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, 2020

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. ☒

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, 2020: $29,444 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, 583,563,479 shares outstanding as of February 12, 2021.

Documents incorporated by reference.  Portions of the Definitive Proxy Statement for the registrant's 2021 Annual Meeting of Stockholders, to be filed within 120 days after December 31, 2020, 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	11
	Information About Our Executive Officers	12
ITEM 1A.	Risk Factors	13
ITEM 1B.	Unresolved Staff Comments	26
ITEM 2.	Properties	26
	Oil and Gas Exploration and Production - Properties and Reserves	26
ITEM 3.	Legal Proceedings	30
ITEM 4.	Mine Safety Disclosures	30
PART II
ITEM 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	30
ITEM 6.	Selected Financial Data	32
ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	33
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk	57
ITEM 8.	Financial Statements and Supplementary Data	57
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	57
ITEM 9A.	Controls and Procedures	57
ITEM 9B.	Other Information	58
PART III
ITEM 10.	Directors, Executive Officers and Corporate Governance	58
ITEM 11.	Executive Compensation	58
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	59
ITEM 13.	Certain Relationships and Related Transactions, and Director Independence	60
ITEM 14.	Principal Accounting Fees and Services	60
PART IV
ITEM 15.	Exhibits, Financial Statement Schedules	61
ITEM 16.	Form 10-K Summary	61
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), The People's Republic of China (China), the Sultanate of Oman (Oman) 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, 2020, EOG's total estimated net proved reserves were 3,220 million barrels of oil equivalent (MMBoe), of which 1,514 million barrels (MMBbl) were crude oil and condensate reserves, 813 MMBbl were NGLs reserves and 5,360 billion cubic feet (Bcf), or 893 MMBoe, were natural gas reserves (see "Supplemental Information to Consolidated Financial Statements").  At such date, approximately 98% of EOG's net proved reserves, on a crude oil equivalent basis, were located in the United States, 1% in Trinidad and 1% in other international areas.  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's business strategy is to maximize the rate of return on investment of capital by controlling operating and capital costs 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 deliver long-term growth in shareholder value and maintain a strong balance sheet.  EOG is focused on innovation and cost-effective utilization of advanced technology associated with three-dimensional seismic and microseismic data, the development of reservoir simulation models, 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, liquids-rich natural gas plays.

At December 31, 2020, on a crude oil equivalent basis, 48% of EOG's net proved reserves in the United States were crude oil and condensate, 26% were NGLs and 26% 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 significant developments during 2020 and anticipated 2021 plans for certain areas of EOG's United States operations.

2020						2021
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
South Texas	162	33	281	1,138	223	160
Delaware Basin	183	75	460	404	247	275
Rocky Mountain	49	14	159	1,167	56	50
Mid-Continent	10	14	87	310	15	<5
Other Areas	4	—	53	851	7	15
Total	408	136	1,040	3,870	548	~500

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

The South Texas area includes our Eagle Ford play and our newly announced Dorado gas play. EOG holds approximately 516,000 total net acres in the prolific oil window of the Eagle Ford and approximately 163,000 net acres in the Dorado prospect area. During the second and third quarters of 2020, EOG significantly curtailed its Eagle Ford oil production due to low crude oil prices; operations in the Eagle Ford returned to normal by the end of the third quarter of 2020. In the Dorado play, with the onset of the pandemic and resulting market downturn, EOG elected to defer its 2020 drilling program and instead focus on gathering and analyzing data regarding the production performance of its 2019 Dorado drilling program. In 2020, EOG completed 213 net Eagle Ford wells and, late in 2020, acquired and completed one net Dorado well to further delineate the play. In 2021, EOG expects to complete approximately 145 net Eagle Ford wells and to drill and complete approximately 15 net Dorado wells.

In the Delaware Basin, EOG completed 247 net wells during 2020, primarily in the Delaware Basin 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 404,000 total net acreage position.

In the Delaware Basin Upper Wolfcamp play, EOG has approximately 226,000 net acres and completed 166 net wells in 2020. EOG continued its Upper Wolfcamp development plan with well spacing as close as 500 feet in the crude oil portion of the play and 880 feet in the combination crude oil and natural gas portion. In addition to the Upper Wolfcamp, EOG completed 7 net wells in 2020 in the newly announced Middle Wolfcamp play and has identified 193,000 net prospective acres. Continued improvement and excellent results in the Delaware Basin Wolfcamp program were supported by optimized well spacing, enhanced well completions, precision drilling and continued cost reductions. Moving forward into 2021, the Delaware Basin 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 2020, EOG completed 56 total net Bone Spring wells within the three sub-plays on its combined 289,000 net prospective acres. Of the three sub-plays, the Second Bone Spring had the majority of the activity in 2020 with EOG completing 42 net wells. The Bone Spring plays continue to be an integral part of EOG’s Delaware Basin plans and portfolio.

In the Leonard play, EOG holds approximately 160,000 net acres and maintained its development plan with 18 net wells completed in 2020. With a strategy of developing deeper targets first while simultaneously collecting data from the shallow targets, the Leonard play will progressively become a more active part of EOG’s program.

Activity in 2021 will remain focused on the Delaware Basin Wolfcamp, Bone Spring, and Leonard plays, where EOG expects to complete approximately 275 net wells.

2

Activity in the Rocky Mountain area in 2020 was focused on the Wyoming Powder River Basin. In the Powder River Basin, EOG operated a one-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 going forward. In the DJ Basin, EOG operated one rig for a partial year and completed 17 net wells in both the Codell and the Niobrara formations. Activity in the DJ Basin is expected to be minimal in 2021 as development continues to shift to the Powder River Basin. In the Williston Basin, EOG completed 3 net wells in the Bakken and Three Forks. In 2020, production in the Rocky Mountain area and Williston Basin was significantly curtailed, primarily in the second quarter, in response to crude oil price declines, but has subsequently returned to normal levels. In 2021, activity will be focused on development in the Powder River Basin with plans to complete approximately 45 net wells. EOG currently holds approximately 1.2 million net acres in the Rocky Mountain area.

In the Mid-Continent area, EOG continued its development of the Woodford Oil Window play with 15 net wells completed during 2020. EOG holds approximately 37,000 net acres in the play and plans to have minimal activity in 2021.

Operations Outside the United States

EOG has operations offshore Trinidad, in the China Sichuan Basin, Oman and in Canada and is evaluating additional exploration, development and exploitation opportunities in these and other select international areas.

Trinidad. EOG, through its subsidiaries, including EOG Resources Trinidad Limited, holds interests in (i) the exploration and production licenses covering the South East Coast Consortium (SECC) Block, Pelican and Banyan Fields, Sercan Area and each of their related facilities and the Ska, Mento, Reggae and deep Teak, Saaman and Poui Areas, all of which are offshore Trinidad; and (ii) a production sharing contract with the Government of Trinidad and Tobago for each of the Modified U(a), Modified U(b) and 4(a) Blocks.

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

In 2020, EOG's net production averaged approximately 180 MMcfd of natural gas and approximately 1.0 MBbld of crude oil and condensate. In 2020, EOG drilled three net wells and completed two net wells. The remaining net well made a discovery that is being evaluated. All wells discovered commercially economic reserves.

In 2021, EOG expects to focus on the design and fabrication of the platform and related infrastructure for the previously announced discovery made in the Modified U(a) Block. In addition, EOG expects to continue its exploration program.

China. Since 2008, EOG has been developing the Baijaochang Field in the Chuan Zhong Block exploration area in the Sichuan Basin, Sichuan Province, China with its partner, PetroChina, under a production sharing contract. In 2020, EOG's net production averaged approximately 26 MMcfd of natural gas. EOG continues to work with PetroChina to ensure uninterrupted production.

Oman. In September 2020, EOG reached an agreement with APEX Oman (Block 36) Inc. to acquire its entire interest in Block 36 in Oman. The Royal Decree was issued on October 28, 2020 at which point EOG became the operator and held all rights under the Exploration and Production Sharing Agreement for Block 36. Additionally, in December 2020 the Ministry of Energy and Minerals for Oman approved the assignment of Block 49 to EOG pursuant to the terms of the farm-in agreement with Tethys Oil Montasar Limited. In accordance with the terms of the farm-in agreement EOG participated in the drilling of an exploratory well which was in progress at December 31, 2020. In 2021, EOG expects to drill two net exploration wells in Block 36.

Canada. EOG maintains approximately 47,000 net acres in the Horn River area in Northeast British Columbia. In March 2020, EOG began the process of exiting its Canada operations.

3

Marketing

In 2020, 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 2020, EOG also sold crude oil at the Houston Ship Channel and 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 2021, the pricing mechanism for such production is expected to remain the same. At December 31, 2020, EOG was committed to deliver to multiple parties fixed quantities of crude oil of 8 MMBbls in 2021, all of which is expected to be delivered from future production of available reserves.

In 2020, 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 NGL production for purity products received downstream, which were sold at prevailing market prices. In 2021, such pricing mechanisms are expected to remain the same.

In 2020, 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; Southern California; 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 2021, the pricing mechanism for such production is expected to remain the same. Additionally, EOG sells natural gas to a liquefied natural gas liquefaction facility near Corpus Christi, Texas, and receives pricing based on the Platts Japan Korea Marker. At December 31, 2020, EOG was committed to deliver to multiple parties fixed quantities of natural gas of 170 Bcf in 2021, 105 Bcf in 2022, 91 Bcf in 2023, 94 Bcf in 2024, 81 Bcf in 2025 and 1,609 Bcf thereafter, all of which is expected to be delivered from future production of available reserves.

In 2020, a majority of the wellhead natural gas volumes from Trinidad were sold under contracts with prices which were either wholly or partially dependent on Caribbean ammonia index prices and/or methanol prices. The remaining volumes were sold under a contract at prices partially dependent on United States Henry Hub market prices or under a fixed price contract. In 2021, natural gas volumes from Trinidad will be sold under a fixed price contract ending in 2026.

In 2020, all wellhead natural gas volumes from China were sold at regulated prices based on the purchaser's pipeline sales volumes to various local market segments. The pricing mechanism for production in China is expected to remain the same in 2021.

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

4

During 2020, 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 three 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.

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, 2020, 2019 and 2018. 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	2020	2019	2018
Crude Oil and Condensate Volumes (MMBbl) (1)
United States:
Eagle Ford	54.6	68.3	62.4
Delaware Basin	67.0	63.4	46.3
Other	27.8	34.6	35.4
United States	149.4	166.3	144.1
Trinidad	0.4	0.2	0.3
Other International (2)	—	0.1	1.6
Total	149.8	166.6	146.0
Natural Gas Liquids Volumes (MMBbl) (1)
United States:
Eagle Ford	9.7	10.7	11.4
Delaware Basin	27.7	23.5	15.8
Other	12.4	14.7	15.3
United States	49.8	48.9	42.5
Other International (2)	—	—	—
Total	49.8	48.9	42.5
Natural Gas Volumes (Bcf) (1)
United States:
Eagle Ford	53	53	58
Delaware Basin	168	147	110
Other	160	190	169
United States	381	390	337
Trinidad	66	95	97
Other International (2)	11	14	11
Total	458	499	445
Crude Oil Equivalent Volumes (MMBoe) (3)
United States:
Eagle Ford	73.1	87.8	83.5
Delaware Basin	122.7	111.4	80.3
Other	66.9	81.0	78.8
United States	262.7	280.2	242.6
Trinidad	11.4	16.0	16.5
Other International (2)	1.8	2.4	3.4
Total	275.9	298.6	262.5

5

Year Ended December 31	2020		2019		2018
Average Crude Oil and Condensate Prices ($/Bbl) (4)
United States	$	38.65	$	57.74	$	65.16
Trinidad	30.20		47.16		57.26
Other International (2)	43.08		57.40		71.45
Composite	38.63		57.72		65.21
Average Natural Gas Liquids Prices ($/Bbl) (4)
United States	$	13.41	$	16.03	$	26.60
Other International (2)	—		—		—
Composite	13.41		16.03		26.60
Average Natural Gas Prices ($/Mcf) (4)
United States	$	1.61	$	2.22	$	2.88
Trinidad	2.57		2.72		2.94
Other International (2)	4.66		4.44		4.08
Composite	1.83		2.38		2.92

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

(2)Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.

(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).

Human Capital Management

As of December 31, 2020, EOG employed approximately 2,900 persons, including foreign national employees. EOG's approach to human capital management includes oversight by the Board of Directors and Compensation Committee and focuses on various areas, including the following:

Culture; Recruiting; Retention. EOG's unique culture is key to its sustainable success. By providing employees with a quality environment in which to work, and by maintaining a consistent college recruiting and internship program, EOG is able to attract and retain some 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 survey. Based on the results of the survey, EOG has received "top workplace" recognition in various office locations.

Compensation, Benefits, Health & Wellness. EOG places a high level of importance on attracting and retaining top talent, by providing 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, with new-hire stock grants and an annual stock grant program, every employee is a participant in EOG's success.

In 2020, in response to the COVID-19 pandemic, EOG focused on keeping its employees and their families safe, including providing technology and support to employees enabling them to work productively from home. In addition, at its offices and work sites, EOG has instituted social distancing practices and protocols and has provided masks, hand sanitizer and additional cleaning.

Training and Development. EOG provides training in leadership, management skills, communication, team effectiveness, technical skills and development and use of EOG systems and applications. EOG's leadership training is focused on providing continuity of leadership at EOG by 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 cost of professional certification.

6

Diversity and Inclusion. Gender, racial, ethnic and cultural diversity, and diversity in background and experience, leads to diversity of thought, which is a tremendous asset and is actively embraced by EOG. 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. EOG's collaborative culture fosters inclusiveness at all levels of the company. Further, EOG focuses on developing its employees, including those with diverse backgrounds, to allow for career opportunities, including promotion into supervisory and management positions.

Safety. EOG's safety management programs and processes are centered on a performance-based philosophy, pursuant to which EOG sets safety expectations and provides a framework within which management can achieve and assess safety performance in a systematic way. EOG's safety performance is also considered in evaluating employee performance and compensation. EOG provides initial, periodic and refresher safety training to employees as well as to contractors and others who may work at or visit EOG's facilities. These training programs address various topics, including operating procedures, safe work practices and emergency and incident response procedures.

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

2020 Election. In November 2020, Joseph R. Biden Jr. was elected President of the United States. New or revised rules, regulations and policies may be issued, and new legislation may be proposed, during the current administration 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 federal lands, (ii) the leasing of federal lands for oil and gas development, (iii) the regulation 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 federal lands, (v) the calculation of royalty payments in respect of oil and gas production from federal lands and (vi) U.S. federal income tax laws applicable to oil and gas exploration and production companies. See the below discussion and ITEM 1A, Risk Factors, for additional information.

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.

A portion of EOG's oil and gas leases in New Mexico, North Dakota, Utah, Wyoming and the Gulf of Mexico, 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) or, in the case of offshore leases (which, for EOG, are de minimis), by the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE), all 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.

7

BLM, BIA and BOEM leases contain relatively standardized terms requiring compliance with detailed regulations and, in the case of offshore leases, orders pursuant to the Outer Continental Shelf Lands Act (which are subject to change by the BOEM or BSEE). Under certain circumstances, the BLM, BIA, BOEM or BSEE (as applicable) 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. Further, on January 27, 2021, President Biden issued Executive Order 14008 entitled "Tackling the Climate Crisis at Home and Abroad," directing the Secretary of the Interior, to the extent consistent with applicable law and in consultation with other agencies and stakeholders, to, among other things, pause approval of new oil and natural gas leases on federal lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. 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.

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 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 in the Permian Basin in West Texas and New Mexico, the Fort Worth Basin Barnett Shale in North Texas, the Williston Basin Bakken and Three Forks plays in North Dakota, and the Eagle Ford 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 rail loading facilities in North Dakota and 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, permitting and packaging/labeling 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 its crude-by-rail assets and 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 2020.

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

Environmental Regulation Generally - United States. EOG is subject to various federal, state and local laws and regulations covering the discharge 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. 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.

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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 or results of operations. 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, given that such laws and regulations are subject to change, EOG is unable to predict the ultimate cost of compliance or the ultimate effect on EOG's operations, financial condition and results of operations.

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. In addition to the U.S. EPA's rule requiring annual reporting of GHG emissions, 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 September 2020, the U.S. EPA issued a final rule that removed the transmission and storage segment from the 2016 new source performance standards, rescinded VOC and methane emissions standards for the transmission and storage segment and rescinded methane emissions standards for the production and processing segments. Various states and industry and environmental groups are separately challenging the U.S. EPA's 2016 standards and its September 2020 final rule. Notwithstanding the current court challenges, the U.S. EPA under the Biden Administration may reconsider the September 2020 final rule, which could result in more stringent methane emission rulemaking.

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 on November 4, 2016. While the U.S. withdrew from the Paris Agreement on November 4, 2020, President Biden issued an executive order on January 20, 2021 recommitting the United States to the Paris Agreement. In addition, many state and local officials have stated their intent to intensify efforts to uphold the commitments set forth in the international accord. Further, on January 27, 2021, President Biden issued Executive Order 14008 entitled "Tackling the Climate Crisis at Home and Abroad," directing the Secretary of the Interior, to the extent consistent with applicable law and in consultation with other agencies and stakeholders, to, among other things, consider whether to adjust royalties associated with oil and gas resources extracted from federal lands and offshore waters to account for corresponding climate costs.

EOG believes that its strategy to reduce GHG emissions throughout its operations is both in the best interest of the environment and a prudent business practice. EOG has developed a system that is utilized in calculating GHG emissions from its operating facilities. This emissions management system calculates emissions based on recognized regulatory methodologies, where applicable, and on commonly accepted engineering practices. EOG reports GHG emissions for facilities covered under the U.S. EPA's Mandatory Reporting of Greenhouse Gases Rule published in 2009, as amended.

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. by the new administration), but the direct and indirect costs of such developments (if enacted, issued or applied) could materially and adversely affect EOG's operations, financial condition and results of operations. 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.

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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 the hydraulic fracturing process typically includes water and sand, and less than 1% of highly diluted chemical additives; lists of the chemical additives used in fracturing fluids are available to the public via internet websites and in other publications sponsored by industry trade associations and through state agencies in those states that require the reporting of the components of fracturing fluids. While the majority of the sand remains underground to hold open the fractures, a significant amount of the water and chemical additives flow back and are then either reused or safely disposed of at sites that are approved and permitted by the appropriate regulatory authorities. EOG periodically conducts regulatory assessments of these disposal facilities to monitor compliance with applicable regulations.

The regulation of hydraulic fracturing is primarily conducted at the state and local level through permitting and other compliance requirements. In April 2012, however, the U.S. EPA issued regulations specifically applicable to the oil and gas industry that require operators to significantly reduce VOC emissions from natural gas wells that are hydraulically fractured through the use of "green completions" to capture natural gas that would otherwise escape into the air. The U.S. EPA has also issued regulations that establish standards for VOC emissions from several types of equipment, including storage tanks, compressors, dehydrators, and valves and sweetening units at gas processing plants. In addition, in May 2016, the U.S. EPA issued regulations that require operators to reduce methane and VOC emissions 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 September 2020, the U.S. EPA issued amendments to the 2012 and 2016 new source performance standards, which removed the transmission and storage segment from the new source performance standards, rescinded VOC and methane emissions standards for the transmission and storage segment, and rescinded methane emissions standards for the production and processing segments.

From time to time, there have been various other proposals to regulate hydraulic fracturing at the federal level. In addition, there were proposals and positions taken by President Biden during his campaign regarding the use of hydraulic fracturing on federal lands and waters. Further, on January 27, 2021, President Biden issued Executive Order 14008 entitled "Tackling the Climate Crisis at Home and Abroad," directing the Secretary of the Interior, to the extent consistent with applicable law and in consultation with other agencies and stakeholders, to, among other things, pause approval of new oil and natural gas leases on federal lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices.

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 prohibition 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 or results of operations. 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 and results of operations 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 and results of operations.

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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 currently has operations in Trinidad, China and Canada, and an exploration program in Oman. 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 and results of operations. 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.

Other Regulation. EOG has sand mining and processing operations in Texas and Wisconsin, which support EOG's exploration and development operations. EOG's sand mining operations are subject to regulation by the federal Mine Safety and Health Administration (in respect of safety and health matters) and by state agencies (in respect of air permitting and other environmental matters). The information concerning mine safety violations and other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95 to this report.

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 ITEM 1A, Risk Factors.

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 33% in 2020 and 11% in 2019 and increased 28% in 2018, each as compared to the immediately preceding year. EOG's quarterly price realizations ranged from $20.40 per barrel to $46.97 per barrel in 2020. Average NGL prices received by EOG for production in the United States decreased 16% in 2020 and 40% in 2019 and increased 18% in 2018, each as compared to the immediately preceding year. These fluctuations resulted in a 27% decrease in the average wellhead natural gas price received by EOG for production in the United States in 2020, a 23% decrease in 2019, and a 31% increase (inclusive of a positive revenue adjustment of $0.44 per Mcf related to the adoption of Accounting Standards Update 2014-09) in 2018, 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, and the duration and impact of the ongoing COVID-19 pandemic), 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 and the risks that such changes may present to EOG, see ITEM 1A, Risk Factors.

Including the impact of EOG's crude oil and NGL derivative contracts (exclusive of basis swaps) and based on EOG's tax position, EOG's price sensitivity in 2021 for each $1.00 per barrel increase or decrease in wellhead crude oil and condensate price, combined with the estimated change in NGL price, is approximately $99 million for net income and $127 million for pretax cash flows from operating activities. Including the impact of EOG's natural gas derivative contracts and based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2021 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 $31 million for net income and $40 million for pretax cash flows from operating activities. For a summary of EOG's financial commodity derivative contracts through February 18, 2021, see ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Commodity Derivative Transactions. For a summary of EOG's financial commodity derivative contracts for the twelve months ended December 31, 2020, see Note 12 to Consolidated Financial Statements.

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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 18, 2021, see ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations ‑ Capital Resources and Liquidity - Commodity Derivative Transactions.

All of EOG's crude oil, NGL and natural gas activities are subject to the risks normally incident to the exploration for, and development, production and transportation of, crude oil, NGL 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, flooding and other adverse weather events. Moreover, EOG's activities are subject to governmental regulations as well as interruption or termination by governmental authorities based on environmental and other considerations. Losses and liabilities arising from such events could reduce EOG's revenues and increase costs to EOG to the extent not covered by insurance.

Insurance is maintained by EOG against 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, in the event an incident involving EOG's operations 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 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 25, 2021) are as follows:

Name	Age	Position
William R. Thomas	68	Chairman of the Board and Chief Executive Officer
Lloyd W. Helms, Jr.	63	Chief Operating Officer
Ezra Y. Yacob	44	President
Kenneth W. Boedeker	58	Executive Vice President, Exploration and Production
Timothy K. Driggers	59	Executive Vice President and Chief Financial Officer
Michael P. Donaldson	58	Executive Vice President, General Counsel and Corporate Secretary

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William R. Thomas was elected Chairman of the Board and Chief Executive Officer effective January 2014. He was elected Senior Vice President and General Manager of EOG's Fort Worth, Texas, office in June 2004, Executive Vice President and General Manager of EOG's Fort Worth, Texas, office in February 2007 and Senior Executive Vice President, Exploitation in February 2011. He subsequently served as Senior Executive Vice President, Exploration from July 2011 to September 2011, as President from September 2011 to July 2013 and as President and Chief Executive Officer from July 2013 to December 2013. Mr. Thomas joined a predecessor of EOG in January 1979. Mr. Thomas is EOG's principal executive officer.

Lloyd W. Helms, Jr. was elected Chief Operating Officer in December 2017. Prior to that, he served 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.

Ezra Y. Yacob was elected President effective January 2021. Prior to that, he served as Executive Vice President, Exploration and Production from December 2017 to January 2021 and as 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.

Kenneth W. Boedeker was elected Executive Vice President, Exploration and Production in December 2018.  He served as Vice President and General Manager of EOG's Denver, Colorado, office from October 2016 to December 2018, and as Vice President, Engineering and Acquisitions from July 2015 to October 2016.  Prior to that, Mr. Boedeker held technical and managerial positions of increasing responsibility across multiple offices and functional areas within EOG.  Mr. Boedeker joined EOG in July 1994.

Timothy K. Driggers was elected Executive Vice President and Chief Financial Officer in April 2016. Previously, Mr. Driggers served as Vice President and Chief Financial Officer from July 2007 to April 2016. He was elected Vice President and Controller of EOG in October 1999, was subsequently named Vice President, Accounting and Land Administration in October 2000 and Vice President and Chief Accounting Officer in August 2003. Mr. Driggers is EOG's principal financial officer. Mr. Driggers joined a predecessor of EOG in August 1995.

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

ITEM 1A. Risk Factors

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

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

Crude oil, natural gas and NGL 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 crude oil, NGLs and natural gas;

•domestic and international drilling activity;

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

•consumer and industrial/commercial demand for crude oil, natural gas and NGLs;

•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 ongoing COVID-19 pandemic;

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

•the nature and extent of governmental regulation, including any changes or other actions which may result from the recent elections in the United States of America (United States or U.S.) and change in administration, and including environmental and other climate change-related regulation, regulation of derivatives 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

•weather conditions and changes in weather patterns.

In the first half of 2020, the prices for crude oil, NGLs and natural gas declined substantially as a result of the economic downturn and overall reduction of demand prompted by the COVID-19 pandemic and the oversupply of crude oil from certain foreign oil-exporting countries. In the second half of 2020, (i) the prices for NGLs and natural gas recovered to pre-pandemic levels and (ii) the prices for crude oil increased but remain significantly below pre-pandemic levels.

The above-described factors and the volatility of commodity prices make it difficult to predict crude oil, NGLs and natural gas prices in 2021 and thereafter. As a result, there can be no assurance that the prices for crude oil, NGLs and/or natural gas will continue to increase from, or sustain, their current levels, nor can there be any assurance that the prices for crude oil, NGLs and/or natural gas will not again decline.

Our cash flows 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 expenses, the terms on which we can access the credit and capital markets and our results of operations.

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 proved 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.

In fact, the substantial declines in crude oil, NGLs and natural gas prices that occurred in the first half of 2020 materially and adversely affected the amount of cash flows we had available for our 2020 capital expenditures and operating expenses, our results of operations during the first half of 2020 and the trading price of our common stock. Such commodity price declines also resulted in aggregate impairment charges of approximately $1.8 billion in the first half of 2020 with respect to our proved oil and gas properties and related assets. Such declines in commodity prices also resulted in our making a downward adjustment of 278 million barrels of oil equivalent to our estimated net proved reserves at December 31, 2020.

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If commodity prices decline from current levels for an extended period of time, our financial condition, cash flows and results of operations will be adversely affected and we may be limited in our ability to maintain our current level of dividends on our common stock. In addition, we may be required to incur additional impairment charges and/or make additional downward adjustments to our proved reserve estimates. As a result, our financial condition and results of operations and the trading price of our common stock may be materially and adversely affected.

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

We make, and will continue to make, substantial capital expenditures for the acquisition, exploration, development, production and transportation of crude oil, NGLs and natural gas reserves. We intend to finance our capital expenditures primarily through our cash flows from operations and sales of non-core assets and, to a lesser extent and if and as necessary, commercial paper borrowings, bank borrowings, borrowings under our revolving credit facility and public and private equity and debt offerings.

Lower crude oil, NGLs and natural gas prices, however, reduce our cash flows and could also delay or impair our ability to consummate certain planned non-core asset sales and 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 equity or debt offerings or other borrowings.

Similarly, a reduction in our cash flows (for example, as a result of lower crude oil, natural gas and/or NGLs 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.

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.

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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 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 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 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.

We use 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. A portion of our forecasted production for 2021 and 2022 is subject to fluctuating market prices. If we are ultimately unable to hedge additional production volumes for 2021, 2022 and beyond, we may be materially and adversely impacted by any declines in commodity prices, which may result in lower net cash provided by 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 the unavailability of required facilities or equipment due to mechanical failure or market conditions. 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 and refining facilities; or market or other factors and conditions.

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

Risks Related to our Operations

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

Drilling crude oil and natural gas wells, 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 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;

•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;

•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 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, 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 operations or those of our third-party operators, and/or curtailments, delays or cancellations of our drilling 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 and transporting, crude oil 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;

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•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;

•fires and explosions;

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

•formations with abnormal or unexpected pressures;

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

•malfunctions of, or damage to, gathering, processing, compression and transportation 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.

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 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 and export facilities and equipment owned by third parties. These facilities and equipment may be temporarily unavailable to us due to market conditions, 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 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 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 rail 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 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.

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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 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.

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 and results of operations.

If we acquire crude oil, NGLs and natural gas properties, our failure to fully identify existing and potential problems, 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 - for example, our October 2016 mergers and related asset purchase transactions with Yates Petroleum Corporation and certain of its affiliated entities. 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 problems (such as title 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 problems 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 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 business 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 Our International Operations

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

•changes in laws and policies governing operations of foreign-based companies;

•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; 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 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, 2020, less than 1% of our net operating revenues related to operations of our foreign subsidiaries whose functional currency was not the U.S. dollar.

Risks Related to Regulatory and Legal Matters

The regulatory, legislative and policy changes pursued by the new U.S. presidential administration may materially and adversely affect the oil and gas exploration and production industry.

In November 2020, Joseph R. Biden Jr. was elected President of the United States. New or revised rules, regulations and policies may be issued, and new legislation may be proposed, during the current administration 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 federal lands, (ii) the leasing of federal lands for oil and gas development, (iii) the regulation 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 federal lands, (v) the calculation of royalty payments in respect of oil and gas production from federal lands and (vi) U.S. federal income tax laws applicable to oil and gas exploration and production companies. On January 27, 2021, President Biden issued Executive Order 14008 entitled “Tackling the Climate Crisis at Home and Abroad,” directing the Secretary of the Interior, to the extent consistent with applicable law and in consultation with other agencies and stakeholders, to (i) pause approval of new oil and natural gas leases on federal lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices and (ii) consider whether to adjust royalties associated with oil and gas resources extracted from federal lands and offshore waters to account for corresponding climate costs.

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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 and financial condition.

For related discussion, see the below risk factors regarding legislative and regulatory matters impacting the oil and gas exploration and production industry.

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 and financial condition, including any changes that may result from the recent U.S. elections and change in administration (see the risk factor above with respect to the new U.S. administration).

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, including any changes that may result from the recent U.S. elections and change in administration, could lead to increased operating and compliance costs and, in turn, materially and adversely affect our business, results of operations and financial condition.

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. In addition, there were proposals and positions taken by President Biden during his campaign regarding the use of hydraulic fracturing on federal lands and waters. Further, on January 27, 2021, President Biden issued Executive Order 14008 entitled "Tackling the Climate Crisis at Home and Abroad," directing the Secretary of the Interior, to the extent consistent with applicable law and in consultation with other agencies and stakeholders, to, among other things, pause approval of new oil and natural gas leases on federal lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices.

Any such requirements, restrictions, conditions or prohibition 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 and financial condition. 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 derivatives transactions and entities (such as EOG) that participate in such transactions.

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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. 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.

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 on November 4, 2016. While the U.S. withdrew from the Paris Agreement on November 4, 2020, President Biden issued an executive order on January 20, 2021 recommitting the United States to the Paris Agreement. In addition, many state and local officials have stated their intent to intensify efforts to uphold the commitments set forth in the international accord. Further, on January 27, 2021, President Biden issued Executive Order 14008 entitled 'Tackling the Climate Crisis at Home and Abroad,' directing the Secretary of the Interior, to the extent consistent with applicable law and in consultation with other agencies and stakeholders, to, among other things, consider whether to adjust royalties associated with oil and gas resources extracted from federal lands and offshore waters to account for corresponding climate costs.

It is possible that the Paris Agreement and subsequent domestic and international regulations and government policies will have adverse effects on the market for crude oil, natural gas and other fossil fuel products as well as adverse effects on the business and operations of companies engaged in the exploration for, and production of, crude oil, natural gas and other fossil fuel products. 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. by the new administration), but the direct and indirect costs of such developments (if enacted, issued or applied) could materially and adversely affect our operations, financial condition and results of operations. 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. For additional discussion regarding climate change regulation, see (i) Climate Change - United States under ITEM 1, Business – Regulation and (ii) the risk factor above with respect to the new U.S. administration.

In addition, the achievement of our current or future internal initiatives relating to the reduction of GHG emissions may increase our costs, including requiring us to purchase emissions credits or offsets, or may impact or otherwise limit our ability to execute on our business plans.

Further, 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.

Tax laws and regulations applicable to crude oil and natural gas exploration and production companies may change over time, and such changes could materially and adversely affect our 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 income tax laws applicable to crude oil and natural gas exploration and production companies, such as with respect to the intangible drilling and development costs deduction and bonus tax depreciation. While these specific changes were not included in the Tax Cuts and Jobs Act signed into law in December 2017, no accurate prediction can be made as to whether any such legislative changes or similar or other tax law changes will be proposed in the future (for example, by the new U.S. administration) and, if enacted, what the specific provisions or the effective date of any such legislation would be. The elimination of certain U.S. federal income tax deductions, as well as any other changes to, or the imposition of new, federal, state, local or non-U.S. taxes (including the imposition of, or increases in, production, severance or similar taxes), could materially and adversely affect our 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 would generally increase the prices for crude oil, natural gas and NGLs. Such price increases may, in turn, reduce demand for crude oil, natural gas and NGLs and materially and adversely affect our cash flows, results of operations and financial condition.

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

Federal legislation and related regulations regarding derivatives transactions could have a material and adverse impact on our hedging activities.

As discussed in the risk factor above regarding our hedging activities, we use derivative instruments to hedge the impact of fluctuations in crude oil, NGLs and natural gas prices on our results of operations and cash flows. In 2010, Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), which, among other matters, provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market and mandates that the Commodity Futures Trading Commission (CFTC), the U.S. Securities and Exchange Commission (SEC) and certain federal agencies that regulate the banking and insurance sectors (the Prudential Regulators) adopt rules or regulations implementing the Dodd-Frank Act and providing definitions of terms used in the Dodd-Frank Act. The Dodd-Frank Act establishes margin requirements and requires clearing and trade execution practices for certain categories of swaps and may result in certain market participants needing to curtail their derivatives activities. Although some of the rules necessary to implement the Dodd-Frank Act are yet to be adopted, the CFTC, the SEC and the Prudential Regulators have issued numerous rules, including a rule establishing an “end-user” exception to mandatory clearing (End-User Exception), a rule regarding margin for uncleared swaps (Margin Rule) and a proposed rule imposing position limits (Position Limits Rule).

We qualify as a "non-financial entity" for purposes of the End-User Exception and, as such, we are eligible for such exception. As a result, our hedging activities are not subject to mandatory clearing or the margin requirements imposed in connection with mandatory clearing. We also qualify as a "non-financial end user" for purposes of the Margin Rule; therefore, our uncleared swaps are not subject to regulatory margin requirements. Finally, we believe our hedging activities would constitute bona fide hedging under the Position Limits Rule and would not be subject to limitation under such rule if it is enacted. However, many of our hedge counterparties and many other market participants are not eligible for the End-User Exception, are subject to mandatory clearing and the Margin Rule for swaps with some or all of their other swap counterparties, and may be subject to the Position Limits Rule. In addition, the European Union and other non-U.S. jurisdictions have enacted laws and regulations related to derivatives (collectively, Foreign Regulations) which apply to our transactions with counterparties subject to such Foreign Regulations.

The Dodd-Frank Act, the rules adopted thereunder and the Foreign Regulations could increase the cost of derivative contracts, alter the terms of derivative contracts, reduce the availability of derivatives to protect against the price risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, lessen the number of available counterparties and, in turn, increase our exposure to less creditworthy counterparties. If our use of derivatives is reduced as a result of the Dodd-Frank Act, related regulations or the Foreign Regulations, our results of operations may become more volatile, and our cash flows may be less predictable, which could adversely affect our ability to plan for, and fund, our capital expenditure requirements. Any of these consequences could have a material and adverse effect on our business, financial condition and results of operations.

Risks Related to COVID-19, Cybersecurity and Other External Factors

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, natural gas and NGLs, 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, natural gas and NGL prices.

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For example, the current pandemic involving a highly transmissible and pathogenic coronavirus (COVID-19) and the measures being taken to address and limit the spread of the virus have adversely affected the economies and financial markets of the world, resulting in an economic downturn that has negatively impacted, and may continue to negatively impact, global demand and prices for crude oil, natural gas and NGLs. In fact, the substantial declines in crude oil, natural gas and NGL prices that occurred in the first half of 2020 as a result of the economic downturn and overall reduction of demand prompted by the COVID-19 pandemic (and the oversupply of crude oil from certain foreign oil-exporting countries) materially and adversely affected the amount of cash flows we had available for our 2020 capital expenditures and other operating expenses, our results of operations during the first half of 2020 and the trading price of our common stock.

While in the second half of 2020 the prices for natural gas and NGLs recovered to pre-pandemic levels and the prices for crude oil increased from their first half 2020 levels, if such price declines were to reoccur and continue for an extended period of time, our cash flows and results of operations would be further adversely affected, as could the trading price of our common stock. For further discussion regarding the potential impacts on us of lower commodity prices and extended declines in commodity prices, see the related discussion in the first risk factor in this section.

Further, if the COVID-19 outbreak should continue or worsen, we may also 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 the resulting economic downturn should continue or worsen, 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 are still too many variables and uncertainties regarding the COVID-19 pandemic, including the duration and severity of the outbreak and the extent of travel restrictions and business closures imposed in affected countries, to fully assess the potential impact on our business, financial condition and results of operations.

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 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, transportation, pipelines and other related activities and (iv) communicate with our employees and vendors, suppliers and other third parties. 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 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 and refining 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 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 attacks in the past, we have not suffered any losses as a result of such attacks; however, there is no assurance that we will not suffer such 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, which could require us to expend significant additional resources to meet such requirements.

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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 and natural gas, increased volatility in crude oil 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 in the Gulf of Mexico, 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, transportation and/or export facilities and the availability of, and our access to, necessary third-party services, such as gathering, processing, compression, storage and transportation services and export services. 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.

ITEM 1B.  Unresolved Staff Comments

Not applicable.

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 proved 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."

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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 proved reserves, conducts successful exploration, exploitation and development activities or, through engineering studies, identifies additional behind-pipe zones or secondary recovery reserves, the proved 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, 2020. Excluded is acreage in which EOG's interest is limited to owned royalty, overriding royalty and other similar interests.

	Developed		Undeveloped		Total
	Gross	Net	Gross	Net	Gross	Net
United States	2,528,907	1,887,080	2,871,470	1,983,209	5,400,377	3,870,289
Trinidad	79,410	67,580	201,302	115,168	280,712	182,748
China	130,548	130,548	—	—	130,548	130,548
Canada	30,771	27,513	19,197	19,197	49,968	46,710
Oman	—	—	8,400,348	7,828,089	8,400,348	7,828,089
Total	2,769,636	2,112,721	11,492,317	9,945,663	14,261,953	12,058,384

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 0.2 million net acres will expire in 2021, 0.2 million net acres will expire in 2022 and 0.1 million net acres will expire in 2023 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, 2020, there were no proved undeveloped reserves (PUDs) associated with such undeveloped acreage. 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 Oman is set to expire in 2024, with certain provisions allowing for extension of such term if commercial discoveries are found.

Productive Well Summary. The following table represents EOG's gross and net productive wells, including 2,482 wells in which we hold a royalty interest.

	Crude Oil		Natural Gas		Total
	Gross	Net	Gross	Net	Gross	Net
United States	9,658	6,724	3,985	1,942	13,643	8,666
Trinidad	2	1	33	27	35	28
China	—	—	36	36	36	36
Canada	—	—	1	—	1	—
Total (1)	9,660	6,725	4,055	2,005	13,715	8,730

(1)    EOG operated 9,491 gross and 8,394 net producing crude oil and natural gas wells at December 31, 2020. Gross crude oil and natural gas wells include 142 wells with multiple completions.

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Drilling and Acquisition Activities.  During the years ended December 31, 2020, 2019 and 2018, EOG expended $3.7 billion, $6.6 billion and $6.4 billion, respectively, for exploratory and development drilling, facilities and acquisition of leases and producing properties, including asset retirement obligations of $117 million, $186 million and $70 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, 2020, 2019 and 2018:

	Gross Development Wells Completed				Gross Exploratory Wells Completed
	Crude Oil	Natural Gas	Dry Hole	Total	Crude Oil	Natural Gas	Dry Hole	Total
2020
United States	580	13	15	608	3	—	4	7
Trinidad	—	—	—	—	—	3	—	3
China	—	—	—	—	—	—	—	—
Total	580	13	15	608	3	3	4	10
2019
United States	833	26	14	873	4	—	1	5
Trinidad	—	1	—	1	—	—	1	1
China	—	2	—	2	—	—	1	1
Total	833	29	14	876	4	—	3	7
2018
United States	834	39	22	895	—	—	1	1
Trinidad	—	—	—	—	—	—	—	—
China	—	1	—	1	—	2	—	2
Total	834	40	22	896	—	2	1	3

The following tables set forth the results of the net crude oil and natural gas wells completed for the years ended December 31, 2020, 2019 and 2018:

	Net Development Wells Completed				Net Exploratory Wells Completed
	Crude Oil	Natural Gas	Dry Hole	Total	Crude Oil	Natural Gas	Dry Hole	Total
2020
United States	516	12	15	543	2	—	3	5
Trinidad	—	—	—	—	—	2	—	2
China	—	—	—	—	—	—	—	—
Total	516	12	15	543	2	2	3	7
2019
United States	721	22	12	755	4	—	1	5
Trinidad	—	1	—	1	—	—	1	1
China	—	2	—	2	—	—	1	1
Total	721	25	12	758	4	—	3	7
2018
United States	704	37	18	759	—	—	1	1
Trinidad	—	—	—	—	—	—	—	—
China	—	1	—	1	—	2	—	2
Total	704	38	18	760	—	2	1	3

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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, 2020, 2019 and 2018:

	Wells in Progress at End of Period
	2020		2019		2018
	Gross	Net	Gross	Net	Gross	Net
United States	155	147	317	286	297	238
Trinidad	1	1	1	1	—	—
China	3	3	3	3	4	4
Oman	1	1	—	—	—	—
Total	160	152	321	290	301	242

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, 2020, there were approximately 84 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
	2020		2019		2018
	Gross	Net	Gross	Net	Gross	Net
United States	89	86	188	165	168	137
China	3	3	3	3	3	3
Total	92	89	191	168	171	140

EOG acquired wells as set forth in the following tables as of the end of each period (excluding the acquisition of additional interests in 8, 11 and 114 net wells in which EOG previously owned an interest for the years ended December 31, 2020, 2019 and 2018, respectively):

	Gross Acquired Wells			Net Acquired Wells
	Crude Oil	Natural Gas	Total	Crude Oil	Natural Gas	Total
2020
United States	80	3	83	70	3	73
Total	80	3	83	70	3	73
2019
United States	9	45	54	9	37	46
Total	9	45	54	9	37	46
2018
United States	15	13	28	10	6	16
Total	15	13	28	10	6	16

Other Property, Plant and Equipment. EOG's other property, plant and equipment primarily includes gathering, transportation and processing infrastructure assets, buildings and sand processing assets which support EOG's exploration and production activities. 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. 

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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 recent amendments to this item, EOG will be using 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. Applying this threshold, there are no environmental proceedings to disclose for the quarter and year ended December 31, 2020.

ITEM 4.  Mine Safety Disclosures

The information concerning mine safety violations and other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95 to this report.

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 12, 2021, there were approximately 2,060 record holders and approximately 321,000 beneficial owners of EOG's common stock.

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 Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs (2)
October 1, 2020 - October 31, 2020	3,892	$	34.56	—	6,386,200
November 1, 2020 - November 30, 2020	3,678	41.84		—	6,386,200
December 1, 2020 - December 31, 2020	19,548	52.21		—	6,386,200
Total	27,118	$	48.27

(1)The 27,118 total shares for the quarter ended December 31, 2020, and the 389,613 total shares for the full year 2020, consist solely of 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 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.  These shares do not count against the 10 million aggregate share repurchase authorization of EOG's Board discussed below.

(2)In September 2001, the Board authorized the repurchase of up to 10,000,000 shares of EOG's common stock.  During 2020, EOG did not repurchase any shares under the Board-authorized repurchase program. EOG last repurchased shares under this program in March 2003.

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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 on EOG's common stock as compared to the cumulative five-year total returns on 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, 2015 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, 2020)

	2015		2016		2017		2018		2019		2020
EOG	$	100.00	$	144.04	$	154.79	$	125.91	$	122.37	$	74.85
S&P 500	$	100.00	$	111.96	$	136.40	$	130.42	$	171.49	$	203.05
S&P O&G E&P	$	100.00	$	132.83	$	124.46	$	100.19	$	112.23	$	73.61

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ITEM 6.  Selected Financial Data

(In Thousands, Except Per Share Data)

    The following selected consolidated financial information should be read in conjunction with ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations and ITEM 8, Financial Statements and Supplementary Data.

Year Ended December 31	2020		2019		2018		2017		2016
Statement of Income Data:
Operating Revenues and Other (1)	$	11,032,048	$	17,379,973	$	17,275,399	$	11,208,320	$	7,650,632
Operating Income (Loss)	$	(544,016)	$	3,699,011	$	4,469,346	$	926,402	$	(1,225,281)
Net Income (Loss)	$	(604,572)	$	2,734,910	$	3,419,040	$	2,582,579	$	(1,096,686)
Net Income (Loss) Per Share
Basic	$	(1.04)	$	4.73	$	5.93	$	4.49	$	(1.98)
Diluted	$	(1.04)	$	4.71	$	5.89	$	4.46	$	(1.98)
Dividends Per Common Share	$	1.50	$	1.0825	$	0.81	$	0.67	$	0.67
Average Number of Common Shares
Basic	578,949		577,670		576,578		574,620		553,384
Diluted	578,949		580,777		580,441		578,693		553,384

At December 31	2020		2019		2018		2017		2016
Balance Sheet Data:
Total Property, Plant and Equipment, Net	$	28,598,627	$	30,364,595	$	28,075,519	$	25,665,037	$	25,707,078
Total Assets (2) (3) (4)	35,804,601		37,124,608		33,934,474		29,833,078		29,299,201
Total Debt	5,816,405		5,175,443		6,083,262		6,387,071		6,986,358
Total Stockholders' Equity	20,301,887		21,640,716		19,364,188		16,283,273		13,981,581

(1)    Effective January 1, 2018, EOG adopted the provisions of Accounting Standards Update (ASU) 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements within its United States segment as Gathering and Processing Costs instead of as a deduction to Natural Gas Revenues. There was no impact to operating income, net income or cash flows resulting from changes to the presentation of natural gas processing fees. EOG elected to adopt ASU 2014-09 using the modified retrospective approach with no reclassification of amounts for the years ended December 31, 2017 and 2016 (see Note 1 to Consolidated Financial Statements).

(2)    Effective January 1, 2020, EOG adopted the provisions of ASU 2016-13, "Measurement of Credit Losses on Financial Instruments" (ASU 2016-13). ASU 2016-13 changes the impairment model for financial assets and certain other instruments by requiring entities to adopt a forward-looking expected loss model that will result in earlier recognition of credit losses. EOG elected to adopt ASU 2016-13 using the modified retrospective approach with a cumulative-effect adjustment to retained earnings as of the effective date. Financial results reported in periods prior to January 1, 2020, are unchanged. There was no impact to retained earnings upon adoption of ASU 2016-13 and EOG expects current and future credit losses to be immaterial. EOG continues to monitor the credit risk from third-party companies to determine if expected credit losses may become material.

(3)    Effective January 1, 2019, EOG adopted the provisions of ASU 2016-02, "Leases (Topic 842)" (ASU 2016-02), which require that lessees recognize a right-of-use (ROU) asset and related lease liability, representing the obligation to make lease payments of certain lease transactions, on the Consolidated Balance Sheets. EOG elected to adopt ASU 2016-02 and other related ASUs using the modified retrospective approach with a cumulative-effect adjustment to the opening balance of retained earnings as of the effective date. Financial results reported in periods prior to January 1, 2019, are unchanged. There was no impact to retained earnings upon adoption of ASU 2016-02 and other related ASUs. See Notes 1 and 18 to Consolidated Financial Statements.

(4)    Effective January 1, 2017, EOG adopted the provisions of ASU 2015-17, "Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes" (ASU 2015-17), which simplifies the presentation of deferred taxes in a classified balance sheet by eliminating the requirement to separate deferred income tax liabilities and assets into current and noncurrent amounts. Instead, ASU 2015-17 requires that all deferred tax liabilities and assets be shown as noncurrent in a classified balance sheet. In connection with the adoption of ASU 2015-17, EOG restated $160 million from deferred tax liabilities to deferred tax assets on its Consolidated Balance Sheet at December 31, 2016.

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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 with proved reserves in the United States, Trinidad and China.  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 and capital costs 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 deliver long-term growth in shareholder value and maintain a strong balance sheet.  EOG implements its strategy primarily by emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves.  Maintaining the lowest possible operating cost structure, coupled with efficient and safe operations and robust environmental stewardship practices and performance, is integral in the implementation of EOG's strategy.

EOG realized a net loss of $605 million during 2020 as compared to net income of $2,735 million for 2019. At December 31, 2020, EOG's total estimated net proved reserves were 3,220 million barrels of oil equivalent (MMBoe), a decrease of 109 MMBoe from December 31, 2019.  During 2020, net proved crude oil and condensate and natural gas liquids (NGLs) reserves decreased by 108 million barrels (MMBbl), and net proved natural gas reserves decreased by 9 billion cubic feet or 1 MMBoe, in each case from December 31, 2019.

Recent Developments

Commodity Prices. The COVID-19 pandemic and the measures being taken to address and limit the spread of the virus have adversely affected the economies and financial markets of the world, resulting in an economic downturn that has negatively impacted, and may continue to negatively impact, global demand and prices for crude oil and condensate, NGLs and natural gas. See ITEM 1A, Risk Factors for further discussion.

In early March 2020, due to the failure of the members of the Organization of the Petroleum Exporting Countries and Russia (OPEC+) to reach an agreement on individual crude oil production limits, Saudi Arabia unilaterally reduced the sales price of its crude oil and announced that it would increase its crude oil production. The combination of these actions, and the effects of the COVID-19 pandemic on crude oil demand, resulted in significantly lower commodity prices in March and April 2020. In April 2020, the members of OPEC+ reached an agreement to cut crude oil production beginning in May 2020 and extending through April 2022 with the quantity of the production cuts decreasing over time. Subsequent indications of conformity with these agreed-upon production cuts by OPEC+, combined with the evolving impacts of COVID-19 on crude oil demand, have resulted in gradually-improving market conditions. In the second half of 2020, crude oil prices increased, but remain significantly below average prices in 2019, as a result of the continuing rebalancing of crude oil supply resulting from the actions of OPEC+ and the continuing effect of the COVID-19 pandemic on global demand. In addition, NGL and natural gas prices have recovered to pre-pandemic levels.

In response to the commodity price environment in 2020, EOG reduced activity across its operating areas and decreased its total capital expenditures. EOG also elected to reduce crude oil production, by delaying initial production from new wells and shutting-in or otherwise curtailing existing production.

In early 2021, the members of OPEC+ met and agreed to taper off certain of their production curtailments (agreed to in April 2020) through March 2021. Subsequent to the meeting, Saudi Arabia announced that it would unilaterally cut its production by an additional one million barrels per day in February 2021 and March 2021. These announcements have had a positive impact on crude oil prices.

As a result of the many uncertainties associated with (i) the world economic environment, (ii) the COVID-19 pandemic and its continuing effect on the economies and financial markets of the world and (iii) any future actions by the members of OPEC+, and the effect of these uncertainties on worldwide supplies of, and demand for, crude oil and condensate, NGLs and natural gas, EOG is unable to predict what changes may occur in crude oil and condensate, NGLs and natural gas prices in the future. However, prices for crude oil and condensate, NGLs and natural gas have historically been volatile, and this volatility is expected to continue. For related discussion, see ITEM 1A, Risk Factors.

EOG will continue to monitor future market conditions and adjust its capital allocation strategy and production outlook accordingly in order to maximize shareholder value while maintaining its strong financial position.

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2020 Election. In November 2020, Joseph R. Biden Jr. was elected President of the United States. On January 27, 2021, President Biden issued Executive Order 14008 entitled "Tackling the Climate Crisis at Home and Abroad," directing the Secretary of the Interior, to the extent consistent with applicable law and in consultation with other agencies and stakeholders, to (i) pause approval of new oil and natural gas leases on federal lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices and (ii) consider whether to adjust royalties associated with oil and gas resources extracted from federal lands and offshore waters to account for corresponding climate costs. In addition, new or revised rules, regulations and policies may be issued, and new legislation may be proposed, during the current administration 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 federal lands, (ii) the leasing of federal lands for oil and gas development, (iii) the regulation of greenhouse gas emissions and/or other climate change-related matters associated with oil and gas operations, (iv) the use of hydraulic fracturing on federal lands, (v) the calculation of royalty payments in respect of oil and gas production from federal lands and (vi) U.S. federal income tax laws applicable to oil and gas exploration and production companies. See "Regulation" in ITEM 1, Business and ITEM 1A, Risk Factors for further discussion.

EOG will continue to monitor and assess any actions that could impact 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, 2020.

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 liquids-rich reservoirs.

During 2020, EOG continued to focus on increasing drilling, completion and operating efficiencies gained in prior years. Such efficiencies, combined with new innovation and decreased service costs, resulted in lower operating, drilling and completion costs in 2020. 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 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 76% and 77% of United States production during 2020 and 2019, respectively. During 2020, 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. In the second quarter of 2020, EOG delayed initial production from most newly-completed wells and shut in some existing production. During the third quarter of 2020, EOG resumed the process of initiating production from completed wells, and the legacy wells that were shut-in were largely brought back on-line. See ITEM 1, Business - Exploration and Production for further discussion.

Trinidad. In Trinidad, EOG continues to deliver natural gas under existing supply contracts. Several fields in the South East Coast Consortium Block, Modified U(a) Block, Block 4(a), Modified U(b) Block, 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, and crude oil and condensate which is sold to Heritage Petroleum Company Limited.

In 2020, EOG drilled three net wells and completed two net wells in Trinidad. The remaining net well made a discovery that is being evaluated.

Other International. In the Sichuan Basin, Sichuan Province, China, EOG continues to work with its partner, PetroChina, under the Production Sharing Contract and other related agreements, to ensure uninterrupted production. All natural gas produced from the Baijaochang Field is sold under a long-term contract to PetroChina.

In 2020, EOG entered into two agreements related to exploration and production rights in the Sultanate of Oman (Oman). One agreement resulted in EOG acquiring exploration and production rights to Block 36 within Oman. The second agreement was a farm-in agreement allowing EOG to share in exploration and production rights within Block 49. Pursuant to that agreement, EOG participated in the drilling of one gross exploratory well which was in progress as of December 31, 2020.

In March 2020, EOG began the process of exiting its Canada operations.

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EOG continues to evaluate other select crude oil and natural gas opportunities outside the United States, primarily by pursuing exploitation 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 22% at December 31, 2020 and 19% at December 31, 2019.  As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

On April 1, 2020, EOG repaid upon maturity the $500 million aggregate principal amount of its 2.45% Senior Notes due 2020.

On April 14, 2020, EOG closed on its offering of $750 million aggregate principal amount of its 4.375% Senior Notes due 2030 and $750 million aggregate principal amount of its 4.950% Senior Notes due 2050 (together, the Notes). EOG received net proceeds of $1.48 billion from the issuance of the Notes, which were used to repay the 4.40% Senior Notes due 2020 when they matured on June 1, 2020 (see below), and for general corporate purposes, including the funding of capital expenditures.

On June 1, 2020, EOG repaid upon maturity the $500 million aggregate principal amount of its 4.40% Senior Notes due 2020.

On February 1, 2021, EOG repaid upon maturity the $750 million aggregate principal amount of its 4.100% Senior Notes due 2021.

During 2020, EOG funded $4.0 billion ($386 million of which was non-cash) in exploration and development and other property, plant and equipment expenditures (excluding asset retirement obligations), repaid $1.0 billion aggregate principal amount of long-term debt and paid $821 million in dividends to common stockholders, primarily by utilizing net cash provided from its operating activities, net proceeds of $1.48 billion from the issuance of the Notes and net proceeds of $192 million from the sale of assets.

Total anticipated 2021 capital expenditures are estimated to range from approximately $3.7 billion to $4.1 billion, excluding acquisitions and non-cash transactions. The majority of 2021 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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Results of Operations

The following review of operations for each of the three years in the period ended December 31, 2020, should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning on page F-1.

Operating Revenues and Other

During 2020, operating revenues decreased $6,348 million, or 37%, to $11,032 million from $17,380 million in 2019. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, decreased $4,291, or 37%, to $7,290 million in 2020 from $11,581 million in 2019. Revenues from the sales of crude oil and condensate and NGLs in 2020 were approximately 89% of total wellhead revenues compared to 90% in 2019. During 2020, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $1,145 million compared to net gains of $180 million in 2019. Gathering, processing and marketing revenues decreased $2,777 million during 2020, to $2,583 million from $5,360 million in 2019. Net losses on asset dispositions of $47 million in 2020 were primarily due to the sales of proved properties and non-cash property exchanges of unproved leasehold in Texas and New Mexico and the disposition of the Marcellus Shale assets compared to net gains on asset dispositions of $124 million in 2019.

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Wellhead volume and price statistics for the years ended December 31, 2020, 2019 and 2018 were as follows:

Year Ended December 31	2020		2019		2018
Crude Oil and Condensate Volumes (MBbld) (1)
United States	408.1		455.5		394.8
Trinidad	1.0		0.6		0.8
Other International (2)	0.1		0.1		4.3
Total	409.2		456.2		399.9
Average Crude Oil and Condensate Prices ($/Bbl) (3)
United States	$	38.65	$	57.74	$	65.16
Trinidad	30.20		47.16		57.26
Other International (2)	43.08		57.40		71.45
Composite	38.63		57.72		65.21
Natural Gas Liquids Volumes (MBbld) (1)
United States	136.0		134.1		116.1
Other International (2)	—		—		—
Total	136.0		134.1		116.1
Average Natural Gas Liquids Prices ($/Bbl) (3)
United States	$	13.41	$	16.03	$	26.60
Other International (2)	—		—		—
Composite	13.41		16.03		26.60
Natural Gas Volumes (MMcfd) (1)
United States	1,040		1,069		923
Trinidad	180		260		266
Other International (2)	32		37		30
Total	1,252		1,366		1,219
Average Natural Gas Prices ($/Mcf) (3)
United States	$	1.61	$	2.22	$	2.88
Trinidad	2.57		2.72		2.94
Other International (2)	4.66		4.44		4.08
Composite	1.83		2.38		2.92
Crude Oil Equivalent Volumes (MBoed) (4)
United States	717.5		767.8		664.7
Trinidad	30.9		44.0		45.1
Other International (2)	5.4		6.2		9.4
Total	753.8		818.0		719.2
Total MMBoe (4)	275.9		298.6		262.5

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

(2)Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.

(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.

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2020 compared to 2019. Wellhead crude oil and condensate revenues in 2020 decreased $3,827 million, or 40%, to $5,786 million from $9,613 million in 2019, due primarily to a lower composite average wellhead crude oil and condensate price ($2,860 million) and a decrease in production ($967 million). EOG's composite wellhead crude oil and condensate price for 2020 decreased 33% to $38.63 per barrel compared to $57.72 per barrel in 2019. Wellhead crude oil and condensate production in 2020 decreased 10% to 409 MBbld as compared to 456 MBbld in 2019. The decreased production was primarily in the Eagle Ford and the Rocky Mountain area, partially offset by increased production in the Permian Basin.

NGLs revenues in 2020 decreased $116 million, or 15%, to $668 million from $784 million in 2019 primarily due to a lower composite average wellhead NGLs price ($130 million), partially offset by an increase in production ($13 million). EOG's composite average wellhead NGLs price decreased 16% to $13.41 per barrel in 2020 compared to $16.03 per barrel in 2019. NGL production in 2020 increased 1% to 136 MBbld as compared to 134 MBbld in 2019. The increased production was primarily in the Permian Basin, partially offset by decreased production in the Eagle Ford.

Wellhead natural gas revenues in 2020 decreased $347 million, or 29%, to $837 million from $1,184 million in 2019, primarily due to a lower composite wellhead natural gas price ($251 million) and a decrease in natural gas deliveries ($96 million). EOG's composite average wellhead natural gas price decreased 23% to $1.83 per Mcf in 2020 compared to $2.38 per Mcf in 2019. Natural gas deliveries in 2020 decreased 8% to 1,252 MMcfd as compared to 1,366 MMcfd in 2019. The decrease in production was primarily due to lower natural gas volumes in Trinidad, the Marcellus Shale and the Rocky Mountain area, partially offset by increased production of associated natural gas from the Permian Basin.

During 2020, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $1,145 million, which included net cash received for settlements of crude oil, NGL and natural gas financial derivative contracts of $1,071 million. During 2019, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $180 million, which included net cash received for settlements of crude oil and natural gas financial derivative contracts of $231 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 transportation capacity with production in certain areas and to utilize excess capacity at EOG-owned facilities. EOG sells sand in order to balance the timing of firm purchase agreements with completion operations and to utilize excess capacity at EOG-owned facilities. Marketing costs represent the costs to purchase third-party crude oil, natural gas and sand and the associated transportation costs, as well as costs associated with EOG-owned sand sold to third parties.

Gathering, processing and marketing revenues less marketing costs in 2020 decreased $124 million compared to 2019, primarily due to lower margins on crude oil and condensate marketing activities. The margin on crude oil marketing activities in 2020 was negatively impacted by the price decline for crude oil in inventory awaiting delivery to customers and EOG's decision early in the second quarter of 2020 to reduce commodity price volatility by selling May and June 2020 deliveries under fixed price arrangements.

2019 compared to 2018. Wellhead crude oil and condensate revenues in 2019 increased $96 million, or 1%, to $9,613 million from $9,517 million in 2018, due primarily to an increase in production ($1,351 million); partially offset by a lower composite average wellhead crude oil and condensate price ($1,255 million). EOG's composite wellhead crude oil and condensate price for 2019 decreased 11% to $57.72 per barrel compared to $65.21 per barrel in 2018. Wellhead crude oil and condensate production in 2019 increased 14% to 456 MBbld as compared to 400 MBbld in 2018. The increased production was primarily in the Permian Basin and the Eagle Ford.

NGLs revenues in 2019 decreased $343 million, or 30%, to $784 million from $1,127 million in 2018 primarily due to a lower composite average wellhead NGLs price ($518 million), partially offset by an increase in production ($175 million). EOG's composite average wellhead NGLs price decreased 40% to $16.03 per barrel in 2019 compared to $26.60 per barrel in 2018. NGL production in 2019 increased 16% to 134 MBbld as compared to 116 MBbld in 2018. The increased production was primarily in the Permian Basin.

Wellhead natural gas revenues in 2019 decreased $118 million, or 9%, to $1,184 million from $1,302 million in 2018, primarily due to a lower composite wellhead natural gas price ($280 million), partially offset by an increase in natural gas deliveries ($162 million). EOG's composite average wellhead natural gas price decreased 18% to $2.38 per Mcf in 2019 compared to $2.92 per Mcf in 2018. Natural gas deliveries in 2019 increased 12% to 1,366 MMcfd as compared to 1,219 MMcfd in 2018. The increase in production was primarily due to higher deliveries in the United States resulting from increased production of associated natural gas from the Permian Basin and higher natural gas volumes in South Texas.

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During 2019, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $180 million, which included net cash received for settlements of crude oil and natural gas financial derivative contracts of $231 million. During 2018, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $166 million, which included net cash paid for settlements of crude oil and natural gas financial derivative contracts of $259 million.

Gathering, processing and marketing revenues less marketing costs in 2019 decreased $18 million compared to 2018, primarily due to lower margins on crude oil and condensate marketing activities, partially offset by higher margins on natural gas marketing activities.

Operating and Other Expenses

2020 compared to 2019.  During 2020, operating expenses of $11,576 million were $2,105 million lower than the $13,681 million incurred during 2019.  The following table presents the costs per barrel of oil equivalent (Boe) for the years ended December 31, 2020 and 2019:

	2020		2019
Lease and Well	$	3.85	$	4.58
Transportation Costs	2.66		2.54
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties	11.85		12.25
Other Property, Plant and Equipment	0.47		0.31
General and Administrative (G&A)	1.75		1.64
Net Interest Expense	0.74		0.62
Total (1)	$	21.32	$	21.94

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

The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, G&A and net interest expense for 2020 compared to 2019 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, salt 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 $1,063 million in 2020 decreased $304 million from $1,367 million in 2019 primarily due to lower operating and maintenance costs in the United States ($157 million) and in Canada ($25 million), lower workovers expenditures in the United States ($103 million) and lower lease and well administrative expenses in the United States ($12 million). Lease and well expenses decreased in the United States primarily due to decreased operating activities resulting from decreased production, efficiency improvements and service cost reductions.

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, 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.

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Transportation costs of $735 million in 2020 decreased $23 million from $758 million in 2019 primarily due to decreased transportation costs in the Fort Worth Basin Barnett Shale ($27 million), the Rocky Mountain area ($24 million) and the Eagle Ford ($20 million), partially offset by increased transportation costs in the Permian Basin ($56 million).

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

DD&A expenses in 2020 decreased $350 million to $3,400 million from $3,750 million in 2019.  DD&A expenses associated with oil and gas properties in 2020 were $390 million lower than in 2019 primarily due to a decrease in production in the United States ($222 million) and Trinidad ($22 million) and lower unit rates in the United States ($150 million). Unit rates in the United States decreased primarily due to upward reserve revisions and reserves added at lower costs as a result of increased efficiencies. DD&A expenses associated with other property, plant and equipment in 2020 were $40 million higher than in 2019 primarily due to an increase in expense related to gathering and storage assets and equipment.

G&A expenses of $484 million in 2020 decreased $5 million from $489 million in 2019 primarily due to decreased employee-related expenses ($43 million) and professional and other services ($7 million), partially offset by idle equipment and termination fees ($46 million).

Net interest expense of $205 million in 2020 was $20 million higher than 2019 primarily due to the issuance of the Notes in April 2020 ($51 million) and lower capitalized interest ($7 million), partially offset by repayment in June 2019 of the $900 million aggregate principal amount of 5.625% Senior Notes due 2019 ($21 million), repayment in June 2020 of the $500 million aggregate principal amount of 4.40% Senior Notes due 2020 ($13 million) and repayment in April 2020 of the $500 million aggregate principal amount of 2.45% Senior Notes due 2020 ($10 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 decreased $20 million to $459 million in 2020 compared to $479 million in 2019 primarily due to decreased operating costs in the Eagle Ford ($16 million) and decreased gathering and processing fees in the Eagle Ford ($9 million) and the Fort Worth Basin Barnett Shale ($5 million); partially offset by increased gathering and processing fees in the Permian Basin ($15 million).

Exploration costs of $146 million in 2020 increased $6 million from $140 million in 2019 primarily due to increased geological and geophysical expenditures in the United States ($15 million), partially offset by decreased general and administrative expenses in the United States ($8 million).

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 asset.  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.

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The following table represents impairments for the years ended December 31, 2020 and 2019 (in millions):

	2020		2019
Proved properties	$	1,268	$	207
Unproved properties	472		220
Other assets	300		91
Firm commitment contracts	60		—
Total	$	2,100	$	518

Impairments of proved properties were primarily due to the write-down to fair value of legacy and non-core natural gas and crude oil and combo plays in 2020 and legacy natural gas assets in 2019.

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 2020 decreased $322 million to $478 million (6.6% of wellhead revenues) from $800 million (6.9% of wellhead revenues) in 2019. The decrease in taxes other than income was primarily due to decreased severance/production taxes in the United States ($232 million), decreased ad valorem/property taxes in the United States ($51 million) and a state severance tax refund ($27 million).

Other income, net, was $10 million in 2020 compared to other income, net, of $31 million in 2019. The decrease of $21 million in 2020 was primarily due to a decrease in interest income.

In response to the economic impacts of the COVID-19 pandemic, the President of the United States signed the Coronavirus Aid, Relief, and Economic Security Act (the CARES Act) into law on March 27, 2020. The CARES Act provides economic support to individuals and businesses through enhanced loan programs, expanded unemployment benefits, and certain payroll and income tax relief, among other provisions.  The primary tax benefit of the CARES Act for EOG was the acceleration of approximately $150 million of additional refundable alternative minimum tax (AMT) credits into tax year 2019.  These credits originated from AMT paid by EOG in years prior to 2018 and were reflected as a deferred tax asset and a non-current receivable as of December 31, 2019 since they had been expected to either offset future current tax liabilities or be refunded on a declining balance schedule through 2021. The $150 million of additional refundable AMT credits was received in July 2020.

Further pandemic relief was contained in the Consolidated Appropriations Act of 2021 (the CA Act) which was signed into law by the President of the United States on December 27, 2020. In addition, the CA Act provided government funding and limited corporate income tax relief primarily related to making permanent or extending certain tax provisions, none of which were a material benefit for EOG.

EOG recognized an income tax benefit of $135 million in 2020 compared to an income tax provision of $810 million in 2019, primarily due to decreased pretax income. The net effective tax rate for 2020 decreased to 18% from 23% in 2019. The lower effective tax rate is mostly due to taxes attributable to EOG's foreign operations and increased stock-based compensation tax deficiencies.

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2019 compared to 2018.  During 2019, operating expenses of $13,681 million were $875 million higher than the $12,806 million incurred during 2018.  The following table presents the costs per Boe for the years ended December 31, 2019 and 2018:

	2019		2018
Lease and Well	$	4.58	$	4.89
Transportation Costs	2.54		2.85
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties	12.25		12.65
Other Property, Plant and Equipment	0.31		0.44
General and Administrative (G&A)	1.64		1.63
Net Interest Expense	0.62		0.93
Total (1)	$	21.94	$	23.39

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

The primary factors impacting the cost components of per-unit rates of lease and well, transportation costs, DD&A, G&A and net interest expense for 2019 compared to 2018 are set forth below.  See "Operating Revenues and Other" above for a discussion of production volumes.

Lease and well expenses of $1,367 million in 2019 increased $84 million from $1,283 million in 2018 primarily due to higher operating and maintenance costs ($76 million) and higher lease and well administrative expenses ($29 million) in the United States, partially offset by lower operating and maintenance costs in the United Kingdom ($15 million) due to the sale of operations in the fourth quarter of 2018 and in Canada ($11 million). Lease and well expenses increased in the United States primarily due to increased operating activities resulting in increased production.

Transportation costs of $758 million in 2019 increased $11 million from $747 million in 2018 primarily due to increased transportation costs in the Permian Basin ($91 million) and South Texas ($11 million), partially offset by decreased transportation costs in the Eagle Ford ($77 million) and the Fort Worth Basin Barnett Shale ($13 million).

DD&A expenses in 2019 increased $315 million to $3,750 million from $3,435 million in 2018.  DD&A expenses associated with oil and gas properties in 2019 were $337 million higher than in 2018 primarily due to an increase in production in the United States ($489 million), partially offset by lower unit rates in the United States ($119 million) and the sale of the United Kingdom operations in the fourth quarter of 2018 ($33 million). Unit rates in the United States decreased primarily due to upward reserve revisions and reserves added at lower costs as a result of increased efficiencies.

G&A expenses of $489 million in 2019 increased $62 million from $427 million in 2018 primarily due to increased employee-related expenses ($48 million) and increased information systems costs ($8 million) resulting from expanded operations.

Net interest expense of $185 million in 2019 was $60 million lower than 2018 primarily due to repayment of the $900 million aggregate principal amount of 5.625% Senior Notes due 2019 in June 2019 ($30 million) and the $350 million aggregate principal amount of 6.875% Senior Notes due 2018 in October 2018 ($18 million) and an increase in capitalized interest ($14 million).

Gathering and processing costs increased $42 million to $479 million in 2019 compared to $437 million in 2018 primarily due to increased operating costs and fees in the Permian Basin ($52 million), the Rocky Mountain area ($13 million) and South Texas ($5 million); partially offset by decreased operating costs in the United Kingdom ($33 million) due to the sale of operations in the fourth quarter of 2018.

Exploration costs of $140 million in 2019 decreased $9 million from $149 million in 2018 primarily due to decreased geological and geophysical expenditures in the Trinidad ($17 million), partially offset by increased general and administrative expenses in the United States ($7 million).

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The following table represents impairments for the years ended December 31, 2019 and 2018 (in millions):

	2019		2018
Proved properties	$	207	$	121
Unproved properties	220		173
Other assets	91		49
Inventories	—		4
Total	$	518	$	347

Impairments of proved properties were primarily due to the write-down to fair value of legacy natural gas assets in 2019 and 2018.

Taxes other than income in 2019 increased $28 million to $800 million (6.9% of wellhead revenues) from $772 million (6.5% of wellhead revenues) in 2018. The increase in taxes other than income was primarily due to an increase in ad valorem/property taxes ($53 million), partially offset by an increase in credits available to EOG in 2019 for state incentive severance tax rate reductions ($12 million) and a decrease in severance/production taxes ($12 million) primarily as a result of decreased wellhead revenues, all in the United States.

Other income, net, was $31 million in 2019 compared to other income, net, of $17 million in 2018. The increase of $14 million in 2019 was primarily due to an increase in interest income ($14 million) and an increase in foreign currency transaction gains ($9 million), partially offset by an increase in deferred compensation expense ($4 million).

EOG recognized an income tax provision of $810 million in 2019 compared to an income tax provision of $822 million in 2018, primarily due to decreased pretax income, partially offset by the absence of tax benefits from certain tax reform measurement-period adjustments. The net effective tax rate for 2019 increased to 23% from 19% in the prior year, primarily due to the absence of tax benefits from certain tax reform measurement-period adjustments.

Capital Resources and Liquidity

Cash Flow

The primary sources of cash for EOG during the three-year period ended December 31, 2020, were funds generated from operations, net proceeds from the issuance of long-term debt, net cash received from settlements of commodity derivative contracts and proceeds from asset sales.  The primary uses of cash were funds used in operations; exploration and development expenditures; repayments of debt; dividend payments to stockholders and other property, plant and equipment expenditures.

2020 compared to 2019.  Net cash provided by operating activities of $5,008 million in 2020 decreased $3,155 million from $8,163 million in 2019 primarily due to a decrease in wellhead revenues ($4,291 million); unfavorable changes in working capital and other assets and liabilities ($166 million); a decrease in gathering, processing and marketing revenues less marketing costs ($124 million) and an increase in net cash paid for income taxes ($86 million); partially offset by an increase in cash received for settlements of commodity derivative contracts ($840 million) and a decrease in cash operating expenses ($641 million).

Net cash used in investing activities of $3,348 million in 2020 decreased by $2,829 million from $6,177 million in 2019 primarily due to a decrease in additions to oil and gas properties ($2,908 million); an increase in proceeds from the sale of assets ($52 million); a decrease in additions to other property, plant and equipment ($49 million); and a decrease in other investing activities ($10 million); partially offset by an unfavorable change in working capital associated with investing activities ($190 million).

Net cash used in financing activities of $359 million in 2020 included repayments of long-term debt ($1,000 million), cash dividend payments ($821 million), repayment of finance lease liabilities ($19 million) and purchases of treasury stock in connection with stock compensation plans ($16 million). Cash provided by financing activities in 2020 included long-term debt borrowings ($1,484 million) and proceeds from stock options exercised and employee stock purchase plan activity ($16 million). 

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2019 compared to 2018.  Net cash provided by operating activities of $8,163 million in 2019 increased $394 million from $7,769 million in 2018 primarily reflecting an increase in cash received for settlements of commodity derivative contracts ($490 million), a decrease in net cash paid for income taxes ($367 million) and favorable changes in working capital and other assets and liabilities ($122 million); partially offset by a decrease in wellhead revenues ($365 million) and an increase in cash operating expenses ($202 million).

Net cash used in investing activities of $6,177 million in 2019 increased by $7 million from $6,170 million in 2018 primarily due to an increase in additions to oil and gas properties ($313 million), a decrease in proceeds from the sale of assets ($87 million) and an increase in additions to other property, plant and equipment ($33 million); partially offset by favorable changes in working capital associated with investing activities ($416 million) and a decrease in other investing activities ($10 million).

Net cash used in financing activities of $1,513 million in 2019 included repayments of long-term debt ($900 million), cash dividend payments ($588 million) and purchases of treasury stock in connection with stock compensation plans ($25 million). Cash provided by financing activities in 2019 included proceeds from stock options exercised and employee stock purchase plan activity ($18 million). 

Total Expenditures

The table below sets out components of total expenditures for the years ended December 31, 2020, 2019 and 2018 (in millions):

	2020		2019		2018
Expenditure Category
Capital
Exploration and Development Drilling	$	2,664	$	4,951	$	4,935
Facilities	347		629		625
Leasehold Acquisitions (1)	265		276		488
Property Acquisitions (2)	135		380		124
Capitalized Interest	31		38		24
Subtotal	3,442		6,274		6,196
Exploration Costs	146		140		149
Dry Hole Costs	13		28		5
Exploration and Development Expenditures	3,601		6,442		6,350
Asset Retirement Costs	117		186		70
Total Exploration and Development Expenditures	3,718		6,628		6,420
Other Property, Plant and Equipment (3)	395		272		286
Total Expenditures	$	4,113	$	6,900	$	6,706

(1)Leasehold acquisitions included $197 million, $98 million and $291 million related to non-cash property exchanges in 2020, 2019 and 2018, respectively.

(2)Property acquisitions included $15 million, $52 million and $71 million related to non-cash property exchanges in 2020, 2019 and 2018, respectively.

(3)Other property, plant and equipment included non-cash additions of $174 million, primarily related to finance lease transactions for storage facilities, and $49 million, primarily related to a finance lease transaction in the Permian Basin, in 2020 and 2018, respectively.

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Exploration and development expenditures of $3,601 million for 2020 were $2,841 million lower than the prior year. The decrease was primarily due to decreased exploration and development drilling expenditures in the United States ($2,309 million), decreased facilities expenditures ($282 million) and decreased property acquisitions ($245 million), partially offset by increased exploration and development drilling expenditures in Trinidad ($27 million). The 2020 exploration and development expenditures of $3,601 million included $2,905 million in development drilling and facilities, $530 million in exploration, $135 million in property acquisitions and $31 million in capitalized interest. The 2019 exploration and development expenditures of $6,442 million included $5,513 million in development drilling and facilities, $511 million in exploration, $380 million in property acquisitions and $38 million in capitalized interest. The 2018 exploration and development expenditures of $6,350 million included $5,546 million in development drilling and facilities, $656 million in exploration, $124 million in property acquisitions and $24 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.

Commodity Derivative Transactions

Crude Oil Derivative Contracts. Prices received by EOG for its crude oil production generally vary from U.S. New York Mercantile Exchange (NYMEX) West Texas Intermediate (WTI) prices due to adjustments for delivery location (basis) and other factors. EOG has entered into crude oil basis swap contracts in order to fix the differential between Intercontinental Exchange (ICE) Brent pricing and pricing in Cushing, Oklahoma (ICE Brent Differential). Presented below is a comprehensive summary of EOG's ICE Brent Differential basis swap contracts through February 18, 2021. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.

ICE Brent Differential Basis Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)
2020
May 2020 (closed)	10,000	$	4.92

EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in Houston, Texas, and Cushing, Oklahoma (Houston Differential). Presented below is a comprehensive summary of EOG's Houston Differential basis swap contracts through February 18, 2021. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.

Houston Differential Basis Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)
2020
May 2020 (closed)	10,000	$	1.55

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EOG has also entered into crude oil swaps in order to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month (Roll Differential). Presented below is a comprehensive summary of EOG's Roll Differential basis swap contracts through February 18, 2021. The weighted average price differential expressed in $/Bbl represents the amount of net addition (reduction) to delivery month prices for the notional volumes expressed in Bbld covered by the swap contracts.

Roll Differential Basis Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)
2020
February 1, 2020 through June 30, 2020 (closed)	10,000	$	0.70
July 1, 2020 through September 30, 2020 (closed)	88,000	(1.16)
October 1, 2020 through December 31, 2020 (closed)	66,000	(1.16)
2021
February 2021 (closed)	30,000	$	0.11
March 1, 2021 through December 31, 2021	125,000	0.17
2022
January 1, 2022 through December 31, 2022	125,000	$	0.15

In May 2020, EOG entered into crude oil Roll Differential basis swap contracts for the period from July 1, 2020 through September 30, 2020, with notional volumes of 22,000 Bbld at a weighted average price differential of $(0.43) per Bbl, and for the period from October 1, 2020 through December 31, 2020, with notional volumes of 44,000 Bbld at a weighted average price differential of $(0.73) per Bbl. These contracts partially offset certain outstanding Roll Differential basis swap contracts for the same time periods and volumes at a weighted average price differential of $(1.16) per Bbl. EOG paid net cash of $3.2 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.

Presented below is a comprehensive summary of EOG's crude oil NYMEX WTI price swap contracts through February 18, 2021, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

Crude Oil NYMEX WTI Price Swap Contracts
	Volume (Bbld)	Weighted Average Price ($/Bbl)
2020
January 1, 2020 through March 31, 2020 (closed)	200,000	$	59.33
April 1, 2020 through May 31, 2020 (closed)	265,000	51.36
2021
January 2021 (closed)	151,000	$	50.06
February 1, 2021 through March 31, 2021	201,000	51.29
April 1, 2021 through June 30, 2021	150,000	51.68
July 1, 2021 through September 30, 2021	150,000	52.71

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In April and May 2020, EOG entered into crude oil NYMEX WTI price swap contracts for the period from June 1, 2020 through June 30, 2020, with notional volumes of 265,000 Bbld at a weighted average price of $33.80 per Bbl, for the period from July 1, 2020 through July 31, 2020, with notional volumes of 254,000 Bbld at a weighted average price of $33.75 per Bbl, for the period from August 1, 2020 through September 30, 2020, with notional volumes of 154,000 Bbld at a weighted average price of $34.18 per Bbl and for the period from October 1, 2020 through December 31, 2020, with notional volumes of 47,000 Bbld at a weighted average price of $30.04 per Bbl. These contracts offset the remaining crude oil NYMEX WTI price swap contracts for the same time periods and volumes at a weighted average price of $51.36 per Bbl for the period from June 1, 2020 through June 30, 2020, $42.36 per Bbl for the period from July 1, 2020 through July 31, 2020, $50.42 per Bbl for the period from August 1, 2020 through September 30, 2020 and $31.00 per Bbl for the period from October 1, 2020 through December 31, 2020. EOG received net cash of $364.0 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.

Presented below is a comprehensive summary of EOG's crude oil ICE Brent price swap contracts through February 18, 2021, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

Crude Oil ICE Brent Price Swap Contracts
	Volume (Bbld)	Weighted Average Price ($/Bbl)
2020
April 2020 (closed)	75,000	$	25.66
May 2020 (closed)	35,000	26.53

NGLs Derivative Contracts. Presented below is a comprehensive summary of EOG's Mont Belvieu propane (non-TET) price swap contracts through February 18, 2021, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

Mont Belvieu Propane Price Swap Contracts
	Volume (Bbld)	Weighted Average Price ($/Bbl)
2020
January 1, 2020 through February 29, 2020 (closed)	4,000	$	21.34
March 1, 2020 through April 30, 2020 (closed)	25,000	17.92
2021
January 2021 (closed)	15,000	$	29.44
February 1, 2021 through December 31, 2021	15,000	29.44

In April and May 2020, EOG entered into Mont Belvieu propane price swap contracts for the period from May 1, 2020 through December 31, 2020, with notional volumes of 25,000 Bbld at a weighted average price of $16.41 per Bbl. These contracts offset the remaining Mont Belvieu propane price swap contracts for the same time period with notional volumes of 25,000 Bbld at a weighted average price of $17.92 per Bbl. EOG received net cash of $9.2 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.

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Natural Gas Derivative Contracts. Presented below is a comprehensive summary of EOG's natural gas NYMEX Henry Hub price swap contracts through February 18, 2021, with notional volumes sold (purchased) expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu). In January 2021, EOG executed the early termination provision granting EOG the right to terminate certain 2022 natural gas NYMEX Henry Hub price swap contracts with notional volumes of 20,000 MMBtud at a weighted average price of $2.75 per MMBtu for the period from January 1, 2022 through December 31, 2022. EOG received net cash of $0.6 million for the settlement of these contracts.

Natural Gas NYMEX Henry Hub Price Swap Contracts
	Volume (MMBtud)	Weighted Average Price ($/MMBtu)
2021
April 1, 2021 through September 30, 2021	(70,000)	$	2.64
2022
January 1, 2022 through December 31, 2022 (closed)	20,000	$	2.75

In December 2020 and January 2021, EOG entered into natural gas NYMEX Henry Hub price swap contracts for the period from January 1, 2021 through March 31, 2021, with notional volumes of 500,000 MMBtud at a weighted average price of $2.43 per MMBtu and for the period from April 1, 2021 through December 31, 2021, with notional volumes of 500,000 MMBtud at a weighted average price of $2.83 per MMBtu. These contracts offset the remaining natural gas NYMEX Henry Hub price swap contracts for the same time periods with notional volumes of 500,000 MMBtud at a weighted average price of $2.99 per MMBtu. EOG received net cash of $16.5 million through February 18, 2021, for the settlement of certain of these contracts, and expects to receive net cash of $30.3 million during the remainder of 2021 for the settlement of the remaining contracts. The offsetting contracts were excluded from the above table.

Presented below is a comprehensive summary of EOG's natural gas Japan Korea Marker (JKM) price swap contracts through February 18, 2021, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.

Natural Gas JKM Price Swap Contracts
	Volume (MMBtud)	Weighted Average Price ($/MMBtu)
2021
April 1, 2021 through September 30, 2021	70,000	$	6.65

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EOG has entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the Henry Hub Index Price in the event the Henry Hub Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price. In March 2020, EOG executed the early termination provision granting EOG the right to terminate certain 2020 natural gas collar contracts with notional volumes of 250,000 MMBtud at a weighted average ceiling price of $2.50 per MMBtu and a weighted average floor price of $2.00 per MMBtu for the period from April 1, 2020 through July 31, 2020. EOG received net cash of $7.8 million for the settlement of these contracts. Presented below is a comprehensive summary of EOG's natural gas collar contracts through February 18, 2021, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.

Natural Gas Collar Contracts
		Weighted Average Price ($/MMBtu)
	Volume (MMBtud)	Ceiling Price		Floor Price
2020
April 1, 2020 through July 31, 2020 (closed)	250,000	$	2.50	$	2.00

In April 2020, EOG entered into natural gas collar contracts for the period from August 1, 2020 through October 31, 2020, with notional volumes of 250,000 MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu. These contracts offset the remaining natural gas collar contracts for the same time period with notional volumes of 250,000 MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu. EOG received net cash of $1.1 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.

Prices received by EOG for its natural gas production generally vary from NYMEX Henry Hub prices due to adjustments for delivery location (basis) and other factors. EOG has entered into natural gas basis swap contracts in order to fix the differential between pricing in the Rocky Mountain area and NYMEX Henry Hub prices (Rockies Differential). Presented below is a comprehensive summary of EOG's Rockies Differential basis swap contracts through February 18, 2021. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts.

Rockies Differential Basis Swap Contracts
	Volume (MMBtud)	Weighted Average Price Differential ($/MMBtu)
2020
January 1, 2020 through December 31, 2020 (closed)	30,000	$	0.55

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EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Houston Ship Channel (HSC) and NYMEX Henry Hub prices (HSC Differential). In March 2020, EOG executed the early termination provision granting EOG the right to terminate certain 2020 HSC Differential basis swaps with notional volumes of 60,000 MMBtud at a weighted average price differential of $0.05 per MMBtu for the period from April 1, 2020 through December 31, 2020. EOG paid net cash of $0.4 million for the settlement of these contracts. Presented below is a comprehensive summary of EOG's HSC Differential basis swap contracts through February 18, 2021. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts.

HSC Differential Basis Swap Contracts
	Volume (MMBtud)	Weighted Average Price Differential ($/MMBtu)
2020
January 1, 2020 through December 31, 2020 (closed)	60,000	$	0.05

EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Waha Hub in West Texas and NYMEX Henry Hub prices (Waha Differential). Presented below is a comprehensive summary of EOG's Waha Differential basis swap contracts through February 18, 2021. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts.

Waha Differential Basis Swap Contracts
	Volume (MMBtud)	Weighted Average Price Differential ($/MMBtu)
2020
January 1, 2020 through April 30, 2020 (closed)	50,000	$	1.40

In April 2020, EOG entered into Waha Differential basis swap contracts for the period from May 1, 2020 through December 31, 2020, with notional volumes of 50,000 MMBtud at a weighted average price differential of $0.43 per MMBtu. These contracts offset the remaining Waha Differential basis swap contracts for the same time period with notional volumes of 50,000 MMBtud at a weighted average price differential of $1.40 per MMBtu. EOG paid net cash of $11.9 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.

Financing

EOG's debt-to-total capitalization ratio was 22% at December 31, 2020, compared to 19% at December 31, 2019.  As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

At December 31, 2020 and 2019, respectively, EOG had outstanding $5,640 million and $5,140 million aggregate principal amount of senior notes which had estimated fair values of $6,505 million and $5,452 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 2020, EOG funded its capital program and operations primarily by utilizing cash provided by operating activities, issuance of the Notes and proceeds from asset sales.  While EOG maintains a $2.0 billion revolving credit facility to back its commercial paper program, there were no borrowings outstanding at any time during 2020 and the amount outstanding at year-end was zero.  EOG considers the availability of its $2.0 billion senior unsecured revolving credit facility, as described in Note 2 to Consolidated Financial Statements, to be sufficient to meet its ongoing operating needs.

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Contractual Obligations

The following table summarizes EOG's contractual obligations at December 31, 2020 (in millions):

Contractual Obligations (1)	Total		2021		2022-2023		2024-2025		2026 & Beyond
Current and Long-Term Debt	$	5,640	$	750	$	1,250	$	500	$	3,140
Interest Payments on Long-Term Debt	2,297		207		366		309		1,415
Finance Leases (2)	239		36		60		56		87
Operating Leases (2)	1,039		323		344		166		206
Leases Effective, Not Commenced (2)	100		14		28		22		36
Transportation and Storage Service Commitments (3)	6,665		964		1,830		1,296		2,575
Purchase and Service Obligations	1,258		429		497		143		189
Total Contractual Obligations	$	17,238	$	2,723	$	4,375	$	2,492	$	7,648

(1)This table does not include the liability for unrecognized tax benefits, EOG's pension or postretirement benefit obligations or liability for dismantlement, abandonment and asset retirement obligations (see Notes 6, 7 and 15, respectively, to Consolidated Financial Statements). These amounts are excluded because they are subject to estimates and the timing of settlement is unknown.

(2)For more information on contracts that meet the definition of a lease under ASU 2016-02, see Note 18 to Consolidated Financial Statements.

(3)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, 2020.  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.

Off-Balance Sheet Arrangements

EOG does not participate in financial transactions that generate relationships with unconsolidated entities or financial partnerships.  Such entities or partnerships, often referred to as variable interest entities (VIE) or special purpose entities (SPE), are generally established for the purpose of facilitating off-balance sheet arrangements or other limited purposes. EOG was not involved in any unconsolidated VIE or SPE financial transactions or any other "off-balance sheet arrangement" (as defined in Item 303(a)(4)(ii) of Regulation S-K) during any of the periods covered by this report and currently has no intention of participating in any such transaction or arrangement in the foreseeable future.

Foreign Currency Exchange Rate Risk

During 2020, EOG was exposed to foreign currency exchange rate risk inherent in its operations in foreign countries, including Trinidad, China and Canada.  EOG continues to monitor the foreign currency exchange rates of countries in which it is currently conducting business and may implement measures to protect against foreign currency exchange rate risk.

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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 political environment, worldwide supplies of, and demand for, crude oil and condensate, NGLs and natural gas, the availabilities of other worldwide 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 2021 will impact the amount of cash generated from EOG's operating activities, which will in turn impact EOG's financial position. As of February 18, 2021, the average 2021 NYMEX crude oil and natural gas prices were $57.51 per barrel and $2.98 per MMBtu, respectively, representing an increase of 46% for crude oil and an increase of 43% for natural gas from the average NYMEX prices in 2020. See ITEM 1A, Risk Factors.

Including the impact of EOG's crude oil and NGL derivative contracts (exclusive of basis swaps) and based on EOG's tax position, EOG's price sensitivity in 2021 for each $1.00 per barrel increase or decrease in wellhead crude oil and condensate price, combined with the estimated change in NGL price, is approximately $99 million for net income and $127 million for pretax cash flows from operating activities.  Including the impact of EOG's natural gas derivative contracts and based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2021 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 $31 million for net income and $40 million for pretax cash flows from operating activities.  For information regarding EOG's crude oil, NGLs and natural gas financial commodity derivative contracts through February 18, 2021, see "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 crude oil drilling activity in its Delaware Basin, Eagle Ford and Rocky Mountain area 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 lower drilling and completion costs through efficiency gains and lower service costs. In addition, EOG expects to spend a portion of its anticipated 2021 capital expenditures on leasing acreage and evaluating new prospects.

The total anticipated 2021 capital expenditures of approximately $3.7 billion to $4.1 billion, excluding acquisitions and non-cash transactions, 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 $2.0 billion senior unsecured revolving credit facility and equity and debt offerings.

Operations. In 2021, total crude oil production is expected to remain at fourth quarter 2020 levels. In 2021, EOG expects to continue to focus on reducing operating costs through efficiency improvements.

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Summary of Critical Accounting Policies

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 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 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.  Following is a discussion of EOG's most critical accounting policies:

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.  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."

Oil and Gas Exploration and Development Costs

EOG accounts for its crude oil and natural gas exploration and production activities under the successful efforts method of accounting.  Oil and gas exploration costs, other than the costs of drilling exploratory wells, are expensed as incurred.  The costs of drilling exploratory wells are capitalized pending determination of whether EOG has discovered commercial quantities of proved reserves.  If commercial quantities of proved reserves are not discovered, such drilling costs are expensed.  In some circumstances, it may be uncertain whether commercial quantities of proved reserves have been discovered when drilling has been completed.  Such exploratory well drilling costs may continue to be capitalized if the estimated reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made.  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 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.  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 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.

Depreciation, depletion and amortization rates are updated quarterly to reflect the addition of capital costs, reserve revisions (upwards or downwards) and additions, property acquisitions and/or property dispositions and impairments.

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Depreciation and amortization of other property, plant and equipment is calculated on a straight-line basis over the estimated useful life of the asset.

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.

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 asset.  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, 2020, WTI crude oil spot prices have fluctuated from approximately $(36.98) per barrel to $77.41 per barrel, and Henry Hub natural gas spot prices have ranged from approximately $1.33 per MMBtu to $6.24 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.  Proved reserves are estimated using a trailing 12-month average price, in accordance with SEC rules. In the future, if any combination of crude oil prices, NGLs prices, natural gas prices, actual production or operating costs diverge negatively from EOG's current estimates, impairment charges and downward adjustments to our estimated proved reserves may be necessary.

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.  Significant assumptions used in estimating future taxable income include future crude oil, NGLs and natural gas prices and levels of capital reinvestment.  Changes in such assumptions or changes in tax laws and regulations could materially affect the recognized amounts of valuation allowances.

Stock-Based Compensation

In accounting for stock-based compensation, judgments and estimates are made regarding, among other things, the appropriate valuation methodology to follow in valuing stock compensation awards and the related inputs required by those valuation methodologies. Assumptions regarding expected volatility of EOG's common stock, the level of risk-free interest rates, expected dividend yields on EOG's common stock, the expected term of the awards, expected volatility in the price of shares and composition of EOG's peer companies and other valuation inputs are subject to change. Any such changes could result in different valuations and thus impact the amount of stock-based compensation expense recognized on the Consolidated Statements of Income and Comprehensive Income.

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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, 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," "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 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 operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness, or pay and/or increase dividends 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 these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. 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, 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, operating and capital costs 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 extent to which EOG is successful in its efforts to market its production of crude oil and condensate, natural gas liquids, 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;

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

•the availability, cost, terms and timing of issuance or execution of, and competition for, 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 any changes or other actions which may result from the recent U.S. elections and change in U.S. administration and including tax laws and regulations; climate change and other environmental, health and safety laws and regulations relating to air emissions, 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 and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;

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

•the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully and economically;

•competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties, employees and other personnel, facilities, equipment, materials and services;

•the availability and cost of employees and other personnel, facilities, equipment, materials (such as water and tubulars) and services;

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

56

•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, 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, including the COVID-19 pandemic;

•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 conflict), including in the areas in which EOG operates;

•the use of competing energy sources and the development of alternative energy sources;

•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.

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 "Commodity Derivative Transactions," "Financing," "Foreign Currency Exchange Rate Risk" 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, 2020. 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, 2020.

57

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.

EOG's management assessed the effectiveness of EOG's internal control over financial reporting as of December 31, 2020. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (2013). Based on this assessment and such criteria, EOG's management believes that EOG's internal control over financial reporting was effective as of December 31, 2020. See also "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, 2020, that have materially affected, or are reasonably likely to materially affect, EOG's internal control over financial reporting.

ITEM 9B.  Other Information

None.

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 2021 Annual Meeting of Stockholders to be filed not later than April 30, 2021 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.

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ITEM 11.  Executive Compensation

The information required by this Item is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 2021 Annual Meeting of Stockholders to be filed not later than April 30, 2021. The Compensation 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 2021 Annual Meeting of Stockholders to be filed not later than April 30, 2021.

Equity Compensation Plan Information

Stock Plans Approved by EOG Stockholders.  EOG's stockholders approved the EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (2008 Plan) at the 2008 Annual Meeting of Stockholders in May 2008.  At the 2010 Annual Meeting of Stockholders in April 2010 (2010 Annual Meeting), an amendment to the 2008 Plan was approved, pursuant to which the number of shares of common stock available for future grants of stock options, stock-settled stock appreciation rights (SARs), restricted stock, restricted stock units, performance units and other stock-based awards under the 2008 Plan was increased by an additional 13.8 million shares, to an aggregate maximum of 25.8 million shares plus shares underlying forfeited or canceled grants under the prior stock plans referenced in the 2008 Plan document.  At the 2013 Annual Meeting of Stockholders in May 2013, EOG's stockholders approved the Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Amended and Restated 2008 Plan).  As more fully discussed in the Amended and Restated 2008 Plan document, the Amended and Restated 2008 Plan, among other things, authorizes an additional 31.0 million shares of EOG common stock for grant under the plan and extends the expiration date of the plan to May 2023.  Under the Amended and Restated 2008 Plan, grants may be made to employees and non-employee members of EOG's Board.

Also at the 2010 Annual Meeting, an amendment to the EOG Resources, Inc. Employee Stock Purchase Plan (ESPP) was approved to increase the shares available for grant by 2.0 million shares.  The ESPP was originally approved by EOG's stockholders in 2001, and would have expired on July 1, 2011.  The amendment also extended the term of the ESPP to December 31, 2019, unless terminated earlier by its terms or by EOG. At the 2018 Annual Meeting of Stockholders in April 2018, stockholders approved an amendment and restatement of the 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 2008 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, 2020, 368,745 phantom shares had been issued. The Deferral Plan is currently EOG's only stock plan that has not been approved by EOG's stockholders.

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   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, 2020.

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	11,753,761	(2)	$	84.08	3,891,544	(3)
Equity Compensation Plans Not Approved by EOG Stockholders	248,363	(4)	N/A		171,255	(5)
Total	12,002,124		$	84.08	4,062,799

(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 shares that will be issued upon the vesting of outstanding restricted stock unit and performance unit grants, or Deferral Plan phantom shares, all of which have no exercise price.

(2)Amount includes 954,949 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. Amount also includes 612,951 outstanding performance units and assumes, for purposes of this table, (i) the application of a 100% performance multiple upon the completion of each of the remaining performance periods in respect of such performance unit grants and (ii) accordingly, the issuance, on a one-for-one basis, of an aggregate 612,951 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 76,785 and a maximum of 1,149,117 performance units could be outstanding and (B) accordingly, a minimum of 76,785 and a maximum of 1,149,117 shares of EOG common stock could be issued upon the vesting of such grants.

(3)Consists of (i) 1,996,101 shares remaining available for issuance under the Amended and Restated 2008 Plan and (ii) 1,895,443 shares remaining available for purchase under the ESPP.  Pursuant to the fungible share design of the Amended and Restated 2008 Plan, each share issued as a SAR or stock option under the Amended and Restated 2008 Plan counts as 1.0 share against the aggregate plan share limit, and each share issued as a "full value award" (i.e., as restricted stock, restricted stock units or performance units) counts as 2.45 shares against the aggregate plan share limit.  Thus, from the 1,996,101 shares remaining available for issuance under the Amended and Restated 2008 Plan, (i) the maximum number of shares we could issue as SAR and stock option awards is 1,996,101 (i.e., if all shares remaining available for issuance under the Amended and Restated 2008 Plan are issued as SAR and stock option awards) and (ii) the maximum number of shares we could issue as full value awards is 814,735 (i.e., if all shares remaining available for issuance under the Amended and Restated 2008 Plan are issued as full value awards).

(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 248,363 phantom shares issued and outstanding under the Deferral Plan as of December 31, 2020).

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

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

The information required by this Item is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 2021 Annual Meeting of Stockholders to be filed not later than April 30, 2021.

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 2021 Annual Meeting of Stockholders to be filed not later than April 30, 2021.

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PART IV

ITEM 15.  Exhibits, 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.

61

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	F-3
Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) for Each of the Three Years in the Period Ended December 31, 2020	F-6
Consolidated Balance Sheets - December 31, 2020 and 2019	F-7
Consolidated Statements of Stockholders' Equity for Each of the Three Years in the Period Ended December 31, 2020	F-8
Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2020	F-9
Notes to Consolidated Financial Statements	F-10
Supplemental Information to Consolidated Financial Statements	F-43

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, 2020.  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, 2020.

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.

WILLIAM R. THOMAS	TIMOTHY K. DRIGGERS
Chairman of the Board and	Executive Vice President and Chief
Chief Executive Officer	Financial Officer
Houston, Texas
February 25, 2021

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and the Board of Directors of

EOG Resources, Inc.

Houston, Texas

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, 2020 and 2019, 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, 2020, 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, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, 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, 2020, based on the 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 Annual Report on Internal Control over 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 and Impairment – Crude Oil and Condensate, NGLs, and Natural Gas Reserves —Refer to Notes 1, 13 and 14 to the Financial Statements

Critical Audit Matter Description

The Company’s proved oil and natural gas properties are depleted using the units of production method and are evaluated for impairment by comparison to the future net cash flows of the underlying proved crude oil, natural gas liquids (NGLs) and natural gas reserves. The development of the Company’s crude oil, NGLs and natural gas reserve volumes and the related future net cash flows requires management to make significant estimates and scheduling assumptions related to the five-year development plan for proved undeveloped reserves, future crude oil, NGLs and natural gas prices, and future well costs. The Company’s reserve engineers estimate crude oil, NGLs and natural gas quantities using these estimates and assumptions and engineering data. Changes in these assumptions could have a significant impact on the amount of depletion and any proved oil and gas impairment. Proved oil and gas properties were $23 billion as of December 31, 2020, and depletion and proved property impairment were $3.2 billion and $1.3 billion, respectively, for the year then ended.

Given the significant judgments made by management, performing audit procedures to evaluate the Company’s proved crude oil, NGLs and natural gas reserve quantities and the related future net cash flows including management’s estimates and assumptions related to the five-year development plan, future crude oil, NGLs and natural gas prices and future well costs, required a high degree of auditor judgment and an increased extent of effort, including the need to involve our fair value specialists.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to management’s estimates and assumptions related to crude oil, NGLs and natural gas reserve quantities and estimates of future net cash flows included the following, among others:

•We tested the effectiveness of controls over the Company’s estimation of proved crude oil, NGLs and natural gas reserve quantities and related future net cash flows, including controls relating to the five-year development plan, future crude oil, NGLs and natural gas prices and future well costs.

•We evaluated the reasonableness of management’s five-year development plan by comparing the forecasts to:

◦Historical conversions of proved undeveloped reserves.

◦Internal communications to management and the Board of Directors.

◦Approval for expenditures.

◦Analyst and industry reports for the Company and certain of its peer companies.

•With the assistance of our fair value specialists, we evaluated management’s estimated future crude oil, NGLs and natural gas prices by:

◦Understanding the methodology used by management for development of the future prices and comparing the estimated prices to an independently determined range of prices.

◦Comparing management’s estimates to published forward pricing indices and third-party industry sources.

◦Evaluating the historical realized price differentials incorporated in the future crude oil, NGLs and natural gas prices.

F-4

•We evaluated the reasonableness of capital expenditures (well costs) by comparing the estimate to:

◦Historical development of similar wells drilled.

◦Analyst and industry reports.

•We evaluated the Company’s oil and natural gas reserve volumes by:

◦Comparing the Company’s reserve volumes to historical production volumes.

◦Comparing the Company’s reserve volumes to those independently developed by the independent petroleum consultants.

◦Evaluating the reasonableness of the production volume decline curves.

◦Understanding the experience, qualifications, and objectivity of the Company’s reserve engineers and the independent petroleum consultants.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 25, 2021

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

F-5

EOG RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)

(In Thousands, Except Per Share Data)

Year Ended December 31	2020		2019		2018
Operating Revenues and Other
Crude Oil and Condensate	$	5,785,609	$	9,612,532	$	9,517,440
Natural Gas Liquids	667,514		784,818		1,127,510
Natural Gas	837,133		1,184,095		1,301,537
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts	1,144,737		180,275		(165,640)
Gathering, Processing and Marketing	2,582,984		5,360,282		5,230,355
Gains (Losses) on Asset Dispositions, Net	(46,883)		123,613		174,562
Other, Net	60,954		134,358		89,635
Total	11,032,048		17,379,973		17,275,399
Operating Expenses
Lease and Well	1,063,374		1,366,993		1,282,678
Transportation Costs	734,989		758,300		746,876
Gathering and Processing Costs	459,211		479,102		436,973
Exploration Costs	145,788		139,881		148,999
Dry Hole Costs	13,083		28,001		5,405
Impairments	2,099,780		517,896		347,021
Marketing Costs	2,697,729		5,351,524		5,203,243
Depreciation, Depletion and Amortization	3,400,353		3,749,704		3,435,408
General and Administrative	483,823		489,397		426,969
Taxes Other Than Income	477,934		800,164		772,481
Total	11,576,064		13,680,962		12,806,053
Operating Income (Loss)	(544,016)		3,699,011		4,469,346
Other Income, Net	10,228		31,385		16,704
Income (Loss) Before Interest Expense and Income Taxes	(533,788)		3,730,396		4,486,050
Interest Expense
Incurred	236,154		223,421		269,549
Capitalized	(30,888)		(38,292)		(24,497)
Net Interest Expense	205,266		185,129		245,052
Income (Loss) Before Income Taxes	(739,054)		3,545,267		4,240,998
Income Tax Provision (Benefit)	(134,482)		810,357		821,958
Net Income (Loss)	$	(604,572)	$	2,734,910	$	3,419,040
Net Income (Loss) Per Share
Basic	$	(1.04)	$	4.73	$	5.93
Diluted	$	(1.04)	$	4.71	$	5.89
Average Number of Common Shares
Basic	578,949		577,670		576,578
Diluted	578,949		580,777		580,441
Comprehensive Income (Loss)
Net Income (Loss)	$	(604,572)	$	2,734,910	$	3,419,040
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments	(7,346)		(2,883)		16,816
Other, Net of Tax	(330)		(678)		1,123
Other Comprehensive Income (Loss)	(7,676)		(3,561)		17,939
Comprehensive Income (Loss)	$	(612,248)	$	2,731,349	$	3,436,979

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

F-6

EOG RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Data)

At December 31	2020		2019
ASSETS
Current Assets
Cash and Cash Equivalents	$	3,328,928	$	2,027,972
Accounts Receivable, Net	1,522,256		2,001,658
Inventories	629,401		767,297
Assets from Price Risk Management Activities	64,559		1,299
Income Taxes Receivable	23,037		151,665
Other	293,987		323,448
Total	5,862,168		5,273,339
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)	64,792,798		62,830,415
Other Property, Plant and Equipment	4,478,976		4,472,246
Total Property, Plant and Equipment	69,271,774		67,302,661
Less: Accumulated Depreciation, Depletion and Amortization	(40,673,147)		(36,938,066)
Total Property, Plant and Equipment, Net	28,598,627		30,364,595
Deferred Income Taxes	2,127		2,363
Other Assets	1,341,679		1,484,311
Total Assets	$	35,804,601	$	37,124,608
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable	$	1,681,193	$	2,429,127
Accrued Taxes Payable	205,754		254,850
Dividends Payable	217,419		166,273
Liabilities from Price Risk Management Activities	—		20,194
Current Portion of Long-Term Debt	781,054		1,014,524
Current Portion of Operating Lease Liabilities	295,089		369,365
Other	279,595		232,655
Total	3,460,104		4,486,988
Long-Term Debt	5,035,351		4,160,919
Other Liabilities	2,147,932		1,789,884
Deferred Income Taxes	4,859,327		5,046,101
Commitments and Contingencies (Note 8)
Stockholders' Equity
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 583,694,850 Shares and 582,213,016 Shares Issued at December 31, 2020 and 2019, respectively	205,837		205,822
Additional Paid in Capital	5,945,024		5,817,475
Accumulated Other Comprehensive Loss	(12,328)		(4,652)
Retained Earnings	14,169,969		15,648,604
Common Stock Held in Treasury, 124,265 Shares and 298,820 Shares at December 31, 2020 and 2019, respectively	(6,615)		(26,533)
Total Stockholders' Equity	20,301,887		21,640,716
Total Liabilities and Stockholders' Equity	$	35,804,601	$	37,124,608

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

F-7

EOG RESOURCES, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(In Thousands, Except Per Share Data)

	Common Stock		Additional Paid In Capital		Accumulated Other Comprehensive Income (Loss)		Retained Earnings		Common Stock Held In Treasury		Total Stockholders' Equity
Balance at December 31, 2017	$	205,788	$	5,536,547	$	(19,297)	$	10,593,533	$	(33,298)	$	16,283,273
Net Income	—		—		—		3,419,040		—		3,419,040
Common Stock Issued Under Stock Plans	8		5,612		—		—		—		5,620
Common Stock Dividends Declared, $0.81 Per Share	—		—		—		(469,443)		—		(469,443)
Other Comprehensive Income	—		—		17,939		—		—		17,939
Change in Treasury Stock - Stock Compensation Plans, Net	—		(35,118)		—		—		(13,336)		(48,454)
Restricted Stock and Restricted Stock Units, Net	8		(3,891)		—		—		3,883		—
Stock-Based Compensation Expenses	—		155,337		—		—		—		155,337
Treasury Stock Issued as Compensation	—		307		—		—		569		876
Balance at December 31, 2018	205,804		5,658,794		(1,358)		13,543,130		(42,182)		19,364,188
Net Income	—		—		—		2,734,910		—		2,734,910
Common Stock Issued Under Stock Plans	1		(9)		—		—		—		(8)
Common Stock Dividends Declared, $1.0825 Per Share	—		—		—		(629,169)		—		(629,169)
Other Comprehensive Loss	—		—		(3,561)		—		—		(3,561)
Change in Treasury Stock - Stock Compensation Plans, Net	—		(10,637)		—		—		3,784		(6,853)
Restricted Stock and Restricted Stock Units, Net	17		(4,566)		—		—		4,549		—
Stock-Based Compensation Expenses	—		174,738		—		—		—		174,738
Treasury Stock Issued as Compensation	—		(845)		—		—		7,316		6,471
Cumulative Effect of Accounting Changes	—		—		267		(267)		—		—
Balance at December 31, 2019	205,822		5,817,475		(4,652)		15,648,604		(26,533)		21,640,716
Net Loss	—		—		—		(604,572)		—		(604,572)
Common Stock Issued Under Stock Plans	—		—		—		—		—		—
Common Stock Dividends Declared, $1.50 Per Share	—		—		—		(874,063)		—		(874,063)
Other Comprehensive Loss	—		—		(7,676)		—		—		(7,676)
Change in Treasury Stock - Stock Compensation Plans, Net	—		(9,152)		—		—		9,089		(63)
Restricted Stock and Restricted Stock Units, Net	15		(9,310)		—		—		9,295		—
Stock-Based Compensation Expenses	—		146,396		—		—		—		146,396
Treasury Stock Issued as Compensation	—		(385)		—		—		1,534		1,149
Balance at December 31, 2020	$	205,837	$	5,945,024	$	(12,328)	$	14,169,969	$	(6,615)	$	20,301,887

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

F-8

EOG RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

Year Ended December 31	2020		2019		2018
Cash Flows from Operating Activities
Reconciliation of Net Income (Loss) to Net Cash Provided by Operating Activities:
Net Income (Loss)	$	(604,572)	$	2,734,910	$	3,419,040
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization	3,400,353		3,749,704		3,435,408
Impairments	2,099,780		517,896		347,021
Stock-Based Compensation Expenses	146,396		174,738		155,337
Deferred Income Taxes	(186,390)		631,658		894,156
(Gains) Losses on Asset Dispositions, Net	46,883		(123,613)		(174,562)
Other, Net	12,826		4,496		7,066
Dry Hole Costs	13,083		28,001		5,405
Mark-to-Market Commodity Derivative Contracts
Total (Gains) Losses	(1,144,737)		(180,275)		165,640
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts	1,070,647		231,229		(258,906)
Other, Net	1,354		962		3,108
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	466,523		(91,792)		(368,180)
Inventories	122,647		90,284		(395,408)
Accounts Payable	(795,267)		168,539		439,347
Accrued Taxes Payable	(49,096)		40,122		(92,461)
Other Assets	324,521		358,001		(125,435)
Other Liabilities	8,098		(56,619)		10,949
Changes in Components of Working Capital Associated with Investing and Financing Activities	74,734		(115,061)		301,083
Net Cash Provided by Operating Activities	5,007,783		8,163,180		7,768,608
Investing Cash Flows
Additions to Oil and Gas Properties	(3,243,474)		(6,151,885)		(5,839,294)
Additions to Other Property, Plant and Equipment	(221,226)		(270,641)		(237,181)
Proceeds from Sales of Assets	191,928		140,292		227,446
Other Investing Activities	—		(10,000)		(19,993)
Changes in Components of Working Capital Associated with Investing Activities	(74,734)		115,061		(301,140)
Net Cash Used in Investing Activities	(3,347,506)		(6,177,173)		(6,170,162)
Financing Cash Flows
Long-Term Debt Borrowings	1,483,852		—		—
Long-Term Debt Repayments	(1,000,000)		(900,000)		(350,000)
Dividends Paid	(820,823)		(588,200)		(438,045)
Treasury Stock Purchased	(16,130)		(25,152)		(63,456)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan	16,169		17,946		20,560
Debt Issuance Costs	(2,649)		(5,016)		—
Repayment of Finance Lease Liabilities	(19,444)		(12,899)		(8,219)
Changes in Components of Working Capital Associated with Financing Activities	—		—		57
Net Cash Used in Financing Activities	(359,025)		(1,513,321)		(839,103)
Effect of Exchange Rate Changes on Cash	(296)		(348)		(37,937)
Increase in Cash and Cash Equivalents	1,300,956		472,338		721,406
Cash and Cash Equivalents at Beginning of Year	2,027,972		1,555,634		834,228
Cash and Cash Equivalents at End of Year	$	3,328,928	$	2,027,972	$	1,555,634

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

Principles of Consolidation.  The consolidated financial statements of EOG Resources, Inc. (EOG) include the accounts of all domestic and foreign subsidiaries.  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, commodity derivative contracts, accounts receivable, accounts payable and current and long-term debt.  The carrying values of cash and cash equivalents, commodity derivative contracts, accounts receivable and accounts payable approximate fair value (see Notes 2 and 12).

Effective January 1, 2020, EOG adopted the provisions of Accounting Standards Update (ASU) 2016-13, "Measurement of Credit Losses on Financial Instruments" (ASU 2016-13). ASU 2016-13 changes the impairment model for financial assets and certain other instruments by requiring entities to adopt a forward-looking expected loss model that will result in earlier recognition of credit losses. EOG elected to adopt ASU 2016-13 using the modified retrospective approach with a cumulative effect adjustment to retained earnings as of the effective date. Financial results reported in periods prior to January 1, 2020, are unchanged. EOG assessed its applicable financial assets, which are primarily its accounts receivable from hydrocarbon sales and joint interest billings to third-party companies, including foreign state-owned entities in the oil and gas industry. Based on its assessment and various potential remedies ensuring collection, EOG did not record an impact to retained earnings upon adoption and expects current and future credit losses to be immaterial. EOG continues to monitor the credit risk from third-party companies to determine if expected credit losses may become material.

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.

F-10

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 costs, 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 asset.  If the expected undiscounted future cash flows, based on EOG's estimate of (and assumptions regarding) future crude oil, natural gas liquids (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.

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

Revenue Recognition. Effective January 1, 2018, EOG adopted the provisions of ASU 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09). ASU 2014-09 and other related ASUs require entities to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. EOG elected to adopt ASU 2014-09 using the modified retrospective approach, which required EOG to recognize in retained earnings the cumulative effect at the date of adoption for all existing contracts with customers which were not substantially complete as of January 1, 2018. There was no impact to retained earnings upon adoption of ASU 2014-09.

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

In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements within its United States segment as Gathering and Processing Costs, instead of as a deduction to Revenues within its Consolidated Statements of Income (Loss) and Comprehensive Income (Loss). There was no impact to operating income, net income or cash flows resulting from changes to the presentation of natural gas processing fees. The impacts of the adoption of ASU 2014-09 for the year ended December 31, 2018, were as follows (in thousands):

F-11

	As Reported		Amounts Without Adoption of ASU 2014-09		Effect of Change
Operating Revenues and Other
Crude Oil and Condensate	$	9,517,440	$	9,517,440	$	—
Natural Gas Liquids	1,127,510		1,121,237		6,273
Natural Gas	1,301,537		1,104,095		197,442
Gathering, Processing and Marketing	5,230,355		5,211,136		19,219
Total Operating Revenues and Other	17,275,399		17,052,465		222,934
Operating Expenses
Gathering and Processing Costs	436,973		233,258		203,715
Marketing Costs	5,203,243		5,184,024		19,219
Total Operating Expenses	12,806,053		12,583,119		222,934
Operating Income	4,469,346		4,469,346		—

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, 2020 and 2019 and upon adoption of ASU 2014-09 effective January 1, 2018, were $1,337 million, $1,619 million and $1,460 million, respectively, and were included in Accounts Receivable, Net on the Consolidated Balance Sheets. Losses incurred on receivables from contracts with customers are infrequent and have been immaterial.

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 processing fees recognized as Gathering and Processing Costs.

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

F-12

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.

Other Property, Plant and Equipment.  Other property, plant and equipment consists of gathering and processing assets, compressors, buildings and leasehold improvements, sand processing assets, 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.

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. The capitalization of interest is excluded on significant acquisitions of unproved oil and gas properties financed through non-interest-bearing instruments, such as the issuance of shares of Common Stock, or through non-cash property exchanges.

Accounting for Risk Management Activities.  Derivative instruments are recorded on the balance sheet as either an asset or liability measured at fair value, and changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met.  During the three-year period ended December 31, 2020, 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 Commodity Derivative Contracts on the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss).  The related cash flow impact of settled contracts is reflected as cash flows from operating activities.  EOG employs net presentation of derivative assets and liabilities for financial reporting purposes when such assets and liabilities are with the same counterparty and subject to a master netting arrangement.  See Note 12.

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

Foreign Currency Translation.  The United States dollar is the functional currency for all of EOG's consolidated subsidiaries except for its Canadian subsidiaries, for which the functional currency is the Canadian dollar, and its United Kingdom subsidiary (which was sold in the fourth quarter of 2018), for which the functional currency was the British pound.  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 Notes 4 and 17.

Net Income (Loss) Per Share.  Basic net income (loss) per share is computed on the basis of the weighted-average number of common shares outstanding during the period.  Diluted net income (loss) 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. Effective January 1, 2019, EOG adopted the provisions of ASU 2016-02, "Leases (Topic 842)" (ASU 2016-02). ASU 2016-02 and other related ASUs require that lessees recognize a right-of-use (ROU) asset and related lease liability, representing the obligation to make lease payments for certain lease transactions, on the Consolidated Balance Sheets and disclose additional leasing information.

F-13

EOG elected to adopt ASU 2016-02 and other related ASUs using the modified retrospective approach with a cumulative-effect adjustment to the opening balance of retained earnings as of the effective date. Financial results reported in periods prior to January 1, 2019, are unchanged. Additionally, EOG elected the package of practical expedients within ASU 2016-02 that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases, or (iii) initial direct costs for any existing leases, but did not elect the practical expedient of hindsight when determining the lease term of existing contracts at the effective date. EOG also elected the practical expedient under ASU 2018-01, "Leases (Topic 842) - Land Easement Practical Expedient for Transition to Topic 842," and did not evaluate existing or expired land easements not previously accounted for as leases prior to the January 1, 2019 effective date. There was no impact to retained earnings upon adoption of ASU 2016-02 and other related ASUs.

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 ASU 2016-02. 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.

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 from all leases, excluding those for fracturing services, real estate and salt water disposal, as lease payments under these contracts contain significant non-lease components, such as labor and operating costs. See Note 18.

Recently Issued Accounting Standards. In March 2020, the FASB issued ASU 2020-04, "Reference Rate Reform (Topic 848)" (ASU 2020-04), which provides optional expedients and exceptions for accounting treatment of contracts which are affected by the anticipated discontinuation of the London InterBank Offered Rate (LIBOR) and other rates resulting from rate reform. Contract terms that are modified due to the replacement of a reference rate are not required to be remeasured or reassessed under relevant accounting standards. Early adoption is permitted. ASU 2020-04 covers certain contracts which reference these rates and that are entered into on or before December 31, 2022. EOG is evaluating the provisions of ASU 2020-04 and has not determined the full impact on its consolidated financial statements and related disclosures related to its $2.0 billion senior unsecured Revolving Credit Agreement.

In December 2019, the FASB issued ASU 2019-12, "Income Taxes (Topic 740) ‑ Simplifying the Accounting for Income Taxes" (ASU 2019-12), which amends certain aspects of accounting for income taxes. ASU 2019-12 removes specific exceptions within existing U.S. GAAP related to the incremental approach for intraperiod tax allocation and to the general methodology for calculating income taxes in interim periods, among other changes. ASU 2019-12 also requires an entity to reflect the effect of an enacted change in tax laws or rates in the annual effective tax rate computation in the interim period that includes the enactment date, among other requirements. ASU 2019-12 is effective for interim and annual periods beginning after December 15, 2020, and early adoption is permitted. EOG will adopt ASU 2019-12 effective January 1, 2021, with all of the anticipated and applicable effects to be required on a prospective basis. EOG does not expect the adoption of ASU 2019-12 to have a material impact on its consolidated financial statements and related disclosures.

F-14

2.  Long-Term Debt

Long-Term Debt at December 31, 2020 and 2019 consisted of the following (in thousands):

	2020		2019
4.40% Senior Notes due 2020	$	—	$	500,000
2.45% Senior Notes due 2020	—		500,000
4.100% Senior Notes due 2021	750,000		750,000
2.625% Senior Notes due 2023	1,250,000		1,250,000
3.15% Senior Notes due 2025	500,000		500,000
4.15% Senior Notes due 2026	750,000		750,000
6.65% Senior Notes due 2028	140,000		140,000
4.375% Senior Notes due 2030	750,000		—
3.90% Senior Notes due 2035	500,000		500,000
5.10% Senior Notes due 2036	250,000		250,000
4.950% Senior Notes due 2050	750,000		—
Long-Term Debt	5,640,000		5,140,000
Finance Leases (see Note 18)	212,217		57,900
Less: Current Portion of Long-Term Debt	781,054		1,014,524
Unamortized Debt Discount	30,931		19,528
Debt Issuance Costs	4,881		2,929
Total Long-Term Debt	$	5,035,351	$	4,160,919

At December 31, 2020, the aggregate annual maturities of long-term debt (excluding finance lease obligations) were $750 million in 2021, zero in 2022, $1.25 billion in 2023, zero in 2024 and $500 million in 2025. 

At December 31, 2020 and 2019, EOG had no outstanding commercial paper borrowings and did not utilize any commercial paper borrowings during 2020 and 2019.

On February 1, 2021, EOG repaid upon maturity the $750 million aggregate principal amount of its 4.100% Senior Notes due 2021.

On June 1, 2020, EOG repaid upon maturity the $500 million aggregate principal amount of its 4.40% Senior Notes due 2020.

On April 14, 2020, EOG closed on its offering of $750 million aggregate principal amount of its 4.375% Senior Notes due 2030 and $750 million aggregate principal amount of its 4.950% Senior Notes due 2050 (together, the Notes). Interest on the Notes is payable semi-annually in arrears on April 15 and October 15 of each year, beginning on October 15, 2020. EOG received net proceeds of $1.48 billion from the issuance of the Notes, which were used to repay the 4.40% Senior Notes due 2020 when they matured on June 1, 2020 (see below), and for general corporate purposes, including the funding of capital expenditures.

On April 1, 2020, EOG repaid upon maturity the $500 million aggregate principal amount of its 2.45% Senior Notes due 2020.

On June 27, 2019, EOG entered into a new $2.0 billion senior unsecured Revolving Credit Agreement (the Agreement) with domestic and foreign lenders (Banks). The Agreement replaced EOG's $2.0 billion senior unsecured Revolving Credit Agreement, dated as of July 21, 2015, with domestic and foreign lenders, which had a scheduled maturity date of July 21, 2020 and which was terminated by EOG (without penalty), effective as of June 27, 2019, in connection with the execution of the Agreement.

F-15

The Agreement has a scheduled maturity date of June 27, 2024, and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods subject to certain terms and conditions. The Agreement (i) commits the Banks to provide advances up to an aggregate principal amount of $2.0 billion at any one time outstanding, with an option for EOG to request increases in the aggregate commitments to an amount not to exceed $3.0 billion, subject to certain terms and conditions and (ii) includes a swingline subfacility and a letter of credit subfacility. Advances under the Agreement will accrue interest based, at EOG's option, on either the LIBOR plus an applicable margin (Eurodollar rate) or the base rate (as defined in the Agreement) plus an applicable margin. The Agreement contains representations, warranties, covenants and events of default that EOG believes are customary for investment-grade, senior unsecured commercial bank credit agreements, including a financial covenant for the maintenance of a ratio of total debt-to-capitalization (as such terms are defined in the Agreement) of no greater than 65%. At December 31, 2020, EOG was in compliance with this financial covenant. At December 31, 2020 and December 31, 2019, there were no borrowings or letters of credit outstanding under the Agreement. The Eurodollar rate and base rate (inclusive of the applicable margin), had there been any amounts borrowed under the Agreement at December 31, 2020, would have been 1.04% and 3.25%, respectively.

On June 3, 2019, EOG repaid upon maturity the $900 million aggregate principal amount of its 5.625% Senior Notes due 2019.

3.  Stockholders' Equity

Common Stock.  In September 2001, EOG's Board of Directors (Board) authorized the purchase of an aggregate maximum of 10 million shares of Common Stock that superseded all previous authorizations.  At December 31, 2020, 6,386,200 shares remained available for purchase under this authorization.  EOG last purchased shares of its Common Stock under this authorization in March 2003.  In addition, 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 do not count against the Board authorization discussed above.  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 25, 2021, the Board increased the quarterly cash dividend on the common stock from the previous $0.375 per share to $0.4125 per share, effective beginning with the dividend to be paid on April 30, 2021, to stockholders of record as of April 16, 2021.

On February 27, 2020, the Board increased the quarterly cash dividend on the common stock from the previous $0.2875 per share to $0.375 per share, effective beginning with the dividend to be paid on April 30, 2020, to stockholders of record as of April 16, 2020.

On May 2, 2019, the Board increased the quarterly cash dividend on the common stock from the previous $0.22 per share to $0.2875 per share, effective beginning with the dividend paid on July 31, 2019, to stockholders of record as of July 17, 2019.

On August 2, 2018, the Board increased the quarterly cash dividend on the common stock from the previous $0.1850 per share to $0.22 per share, effective beginning with the dividend paid on October 31, 2018, to stockholders of record as of October 17, 2018. On February 27, 2018, the Board increased the quarterly cash dividend on the common stock from the previous $0.1675 per share to $0.1850 per share, effective beginning with the dividend paid on April 30, 2018, to stockholders of record as of April 16, 2018.

F-16

The following summarizes Common Stock activity for each of the years ended December 31, 2018, 2019 and 2020 (in thousands):

	Common Shares
	Issued	Treasury	Outstanding
Balance at December 31, 2017	578,828	(351)	578,477
Common Stock Issued Under Stock-Based Compensation Plans	1,580	—	1,580
Treasury Stock Purchased (1)	—	(539)	(539)
Common Stock Issued Under Employee Stock Purchase Plan	—	180	180
Treasury Stock Issued Under Stock-Based Compensation Plans	—	325	325
Balance at December 31, 2018	580,408	(385)	580,023
Common Stock Issued Under Stock-Based Compensation Plans	1,688	—	1,688
Treasury Stock Purchased (1)	—	(310)	(310)
Common Stock Issued Under Employee Stock Purchase Plan	117	106	223
Treasury Stock Issued Under Stock-Based Compensation Plans	—	290	290
Balance at December 31, 2019	582,213	(299)	581,914
Common Stock Issued Under Stock-Based Compensation Plans	1,482	—	1,482
Treasury Stock Purchased (1)	—	(389)	(389)
Common Stock Issued Under Employee Stock Purchase Plan	—	377	377
Treasury Stock Issued Under Stock-Based Compensation Plans	—	187	187
Balance at December 31, 2020	583,695	(124)	583,571

(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.

Preferred Stock.  EOG currently has one authorized series of preferred stock.  As of December 31, 2020, there were no shares of preferred stock outstanding.

F-17

4.  Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss includes certain transactions that have generally been reported in the Consolidated Statements of Stockholders' Equity. The components of Accumulated Other Comprehensive Loss at December 31, 2020 and 2019 consisted of the following (in thousands):

	Foreign Currency Translation Adjustment		Other		Total
December 31, 2018	$	174	$	(1,532)	$	(1,358)
Cumulative effect of accounting changes	—		267		267
Other comprehensive loss before taxes	(2,883)		(533)		(3,416)
Tax effects	—		(145)		(145)
Other comprehensive loss	(2,883)		(678)		(3,561)
December 31, 2019	(2,709)		(1,943)		(4,652)
Other comprehensive loss before taxes	(7,346)		(183)		(7,529)
Tax effects	—		(147)		(147)
Other comprehensive loss	(7,346)		(330)		(7,676)
December 31, 2020	$	(10,055)	$	(2,273)	$	(12,328)

    No significant amount was reclassified out of Accumulated Other Comprehensive Loss during the years ended December 31, 2020, 2019 and 2018.

5.  Other Income, Net

Other income, net for 2020 included interest income ($12 million), partially offset by equity losses from investments in ammonia plants in Trinidad ($2 million). Other income, net for 2019 included interest income ($26 million) and net foreign currency transaction gains ($2 million). Other income, net for 2018 included interest income ($12 million), a downward adjustment to deferred compensation expense ($6 million) and equity income from investments in ammonia plants in Trinidad ($2 million), partially offset by net foreign currency transaction losses ($7 million).

F-18

6.  Income Taxes

The principal components of EOG's total net deferred income tax liabilities at December 31, 2020 and 2019 were as follows (in thousands):

	2020		2019
Deferred Income Tax Assets (Liabilities)
Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization	$	25,129	$	5,825
Foreign Net Operating Loss	74,280		66,675
Foreign Valuation Allowances	(97,499)		(70,455)
Foreign Other	217		318
Total Net Deferred Income Tax Assets	$	2,127	$	2,363
Deferred Income Tax (Assets) Liabilities
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization	$	5,028,010	$	5,277,550
Commodity Hedging Contracts	14,518		(4,699)
Deferred Compensation Plans	(42,594)		(47,650)
Accrued Expenses and Liabilities	—		(8,502)
Equity Awards	(102,944)		(108,324)
Alternative Minimum Tax Credit Carryforward	—		(31,904)
Undistributed Foreign Earnings	9,843		15,746
Other	(47,506)		(46,116)
Total Net Deferred Income Tax Liabilities	$	4,859,327	$	5,046,101
Total Net Deferred Income Tax Liabilities	$	4,857,200	$	5,043,738

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

	2020		2019		2018
United States	$	(756,479)	$	3,466,578	$	4,084,156
Foreign	17,425		78,689		156,842
Total	$	(739,054)	$	3,545,267	$	4,240,998

F-19

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

	2020		2019		2018
Current:
Federal	$	(107,834)	$	(152,258)	$	(303,853)
State	6,790		10,819		17,048
Foreign	40,248		81,426		65,615
Total	(60,796)		(60,013)		(221,190)
Deferred:
Federal	(153,027)		626,901		862,075
State	(15,400)		32,541		43,293
Foreign	(17,963)		(27,784)		(11,212)
Total	(186,390)		631,658		894,156
Other Non-Current: (1)
Federal	112,704		245,125		148,992
Foreign	—		(6,413)		—
Total	112,704		238,712		148,992
Income Tax Provision (Benefit)	$	(134,482)	$	810,357	$	821,958

(1)    Includes changes in certain amounts that are expected to be paid or received beyond the next twelve months. The primary component is refundable alternative minimum tax (AMT) credits.

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:

	2020		2019		2018
Statutory Federal Income Tax Rate	21.00	%	21.00	%	21.00	%
State Income Tax, Net of Federal Benefit	0.92		0.97		1.12
Income Tax Provision Related to Foreign Operations	(0.09)		0.87		0.51
Income Tax Provision Related to Canadian Operations	(2.43)		—		—
TCJA (1)	—		—		(2.60)		(2)
Share-Based Compensation	(2.94)		0.02		(0.47)
Other	1.74		—		(0.18)
Effective Income Tax Rate	18.20	%	22.86	%	19.38	%

(1)    The Tax Cuts and Jobs Act (TCJA) was enacted in 2017 and required certain measurement-period adjustments in 2018.

(2)    Includes impact of utilizing certain tax net operating losses (NOLs) ((1.2)%), the reversal of the federal sequestration charge ((1.0)%) and other TCJA impacts ((0.4)%).

The net effective tax rate of 18% in 2020 was lower than the prior year rate of 23% primarily due to taxes attributable to EOG's foreign operations and increased stock-based compensation tax deficiencies.

Deferred tax assets are recorded for certain tax benefits, including tax 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-20

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

	2020		2019		2018
Beginning Balance	$	200,831	$	167,142	$	466,421
Increase (1)	25,573		30,673		23,062
Decrease (2)	(11,343)		(75)		(26,219)
Other (3)	3,942		3,091		(296,122)
Ending Balance	$	219,003	$	200,831	$	167,142

(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. The United Kingdom operations were sold in the fourth quarter of 2018.

As of December 31, 2020, EOG had state income tax NOLs of approximately $1.9 billion, which, if unused, expire between 2021 and 2039. EOG also has Canadian NOLs of $275 million, some of which can be carried forward up to 20 years. As described above, these NOLs and other less significant tax benefits have been evaluated for the likelihood of utilization, and valuation allowances have been established for the portion of these deferred income tax assets that do not meet the “more likely than not” threshold.

The total balance of unrecognized tax benefits for all jurisdictions at December 31, 2020, was $10 million, resulting from the tax treatment of certain compensation deductions, of which the full amount may potentially have an earnings impact. During the fourth quarter of 2020, EOG settled uncertain tax positions resulting from its tax treatment of research and experiential expenditures related to certain innovations in its horizontal drilling and completion operations for taxable years 2016 and 2017. Consequently, the balance of uncertain tax positions and earnings for the period decreased $29 million and $5 million, respectively. EOG records interest and penalties related to unrecognized tax benefits to its income tax provision. No interest expense has been recognized in the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) related to the remaining unrecognized tax benefits as these positions will be claimed on amended returns or as self-proposed audit adjustments, which, if sustained, will result in refunds. EOG does not anticipate that the amount of the unrecognized tax benefits will change materially during 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 (2016), Canada (2016), Trinidad (2013) and China (2010).

EOG's foreign subsidiaries' undistributed earnings are not considered to be permanently reinvested outside of the U.S. Accordingly, EOG may be required to accrue certain U.S. federal, state, and foreign deferred income taxes on these undistributed earnings as well as on any other outside basis differences related to its investments in these subsidiaries. As of December 31, 2020, EOG has cumulatively recorded $10 million of deferred foreign income taxes for withholdings on its undistributed foreign earnings. 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 2020, EOG maintained various stock-based compensation plans as discussed below.  EOG recognizes compensation expense on grants of stock options, SARs, restricted stock and restricted stock units, 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-21

Stock-based compensation expense is included on the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) 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, 2020, 2019 and 2018 was as follows (in millions):

	2020		2019		2018
Lease and Well	$	52	$	56	$	51
Gathering and Processing Costs	1		1		1
Exploration Costs	21		26		25
General and Administrative	72		92		78
Total	$	146	$	175	$	155

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

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 Committee's certification of the applicable performance multiple

At December 31, 2020, approximately 2.0 million common shares remained available for grant under the 2008 Plan.  EOG's policy is to issue shares related to the 2008 Plan from previously authorized unissued shares or treasury shares to the extent treasury shares are available.

During 2020, 2019 and 2018, EOG issued shares in connection with stock option/SAR exercises, restricted stock grants, restricted stock unit and performance unit releases and ESPP purchases.  Net tax deficiencies and excess tax benefits recognized within the income tax provision were $(22) million, $(1) million and $20 million for the years ended December 31, 2020, 2019 and 2018, 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) have been or may be granted options to purchase shares of Common Stock.  In addition, participants in EOG's stock plans (including the 2008 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'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.

F-22

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 $62 million, $63 million and $60 million for the years ended December 31, 2020, 2019 and 2018, respectively.

Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants for the years ended December 31, 2020, 2019 and 2018 were as follows:

	Stock Options/SARs									ESPP
	2020			2019			2018			2020			2019			2018
Weighted Average Fair Value of Grants	$	11.06		$	19.49		$	33.46		$	19.14		$	22.83		$	25.75
Expected Volatility	44.47		%	32.02		%	28.23		%	53.48		%	34.78		%	24.59		%
Risk-Free Interest Rate	0.21		%	1.69		%	2.68		%	0.90		%	2.27		%	1.89		%
Dividend Yield	3.27		%	1.39		%	0.72		%	2.27		%	1.04		%	0.64		%
Expected Life	5.2 years			5.1 years			5.0 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, 2020, 2019 and 2018 (stock options and SARs in thousands):

	2020			2019			2018
	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	9,395	$	94.53	8,310	$	96.90	9,103	$	83.89
Granted	1,996	37.63		1,965	75.39		1,906	126.49
Exercised (1)	(23)	69.59		(606)	61.43		(2,493)	72.21
Forfeited	(1,182)	88.93		(274)	102.57		(206)	94.43
Outstanding at December 31	10,186	84.08		9,395	94.53		8,310	96.90
Stock Options/SARs Exercisable at December 31	6,343	96.41		5,275	94.21		3,969	85.82

(1)The total intrinsic value of stock options/SARs exercised during the years 2020, 2019 and 2018 was $0.4 million, $14 million and $118 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, 2020, there were 9.9 million stock options/SARs vested or expected to vest with a weighted average grant price of $84.76 per share, an intrinsic value of $22.5 million and a weighted average remaining contractual life of 4.2 years.

F-23

The following table summarizes certain information for the stock options and SARs outstanding and exercisable at December 31, 2020 (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 $  43.99	1,974	7	$	37.43			10	1	$	37.44
44.00 to     74.99	872	2	69.37				846	2	69.47
75.00 to     75.99	1,863	6	75.09				636	5	75.09
76.00 to     95.99	1,242	3	94.47				1,215	3	94.63
96.00 to   101.99	2,477	3	97.95				2,457	3	97.95
102.00 to   129.99	1,758	5	126.44				1,179	5	126.37
	10,186	4	84.08		$	24,578	6,343	3	96.41		$	124

(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 thousands.

At December 31, 2020, unrecognized compensation expense related to non-vested stock option and SAR grants totaled $53 million.  This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.1 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, 2020, approximately 1.9 million shares of Common Stock remained available for grant under the ESPP.  The following table summarizes ESPP activity for the years ended December 31, 2020, 2019 and 2018 (in thousands, except number of participants):

	2020		2019		2018
Approximate Number of Participants	2,063		1,998		1,934
Shares Purchased	377		224		180
Aggregate Purchase Price	$	16,103	$	16,533	$	14,887

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 $75 million, $97 million and $81 million for the years ended December 31, 2020, 2019 and 2018, respectively.

F-24

The following table sets forth the restricted stock and restricted stock unit transactions for the years ended December 31, 2020, 2019 and 2018 (shares and units in thousands):

	2020			2019			2018
	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	4,546	$	90.16	3,792	$	96.64	3,905	$	88.57
Granted	1,488	38.10		1,749	80.01		812	117.55
Released (1)	(1,213)	85.92		(855)	96.93		(740)	78.16
Forfeited	(79)	86.52		(140)	97.54		(185)	92.12
Outstanding at December 31 (2)	4,742	74.97		4,546	90.16		3,792	96.64

(1)The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2020, 2019 and 2018 was $48 million, $70 million and $84 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)The total intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2020, 2019 and 2018 was $236 million, $381 million and $331 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, 2020, unrecognized compensation expense related to restricted stock and restricted stock units totaled $178 million. Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 1.6 years.

Performance Units.  EOG has granted performance units (Performance Awards) to its executive officers annually since 2012. As more fully discussed in the grant agreements, the performance metric applicable to these performance-based grants is EOG's total shareholder return over a three-year performance period relative to the total shareholder return of a designated group of peer companies (Performance Period). Upon the application of the performance multiple at the completion of the Performance Period, a minimum of 0% and a maximum of 200% of the Performance Awards granted could be outstanding. The fair value of the Performance Awards is estimated using a Monte Carlo simulation. Stock-based compensation expense related to the Performance Award grants totaled $9 million, $15 million and $14 million for the years ended December 31, 2020, 2019 and 2018, respectively.

  Weighted average fair values and valuation assumptions used to value Performance Awards during the years ended December 31, 2020, 2019 and 2018 were as follows:

	2020			2019			2018
Weighted Average Fair Value of Grants	$	42.77		$	79.98		$	136.74
Expected Volatility	47.27		%	29.20		%	29.92		%
Risk-Free Interest Rate	0.16		%	1.51		%	2.85		%

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-25

The following table sets forth the Performance Award transactions for the years ended December 31, 2020, 2019 and 2018 (units in thousands):

	2020				2019			2018
	Number of Units		Weighted Average Price per Grant Date		Number of Units	Weighted Average Price per Grant Date		Number of Units	Weighted Average Price per Grant Date
Outstanding at January 1	598		$	92.19	539	$	101.53	502	$	90.96
Granted	172		37.44		172	75.09		113	125.73
Granted for Performance Multiple (1)	66		100.95		72	69.43		72	101.87
Released (2)	(223)		88.52		(185)	94.63		(148)	84.43
Forfeited	—		—		—	—		—	—
Outstanding at December 31 (3)	613	(4)	79.10		598	92.19		539	101.53

(1)Upon completion of the Performance Period for the Performance Awards granted in 2016, 2015 and 2014, a performance multiple of 150%, 200% and 200%, respectively, was applied to each of the grants resulting in additional grants of Performance Awards in February 2020, 2019 and 2018.

(2)The total intrinsic value of Performance Awards released during the years ended December 31, 2020, 2019 and 2018 was $13 million, $15 million and $18 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date Performance Awards are released.

(3)The total intrinsic value of Performance Awards outstanding at December 31, 2020, 2019 and 2018 was $31 million, $50 million and $47 million, respectively. The intrinsic value is based on the closing market price of the Common Stock on the last trading day of the year.

(4)Upon the application of the relevant performance multiple at the completion of each of the remaining Performance Periods, a minimum of 77 and a maximum of 1,149 Performance Awards could be outstanding.

At December 31, 2020, unrecognized compensation expense related to Performance Awards totaled $5 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 1.9 years.

Upon completion of the Performance Period for the Performance Awards granted in September 2017, a performance multiple of 125% was applied to the grants resulting in an additional grant of 19,629 Performance Awards in February 2021.

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 $46 million, $51 million and $43 million for 2020, 2019 and 2018, 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 2020, 2019 and 2018, respectively.

For the Trinidadian defined benefit pension plan, the benefit obligation, fair value of plan assets and accrued benefit cost totaled $13 million, $12 million and $0.1 million, respectively, at December 31, 2020, and $12 million, $10 million and $0.1 million, respectively, at December 31, 2019.

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-26

8.  Commitments and Contingencies

Letters of Credit and Guarantees.  At December 31, 2020 and 2019, respectively, EOG had standby letters of credit and guarantees outstanding totaling $854 million and $902 million, primarily representing guarantees of payment or performance obligations on behalf of subsidiaries. As of February 18, 2021, EOG had received no demands for payment under these guarantees.

Minimum Commitments. At December 31, 2020, 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, 2020, were as follows (in millions):

	Total Minimum Commitments
2021	$	1,393
2022	1,263
2023	1,064
2024	790
2025	649
2026 and beyond	2,764
	$	7,923

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 (Loss) Per Share

The following table sets forth the computation of Net Income (Loss) Per Share for the years ended December 31, 2020, 2019 and 2018 (in thousands, except per share data):

	2020		2019		2018
Numerator for Basic and Diluted Earnings per Share -
Net Income (Loss)	$	(604,572)	$	2,734,910	$	3,419,040
Denominator for Basic Earnings per Share -
Weighted Average Shares	578,949		577,670		576,578
Potential Dilutive Common Shares -
Stock Options/SARs	—		258		1,137
Restricted Stock/Units and Performance Units	—		2,849		2,726
Denominator for Diluted Earnings per Share -
Adjusted Diluted Weighted Average Shares	578,949		580,777		580,441
Net Income (Loss) Per Share
Basic	$	(1.04)	$	4.73	$	5.93
Diluted	$	(1.04)	$	4.71	$	5.89

The diluted earnings per share calculation excludes stock options, SARs, restricted stock, restricted stock units, performance units and ESPP grants that were anti-dilutive.  Shares underlying the excluded stock options, SARs and ESPP grants were 9.6 million, 6.1 million and 0.6 million for the years ended December 31, 2020, 2019 and 2018, respectively. Shares underlying the excluded restricted stock, restricted stock unit and performance unit grants were 5.0 million shares for the year ended December 31, 2020.

F-27

10.  Supplemental Cash Flow Information

Net cash paid (received) for interest and income taxes was as follows for the years ended December 31, 2020, 2019 and 2018 (in thousands):

	2020		2019		2018
Interest, Net of Capitalized Interest	$	205,447	$	186,546	$	243,279
Income Taxes, Net of Refunds Received	$	(205,795)	$	(291,849)	$	75,634

EOG's accrued capital expenditures at December 31, 2020, 2019 and 2018 were $414 million, $612 million and $592 million, respectively.

Non-cash investing activities for the year ended December 31, 2020, included additions of $212 million to EOG's oil and gas properties as a result of property exchanges and an addition of $174 million to EOG's other property, plant and equipment made in connection with finance lease transactions for storage facilities.

Non-cash investing activities for the year ended December 31, 2019, included additions of $150 million to EOG's oil and gas properties as a result of property exchanges.

Non-cash investing activities for the year ended December 31, 2018, included additions of $362 million to EOG's oil and gas properties as a result of property exchanges and an addition of $49 million to EOG's other property, plant and equipment primarily in connection with a finance lease transaction in the Permian Basin.

Cash paid for leases for the years ended December 31, 2020 and 2019, 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 in the United States, Trinidad and China and its exploration program in the Sultanate of Oman (Oman).  For segment reporting purposes, the chief operating decision makers consider the major United States producing areas to be one operating segment.

F-28

Financial information by reportable segment is presented below as of and for the years ended December 31, 2020, 2019 and 2018 (in thousands):

	United States		Trinidad		Other International (1)		Total
2020
Crude Oil and Condensate	$	5,773,582	$	10,723	$	1,304	$	5,785,609
Natural Gas Liquids	667,514		—		—		667,514
Natural Gas	614,002		168,967		54,164		837,133
Gains on Mark-to-Market Commodity Derivative Contracts	1,144,737		—		—		1,144,737
Gathering, Processing and Marketing	2,581,493		1,491		—		2,582,984
Gains (Losses) on Asset Dispositions, Net	(47,018)		(44)		179		(46,883)
Other, Net	60,989		(35)		—		60,954
Operating Revenues and Other (2)	10,795,299		181,102		55,647		11,032,048
Depreciation, Depletion and Amortization	3,323,800		60,629		15,924		3,400,353
Operating Income (Loss) (3)	(545,566)		74,801		(73,251)		(544,016)
Interest Income	10,783		922		34		11,739
Other Income (Expense)	153		(2,129)		465		(1,511)
Net Interest Expense	205,266		—		—		205,266
Income (Loss) Before Income Taxes	(739,896)		73,594		(72,752)		(739,054)
Income Tax Provision (Benefit)	(156,834)		14,568		7,784		(134,482)
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	3,316,724		83,173		41,961		3,441,858
Total Property, Plant and Equipment, Net	28,283,027		210,278		105,322		28,598,627
Total Assets	35,047,485		546,120		210,996		35,804,601

2019
Crude Oil and Condensate	$	9,599,125	$	11,138	$	2,269	$	9,612,532
Natural Gas Liquids	784,818		—		—		784,818
Natural Gas	866,911		258,819		58,365		1,184,095
Gains on Mark-to-Market Commodity Derivative Contracts	180,275		—		—		180,275
Gathering, Processing and Marketing	5,355,463		4,819		—		5,360,282
Gains (Losses) on Asset Dispositions, Net	131,446		(3,688)		(4,145)		123,613
Other, Net	134,325		18		15		134,358
Operating Revenues and Other (4)	17,052,363		271,106		56,504		17,379,973
Depreciation, Depletion and Amortization	3,652,294		79,389		18,021		3,749,704
Operating Income (Loss)	3,618,907		112,790		(32,686)		3,699,011
Interest Income	22,122		3,686		218		26,026
Other Income	3,235		727		1,397		5,359
Net Interest Expense	192,587		—		(7,458)		185,129
Income (Loss) Before Income Taxes	3,451,677		117,203		(23,613)		3,545,267
Income Tax Provision	760,881		40,901		8,575		810,357
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	6,208,394		53,325		12,233		6,273,952
Total Property, Plant and Equipment, Net	30,101,857		184,606		78,132		30,364,595
Total Assets	36,274,942		705,747		143,919		37,124,608

F-29

	United States		Trinidad		Other International (1)		Total
2018
Crude Oil and Condensate	$	9,390,244	$	17,059	$	110,137	$	9,517,440
Natural Gas Liquids	1,127,510		—		—		1,127,510
Natural Gas	970,866		285,053		45,618		1,301,537
Loses on Mark-to-Market Commodity Derivative Contracts	(165,640)		—		—		(165,640)
Gathering, Processing and Marketing	5,227,051		3,304		—		5,230,355
Gains on Asset Dispositions, Net	154,852		4,493		15,217		174,562
Other, Net	89,708		(49)		(24)		89,635
Operating Revenues and Other (5)	16,794,591		309,860		170,948		17,275,399
Depreciation, Depletion and Amortization	3,296,499		91,971		46,938		3,435,408
Operating Income (Loss)	4,334,364		147,240		(12,258)		4,469,346
Interest Income	9,326		1,612		608		11,546
Other Income (Expense)	9,580		2,436		(6,858)		5,158
Net Interest Expense	253,352		—		(8,300)		245,052
Income (Loss) Before Income Taxes	4,099,918		151,288		(10,208)		4,240,998
Income Tax Provision	765,986		54,272		1,700		821,958
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	6,155,874		1,618		37,838		6,195,330
Total Property, Plant and Equipment, Net	27,786,086		210,183		79,250		28,075,519
Total Assets	33,178,733		629,633		126,108		33,934,474

(1)Other International primarily consists of EOG's United Kingdom, China and Canada operations. EOG began an exploration program in Oman in the third quarter of 2020. The United Kingdom operations were sold in the fourth quarter of 2018.

(2)EOG had sales activity with three significant purchasers in 2020, each totaling $1.1 billion of consolidated Operating Revenues and Other in the United States segment.

(3)EOG recorded pretax impairment charges of $1,570 million in 2020 for proved oil and gas properties, leasehold costs and other assets due to the decline in commodity prices and revisions of asset retirement obligations for certain properties in the United States segment. In addition, EOG recorded pretax impairment charges of $228 million in 2020 for owned and leased sand and crude-by-rail assets, also in the United States segment. EOG recorded pretax impairment charges of $81 million in 2020 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 Notes 13 and 14.

(4)EOG had sales activity with two significant purchasers in 2019, one totaling $2.4 billion and the other totaling $2.2 billion of consolidated Operating Revenues and Other in the United States segment.

(5)EOG had sales activity with two significant purchasers in 2018, one totaling $2.6 billion and the other totaling $2.3 billion of consolidated Operating Revenues and Other in the United States segment.

F-30

12.  Risk Management Activities

Commodity Price Risks.  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 2020, 2019 and 2018, 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 Commodity Derivative Contracts on the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss).  The related cash flow impact is reflected in Cash Flows from Operating Activities.  During 2020, 2019 and 2018, EOG recognized net gains (losses) on the mark-to-market of financial commodity derivative contracts of $1,145 million, $180 million and $(166) million, respectively, which included cash received from (payments for) settlements of crude oil, NGLs and natural gas derivative contracts of $1,071 million, $231 million and $(259) million, respectively.

Crude Oil Derivative Contracts. Prices received by EOG for its crude oil production generally vary from U.S. New York Mercantile Exchange (NYMEX) West Texas Intermediate (WTI) prices due to adjustments for delivery location (basis) and other factors. EOG has entered into crude oil basis swap contracts in order to fix the differential between Intercontinental Exchange (ICE) Brent pricing and pricing in Cushing, Oklahoma (ICE Brent Differential). Presented below is a comprehensive summary of EOG's ICE Brent Differential basis swap contracts as of December 31, 2020. The weighted average price differential expressed in dollars per barrel ($/Bbl) represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in barrels per day (Bbld) covered by the basis swap contracts.

ICE Brent Differential Basis Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)
2020
May 2020 (closed)	10,000	$	4.92

EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in Houston, Texas, and Cushing, Oklahoma (Houston Differential). Presented below is a comprehensive summary of EOG's Houston Differential basis swap contracts as of December 31, 2020. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.

Houston Differential Basis Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)
2020
May 2020 (closed)	10,000	$	1.55

F-31

EOG has also entered into crude oil swaps in order to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month (Roll Differential). Presented below is a comprehensive summary of EOG's Roll Differential basis swap contracts as of December 31, 2020. The weighted average price differential expressed in $/Bbl represents the amount of net addition (reduction) to delivery month prices for the notional volumes expressed in Bbld covered by the swap contracts.

Roll Differential Basis Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)
2020
February 1, 2020 through June 30, 2020 (closed)	10,000	$	0.70
July 1, 2020 through September 30, 2020 (closed)	88,000	(1.16)
October 1, 2020 through December 31, 2020 (closed)	66,000	(1.16)
2021
February 1, 2021 through December 31, 2021	25,000	$	0.10
2022
January 1, 2022 through December 31, 2022	50,000	$	0.11

In May 2020, EOG entered into crude oil Roll Differential basis swap contracts for the period from July 1, 2020 through September 30, 2020, with notional volumes of 22,000 Bbld at a weighted average price differential of $(0.43) per Bbl, and for the period from October 1, 2020 through December 31, 2020, with notional volumes of 44,000 Bbld at a weighted average price differential of $(0.73) per Bbl. These contracts partially offset certain outstanding Roll Differential basis swap contracts for the same time periods and volumes at a weighted average price differential of $(1.16) per Bbl. EOG paid net cash of $3.2 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.

Presented below is a comprehensive summary of EOG's crude oil NYMEX WTI price swap contracts as of December 31, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

Crude Oil NYMEX WTI Price Swap Contracts
	Volume (Bbld)	Weighted Average Price ($/Bbl)
2020
January 1, 2020 through March 31, 2020 (closed)	200,000	$	59.33
April 1, 2020 through May 31, 2020 (closed)	265,000	51.36

In April and May 2020, EOG entered into crude oil NYMEX WTI price swap contracts for the period from June 1, 2020 through June 30, 2020, with notional volumes of 265,000 Bbld at a weighted average price of $33.80 per Bbl, for the period from July 1, 2020 through July 31, 2020, with notional volumes of 254,000 Bbld at a weighted average price of $33.75 per Bbl, for the period from August 1, 2020 through September 30, 2020, with notional volumes of 154,000 Bbld at a weighted average price of $34.18 per Bbl and for the period from October 1, 2020 through December 31, 2020, with notional volumes of 47,000 Bbld at a weighted average price of $30.04 per Bbl. These contracts offset the remaining crude oil NYMEX WTI price swap contracts for the same time periods and volumes at a weighted average price of $51.36 per Bbl for the period from June 1, 2020 through June 30, 2020, $42.36 per Bbl for the period from July 1, 2020 through July 31, 2020, $50.42 per Bbl for the period from August 1, 2020 through September 30, 2020 and $31.00 per Bbl for the period from October 1, 2020 through December 31, 2020. EOG received net cash of $362.6 million through December 31, 2020, for the settlement of certain of these contracts, and expects to receive net cash of $1.4 million during January 2021 for the settlement of the remaining contracts. The offsetting contracts were excluded from the above table.

F-32

Presented below is a comprehensive summary of EOG's crude oil ICE Brent price swap contracts as of December 31, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

Crude Oil ICE Brent Price Swap Contracts
	Volume (Bbld)	Weighted Average Price ($/Bbl)
2020
April 2020 (closed)	75,000	$	25.66
May 2020 (closed)	35,000	26.53

NGLs Derivative Contracts. Presented below is a comprehensive summary of EOG's Mont Belvieu propane (non-TET) price swap contracts as of December 31, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

Mont Belvieu Propane Price Swap Contracts
	Volume (Bbld)	Weighted Average Price ($/Bbl)
2020
January 1, 2020 through February 29, 2020 (closed)	4,000	$	21.34
March 1, 2020 through April 30, 2020 (closed)	25,000	17.92

In April and May 2020, EOG entered into Mont Belvieu propane price swap contracts for the period from May 1, 2020 through December 31, 2020, with notional volumes of 25,000 Bbld at a weighted average price of $16.41 per Bbl. These contracts offset the remaining Mont Belvieu propane price swap contracts for the same time period with notional volumes of 25,000 Bbld at a weighted average price of $17.92 per Bbl. EOG received net cash of $8.0 million through December 31, 2020, for the settlement of certain of these contracts, and expects to receive net cash of $1.2 million during January 2021 for the settlement of the remaining contracts. The offsetting contracts were excluded from the above table.

Natural Gas Derivative Contracts. Presented below is a comprehensive summary of EOG's natural gas NYMEX Henry Hub price swap contracts as of December 31, 2020, with notional volumes sold (purchased) expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).

Natural Gas NYMEX Henry Hub Price Swap Contracts
	Volume (MMBtud)	Weighted Average Price ($/MMBtu)
2021
April 1, 2021 through December 31, 2021	500,000	$	2.99
2022
January 1, 2022 through December 31, 2022	20,000	$	2.75

In December 2020, EOG entered into natural gas NYMEX Henry Hub price swap contracts for the period from January 1, 2021 through March 31, 2021, with notional volumes of 500,000 MMBtud at a weighted average price of $2.43 per MMBtu. These contracts offset the remaining natural gas NYMEX Henry Hub price swap contracts for the same time period with notional volumes of 500,000 MMBtud at a weighted average price of $2.99 per MMBtu. EOG expects to receive net cash of $25.2 million during 2021 for the settlement of these contracts. The offsetting contracts were excluded from the above table.

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EOG has entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price. In March 2020, EOG executed the early termination provision granting EOG the right to terminate certain 2020 natural gas collar contracts with notional volumes of 250,000 MMBtud at a weighted average ceiling price of $2.50 per MMBtu and a weighted average floor price of $2.00 per MMBtu for the period from April 1, 2020 through July 31, 2020. EOG received net cash of $7.8 million for the settlement of these contracts. Presented below is a comprehensive summary of EOG's natural gas collar contracts as of December 31, 2020, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.

Natural Gas Collar Contracts
		Weighted Average Price ($/MMBtu)
	Volume (MMBtud)	Ceiling Price		Floor Price
2020
April 1, 2020 through July 31, 2020 (closed)	250,000	$	2.50	$	2.00

In April 2020, EOG entered into natural gas collar contracts for the period from August 1, 2020 through October 31, 2020, with notional volumes of 250,000 MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu. These contracts offset the remaining natural gas collar contracts for the same time period with notional volumes of 250,000 MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu. EOG received net cash of $1.1 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.

Prices received by EOG for its natural gas production generally vary from NYMEX Henry Hub prices due to adjustments for delivery location (basis) and other factors. EOG has entered into natural gas basis swap contracts in order to fix the differential between pricing in the Rocky Mountain area and NYMEX Henry Hub prices (Rockies Differential). Presented below is a comprehensive summary of EOG's Rockies Differential basis swap contracts as of December 31, 2020. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts.

Rockies Differential Basis Swap Contracts
	Volume (MMBtud)	Weighted Average Price Differential ($/MMBtu)
2020
January 1, 2020 through December 31, 2020 (closed)	30,000	$	0.55

EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Houston Ship Channel (HSC) and NYMEX Henry Hub prices (HSC Differential). In March 2020, EOG executed the early termination provision granting EOG the right to terminate certain 2020 HSC Differential basis swaps with notional volumes of 60,000 MMBtud at a weighted average price differential of $0.05 per MMBtu for the period from April 1, 2020 through December 31, 2020. EOG paid net cash of $0.4 million for the settlement of these contracts. Presented below is a comprehensive summary of EOG's HSC Differential basis swap contracts as of December 31, 2020. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts.

HSC Differential Basis Swap Contracts
	Volume (MMBtud)	Weighted Average Price Differential ($/MMBtu)
2020
January 1, 2020 through December 31, 2020 (closed)	60,000	$	0.05

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EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Waha Hub in West Texas and NYMEX Henry Hub prices (Waha Differential). Presented below is a comprehensive summary of EOG's Waha Differential basis swap contracts as of December 31, 2020. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts.

Waha Differential Basis Swap Contracts
	Volume (MMBtud)	Weighted Average Price Differential ($/MMBtu)
2020
January 1, 2020 through April 30, 2020 (closed)	50,000	$	1.40

In April 2020, EOG entered into Waha Differential basis swap contracts for the period from May 1, 2020 through December 31, 2020, with notional volumes of 50,000 MMBtud at a weighted average price differential of $0.43 per MMBtu. These contracts offset the remaining Waha Differential basis swap contracts for the same time period with notional volumes of 50,000 MMBtud at a weighted average price differential of $1.40 per MMBtu. EOG paid net cash of $11.9 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.

 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, 2020 and 2019, 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 thousands):

		Fair Value at December 31,
Description	Location on Balance Sheet	2020		2019
Asset Derivatives
Crude oil, NGLs and natural gas derivative contracts -
Current portion	Assets from Price Risk Management Activities (1)	$	64,559	$	1,299
Noncurrent portion	Other Assets	1,063		—
Liability Derivatives
Crude oil, NGLs and natural gas derivative contracts -
Current portion	Liabilities from Price Risk Management Activities (2)	$	—	$	20,194
Noncurrent Portion	Other Liabilities	455		—

(1)    The current portion of Assets from Price Risk Management Activities consists of gross assets of $3 million, partially offset by gross liabilities of $2 million, at December 31, 2019.

(2)    The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $23 million, partially offset by gross assets of $3 million at December 31, 2019.

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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, 2020, EOG's net accounts receivable balance related to United States hydrocarbon sales included two receivable balances, each of which accounted for more than 10% of the total balance.  The receivables were due from two petroleum refinery companies.  The related amounts were collected during early 2021.  At December 31, 2019, 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 2020.

In 2020 and 2019, all natural gas from EOG's Trinidad operations was sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary. In 2020 and 2019, all crude oil and condensate from EOG's Trinidad operations was sold to Heritage Petroleum Company Limited. In 2020 and 2019, all natural gas from EOG's China operations was sold to Petrochina Company Limited.

All of EOG's derivative instruments are covered by International Swap Dealers Association Master Agreements (ISDAs) with counterparties.  The ISDAs may contain provisions that require EOG, if it is the party in a net liability position, to post collateral when the amount of the net liability exceeds the threshold level specified for EOG'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 derivatives under the ISDA to be settled immediately.  See Note 13 for the aggregate fair value of all derivative instruments that were in a net asset position at December 31, 2020 and a net liability position at December 31, 2019.  EOG had no collateral posted and held no collateral at December 31, 2020 and 2019.

Substantially all of EOG's accounts receivable at December 31, 2020 and 2019 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, 2020, 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.

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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, 2020 and 2019. Amounts shown in thousands.

	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, 2020
Financial Assets (1):
Natural Gas Swaps	$	—	$	66,064	$	—	$	66,064
Financial Liabilities (2):
Crude Oil Roll Differential Swaps	—		897		—		897
At December 31, 2019
Financial Assets (1):
Natural Gas Liquids Swaps	$	—	$	3,401	$	—	$	3,401
Natural Gas Basis Swaps	—		970		—		970
Financial Liabilities (2):
Crude Oil Swaps	—		23,266		—		23,266

(1)    $65 million and $1 million are included in "Current Assets - Assets from Price Risk Management Activities" at December 31, 2020 and 2019, respectively, on the Consolidated Balance Sheets. $1 million is included in "Other Assets" at December 31, 2020, on the Consolidated Balance Sheets.

(2)    $1 million is included in "Other Liabilities" at December 31, 2020, on the Consolidated Balance Sheets. $20 million is included in "Current Liabilities - Liabilities from Price Risk Management Activities" at December 31, 2019 on the Consolidated Balance Sheets.

The estimated fair value of crude oil, NGLs and natural gas derivative contracts (including options/collars) was based upon forward commodity price curves based on quoted market prices.  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 asset. 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 2020, due to the decline in commodity prices and revisions of asset retirement obligations for certain properties, proved oil and gas properties with a carrying amount of $1,587 million were written down to their fair value of $319 million, resulting in pretax impairment charges of $1,268 million. In addition, EOG recorded pretax impairment charges in 2020 of $72 million for a commodity price-related write-down of other assets.

During 2019, proved oil and gas properties; other property, plant and equipment; and other assets with a carrying amount of $998 million were written down to their fair value of $701 million, resulting in pretax impairment charges of $297 million. Included in the $297 million pretax impairment charges are $152 million of impairments of proved oil and gas properties for which EOG utilized an accepted offer from a third-party purchaser as the basis for determining fair value. In addition, EOG recorded pretax impairment charges in 2019 of $90 million for a commodity price-related write-down of other assets.

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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, 2020 and 2019, respectively, EOG had outstanding $5,640 million and $5,140 million aggregate principal amount of senior notes, which had estimated fair values of approximately $6,505 million and $5,452 million, respectively. The estimated fair value of debt was based upon quoted market prices and, where such prices were not available, other observable (Level 2) inputs regarding interest rates available to EOG at year-end.

14.  Impairment Expense

Impairment expense was as follows for the years ended December 31, 2020, 2019 and 2018 (in thousands):

	2020		2019		2018
Proved properties (1)	$	1,268,073	$	206,469	$	120,859
Unproved properties (2)	472,143		220,444		173,383
Other assets (3)	299,851		90,983		48,732
Inventories	—		—		4,047
Firm commitment contracts (4)	59,713		—		—
Total	$	2,099,780	$	517,896	$	347,021

(1)    Impairments to proved oil and gas properties in 2020 included legacy and non-core natural gas and crude oil and combo plays. Impairments to proved oil and gas properties in 2019 and 2018 included domestic legacy natural gas assets. See Notes 1 and 13.

(2)    Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. Impairments of unproved oil and gas properties included charges of $252 million in 2020 for certain leasehold costs that are no longer expected to be developed before expiration. See Note 1.

(3)    Includes impairment charges for owned and leased sand and crude-by-rail assets of $228 million in 2020 (see Note 18) and a commodity price-related write-down of other assets of $72 million, $90 million and $49 million in 2020, 2019 and 2018, respectively (see Note 13).

(4)    Includes impairment charges of $60 million in 2020 for firm commitment contracts related to its decision to exit the Horn River Basin in British Columbia, Canada.

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, 2020 and 2019 (in thousands):

	2020		2019
Carrying Amount at Beginning of Period	$	1,110,710	$	954,377
Liabilities Incurred	57,477		98,874
Liabilities Settled (1)	(54,027)		(58,673)
Accretion	47,083		43,462
Revisions	53,888		72,425
Foreign Currency Translations	1,407		245
Carrying Amount at End of Period	$	1,216,538	$	1,110,710
Current Portion	$	49,548	$	37,127
Noncurrent Portion	$	1,166,990	$	1,073,583

(1)    Includes settlements related to asset sales.

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

16.  Exploratory Well Costs

EOG's net changes in capitalized exploratory well costs for the years ended December 31, 2020, 2019 and 2018 are presented below (in thousands):

	2020		2019		2018
Balance at January 1	$	25,897	$	4,121	$	2,167
Additions Pending the Determination of Proved Reserves	107,852		83,175		10,304
Reclassifications to Proved Properties	(81,071)		(39,325)		(7,917)
Costs Charged to Expense (1)	(23,822)		(22,074)		(433)
Balance at December 31	$	28,856	$	25,897	$	4,121

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

	2020		2019		2018
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	26,408	$	25,897	$	4,121
Capitalized exploratory well costs that have been capitalized for a period greater than one year (1)	2,448		—		—
Balance at December 31	$	28,856	$	25,897	$	4,121
Number of exploratory wells that have been capitalized for a period greater than one year	1		—		—

(1)    Consists of costs related to a project in the United States at December 31, 2020.

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17.  Acquisitions and Divestitures

During 2020, EOG paid cash for property acquisitions of $82 million in the United States and $38 million in Other International, primarily in Oman. Additionally during 2020, EOG recognized net losses on asset dispositions of $47 million primarily due to sales of proved properties and non-cash property exchanges of unproved leasehold in Texas and New Mexico and the disposition of the Marcellus Shale assets, and received proceeds of approximately $192 million.

During 2019, EOG paid cash for property acquisitions of $328 million in the United States. Additionally during 2019, EOG recognized net gains on asset dispositions of $124 million primarily due to sales of producing properties, acreage and other assets, as well as non-cash property exchanges in New Mexico, and received proceeds of approximately $140 million.

During 2018, EOG recognized net gains on asset dispositions of $175 million primarily due to non-cash property exchanges in Texas, New Mexico and Wyoming. Additionally, EOG received proceeds in 2018 of approximately $227 million, primarily due to the sale of its United Kingdom operations in the fourth quarter of 2018.

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, 2020 and 2019 were as follows (in millions):

	2020		2019
Operating Lease Cost (1)	$	393	$	497
Finance Lease Cost:
Amortization of Lease Assets	21		13
Interest on Lease Liabilities	4		2
Variable Lease Cost	91		138
Short-Term Lease Cost	194		333
Total Lease Cost	$	703	$	983

(1)    Operating lease cost includes impairment expenses of $35 million in 2020.

F-40

The following table sets forth the amounts and classification of EOG's outstanding ROU assets and related lease liabilities at December 31, 2020 and 2019 and supplemental information for the years ended December 31, 2020 and 2019 (in millions, except lease terms and discount rates):

Description	Location on Balance Sheet	2020		2019
Assets
Operating Leases	Other Assets	$	869	$	773
Finance Leases	Property, Plant and Equipment, Net (1)	206		53
Total		$	1,075	$	826
Liabilities
Current
Operating Leases	Current Portion of Operating Lease Liabilities	$	295	$	369
Finance Leases	Current Portion of Long-Term Debt	31		15
Long-Term
Operating Leases	Other Liabilities	641		430
Finance Leases	Long-Term Debt	181		43
Total		$	1,148	$	857

(1)    Finance lease assets are recorded net of accumulated amortization of $81 million and $60 million at December 31, 2020 and 2019, respectively.

	2020		2019
Weighted Average Remaining Lease Term (in years):
Operating Leases	5.3		3.2
Finance Leases	7.6		4.7
Weighted Average Discount Rate:
Operating Leases	3.4	%	3.5	%
Finance Leases	2.8	%	3.0	%

Cash paid for leases for the years ended December 31, 2020 and 2019 was as follows (in millions):

	2020		2019
Repayment of Operating Lease Liabilities Associated with Operating Activities	$	223	$	225
Repayment of Operating Lease Liabilities Associated with Investing Activities	130		270
Repayment of Finance Lease Liabilities	19		13

Non-cash leasing activities for the year ended December 31, 2020, included the additions of $893 million of operating leases and $174 million of finance leases. Non-cash leasing activities for the year ended December 31, 2019, included the addition of $784 million of operating leases. Upon adoption of ASU 2016-02 effective January 1, 2019, EOG recognized operating lease ROU of $566 million.

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At December 31, 2020, the future minimum lease payments under non-cancellable leases were as follows (in millions):

	Operating Leases		Finance Leases
2021	$	323	$	36
2022	210		32
2023	134		28
2024	96		29
2025	70		27
2026 and Beyond	206		87
Total Lease Payments	1,039		239
Less: Discount to Present Value	103		27
Total Lease Liabilities	936		212
Less: Current Portion of Lease Liabilities	295		31
Long-Term Lease Liabilities	$	641	$	181

At December 31, 2020, EOG had additional leases of $100 million, which are expected to commence in 2021 with lease terms of two to nine years.

Prior to the adoption of ASU 2016-02 and other related ASUs, the future minimum commitments under non-cancellable leases, including non-lease components and excluding contracts with lease terms of less than 12 months as December 31, 2018, were as follows (in millions):

	Operating Leases		Finance Leases
2019	$	380	$	15
2020	213		15
2021	86		15
2022	39		12
2023	30		8
2024 and Beyond	62		14
Total Lease Payments	$	810	$	79

F-42

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS

(In Thousands, 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, NGL 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.  For related discussion, see ITEM 1A, Risk Factors.

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 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, 2020.  Under these plans, each PUD location will be drilled within five years from the date it was 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.

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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, 2020, 2019 and 2018 were based on studies performed by the engineering staff of EOG.  The Engineering and Acquisitions Department is directly responsible for EOG's reserve evaluation process and consists of 17 professionals, 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 34 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, NGL and natural gas prices, production costs, transportation 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 Chief Operating Officer; the President; the Executive Vice President, Exploration and Production; and the Executive Vice President and Chief Financial Officer, for approval.

Opinions by D&M for the years ended December 31, 2020, 2019 and 2018 covered producing areas containing 83%, 82% and 79%, 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, 2021, 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, 2020, 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, 2020, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2020, as estimated by the Engineering and Acquisitions Department of EOG:

F-44

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 (MBbl) (2)
Net proved reserves at December 31, 2017	1,304,071	898	8,004	1,312,973
Revisions of previous estimates	(13,237)	(183)	44	(13,376)
Purchases in place	2,743	—	—	2,743
Extensions, discoveries and other additions	383,003	—	15	383,018
Sales in place	(768)	—	(6,310)	(7,078)
Production	(144,128)	(298)	(1,542)	(145,968)
Net proved reserves at December 31, 2018	1,531,684	417	211	1,532,312
Revisions of previous estimates	(42,959)	85	(8)	(42,882)
Purchases in place	2,859	—	—	2,859
Extensions, discoveries and other additions	369,968	—	28	369,996
Sales in place	(1,282)	—	—	(1,282)
Production	(166,310)	(236)	(40)	(166,586)
Net proved reserves at December 31, 2019	1,693,960	266	191	1,694,417
Revisions of previous estimates	(225,375)	(19)	(18)	(225,412)
Purchases in place	2,176	—	—	2,176
Extensions, discoveries and other additions	194,724	863	—	195,587
Sales in place	(3,183)	—	—	(3,183)
Production	(149,402)	(355)	(30)	(149,787)
Net proved reserves at December 31, 2020	1,512,900	755	143	1,513,798
Natural Gas Liquids (MBbl) (2)
Net proved reserves at December 31, 2017	503,473	—	—	503,473
Revisions of previous estimates	23,942	—	—	23,942
Purchases in place	2,006	—	—	2,006
Extensions, discoveries and other additions	127,409	—	—	127,409
Sales in place	(41)	—	—	(41)
Production	(42,460)	—	—	(42,460)
Net proved reserves at December 31, 2018	614,329	—	—	614,329
Revisions of previous estimates	5,380	—	—	5,380
Purchases in place	1,948	—	—	1,948
Extensions, discoveries and other additions	167,782	—	—	167,782
Sales in place	(855)	—	—	(855)
Production	(48,892)	—	—	(48,892)
Net proved reserves at December 31, 2019	739,692	—	—	739,692
Revisions of previous estimates	(59,790)	—	—	(59,790)
Purchases in place	3,831	—	—	3,831
Extensions, discoveries and other additions	180,205	—	—	180,205
Sales in place	(1,399)	—	—	(1,399)
Production	(49,796)	—	—	(49,796)
Net proved reserves at December 31, 2020	812,743	—	—	812,743

F-45

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, 2017	3,898.5	313.4	51.2	4,263.1
Revisions of previous estimates	(127.2)	20.7	15.0	(91.5)
Purchases in place	41.3	—	—	41.3
Extensions, discoveries and other additions	951.4	—	4.6	956.0
Sales in place	(22.2)	—	—	(22.2)
Production	(351.2)	(97.1)	(11.2)	(459.5)
Net proved reserves at December 31, 2018	4,390.6	237.0	59.6	4,687.2
Revisions of previous estimates	(184.4)	47.0	2.6	(134.8)
Purchases in place	71.7	—	—	71.7
Extensions, discoveries and other additions	1,175.9	87.5	9.7	1,273.1
Sales in place	(14.5)	—	—	(14.5)
Production	(404.5)	(95.4)	(13.1)	(513.0)
Net proved reserves at December 31, 2019	5,034.8	276.1	58.8	5,369.7
Revisions of previous estimates	(497.7)	4.8	1.6	(491.3)
Purchases in place	26.3	—	—	26.3
Extensions, discoveries and other additions	1,077.9	53.9	—	1,131.8
Sales in place	(157.3)	—	—	(157.3)
Production	(441.4)	(65.9)	(11.6)	(518.9)
Net proved reserves at December 31, 2020	5,042.6	268.9	48.8	5,360.3
Oil Equivalents (MBoe) (2)
Net proved reserves at December 31, 2017	2,457,302	53,142	16,526	2,526,970
Revisions of previous estimates	(10,500)	3,272	2,544	(4,684)
Purchases in place	11,640	—	—	11,640
Extensions, discoveries and other additions	668,972	—	778	669,750
Sales in place	(4,509)	—	(6,310)	(10,819)
Production	(245,127)	(16,478)	(3,406)	(265,011)
Net proved reserves at December 31, 2018	2,877,778	39,936	10,132	2,927,846
Revisions of previous estimates	(68,317)	7,915	431	(59,971)
Purchases in place	16,761	—	—	16,761
Extensions, discoveries and other additions	733,730	14,577	1,661	749,968
Sales in place	(4,555)	—	—	(4,555)
Production	(282,619)	(16,130)	(2,232)	(300,981)
Net proved reserves at December 31, 2019	3,272,778	46,298	9,992	3,329,068
Revisions of previous estimates	(368,127)	773	259	(367,095)
Purchases in place	10,398	—	—	10,398
Extensions, discoveries and other additions	554,585	9,840	—	564,425
Sales in place	(30,802)	—	—	(30,802)
Production	(272,757)	(11,347)	(1,969)	(286,073)
Net proved reserves at December 31, 2020	3,166,075	45,564	8,282	3,219,921

(1)Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.

(2)Thousand barrels or thousand 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.

F-46

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

During 2020, EOG added 564 million barrels of oil equivalent (MMBoe) of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin.  Approximately 67% of the 2020 reserve additions were crude oil and condensate and NGLs, and substantially all were in the United States.  Sales in place of 31 MMBoe were primarily related to the sale of the Marcellus Shale assets and the sale or exchange of other producing assets. Revisions of previous estimates of negative 367 MMBoe for 2020 included a downward revision of 278 MMBoe primarily due to decreases in the average crude oil, NGLs and natural gas prices used in the December 31, 2020, reserves estimation as compared to the prices used in the prior year estimate. The primary areas affected were the Eagle Ford and the Rocky Mountain area. Purchases in place of 10 MMBoe were primarily related to the Permian Basin and the purchase or exchange of other producing assets.

During 2019, EOG added 750 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin, the Eagle Ford and the Rocky Mountain area.  Approximately 72% of the 2019 reserve additions were crude oil and condensate and NGLs, and substantially all were in the United States.  Sales in place of 5 MMBoe were primarily related to the sale of certain South Texas area operations and the sale or exchange of other producing assets. Revisions of previous estimates of negative 60 MMBoe for 2019 included a decrease in the average crude oil, NGLs and natural gas prices used in the December 31, 2019, reserves estimation as compared to the prices used in the prior year estimate. The primary area affected was the Rocky Mountain area. Purchases in place of 17 MMBoe were primarily related to the South Texas area.

During 2018, EOG added 670 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin, the Eagle Ford, the Rocky Mountain area and the Mid-Continent area.  Approximately 76% of the 2018 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 United Kingdom operations and the sale or exchange of other producing assets. Revisions of previous estimates of negative 5 MMBoe for 2018 included an upward revision of 35 MMBoe primarily due to increases in the average crude oil, NGLs and natural gas prices used in the December 31, 2018, reserves estimation as compared to the prices used in the prior year estimate. The primary areas affected were in the Rocky Mountain area, the Eagle Ford and the Permian Basin. Downward revisions other than price of 40 MMBoe resulted primarily from changes in production forecasts and higher production costs. Purchases in place of 12 MMBoe were primarily related to the South Texas area.

F-47

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	United States	Trinidad	Other International (1)	Total
NET PROVED DEVELOPED RESERVES
Crude Oil (MBbl)
December 31, 2017	605,405	898	7,933	614,236
December 31, 2018	712,218	417	150	712,785
December 31, 2019	801,189	266	143	801,598
December 31, 2020	791,744	755	93	792,592
Natural Gas Liquids (MBbl)
December 31, 2017	286,872	—	—	286,872
December 31, 2018	341,386	—	—	341,386
December 31, 2019	387,253	—	—	387,253
December 31, 2020	391,708	—	—	391,708
Natural Gas (Bcf)
December 31, 2017	2,450.8	299.2	29.3	2,779.3
December 31, 2018	2,699.0	223.9	40.9	2,963.8
December 31, 2019	2,974.6	177.7	41.8	3,194.1
December 31, 2020	2,586.1	171.1	31.6	2,788.8
Oil Equivalents (MBoe)
December 31, 2017	1,300,758	50,779	12,798	1,364,335
December 31, 2018	1,503,441	37,746	6,950	1,548,137
December 31, 2019	1,684,209	29,886	7,117	1,721,212
December 31, 2020	1,614,462	29,268	5,368	1,649,098
NET PROVED UNDEVELOPED RESERVES
Crude Oil (MBbl)
December 31, 2017	698,666	—	71	698,737
December 31, 2018	819,466	—	61	819,527
December 31, 2019	892,771	—	48	892,819
December 31, 2020	721,156	—	50	721,206
Natural Gas Liquids (MBbl)
December 31, 2017	216,601	—	—	216,601
December 31, 2018	272,943	—	—	272,943
December 31, 2019	352,439	—	—	352,439
December 31, 2020	421,035	—	—	421,035
Natural Gas (Bcf)
December 31, 2017	1,447.7	14.2	21.9	1,483.8
December 31, 2018	1,691.6	13.1	18.7	1,723.4
December 31, 2019	2,060.2	98.4	17.0	2,175.6
December 31, 2020	2,456.5	97.8	17.2	2,571.5
Oil Equivalents (MBoe)
December 31, 2017	1,156,544	2,363	3,728	1,162,635
December 31, 2018	1,374,337	2,190	3,182	1,379,709
December 31, 2019	1,588,569	16,412	2,875	1,607,856
December 31, 2020	1,551,613	16,296	2,914	1,570,823

(1)Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.

F-48

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Net Proved Undeveloped Reserves. The following table presents the changes in EOG's total PUDs during 2020, 2019 and 2018 (in MBoe):

	2020	2019	2018
Balance at January 1	1,607,856	1,379,709	1,162,635
Extensions and Discoveries	456,073	578,317	490,725
Revisions	(277,325)	(49,837)	(8,244)
Acquisition of Reserves	47	1,711	311
Sale of Reserves	(3,670)	—	—
Conversion to Proved Developed Reserves	(212,158)	(302,044)	(265,718)
Balance at December 31	1,570,823	1,607,856	1,379,709

For the twelve-month period ended December 31, 2020, total PUDs decreased by 37 MMBoe to 1,571 MMBoe.  EOG added approximately 7 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-43 and F-44 of this Annual Report on Form 10-K), EOG added 449 MMBoe of PUDs.  The PUD additions were primarily in the Permian Basin and 67% of the additions were crude oil and condensate and NGLs.  During 2020, EOG drilled and transferred 212 MMBoe of PUDs to proved developed reserves at a total capital cost of $1,674 million. Revisions of previous estimates of negative 277 MMBoe of PUDs for 2020 included a downward price revision of 77 MMBoe due to decreases in the average crude oil, NGLs and natural gas prices used in the December 31, 2020, reserves estimation as compared to the prices used in the prior year estimate.  Revisions other than price of negative 200 MMBoe were primarily related to the removal of PUD locations due to lower projected capital spending over the next five years as compared to the prior year projections. The primary areas affected were the Eagle Ford and the Rocky Mountain area. 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, 2019, total PUDs increased by 228 MMBoe to 1,608 MMBoe.  EOG added approximately 38 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 540 MMBoe.  The PUD additions were primarily in the Permian Basin, the Eagle Ford and, to a lesser extent, the Rocky Mountain area, and 73% of the additions were crude oil and condensate and NGLs.  During 2019, EOG drilled and transferred 302 MMBoe of PUDs to proved developed reserves at a total capital cost of $3,032 million. 

For the twelve-month period ended December 31, 2018, total PUDs increased by 217 MMBoe to 1,380 MMBoe.  EOG added approximately 31 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 460 MMBoe.  The PUD additions were primarily in the Permian Basin, Anadarko Basin, the Eagle Ford and, to a lesser extent, the Rocky Mountain area, and 80% of the additions were crude oil and condensate and NGLs.  During 2018, EOG drilled and transferred 266 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,745 million. 

F-49

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, 2020 and 2019:

	2020		2019
Proved properties	$	61,724,487	$	59,229,686
Unproved properties	3,068,311		3,600,729
Total	64,792,798		62,830,415
Accumulated depreciation, depletion and amortization	(38,750,852)		(35,033,085)
Net capitalized costs	$	26,041,946	$	27,797,330

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-50

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, 2020, 2019 and 2018:

	United States		Trinidad		Other International (1)		Total
2020
Acquisition Costs of Properties
Unproved (2)	$	264,778	$	—	$	—	$	264,778
Proved (3)	97,073		—		38,089		135,162
Subtotal	361,851		—		38,089		399,940
Exploration Costs	203,403		81,216		11,409		296,028
Development Costs (4)	2,998,155		4,036		20,072		3,022,263
Total	$	3,563,409	$	85,252	$	69,570	$	3,718,231
2019
Acquisition Costs of Properties
Unproved (5)	$	276,092	$	—	$	—	$	276,092
Proved (6)	379,938		—		—		379,938
Subtotal	656,030		—		—		656,030
Exploration Costs	213,505		46,616		13,218		273,339
Development Costs (7)	5,661,753		25,007		12,096		5,698,856
Total	$	6,531,288	$	71,623	$	25,314	$	6,628,225
2018
Acquisition Costs of Properties
Unproved (8)	$	486,081	$	1,258	$	—	$	487,339
Proved (9)	123,684		—		—		123,684
Subtotal	609,765		1,258		—		611,023
Exploration Costs	157,222		22,511		13,895		193,628
Development Costs (10)	5,605,264		(12,863)		22,628		5,615,029
Total	$	6,372,251	$	10,906	$	36,523	$	6,419,680

(1)Other International primarily consists of EOG's United Kingdom, China and Canada operations. EOG began an exploration program in Oman in the third quarter of 2020. The United Kingdom operations were sold in the fourth quarter of 2018.

(2)Includes non-cash unproved leasehold acquisition costs of $197 million related to property exchanges.

(3)Includes non-cash proved property acquisition costs of $15 million related to property exchanges.

(4)Includes Asset Retirement Costs of $97 million and $20 million for the United States and Other International, respectively. Excludes other property, plant and equipment.

(5)Includes non-cash unproved leasehold acquisition costs of $98 million related to property exchanges.

(6)Includes non-cash proved property acquisition costs of $52 million related to property exchanges.

(7)Includes Asset Retirement Costs of $181 million, $1 million and $4 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 $291 million related to property exchanges.

(9)Includes non-cash proved property acquisition costs of $71 million related to property exchanges.

(10)Includes Asset Retirement Costs of $90 million, $(12) million and $(8) million for the United States, Trinidad and Other International, respectively.  Excludes other property, plant and equipment.

F-51

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, 2020, 2019 and 2018:

	United States		Trinidad		Other International (2)		Total
2020
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	7,055,098	$	179,690	$	55,468	$	7,290,256
Other	60,989		(35)		—		60,954
Total	7,116,087		179,655		55,468		7,351,210
Exploration Costs	136,266		1,909		7,613		145,788
Dry Hole Costs	13,055		—		28		13,083
Transportation Costs	734,071		747		171		734,989
Gathering and Processing Costs	459,211		—		—		459,211
Production Costs	1,479,976		26,964		10,407		1,517,347
Impairments	2,018,283		815		80,682		2,099,780
Depreciation, Depletion and Amortization	3,192,000		60,328		15,747		3,268,075
Income (Loss) Before Income Taxes	(916,775)		88,892		(59,180)		(887,063)
Income Tax Provision	(220,437)		23,526		3,428		(193,483)
Results of Operations	$	(696,338)	$	65,366	$	(62,608)	$	(693,580)
2019
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	11,250,853	$	269,957	$	60,635	$	11,581,445
Other	134,325		18		15		134,358
Total	11,385,178		269,975		60,650		11,715,803
Exploration Costs	130,302		4,290		5,289		139,881
Dry Hole Costs	11,133		13,033		3,835		28,001
Transportation Costs	753,558		4,014		728		758,300
Gathering and Processing Costs	479,102		—		—		479,102
Production Costs	2,063,078		30,539		40,369		2,133,986
Impairments	510,948		5,713		1,235		517,896
Depreciation, Depletion and Amortization	3,560,609		79,156		17,832		3,657,597
Income (Loss) Before Income Taxes	3,876,448		133,230		(8,638)		4,001,040
Income Tax Provision	884,450		54,980		3,152		942,582
Results of Operations	$	2,991,998	$	78,250	$	(11,790)	$	3,058,458
2018
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	11,488,620	$	302,112	$	155,755	$	11,946,487
Other	89,708		(49)		(24)		89,635
Total	11,578,328		302,063		155,731		12,036,122
Exploration Costs	121,572		21,402		6,025		148,999
Dry Hole Costs	4,983		—		422		5,405
Transportation Costs	742,792		3,236		848		746,876
Gathering and Processing Costs (3)	404,471		—		32,502		436,973
Production Costs	1,924,504		33,506		70,073		2,028,083
Impairments	344,595		—		2,426		347,021
Depreciation, Depletion and Amortization	3,181,801		91,788		46,687		3,320,276
Income (Loss) Before Income Taxes	4,853,610		152,131		(3,252)		5,002,489
Income Tax Provision	1,086,077		12,170		1,898		1,100,145
Results of Operations	$	3,767,533	$	139,961	$	(5,150)	$	3,902,344

(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, 2020.

(2)Other International primarily consists of EOG's United Kingdom, China and Canada operations. EOG began an exploration program in Oman in the third quarter of 2020. The United Kingdom operations were sold in the fourth quarter of 2018.

(3)Effective January 1, 2018, EOG adopted the provisions of Accounting Standards Update (ASU) 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements within its United States segment as Gathering and Processing Costs instead of as a deduction to Natural Gas Revenues. There was no impact to operating income or net income resulting from changes to the presentation of natural gas processing fees (see Note 1 to Consolidated Financial Statements).

F-52

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, 2020, 2019 and 2018:

	United States		Trinidad		Other International (1)		Composite
Year Ended December 31, 2020	$	3.75	$	2.33	$	6.78	$	3.72
Year Ended December 31, 2019	$	4.59	$	1.85	$	18.26	$	4.54
Year Ended December 31, 2018	$	4.84	$	1.67	$	20.19	$	4.84

(1)    Other International primarily consists of EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.

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 2020, 2019 and 2018.  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-53

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, 2020, 2019 and 2018:

	United States		Trinidad		Other International (1)		Total
2020
Future cash inflows (2)	$	73,726,893	$	900,815	$	281,658	$	74,909,366
Future production costs	(34,618,860)		(153,275)		(53,933)		(34,826,068)
Future development costs	(15,159,373)		(226,430)		(18,400)		(15,404,203)
Future income taxes	(4,336,578)		(81,368)		(24,311)		(4,442,257)
Future net cash flows	19,612,082		439,742		185,014		20,236,838
Discount to present value at 10% annual rate	(8,410,282)		(100,350)		(36,194)		(8,546,826)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	11,201,800	$	339,392	$	148,820	$	11,690,012
2019
Future cash inflows (3)	$	120,359,769	$	813,102	$	305,491	$	121,478,362
Future production costs	(42,387,801)		(166,705)		(87,381)		(42,641,887)
Future development costs	(20,355,746)		(212,303)		(18,400)		(20,586,449)
Future income taxes	(11,459,567)		(73,508)		(32,423)		(11,565,498)
Future net cash flows	46,156,655		360,586		167,287		46,684,528
Discount to present value at 10% annual rate	(21,042,593)		(86,009)		(35,161)		(21,163,763)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	25,114,062	$	274,577	$	132,126	$	25,520,765
2018
Future cash inflows (4)	$	133,066,375	$	749,695	$	303,620	$	134,119,690
Future production costs	(42,351,174)		(204,444)		(99,024)		(42,654,642)
Future development costs	(16,577,794)		(78,199)		(11,900)		(16,667,893)
Future income taxes	(14,756,011)		(174,382)		(31,748)		(14,962,141)
Future net cash flows	59,381,396		292,670		160,948		59,835,014
Discount to present value at 10% annual rate	(27,348,744)		(26,832)		(33,483)		(27,409,059)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	32,032,652	$	265,838	$	127,465	$	32,425,955

(1)Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.

(2)Estimated crude oil prices used to calculate 2020 future cash inflows for the United States, Trinidad and Other International were $37.19, $26.75, and $41.87, respectively. Estimated NGL price used to calculate 2020 future cash inflows for the United States was $12.47. Estimated natural gas prices used to calculate 2020 future cash inflows for the United States, Trinidad and Other International were $1.45, $3.28, and $5.65, respectively.

(3)Estimated crude oil prices used to calculate 2019 future cash inflows for the United States, Trinidad and Other International were $57.51, $46.77 and $57.22, respectively. Estimated NGL price used to calculate 2019 future cash inflows for the United States was $16.91. Estimated natural gas prices used to calculate 2019 future cash inflows for the United States, Trinidad and Other International were $2.07, $2.90 and $5.01, respectively.

(4)Estimated crude oil prices used to calculate 2018 future cash inflows for the United States, Trinidad and Other International were $68.54, $55.66 and $61.66, respectively. Estimated NGL price used to calculate 2018 future cash inflows for the United States was $27.83. Estimated natural gas prices used to calculate 2018 future cash inflows for the United States, Trinidad and Other International were $2.50, $3.06 and $4.88, respectively.

F-54

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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, 2020:

	United States		Trinidad		Other International (1)		Total
December 31, 2017	$	17,756,935	$	332,427	$	238,298	$	18,327,660
Sales and transfers of oil and gas produced, net of production costs	(8,416,853)		(265,370)		(52,399)		(8,734,622)
Net changes in prices and production costs	12,750,466		84,353		21,610		12,856,429
Extensions, discoveries, additions and improved recovery, net of related costs	8,418,666		—		12,287		8,430,953
Development costs incurred	2,732,560		—		12,600		2,745,160
Revisions of estimated development cost	(410,741)		4,030		(3,814)		(410,525)
Revisions of previous quantity estimates	(173,084)		39,608		31,750		(101,726)
Accretion of discount	1,967,592		50,191		24,839		2,042,622
Net change in income taxes	(4,965,373)		3,844		(11,529)		(4,973,058)
Purchases of reserves in place	116,887		—		—		116,887
Sales of reserves in place	(35,874)		—		(82,058)		(117,932)
Changes in timing and other	2,291,471		16,755		(64,119)		2,244,107
December 31, 2018	32,032,652		265,838		127,465		32,425,955
Sales and transfers of oil and gas produced, net of production costs	(7,955,115)		(235,404)		(19,919)		(8,210,438)
Net changes in prices and production costs	(10,973,981)		65,962		27,572		(10,880,447)
Extensions, discoveries, additions and improved recovery, net of related costs	5,608,038		85,233		16,287		5,709,558
Development costs incurred	3,003,510		22,820		5,820		3,032,150
Revisions of estimated development cost	(597,869)		(129,047)		(11,108)		(738,024)
Revisions of previous quantity estimates	(812,781)		116,062		1,198		(695,521)
Accretion of discount	3,891,701		43,148		14,909		3,949,758
Net change in income taxes	1,454,050		93,975		682		1,548,707
Purchases of reserves in place	98,539		—		—		98,539
Sales of reserves in place	(50,651)		—		—		(50,651)
Changes in timing and other	(584,031)		(54,010)		(30,780)		(668,821)
December 31, 2019	25,114,062		274,577		132,126		25,520,765
Sales and transfers of oil and gas produced, net of production costs	(4,381,840)		(151,979)		(45,355)		(4,579,174)
Net changes in prices and production costs	(18,624,768)		131,859		46,916		(18,445,993)
Extensions, discoveries, additions and improved recovery, net of related costs	1,436,988		64,385		—		1,501,373
Development costs incurred	1,674,800		—		—		1,674,800
Revisions of estimated development cost	4,148,768		(11,161)		—		4,137,607
Revisions of previous quantity estimates	(3,307,180)		11,632		(1,764)		(3,297,312)
Accretion of discount	3,054,437		34,624		15,307		3,104,368
Net change in income taxes	3,497,362		(12,185)		3,022		3,488,199
Purchases of reserves in place	49,232		—		—		49,232
Sales of reserves in place	(156,293)		—		—		(156,293)
Changes in timing and other	(1,303,768)		(2,360)		(1,432)		(1,307,560)
December 31, 2020	$	11,201,800	$	339,392	$	148,820	$	11,690,012

(1)    Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.

F-55

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

Unaudited Quarterly Financial Information

(In Thousands, Except Per Share Data)

Quarter Ended	Mar 31		Jun 30		Sep 30		Dec 31
2020
Operating Revenues and Other	$	4,717,692	$	1,103,374	$	2,245,484	$	2,965,498
Operating Income (Loss)	$	57,585	$	(1,086,549)	$	(2,714)	$	487,662
Income (Loss) Before Income Taxes	$	31,003	$	(1,145,262)	$	(52,555)	$	427,760
Income Tax Provision (Benefit)	21,190		(235,878)		(10,088)		90,294
Net Income (Loss)	$	9,813	$	(909,384)	$	(42,467)	$	337,466
Net Income (Loss) Per Share (1)
Basic	$	0.02	$	(1.57)	$	(0.07)	$	0.58
Diluted	$	0.02	$	(1.57)	$	(0.07)	$	0.58
Average Number of Common Shares
Basic	578,462		578,719		579,055		579,624
Diluted	580,283		578,719		579,055		580,885
2019
Operating Revenues and Other	$	4,058,642	$	4,697,630	$	4,303,455	$	4,320,246
Operating Income	$	876,530	$	1,130,771	$	827,959	$	863,751
Income Before Income Taxes	$	827,236	$	1,089,366	$	797,457	$	831,208
Income Tax Provision	191,810		241,525		182,335		194,687
Net Income	$	635,426	$	847,841	$	615,122	$	636,521
Net Income Per Share (1)
Basic	$	1.10	$	1.47	$	1.06	$	1.10
Diluted	$	1.10	$	1.46	$	1.06	$	1.10
Average Number of Common Shares
Basic	577,207		577,460		577,839		578,219
Diluted	580,222		580,247		581,271		580,849

(1)The sum of quarterly net income (loss) per share may not agree with total year net income (loss) per share as each quarterly computation is based on the weighted average of common shares outstanding.

F-56

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	-	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).
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	-	Specimen of Certificate evidencing EOG's Common Stock (Exhibit 3.3 to EOG's Annual Report on Form 10-K for the year ended December 31, 1999) (SEC File No. 001-09743).
4.3	-	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
#4.4(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.
#4.4(b)	-	Global Note with respect to the 6.65% Notes due April 1, 2028 of Enron Oil & Gas Company (predecessor to EOG).
4.5	-	Indenture, dated as of May 18, 2009, between EOG and 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).
4.6(a)	-	Officers' Certificate Establishing 2.500% Senior Notes due 2016, 4.100% Senior Notes due 2021 and Floating Rate Senior Notes due 2014 of EOG, dated November 23, 2010 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed November 24, 2010) (SEC File No. 001-09743).
4.6(b)	-	Form of Global Note with respect to the 4.100% Senior Notes due 2021 of EOG (Exhibit 4.4 to EOG's Current Report on Form 8-K, filed November 24, 2010) (SEC File No. 001-09743).
4.7(a)	-	Officers' Certificate Establishing 2.625% Senior Notes due 2023 of EOG, dated September 10, 2012 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed September 11, 2012) (SEC File No. 001-09743).
4.7(b)	-	Form of Global Note with respect to the 2.625% Senior Notes due 2023 of EOG (Exhibit 4.3 to EOG's Current Report on Form 8-K, filed September 11, 2012) (SEC File No. 001-09743).
4.8(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).
4.8(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).
4.8(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).
4.9(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).
4.9(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).
4.9(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).
4.10(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).
4.10(b)	-	Form of Global Note with respect to the 4.375% Senior Notes due 2030 of EOG (included in Exhibit 4.10(a)).
4.10(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 prior to September 25, 2017) (Exhibit 4.5 to EOG's Registration Statement on Form S-8, SEC File No. 333-188352, filed May 3, 2013).
10.1(c)+	-	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 25, 2017 and prior to September 27, 2018) (Exhibit 10.1 to EOG's Current Report on Form 8-K, filed September 29, 2017) (SEC File No. 001-09743).

E-2

Exhibit Number		Description
10.1(d)+	-	Form of Restricted Stock Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made effective September 27, 2018 and prior to September 28, 2020) (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2018) (SEC File No. 001-09743).
10.1(e)+	-	Form of Restricted Stock Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made effective September 28, 2020 and subsequent grants) (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(f)+	-	Form of Restricted Stock Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made prior to September 25, 2017) (Exhibit 4.6 to EOG's Registration Statement on Form S-8, SEC File No. 333-188352, filed May 3, 2013).
10.1(g)+	-	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 25, 2017 and prior to September 27, 2018) (Exhibit 10.2 to EOG's Current Report on Form 8-K, filed September 29, 2017) (SEC File No. 001-09743).
10.1(h)+		Form of Restricted Stock Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made effective September 27, 2018 and prior to September 28, 2020) (Exhibit 10.2 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2018) (SEC File No. 001-09743).
10.1(i)+	-	Form of Restricted Stock Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made effective September 28, 2020 and subsequent grants) (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(j)+	-	Form of Stock-Settled Stock Appreciation Right Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made prior to September 25, 2017) (Exhibit 4.7 to EOG's Registration Statement on Form S-8, SEC File No. 333-188352, filed May 3, 2013).
10.1(k)+	-	Form of Stock-Settled Stock Appreciation Right Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made effective 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(l)+	-	Form of Stock-Settled Stock Appreciation Right Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made effective September 28, 2020 and subsequent grants) (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(m)+	-	Form of Performance Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made prior to September 22, 2014) (Exhibit 4.8 to EOG's Registration Statement on Form S-8, SEC File No. 333-188352, filed May 3, 2013).
10.1(n)+	-	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 22, 2014 and prior to September 27, 2016) (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014) (SEC File No. 001-09743).
10.1(o)+	-	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 27, 2016 and prior to September 25, 2017) (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2016) (SEC File No. 001-09743).
10.1(p)+	-	Form of Performance Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable only to grants made effective December 13, 2016) (Exhibit 10.1 to EOG's Current Report on Form 8-K, filed December 19, 2016) (SEC File No. 001-09743).
10.1(q)+	-	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 25, 2017 and prior to September 27, 2018) (Exhibit 10.3 to EOG's Current Report on Form 8-K, filed September 29, 2017) (SEC File No. 001-09743).

E-3

Exhibit Number		Description
10.1(r)+	-	Form of Performance Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made effective September 27, 2018 and prior to September 26, 2019) (Exhibit 10.3 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2018) (SEC File No. 001-09743).
10.1(s)+	-	Form of Performance Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made effective September 26, 2019 and prior to September 28, 2020) (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2019) (SEC File No. 001-09743).
10.1(t)+	-	Form of Performance Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made effective September 28, 2020 and subsequent grants) (Exhibit 10.4 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2020) (SEC File No. 001-09743).
*10.1(u)+	-	Form of Performance Unit Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grant made to Ezra Y. Yacob effective January 4, 2021).
10.1(v)+	-	Form of Performance Stock Award Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Exhibit 4.9 to EOG's Registration Statement on Form S-8, SEC File No. 333-188352, filed May 3, 2013).
10.1(w)	-	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 prior to May 6, 2019) (Exhibit 4.10 to EOG's Registration Statement on Form S-8, SEC File No. 333-188352, filed May 3, 2013).
10.1(x)	-	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 effective May 6, 2019 and subsequent grants) (Exhibit 10.2 to EOG's Quarterly Report on Form 10-Q for the quarter ended June 30, 2019) (SEC File No. 001-09743).
10.1(y)	-	Form of Non-Employee Director Stock-Settled Stock Appreciation Right Agreement for Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Exhibit 4.11 to EOG's Registration Statement on Form S-8, SEC File No. 333-188352, filed May 3, 2013).
10.2(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).
10.2(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).
10.2(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).
10.2(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).
*10.2(e)+	-	Third Amendment to the EOG Resources, Inc. 409A Deferred Compensation Plan, effective as of December 17, 2020.
10.2(f)+	-	Amended and Restated 1996 Deferral Plan (Exhibit 4.4 to EOG's Registration Statement on Form S-8, SEC File No. 333-84014, filed March 8, 2002).
10.2(g)+	-	First Amendment to Amended and Restated 1996 Deferral Plan, effective as of September 10, 2002 (Exhibit 10.9(e) to EOG's Annual Report on Form 10-K for the year ended December 31, 2002) (SEC File No. 001-09743).
10.3(a)+	-	Change of Control Agreement between EOG and William R. Thomas, effective as of January 12, 2011 (Exhibit 10.2 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2011) (SEC File No. 001-09743).

E-4

Exhibit Number		Description
10.3(b)+	-	First Amendment to Change of Control Agreement between EOG and William R. Thomas, effective as of September 13, 2011 (Exhibit 10.2 to EOG's Current Report on Form 8-K, filed September 13, 2011) (SEC File No. 001-09743).
10.3(c)+	-	Second Amendment to Change of Control Agreement between EOG and William R. Thomas, effective as of September 4, 2013 (Exhibit 10.2 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013) (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+	-	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).
10.9(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).
10.9(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).
10.10(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).
10.10(b)+	-	EOG Resources, Inc. Amended and Restated Executive Officer Annual Bonus Plan (terminated effective January 1, 2019) (Exhibit 10.4 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2010) (SEC File No. 001-09743).
10.11(a)+	-	EOG Resources, Inc. Employee Stock Purchase Plan (As Amended and Restated Effective January 1, 2018)(Exhibit 4.4(a) to EOG's Registration Statement on Form S-8, SEC File No. 333-224466, filed April 26, 2018).
10.11(b)+	-	EOG Resources, Inc. Employee Stock Purchase Plan (as in effect prior to January 1, 2018) (Exhibit 4.4 to EOG's Registration Statement on Form S-8, SEC File No. 333-62256, filed June 4, 2001).
10.11(c)+	-	Amendment to EOG Resources, Inc. Employee Stock Purchase Plan, dated effective as of January 1, 2010 (as in effect prior to January 1, 2018) (Exhibit 4.3(b) to EOG's Registration Statement on Form S-8, SEC File No. 333-166518, filed May 4, 2010).

E-5

Exhibit Number		Description
10.12	-	Revolving Credit Agreement, dated as of June 27, 2019, 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 July 2, 2019) (SEC File No. 001-09743).
*21	-	Subsidiaries of EOG, as of December 31, 2020.
*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.
*95	-	Mine Safety Disclosure Exhibit.
*99.1	-	Opinion of DeGolyer and MacNaughton, dated January 26, 2021.
101.INS	-	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
*  **101.SCH	-	Inline XBRL Schema Document.
*  **101.CAL	-	Inline XBRL Calculation Linkbase Document.
*  **101.DEF	-	Inline XBRL Definition Linkbase Document.
*  **101.LAB	-	Inline XBRL Label Linkbase Document.
*  **101.PRE	-	Inline XBRL Presentation Linkbase Document.
104	-	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

*Exhibits filed herewith

**Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) for Each of the Three Years in the Period Ended December 31, 2020, (ii) the Consolidated Balance Sheets - December 31, 2020 and 2019, (iii) the Consolidated Statements of Stockholders' Equity for Each of the Three Years in the Period Ended December 31, 2020, (iv) the Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2020 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 25, 2021	By:	/s/ TIMOTHY K. DRIGGERS                                                                         Timothy K. Driggers 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 25th day of February, 2021.

	Signature	Title
	/s/ WILLIAM R. THOMAS	Chairman of the Board and Chief Executive Officer and
	(William R. Thomas)	Director (Principal Executive Officer)
	/s/ TIMOTHY K. DRIGGERS	Executive Vice President and Chief Financial Officer
	(Timothy K. Driggers)	(Principal Financial Officer)
	/s/ ANN D. JANSSEN	Senior Vice President and Chief Accounting Officer
	(Ann D. Janssen)	(Principal Accounting Officer)
	*	Director
	(Janet F. Clark)
	*	Director
	(Charles R. Crisp)
	*	Director
	(Robert P. Daniels)
	*	Director
	(James C. Day)
	*	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-10.1

EXHIBIT 10.1(u)

This document constitutes part of a prospectus covering securities

that have been registered under the Securities Act of 1933.

EOG RESOURCES, INC.

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:	January 4, 2021
Performance Units granted under this Award (subject to adjustment as set forth below):	[Granted: Shares Granted]
Vesting Date:	February 28, 2024

The Compensation 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 Amended and Restated EOG Resources, Inc. 2008 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 (i.e., the lapse of the forfeiture restrictions thereon) or the Performance Units are forfeited and canceled pursuant to this Agreement.

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 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) and the Company’s corresponding TSR Rank (see chart on Annex A) for the Performance Period and the applicable Performance Multiple (as specified in the chart 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 granted 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 granted hereunder shall be deemed forfeited and canceled), your Performance Unit ledger account shall be adjusted to reflect (i) the additional Performance Units credited to you (in the case of a Performance Multiple greater than 100%) or (ii) your decreased Performance Units (in the case of a Performance Multiple less than 100% but greater than 0%).

Voting Rights; Dividend Equivalents. You will have no voting rights with respect to the Company common stock represented by your 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 upon your vesting in the Performance Units. Dividend equivalents on unvested Performance Units shall accrue and be credited by the Company for your benefit, and any such dividend equivalents accrued and credited for your benefit shall have the same Performance Multiple applied as is applied to your Performance Units. However, such dividend equivalents shall not be paid to you until you become vested in the related Performance Units and shall be forfeited in the event of the forfeiture and cancellation of the related Performance Units pursuant to this Agreement.

Vesting. Assuming your continuous employment with the Company or an Affiliate, this Award shall vest as of the close of business on the Vesting Date, and the shares of Company common stock represented (on a one-for-one basis) by the Performance Units granted hereunder (as adjusted for the applicable Performance Multiple) and all dividend equivalents with respect to such Performance Units 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.

Termination of Employment. If your employment with the Company or an Affiliate terminates prior to the Vesting Date, your Performance Units granted hereunder, and any dividend equivalents credited with respect to such Performance Units, shall vest and be distributed to you, or shall be forfeited and canceled, as set forth below.

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 granted hereunder shall lapse effective as of the date of your death; (ii) the Performance Multiple to be applied to the number of Performance Units granted hereunder shall be 100%; and (iii) all shares of Company common stock represented by the Performance Units granted 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 granted hereunder shall lapse effective as of the date of your death; (ii) the Performance Multiple to be applied to the number of Performance Units granted 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 granted 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 granted hereunder shall lapse effective as of the date of such termination; (ii) the Performance Multiple to be applied to the number of Performance Units granted 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 granted hereunder (as adjusted for the applicable Performance Multiple) shall be distributed to you as soon as administratively practicable following the later of (A) the date that is six months following the effective date of such termination (to account for the six-month delay applicable to specified employees described under “Section 409A” below) or (B) the Vesting Date, but no later than 60 days after the later of such dates.

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

Due to Retirement Prior to Age 62. If your employment with the Company or an Affiliate terminates voluntarily 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 granted 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 one-third (33%) of the shares of Company common stock represented by the Performance Units granted hereunder (as adjusted for the applicable Performance Multiple). Such shares of Company common stock shall be distributed to you as soon as administratively practicable following the later of (A) the date that is six months following the effective date of such Retirement or (B) the Vesting Date, but no later than 60 days after the later of such dates, provided that 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 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 for Other than Performance Reasons. In the event of your Involuntary Termination for any reason other than performance reasons prior to the Vesting Date, (i) the Performance Multiple to be applied to the number of Performance Units granted hereunder shall be the Performance Multiple for the Performance Period as certified by the Committee; (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 termination, you shall be eligible to receive a distribution of one-third (33%) of the shares of Company common stock represented by the Performance Units granted hereunder (as adjusted for the applicable Performance Multiple); and (iii) such shares of Company common stock shall be distributed to you as soon as administratively practicable following the later of (A) the date that is six months following the effective date of such termination (to account for the six-month delay applicable to specified employees described under “Section 409A” below) or (B) the Vesting Date, but no later than 60 days after the later of such dates.

Due to Performance Reasons, Cause or Voluntary Termination. In the event of your Involuntary Termination for performance reasons, Termination for Cause, or voluntary termination prior to the Vesting Date, all Performance Units granted hereunder shall be forfeited and canceled.

Vesting Upon a Change in Control. Upon a Change in Control of the Company (as defined in the Plan) with an effective date on or prior to the end date of the Performance Period, (i) all forfeiture restrictions on the Performance Units granted hereunder shall lapse effective as of the effective date of the Change in Control of the Company; and (ii) the Performance Multiple to be applied to the number of Performance Units granted hereunder shall be based on the respective Total Shareholder Return of the Company and each of the Peer Companies over the Performance Period (using, for purposes of such Total Shareholder Return calculations, the 30 calendar day period immediately preceding the effective date of the Change in Control of the Company as the end month of the Performance Period) as certified by the Committee (or its successor).

Upon a Change in Control of the Company (as defined in the Plan) with an effective date subsequent to the end date of the Performance Period, but prior to the Vesting Date, (i) all forfeiture restrictions on the Performance Units granted hereunder shall lapse effective as of the effective date of the Change in Control of the Company; and (ii) the Performance Multiple to be applied to the number of Performance Units granted 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 granted hereunder (as adjusted for the applicable Performance Multiple) shall be distributed to you as soon as administratively practicable following the effective date of such Change in Control of the Company, but no later than 60 days after such date; 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 13.2 of the Plan, such distribution shall be delayed until the earliest time that such distribution would be Permissible under Section 409A.

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. The Company, in its sole discretion, shall determine if you are a “specified employee” of the Company (as that phrase is defined for purposes of Section 409A) on the date of your termination of employment or your Retirement prior to the Vesting Date and whether you are subject to any six-month delay in distribution of amounts due 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 UBS Financial Services, Inc. website; (iii) the delivery of such documents via the UBS Financial Services, Inc. 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 applicable plan or document, select the appropriate link below:

Annual Report

Proxy Statement

Amended and Restated EOG Resources, Inc. 2008 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 September 2018

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 January 2020

Equal Employment Opportunity Policy, effective May 2017

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.

Definitions of Certain Terms

Annex A

“Performance Period” shall mean January 1, 2021 through December 31, 2023 (except as provided above under “Vesting Upon a Change in Control” in the case of a Change in Control of the Company).

“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 S5OILP (as defined below)) for December 2020 as compared to the average daily closing stock price (or average daily closing index value, in the case of S5OILP) for December 2023, except as provided above under “Vesting Upon a Change in Control” in the case of a Change in Control of the Company), 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 (as defined below) 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.

“Replaced Peer Company’s Total Shareholder Return” shall mean the Replaced Peer Company’s average daily closing stock price for December 2020 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 2023, except as provided above under “Vesting Upon a Change in Control” in the case of a Change in Control of the Company), 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 2023, 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 2023.

“Peer Company” shall mean each of (i) Apache Corporation (ticker symbol: APA); (ii) ConocoPhillips (ticker symbol: COP); (iii) Devon Energy Corporation (ticker symbol: DVN); (iv) Diamondback Energy, Inc. (ticker symbol: FANG); (v) Hess Corporation (ticker symbol: HES); (vi) Marathon Oil Corporation (ticker symbol: MRO); (vii) Occidental Petroleum Corporation (ticker symbol: OXY); (viii) Pioneer Natural Resources Company (ticker symbol: PXD); and (ix) S5OILP (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 above 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.

“TSR Rank” of the Company among the Ten Total Companies (i.e., the Company and Nine (9) Peer Companies)	Applicable “Performance Multiple”
1	200%
2	175%
3	150%
4	125%
5	100%
6	75%
7	50%
8	25%
9	0%
10	0%

EX-10.2

EXHIBIT 10.2(e)

THIRD AMENDMENT TO THE

EOG RESOURCES, INC. 409A DEFERRED COMPENSATION PLAN

THIS AGREEMENT by EOG Resources, Inc. (the “Sponsor”),

WITNESSETH:

WHEREAS, the Sponsor maintains the EOG Resources, Inc. 409A Deferred Compensation Plan (the “Plan”);

WHEREAS, the Sponsor retained the right in Section 12 of the Plan to amend the Plan at any time; and

WHEREAS, the Sponsor desires to amend the Plan;

NOW, THEREFORE, the Plan is hereby amended as follows:

1.    Effective as of the date set forth below, the second sentence of Section 9.7 of the Plan is hereby amended and restated in its entirety to read as follows:

“Notwithstanding the foregoing, in the case of payments: (i) of Grandfathered Amounts (as defined below), the deduction for which would be limited or eliminated by the application of Section 162(m) of the Code; (ii) that would violate securities or other applicable laws; or (iii) that would jeopardize the ability of the Employer to continue as a going concern in accordance with Code Section 409A and the regulations thereunder, deferral of such payments may be made by the Employer at the Employer’s discretion.”

2.    Effective as of the date set forth below, the third sentence of Section 9.7 of the Plan is hereby amended and restated in its entirety to read as follows:

“In the case of a payment described in (i) above, if the Employer, in its sole discretion, elects to defer such payment as provided in the prior sentence, then such payment must be deferred either to a date in the first year in which the Employer or Administrator reasonably anticipates that a payment of such amount would not result in a limitation of a deduction with respect to the payment of such amount under Section 162(m), or the year in which the Participant’s Termination Date occurs.”

3.    Effective as of the date set forth below, a new fourth sentence is hereby added to Section 9.7 of the Plan to read as follows:

“For purposes of this Section 9.7, ‘Grandfathered Amounts’ means amounts that qualify for the transition relief set forth in Section 13601(e)(2) of the Tax Cuts and Jobs Act of 2017.”

1

IN WITNESS WHEREOF, the Sponsor has executed this Agreement this 17th day of December, 2020.

EOG RESOURCES, INC.

By /s/ Patricia L. Edwards

Patricia L. Edwards, Senior Vice President and

Chief Human Resources Officer

2

EX-21

EXHIBIT 21

EOG Resources, Inc.

Subsidiaries

As of December 31, 2020

EOG Resources, Inc., a Delaware corporation, had the U.S. and international subsidiaries shown below as of December 31, 2020. The names of certain subsidiaries have been omitted (pursuant to Regulation S-K, Item 601(b)(21)(ii)) since, considered in the aggregate as a single subsidiary, they would not constitute a “significant subsidiary” (as that term is defined in Rule 1-02(w) of Regulation S-X) as of the year end covered by this report. Inclusion in this list is not, however, a representation that the listed subsidiary is a “significant subsidiary”.

Name of Subsidiary	Jurisdiction of Organization/Incorporation
EOG – Canada, Inc.	Delaware
EOG Canada Oil & Gas Inc.	Alberta
EOG Expat Services, Inc.	Delaware
EOG Resources Block 4(a) Company	Cayman Islands
EOG Resources (Nevis) Block 4 (a) Limited	Nevis
EOG Resources China Limited	Hong Kong
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 Nitro2000 Ltd.	Nevis
EOG Resources Oman Block 49 Limited	Cayman Islands
EOG Resources Oman Limited	Cayman Islands
EOG Resources Railyard (North Dakota), Inc.	Delaware
EOG Resources Railyard, Inc.	Delaware
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
EOGI China International Ltd.	Cayman Islands
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
Hawthorn Oil Transportation (North Dakota), Inc.	Delaware
Hawthorn Oil Transportation, Inc.	Delaware
Murrott Capital Ltd.	Nevis
Nilo Operating Company	Delaware
Pecan Pipeline (North Dakota), Inc.	Delaware
Pecan Pipeline Company	Delaware

EX-23.1

EXHIBIT 23.1

DEGOLYER AND MACNAUGHTON

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

February 25, 2021

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 oil, condensate, natural gas liquids, and 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, 2020, to be filed with the United States Securities and Exchange Commission on or about February 25, 2021. The opinions are contained in our reports of third party dated January 25, 2019, January 24, 2020, and January 26, 2021, with respect to the reserves estimates as of December 31, 2018, December 31, 2019, and December 31, 2020, 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 Statement (File Nos. 333-62256, 333-84014, 333-150791, 333-166517, 333-166518, 333-179884, 333-188352, 333-214894, 333‑224466, and 333-228827).

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 Nos.: 333-214894 and 333-228827 on Form S-3 and Nos.: 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 25, 2021 relating to the consolidated financial statements of EOG Resources, Inc. and subsidiaries, and the effectiveness of EOG Resources, Inc. and subsidiaries' internal control over financial reporting, appearing in this Annual Report on Form 10-K for the year ended December 31, 2020.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 25, 2021

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, 2020 with the United States Securities and Exchange Commission, the undersigned director of the Company hereby constitutes and appoints Timothy K. Driggers 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 7th day of February, 2021.

/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, 2020 with the United States Securities and Exchange Commission, the undersigned director of the Company hereby constitutes and appoints Timothy K. Driggers 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 28th day of January, 2021.

/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, 2020 with the United States Securities and Exchange Commission, the undersigned director of the Company hereby constitutes and appoints Timothy K. Driggers 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 26th day of January 2021.

/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, 2020 with the United States Securities and Exchange Commission, the undersigned director of the Company hereby constitutes and appoints Timothy K. Driggers 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 26th day of January 2021.

/s/ JAMES C. DAY

JAMES C. DAY

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, 2020 with the United States Securities and Exchange Commission, the undersigned director of the Company hereby constitutes and appoints Timothy K. Driggers 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 28th day of January, 2021.

/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, 2020 with the United States Securities and Exchange Commission, the undersigned director of the Company hereby constitutes and appoints Timothy K. Driggers 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 1st day of February, 2021.

/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, 2020 with the United States Securities and Exchange Commission, the undersigned director of the Company hereby constitutes and appoints Timothy K. Driggers 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 9th day of February, 2021.

/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, 2020 with the United States Securities and Exchange Commission, the undersigned director of the Company hereby constitutes and appoints Timothy K. Driggers 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 9th day of February 2021.

/s/ DONALD F. TEXTOR

DONALD F. TEXTOR

EX-31.1

EXHIBIT 31.1

CERTIFICATIONS

I, William R. Thomas, 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 25, 2021

/s/ WILLIAM R. THOMAS

William R. Thomas

Chairman of the Board and Chief Executive Officer

(Principal Executive Officer)

EX-31.2

EXHIBIT 31.2

CERTIFICATIONS

I, Timothy K. Driggers, 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 25, 2021

/s/ TIMOTHY K. DRIGGERS

Timothy K. Driggers

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF PERIODIC REPORT

I, William R. Thomas, 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, 2020 (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 25, 2021

/s/ WILLIAM R. THOMAS

William R. Thomas

Chairman of the Board and Chief Executive Officer

(Principal Executive Officer)

EX-32.2

EXHIBIT 32.2

CERTIFICATION OF PERIODIC REPORT

I, Timothy K. Driggers, 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, 2020 (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 25, 2021

/s/ TIMOTHY K. DRIGGERS

Timothy K. Driggers

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-95

EXHIBIT 95

Mine Safety Disclosure Exhibit

Under the Dodd-Frank Wall Street Reform and Consumer Protection Act and the related rules promulgated thereunder by the United States Securities and Exchange Commission (SEC), each operator of a coal or other mine is required to disclose certain mine safety matters in its periodic reports filed with the SEC.

EOG Resources, Inc. (EOG) has sand mining operations in Texas and Wisconsin, which support EOG's exploration and development operations. EOG's sand mining operations are subject to regulation by the federal Mine Safety and Health Administration (MSHA) under the Federal Mine Safety and Health Act of 1977 (Mine Act). MSHA inspects mining facilities on a regular basis and issues citations and orders when it believes a violation has occurred under the Mine Act.

EOG was the operator of the following sand mining facilities during the year ended December 31, 2020:

•Hood County Sand Plant - Hood County, TX (MSHA ID 41-04696);

•Rawhide Sand Plant - Hood County, TX (MSHA ID 41-04777); and

•Chippewa Falls Sand Plant - Chippewa County, WI (MSHA ID 47-03624).

__________

For the year ended December 31, 2020, EOG did not receive any of the following from MSHA: (i) a citation for a violation of a mandatory health or safety standard that could significantly and substantially contribute to the cause and effect of a mine safety or health hazard under Section 104 of the Mine Act; (ii) an order issued under Section 104(b) of the Mine Act; (iii) a citation or order for unwarrantable failure to comply with mandatory health or safety standards under Section 104(d) of the Mine Act; (iv) written notice of a flagrant violation under Section 110(b)(2) of the Mine Act; (v) an imminent danger order issued under Section 107(a) of the Mine Act; (vi) any proposed assessments under the Mine Act; (vii) written notice of a pattern of violations of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of mine health or safety hazards under Section 104(e) of the Mine Act; or (viii) written notice of the potential to have such a pattern. Moreover, during the year ended December 31, 2020, EOG did not experience a mining-related fatality.

In addition, as of December 31, 2020, EOG did not have any legal action pending before the Federal Mine Safety and Health Review Commission (Mine Commission), and did not have any legal actions instituted or resolved before the Mine Commission during the year ended December 31, 2020.

EX-99.1

EXHIBIT 99.1

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

January 26, 2021

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, 2020, 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, 2021. The properties evaluated consist of working and royalty interests located in the States of New Mexico and Texas; China; and offshore from Trinidad. EOG has represented that these properties account for 82.9 percent on a net equivalent barrel basis of EOG’s net proved reserves as of December 31, 2020, 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 Securities and Exchange Commission (SEC) of the United States. It is our opinion that the procedures and methodologies employed by EOG for the preparation of its proved reserves estimates as of December 31, 2020, 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, 2020, 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, 2020. 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 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.

2

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.

(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.

3

(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 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.

4

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 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 in China and 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, 2020, and made available for this evaluation were used to prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly production data available for certain properties only through November 2020. Estimated cumulative production, as of December 31, 2020, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 1 month.

5

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 reserves 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 West Texas Intermediate (WTI) pricing, 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. The oil, condensate, and NGL prices were calculated using differentials furnished by EOG to the reference price of $39.57 per barrel and held constant thereafter. The volume-weighted average prices attributable to the estimated proved reserves over the lives of the properties were $37.31 per barrel of oil and condensate and $12.42 per barrel of NGL.

6

Gas Prices

EOG has represented that the gas prices were based on Henry Hub pricing, 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. The gas prices were calculated for each property using differentials furnished by EOG to the reference price of $1.985 per million Btu ($/MMBtu) and 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 $1.418 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 located 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, provided by EOG and based on current expenses, were held constant for the lives of the properties. Future capital expenditures were estimated using 2020 values, provided by EOG, and were not adjusted for inflation. 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 undeveloped reserves estimated herein.

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.

7

Summary of Conclusions

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, 2020, attributable to these properties, which represent 82.9 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):

	Estimated by EOG Net Proved Reserves as of December 31, 2020
Properties Evaluated by DeGolyer and MacNaughton	Oil and Condensate (Mbbl)	NGL (Mbbl)	Sales Gas (MMcf)	Oil Equivalent (Mboe)
Proved Developed	611,423	273,862	1,832,494	1,190,700
Proved Undeveloped	680,248	396,159	2,417,354	1,479,300
Total Proved	1,291,671	670,021	4,249,848	2,670,000
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, 2020, 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 DeGoyler and MacNaughton Net Proved Reserves as of December 31, 2020
Properties Evaluated by DeGolyer and MacNaughton	Oil and Condensate (Mbbl)	NGL (Mbbl)	Sales Gas (MMcf)	Oil Equivalent (Mboe)
Proved Developed	617,881	248,889	1,712,549	1,152,195
Proved Undeveloped	748,188	378,097	2,306,494	1,510,701
Total Proved	1,366,069	626,987	4,019,043	2,662,896
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.

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 0.3 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.

8

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, 2020, 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.

Senior Vice President

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 Senior Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to EOG dated January 26, 2021, and that I, as Senior 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 10 years of experience in oil and gas reservoir studies and reserves evaluations.

/s/ Dilhan Ilk

Dilhan Ilk, P.E.

Senior Vice President

DeGoyler and MacNaughton

XML

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Feb. 12, 2021	Jun. 30, 2020
Cover [Abstract]
Document Type	10-K
Entity Registrant Name	EOG RESOURCES, INC.
Document Annual Report	true
Document Transition Report	false
Entity Central Index Key	0000821189
Entity File Number	1-9743
Current Fiscal Year End Date	--12-31
Document Period End Date	Dec. 31, 2020
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2020
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
Entity Shell Company	false
Amendment Flag	false
Entity Public Float			$ 29,444
Entity Common Stock, Shares Outstanding		583,563,479
ICFR Auditor Attestation Flag	true
Documents Incorporated by Reference	Documents incorporated by reference.  Portions of the Definitive Proxy Statement for the registrant's 2021 Annual Meeting of Stockholders, to be filed within 120 days after December 31, 2020, are incorporated by reference into Part III of this report.

XML

Consolidated Statements of Income and Comprehensive Income shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2020 USD ($) $ / shares shares		Dec. 31, 2019 USD ($) $ / shares shares		Dec. 31, 2018 USD ($) $ / shares shares
Total	$ 11,032,048		$ 17,379,973		$ 17,275,399
Net Income (Loss)	$ (604,572)		$ 2,734,910		$ 3,419,040
Diluted | $ / shares	$ (1.04)		$ 4.71		$ 5.89
Basic | $ / shares	$ (1.04)		$ 4.73		$ 5.93
Basic (in shares) | shares	578,949		577,670		576,578
Diluted (in shares) | shares	578,949		580,777		580,441
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	$ (612,248)		$ 2,731,349		$ 3,436,979
Other Comprehensive Income (Loss)	(7,676)		(3,561)		17,939
Accounts Receivable, after Allowance for Credit Loss, Current	1,337,000		1,619,000		1,460,000
Other, Net of Tax	(330)		(678)		1,123
Foreign Currency Translation Adjustments	(7,346)		(2,883)		16,816
Operating Expenses
Lease and Well	1,063,374		1,366,993		1,282,678
Transportation Costs	734,989	[1]	758,300	[1]	746,876	[1]
Gathering and Processing Costs	459,211	[1]	479,102	[1]	436,973
Exploration Costs	145,788		139,881		148,999
Dry Hole Costs	13,083	[1]	28,001	[1]	5,405	[1]
Impairments	2,099,780		517,896		347,021
Marketing Costs	2,697,729		5,351,524		5,203,243
Depreciation, Depletion and Amortization	3,400,353		3,749,704		3,435,408
General and Administrative	483,823		489,397		426,969
Taxes Other Than Income	477,934		800,164		772,481
Total	11,576,064		13,680,962		12,806,053
Operating Income (Loss)	(544,016)		3,699,011		4,469,346
Other Income, Net	10,228		31,385		16,704
Income (Loss) Before Interest Expense and Income Taxes	(533,788)		3,730,396		4,486,050
Interest Expense
Incurred	236,154		223,421		269,549
Capitalized	(30,888)		(38,292)		(24,497)
Net Interest Expense	205,266		185,129		245,052
Income (Loss) Before Income Taxes	(739,054)		3,545,267		4,240,998
Income Tax Provision (Benefit)	(134,482)		810,357		821,958
Net Income (Loss)	$ (604,572)		$ 2,734,910		$ 3,419,040
Net Income (Loss) Per Share
Basic | $ / shares	$ (1.04)		$ 4.73		$ 5.93
Diluted | $ / shares	$ (1.04)		$ 4.71		$ 5.89
Average Number of Common Shares [Abstract]
Basic (in shares) | shares	578,949		577,670		576,578
Diluted (in shares) | shares	578,949		580,777		580,441
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments	$ (7,346)		$ (2,883)		$ 16,816
Other, Net of Tax	(330)		(678)		1,123
Other Comprehensive Income (Loss)	(7,676)		(3,561)		17,939
Comprehensive Income (Loss)	(612,248)		2,731,349		3,436,979
Crude Oil and Condensate
Revenues	5,785,609		9,612,532		9,517,440
Natural Gas Liquids
Revenues	667,514		784,818		1,127,510
Natural Gas
Revenues	837,133		1,184,095		1,301,537
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts
Revenues	1,144,737		180,275		(165,640)
Gathering, Processing and Marketing
Revenues	2,582,984		5,360,282		5,230,355
Gains (Losses) on Asset Dispositions, Net
Revenues	(46,883)		123,613		174,562
Other, Net
Revenues	$ 60,954		$ 134,358		$ 89,635

[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, 2020.

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Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Current Assets
Cash and Cash Equivalents	$ 3,328,928	$ 2,027,972
Accounts Receivable, Net	1,522,256	2,001,658
Inventories	629,401	767,297
Assets from Price Risk Management Activities	64,559	1,299
Income Taxes Receivable	23,037	151,665
Other	293,987	323,448
Total	5,862,168	5,273,339
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)	64,792,798	62,830,415
Other Property, Plant and Equipment	4,478,976	4,472,246
Total Property, Plant and Equipment	69,271,774	67,302,661
Less: Accumulated Depreciation, Depletion and Amortization	(40,673,147)	(36,938,066)
Total Property, Plant and Equipment, Net	28,598,627	30,364,595
Deferred Income Taxes	2,127	2,363
Other Assets	1,341,679	1,484,311
Total Assets	35,804,601	37,124,608
Current Liabilities
Accounts Payable	1,681,193	2,429,127
Accrued Taxes Payable	205,754	254,850
Dividends Payable	217,419	166,273
Liabilities from Price Risk Management Activities	0	20,194
Current Portion of Long-Term Debt	781,054	1,014,524
Current Portion of Operating Lease Liabilities	295,089	369,365
Other	279,595	232,655
Total	3,460,104	4,486,988
Long-Term Debt	5,035,351	4,160,919
Other Liabilities	2,147,932	1,789,884
Deferred Income Taxes	4,859,327	5,046,101
Commitments and Contingencies (Note 8)
Stockholders' Equity
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 583,694,850 Shares and 582,213,016 Shares Issued at December 31, 2020 and 2019, respectively	205,837	205,822
Additional Paid in Capital	5,945,024	5,817,475
Accumulated Other Comprehensive Loss	(12,328)	(4,652)
Retained Earnings	14,169,969	15,648,604
Common Stock Held in Treasury, 124,265 Shares and 298,820 Shares at December 31, 2020 and 2019, respectively	(6,615)	(26,533)
Total Stockholders' Equity	20,301,887	21,640,716
Total Liabilities and Stockholders' Equity	$ 35,804,601	$ 37,124,608

XML

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2020	Dec. 31, 2019
Common Stock
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)	583,694,850	582,213,016
Treasury Stock
Common Stock Held in Treasury (in shares)	124,265	298,820

XML

Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Accumulated Other Comprehensive Income (Loss)	Retained Earnings [Member]	Treasury Stock, Common [Member]	Common Shares, Treasury [Member]
Balance at Dec. 31, 2017	$ 16,283,273	$ 205,788	$ 5,536,547	$ (19,297)	$ 10,593,533	$ (33,298)
Net Income (Loss)	3,419,040	0	0	0	3,419,040	0
Common Stock Issued Under Stock Plans	5,620	8	5,612	0	0	0
Common Stock Dividends Declared	(469,443)	0	0	0	(469,443)	0
Other Comprehensive Income (Loss)	17,939	0	0	17,939	0	0
Change in Treasury Stock - Stock Compensation Plans, Net	(48,454)	0	(35,118)	0	0	(13,336)
Restricted Stock and Restricted Stock Units, Net	0	8	(3,891)	0	0	3,883
Stock-Based Compensation Expenses	155,337	0	155,337	0	0	0
Treasury Stock Issued as Compensation	876	0	307	0	0	569
Balance at Dec. 31, 2018	$ 19,364,188	205,804	5,658,794	(1,358)	13,543,130	(42,182)
Common Stock Dividends Declared (in dollars per share)	$ 0.81
Net Income (Loss)	$ 2,734,910	0	0	0	2,734,910	0
Common Stock Issued Under Stock Plans	(8)	1	(9)	0	0	0
Common Stock Dividends Declared	(629,169)	0	0	0	(629,169)	0
Other Comprehensive Income (Loss)	(3,561)	0	0	(3,561)	0	0
Change in Treasury Stock - Stock Compensation Plans, Net	(6,853)	0	(10,637)	0	0	3,784
Restricted Stock and Restricted Stock Units, Net	0	17	(4,566)	0	0	4,549
Stock-Based Compensation Expenses	174,738	0	174,738	0	0	0
Treasury Stock Issued as Compensation	6,471	0	(845)	0	0	7,316
Cumulative Effect of Account Changes	0	0	0	267	(267)		$ 0
Balance at Dec. 31, 2019	$ 21,640,716	205,822	5,817,475	(4,652)	15,648,604	(26,533)
Common Stock Dividends Declared (in dollars per share)	$ 1.0825
Net Income (Loss)	$ (604,572)	0	0	0	(604,572)	0
Common Stock Issued Under Stock Plans	0	0	0	0	0	0
Common Stock Dividends Declared	(874,063)	0	0	0	(874,063)	0
Other Comprehensive Income (Loss)	(7,676)	0	0	(7,676)	0	0
Change in Treasury Stock - Stock Compensation Plans, Net	(63)	0	(9,152)	0	0	9,089
Restricted Stock and Restricted Stock Units, Net	0	15	(9,310)	0	0	9,295
Stock-Based Compensation Expenses	146,396	0	146,396	0	0	0
Treasury Stock Issued as Compensation	1,149	0	(385)	0	0	1,534
Cumulative Effect of Account Changes	267
Balance at Dec. 31, 2020	$ 20,301,887	$ 205,837	$ 5,945,024	$ (12,328)	$ 14,169,969	$ (6,615)
Common Stock Dividends Declared (in dollars per share)	$ 1.50

XML

Consolidated Statements of Stockholders' Equity (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Statement of Stockholders' Equity [Abstract]
Common Stock Dividends Declared	$ 874,063	$ 629,169	$ 469,443
Common Stock Dividends Declared (in dollars per share)	$ 1.50	$ 1.0825	$ 0.81

XML

Consolidated Statements of Cash Flows - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Cash Flows from Operating Activities
Net Income (Loss)		$ (604,572)	$ 2,734,910	$ 3,419,040
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization		3,400,353	3,749,704	3,435,408
Impairments		2,099,780	517,896	347,021
Stock-Based Compensation Expenses		146,396	174,738	155,337
Deferred Income Taxes		(186,390)	631,658	894,156
(Gains) Losses on Asset Dispositions, Net		46,883	(123,613)	(174,562)
Other, Net		12,826	4,496	7,066
Dry Hole Costs	[1]	13,083	28,001	5,405
Mark-to-Market Commodity Derivative Contracts
Total (Gains) Losses		(1,144,737)	(180,275)	165,640
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts		1,070,647	231,229	(258,906)
Other, Net		1,354	962	3,108
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		466,523	(91,792)	(368,180)
Inventories		122,647	90,284	(395,408)
Accounts Payable		(795,267)	168,539	439,347
Accrued Taxes Payable		(49,096)	40,122	(92,461)
Other Assets		324,521	358,001	(125,435)
Other Liabilities		8,098	(56,619)	10,949
Changes in Components of Working Capital Associated with Investing and Financing Activities		74,734	(115,061)	301,083
Net Cash Provided by Operating Activities		5,007,783	8,163,180	7,768,608
Investing Cash Flows
Additions to Oil and Gas Properties		(3,243,474)	(6,151,885)	(5,839,294)
Additions to Other Property, Plant and Equipment		(221,226)	(270,641)	(237,181)
Proceeds from Sales of Assets		191,928	140,292	227,446
Payments for (Proceeds from) Other Investing Activities		0	(10,000)	(19,993)
Changes in Components of Working Capital Associated with Investing Activities		(74,734)	115,061	(301,140)
Net Cash Used in Investing Activities		(3,347,506)	(6,177,173)	(6,170,162)
Financing Cash Flows
Long-Term Debt Repayments		(1,000,000)	(900,000)	(350,000)
Dividends Paid		(820,823)	(588,200)	(438,045)
Treasury Stock Purchased		(16,130)	(25,152)	(63,456)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan		16,169	17,946	20,560
Debt Issuance Costs		(2,649)	(5,016)	0
Repayment of Capital Lease Obligation		(19,444)	(12,899)	(8,219)
Other, Net		0	0	57
Net Cash Used in Financing Activities		(359,025)	(1,513,321)	(839,103)
Effect of Exchange Rate Changes on Cash		(296)	(348)	(37,937)
Increase in Cash and Cash Equivalents		1,300,956	472,338	721,406
Cash and Cash Equivalents at Beginning of Year		2,027,972	1,555,634	834,228
Cash and Cash Equivalents at End of Year		3,328,928	2,027,972	1,555,634
Proceeds from Issuance of Senior Long-term Debt		$ 1,483,852	$ 0	$ 0

[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, 2020.

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Summary of Significant Accounting Policies (Notes)

12 Months Ended

Dec. 31, 2020

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Principles of Consolidation.  The consolidated financial statements of EOG Resources, Inc. (EOG) include the accounts of all domestic and foreign subsidiaries.  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, commodity derivative contracts, accounts receivable, accounts payable and current and long-term debt.  The carrying values of cash and cash equivalents, commodity derivative contracts, accounts receivable and accounts payable approximate fair value (see Notes 2 and 12).

Effective January 1, 2020, EOG adopted the provisions of Accounting Standards Update (ASU) 2016-13, "Measurement of Credit Losses on Financial Instruments" (ASU 2016-13). ASU 2016-13 changes the impairment model for financial assets and certain other instruments by requiring entities to adopt a forward-looking expected loss model that will result in earlier recognition of credit losses. EOG elected to adopt ASU 2016-13 using the modified retrospective approach with a cumulative effect adjustment to retained earnings as of the effective date. Financial results reported in periods prior to January 1, 2020, are unchanged. EOG assessed its applicable financial assets, which are primarily its accounts receivable from hydrocarbon sales and joint interest billings to third-party companies, including foreign state-owned entities in the oil and gas industry. Based on its assessment and various potential remedies ensuring collection, EOG did not record an impact to retained earnings upon adoption and expects current and future credit losses to be immaterial. EOG continues to monitor the credit risk from third-party companies to determine if expected credit losses may become material.

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 costs, 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 asset.  If the expected undiscounted future cash flows, based on EOG's estimate of (and assumptions regarding) future crude oil, natural gas liquids (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.

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

Revenue Recognition. Effective January 1, 2018, EOG adopted the provisions of ASU 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09). ASU 2014-09 and other related ASUs require entities to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. EOG elected to adopt ASU 2014-09 using the modified retrospective approach, which required EOG to recognize in retained earnings the cumulative effect at the date of adoption for all existing contracts with customers which were not substantially complete as of January 1, 2018. There was no impact to retained earnings upon adoption of ASU 2014-09.

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

In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements within its United States segment as Gathering and Processing Costs, instead of as a deduction to Revenues within its Consolidated Statements of Income (Loss) and Comprehensive Income (Loss). There was no impact to operating income, net income or cash flows resulting from changes to the presentation of natural gas processing fees. The impacts of the adoption of ASU 2014-09 for the year ended December 31, 2018, were as follows (in thousands):

	As Reported		Amounts Without Adoption of ASU 2014-09		Effect of Change
Operating Revenues and Other
Crude Oil and Condensate	$	9,517,440	$	9,517,440	$	—
Natural Gas Liquids	1,127,510		1,121,237		6,273
Natural Gas	1,301,537		1,104,095		197,442
Gathering, Processing and Marketing	5,230,355		5,211,136		19,219
Total Operating Revenues and Other	17,275,399		17,052,465		222,934
Operating Expenses
Gathering and Processing Costs	436,973		233,258		203,715
Marketing Costs	5,203,243		5,184,024		19,219
Total Operating Expenses	12,806,053		12,583,119		222,934
Operating Income	4,469,346		4,469,346		—

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, 2020 and 2019 and upon adoption of ASU 2014-09 effective January 1, 2018, were $1,337 million, $1,619 million and $1,460 million, respectively, and were included in Accounts Receivable, Net on the Consolidated Balance Sheets. Losses incurred on receivables from contracts with customers are infrequent and have been immaterial.

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 processing fees recognized as Gathering and Processing Costs.

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

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

Other Property, Plant and Equipment.  Other property, plant and equipment consists of gathering and processing assets, compressors, buildings and leasehold improvements, sand processing assets, 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.

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. The capitalization of interest is excluded on significant acquisitions of unproved oil and gas properties financed through non-interest-bearing instruments, such as the issuance of shares of Common Stock, or through non-cash property exchanges.

Accounting for Risk Management Activities.  Derivative instruments are recorded on the balance sheet as either an asset or liability measured at fair value, and changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met.  During the three-year period ended December 31, 2020, 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 Commodity Derivative Contracts on the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss).  The related cash flow impact of settled contracts is reflected as cash flows from operating activities.  EOG employs net presentation of derivative assets and liabilities for financial reporting purposes when such assets and liabilities are with the same counterparty and subject to a master netting arrangement.  See Note 12.

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

Foreign Currency Translation.  The United States dollar is the functional currency for all of EOG's consolidated subsidiaries except for its Canadian subsidiaries, for which the functional currency is the Canadian dollar, and its United Kingdom subsidiary (which was sold in the fourth quarter of 2018), for which the functional currency was the British pound.  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 Notes 4 and 17.

Net Income (Loss) Per Share.  Basic net income (loss) per share is computed on the basis of the weighted-average number of common shares outstanding during the period.  Diluted net income (loss) 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. Effective January 1, 2019, EOG adopted the provisions of ASU 2016-02, "Leases (Topic 842)" (ASU 2016-02). ASU 2016-02 and other related ASUs require that lessees recognize a right-of-use (ROU) asset and related lease liability, representing the obligation to make lease payments for certain lease transactions, on the Consolidated Balance Sheets and disclose additional leasing information.

EOG elected to adopt ASU 2016-02 and other related ASUs using the modified retrospective approach with a cumulative-effect adjustment to the opening balance of retained earnings as of the effective date. Financial results reported in periods prior to January 1, 2019, are unchanged. Additionally, EOG elected the package of practical expedients within ASU 2016-02 that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases, or (iii) initial direct costs for any existing leases, but did not elect the practical expedient of hindsight when determining the lease term of existing contracts at the effective date. EOG also elected the practical expedient under ASU 2018-01, "Leases (Topic 842) - Land Easement Practical Expedient for Transition to Topic 842," and did not evaluate existing or expired land easements not previously accounted for as leases prior to the January 1, 2019 effective date. There was no impact to retained earnings upon adoption of ASU 2016-02 and other related ASUs.

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 ASU 2016-02. 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.

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 from all leases, excluding those for fracturing services, real estate and salt water disposal, as lease payments under these contracts contain significant non-lease components, such as labor and operating costs. See Note 18.

Recently Issued Accounting Standards. In March 2020, the FASB issued ASU 2020-04, "Reference Rate Reform (Topic 848)" (ASU 2020-04), which provides optional expedients and exceptions for accounting treatment of contracts which are affected by the anticipated discontinuation of the London InterBank Offered Rate (LIBOR) and other rates resulting from rate reform. Contract terms that are modified due to the replacement of a reference rate are not required to be remeasured or reassessed under relevant accounting standards. Early adoption is permitted. ASU 2020-04 covers certain contracts which reference these rates and that are entered into on or before December 31, 2022. EOG is evaluating the provisions of ASU 2020-04 and has not determined the full impact on its consolidated financial statements and related disclosures related to its $2.0 billion senior unsecured Revolving Credit Agreement.

In December 2019, the FASB issued ASU 2019-12, "Income Taxes (Topic 740) ‑ Simplifying the Accounting for Income Taxes" (ASU 2019-12), which amends certain aspects of accounting for income taxes. ASU 2019-12 removes specific exceptions within existing U.S. GAAP related to the incremental approach for intraperiod tax allocation and to the general methodology for calculating income taxes in interim periods, among other changes. ASU 2019-12 also requires an entity to reflect the effect of an enacted change in tax laws or rates in the annual effective tax rate computation in the interim period that includes the enactment date, among other requirements. ASU 2019-12 is effective for interim and annual periods beginning after December 15, 2020, and early adoption is permitted. EOG will adopt ASU 2019-12 effective January 1, 2021, with all of the anticipated and applicable effects to be required on a prospective basis. EOG does not expect the adoption of ASU 2019-12 to have a material impact on its consolidated financial statements and related disclosures.

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Long-Term Debt (Notes)

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

Long-Term Debt at December 31, 2020 and 2019 consisted of the following (in thousands):

	2020		2019
4.40% Senior Notes due 2020	$	—	$	500,000
2.45% Senior Notes due 2020	—		500,000
4.100% Senior Notes due 2021	750,000		750,000
2.625% Senior Notes due 2023	1,250,000		1,250,000
3.15% Senior Notes due 2025	500,000		500,000
4.15% Senior Notes due 2026	750,000		750,000
6.65% Senior Notes due 2028	140,000		140,000
4.375% Senior Notes due 2030	750,000		—
3.90% Senior Notes due 2035	500,000		500,000
5.10% Senior Notes due 2036	250,000		250,000
4.950% Senior Notes due 2050	750,000		—
Long-Term Debt	5,640,000		5,140,000
Finance Leases (see Note 18)	212,217		57,900
Less: Current Portion of Long-Term Debt	781,054		1,014,524
Unamortized Debt Discount	30,931		19,528
Debt Issuance Costs	4,881		2,929
Total Long-Term Debt	$	5,035,351	$	4,160,919

At December 31, 2020, the aggregate annual maturities of long-term debt (excluding finance lease obligations) were $750 million in 2021, zero in 2022, $1.25 billion in 2023, zero in 2024 and $500 million in 2025. 

At December 31, 2020 and 2019, EOG had no outstanding commercial paper borrowings and did not utilize any commercial paper borrowings during 2020 and 2019.

On February 1, 2021, EOG repaid upon maturity the $750 million aggregate principal amount of its 4.100% Senior Notes due 2021.

On June 1, 2020, EOG repaid upon maturity the $500 million aggregate principal amount of its 4.40% Senior Notes due 2020.

On April 14, 2020, EOG closed on its offering of $750 million aggregate principal amount of its 4.375% Senior Notes due 2030 and $750 million aggregate principal amount of its 4.950% Senior Notes due 2050 (together, the Notes). Interest on the Notes is payable semi-annually in arrears on April 15 and October 15 of each year, beginning on October 15, 2020. EOG received net proceeds of $1.48 billion from the issuance of the Notes, which were used to repay the 4.40% Senior Notes due 2020 when they matured on June 1, 2020 (see below), and for general corporate purposes, including the funding of capital expenditures.

On April 1, 2020, EOG repaid upon maturity the $500 million aggregate principal amount of its 2.45% Senior Notes due 2020.

On June 27, 2019, EOG entered into a new $2.0 billion senior unsecured Revolving Credit Agreement (the Agreement) with domestic and foreign lenders (Banks). The Agreement replaced EOG's $2.0 billion senior unsecured Revolving Credit Agreement, dated as of July 21, 2015, with domestic and foreign lenders, which had a scheduled maturity date of July 21, 2020 and which was terminated by EOG (without penalty), effective as of June 27, 2019, in connection with the execution of the Agreement.

The Agreement has a scheduled maturity date of June 27, 2024, and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods subject to certain terms and conditions. The Agreement (i) commits the Banks to provide advances up to an aggregate principal amount of $2.0 billion at any one time outstanding, with an option for EOG to request increases in the aggregate commitments to an amount not to exceed $3.0 billion, subject to certain terms and conditions and (ii) includes a swingline subfacility and a letter of credit subfacility. Advances under the Agreement will accrue interest based, at EOG's option, on either the LIBOR plus an applicable margin (Eurodollar rate) or the base rate (as defined in the Agreement) plus an applicable margin. The Agreement contains representations, warranties, covenants and events of default that EOG believes are customary for investment-grade, senior unsecured commercial bank credit agreements, including a financial covenant for the maintenance of a ratio of total debt-to-capitalization (as such terms are defined in the Agreement) of no greater than 65%. At December 31, 2020, EOG was in compliance with this financial covenant. At December 31, 2020 and December 31, 2019, there were no borrowings or letters of credit outstanding under the Agreement. The Eurodollar rate and base rate (inclusive of the applicable margin), had there been any amounts borrowed under the Agreement at December 31, 2020, would have been 1.04% and 3.25%, respectively.

On June 3, 2019, EOG repaid upon maturity the $900 million aggregate principal amount of its 5.625% Senior Notes due 2019.

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Stockholder's Equity (Notes)

12 Months Ended

Dec. 31, 2020

Stockholders' Equity Note [Abstract]

Stockholder's Equity

Stockholders' Equity

Common Stock.  In September 2001, EOG's Board of Directors (Board) authorized the purchase of an aggregate maximum of 10 million shares of Common Stock that superseded all previous authorizations.  At December 31, 2020, 6,386,200 shares remained available for purchase under this authorization.  EOG last purchased shares of its Common Stock under this authorization in March 2003.  In addition, 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 do not count against the Board authorization discussed above.  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 25, 2021, the Board increased the quarterly cash dividend on the common stock from the previous $0.375 per share to $0.4125 per share, effective beginning with the dividend to be paid on April 30, 2021, to stockholders of record as of April 16, 2021.

On February 27, 2020, the Board increased the quarterly cash dividend on the common stock from the previous $0.2875 per share to $0.375 per share, effective beginning with the dividend to be paid on April 30, 2020, to stockholders of record as of April 16, 2020.

On May 2, 2019, the Board increased the quarterly cash dividend on the common stock from the previous $0.22 per share to $0.2875 per share, effective beginning with the dividend paid on July 31, 2019, to stockholders of record as of July 17, 2019.

On August 2, 2018, the Board increased the quarterly cash dividend on the common stock from the previous $0.1850 per share to $0.22 per share, effective beginning with the dividend paid on October 31, 2018, to stockholders of record as of October 17, 2018. On February 27, 2018, the Board increased the quarterly cash dividend on the common stock from the previous $0.1675 per share to $0.1850 per share, effective beginning with the dividend paid on April 30, 2018, to stockholders of record as of April 16, 2018.

The following summarizes Common Stock activity for each of the years ended December 31, 2018, 2019 and 2020 (in thousands):

	Common Shares
	Issued	Treasury	Outstanding
Balance at December 31, 2017	578,828	(351)	578,477
Common Stock Issued Under Stock-Based Compensation Plans	1,580	—	1,580
Treasury Stock Purchased (1)	—	(539)	(539)
Common Stock Issued Under Employee Stock Purchase Plan	—	180	180
Treasury Stock Issued Under Stock-Based Compensation Plans	—	325	325
Balance at December 31, 2018	580,408	(385)	580,023
Common Stock Issued Under Stock-Based Compensation Plans	1,688	—	1,688
Treasury Stock Purchased (1)	—	(310)	(310)
Common Stock Issued Under Employee Stock Purchase Plan	117	106	223
Treasury Stock Issued Under Stock-Based Compensation Plans	—	290	290
Balance at December 31, 2019	582,213	(299)	581,914
Common Stock Issued Under Stock-Based Compensation Plans	1,482	—	1,482
Treasury Stock Purchased (1)	—	(389)	(389)
Common Stock Issued Under Employee Stock Purchase Plan	—	377	377
Treasury Stock Issued Under Stock-Based Compensation Plans	—	187	187
Balance at December 31, 2020	583,695	(124)	583,571

(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.

Preferred Stock.  EOG currently has one authorized series of preferred stock.  As of December 31, 2020, there were no shares of preferred stock outstanding.

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Accumulated Other Comprehensive Loss (Notes)

12 Months Ended

Dec. 31, 2020

Equity [Abstract]

Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss includes certain transactions that have generally been reported in the Consolidated Statements of Stockholders' Equity. The components of Accumulated Other Comprehensive Loss at December 31, 2020 and 2019 consisted of the following (in thousands):

	Foreign Currency Translation Adjustment		Other		Total
December 31, 2018	$	174	$	(1,532)	$	(1,358)
Cumulative effect of accounting changes	—		267		267
Other comprehensive loss before taxes	(2,883)		(533)		(3,416)
Tax effects	—		(145)		(145)
Other comprehensive loss	(2,883)		(678)		(3,561)
December 31, 2019	(2,709)		(1,943)		(4,652)
Other comprehensive loss before taxes	(7,346)		(183)		(7,529)
Tax effects	—		(147)		(147)
Other comprehensive loss	(7,346)		(330)		(7,676)
December 31, 2020	$	(10,055)	$	(2,273)	$	(12,328)

    No significant amount was reclassified out of Accumulated Other Comprehensive Loss during the years ended December 31, 2020, 2019 and 2018.

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Other Income, Net (Notes)	12 Months Ended
	Dec. 31, 2020
Other Income and Expenses [Abstract]
Other Income, Net	Other Income, NetOther income, net for 2020 included interest income ($12 million), partially offset by equity losses from investments in ammonia plants in Trinidad ($2 million). Other income, net for 2019 included interest income ($26 million) and net foreign currency transaction gains ($2 million). Other income, net for 2018 included interest income ($12 million), a downward adjustment to deferred compensation expense ($6 million) and equity income from investments in ammonia plants in Trinidad ($2 million), partially offset by net foreign currency transaction losses ($7 million).

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Employee Benefit Plans (Notes)

12 Months Ended

Dec. 31, 2020

Share-based Payment Arrangement [Abstract]

Employee Benefit Plans

Employee Benefit Plans

Stock-Based Compensation

During 2020, EOG maintained various stock-based compensation plans as discussed below.  EOG recognizes compensation expense on grants of stock options, SARs, restricted stock and restricted stock units, 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 (Loss) and Comprehensive Income (Loss) 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, 2020, 2019 and 2018 was as follows (in millions):

	2020		2019		2018
Lease and Well	$	52	$	56	$	51
Gathering and Processing Costs	1		1		1
Exploration Costs	21		26		25
General and Administrative	72		92		78
Total	$	146	$	175	$	155

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

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 Committee's certification of the applicable performance multiple

At December 31, 2020, approximately 2.0 million common shares remained available for grant under the 2008 Plan.  EOG's policy is to issue shares related to the 2008 Plan from previously authorized unissued shares or treasury shares to the extent treasury shares are available.

During 2020, 2019 and 2018, EOG issued shares in connection with stock option/SAR exercises, restricted stock grants, restricted stock unit and performance unit releases and ESPP purchases.  Net tax deficiencies and excess tax benefits recognized within the income tax provision were $(22) million, $(1) million and $20 million for the years ended December 31, 2020, 2019 and 2018, 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) have been or may be granted options to purchase shares of Common Stock.  In addition, participants in EOG's stock plans (including the 2008 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'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 $62 million, $63 million and $60 million for the years ended December 31, 2020, 2019 and 2018, respectively.

Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants for the years ended December 31, 2020, 2019 and 2018 were as follows:

	Stock Options/SARs									ESPP
	2020			2019			2018			2020			2019			2018
Weighted Average Fair Value of Grants	$	11.06		$	19.49		$	33.46		$	19.14		$	22.83		$	25.75
Expected Volatility	44.47		%	32.02		%	28.23		%	53.48		%	34.78		%	24.59		%
Risk-Free Interest Rate	0.21		%	1.69		%	2.68		%	0.90		%	2.27		%	1.89		%
Dividend Yield	3.27		%	1.39		%	0.72		%	2.27		%	1.04		%	0.64		%
Expected Life	5.2 years			5.1 years			5.0 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, 2020, 2019 and 2018 (stock options and SARs in thousands):

	2020			2019			2018
	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	9,395	$	94.53	8,310	$	96.90	9,103	$	83.89
Granted	1,996	37.63		1,965	75.39		1,906	126.49
Exercised (1)	(23)	69.59		(606)	61.43		(2,493)	72.21
Forfeited	(1,182)	88.93		(274)	102.57		(206)	94.43
Outstanding at December 31	10,186	84.08		9,395	94.53		8,310	96.90
Stock Options/SARs Exercisable at December 31	6,343	96.41		5,275	94.21		3,969	85.82

(1)The total intrinsic value of stock options/SARs exercised during the years 2020, 2019 and 2018 was $0.4 million, $14 million and $118 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, 2020, there were 9.9 million stock options/SARs vested or expected to vest with a weighted average grant price of $84.76 per share, an intrinsic value of $22.5 million and a weighted average remaining contractual life of 4.2 years.

The following table summarizes certain information for the stock options and SARs outstanding and exercisable at December 31, 2020 (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 $  43.99	1,974	7	$	37.43			10	1	$	37.44
44.00 to     74.99	872	2	69.37				846	2	69.47
75.00 to     75.99	1,863	6	75.09				636	5	75.09
76.00 to     95.99	1,242	3	94.47				1,215	3	94.63
96.00 to   101.99	2,477	3	97.95				2,457	3	97.95
102.00 to   129.99	1,758	5	126.44				1,179	5	126.37
	10,186	4	84.08		$	24,578	6,343	3	96.41		$	124

(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 thousands.

At December 31, 2020, unrecognized compensation expense related to non-vested stock option and SAR grants totaled $53 million.  This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.1 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, 2020, approximately 1.9 million shares of Common Stock remained available for grant under the ESPP.  The following table summarizes ESPP activity for the years ended December 31, 2020, 2019 and 2018 (in thousands, except number of participants):

	2020		2019		2018
Approximate Number of Participants	2,063		1,998		1,934
Shares Purchased	377		224		180
Aggregate Purchase Price	$	16,103	$	16,533	$	14,887

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 $75 million, $97 million and $81 million for the years ended December 31, 2020, 2019 and 2018, respectively.

The following table sets forth the restricted stock and restricted stock unit transactions for the years ended December 31, 2020, 2019 and 2018 (shares and units in thousands):

	2020			2019			2018
	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	4,546	$	90.16	3,792	$	96.64	3,905	$	88.57
Granted	1,488	38.10		1,749	80.01		812	117.55
Released (1)	(1,213)	85.92		(855)	96.93		(740)	78.16
Forfeited	(79)	86.52		(140)	97.54		(185)	92.12
Outstanding at December 31 (2)	4,742	74.97		4,546	90.16		3,792	96.64

(1)The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2020, 2019 and 2018 was $48 million, $70 million and $84 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)The total intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2020, 2019 and 2018 was $236 million, $381 million and $331 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, 2020, unrecognized compensation expense related to restricted stock and restricted stock units totaled $178 million. Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 1.6 years.

Performance Units.  EOG has granted performance units (Performance Awards) to its executive officers annually since 2012. As more fully discussed in the grant agreements, the performance metric applicable to these performance-based grants is EOG's total shareholder return over a three-year performance period relative to the total shareholder return of a designated group of peer companies (Performance Period). Upon the application of the performance multiple at the completion of the Performance Period, a minimum of 0% and a maximum of 200% of the Performance Awards granted could be outstanding. The fair value of the Performance Awards is estimated using a Monte Carlo simulation. Stock-based compensation expense related to the Performance Award grants totaled $9 million, $15 million and $14 million for the years ended December 31, 2020, 2019 and 2018, respectively.

  Weighted average fair values and valuation assumptions used to value Performance Awards during the years ended December 31, 2020, 2019 and 2018 were as follows:

	2020			2019			2018
Weighted Average Fair Value of Grants	$	42.77		$	79.98		$	136.74
Expected Volatility	47.27		%	29.20		%	29.92		%
Risk-Free Interest Rate	0.16		%	1.51		%	2.85		%

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 Award transactions for the years ended December 31, 2020, 2019 and 2018 (units in thousands):

	2020				2019			2018
	Number of Units		Weighted Average Price per Grant Date		Number of Units	Weighted Average Price per Grant Date		Number of Units	Weighted Average Price per Grant Date
Outstanding at January 1	598		$	92.19	539	$	101.53	502	$	90.96
Granted	172		37.44		172	75.09		113	125.73
Granted for Performance Multiple (1)	66		100.95		72	69.43		72	101.87
Released (2)	(223)		88.52		(185)	94.63		(148)	84.43
Forfeited	—		—		—	—		—	—
Outstanding at December 31 (3)	613	(4)	79.10		598	92.19		539	101.53

(1)Upon completion of the Performance Period for the Performance Awards granted in 2016, 2015 and 2014, a performance multiple of 150%, 200% and 200%, respectively, was applied to each of the grants resulting in additional grants of Performance Awards in February 2020, 2019 and 2018.

(2)The total intrinsic value of Performance Awards released during the years ended December 31, 2020, 2019 and 2018 was $13 million, $15 million and $18 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date Performance Awards are released.

(3)The total intrinsic value of Performance Awards outstanding at December 31, 2020, 2019 and 2018 was $31 million, $50 million and $47 million, respectively. The intrinsic value is based on the closing market price of the Common Stock on the last trading day of the year.

(4)Upon the application of the relevant performance multiple at the completion of each of the remaining Performance Periods, a minimum of 77 and a maximum of 1,149 Performance Awards could be outstanding.

At December 31, 2020, unrecognized compensation expense related to Performance Awards totaled $5 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 1.9 years.

Upon completion of the Performance Period for the Performance Awards granted in September 2017, a performance multiple of 125% was applied to the grants resulting in an additional grant of 19,629 Performance Awards in February 2021.

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 $46 million, $51 million and $43 million for 2020, 2019 and 2018, 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 2020, 2019 and 2018, respectively.

For the Trinidadian defined benefit pension plan, the benefit obligation, fair value of plan assets and accrued benefit cost totaled $13 million, $12 million and $0.1 million, respectively, at December 31, 2020, and $12 million, $10 million and $0.1 million, respectively, at December 31, 2019.

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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Income Taxes (Notes)

12 Months Ended

Dec. 31, 2020

Disclosure Text Block [Abstract]

Income Taxes

Income Taxes

The principal components of EOG's total net deferred income tax liabilities at December 31, 2020 and 2019 were as follows (in thousands):

	2020		2019
Deferred Income Tax Assets (Liabilities)
Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization	$	25,129	$	5,825
Foreign Net Operating Loss	74,280		66,675
Foreign Valuation Allowances	(97,499)		(70,455)
Foreign Other	217		318
Total Net Deferred Income Tax Assets	$	2,127	$	2,363
Deferred Income Tax (Assets) Liabilities
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization	$	5,028,010	$	5,277,550
Commodity Hedging Contracts	14,518		(4,699)
Deferred Compensation Plans	(42,594)		(47,650)
Accrued Expenses and Liabilities	—		(8,502)
Equity Awards	(102,944)		(108,324)
Alternative Minimum Tax Credit Carryforward	—		(31,904)
Undistributed Foreign Earnings	9,843		15,746
Other	(47,506)		(46,116)
Total Net Deferred Income Tax Liabilities	$	4,859,327	$	5,046,101
Total Net Deferred Income Tax Liabilities	$	4,857,200	$	5,043,738

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

	2020		2019		2018
United States	$	(756,479)	$	3,466,578	$	4,084,156
Foreign	17,425		78,689		156,842
Total	$	(739,054)	$	3,545,267	$	4,240,998

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

	2020		2019		2018
Current:
Federal	$	(107,834)	$	(152,258)	$	(303,853)
State	6,790		10,819		17,048
Foreign	40,248		81,426		65,615
Total	(60,796)		(60,013)		(221,190)
Deferred:
Federal	(153,027)		626,901		862,075
State	(15,400)		32,541		43,293
Foreign	(17,963)		(27,784)		(11,212)
Total	(186,390)		631,658		894,156
Other Non-Current: (1)
Federal	112,704		245,125		148,992
Foreign	—		(6,413)		—
Total	112,704		238,712		148,992
Income Tax Provision (Benefit)	$	(134,482)	$	810,357	$	821,958

(1)    Includes changes in certain amounts that are expected to be paid or received beyond the next twelve months. The primary component is refundable alternative minimum tax (AMT) credits.

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:

	2020		2019		2018
Statutory Federal Income Tax Rate	21.00	%	21.00	%	21.00	%
State Income Tax, Net of Federal Benefit	0.92		0.97		1.12
Income Tax Provision Related to Foreign Operations	(0.09)		0.87		0.51
Income Tax Provision Related to Canadian Operations	(2.43)		—		—
TCJA (1)	—		—		(2.60)		(2)
Share-Based Compensation	(2.94)		0.02		(0.47)
Other	1.74		—		(0.18)
Effective Income Tax Rate	18.20	%	22.86	%	19.38	%

(1)    The Tax Cuts and Jobs Act (TCJA) was enacted in 2017 and required certain measurement-period adjustments in 2018.

(2)    Includes impact of utilizing certain tax net operating losses (NOLs) ((1.2)%), the reversal of the federal sequestration charge ((1.0)%) and other TCJA impacts ((0.4)%).

The net effective tax rate of 18% in 2020 was lower than the prior year rate of 23% primarily due to taxes attributable to EOG's foreign operations and increased stock-based compensation tax deficiencies.

Deferred tax assets are recorded for certain tax benefits, including tax 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 thousands):

	2020		2019		2018
Beginning Balance	$	200,831	$	167,142	$	466,421
Increase (1)	25,573		30,673		23,062
Decrease (2)	(11,343)		(75)		(26,219)
Other (3)	3,942		3,091		(296,122)
Ending Balance	$	219,003	$	200,831	$	167,142

(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. The United Kingdom operations were sold in the fourth quarter of 2018.

As of December 31, 2020, EOG had state income tax NOLs of approximately $1.9 billion, which, if unused, expire between 2021 and 2039. EOG also has Canadian NOLs of $275 million, some of which can be carried forward up to 20 years. As described above, these NOLs and other less significant tax benefits have been evaluated for the likelihood of utilization, and valuation allowances have been established for the portion of these deferred income tax assets that do not meet the “more likely than not” threshold.

The total balance of unrecognized tax benefits for all jurisdictions at December 31, 2020, was $10 million, resulting from the tax treatment of certain compensation deductions, of which the full amount may potentially have an earnings impact. During the fourth quarter of 2020, EOG settled uncertain tax positions resulting from its tax treatment of research and experiential expenditures related to certain innovations in its horizontal drilling and completion operations for taxable years 2016 and 2017. Consequently, the balance of uncertain tax positions and earnings for the period decreased $29 million and $5 million, respectively. EOG records interest and penalties related to unrecognized tax benefits to its income tax provision. No interest expense has been recognized in the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) related to the remaining unrecognized tax benefits as these positions will be claimed on amended returns or as self-proposed audit adjustments, which, if sustained, will result in refunds. EOG does not anticipate that the amount of the unrecognized tax benefits will change materially during 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 (2016), Canada (2016), Trinidad (2013) and China (2010).

EOG's foreign subsidiaries' undistributed earnings are not considered to be permanently reinvested outside of the U.S. Accordingly, EOG may be required to accrue certain U.S. federal, state, and foreign deferred income taxes on these undistributed earnings as well as on any other outside basis differences related to its investments in these subsidiaries. As of December 31, 2020, EOG has cumulatively recorded $10 million of deferred foreign income taxes for withholdings on its undistributed foreign earnings. 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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Commitments and Contingencies (Notes)

12 Months Ended

Dec. 31, 2020

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Letters of Credit and Guarantees.  At December 31, 2020 and 2019, respectively, EOG had standby letters of credit and guarantees outstanding totaling $854 million and $902 million, primarily representing guarantees of payment or performance obligations on behalf of subsidiaries. As of February 18, 2021, EOG had received no demands for payment under these guarantees.

Minimum Commitments. At December 31, 2020, 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, 2020, were as follows (in millions):

	Total Minimum Commitments
2021	$	1,393
2022	1,263
2023	1,064
2024	790
2025	649
2026 and beyond	2,764
	$	7,923

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 (Loss) Per Share (Notes)

12 Months Ended

Dec. 31, 2020

Earnings Per Share [Abstract]

Net Income (Loss) Per Share

Net Income (Loss) Per Share

The following table sets forth the computation of Net Income (Loss) Per Share for the years ended December 31, 2020, 2019 and 2018 (in thousands, except per share data):

	2020		2019		2018
Numerator for Basic and Diluted Earnings per Share -
Net Income (Loss)	$	(604,572)	$	2,734,910	$	3,419,040
Denominator for Basic Earnings per Share -
Weighted Average Shares	578,949		577,670		576,578
Potential Dilutive Common Shares -
Stock Options/SARs	—		258		1,137
Restricted Stock/Units and Performance Units	—		2,849		2,726
Denominator for Diluted Earnings per Share -
Adjusted Diluted Weighted Average Shares	578,949		580,777		580,441
Net Income (Loss) Per Share
Basic	$	(1.04)	$	4.73	$	5.93
Diluted	$	(1.04)	$	4.71	$	5.89

The diluted earnings per share calculation excludes stock options, SARs, restricted stock, restricted stock units, performance units and ESPP grants that were anti-dilutive.  Shares underlying the excluded stock options, SARs and ESPP grants were 9.6 million, 6.1 million and 0.6 million for the years ended December 31, 2020, 2019 and 2018, respectively. Shares underlying the excluded restricted stock, restricted stock unit and performance unit grants were 5.0 million shares for the year ended December 31, 2020.

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Supplemental Cash Flow Information (Notes)

12 Months Ended

Dec. 31, 2020

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

Supplemental Cash Flow Information

Net cash paid (received) for interest and income taxes was as follows for the years ended December 31, 2020, 2019 and 2018 (in thousands):

	2020		2019		2018
Interest, Net of Capitalized Interest	$	205,447	$	186,546	$	243,279
Income Taxes, Net of Refunds Received	$	(205,795)	$	(291,849)	$	75,634

EOG's accrued capital expenditures at December 31, 2020, 2019 and 2018 were $414 million, $612 million and $592 million, respectively.

Non-cash investing activities for the year ended December 31, 2020, included additions of $212 million to EOG's oil and gas properties as a result of property exchanges and an addition of $174 million to EOG's other property, plant and equipment made in connection with finance lease transactions for storage facilities.

Non-cash investing activities for the year ended December 31, 2019, included additions of $150 million to EOG's oil and gas properties as a result of property exchanges.

Non-cash investing activities for the year ended December 31, 2018, included additions of $362 million to EOG's oil and gas properties as a result of property exchanges and an addition of $49 million to EOG's other property, plant and equipment primarily in connection with a finance lease transaction in the Permian Basin.

Cash paid for leases for the years ended December 31, 2020 and 2019, is disclosed in Note 18.

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Business Segment Information (Notes)

12 Months Ended

Dec. 31, 2020

Segment Reporting [Abstract]

Business Segment Information

Business Segment InformationEOG'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 in the United States, Trinidad and China and its exploration program in the Sultanate of Oman (Oman).  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, 2020, 2019 and 2018 (in thousands):

	United States		Trinidad		Other International (1)		Total
2020
Crude Oil and Condensate	$	5,773,582	$	10,723	$	1,304	$	5,785,609
Natural Gas Liquids	667,514		—		—		667,514
Natural Gas	614,002		168,967		54,164		837,133
Gains on Mark-to-Market Commodity Derivative Contracts	1,144,737		—		—		1,144,737
Gathering, Processing and Marketing	2,581,493		1,491		—		2,582,984
Gains (Losses) on Asset Dispositions, Net	(47,018)		(44)		179		(46,883)
Other, Net	60,989		(35)		—		60,954
Operating Revenues and Other (2)	10,795,299		181,102		55,647		11,032,048
Depreciation, Depletion and Amortization	3,323,800		60,629		15,924		3,400,353
Operating Income (Loss) (3)	(545,566)		74,801		(73,251)		(544,016)
Interest Income	10,783		922		34		11,739
Other Income (Expense)	153		(2,129)		465		(1,511)
Net Interest Expense	205,266		—		—		205,266
Income (Loss) Before Income Taxes	(739,896)		73,594		(72,752)		(739,054)
Income Tax Provision (Benefit)	(156,834)		14,568		7,784		(134,482)
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	3,316,724		83,173		41,961		3,441,858
Total Property, Plant and Equipment, Net	28,283,027		210,278		105,322		28,598,627
Total Assets	35,047,485		546,120		210,996		35,804,601

2019
Crude Oil and Condensate	$	9,599,125	$	11,138	$	2,269	$	9,612,532
Natural Gas Liquids	784,818		—		—		784,818
Natural Gas	866,911		258,819		58,365		1,184,095
Gains on Mark-to-Market Commodity Derivative Contracts	180,275		—		—		180,275
Gathering, Processing and Marketing	5,355,463		4,819		—		5,360,282
Gains (Losses) on Asset Dispositions, Net	131,446		(3,688)		(4,145)		123,613
Other, Net	134,325		18		15		134,358
Operating Revenues and Other (4)	17,052,363		271,106		56,504		17,379,973
Depreciation, Depletion and Amortization	3,652,294		79,389		18,021		3,749,704
Operating Income (Loss)	3,618,907		112,790		(32,686)		3,699,011
Interest Income	22,122		3,686		218		26,026
Other Income	3,235		727		1,397		5,359
Net Interest Expense	192,587		—		(7,458)		185,129
Income (Loss) Before Income Taxes	3,451,677		117,203		(23,613)		3,545,267
Income Tax Provision	760,881		40,901		8,575		810,357
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	6,208,394		53,325		12,233		6,273,952
Total Property, Plant and Equipment, Net	30,101,857		184,606		78,132		30,364,595
Total Assets	36,274,942		705,747		143,919		37,124,608

	United States		Trinidad		Other International (1)		Total
2018
Crude Oil and Condensate	$	9,390,244	$	17,059	$	110,137	$	9,517,440
Natural Gas Liquids	1,127,510		—		—		1,127,510
Natural Gas	970,866		285,053		45,618		1,301,537
Loses on Mark-to-Market Commodity Derivative Contracts	(165,640)		—		—		(165,640)
Gathering, Processing and Marketing	5,227,051		3,304		—		5,230,355
Gains on Asset Dispositions, Net	154,852		4,493		15,217		174,562
Other, Net	89,708		(49)		(24)		89,635
Operating Revenues and Other (5)	16,794,591		309,860		170,948		17,275,399
Depreciation, Depletion and Amortization	3,296,499		91,971		46,938		3,435,408
Operating Income (Loss)	4,334,364		147,240		(12,258)		4,469,346
Interest Income	9,326		1,612		608		11,546
Other Income (Expense)	9,580		2,436		(6,858)		5,158
Net Interest Expense	253,352		—		(8,300)		245,052
Income (Loss) Before Income Taxes	4,099,918		151,288		(10,208)		4,240,998
Income Tax Provision	765,986		54,272		1,700		821,958
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	6,155,874		1,618		37,838		6,195,330
Total Property, Plant and Equipment, Net	27,786,086		210,183		79,250		28,075,519
Total Assets	33,178,733		629,633		126,108		33,934,474

(1)Other International primarily consists of EOG's United Kingdom, China and Canada operations. EOG began an exploration program in Oman in the third quarter of 2020. The United Kingdom operations were sold in the fourth quarter of 2018.

(2)EOG had sales activity with three significant purchasers in 2020, each totaling $1.1 billion of consolidated Operating Revenues and Other in the United States segment.

(3)EOG recorded pretax impairment charges of $1,570 million in 2020 for proved oil and gas properties, leasehold costs and other assets due to the decline in commodity prices and revisions of asset retirement obligations for certain properties in the United States segment. In addition, EOG recorded pretax impairment charges of $228 million in 2020 for owned and leased sand and crude-by-rail assets, also in the United States segment. EOG recorded pretax impairment charges of $81 million in 2020 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 Notes 13 and 14.

(4)EOG had sales activity with two significant purchasers in 2019, one totaling $2.4 billion and the other totaling $2.2 billion of consolidated Operating Revenues and Other in the United States segment.

(5)EOG had sales activity with two significant purchasers in 2018, one totaling $2.6 billion and the other totaling $2.3 billion of consolidated Operating Revenues and Other in the United States segment.

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Risk Management Activities (Notes)

12 Months Ended

Dec. 31, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Risk Management Activities

Risk Management Activities

Commodity Price Risks.  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 2020, 2019 and 2018, 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 Commodity Derivative Contracts on the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss).  The related cash flow impact is reflected in Cash Flows from Operating Activities.  During 2020, 2019 and 2018, EOG recognized net gains (losses) on the mark-to-market of financial commodity derivative contracts of $1,145 million, $180 million and $(166) million, respectively, which included cash received from (payments for) settlements of crude oil, NGLs and natural gas derivative contracts of $1,071 million, $231 million and $(259) million, respectively.

Crude Oil Derivative Contracts. Prices received by EOG for its crude oil production generally vary from U.S. New York Mercantile Exchange (NYMEX) West Texas Intermediate (WTI) prices due to adjustments for delivery location (basis) and other factors. EOG has entered into crude oil basis swap contracts in order to fix the differential between Intercontinental Exchange (ICE) Brent pricing and pricing in Cushing, Oklahoma (ICE Brent Differential). Presented below is a comprehensive summary of EOG's ICE Brent Differential basis swap contracts as of December 31, 2020. The weighted average price differential expressed in dollars per barrel ($/Bbl) represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in barrels per day (Bbld) covered by the basis swap contracts.

ICE Brent Differential Basis Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)
2020
May 2020 (closed)	10,000	$	4.92

EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in Houston, Texas, and Cushing, Oklahoma (Houston Differential). Presented below is a comprehensive summary of EOG's Houston Differential basis swap contracts as of December 31, 2020. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.

Houston Differential Basis Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)
2020
May 2020 (closed)	10,000	$	1.55

EOG has also entered into crude oil swaps in order to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month (Roll Differential). Presented below is a comprehensive summary of EOG's Roll Differential basis swap contracts as of December 31, 2020. The weighted average price differential expressed in $/Bbl represents the amount of net addition (reduction) to delivery month prices for the notional volumes expressed in Bbld covered by the swap contracts.

Roll Differential Basis Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)
2020
February 1, 2020 through June 30, 2020 (closed)	10,000	$	0.70
July 1, 2020 through September 30, 2020 (closed)	88,000	(1.16)
October 1, 2020 through December 31, 2020 (closed)	66,000	(1.16)
2021
February 1, 2021 through December 31, 2021	25,000	$	0.10
2022
January 1, 2022 through December 31, 2022	50,000	$	0.11

In May 2020, EOG entered into crude oil Roll Differential basis swap contracts for the period from July 1, 2020 through September 30, 2020, with notional volumes of 22,000 Bbld at a weighted average price differential of $(0.43) per Bbl, and for the period from October 1, 2020 through December 31, 2020, with notional volumes of 44,000 Bbld at a weighted average price differential of $(0.73) per Bbl. These contracts partially offset certain outstanding Roll Differential basis swap contracts for the same time periods and volumes at a weighted average price differential of $(1.16) per Bbl. EOG paid net cash of $3.2 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.

Presented below is a comprehensive summary of EOG's crude oil NYMEX WTI price swap contracts as of December 31, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

Crude Oil NYMEX WTI Price Swap Contracts
	Volume (Bbld)	Weighted Average Price ($/Bbl)
2020
January 1, 2020 through March 31, 2020 (closed)	200,000	$	59.33
April 1, 2020 through May 31, 2020 (closed)	265,000	51.36

In April and May 2020, EOG entered into crude oil NYMEX WTI price swap contracts for the period from June 1, 2020 through June 30, 2020, with notional volumes of 265,000 Bbld at a weighted average price of $33.80 per Bbl, for the period from July 1, 2020 through July 31, 2020, with notional volumes of 254,000 Bbld at a weighted average price of $33.75 per Bbl, for the period from August 1, 2020 through September 30, 2020, with notional volumes of 154,000 Bbld at a weighted average price of $34.18 per Bbl and for the period from October 1, 2020 through December 31, 2020, with notional volumes of 47,000 Bbld at a weighted average price of $30.04 per Bbl. These contracts offset the remaining crude oil NYMEX WTI price swap contracts for the same time periods and volumes at a weighted average price of $51.36 per Bbl for the period from June 1, 2020 through June 30, 2020, $42.36 per Bbl for the period from July 1, 2020 through July 31, 2020, $50.42 per Bbl for the period from August 1, 2020 through September 30, 2020 and $31.00 per Bbl for the period from October 1, 2020 through December 31, 2020. EOG received net cash of $362.6 million through December 31, 2020, for the settlement of certain of these contracts, and expects to receive net cash of $1.4 million during January 2021 for the settlement of the remaining contracts. The offsetting contracts were excluded from the above table.

Presented below is a comprehensive summary of EOG's crude oil ICE Brent price swap contracts as of December 31, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

Crude Oil ICE Brent Price Swap Contracts
	Volume (Bbld)	Weighted Average Price ($/Bbl)
2020
April 2020 (closed)	75,000	$	25.66
May 2020 (closed)	35,000	26.53

NGLs Derivative Contracts. Presented below is a comprehensive summary of EOG's Mont Belvieu propane (non-TET) price swap contracts as of December 31, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

Mont Belvieu Propane Price Swap Contracts
	Volume (Bbld)	Weighted Average Price ($/Bbl)
2020
January 1, 2020 through February 29, 2020 (closed)	4,000	$	21.34
March 1, 2020 through April 30, 2020 (closed)	25,000	17.92

In April and May 2020, EOG entered into Mont Belvieu propane price swap contracts for the period from May 1, 2020 through December 31, 2020, with notional volumes of 25,000 Bbld at a weighted average price of $16.41 per Bbl. These contracts offset the remaining Mont Belvieu propane price swap contracts for the same time period with notional volumes of 25,000 Bbld at a weighted average price of $17.92 per Bbl. EOG received net cash of $8.0 million through December 31, 2020, for the settlement of certain of these contracts, and expects to receive net cash of $1.2 million during January 2021 for the settlement of the remaining contracts. The offsetting contracts were excluded from the above table.

Natural Gas Derivative Contracts. Presented below is a comprehensive summary of EOG's natural gas NYMEX Henry Hub price swap contracts as of December 31, 2020, with notional volumes sold (purchased) expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).

Natural Gas NYMEX Henry Hub Price Swap Contracts
	Volume (MMBtud)	Weighted Average Price ($/MMBtu)
2021
April 1, 2021 through December 31, 2021	500,000	$	2.99
2022
January 1, 2022 through December 31, 2022	20,000	$	2.75

In December 2020, EOG entered into natural gas NYMEX Henry Hub price swap contracts for the period from January 1, 2021 through March 31, 2021, with notional volumes of 500,000 MMBtud at a weighted average price of $2.43 per MMBtu. These contracts offset the remaining natural gas NYMEX Henry Hub price swap contracts for the same time period with notional volumes of 500,000 MMBtud at a weighted average price of $2.99 per MMBtu. EOG expects to receive net cash of $25.2 million during 2021 for the settlement of these contracts. The offsetting contracts were excluded from the above table.

EOG has entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price. In March 2020, EOG executed the early termination provision granting EOG the right to terminate certain 2020 natural gas collar contracts with notional volumes of 250,000 MMBtud at a weighted average ceiling price of $2.50 per MMBtu and a weighted average floor price of $2.00 per MMBtu for the period from April 1, 2020 through July 31, 2020. EOG received net cash of $7.8 million for the settlement of these contracts. Presented below is a comprehensive summary of EOG's natural gas collar contracts as of December 31, 2020, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.

Natural Gas Collar Contracts
		Weighted Average Price ($/MMBtu)
	Volume (MMBtud)	Ceiling Price		Floor Price
2020
April 1, 2020 through July 31, 2020 (closed)	250,000	$	2.50	$	2.00

In April 2020, EOG entered into natural gas collar contracts for the period from August 1, 2020 through October 31, 2020, with notional volumes of 250,000 MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu. These contracts offset the remaining natural gas collar contracts for the same time period with notional volumes of 250,000 MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu. EOG received net cash of $1.1 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.

Prices received by EOG for its natural gas production generally vary from NYMEX Henry Hub prices due to adjustments for delivery location (basis) and other factors. EOG has entered into natural gas basis swap contracts in order to fix the differential between pricing in the Rocky Mountain area and NYMEX Henry Hub prices (Rockies Differential). Presented below is a comprehensive summary of EOG's Rockies Differential basis swap contracts as of December 31, 2020. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts.

Rockies Differential Basis Swap Contracts
	Volume (MMBtud)	Weighted Average Price Differential ($/MMBtu)
2020
January 1, 2020 through December 31, 2020 (closed)	30,000	$	0.55

EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Houston Ship Channel (HSC) and NYMEX Henry Hub prices (HSC Differential). In March 2020, EOG executed the early termination provision granting EOG the right to terminate certain 2020 HSC Differential basis swaps with notional volumes of 60,000 MMBtud at a weighted average price differential of $0.05 per MMBtu for the period from April 1, 2020 through December 31, 2020. EOG paid net cash of $0.4 million for the settlement of these contracts. Presented below is a comprehensive summary of EOG's HSC Differential basis swap contracts as of December 31, 2020. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts.

HSC Differential Basis Swap Contracts
	Volume (MMBtud)	Weighted Average Price Differential ($/MMBtu)
2020
January 1, 2020 through December 31, 2020 (closed)	60,000	$	0.05

EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Waha Hub in West Texas and NYMEX Henry Hub prices (Waha Differential). Presented below is a comprehensive summary of EOG's Waha Differential basis swap contracts as of December 31, 2020. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts.

Waha Differential Basis Swap Contracts
	Volume (MMBtud)	Weighted Average Price Differential ($/MMBtu)
2020
January 1, 2020 through April 30, 2020 (closed)	50,000	$	1.40

In April 2020, EOG entered into Waha Differential basis swap contracts for the period from May 1, 2020 through December 31, 2020, with notional volumes of 50,000 MMBtud at a weighted average price differential of $0.43 per MMBtu. These contracts offset the remaining Waha Differential basis swap contracts for the same time period with notional volumes of 50,000 MMBtud at a weighted average price differential of $1.40 per MMBtu. EOG paid net cash of $11.9 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.

 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, 2020 and 2019, 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 thousands):

		Fair Value at December 31,
Description	Location on Balance Sheet	2020		2019
Asset Derivatives
Crude oil, NGLs and natural gas derivative contracts -
Current portion	Assets from Price Risk Management Activities (1)	$	64,559	$	1,299
Noncurrent portion	Other Assets	1,063		—
Liability Derivatives
Crude oil, NGLs and natural gas derivative contracts -
Current portion	Liabilities from Price Risk Management Activities (2)	$	—	$	20,194
Noncurrent Portion	Other Liabilities	455		—

(1)    The current portion of Assets from Price Risk Management Activities consists of gross assets of $3 million, partially offset by gross liabilities of $2 million, at December 31, 2019.

(2)    The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $23 million, partially offset by gross assets of $3 million at December 31, 2019.

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, 2020, EOG's net accounts receivable balance related to United States hydrocarbon sales included two receivable balances, each of which accounted for more than 10% of the total balance.  The receivables were due from two petroleum refinery companies.  The related amounts were collected during early 2021.  At December 31, 2019, 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 2020.

In 2020 and 2019, all natural gas from EOG's Trinidad operations was sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary. In 2020 and 2019, all crude oil and condensate from EOG's Trinidad operations was sold to Heritage Petroleum Company Limited. In 2020 and 2019, all natural gas from EOG's China operations was sold to Petrochina Company Limited.

All of EOG's derivative instruments are covered by International Swap Dealers Association Master Agreements (ISDAs) with counterparties.  The ISDAs may contain provisions that require EOG, if it is the party in a net liability position, to post collateral when the amount of the net liability exceeds the threshold level specified for EOG'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 derivatives under the ISDA to be settled immediately.  See Note 13 for the aggregate fair value of all derivative instruments that were in a net asset position at December 31, 2020 and a net liability position at December 31, 2019.  EOG had no collateral posted and held no collateral at December 31, 2020 and 2019.

Substantially all of EOG's accounts receivable at December 31, 2020 and 2019 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, 2020, credit losses incurred on receivables by EOG have been immaterial.

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Fair Value Measurements (Notes)

12 Months Ended

Dec. 31, 2020

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value MeasurementsCertain 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, 2020 and 2019. Amounts shown in thousands.

	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, 2020
Financial Assets (1):
Natural Gas Swaps	$	—	$	66,064	$	—	$	66,064
Financial Liabilities (2):
Crude Oil Roll Differential Swaps	—		897		—		897
At December 31, 2019
Financial Assets (1):
Natural Gas Liquids Swaps	$	—	$	3,401	$	—	$	3,401
Natural Gas Basis Swaps	—		970		—		970
Financial Liabilities (2):
Crude Oil Swaps	—		23,266		—		23,266

(1)    $65 million and $1 million are included in "Current Assets - Assets from Price Risk Management Activities" at December 31, 2020 and 2019, respectively, on the Consolidated Balance Sheets. $1 million is included in "Other Assets" at December 31, 2020, on the Consolidated Balance Sheets.

(2)    $1 million is included in "Other Liabilities" at December 31, 2020, on the Consolidated Balance Sheets. $20 million is included in "Current Liabilities - Liabilities from Price Risk Management Activities" at December 31, 2019 on the Consolidated Balance Sheets.

The estimated fair value of crude oil, NGLs and natural gas derivative contracts (including options/collars) was based upon forward commodity price curves based on quoted market prices.  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 asset. 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 2020, due to the decline in commodity prices and revisions of asset retirement obligations for certain properties, proved oil and gas properties with a carrying amount of $1,587 million were written down to their fair value of $319 million, resulting in pretax impairment charges of $1,268 million. In addition, EOG recorded pretax impairment charges in 2020 of $72 million for a commodity price-related write-down of other assets.

During 2019, proved oil and gas properties; other property, plant and equipment; and other assets with a carrying amount of $998 million were written down to their fair value of $701 million, resulting in pretax impairment charges of $297 million. Included in the $297 million pretax impairment charges are $152 million of impairments of proved oil and gas properties for which EOG utilized an accepted offer from a third-party purchaser as the basis for determining fair value. In addition, EOG recorded pretax impairment charges in 2019 of $90 million for a commodity price-related write-down of other assets.

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, 2020 and 2019, respectively, EOG had outstanding $5,640 million and $5,140 million aggregate principal amount of senior notes, which had estimated fair values of approximately $6,505 million and $5,452 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.

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Impairment Expense (Notes)

12 Months Ended

Dec. 31, 2020

Impairment Expense [Abstract]

Impairment Expense

Impairment Expense

Impairment expense was as follows for the years ended December 31, 2020, 2019 and 2018 (in thousands):

	2020		2019		2018
Proved properties (1)	$	1,268,073	$	206,469	$	120,859
Unproved properties (2)	472,143		220,444		173,383
Other assets (3)	299,851		90,983		48,732
Inventories	—		—		4,047
Firm commitment contracts (4)	59,713		—		—
Total	$	2,099,780	$	517,896	$	347,021

(1)    Impairments to proved oil and gas properties in 2020 included legacy and non-core natural gas and crude oil and combo plays. Impairments to proved oil and gas properties in 2019 and 2018 included domestic legacy natural gas assets. See Notes 1 and 13.

(2)    Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. Impairments of unproved oil and gas properties included charges of $252 million in 2020 for certain leasehold costs that are no longer expected to be developed before expiration. See Note 1.

(3)    Includes impairment charges for owned and leased sand and crude-by-rail assets of $228 million in 2020 (see Note 18) and a commodity price-related write-down of other assets of $72 million, $90 million and $49 million in 2020, 2019 and 2018, respectively (see Note 13).

(4)    Includes impairment charges of $60 million in 2020 for firm commitment contracts related to its decision to exit the Horn River Basin in British Columbia, Canada.

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Asset Retirement Obligations (Notes)

12 Months Ended

Dec. 31, 2020

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, 2020 and 2019 (in thousands):

	2020		2019
Carrying Amount at Beginning of Period	$	1,110,710	$	954,377
Liabilities Incurred	57,477		98,874
Liabilities Settled (1)	(54,027)		(58,673)
Accretion	47,083		43,462
Revisions	53,888		72,425
Foreign Currency Translations	1,407		245
Carrying Amount at End of Period	$	1,216,538	$	1,110,710
Current Portion	$	49,548	$	37,127
Noncurrent Portion	$	1,166,990	$	1,073,583

(1)    Includes settlements related to asset sales.

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 (Notes)

12 Months Ended

Dec. 31, 2020

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, 2020, 2019 and 2018 are presented below (in thousands):

	2020		2019		2018
Balance at January 1	$	25,897	$	4,121	$	2,167
Additions Pending the Determination of Proved Reserves	107,852		83,175		10,304
Reclassifications to Proved Properties	(81,071)		(39,325)		(7,917)
Costs Charged to Expense (1)	(23,822)		(22,074)		(433)
Balance at December 31	$	28,856	$	25,897	$	4,121

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

	2020		2019		2018
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	26,408	$	25,897	$	4,121
Capitalized exploratory well costs that have been capitalized for a period greater than one year (1)	2,448		—		—
Balance at December 31	$	28,856	$	25,897	$	4,121
Number of exploratory wells that have been capitalized for a period greater than one year	1		—		—

(1)    Consists of costs related to a project in the United States at December 31, 2020.

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Acquisitions and Divestitures (Notes)

12 Months Ended

Dec. 31, 2020

Business Combinations [Abstract]

Acquisitions and Divestitures

Acquisitions and Divestitures

During 2020, EOG paid cash for property acquisitions of $82 million in the United States and $38 million in Other International, primarily in Oman. Additionally during 2020, EOG recognized net losses on asset dispositions of $47 million primarily due to sales of proved properties and non-cash property exchanges of unproved leasehold in Texas and New Mexico and the disposition of the Marcellus Shale assets, and received proceeds of approximately $192 million.

During 2019, EOG paid cash for property acquisitions of $328 million in the United States. Additionally during 2019, EOG recognized net gains on asset dispositions of $124 million primarily due to sales of producing properties, acreage and other assets, as well as non-cash property exchanges in New Mexico, and received proceeds of approximately $140 million.

During 2018, EOG recognized net gains on asset dispositions of $175 million primarily due to non-cash property exchanges in Texas, New Mexico and Wyoming. Additionally, EOG received proceeds in 2018 of approximately $227 million, primarily due to the sale of its United Kingdom operations in the fourth quarter of 2018.

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Leases (Notes)

12 Months Ended

Dec. 31, 2020

Leases [Abstract]

Lessee Operating and Finance Leases [Text Block]

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, 2020 and 2019 were as follows (in millions):

	2020		2019
Operating Lease Cost (1)	$	393	$	497
Finance Lease Cost:
Amortization of Lease Assets	21		13
Interest on Lease Liabilities	4		2
Variable Lease Cost	91		138
Short-Term Lease Cost	194		333
Total Lease Cost	$	703	$	983

(1)    Operating lease cost includes impairment expenses of $35 million in 2020.

The following table sets forth the amounts and classification of EOG's outstanding ROU assets and related lease liabilities at December 31, 2020 and 2019 and supplemental information for the years ended December 31, 2020 and 2019 (in millions, except lease terms and discount rates):

Description	Location on Balance Sheet	2020		2019
Assets
Operating Leases	Other Assets	$	869	$	773
Finance Leases	Property, Plant and Equipment, Net (1)	206		53
Total		$	1,075	$	826
Liabilities
Current
Operating Leases	Current Portion of Operating Lease Liabilities	$	295	$	369
Finance Leases	Current Portion of Long-Term Debt	31		15
Long-Term
Operating Leases	Other Liabilities	641		430
Finance Leases	Long-Term Debt	181		43
Total		$	1,148	$	857

(1)    Finance lease assets are recorded net of accumulated amortization of $81 million and $60 million at December 31, 2020 and 2019, respectively.

	2020		2019
Weighted Average Remaining Lease Term (in years):
Operating Leases	5.3		3.2
Finance Leases	7.6		4.7
Weighted Average Discount Rate:
Operating Leases	3.4	%	3.5	%
Finance Leases	2.8	%	3.0	%

Cash paid for leases for the years ended December 31, 2020 and 2019 was as follows (in millions):

	2020		2019
Repayment of Operating Lease Liabilities Associated with Operating Activities	$	223	$	225
Repayment of Operating Lease Liabilities Associated with Investing Activities	130		270
Repayment of Finance Lease Liabilities	19		13

Non-cash leasing activities for the year ended December 31, 2020, included the additions of $893 million of operating leases and $174 million of finance leases. Non-cash leasing activities for the year ended December 31, 2019, included the addition of $784 million of operating leases. Upon adoption of ASU 2016-02 effective January 1, 2019, EOG recognized operating lease ROU of $566 million.

At December 31, 2020, the future minimum lease payments under non-cancellable leases were as follows (in millions):

	Operating Leases		Finance Leases
2021	$	323	$	36
2022	210		32
2023	134		28
2024	96		29
2025	70		27
2026 and Beyond	206		87
Total Lease Payments	1,039		239
Less: Discount to Present Value	103		27
Total Lease Liabilities	936		212
Less: Current Portion of Lease Liabilities	295		31
Long-Term Lease Liabilities	$	641	$	181

At December 31, 2020, EOG had additional leases of $100 million, which are expected to commence in 2021 with lease terms of two to nine years.

Prior to the adoption of ASU 2016-02 and other related ASUs, the future minimum commitments under non-cancellable leases, including non-lease components and excluding contracts with lease terms of less than 12 months as December 31, 2018, were as follows (in millions):

	Operating Leases		Finance Leases
2019	$	380	$	15
2020	213		15
2021	86		15
2022	39		12
2023	30		8
2024 and Beyond	62		14
Total Lease Payments	$	810	$	79

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Oil and Gas Exploration and Production Industries Disclosures (Notes)

12 Months Ended

Dec. 31, 2020

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Oil and Gas Exploration and Production Industries Disclosures

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, NGL 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.  For related discussion, see ITEM 1A, Risk Factors.

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 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, 2020.  Under these plans, each PUD location will be drilled within five years from the date it was 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.

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, 2020, 2019 and 2018 were based on studies performed by the engineering staff of EOG.  The Engineering and Acquisitions Department is directly responsible for EOG's reserve evaluation process and consists of 17 professionals, 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 34 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, NGL and natural gas prices, production costs, transportation 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 Chief Operating Officer; the President; the Executive Vice President, Exploration and Production; and the Executive Vice President and Chief Financial Officer, for approval.

Opinions by D&M for the years ended December 31, 2020, 2019 and 2018 covered producing areas containing 83%, 82% and 79%, 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, 2021, 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, 2020, 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, 2020, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2020, as estimated by the Engineering and Acquisitions Department of EOG:

NET PROVED RESERVE SUMMARY

	United States	Trinidad	Other International (1)	Total
NET PROVED RESERVES
Crude Oil (MBbl) (2)
Net proved reserves at December 31, 2017	1,304,071	898	8,004	1,312,973
Revisions of previous estimates	(13,237)	(183)	44	(13,376)
Purchases in place	2,743	—	—	2,743
Extensions, discoveries and other additions	383,003	—	15	383,018
Sales in place	(768)	—	(6,310)	(7,078)
Production	(144,128)	(298)	(1,542)	(145,968)
Net proved reserves at December 31, 2018	1,531,684	417	211	1,532,312
Revisions of previous estimates	(42,959)	85	(8)	(42,882)
Purchases in place	2,859	—	—	2,859
Extensions, discoveries and other additions	369,968	—	28	369,996
Sales in place	(1,282)	—	—	(1,282)
Production	(166,310)	(236)	(40)	(166,586)
Net proved reserves at December 31, 2019	1,693,960	266	191	1,694,417
Revisions of previous estimates	(225,375)	(19)	(18)	(225,412)
Purchases in place	2,176	—	—	2,176
Extensions, discoveries and other additions	194,724	863	—	195,587
Sales in place	(3,183)	—	—	(3,183)
Production	(149,402)	(355)	(30)	(149,787)
Net proved reserves at December 31, 2020	1,512,900	755	143	1,513,798
Natural Gas Liquids (MBbl) (2)
Net proved reserves at December 31, 2017	503,473	—	—	503,473
Revisions of previous estimates	23,942	—	—	23,942
Purchases in place	2,006	—	—	2,006
Extensions, discoveries and other additions	127,409	—	—	127,409
Sales in place	(41)	—	—	(41)
Production	(42,460)	—	—	(42,460)
Net proved reserves at December 31, 2018	614,329	—	—	614,329
Revisions of previous estimates	5,380	—	—	5,380
Purchases in place	1,948	—	—	1,948
Extensions, discoveries and other additions	167,782	—	—	167,782
Sales in place	(855)	—	—	(855)
Production	(48,892)	—	—	(48,892)
Net proved reserves at December 31, 2019	739,692	—	—	739,692
Revisions of previous estimates	(59,790)	—	—	(59,790)
Purchases in place	3,831	—	—	3,831
Extensions, discoveries and other additions	180,205	—	—	180,205
Sales in place	(1,399)	—	—	(1,399)
Production	(49,796)	—	—	(49,796)
Net proved reserves at December 31, 2020	812,743	—	—	812,743

	United States	Trinidad	Other International (1)	Total
Natural Gas (Bcf) (3)
Net proved reserves at December 31, 2017	3,898.5	313.4	51.2	4,263.1
Revisions of previous estimates	(127.2)	20.7	15.0	(91.5)
Purchases in place	41.3	—	—	41.3
Extensions, discoveries and other additions	951.4	—	4.6	956.0
Sales in place	(22.2)	—	—	(22.2)
Production	(351.2)	(97.1)	(11.2)	(459.5)
Net proved reserves at December 31, 2018	4,390.6	237.0	59.6	4,687.2
Revisions of previous estimates	(184.4)	47.0	2.6	(134.8)
Purchases in place	71.7	—	—	71.7
Extensions, discoveries and other additions	1,175.9	87.5	9.7	1,273.1
Sales in place	(14.5)	—	—	(14.5)
Production	(404.5)	(95.4)	(13.1)	(513.0)
Net proved reserves at December 31, 2019	5,034.8	276.1	58.8	5,369.7
Revisions of previous estimates	(497.7)	4.8	1.6	(491.3)
Purchases in place	26.3	—	—	26.3
Extensions, discoveries and other additions	1,077.9	53.9	—	1,131.8
Sales in place	(157.3)	—	—	(157.3)
Production	(441.4)	(65.9)	(11.6)	(518.9)
Net proved reserves at December 31, 2020	5,042.6	268.9	48.8	5,360.3
Oil Equivalents (MBoe) (2)
Net proved reserves at December 31, 2017	2,457,302	53,142	16,526	2,526,970
Revisions of previous estimates	(10,500)	3,272	2,544	(4,684)
Purchases in place	11,640	—	—	11,640
Extensions, discoveries and other additions	668,972	—	778	669,750
Sales in place	(4,509)	—	(6,310)	(10,819)
Production	(245,127)	(16,478)	(3,406)	(265,011)
Net proved reserves at December 31, 2018	2,877,778	39,936	10,132	2,927,846
Revisions of previous estimates	(68,317)	7,915	431	(59,971)
Purchases in place	16,761	—	—	16,761
Extensions, discoveries and other additions	733,730	14,577	1,661	749,968
Sales in place	(4,555)	—	—	(4,555)
Production	(282,619)	(16,130)	(2,232)	(300,981)
Net proved reserves at December 31, 2019	3,272,778	46,298	9,992	3,329,068
Revisions of previous estimates	(368,127)	773	259	(367,095)
Purchases in place	10,398	—	—	10,398
Extensions, discoveries and other additions	554,585	9,840	—	564,425
Sales in place	(30,802)	—	—	(30,802)
Production	(272,757)	(11,347)	(1,969)	(286,073)
Net proved reserves at December 31, 2020	3,166,075	45,564	8,282	3,219,921

(1)Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.

(2)Thousand barrels or thousand 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.

During 2020, EOG added 564 million barrels of oil equivalent (MMBoe) of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin.  Approximately 67% of the 2020 reserve additions were crude oil and condensate and NGLs, and substantially all were in the United States.  Sales in place of 31 MMBoe were primarily related to the sale of the Marcellus Shale assets and the sale or exchange of other producing assets. Revisions of previous estimates of negative 367 MMBoe for 2020 included a downward revision of 278 MMBoe primarily due to decreases in the average crude oil, NGLs and natural gas prices used in the December 31, 2020, reserves estimation as compared to the prices used in the prior year estimate. The primary areas affected were the Eagle Ford and the Rocky Mountain area. Purchases in place of 10 MMBoe were primarily related to the Permian Basin and the purchase or exchange of other producing assets.

During 2019, EOG added 750 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin, the Eagle Ford and the Rocky Mountain area.  Approximately 72% of the 2019 reserve additions were crude oil and condensate and NGLs, and substantially all were in the United States.  Sales in place of 5 MMBoe were primarily related to the sale of certain South Texas area operations and the sale or exchange of other producing assets. Revisions of previous estimates of negative 60 MMBoe for 2019 included a decrease in the average crude oil, NGLs and natural gas prices used in the December 31, 2019, reserves estimation as compared to the prices used in the prior year estimate. The primary area affected was the Rocky Mountain area. Purchases in place of 17 MMBoe were primarily related to the South Texas area.

During 2018, EOG added 670 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin, the Eagle Ford, the Rocky Mountain area and the Mid-Continent area.  Approximately 76% of the 2018 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 United Kingdom operations and the sale or exchange of other producing assets. Revisions of previous estimates of negative 5 MMBoe for 2018 included an upward revision of 35 MMBoe primarily due to increases in the average crude oil, NGLs and natural gas prices used in the December 31, 2018, reserves estimation as compared to the prices used in the prior year estimate. The primary areas affected were in the Rocky Mountain area, the Eagle Ford and the Permian Basin. Downward revisions other than price of 40 MMBoe resulted primarily from changes in production forecasts and higher production costs. Purchases in place of 12 MMBoe were primarily related to the South Texas area.

	United States	Trinidad	Other International (1)	Total
NET PROVED DEVELOPED RESERVES
Crude Oil (MBbl)
December 31, 2017	605,405	898	7,933	614,236
December 31, 2018	712,218	417	150	712,785
December 31, 2019	801,189	266	143	801,598
December 31, 2020	791,744	755	93	792,592
Natural Gas Liquids (MBbl)
December 31, 2017	286,872	—	—	286,872
December 31, 2018	341,386	—	—	341,386
December 31, 2019	387,253	—	—	387,253
December 31, 2020	391,708	—	—	391,708
Natural Gas (Bcf)
December 31, 2017	2,450.8	299.2	29.3	2,779.3
December 31, 2018	2,699.0	223.9	40.9	2,963.8
December 31, 2019	2,974.6	177.7	41.8	3,194.1
December 31, 2020	2,586.1	171.1	31.6	2,788.8
Oil Equivalents (MBoe)
December 31, 2017	1,300,758	50,779	12,798	1,364,335
December 31, 2018	1,503,441	37,746	6,950	1,548,137
December 31, 2019	1,684,209	29,886	7,117	1,721,212
December 31, 2020	1,614,462	29,268	5,368	1,649,098
NET PROVED UNDEVELOPED RESERVES
Crude Oil (MBbl)
December 31, 2017	698,666	—	71	698,737
December 31, 2018	819,466	—	61	819,527
December 31, 2019	892,771	—	48	892,819
December 31, 2020	721,156	—	50	721,206
Natural Gas Liquids (MBbl)
December 31, 2017	216,601	—	—	216,601
December 31, 2018	272,943	—	—	272,943
December 31, 2019	352,439	—	—	352,439
December 31, 2020	421,035	—	—	421,035
Natural Gas (Bcf)
December 31, 2017	1,447.7	14.2	21.9	1,483.8
December 31, 2018	1,691.6	13.1	18.7	1,723.4
December 31, 2019	2,060.2	98.4	17.0	2,175.6
December 31, 2020	2,456.5	97.8	17.2	2,571.5
Oil Equivalents (MBoe)
December 31, 2017	1,156,544	2,363	3,728	1,162,635
December 31, 2018	1,374,337	2,190	3,182	1,379,709
December 31, 2019	1,588,569	16,412	2,875	1,607,856
December 31, 2020	1,551,613	16,296	2,914	1,570,823

(1)Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.

Net Proved Undeveloped Reserves. The following table presents the changes in EOG's total PUDs during 2020, 2019 and 2018 (in MBoe):

	2020	2019	2018
Balance at January 1	1,607,856	1,379,709	1,162,635
Extensions and Discoveries	456,073	578,317	490,725
Revisions	(277,325)	(49,837)	(8,244)
Acquisition of Reserves	47	1,711	311
Sale of Reserves	(3,670)	—	—
Conversion to Proved Developed Reserves	(212,158)	(302,044)	(265,718)
Balance at December 31	1,570,823	1,607,856	1,379,709

For the twelve-month period ended December 31, 2020, total PUDs decreased by 37 MMBoe to 1,571 MMBoe.  EOG added approximately 7 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-43 and F-44 of this Annual Report on Form 10-K), EOG added 449 MMBoe of PUDs.  The PUD additions were primarily in the Permian Basin and 67% of the additions were crude oil and condensate and NGLs.  During 2020, EOG drilled and transferred 212 MMBoe of PUDs to proved developed reserves at a total capital cost of $1,674 million. Revisions of previous estimates of negative 277 MMBoe of PUDs for 2020 included a downward price revision of 77 MMBoe due to decreases in the average crude oil, NGLs and natural gas prices used in the December 31, 2020, reserves estimation as compared to the prices used in the prior year estimate.  Revisions other than price of negative 200 MMBoe were primarily related to the removal of PUD locations due to lower projected capital spending over the next five years as compared to the prior year projections. The primary areas affected were the Eagle Ford and the Rocky Mountain area. 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, 2019, total PUDs increased by 228 MMBoe to 1,608 MMBoe.  EOG added approximately 38 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 540 MMBoe.  The PUD additions were primarily in the Permian Basin, the Eagle Ford and, to a lesser extent, the Rocky Mountain area, and 73% of the additions were crude oil and condensate and NGLs.  During 2019, EOG drilled and transferred 302 MMBoe of PUDs to proved developed reserves at a total capital cost of $3,032 million. 

For the twelve-month period ended December 31, 2018, total PUDs increased by 217 MMBoe to 1,380 MMBoe.  EOG added approximately 31 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 460 MMBoe.  The PUD additions were primarily in the Permian Basin, Anadarko Basin, the Eagle Ford and, to a lesser extent, the Rocky Mountain area, and 80% of the additions were crude oil and condensate and NGLs.  During 2018, EOG drilled and transferred 266 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,745 million. 

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, 2020 and 2019:

	2020		2019
Proved properties	$	61,724,487	$	59,229,686
Unproved properties	3,068,311		3,600,729
Total	64,792,798		62,830,415
Accumulated depreciation, depletion and amortization	(38,750,852)		(35,033,085)
Net capitalized costs	$	26,041,946	$	27,797,330

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

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

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

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

The following table sets forth costs incurred related to EOG's oil and gas activities for the years ended December 31, 2020, 2019 and 2018:

	United States		Trinidad		Other International (1)		Total
2020
Acquisition Costs of Properties
Unproved (2)	$	264,778	$	—	$	—	$	264,778
Proved (3)	97,073		—		38,089		135,162
Subtotal	361,851		—		38,089		399,940
Exploration Costs	203,403		81,216		11,409		296,028
Development Costs (4)	2,998,155		4,036		20,072		3,022,263
Total	$	3,563,409	$	85,252	$	69,570	$	3,718,231
2019
Acquisition Costs of Properties
Unproved (5)	$	276,092	$	—	$	—	$	276,092
Proved (6)	379,938		—		—		379,938
Subtotal	656,030		—		—		656,030
Exploration Costs	213,505		46,616		13,218		273,339
Development Costs (7)	5,661,753		25,007		12,096		5,698,856
Total	$	6,531,288	$	71,623	$	25,314	$	6,628,225
2018
Acquisition Costs of Properties
Unproved (8)	$	486,081	$	1,258	$	—	$	487,339
Proved (9)	123,684		—		—		123,684
Subtotal	609,765		1,258		—		611,023
Exploration Costs	157,222		22,511		13,895		193,628
Development Costs (10)	5,605,264		(12,863)		22,628		5,615,029
Total	$	6,372,251	$	10,906	$	36,523	$	6,419,680

(1)Other International primarily consists of EOG's United Kingdom, China and Canada operations. EOG began an exploration program in Oman in the third quarter of 2020. The United Kingdom operations were sold in the fourth quarter of 2018.

(2)Includes non-cash unproved leasehold acquisition costs of $197 million related to property exchanges.

(3)Includes non-cash proved property acquisition costs of $15 million related to property exchanges.

(4)Includes Asset Retirement Costs of $97 million and $20 million for the United States and Other International, respectively. Excludes other property, plant and equipment.

(5)Includes non-cash unproved leasehold acquisition costs of $98 million related to property exchanges.

(6)Includes non-cash proved property acquisition costs of $52 million related to property exchanges.

(7)Includes Asset Retirement Costs of $181 million, $1 million and $4 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 $291 million related to property exchanges.

(9)Includes non-cash proved property acquisition costs of $71 million related to property exchanges.

(10)Includes Asset Retirement Costs of $90 million, $(12) million and $(8) million for the United States, Trinidad and Other International, respectively.  Excludes other property, plant and equipment.

Results of Operations for Oil and Gas Producing Activities (1). The following table sets forth results of operations for oil and gas producing activities for the years ended December 31, 2020, 2019 and 2018:

	United States		Trinidad		Other International (2)		Total
2020
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	7,055,098	$	179,690	$	55,468	$	7,290,256
Other	60,989		(35)		—		60,954
Total	7,116,087		179,655		55,468		7,351,210
Exploration Costs	136,266		1,909		7,613		145,788
Dry Hole Costs	13,055		—		28		13,083
Transportation Costs	734,071		747		171		734,989
Gathering and Processing Costs	459,211		—		—		459,211
Production Costs	1,479,976		26,964		10,407		1,517,347
Impairments	2,018,283		815		80,682		2,099,780
Depreciation, Depletion and Amortization	3,192,000		60,328		15,747		3,268,075
Income (Loss) Before Income Taxes	(916,775)		88,892		(59,180)		(887,063)
Income Tax Provision	(220,437)		23,526		3,428		(193,483)
Results of Operations	$	(696,338)	$	65,366	$	(62,608)	$	(693,580)
2019
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	11,250,853	$	269,957	$	60,635	$	11,581,445
Other	134,325		18		15		134,358
Total	11,385,178		269,975		60,650		11,715,803
Exploration Costs	130,302		4,290		5,289		139,881
Dry Hole Costs	11,133		13,033		3,835		28,001
Transportation Costs	753,558		4,014		728		758,300
Gathering and Processing Costs	479,102		—		—		479,102
Production Costs	2,063,078		30,539		40,369		2,133,986
Impairments	510,948		5,713		1,235		517,896
Depreciation, Depletion and Amortization	3,560,609		79,156		17,832		3,657,597
Income (Loss) Before Income Taxes	3,876,448		133,230		(8,638)		4,001,040
Income Tax Provision	884,450		54,980		3,152		942,582
Results of Operations	$	2,991,998	$	78,250	$	(11,790)	$	3,058,458
2018
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	11,488,620	$	302,112	$	155,755	$	11,946,487
Other	89,708		(49)		(24)		89,635
Total	11,578,328		302,063		155,731		12,036,122
Exploration Costs	121,572		21,402		6,025		148,999
Dry Hole Costs	4,983		—		422		5,405
Transportation Costs	742,792		3,236		848		746,876
Gathering and Processing Costs (3)	404,471		—		32,502		436,973
Production Costs	1,924,504		33,506		70,073		2,028,083
Impairments	344,595		—		2,426		347,021
Depreciation, Depletion and Amortization	3,181,801		91,788		46,687		3,320,276
Income (Loss) Before Income Taxes	4,853,610		152,131		(3,252)		5,002,489
Income Tax Provision	1,086,077		12,170		1,898		1,100,145
Results of Operations	$	3,767,533	$	139,961	$	(5,150)	$	3,902,344

(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, 2020.

(2)Other International primarily consists of EOG's United Kingdom, China and Canada operations. EOG began an exploration program in Oman in the third quarter of 2020. The United Kingdom operations were sold in the fourth quarter of 2018.

(3)Effective January 1, 2018, EOG adopted the provisions of Accounting Standards Update (ASU) 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements within its United States segment as Gathering and Processing Costs instead of as a deduction to Natural Gas Revenues. There was no impact to operating income or net income resulting from changes to the presentation of natural gas processing fees (see Note 1 to Consolidated Financial Statements).

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, 2020, 2019 and 2018:

	United States		Trinidad		Other International (1)		Composite
Year Ended December 31, 2020	$	3.75	$	2.33	$	6.78	$	3.72
Year Ended December 31, 2019	$	4.59	$	1.85	$	18.26	$	4.54
Year Ended December 31, 2018	$	4.84	$	1.67	$	20.19	$	4.84

(1)    Other International primarily consists of EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.

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 2020, 2019 and 2018.  The following information may be useful for certain comparative purposes, but should not be solely relied upon in evaluating EOG or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of EOG.

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

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

The following table sets forth the standardized measure of discounted future net cash flows from projected production of EOG's oil and gas reserves for the years ended December 31, 2020, 2019 and 2018:

	United States		Trinidad		Other International (1)		Total
2020
Future cash inflows (2)	$	73,726,893	$	900,815	$	281,658	$	74,909,366
Future production costs	(34,618,860)		(153,275)		(53,933)		(34,826,068)
Future development costs	(15,159,373)		(226,430)		(18,400)		(15,404,203)
Future income taxes	(4,336,578)		(81,368)		(24,311)		(4,442,257)
Future net cash flows	19,612,082		439,742		185,014		20,236,838
Discount to present value at 10% annual rate	(8,410,282)		(100,350)		(36,194)		(8,546,826)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	11,201,800	$	339,392	$	148,820	$	11,690,012
2019
Future cash inflows (3)	$	120,359,769	$	813,102	$	305,491	$	121,478,362
Future production costs	(42,387,801)		(166,705)		(87,381)		(42,641,887)
Future development costs	(20,355,746)		(212,303)		(18,400)		(20,586,449)
Future income taxes	(11,459,567)		(73,508)		(32,423)		(11,565,498)
Future net cash flows	46,156,655		360,586		167,287		46,684,528
Discount to present value at 10% annual rate	(21,042,593)		(86,009)		(35,161)		(21,163,763)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	25,114,062	$	274,577	$	132,126	$	25,520,765
2018
Future cash inflows (4)	$	133,066,375	$	749,695	$	303,620	$	134,119,690
Future production costs	(42,351,174)		(204,444)		(99,024)		(42,654,642)
Future development costs	(16,577,794)		(78,199)		(11,900)		(16,667,893)
Future income taxes	(14,756,011)		(174,382)		(31,748)		(14,962,141)
Future net cash flows	59,381,396		292,670		160,948		59,835,014
Discount to present value at 10% annual rate	(27,348,744)		(26,832)		(33,483)		(27,409,059)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	32,032,652	$	265,838	$	127,465	$	32,425,955

(1)Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.

(2)Estimated crude oil prices used to calculate 2020 future cash inflows for the United States, Trinidad and Other International were $37.19, $26.75, and $41.87, respectively. Estimated NGL price used to calculate 2020 future cash inflows for the United States was $12.47. Estimated natural gas prices used to calculate 2020 future cash inflows for the United States, Trinidad and Other International were $1.45, $3.28, and $5.65, respectively.

(3)Estimated crude oil prices used to calculate 2019 future cash inflows for the United States, Trinidad and Other International were $57.51, $46.77 and $57.22, respectively. Estimated NGL price used to calculate 2019 future cash inflows for the United States was $16.91. Estimated natural gas prices used to calculate 2019 future cash inflows for the United States, Trinidad and Other International were $2.07, $2.90 and $5.01, respectively.

(4)Estimated crude oil prices used to calculate 2018 future cash inflows for the United States, Trinidad and Other International were $68.54, $55.66 and $61.66, respectively. Estimated NGL price used to calculate 2018 future cash inflows for the United States was $27.83. Estimated natural gas prices used to calculate 2018 future cash inflows for the United States, Trinidad and Other International were $2.50, $3.06 and $4.88, respectively.

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, 2020:

	United States		Trinidad		Other International (1)		Total
December 31, 2017	$	17,756,935	$	332,427	$	238,298	$	18,327,660
Sales and transfers of oil and gas produced, net of production costs	(8,416,853)		(265,370)		(52,399)		(8,734,622)
Net changes in prices and production costs	12,750,466		84,353		21,610		12,856,429
Extensions, discoveries, additions and improved recovery, net of related costs	8,418,666		—		12,287		8,430,953
Development costs incurred	2,732,560		—		12,600		2,745,160
Revisions of estimated development cost	(410,741)		4,030		(3,814)		(410,525)
Revisions of previous quantity estimates	(173,084)		39,608		31,750		(101,726)
Accretion of discount	1,967,592		50,191		24,839		2,042,622
Net change in income taxes	(4,965,373)		3,844		(11,529)		(4,973,058)
Purchases of reserves in place	116,887		—		—		116,887
Sales of reserves in place	(35,874)		—		(82,058)		(117,932)
Changes in timing and other	2,291,471		16,755		(64,119)		2,244,107
December 31, 2018	32,032,652		265,838		127,465		32,425,955
Sales and transfers of oil and gas produced, net of production costs	(7,955,115)		(235,404)		(19,919)		(8,210,438)
Net changes in prices and production costs	(10,973,981)		65,962		27,572		(10,880,447)
Extensions, discoveries, additions and improved recovery, net of related costs	5,608,038		85,233		16,287		5,709,558
Development costs incurred	3,003,510		22,820		5,820		3,032,150
Revisions of estimated development cost	(597,869)		(129,047)		(11,108)		(738,024)
Revisions of previous quantity estimates	(812,781)		116,062		1,198		(695,521)
Accretion of discount	3,891,701		43,148		14,909		3,949,758
Net change in income taxes	1,454,050		93,975		682		1,548,707
Purchases of reserves in place	98,539		—		—		98,539
Sales of reserves in place	(50,651)		—		—		(50,651)
Changes in timing and other	(584,031)		(54,010)		(30,780)		(668,821)
December 31, 2019	25,114,062		274,577		132,126		25,520,765
Sales and transfers of oil and gas produced, net of production costs	(4,381,840)		(151,979)		(45,355)		(4,579,174)
Net changes in prices and production costs	(18,624,768)		131,859		46,916		(18,445,993)
Extensions, discoveries, additions and improved recovery, net of related costs	1,436,988		64,385		—		1,501,373
Development costs incurred	1,674,800		—		—		1,674,800
Revisions of estimated development cost	4,148,768		(11,161)		—		4,137,607
Revisions of previous quantity estimates	(3,307,180)		11,632		(1,764)		(3,297,312)
Accretion of discount	3,054,437		34,624		15,307		3,104,368
Net change in income taxes	3,497,362		(12,185)		3,022		3,488,199
Purchases of reserves in place	49,232		—		—		49,232
Sales of reserves in place	(156,293)		—		—		(156,293)
Changes in timing and other	(1,303,768)		(2,360)		(1,432)		(1,307,560)
December 31, 2020	$	11,201,800	$	339,392	$	148,820	$	11,690,012

(1)    Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.

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Unaudited Quarterly Financial Information (Notes)

12 Months Ended

Dec. 31, 2020

Quarterly Financial Information Disclosure [Abstract]

Unaudited Quarterly Financial Information

Unaudited Quarterly Financial Information

(In Thousands, Except Per Share Data)

Quarter Ended	Mar 31		Jun 30		Sep 30		Dec 31
2020
Operating Revenues and Other	$	4,717,692	$	1,103,374	$	2,245,484	$	2,965,498
Operating Income (Loss)	$	57,585	$	(1,086,549)	$	(2,714)	$	487,662
Income (Loss) Before Income Taxes	$	31,003	$	(1,145,262)	$	(52,555)	$	427,760
Income Tax Provision (Benefit)	21,190		(235,878)		(10,088)		90,294
Net Income (Loss)	$	9,813	$	(909,384)	$	(42,467)	$	337,466
Net Income (Loss) Per Share (1)
Basic	$	0.02	$	(1.57)	$	(0.07)	$	0.58
Diluted	$	0.02	$	(1.57)	$	(0.07)	$	0.58
Average Number of Common Shares
Basic	578,462		578,719		579,055		579,624
Diluted	580,283		578,719		579,055		580,885
2019
Operating Revenues and Other	$	4,058,642	$	4,697,630	$	4,303,455	$	4,320,246
Operating Income	$	876,530	$	1,130,771	$	827,959	$	863,751
Income Before Income Taxes	$	827,236	$	1,089,366	$	797,457	$	831,208
Income Tax Provision	191,810		241,525		182,335		194,687
Net Income	$	635,426	$	847,841	$	615,122	$	636,521
Net Income Per Share (1)
Basic	$	1.10	$	1.47	$	1.06	$	1.10
Diluted	$	1.10	$	1.46	$	1.06	$	1.10
Average Number of Common Shares
Basic	577,207		577,460		577,839		578,219
Diluted	580,222		580,247		581,271		580,849

(1)The sum of quarterly net income (loss) per share may not agree with total year net income (loss) per share as each quarterly computation is based on the weighted average of common shares outstanding.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2020

Accounting Policies [Abstract]

Principles of Consolidation

Principles of Consolidation.  The consolidated financial statements of EOG Resources, Inc. (EOG) include the accounts of all domestic and foreign subsidiaries.  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, commodity derivative contracts, accounts receivable, accounts payable and current and long-term debt.  The carrying values of cash and cash equivalents, commodity derivative contracts, accounts receivable and accounts payable approximate fair value (see Notes 2 and 12).

Effective January 1, 2020, EOG adopted the provisions of Accounting Standards Update (ASU) 2016-13, "Measurement of Credit Losses on Financial Instruments" (ASU 2016-13). ASU 2016-13 changes the impairment model for financial assets and certain other instruments by requiring entities to adopt a forward-looking expected loss model that will result in earlier recognition of credit losses. EOG elected to adopt ASU 2016-13 using the modified retrospective approach with a cumulative effect adjustment to retained earnings as of the effective date. Financial results reported in periods prior to January 1, 2020, are unchanged. EOG assessed its applicable financial assets, which are primarily its accounts receivable from hydrocarbon sales and joint interest billings to third-party companies, including foreign state-owned entities in the oil and gas industry. Based on its assessment and various potential remedies ensuring collection, EOG did not record an impact to retained earnings upon adoption and expects current and future credit losses to be immaterial. EOG continues to monitor the credit risk from third-party companies to determine if expected credit losses may become material.

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 costs, 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 asset.  If the expected undiscounted future cash flows, based on EOG's estimate of (and assumptions regarding) future crude oil, natural gas liquids (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.

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

Revenue Recognition

Revenue Recognition. Effective January 1, 2018, EOG adopted the provisions of ASU 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09). ASU 2014-09 and other related ASUs require entities to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. EOG elected to adopt ASU 2014-09 using the modified retrospective approach, which required EOG to recognize in retained earnings the cumulative effect at the date of adoption for all existing contracts with customers which were not substantially complete as of January 1, 2018. There was no impact to retained earnings upon adoption of ASU 2014-09.

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

In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements within its United States segment as Gathering and Processing Costs, instead of as a deduction to Revenues within its Consolidated Statements of Income (Loss) and Comprehensive Income (Loss). There was no impact to operating income, net income or cash flows resulting from changes to the presentation of natural gas processing fees. The impacts of the adoption of ASU 2014-09 for the year ended December 31, 2018, were as follows (in thousands):

	As Reported		Amounts Without Adoption of ASU 2014-09		Effect of Change
Operating Revenues and Other
Crude Oil and Condensate	$	9,517,440	$	9,517,440	$	—
Natural Gas Liquids	1,127,510		1,121,237		6,273
Natural Gas	1,301,537		1,104,095		197,442
Gathering, Processing and Marketing	5,230,355		5,211,136		19,219
Total Operating Revenues and Other	17,275,399		17,052,465		222,934
Operating Expenses
Gathering and Processing Costs	436,973		233,258		203,715
Marketing Costs	5,203,243		5,184,024		19,219
Total Operating Expenses	12,806,053		12,583,119		222,934
Operating Income	4,469,346		4,469,346		—

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, 2020 and 2019 and upon adoption of ASU 2014-09 effective January 1, 2018, were $1,337 million, $1,619 million and $1,460 million, respectively, and were included in Accounts Receivable, Net on the Consolidated Balance Sheets. Losses incurred on receivables from contracts with customers are infrequent and have been immaterial.

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 processing fees recognized as Gathering and Processing Costs.

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

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

Other Property, Plant and Equipment

Other Property, Plant and Equipment.  Other property, plant and equipment consists of gathering and processing assets, compressors, buildings and leasehold improvements, sand processing assets, 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.

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. The capitalization of interest is excluded on significant acquisitions of unproved oil and gas properties financed through non-interest-bearing instruments, such as the issuance of shares of Common Stock, or through non-cash property exchanges.

Accounting for Risk Management Activities

Accounting for Risk Management Activities.  Derivative instruments are recorded on the balance sheet as either an asset or liability measured at fair value, and changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met.  During the three-year period ended December 31, 2020, 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 Commodity Derivative Contracts on the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss).  The related cash flow impact of settled contracts is reflected as cash flows from operating activities.  EOG employs net presentation of 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.

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, and its United Kingdom subsidiary (which was sold in the fourth quarter of 2018), for which the functional currency was the British pound.  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 Notes 4 and 17.

Net Income (Loss) Per Share

Net Income (Loss) Per Share.  Basic net income (loss) per share is computed on the basis of the weighted-average number of common shares outstanding during the period.  Diluted net income (loss) 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. Effective January 1, 2019, EOG adopted the provisions of ASU 2016-02, "Leases (Topic 842)" (ASU 2016-02). ASU 2016-02 and other related ASUs require that lessees recognize a right-of-use (ROU) asset and related lease liability, representing the obligation to make lease payments for certain lease transactions, on the Consolidated Balance Sheets and disclose additional leasing information.

EOG elected to adopt ASU 2016-02 and other related ASUs using the modified retrospective approach with a cumulative-effect adjustment to the opening balance of retained earnings as of the effective date. Financial results reported in periods prior to January 1, 2019, are unchanged. Additionally, EOG elected the package of practical expedients within ASU 2016-02 that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases, or (iii) initial direct costs for any existing leases, but did not elect the practical expedient of hindsight when determining the lease term of existing contracts at the effective date. EOG also elected the practical expedient under ASU 2018-01, "Leases (Topic 842) - Land Easement Practical Expedient for Transition to Topic 842," and did not evaluate existing or expired land easements not previously accounted for as leases prior to the January 1, 2019 effective date. There was no impact to retained earnings upon adoption of ASU 2016-02 and other related ASUs.

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 ASU 2016-02. 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.

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 from all leases, excluding those for fracturing services, real estate and salt water disposal, as lease payments under these contracts contain significant non-lease components, such as labor and operating costs. See Note 18.

Recently Issued Accounting Standards and Developments

Recently Issued Accounting Standards. In March 2020, the FASB issued ASU 2020-04, "Reference Rate Reform (Topic 848)" (ASU 2020-04), which provides optional expedients and exceptions for accounting treatment of contracts which are affected by the anticipated discontinuation of the London InterBank Offered Rate (LIBOR) and other rates resulting from rate reform. Contract terms that are modified due to the replacement of a reference rate are not required to be remeasured or reassessed under relevant accounting standards. Early adoption is permitted. ASU 2020-04 covers certain contracts which reference these rates and that are entered into on or before December 31, 2022. EOG is evaluating the provisions of ASU 2020-04 and has not determined the full impact on its consolidated financial statements and related disclosures related to its $2.0 billion senior unsecured Revolving Credit Agreement.

In December 2019, the FASB issued ASU 2019-12, "Income Taxes (Topic 740) ‑ Simplifying the Accounting for Income Taxes" (ASU 2019-12), which amends certain aspects of accounting for income taxes. ASU 2019-12 removes specific exceptions within existing U.S. GAAP related to the incremental approach for intraperiod tax allocation and to the general methodology for calculating income taxes in interim periods, among other changes. ASU 2019-12 also requires an entity to reflect the effect of an enacted change in tax laws or rates in the annual effective tax rate computation in the interim period that includes the enactment date, among other requirements. ASU 2019-12 is effective for interim and annual periods beginning after December 15, 2020, and early adoption is permitted. EOG will adopt ASU 2019-12 effective January 1, 2021, with all of the anticipated and applicable effects to be required on a prospective basis. EOG does not expect the adoption of ASU 2019-12 to have a material impact on its consolidated financial statements and related disclosures.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2020

Accounting Policies [Abstract]

Accounting Standards Update and Change in Accounting Principle

The impacts of the adoption of ASU 2014-09 for the year ended December 31, 2018, were as follows (in thousands):

	As Reported		Amounts Without Adoption of ASU 2014-09		Effect of Change
Operating Revenues and Other
Crude Oil and Condensate	$	9,517,440	$	9,517,440	$	—
Natural Gas Liquids	1,127,510		1,121,237		6,273
Natural Gas	1,301,537		1,104,095		197,442
Gathering, Processing and Marketing	5,230,355		5,211,136		19,219
Total Operating Revenues and Other	17,275,399		17,052,465		222,934
Operating Expenses
Gathering and Processing Costs	436,973		233,258		203,715
Marketing Costs	5,203,243		5,184,024		19,219
Total Operating Expenses	12,806,053		12,583,119		222,934
Operating Income	4,469,346		4,469,346		—

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt at December 31, 2020 and 2019 consisted of the following (in thousands):

	2020		2019
4.40% Senior Notes due 2020	$	—	$	500,000
2.45% Senior Notes due 2020	—		500,000
4.100% Senior Notes due 2021	750,000		750,000
2.625% Senior Notes due 2023	1,250,000		1,250,000
3.15% Senior Notes due 2025	500,000		500,000
4.15% Senior Notes due 2026	750,000		750,000
6.65% Senior Notes due 2028	140,000		140,000
4.375% Senior Notes due 2030	750,000		—
3.90% Senior Notes due 2035	500,000		500,000
5.10% Senior Notes due 2036	250,000		250,000
4.950% Senior Notes due 2050	750,000		—
Long-Term Debt	5,640,000		5,140,000
Finance Leases (see Note 18)	212,217		57,900
Less: Current Portion of Long-Term Debt	781,054		1,014,524
Unamortized Debt Discount	30,931		19,528
Debt Issuance Costs	4,881		2,929
Total Long-Term Debt	$	5,035,351	$	4,160,919

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Stockholder's Equity (Tables)

12 Months Ended

Dec. 31, 2020

Stockholders' Equity Note [Abstract]

Common stock activity

The following summarizes Common Stock activity for each of the years ended December 31, 2018, 2019 and 2020 (in thousands):

	Common Shares
	Issued	Treasury	Outstanding
Balance at December 31, 2017	578,828	(351)	578,477
Common Stock Issued Under Stock-Based Compensation Plans	1,580	—	1,580
Treasury Stock Purchased (1)	—	(539)	(539)
Common Stock Issued Under Employee Stock Purchase Plan	—	180	180
Treasury Stock Issued Under Stock-Based Compensation Plans	—	325	325
Balance at December 31, 2018	580,408	(385)	580,023
Common Stock Issued Under Stock-Based Compensation Plans	1,688	—	1,688
Treasury Stock Purchased (1)	—	(310)	(310)
Common Stock Issued Under Employee Stock Purchase Plan	117	106	223
Treasury Stock Issued Under Stock-Based Compensation Plans	—	290	290
Balance at December 31, 2019	582,213	(299)	581,914
Common Stock Issued Under Stock-Based Compensation Plans	1,482	—	1,482
Treasury Stock Purchased (1)	—	(389)	(389)
Common Stock Issued Under Employee Stock Purchase Plan	—	377	377
Treasury Stock Issued Under Stock-Based Compensation Plans	—	187	187
Balance at December 31, 2020	583,695	(124)	583,571

(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.

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Accumulated Other Comprehensive Loss (Tables)

12 Months Ended

Dec. 31, 2020

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

The components of Accumulated Other Comprehensive Loss at December 31, 2020 and 2019 consisted of the following (in thousands):

	Foreign Currency Translation Adjustment		Other		Total
December 31, 2018	$	174	$	(1,532)	$	(1,358)
Cumulative effect of accounting changes	—		267		267
Other comprehensive loss before taxes	(2,883)		(533)		(3,416)
Tax effects	—		(145)		(145)
Other comprehensive loss	(2,883)		(678)		(3,561)
December 31, 2019	(2,709)		(1,943)		(4,652)
Other comprehensive loss before taxes	(7,346)		(183)		(7,529)
Tax effects	—		(147)		(147)
Other comprehensive loss	(7,346)		(330)		(7,676)
December 31, 2020	$	(10,055)	$	(2,273)	$	(12,328)

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Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2020

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 (Loss) and Comprehensive Income (Loss) 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, 2020, 2019 and 2018 was as follows (in millions):

	2020		2019		2018
Lease and Well	$	52	$	56	$	51
Gathering and Processing Costs	1		1		1
Exploration Costs	21		26		25
General and Administrative	72		92		78
Total	$	146	$	175	$	155

Vesting Schedule

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 Committee's certification of the applicable performance multiple

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, 2020, 2019 and 2018 were as follows:

	Stock Options/SARs									ESPP
	2020			2019			2018			2020			2019			2018
Weighted Average Fair Value of Grants	$	11.06		$	19.49		$	33.46		$	19.14		$	22.83		$	25.75
Expected Volatility	44.47		%	32.02		%	28.23		%	53.48		%	34.78		%	24.59		%
Risk-Free Interest Rate	0.21		%	1.69		%	2.68		%	0.90		%	2.27		%	1.89		%
Dividend Yield	3.27		%	1.39		%	0.72		%	2.27		%	1.04		%	0.64		%
Expected Life	5.2 years			5.1 years			5.0 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, 2020, 2019 and 2018 (stock options and SARs in thousands):

	2020			2019			2018
	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	9,395	$	94.53	8,310	$	96.90	9,103	$	83.89
Granted	1,996	37.63		1,965	75.39		1,906	126.49
Exercised (1)	(23)	69.59		(606)	61.43		(2,493)	72.21
Forfeited	(1,182)	88.93		(274)	102.57		(206)	94.43
Outstanding at December 31	10,186	84.08		9,395	94.53		8,310	96.90
Stock Options/SARs Exercisable at December 31	6,343	96.41		5,275	94.21		3,969	85.82

(1)The total intrinsic value of stock options/SARs exercised during the years 2020, 2019 and 2018 was $0.4 million, $14 million and $118 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.

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, 2020 (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 $  43.99	1,974	7	$	37.43			10	1	$	37.44
44.00 to     74.99	872	2	69.37				846	2	69.47
75.00 to     75.99	1,863	6	75.09				636	5	75.09
76.00 to     95.99	1,242	3	94.47				1,215	3	94.63
96.00 to   101.99	2,477	3	97.95				2,457	3	97.95
102.00 to   129.99	1,758	5	126.44				1,179	5	126.37
	10,186	4	84.08		$	24,578	6,343	3	96.41		$	124

(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 thousands.

ESPP Activity

The following table summarizes ESPP activity for the years ended December 31, 2020, 2019 and 2018 (in thousands, except number of participants):

	2020		2019		2018
Approximate Number of Participants	2,063		1,998		1,934
Shares Purchased	377		224		180
Aggregate Purchase Price	$	16,103	$	16,533	$	14,887

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, 2020, 2019 and 2018 (shares and units in thousands):

	2020			2019			2018
	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	4,546	$	90.16	3,792	$	96.64	3,905	$	88.57
Granted	1,488	38.10		1,749	80.01		812	117.55
Released (1)	(1,213)	85.92		(855)	96.93		(740)	78.16
Forfeited	(79)	86.52		(140)	97.54		(185)	92.12
Outstanding at December 31 (2)	4,742	74.97		4,546	90.16		3,792	96.64

(1)The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2020, 2019 and 2018 was $48 million, $70 million and $84 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)The total intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2020, 2019 and 2018 was $236 million, $381 million and $331 million, respectively. The intrinsic value is based on the closing market price of the Common Stock on the last trading day of the year.

Weighted Average Fair Values and Valuation Assumptions for Performance Units/Stocks

Weighted average fair values and valuation assumptions used to value Performance Awards during the years ended December 31, 2020, 2019 and 2018 were as follows:

	2020			2019			2018
Weighted Average Fair Value of Grants	$	42.77		$	79.98		$	136.74
Expected Volatility	47.27		%	29.20		%	29.92		%
Risk-Free Interest Rate	0.16		%	1.51		%	2.85		%

Performance Unit and Performance Stock Transactions

The following table sets forth the Performance Award transactions for the years ended December 31, 2020, 2019 and 2018 (units in thousands):

	2020				2019			2018
	Number of Units		Weighted Average Price per Grant Date		Number of Units	Weighted Average Price per Grant Date		Number of Units	Weighted Average Price per Grant Date
Outstanding at January 1	598		$	92.19	539	$	101.53	502	$	90.96
Granted	172		37.44		172	75.09		113	125.73
Granted for Performance Multiple (1)	66		100.95		72	69.43		72	101.87
Released (2)	(223)		88.52		(185)	94.63		(148)	84.43
Forfeited	—		—		—	—		—	—
Outstanding at December 31 (3)	613	(4)	79.10		598	92.19		539	101.53

(1)Upon completion of the Performance Period for the Performance Awards granted in 2016, 2015 and 2014, a performance multiple of 150%, 200% and 200%, respectively, was applied to each of the grants resulting in additional grants of Performance Awards in February 2020, 2019 and 2018.

(2)The total intrinsic value of Performance Awards released during the years ended December 31, 2020, 2019 and 2018 was $13 million, $15 million and $18 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date Performance Awards are released.

(3)The total intrinsic value of Performance Awards outstanding at December 31, 2020, 2019 and 2018 was $31 million, $50 million and $47 million, respectively. The intrinsic value is based on the closing market price of the Common Stock on the last trading day of the year.

(4)Upon the application of the relevant performance multiple at the completion of each of the remaining Performance Periods, a minimum of 77 and a maximum of 1,149 Performance Awards could be outstanding.

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2020

Table Text Block [Abstract]

Deferred Income Tax Liabilities, Net

The principal components of EOG's total net deferred income tax liabilities at December 31, 2020 and 2019 were as follows (in thousands):

	2020		2019
Deferred Income Tax Assets (Liabilities)
Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization	$	25,129	$	5,825
Foreign Net Operating Loss	74,280		66,675
Foreign Valuation Allowances	(97,499)		(70,455)
Foreign Other	217		318
Total Net Deferred Income Tax Assets	$	2,127	$	2,363
Deferred Income Tax (Assets) Liabilities
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization	$	5,028,010	$	5,277,550
Commodity Hedging Contracts	14,518		(4,699)
Deferred Compensation Plans	(42,594)		(47,650)
Accrued Expenses and Liabilities	—		(8,502)
Equity Awards	(102,944)		(108,324)
Alternative Minimum Tax Credit Carryforward	—		(31,904)
Undistributed Foreign Earnings	9,843		15,746
Other	(47,506)		(46,116)
Total Net Deferred Income Tax Liabilities	$	4,859,327	$	5,046,101
Total Net Deferred Income Tax Liabilities	$	4,857,200	$	5,043,738

Components of Income (Loss) Before Income Taxes

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

	2020		2019		2018
United States	$	(756,479)	$	3,466,578	$	4,084,156
Foreign	17,425		78,689		156,842
Total	$	(739,054)	$	3,545,267	$	4,240,998

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 thousands):

	2020		2019		2018
Current:
Federal	$	(107,834)	$	(152,258)	$	(303,853)
State	6,790		10,819		17,048
Foreign	40,248		81,426		65,615
Total	(60,796)		(60,013)		(221,190)
Deferred:
Federal	(153,027)		626,901		862,075
State	(15,400)		32,541		43,293
Foreign	(17,963)		(27,784)		(11,212)
Total	(186,390)		631,658		894,156
Other Non-Current: (1)
Federal	112,704		245,125		148,992
Foreign	—		(6,413)		—
Total	112,704		238,712		148,992
Income Tax Provision (Benefit)	$	(134,482)	$	810,357	$	821,958

(1)    Includes changes in certain amounts that are expected to be paid or received beyond the next twelve months. The primary component is refundable alternative minimum tax (AMT) credits.

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:

	2020		2019		2018
Statutory Federal Income Tax Rate	21.00	%	21.00	%	21.00	%
State Income Tax, Net of Federal Benefit	0.92		0.97		1.12
Income Tax Provision Related to Foreign Operations	(0.09)		0.87		0.51
Income Tax Provision Related to Canadian Operations	(2.43)		—		—
TCJA (1)	—		—		(2.60)		(2)
Share-Based Compensation	(2.94)		0.02		(0.47)
Other	1.74		—		(0.18)
Effective Income Tax Rate	18.20	%	22.86	%	19.38	%

(1)    The Tax Cuts and Jobs Act (TCJA) was enacted in 2017 and required certain measurement-period adjustments in 2018.

(2)    Includes impact of utilizing certain tax net operating losses (NOLs) ((1.2)%), the reversal of the federal sequestration charge ((1.0)%) and other TCJA impacts ((0.4)%).

Summary 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 thousands):

	2020		2019		2018
Beginning Balance	$	200,831	$	167,142	$	466,421
Increase (1)	25,573		30,673		23,062
Decrease (2)	(11,343)		(75)		(26,219)
Other (3)	3,942		3,091		(296,122)
Ending Balance	$	219,003	$	200,831	$	167,142

(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. The United Kingdom operations were sold in the fourth quarter of 2018.

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2020

Commitments and Contingencies Disclosure [Abstract]

Minimum commitments for unrecorded unconditional purchase obligations

At December 31, 2020, 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, 2020, were as follows (in millions):

	Total Minimum Commitments
2021	$	1,393
2022	1,263
2023	1,064
2024	790
2025	649
2026 and beyond	2,764
	$	7,923

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Net Income (Loss) Per Share (Tables)

12 Months Ended

Dec. 31, 2020

Earnings Per Share [Abstract]

Computation of Net Income (Loss) Per Share

The following table sets forth the computation of Net Income (Loss) Per Share for the years ended December 31, 2020, 2019 and 2018 (in thousands, except per share data):

	2020		2019		2018
Numerator for Basic and Diluted Earnings per Share -
Net Income (Loss)	$	(604,572)	$	2,734,910	$	3,419,040
Denominator for Basic Earnings per Share -
Weighted Average Shares	578,949		577,670		576,578
Potential Dilutive Common Shares -
Stock Options/SARs	—		258		1,137
Restricted Stock/Units and Performance Units	—		2,849		2,726
Denominator for Diluted Earnings per Share -
Adjusted Diluted Weighted Average Shares	578,949		580,777		580,441
Net Income (Loss) Per Share
Basic	$	(1.04)	$	4.73	$	5.93
Diluted	$	(1.04)	$	4.71	$	5.89

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2020

Supplemental Cash Flow Information [Abstract]

Net Cash Paid For Interest and Income Taxes

Net cash paid (received) for interest and income taxes was as follows for the years ended December 31, 2020, 2019 and 2018 (in thousands):

	2020		2019		2018
Interest, Net of Capitalized Interest	$	205,447	$	186,546	$	243,279
Income Taxes, Net of Refunds Received	$	(205,795)	$	(291,849)	$	75,634

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Business Segment Information (Tables)

12 Months Ended

Dec. 31, 2020

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

Financial information by reportable segment is presented below as of and for the years ended December 31, 2020, 2019 and 2018 (in thousands):

	United States		Trinidad		Other International (1)		Total
2020
Crude Oil and Condensate	$	5,773,582	$	10,723	$	1,304	$	5,785,609
Natural Gas Liquids	667,514		—		—		667,514
Natural Gas	614,002		168,967		54,164		837,133
Gains on Mark-to-Market Commodity Derivative Contracts	1,144,737		—		—		1,144,737
Gathering, Processing and Marketing	2,581,493		1,491		—		2,582,984
Gains (Losses) on Asset Dispositions, Net	(47,018)		(44)		179		(46,883)
Other, Net	60,989		(35)		—		60,954
Operating Revenues and Other (2)	10,795,299		181,102		55,647		11,032,048
Depreciation, Depletion and Amortization	3,323,800		60,629		15,924		3,400,353
Operating Income (Loss) (3)	(545,566)		74,801		(73,251)		(544,016)
Interest Income	10,783		922		34		11,739
Other Income (Expense)	153		(2,129)		465		(1,511)
Net Interest Expense	205,266		—		—		205,266
Income (Loss) Before Income Taxes	(739,896)		73,594		(72,752)		(739,054)
Income Tax Provision (Benefit)	(156,834)		14,568		7,784		(134,482)
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	3,316,724		83,173		41,961		3,441,858
Total Property, Plant and Equipment, Net	28,283,027		210,278		105,322		28,598,627
Total Assets	35,047,485		546,120		210,996		35,804,601

2019
Crude Oil and Condensate	$	9,599,125	$	11,138	$	2,269	$	9,612,532
Natural Gas Liquids	784,818		—		—		784,818
Natural Gas	866,911		258,819		58,365		1,184,095
Gains on Mark-to-Market Commodity Derivative Contracts	180,275		—		—		180,275
Gathering, Processing and Marketing	5,355,463		4,819		—		5,360,282
Gains (Losses) on Asset Dispositions, Net	131,446		(3,688)		(4,145)		123,613
Other, Net	134,325		18		15		134,358
Operating Revenues and Other (4)	17,052,363		271,106		56,504		17,379,973
Depreciation, Depletion and Amortization	3,652,294		79,389		18,021		3,749,704
Operating Income (Loss)	3,618,907		112,790		(32,686)		3,699,011
Interest Income	22,122		3,686		218		26,026
Other Income	3,235		727		1,397		5,359
Net Interest Expense	192,587		—		(7,458)		185,129
Income (Loss) Before Income Taxes	3,451,677		117,203		(23,613)		3,545,267
Income Tax Provision	760,881		40,901		8,575		810,357
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	6,208,394		53,325		12,233		6,273,952
Total Property, Plant and Equipment, Net	30,101,857		184,606		78,132		30,364,595
Total Assets	36,274,942		705,747		143,919		37,124,608

	United States		Trinidad		Other International (1)		Total
2018
Crude Oil and Condensate	$	9,390,244	$	17,059	$	110,137	$	9,517,440
Natural Gas Liquids	1,127,510		—		—		1,127,510
Natural Gas	970,866		285,053		45,618		1,301,537
Loses on Mark-to-Market Commodity Derivative Contracts	(165,640)		—		—		(165,640)
Gathering, Processing and Marketing	5,227,051		3,304		—		5,230,355
Gains on Asset Dispositions, Net	154,852		4,493		15,217		174,562
Other, Net	89,708		(49)		(24)		89,635
Operating Revenues and Other (5)	16,794,591		309,860		170,948		17,275,399
Depreciation, Depletion and Amortization	3,296,499		91,971		46,938		3,435,408
Operating Income (Loss)	4,334,364		147,240		(12,258)		4,469,346
Interest Income	9,326		1,612		608		11,546
Other Income (Expense)	9,580		2,436		(6,858)		5,158
Net Interest Expense	253,352		—		(8,300)		245,052
Income (Loss) Before Income Taxes	4,099,918		151,288		(10,208)		4,240,998
Income Tax Provision	765,986		54,272		1,700		821,958
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	6,155,874		1,618		37,838		6,195,330
Total Property, Plant and Equipment, Net	27,786,086		210,183		79,250		28,075,519
Total Assets	33,178,733		629,633		126,108		33,934,474

(1)Other International primarily consists of EOG's United Kingdom, China and Canada operations. EOG began an exploration program in Oman in the third quarter of 2020. The United Kingdom operations were sold in the fourth quarter of 2018.

(2)EOG had sales activity with three significant purchasers in 2020, each totaling $1.1 billion of consolidated Operating Revenues and Other in the United States segment.

(3)EOG recorded pretax impairment charges of $1,570 million in 2020 for proved oil and gas properties, leasehold costs and other assets due to the decline in commodity prices and revisions of asset retirement obligations for certain properties in the United States segment. In addition, EOG recorded pretax impairment charges of $228 million in 2020 for owned and leased sand and crude-by-rail assets, also in the United States segment. EOG recorded pretax impairment charges of $81 million in 2020 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 Notes 13 and 14.

(4)EOG had sales activity with two significant purchasers in 2019, one totaling $2.4 billion and the other totaling $2.2 billion of consolidated Operating Revenues and Other in the United States segment.

(5)EOG had sales activity with two significant purchasers in 2018, one totaling $2.6 billion and the other totaling $2.3 billion of consolidated Operating Revenues and Other in the United States segment.

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Risk Management Activities (Tables)

12 Months Ended

Dec. 31, 2020

Price Risk Derivative [Member]

Derivatives, Fair Value [Line Items]

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, 2020 and 2019, 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 thousands):

		Fair Value at December 31,
Description	Location on Balance Sheet	2020		2019
Asset Derivatives
Crude oil, NGLs and natural gas derivative contracts -
Current portion	Assets from Price Risk Management Activities (1)	$	64,559	$	1,299
Noncurrent portion	Other Assets	1,063		—
Liability Derivatives
Crude oil, NGLs and natural gas derivative contracts -
Current portion	Liabilities from Price Risk Management Activities (2)	$	—	$	20,194
Noncurrent Portion	Other Liabilities	455		—

(1)    The current portion of Assets from Price Risk Management Activities consists of gross assets of $3 million, partially offset by gross liabilities of $2 million, at December 31, 2019.

(2)    The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $23 million, partially offset by gross assets of $3 million at December 31, 2019.

Crude Oil | Roll Differential Swap

Derivatives, Fair Value [Line Items]

Schedule of Derivative Instruments

EOG has also entered into crude oil swaps in order to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month (Roll Differential). Presented below is a comprehensive summary of EOG's Roll Differential basis swap contracts as of December 31, 2020. The weighted average price differential expressed in $/Bbl represents the amount of net addition (reduction) to delivery month prices for the notional volumes expressed in Bbld covered by the swap contracts.

Roll Differential Basis Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)
2020
February 1, 2020 through June 30, 2020 (closed)	10,000	$	0.70
July 1, 2020 through September 30, 2020 (closed)	88,000	(1.16)
October 1, 2020 through December 31, 2020 (closed)	66,000	(1.16)
2021
February 1, 2021 through December 31, 2021	25,000	$	0.10
2022
January 1, 2022 through December 31, 2022	50,000	$	0.11

In May 2020, EOG entered into crude oil Roll Differential basis swap contracts for the period from July 1, 2020 through September 30, 2020, with notional volumes of 22,000 Bbld at a weighted average price differential of $(0.43) per Bbl, and for the period from October 1, 2020 through December 31, 2020, with notional volumes of 44,000 Bbld at a weighted average price differential of $(0.73) per Bbl. These contracts partially offset certain outstanding Roll Differential basis swap contracts for the same time periods and volumes at a weighted average price differential of $(1.16) per Bbl. EOG paid net cash of $3.2 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.

Crude Oil | Houston Differential Basis Swap

Derivatives, Fair Value [Line Items]

Schedule of Derivative Instruments

EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in Houston, Texas, and Cushing, Oklahoma (Houston Differential). Presented below is a comprehensive summary of EOG's Houston Differential basis swap contracts as of December 31, 2020. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.

Houston Differential Basis Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)
2020
May 2020 (closed)	10,000	$	1.55

Crude Oil | ICE Brent Differential Basis Swap

Derivatives, Fair Value [Line Items]

Schedule of Derivative Instruments

EOG has entered into crude oil basis swap contracts in order to fix the differential between Intercontinental Exchange (ICE) Brent pricing and pricing in Cushing, Oklahoma (ICE Brent Differential). Presented below is a comprehensive summary of EOG's ICE Brent Differential basis swap contracts as of December 31, 2020. The weighted average price differential expressed in dollars per barrel ($/Bbl) represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in barrels per day (Bbld) covered by the basis swap contracts.

ICE Brent Differential Basis Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)
2020
May 2020 (closed)	10,000	$	4.92

Crude Oil | Price Swaps

Derivatives, Fair Value [Line Items]

Schedule of Derivative Instruments

Presented below is a comprehensive summary of EOG's crude oil NYMEX WTI price swap contracts as of December 31, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

Crude Oil NYMEX WTI Price Swap Contracts
	Volume (Bbld)	Weighted Average Price ($/Bbl)
2020
January 1, 2020 through March 31, 2020 (closed)	200,000	$	59.33
April 1, 2020 through May 31, 2020 (closed)	265,000	51.36

In April and May 2020, EOG entered into crude oil NYMEX WTI price swap contracts for the period from June 1, 2020 through June 30, 2020, with notional volumes of 265,000 Bbld at a weighted average price of $33.80 per Bbl, for the period from July 1, 2020 through July 31, 2020, with notional volumes of 254,000 Bbld at a weighted average price of $33.75 per Bbl, for the period from August 1, 2020 through September 30, 2020, with notional volumes of 154,000 Bbld at a weighted average price of $34.18 per Bbl and for the period from October 1, 2020 through December 31, 2020, with notional volumes of 47,000 Bbld at a weighted average price of $30.04 per Bbl. These contracts offset the remaining crude oil NYMEX WTI price swap contracts for the same time periods and volumes at a weighted average price of $51.36 per Bbl for the period from June 1, 2020 through June 30, 2020, $42.36 per Bbl for the period from July 1, 2020 through July 31, 2020, $50.42 per Bbl for the period from August 1, 2020 through September 30, 2020 and $31.00 per Bbl for the period from October 1, 2020 through December 31, 2020. EOG received net cash of $362.6 million through December 31, 2020, for the settlement of certain of these contracts, and expects to receive net cash of $1.4 million during January 2021 for the settlement of the remaining contracts. The offsetting contracts were excluded from the above table.

Crude Oil | ICE Brent Price Swap

Derivatives, Fair Value [Line Items]

Schedule of Derivative Instruments

Presented below is a comprehensive summary of EOG's crude oil ICE Brent price swap contracts as of December 31, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

Crude Oil ICE Brent Price Swap Contracts
	Volume (Bbld)	Weighted Average Price ($/Bbl)
2020
April 2020 (closed)	75,000	$	25.66
May 2020 (closed)	35,000	26.53

Natural Gas Liquids | Mont Belvieu Propane Price Swap

Derivatives, Fair Value [Line Items]

Schedule of Derivative Instruments

Presented below is a comprehensive summary of EOG's Mont Belvieu propane (non-TET) price swap contracts as of December 31, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

Mont Belvieu Propane Price Swap Contracts
	Volume (Bbld)	Weighted Average Price ($/Bbl)
2020
January 1, 2020 through February 29, 2020 (closed)	4,000	$	21.34
March 1, 2020 through April 30, 2020 (closed)	25,000	17.92

In April and May 2020, EOG entered into Mont Belvieu propane price swap contracts for the period from May 1, 2020 through December 31, 2020, with notional volumes of 25,000 Bbld at a weighted average price of $16.41 per Bbl. These contracts offset the remaining Mont Belvieu propane price swap contracts for the same time period with notional volumes of 25,000 Bbld at a weighted average price of $17.92 per Bbl. EOG received net cash of $8.0 million through December 31, 2020, for the settlement of certain of these contracts, and expects to receive net cash of $1.2 million during January 2021 for the settlement of the remaining contracts. The offsetting contracts were excluded from the above table.

Natural Gas | Price Swaps

Derivatives, Fair Value [Line Items]

Schedule of Derivative Instruments

Presented below is a comprehensive summary of EOG's natural gas NYMEX Henry Hub price swap contracts as of December 31, 2020, with notional volumes sold (purchased) expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).

Natural Gas NYMEX Henry Hub Price Swap Contracts
	Volume (MMBtud)	Weighted Average Price ($/MMBtu)
2021
April 1, 2021 through December 31, 2021	500,000	$	2.99
2022
January 1, 2022 through December 31, 2022	20,000	$	2.75

In December 2020, EOG entered into natural gas NYMEX Henry Hub price swap contracts for the period from January 1, 2021 through March 31, 2021, with notional volumes of 500,000 MMBtud at a weighted average price of $2.43 per MMBtu. These contracts offset the remaining natural gas NYMEX Henry Hub price swap contracts for the same time period with notional volumes of 500,000 MMBtud at a weighted average price of $2.99 per MMBtu. EOG expects to receive net cash of $25.2 million during 2021 for the settlement of these contracts. The offsetting contracts were excluded from the above table.

Natural Gas | Collars

Derivatives, Fair Value [Line Items]

Schedule of Derivative Instruments

EOG has entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price. In March 2020, EOG executed the early termination provision granting EOG the right to terminate certain 2020 natural gas collar contracts with notional volumes of 250,000 MMBtud at a weighted average ceiling price of $2.50 per MMBtu and a weighted average floor price of $2.00 per MMBtu for the period from April 1, 2020 through July 31, 2020. EOG received net cash of $7.8 million for the settlement of these contracts. Presented below is a comprehensive summary of EOG's natural gas collar contracts as of December 31, 2020, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.

Natural Gas Collar Contracts
		Weighted Average Price ($/MMBtu)
	Volume (MMBtud)	Ceiling Price		Floor Price
2020
April 1, 2020 through July 31, 2020 (closed)	250,000	$	2.50	$	2.00

In April 2020, EOG entered into natural gas collar contracts for the period from August 1, 2020 through October 31, 2020, with notional volumes of 250,000 MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu. These contracts offset the remaining natural gas collar contracts for the same time period with notional volumes of 250,000 MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu. EOG received net cash of $1.1 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.

Natural Gas | Rockies Differential Basis Swaps

Derivatives, Fair Value [Line Items]

Schedule of Derivative Instruments

EOG has entered into natural gas basis swap contracts in order to fix the differential between pricing in the Rocky Mountain area and NYMEX Henry Hub prices (Rockies Differential). Presented below is a comprehensive summary of EOG's Rockies Differential basis swap contracts as of December 31, 2020. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts.

Rockies Differential Basis Swap Contracts
	Volume (MMBtud)	Weighted Average Price Differential ($/MMBtu)
2020
January 1, 2020 through December 31, 2020 (closed)	30,000	$	0.55

Natural Gas | HSC Differential Basis Swaps [Member]

Derivatives, Fair Value [Line Items]

Schedule of Derivative Instruments

EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Houston Ship Channel (HSC) and NYMEX Henry Hub prices (HSC Differential). In March 2020, EOG executed the early termination provision granting EOG the right to terminate certain 2020 HSC Differential basis swaps with notional volumes of 60,000 MMBtud at a weighted average price differential of $0.05 per MMBtu for the period from April 1, 2020 through December 31, 2020. EOG paid net cash of $0.4 million for the settlement of these contracts. Presented below is a comprehensive summary of EOG's HSC Differential basis swap contracts as of December 31, 2020. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts.

HSC Differential Basis Swap Contracts
	Volume (MMBtud)	Weighted Average Price Differential ($/MMBtu)
2020
January 1, 2020 through December 31, 2020 (closed)	60,000	$	0.05

Natural Gas | Waha Differential Basis Swaps [Member]

Derivatives, Fair Value [Line Items]

Schedule of Derivative Instruments

EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Waha Hub in West Texas and NYMEX Henry Hub prices (Waha Differential). Presented below is a comprehensive summary of EOG's Waha Differential basis swap contracts as of December 31, 2020. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts.

Waha Differential Basis Swap Contracts
	Volume (MMBtud)	Weighted Average Price Differential ($/MMBtu)
2020
January 1, 2020 through April 30, 2020 (closed)	50,000	$	1.40

In April 2020, EOG entered into Waha Differential basis swap contracts for the period from May 1, 2020 through December 31, 2020, with notional volumes of 50,000 MMBtud at a weighted average price differential of $0.43 per MMBtu. These contracts offset the remaining Waha Differential basis swap contracts for the same time period with notional volumes of 50,000 MMBtud at a weighted average price differential of $1.40 per MMBtu. EOG paid net cash of $11.9 million for the settlement of these contracts. The offsetting contracts were excluded from the above table.

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2020

Fair Value Disclosures [Abstract]

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, 2020 and 2019. Amounts shown in thousands.

	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, 2020
Financial Assets (1):
Natural Gas Swaps	$	—	$	66,064	$	—	$	66,064
Financial Liabilities (2):
Crude Oil Roll Differential Swaps	—		897		—		897
At December 31, 2019
Financial Assets (1):
Natural Gas Liquids Swaps	$	—	$	3,401	$	—	$	3,401
Natural Gas Basis Swaps	—		970		—		970
Financial Liabilities (2):
Crude Oil Swaps	—		23,266		—		23,266

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Impairment Expense (Tables)

12 Months Ended

Dec. 31, 2020

Impairment Expense [Abstract]

Impairment Expenses

Impairment expense was as follows for the years ended December 31, 2020, 2019 and 2018 (in thousands):

	2020		2019		2018
Proved properties (1)	$	1,268,073	$	206,469	$	120,859
Unproved properties (2)	472,143		220,444		173,383
Other assets (3)	299,851		90,983		48,732
Inventories	—		—		4,047
Firm commitment contracts (4)	59,713		—		—
Total	$	2,099,780	$	517,896	$	347,021

(1)    Impairments to proved oil and gas properties in 2020 included legacy and non-core natural gas and crude oil and combo plays. Impairments to proved oil and gas properties in 2019 and 2018 included domestic legacy natural gas assets. See Notes 1 and 13.

(2)    Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. Impairments of unproved oil and gas properties included charges of $252 million in 2020 for certain leasehold costs that are no longer expected to be developed before expiration. See Note 1.

(3)    Includes impairment charges for owned and leased sand and crude-by-rail assets of $228 million in 2020 (see Note 18) and a commodity price-related write-down of other assets of $72 million, $90 million and $49 million in 2020, 2019 and 2018, respectively (see Note 13).

(4)    Includes impairment charges of $60 million in 2020 for firm commitment contracts related to its decision to exit the Horn River Basin in British Columbia, Canada.

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2020

Asset Retirement Obligations, Noncurrent [Abstract]

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, 2020 and 2019 (in thousands):

	2020		2019
Carrying Amount at Beginning of Period	$	1,110,710	$	954,377
Liabilities Incurred	57,477		98,874
Liabilities Settled (1)	(54,027)		(58,673)
Accretion	47,083		43,462
Revisions	53,888		72,425
Foreign Currency Translations	1,407		245
Carrying Amount at End of Period	$	1,216,538	$	1,110,710
Current Portion	$	49,548	$	37,127
Noncurrent Portion	$	1,166,990	$	1,073,583

(1)    Includes settlements related to asset sales.

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Exploratory Well Costs (Tables)

12 Months Ended

Dec. 31, 2020

Capitalized Exploratory Well Costs [Abstract]

Net Changes in Capitalized Exploratory Well Costs

EOG's net changes in capitalized exploratory well costs for the years ended December 31, 2020, 2019 and 2018 are presented below (in thousands):

	2020		2019		2018
Balance at January 1	$	25,897	$	4,121	$	2,167
Additions Pending the Determination of Proved Reserves	107,852		83,175		10,304
Reclassifications to Proved Properties	(81,071)		(39,325)		(7,917)
Costs Charged to Expense (1)	(23,822)		(22,074)		(433)
Balance at December 31	$	28,856	$	25,897	$	4,121

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

Schedule of Aging of Capitalized Exploratory Well Costs

	2020		2019		2018
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	26,408	$	25,897	$	4,121
Capitalized exploratory well costs that have been capitalized for a period greater than one year (1)	2,448		—		—
Balance at December 31	$	28,856	$	25,897	$	4,121
Number of exploratory wells that have been capitalized for a period greater than one year	1		—		—

(1)    Consists of costs related to a project in the United States at December 31, 2020.

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Leases (Tables)

12 Months Ended

Dec. 31, 2020

Leases [Abstract]

Lease

The components of lease cost for the years ended December 31, 2020 and 2019 were as follows (in millions):

	2020		2019
Operating Lease Cost (1)	$	393	$	497
Finance Lease Cost:
Amortization of Lease Assets	21		13
Interest on Lease Liabilities	4		2
Variable Lease Cost	91		138
Short-Term Lease Cost	194		333
Total Lease Cost	$	703	$	983

(1)    Operating lease cost includes impairment expenses of $35 million in 2020.

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, 2020 and 2019 and supplemental information for the years ended December 31, 2020 and 2019 (in millions, except lease terms and discount rates):

Description	Location on Balance Sheet	2020		2019
Assets
Operating Leases	Other Assets	$	869	$	773
Finance Leases	Property, Plant and Equipment, Net (1)	206		53
Total		$	1,075	$	826
Liabilities
Current
Operating Leases	Current Portion of Operating Lease Liabilities	$	295	$	369
Finance Leases	Current Portion of Long-Term Debt	31		15
Long-Term
Operating Leases	Other Liabilities	641		430
Finance Leases	Long-Term Debt	181		43
Total		$	1,148	$	857

(1)    Finance lease assets are recorded net of accumulated amortization of $81 million and $60 million at December 31, 2020 and 2019, respectively.

Weighted Average Remaining Lease Term And Discount Rate

	2020		2019
Weighted Average Remaining Lease Term (in years):
Operating Leases	5.3		3.2
Finance Leases	7.6		4.7
Weighted Average Discount Rate:
Operating Leases	3.4	%	3.5	%
Finance Leases	2.8	%	3.0	%

Cash Paid for Leases

Cash paid for leases for the years ended December 31, 2020 and 2019 was as follows (in millions):

	2020		2019
Repayment of Operating Lease Liabilities Associated with Operating Activities	$	223	$	225
Repayment of Operating Lease Liabilities Associated with Investing Activities	130		270
Repayment of Finance Lease Liabilities	19		13

Operating And Finance Non-Cancellable Leases Maturity

At December 31, 2020, the future minimum lease payments under non-cancellable leases were as follows (in millions):

	Operating Leases		Finance Leases
2021	$	323	$	36
2022	210		32
2023	134		28
2024	96		29
2025	70		27
2026 and Beyond	206		87
Total Lease Payments	1,039		239
Less: Discount to Present Value	103		27
Total Lease Liabilities	936		212
Less: Current Portion of Lease Liabilities	295		31
Long-Term Lease Liabilities	$	641	$	181

Prior To Adoption Operating And Finance Non-Cancellable Leases Maturity

Prior to the adoption of ASU 2016-02 and other related ASUs, the future minimum commitments under non-cancellable leases, including non-lease components and excluding contracts with lease terms of less than 12 months as December 31, 2018, were as follows (in millions):

	Operating Leases		Finance Leases
2019	$	380	$	15
2020	213		15
2021	86		15
2022	39		12
2023	30		8
2024 and Beyond	62		14
Total Lease Payments	$	810	$	79

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Oil and Gas Exploration and Production Industries Disclosures (Tables)

12 Months Ended

Dec. 31, 2020

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Net Proved and Proved Developed Oil and Gas Reserve Quantities

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, 2020, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2020, as estimated by the Engineering and Acquisitions Department of EOG:

NET PROVED RESERVE SUMMARY

	United States	Trinidad	Other International (1)	Total
NET PROVED RESERVES
Crude Oil (MBbl) (2)
Net proved reserves at December 31, 2017	1,304,071	898	8,004	1,312,973
Revisions of previous estimates	(13,237)	(183)	44	(13,376)
Purchases in place	2,743	—	—	2,743
Extensions, discoveries and other additions	383,003	—	15	383,018
Sales in place	(768)	—	(6,310)	(7,078)
Production	(144,128)	(298)	(1,542)	(145,968)
Net proved reserves at December 31, 2018	1,531,684	417	211	1,532,312
Revisions of previous estimates	(42,959)	85	(8)	(42,882)
Purchases in place	2,859	—	—	2,859
Extensions, discoveries and other additions	369,968	—	28	369,996
Sales in place	(1,282)	—	—	(1,282)
Production	(166,310)	(236)	(40)	(166,586)
Net proved reserves at December 31, 2019	1,693,960	266	191	1,694,417
Revisions of previous estimates	(225,375)	(19)	(18)	(225,412)
Purchases in place	2,176	—	—	2,176
Extensions, discoveries and other additions	194,724	863	—	195,587
Sales in place	(3,183)	—	—	(3,183)
Production	(149,402)	(355)	(30)	(149,787)
Net proved reserves at December 31, 2020	1,512,900	755	143	1,513,798
Natural Gas Liquids (MBbl) (2)
Net proved reserves at December 31, 2017	503,473	—	—	503,473
Revisions of previous estimates	23,942	—	—	23,942
Purchases in place	2,006	—	—	2,006
Extensions, discoveries and other additions	127,409	—	—	127,409
Sales in place	(41)	—	—	(41)
Production	(42,460)	—	—	(42,460)
Net proved reserves at December 31, 2018	614,329	—	—	614,329
Revisions of previous estimates	5,380	—	—	5,380
Purchases in place	1,948	—	—	1,948
Extensions, discoveries and other additions	167,782	—	—	167,782
Sales in place	(855)	—	—	(855)
Production	(48,892)	—	—	(48,892)
Net proved reserves at December 31, 2019	739,692	—	—	739,692
Revisions of previous estimates	(59,790)	—	—	(59,790)
Purchases in place	3,831	—	—	3,831
Extensions, discoveries and other additions	180,205	—	—	180,205
Sales in place	(1,399)	—	—	(1,399)
Production	(49,796)	—	—	(49,796)
Net proved reserves at December 31, 2020	812,743	—	—	812,743

	United States	Trinidad	Other International (1)	Total
Natural Gas (Bcf) (3)
Net proved reserves at December 31, 2017	3,898.5	313.4	51.2	4,263.1
Revisions of previous estimates	(127.2)	20.7	15.0	(91.5)
Purchases in place	41.3	—	—	41.3
Extensions, discoveries and other additions	951.4	—	4.6	956.0
Sales in place	(22.2)	—	—	(22.2)
Production	(351.2)	(97.1)	(11.2)	(459.5)
Net proved reserves at December 31, 2018	4,390.6	237.0	59.6	4,687.2
Revisions of previous estimates	(184.4)	47.0	2.6	(134.8)
Purchases in place	71.7	—	—	71.7
Extensions, discoveries and other additions	1,175.9	87.5	9.7	1,273.1
Sales in place	(14.5)	—	—	(14.5)
Production	(404.5)	(95.4)	(13.1)	(513.0)
Net proved reserves at December 31, 2019	5,034.8	276.1	58.8	5,369.7
Revisions of previous estimates	(497.7)	4.8	1.6	(491.3)
Purchases in place	26.3	—	—	26.3
Extensions, discoveries and other additions	1,077.9	53.9	—	1,131.8
Sales in place	(157.3)	—	—	(157.3)
Production	(441.4)	(65.9)	(11.6)	(518.9)
Net proved reserves at December 31, 2020	5,042.6	268.9	48.8	5,360.3
Oil Equivalents (MBoe) (2)
Net proved reserves at December 31, 2017	2,457,302	53,142	16,526	2,526,970
Revisions of previous estimates	(10,500)	3,272	2,544	(4,684)
Purchases in place	11,640	—	—	11,640
Extensions, discoveries and other additions	668,972	—	778	669,750
Sales in place	(4,509)	—	(6,310)	(10,819)
Production	(245,127)	(16,478)	(3,406)	(265,011)
Net proved reserves at December 31, 2018	2,877,778	39,936	10,132	2,927,846
Revisions of previous estimates	(68,317)	7,915	431	(59,971)
Purchases in place	16,761	—	—	16,761
Extensions, discoveries and other additions	733,730	14,577	1,661	749,968
Sales in place	(4,555)	—	—	(4,555)
Production	(282,619)	(16,130)	(2,232)	(300,981)
Net proved reserves at December 31, 2019	3,272,778	46,298	9,992	3,329,068
Revisions of previous estimates	(368,127)	773	259	(367,095)
Purchases in place	10,398	—	—	10,398
Extensions, discoveries and other additions	554,585	9,840	—	564,425
Sales in place	(30,802)	—	—	(30,802)
Production	(272,757)	(11,347)	(1,969)	(286,073)
Net proved reserves at December 31, 2020	3,166,075	45,564	8,282	3,219,921

(1)Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.

(2)Thousand barrels or thousand 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.

Net Proved Developed and Net Proved Undeveloped Oil and Gas Reserve Quantities

	United States	Trinidad	Other International (1)	Total
NET PROVED DEVELOPED RESERVES
Crude Oil (MBbl)
December 31, 2017	605,405	898	7,933	614,236
December 31, 2018	712,218	417	150	712,785
December 31, 2019	801,189	266	143	801,598
December 31, 2020	791,744	755	93	792,592
Natural Gas Liquids (MBbl)
December 31, 2017	286,872	—	—	286,872
December 31, 2018	341,386	—	—	341,386
December 31, 2019	387,253	—	—	387,253
December 31, 2020	391,708	—	—	391,708
Natural Gas (Bcf)
December 31, 2017	2,450.8	299.2	29.3	2,779.3
December 31, 2018	2,699.0	223.9	40.9	2,963.8
December 31, 2019	2,974.6	177.7	41.8	3,194.1
December 31, 2020	2,586.1	171.1	31.6	2,788.8
Oil Equivalents (MBoe)
December 31, 2017	1,300,758	50,779	12,798	1,364,335
December 31, 2018	1,503,441	37,746	6,950	1,548,137
December 31, 2019	1,684,209	29,886	7,117	1,721,212
December 31, 2020	1,614,462	29,268	5,368	1,649,098
NET PROVED UNDEVELOPED RESERVES
Crude Oil (MBbl)
December 31, 2017	698,666	—	71	698,737
December 31, 2018	819,466	—	61	819,527
December 31, 2019	892,771	—	48	892,819
December 31, 2020	721,156	—	50	721,206
Natural Gas Liquids (MBbl)
December 31, 2017	216,601	—	—	216,601
December 31, 2018	272,943	—	—	272,943
December 31, 2019	352,439	—	—	352,439
December 31, 2020	421,035	—	—	421,035
Natural Gas (Bcf)
December 31, 2017	1,447.7	14.2	21.9	1,483.8
December 31, 2018	1,691.6	13.1	18.7	1,723.4
December 31, 2019	2,060.2	98.4	17.0	2,175.6
December 31, 2020	2,456.5	97.8	17.2	2,571.5
Oil Equivalents (MBoe)
December 31, 2017	1,156,544	2,363	3,728	1,162,635
December 31, 2018	1,374,337	2,190	3,182	1,379,709
December 31, 2019	1,588,569	16,412	2,875	1,607,856
December 31, 2020	1,551,613	16,296	2,914	1,570,823

(1)Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.

Net Proved Undeveloped Reserves

The following table presents the changes in EOG's total PUDs during 2020, 2019 and 2018 (in MBoe):

	2020	2019	2018
Balance at January 1	1,607,856	1,379,709	1,162,635
Extensions and Discoveries	456,073	578,317	490,725
Revisions	(277,325)	(49,837)	(8,244)
Acquisition of Reserves	47	1,711	311
Sale of Reserves	(3,670)	—	—
Conversion to Proved Developed Reserves	(212,158)	(302,044)	(265,718)
Balance at December 31	1,570,823	1,607,856	1,379,709

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, 2020 and 2019:

	2020		2019
Proved properties	$	61,724,487	$	59,229,686
Unproved properties	3,068,311		3,600,729
Total	64,792,798		62,830,415
Accumulated depreciation, depletion and amortization	(38,750,852)		(35,033,085)
Net capitalized costs	$	26,041,946	$	27,797,330

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

The following table sets forth costs incurred related to EOG's oil and gas activities for the years ended December 31, 2020, 2019 and 2018:

	United States		Trinidad		Other International (1)		Total
2020
Acquisition Costs of Properties
Unproved (2)	$	264,778	$	—	$	—	$	264,778
Proved (3)	97,073		—		38,089		135,162
Subtotal	361,851		—		38,089		399,940
Exploration Costs	203,403		81,216		11,409		296,028
Development Costs (4)	2,998,155		4,036		20,072		3,022,263
Total	$	3,563,409	$	85,252	$	69,570	$	3,718,231
2019
Acquisition Costs of Properties
Unproved (5)	$	276,092	$	—	$	—	$	276,092
Proved (6)	379,938		—		—		379,938
Subtotal	656,030		—		—		656,030
Exploration Costs	213,505		46,616		13,218		273,339
Development Costs (7)	5,661,753		25,007		12,096		5,698,856
Total	$	6,531,288	$	71,623	$	25,314	$	6,628,225
2018
Acquisition Costs of Properties
Unproved (8)	$	486,081	$	1,258	$	—	$	487,339
Proved (9)	123,684		—		—		123,684
Subtotal	609,765		1,258		—		611,023
Exploration Costs	157,222		22,511		13,895		193,628
Development Costs (10)	5,605,264		(12,863)		22,628		5,615,029
Total	$	6,372,251	$	10,906	$	36,523	$	6,419,680

(1)Other International primarily consists of EOG's United Kingdom, China and Canada operations. EOG began an exploration program in Oman in the third quarter of 2020. The United Kingdom operations were sold in the fourth quarter of 2018.

(2)Includes non-cash unproved leasehold acquisition costs of $197 million related to property exchanges.

(3)Includes non-cash proved property acquisition costs of $15 million related to property exchanges.

(4)Includes Asset Retirement Costs of $97 million and $20 million for the United States and Other International, respectively. Excludes other property, plant and equipment.

(5)Includes non-cash unproved leasehold acquisition costs of $98 million related to property exchanges.

(6)Includes non-cash proved property acquisition costs of $52 million related to property exchanges.

(7)Includes Asset Retirement Costs of $181 million, $1 million and $4 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 $291 million related to property exchanges.

(9)Includes non-cash proved property acquisition costs of $71 million related to property exchanges.

(10)Includes Asset Retirement Costs of $90 million, $(12) million and $(8) million for the United States, Trinidad and Other International, respectively.  Excludes other property, plant and equipment.

Results of Operations for Oil and Gas Producing Activities

esults 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, 2020, 2019 and 2018:

	United States		Trinidad		Other International (2)		Total
2020
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	7,055,098	$	179,690	$	55,468	$	7,290,256
Other	60,989		(35)		—		60,954
Total	7,116,087		179,655		55,468		7,351,210
Exploration Costs	136,266		1,909		7,613		145,788
Dry Hole Costs	13,055		—		28		13,083
Transportation Costs	734,071		747		171		734,989
Gathering and Processing Costs	459,211		—		—		459,211
Production Costs	1,479,976		26,964		10,407		1,517,347
Impairments	2,018,283		815		80,682		2,099,780
Depreciation, Depletion and Amortization	3,192,000		60,328		15,747		3,268,075
Income (Loss) Before Income Taxes	(916,775)		88,892		(59,180)		(887,063)
Income Tax Provision	(220,437)		23,526		3,428		(193,483)
Results of Operations	$	(696,338)	$	65,366	$	(62,608)	$	(693,580)
2019
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	11,250,853	$	269,957	$	60,635	$	11,581,445
Other	134,325		18		15		134,358
Total	11,385,178		269,975		60,650		11,715,803
Exploration Costs	130,302		4,290		5,289		139,881
Dry Hole Costs	11,133		13,033		3,835		28,001
Transportation Costs	753,558		4,014		728		758,300
Gathering and Processing Costs	479,102		—		—		479,102
Production Costs	2,063,078		30,539		40,369		2,133,986
Impairments	510,948		5,713		1,235		517,896
Depreciation, Depletion and Amortization	3,560,609		79,156		17,832		3,657,597
Income (Loss) Before Income Taxes	3,876,448		133,230		(8,638)		4,001,040
Income Tax Provision	884,450		54,980		3,152		942,582
Results of Operations	$	2,991,998	$	78,250	$	(11,790)	$	3,058,458
2018
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	11,488,620	$	302,112	$	155,755	$	11,946,487
Other	89,708		(49)		(24)		89,635
Total	11,578,328		302,063		155,731		12,036,122
Exploration Costs	121,572		21,402		6,025		148,999
Dry Hole Costs	4,983		—		422		5,405
Transportation Costs	742,792		3,236		848		746,876
Gathering and Processing Costs (3)	404,471		—		32,502		436,973
Production Costs	1,924,504		33,506		70,073		2,028,083
Impairments	344,595		—		2,426		347,021
Depreciation, Depletion and Amortization	3,181,801		91,788		46,687		3,320,276
Income (Loss) Before Income Taxes	4,853,610		152,131		(3,252)		5,002,489
Income Tax Provision	1,086,077		12,170		1,898		1,100,145
Results of Operations	$	3,767,533	$	139,961	$	(5,150)	$	3,902,344

(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, 2020.

(2)Other International primarily consists of EOG's United Kingdom, China and Canada operations. EOG began an exploration program in Oman in the third quarter of 2020. The United Kingdom operations were sold in the fourth quarter of 2018.

(3)Effective January 1, 2018, EOG adopted the provisions of Accounting Standards Update (ASU) 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements within its United States segment as Gathering and Processing Costs instead of as a deduction to Natural Gas Revenues. There was no impact to operating income or net income resulting from changes to the presentation of natural gas processing fees (see Note 1 to Consolidated Financial Statements).

Production Costs Per Barrel of Oil Equivalent

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, 2020, 2019 and 2018:

	United States		Trinidad		Other International (1)		Composite
Year Ended December 31, 2020	$	3.75	$	2.33	$	6.78	$	3.72
Year Ended December 31, 2019	$	4.59	$	1.85	$	18.26	$	4.54
Year Ended December 31, 2018	$	4.84	$	1.67	$	20.19	$	4.84

(1)    Other International primarily consists of EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Table

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, 2020, 2019 and 2018:

	United States		Trinidad		Other International (1)		Total
2020
Future cash inflows (2)	$	73,726,893	$	900,815	$	281,658	$	74,909,366
Future production costs	(34,618,860)		(153,275)		(53,933)		(34,826,068)
Future development costs	(15,159,373)		(226,430)		(18,400)		(15,404,203)
Future income taxes	(4,336,578)		(81,368)		(24,311)		(4,442,257)
Future net cash flows	19,612,082		439,742		185,014		20,236,838
Discount to present value at 10% annual rate	(8,410,282)		(100,350)		(36,194)		(8,546,826)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	11,201,800	$	339,392	$	148,820	$	11,690,012
2019
Future cash inflows (3)	$	120,359,769	$	813,102	$	305,491	$	121,478,362
Future production costs	(42,387,801)		(166,705)		(87,381)		(42,641,887)
Future development costs	(20,355,746)		(212,303)		(18,400)		(20,586,449)
Future income taxes	(11,459,567)		(73,508)		(32,423)		(11,565,498)
Future net cash flows	46,156,655		360,586		167,287		46,684,528
Discount to present value at 10% annual rate	(21,042,593)		(86,009)		(35,161)		(21,163,763)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	25,114,062	$	274,577	$	132,126	$	25,520,765
2018
Future cash inflows (4)	$	133,066,375	$	749,695	$	303,620	$	134,119,690
Future production costs	(42,351,174)		(204,444)		(99,024)		(42,654,642)
Future development costs	(16,577,794)		(78,199)		(11,900)		(16,667,893)
Future income taxes	(14,756,011)		(174,382)		(31,748)		(14,962,141)
Future net cash flows	59,381,396		292,670		160,948		59,835,014
Discount to present value at 10% annual rate	(27,348,744)		(26,832)		(33,483)		(27,409,059)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	32,032,652	$	265,838	$	127,465	$	32,425,955

(1)Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.

(2)Estimated crude oil prices used to calculate 2020 future cash inflows for the United States, Trinidad and Other International were $37.19, $26.75, and $41.87, respectively. Estimated NGL price used to calculate 2020 future cash inflows for the United States was $12.47. Estimated natural gas prices used to calculate 2020 future cash inflows for the United States, Trinidad and Other International were $1.45, $3.28, and $5.65, respectively.

(3)Estimated crude oil prices used to calculate 2019 future cash inflows for the United States, Trinidad and Other International were $57.51, $46.77 and $57.22, respectively. Estimated NGL price used to calculate 2019 future cash inflows for the United States was $16.91. Estimated natural gas prices used to calculate 2019 future cash inflows for the United States, Trinidad and Other International were $2.07, $2.90 and $5.01, respectively.

(4)Estimated crude oil prices used to calculate 2018 future cash inflows for the United States, Trinidad and Other International were $68.54, $55.66 and $61.66, respectively. Estimated NGL price used to calculate 2018 future cash inflows for the United States was $27.83. Estimated natural gas prices used to calculate 2018 future cash inflows for the United States, Trinidad and Other International were $2.50, $3.06 and $4.88, respectively.

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

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, 2020:

	United States		Trinidad		Other International (1)		Total
December 31, 2017	$	17,756,935	$	332,427	$	238,298	$	18,327,660
Sales and transfers of oil and gas produced, net of production costs	(8,416,853)		(265,370)		(52,399)		(8,734,622)
Net changes in prices and production costs	12,750,466		84,353		21,610		12,856,429
Extensions, discoveries, additions and improved recovery, net of related costs	8,418,666		—		12,287		8,430,953
Development costs incurred	2,732,560		—		12,600		2,745,160
Revisions of estimated development cost	(410,741)		4,030		(3,814)		(410,525)
Revisions of previous quantity estimates	(173,084)		39,608		31,750		(101,726)
Accretion of discount	1,967,592		50,191		24,839		2,042,622
Net change in income taxes	(4,965,373)		3,844		(11,529)		(4,973,058)
Purchases of reserves in place	116,887		—		—		116,887
Sales of reserves in place	(35,874)		—		(82,058)		(117,932)
Changes in timing and other	2,291,471		16,755		(64,119)		2,244,107
December 31, 2018	32,032,652		265,838		127,465		32,425,955
Sales and transfers of oil and gas produced, net of production costs	(7,955,115)		(235,404)		(19,919)		(8,210,438)
Net changes in prices and production costs	(10,973,981)		65,962		27,572		(10,880,447)
Extensions, discoveries, additions and improved recovery, net of related costs	5,608,038		85,233		16,287		5,709,558
Development costs incurred	3,003,510		22,820		5,820		3,032,150
Revisions of estimated development cost	(597,869)		(129,047)		(11,108)		(738,024)
Revisions of previous quantity estimates	(812,781)		116,062		1,198		(695,521)
Accretion of discount	3,891,701		43,148		14,909		3,949,758
Net change in income taxes	1,454,050		93,975		682		1,548,707
Purchases of reserves in place	98,539		—		—		98,539
Sales of reserves in place	(50,651)		—		—		(50,651)
Changes in timing and other	(584,031)		(54,010)		(30,780)		(668,821)
December 31, 2019	25,114,062		274,577		132,126		25,520,765
Sales and transfers of oil and gas produced, net of production costs	(4,381,840)		(151,979)		(45,355)		(4,579,174)
Net changes in prices and production costs	(18,624,768)		131,859		46,916		(18,445,993)
Extensions, discoveries, additions and improved recovery, net of related costs	1,436,988		64,385		—		1,501,373
Development costs incurred	1,674,800		—		—		1,674,800
Revisions of estimated development cost	4,148,768		(11,161)		—		4,137,607
Revisions of previous quantity estimates	(3,307,180)		11,632		(1,764)		(3,297,312)
Accretion of discount	3,054,437		34,624		15,307		3,104,368
Net change in income taxes	3,497,362		(12,185)		3,022		3,488,199
Purchases of reserves in place	49,232		—		—		49,232
Sales of reserves in place	(156,293)		—		—		(156,293)
Changes in timing and other	(1,303,768)		(2,360)		(1,432)		(1,307,560)
December 31, 2020	$	11,201,800	$	339,392	$	148,820	$	11,690,012

(1)    Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.

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Unaudited Quarterly Financial Information (Tables)

12 Months Ended

Dec. 31, 2020

Quarterly Financial Information Disclosure [Abstract]

Unaudited Quarterly Financial Information

Unaudited Quarterly Financial Information

(In Thousands, Except Per Share Data)

Quarter Ended	Mar 31		Jun 30		Sep 30		Dec 31
2020
Operating Revenues and Other	$	4,717,692	$	1,103,374	$	2,245,484	$	2,965,498
Operating Income (Loss)	$	57,585	$	(1,086,549)	$	(2,714)	$	487,662
Income (Loss) Before Income Taxes	$	31,003	$	(1,145,262)	$	(52,555)	$	427,760
Income Tax Provision (Benefit)	21,190		(235,878)		(10,088)		90,294
Net Income (Loss)	$	9,813	$	(909,384)	$	(42,467)	$	337,466
Net Income (Loss) Per Share (1)
Basic	$	0.02	$	(1.57)	$	(0.07)	$	0.58
Diluted	$	0.02	$	(1.57)	$	(0.07)	$	0.58
Average Number of Common Shares
Basic	578,462		578,719		579,055		579,624
Diluted	580,283		578,719		579,055		580,885
2019
Operating Revenues and Other	$	4,058,642	$	4,697,630	$	4,303,455	$	4,320,246
Operating Income	$	876,530	$	1,130,771	$	827,959	$	863,751
Income Before Income Taxes	$	827,236	$	1,089,366	$	797,457	$	831,208
Income Tax Provision	191,810		241,525		182,335		194,687
Net Income	$	635,426	$	847,841	$	615,122	$	636,521
Net Income Per Share (1)
Basic	$	1.10	$	1.47	$	1.06	$	1.10
Diluted	$	1.10	$	1.46	$	1.06	$	1.10
Average Number of Common Shares
Basic	577,207		577,460		577,839		578,219
Diluted	580,222		580,247		581,271		580,849

(1)The sum of quarterly net income (loss) per share may not agree with total year net income (loss) per share as each quarterly computation is based on the weighted average of common shares outstanding.

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Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020		Dec. 31, 2019		Dec. 31, 2018
Total Operating Revenues and Other	$ 2,965,498	$ 2,245,484	$ 1,103,374	$ 4,717,692	$ 4,320,246	$ 4,303,455	$ 4,697,630	$ 4,058,642	$ 11,032,048		$ 17,379,973		$ 17,275,399
Gathering and Processing Costs									459,211	[1]	479,102	[1]	436,973
Marketing Costs									2,697,729		5,351,524		5,203,243
Total Operating Expenses									11,576,064		13,680,962		12,806,053
Operating Income	487,662	$ (2,714)	$ (1,086,549)	$ 57,585	863,751	$ 827,959	$ 1,130,771	$ 876,530	(544,016)		3,699,011		4,469,346
Accounts Receivable From Contracts With Customers	1,337,000				$ 1,619,000				1,337,000		1,619,000		1,460,000
Revolving Credit Agreement (New Facility)
Maximum borrowing capacity	$ 2,000,000								2,000,000
Crude Oil and Condensate
Revenues									5,785,609		9,612,532		9,517,440
Natural Gas Liquids
Revenues									667,514		784,818		1,127,510
Natural Gas
Revenues									837,133		1,184,095		1,301,537
Gathering, Processing and Marketing
Revenues									$ 2,582,984		$ 5,360,282		5,230,355
Accounting Standards Update 2014-09 [Member]
Total Operating Revenues and Other													17,052,465
Gathering and Processing Costs													233,258
Marketing Costs													5,184,024
Total Operating Expenses													12,583,119
Operating Income													4,469,346
Accounting Standards Update 2014-09 [Member] | Crude Oil and Condensate
Revenues													9,517,440
Accounting Standards Update 2014-09 [Member] | Natural Gas Liquids
Revenues													1,121,237
Accounting Standards Update 2014-09 [Member] | Natural Gas
Revenues													1,104,095
Accounting Standards Update 2014-09 [Member] | Gathering, Processing and Marketing
Revenues													5,211,136
Effect of Change [Member]
Total Operating Revenues and Other													222,934
Gathering and Processing Costs													203,715
Marketing Costs													19,219
Total Operating Expenses													222,934
Operating Income													0
Effect of Change [Member] | Crude Oil and Condensate
Revenues													0
Effect of Change [Member] | Natural Gas Liquids
Revenues													6,273
Effect of Change [Member] | Natural Gas
Revenues													197,442
Effect of Change [Member] | Gathering, Processing and Marketing
Revenues													$ 19,219

[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, 2020.

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Long-Term Debt (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Long-Term Debt	$ 5,640,000	$ 5,140,000
Capital Lease Obligation	212,217	57,900
Less: Current Portion of Long-Term Debt	781,054	1,014,524
Unamortized Debt Discount	30,931	19,528
Debt Issuance Costs	4,881	2,929
Total Long-Term Debt	5,035,351	4,160,919
Long-Term Debt by Maturity [Abstract]
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2021	750,000
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2022	0
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2023	1,250,000
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
Line of Credit Facility [Line Items]
Proceeds from Debt, Net of Issuance Costs	$ 1,480,000
Revolving Credit Agreement 2020
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Date	Jul. 21, 2020
Maximum borrowing capacity	$ 2,000,000
Senior Unsecured Revolving Credit Agreement Due 2024 [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Date	Jun. 27, 2024
Line Of Credit Facility Increase Additional Borrowings	$ 3,000,000
Maximum borrowing capacity	$ 2,000,000
Maximum total debt-to-total capitalization ratio allowed under financial covenant (in hundredths)	65.00%
Line of Credit Facility, Maximum Amount Outstanding During Period	$ 0	0
Senior Unsecured Revolving Credit Agreement Due 2024 [Member] | Eurodollar [Member]
Line of Credit Facility [Line Items]
Effective Interest Rate (in hundredths)	1.04%
Senior Unsecured Revolving Credit Agreement Due 2024 [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Effective Interest Rate (in hundredths)	3.25%
Commercial Paper
Line of Credit Facility [Line Items]
Current Borrowings Outstanding	$ 0	0
4.40% Senior Notes Due 2020
Debt Instrument [Line Items]
Long-Term Debt	0	500,000
Debt Instrument Issuance Face Amount	$ 500,000
Debt Instrument Issuance Interest Rate	4.40%
2.45% Senior Notes due 2020
Debt Instrument [Line Items]
Long-Term Debt	$ 0	500,000
Debt Instrument Issuance Face Amount	$ 500,000
Debt Instrument Issuance Interest Rate	2.45%
4.100% Senior Notes due 2021
Debt Instrument [Line Items]
Long-Term Debt	$ 750,000	750,000
Debt Instrument Issuance Face Amount	$ 750,000
Debt Instrument Issuance Interest Rate	4.10%
2.625% Senior Notes due 2023
Debt Instrument [Line Items]
Long-Term Debt	$ 1,250,000	1,250,000
4.15% Senior Notes due 2026
Debt Instrument [Line Items]
Long-Term Debt	750,000	750,000
3.15% Senior Notes due 2025
Debt Instrument [Line Items]
Long-Term Debt	500,000	500,000
6.65% Senior Notes due 2028
Debt Instrument [Line Items]
Long-Term Debt	140,000	140,000
4.375% Senior Notes due 2030
Debt Instrument [Line Items]
Long-Term Debt	750,000	0
Debt Instrument Issuance Face Amount	$ 750,000
Debt Instrument Issuance Interest Rate	4.375%
3.90% Senior Notes due 2035
Debt Instrument [Line Items]
Long-Term Debt	$ 500,000	500,000
4.95% Senior Notes due 2050
Debt Instrument [Line Items]
Long-Term Debt	750,000	0
Debt Instrument Issuance Face Amount	$ 750,000
Debt Instrument Issuance Interest Rate	4.95%
5.10% Senior Notes due 2036
Debt Instrument [Line Items]
Long-Term Debt	$ 250,000	250,000
5.625% Senior Notes Due 2019
Debt Instrument [Line Items]
Debt Instrument Issuance Face Amount		$ 900,000
Debt Instrument Issuance Interest Rate		5.625%

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Stockholder's Equity (Details) - $ / shares			12 Months Ended
		Feb. 25, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Stockholders' Equity Note [Abstract]
An aggregate maximum of shares of common stock authorized for repurchase			10,000,000
Remaining shares available for purchase under share repurchase authorization			6,386,200
Dividends Common Stock Declared Per Share		$ 0.375	$ 0.2875	$ 0.22	$ 0.1850
Dividends Payable, Amount Per Share After Increase		$ 0.4125	$ 0.375	$ 0.2875	$ 0.22	$ 0.1675
Common Stock, Shares Authorized			1,280,000,000	1,280,000,000
Common Stock Activity [Line Items]
Beginning Balance (in shares)			582,213,016
Ending Balance (in shares)			583,694,850	582,213,016
Preferred Stock, Shares Outstanding			0
Common Shares, Outstanding [Member]
Common Stock Activity [Line Items]
Beginning Balance (in shares)			581,914,000	580,023,000	578,477,000
Common Stock Issued Under Stock-Based Compensation Plans (in shares)			1,482,000	1,688,000	1,580,000
Treasury Stock Purchased (1) (in shares)	[1]		(389,000)	(310,000)	(539,000)
Common Stock Issued Under Employee Stock Purchase Plan (in shares)			377,000	223,000	180,000
Treasury Stock Issued Under Stock-Based Compensation Plans (in shares)			187,000	290,000	325,000
Ending Balance (in shares)			583,571,000	581,914,000	580,023,000	578,477,000
Common Shares, Treasury [Member]
Common Stock Activity [Line Items]
Beginning Balance (in shares)			(299,000)	(385,000)	(351,000)
Common Stock Issued Under Stock-Based Compensation Plans (in shares)			0	0	0
Treasury Stock Purchased (1) (in shares)	[1]		(389,000)	(310,000)	(539,000)
Common Stock Issued Under Employee Stock Purchase Plan (in shares)			377,000	106,000	180,000
Treasury Stock Issued Under Stock-Based Compensation Plans (in shares)			187,000	290,000	325,000
Ending Balance (in shares)			(124,000)	(299,000)	(385,000)	(351,000)
Common Shares, Issued [Member]
Common Stock Activity [Line Items]
Beginning Balance (in shares)			582,213,000	580,408,000	578,828,000
Common Stock Issued Under Stock-Based Compensation Plans (in shares)			1,482,000	1,688,000	1,580,000
Treasury Stock Purchased (1) (in shares)	[1]		0	0	0
Common Stock Issued Under Employee Stock Purchase Plan (in shares)			0	117,000	0
Treasury Stock Issued Under Stock-Based Compensation Plans (in shares)			0	0	0
Ending Balance (in shares)			583,695,000	582,213,000	580,408,000	578,828,000

[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.

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Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss)	$ (12,328)	$ (4,652)
Cumulative effect of accounting changes	267	0
Other Comprehensive Loss	(7,676)	(3,561)	$ 17,939
Significant Amount Reclassified Out of AOCI	0	0	0
Foreign Currency Translation Adjustment
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss)	(10,055)	(2,709)	174
Cumulative effect of accounting changes		0
Other comprehensive loss before taxes	(7,346)	(2,883)
Tax Effects	0	0
Other Comprehensive Loss	(7,346)	(2,883)
Other
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss)	(2,273)	(1,943)	(1,532)
Cumulative effect of accounting changes		267
Other comprehensive loss before taxes	(183)	(533)
Tax Effects	(147)	(145)
Other Comprehensive Loss	(330)	(678)
Accumulated Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss)	(12,328)	(4,652)	(1,358)
Cumulative effect of accounting changes		267
Other comprehensive loss before taxes	(7,529)	(3,416)
Tax Effects	(147)	(145)
Other Comprehensive Loss	$ (7,676)	$ (3,561)	$ 17,939

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Other Income, Net (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Other Income and Expenses [Abstract]
Interest income	$ 12	$ 26	$ 12
Equity income (loss) from investments in Trinidad	$ (2)		2
Net Foreign Currency Transaction Gains (Losses)		$ 2	(7)
Adjustment to Deferred Compensation Expense			$ 6

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Employee Benefit Plans (Details)			12 Months Ended
		Feb. 01, 2021 shares	Dec. 31, 2020 USD ($) $ / shares shares		Dec. 31, 2019 USD ($) $ / shares shares		Dec. 31, 2018 USD ($) $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense related to the company's stock-based compensation plans | $			$ 146,396,000		$ 174,738,000		$ 155,337,000
Common Shares Available for Grant			2,000,000.0
Share-based Payment Arrangement, Expense, Tax Benefit | $			$ (22,000,000)		(1,000,000)		20,000,000
Stock Options and Sars [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum term of stock options and SARs granted			7 years
Share-based Compensation Expense Related To Stock Options, SAR and ESPP Grants | $			$ 62,000,000		$ 63,000,000		$ 60,000,000
Unrecognized compensation expense | $			$ 53,000,000
Stock Options/SARs Vested or Expected to Vest (in shares)			9,900,000
Intrinsic value of stock options/SARs vested or expected to vest | $			$ 22,500,000
Weighted Average Remaining Contractual Life for Stock Options/SARs Vested or Expected to Vest			4 years 2 months 12 days
Weighted average period over which unrecognized compensation expense will be recognized			2 years 1 month 6 days
Weighted average grant price for stock options/SARs vested or expected to vest (per share) | $ / shares			$ 84.76
Stock Options and SARs Rollforward [Abstract]
Outstanding at January 1 (in shares)			9,395,000		8,310,000		9,103,000
Granted (in shares)			1,996,000		1,965,000		1,906,000
Exercised (1) (in shares)	[1]		(23,000)		(606,000)		(2,493,000)
Forfeited (in shares)			(1,182,000)		(274,000)		(206,000)
Outstanding at December 31 (in shares)			10,186,000		9,395,000		8,310,000
Stock Options/SARs Exercisable at December 31 (in shares)			6,343,000		5,275,000		3,969,000
Intrinsic Value Of Stock Options/SARs Exercised During The Period | $			$ 400,000		$ 14,000,000		$ 118,000,000
Weighted Average Grant Price Stock Option and SARs [Rollfoward]
Outstanding at January 1 (in dollars per share) | $ / shares			$ 94.53		$ 96.90		$ 83.89
Granted (in dollars per share) | $ / shares			37.63		75.39		126.49
Exercised (in dollars per share) | $ / shares	[1]		69.59		61.43		72.21
Forfeited (in dollars per share) | $ / shares			88.93		102.57		94.43
Outstanding at December 31 (in dollars per share) | $ / shares			84.08		94.53		96.90
Stock Options/SARs Exercisable at December 31 (in dollars per share) | $ / shares			96.41		94.21		85.82
Weighted Average Fair Value And Valuation Assumptions Used To Value Stock Options/SARs, ESPP, and Performance Units/Stock-Based Compensation [Abstract]
Weighted Average Fair Value of Grants (price per share) | $ / shares			$ 11.06		$ 19.49		$ 33.46
Expected Volatility (in hundredths)			44.47%		32.02%		28.23%
Risk-Free Interest Rate (in hundredths)			0.21%		1.69%		2.68%
Dividend Yield (in hundredths)			3.27%		1.39%		0.72%
Expected Life (in years)			5 years 2 months 12 days		5 years 1 month 6 days		5 years
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			10,186,000
Weighted Average Remaining Life for Outstanding Options and SARs			4 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 84.08
Aggregate Intrinsic Value For Outstanding Options and SARs | $	[2]		$ 24,578
Stock Options and SARs Exercisable			6,343,000
Weighted Average Remaining Life For Exercisable Units			3 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 96.41
Aggregate Intrinsic Value For Exercisable Units | $	[2]		$ 124
Stock Options and Sars [Member] | Vesting Schedule - First Anniversary [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period Increments (in hundredths)			33.30%
Stock Options and Sars [Member] | Vesting Schedule - Second Anniversary [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period Increments (in hundredths)			33.30%
Stock Options and Sars [Member] | Vesting Schedule - Third Anniversary [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period Increments (in hundredths)			33.40%
ESPP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common Shares Available for Grant			1,900,000
Maximum Percentage Of Employee Pay Eligible For Contribution To ESPP Percentage			10.00%
Percentage of fair market value at which employees may purchase company stock via the ESPP			85.00%
Employee Stock Purchase Plan (ESPP) Disclosures [Abstract]
Aggregate Purchase Price | $			$ 16,103,000		$ 16,533,000		$ 14,887,000
Shares Purchased			377,000		224,000		180,000
Approximate Number of Participants			2,063		1,998		1,934
Weighted Average Fair Value And Valuation Assumptions Used To Value Stock Options/SARs, ESPP, and Performance Units/Stock-Based Compensation [Abstract]
Weighted Average Fair Value of Grants (price per share) | $ / shares			$ 19.14		$ 22.83		$ 25.75
Expected Volatility (in hundredths)			53.48%		34.78%		24.59%
Risk-Free Interest Rate (in hundredths)			0.90%		2.27%		1.89%
Dividend Yield (in hundredths)			2.27%		1.04%		0.64%
Expected Life (in years)			6 months		6 months		6 months
Restricted Stock and Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-Based Compensation Expense | $			$ 75,000,000		$ 97,000,000		$ 81,000,000
Intrinsic value released during the year | $			48,000,000		70,000,000		84,000,000
Aggregate intrinsic value of stock and unit outstanding | $			236,000,000		$ 381,000,000		$ 331,000,000
Unrecognized compensation expense | $			$ 178,000,000
Weighted average period over which unrecognized compensation expense will be recognized			1 year 7 months 6 days
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period			3 years
Number of Shares and Units [Roll Forward]
Outstanding at January 1 (in shares)			4,546,000	[3]	3,792,000	[3]	3,905,000
Granted (in shares)			1,488,000		1,749,000		812,000
Released (in shares)	[4]		(1,213,000)		(855,000)		(740,000)
Forfeited (in shares)			(79,000)		(140,000)		(185,000)
Outstanding at December 31 (in shares)	[3]		4,742,000		4,546,000		3,792,000
Weighted Average Grant Fair Value [Abstract]
Outstanding at January 1 (in dollars per share) | $ / shares			$ 90.16	[3]	$ 96.64	[3]	$ 88.57
Granted (in dollars per share) | $ / shares			38.10		80.01		117.55
Released (in dollars per share) | $ / shares	[4]		85.92		96.93		78.16
Forfeited (in dollars per share) | $ / shares			86.52		97.54		92.12
Outstanding at December 31 (in dollars per share) | $ / shares	[3]		$ 74.97		$ 90.16		$ 96.64
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense related to the company's stock-based compensation plans | $			$ 9,000,000		$ 15,000,000		$ 14,000,000
Intrinsic value released during the year | $			13,000,000		15,000,000		18,000,000
Aggregate intrinsic value of stock and unit outstanding | $			31,000,000		$ 50,000,000		$ 47,000,000
Unrecognized compensation expense | $			$ 5,000,000
Weighted average period over which unrecognized compensation expense will be recognized			1 year 10 months 24 days
Cliff Vesting Period			41 months
Number of Shares and Units [Roll Forward]
Outstanding at January 1 (in shares)			598,000	[5]	539,000	[5]	502,000
Granted (in shares)			172,000		172,000		113,000
Granted for Performance Multiple (1) (in shares)	[6]		66,000		72,000		72,000
Released (in shares)	[7]		(223,000)		(185,000)		(148,000)
Forfeited (in shares)			0		0		0
Outstanding at December 31 (in shares)	[5]		613,000	[8]	598,000		539,000
Weighted Average Grant Fair Value [Abstract]
Outstanding at January 1 (in dollars per share) | $ / shares			$ 92.19	[5]	$ 101.53	[5]	$ 90.96
Granted (in dollars per share) | $ / shares			37.44		75.09		125.73
Granted for Performance Multiple (1) (in dollars per share) | $ / shares	[6]		100.95		69.43		101.87
Released (in dollars per share) | $ / shares	[7]		88.52		94.63		84.43
Forfeited (in dollars per share) | $ / shares			0		0		0
Outstanding at December 31 (in dollars per share) | $ / shares	[5]		79.10		92.19		101.53
Weighted Average Fair Value And Valuation Assumptions Used To Value Stock Options/SARs, ESPP, and Performance Units/Stock-Based Compensation [Abstract]
Weighted Average Fair Value of Grants (price per share) | $ / shares			$ 42.77		$ 79.98		$ 136.74
Expected Volatility (in hundredths)			47.27%		29.20%		29.92%
Risk-Free Interest Rate (in hundredths)			0.16%		1.51%		2.85%
Performance Units and Performance Stock [Abstract]
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%
Performance Multiple Applied at the Completion Period		125.00%	150.00%		200.00%		200.00%
Minimum Performance Units and Stock Allowed to be Outstanding			77
Maximum Performance Units and Stock Allowed to be Outstanding			1,149
Maximum Performance Multiple Applied at the Completion Period					200.00%		200.00%
Additional Performance Awards Granted		19,629
Pension Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total pension plan costs | $			$ 46,000,000		$ 51,000,000		$ 43,000,000
Company contributions to foreign pension plans | $			1,000,000		1,000,000		1,000,000
Defined Benefit Plan, Benefit Obligation | $			13,000,000		12,000,000
Fair value of foreign pension plan assets | $			12,000,000		10,000,000
Accrued benefit cost | $			(100,000)		(100,000)
Lease And Well [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense related to the company's stock-based compensation plans | $			52,000,000		56,000,000		51,000,000
Gathering And Processing Costs [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense related to the company's stock-based compensation plans | $			1,000,000		1,000,000		1,000,000
Exploration Costs [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense related to the company's stock-based compensation plans | $			21,000,000		26,000,000		25,000,000
General And Administrative [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense related to the company's stock-based compensation plans | $			$ 72,000,000		$ 92,000,000		$ 78,000,000
$ 34.00 to $  43.99 | Stock Options and Sars [Member]
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			1,974,000
Weighted Average Remaining Life for Outstanding Options and SARs			7 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 37.43
Stock Options and SARs Exercisable			10,000
Weighted Average Remaining Life For Exercisable Units			1 year
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 37.44
44.00 to     74.99 | Stock Options and Sars [Member]
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			872,000
Weighted Average Remaining Life for Outstanding Options and SARs			2 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 69.37
Stock Options and SARs Exercisable			846,000
Weighted Average Remaining Life For Exercisable Units			2 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 69.47
75.00 to     75.99 | Stock Options and Sars [Member]
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			1,863,000
Weighted Average Remaining Life for Outstanding Options and SARs			6 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 75.09
Stock Options and SARs Exercisable			636,000
Weighted Average Remaining Life For Exercisable Units			5 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 75.09
76.00 to     95.99 | Stock Options and Sars [Member]
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			1,242,000
Weighted Average Remaining Life for Outstanding Options and SARs			3 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 94.47
Stock Options and SARs Exercisable			1,215,000
Weighted Average Remaining Life For Exercisable Units			3 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 94.63
96.00 to   101.99 | Stock Options and Sars [Member]
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			2,477,000
Weighted Average Remaining Life for Outstanding Options and SARs			3 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 97.95
Stock Options and SARs Exercisable			2,457,000
Weighted Average Remaining Life For Exercisable Units			3 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 97.95
102.00 to   129.99 | Stock Options and Sars [Member]
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			1,758,000
Weighted Average Remaining Life for Outstanding Options and SARs			5 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 126.44
Stock Options and SARs Exercisable			1,179,000
Weighted Average Remaining Life For Exercisable Units			5 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 126.37

[1] The total intrinsic value of stock options/SARs exercised during the years 2020, 2019 and 2018 was $0.4 million, $14 million and $118 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.

[2] 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 thousands.

[3] The total intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2020, 2019 and 2018 was $236 million, $381 million and $331 million, respectively. The intrinsic value is based on the closing market price of the Common Stock on the last trading day of the year.

[4] The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2020, 2019 and 2018 was $48 million, $70 million and $84 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.

[5] The total intrinsic value of Performance Awards outstanding at December 31, 2020, 2019 and 2018 was $31 million, $50 million and $47 million, respectively. The intrinsic value is based on the closing market price of the Common Stock on the last trading day of the year.

[6] Upon completion of the Performance Period for the Performance Awards granted in 2016, 2015 and 2014, a performance multiple of 150%, 200% and 200%, respectively, was applied to each of the grants resulting in additional grants of Performance Awards in February 2020, 2019 and 2018.

[7] The total intrinsic value of Performance Awards released during the years ended December 31, 2020, 2019 and 2018 was $13 million, $15 million and $18 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date Performance Awards are released.

[8] Upon the application of the relevant performance multiple at the completion of each of the remaining Performance Periods, a minimum of 77 and a maximum of 1,149 Performance Awards could be outstanding.

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Income Taxes (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2020		Dec. 31, 2019		Dec. 31, 2018
Current income tax provision (benefit) [Abstract]
Federal		$ (107,834)		$ (152,258)		$ (303,853)
State		6,790		10,819		17,048
Foreign		40,248		81,426		65,615
Total		(60,796)		(60,013)		(221,190)
Deferred income tax provision (benefit) [Abstract]
Federal		(153,027)		626,901		862,075
State		(15,400)		32,541		43,293
Foreign		(17,963)		(27,784)		(11,212)
Total		(186,390)		631,658		894,156
Other Non-Current (1)
Federal		112,704	[1]	245,125	[2]	148,992	[1]
Other Noncurrent Foreign Income Tax		0		(6,413)		0
Total		112,704		238,712		148,992
Income Tax Provision (Benefit)		(134,482)		810,357		$ 821,958
Deferred Tax Assets, Net of Valuation Allowance, Noncurrent Classification [Abstract]
Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization		25,129		5,825
Foreign Net Operating Loss		74,280		66,675
Foreign Valuation Allowances		(97,499)		(70,455)
Foreign Other		217		318
Total Net Noncurrent Deferred Income Tax Assets		2,127		2,363
Deferred tax liabilities net noncurrent classification [Abstract]
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization		5,028,010		5,277,550
Commodity Hedging Contracts		14,518		(4,699)
Deferred Compensation Plans		(42,594)		(47,650)
Accrued Expenses and Liabilities		0		(8,502)
Equity Awards		(102,944)		(108,324)
Alternative Minimum Tax Credit Carryforward		0		(31,904)
Undistributed Foreign Earnings		9,843		15,746
Other		(47,506)		(46,116)
Total Net Noncurrent Deferred Income Tax Liabilities		4,859,327		5,046,101
Total Net Deferred Income Tax Liabilities		$ 4,857,200		$ 5,043,738
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Statutory Federal Income Tax Rate (in hundredths)		21.00%		21.00%		21.00%
State Income Tax, Net of Federal Benefit (in hundredths)		0.92%		0.97%		1.12%
Income Tax Provision Related to Foreign Operations (in hundredths)		(0.09%)		0.87%		0.51%
Income Tax Provision Related to Canadian Operations (in hundredths)		(2.43%)		0.00%		0.00%
TCJA (in hundredths)		0.00%		0.00%	[3],[4]	(2.60%)	[4]
Shared-Based Compensation (in hundredths)		(2.94%)		0.02%		(0.47%)
Other (in hundredths)		1.74%		0.00%		(0.18%)
Effective Income Tax Rate (in hundredths)		18.20%		22.86%		19.38%
Tax NOLs (in hundredths)						(1.20%)
Sequestration (in hundredths)						(1.00%)
Other Tax Reform Impacts (in hundredths)						(0.40%)
Income Tax Disclosure [Abstract]
Balance of state net operating loss expected to be carried forward		$ 1,900,000
Canadian Net Operating Loss Carryforwards		275,000
Unrecognized Tax Benefits Balance		10,000
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense		0
Foreign and State Deferred Income Taxes		10,000
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities		29,000
Earnings Decrease Due to Settlement of Uncertain Tax Positions		5,000
Results of Operations, Income before Income Taxes [Abstract]
United States		(756,479)		$ 3,466,578		$ 4,084,156
Foreign		17,425		78,689		156,842
Income (Loss) Before Income Taxes		(739,054)		3,545,267		4,240,998
Valuation Allowance [Abstract]
Beginning Balance		200,831		167,142		466,421
Increase	[5]	25,573		30,673		23,062
Decrease	[6]	(11,343)		(75)		(26,219)
Other	[7]	3,942		3,091		(296,122)
Ending Balance		$ 219,003		$ 200,831		$ 167,142

[1] Includes changes in certain amounts that are expected to be paid or received beyond the next twelve months. The primary component is refundable alternative minimum tax (AMT) credits.

[2] Includes changes in certain amounts that are expected to be paid or received beyond the next twelve months. The primary component is refundable alternative minimum tax (AMT) credits.

[3] Includes impact of utilizing certain tax net operating losses (NOLs) ((1.2)%), the reversal of the federal sequestration charge ((1.0)%) and other TCJA impacts ((0.4)%).

[4] The Tax Cuts and Jobs Act (TCJA) was enacted in 2017 and required certain measurement-period adjustments in 2018.

[5] Increase in valuation allowance related to the generation of tax NOLs and other deferred tax assets.

[6] Decrease in valuation allowance associated with adjustments to certain deferred tax assets and their related allowances.

[7] Represents dispositions, revisions and/or foreign exchange rate variances and the effect of statutory income tax rate changes. The United Kingdom operations were sold in the fourth quarter of 2018.

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Commitments and Contingencies (Details) - USD ($)	Feb. 18, 2021	Dec. 31, 2020	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Standby letters of credit and guarantees outstanding		$ 854,000,000	$ 902,000,000
Total Minimum Commitments [Abstract]
2021		1,393,000,000
2022		1,263,000,000
2023		1,064,000,000
2024		790,000,000
2025		649,000,000
2026 and beyond		2,764,000,000
Total Minimum Commitments		$ 7,923,000,000
Subsidiary guarantees demand for payment	$ 0

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Net Income (Loss) Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2020		Sep. 30, 2020		Jun. 30, 2020		Mar. 31, 2020		Dec. 31, 2019		Sep. 30, 2019		Jun. 30, 2019		Mar. 31, 2019		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Numerator for Basic and Diluted Earnings per Share - [Abstract]
Net Income (Loss)	$ 337,466		$ (42,467)		$ (909,384)		$ 9,813		$ 636,521		$ 615,122		$ 847,841		$ 635,426		$ (604,572)	$ 2,734,910	$ 3,419,040
Denominator for Basic Earnings per Share - [Abstract]
Weighted Average Shares	579,624		579,055		578,719		578,462		578,219		577,839		577,460		577,207		578,949	577,670	576,578
Denominator for Diluted Earnings per Share - [Abstract]
Adjusted Diluted Weighted Average Shares	580,885		579,055		578,719		580,283		580,849		581,271		580,247		580,222		578,949	580,777	580,441
Antidilutive Securities Excluded from Computation of Earnings Per Share [Abstract]
Anti-dilutive Securities excluded from Diluted Earnings Per Share Calculation																	9,600	6,100	600
Net Income (Loss) Per Share [Abstract]
Basic	$ 0.58	[1]	$ (0.07)	[1]	$ (1.57)	[1]	$ 0.02	[1]	$ 1.10	[1]	$ 1.06	[1]	$ 1.47	[1]	$ 1.10	[1]	$ (1.04)	$ 4.73	$ 5.93
Diluted	$ 0.58	[1]	$ (0.07)	[1]	$ (1.57)	[1]	$ 0.02	[1]	$ 1.10	[1]	$ 1.06	[1]	$ 1.46	[1]	$ 1.10	[1]	$ (1.04)	$ 4.71	$ 5.89
Stock Options and Sars [Member]
Potential Dilutive Common Shares -[Abstract]
Common Shares Attributable to Dilutive Effect of Share-Based Payment Arrangments																	0	258	1,137
Restricted Stock/Units and Performance Units/Stock [Member]
Potential Dilutive Common Shares -[Abstract]
Common Shares Attributable to Dilutive Effect of Share-Based Payment Arrangments																	0	2,849	2,726
Antidilutive Securities Excluded from Computation of Earnings Per Share [Abstract]
Anti-dilutive Securities excluded from Diluted Earnings Per Share Calculation																	5,000

[1] The sum of quarterly net income (loss) per share may not agree with total year net income (loss) per share as each quarterly computation is based on the weighted average of common shares outstanding.

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Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Supplemental Cash Flow Information [Abstract]
Interest, Net of Capitalized Interest	$ 205,447	$ 186,546	$ 243,279
Income Taxes, Net of Refunds Received	(205,795)	(291,849)	75,634
Accrued Capital Expenditures	414,000	612,000	592,000
Non-cash investing and financing activities from property exchanges.	212,000	$ 150,000	362,000
Non-cash investing activities from other, property, plant and equipment	174,000		$ 49,000
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2024	$ 0

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Business Segment Information (Details) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020		Dec. 31, 2019		Dec. 31, 2018
Schedule of Segment Reporting Information By Segment [Abstract]
Operating Revenues and Other		$ 2,965,498	$ 2,245,484	$ 1,103,374	$ 4,717,692	$ 4,320,246	$ 4,303,455	$ 4,697,630	$ 4,058,642	$ 11,032,048		$ 17,379,973		$ 17,275,399
Depreciation, Depletion and Amortization										3,400,353		3,749,704		3,435,408
Operating Income (Loss)		487,662	(2,714)	(1,086,549)	57,585	863,751	827,959	1,130,771	876,530	(544,016)		3,699,011		4,469,346
Interest Income										11,739		26,026		11,546
Other Income										(1,511)		5,359		5,158
Net Interest Expense										205,266		185,129		245,052
Income (Loss) Before Income Taxes										(739,054)		3,545,267		4,240,998
Income Tax Provision (Benefit)		90,294	$ (10,088)	$ (235,878)	$ 21,190	194,687	$ 182,335	$ 241,525	$ 191,810	(134,482)		810,357		821,958
Additions to Oil and Gas Properties, Excluding Dry Hole Costs										3,441,858		6,273,952		6,195,330
Total Property, Plant and Equipment, Net		28,598,627				30,364,595				28,598,627		30,364,595		28,075,519
Total Assets		35,804,601				37,124,608				35,804,601		37,124,608		33,934,474
Pretax Impairment Charges For Other Assets		228,000								228,000
Crude Oil and Condensate
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										5,785,609		9,612,532		9,517,440
Natural Gas Liquids
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										667,514		784,818		1,127,510
Natural Gas
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										837,133		1,184,095		1,301,537
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										1,144,737		180,275		(165,640)
Gathering, Processing and Marketing
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										2,582,984		5,360,282		5,230,355
Gains (Losses) on Asset Dispositions, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										(46,883)		123,613		174,562
Other, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										60,954		134,358		89,635
United States
Schedule of Segment Reporting Information By Segment [Abstract]
Operating Revenues and Other										10,795,299	[1]	17,052,363	[2]	16,794,591	[3]
Depreciation, Depletion and Amortization										3,323,800		3,652,294		3,296,499
Operating Income (Loss)										(545,566)		3,618,907		4,334,364
Interest Income										10,783		22,122		9,326
Other Income										153		3,235
Other Expense														9,580
Net Interest Expense										205,266		192,587		253,352
Income (Loss) Before Income Taxes										(739,896)		3,451,677		4,099,918
Income Tax Provision (Benefit)										(156,834)		760,881		765,986
Additions to Oil and Gas Properties, Excluding Dry Hole Costs										3,316,724		6,208,394		6,155,874
Total Property, Plant and Equipment, Net		28,283,027				30,101,857				28,283,027		30,101,857		27,786,086
Total Assets		35,047,485				36,274,942				35,047,485		36,274,942		33,178,733
Amount of sales with a single significant purchaser in the United States segment										1,100,000		2,400,000		2,600,000
Amount of sales with a second significant purchaser in the United States segment.												2,200,000		2,300,000
Pretax Impairment Charges For Proved Oil And Gas Properties And Other Property Plant And Equipment										1,570,000
Pretax Impairment Charges For Other Assets		228,000								228,000
United States | Crude Oil and Condensate
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										5,773,582		9,599,125		9,390,244
United States | Natural Gas Liquids
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										667,514		784,818		1,127,510
United States | Natural Gas
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										614,002		866,911		970,866
United States | Gains (Losses) on Mark-to-Market Commodity Derivative Contracts
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										1,144,737		180,275		(165,640)
United States | Gathering, Processing and Marketing
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										2,581,493		5,355,463		5,227,051
United States | Gains (Losses) on Asset Dispositions, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										(47,018)		131,446		154,852
United States | Other, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										60,989		134,325		89,708
Trinidad
Schedule of Segment Reporting Information By Segment [Abstract]
Operating Revenues and Other										181,102		271,106		309,860
Depreciation, Depletion and Amortization										60,629		79,389		91,971
Operating Income (Loss)										74,801		112,790		147,240
Interest Income										922		3,686		1,612
Other Income										(2,129)		727		2,436
Net Interest Expense										0		0		0
Income (Loss) Before Income Taxes										73,594		117,203		151,288
Income Tax Provision (Benefit)										14,568		40,901		54,272
Additions to Oil and Gas Properties, Excluding Dry Hole Costs										83,173		53,325		1,618
Total Property, Plant and Equipment, Net		210,278				184,606				210,278		184,606		210,183
Total Assets		546,120				705,747				546,120		705,747		629,633
Trinidad | Crude Oil and Condensate
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										10,723		11,138		17,059
Trinidad | Natural Gas Liquids
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										0		0		0
Trinidad | Natural Gas
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										168,967		258,819		285,053
Trinidad | Gains (Losses) on Mark-to-Market Commodity Derivative Contracts
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										0		0		0
Trinidad | Gathering, Processing and Marketing
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										1,491		4,819		3,304
Trinidad | Gains (Losses) on Asset Dispositions, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										(44)		(3,688)		4,493
Trinidad | Other, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										(35)		18		(49)
Other International
Schedule of Segment Reporting Information By Segment [Abstract]
Operating Revenues and Other	[4]									55,647		56,504		170,948
Depreciation, Depletion and Amortization	[4]									15,924		18,021		46,938
Operating Income (Loss)	[4]									(73,251)		(32,686)		(12,258)
Interest Income	[4]									34		218		608
Other Income										465				(6,858)	[4]
Other Expense	[4]											1,397
Net Interest Expense	[4]									0		(7,458)		(8,300)
Income (Loss) Before Income Taxes	[4]									(72,752)		(23,613)		(10,208)
Income Tax Provision (Benefit)	[4]									7,784		8,575		1,700
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	[4]									41,961		12,233		37,838
Total Property, Plant and Equipment, Net	[4]	105,322				78,132				105,322		78,132		79,250
Total Assets	[4]	$ 210,996				$ 143,919				210,996		143,919		126,108
Other International | Crude Oil and Condensate
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues	[4]									1,304		2,269		110,137
Other International | Natural Gas Liquids
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues	[4]									0		0		0
Other International | Natural Gas
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues	[4]									54,164		58,365		45,618
Other International | Gains (Losses) on Mark-to-Market Commodity Derivative Contracts
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues	[4]									0		0		0
Other International | Gathering, Processing and Marketing
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues	[4]									0		0		0
Other International | Gains (Losses) on Asset Dispositions, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues	[4]									179		(4,145)		15,217
Other International | Other, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues	[4]									$ 0		$ 15		$ (24)

[1] EOG had sales activity with three significant purchasers in 2020, each totaling $1.1 billion of consolidated Operating Revenues and Other in the United States segment.(3)EOG recorded pretax impairment charges of $1,570 million in 2020 for proved oil and gas properties, leasehold costs and other assets due to the decline in commodity prices and revisions of asset retirement obligations for certain properties in the United States segment. In addition, EOG recorded pretax impairment charges of $228 million in 2020 for owned and leased sand and crude-by-rail assets, also in the United States segment. EOG recorded pretax impairment charges of $81 million in 2020 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 Notes 13 and 14.

[2] EOG had sales activity with two significant purchasers in 2019, one totaling $2.4 billion and the other totaling $2.2 billion of consolidated Operating Revenues and Other in the United States segment.

[3] EOG had sales activity with two significant purchasers in 2018, one totaling $2.6 billion and the other totaling $2.3 billion of consolidated Operating Revenues and Other in the United States segment.

[4] Other International primarily consists of EOG's United Kingdom, China and Canada operations. EOG began an exploration program in Oman in the third quarter of 2020. The United Kingdom operations were sold in the fourth quarter of 2018.

XML

Risk Management Activities (Details)		3 Months Ended	12 Months Ended
		Mar. 31, 2020 bbl	Dec. 31, 2020 USD ($) MMBTU $ / bbl $ / MMBTU bbl	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Mar. 31, 2021 USD ($)
Derivatives, Fair Value [Line Items]
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts | $			$ 1,144,737,000	$ 180,275,000	$ (165,640,000)
Net Cash Received from (Payments for) Settlements of Commodity Derivatives Contracts | $			1,070,647,000	231,229,000	(258,906,000)
Assets from Price Risk Management Activities | $			64,559,000	1,299,000
Liabilities from Price Risk Management Activities | $			$ 0	$ 20,194,000
Receivable Major Customer Percentage			10.00%	10.00%
Derivative Collateral [Abstract]
Collateral Held on Derivative | $			$ 0		0
Collateral Had on Derivaitve | $			0		$ 0
Price Risk Derivative [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Noncurrent | $			1,063,000	$ 0
Derivative Liability, Noncurrent | $			455,000	0
Liabilities From Price Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Assets from Price Risk Management Activities | $				3,000,000
Liabilities from Price Risk Management Activities | $				23,000,000
Liabilities From Price Risk Management Activities [Member] | Price Risk Derivative [Member]
Derivatives, Fair Value [Line Items]
Liabilities from Price Risk Management Activities | $	[1]		0	20,194,000
Assets From Price Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Assets from Price Risk Management Activities | $				3,000,000
Liabilities from Price Risk Management Activities | $				2,000,000
Assets From Price Risk Management Activities [Member] | Price Risk Derivative [Member]
Derivatives, Fair Value [Line Items]
Assets from Price Risk Management Activities | $	[2]		64,559,000	$ 1,299,000
Crude Oil | Roll Differential Swap
Derivatives, Fair Value [Line Items]
Cash Received (Paid) On Derivative Instruments Net | $			3,200,000
Crude Oil | Price Swaps
Derivatives, Fair Value [Line Items]
Cash Received (Paid) On Derivative Instruments Net | $			$ 362,600,000			$ 1,400,000
Crude Oil | Derivative Contracts - May (closed) | ICE Brent Differential Basis Swap
Derivatives, Fair Value [Line Items]
Volume (Bbld)			10,000
Weighted Average Price | $ / bbl			4.92
Crude Oil | Derivative Contracts - May (closed) | Houston Differential Basis Swap
Derivatives, Fair Value [Line Items]
Volume (Bbld)			10,000
Weighted Average Price | $ / bbl			1.55
Crude Oil | Derivative Contracts - May (closed) | ICE Brent Price Swap
Derivatives, Fair Value [Line Items]
Volume (Bbld)			35,000
Weighted Average Price | $ / bbl			26.53
Crude Oil | Derivative Contacts - April (closed) | ICE Brent Price Swap
Derivatives, Fair Value [Line Items]
Volume (Bbld)			75,000
Weighted Average Price | $ / bbl			25.66
Crude Oil | Derivative Contracts - February through June (closed) | Roll Differential Swap
Derivatives, Fair Value [Line Items]
Volume (Bbld)			10,000
Weighted Average Price | $ / bbl			0.70
Crude Oil | Derivative Contracts - July through September (closed) | Roll Differential Swap
Derivatives, Fair Value [Line Items]
Volume (Bbld)			88,000
Weighted Average Price | $ / bbl			(1.16)
Crude Oil | Derivative Contracts - October through December (closed) | Roll Differential Swap
Derivatives, Fair Value [Line Items]
Volume (Bbld)			66,000
Weighted Average Price | $ / bbl			(1.16)
Crude Oil | Derivative Contracts - October through December (closed) | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld)			47,000
Crude Oil | Derivative Contracts - Year Two - February through December | Roll Differential Swap
Derivatives, Fair Value [Line Items]
Volume (Bbld)			25,000
Weighted Average Price | $ / bbl			0.10
Crude Oil | Derivative Contracts - Year Three - January through December | Roll Differential Swap
Derivatives, Fair Value [Line Items]
Volume (Bbld)			50,000
Weighted Average Price | $ / bbl			0.11
Crude Oil | OffSetting Derivative Contracts - July through September | Roll Differential Swap
Derivatives, Fair Value [Line Items]
Volume (Bbld)			22,000
Weighted Average Price | $ / bbl			0.43
Crude Oil | Derivative Contracts - July through September | Roll Differential Swap
Derivatives, Fair Value [Line Items]
Volume (Bbld)			22,000
Crude Oil | Derivative Contracts - October through December | Roll Differential Swap
Derivatives, Fair Value [Line Items]
Volume (Bbld)			44,000
Crude Oil | OffSetting Derivative Contracts - October through December | Roll Differential Swap
Derivatives, Fair Value [Line Items]
Volume (Bbld)			44,000
Weighted Average Price | $ / bbl			0.73
Crude Oil | OffSetting Derivative Contracts - October through December | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld)			47,000
Weighted Average Price | $ / bbl			30.04
Crude Oil | Derivative Contracts - January through March (closed) | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld)			200,000
Weighted Average Price | $ / bbl			59.33
Crude Oil | Derivative Contracts - April through May (closed) | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld)			265,000
Weighted Average Price | $ / bbl			51.36
Crude Oil | Derivative Contracts - June (closed) | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld)			265,000
Crude Oil | OffSetting Derivative Contracts - June | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld)			265,000
Weighted Average Price | $ / bbl			33.80
Crude Oil | Derivative Contracts - July (closed) | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld)			254,000
Crude Oil | OffSetting Derivative Contracts - July | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld)			254,000
Weighted Average Price | $ / bbl			33.75
Crude Oil | Derivative Contracts - August Through September | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld)			154,000
Crude Oil | OffSetting Derivative Contracts - August through September | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld)			154,000
Weighted Average Price | $ / bbl			34.18
Crude Oil | Price Swaps | Derivative Contracts - June (closed)
Derivatives, Fair Value [Line Items]
Weighted Average Price | $ / bbl			51.36
Crude Oil | Price Swaps | Derivative Contracts - July (closed)
Derivatives, Fair Value [Line Items]
Weighted Average Price | $ / bbl			42.36
Crude Oil | Price Swaps | Derivative Contracts - August Through September
Derivatives, Fair Value [Line Items]
Weighted Average Price | $ / bbl			50.42
Crude Oil | Price Swaps | Derivative Contracts - October through December (closed)
Derivatives, Fair Value [Line Items]
Weighted Average Price | $ / bbl			31.00
Natural Gas Liquids | Mont Belvieu Propane Price Swap
Derivatives, Fair Value [Line Items]
Weighted Average Price | $ / bbl			8,000,000.0
Cash Received (Paid) On Derivative Instruments Net | $						1,200,000
Natural Gas Liquids | Derivative Contracts - January through February (closed) | Mont Belvieu Propane Price Swap
Derivatives, Fair Value [Line Items]
Volume (Bbld)		4,000
Weighted Average Price | $ / bbl			21.34
Natural Gas Liquids | Derivative Contracts - March through April (closed) | Mont Belvieu Propane Price Swap
Derivatives, Fair Value [Line Items]
Volume (Bbld)		25,000
Weighted Average Price | $ / bbl			17.92
Natural Gas Liquids | Derivative Contracts - May through December (closed) [Member] | Mont Belvieu Propane Price Swap
Derivatives, Fair Value [Line Items]
Volume (Bbld)			25,000
Weighted Average Price | $ / bbl			17.92
Natural Gas | Price Swaps
Derivatives, Fair Value [Line Items]
Cash Received (Paid) On Derivative Instruments Net | $						$ 25,200,000
Natural Gas | Collars
Derivatives, Fair Value [Line Items]
Cash Received (Paid) On Derivative Instruments Net | $			$ 1,100,000
Cash Received For Early Termination Of Contracts | $			7,800,000
Natural Gas | HSC Differential Basis Swaps [Member]
Derivatives, Fair Value [Line Items]
Cash Paid For Early Termination Of Contracts | $			400,000
Natural Gas | Waha Differential Basis Swaps [Member]
Derivatives, Fair Value [Line Items]
Cash Received (Paid) On Derivative Instruments Net | $			$ 11,900,000
Natural Gas | Derivative Contracts - Year Three - January through December | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | MMBTU			20,000
Weighted Average Price | $ / MMBTU			2.75
Natural Gas | Derivative Contracts - Year Two - April through December | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | MMBTU			500,000
Weighted Average Price | $ / MMBTU			2.99
Natural Gas | Derivative Contracts - Year Two - January through March [Member] | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld)			500,000
Natural Gas | Derivative Contracts - April through July (closed) | Collars
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | MMBTU			250,000
Weighted Average Price (MMBtu) | $ / MMBTU			2.50
Derivative, Average Floor Price | $ / MMBTU			2.00
Natural Gas | Offsetting Derivative Contracts - August Through October | Collars
Derivatives, Fair Value [Line Items]
Volume (Bbld)			250,000
Derivative, Average Floor Price | $ / MMBTU			2.00
Natural Gas | Derivative Contracts - January through December (closed) [Member] | HSC Differential Basis Swaps [Member]
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | MMBTU			60,000
Weighted Average Price | $ / MMBTU			0.05
Natural Gas | Derivative Contracts - January through December (closed) [Member] | Rockies Differential Basis Swap
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | MMBTU			30,000
Weighted Average Price | $ / MMBTU			0.55
Natural Gas | Derivative Contracts - January through April (closed) | Waha Differential Basis Swaps [Member]
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | MMBTU			50,000
Weighted Average Price | $ / bbl			1.40
Natural Gas | Offsetting Derivative Contracts - May Through December | Waha Differential Basis Swaps [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld)			50,000
Weighted Average Price | $ / bbl			0.43
Natural Gas | Derivative Contracts - May through December (closed) [Member] | Waha Differential Basis Swaps [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld)			50,000
Weighted Average Price | $ / bbl			1.40
Natural Gas | Offsetting Derivative Contracts - Year Two - January through March | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld)			500,000
Weighted Average Price | $ / MMBTU			2.43
Natural Gas | Derivative Contracts - April through December (closed) | HSC Differential Basis Swaps [Member]
Derivatives, Fair Value [Line Items]
Weighted Average Price | $ / MMBTU			0.05
Natural Gas | Derivative Contracts - April through December (closed) | Rockies Differential Basis Swap
Derivatives, Fair Value [Line Items]
Weighted Average Price | $ / MMBTU			60,000
Natural Gas | Price Swaps | Derivative Contracts - Year Two - January through March [Member]
Derivatives, Fair Value [Line Items]
Weighted Average Price | $ / MMBTU			2.99
Natural Gas | Collars | Offsetting Derivative Contracts - August Through October
Derivatives, Fair Value [Line Items]
Weighted Average Price (MMBtu) | $ / MMBTU			2.50
Mont Belvieu Propane Price Swap | Offsetting Derivative Contracts - May Through December | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld)			25,000
Weighted Average Price | $ / bbl			16.41

[1] The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $23 million, partially offset by gross assets of $3 million at December 31, 2019.

[2] The current portion of Assets from Price Risk Management Activities consists of gross assets of $3 million, partially offset by gross liabilities of $2 million, at December 31, 2019.

XML

Fair Value Measurements (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Financial Assets:
Pretax impairment charges for proved oil and gas properties and other assets for firm commitment contracts		$ 152,000
Proved Oil and Gas Properties, Other Property, Plant and Equipment and Other Assets [Abstract]
Proved oil and gas properties, other property, plant and equipment and other assets, carrying amount	$ 1,587,000	998,000
Proved oil and gas properties, other property, plant and equipment and other assets written down during the period - fair value at end of period	319,000	701,000
Pretax impairment charge for a commodity price-related write-down of other assets	72,000	90,000
Pretax impairment charges for proved oil and gas properties, other property, plant and equipment and other assets	1,268,000	297,000
Debt Disclosure [Abstract]
Aggregate Principal Amount of Current and Long-Term Debt	5,640,000	5,140,000
Debt Instrument, Fair Value Disclosure	6,505,000	5,452,000
Assets From Price Risk Management Activities [Member]
Financial Assets:
Assets, Fair Value Disclosure	65,000	1,000
Liabilities From Price Risk Management Activities [Member]
Financial Assets:
Liabilities, Fair Value Disclosure		20,000
Other Liabilities
Financial Assets:
Liabilities, Fair Value Disclosure	1,000
Other Assets
Financial Assets:
Assets, Fair Value Disclosure	1,000
Commodity Contract [Member] | Crude Oil | Price Swaps
Financial Assets:
Liabilities, Fair Value Disclosure		23,266
Commodity Contract [Member] | Crude Oil | Price Swaps | Fair Value, Inputs, Level 1 [Member]
Financial Assets:
Liabilities, Fair Value Disclosure		0
Commodity Contract [Member] | Crude Oil | Price Swaps | Fair Value, Inputs, Level 2 [Member]
Financial Assets:
Liabilities, Fair Value Disclosure		23,266
Commodity Contract [Member] | Crude Oil | Price Swaps | Fair Value, Inputs, Level 3 [Member]
Financial Assets:
Liabilities, Fair Value Disclosure		0
Commodity Contract [Member] | Crude Oil | Roll Differential Swap
Financial Assets:
Liabilities, Fair Value Disclosure	897
Commodity Contract [Member] | Crude Oil | Roll Differential Swap | Fair Value, Inputs, Level 1 [Member]
Financial Assets:
Liabilities, Fair Value Disclosure	0
Commodity Contract [Member] | Crude Oil | Roll Differential Swap | Fair Value, Inputs, Level 2 [Member]
Financial Assets:
Liabilities, Fair Value Disclosure	897
Commodity Contract [Member] | Crude Oil | Roll Differential Swap | Fair Value, Inputs, Level 3 [Member]
Financial Assets:
Liabilities, Fair Value Disclosure	0
Commodity Contract [Member] | Natural Gas Liquids | Price Swaps
Financial Assets:
Assets, Fair Value Disclosure		3,401
Commodity Contract [Member] | Natural Gas Liquids | Price Swaps | Fair Value, Inputs, Level 1 [Member]
Financial Assets:
Assets, Fair Value Disclosure		0
Commodity Contract [Member] | Natural Gas Liquids | Price Swaps | Fair Value, Inputs, Level 2 [Member]
Financial Assets:
Assets, Fair Value Disclosure		3,401
Commodity Contract [Member] | Natural Gas Liquids | Price Swaps | Fair Value, Inputs, Level 3 [Member]
Financial Assets:
Assets, Fair Value Disclosure		0
Commodity Contract [Member] | Natural Gas | Price Swaps
Financial Assets:
Assets, Fair Value Disclosure	66,064
Commodity Contract [Member] | Natural Gas | Price Swaps | Fair Value, Inputs, Level 1 [Member]
Financial Assets:
Assets, Fair Value Disclosure	0
Commodity Contract [Member] | Natural Gas | Price Swaps | Fair Value, Inputs, Level 2 [Member]
Financial Assets:
Assets, Fair Value Disclosure	66,064
Commodity Contract [Member] | Natural Gas | Price Swaps | Fair Value, Inputs, Level 3 [Member]
Financial Assets:
Assets, Fair Value Disclosure	$ 0
Commodity Contract [Member] | Natural Gas | Basis Swaps [Member]
Financial Assets:
Assets, Fair Value Disclosure		970
Commodity Contract [Member] | Natural Gas | Basis Swaps [Member] | Fair Value, Inputs, Level 1 [Member]
Financial Assets:
Assets, Fair Value Disclosure		0
Commodity Contract [Member] | Natural Gas | Basis Swaps [Member] | Fair Value, Inputs, Level 2 [Member]
Financial Assets:
Assets, Fair Value Disclosure		970
Commodity Contract [Member] | Natural Gas | Basis Swaps [Member] | Fair Value, Inputs, Level 3 [Member]
Financial Assets:
Assets, Fair Value Disclosure		$ 0

XML

Impairment Expense (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2020		Dec. 31, 2019	Dec. 31, 2018
Impairment of Oil and Gas Properties [Line Items]
Impairment of Oil and Gas Properties		$ 2,099,780		$ 517,896	$ 347,021
Proved Properties
Impairment of Oil and Gas Properties [Line Items]
Impairment of Oil and Gas Properties	[1]	1,268,073		206,469	120,859
Unproved Properties
Impairment of Oil and Gas Properties [Line Items]
Impairment of Oil and Gas Properties	[2]	472,143		220,444	173,383
Leasehold Costs of Impairments of Unproved Oil and Gas Properties		252,000
Other Assets
Impairment of Oil and Gas Properties [Line Items]
Other Assets Impairments Related to Commodity Price-Related Write-Down		72,000		90,000	49,000
Impairment of Oil and Gas Properties	[3]	299,851		90,983	48,732
Impairments for Owned and Leased Sand and Crude-by-Rail Assets		228,000
Inventories
Impairment of Oil and Gas Properties [Line Items]
Impairment of Oil and Gas Properties		0		0	4,047
Firm Commitments Contracts
Impairment of Oil and Gas Properties [Line Items]
Impairment of Oil and Gas Properties		59,713	[4]	$ 0	$ 0
Canadian Firm Commitment Contracts		$ 60,000

[1] Impairments to proved oil and gas properties in 2020 included legacy and non-core natural gas and crude oil and combo plays. Impairments to proved oil and gas properties in 2019 and 2018 included domestic legacy natural gas assets. See Notes 1 and 13.

[2] Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. Impairments of unproved oil and gas properties included charges of $252 million in 2020 for certain leasehold costs that are no longer expected to be developed before expiration. See Note 1.

[3] Includes impairment charges for owned and leased sand and crude-by-rail assets of $228 million in 2020 (see Note 18) and a commodity price-related write-down of other assets of $72 million, $90 million and $49 million in 2020, 2019 and 2018, respectively (see Note 13).

[4] Includes impairment charges of $60 million in 2020 for firm commitment contracts related to its decision to exit the Horn River Basin in British Columbia, Canada.

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Asset Retirement Obligations (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligations, Noncurrent [Abstract]
Carrying Amount at Beginning of Period		$ 1,110,710	$ 954,377
Liabilities Incurred		57,477	98,874
Liabilities Settled (1)	[1]	(54,027)	(58,673)
Accretion		47,083	43,462
Revisions		53,888	72,425
Foreign Currency Translations		1,407	245
Carrying Amount at End of Period		1,216,538	1,110,710
Current Portion		49,548	37,127
Noncurrent Portion		$ 1,166,990	$ 1,073,583

[1] Includes settlements related to asset sales.

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Exploratory Well Costs (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2020 USD ($) well	Dec. 31, 2019 USD ($) well	Dec. 31, 2018 USD ($) well
Capitalized Exploratory Well Costs [Abstract]
Balance at January 1		$ 25,897	$ 4,121	$ 2,167
Additions Pending the Determination of Proved Reserves		107,852	83,175	10,304
Reclassifications to Proved Properties		(81,071)	(39,325)	(7,917)
Costs Charged to Expense (1)	[1]	(23,822)	(22,074)	(433)
Balance at December 31		$ 28,856	$ 25,897	$ 4,121
Projects that have Exploratory Well Costs that have been Capitalized for Period Greater than One Year, Number of Projects | well		1	0	0
Capitalized Exploratory Well Costs that Have Been Capitalized for Period of One Year or Less		$ 26,408	$ 25,897	$ 4,121
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year		$ 2,448	$ 0	$ 0

[1] Includes capitalized exploratory well costs charged to either dry hole costs or impairments.

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Acquisitions and Divestitures (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Business Combination, Separately Recognized Transactions [Line Items]
Gains (Losses) on Asset Dispositions, Net	$ (46,883)	$ 123,613	$ 174,562
Proceeds from Sale of Oil and Gas Properties and Equipment	191,928	140,292	$ 227,446
United States
Business Combination, Separately Recognized Transactions [Line Items]
Payments to Acquire Oil and Gas Property	82,000	$ 328,000
Other International
Business Combination, Separately Recognized Transactions [Line Items]
Payments to Acquire Oil and Gas Property	$ 38,000

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Leases (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating and Finance Leases [Line Items]
Operating Lease, Right-of-Use Asset				$ 566,000
Lease, Cost [Abstract]
Operating Lease Cost	[1]	$ 393,000	$ 497,000
Amortization of Lease Assets		21,000	13,000
Interest on Lease Liabilities		4,000	2,000
Variable Lease Cost		91,000	138,000
Total Lease Cost		703,000	983,000
Lease Assets and Liabilities [Abstract]
Total		1,075,000	826,000
Current Liability		295,089	369,365
Total		1,148,000	857,000
Finance Lease Net of Accumulated Depreciation		40,673,147	36,938,066
Cash Flow Operating And Financing Activities [Abstract]
Operating Leases Non-Cash Leasing Activities		893,000	784,000
Operating And Finance Leases Future Minimum Payments [Abstract]
Operating And Finance Leases Not Yet Commenced		$ 100,000
Minimum Operating And Finance Leases Not Yet Commenced Lease Term		2 years
Maximum Operating And Finance Leases Not Yet Commenced Lease Term		9 years
Capital Leases Future Minimum Payments Due [Abstract]
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability		$ 174,000
Short-term Lease Cost		194,000	$ 333,000
Finance Leases
Lease Assets and Liabilities [Abstract]
Current Liability		31,000
Long-Term Liability		$ 181,000
Weighted Average Remaining Lease Term And Discount Rate [Abstract]
Finance Lease Weighted Average Remaining Lease Term (in years)		7 years 7 months 6 days	4 years 8 months 12 days
Finance Lease Weighted Average Discount Rate (%)		2.80%	3.00%
Cash Flow Operating And Financing Activities [Abstract]
Repayment of Finance Lease Liabilities		$ 19,000	$ 13,000
Operating And Finance Leases Future Minimum Payments [Abstract]
2021		36,000
2022		32,000
2023		28,000
2024		29,000
2025		27,000
2026 and Beyond		87,000
Total Lease Payments		239,000
Less: Discount to Present Value		27,000
Total Lease Liabilities		212,000
Capital Leases Future Minimum Payments Due [Abstract]
2019				15,000
2020				15,000
2021				15,000
2022				12,000
2023				8,000
2024 and Beyond				14,000
Total Leases Payments				79,000
Operating Leases [Member]
Lease Assets and Liabilities [Abstract]
Current Liability		295,000
Long-Term Liability		$ 641,000
Weighted Average Remaining Lease Term And Discount Rate [Abstract]
Operating Lease Weighted Average Remaining Lease Term (in years)		5 years 3 months 18 days	3 years 2 months 12 days
Operating Lease Weighted Average Discount Rate (%)		3.40%	3.50%
Operating And Finance Leases Future Minimum Payments [Abstract]
2021		$ 323,000
2022		210,000
2023		134,000
2024		96,000
2025		70,000
2026 and Beyond		206,000
Total Lease Payments		1,039,000
Less: Discount to Present Value		103,000
Total Lease Liabilities		936,000
Operating Leases Future Minimum Payments Due [Abstract]
2019				380,000
2020				213,000
2021				86,000
2022				39,000
2023				30,000
2024 and Beyond				62,000
Total Leases Payments				$ 810,000
Operating Leases [Member] | Operating Activities
Cash Flow Operating And Financing Activities [Abstract]
Repayment of Operating Lease Liabilities		223,000	$ 225,000
Operating Leases [Member] | Investing Activities
Cash Flow Operating And Financing Activities [Abstract]
Repayment of Operating Lease Liabilities		130,000	270,000
Property, Plant and Equipment
Lease Assets and Liabilities [Abstract]
Finance Lease Net of Accumulated Depreciation		81,000	60,000
Property, Plant and Equipment | Finance Leases
Operating and Finance Leases [Line Items]
Operating Lease, Right-of-Use Asset		869,000	773,000
Lease Assets and Liabilities [Abstract]
Right-of-Use Asset	[2]	206,000	53,000
Current Portion of Operating Lease Liabilities | Operating Leases [Member]
Lease Assets and Liabilities [Abstract]
Current Liability		295,000	369,000
Current Portion of Long-Term Debt | Finance Leases
Lease Assets and Liabilities [Abstract]
Current Liability		31,000	15,000
Other Liabilities | Operating Leases [Member]
Lease Assets and Liabilities [Abstract]
Long-Term Liability		641,000	430,000
Long-term Debt [Member] | Finance Leases
Lease Assets and Liabilities [Abstract]
Long-Term Liability		$ 181,000	$ 43,000

[1] Operating lease cost includes impairment expenses of $35 million in 2020.

[2] Finance lease assets are recorded net of accumulated amortization of $81 million and $60 million at December 31, 2020 and 2019, respectively.

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Oil and Gas Exploration and Production Industries Disclosures (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2020 USD ($) MBoe MBbls MMcf	Dec. 31, 2019 USD ($) MBoe MMcf MBbls	Dec. 31, 2018 MBoe MBbls MMcf	Dec. 31, 2017 MBoe MMcf MBbls
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves (MBOE) | MBoe		1,649,098	1,721,212	1,548,137	1,364,335
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Balance at January 1 | MBoe		1,607,856	1,379,709	1,162,635
Extensions and Discoveries | MBoe		456,073	578,317	490,725
Revisions | MBoe		(277,325)	(49,837)	(8,244)
Acquisition of Reserves | MBoe		47	1,711	311
Sales of Reserves | MBoe		(3,670)	0	0
Conversion to Proved Developed Reserves | MBoe		(212,158)	(302,044)	(265,718)
Balance at December 31 | MBoe		1,570,823	1,607,856	1,379,709
Capitalized Costs, Oil and Gas Producing Activities, Gross [Abstract]
Proved properties | $		$ 61,724,487	$ 59,229,686
Unproved properties | $		3,068,311	3,600,729
Total | $		64,792,798	62,830,415
Accumulated depreciation, depletion and amortization | $		(38,750,852)	(35,033,085)
Net capitalized costs | $		$ 26,041,946	$ 27,797,330
Crude Oil (MBbl)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	1,694,417	1,532,312	1,312,973
Revisions of previous estimates	[1]	(225,412)	(42,882)	(13,376)
Purchases in place	[1]	2,176	2,859	2,743
Extensions, discoveries and other additions	[1]	195,587	369,996	383,018
Sales in place	[1]	(3,183)	(1,282)	(7,078)
Production	[1]	(149,787)	(166,586)	(145,968)
Net proved reserves - end of period	[1]	1,513,798	1,694,417	1,532,312
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves		792,592	801,598	712,785	614,236
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves		721,206	892,819	819,527	698,737
Natural Gas Liquids
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	739,692	614,329	503,473
Revisions of previous estimates	[1]	(59,790)	5,380	23,942
Purchases in place	[1]	3,831	1,948	2,006
Extensions, discoveries and other additions	[1]	180,205	167,782	127,409
Sales in place	[1]	(1,399)	(855)	(41)
Production	[1]	(49,796)	(48,892)	(42,460)
Net proved reserves - end of period	[1]	812,743	739,692	614,329
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves		391,708	387,253	341,386	286,872
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves		421,035	352,439	272,943	216,601
Natural Gas (MMcf)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period | MMcf	[2]	5,369,700	4,687,200	4,263,100
Revisions of previous estimates | MMcf	[2]	(491,300)	(134,800)	(91,500)
Purchases in place | MMcf	[2]	26,300	71,700	41,300
Extensions, discoveries and other additions | MMcf	[2]	1,131,800	1,273,100	956,000.0
Sales in place | MMcf	[2]	(157,300)	(14,500)	(22,200)
Production | MMcf	[2]	(518,900)	(513,000.0)	(459,500)
Net proved reserves - end of period | MMcf	[2]	5,360,300	5,369,700	4,687,200
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves | MMcf		2,788,800	3,194,100	2,963,800	2,779,300
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves | MMcf		2,571,500	2,175,600	1,723,400	1,483,800
Oil Equivalents (MBoe)
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved reserves - beginning of period | MBoe	[1]	3,329,068	2,927,846	2,526,970
Revisions of previous estimates | MBoe	[1]	(367,095)	(59,971)	(4,684)
Purchases in place | MBoe	[1]	10,398	16,761	11,640
Extensions, discoveries and other additions | MBoe	[1]	564,425	749,968	669,750
Sales in place | MBoe	[1]	(30,802)	(4,555)	(10,819)
Production | MBoe	[1]	(286,073)	(300,981)	(265,011)
Net proved reserves - end of period | MBoe	[1]	3,219,921	3,329,068	2,927,846
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserve (MBOE) | MBoe		1,570,823	1,607,856	1,379,709	1,162,635
United States
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves (MBOE) | MBoe		1,614,462	1,684,209	1,503,441	1,300,758
United States | Crude Oil (MBbl)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	1,693,960	1,531,684	1,304,071
Revisions of previous estimates	[1]	(225,375)	(42,959)	(13,237)
Purchases in place	[1]	2,176	2,859	2,743
Extensions, discoveries and other additions	[1]	194,724	369,968	383,003
Sales in place	[1]	(3,183)	(1,282)	(768)
Production	[1]	(149,402)	(166,310)	(144,128)
Net proved reserves - end of period	[1]	1,512,900	1,693,960	1,531,684
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves		791,744	801,189	712,218	605,405
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves		721,156	892,771	819,466	698,666
United States | Natural Gas Liquids
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	739,692	614,329	503,473
Revisions of previous estimates	[1]	(59,790)	5,380	23,942
Purchases in place	[1]	3,831	1,948	2,006
Extensions, discoveries and other additions	[1]	180,205	167,782	127,409
Sales in place	[1]	(1,399)	(855)	(41)
Production	[1]	(49,796)	(48,892)	(42,460)
Net proved reserves - end of period	[1]	812,743	739,692	614,329
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves		391,708	387,253	341,386	286,872
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves		421,035	352,439	272,943	216,601
United States | Natural Gas (MMcf)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period | MMcf	[2]	5,034,800	4,390,600	3,898,500
Revisions of previous estimates | MMcf	[2]	(497,700)	(184,400)	(127,200)
Purchases in place | MMcf	[2]	26,300	71,700	41,300
Extensions, discoveries and other additions | MMcf	[2]	1,077,900	1,175,900	951,400
Sales in place | MMcf	[2]	(157,300)	(14,500)	(22,200)
Production | MMcf	[2]	(441,400)	(404,500)	(351,200)
Net proved reserves - end of period | MMcf	[2]	5,042,600	5,034,800	4,390,600
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves | MMcf		2,586,100	2,974,600	2,699,000.0	2,450,800
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves | MMcf		2,456,500	2,060,200	1,691,600	1,447,700
United States | Oil Equivalents (MBoe)
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved reserves - beginning of period | MBoe	[1]	3,272,778	2,877,778	2,457,302
Revisions of previous estimates | MBoe	[1]	(368,127)	(68,317)	(10,500)
Purchases in place | MBoe	[1]	10,398	16,761	11,640
Extensions, discoveries and other additions | MBoe	[1]	554,585	733,730	668,972
Sales in place | MBoe	[1]	(30,802)	(4,555)	(4,509)
Production | MBoe	[1]	(272,757)	(282,619)	(245,127)
Net proved reserves - end of period | MBoe	[1]	3,166,075	3,272,778	2,877,778
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserve (MBOE) | MBoe		1,551,613	1,588,569	1,374,337	1,156,544
Trinidad
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves (MBOE) | MBoe		29,268	29,886	37,746	50,779
Trinidad | Crude Oil (MBbl)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	266	417	898
Revisions of previous estimates	[1]	(19)	85	(183)
Purchases in place	[1]	0	0	0
Extensions, discoveries and other additions	[1]	863	0	0
Sales in place	[1]	0	0	0
Production	[1]	(355)	(236)	(298)
Net proved reserves - end of period	[1]	755	266	417
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves		755	266	417	898
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves		0	0	0	0
Trinidad | Natural Gas Liquids
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	0	0	0
Revisions of previous estimates	[1]	0	0	0
Purchases in place	[1]	0	0	0
Extensions, discoveries and other additions	[1]	0	0	0
Sales in place	[1]	0	0	0
Production	[1]	0	0	0
Net proved reserves - end of period	[1]	0	0	0
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves		0	0	0	0
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves		0	0	0	0
Trinidad | Natural Gas (MMcf)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period | MMcf	[2]	276,100	237,000.0	313,400
Revisions of previous estimates | MMcf	[2]	4,800	47,000.0	20,700
Purchases in place | MMcf	[2]	0	0	0
Extensions, discoveries and other additions | MMcf	[2]	53,900	87,500	0
Sales in place | MMcf	[2]	0	0	0
Production | MMcf	[2]	(65,900)	(95,400)	(97,100)
Net proved reserves - end of period | MMcf	[2]	268,900	276,100	237,000.0
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves | MMcf		171,100	177,700	223,900	299,200
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves | MMcf		97,800	98,400	13,100	14,200
Trinidad | Oil Equivalents (MBoe)
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved reserves - beginning of period | MBoe	[1]	46,298	39,936	53,142
Revisions of previous estimates | MBoe	[1]	773	7,915	3,272
Purchases in place | MBoe	[1]	0	0	0
Extensions, discoveries and other additions | MBoe	[1]	9,840	14,577	0
Sales in place | MBoe	[1]	0	0	0
Production | MBoe	[1]	(11,347)	(16,130)	(16,478)
Net proved reserves - end of period | MBoe	[1]	45,564	46,298	39,936
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserve (MBOE) | MBoe		16,296	16,412	2,190	2,363
Other International
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves (MBOE) | MBoe	[3]	5,368	7,117	6,950	12,798
Other International | Crude Oil (MBbl)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1],[3]	191	211	8,004
Revisions of previous estimates	[1],[3]	(18)	(8)	44
Purchases in place	[1],[3]	0	0	0
Extensions, discoveries and other additions	[1],[3]	0	28	15
Sales in place	[1],[3]	0	0	(6,310)
Production	[1],[3]	(30)	(40)	(1,542)
Net proved reserves - end of period	[1],[3]	143	191	211
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves	[3]	93	143	150	7,933
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves	[3]	50	48	61	71
Other International | Natural Gas Liquids
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1],[3]	0	0	0
Revisions of previous estimates	[1],[3]	0	0	0
Purchases in place	[1],[3]	0	0	0
Extensions, discoveries and other additions	[1],[3]	0	0	0
Sales in place	[1],[3]	0	0	0
Production	[1],[3]	0	0	0
Net proved reserves - end of period	[1],[3]	0	0	0
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves	[3]	0	0	0	0
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves	[3]	0	0	0	0
Other International | Natural Gas (MMcf)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period | MMcf	[2],[3]	58,800	59,600	51,200
Revisions of previous estimates | MMcf	[2],[3]	1,600	2,600	15,000.0
Purchases in place | MMcf	[2],[3]	0	0	0
Extensions, discoveries and other additions | MMcf	[2],[3]	0	9,700	4,600
Sales in place | MMcf	[2],[3]	0	0	0
Production | MMcf	[2],[3]	(11,600)	(13,100)	(11,200)
Net proved reserves - end of period | MMcf	[2],[3]	48,800	58,800	59,600
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves | MMcf	[3]	31,600	41,800	40,900	29,300
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves | MMcf	[3]	17,200	17,000.0	18,700	21,900
Other International | Oil Equivalents (MBoe)
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved reserves - beginning of period | MBoe	[1],[3]	9,992	10,132	16,526
Revisions of previous estimates | MBoe	[1],[3]	259	431	2,544
Purchases in place | MBoe	[1],[3]	0	0	0
Extensions, discoveries and other additions | MBoe	[1],[3]	0	1,661	778
Sales in place | MBoe	[1],[3]	0	0	(6,310)
Production | MBoe	[1],[3]	(1,969)	(2,232)	(3,406)
Net proved reserves - end of period | MBoe	[1],[3]	8,282	9,992	10,132
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserve (MBOE) | MBoe	[3]	2,914	2,875	3,182	3,728

[1] Thousand barrels or thousand barrels of oil equivalent, as applicable; oil equivalents include crude oil and condensate, NGLs and natural gas. Oil equivalents are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas.

[2] Billion cubic feet.

[3] Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.

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Oil and Gas Exploration and Production Industries Disclosures, Costs Incurred (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2020		Dec. 31, 2019		Dec. 31, 2018
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Unproved		$ 264,778	[1]	$ 276,092	[2]	$ 487,339	[3]
Acquisition Costs of Properties - Proved		135,162	[4]	379,938	[5]	123,684	[6]
Subtotal		399,940		656,030		611,023
Exploration Costs		296,028		273,339		193,628
Development Costs		3,022,263	[7]	5,698,856	[8]	5,615,029	[9]
Total		3,718,231		6,628,225		6,419,680
Non-Cash Unproved Leasehold Acquisition Costs Related to Property Exchanges		197,000		98,000		291,000
Non-Cash Proved Property Acquisition Costs Related to Property Exchanges		15,000		52,000		71,000
United States
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Unproved		264,778	[1]	276,092	[2]	486,081	[3]
Acquisition Costs of Properties - Proved		97,073	[4]	379,938	[5]	123,684	[6]
Subtotal		361,851		656,030		609,765
Exploration Costs		203,403		213,505		157,222
Development Costs		2,998,155	[7]	5,661,753	[8]	5,605,264	[9]
Total		3,563,409		6,531,288		6,372,251
Asset Retirement Costs Included In Development		97,000		181,000		90,000
Trinidad
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Unproved		0	[1]	0	[2]	1,258	[3]
Acquisition Costs of Properties - Proved		0	[4]	0	[5]	0	[6]
Subtotal		0		0		1,258
Exploration Costs		81,216		46,616		22,511
Development Costs		4,036	[7]	25,007	[8]	(12,863)	[9]
Total		85,252		71,623		10,906
Asset Retirement Costs Included In Development				1,000		(12,000)
Other International
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Unproved	[10]	0	[1]	0	[2]	0	[3]
Acquisition Costs of Properties - Proved	[10]	38,089	[4]	0	[5]	0	[6]
Subtotal	[10]	38,089		0		0
Exploration Costs	[10]	11,409		13,218		13,895
Development Costs	[10]	20,072	[7]	12,096	[8]	22,628	[9]
Total	[10]	69,570		25,314		36,523
Asset Retirement Costs Included In Development		$ 20,000		$ 4,000		$ (8,000)

[1] Includes non-cash unproved leasehold acquisition costs of $197 million related to property exchanges.

[2] Includes non-cash unproved leasehold acquisition costs of $98 million related to property exchanges.

[3] Includes non-cash unproved leasehold acquisition costs of $291 million related to property exchanges.

[4] Includes non-cash proved property acquisition costs of $15 million related to property exchanges.

[5] Includes non-cash proved property acquisition costs of $52 million related to property exchanges.

[6] Includes non-cash proved property acquisition costs of $71 million related to property exchanges.

[7] Includes Asset Retirement Costs of $97 million and $20 million for the United States and Other International, respectively. Excludes other property, plant and equipment.

[8] Includes Asset Retirement Costs of $181 million, $1 million and $4 million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment.

[9] Includes Asset Retirement Costs of $90 million, $(12) million and $(8) million for the United States, Trinidad and Other International, respectively.  Excludes other property, plant and equipment.

[10] Other International primarily consists of EOG's United Kingdom, China and Canada operations. EOG began an exploration program in Oman in the third quarter of 2020. The United Kingdom operations were sold in the fourth quarter of 2018.

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Oil and Gas Exploration and Production Industries Disclosures, Results Of Operations (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2020		Dec. 31, 2019		Dec. 31, 2018
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	[1]	$ 7,290,256		$ 11,581,445		$ 11,946,487
Other	[1]	60,954		134,358		89,635
Total	[1]	7,351,210		11,715,803		12,036,122
Exploration Costs	[1]	145,788		139,881		148,999
Dry Hole Costs	[1]	13,083		28,001		5,405
Transportation Costs	[1]	734,989		758,300		746,876
Gathering and Processing Costs		459,211	[1]	479,102	[1]	436,973
Production Costs	[1]	1,517,347		2,133,986		2,028,083
Impairments	[1]	2,099,780		517,896		347,021
Depreciation, Depletion and Amortization	[1]	3,268,075		3,657,597		3,320,276
Income (Loss) Before Income Taxes	[1]	(887,063)		4,001,040		5,002,489
Income Tax Provision (Benefit)	[1]	(193,483)		942,582		1,100,145
Results of Operations	[1]	(693,580)		3,058,458		3,902,344
United States
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	[1]	7,055,098		11,250,853		11,488,620
Other	[1]	60,989		134,325		89,708
Total	[1]	7,116,087		11,385,178		11,578,328
Exploration Costs	[1]	136,266		130,302		121,572
Dry Hole Costs	[1]	13,055		11,133		4,983
Transportation Costs	[1]	734,071		753,558		742,792
Gathering and Processing Costs		459,211	[1]	479,102	[1]	404,471
Production Costs	[1]	1,479,976		2,063,078		1,924,504
Impairments	[1]	2,018,283		510,948		344,595
Depreciation, Depletion and Amortization	[1]	3,192,000		3,560,609		3,181,801
Income (Loss) Before Income Taxes	[1]	(916,775)		3,876,448		4,853,610
Income Tax Provision (Benefit)	[1]	(220,437)		884,450		1,086,077
Results of Operations	[1]	(696,338)		2,991,998		3,767,533
Trinidad
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	[1]	179,690		269,957		302,112
Other	[1]	(35)		18		(49)
Total	[1]	179,655		269,975		302,063
Exploration Costs	[1]	1,909		4,290		21,402
Dry Hole Costs	[1]	0		13,033		0
Transportation Costs	[1]	747		4,014		3,236
Gathering and Processing Costs		0	[1]	0	[1]	0
Production Costs	[1]	26,964		30,539		33,506
Impairments	[1]	815		5,713		0
Depreciation, Depletion and Amortization	[1]	60,328		79,156		91,788
Income (Loss) Before Income Taxes	[1]	88,892		133,230		152,131
Income Tax Provision (Benefit)	[1]	23,526		54,980		12,170
Results of Operations	[1]	65,366		78,250		139,961
Other International
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	[1],[2]	55,468		60,635		155,755
Other	[1],[2]	0		15		(24)
Total	[1],[2]	55,468		60,650		155,731
Exploration Costs	[1],[2]	7,613		5,289		6,025
Dry Hole Costs	[1],[2]	28		3,835		422
Transportation Costs	[1],[2]	171		728		848
Gathering and Processing Costs		0	[1],[2]	0	[1],[2]	32,502
Production Costs	[1],[2]	10,407		40,369		70,073
Impairments	[1],[2]	80,682		1,235		2,426
Depreciation, Depletion and Amortization	[1],[2]	15,747		17,832		46,687
Income (Loss) Before Income Taxes	[1],[2]	(59,180)		(8,638)		(3,252)
Income Tax Provision (Benefit)	[1],[2]	3,428		3,152		1,898
Results of Operations	[1],[2]	$ (62,608)		$ (11,790)		$ (5,150)

[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, 2020.

[2] Other International primarily consists of EOG's United Kingdom, China and Canada operations. EOG began an exploration program in Oman in the third quarter of 2020. The United Kingdom operations were sold in the fourth quarter of 2018. (3)Effective January 1, 2018, EOG adopted the provisions of Accounting Standards Update (ASU) 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements within its United States segment as Gathering and Processing Costs instead of as a deduction to Natural Gas Revenues. There was no impact to operating income or net income resulting from changes to the presentation of natural gas processing fees (see Note 1 to Consolidated Financial Statements).

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Oil and Gas Exploration and Production Industries Disclosures, Average Sales Price (Details) - $ / bbl		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent		3.72	4.54	4.84
United States
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent		3.75	4.59	4.84
Trinidad
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent		2.33	1.85	1.67
Other International
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent	[1]	6.78	18.26	20.19

[1] Other International primarily consists of EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.

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Oil and Gas Exploration and Production Industries Disclosures, Discounted Future Net Cash Flows (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2020 USD ($)		Dec. 31, 2019 USD ($)		Dec. 31, 2018 USD ($)
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows					$ 74,909,366	[1]	$ 121,478,362	[2]	$ 134,119,690	[3]
Future production costs					(34,826,068)		(42,641,887)		(42,654,642)
Future development costs					(15,404,203)		(20,586,449)		(16,667,893)
Future income taxes					(4,442,257)		(11,565,498)		(14,962,141)
Future net cash flows					20,236,838		46,684,528		59,835,014
Discount to present value at 10% annual rate					(8,546,826)		(21,163,763)		(27,409,059)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves		$ 11,690,012	$ 32,425,955	$ 32,425,955	11,690,012		25,520,765		32,425,955
Annual Rate of Discount to Present Value		10.00%	10.00%	10.00%
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at Beginning of Period		$ 25,520,765	$ 32,425,955	$ 18,327,660
Sales and transfers of oil and gas produced, net of production costs		(4,579,174)	(8,210,438)	(8,734,622)
Net changes in prices and production costs		(18,445,993)	(10,880,447)	12,856,429
Extensions, discoveries, additions and improved recovery, net of related costs		1,501,373	5,709,558	8,430,953
Development costs incurred		1,674,800	3,032,150	2,745,160
Revisions of estimated development cost		4,137,607	(738,024)	(410,525)
Revisions of previous quantity estimates		(3,297,312)	(695,521)	(101,726)
Accretion of discount		3,104,368	3,949,758	2,042,622
Net change in income taxes		3,488,199	1,548,707	(4,973,058)
Purchases of reserves in place		49,232	98,539	116,887
Sales of reserves in place		(156,293)	(50,651)	(117,932)
Changes in timing and other		(1,307,560)	(668,821)	2,244,107
Balance at End of Period		11,690,012	25,520,765	32,425,955
United States
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows					73,726,893	[1]	120,359,769	[2]	133,066,375	[3]
Future production costs					(34,618,860)		(42,387,801)		(42,351,174)
Future development costs					(15,159,373)		(20,355,746)		(16,577,794)
Future income taxes					(4,336,578)		(11,459,567)		(14,756,011)
Future net cash flows					19,612,082		46,156,655		59,381,396
Discount to present value at 10% annual rate					(8,410,282)		(21,042,593)		(27,348,744)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves		25,114,062	32,032,652	32,032,652	$ 11,201,800		$ 25,114,062		$ 32,032,652
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at Beginning of Period		25,114,062	32,032,652	17,756,935
Sales and transfers of oil and gas produced, net of production costs		(4,381,840)	(7,955,115)	(8,416,853)
Net changes in prices and production costs		(18,624,768)	(10,973,981)	12,750,466
Extensions, discoveries, additions and improved recovery, net of related costs		1,436,988	5,608,038	8,418,666
Development costs incurred		1,674,800	3,003,510	2,732,560
Revisions of estimated development cost		4,148,768	(597,869)	(410,741)
Revisions of previous quantity estimates		(3,307,180)	(812,781)	(173,084)
Accretion of discount		3,054,437	3,891,701	1,967,592
Net change in income taxes		3,497,362	1,454,050	(4,965,373)
Purchases of reserves in place		49,232	98,539	116,887
Sales of reserves in place		(156,293)	(50,651)	(35,874)
Changes in timing and other		(1,303,768)	(584,031)	2,291,471
Balance at End of Period		11,201,800	25,114,062	32,032,652
United States | Crude Oil
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows					37.19		57.51		68.54
United States | Natural Gas Liquids [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows					12.47		16.91		27.83
United States | Natural Gas
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows					1.45		2.07		2.50
Trinidad
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows					$ 900,815	[1]	$ 813,102	[2]	$ 749,695	[3]
Future production costs					(153,275)		(166,705)		(204,444)
Future development costs					(226,430)		(212,303)		(78,199)
Future income taxes					(81,368)		(73,508)		(174,382)
Future net cash flows					439,742		360,586		292,670
Discount to present value at 10% annual rate					(100,350)		(86,009)		(26,832)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves		339,392	265,838	332,427	$ 339,392		$ 274,577		$ 265,838
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at Beginning of Period		274,577	265,838	332,427
Sales and transfers of oil and gas produced, net of production costs		(151,979)	(235,404)	(265,370)
Net changes in prices and production costs		131,859	65,962	84,353
Extensions, discoveries, additions and improved recovery, net of related costs		64,385	85,233	0
Development costs incurred		0	22,820	0
Revisions of estimated development cost		(11,161)	(129,047)	4,030
Revisions of previous quantity estimates		11,632	116,062	39,608
Accretion of discount		34,624	43,148	50,191
Net change in income taxes		(12,185)	93,975	3,844
Purchases of reserves in place		0	0	0
Sales of reserves in place		0	0	0
Changes in timing and other		(2,360)	(54,010)	16,755
Balance at End of Period		339,392	274,577	265,838
Trinidad | Crude Oil
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows					26.75		46.77		55.66
Trinidad | Natural Gas
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows					3.28		2.90		3.06
Other International (1)
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	[4]				$ 281,658	[1]	$ 305,491	[2]	$ 303,620	[3]
Future production costs	[4]				(53,933)		(87,381)		(99,024)
Future development costs	[4]				(18,400)		(18,400)		(11,900)
Future income taxes	[4]				(24,311)		(32,423)		(31,748)
Future net cash flows	[4]				185,014		167,287		160,948
Discount to present value at 10% annual rate	[4]				(36,194)		(35,161)		(33,483)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	[4]	148,820	132,126	127,465	$ 148,820		$ 132,126		$ 127,465
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at Beginning of Period	[4]	132,126	127,465	238,298
Sales and transfers of oil and gas produced, net of production costs	[4]	(45,355)	(19,919)	(52,399)
Net changes in prices and production costs	[4]	46,916	27,572	21,610
Extensions, discoveries, additions and improved recovery, net of related costs	[4]	0	16,287	12,287
Development costs incurred	[4]	0	5,820	12,600
Revisions of estimated development cost	[4]	0	(11,108)	(3,814)
Revisions of previous quantity estimates	[4]	(1,764)	1,198	31,750
Accretion of discount	[4]	15,307	14,909	24,839
Net change in income taxes	[4]	3,022	682	(11,529)
Purchases of reserves in place	[4]	0	0	0
Sales of reserves in place	[4]	0	0	(82,058)
Changes in timing and other	[4]	(1,432)	(30,780)	(64,119)
Balance at End of Period	[4]	$ 148,820	$ 132,126	$ 127,465
Other International (1) | Crude Oil
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows					41.87		57.22		61.66
Other International (1) | Natural Gas
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows					5.65		5.01		4.88

[1] Estimated crude oil prices used to calculate 2020 future cash inflows for the United States, Trinidad and Other International were $37.19, $26.75, and $41.87, respectively. Estimated NGL price used to calculate 2020 future cash inflows for the United States was $12.47. Estimated natural gas prices used to calculate 2020 future cash inflows for the United States, Trinidad and Other International were $1.45, $3.28, and $5.65, respectively.

[2] Estimated crude oil prices used to calculate 2019 future cash inflows for the United States, Trinidad and Other International were $57.51, $46.77 and $57.22, respectively. Estimated NGL price used to calculate 2019 future cash inflows for the United States was $16.91. Estimated natural gas prices used to calculate 2019 future cash inflows for the United States, Trinidad and Other International were $2.07, $2.90 and $5.01, respectively.

[3] Estimated crude oil prices used to calculate 2018 future cash inflows for the United States, Trinidad and Other International were $68.54, $55.66 and $61.66, respectively. Estimated NGL price used to calculate 2018 future cash inflows for the United States was $27.83. Estimated natural gas prices used to calculate 2018 future cash inflows for the United States, Trinidad and Other International were $2.50, $3.06 and $4.88, respectively.

[4] Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.

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Unaudited Quarterly Financial Information (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2020		Sep. 30, 2020		Jun. 30, 2020		Mar. 31, 2020		Dec. 31, 2019		Sep. 30, 2019		Jun. 30, 2019		Mar. 31, 2019		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
Operating Revenues and Other	$ 2,965,498		$ 2,245,484		$ 1,103,374		$ 4,717,692		$ 4,320,246		$ 4,303,455		$ 4,697,630		$ 4,058,642		$ 11,032,048	$ 17,379,973	$ 17,275,399
Operating Income	487,662		(2,714)		(1,086,549)		57,585		863,751		827,959		1,130,771		876,530		(544,016)	3,699,011	4,469,346
Income (Loss) Before Income Taxes	427,760		(52,555)		(1,145,262)		31,003		831,208		797,457		1,089,366		827,236
Income Tax Provision (Benefit)	90,294		(10,088)		(235,878)		21,190		194,687		182,335		241,525		191,810		(134,482)	810,357	821,958
Net Income (Loss)	$ 337,466		$ (42,467)		$ (909,384)		$ 9,813		$ 636,521		$ 615,122		$ 847,841		$ 635,426		$ (604,572)	$ 2,734,910	$ 3,419,040
Net Income (Loss) Per Share
Basic (in dollars per share)	$ 0.58	[1]	$ (0.07)	[1]	$ (1.57)	[1]	$ 0.02	[1]	$ 1.10	[1]	$ 1.06	[1]	$ 1.47	[1]	$ 1.10	[1]	$ (1.04)	$ 4.73	$ 5.93
Diluted (in dollars per share)	$ 0.58	[1]	$ (0.07)	[1]	$ (1.57)	[1]	$ 0.02	[1]	$ 1.10	[1]	$ 1.06	[1]	$ 1.46	[1]	$ 1.10	[1]	$ (1.04)	$ 4.71	$ 5.89
Average Number of Common Shares [Abstract]
Basic (in shares)	579,624		579,055		578,719		578,462		578,219		577,839		577,460		577,207		578,949	577,670	576,578
Diluted (in shares)	580,885		579,055		578,719		580,283		580,849		581,271		580,247		580,222		578,949	580,777	580,441

[1] The sum of quarterly net income (loss) per share may not agree with total year net income (loss) per share as each quarterly computation is based on the weighted average of common shares outstanding.