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, 2021

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, 2021: $48,608 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, 585,419,164 shares outstanding as of February 11, 2022.

Documents incorporated by reference.  Portions of the Definitive Proxy Statement for the registrant's 2022 Annual Meeting of Stockholders, to be filed within 120 days after December 31, 2021, 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	3
	Wellhead Volumes and Prices	4
	Human Capital Management	6
	Competition	7
	Regulation	7
	Other Matters	11
	Information About Our Executive Officers	13
ITEM 1A.	Risk Factors	14
ITEM 1B.	Unresolved Staff Comments	27
ITEM 2.	Properties	27
	Oil and Gas Exploration and Production - Properties and Reserves	27
ITEM 3.	Legal Proceedings	30
ITEM 4.	Mine Safety Disclosures	31
PART II
ITEM 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	32
ITEM 6.	Reserved	34
ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	34
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk	54
ITEM 8.	Financial Statements and Supplementary Data	54
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	54
ITEM 9A.	Controls and Procedures	54
ITEM 9B.	Other Information	55
ITEM 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	55
PART III
ITEM 10.	Directors, Executive Officers and Corporate Governance	55
ITEM 11.	Executive Compensation	56
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	56
ITEM 13.	Certain Relationships and Related Transactions, and Director Independence	57
ITEM 14.	Principal Accounting Fees and Services	57
PART IV
ITEM 15.	Exhibits, Financial Statement Schedules	58
ITEM 16.	Form 10-K Summary	58
SIGNATURES

(i)

PART I

ITEM 1.  Business

General

EOG Resources, Inc., a Delaware corporation organized in 1985, together with its subsidiaries (collectively, EOG), explores for, develops, produces and markets crude oil, natural gas liquids (NGLs) and natural gas primarily in major producing basins in the United States of America (United States or U.S.), The Republic of Trinidad and Tobago (Trinidad) and, from time to time, select other international areas.  EOG's principal producing areas are further described in "Exploration and Production" below.  EOG's Annual Reports on Form 10-K, Quarterly Reports on Form 10‑Q, Current Reports on Form 8-K and any amendments to those reports (including related exhibits and supplemental schedules) filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (as amended) are made available, free of charge, through EOG's website, as soon as reasonably practicable after such reports have been filed with, or furnished to, the United States Securities and Exchange Commission (SEC).  EOG's website address is www.eogresources.com. Information on our website is not incorporated by reference into, and does not constitute a part of, this report.

At December 31, 2021, EOG's total estimated net proved reserves were 3,747 million barrels of oil equivalent (MMBoe), of which 1,548 million barrels (MMBbl) were crude oil and condensate reserves, 829 MMBbl were NGLs reserves and 8,222 billion cubic feet (Bcf), or 1,370 MMBoe, were natural gas reserves (see "Supplemental Information to Consolidated Financial Statements").  At such date, approximately 99% of EOG's net proved reserves, on a crude oil equivalent basis, were located in the United States and 1% in Trinidad.  Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet (Mcf) of natural gas.

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

EOG'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 and the use of improved drilling equipment and completion technologies for horizontal drilling and formation evaluation.  These advanced technologies are used, as appropriate, throughout EOG to reduce the risks and costs associated with all aspects of oil and gas exploration, development and exploitation.  EOG implements its strategy primarily by emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves.  Maintaining the lowest possible operating cost structure, coupled with efficient and safe operations and robust environmental stewardship practices and performance, is integral in the implementation of EOG's strategy.

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

Exploration and Production

United States Operations

EOG's operations are located in most of the productive basins in the United States with a focus on crude oil and, to a lesser extent, liquids-rich natural gas plays.

At December 31, 2021, on a crude oil equivalent basis, 42% of EOG's net proved reserves in the United States were crude oil and condensate, 22% were NGLs and 36% were natural gas. The majority of these reserves are in long-lived fields with well-established production characteristics. EOG believes that opportunities exist to increase production through continued development in and around many of these fields and through the utilization of applicable technologies. EOG also maintains an active exploration program designed to extend fields and add new trends and resource plays to its already broad portfolio.

1

The following is a summary of wellhead volume statistics and net well completions for the year ended December 31, 2021, total net acres at December 31, 2021, and expected net well completions planned for 2022 for certain areas of EOG's United States operations.

2021						2022
Area of Operation	Crude Oil & Condensate Volumes (MBbld) (1)	Natural Gas Liquids Volumes (MBbld) (1)	Natural Gas Volumes (MMcfd) (1)	Total Net Acres (in thousands)	Net Well Completions	Expected Net Well Completions
Delaware Basin	231.1	84.6	651	395	288	375
South Texas	149.5	29.3	273	1,131	166	125
Rocky Mountain	50.3	16.9	182	1,037	50	<50
Other Areas	12.5	13.7	104	1,130	12	20
Total	443.4	144.5	1,210	3,693	516	520

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

In the Delaware Basin, EOG completed 288 net wells during 2021, 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 395,000 net acre position.

In the Delaware Basin Wolfcamp play, EOG has completed 189 net wells in 2021. Continued improvement and excellent results in the Delaware Basin Wolfcamp program were supported by optimized well spacing and co-development, enhanced well completions, precision drilling and continued cost reductions. In 2022, 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 2021, EOG completed 79 total net Bone Spring wells within the three sub-plays. Of the three sub-plays, the Second Bone Spring had the majority of the activity in 2021 with EOG completing 63 net wells. The Bone Spring play continues to be an integral part of EOG's Delaware Basin plans and portfolio.

In the Leonard play, EOG maintained its development plan with 20 net wells completed in 2021. EOG has tested co-development of up to three Leonard zones simultaneously, and expects the Leonard play to become a more active part of EOG's program in the next several years.

Activity in 2022 will remain focused on the Delaware Basin Wolfcamp, Bone Spring, and Leonard plays, where EOG expects to complete approximately 375 net wells.

The South Texas area includes our Eagle Ford oil play and our Dorado gas play. EOG holds approximately 516,000 total net acres in the prolific oil window of the Eagle Ford oil play and approximately 160,000 net acres in the Dorado gas play. In the Dorado gas play, EOG has continued to delineate the Eagle Ford and Austin Chalk formations with excellent results. In 2021, EOG completed 155 net Eagle Ford oil play wells, and 11 net wells in the Dorado gas play. In 2022, EOG expects to complete approximately 95 net Eagle Ford oil play wells and 30 net Dorado wells.

Activity in the Rocky Mountain area in 2021 was focused on the Wyoming Powder River Basin. In the Powder River Basin, EOG operated a two-rig program and completed 45 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 drilled and completed one net well in the Codell formation. In the Williston Basin, EOG completed four net wells in the Bakken and Three Forks formations. Activity in both the DJ and Williston Basins is expected to be minimal in 2022 as development remains focused on the Powder River Basin where EOG plans to complete approximately 40 net wells.

2

Operations Outside the United States

EOG has operations offshore Trinidad and is making preparations to drill offshore Australia, as well as evaluating additional exploration, development and exploitation opportunities in these and other select international areas. In addition, EOG is in the process of exiting Block 36 and Block 49 in the Sultanate of Oman (Oman) and is executing an abandonment and reclamation program in Canada. EOG sold its operations in the China Sichuan Basin (China) in the second quarter of 2021.

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

In 2021, EOG's net production averaged approximately 217 MMcfd of natural gas and approximately 1.5 MBbld of crude oil and condensate. In 2021, EOG made progress on the design and fabrication of a platform and related facilities for its previously announced discovery in the Modified U(a) Block.

In 2022, EOG expects to drill one net exploratory well in the EOG Area in addition to three development wells and one exploratory well in the Modified U(a) Block.

Australia. On April 22, 2021, a subsidiary of EOG entered into a purchase and sale agreement to acquire a 100% interest in the WA-488-P Block, located offshore Western Australia. On November 19, 2021, the petroleum exploration permit for that block was transferred to that subsidiary.

In 2022, EOG will continue preparing for the drilling of an exploration well which is expected to commence in 2023.

Oman. EOG, through its subsidiaries, holds interests in Exploration and Production Sharing Agreements in Block 36 and Block 49 located in Oman.

In 2021, EOG's partner in Block 49 completed the drilling and testing of one net exploratory well, which was determined to be a dry hole. EOG notified its partner and the Ministry of Energy and Minerals of its intention to withdraw from Block 49. Additionally, EOG drilled two exploratory wells and completed one exploratory well in Block 36. There was a discovery of natural gas in Block 36, but the well results did not yield sufficient projected returns for EOG to move forward with the project. In 2022, EOG expects to exit Block 36 in Oman.

China. In May 2021, EOG completed the sale of all of its interest in EOG Resources China Limited. EOG no longer has any operations or assets in China. EOG's net production averaged approximately 25 MMcfd of natural gas prior to the sale.

Canada. In March 2020, EOG began the process of exiting its Canada operations in the Horn River area in Northeast British Columbia.

3

Marketing

In 2021, 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 2021, 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 2022, the pricing mechanism for such production is expected to remain the same. At December 31, 2021, EOG was committed to deliver to multiple parties fixed quantities of crude oil of 16 MMBbls in 2022, 7 MMBbls in 2023, 7 MMBbls in 2024, and 1 MMBbls in 2025, all of which is expected to be sourced from future production of available reserves.

In 2021, 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 2022, such pricing mechanisms are expected to remain the same. In 2021, EOG also sold purity products at the Houston Ship Channel 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 2022, the pricing mechanism for such production is expected to remain the same. At December 31, 2021, EOG was not committed to deliver fixed quantities of NGLs in 2022.

In 2021, 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 2022, the pricing mechanism for such production is expected to remain the same. Additionally, EOG sells natural gas to a liquefaction facility near Corpus Christi, Texas, and receives pricing based on the Platts Japan Korea Marker. At December 31, 2021, EOG was committed to deliver to multiple parties fixed quantities of natural gas of 223 Bcf in 2022, 190 Bcf in 2023, 150 Bcf in 2024, 138 Bcf in 2025, 195 Bcf in 2026 and 1,459 Bcf thereafter, all of which is expected to be sourced from future production of available reserves.

In 2021, natural gas volumes from Trinidad were sold under a fixed price contract ending in 2026. The pricing mechanism for production in Trinidad is expected to remain the same in 2022.

Through May 2021, 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.

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

During 2021, two purchasers 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 two 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, 2021, 2020 and 2019. 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.

4

Year Ended December 31	2021	2020	2019
Crude Oil and Condensate Volumes (MMBbl) (1)
United States:
Eagle Ford Oil Play	51.8	54.6	68.3
Delaware Basin	84.3	67.0	63.4
Other	25.7	27.8	34.6
United States	161.8	149.4	166.3
Trinidad	0.5	0.4	0.2
Other International (2)	—	—	0.1
Total	162.3	149.8	166.6
Natural Gas Liquids Volumes (MMBbl) (1)
United States:
Eagle Ford Oil Play	9.0	9.7	10.7
Delaware Basin	30.9	27.7	23.5
Other	12.8	12.4	14.7
United States	52.7	49.8	48.9
Other International (2)	—	—	—
Total	52.7	49.8	48.9
Natural Gas Volumes (Bcf) (1)
United States:
Eagle Ford Oil Play	55	53	53
Delaware Basin	238	168	147
Other	149	160	190
United States	442	381	390
Trinidad	79	66	95
Other International (2)	3	11	14
Total	524	458	499
Crude Oil Equivalent Volumes (MMBoe) (3)
United States:
Eagle Ford Oil Play	70.0	73.1	87.8
Delaware Basin	154.9	122.7	111.4
Other	63.3	66.9	81.0
United States	288.2	262.7	280.2
Trinidad	13.7	11.4	16.0
Other International (2)	0.6	1.8	2.4
Total	302.5	275.9	298.6

5

Year Ended December 31	2021		2020		2019
Average Crude Oil and Condensate Prices ($/Bbl) (4)
United States	$	68.54	$	38.65	$	57.74
Trinidad	56.26		30.20		47.16
Other International (2)	42.36		43.08		57.40
Composite	68.50		38.63		57.72
Average Natural Gas Liquids Prices ($/Bbl) (4)
United States	$	34.35	$	13.41	$	16.03
Other International (2)	—		—		—
Composite	34.35		13.41		16.03
Average Natural Gas Prices ($/Mcf) (4)
United States	$	4.88	$	1.61	$	2.22
Trinidad	3.40		2.57		2.72
Other International (2)	5.67		4.66		4.44
Composite	4.66		1.83		2.38

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

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

(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, 2021, EOG employed approximately 2,800 persons, including foreign national employees. EOG's approach to human capital management includes oversight by the Board of Directors (Board) and the Compensation and Human Resources Committee of the Board and focuses on various areas, including the following:

Culture; Recruiting; Retention. EOG's culture is key to its sustainable success. By providing employees with a quality 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 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, an annual stock grant program and an employee stock purchase plan, every employee has the opportunity to be a participant in EOG's success.

COVID-19 Pandemic. 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 to enable them to not only work safely and productively from the office or at home, but also to remain engaged and connected across the company. In 2021, EOG continued to provide such technology and support and remained focused on the safety of its employees, reopening its offices and worksites in a phased approach and instituting additional practices and protocols, including those related to social distancing, mask wearing and symptom screening.

6

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

Diversity and Inclusion. EOG believes gender, racial, ethnic and cultural diversity, and diversity in background and experience, leads to diversity of thought, which is valued by EOG. As part of its effort to build and maintain a diverse and inclusive workplace, EOG focuses on creating a collaborative culture that fosters inclusion at all levels of the company and reflects the diversity of thought of its employees. EOG also takes steps to raise employee awareness, provide leadership and offer training to help advance diversity and inclusion within EOG. Further, as reflected in its Code of Business Conduct and Ethics for Directors, Officers and Employees, EOG is committed to providing equal opportunity in all aspects of employment and to hiring, evaluating and promoting employees based on skills and performance.

Safety. EOG's safety management programs and processes provide a framework within which management can 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.

7

Regulation

General. New or revised rules, regulations and policies may be issued, and new legislation may be proposed, that could impact the oil and gas exploration and production industry. Such rules, regulations, policies and legislation may affect, among other things, (i) permitting for oil and gas drilling on 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. For additional discussion regarding the regulatory-related risks to which EOG's operations, financial condition and results of operations are or may be subject, see the below discussion and ITEM 1A, Risk Factors.

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

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

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.

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. From time to time, the U.S. Department of the Interior has also considered limiting or pausing new oil and natural gas leases on federal lands or in offshore waters. 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 supporting EOG's operations 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.

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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 2021.

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.

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, EOG is unable to predict (i) the timing, scope and effect of any currently proposed or future laws or regulations regarding the environment and (ii) the ultimate cost of compliance or the ultimate effect on EOG's operations, financial condition and results of operations relating to such future laws and regulations. The direct and indirect cost of such laws and regulations (in enacted) could materially and adversely affect EOG's operations, financial condition and results of operations.

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Climate Change - United States. Local, state, federal and international regulatory bodies have been increasingly focused on GHG emissions and climate change issues in recent years. The U.S. Congress has, from time to time, proposed legislation for imposing restrictions or requiring fees or carbon taxes for GHG emissions. 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 November 2021, the EPA proposed a rule to further reduce methane and VOC emissions from new and existing sources in the oil and natural gas sector.

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 and which the United States formally rejoined in February 2021. The United States has established economy-wide targets of (i) reducing its net GHG emissions by 50-52 percent below 2005 levels by 2030 and (ii) achieving net zero GHG emissions economy-wide by no later than 2050. In addition, many state and local officials have stated their intent to intensify efforts to uphold the commitments set forth in the international accord. Further, in November 2021, the U.S. Department of the Interior released its "Report on the Federal Oil and Gas Leasing Program," which recommended increasing 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.), but the direct and indirect costs of such investigations, laws, regulations, treaties or policies (if enacted, issued or applied) could materially and adversely affect EOG's operations, financial condition and results of operations. The potential increase in the costs of our operations could include costs to operate and maintain our facilities, install new emissions controls on our facilities, acquire allowances or credits to cover our GHG emissions, pay taxes or fees related to our GHG emissions, or administer and manage a GHG emissions program. In addition, changes in regulatory policies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to GHG emissions, or restrictions on their use, could also adversely affect market demand for, and in turn the prices we receive for our production of, crude oil, NGLs and natural gas. Further, the increasing attention to global climate change risks has created the potential for a greater likelihood of governmental investigations and private and public litigation, which could increase our costs or otherwise adversely affect our business. See ITEM 1A, Risk Factors, for additional discussion regarding climate change-related developments..

Regulation of Hydraulic Fracturing and Other Operations - United States. Substantially all of the onshore crude oil and natural gas wells drilled by EOG are completed and stimulated through the use of hydraulic fracturing. Hydraulic fracturing technology, which has been used by the oil and gas industry for more than 60 years and is constantly being enhanced, enables EOG to produce crude oil and natural gas that otherwise would not be recovered. Specifically, hydraulic fracturing is a process in which pressurized fluid is pumped into underground formations to create tiny fractures or spaces that allow crude oil and natural gas to flow from the reservoir into the well so that it can be brought to the surface. Hydraulic fracturing generally takes place thousands of feet underground, a considerable distance below any drinking water aquifers, and there are impermeable layers of rock between the area fractured and the water aquifers. The makeup of the fluid used in 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.

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The regulation of hydraulic fracturing is primarily conducted at the state and local level through permitting and other compliance requirements. In April 2012, however, the U.S. EPA issued regulations specifically applicable to the oil and gas industry that require operators to significantly reduce VOC emissions from natural gas wells that are hydraulically fractured through the use of "green completions" to capture natural gas that would otherwise escape into the air. The U.S. EPA has also issued regulations that establish standards for VOC emissions from several types of equipment, including storage tanks, compressors, dehydrators, and valves and sweetening units at gas processing plants. In addition, 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 November 2021, the EPA proposed a rule to further reduce methane and VOC emissions from new and existing sources in the oil and natural gas sector. From time to time, there have been various other proposals to regulate hydraulic fracturing at the federal level.

In addition to the above-described federal regulations, some state and local governments have imposed, or have considered imposing, various conditions and restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water; disclosure of the chemical additives used in hydraulic fracturing operations; restrictions on the type of chemical additives that may be used in hydraulic fracturing operations; and restrictions on drilling or injection activities on certain lands lying within wilderness wetlands, ecologically or seismically sensitive areas, and other protected areas. Such federal, state and local permitting and disclosure requirements, operating restrictions, conditions or 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.

Other International Regulation. EOG's exploration and production operations outside the United States are subject to various types of regulations, including environmental regulations, imposed by the respective governments of the countries in which EOG's operations are conducted, and may affect EOG's operations and costs of compliance within those countries. EOG is unable to predict the timing, scope and effect of any currently proposed or future laws, regulations or treaties, including those regarding climate change and hydraulic fracturing, but the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely affect EOG's operations, financial condition 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.

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Other Matters

Energy Prices. EOG is a crude oil and natural gas producer and is impacted by changes in the prices for crude oil and condensate, NGLs and natural gas. During the last three years, average United States commodity prices have fluctuated, at times rather dramatically. Average crude oil and condensate prices received by EOG for production in the United States increased 77% in 2021, decreased 33% in 2020 and decreased 11% in 2019, each as compared to the immediately preceding year. Average NGL prices received by EOG for production in the United States increased 156% in 2021, decreased 16% in 2020 and decreased 40% in 2019, each as compared to the immediately preceding year. Fluctuations in average natural gas prices received by EOG for production in the United States resulted in a 203% increase in 2021, a 27% decrease in 2020, and a 23% decrease in 2019, 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, the potential impacts on EOG 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 2022 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 $107 million for net income and $138 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 2022 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 $15 million for net income and $19 million for pretax cash flows from operating activities. For a summary of EOG's financial commodity derivative contracts through February 18, 2022, 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 year ended December 31, 2021, see Note 12 to Consolidated Financial Statements.

Risk Management. EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in prices of crude oil, NGLs and natural gas. EOG utilizes financial commodity derivative instruments, primarily price swap, option, swaption, collar and basis swap contracts, as a means to manage this price risk. See Note 12 to Consolidated Financial Statements. For a summary of EOG's financial commodity derivative contracts through February 18, 2022, 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, for any incident involving EOG's operations which results in negative environmental effects, EOG maintains operators extra expense coverage provided by third-party insurers for obligations, expenses or claims that EOG may incur from such an incident, including obligations, expenses or claims in respect of 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.

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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 24, 2022) are as follows:

Name	Age	Position
Ezra Y. Yacob	45	Chief Executive Officer
Lloyd W. Helms, Jr.	64	President and Chief Operating Officer
Kenneth W. Boedeker	59	Executive Vice President, Exploration and Production
Jeffrey R. Leitzell	42	Executive Vice President, Exploration and Production
Timothy K. Driggers	60	Executive Vice President and Chief Financial Officer
Michael P. Donaldson	59	Executive Vice President, General Counsel and Corporate Secretary

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

Lloyd W. Helms, Jr. was elected President and Chief Operating Officer effective October 2021. Mr. Helms has served as Chief Operating Officer since 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.

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.

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

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

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

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

•domestic and international drilling activity;

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

•worldwide economic conditions, geopolitical factors and political conditions, including, but not limited to, the imposition of tariffs or trade or other economic sanctions, political instability or armed conflict in oil and gas producing regions;

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

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

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

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

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

•the nature and extent of governmental regulation, including environmental and other climate change-related regulation, regulation of 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

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

The above-described factors and the volatility of commodity prices make it difficult to predict crude oil, NGLs and natural gas prices in 2022 and thereafter. As a result, there can be no assurance that the prices for crude oil, NGLs and/or natural gas will sustain, or increase from, their current levels, nor can there be any assurance that the prices for crude oil, NGLs and/or natural gas will not decline.

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

Lower commodity prices can also reduce the amount of crude oil, NGLs and natural gas that we can produce economically. Substantial and extended declines in the prices of these commodities can render uneconomic a portion of our exploration, development and exploitation projects, resulting in our having to make downward adjustments 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.

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

Governmental and regulatory bodies, investors, consumers, industry and other stakeholders have been increasingly focused on climate change matters in recent years. This focus, together with changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy, the use of crude oil, NGLs and natural gas and the use of products manufactured with, or powered by, crude oil, NGLs and natural gas, may result in (i) the enactment of climate change-related regulations, policies and initiatives (at the government, corporate and/or investor community levels), including alternative energy requirements and energy conservation measures, (ii) technological advances with respect to the generation, transmission, storage and consumption of energy (e.g., wind, solar and hydrogen power, smart grid technology and battery technology) and (iii) increased availability of, and increased consumer and industrial/commercial demand for, non-hydrocarbon energy sources (e.g., alternative energy sources) and products manufactured with, or powered by, non-hydrocarbon sources (e.g., electric vehicles and renewable residential and commercial power supplies). These developments may adversely affect the demand for products manufactured with, or powered by, crude oil, NGLs and natural gas and the demand for, and in turn the prices of, the crude oil, NGLs and natural gas that we sell. See the risk factor above for a discussion of the impact of commodity prices (including fluctuations in commodity prices) on our financial condition, cash flows and results of operations.

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

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

In addition, the enactment of climate change-related regulations, policies and initiatives (at the government, corporate and/or investor community levels) may also result in increases in our compliance costs and other operating costs and have other adverse effects (e.g., greater potential for governmental investigations or litigation). For further discussion regarding the risks to us of climate change-related regulations, policies and initiatives, see the discussion below in the section entitled "Risks Related to Regulatory and Legal Matters."

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

We make, and expect to continue to make, substantial capital expenditures for the acquisition, exploration, development and production of crude oil, NGLs and natural gas reserves. We intend to finance our capital expenditures primarily through our cash flows from operations, cash on hand 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.

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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.

In addition, companies in the oil and gas sector may be exposed to increasing reputational risks and, in turn, certain financial risks. Specifically, certain financial institutions (including certain investment advisors and sovereign wealth, pension and endowment funds), in response to concerns related to climate change and the requests and other influence of environmental groups and similar stakeholders, have elected to shift some or all of their investments away from oil and gas-related sectors, and additional financial institutions and other investors may elect to do likewise in the future. As a result, fewer financial institutions and other investors may be willing to invest in, and provide capital to, companies in the oil and gas sector. A material reduction in capital available to the oil and gas sector could make it more difficult (e.g., due to a lack of investor interest in our equity or debt securities) and/or more costly (e.g., due to higher interest rates on our debt securities or other borrowings) to secure funding for our operations, which, in turn, could adversely affect our ability to successfully carry out our business strategy and have a material and adverse effect on our business, financial condition and operations.

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

Estimating quantities of crude oil, NGLs and natural gas reserves and future net cash flows from such reserves is a complex, inexact process. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors, made by our management. Any significant inaccuracies in these interpretations or assumptions could cause the reported quantities of our reserves and future net cash flows from such reserves to be overstated or understated. Also, the data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, continual reassessment of the viability of production under varying economic conditions and improvements and other changes in geological, geophysical and engineering evaluation methods.