretax impairment charges of $45 million and dry hole costs of $42 million in 2021 in the Other International segment related to its decision in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman. In addition, EOG recorded net gains of asset dispositions of $58 million in 2021 in the Other International segment during the second quarter of 2021 due to the sale of its China operations. See Notes 14 and 17, respectively.

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Risk Management Activities

12 Months Ended

Dec. 31, 2023

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Risk Management Activities

Risk Management Activities

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

During 2023, 2022 and 2021, EOG elected not to designate any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounted for these financial commodity derivative contracts using the mark-to-market accounting method.  Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts, Net on the Consolidated Statements of Income and Comprehensive Income.  The related cash flow impact is reflected in Cash Flows from Operating Activities.  During 2023, 2022 and 2021, EOG recognized net gains (losses) on the mark-to-market of financial commodity derivative contracts of $818 million, $(3,982) million and $(1,152) million, respectively, which included net cash payments for settlements of crude oil, NGLs and natural gas financial derivative contracts of $(112) million, $(3,501) million and $(638) million, respectively.

Presented below is a comprehensive summary of EOG's financial commodity derivative contracts settled during the year ended December 31, 2023 (closed) and remaining for 2024 and thereafter, as of December 31, 2023. Crude oil volumes are presented in MBbld and prices are presented in $/Bbl. Natural gas volumes are presented in MMBtu per day (MMBtud) and prices are presented in dollars per MMBtu ($/MMBtu).

Crude Oil Financial Price Swap Contracts
		Contracts Sold			Contracts Purchased
Period	Settlement Index	Volume (MBbld)	Weighted Average Price ($/Bbl)		Volume (MBbld)	Weighted Average Price ($/Bbl)
January - March 2023 (closed)	NYMEX WTI	95	$	67.90	6	$	102.26
April - May 2023 (closed)	NYMEX WTI	91	67.63		2	98.15
June 2023 (closed)	NYMEX WTI	2	69.10		2	98.15

Natural Gas Financial Price Swap Contracts
		Contracts Sold
Period	Settlement Index	Volume (MMBtud in thousands)	Weighted Average Price ($/MMBtu)
January 2023 - December 2023 (closed)	NYMEX Henry Hub	300	$	3.36
January 2024 (closed)	NYMEX Henry Hub	725	3.07
February - December 2024	NYMEX Henry Hub	725	3.07
January - 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 2023 (closed)	NYMEX Henry Hub Houston Ship Channel (HSC) Differential (1)	135	$	0.01
January - December 2024	NYMEX Henry Hub HSC Differential	10	0.00
January - 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.

Financial Commodity Derivatives Location on Balance Sheet. The following table sets forth the amounts and classification of EOG's outstanding derivative financial instruments at December 31, 2023 and 2022, respectively.  Certain amounts may be presented on a net basis on the consolidated financial statements when such amounts are with the same counterparty and subject to a master netting arrangement (in millions):

		Fair Value at December 31,
Description	Location on Balance Sheet	2023		2022
Asset Derivatives
Crude oil, NGLs and natural gas financial derivative contracts -
Current portion	Assets from Price Risk Management (1)	$	106	$	—
Liability Derivatives
Crude oil, NGLs and natural gas financial derivative contracts -
Current portion	Liabilities from Price Risk Management Activities	$	—	$	169
Noncurrent Portion	Other Liabilities (2)	103		371

(1)    The current portion of Assets from Price Risk Management Activities consists of gross assets of $106 million at December 31, 2023.

(2)    The noncurrent portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $104 million, partially offset by gross assets of $1 million, at December 31, 2023.

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

At December 31, 2023, EOG's net accounts receivable balance related to United States hydrocarbon sales included three receivable balances, each of which accounted for more than 10% of the total balance.  The receivables were due from three petroleum refinery companies. The related amounts were collected during early 2024. At December 31, 2022, EOG's net accounts receivable balance related to United States hydrocarbon sales included one receivable balance which accounted for more than 10% of the total balance.  The receivable was due from a petroleum refinery company.  The related amount was collected during early 2023.

In 2023 and 2022, all natural gas from EOG's Trinidad operations was sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary. In 2023 and 2022, all crude oil and condensate from EOG's Trinidad operations was sold to Heritage Petroleum Company Limited.

All of EOG's financial derivative instruments are covered by International Swap Dealers Association Master Agreements (ISDAs) with counterparties.  The ISDAs may contain provisions that (i) require EOG, if it is the party in a net liability position, to post collateral with the counterparty when the amount of the net liability exceeds the threshold level specified for EOG's then-current credit ratings or (ii) require the counterparty, if it is in a net liability position, to post collateral with EOG when the amount of the net liability exceeds the threshold level specified for the counterparty's then-current credit ratings. In addition, the ISDAs may also provide that as a result of certain circumstances, including certain events that cause EOG's credit ratings to become materially weaker than its then-current ratings, the counterparty may require all outstanding financial derivatives under the ISDA to be settled immediately.  See Note 13 for the aggregate fair value of all financial derivative instruments that were in a net liability position at December 31, 2023 and 2022.  EOG had no collateral posted or held at December 31, 2023 and had $324 million of collateral posted and no collateral held at December 31, 2022.

Substantially all of EOG's accounts receivable at December 31, 2023 and 2022 resulted from hydrocarbon sales and/or joint interest billings to third-party companies, including foreign state-owned entities in the oil and gas industry.  This concentration of customers and joint interest owners may impact EOG's overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions.  In determining whether or not to require collateral or other credit enhancements from a customer, EOG typically analyzes the entity's net worth, cash flows, earnings and credit ratings.  Receivables are generally not collateralized.  During the three-year period ended December 31, 2023, credit losses incurred on receivables by EOG have been immaterial.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2023

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

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

Recurring Fair Value Measurements. The following table provides fair value measurement information within the fair value hierarchy for certain of EOG's financial assets and liabilities carried at fair value on a recurring basis at December 31, 2023 and 2022 (in millions):

	Fair Value Measurements Using:
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
At December 31, 2023
Financial Assets:
Natural Gas Swaps	$	—	$	105	$	—	$	105
Natural Gas Basis Swaps	—		2		—		2
Financial Liabilities:
Natural Gas Swaps	—		104		—		104
At December 31, 2022
Financial Assets:
Natural Gas Basis Swaps	$	—	$	29	$	—	$	29
Financial Liabilities:
Natural Gas Swaps	—		703		—		703
Crude Oil Swaps	—		190		—		190

See Note 12 for the balance sheet amounts and classification of EOG's financial derivative instruments at December 31, 2023 and 2022.

The estimated fair value of crude oil, NGLs and natural gas financial derivative contracts (including options/collars) was based upon forward commodity price curves based on quoted market prices.  Financial commodity derivative contracts were valued by utilizing an independent third-party derivative valuation provider who uses various types of valuation models, as applicable.

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

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

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

During 2022, proved oil and gas properties with a carrying amount of $146 million were written down to their fair value of $26 million, resulting in pretax impairment charges of $120 million

During 2021, proved oil and gas properties with a carrying amount of $27 million were written down to their fair value of $7 million, resulting in pretax impairment charges of $20 million.

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

Fair Value of Debt. At December 31, 2023 and 2022, respectively, EOG had outstanding $3,640 million and $4,890 million aggregate principal amount of senior notes, which had estimated fair values of $3,574 million and $4,740 million, respectively. The estimated fair value of debt was based upon quoted market prices and, where such prices were not available, other observable (Level 2) inputs regarding interest rates available to EOG at year-end.

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 will be accounted for as a derivative beginning in the first quarter of 2024 (effective upon the execution of the agreement) using the mark-to-market accounting method. Changes in the fair value will be recognized as gains or losses in the period of change on the Consolidated Statements of Income and Comprehensive Income.

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Impairment Expense

12 Months Ended

Dec. 31, 2023

Impairment Expense [Abstract]

Impairment Expense

Impairment Expense

Impairment expense was as follows for the years ended December 31, 2023, 2022 and 2021 (in millions):

	2023		2022		2021
Proved properties	$	44	$	120	$	20
Unproved properties (1)	125		206		310
Other assets	31		29		28
Inventories	—		25		13
Firm commitment contracts	2		2		5
Total	$	202	$	382	$	376

(1)    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. Impairments of unproved oil and gas properties included $38 million in 2021 for the decision in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman. See Note 1.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2023

Asset Retirement Obligations, Noncurrent [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

The following table presents the reconciliation of the beginning and ending aggregate carrying amounts of short-term and long-term legal obligations associated with the retirement of property, plant and equipment for the years ended December 31, 2023 and 2022 (in millions):

	2023		2022
Carrying Amount at Beginning of Period	$	1,328	$	1,231
Liabilities Incurred	71		100
Liabilities Settled (1)	(114)		(215)
Accretion	53		43
Revisions	166		173
Foreign Currency Translations	2		(4)
Carrying Amount at End of Period	$	1,506	$	1,328
Current Portion	$	37	$	38
Noncurrent Portion	$	1,469	$	1,290

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

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

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Exploratory Well Costs

12 Months Ended

Dec. 31, 2023

Capitalized Exploratory Well Costs [Abstract]

Exploratory Well Costs

Exploratory Well Costs

EOG's net changes in capitalized exploratory well costs for the years ended December 31, 2023, 2022 and 2021 are presented below (in millions):

	2023		2022		2021
Balance at January 1	$	15	$	7	$	29
Additions Pending the Determination of Proved Reserves	195		135		73
Reclassifications to Proved Properties	(133)		(88)		(41)
Costs Charged to Expense (1)	(1)		(39)		(54)
Balance at December 31	$	76	$	15	$	7

(1)    Includes capitalized exploratory well costs charged to either dry hole costs or impairments.

	2023		2022		2021
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	73	$	15	$	7
Capitalized exploratory well costs that have been capitalized for a period greater than one year (1)	3		—		—
Balance at December 31	$	76	$	15	$	7
Number of exploratory wells that have been capitalized for a period greater than one year	2		—		—

(1)    Consists of costs related to two projects in the United States at December 31, 2023.

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Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2023

Business Combination and Asset Acquisition [Abstract]

Acquisitions and Divestitures

Acquisitions and Divestitures

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

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

During 2021, EOG paid cash for property acquisitions of $95 million in the United States. Additionally during 2021, EOG recognized net gains on asset dispositions of $17 million and received proceeds of $231 million primarily due to the sale of the China assets and the disposition of the Northwest Shelf assets in New Mexico. Additionally, in the fourth quarter of 2021, EOG signed a purchase and sale agreement for the sale of primarily producing properties in the Rocky Mountain area. At December 31, 2021, the book value of these assets and their related asset retirement obligations were $99 million and $105 million, respectively.

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Leases

12 Months Ended

Dec. 31, 2023

Leases [Abstract]

Leases

Leases

Lease costs are classified by the function of the ROU asset. The lease costs related to exploration and development activities are initially included in the Oil and Gas Properties line on the Consolidated Balance Sheets and subsequently accounted for in accordance with the Extractive Industries - Oil and Gas Topic of the ASC. Variable lease cost represents costs incurred above the contractual minimum payments and other charges associated with leased equipment, primarily for drilling and fracturing contracts classified as operating leases. The components of lease cost for the years ended December 31, 2023, 2022 and 2021 were as follows (in millions):

	2023		2022		2021
Operating Lease Cost	$	387	$	282	$	295
Finance Lease Cost:
Amortization of Lease Assets	33		36		39
Interest on Lease Liabilities	5		6		7
Variable Lease Cost	91		71		63
Short-Term Lease Cost	567		425		257
Total Lease Cost	$	1,083	$	820	$	661

The following table sets forth the amounts and classification of EOG's outstanding ROU assets and related lease liabilities at December 31, 2023 and 2022 and supplemental information for the years ended December 31, 2023 and 2022 (in millions, except lease terms and discount rates):

Description	Location on Balance Sheet	2023		2022
Assets
Operating Leases	Other Assets	$	974	$	846
Finance Leases	Property, Plant and Equipment, Net (1)	170		203
Total		$	1,144	$	1,049
Liabilities
Current
Operating Leases	Current Portion of Operating Lease Liabilities	$	325	$	296
Finance Leases	Current Portion of Long-Term Debt	34		33
Long-Term
Operating Leases	Other Liabilities	676		584
Finance Leases	Long-Term Debt	149		182
Total		$	1,184	$	1,095

(1)    Finance lease assets are recorded net of accumulated amortization of $190 million and $157 million at December 31, 2023 and 2022, respectively.

	2023		2022
Weighted Average Remaining Lease Term (in years):
Operating Leases	5.3		4.9
Finance Leases	5.5		6.5
Weighted Average Discount Rate:
Operating Leases	4.3	%	3.4	%
Finance Leases	2.6	%	2.6	%

Cash paid for leases for the years ended December 31, 2023, 2022 and 2021 was as follows (in millions):

	2023		2022		2021
Repayment of Operating Lease Liabilities Associated with Operating Activities	$	226	$	199	$	207
Repayment of Operating Lease Liabilities Associated with Investing Activities	172		95		98
Repayment of Finance Lease Liabilities	32		35		37

Non-cash leasing activities for the year ended December 31, 2023, included the additions of $727 million of operating leases and no finance leases. Non-cash leasing activities for the year ended December 31, 2022, included the additions of $511 million of operating leases and no finance leases. Non-cash leasing activities for the year ended December 31, 2021, included the additions of $333 million of operating leases and $74 million of finance leases.

At December 31, 2023, the future minimum lease payments under non-cancellable leases were as follows (in millions):

	Operating Leases		Finance Leases
2024	$	363	$	37
2025	213		35
2026	129		30
2027	100		30
2028	99		30
2029 and beyond	222		35
Total Lease Payments	1,126		197
Less: Discount to Present Value	125		14
Total Lease Liabilities	1,001		183
Less: Current Portion of Lease Liabilities	325		34
Long-Term Lease Liabilities	$	676	$	149

At December 31, 2023, EOG had additional minimum lease payments of $350 million, which are expected to commence beginning in 2024 with lease terms of two to ten years.

Leases

Leases

Lease costs are classified by the function of the ROU asset. The lease costs related to exploration and development activities are initially included in the Oil and Gas Properties line on the Consolidated Balance Sheets and subsequently accounted for in accordance with the Extractive Industries - Oil and Gas Topic of the ASC. Variable lease cost represents costs incurred above the contractual minimum payments and other charges associated with leased equipment, primarily for drilling and fracturing contracts classified as operating leases. The components of lease cost for the years ended December 31, 2023, 2022 and 2021 were as follows (in millions):

	2023		2022		2021
Operating Lease Cost	$	387	$	282	$	295
Finance Lease Cost:
Amortization of Lease Assets	33		36		39
Interest on Lease Liabilities	5		6		7
Variable Lease Cost	91		71		63
Short-Term Lease Cost	567		425		257
Total Lease Cost	$	1,083	$	820	$	661

The following table sets forth the amounts and classification of EOG's outstanding ROU assets and related lease liabilities at December 31, 2023 and 2022 and supplemental information for the years ended December 31, 2023 and 2022 (in millions, except lease terms and discount rates):

Description	Location on Balance Sheet	2023		2022
Assets
Operating Leases	Other Assets	$	974	$	846
Finance Leases	Property, Plant and Equipment, Net (1)	170		203
Total		$	1,144	$	1,049
Liabilities
Current
Operating Leases	Current Portion of Operating Lease Liabilities	$	325	$	296
Finance Leases	Current Portion of Long-Term Debt	34		33
Long-Term
Operating Leases	Other Liabilities	676		584
Finance Leases	Long-Term Debt	149		182
Total		$	1,184	$	1,095

(1)    Finance lease assets are recorded net of accumulated amortization of $190 million and $157 million at December 31, 2023 and 2022, respectively.

	2023		2022
Weighted Average Remaining Lease Term (in years):
Operating Leases	5.3		4.9
Finance Leases	5.5		6.5
Weighted Average Discount Rate:
Operating Leases	4.3	%	3.4	%
Finance Leases	2.6	%	2.6	%

Cash paid for leases for the years ended December 31, 2023, 2022 and 2021 was as follows (in millions):

	2023		2022		2021
Repayment of Operating Lease Liabilities Associated with Operating Activities	$	226	$	199	$	207
Repayment of Operating Lease Liabilities Associated with Investing Activities	172		95		98
Repayment of Finance Lease Liabilities	32		35		37

Non-cash leasing activities for the year ended December 31, 2023, included the additions of $727 million of operating leases and no finance leases. Non-cash leasing activities for the year ended December 31, 2022, included the additions of $511 million of operating leases and no finance leases. Non-cash leasing activities for the year ended December 31, 2021, included the additions of $333 million of operating leases and $74 million of finance leases.

At December 31, 2023, the future minimum lease payments under non-cancellable leases were as follows (in millions):

	Operating Leases		Finance Leases
2024	$	363	$	37
2025	213		35
2026	129		30
2027	100		30
2028	99		30
2029 and beyond	222		35
Total Lease Payments	1,126		197
Less: Discount to Present Value	125		14
Total Lease Liabilities	1,001		183
Less: Current Portion of Lease Liabilities	325		34
Long-Term Lease Liabilities	$	676	$	149

At December 31, 2023, EOG had additional minimum lease payments of $350 million, which are expected to commence beginning in 2024 with lease terms of two to ten years.

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Pay vs Performance Disclosure - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pay vs Performance Disclosure
Net Income	$ 7,594	$ 7,759	$ 4,664

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Insider Trading Arrangements	3 Months Ended
	Dec. 31, 2023
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Principles of Consolidation

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

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

Financial Instruments

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

Cash and Cash Equivalents

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

Oil and Gas Operations

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

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

Oil and gas exploration costs, other than the costs of drilling exploratory wells, are expensed as incurred.  The costs of drilling exploratory wells are capitalized pending determination of whether EOG has discovered commercial quantities of proved reserves.  If commercial quantities of proved reserves are not discovered, such drilling costs are expensed.  In some circumstances, it may be uncertain whether commercial quantities of proved reserves have been discovered when drilling has been completed.  Such exploratory well drilling costs may continue to be capitalized if the estimated reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made (see Note 16).  Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized.

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

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

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

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

Other Property, Plant and Equipment

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

Inventories

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

Revenue Recognition

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

Revenues are recognized for the sale of crude oil and condensate, NGLs and natural gas at the point control of the product is transferred to the customer, typically when production is delivered and title or risk of loss transfers to the customer. Arrangements for such sales are evidenced by signed contracts with prices typically based on stated market indices, with certain adjustments for product quality and geographic location. As EOG typically invoices customers shortly after performance obligations have been fulfilled, contract assets and contract liabilities are not recognized. The balances of accounts receivable from contracts with customers as of December 31, 2023 and 2022, were $2,237 million and $2,340 million, respectively, and are included in Accounts Receivable, Net on the Consolidated Balance Sheets. Losses incurred on receivables from contracts with customers are infrequent and have been immaterial. Certain arrangements provide for the sale of fixed quantities of commodities in future years with pricing mechanisms based on future market prices of the commodity at time of delivery. EOG does not disclose the value of these obligations given the uncertainty of the future realized transaction price.

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

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

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

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

Capitalized Interest Costs

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

Accounting for Risk Management Activities

Accounting for Risk Management Activities.  Financial commodity derivative instruments are recorded on the balance sheet as either an asset or liability measured at fair value, and changes in the instrument's fair value are recognized currently in earnings unless specific hedge accounting criteria are met.  During the three-year period ended December 31, 2023, EOG elected not to designate any of its financial commodity derivative instruments as accounting hedges and, accordingly, changes in the fair value of these outstanding derivative instruments are recognized as gains or losses in the period of change.  The gains or losses are recorded as Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts on the Consolidated Statements of Income and Comprehensive Income.  The related cash flow impact of settled contracts is reflected as cash flows from operating activities.  EOG employs net presentation of financial commodity derivative assets and liabilities for financial reporting purposes when such assets and liabilities are with the same counterparty and subject to a master netting arrangement.  See Note 12.

Income Taxes

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

Effective January 1, 2021, EOG adopted the provisions of ASU 2019-12, "Income Taxes (Topic 740) Simplifying the Accounting for Income Taxes" (ASU 2019-12). There was no impact upon adoption of ASU 2019-12 to EOG's consolidated financial statements or related disclosures.

Foreign Currency Translation

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

Net Income Per Share

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

Stock-Based Compensation

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

Leases

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

Right of Use (ROU) assets and related liabilities are recognized on the commencement date on the Consolidated Balance Sheets based on future lease payments, discounted based on the rate implicit in the contract, if readily determinable, or EOG's incremental borrowing rate commensurate with the lease term of the contract. EOG estimates its incremental borrowing rate based on the approximate rate required to borrow on a collateralized basis. Contracts with lease terms of less than 12 months are not recorded on the Consolidated Balance Sheets, but instead are disclosed as short-term lease cost. EOG has elected not to separate non-lease components for most asset classes, except for those asset classes where the non-lease (i.e. service) components comprise a material amount of the minimum lease payments. See Note 18.

Recently Issued Accounting Standards

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

In November 2023, the FASB issued ASU 2023-07 "Segment Reporting (Topic 820)," which updates reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. In addition, the amendment prescribes interim disclosure requirements, clarifies circumstances in which an entity can disclose multiple segment measures of profit or loss, provides new segment disclosure requirements for entities with a single reportable segment, and contains other disclosure requirements. The ASU is effective for public companies with annual periods beginning after December 15, 2023, and interim periods within annual periods beginning after December 15, 2024, with early adoption permitted. EOG is currently evaluating the impact of the standard on our segment reporting disclosures.

In December 2023, the FASB issued ASU 2023-09, "Income Taxes (Topic 740): Improvements to Income Tax Disclosures" (ASU 2023-09). ASU 2023-09 requires companies to disclose, on an annual basis, specific categories in the effective tax rate reconciliation and provide additional information for reconciling items that meet a quantitative threshold. In addition, ASU 2023-09 requires companies to disclose additional information about income taxes paid. ASU 2023-09 will be effective for annual periods beginning after December 15, 2024, and although permitted, EOG does not intend to early adopt. EOG is continuing to evaluate the provisions of ASU 2023-09 and does not anticipate a material impact on its consolidated financial statements and related disclosures upon adoption.

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2023

Debt Disclosure [Abstract]

Schedule of Long-Term Debt

Long-Term Debt at December 31, 2023 and 2022 consisted of the following (in millions):

	2023		2022
2.625% Senior Notes due 2023	$	—	$	1,250
3.15% Senior Notes due 2025	500		500
4.15% Senior Notes due 2026	750		750
6.65% Senior Notes due 2028	140		140
4.375% Senior Notes due 2030	750		750
3.90% Senior Notes due 2035	500		500
5.10% Senior Notes due 2036	250		250
4.950% Senior Notes due 2050	750		750
Long-Term Debt	3,640		4,890
Finance Leases (see Note 18)	183		215
Less: Current Portion of Long-Term Debt	34		1,283
Unamortized Debt Discount	21		23
Debt Issuance Costs	3		4
Total Long-Term Debt	$	3,765	$	3,795

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Stockholder's Equity (Tables)

12 Months Ended

Dec. 31, 2023

Stockholders' Equity Note [Abstract]

Schedule of Common Stock Activity

The following summarizes Common Stock activity for each of the years ended December 31, 2023, 2022 and 2021 (in thousands):

	Common Shares
	Issued	Treasury	Outstanding
Balance at December 31, 2020	583,695	(124)	583,571
Common Stock Issued Under Stock-Based Compensation Plans	1,511	—	1,511
Treasury Stock Purchased (1)	—	(504)	(504)
Common Stock Issued Under Employee Stock Purchase Plan	316	—	316
Treasury Stock Issued Under Stock-Based Compensation Plans	—	371	371
Balance at December 31, 2021	585,522	(257)	585,265
Common Stock Issued Under Stock-Based Compensation Plans	2,674	—	2,674
Treasury Stock Purchased (1)	—	(997)	(997)
Common Stock Issued Under Employee Stock Purchase Plan	201	—	201
Treasury Stock Issued Under Stock-Based Compensation Plans	—	554	554
Balance at December 31, 2022	588,397	(700)	587,697
Common Stock Issued Under Stock-Based Compensation Plans	159	—	159
Treasury Stock Purchased (2)	—	(9,177)	(9,177)
Common Stock Issued Under Employee Stock Purchase Plan	193	—	193
Treasury Stock Issued Under Stock-Based Compensation Plans	—	1,989	1,989
Balance at December 31, 2023	588,749	(7,888)	580,861

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

(2)    Represents shares that were repurchased under the November 2021 Authorization and/or that were withheld by or returned to EOG (i) in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or SARs or the vesting of restricted stock, restricted stock unit or performance unit grants or (ii) in payment of the exercise price of employee stock options.

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Accumulated Other Comprehensive (Loss) (Tables)

12 Months Ended

Dec. 31, 2023

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

The components of Accumulated Other Comprehensive Loss at December 31, 2023 and 2022 consisted of the following (in millions):

	Foreign Currency Translation Adjustment		Other		Total
December 31, 2021	$	(11)	$	(1)	$	(12)
Other comprehensive income before taxes	4		—		4
Tax effects	—		—		—
Other comprehensive income	4		—		4
December 31, 2022	(7)		(1)		(8)
Other comprehensive loss before taxes	(1)		—		(1)
Tax effects	—		—		—
Other comprehensive loss	(1)		—		(1)
December 31, 2023	$	(8)	$	(1)	$	(9)

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2023

Income Tax Disclosure [Abstract]

Schedule of Deferred Income Tax Assets (Liabilities), Net

The principal components of EOG's total net deferred income tax liabilities at December 31, 2023 and 2022 were as follows (in millions):

	2023		2022
Deferred Income Tax Assets (Liabilities)
Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization	$	(26)	$	(18)
Foreign Asset Retirement Obligations	84		81
Foreign Accrued Expenses and Liabilities	12		13
Foreign Net Operating Loss	97		82
Foreign Valuation Allowances	(126)		(116)
Foreign Other	1		(9)
Total Net Deferred Income Tax Assets	$	42	$	33
Deferred Income Tax (Assets) Liabilities
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization	$	5,778	$	5,291
Financial Commodity Derivative Contracts	—		(421)
Deferred Compensation Plans	(61)		(58)
Equity Awards	(59)		(60)
Corporate Alternative Minimum Tax	(212)		—
Other	(44)		(42)
Total Net Deferred Income Tax Liabilities	$	5,402	$	4,710
Total Net Deferred Income Tax Liabilities	$	5,360	$	4,677

Schedule of Components of Income (Loss) Before Income Taxes

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

	2023		2022		2021
United States	$	9,576	$	9,752	$	5,787
Foreign	113		149		146
Total	$	9,689	$	9,901	$	5,933

Schedule of Components of Income Tax Provision (Benefit)

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

	2023		2022		2021
Current:
Federal	$	1,334	$	2,020	$	1,203
State	76		126		85
Foreign	5		62		105
Total	1,415		2,208		1,393
Deferred:
Federal	628		(2)		(41)
State	55		(37)		(62)
Foreign	—		(22)		(19)
Total	683		(61)		(122)
Other Non-Current:
Foreign	(3)		(5)		(2)
Total	(3)		(5)		(2)
Income Tax Provision	$	2,095	$	2,142	$	1,269

Schedule of Tax Rate Reconciliation

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

	2023		2022		2021
Statutory Federal Income Tax Rate	21.0	%	21.0	%	21.0	%
State Income Tax, Net of Federal Benefit	1.0		0.7		0.3
Income Tax Provision Related to Foreign Operations	(0.2)		—		0.9
Stock-Based Compensation	—		—		0.2
Other	(0.2)		—		(1.0)
Effective Income Tax Rate	21.6	%	21.7	%	21.4	%

Schedule of Valuation Allowance

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

	2023		2022		2021
Beginning Balance	$	207	$	219	$	219
Increase (1)	8		27		15
Decrease (2)	—		(33)		(14)
Other (3)	1		(6)		(1)
Ending Balance	$	216	$	207	$	219

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

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

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

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Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2023

Share-Based Payment Arrangement [Abstract]

Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs

Stock-based compensation expense is included on the Consolidated Statements of Income and Comprehensive Income based upon the job functions of the employees receiving the grants.  Compensation expense related to EOG's stock-based compensation plans for the years ended December 31, 2023, 2022 and 2021 was as follows (in millions):

	2023		2022		2021
Lease and Well	$	54	$	40	$	49
Gathering and Processing Costs	4		4		3
Exploration Costs	24		15		20
General and Administrative	95		74		80
Total	$	177	$	133	$	152

Schedule of Vesting

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

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

Schedule of Weighted Average Fair Values and Valuation Assumptions

Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants for the years ended December 31, 2023, 2022 and 2021 were as follows:

	Stock Options/SARs							ESPP
		2022			2021			2023			2022			2021
Weighted Average Fair Value of Grants		$	28.30		$	24.92		$	29.35		$	26.62		$	18.12
Expected Volatility		42.20		%	42.24		%	38.01		%	43.00		%	51.27		%
Risk-Free Interest Rate		0.89		%	0.50		%	5.02		%	1.30		%	0.07		%
Dividend Yield		3.28		%	2.26		%	2.68		%	2.89		%	2.89		%
Expected Life		5.3 years			5.2 years			0.5 years			0.5 years			0.5 years

Schedule of Share Based Compensation Arrangement By Share Based Payment Award

The following table sets forth the stock option and SAR transactions for the years ended December 31, 2023, 2022 and 2021 (stock options and SARs in thousands):

	2023			2022			2021
	Number of Stock Options/ SARs	Weighted Average Grant Price		Number of Stock Options/ SARs	Weighted Average Grant Price		Number of Stock Options/ SARs	Weighted Average Grant Price
Outstanding at January 1	4,225	$	77.49	9,969	$	84.37	10,186	$	84.08
Granted	—	—		2	97.64		1,982	81.68
Exercised (1)	(1,294)	73.01		(5,526)	89.70		(1,130)	63.98
Forfeited	(88)	87.74		(220)	82.74		(1,069)	98.15
Outstanding at December 31	2,843	79.22		4,225	77.49		9,969	84.37
Stock Options/SARs Exercisable at December 31	2,282	78.60		2,462	84.53		6,197	95.33

(1)The total intrinsic value of stock options/SARs exercised during the years 2023, 2022 and 2021 was $70 million, $190 million and $27 million, respectively.  The intrinsic value is based upon the difference between the market price of the Common Stock on the date of exercise and the grant price of the stock options/SARs.

Schedule of Stock Options and SARs Outstanding and Exercisable

The following table summarizes certain information for the stock options and SARs outstanding and exercisable at December 31, 2023 (stock options and SARs in thousands):

Stock Options/SARs Outstanding							Stock Options/SARs Exercisable
Range of Grant Prices	Stock Options/ SARs	Weighted Average Remaining Life (Years)	Weighted Average Grant Price		Aggregate Intrinsic Value(1)		Stock Options/ SARs	Weighted Average Remaining Life (Years)	Weighted Average Grant Price		Aggregate Intrinsic Value (1)
$ 34.00 to $ 52.99	634	3	$	37.49			633	3	$	37.46
53.00 to     80.99	380	3	74.99				376	3	75.03
81.00 to     81.99	1,140	5	81.81				588	4	81.81
82.00 to     96.99	246	1	95.97				242	1	96.09
97.00 to   129.99	443	2	126.57				443	2	126.58
	2,843	3	79.22		$	121	2,282	3	78.60		$	99

(1)Based upon the difference between the closing market price of the Common Stock on the last trading day of the year and the grant price of in-the-money stock options and SARs, in millions.

Schedule of ESPP Activity

The following table summarizes ESPP activity for the years ended December 31, 2023, 2022 and 2021 (in thousands, except number of participants):

	2023		2022		2021
Approximate Number of Participants	2,015		1,969		2,036
Shares Purchased	193		201		316
Aggregate Purchase Price	$	18,759	$	17,250	$	17,224

Schedule of Restricted Stock and Restricted Stock Unit Transactions

The following table sets forth the restricted stock and restricted stock unit transactions for the years ended December 31, 2023, 2022 and 2021 (shares and units in thousands):

	2023			2022			2021
	Number of Shares and Units	Weighted Average Grant Date Fair Value		Number of Shares and Units	Weighted Average Grant Date Fair Value		Number of Shares and Units	Weighted Average Grant Date Fair Value
Outstanding at January 1	4,113	$	80.77	4,680	$	69.37	4,742	$	74.97
Granted	1,680	131.10		1,637	113.21		1,422	81.50
Released (1)	(1,295)	42.03		(2,019)	81.76		(1,388)	101.00
Forfeited	(134)	93.54		(185)	68.89		(96)	68.26
Outstanding at December 31 (2)	4,364	111.24		4,113	80.77		4,680	69.37

(1)

(1)The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2023, 2022 and 2021 was $166 million, $223 million and $110 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date restricted stock and restricted stock units are released.

(2)

(2)The total intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2023, 2022 and 2021 was $528 million, $533 million and $416 million, respectively. The intrinsic value is based on the closing market price of the Common Stock on the last trading day of the year.

Schedule of Weighted Average Fair Values and Valuation Assumptions for Performance Units/Stocks

Weighted average fair values and valuation assumptions used to value Performance Units during the years ended December 31, 2023, 2022 and 2021 were as follows:

	2023			2022			2021
Weighted Average Fair Value of Grants	$	142.20		$	126.55		$	95.16
Expected Volatility	44.76		%	56.11		%	53.80		%
Risk-Free Interest Rate	4.53		%	4.01		%	0.59		%

Schedule of Performance Unit and Performance Stock Transactions

The following table sets forth the Performance Unit transactions for the years ended December 31, 2023, 2022 and 2021 (units in thousands):

	2023				2022			2021
	Number of Units		Weighted Average Grant Date Fair Value		Number of Units	Weighted Average Grant Date Fair Value		Number of Units	Weighted Average Grant Date Fair Value
Outstanding at January 1	688		$	83.82	679	$	84.97	613	$	88.38
Granted	114		142.20		122	126.55		222	95.16
Granted for Performance Multiple (1)	—		—		—	—		19	113.81
Released (2)	(86)		79.98		(57)	136.74		(175)	113.06
Forfeited for Performance Multiple (3)	(86)		79.98		(56)	136.74		—	—
Outstanding at December 31 (4)	630	(5)	95.49		688	83.82		679	84.97

(1)Upon completion of the performance period for the Performance Units granted in 2017, a performance multiple of 125% was applied to the grants resulting in additional grants of Performance Units in February 2021.

(2)The total intrinsic value of Performance Units released during the years ended December 31, 2023, 2022 and 2021 was $10 million, $7 million and $13 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date Performance Units are released.

(3)Upon completion of the performance period for the Performance Units granted in 2019 and 2018, a performance multiple of 50% was applied to each of the grants resulting in a forfeiture of Performance Units in both February 2023 and February 2022.

(4)The total intrinsic value of Performance Units outstanding at December 31, 2023, 2022 and 2021 was $76 million, $89 million and $60 million, respectively. The intrinsic value is based on the closing market price of the Common Stock on the last trading day of the year.

(5)Upon the application of the relevant performance multiple at the completion of each of the remaining performance periods, a minimum of zero and a maximum of 1,261 Performance Units could be outstanding.

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2023

Commitments and Contingencies Disclosure [Abstract]

Schedule of Minimum Commitments for Unrecorded Unconditional Purchase Obligations

At December 31, 2023, total minimum commitments from purchase and service obligations and transportation and storage service commitments not qualifying as leases, based on current transportation and storage rates and the foreign currency exchange rates used to convert Canadian dollars into United States dollars at December 31, 2023, were as follows (in millions):

	Total Minimum Commitments
2024	$	1,751
2025	1,201
2026	983
2027	829
2028	545
2029 and beyond	1,375
	$	6,684

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Net Income Per Share (Tables)

12 Months Ended

Dec. 31, 2023

Earnings Per Share [Abstract]

Schedule of Computation of Net Income Per Share

The following table sets forth the computation of Net Income Per Share for the years ended December 31, 2023, 2022 and 2021 (in millions, except per share data):

	2023		2022		2021
Numerator for Basic and Diluted Earnings per Share -
Net Income	$	7,594	$	7,759	$	4,664
Denominator for Basic Earnings per Share -
Weighted Average Shares	581		583		581
Potential Dilutive Common Shares -
Stock Options/SARs	1		2		—
Restricted Stock/Units and Performance Units	2		2		3
Denominator for Diluted Earnings per Share -
Adjusted Diluted Weighted Average Shares	584		587		584
Net Income Per Share
Basic	$	13.07	$	13.31	$	8.03
Diluted	$	13.00	$	13.22	$	7.99

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2023

Supplemental Cash Flow Information [Abstract]

Schedule of Net Cash Paid For Interest and Income Taxes

Net cash paid for interest and income taxes was as follows for the years ended December 31, 2023, 2022 and 2021 (in millions):

	2023		2022		2021
Interest, Net of Capitalized Interest	$	161	$	173	$	185
Income Taxes, Net of Refunds Received	$	1,229	$	2,475	$	1,114

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Business Segment Information (Tables)

12 Months Ended

Dec. 31, 2023

Segment Reporting [Abstract]

Schedule of Selected Financial Information by Reportable Segment

Financial information by reportable segment is presented below as of and for the years ended December 31, 2023, 2022 and 2021 (in millions):

	United States		Trinidad		Other International (1)		Total
2023
Crude Oil and Condensate	$	13,734	$	14	$	—	$	13,748
Natural Gas Liquids	1,884		—		—		1,884
Natural Gas	1,530		214		—		1,744
Gains on Mark-to-Market Financial Commodity Derivative Contracts, Net	818		—		—		818
Gathering, Processing and Marketing	5,806		—		—		5,806
Gains on Asset Dispositions, Net	53		42		—		95
Other, Net	91		—		—		91
Operating Revenues and Other (2)	23,916		270		—		24,186
Depreciation, Depletion and Amortization	3,414		78		—		3,492
Operating Income (Loss) (3)	9,516		124		(37)		9,603
Interest Income	223		12		5		240
Other Income (Expense)	(6)		1		(1)		(6)
Interest Expense, Net	148		—		—		148
Income (Loss) Before Income Taxes	9,585		137		(33)		9,689
Income Tax Provision	2,093		2		—		2,095
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	5,413		162		4		5,579
Total Property, Plant and Equipment, Net	31,876		404		17		32,297
Total Assets	42,674		1,063		120		43,857

2022
Crude Oil and Condensate	$	16,349	$	18	$	—	$	16,367
Natural Gas Liquids	2,648		—		—		2,648
Natural Gas	3,489		292		—		3,781
Losses on Mark-to-Market Financial Commodity Derivative Contracts, Net	(3,982)		—		—		(3,982)
Gathering, Processing and Marketing	6,695		1		—		6,696
Gains (Losses) on Asset Dispositions, Net	77		(4)		1		74
Other, Net	118		—		—		118
Operating Revenues and Other (4)	25,394		307		1		25,702
Depreciation, Depletion and Amortization	3,469		73		—		3,542
Operating Income (Loss) (5)	9,880		122		(36)		9,966
Interest Income	81		2		2		85
Other Income (Expense)	(17)		46		—		29
Interest Expense, Net	179		—		—		179
Income (Loss) Before Income Taxes	9,765		170		(34)		9,901
Income Tax Provision	2,106		35		1		2,142
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	4,599		122		6		4,727
Total Property, Plant and Equipment, Net	29,109		307		13		29,429
Total Assets	40,349		879		143		41,371

	United States		Trinidad		Other International (1)		Total
2021
Crude Oil and Condensate	$	11,094	$	31	$	—	$	11,125
Natural Gas Liquids	1,812		—		—		1,812
Natural Gas	2,156		270		18		2,444
Losses on Mark-to-Market Financial Commodity Derivative Contracts, Net	(1,152)		—		—		(1,152)
Gathering, Processing and Marketing	4,287		1		—		4,288
Gains (Losses) on Asset Dispositions, Net	(40)		(2)		59		17
Other, Net	108		—		—		108
Operating Revenues and Other (6)	18,265		300		77		18,642
Depreciation, Depletion and Amortization	3,558		87		6		3,651
Operating Income (Loss) (7)	6,013		151		(62)		6,102
Interest Income	3		—		—		3
Other Income (Expense)	(14)		8		12		6
Interest Expense, Net	178		—		—		178
Income (Loss) Before Income Taxes	5,824		159		(50)		5,933
Income Tax Provision (Benefit)	1,247		66		(44)		1,269
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	3,557		55		5		3,617
Total Property, Plant and Equipment, Net	28,213		204		9		28,426
Total Assets	37,436		637		163		38,236

(1)Other International primarily consists of EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. EOG is continuing the process of exiting its Canada operations. EOG began exploration programs in Australia in the third quarter of 2021 and in Oman in the third quarter of 2020. The decision was reached in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman.

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

(3)EOG recorded pretax impairment charges of $18 million in 2023 for proved oil and gas properties and firm commitment contracts related to its decision to exit the Horn River Basin in British Columbia, Canada, in the Other International segment. See Note 14.

(4)EOG had sales activity with three significant purchasers in 2022, one totaling $3.3 billion, another totaling $3.1 billion and a third totaling $3.0 billion of consolidated Operating Revenues and Other in the United States segment.

(5)EOG recorded pretax impairment charges of $15 million in 2022 for proved oil and gas properties and firm commitment contracts related to its decision to exit the Horn River Basin in British Columbia, Canada, in the Other International segment. See Note 14.

(6)EOG had sales activity with two significant purchasers in 2021, one totaling $2.7 billion and the other totaling $2.6 billion of consolidated Operating Revenues and Other in the United States segment.

(7)EOG recorded pretax impairment charges of $45 million and dry hole costs of $42 million in 2021 in the Other International segment related to its decision in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman. In addition, EOG recorded net gains of asset dispositions of $58 million in 2021 in the Other International segment during the second quarter of 2021 due to the sale of its China operations. See Notes 14 and 17, respectively.

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Risk Management Activities (Tables)

12 Months Ended

Dec. 31, 2023

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments

Presented below is a comprehensive summary of EOG's financial commodity derivative contracts settled during the year ended December 31, 2023 (closed) and remaining for 2024 and thereafter, as of December 31, 2023. Crude oil volumes are presented in MBbld and prices are presented in $/Bbl. Natural gas volumes are presented in MMBtu per day (MMBtud) and prices are presented in dollars per MMBtu ($/MMBtu).

Crude Oil Financial Price Swap Contracts
		Contracts Sold			Contracts Purchased
Period	Settlement Index	Volume (MBbld)	Weighted Average Price ($/Bbl)		Volume (MBbld)	Weighted Average Price ($/Bbl)
January - March 2023 (closed)	NYMEX WTI	95	$	67.90	6	$	102.26
April - May 2023 (closed)	NYMEX WTI	91	67.63		2	98.15
June 2023 (closed)	NYMEX WTI	2	69.10		2	98.15

Natural Gas Financial Price Swap Contracts
		Contracts Sold
Period	Settlement Index	Volume (MMBtud in thousands)	Weighted Average Price ($/MMBtu)
January 2023 - December 2023 (closed)	NYMEX Henry Hub	300	$	3.36
January 2024 (closed)	NYMEX Henry Hub	725	3.07
February - December 2024	NYMEX Henry Hub	725	3.07
January - 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 2023 (closed)	NYMEX Henry Hub Houston Ship Channel (HSC) Differential (1)	135	$	0.01
January - December 2024	NYMEX Henry Hub HSC Differential	10	0.00
January - 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.

Schedule of Derivative Instruments In Statement Of Financial Position, Fair Value

The following table sets forth the amounts and classification of EOG's outstanding derivative financial instruments at December 31, 2023 and 2022, respectively.  Certain amounts may be presented on a net basis on the consolidated financial statements when such amounts are with the same counterparty and subject to a master netting arrangement (in millions):

		Fair Value at December 31,
Description	Location on Balance Sheet	2023		2022
Asset Derivatives
Crude oil, NGLs and natural gas financial derivative contracts -
Current portion	Assets from Price Risk Management (1)	$	106	$	—
Liability Derivatives
Crude oil, NGLs and natural gas financial derivative contracts -
Current portion	Liabilities from Price Risk Management Activities	$	—	$	169
Noncurrent Portion	Other Liabilities (2)	103		371

(1)    The current portion of Assets from Price Risk Management Activities consists of gross assets of $106 million at December 31, 2023.

(2)    The noncurrent portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $104 million, partially offset by gross assets of $1 million, at December 31, 2023.

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2023

Fair Value Disclosures [Abstract]

Schedule of Fair Value Assets and Liabilities Measured on Recurring Basis

The following table provides fair value measurement information within the fair value hierarchy for certain of EOG's financial assets and liabilities carried at fair value on a recurring basis at December 31, 2023 and 2022 (in millions):

	Fair Value Measurements Using:
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
At December 31, 2023
Financial Assets:
Natural Gas Swaps	$	—	$	105	$	—	$	105
Natural Gas Basis Swaps	—		2		—		2
Financial Liabilities:
Natural Gas Swaps	—		104		—		104
At December 31, 2022
Financial Assets:
Natural Gas Basis Swaps	$	—	$	29	$	—	$	29
Financial Liabilities:
Natural Gas Swaps	—		703		—		703
Crude Oil Swaps	—		190		—		190

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Impairment Expense (Tables)

12 Months Ended

Dec. 31, 2023

Impairment Expense [Abstract]

Schedule of Impairment Expenses

Impairment expense was as follows for the years ended December 31, 2023, 2022 and 2021 (in millions):

	2023		2022		2021
Proved properties	$	44	$	120	$	20
Unproved properties (1)	125		206		310
Other assets	31		29		28
Inventories	—		25		13
Firm commitment contracts	2		2		5
Total	$	202	$	382	$	376

(1)    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. Impairments of unproved oil and gas properties included $38 million in 2021 for the decision in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman. See Note 1.

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2023

Asset Retirement Obligations, Noncurrent [Abstract]

Schedule of Asset Retirement Obligation Rollforward Analysis

The following table presents the reconciliation of the beginning and ending aggregate carrying amounts of short-term and long-term legal obligations associated with the retirement of property, plant and equipment for the years ended December 31, 2023 and 2022 (in millions):

	2023		2022
Carrying Amount at Beginning of Period	$	1,328	$	1,231
Liabilities Incurred	71		100
Liabilities Settled (1)	(114)		(215)
Accretion	53		43
Revisions	166		173
Foreign Currency Translations	2		(4)
Carrying Amount at End of Period	$	1,506	$	1,328
Current Portion	$	37	$	38
Noncurrent Portion	$	1,469	$	1,290

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

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Exploratory Well Costs (Tables)

12 Months Ended

Dec. 31, 2023

Capitalized Exploratory Well Costs [Abstract]

Schedule of Net Changes in Capitalized Exploratory Well Costs

EOG's net changes in capitalized exploratory well costs for the years ended December 31, 2023, 2022 and 2021 are presented below (in millions):

	2023		2022		2021
Balance at January 1	$	15	$	7	$	29
Additions Pending the Determination of Proved Reserves	195		135		73
Reclassifications to Proved Properties	(133)		(88)		(41)
Costs Charged to Expense (1)	(1)		(39)		(54)
Balance at December 31	$	76	$	15	$	7

(1)    Includes capitalized exploratory well costs charged to either dry hole costs or impairments.

Schedule of Aging of Capitalized Exploratory Well Costs

	2023		2022		2021
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	73	$	15	$	7
Capitalized exploratory well costs that have been capitalized for a period greater than one year (1)	3		—		—
Balance at December 31	$	76	$	15	$	7
Number of exploratory wells that have been capitalized for a period greater than one year	2		—		—

(1)    Consists of costs related to two projects in the United States at December 31, 2023.

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Leases (Tables)

12 Months Ended

Dec. 31, 2023

Leases [Abstract]

Schedule of Lease

The components of lease cost for the years ended December 31, 2023, 2022 and 2021 were as follows (in millions):

	2023		2022		2021
Operating Lease Cost	$	387	$	282	$	295
Finance Lease Cost:
Amortization of Lease Assets	33		36		39
Interest on Lease Liabilities	5		6		7
Variable Lease Cost	91		71		63
Short-Term Lease Cost	567		425		257
Total Lease Cost	$	1,083	$	820	$	661

Schedule of Outstanding Lease Assets And Lease Liabilities

The following table sets forth the amounts and classification of EOG's outstanding ROU assets and related lease liabilities at December 31, 2023 and 2022 and supplemental information for the years ended December 31, 2023 and 2022 (in millions, except lease terms and discount rates):

Description	Location on Balance Sheet	2023		2022
Assets
Operating Leases	Other Assets	$	974	$	846
Finance Leases	Property, Plant and Equipment, Net (1)	170		203
Total		$	1,144	$	1,049
Liabilities
Current
Operating Leases	Current Portion of Operating Lease Liabilities	$	325	$	296
Finance Leases	Current Portion of Long-Term Debt	34		33
Long-Term
Operating Leases	Other Liabilities	676		584
Finance Leases	Long-Term Debt	149		182
Total		$	1,184	$	1,095

(1)    Finance lease assets are recorded net of accumulated amortization of $190 million and $157 million at December 31, 2023 and 2022, respectively.

Schedule of Weighted Average Remaining Lease Term And Discount Rate

	2023		2022
Weighted Average Remaining Lease Term (in years):
Operating Leases	5.3		4.9
Finance Leases	5.5		6.5
Weighted Average Discount Rate:
Operating Leases	4.3	%	3.4	%
Finance Leases	2.6	%	2.6	%

Schedule of Cash Paid for Leases

Cash paid for leases for the years ended December 31, 2023, 2022 and 2021 was as follows (in millions):

	2023		2022		2021
Repayment of Operating Lease Liabilities Associated with Operating Activities	$	226	$	199	$	207
Repayment of Operating Lease Liabilities Associated with Investing Activities	172		95		98
Repayment of Finance Lease Liabilities	32		35		37

Schedule of Operating And Finance Non-Cancellable Leases Maturity

At December 31, 2023, the future minimum lease payments under non-cancellable leases were as follows (in millions):

	Operating Leases		Finance Leases
2024	$	363	$	37
2025	213		35
2026	129		30
2027	100		30
2028	99		30
2029 and beyond	222		35
Total Lease Payments	1,126		197
Less: Discount to Present Value	125		14
Total Lease Liabilities	1,001		183
Less: Current Portion of Lease Liabilities	325		34
Long-Term Lease Liabilities	$	676	$	149

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Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Accounts receivable from contracts with customers	$ 2,237	$ 2,340
Minimum
Property, plant and equipment, useful life	3 years
Lease term	1 month
Maximum
Property, plant and equipment, useful life	45 years
Lease term	30 years

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Long-Term Debt - Schedule of Long-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Long-Term Debt	$ 3,640	$ 4,890
Finance Leases (see Note 18)	183	215
Less: Current Portion of Long-Term Debt	34	1,283
Unamortized Debt Discount	21	23
Debt Issuance Costs	3	4
Total Long-Term Debt	$ 3,765	3,795
2.625% Senior Notes due 2023
Debt Instrument [Line Items]
Debt instrument, interest rate (as a percent)	2.625%
Long-Term Debt	$ 0	1,250
3.15% Senior Notes due 2025
Debt Instrument [Line Items]
Debt instrument, interest rate (as a percent)	3.15%
Long-Term Debt	$ 500	500
4.15% Senior Notes due 2026
Debt Instrument [Line Items]
Debt instrument, interest rate (as a percent)	4.15%
Long-Term Debt	$ 750	750
6.65% Senior Notes due 2028
Debt Instrument [Line Items]
Debt instrument, interest rate (as a percent)	6.65%
Long-Term Debt	$ 140	140
4.375% Senior Notes due 2030
Debt Instrument [Line Items]
Debt instrument, interest rate (as a percent)	4.375%
Long-Term Debt	$ 750	750
3.90% Senior Notes due 2035
Debt Instrument [Line Items]
Debt instrument, interest rate (as a percent)	3.90%
Long-Term Debt	$ 500	500
5.10% Senior Notes due 2036
Debt Instrument [Line Items]
Debt instrument, interest rate (as a percent)	5.10%
Long-Term Debt	$ 250	250
4.950% Senior Notes due 2050
Debt Instrument [Line Items]
Debt instrument, interest rate (as a percent)	4.95%
Long-Term Debt	$ 750	$ 750

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Long-Term Debt - Narrative (Details)	12 Months Ended
	Dec. 31, 2023 USD ($) Term	Mar. 15, 2023 USD ($)	Feb. 17, 2023 USD ($)	Dec. 31, 2022 USD ($)	Jun. 27, 2019 USD ($)
Long-Term Debt by Maturity [Abstract]
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2024	$ 0
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2025	500,000,000
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2026	750,000,000
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2027	0
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2028	$ 140,000,000
SOFR
Long-Term Debt by Maturity [Abstract]
Basis spread on debt	0.10%
Revolving Credit Facility | Revolving Credit Agreement (New Facility)
Long-Term Debt by Maturity [Abstract]
Debt instrument, face amount					$ 2,000,000,000
Maximum borrowing capacity	$ 1,900,000,000		$ 1,900,000,000
Line of credit facility, maturity term extensions | Term	2
Line of credit facility, extension period	1 year
Commitment threshold	0.50
Line of credit facility increase additional borrowings (not to exceed)	$ 3,000,000,000
Maximum total debt-to-total capitalization ratio allowed under financial covenant (in hundredths)	65.00%
Revolving Credit Facility | Revolving Credit Agreement (New Facility) | Eurodollar
Long-Term Debt by Maturity [Abstract]
Weighted average interest rate (in hundredths)	6.35%
Revolving Credit Facility | Revolving Credit Agreement (New Facility) | Base Rate
Long-Term Debt by Maturity [Abstract]
Weighted average interest rate (in hundredths)	8.50%
Commercial Paper
Long-Term Debt by Maturity [Abstract]
Line of credit facility, current borrowing capacity	$ 0			$ 0
Senior Notes | Senior Notes Due 2021
Long-Term Debt by Maturity [Abstract]
Debt instrument, face amount		$ 1,250,000,000
Debt instrument, interest rate (as a percent)		2.625%

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Stockholder's Equity (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
	Feb. 22, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Nov. 04, 2021	Sep. 30, 2001
Common Stock Activity [Line Items]
An aggregate maximum of shares of common stock authorized for repurchase (in shares)						10,000,000
Stock repurchase program, authorized amount					$ 5,000
Stock repurchased during period, shares		8,600,000
Stock repurchased during period, value		$ 971
Stock repurchase program, remaining authorized repurchase amount		4,000
Estimated federal excise taxes		$ 8
Common stock dividends declared (in USD per share)		$ 5.8850	$ 8.8750	$ 4.9875
Series E Preferred stock, shares issued (in shares)		0
Series E Preferred stock, shares outstanding (in shares)		0
Subsequent Event
Common Stock Activity [Line Items]
Common stock dividends declared (in USD per share)	$ 0.91
Series E Preferred Stock
Common Stock Activity [Line Items]
Series E Preferred stock, shares authorized (in shares)		3,000,000

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Stockholder's Equity - Schedule of Common Stock Activity (Details) - shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Common Stock Activity [Roll Forward]
Beginning Balance (in shares)	588,396,757
Treasury Stock Purchased (in shares)	(8,600,000)
Ending Balance (in shares)	588,748,473	588,396,757
Common Shares, Issued
Common Stock Activity [Roll Forward]
Beginning Balance (in shares)	588,397,000	585,522,000	583,695,000
Common Stock Issued Under Stock-Based Compensation Plans (in shares)	159,000	2,674,000	1,511,000
Treasury Stock Purchased (in shares)	0	0	0
Common Stock Issued Under Employee Stock Purchase Plan (in shares)	193,000	201,000	316,000
Treasury Stock Issued Under Stock-Based Compensation Plans (in shares)	0	0	0
Ending Balance (in shares)	588,749,000	588,397,000	585,522,000
Common Stock Held In Treasury
Common Stock Activity [Roll Forward]
Beginning Balance (in shares)	700,000	257,000	124,000
Common Stock Issued Under Stock-Based Compensation Plans (in shares)	0	0	0
Treasury Stock Purchased (in shares)	(9,177,000)	(997,000)	(504,000)
Common Stock Issued Under Employee Stock Purchase Plan (in shares)	0	0	0
Treasury Stock Issued Under Stock-Based Compensation Plans (in shares)	1,989,000	554,000	371,000
Ending Balance (in shares)	7,888,000	700,000	257,000
Common Shares, Outstanding
Common Stock Activity [Roll Forward]
Beginning Balance (in shares)	587,697,000	585,265,000	583,571,000
Common Stock Issued Under Stock-Based Compensation Plans (in shares)	159,000	2,674,000	1,511,000
Treasury Stock Purchased (in shares)	(9,177,000)	(997,000)	(504,000)
Common Stock Issued Under Employee Stock Purchase Plan (in shares)	193,000	201,000	316,000
Treasury Stock Issued Under Stock-Based Compensation Plans (in shares)	1,989,000	554,000	371,000
Ending Balance (in shares)	580,861,000	587,697,000	585,265,000

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Accumulated Other Comprehensive (Loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	$ 24,779	$ 22,180	$ 20,302
Other comprehensive income (Loss) before taxes	(1)	4
Tax effects	0	0
Other comprehensive income		4
Other comprehensive (loss) income	(1)	4	0
Ending balance	28,090	24,779	22,180
Significant amount reclassified out of AOCI	0	0
Foreign Currency Translation Adjustment
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(7)	(11)
Other comprehensive income (Loss) before taxes	(1)	4
Tax effects	0	0
Other comprehensive income		4
Other comprehensive (loss) income	(1)
Ending balance	(8)	(7)	(11)
Other
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(1)	(1)
Other comprehensive income (Loss) before taxes	0	0
Tax effects	0	0
Other comprehensive income		0
Other comprehensive (loss) income	0
Ending balance	(1)	(1)	(1)
Accumulated Other Comprehensive Loss
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(8)	(12)	(12)
Other comprehensive (loss) income	(1)	4	0
Ending balance	$ (9)	$ (8)	$ (12)

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Other Income, Net (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Other Income and Expenses [Abstract]
Interest income	$ 240	$ 85	$ 3
Adjustment to deferred compensation expense	$ 7	15	13
Equity income (loss) from investments in Trinidad		$ 46	$ 18

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Income Taxes - Schedule of Deferred Income Tax Assets (Liabilities), Net (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Deferred Income Tax Assets (Liabilities)
Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization	$ (26)	$ (18)
Foreign Asset Retirement Obligations	84	81
Foreign Accrued Expenses and Liabilities	12	13
Foreign Net Operating Loss	97	82
Foreign Valuation Allowances	(126)	(116)
Foreign Other	1	(9)
Total Net Deferred Income Tax Assets	42	33
Deferred Income Tax (Assets) Liabilities
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization	5,778	5,291
Financial Commodity Derivative Contracts	0	(421)
Deferred Compensation Plans	(61)	(58)
Equity Awards	(59)	(60)
Corporate Alternative Minimum Tax	(212)	0
Other	(44)	(42)
Total Net Deferred Income Tax Liabilities	5,402	4,710
Total Net Deferred Income Tax Liabilities	$ 5,360	$ 4,677

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Income Taxes - Schedule of Components of Income Before Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Components Income (Loss) Before Income Taxes [Abstract]
United States	$ 9,576	$ 9,752	$ 5,787
Foreign	113	149	146
Total	$ 9,689	$ 9,901	$ 5,933

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Income Taxes - Schedule of Components of Income Tax Provision (Benefit) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Current:
Federal	$ 1,334	$ 2,020	$ 1,203
State	76	126	85
Foreign	5	62	105
Total	1,415	2,208	1,393
Deferred:
Federal	628	(2)	(41)
State	55	(37)	(62)
Foreign	0	(22)	(19)
Total	683	(61)	(122)
Other Non-Current
Foreign	(3)	(5)	(2)
Total	(3)	(5)	(2)
Income Tax Provision	$ 2,095	$ 2,142	$ 1,269

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Income Taxes - Schedule of Tax Rate Reconciliation (Details)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Federal Statutory and Effective Income Tax Rates [Abstract]
Statutory Federal Income Tax Rate	21.00%	21.00%	21.00%
State Income Tax, Net of Federal Benefit	1.00%	0.70%	0.30%
Income Tax Provision Related to Foreign Operations	(0.20%)	0.00%	0.90%
Stock-Based Compensation	0.00%	0.00%	0.20%
Other	(0.20%)	0.00%	(1.00%)
Effective Income Tax Rate	21.60%	21.70%	21.40%

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Income Taxes - Schedule of Valuation Allowance (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Increase Decrease of Valuation of Allowance [Roll Forward]
Beginning Balance	$ 207	$ 219	$ 219
Increase	8	27	15
Decrease	0	(33)	(14)
Other	1	(6)	(1)
Ending Balance	$ 216	$ 207	$ 219

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Income Taxes - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Balance of state net operating income expected to be carried forward	$ 1,900
Canadian Net operating loss carryforwards	333
Corporate Alternative Minimum Tax	$ 212	$ 0

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Employee Benefit Plans -Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expenses	$ 177	$ 133	$ 152
Lease and Well
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expenses	54	40	49
Gathering and Processing Costs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expenses	4	4	3
Exploration Costs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expenses	24	15	20
General and Administrative
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expenses	$ 95	$ 74	$ 80

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Employee Benefit Plans - Narrative (Details) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Feb. 22, 2024 shares	Dec. 31, 2023 USD ($) awardPeriod $ / shares shares	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate maximum of common shares (in shares) | shares		20,000,000
Common shares available for grant(in shares) | shares		15,000,000
Net tax benefits / (deficiencies) recognized		$ 32.0	$ 22.0	$ (11.0)
Stock-Based Compensation Expenses		177.0	133.0	152.0
Pension Plans
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total pension plan costs		61.0	56.0	52.0
Company contributions to foreign pension plans		1.0	1.0	1.0
Defined benefit plan, benefit obligation		16.0	14.0
Fair value of foreign pension plan assets		16.0	15.0
(Prepaid) / Accrued benefit cost		$ (0.9)	(0.5)
Stock Options/SARs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Terms for stock options and SARs granted maximum		7 years
Stock-based compensation expense		$ 24.0	34.0	48.0
Stock options/SARs vested or expected to vest (in shares) | shares		2,800,000
Weighted average grant price vested or expected to vest (per share) | $ / shares		$ 79.17
Intrinsic value of stock options/SARs vested or expected to vest		$ 119.0
Weighted average remaining contractual life		3 years 3 months 18 days
Unrecognized compensation expense		$ 13.0
Weighted average period over which unrecognized compensation expense will be recognized		8 months 12 days
ESPP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common shares available for grant(in shares) | shares		1,200,000
Percentage of fair market value at which employees may purchase company stock via the ESPP		85.00%
Contributions to the ESPP percentage		10.00%
Number of award offerings | awardPeriod		2
ESPP offering period		6 months
Restricted Stock and Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense		$ 137.0	88.0	89.0
Unrecognized compensation expense		$ 357.0
Weighted average period over which unrecognized compensation expense will be recognized		1 year 9 months 18 days
Performance Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation expense		$ 18.0
Weighted average period over which unrecognized compensation expense will be recognized		1 year 8 months 12 days
Performance period for performance units		3 years
Minimum performance multiple at the completion performance period		0.00%
Maximum performance multiple at the completion performance period		200.00%
Maximum performance multiple if TSR is negative		100.00%
Average return of capital employed, number of years		3 years
Stock-Based Compensation Expenses		$ 16.0	$ 11.0	$ 15.0
Performance multiple applied at the completion period					50.00%	50.00%	125.00%
Performance Units | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance multiple applied at the completion period	25.00%
Additional performance awards granted (in shares) | shares	134,981
Performance Units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Modifier applied to performance based multiple		(70.00%)
Performance Units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Modifier applied to performance based multiple		70.00%

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Employee Benefit Plans - Schedule of Vesting (Details)	12 Months Ended
	Dec. 31, 2023
Stock Options/SARs | Vesting Schedule - First Anniversary
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period increments	33.30%
Stock Options/SARs | Vesting Schedule - Second Anniversary
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period increments	33.30%
Stock Options/SARs | Vesting Schedule - Third Anniversary
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period increments	33.40%
Restricted Stock and Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based payment award, award vesting period	3 years
Performance Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Cliff vesting period	3 years

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Employee Benefit Plans- Schedule of Weighted Average Fair Values and Valuation Assumptions (Details) - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Stock Options/SARs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Fair Value of Grants (in usd per share)		$ 28.30	$ 24.92
Expected Volatility		42.20%	42.24%
Risk-Free Interest Rate		0.89%	0.50%
Dividend Yield		3.28%	2.26%
Expected Life		5 years 3 months 18 days	5 years 2 months 12 days
ESPP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Fair Value of Grants (in usd per share)	$ 29.35	$ 26.62	$ 18.12
Expected Volatility	38.01%	43.00%	51.27%
Risk-Free Interest Rate	5.02%	1.30%	0.07%
Dividend Yield	2.68%	2.89%	2.89%
Expected Life	6 months	6 months	6 months

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Employee Benefit Plans- Schedule of Stock Options and SARs Transactions (Details) - Stock Options/SARs - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Stock Options and SARs Rollforward [Abstract]
Beginning balance (in shares)	4,225	9,969	10,186
Granted (in shares)	0	2	1,982
Exercised (in shares)	(1,294)	(5,526)	(1,130)
Forfeited (in shares)	(88)	(220)	(1,069)
Ending balance (in shares)	2,843	4,225	9,969
Vested or Expected to Vest (in shares)	2,282	2,462	6,197
Stock Options and SARs Rollforward [Abstract]
Beginning balance (in USD per share)	$ 77.49	$ 84.37	$ 84.08
Granted (in USD per share)	0	97.64	81.68
Exercised (in USD per share)	73.01	89.70	63.98
Forfeited (in USD per share)	87.74	82.74	98.15
Ending balance (in USD per share)	79.22	77.49	84.37
Vested or Expected to Vest (in USD per share)	$ 78.60	$ 84.53	$ 95.33
Intrinsic value of stock options/SARs exercised during the year	$ 70	$ 190	$ 27

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Employee Benefit Plans - Schedule of Stock Options and SARs Outstanding and Exercisable (Details) - Stock Options/SARs $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) $ / shares shares
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items]
Stock Options and SARs Outstanding (in shares) | shares	2,843
Weighted Average Remaining Life for Stock Options/SARs Outstanding (Years)	3 years
Weighted Average Grant Price For Stock Options/SARs Outstanding (in usd per share)	$ 79.22
Aggregate Intrinsic Value For Stock Options/SARs Outstanding | $	$ 121
Stock Options and SARs Exercisable (in shares) | shares	2,282
Weighted Average Remaining Life For Stock Options/SARs Exercisable (Years)	3 years
Weighted Average Grant Price For Stock Options/SARs Exercisable (in usd per share)	$ 78.60
Aggregate Intrinsic Value For Stock Options/SARs Exercisable | $	$ 99
$ 34.00 to $ 52.99
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items]
Range of Grant Prices Lower Limit (in USD per share)	$ 34
Range of Grant Prices Upper Range Limit (in USD per share)	$ 52.99
Stock Options and SARs Outstanding (in shares) | shares	634
Weighted Average Remaining Life for Stock Options/SARs Outstanding (Years)	3 years
Weighted Average Grant Price For Stock Options/SARs Outstanding (in usd per share)	$ 37.49
Stock Options and SARs Exercisable (in shares) | shares	633
Weighted Average Remaining Life For Stock Options/SARs Exercisable (Years)	3 years
Weighted Average Grant Price For Stock Options/SARs Exercisable (in usd per share)	$ 37.46
53.00 to     80.99
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items]
Range of Grant Prices Lower Limit (in USD per share)	53.00
Range of Grant Prices Upper Range Limit (in USD per share)	$ 80.99
Stock Options and SARs Outstanding (in shares) | shares	380
Weighted Average Remaining Life for Stock Options/SARs Outstanding (Years)	3 years
Weighted Average Grant Price For Stock Options/SARs Outstanding (in usd per share)	$ 74.99
Stock Options and SARs Exercisable (in shares) | shares	376
Weighted Average Remaining Life For Stock Options/SARs Exercisable (Years)	3 years
Weighted Average Grant Price For Stock Options/SARs Exercisable (in usd per share)	$ 75.03
81.00 to     81.99
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items]
Range of Grant Prices Lower Limit (in USD per share)	81.00
Range of Grant Prices Upper Range Limit (in USD per share)	$ 81.99
Stock Options and SARs Outstanding (in shares) | shares	1,140
Weighted Average Remaining Life for Stock Options/SARs Outstanding (Years)	5 years
Weighted Average Grant Price For Stock Options/SARs Outstanding (in usd per share)	$ 81.81
Stock Options and SARs Exercisable (in shares) | shares	588
Weighted Average Remaining Life For Stock Options/SARs Exercisable (Years)	4 years
Weighted Average Grant Price For Stock Options/SARs Exercisable (in usd per share)	$ 81.81
82.00 to     96.99
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items]
Range of Grant Prices Lower Limit (in USD per share)	82.00
Range of Grant Prices Upper Range Limit (in USD per share)	$ 96.99
Stock Options and SARs Outstanding (in shares) | shares	246
Weighted Average Remaining Life for Stock Options/SARs Outstanding (Years)	1 year
Weighted Average Grant Price For Stock Options/SARs Outstanding (in usd per share)	$ 95.97
Stock Options and SARs Exercisable (in shares) | shares	242
Weighted Average Remaining Life For Stock Options/SARs Exercisable (Years)	1 year
Weighted Average Grant Price For Stock Options/SARs Exercisable (in usd per share)	$ 96.09
97.00 to   129.99
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items]
Range of Grant Prices Lower Limit (in USD per share)	97.00
Range of Grant Prices Upper Range Limit (in USD per share)	$ 129.99
Stock Options and SARs Outstanding (in shares) | shares	443
Weighted Average Remaining Life for Stock Options/SARs Outstanding (Years)	2 years
Weighted Average Grant Price For Stock Options/SARs Outstanding (in usd per share)	$ 126.57
Stock Options and SARs Exercisable (in shares) | shares	443
Weighted Average Remaining Life For Stock Options/SARs Exercisable (Years)	2 years
Weighted Average Grant Price For Stock Options/SARs Exercisable (in usd per share)	$ 126.58

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Employee Benefit Plans - Schedule of ESPP Activity (Details) - ESPP shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) participant shares	Dec. 31, 2022 USD ($) participant shares	Dec. 31, 2021 USD ($) participant shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Approximate Number of Participants | participant	2,015	1,969	2,036
Shares Purchased (in shares) | shares	193	201	316
Aggregate Purchase Price | $	$ 18,759	$ 17,250	$ 17,224

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Employee Benefit Plans - Schedule of Restricted Stock and Restricted Stock Unit Transactions (Details) - Restricted Stock and Restricted Stock Units - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Number of Shares and Units [Roll Forward]
Beginning balance (in shares)	4,113	4,680	4,742
Granted (in shares)	1,680	1,637	1,422
Released (in shares)	(1,295)	(2,019)	(1,388)
Forfeited (in shares)	(134)	(185)	(96)
Ending balance (in shares)	4,364	4,113	4,680
Weighted Average Grant Price Stock Option and SARs [Rollfoward]
Beginning balance (in USD per share)	$ 80.77	$ 69.37	$ 74.97
Granted (in USD per share)	131.10	113.21	81.50
Released (in USD per share)	42.03	81.76	101.00
Forfeited (in USD per share)	93.54	68.89	68.26
Ending balance (in USD per share)	$ 111.24	$ 80.77	$ 69.37
Intrinsic value of restricted stock and restrcited stock units	$ 166	$ 223	$ 110
Aggregate intrinsic value of restricted stock and restricted stock units	$ 528	$ 533	$ 416

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Employee Benefit Plans - Schedule of Weighted Average Fair Values and Valuation Assumptions for Performance Units/Stocks (Details) - Performance Units - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Fair Value of Grants (in usd per share)	$ 142.20	$ 126.55	$ 95.16
Expected Volatility	44.76%	56.11%	53.80%
Risk-Free Interest Rate	4.53%	4.01%	0.59%

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Employee Benefit Plans - Schedule of Performance Unit and Performance Stock Transactions (Details) - Performance Units - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Number of Shares and Units [Roll Forward]
Beginning balance (in shares)	688,000	679,000	613,000
Granted (in shares)	114,000	122,000	222,000
Granted for Performance Multiple (in shares)	0	0	19,000
Released (in shares)	(86,000)	(57,000)	(175,000)
Forfeited for Performance Multiple (in shares)	(86,000)	(56,000)	0
Ending balance (in shares)	630,000	688,000	679,000
Weighted Average Grant Price Stock Option and SARs [Rollfoward]
Beginning balance (in USD per share)	$ 83.82	$ 84.97	$ 88.38
Granted (in USD per share)	142.20	126.55	95.16
Granted for Performance Multiple (in USD per share)	0	0	113.81
Released (in USD per share)	79.98	136.74	113.06
Forfeited for Performance Multiple (in USD per share)	79.98	136.74	0
Ending balance (in USD per share)	$ 95.49	$ 83.82	$ 84.97
Performance multiple applied at the completion period				50.00%	50.00%	125.00%
Intrinsic value of performance units released during the years	$ 10	$ 7	$ 13
Aggregate intrinsic value of Performance units outstanding	$ 76	$ 89	$ 60
Minimum performance units and stock allowed to be outstanding (in shares)	0
Maximum performance units and stock allowed to be outstanding (in shares)	1,261,000

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Commitments and Contingencies (Details)	Feb. 16, 2024 USD ($)	Dec. 31, 2023 USD ($) Bcfe MBbls	Dec. 31, 2022 USD ($)
Loss Contingencies [Line Items]
Standby letters of credit and guarantees outstanding		$ 907,000,000	$ 776,000,000
Total Minimum Commitments [Abstract]
2024		1,751,000,000
2025		1,201,000,000
2026		983,000,000
2027		829,000,000
2028		545,000,000
2029 and beyond		1,375,000,000
Total Minimum Commitments		$ 6,684,000,000
Oil and gas, delivery commitment, quantity committed, year 2024 | MBbls		7,000
Oil and gas, delivery commitment, quantity committed, year 2025 | MBbls		1,000
Natural gas, delivery commitment, quantity committed, year 2024 | Bcfe		371
Natural gas, delivery commitment, quantity committed, year 2025 | Bcfe		282
Natural gas, delivery commitment, quantity committed, year 2026 | Bcfe		297
Natural gas, delivery commitment, quantity committed, year 2027 | Bcfe		293
Natural gas, delivery commitment, quantity committed, year 2028 | Bcfe		263
Natural gas, delivery commitment, quantity committed, thereafter | Bcfe		3,277
Subsequent Event
Loss Contingencies [Line Items]
Subsidiary guarantees demand for payment	$ 0

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Net Income Per Share - Schedule of Computation of Net Income Per Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Numerator for Basic and Diluted Earnings per Share -
Net income (loss) - basic	$ 7,594	$ 7,759	$ 4,664
Net income (loss) - diluted	$ 7,594	$ 7,759	$ 4,664
Denominator for Basic Earnings per Share -
Weighted average shares (in shares)	581	583	581
Denominator for Diluted Earnings per Share -
Adjusted diluted weighted average shares (in shares)	584	587	584
Net Income Per Share
Basic ( in usd per share)	$ 13.07	$ 13.31	$ 8.03
Diluted (in usd per share)	$ 13.00	$ 13.22	$ 7.99
Stock Options/SARs
Potential Dilutive Common Shares -
Common shares attributable to dilutive effect of share-based payment arrangements (in shares)	1	2	0
Restricted Stock/Units and Performance Units
Potential Dilutive Common Shares -
Common shares attributable to dilutive effect of share-based payment arrangements (in shares)	2	2	3

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Net Income Per Share - Narrative (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Stock Options/SARs
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, amount ( in shares)	1	1	6

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Supplemental Cash Flow Information - Schedule of Computation of Net Income Per Share (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Supplemental Cash Flow Information [Abstract]
Interest, Net of Capitalized Interest	$ 161	$ 173	$ 185
Income Taxes, Net of Refunds Received	$ 1,229	$ 2,475	$ 1,114

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Supplemental Cash Flow Information - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Equity [Abstract]
Accrued capital expenditures	$ 631	$ 713	$ 592
Non-cash property exchanges	$ 195	$ 153	50
Noncash additions to other property, plant and equipment			$ 74

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Business Segment Information - Narrative (Details)	12 Months Ended
	Dec. 31, 2023 Segment
Segment Reporting [Abstract]
Number of operating segments	1

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Business Segment Information - Schedule of Selected Financial Information by Reportable Segment (Details) $ in Millions	3 Months Ended	12 Months Ended
	Jun. 30, 2021 USD ($)	Dec. 31, 2023 USD ($) purchaser	Dec. 31, 2022 USD ($) purchaser	Dec. 31, 2021 USD ($) purchaser
Schedule of Segment Reporting Information By Segment [Abstract]
Gains on Asset Dispositions, Net		$ 95	$ 74	$ 17
Operating Revenues and Other		24,186	25,702	18,642
Depreciation, Depletion and Amortization		3,492	3,542	3,651
Operating Income (Loss)		9,603	9,966	6,102
Interest Income		240	85	3
Other Income (Expense)		(6)	29	6
Interest Expense, Net		148	179	178
Income Before Income Taxes		9,689	9,901	5,933
Income Tax Provision		2,095	2,142	1,269
Additions to Oil and Gas Properties, Excluding Dry Hole Costs		5,579	4,727	3,617
Total Property, Plant and Equipment, Net		32,297	29,429	28,426
Total Assets		$ 43,857	$ 41,371	$ 38,236
Number of significant purchaser | purchaser		3	3	2
First sale with significant purchaser | purchaser		1	1	1
Sales made with second significant purchaser | purchaser		2	1
Sales made with third significant purchaser | purchaser			1	1
Dry hole costs		$ 1	$ 45	$ 71
Crude Oil and Condensate
Schedule of Segment Reporting Information By Segment [Abstract]
Revenue from contract with customer		13,748	16,367	11,125
Natural Gas Liquids
Schedule of Segment Reporting Information By Segment [Abstract]
Revenue from contract with customer		1,884	2,648	1,812
Natural Gas
Schedule of Segment Reporting Information By Segment [Abstract]
Revenue from contract with customer		1,744	3,781	2,444
Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenue not from contract with customer		818	(3,982)	(1,152)
Gathering, Processing and Marketing
Schedule of Segment Reporting Information By Segment [Abstract]
Revenue from contract with customer		5,806	6,696	4,288
Other, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenue not from contract with customer		91	118	108
United States
Schedule of Segment Reporting Information By Segment [Abstract]
Gains on Asset Dispositions, Net		53	77	(40)
Operating Revenues and Other		23,916	25,394	18,265
Depreciation, Depletion and Amortization		3,414	3,469	3,558
Operating Income (Loss)		9,516	9,880	6,013
Interest Income		223	81	3
Other Income (Expense)		(6)	(17)	(14)
Interest Expense, Net		148	179	178
Income Before Income Taxes		9,585	9,765	5,824
Income Tax Provision		2,093	2,106	1,247
Additions to Oil and Gas Properties, Excluding Dry Hole Costs		5,413	4,599	3,557
Total Property, Plant and Equipment, Net		31,876	29,109	28,213
Total Assets		42,674	40,349	37,436
Amount of sales with a single significant purchaser in the United States segment		3,300	3,300	2,700
Amount of sales with a second significant purchaser in the United States segment.		2,600	3,100	2,600
Amount of sales with a third significant purchaser in the United States segment.		2,600	3,000
United States | Crude Oil and Condensate
Schedule of Segment Reporting Information By Segment [Abstract]
Revenue from contract with customer		13,734	16,349	11,094
United States | Natural Gas Liquids
Schedule of Segment Reporting Information By Segment [Abstract]
Revenue from contract with customer		1,884	2,648	1,812
United States | Natural Gas
Schedule of Segment Reporting Information By Segment [Abstract]
Revenue from contract with customer		1,530	3,489	2,156
United States | Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenue not from contract with customer		818	(3,982)	(1,152)
United States | Gathering, Processing and Marketing
Schedule of Segment Reporting Information By Segment [Abstract]
Revenue from contract with customer		5,806	6,695	4,287
United States | Other, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenue not from contract with customer		91	118	108
Trinidad
Schedule of Segment Reporting Information By Segment [Abstract]
Gains on Asset Dispositions, Net		42	(4)	(2)
Operating Revenues and Other		270	307	300
Depreciation, Depletion and Amortization		78	73	87
Operating Income (Loss)		124	122	151
Interest Income		12	2	0
Other Income (Expense)		1	46	8
Interest Expense, Net		0	0	0
Income Before Income Taxes		137	170	159
Income Tax Provision		2	35	66
Additions to Oil and Gas Properties, Excluding Dry Hole Costs		162	122	55
Total Property, Plant and Equipment, Net		404	307	204
Total Assets		1,063	879	637
Trinidad | Crude Oil and Condensate
Schedule of Segment Reporting Information By Segment [Abstract]
Revenue from contract with customer		14	18	31
Trinidad | Natural Gas Liquids
Schedule of Segment Reporting Information By Segment [Abstract]
Revenue from contract with customer		0	0	0
Trinidad | Natural Gas
Schedule of Segment Reporting Information By Segment [Abstract]
Revenue from contract with customer		214	292	270
Trinidad | Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenue not from contract with customer		0	0	0
Trinidad | Gathering, Processing and Marketing
Schedule of Segment Reporting Information By Segment [Abstract]
Revenue from contract with customer		0	1	1
Trinidad | Other, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenue not from contract with customer		0	0	0
Other International
Schedule of Segment Reporting Information By Segment [Abstract]
Gains on Asset Dispositions, Net	$ 58	0	1	59
Operating Revenues and Other		0	1	77
Depreciation, Depletion and Amortization		0	0	6
Operating Income (Loss)		(37)	(36)	(62)
Interest Income		5	2	0
Other Income (Expense)		(1)	0	12
Interest Expense, Net		0	0	0
Income Before Income Taxes		(33)	(34)	(50)
Income Tax Provision		0	1	(44)
Additions to Oil and Gas Properties, Excluding Dry Hole Costs		4	6	5
Total Property, Plant and Equipment, Net		17	13	9
Total Assets		120	143	163
Pretax impairment charges		18	15	45
Dry hole costs				42
Other International | Crude Oil and Condensate
Schedule of Segment Reporting Information By Segment [Abstract]
Revenue from contract with customer		0	0	0
Other International | Natural Gas Liquids
Schedule of Segment Reporting Information By Segment [Abstract]
Revenue from contract with customer		0	0	0
Other International | Natural Gas
Schedule of Segment Reporting Information By Segment [Abstract]
Revenue from contract with customer		0	0	18
Other International | Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenue not from contract with customer		0	0	0
Other International | Gathering, Processing and Marketing
Schedule of Segment Reporting Information By Segment [Abstract]
Revenue from contract with customer		0	0	0
Other International | Other, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenue not from contract with customer		$ 0	$ 0	$ 0

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Risk Management Activities - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Unrealized gain (loss) on derivatives and commodity contracts	$ 818	$ (3,982)	$ (1,152)
Cash received from (payments for) settlements of crude oil	$ (112)	$ (3,501)	$ (638)
Receivable major customer percentage	10.00%	10.00%
Collateral already posted on derivative	$ 0	$ 324
Collateral held on derivative	$ 0	$ 0

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Risk Management Activities - Schedule of Derivative Instruments (Details)	12 Months Ended
	Dec. 31, 2023 MMBoe MMBTU $ / bbl $ / MMBTU $ / mMBTu MBbls
Crude Oil | Derivative Contracts - January through March (closed) | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld) | MBbls	95
Weighted Average Price ($/MMBtu)(in usd per share) | $ / bbl	67.90
Crude Oil | OffSetting Derivative Contracts - January through March (closed) | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld) | MBbls	6
Weighted Average Price ($/MMBtu)(in usd per share) | $ / bbl	102.26
Crude Oil | Derivative Contracts - April Through May (closed) | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld) | MBbls	91
Weighted Average Price ($/MMBtu)(in usd per share) | $ / bbl	67.63
Crude Oil | offsetting Derivative Contracts - April Through May (closed) | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld) | MBbls	2
Weighted Average Price ($/MMBtu)(in usd per share) | $ / bbl	98.15
Crude Oil | Derivative Contracts - June (closed) | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld) | MBbls	2
Weighted Average Price ($/MMBtu)(in usd per share) | $ / bbl	69.10
Crude Oil | OffSetting Derivative Contracts - June (closed) | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld) | MBbls	2
Weighted Average Price ($/MMBtu)(in usd per share) | $ / bbl	98.15
Natural Gas | Derivative Contracts - January - December (closed) | Price Swaps
Derivatives, Fair Value [Line Items]
Weighted Average Price ($/MMBtu)(in usd per share) | $ / mMBTu	3.36
Volume (MMBtu) | MMBoe	300
Natural Gas | Derivative Contracts - January - December (closed) | HSC Differential Basis Swaps
Derivatives, Fair Value [Line Items]
Volume (MMBtu) | MMBTU	135
Weighted Average Price Differential (MMBtu) ( in usd per share) | $ / MMBTU	0.01
Natural Gas | Derivative Contracts - January (closed) | Price Swaps
Derivatives, Fair Value [Line Items]
Weighted Average Price ($/MMBtu)(in usd per share) | $ / mMBTu	3.07
Volume (MMBtu) | MMBoe	725
Natural Gas | Derivative Contracts - February Through December | Price Swaps
Derivatives, Fair Value [Line Items]
Weighted Average Price ($/MMBtu)(in usd per share) | $ / mMBTu	3.07
Volume (MMBtu) | MMBoe	725
Natural Gas | Derivative Contracts - January through December Year One | Price Swaps
Derivatives, Fair Value [Line Items]
Weighted Average Price ($/MMBtu)(in usd per share) | $ / mMBTu	3.07
Volume (MMBtu) | MMBoe	725
Natural Gas | Derivative Contracts - January through December Year Two | HSC Differential Basis Swaps
Derivatives, Fair Value [Line Items]
Volume (MMBtu) | MMBTU	10
Weighted Average Price Differential (MMBtu) ( in usd per share) | $ / MMBTU	0.00
Natural Gas | Derivative Contracts - January through December Year Three | HSC Differential Basis Swaps
Derivatives, Fair Value [Line Items]
Volume (MMBtu) | MMBTU	10
Weighted Average Price Differential (MMBtu) ( in usd per share) | $ / MMBTU	0.00

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Risk Management Activities - Schedule of Derivative Instruments In Statement Of Financial Position, Fair Value (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Derivatives, Fair Value [Line Items]
Assets from Price Risk Management, Current	$ 106
Liabilities from Price Risk Management Activities	0	$ 169
Price Risk Derivative
Derivatives, Fair Value [Line Items]
Assets from Price Risk Management, Current		0
Liabilities from Price Risk Management Activities	0	169
Other Liabilities	103	$ 371
Other Liabilities
Derivatives, Fair Value [Line Items]
Derivative gross liability	104
Derivative , gross asset	$ 1

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Fair Value Measurements - Schedule of Fair Value Assets and Liabilities Measured on Recurring Basis (Details) - Commodity Contract - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Natural Gas | Price Swaps
Financial Liabilities:
Liabilities, fair value disclosure	$ 104	$ 703
Natural Gas | Price Swaps | Quoted Prices in Active Markets (Level 1)
Financial Liabilities:
Liabilities, fair value disclosure	0	0
Natural Gas | Price Swaps | Significant Other Observable Inputs (Level 2)
Financial Liabilities:
Liabilities, fair value disclosure	104	703
Natural Gas | Price Swaps | Significant Unobservable Inputs (Level 3)
Financial Liabilities:
Liabilities, fair value disclosure	0	0
Natural Gas | Basis Swaps
Financial Assets:
Assets, fair value disclosure	2	29
Natural Gas | Basis Swaps | Quoted Prices in Active Markets (Level 1)
Financial Assets:
Assets, fair value disclosure	0	0
Natural Gas | Basis Swaps | Significant Other Observable Inputs (Level 2)
Financial Assets:
Assets, fair value disclosure	2	29
Natural Gas | Basis Swaps | Significant Unobservable Inputs (Level 3)
Financial Assets:
Assets, fair value disclosure	0	0
Natural Gas Swaps | Basis Swaps
Financial Assets:
Assets, fair value disclosure	105
Natural Gas Swaps | Basis Swaps | Quoted Prices in Active Markets (Level 1)
Financial Assets:
Assets, fair value disclosure	0
Natural Gas Swaps | Basis Swaps | Significant Other Observable Inputs (Level 2)
Financial Assets:
Assets, fair value disclosure	105
Natural Gas Swaps | Basis Swaps | Significant Unobservable Inputs (Level 3)
Financial Assets:
Assets, fair value disclosure	$ 0
Crude Oil | Price Swaps
Financial Liabilities:
Liabilities, fair value disclosure		190
Crude Oil | Price Swaps | Quoted Prices in Active Markets (Level 1)
Financial Liabilities:
Liabilities, fair value disclosure		0
Crude Oil | Price Swaps | Significant Other Observable Inputs (Level 2)
Financial Liabilities:
Liabilities, fair value disclosure		190
Crude Oil | Price Swaps | Significant Unobservable Inputs (Level 3)
Financial Liabilities:
Liabilities, fair value disclosure		$ 0

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Fair Value Measurements - Narrative (Details) MMBTU in Thousands, $ in Millions	1 Months Ended	12 Months Ended
	Feb. 22, 2024 MMBTU	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Proved Oil and Gas Properties, Other Property, Plant and Equipment and Other Assets [Abstract]
Proved oil and gas properties carrying amount		$ 59	$ 146	$ 27
Assets written down during the period - fair value at end of period		15	26	7
Pretax impairment charges		44	120	$ 20
Debt Disclosure [Abstract]
Aggregate principal amount of current and long-term debt		3,640	4,890
Estimated fair value of debt		$ 3,574	$ 4,740
Subsequent Event
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Sales agreement term	10 years
Agreement to sell domestic gas production | MMBTU	180
Agreement to sell at a price indexed to Brent Crude Oil | MMBTU	140

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Impairment Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Impairment of Oil and Gas Properties [Line Items]
Impairment of oil and gas properties	$ 202	$ 382	$ 376
Proved Properties
Impairment of Oil and Gas Properties [Line Items]
Impairment of oil and gas properties	44	120	20
Unproved Properties
Impairment of Oil and Gas Properties [Line Items]
Impairment of oil and gas properties	125	206	310
Impairment of oil and gas properties due to exit activities			38
Other Assets
Impairment of Oil and Gas Properties [Line Items]
Impairment of oil and gas properties	31	29	28
Inventories
Impairment of Oil and Gas Properties [Line Items]
Impairment of oil and gas properties	0	25	13
Firm Commitments Contracts
Impairment of Oil and Gas Properties [Line Items]
Impairment of oil and gas properties	$ 2	$ 2	$ 5

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Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Carrying Amount at Beginning of Period	$ 1,328	$ 1,231
Liabilities Incurred	71	100
Liabilities Settled	(114)	(215)
Accretion	53	43
Revisions	166	173
Foreign Currency Translations	2	(4)
Carrying Amount at End of Period	1,506	1,328
Current Portion	37	38
Noncurrent Portion	$ 1,469	$ 1,290

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Exploratory Well Costs (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) well project	Dec. 31, 2022 USD ($) well	Dec. 31, 2021 USD ($) well
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Beginning balance	$ 15	$ 7	$ 29
Additions Pending the Determination of Proved Reserves	195	135	73
Reclassifications to Proved Properties	(133)	(88)	(41)
Costs Charged to Expense	(1)	(39)	(54)
Ending balance	76	15	7
Capitalized exploratory well costs that have been capitalized for a period of one year or less	73	15	7
Capitalized exploratory well costs that have been capitalized for a period greater than one year	$ 3	$ 0	$ 0
Number of exploratory wells that have been capitalized for a period greater than one year | well	2	0	0
Number of projects | project	2

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Acquisitions and Divestitures (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Business Combination, Separately Recognized Transactions [Line Items]
Gains (losses) on asset dispositions, net	$ 95	$ 74	$ 17
Proceeds on asset dispositions	140	349	231
United States
Business Combination, Separately Recognized Transactions [Line Items]
Payments to acquire oil and gas property	$ 144	$ 393	95
Held-for-sale
Business Combination, Separately Recognized Transactions [Line Items]
Book value of assets held-for-sale			99
Book value of asset retirement obligations			$ 105

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Leases - Schedule of Lease (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Leases [Abstract]
Operating Lease Cost	$ 387	$ 282	$ 295
Amortization of Lease Assets	33	36	39
Interest on Lease Liabilities	5	6	7
Variable Lease Cost	91	71	63
Short-Term Lease Cost	567	425	257
Total Lease Cost	$ 1,083	$ 820	$ 661

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Leases - Schedule of Outstanding Lease Assets And Lease Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Operating and Finance Leases [Line Items]
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other Assets, Noncurrent	Other Assets, Noncurrent
Other Assets	$ 974	$ 846
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Property, Plant and Equipment, Gross	Property, Plant and Equipment, Gross
Property, Plant and Equipment, Net	$ 170	$ 203
Total	$ 1,144	$ 1,049
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Current Portion of Operating Lease Liabilities	Current Portion of Operating Lease Liabilities
Current Portion of Operating Lease Liabilities	$ 325	$ 296
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Current Portion of Long-Term Debt	Current Portion of Long-Term Debt
Current Portion of Long-Term Debt	$ 34	$ 33
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other Liabilities	Other Liabilities
Other Liabilities	$ 676	$ 584
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Long-Term Debt	Long-Term Debt
Long-Term Debt	$ 149	$ 182
Total	1,184	1,095
Property, Plant and Equipment
Operating and Finance Leases [Line Items]
Finance lease, accumulated amortization	$ 190	$ 157

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Leases - Schedule of Weighted Average Remaining Lease Term And Discount Rate (Details)	Dec. 31, 2023	Dec. 31, 2022
Weighted Average Remaining Lease Term (in years):
Operating Leases	5 years 3 months 18 days	4 years 10 months 24 days
Finance Leases	5 years 6 months	6 years 6 months
Weighted Average Discount Rate:
Operating Leases	4.30%	3.40%
Finance Leases	2.60%	2.60%

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Leases - Schedule of Cash Paid for Leases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating and Finance Leases [Line Items]
Repayment of Finance Lease Liabilities	$ 32	$ 35	$ 37
Operating Activities
Operating and Finance Leases [Line Items]
Repayment of Operating Lease Liabilities Associated with Operating Activities and Investing Activities	226	199	207
Investing Activities
Operating and Finance Leases [Line Items]
Repayment of Operating Lease Liabilities Associated with Operating Activities and Investing Activities	$ 172	$ 95	$ 98

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Leases - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Leases [Abstract]
Operating leases non-cash leasing activities	$ 727	$ 511	$ 333
Finance leases non-Cash leasing activities	0	$ 0	$ 74
Leases not yet commenced	$ 350
Minimum commenced lease term	2 years
Maximum commenced lease term	10 years

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Leases - Schedule of Operating And Finance Non-Cancellable Leases Maturity (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Operating Leases
2024	$ 363
2025	213
2026	129
2027	100
2028	99
2029 and beyond	222
Total Lease Payments	1,126
Less: Discount to Present Value	125
Total Lease Liabilities	1,001
Less: Current Portion of Lease Liabilities	325	$ 296
Long-Term Lease Liabilities	676	584
Finance Leases
2024	37
2025	35
2026	30
2027	30
2028	30
2029 and beyond	35
Total Lease Payments	197
Less: Discount to Present Value	14
Total Lease Liabilities	183	215
Less: Current Portion of Lease Liabilities	34	33
Long-Term Lease Liabilities	$ 149	$ 182