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, 2019

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 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, 2019: $54,011 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, 582,054,451 shares outstanding as of February 13, 2020.

Documents incorporated by reference.  Portions of the Definitive Proxy Statement for the registrant's 2020 Annual Meeting of Stockholders, to be filed within 120 days after December 31, 2019, 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
	Competition	7
	Regulation	7
	Other Matters	11
	Information About Our Executive Officers	12
ITEM 1A.	Risk Factors	13
ITEM 1B.	Unresolved Staff Comments	23
ITEM 2.	Properties	24
	Oil and Gas Exploration and Production - Properties and Reserves	24
ITEM 3.	Legal Proceedings	27
ITEM 4.	Mine Safety Disclosures	27
PART II
ITEM 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	28
ITEM 6.	Selected Financial Data	30
ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	31
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk	50
ITEM 8.	Financial Statements and Supplementary Data	50
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	50
ITEM 9A.	Controls and Procedures	50
ITEM 9B.	Other Information	51
PART III
ITEM 10.	Directors, Executive Officers and Corporate Governance	51
ITEM 11.	Executive Compensation	51
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	52
ITEM 13.	Certain Relationships and Related Transactions, and Director Independence	53
ITEM 14.	Principal Accounting Fees and Services	53
PART IV
ITEM 15.	Exhibits, Financial Statement Schedules	54
ITEM 16.	Form 10-K Summary	54
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), Canada 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, 2019, EOG's total estimated net proved reserves were 3,329 million barrels of oil equivalent (MMBoe), of which 1,694 million barrels (MMBbl) were crude oil and condensate reserves, 740 MMBbl were NGLs reserves and 5,370 billion cubic feet (Bcf), or 895 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.

As of December 31, 2019, EOG employed approximately 2,900 persons, including foreign national employees.

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 production growth while maintaining a strong balance sheet.  EOG is focused on 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, 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 that is consistent with efficient, safe and environmentally responsible operations is also an important goal 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, 2019, on a crude oil equivalent basis, 52% of EOG's net proved reserves in the United States were crude oil and condensate, 23% were NGLs and 25% 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.

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The following is a summary of significant developments during 2019 and anticipated 2020 plans for certain areas of EOG's United States operations.

2019							2020
Area of Operation	Crude Oil & Condensate Volumes (MBbld) (1)	Natural Gas Liquids Volumes (MBbld) (1)	Natural Gas Volumes (MMcfd) (1)	Total Net Acres (2)		Net Well Completions	Expected Net Well Completions
Eagle Ford	187	30	146	579,000		321	300
Austin Chalk	15	7	41	—	(3)	14	6
Delaware Basin	174	65	402	389,000		276	350
Rocky Mountain Area	62	15	188	1,264,000		96	95
Upper Gulf Coast	—	—	10	360,000		1	—
Mid-Continent	10	2	20	120,000		32	20
Fort Worth Basin	2	12	67	146,000		—	—
South Texas	1	1	102	564,000		15	15
Marcellus Shale	—	—	68	151,000		—	—

(1) Thousand barrels per day or million cubic feet per day, as applicable. Total volumes exclude 5 MBbld of crude oil and condensate, 2 MBbld of NGLs and 25 MMcfd of natural gas related to other plays.

(2) Total net acres excludes approximately 0.7 million net acres in other areas.

(3) The Austin Chalk play encompasses the same net acres as the Eagle Ford.

The Eagle Ford is a world-class crude oil field which has produced in excess of 3.4 billion barrels of crude oil and condensate. With approximately 516,000 of its 579,000 total net acres in the prolific oil window, EOG continues to be the largest crude oil producer in the Eagle Ford with cumulative gross production in excess of 600 MMBbl of crude oil and condensate. In 2019, EOG completed 321 net Eagle Ford wells and 14 net Austin Chalk wells. EOG continues to evaluate the prospectivity of the Austin Chalk, which overlays EOG's Eagle Ford acreage. EOG has approximately 150 Eagle Ford net wells in its enhanced oil recovery (EOR) gas injection program. The company did not add wells to the EOR program in 2019 and does not expect to add wells in 2020. EOR is a secondary recovery process and the company continues to evaluate the primary development opportunities on its acreage before expanding the EOR program. In 2020, EOG expects to complete approximately 300 net Eagle Ford wells and 6 net Austin Chalk wells while continuing to improve well productivity and operational efficiencies. The combination of exceptional execution and continuous operational improvements have made this play one of the foundations of EOG's portfolio.

In the Delaware Basin, EOG completed 276 net wells during 2019, primarily in the Delaware Basin Wolfcamp, Bone Spring and Leonard plays. EOG also identified additional drilling locations in the Wolfcamp M and Third Bone Spring formations, expanding its inventory of future drilling locations across its approximately 389,000 total net acre position. The Delaware Basin consists of approximately 4,800 feet of stacked pay potential across multiple zones, offering EOG co-development opportunities across its acreage position.

In the Delaware Basin Wolfcamp play, where it has approximately 346,000 net acres, EOG completed 201 net wells in 2019. EOG continued its development plan with well spacing as close as 500 feet in the crude oil portion and 880 feet in the combination crude oil and natural gas portion. Results in the Delaware Basin Wolfcamp program were supported by optimized well spacing, the application of enhanced well completions, precision drilling and continued cost reductions. The Delaware Basin Wolfcamp play will continue to be a primary area of focus in 2020.

In the Third Bone Spring play, EOG completed 13 net wells in 2019 on its 200,000 net prospective acres. With multiple targets and ample co-development opportunities, the Third Bone Spring play is expected to be a large portion of EOG’s future development program. In the Second Bone Spring play, EOG holds approximately 289,000 net acres and completed 34 net wells in 2019. EOG also continued development in the First Bone Spring play where EOG has approximately 100,000 net acres and completed nine net wells in 2019. Both the First and Second Bone Spring plays continue to be an integral part of EOG’s Delaware Basin portfolio.

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In the Leonard play, EOG has approximately 160,000 net acres and continued development with 19 net wells completed in 2019.

Activity in 2020 will continue to be focused in the Delaware Basin Wolfcamp, Third Bone Spring, Second Bone Spring, First Bone Spring and Leonard plays, where EOG expects to complete approximately 350 net wells.

Activity in the Rocky Mountain area was consistent in 2019 with a focus on the Wyoming Powder River Basin. In the Powder River Basin, EOG operated a two-rig program and completed 32 net wells in the Niobrara, Mowry, Turner and Parkman formations. The focus in 2019 was to delineate the Mowry and Niobrara plays and to begin adding infrastructure. Drilling activity and infrastructure buildout will increase significantly in 2020 as activity shifts to development drilling. The infrastructure added will lower operating costs and increase price realizations going forward. In the Wyoming DJ Basin, EOG operated one rig and completed 44 net wells in 2019 in both the Codell and the Niobrara formations. Activity in the DJ Basin is expected to be moderate in 2020 as activity shifts to the Powder River Basin. In the Williston Basin, EOG completed 20 net wells in the Bakken and Three Forks. On average, well performance in the Williston Basin greatly improved due to better targeting and completion techniques. The seasonal program of completing wells mostly in the summer while drilling throughout the year will continue in 2020, although activity will be at a slightly lower pace than 2019. EOG currently holds approximately 1.3 million net acres in the Rocky Mountain area.

In the Mid-Continent area, EOG continued its development of the Woodford Oil Window play with 30 net wells completed during 2019. EOG holds 41,700 net acres in the play and plans to build on its results in the Woodford Oil Window with 20 net well completions in 2020. In 2019, EOG completed 11 gross (two net) wells in the Western Anadarko Basin Marmaton Sand.

Net production for the Marcellus Shale in 2019 averaged approximately 68.3 MMcfd of natural gas. At December 31, 2019, EOG held approximately 151,000 net acres in the Marcellus Shale.

Fort Worth Basin Barnett Shale production averaged 1.7 MBbld of crude oil and condensate, 12.2 MBbld of NGLs and 67.4 MMcfd of natural gas in 2019.

In the South Texas area, EOG completed 15 net wells in 2019. Exploration and evaluation efforts will continue in this region in 2020, where we expect to drill and complete another 15 net wells.

At December 31, 2019, EOG held approximately 2.3 million net undeveloped acres in the United States.

During 2019, EOG continued to operate gathering and processing facilities in the Eagle Ford in South Texas, the Williston Basin Bakken and Three Forks plays in North Dakota, the Fort Worth Basin Barnett Shale and the Permian Basin in West Texas and New Mexico. At December 31, 2019, EOG-owned natural gas processing capacity in the Eagle Ford and the Fort Worth Basin Barnett Shale totaled 325 MMcfd and 180 MMcfd, respectively.

Operations Outside the United States

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

Trinidad. EOG, through several of its subsidiaries, including EOG Resources Trinidad Limited,

• holds an 80% working interest in the exploration and production license covering the South East Coast Consortium (SECC) Block offshore Trinidad, except in the Deep Ibis area in which EOG's working interest decreased as a result of a third-party farm-out agreement;

• holds an 80% working interest in the exploration and production license covering the Pelican Field and its related facilities;

• holds a 50% working interest in the exploration and production licenses covering the Sercan Area offshore Trinidad;

• holds a 100% working interest in a production sharing contract with the Government of Trinidad and Tobago for each of the Modified U(a) Block, Modified U(b) Block and Block 4(a);

• holds a 50% working interest in the exploration and production license covering the Banyan Field;

• holds a 50% working interest in the exploration and production license covering the Ska, Mento, Reggae Area deep Teak, deep Saaman and deep Poui offshore Trinidad (collectively SMR Area);

• owns a 12% equity interest in an anhydrous ammonia plant in Point Lisas, Trinidad, that is owned and operated by Caribbean Nitrogen Company Limited; and

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• owns a 10% equity interest in an anhydrous ammonia plant in Point Lisas, Trinidad, that is owned and operated by Nitrogen (2000) Unlimited.

Several fields in the SECC Block, Modified U(a) Block, Modified U(b) Block, Block 4(a), the Banyan Field and the Sercan Area have been developed and are producing natural gas and crude oil and condensate. Natural gas from EOG's Trinidad operations currently is sold under various contracts with the National Gas Company of Trinidad and Tobago Limited and its subsidiary (NGC). Crude oil and condensate from EOG's Trinidad operations currently is sold under various contracts to Heritage Petroleum Company Limited (Heritage).

In 2019, EOG's net production from Trinidad averaged approximately 260 MMcfd of natural gas and approximately 0.6 MBbld of crude oil and condensate. In 2019, EOG drilled and completed two net wells in Trinidad and was in the process of drilling another exploratory well at December 31, 2019. One of these wells was a successful development well, while the other well was determined to be an unsuccessful exploratory well. In addition, EOG drilled one stratigraphic exploratory well in Trinidad, which discovered commercially economic reserves. At December 31, 2019, EOG held approximately 115,000 net undeveloped acres in Trinidad.

In 2020, EOG expects to drill and complete three net wells in Trinidad. All of the natural gas produced from EOG's Trinidad operations in 2020 is expected to be sold to NGC. All crude oil and condensate produced from EOG's Trinidad operations in 2020 is expected to be sold to Heritage.

China. In July 2008, EOG acquired rights from ConocoPhillips in a Petroleum Contract covering the Chuan Zhong Block exploration area in the Sichuan Basin, Sichuan Province, China. In October 2008, EOG obtained the rights to shallower zones on the acquired acerage.

In 2019, EOG drilled two natural gas wells to complete the drilling program started in 2018. In 2019, EOG also completed two natural gas wells that were drilled during the 2018 drilling program. All natural gas produced from the Baijaochang Field is sold under a long-term contract to PetroChina. In 2019, production averaged approximately 30 MMcfd of natural gas, net, in China.

EOG plans to continue to complete the remaining drilled uncompleted wells (DUCs) in the future as pipeline capacity allows.

Marketing

In 2019, EOG continued its diversified approach to marketing its wellhead crude oil and condensate production. The majority of production was transported by pipeline to downstream markets with the remainder sold into local markets. Major U.S. sales areas accessed by EOG were various locations along the U.S. Gulf coast, including Houston and Corpus Christi, Texas and Louisiana; Cushing, Oklahoma; the Permian Basin and the Midwest. In late 2019, EOG also sold crude oil at the Houston Ship Channel (HSC) 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 2020, the pricing mechanism for such production is expected to remain the same. In 2020, EOG expects to sell crude oil at the Port of Corpus Christi for export, in addition to sales at the HSC. At December 31, 2019, EOG was committed to deliver to multiple parties fixed quantities of crude oil of 28 MMBbls in 2020 and 2 MMBbls in 2021, all of which is expected to be delivered from future production of available reserves.

In 2019, EOG processed certain of its 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 downstrean, which were sold at prevailing market prices. In 2020, such pricing mechanisms are expected to remain the same.

In 2019, 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 2020, the pricing mechanism for such production is expected to remain the same. Additionally in 2019, EOG entered into an agreement, beginning in 2020, to sell natural gas to an LNG liquefaction facility near Corpus Christi, Texas and receive pricing based on the Platts Japan Korea Marker. At December 31, 2019, EOG was committed to deliver to multiple parties fixed quantities of natural gas of 159 Bcf in 2020, 108 Bcf in 2021, 82 Bcf in 2022, 82 Bcf in 2023, 31 Bcf in 2024 and 1,685 Bcf thereafter, all of which is expected to be delivered from future production of available reserves.

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In 2019, 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 and under a fixed price contract. The pricing mechanisms for these contracts in Trinidad are expected to remain the same in 2020; however, we anticipate the majority of volumes will be sold under a fixed price contract.

In 2019, 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 2020.

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.

During 2019, two 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 two purchasers are in the crude oil refining industry. EOG does not believe that the loss of any single purchaser would have a material adverse effect on its financial condition or results of operations.

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, 2019, 2018 and 2017. 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.

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Year Ended December 31	2019	2018	2017
Crude Oil and Condensate Volumes (MMBbl) (1)
United States:
Eagle Ford	68.3	62.4	57.4
Delaware Basin	63.4	46.3	31.6
Other	34.6	35.4	33.2
United States	166.3	144.1	122.2
Trinidad	0.2	0.3	0.3
Other International (2)	0.1	1.6	0.2
Total	166.6	146.0	122.7
Natural Gas Liquids Volumes (MMBbl) (1)
United States:
Eagle Ford	10.7	11.4	9.4
Delaware Basin	23.5	15.8	8.8
Other	14.7	15.3	14.1
United States	48.9	42.5	32.3
Other International (2)	—	—	—
Total	48.9	42.5	32.3
Natural Gas Volumes (Bcf) (1)
United States:
Eagle Ford	53	58	55
Delaware Basin	147	110	81
Other	190	169	143
United States	390	337	279
Trinidad	95	97	114
Other International (2)	14	11	9
Total	499	445	402
Crude Oil Equivalent Volumes (MMBoe) (3)
United States:
Eagle Ford	87.8	83.5	76.0
Delaware Basin	111.4	80.3	53.9
Other	81.0	78.8	71.2
United States	280.2	242.6	201.1
Trinidad	16.0	16.5	19.4
Other International (2)	2.4	3.4	1.8
Total	298.6	262.5	222.3

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Year Ended December 31	2019		2018			2017
Average Crude Oil and Condensate Prices ($/Bbl) (4)
United States	$	57.74	$	65.16		$	50.91
Trinidad	47.16		57.26			42.30
Other International (2)	57.40		71.45			57.20
Composite	57.72		65.21			50.91
Average Natural Gas Liquids Prices ($/Bbl) (4)
United States	$	16.03	$	26.60		$	22.61
Other International (2)	—		—			—
Composite	16.03		26.60			22.61
Average Natural Gas Prices ($/Mcf) (4)
United States	$	2.22	$	2.88		$	2.20
Trinidad	2.72		2.94			2.38
Other International (2)	4.44		4.08			3.89
Composite	2.38		2.92		(5)	2.29

(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).

(5) Includes a positive revenue adjustment of $0.44 per Mcf related to the adoption of Accounting Standards Update (ASU) 2014-09, "Revenue From Contracts with Customers" (ASU 2014-09) (see Note 1 to the Consolidated Financial Statements). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees related to certain processing and marketing agreements as Gathering and Processing Costs, instead of as a deduction to Natural Gas revenues.

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 contract personnel (including geologists, geophysicists, engineers and other specialists) required to explore for, develop, produce, market and transport crude oil 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 and natural gas, such as changing worldwide prices and levels of production and the cost and availability of alternative fuels. EOG also faces competition, to a lesser extent, from competing energy sources, such as alternative energy sources.

Regulation

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.

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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.

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 Barnett Shale in North Texas, the 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 2019.

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

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

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. However, the U.S. has begun the process to withdraw from the Paris Agreement. In response, many state and local officials have stated their intent to intensify efforts to uphold the commitments set forth in the international accord.

EOG believes that its strategy to 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 or treaties regarding climate change and GHG emissions, but the direct and indirect costs of such investigations, laws, regulations and treaties (if enacted) 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.

Also, in November 2016, the BLM issued a final rule that limits venting, flaring and leaking of natural gas from oil and gas wells and equipment on federal and Indian lands, though, in September 2018, the BLM issued a final rule rescinding certain requirements of that rule. There have been various other proposals to regulate hydraulic fracturing at the federal level. In addition, there have been proposals and positions taken by candidates for elected office and others regarding additional restrictions on, or the complete prohibition of, hydraulic fracturing operations.

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. 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.

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. Average crude oil and condensate prices received by EOG for production in the United States decreased 11% in 2019, and increased 28% in 2018 and 22% in 2017, each as compared to the immediately preceding year. Average NGL prices received by EOG for production in the United States decreased 40% in 2019, and increased 18% in 2018 and 55% in 2017, each as compared to the immediately preceding year. During the last three years, average United States wellhead natural gas prices have fluctuated, at times rather dramatically. These fluctuations resulted in a 23% decrease in the average wellhead natural gas price received by EOG for production in the United States in 2019, a 31% increase (inclusive of a positive revenue adjustment of $0.44 per Mcf related to the adoption of ASU 2014-09) in 2018 and a 38% increase in 2017, 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), 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.

Based on EOG's tax position, EOG's price sensitivity (exclusive of basis swaps) in 2020 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 $117 million for net income and $152 million for pretax cash flows from operating activities. Based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2020 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 19, 2020, see ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Derivative Transactions. For a summary of EOG's financial commodity derivative contracts for the twelve months ended December 31, 2019, 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 19, 2020, see ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations ‑ Capital Resources and Liquidity - Derivative Transactions.

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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 27, 2020) are as follows:

Name	Age	Position
William R. Thomas	67	Chairman of the Board and Chief Executive Officer
Lloyd W. Helms, Jr.	62	Chief Operating Officer
Kenneth W. Boedeker	57	Executive Vice President, Exploration and Production
Ezra Y. Yacob	43	Executive Vice President, Exploration and Production
Timothy K. Driggers	58	Executive Vice President and Chief Financial Officer
Michael P. Donaldson	57	Executive Vice President, General Counsel and Corporate Secretary

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.

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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.

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.

Ezra Y. Yacob was elected Executive Vice President, Exploration and Production in December 2017. He served as Vice President and General Manager of EOG's Midland, Texas, office from May 2014 to December 2017. Prior to that, he 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.

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.

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;

• 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 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;

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• 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

• weather conditions and changes in weather patterns.

The above-described factors and the volatility of commodity prices make it difficult to predict future crude oil, natural gas and NGL prices. As a result, there can be no assurance that the prices for crude oil, natural gas and NGLs will sustain, or increase from, their current levels and not 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 other 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, natural gas and NGLs 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 will require us to write down the value of our properties. Such reserve write-downs and asset impairments could materially and adversely affect our results of operations and financial position and, in turn, the trading price of our common stock.

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 impairment charges and/or make 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 adversely affected.

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 and natural gas reserves (including "dry holes"). 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, 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 affected by (among other things) 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 and market crude oil, natural gas and related commodities; and

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• 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;

• 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 adverse effect 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 adverse effect on our business.

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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:

• unauthorized access to, and release of, our business data, reserves information, strategic information or other sensitive or proprietary information, which could have a material adverse effect on our ability to compete for oil and gas resources;

• 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 of America (United States or U.S.). 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.

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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 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.

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 and transportation 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 and transportation facilities and equipment owned by third parties. These facilities 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 and transportation 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 and transportation facilities, 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 or transportation facilities, export facilities and equipment or the availability of these facilities, 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.

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. 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.

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, in turn, materially and adversely affect our business, results of operations and financial condition.

17

Specifically, as a current or past owner or lessee and operator of crude oil and natural gas properties, we are subject to various federal, state, tribal, local and foreign regulations relating to the discharge of materials into, and the protection of, the environment. These regulations may, among other things, impose liability on us for the cost of pollution cleanup resulting from current or past operations, subject us to liability for pollution damages and require suspension or cessation of operations in affected areas. Changes in, or additions to, these regulations could lead to increased operating and compliance costs and, in turn, materially and adversely affect our business, results of operations 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. In November 2016, however, the U.S. Bureau of Land Management (BLM) issued a final rule that limits venting, flaring and leaking of natural gas from oil and gas wells and equipment on federal and Indian lands (in September 2018, the BLM issued a final rule rescinding certain requirements of the rule). In addition, 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. Further, there have been proposals and positions taken by candidates for elected office and others regarding additional restrictions on, or the complete prohibition of, hydraulic fracturing operations.

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.

Regulations 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 greenhouse gas (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, in May 2016, the U.S. EPA issued regulations that require operators to reduce methane emissions and 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, gas processing plants and natural gas transmission compressor stations.

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. However, the U.S. has begun the process to withdraw from the Paris Agreement. In response, many state and local officials have stated their intent to intensify efforts to uphold the commitments set forth in the international accord.

It is possible that the Paris Agreement and subsequent domestic and international regulations 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 or treaties regarding climate change and GHG emissions, but the direct and indirect costs of such investigations, laws, regulations and treaties (if enacted) could materially and adversely affect our operations, financial condition and results of operations. For additional discussion regarding climate change regulation, see Climate Change - United States under ITEM 1, Business - Regulation.

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.

18

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 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.

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 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 assess fully 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 below), 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.

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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, commercial paper borrowings and sales of non-core assets and, to a lesser extent and if and as necessary, 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, NGLs and natural gas prices or unanticipated well shut-ins) and the corresponding adverse effect on our financial condition and results of operations may also increase the interest rates that lenders and commercial paper investors require us to pay. A substantial increase in interest rates would decrease our net cash flows available for reinvestment. Any of these factors could have a material and adverse effect on our business, financial condition and results of operations.

Further, our ability to obtain financings, our borrowing costs and the terms of any financings are, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. The interrelated factors that may impact our credit ratings include our debt levels; planned capital expenditures and sales of assets; near-term and long-term production growth opportunities; liquidity; asset quality; cost structure; product mix; and commodity pricing levels (including, but not limited to, the estimates and assumptions of credit rating agencies with respect to future commodity prices). We cannot provide any assurance that our current credit ratings will remain in effect for any given period of time or that our credit ratings will be raised in the future, nor can we provide any assurance that any of our credit ratings will not be lowered.

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.

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.

20

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 contract personnel (including geologists, geophysicists, engineers and other specialists) necessary to explore for, develop, produce, market and transport crude oil 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 and natural gas, such as changing worldwide prices and levels of production and the cost and availability of alternative fuels. We also face competition, to a lesser extent, from competing energy sources, such as alternative energy sources.

Reserve estimates depend on many interpretations and assumptions that may turn out to be inaccurate. 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 and our independent petroleum consultants. Any significant inaccuracies in these interpretations or assumptions could cause the reported quantities of our reserves and future net cash flows from such reserves to be overstated or understated. Also, the data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, continual reassessment of the viability of production under varying economic conditions and improvements and other changes in geological, geophysical and engineering evaluation methods.

To prepare estimates of our economically recoverable crude oil, NGLs and natural gas reserves and future net cash flows from our reserves, we analyze many variable factors, such as historical production from the area compared with production rates from other producing areas. We also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also involves economic assumptions relating to commodity prices, production costs, gathering, processing, compression, storage and transportation costs, severance, ad valorem and other applicable taxes, capital expenditures and workover and remedial costs, many of which 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 revisions or "write-downs" to our existing reserve estimates, could materially and adversely affect our business, financial condition and results of operations and, in turn, the trading price of our common stock. For related discussion, see ITEM 2, Properties - Oil and Gas Exploration and Production - Properties and Reserves and Supplemental Information to Consolidated Financial Statements.

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 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.

21

Our hedging activities may prevent us from benefiting fully 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 2020 is subject to fluctuating market prices. If we are ultimately unable to hedge additional production volumes for 2020 and beyond, we will be 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.

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 immediately above, 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.

Our business and prospects for future success depend to a significant extent upon the continued service and performance of our management team.

Our business and prospects for future success, including the successful implementation of our strategies and handling of issues integral to our future success, depend to a significant extent upon the continued service and performance of our management team. The loss of any member of our management team, and our inability to attract, motivate and retain substitute management personnel with comparable experience and skills, could materially and adversely affect our business, financial condition and results of operations.

22

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 and modifications to, or withdrawal from, international trade treaties. 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 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, 2019, less than 1% of our net operating revenues related to operations of our foreign subsidiaries whose functional currency was not the U.S. dollar.

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 at times 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 society 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.

ITEM 1B.  Unresolved Staff Comments

Not applicable.

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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."

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.  The volumes to be generated from future activities of EOG are therefore highly dependent upon the level of success in finding or acquiring additional reserves.  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, 2019. 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	2,773,841	2,034,901	3,083,256	2,272,783	5,857,097	4,307,684
Trinidad	79,277	67,474	201,435	115,274	280,712	182,748
China	130,548	130,548	—	—	130,548	130,548
Canada	39,842	35,613	103,618	96,494	143,460	132,107
Total	3,023,508	2,268,536	3,388,309	2,484,551	6,411,817	4,753,087

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 and five years. Approximately 0.4 million net acres will expire in 2020, 0.3 million net acres will expire in 2021 and 0.1 million net acres will expire in 2022 if production is not established or we take no other action to extend the terms of the leases or obtain concessions. 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. As of December 31, 2019, there were no proved undeveloped reserves associated with such undeveloped acreage.

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Productive Well Summary. The following table represents EOG's gross and net productive wells, including 2,465 wells in which we hold a royalty interest.

	Crude Oil		Natural Gas		Total
	Gross	Net	Gross	Net	Gross	Net
United States	9,798	6,882	5,133	2,735	14,931	9,617
Trinidad	2	2	30	24	32	26
China	—	—	38	38	38	38
Canada	—	—	24	23	24	23
Total (1)	9,800	6,884	5,225	2,820	15,025	9,704

(1) EOG operated 10,641 gross and 9,297 net producing crude oil and natural gas wells at December 31, 2019. Gross crude oil and natural gas wells include 238 wells with multiple completions.

Drilling and Acquisition Activities.  During the years ended December 31, 2019, 2018 and 2017, EOG expended $6.6 billion, $6.4 billion and $4.4 billion, respectively, for exploratory and development drilling, facilities and acquisition of leases and producing properties, including asset retirement obligations of $186 million, $70 million and $56 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, 2019, 2018 and 2017:

	Gross Development Wells Completed				Gross Exploratory Wells Completed
	Crude Oil	Natural Gas	Dry Hole	Total	Crude Oil	Natural Gas	Dry Hole	Total
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
2017
United States	568	22	13	603	—	—	1	1
Trinidad	—	8	—	8	—	1	—	1
China	—	3	—	3	—	—	1	1
Total	568	33	13	614	—	1	2	3

25

The following tables set forth the results of the net crude oil and natural gas wells completed for the years ended December 31, 2019, 2018 and 2017:

	Net Development Wells Completed				Net Exploratory Wells Completed
	Crude Oil	Natural Gas	Dry Hole	Total	Crude Oil	Natural Gas	Dry Hole	Total
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
2017
United States	490	21	13	524	—	—	1	1
Trinidad	—	6	—	6	—	1	—	1
China	—	3	—	3	—	—	1	1
Total	490	30	13	533	—	1	2	3

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, 2019, 2018 and 2017:

	Wells in Progress at End of Period
	2019		2018		2017
	Gross	Net	Gross	Net	Gross	Net
United States	317	286	297	238	247	208
Trinidad	1	1	—	—	—	—
China	3	3	4	4	1	1
Total	321	290	301	242	248	209

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, 2019, there were approximately 100 MMBoe of net proved undeveloped reserves (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
	2019		2018		2017
	Gross	Net	Gross	Net	Gross	Net
United States	188	165	168	137	147	121
China	3	3	3	3	1	1
Total	191	168	171	140	148	122

26

EOG acquired wells as set forth in the following tables as of the end of each period (excluding the acquisition of additional interests in 11, 114 and 29 net wells in which EOG previously owned an interest for the years ended December 31, 2019, 2018 and 2017, respectively):

	Gross Acquired Wells			Net Acquired Wells
	Crude Oil	Natural Gas	Total	Crude Oil	Natural Gas	Total
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
2017
United States	12	3	15	6	2	8
Total	12	3	15	6	2	8

Other Property, Plant and Equipment. EOG's other property, plant and equipment primarily includes gathering, transportation and processing infrastructure assets, buildings, crude-by-rail assets, and sand mine 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. 

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 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.

27

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 (NYSE) under the ticker symbol "EOG."

As of February 13, 2020, there were approximately 2,170 record holders and approximately 386,000 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, 2019 - October 31, 2019	18,117	$	71.38	—	6,386,200
November 1, 2019 - November 30, 2019	2,122	71.27		—	6,386,200
December 1, 2019 - December 31, 2019	18,628	78.60		—	6,386,200
Total	38,867	$	74.84

(1) The 38,867 total shares for the quarter ended December 31, 2019, and the 309,888 total shares for the full year 2019, 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 2019, 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, 2014 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, 2019)

	2014		2015		2016		2017		2018		2019
EOG	$	100.00	$	77.47	$	111.59	$	119.93	$	97.55	$	94.81
S&P 500	$	100.00	$	101.39	$	113.52	$	138.30	$	132.24	$	173.88
S&P O&G E&P	$	100.00	$	65.85	$	87.47	$	81.96	$	65.98	$	73.91

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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	2019		2018		2017		2016			2015
Statement of Income Data:
Operating Revenues and Other (1)	$	17,379,973	$	17,275,399	$	11,208,320	$	7,650,632		$	8,757,428
Operating Income (Loss)	$	3,699,011	$	4,469,346	$	926,402	$	(1,225,281	)	$	(6,686,079	)
Net Income (Loss)	$	2,734,910	$	3,419,040	$	2,582,579	$	(1,096,686	)	$	(4,524,515	)
Net Income (Loss) Per Share
Basic	$	4.73	$	5.93	$	4.49	$	(1.98	)	$	(8.29	)
Diluted	$	4.71	$	5.89	$	4.46	$	(1.98	)	$	(8.29	)
Dividends Per Common Share	$	1.0825	$	0.81	$	0.67	$	0.67		$	0.67
Average Number of Common Shares
Basic	577,670		576,578		574,620		553,384			545,697
Diluted	580,777		580,441		578,693		553,384			545,697

At December 31	2019		2018		2017		2016		2015
Balance Sheet Data:
Total Property, Plant and Equipment, Net	$	30,364,595	$	28,075,519	$	25,665,037	$	25,707,078	$	24,210,721
Total Assets (2) (3) (4)	37,124,608		33,934,474		29,833,078		29,299,201		26,834,908
Total Debt (4)	5,175,443		6,083,262		6,387,071		6,986,358		6,655,490
Total Stockholders' Equity	21,640,716		19,364,188		16,283,273		13,981,581		12,943,035

(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, 2016 and 2015 (see Note 1 to Consolidated Financial Statements).

(2) 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.

(3) 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 its Consolidated Balance Sheets at December 31, 2016 and 2015 by $160 million and $136 million, respectively, from deferred tax liabilities to deferred tax assets.

(4) Effective January 1, 2016, EOG adopted the provisions of ASU 2015-03, "Interest - Computation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs" (ASU 2015-03). ASU 2015-03 requires that debt issuance costs be presented in the balance sheet as a direct reduction from the related debt liability rather than as an asset. In connection with the adoption of ASU 2015-03, EOG restated its Consolidated Balance Sheets at December 31, 2015 by $4.8 million of unamortized debt issuance costs from Other Assets to Long-Term Debt.

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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.  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 production growth while maintaining 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 that is consistent with efficient, safe and environmentally responsible operations is also an important goal in the implementation of EOG's strategy.

EOG realized net income of $2,735 million during 2019 as compared to net income of $3,419 million for 2018. At December 31, 2019, EOG's total estimated net proved reserves were 3,329 million barrels of oil equivalent (MMBoe), an increase of 401 MMBoe from December 31, 2018.  During 2019, net proved crude oil and condensate and natural gas liquids (NGLs) reserves increased by 287 million barrels (MMBbl), and net proved natural gas reserves increased by 683 billion cubic feet or 114 MMBoe, in each case from December 31, 2018.

Operations

Several important developments have occurred since January 1, 2019.

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 liquids-rich 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 2019, EOG continued to focus on increasing drilling, completion and operating efficiencies gained in prior years. In addition, EOG continued to evaluate certain potential crude oil and liquids-rich 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 77% of United States production during both 2019 and 2018. During 2019, drilling and completion activities occurred primarily in the Eagle Ford play, Delaware Basin play and Rocky Mountain area. EOG's major producing areas in the United States are in New Mexico, North Dakota, Texas and Wyoming.

Trinidad. In Trinidad, EOG continues to deliver natural gas under existing supply contracts. Several fields in the South East Coast Consortium (SECC) Block, Modified U(a) Block, Block 4(a), 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 (NGC), and crude oil and condensate which is sold to Heritage Petroleum Company Limited. In 2019, EOG drilled and completed two net wells in Trinidad and was in the process of drilling another exploratory well at December 31, 2019. One of these wells was a successful development well, while the other well was determined to be an unsuccessful exploratory well. In addition, EOG drilled one stratigraphic exploratory well in Trinidad, which discovered commercially economic reserves.

Other International. In the Sichuan Basin, Sichuan Province, China, EOG drilled two natural gas wells in 2019 to complete the drilling program started in 2018. In 2019, EOG also completed two natural gas wells that were drilled during the 2018 drilling program. All natural gas produced from the Baijaochang Field is sold under a long-term contract to PetroChina.

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.

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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 19% at December 31, 2019 and 24% at December 31, 2018.  As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

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

On June 27, 2019, EOG entered into a new $2.0 billion senior unsecured Revolving Credit Agreement (New Facility) with domestic and foreign lenders (Banks). The New Facility replaced EOG's $2.0 billion senior unsecured Revolving Credit Agreement, dated as of July 21, 2015, which had a scheduled maturity date of July 21, 2020. The New Facility 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 New Facility (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.

Effective January 1, 2019, EOG adopted the provisions of Accounting Standards Update (ASU) 2016-02, "Leases (Topic 842)" (ASU 2016-02). ASU 2016-02 and other related ASUs resulted in the recognition of right-of-use assets and related lease liabilities representing the obligation to make lease payments for certain lease transactions and the disclosure of additional leasing information. The adoption of ASU 2016-02 and other related ASUs resulted in a significant increase to assets and liabilities related to operating leases on the Consolidated Balance Sheet at December 31, 2019. Financial results prior to January 1, 2019, are unchanged. See Note 1 "Summary of Significant Accounting Policies" and Note 18 "Leases" to EOG's Consolidated Financial Statements in this Annual Report on Form 10-K.

During 2019, EOG funded $6.7 billion ($152 million of which was non-cash) in exploration and development and other property, plant and equipment expenditures (excluding asset retirement obligations), repaid $900 million aggregate principal amount of long-term debt, paid $588 million in dividends to common stockholders and purchased $25 million of treasury stock in connection with stock compensation plans, primarily by utilizing net cash provided from its operating activities and net proceeds of $140 million from the sale of assets.

Total anticipated 2020 capital expenditures are estimated to range from approximately $6.3 billion to $6.7 billion, excluding acquisitions and non-cash exchanges. The majority of 2020 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 New 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.

32

Results of Operations

The following review of operations for each of the three years in the period ended December 31, 2019, 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 2019, operating revenues increased $105 million, or 1%, to $17,380 million from $17,275 million in 2018. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, decreased $365 million, or 3%, to $11,581 million in 2019 from $11,946 million in 2018. Revenues from the sales of crude oil and condensate and NGLs in 2019 were approximately 90% of total wellhead revenues compared to 89% in 2018. During 2019, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $180 million compared to net losses of $166 million in 2018. Gathering, processing and marketing revenues increased $130 million during 2019, to $5,360 million from $5,230 million in 2018. Net gains on asset dispositions of $124 million in 2019 were primarily as a result of sales of producing properties, acreage and other assets, as well as non-cash property exchanges, in New Mexico compared to net gains on asset dispositions of $175 million in 2018.

33

Wellhead volume and price statistics for the years ended December 31, 2019, 2018 and 2017 were as follows:

Year Ended December 31	2019		2018			2017
Crude Oil and Condensate Volumes (MBbld) (1)
United States	455.5		394.8			335.0
Trinidad	0.6		0.8			0.9
Other International (2)	0.1		4.3			0.8
Total	456.2		399.9			336.7
Average Crude Oil and Condensate Prices ($/Bbl) (3)
United States	$	57.74	$	65.16		$	50.91
Trinidad	47.16		57.26			42.30
Other International (2)	57.40		71.45			57.20
Composite	57.72		65.21			50.91
Natural Gas Liquids Volumes (MBbld) (1)
United States	134.1		116.1			88.4
Other International (2)	—		—			—
Total	134.1		116.1			88.4
Average Natural Gas Liquids Prices ($/Bbl) (3)
United States	$	16.03	$	26.60		$	22.61
Other International (2)	—		—			—
Composite	16.03		26.60			22.61
Natural Gas Volumes (MMcfd) (1)
United States	1,069		923			765
Trinidad	260		266			313
Other International (2)	37		30			25
Total	1,366		1,219			1,103
Average Natural Gas Prices ($/Mcf) (3)
United States	$	2.22	$	2.88		$	2.20
Trinidad	2.72		2.94			2.38
Other International (2)	4.44		4.08			3.89
Composite	2.38		2.92		(4)	2.29
Crude Oil Equivalent Volumes (MBoed) (5)
United States	767.8		664.7			551.0
Trinidad	44.0		45.1			53.0
Other International (2)	6.2		9.4			4.9
Total	818.0		719.2			608.9
Total MMBoe (5)	298.6		262.5			222.3

(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) Includes a positive revenue adjustment of $0.44 per Mcf related to the adoption of ASU 2014-09, "Revenue From Contracts with Customers" (ASU 2014-09) (see Note 1 to the Consolidated Financial Statements). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees related to certain processing and marketing agreements as Gathering and Processing Costs, instead of as a deduction to Natural Gas revenues.

(5) 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.

34

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.

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 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 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.

2018 compared to 2017. Wellhead crude oil and condensate revenues in 2018 increased $3,261 million, or 52%, to $9,517 million from $6,256 million in 2017, due primarily to a higher composite average wellhead crude oil and condensate price ($2,088 million) and an increase in production ($1,173 million). EOG's composite wellhead crude oil and condensate price for 2018 increased 28% to $65.21 per barrel compared to $50.91 per barrel in 2017. Wellhead crude oil and condensate production in 2018 increased 19% to 400 MBbld as compared to 337 MBbld in 2017. The increased production was primarily in the Permian Basin and the Eagle Ford.

NGLs revenues in 2018 increased $398 million, or 55%, to $1,127 million from $729 million in 2017 primarily due to an increase in production ($229 million) and a higher composite average wellhead NGLs price ($169 million). EOG's composite average wellhead NGLs price increased 18% to $26.60 per barrel in 2018 compared to $22.61 per barrel in 2017. NGLs production in 2018 increased 31% to 116 MBbld as compared to 88 MBbld in 2017. The increased production was primarily in the Permian Basin and the Eagle Ford.

35

Wellhead natural gas revenues in 2018 increased $380 million, or 41%, to $1,302 million from $922 million in 2017, primarily due to a higher composite wellhead natural gas price ($282 million) and an increase in wellhead natural gas deliveries ($98 million). EOG's composite average wellhead natural gas price increased 28% to $2.92 per Mcf in 2018 compared to $2.29 per Mcf in 2017. This increase in composite wellhead natural gas prices includes a positive revenue adjustment of $0.44 per Mcf related to the adoption of ASU 2014-09. Natural gas deliveries in 2018 increased 11% to 1,219 MMcfd as compared to 1,103 MMcfd in 2017. The increase in production was primarily due to increased production in the United States (158 MMcfd), partially offset by decreased production in Trinidad (47 MMcfd). The increased production in the United States was due primarily to increased production of associated gas in the Permian Basin and Rocky Mountain area and higher volumes in the Marcellus Shale. The decrease in Trinidad was primarily attributable to higher contractual deliveries in 2017.

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. During 2017, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $20 million, which included net cash received from settlements of crude oil and natural gas financial derivative contracts of $7 million.

Gathering, processing and marketing revenues less marketing costs in 2018 increased $59 million compared to 2017, primarily due to higher margins on crude oil and condensate marketing activities.

Operating and Other Expenses

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 barrel of oil equivalent (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 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.

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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 represent costs associated with the delivery of hydrocarbon products from the lease 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.

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 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 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 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. See Note 1 to the Consolidated Financial Statements for discussion related to EOG's adoption of ASU 2014-09.

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 Trinidad ($17 million), partially offset by increased general and administrative expenses in the United States ($7 million).

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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 and natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value.  Fair value is generally calculated by using the Income Approach described in the Fair Value Measurement Topic of the Financial Accounting Standards Board's Accounting Standards Codification (ASC).  In certain instances, EOG utilizes accepted offers from third-party purchasers as the basis for determining fair value.

The following table represents impairments for the years ended December 31, 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 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 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.

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2018 compared to 2017.  During 2018, operating expenses of $12,806 million were $875 million higher than the $10,282 million incurred during 2017.  The following table presents the costs per barrel of oil equivalent (Boe) for the years ended December 31, 2018 and 2017:

	2018		2017
Lease and Well	$	4.89	$	4.70
Transportation Costs	2.85		3.33
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties	12.65		14.83
Other Property, Plant and Equipment	0.44		0.51
General and Administrative (G&A)	1.63		1.95
Net Interest Expense	0.93		1.23
Total (1)	$	23.39	$	26.55

(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 2018 compared to 2017 are set forth below.  See "Operating Revenues and Other" above for a discussion of production volumes.

Lease and well expenses of $1,283 million in 2018 increased $238 million from $1,045 million in 2017 primarily due to higher operating and maintenance costs ($171 million), higher workover expenditures ($44 million) and higher lease and well administrative expenses ($41 million), all in the United States, partially offset by lower operating and maintenance costs in the United Kingdom ($18 million). Lease and well expenses increased in the United States primarily due to increased operating activities resulting in increased production.

Transportation costs of $747 million in 2018 increased $7 million from $740 million in 2017 primarily due to increased transportation costs in the Permian Basin ($116 million), partially offset by decreased transportation costs in the Fort Worth Basin Barnett Shale ($52 million), the Eagle Ford ($31 million) and the Rocky Mountain area ($25 million).

DD&A expenses in 2018 increased $26 million to $3,435 million from $3,409 million in 2017.  DD&A expenses associated with oil and gas properties in 2018 were $24 million higher than in 2017 primarily due to an increase in production in the United States ($647 million) and the United Kingdom ($21 million), partially offset by lower unit rates in the United States ($625 million) and a decrease in production in Trinidad ($16 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 $427 million in 2018 decreased $7 million from $434 million in 2017 primarily due to decreased professional, legal and other services ($24 million); partially offset by increased employee-related expenses resulting from expanded operations ($15 million) and increased information systems costs ($10 million).

Net interest expense of $245 million in 2018 was $29 million lower than 2017 primarily due to repayment of the $600 million aggregate principal amount of 5.875% Senior Notes due 2017 in September 2017 ($25 million) and the $350 million aggregate principal amount of 6.875% Senior Notes due 2018 in October 2018 ($6 million), partially offset by a decrease in capitalized interest ($3 million).

Gathering and processing costs increased $288 million to $437 million in 2018 compared to $149 million in 2017 primarily due to the adoption of ASU 2014-09 ($204 million) and increased operating costs in the Permian Basin ($32 million), the United Kingdom ($28 million) and the Eagle Ford ($25 million).

Exploration costs of $149 million in 2018 increased $4 million from $145 million in 2017 primarily due to increased general and administrative expenses in the United States ($7 million), partially offset by decreased geological and geophysical expenditures in Trinidad ($5 million).

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The following table represents impairments for the years ended December 31, 2018 and 2017 (in millions):

	2018		2017
Proved properties	$	121	$	224
Unproved properties	173		211
Other assets	49		28
Inventories	4		—
Total	$	347	$	463

Impairments of proved properties were primarily due to the write-down to fair value of legacy natural gas assets in 2018 and 2017.

Taxes other than income in 2018 increased $227 million to $772 million (6.5% of wellhead revenues) from $545 million (6.9% of wellhead revenues) in 2017. The increase in taxes other than income was primarily due to increases in severance/production taxes ($190 million) primarily as a result of increased wellhead revenues and an increase in ad valorem/property taxes ($33 million), both in the United States.

Other income, net, was $17 million in 2018 compared to other income, net, of $9 million in 2017. The increase of $8 million in 2018 was primarily due to a decrease in deferred compensation expense ($12 million) and an increase in interest income ($4 million), partially offset by an increase in foreign currency transaction losses ($15 million).

EOG recognized an income tax provision of $822 million in 2018 compared to an income tax benefit of $1,921 million in 2017, primarily due to the absence of certain 2017 tax benefits related to the Tax Cuts and Jobs Act (TCJA) and higher pretax income. The most significant impact of the TCJA on EOG was the reduction in the statutory income tax rate from 35% to 21% which required the existing net United States federal deferred income tax liability to be remeasured resulting in the recognition of an income tax benefit in 2017 of approximately $2.2 billion. The net effective tax rate for 2018 increased to 19% from (291%) in the prior year, primarily due to the absence of the TCJA tax benefits.

Capital Resources and Liquidity

Cash Flow

The primary sources of cash for EOG during the three-year period ended December 31, 2019, were funds generated from operations 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; other property, plant and equipment expenditures; and purchases of treasury stock in connection with stock compensation plans.

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). 

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2018 compared to 2017.  Net cash provided by operating activities of $7,769 million in 2018 increased $3,504 million from $4,265 million in 2017 primarily reflecting an increase in wellhead revenues ($4,039 million), favorable changes in working capital and other assets and liabilities ($758 million) and a favorable change in the cash paid for income taxes ($113 million), partially offset by an increase in cash operating expenses ($746 million) and an unfavorable change in the net cash paid for the settlement of financial commodity derivative contracts ($266 million).

Net cash used in investing activities of $6,170 million in 2018 increased by $2,183 million from $3,987 million in 2017 primarily due to an increase in additions to oil and gas properties ($1,888 million); unfavorable changes in working capital associated with investing activities ($211 million); and an increase in additions to other property, plant and equipment ($64 million).

Net cash used in financing activities of $839 million in 2018 included cash dividend payments ($438 million), repayments of long-term debt ($350 million) and purchases of treasury stock in connection with stock compensation plans ($63 million). Cash provided by financing activities in 2018 included proceeds from stock options exercised and employee stock purchase plan activity ($21 million). 

Total Expenditures

The table below sets out components of total expenditures for the years ended December 31, 2019, 2018 and 2017 (in millions):

	2019		2018		2017
Expenditure Category
Capital
Exploration and Development Drilling	$	4,951	$	4,935	$	3,132
Facilities	629		625		575
Leasehold Acquisitions (1)	276		488		427
Property Acquisitions (2)	380		124		73
Capitalized Interest	38		24		27
Subtotal	6,274		6,196		4,234
Exploration Costs	140		149		145
Dry Hole Costs	28		5		5
Exploration and Development Expenditures	6,442		6,350		4,384
Asset Retirement Costs	186		70		56
Total Exploration and Development Expenditures	6,628		6,420		4,440
Other Property, Plant and Equipment (3)	272		286		173
Total Expenditures	$	6,900	$	6,706	$	4,613

(1) Leasehold acquisitions included $98 million, $291 million and $256 million related to non-cash property exchanges in 2019, 2018 and 2017, respectively.

(2) Property acquisitions included $52 million, $71 million and $26 million related to non-cash property exchanges in 2019, 2018 and 2017, respectively.

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

Exploration and development expenditures of $6,442 million for 2019 were $92 million higher than the prior year. The increase was primarily due to increased property acquisitions ($256 million), increased exploration and development drilling expenditures in Trinidad ($53 million) and increased capitalized interest ($14 million), partially offset by decreased leasehold acquisitions ($212 million) and decreased exploration and development drilling expenditures in the United States ($19 million) and Other International ($19 million). 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 million in exploration, $124 million in property acquisitions and $24 million in capitalized interest. The 2017 exploration and development expenditures of $4,384 million included $3,661 million in development drilling and facilities, $623 million in exploration, $73 million in property acquisitions and $27 million in capitalized interest.

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The level of exploration and development expenditures, including acquisitions, will vary in future periods depending on energy market conditions and other related economic factors.  EOG has significant flexibility 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 pricing in Midland, Texas, and Cushing, Oklahoma (Midland Differential). Presented below is a comprehensive summary of EOG's Midland Differential basis swap contracts through February 19, 2020. The weighted average price differential expressed in $/Bbl represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in barrels per day (Bbld) covered by the basis swap contracts.

Midland Differential Basis Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)
2019
January 1, 2019 through December 31, 2019 (closed)	20,000	$	1.075

EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in the U.S. Gulf Coast and Cushing, Oklahoma (Gulf Coast Differential). Presented below is a comprehensive summary of EOG's Gulf Coast Differential basis swap contracts through February 19, 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.

Gulf Coast Differential Basis Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)
2019
January 1, 2019 through December 31, 2019 (closed)	13,000	$	5.572

EOG has also entered into crude oil swaps 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 swap contracts through February 19, 2020. The weighted average price differential expressed in $/Bbl represents the amount of addition to delivery month prices for the notional volumes expressed in Bbld covered by the swap contracts.

Roll Differential Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)
2020
February 2020 (closed)	10,000	$	0.70
March 1, 2020 through December 31, 2020	10,000	0.70

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Presented below is a comprehensive summary of EOG's crude oil price swap contracts through February 19, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

Crude Oil Price Swap Contracts
	Volume (Bbld)	Weighted Average Price ($/Bbl)
2019
April 2019 (closed)	25,000	$	60.00
May 1, 2019 through December 31, 2019 (closed)	150,000	62.50
2020
January 2020 (closed)	200,000	$	59.33
February 1, 2020 through March 31, 2020	200,000	59.33
April 1, 2020 through June 30, 2020	200,000	59.59
July 1, 2020 through September 30, 2020	107,000	58.94

NGLs Derivative Contracts. Presented below is a comprehensive summary of EOG's Mont Belvieu propane (non-TET) price swap contracts through February 19, 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 2020 (closed)	4,000	$	21.34
February 2020	4,000	21.34
March 1, 2020 through December 31, 2020	25,000	17.92

Natural Gas Derivative Contracts. Presented below is a comprehensive summary of EOG's natural gas price swap contracts through February 19, 2020, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).

Natural Gas Price Swap Contracts
	Volume (MMBtud)	Weighted Average Price ($/MMBtu)
2019
April 1, 2019 through October 31, 2019 (closed)	250,000	$	2.90

EOG has also 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. Presented below is a comprehensive summary of EOG's natural gas collar contracts through February 19, 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 October 31, 2020	250,000	$	2.50	$	2.00

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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 19, 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 February 29, 2020 (closed)	30,000	$	0.55
March 1, 2020 through December 31, 2020	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). Presented below is a comprehensive summary of EOG's HSC Differential basis swap contracts through February 19, 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 February 29, 2020 (closed)	60,000	$	0.05
March 1, 2020 through December 31, 2020	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 19, 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 February 29, 2020 (closed)	50,000	$	1.40
March 1, 2020 through December 31, 2020	50,000	1.40

Financing

EOG's debt-to-total capitalization ratio was 19% at December 31, 2019, compared to 24% at December 31, 2018.  As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

At December 31, 2019 and 2018, respectively, EOG had outstanding $5,140 million and $6,040 million aggregate principal amount of senior notes which had estimated fair values of $5,452 million and $6,027 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.

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During 2019, EOG funded its capital program primarily by utilizing cash provided by operating activities 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 2019 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.

Contractual Obligations

The following table summarizes EOG's contractual obligations at December 31, 2019 (in millions):

Contractual Obligations (1) (2)	Total		2020		2021-2022		2023-2024		2025 & Beyond
Current and Long-Term Debt	$	5,140	$	1,000	$	750	$	1,250	$	2,140
Interest Payments on Long-Term Debt	1,059		169		258		193		439
Finance Leases (3)	64		15		27		16		6
Operating Leases (3)	850		390		335		85		40
Leases Effective, Not Commenced (3)	699		80		132		134		353
Transportation and Storage Service Commitments (4)	6,034		914		1,632		1,130		2,358
Purchase and Service Obligations	1,222		399		498		152		173
Total Contractual Obligations	$	15,068	$	2,967	$	3,632	$	2,960	$	5,509

(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) This table does not include the liability for commitments to purchase fixed quantities of crude oil and natural gas. The amounts are excluded because they are variable and based on future commodity prices. At December 31, 2019, EOG is committed to purchase 1.8 MMBbls of crude oil and 5.5 Bcf of natural gas in 2020 and 1.4 MMBls of crude oil in 2021.

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

(4) 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, 2019.  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 2019, 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 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 2020 will impact the amount of cash generated from EOG's operating activities, which will in turn impact EOG's financial position. As of February 19, 2020, the average 2020 NYMEX crude oil and natural gas prices were $53.75 per barrel and $2.12 per MMBtu, respectively, representing a decrease of 6% for crude oil and a decrease of 20% for natural gas from the average NYMEX prices in 2019. See ITEM 1A, Risk Factors.

Based on EOG's tax position, EOG's price sensitivity (exclusive of basis swaps) in 2020 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 $117 million for net income and $152 million for pretax cash flows from operating activities.  Based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 2020 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 and natural gas financial commodity derivative contracts through February 19, 2020, see "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.

The total anticipated 2020 capital expenditures of approximately $6.3 billion to $6.7 billion, excluding acquisitions and non-cash exchanges, 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 2020, both total production and total crude oil production are expected to increase from 2019 levels. In 2020, 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 the portrayal of 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 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 proved commercial reserves.  If proved commercial reserves are not discovered, such drilling costs are expensed.  In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed.  Such exploratory well drilling costs may continue to be capitalized if the 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 were revised upward or downward, earnings would 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.

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

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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, 2019, WTI crude oil spot prices have fluctuated from approximately $26.19 per barrel to $77.41 per barrel, and Henry Hub natural gas spot prices have ranged from approximately $1.49 per MMBtu to $6.24 per MMBtu.  Market prices for NGLs are influenced by the production composition of ethane, propane, butane and natural gasoline 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 (in each case as of the applicable balance sheet date) as a basis to estimate future crude oil 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, 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 oil and 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 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, returns, 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," "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, 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 crude oil and condensate, natural gas liquids, natural gas and related commodity production;

• 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 and refining 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 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 imposing 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;

• 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 and transportation 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;

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• 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;

• 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, on pages 13 through 23 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 "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, 2019. 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, 2019.

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.

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EOG's management assessed the effectiveness of EOG's internal control over financial reporting as of December 31, 2019. 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, 2019. 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, 2019, 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 2020 Annual Meeting of Stockholders to be filed not later than April 29, 2020 and (ii) Item 1 of this report, specifically the information therein set forth under the caption "Information About Our Executive Officers."

Pursuant to Rule 303A.10 of the New York Stock Exchange and Item 406 of Regulation S-K promulgated under the Securities Exchange Act of 1934, as amended, EOG has adopted a Code of Business Conduct and Ethics for Directors, Officers and Employees (Code of Conduct) that applies to all EOG directors, officers and employees, including EOG's principal executive officer, principal financial officer and principal accounting officer. EOG has also adopted a Code of Ethics for Senior Financial Officers (Code of Ethics) that, along with EOG's Code of Conduct, applies to EOG's principal executive officer, principal financial officer, principal accounting officer and controllers.

You can access the Code of Conduct and Code of Ethics on the "Governance" page under "Investors" on EOG's website at www.eogresources.com, and any EOG stockholder who so requests may obtain a printed copy of the Code of Conduct and Code of Ethics by submitting a written request to EOG's Corporate Secretary.

EOG intends to disclose any amendments to the Code of Conduct or Code of Ethics, and any waivers with respect to the Code of Conduct or Code of Ethics granted to EOG's principal executive officer, principal financial officer, principal accounting officer, any of our controllers or any of our other employees performing similar functions, on its website at www.eogresources.com within four business days of the amendment or waiver. In such case, the disclosure regarding the amendment or waiver will remain available on EOG's website for at least 12 months after the initial disclosure. There have been no waivers granted with respect to EOG's Code of Conduct or Code of Ethics.

ITEM 11.  Executive Compensation

The information required by this Item is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 2020 Annual Meeting of Stockholders to be filed not later than April 29, 2020. 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.

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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 2020 Annual Meeting of Stockholders to be filed not later than April 29, 2020.

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, 2019, 332,248 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, 2019.

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	10,967,766	(2)	$	94.53	9,116,617	(3)
Equity Compensation Plans Not Approved by EOG Stockholders	224,225	(4)	N/A		207,752	(5)
Total	11,191,991		$	94.53	9,324,369

(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 974,484 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 598,147 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 598,147 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 102,382 and a maximum of 1,093,912 performance units could be outstanding and (B) accordingly, a minimum of 102,382 and a maximum of 1,093,912 shares of EOG common stock could be issued upon the vesting of such grants.

(3) Consists of (i) 6,844,409 shares remaining available for issuance under the Amended and Restated 2008 Plan and (ii) 2,272,208 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 6,844,409 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 6,844,409 (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 2,793,636 (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 224,225 phantom shares issued and outstanding under the Deferral Plan as of December 31, 2019).

(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 2020 Annual Meeting of Stockholders to be filed not later than April 29, 2020.

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 2020 Annual Meeting of Stockholders to be filed not later than April 29, 2020.

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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-7 for a listing of the exhibits.

ITEM 16. Form 10-K Summary

None.

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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 and Comprehensive Income for Each of the Three Years in the Period Ended December 31, 2019	F-6
Consolidated Balance Sheets - December 31, 2019 and 2018	F-7
Consolidated Statements of Stockholders' Equity for Each of the Three Years in the Period Ended December 31, 2019	F-8
Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2019	F-9
Notes to Consolidated Financial Statements	F-10
Supplemental Information to Consolidated Financial Statements	F-39

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, 2019.  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, 2019.

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 27, 2020

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, 2019 and 2018, 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, 2019, 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, 2019, 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, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, 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, 2019, 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 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 net cash flows of the underlying proved oil and natural gas reserves. The development of the Company’s oil and natural gas reserve volumes and the related future cash flows requires management to make significant estimates and scheduling assumptions related to the five-year development plan for proved undeveloped reserves, future oil and natural gas prices, and future well costs. The Company’s reserve engineers estimate oil 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 $24 billion as of December 31, 2019, and depletion and proved property impairment were $3.75 billion and $207 million, respectively, for the year then ended.

Given the significant judgments made by management, performing audit procedures to evaluate the Company’s proved oil and natural gas reserve quantities and the related net cash flows including management’s estimates and assumptions related to the five-year development plan, future oil 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 oil 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 oil and natural gas reserve quantities and related future net cash flows, including controls relating to the five-year development plan, future oil 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.

◦ Permits and 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 oil 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 oil and natural gas prices.

• We evaluated the reasonableness of capital expenditures (well costs) by comparing to comparable historical wells drilled and analyst and industry reports.

F-4

• 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 27, 2020

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

F-5

EOG RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(In Thousands, Except Per Share Data)

Year Ended December 31	2019			2018			2017
Operating Revenues and Other
Crude Oil and Condensate	$	9,612,532		$	9,517,440		$	6,256,396
Natural Gas Liquids	784,818			1,127,510			729,561
Natural Gas	1,184,095			1,301,537			921,934
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts	180,275			(165,640		)	19,828
Gathering, Processing and Marketing	5,360,282			5,230,355			3,298,087
Gains (Losses) on Asset Dispositions, Net	123,613			174,562			(99,096		)
Other, Net	134,358			89,635			81,610
Total	17,379,973			17,275,399			11,208,320
Operating Expenses
Lease and Well	1,366,993			1,282,678			1,044,847
Transportation Costs	758,300			746,876			740,352
Gathering and Processing Costs	479,102			436,973			148,775
Exploration Costs	139,881			148,999			145,342
Dry Hole Costs	28,001			5,405			4,609
Impairments	517,896			347,021			479,240
Marketing Costs	5,351,524			5,203,243			3,330,237
Depreciation, Depletion and Amortization	3,749,704			3,435,408			3,409,387
General and Administrative	489,397			426,969			434,467
Taxes Other Than Income	800,164			772,481			544,662
Total	13,680,962			12,806,053			10,281,918
Operating Income	3,699,011			4,469,346			926,402
Other Income, Net	31,385			16,704			9,152
Income Before Interest Expense and Income Taxes	3,730,396			4,486,050			935,554
Interest Expense
Incurred	223,421			269,549			301,801
Capitalized	(38,292		)	(24,497		)	(27,429		)
Net Interest Expense	185,129			245,052			274,372
Income Before Income Taxes	3,545,267			4,240,998			661,182
Income Tax Provision (Benefit)	810,357			821,958			(1,921,397		)
Net Income	$	2,734,910		$	3,419,040		$	2,582,579
Net Income Per Share
Basic	$	4.73		$	5.93		$	4.49
Diluted	$	4.71		$	5.89		$	4.46
Average Number of Common Shares
Basic	577,670			576,578			574,620
Diluted	580,777			580,441			578,693
Comprehensive Income
Net Income	$	2,734,910		$	3,419,040		$	2,582,579
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments	(2,883		)	16,816			2,799
Other, Net of Tax	(678		)	1,123			(3,086		)
Other Comprehensive Income (Loss)	(3,561		)	17,939			(287		)
Comprehensive Income	$	2,731,349		$	3,436,979		$	2,582,292

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	2019			2018
ASSETS
Current Assets
Cash and Cash Equivalents	$	2,027,972		$	1,555,634
Accounts Receivable, Net	2,001,658			1,915,215
Inventories	767,297			859,359
Assets from Price Risk Management Activities	1,299			23,806
Income Taxes Receivable	151,665			427,909
Other	323,448			275,467
Total	5,273,339			5,057,390
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)	62,830,415			57,330,016
Other Property, Plant and Equipment	4,472,246			4,220,665
Total Property, Plant and Equipment	67,302,661			61,550,681
Less: Accumulated Depreciation, Depletion and Amortization	(36,938,066		)	(33,475,162		)
Total Property, Plant and Equipment, Net	30,364,595			28,075,519
Deferred Income Taxes	2,363			777
Other Assets	1,484,311			800,788
Total Assets	$	37,124,608		$	33,934,474
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable	$	2,429,127		$	2,239,850
Accrued Taxes Payable	254,850			214,726
Dividends Payable	166,273			126,971
Liabilities from Price Risk Management Activities	20,194			—
Current Portion of Long-Term Debt	1,014,524			913,093
Current Portion of Operating Lease Liabilities	369,365			—
Other	232,655			233,724
Total	4,486,988			3,728,364
Long-Term Debt	4,160,919			5,170,169
Other Liabilities	1,789,884			1,258,355
Deferred Income Taxes	5,046,101			4,413,398
Commitments and Contingencies (Note 8)
Stockholders' Equity
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 582,213,016 Shares and 580,408,117 Shares Issued at December 31, 2019 and 2018, respectively	205,822			205,804
Additional Paid in Capital	5,817,475			5,658,794
Accumulated Other Comprehensive Loss	(4,652		)	(1,358		)
Retained Earnings	15,648,604			13,543,130
Common Stock Held in Treasury, 298,820 Shares and 385,042 Shares at December 31, 2019 and 2018, respectively	(26,533		)	(42,182		)
Total Stockholders' Equity	21,640,716			19,364,188
Total Liabilities and Stockholders' Equity	$	37,124,608		$	33,934,474

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, 2016	$	205,770	$	5,420,385		$	(19,010	)	$	8,398,118		$	(23,682	)	$	13,981,581
Net Income	—		—			—			2,582,579			—			2,582,579
Common Stock Issued Under Stock Plans	7		7,082			—			—			—			7,089
Common Stock Dividends Declared, $0.67 Per Share	—		—			—			(387,164		)	—			(387,164		)
Other Comprehensive Loss	—		—			(287		)	—			—			(287		)
Change in Treasury Stock - Stock Compensation Plans, Net	—		(27,348		)	—			—			(9,395		)	(36,743		)
Restricted Stock and Restricted Stock Units, Net	11		2,552			—			—			(2,563		)	—
Stock-Based Compensation Expenses	—		133,849			—			—			—			133,849
Treasury Stock Issued as Compensation	—		27			—			—			2,342			2,369
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

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	2019			2018			2017
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash Provided by Operating Activities:
Net Income	$	2,734,910		$	3,419,040		$	2,582,579
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization	3,749,704			3,435,408			3,409,387
Impairments	517,896			347,021			479,240
Stock-Based Compensation Expenses	174,738			155,337			133,849
Deferred Income Taxes	631,658			894,156			(1,473,872		)
(Gains) Losses on Asset Dispositions, Net	(123,613		)	(174,562		)	99,096
Other, Net	4,496			7,066			6,546
Dry Hole Costs	28,001			5,405			4,609
Mark-to-Market Commodity Derivative Contracts
Total (Gains) Losses	(180,275		)	165,640			(19,828		)
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts	231,229			(258,906		)	7,438
Other, Net	962			3,108			1,204
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	(91,792		)	(368,180		)	(392,131		)
Inventories	90,284			(395,408		)	(174,548		)
Accounts Payable	168,539			439,347			324,192
Accrued Taxes Payable	40,122			(92,461		)	(63,937		)
Other Assets	358,001			(125,435		)	(658,609		)
Other Liabilities	(56,619		)	10,949			(89,871		)
Changes in Components of Working Capital Associated with Investing and Financing Activities	(115,061		)	301,083			89,992
Net Cash Provided by Operating Activities	8,163,180			7,768,608			4,265,336
Investing Cash Flows
Additions to Oil and Gas Properties	(6,151,885		)	(5,839,294		)	(3,950,918		)
Additions to Other Property, Plant and Equipment	(270,641		)	(237,181		)	(173,324		)
Proceeds from Sales of Assets	140,292			227,446			226,768
Other Investing Activities	(10,000		)	(19,993		)	—
Changes in Components of Working Capital Associated with Investing Activities	115,061			(301,140		)	(89,935		)
Net Cash Used in Investing Activities	(6,177,173		)	(6,170,162		)	(3,987,409		)
Financing Cash Flows
Long-Term Debt Repayments	(900,000		)	(350,000		)	(600,000		)
Dividends Paid	(588,200		)	(438,045		)	(386,531		)
Treasury Stock Purchased	(25,152		)	(63,456		)	(63,408		)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan	17,946			20,560			20,840
Debt Issuance Costs	(5,016		)	—			—
Repayment of Finance Lease Obligation	(12,899		)	(8,219		)	(6,555		)
Changes in Components of Working Capital Associated with Financing Activities	—			57			(57		)
Net Cash Used in Financing Activities	(1,513,321		)	(839,103		)	(1,035,711		)
Effect of Exchange Rate Changes on Cash	(348		)	(37,937		)	(7,883		)
Increase (Decrease) in Cash and Cash Equivalents	472,338			721,406			(765,667		)
Cash and Cash Equivalents at Beginning of Year	1,555,634			834,228			1,599,895
Cash and Cash Equivalents at End of Year	$	2,027,972		$	1,555,634		$	834,228

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).

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 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.

F-10

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 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, natural gas liquids (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 Accounting Standards Update (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 and Comprehensive Income 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 and Comprehensive Income. 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 on January 1, 2019 and December 31, 2019, were $1,460 million and $1,619 million, respectively, and are included in Accounts Receivable, Net on the Consolidated Balance Sheets. Losses incurred on receivables from contracts with customers are infrequent and have been immaterial.

F-11

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, crude-by-rail assets, sand mine and 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, 2019, 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 and Comprehensive Income.  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.

F-12

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

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

Leases. 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 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 is continuing to evaluate the provisions of ASU 2019-12 and has not determined the full impact on its consolidated financial statements and related disclosures.

F-13

In June 2016, the FASB issued 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. ASU 2016-13 requires adoption through the use of a modified retrospective approach at the effective date by recognizing a cumulative-effect adjustment to the opening balance of retained earnings. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019, and early adoption is permitted. EOG has assessed its applicable financial assets, which are primarily its accounts receivable from hydrocarbon sales and joint interest billings to third-party companies, including state-owned entities in the oil and gas industry. Based on its assessment and various potential remedies ensuring collection, EOG does not expect the impact from forward-looking expected losses will be material. EOG will apply the provisions of ASU 2016-13 on the adoption date, January 1, 2020.

2.  Long-Term Debt

Long-Term Debt at December 31, 2019 and 2018 consisted of the following (in thousands):

	2019		2018
5.625% Senior Notes due 2019	$	—	$	900,000
4.40% Senior Notes due 2020	500,000		500,000
2.45% Senior Notes due 2020	500,000		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
3.90% Senior Notes due 2035	500,000		500,000
5.10% Senior Notes due 2036	250,000		250,000
Long-Term Debt	5,140,000		6,040,000
Finance Leases (see Note 18)	57,900		71,571
Less: Current Portion of Long-Term Debt	1,014,524		913,093
Unamortized Debt Discount	19,528		24,640
Debt Issuance Costs	2,929		3,669
Total Long-Term Debt	$	4,160,919	$	5,170,169

At December 31, 2019, the aggregate annual maturities of long-term debt (excluding finance lease obligations) were $1 billion in 2020, $750 million in 2021, zero in 2022, $1.25 billion in 2023 and zero in 2024. 

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

On October 1, 2018, EOG repaid upon maturity the $350 million aggregate principal amount of its 6.875% Senior Notes due 2018.

At December 31, 2019 and 2018, EOG had no outstanding short-term borrowings under its commercial paper program and did not utilize any such borrowings during 2019. During 2018, EOG utilized commercial paper borrowings, bearing market interest rates, for various corporate financing purposes. The average borrowings outstanding under the commercial paper program were $8 million during the year ended December 31, 2018. The weighted average interest rate for commercial paper borrowings during the year ended December 31, 2018, was 1.97%.

On June 27, 2019, EOG entered into a new $2.0 billion senior unsecured Revolving Credit Agreement (New Facility) with domestic and foreign lenders (Banks). The New Facility replaced EOG's $2.0 billion senior unsecured Revolving Credit Agreement, dated as of July 21, 2015, with domestic and foreign lenders (2015 Facility), 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 completion of the New Facility.

F-14

The New Facility 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 New Facility (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 New Facility will accrue interest based, at EOG’s option, on either the London InterBank Offered Rate plus an applicable margin (Eurodollar Rate) or the Base Rate (as defined in the New Facility) plus an applicable margin. The applicable margin used in connection with interest rates and fees will be based on EOG’s credit rating for its senior unsecured long-term debt at the applicable time.

Consistent with the terms of the 2015 Facility, the New Facility contains representations, warranties, covenants and events of default that we believe are customary for investment grade, senior unsecured commercial bank credit agreements, including a financial covenant for the maintenance of a ratio of total debt-to-total capitalization (as such terms are defined in the New Facility) of no greater than 65%. At December 31, 2019, EOG was in compliance with this financial covenant.

There were no borrowings or letters of credit outstanding under the 2015 Facility as of (i) December 31, 2018 or (ii) the June 27, 2019 effective date of the closing of the New Facility and termination of the 2015 Facility. Further, at December 31, 2019, there were no borrowings or letters of credit outstanding under the New Facility. The Eurodollar Rate and Base Rate (inclusive of the applicable margin), had there been any amounts borrowed under the New Facility at December 31, 2019, would have been 2.66% and 4.75%, respectively.

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, 2019, 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, 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 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 by 19% 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, EOG's Board increased the quarterly cash dividend on the common stock by 10% 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. EOG declared and paid quarterly cash dividends of $0.1675 per share in 2017.

On February 15, 2017, the Board approved an amendment to EOG's Restated Certificate of Incorporation to increase the number of EOG's authorized shares of common stock from 640 million to 1,280 million. EOG's stockholders approved the increase at the Annual Meeting of Stockholders on April 27, 2017, and the amendment was filed with the Delaware Secretary of State on April 28, 2017.

F-15

The following summarizes Common Stock activity for each of the years ended December 31, 2017, 2018 and 2019 (in thousands):

	Common Shares
	Issued	Treasury		Outstanding
Balance at December 31, 2016	576,950	(250	)	576,700
Common Stock Issued Under Stock-Based Compensation Plans	1,878	—		1,878
Treasury Stock Purchased (1)	—	(686	)	(686	)
Common Stock Issued Under Employee Stock Purchase Plan	—	180		180
Treasury Stock Issued Under Stock-Based Compensation Plans	—	405		405
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

(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, 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, 2019, there were no shares of preferred stock outstanding.

F-16

4.  Accumulated Other Comprehensive Income (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, 2019 and 2018 consisted of the following (in thousands):

	Foreign Currency Translation Adjustment			Other			Total
December 31, 2017	$	(16,642	)	$	(2,655	)	$	(19,297	)
Other comprehensive income before reclassifications	2,451			1,131			3,582
Amounts reclassified out of other comprehensive income (loss) (1)	14,365			—			14,365
Tax effects	—			(8		)	(8		)
Other comprehensive income	16,816			1,123			17,939
December 31, 2018	174			(1,532		)	(1,358		)
Cumulative effect of accounting changes	—			267			267
Other comprehensive loss before reclassifications	(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	)

(1) Reclassified to Net Income - Gains (Losses) on Asset Dispositions, Net. See Note 17.

No significant amount was reclassified out of Accumulated Other Comprehensive Loss during the year ended December 31, 2019.

5.  Other Income, Net

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). Other income, net for 2017 included net foreign currency transaction gains ($8 million), interest income ($8 million) and equity income from investments in ammonia plants in Trinidad ($3 million), partially offset by an upward adjustment to deferred compensation expense ($6 million).

F-17

6.  Income Taxes

The principal components of EOG's total net deferred income tax liabilities at December 31, 2019 and 2018 were as follows (in thousands):

	2019			2018
Deferred Income Tax Assets (Liabilities)
Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization	$	5,825		$	4,359
Foreign Net Operating Loss	66,675			55,175
Foreign Valuation Allowances	(70,455		)	(58,932		)
Foreign Other	318			175
Total Net Deferred Income Tax Assets	$	2,363		$	777
Deferred Income Tax (Assets) Liabilities
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization	$	5,277,550		$	4,583,517		(1)
Commodity Hedging Contracts	(4,699		)	4,883
Deferred Compensation Plans	(47,650		)	(39,086		)
Accrued Expenses and Liabilities	(8,502		)	(19,097		)
Equity Awards	(108,324		)	(93,977		)
Alternative Minimum Tax Credit Carryforward	(31,904		)	—
Undistributed Foreign Earnings	15,746			22,945
Other	(46,116		)	(45,787		)
Total Net Deferred Income Tax Liabilities	$	5,046,101		$	4,413,398
Total Net Deferred Income Tax Liabilities	$	5,043,738		$	4,412,621

(1) The 2018 presentation has been changed to conform with current year presentation.

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

	2019		2018		2017
United States	$	3,466,578	$	4,084,156	$	621,610
Foreign	78,689		156,842		39,572
Total	$	3,545,267	$	4,240,998	$	661,182

F-18

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

	2019			2018			2017
Current:
Federal	$	(152,258	)	$	(303,853	)	$	33,058
State	10,819			17,048			(2,502		)
Foreign	81,426			65,615			35,323
Total	(60,013		)	(221,190		)	65,879
Deferred:
Federal	626,901			862,075			(1,504,288		)
State	32,541			43,293			26,942
Foreign	(27,784		)	(11,212		)	3,474
Total	631,658			894,156			(1,473,872		)
Other Non-Current: (1)
Federal	245,125			148,992			(513,404		)
Foreign	(6,413		)	—			—
Total	238,712			148,992			(513,404		)
Income Tax Provision (Benefit)	$	810,357		$	821,958		$	(1,921,397	)

(1) Includes changes in certain amounts that are expected to be paid or received beyond the next twelve months. The primary components are refundable alternative minimum tax (AMT) credits and the 2017 repatriation tax. See the following statutory-to-effective tax rate reconciliation for additional details.

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:

	2019		2018			2017
Statutory Federal Income Tax Rate	21.00	%	21.00	%		35.00	%
State Income Tax, Net of Federal Benefit	0.97		1.12			3.38
Income Tax Provision Related to Foreign Operations	0.87		0.51			(0.30	)
Income Tax Provision Related to United Kingdom Operations	—		—			1.78
Income Tax Provision Related to Canadian Operations	—		—			2.30
TCJA (1)	—		(2.60	)	(2)	(328.10	)	(3)
Share-Based Compensation	0.02		(0.47	)		(4.63	)
Other	—		(0.18	)		(0.03	)
Effective Income Tax Rate	22.86	%	19.38	%		(290.60	)%

(1) The enactment of the Tax Cuts and Jobs Act (TCJA) by the United States in 2017 made numerous changes to federal tax law. Several changes which had a significant impact on EOG include the corporate income tax rate reduction from 35% to 21%, the imposition of a one-time repatriation tax on undistributed foreign earnings and the repeal of the corporate AMT regime (AMT credit carryforwards became refundable over the following four years and were initially subject to a federal sequestration charge). In 2017, EOG revalued its federal deferred income tax assets and liabilities resulting in an earnings benefit of over $2 billion and a substantial reduction of the 2017 effective tax rate. The TCJA measurement-period adjustments were recorded in 2018.

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

(3) Includes impact of the federal rate reduction ((327.8)%), federal repatriation tax ((6.6)%), sequestration ((6.4)%) and other tax reform impacts ((0.1)%).

The net effective tax rate of 23% in 2019 was higher than the prior year rate of 19% primarily due to the absence of tax benefits from certain tax reform measurement-period adjustments.

F-19

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):

	2019			2018			2017
Beginning Balance	$	167,142		$	466,421		$	383,221
Increase (1)	30,673			23,062			67,333
Decrease (2)	(75		)	(26,219		)	(13,687		)
Other (3)	3,091			(296,122		)	29,554
Ending Balance	$	200,831		$	167,142		$	466,421

(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 allowance.

(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, 2019, EOG had state income tax NOLs of approximately $2.1 billion, which, if unused, expire between 2020 and 2038. EOG also has Canadian NOLs of $225 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, 2019, was $39 million, resulting from the tax treatment of research and experimental expenditures related to certain innovations in EOG's horizontal drilling and completion projects and tax treatment of certain compensation deductions, of which $25 million may potentially have an earnings impact. EOG records interest and penalties related to unrecognized tax benefits to its income tax provision. Cumulatively, $4 million of interest has been recognized in the Consolidated Statements of Income and Comprehensive Income. 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 (2015), Trinidad (2013) and China (2009).

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, 2019, EOG has cumulatively recorded $16 million of deferred foreign income taxes for withholdings on its undistributed foreign earnings. Additionally, for tax years beginning in 2018 and later, 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 2019, 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-20

Stock-based compensation expense is included on the Consolidated Statements of Income and Comprehensive Income based upon the job functions of the employees receiving the grants.  Compensation expense related to EOG's stock-based compensation plans for the years ended December 31, 2019, 2018 and 2017 was as follows (in millions):

	2019		2018		2017
Lease and Well	$	56	$	51	$	41
Gathering and Processing Costs	1		1		1
Exploration Costs	26		25		23
General and Administrative	92		78		69
Total	$	175	$	155	$	134

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 as follows:

Grant Type	Vesting Schedule
Stock Options/SARs	Vesting in increments of 33%, 33% and 34% 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 approximately 41 months from the date of grant - specifically, on the February 28th immediately following the Compensation Committee's certifications contemplated by the form of award agreement governing such grant of performance units

At December 31, 2019, approximately 6.8 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 2019, 2018 and 2017, EOG issued shares in connection with stock option/SAR exercises, restricted stock and performance unit 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 $(1) million, $20 million and $32 million for the twelve months ended December 31, 2019, 2018 and 2017, 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 $63 million, $60 million and $56 million for the years ended December 31, 2019, 2018 and 2017, respectively.

F-21

Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants for the years ended December 31, 2019, 2018 and 2017 were as follows:

	Stock Options/SARs									ESPP
	2019			2018			2017			2019			2018			2017
Weighted Average Fair Value of Grants	$	19.49		$	33.46		$	23.95		$	22.83		$	25.75		$	22.20
Expected Volatility	32.02		%	28.23		%	28.28		%	34.78		%	24.59		%	27.12		%
Risk-Free Interest Rate	1.69		%	2.68		%	1.52		%	2.27		%	1.89		%	0.88		%
Dividend Yield	1.39		%	0.72		%	0.75		%	1.04		%	0.64		%	0.71		%
Expected Life	5.1 years			5.0 years			5.1 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, 2019, 2018 and 2017 (stock options and SARs in thousands):

	2019				2018				2017
	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	8,310		$	96.90	9,103		$	83.89	9,850		$	75.53
Granted	1,965		75.39		1,906		126.49		2,274		96.27
Exercised (1)	(606	)	61.43		(2,493	)	72.21		(2,574	)	61.12
Forfeited	(274	)	102.57		(206	)	94.43		(447	)	93.84
Outstanding at December 31	9,395		94.53		8,310		96.90		9,103		83.89
Stock Options/SARs Exercisable at December 31	5,275		94.21		3,969		85.82		4,510		75.76

(1) The total intrinsic value of stock options/SARs exercised during the years 2019, 2018 and 2017 was $14 million, $118 million and $95 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, 2019, there were 9.1 million stock options/SARs vested or expected to vest with a weighted average grant price of $94.52 per share, an intrinsic value of $29.1 million and a weighted average remaining contractual life of 4.2 years.

F-22

The following table summarizes certain information for the stock options and SARs outstanding and exercisable at December 31, 2019 (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)
$ 59.00 to $  74.99	979	3	$	69.43			953	3	$	69.37
75.00 to    75.99	1,894	7	75.09				8	1	75.09
76.00 to     95.99	1,979	3	91.35				1,607	2	90.67
96.00 to     96.99	1,871	4	96.29				1,234	4	96.29
97.00 to   125.99	923	2	102.72				862	2	102.20
126.00 to   129.99	1,749	6	127.01				611	5	127.01
	9,395	4	94.53		$	30,534	5,275	3	94.21		$	13,839

(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.

At December 31, 2019, unrecognized compensation expense related to non-vested stock option and SAR grants totaled $86 million.  This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.0 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, 2019, approximately 2.3 million shares of Common Stock remained available for grant under the ESPP.  The following table summarizes ESPP activity for the years ended December 31, 2019, 2018 and 2017 (in thousands, except number of participants):

	2019		2018		2017
Approximate Number of Participants	1,998		1,934		1,870
Shares Purchased	224		180		180
Aggregate Purchase Price	$	16,533	$	14,887	$	13,997

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 $97 million, $81 million and $68 million for the years ended December 31, 2019, 2018 and 2017, respectively.

F-23

The following table sets forth the restricted stock and restricted stock unit transactions for the years ended December 31, 2019, 2018 and 2017 (shares and units in thousands):

	2019				2018				2017
	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	3,792		$	96.64	3,905		$	88.57	3,962		$	79.63
Granted	1,749		80.01		812		117.55		1,095		97.34
Released (1)	(855	)	96.93		(740	)	78.16		(929	)	61.51
Forfeited	(140	)	97.54		(185	)	92.12		(223	)	85.45
Outstanding at December 31 (2)	4,546		90.16		3,792		96.64		3,905		88.57

(1) The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2019, 2018 and 2017 was $70 million, $84 million and $91 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, 2019, 2018 and 2017 was $381 million, $331 million and $421 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, 2019, unrecognized compensation expense related to restricted stock and restricted stock units totaled $202 million. Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 1.8 years.

Performance Units.  EOG has granted performance units (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 $15 million, $14 million and $10 million for the years ended December 31, 2019, 2018 and 2017, respectively.

      Weighted average fair values and valuation assumptions used to value Performance Awards during the years ended December 31, 2019, 2018 and 2017 were as follows:

	2019			2018			2017
Weighted Average Fair Value of Grants	$	79.98		$	136.74		$	113.81
Expected Volatility	29.20		%	29.92		%	32.19		%
Risk-Free Interest Rate	1.51		%	2.85		%	1.60		%

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-24

The following table sets forth the Performance Award transactions for the years ended December 31, 2019, 2018 and 2017 (shares and units in thousands):

	2019						2018				2017
	Number of Units and Shares				Weighted Average Price per Grant Date		Number of Units and Shares		Weighted Average Price per Grant Date		Number of Units and Shares		Weighted Average Price per Grant Date
Outstanding at January 1	539				$	101.53	502		$	90.96	545		$	80.92
Granted	172				75.09		113		125.73		78		96.29
Granted for Performance Multiple (1)	72				69.43		72		101.87		119		84.43
Released (2)	(185	)			94.63		(148	)	84.43		(240	)	66.69
Forfeited	—				—		—		—		—		—
Outstanding at December 31 (3)	598		(4	)	92.19		539		101.53		502		90.96

(1) Upon completion of the Performance Period for the Performance Awards granted in 2015, 2014 and 2013, a performance multiple of 200% was applied to each of the grants resulting in additional grants of Performance Awards in February 2019, 2018 and 2017.

(2) The total intrinsic value of Performance Awards released during the years ended December 31, 2019, 2018 and 2017 was $15 million, $18 million and $24 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, 2019, 2018 and 2017 was $50 million, $47 million and $54 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 102 and a maximum of 1,094 Performance Awards could be outstanding.

At December 31, 2019, unrecognized compensation expense related to Performance Awards totaled $9 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.0 years.

Upon completion of the Performance Period for the Performance Awards granted in September 2016 and December 2016, a performance multiple of 150% was applied to the grants resulting in an additional grant of 65,872 Performance Awards in February 2020.

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 $51 million, $43 million and $37 million for 2019, 2018 and 2017, respectively.

In addition, EOG's Trinidadian subsidiary maintains a contributory defined benefit pension plan and a matched savings plan.  EOG's United Kingdom subsidiary maintained a pension plan which included a non-contributory defined contribution pension plan and a matched defined contribution savings plan.  These pension plans are available to most employees of the Trinidadian subsidiary and were available to most employees of the United Kingdom subsidiary.  EOG's combined contributions to these plans were $1 million, for each of 2019, 2018 and 2017, respectively. The United Kingdom operations were sold in the fourth quarter of 2018.

For the Trinidadian defined benefit pension plan, the benefit obligation, fair value of plan assets and accrued benefit cost totaled $12 million, $10 million and $0.1 million, respectively, at December 31, 2019, and $11 million, $9 million and $0.2 million, respectively, at December 31, 2018.

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-25

8.  Commitments and Contingencies

Letters of Credit and Guarantees.  At December 31, 2019 and 2018, respectively, EOG had standby letters of credit and guarantees outstanding totaling $902 million and $294 million, primarily representing guarantees of payment or performance obligations on behalf of subsidiaries. As of February 19, 2020, EOG had received no demands for payment under these guarantees.

Minimum Commitments.  At December 31, 2019, 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, 2019, were as follows (in millions):

	Total Minimum Commitments
2020	$	1,312
2021	1,103
2022	1,027
2023	764
2024	519
2025 and beyond	2,531
	$	7,256

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

9.  Net Income Per Share

The following table sets forth the computation of Net Income Per Share for the years ended December 31, 2019, 2018 and 2017 (in thousands, except per share data):

	2019		2018		2017
Numerator for Basic and Diluted Earnings per Share -
Net Income	$	2,734,910	$	3,419,040	$	2,582,579
Denominator for Basic Earnings per Share -
Weighted Average Shares	577,670		576,578		574,620
Potential Dilutive Common Shares -
Stock Options/SARs	258		1,137		1,466
Restricted Stock/Units and Performance Units	2,849		2,726		2,607
Denominator for Diluted Earnings per Share -
Adjusted Diluted Weighted Average Shares	580,777		580,441		578,693
Net Income Per Share
Basic	$	4.73	$	5.93	$	4.49
Diluted	$	4.71	$	5.89	$	4.46

The diluted earnings per share calculation excludes stock options, SARs, restricted stock and units and performance units that were anti-dilutive.  Shares underlying the excluded stock options and SARs totaled 6.1 million, 0.6 million and 2.6 million for the years ended December 31, 2019, 2018 and 2017, respectively.

F-26

10.  Supplemental Cash Flow Information

Net cash paid (received) for interest and income taxes was as follows for the years ended December 31, 2019, 2018 and 2017 (in thousands):

	2019			2018		2017
Interest, Net of Capitalized Interest	$	186,546		$	243,279	$	275,305
Income Taxes, Net of Refunds Received	$	(291,849	)	$	75,634	$	188,946

EOG's accrued capital expenditures at December 31, 2019, 2018 and 2017 were $612 million, $592 million and $475 million, respectively.

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.

Non-cash investing activities for the year ended December 31, 2017, included non-cash additions of $282 million to EOG's oil and gas properties as a result of property exchanges.

Cash paid for leases for the year ended December 31, 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.  For segment reporting purposes, the chief operating decision maker considers the major United States producing areas to be one operating segment.

F-27

Financial information by reportable segment is presented below as of and for the years ended December 31, 2019, 2018 and 2017 (in thousands):

	United States		Trinidad			Other International (1)			Total
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 (2)	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-28

	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
Losses 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 (3)	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
2017
Crude Oil and Condensate	$	6,225,711		$	13,572		$	17,113		$	6,256,396
Natural Gas Liquids	729,545			—			16			729,561
Natural Gas	615,512			271,101			35,321			921,934
Gains on Mark-to-Market Commodity Derivative Contracts	19,828			—			—			19,828
Gathering, Processing and Marketing	3,298,098			(11		)	—			3,298,087
Losses on Asset Dispositions, Net	(98,233		)	(8		)	(855		)	(99,096		)
Other, Net	81,610			59			(59		)	81,610
Operating Revenues and Other (4)	10,872,071			284,713			51,536			11,208,320
Depreciation, Depletion and Amortization	3,269,196			115,321			24,870			3,409,387
Operating Income (Loss)	933,571			101,010			(108,179		)	926,402
Interest Income	3,223			2,201			2,289			7,713
Other Income (Expense)	(9,659		)	3,337			7,761			1,439
Net Interest Expense	303,941			—			(29,569		)	274,372
Income (Loss) Before Income Taxes	623,194			106,548			(68,560		)	661,182
Income Tax Provision (Benefit)	(1,964,343		)	38,798			4,148			(1,921,397		)
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	4,067,359			145,937			14,932			4,228,228
Total Property, Plant and Equipment, Net	25,125,427			313,357			226,253			25,665,037
Total Assets	28,312,599			974,477			546,002			29,833,078

(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.

(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) EOG had sales activity with two significant purchasers in 2017, one totaling $1.5 billion and the other totaling $1.3 billion of consolidated Operating Revenues and Other in the United States segment.

F-29

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 2019, 2018 and 2017, 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 and Comprehensive Income.  The related cash flow impact is reflected in Cash Flows from Operating Activities.  During 2019, 2018 and 2017, EOG recognized net gains (losses) on the mark-to-market of financial commodity derivative contracts of $180 million, $(166) million and $20 million, respectively, which included cash received from (payments for) settlements of crude oil and natural gas derivative contracts of $231 million, $(259) million and $7 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 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 pricing in Midland, Texas, and Cushing, Oklahoma (Midland Differential). Presented below is a comprehensive summary of EOG's Midland Differential basis swap contracts for the year ended December 31, 2019. The weighted average price differential expressed in dollars per barrel ($/Bbl) represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in barrels per day (Bbld) covered by the basis swap contracts.

Midland Differential Basis Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)
2019
January 1, 2019 through December 31, 2019 (closed)	20,000	$	1.075

EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in the U.S. Gulf Coast and Cushing, Oklahoma (Gulf Coast Differential). Presented below is a comprehensive summary of EOG's Gulf Coast Differential basis swap contracts for the year ended December 31, 2019. 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.

Gulf Coast Differential Basis Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)
2019
January 1, 2019 through December 31, 2019 (closed)	13,000	$	5.572

F-30

Presented below is a comprehensive summary of EOG's crude oil price swap contracts for the year ended December 31, 2019, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

Crude Oil Price Swap Contracts
	Volume (Bbld)	Weighted Average Price ($/Bbl)
2019
April 2019 (closed)	25,000	$	60.00
May 1, 2019 through December 31, 2019 (closed)	150,000	62.50
2020
January 1, 2020 through March 31, 2020	200,000	$	59.33
April 1, 2020 through June 30, 2020	150,000	59.03
July 1, 2020 through September 30, 2020	50,000	58.32

NGLs Derivative Contracts. Presented below is a comprehensive summary of EOG's Mont Belvieu propane (non-TET) price swap contracts for the year ended December 31, 2019, 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 December 31, 2020	4,000	$	21.34

Natural Gas Derivative Contracts. Presented below is a comprehensive summary of EOG's natural gas price swap contracts for the year ended December 31, 2019, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).

Natural Gas Price Swap Contracts
	Volume (MMBtud)	Weighted Average Price ($/MMBtu)
2019
April 1, 2019 through October 31, 2019 (closed)	250,000	$	2.90

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 for the year ended December 31, 2019. 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	30,000	$	0.55

F-31

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). Presented below is a comprehensive summary of EOG's HSC Differential basis swap contracts for the year ended December 31, 2019. 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	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 for the year ended December 31, 2019. 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 December 31, 2020	50,000	$	1.40

 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, 2019 and 2018, 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	2019		2018
Asset Derivatives
Crude oil, NGLs and natural gas derivative contracts -
Current portion	Assets from Price Risk Management Activities (1)	$	1,299	$	23,806
Liability Derivatives
Crude oil, NGLs and natural gas derivative contracts -
Current portion	Liabilities from Price Risk Management Activities (2)	$	20,194	$	—

(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.

F-32

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, 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.  At December 31, 2018, 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 2019.

In 2019 and 2018, all natural gas from EOG's Trinidad operations was sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary. In 2019, all crude oil and condensate from EOG's Trinidad operations was sold to Heritage Petroleum Company Limited (Heritage). In 2018, all crude oil and condensate from EOG's Trinidad operations was sold to Heritage and its predecessor, the Petroleum Company of Trinidad and Tobago Limited. In 2019 and 2018, 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 liability position at December 31, 2019.  EOG had no collateral posted and held no collateral at December 31, 2019 and 2018.

Substantially all of EOG's accounts receivable at December 31, 2019 and 2018 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, 2019, credit losses incurred on receivables by EOG have been immaterial.

F-33

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.

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, 2019 and 2018. 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, 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
At December 31, 2018
Financial Assets (1):
Crude Oil Swaps	$	—	$	23,806	$	—	$	23,806

(1) $1 million and $24 million are included in "Current Assets - Assets from Price Risk Management Activities" at December 31, 2019 and 2018, respectively, on the Consolidated Balance Sheets.

(2) $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.

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.

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 impairment charges in 2019 of $90 million for a commodity price-related write-down of other assets.

During 2018, proved oil and gas properties; other property, plant and equipment; and other assets with a carrying amount of $482 million were written down to their fair value of $308 million, resulting in pretax impairment charges of $174 million. Included in the $174 million pretax impairment charges are $104 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 2018 of $49 million for a commodity price-related write-down of other assets.

F-34

Significant Level 3 inputs associated with the calculation of discounted cash flows used in the impairment analysis include EOG's estimate of future crude oil, NGLs and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data.

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, 2019 and 2018, respectively, EOG had outstanding $5,140 million and $6,040 million aggregate principal amount of senior notes, which had estimated fair values of approximately $5,452 million and $6,027 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.  Accounting for Certain Long-Lived Assets

EOG reviews its proved oil and gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the asset.  The carrying values for assets determined to be impaired were adjusted to estimated fair value 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 2019, proved oil and gas properties with a carrying amount of $408 million were written down to their fair value of $201 million, resulting in pretax impairment charges of $207 million. During 2018, proved oil and gas properties with a carrying amount of $139 million were written down to their fair value of $18 million, resulting in pretax impairment charges of $121 million. Impairments in 2019, 2018 and 2017 included domestic legacy natural gas assets. Amortization and impairments of unproved oil and gas property costs, including amortization of capitalized interest, were $220 million, $173 million and $211 million during 2019, 2018 and 2017, respectively.

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, 2019 and 2018 (in thousands):

	2019			2018
Carrying Amount at Beginning of Period	$	954,377		$	946,848
Liabilities Incurred	98,874			79,057
Liabilities Settled (1)	(58,673		)	(70,829		)
Accretion	43,462			36,622
Revisions	72,425			(38,932		)
Foreign Currency Translations	245			1,611
Carrying Amount at End of Period	$	1,110,710		$	954,377
Current Portion	$	37,127		$	26,214
Noncurrent Portion	$	1,073,583		$	928,163

(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.

F-35

16.  Exploratory Well Costs

EOG's net changes in capitalized exploratory well costs for the years ended December 31, 2019, 2018 and 2017 are presented below (in thousands):

	2019			2018			2017
Balance at January 1	$	4,121		$	2,167		$	—
Additions Pending the Determination of Proved Reserves	83,175			10,304			27,487
Reclassifications to Proved Properties	(39,325		)	(7,917		)	(20,802		)
Costs Charged to Expense (1)	(22,074		)	(433		)	(4,518		)
Balance at December 31	$	25,897		$	4,121		$	2,167

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

At December 31, 2019, 2018 and 2017, all exploratory well costs had been capitalized for periods of less than one year.

17.  Acquisitions and Divestitures

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 a net gain 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.

During 2017, EOG recognized a net loss on asset dispositions of $99 million and received proceeds of approximately $227 million primarily from sales of producing properties, other assets and acreage in Texas and Oklahoma.

Also during 2017, EOG completed acquisitions of approximately $73 million to acquire producing properties in various areas in the United States.

F-36

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 year ended December 31, 2019, were as follows (in millions):

	Year Ended December 31, 2019
Operating Lease Cost	$	497
Finance Lease Cost:
Amortization of Lease Assets	13
Interest on Lease Liabilities	2
Variable Lease Cost	138
Short-Term Lease Cost	333
Total Lease Cost	$	983

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

Description	Location on Balance Sheet	Amount
Assets
Operating Leases	Other Assets	$	773
Finance Leases	Property, Plant and Equipment, Net (1)	53
Total		$	826
Liabilities
Current
Operating Leases	Current Portion of Operating Lease Liabilities	$	369
Finance Leases	Current Portion of Long-Term Debt	15
Long-Term
Operating Leases	Other Liabilities	430
Finance Leases	Long-Term Debt	43
Total		$	857

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

	Year Ended December 31, 2019
Weighted Average Remaining Lease Term (in years):
Operating Leases	3.2
Finance Leases	4.7
Weighted Average Discount Rate:
Operating Leases	3.5	%
Finance Leases	3.0	%

F-37

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

	Year Ended December 31, 2019
Repayment of Operating Lease Liabilities Associated with Operating Activities	$	225
Repayment of Operating Lease Liabilities Associated with Investing Activities	270
Repayment of Finance Lease Liabilities	13

Upon adoption of ASU 2016-02 effective January 1, 2019, EOG recognized operating lease ROU assets of $566 million. Non-cash leasing activities for the twelve months ended December 31, 2019, included the addition of $784 million of operating leases.

At December 31, 2019, the future minimum lease payments under non-cancellable leases were as follows (in millions):

	Operating Leases		Finance Leases
2020	$	390	$	15
2021	209		15
2022	126		12
2023	56		8
2024	29		8
2025 and Beyond	40		6
Total Lease Payments	850		64
Less: Discount to Present Value	51		6
Total Lease Liabilities	799		58
Less: Current Portion of Lease Liabilities	369		15
Long-Term Lease Liabilities	$	430	$	43

At December 31, 2019, EOG had additional leases of $699 million, of which $521 million and $178 million were expected to commence in 2020 and 2021, respectively, with lease terms of one month to 10 years.

At December 31, 2018 and 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, 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-38

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 Estimates 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 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, 2019.  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.

F-39

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 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, 2019, 2018 and 2017 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 33 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 Executive Vice Presidents, Exploration and Production; and the Executive Vice President and Chief Financial Officer, for approval.

Opinions by D&M for the years ended December 31, 2019, 2018 and 2017 covered producing areas containing 82%, 79% 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 24, 2020, 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, 2019, 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, 2019, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2019, as estimated by the Engineering and Acquisitions Department of EOG:

F-40

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, 2016	1,168,491		839		8,255		1,177,585
Revisions of previous estimates	57,935		80		(179	)	57,836
Purchases in place	1,111		—		—		1,111
Extensions, discoveries and other additions	207,137		301		119		207,557
Sales in place	(8,393	)	—		—		(8,393	)
Production	(122,210	)	(322	)	(191	)	(122,723	)
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
Natural Gas Liquids (MBbl) (2)
Net proved reserves at December 31, 2016	416,366		—		—		416,366
Revisions of previous estimates	46,843		—		—		46,843
Purchases in place	421		—		—		421
Extensions, discoveries and other additions	75,003		—		—		75,003
Sales in place	(2,887	)	—		—		(2,887	)
Production	(32,273	)	—		—		(32,273	)
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

F-41

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, 2016	3,021.2		280.9		15.8		3,317.9
Revisions of previous estimates	602.8		(27.4	)	8.6		584.0
Purchases in place	4.8		—		—		4.8
Extensions, discoveries and other additions	619.3		174.2		35.9		829.4
Sales in place	(56.4	)	—		—		(56.4	)
Production	(293.2	)	(114.3	)	(9.1	)	(416.6	)
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
Oil Equivalents (MBoe) (2)
Net proved reserves at December 31, 2016	2,088,392		47,661		10,880		2,146,933
Revisions of previous estimates	205,262		(4,493	)	1,249		202,018
Purchases in place	2,332		—		—		2,332
Extensions, discoveries and other additions	385,354		29,340		6,104		420,798
Sales in place	(20,687	)	—		—		(20,687	)
Production	(203,351	)	(19,366	)	(1,707	)	(224,424	)
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

(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-42

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

During 2019, EOG added 750 million barrels of oil equivalent (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.

During 2017, EOG added 421 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 Trinidad.  Approximately 67% of the 2017 reserve additions were crude oil and condensate and NGLs, and 92% were in the United States.  Sales in place of 21 MMBoe were primarily related to the sale or exchange of certain producing assets. Revisions of previous estimates of 202 MMBoe for 2017 included an upward revision of 154 MMBoe primarily due to increases in the average crude oil, NGLs and natural gas prices used in the December 31, 2017, reserves estimation as compared to the prices used in the prior year estimate. The primary plays affected were in the Rocky Mountain area, the Eagle Ford and the Permian Basin. Positive revisions other than price of 48 MMBoe resulted primarily from improved well performance in the Permian Basin and lower production costs. Purchases in place of 2 MMBoe were primarily related to the Permian Basin.

F-43

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, 2016	507,531	839	8,255	516,625
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
Natural Gas Liquids (MBbl)
December 31, 2016	230,219	—	—	230,219
December 31, 2017	286,872	—	—	286,872
December 31, 2018	341,386	—	—	341,386
December 31, 2019	387,253	—	—	387,253
Natural Gas (Bcf)
December 31, 2016	1,804.4	262.2	15.8	2,082.4
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
Oil Equivalents (MBoe)
December 31, 2016	1,038,483	44,543	10,880	1,093,906
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
NET PROVED UNDEVELOPED RESERVES
Crude Oil (MBbl)
December 31, 2016	660,690	—	—	660,690
December 31, 2017	698,666	—	71	698,737
December 31, 2018	819,466	—	61	819,527
December 31, 2019	892,771	—	48	892,819
Natural Gas Liquids (MBbl)
December 31, 2016	186,147	—	—	186,147
December 31, 2017	216,601	—	—	216,601
December 31, 2018	272,943	—	—	272,943
December 31, 2019	352,439	—	—	352,439
Natural Gas (Bcf)
December 31, 2016	1,216.8	18.7	—	1,235.5
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
Oil Equivalents (MBoe)
December 31, 2016	1,049,909	3,118	—	1,053,027
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

(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-44

EOG RESOURCES, INC.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Net Proved Undeveloped Reserves. The following table presents the changes in EOG's total proved undeveloped reserves during 2019, 2018 and 2017 (in MBoe):

	2019		2018		2017
Balance at January 1	1,379,709		1,162,635		1,053,027
Extensions and Discoveries	578,317		490,725		237,378
Revisions	(49,837	)	(8,244	)	33,127
Acquisition of Reserves	1,711		311		—
Sale of Reserves	—		—		(8,253	)
Conversion to Proved Developed Reserves	(302,044	)	(265,718	)	(152,644	)
Balance at December 31	1,607,856		1,379,709		1,162,635

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 (see discussion of technology employed on pages F-39 and F-40 of this Annual Report on Form 10-K), 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.  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, 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. 

For the twelve-month period ended December 31, 2017, total PUDs increased by 110 MMBoe to 1,163 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 199 MMBoe.  The PUD additions were primarily in the Permian Basin and, to a lesser extent, the Eagle Ford and the Rocky Mountain area, and 74% of the additions were crude oil and condensate and NGLs.  During 2017, EOG drilled and transferred 153 MMBoe of PUDs to proved developed reserves at a total capital cost of $1,440 million.  Revisions of PUDs totaled positive 33 MMBoe, primarily due to updated type curves resulting from improved performance of offsetting wells in the Permian Basin, the impact of increases in the average crude oil and natural gas prices used in the December 31, 2017, reserves estimation as compared to the prices used in the prior year estimate, and lower costs.  During 2017, EOG sold or exchanged 8 MMBoe of PUDs primarily in the Permian Basin.

F-45

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, 2019 and 2018:

	2019			2018
Proved properties	$	59,229,686		$	53,624,809
Unproved properties	3,600,729			3,705,207
Total	62,830,415			57,330,016
Accumulated depreciation, depletion and amortization	(35,033,085		)	(31,674,085		)
Net capitalized costs	$	27,797,330		$	25,655,931

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-46

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, 2019, 2018 and 2017:

	United States		Trinidad			Other International (1)		Total
2019
Acquisition Costs of Properties
Unproved (2)	$	276,092	$	—		$	—	$	276,092
Proved (3)	379,938		—			—		379,938
Subtotal	656,030		—			—		656,030
Exploration Costs	213,505		46,616			13,218		273,339
Development Costs (4)	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 (5)	$	486,081	$	1,258		$	—	$	487,339
Proved (6)	123,684		—			—		123,684
Subtotal	609,765		1,258			—		611,023
Exploration Costs	157,222		22,511			13,895		193,628
Development Costs (7)	5,605,264		(12,863		)	22,628		5,615,029
Total	$	6,372,251	$	10,906		$	36,523	$	6,419,680
2017
Acquisition Costs of Properties
Unproved (8)	$	424,118	$	2,422		$	—	$	426,540
Proved (9)	72,584		—			—		72,584
Subtotal	496,702		2,422			—		499,124
Exploration Costs	144,499		62,547			16,553		223,599
Development Costs (10)	3,590,899		109,491			16,297		3,716,687
Total	$	4,232,100	$	174,460		$	32,850	$	4,439,410

(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.

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

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

(4) 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.

(5) Includes non-cash unproved leasehold acquisition costs of $291 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 $90 million, $(12) million and $(8) 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 $256 million related to property exchanges.

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

(10) Includes Asset Retirement Costs of $50 million, $2 million and $4 million for the United States, Trinidad and Other International, respectively.  Excludes other property, plant and equipment.

F-47

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, 2019, 2018 and 2017:

	United States		Trinidad			Other International (2)			Total
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
2017
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	7,570,768	$	284,673		$	52,450		$	7,907,891
Other	81,610		59			(59		)	81,610
Total	7,652,378		284,732			52,391			7,989,501
Exploration Costs	113,334		26,245			5,763			145,342
Dry Hole Costs	91		—			4,518			4,609
Transportation Costs	737,403		1,885			1,064			740,352
Production Costs	1,446,333		27,839			88,038			1,562,210
Impairments	477,223		—			2,017			479,240
Depreciation, Depletion and Amortization	3,157,056		115,174			24,536			3,296,766
Income (Loss) Before Income Taxes	1,720,938		113,589			(73,545		)	1,760,982
Income Tax Provision (Benefit)	625,562		24,882			(1,342		)	649,102
Results of Operations	$	1,095,376	$	88,707		$	(72,203	)	$	1,111,880

(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, 2019.

(2) 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.

(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-48

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, 2019, 2018 and 2017:

	United States		Trinidad		Other International (1)		Composite
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
Year Ended December 31, 2017	$	4.58	$	1.39	$	50.86	$	4.66

(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 2019, 2018 and 2017.  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-49

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, 2019, 2018 and 2017:

	United States			Trinidad			Other International (1)			Total
2019
Future cash inflows (2)	$	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 (3)	$	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
2017
Future cash inflows (4)	$	83,652,363		$	904,141		$	664,560		$	85,221,064
Future production costs	(32,018,812		)	(239,213		)	(311,383		)	(32,569,408		)
Future development costs	(13,395,873		)	(84,379		)	(58,543		)	(13,538,795		)
Future income taxes	(5,948,453		)	(195,855		)	(16,233		)	(6,160,541		)
Future net cash flows	32,289,225			384,694			278,401			32,952,320
Discount to present value at 10% annual rate	(14,532,290		)	(52,267		)	(40,103		)	(14,624,660		)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	17,756,935		$	332,427		$	238,298		$	18,327,660

(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 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) Estimated crude oil prices used to calculate 2017 future cash inflows for the United States, Trinidad and Other International were $49.21, $41.87 and $50.06, respectively. Estimated NGL price used to calculate 2017 future cash inflows for the United States was $23.51. Estimated natural gas prices used to calculate 2017 future cash inflows for the United States, Trinidad and Other International were $1.96, $2.76 and $5.16, respectively.

F-50

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, 2019:

	United States			Trinidad			Other International (1)			Total
December 31, 2016	$	8,493,727		$	185,750		$	132,680		$	8,812,157
Sales and transfers of oil and gas produced, net of production costs	(5,387,031		)	(254,948		)	36,649			(5,605,330		)
Net changes in prices and production costs	6,606,908			436,969			77,668			7,121,545
Extensions, discoveries, additions and improved recovery, net of related costs	3,644,041			270,255			43,952			3,958,248
Development costs incurred	1,435,600			4,700			—			1,440,300
Revisions of estimated development cost	(114,464		)	9,683			(20,096		)	(124,877		)
Revisions of previous quantity estimates	2,460,498			(58,373		)	36,146			2,438,271
Accretion of discount	849,373			24,066			13,268			886,707
Net change in income taxes	(1,918,989		)	(114,575		)	(10,099		)	(2,043,663		)
Purchases of reserves in place	30,362			—			—			30,362
Sales of reserves in place	(76,527		)	—			—			(76,527		)
Changes in timing and other	1,733,437			(171,100		)	(71,870		)	1,490,467
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

(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-51

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
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
2018
Operating Revenues and Other	$	3,681,162	$	4,238,077	$	4,781,624	$	4,574,536
Operating Income	$	874,588	$	964,931	$	1,506,687	$	1,123,140
Income Before Income Taxes	$	813,359	$	892,936	$	1,446,363	$	1,088,340
Income Tax Provision	174,770		196,205		255,411		195,572
Net Income	$	638,589	$	696,731	$	1,190,952	$	892,768
Net Income Per Share (1)
Basic	$	1.11	$	1.21	$	2.06	$	1.55
Diluted	$	1.10	$	1.20	$	2.05	$	1.54
Average Number of Common Shares
Basic	575,775		576,135		577,254		577,035
Diluted	579,726		580,375		581,559		580,288

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

F-52

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.
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 2.95% Senior Notes due 2015 and 4.40% Senior Notes due 2020 of EOG, dated May 20, 2010 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed May 26, 2010) (SEC File No. 001-09743).
4.6(b)	-	Form of Global Note with respect to the 4.40% Senior Notes due 2020 of EOG (Exhibit 4.4 to EOG's Current Report on Form 8-K, filed May 26, 2010) (SEC File No. 001-09743).
4.7(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).
4.7(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).
4.8(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).
4.8(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).
4.9(a)	-	Officers' Certificate Establishing 2.45% Senior Notes due 2020 of EOG, dated March 21, 2014 (Exhibit 4.2 to EOG's Current Report on Form 8-K, filed March 25, 2014) (SEC File No. 001-09743).
4.9(b)	-	Form of Global Note with respect to the 2.45% Senior Notes due 2020 of EOG (Exhibit 4.3 to EOG's Current Report on Form 8-K, filed March 25, 2014) (SEC File No. 001-09743).
4.10(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).
4.10(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).
4.10(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).
4.11(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).
4.11(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).
4.11(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).
10.1(a)+	-	EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan, effective as of May 8, 2008 (Exhibit 10.1 to EOG's Current Report on Form 8-K, filed May 14, 2008) (SEC File No. 001-09743).
10.1(b)+	-	First Amendment to EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan, dated effective as of September 4, 2008 (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2008) (SEC File No. 001-09743).
10.1(c)+	-	Second Amendment to EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan, dated effective as of January 1, 2010 (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2010) (SEC File No. 001-09743).

E-2

Exhibit Number		Description
10.1(d)+	-	Third Amendment to EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan, dated effective as of September 26, 2012 (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012) (SEC File No. 001-09743).
10.1(e)+	-	Form of Stock Option Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made prior to February 23, 2011) (Exhibit 10.2 to EOG's Current Report on Form 8-K, filed May 14, 2008) (SEC File No. 001-09743).
10.1(f)+	-	Form of Stock Option Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made on or after February 23, 2011) (Exhibit 10.3 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2011) (SEC File No. 001-09743).
10.1(g)+	-	Form of Stock-Settled Stock Appreciation Right Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made prior to February 23, 2011) (Exhibit 10.3 to EOG's Current Report on Form 8-K, filed May 14, 2008) (SEC File No. 001-09743).
10.1(h)+	-	Form of Stock-Settled Stock Appreciation Right Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (applicable to grants made on or after February 23, 2011) (Exhibit 10.4 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2011) (SEC File No. 001-09743).
10.1(i)	-	Form of Nonemployee Director Stock-Settled Stock Appreciation Right Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Exhibit 10.4 to EOG's Current Report on Form 8-K, filed May 14, 2008) (SEC File No. 001-09743).
10.1(j)+	-	Form of Restricted Stock Award Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Exhibit 10.5 to EOG's Current Report on Form 8-K, filed May 14, 2008) (SEC File No. 001-09743).
10.1(k)+	-	Form of Restricted Stock Unit Award Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Exhibit 10.6 to EOG's Current Report on Form 8-K, filed May 14, 2008) (SEC File No. 001-09743).
10.1(l)	-	Form of Nonemployee Director Restricted Stock Award Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Exhibit 10.7 to EOG's Current Report on Form 8-K, filed May 14, 2008) (SEC File No. 001-09743).
10.1(m)	-	Form of Nonemployee Director Restricted Stock Unit Award Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Exhibit 10.3 to EOG's Quarterly Report on Form 10-Q for the quarter ended June 30, 2012) (SEC File No. 001-09743).
10.1(n)+	-	Form of Performance Unit Award Agreement for EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Exhibit 10.4 to EOG's Current Report on Form 8-K, filed October 1, 2012) (SEC File No. 001-09743).
10.2(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).
10.2(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).
10.2(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).
10.2(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 subsequent grants) (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2018) (SEC File No. 001-09743).
10.2(e)+	-	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).
10.2(f)+	-	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).

E-3

Exhibit Number		Description
10.2(g)+	-	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 subsequent grants) (Exhibit 10.2 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2018) (SEC File No. 001-09743).
10.2(h)+	-	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).
10.2(i)+	-	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 subsequent grants) (Exhibit 10.4 to EOG's Current Report on Form 8-K, filed September 29, 2017) (SEC File No. 001-09743).
10.2(j)+	-	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).
10.2(k)+	-	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).
10.2(l)+	-	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).
10.2(m)+	-	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).
10.2(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 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).
10.2(o)+	-	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).
10.2(p)+	-	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 subsequent grants) (Exhibit 10.1 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2019) (SEC File No. 001-09743).
10.2(q)+	-	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).
10.2(r)	-	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).
10.2(s)	-	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).
10.2(t)	-	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).
10.3(a)+	-	EOG Resources, Inc. 409A Deferred Compensation Plan - Nonqualified Supplemental Deferred Compensation Plan - Plan Document, effective as of December 16, 2008 (Exhibit 10.2(a) to EOG's Annual Report on Form 10-K for the year ended December 31, 2008) (SEC File No. 001-09743).

E-4

Exhibit Number		Description
10.3(b)+	-	EOG Resources, Inc. 409A Deferred Compensation Plan - Nonqualified Supplemental Deferred Compensation Plan - Adoption Agreement, originally dated as of December 16, 2008 (and as amended through February 24, 2012 (including an amendment to Item 7 thereof, effective January 1, 2012, with respect to the deferral of restricted stock units)) (Exhibit 10.2(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 2011) (originally filed as Exhibit 10.2(b) to EOG's Annual Report on Form 10-K for the year ended December 31, 2008) (SEC File No. 001-09743).
10.3(c)+	-	First Amendment to the EOG Resources, Inc. 409A Deferred Compensation Plan, effective as of January 1, 2013 (Exhibit 10.8 to EOG's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013) (SEC File No. 001-09743).
10.3(d)+	-	Amendment 2 to the EOG Resources, Inc. 409A Deferred Compensation Plan, effective as of January 1, 2018 (Exhibit 10.3(d) to EOG's Annual Report on Form 10-K for the year ended December 31, 2018) (SEC File No. 001-09743).
10.3(e)+	-	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).
10.3(f)+	-	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).
10.4(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).
10.4(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).
10.4(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).
10.5(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).
10.5(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).
10.5(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).
10.6(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).
10.6(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).
10.7(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).
10.7(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).
10.8+	-	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).
10.9+	-	Change of Control Agreement by and between EOG and Kenneth W. Boedeker, effective as of December 19, 2018 (Exhibit 10.11 to EOG's Annual Report on Form 10-K for the year ended December 31, 2018) (SEC File No. 001-09743).

E-5

Exhibit Number		Description
10.10(a)+	-	EOG Resources, Inc. Change of Control Severance Plan, as amended and restated effective as of June 15, 2005 (Exhibit 99.12 to EOG's Current Report on Form 8-K, filed June 21, 2005) (SEC File No. 001-09743).
10.10(b)+	-	First Amendment to the EOG Resources, Inc. Change of Control Severance Plan, effective as of April 30, 2009 (Exhibit 10.6 to EOG's Quarterly Report on Form 10-Q for the quarter ended March 31, 2009) (SEC File No. 001-09743).
10.11(a)+	-	EOG Resources, Inc. 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).
10.11(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).
10.12(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).
10.12(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).
10.12(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).
10.13	-	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, 2019.
*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 24, 2020.

E-6

Exhibit Number		Description
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 and Comprehensive Income for Each of the Three Years in the Period Ended December 31, 2019, (ii) the Consolidated Balance Sheets - December 31, 2019 and 2018, (iii) the Consolidated Statements of Stockholders' Equity for Each of the Three Years in the Period Ended December 31, 2019, (iv) the Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2019 and (v) the Notes to Consolidated Financial Statements.

+ Management contract, compensatory plan or arrangement

E-7

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 27, 2020	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 27^th day of February, 2020.

	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
	(Julie J. Robertson)
	*	Director
	(Donald F. Textor)
*By:	/s/ MICHAEL P. DONALDSON
	(Michael P. Donaldson)
	(Attorney-in-fact for persons indicated)

EX-4.1

EXHIBIT 4.1

DESCRIPTION OF SECURITIES REGISTERED UNDER SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934

As of February 27, 2020, EOG Resources, Inc. (“EOG,” the “Company,” “we,” “us,” and “our”) had one class of securities registered under Section 12 of the Securities Exchange Act of 1934, as amended: our common stock, $0.01 par value per share (the “Common Stock”).

Description of Capital Stock

The following summary of our capital stock does not purport to be complete and is subject to, and qualified in its entirety by reference to, (i) our Restated Certificate of Incorporation, as amended, including the certificates of designations and related certificates of eliminations in respect of previously authorized series of preferred stock (the “Certificate of Incorporation”), (ii) our Bylaws (the “Bylaws”) and (iii) the General Corporation Law of the State of Delaware, including Section 203.

Please refer to these materials for a complete statement of the terms and rights of the Common Stock and preferred stock. Copies of our Certificate of Incorporation and Bylaws have been filed with the United States Securities and Exchange Commission (the “SEC”) as Exhibits 3.1(a-n) and 3.2, respectively, to our Annual Report on Form 10-K.

Authorized Capital Stock

Under the Certificate of Incorporation, our authorized capital stock consists of:

•1,280,000,000 shares of Common Stock, $0.01 par value per share, and

•10,000,000 shares of preferred stock, $0.01 par value per share (“Preferred Stock”), 3,000,000 shares of which have been designated as “Series E Junior Participating Preferred Stock” (“Series E Preferred Stock”), with a liquidation preference of $1.00 per share or an amount equal to the payment made on one share of our Common Stock, whichever is greater.

As of December 31, 2019, we had 581,914,196 shares of our Common Stock outstanding and no shares of Preferred Stock outstanding.

Common Stock

Dividend Rights

The holders of Common Stock are entitled to dividends in such amounts and at such times as may be declared by our board of directors out of legally available funds.

Voting Rights

Our Common Stock possesses ordinary voting rights for the election of directors and in respect of other corporate matters, each share being entitled to one vote. The Common Stock has no cumulative voting rights, meaning that the holders of a majority of the shares cast for the election of directors can elect all the directors if they choose to do so.

Liquidation Rights

Upon our liquidation or dissolution, the holders of our Common Stock are entitled to share ratably in all net assets available for distribution to stockholders after payment of any corporate debts and payment of any liquidation preference established for the Preferred Stock.

Miscellaneous

The Common Stock carries no preemptive rights and is not convertible, redeemable, assessable or entitled to the benefits of any sinking fund. All outstanding shares of Common Stock are duly authorized, validly issued, fully paid and non-assessable.

Listing

Our Common Stock is listed on the New York Stock Exchange under the symbol “EOG.”

Transfer Agent

The transfer agent and registrar of the Common Stock is Computershare Trust Company, N.A., Louisville, Kentucky.

Preferred Stock

Under our Certificate of Incorporation, our board of directors may provide for the issuance of up to 10,000,000 shares of Preferred Stock in one or more series.

We currently have one authorized series of Preferred Stock: the Series E Preferred Stock. In February 2000, our Board of Directors, in connection with a rights agreement, authorized 1,500,000 shares of the Series E Preferred Stock, with a liquidation preference of $1.00 per share or an amount equal to the payment made on one share of our Common Stock, whichever is greater. In March 2005, the Board of Directors increased the authorized shares of the Series E Preferred Stock to 3,000,000 in connection with the two-for-one stock split of our Common Stock effected in March 2005. The rights agreement and the related preferred share purchase rights expired on February 24, 2010. As of December 31, 2019, there were no shares of the Series E Preferred Stock outstanding. The certificate of designations in respect of the Series E Preferred Stock are filed as Exhibits 3.1(g) and 3.1(k) to our Annual Report on Form 10-K.

The rights, preferences, privileges and restrictions, including liquidation preferences, of the Preferred Stock of each additional series will be fixed or designated by our Board of Directors pursuant to a certificate of designations, without any further vote or action by our stockholders. Certificates of designations will be filed with the SEC in connection with the offering of the specific series of Preferred Stock. The issuance of Preferred Stock could have the effect of delaying, deferring or preventing a change in control of EOG. Upon issuance against full payment of the purchase price therefor, shares of Preferred Stock offered will be fully paid and non-assessable.

Limitation on Directors’ Liability

Delaware corporation law authorizes corporations to limit or eliminate the personal liability of directors to corporations and their stockholders for monetary damages for breach of directors’ fiduciary duty of care. The duty of care requires that, when acting on behalf of the corporation, directors must exercise an informed business judgment based on all material information reasonably available to them. Absent the limitations authorized by such laws, directors are accountable to corporations and their stockholders for monetary damages for conduct constituting gross negligence in the exercise of their duty of care. Delaware law enables corporations to limit available relief to equitable remedies such as injunction or rescission.

Our Certificate of Incorporation limits the liabilities of our directors to us or our stockholders, in their capacity as directors but not in their capacity as officers, to the fullest extent permitted by Delaware law. Specifically, our directors will not be personally liable for monetary damages for breach of a director’s fiduciary duty as a director, except for liability:

•for any breach of the director’s duty of loyalty to us or to our stockholders;

•for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law;

•for unlawful payments of dividends or unlawful stock repurchases or redemptions as provided in Section 174 of the General Corporation Law of the State of Delaware; or

•for any transaction from which the director derived an improper personal benefit.

This provision in our Certificate of Incorporation, as amended, may have the effect of reducing the likelihood of derivative litigation against directors, and may discourage or deter stockholders or management from bringing a lawsuit against directors for breach of their duty of care, even though such an action, if successful, might otherwise have benefited us and our stockholders.

Anti-Takeover Provisions

Certain provisions in our organizational documents could delay or prevent an unsolicited change in control of us, including the authority of our Board of Directors to issue Preferred Stock discussed above and advance notice provisions for director nominations or business to be considered at a stockholders meeting. In addition, Delaware law imposes certain restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding Common Stock.

EX-21

EXHIBIT 21

EOG Resources, Inc.

Subsidiaries

As of December 31, 2019

EOG Resources, Inc., a Delaware corporation, had the U.S. and international subsidiaries shown below as of December 31, 2019. 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 (Nevis) Block 4 (a) Limited	Nevis
EOG Resources China Limited	Hong Kong
EOG Resources International, Inc.	Delaware
EOG Resources Marketing LLC	Delaware
EOG Resources Nevis U (b) Block Limited	Nevis
EOG Resources Nitro2000 Ltd.	Nevis
EOG Resources Railyard (North Dakota), Inc.	Delaware
EOG Resources Railyard (Oklahoma), 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 U(b) Block Unlimited	Trinidad
EOGI China International Ltd.	Cayman Islands
EOGI International Company	Cayman Islands
EOGI International, Inc.	Delaware
EOGI Trinidad - U(a) Block Company	Cayman Islands
Hawthorn Oil Transportation (North Dakota), Inc.	Delaware
Hawthorn Oil Transportation (Oklahoma), 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 14, 2020

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, 2019, to be filed with the United States Securities and Exchange Commission on or about February 27, 2020. The opinions are contained in our reports of third party dated January 30, 2018, January 25, 2019, and January 24, 2020, with respect to the reserves estimates as of December 31, 2017, December 31, 2018, and December 31, 2019, 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 27, 2020 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, 2019.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 27, 2020

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, 2019 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 28 day of January 2020.

/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, 2019 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 28^th day of January 2020.

/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, 2019 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 2020.

/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, 2019 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 2020.

/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, 2019 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 29th day of January 2020.

/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, 2019 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 27th day of January 2020.

/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, 2019 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 30th day of January 2020.

/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 27, 2020

/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 27, 2020

/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, 2019 (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 27, 2020

/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, 2019 (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 27, 2020

/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, 2019:

• 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, 2019, 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, 2019, EOG did not experience a mining-related fatality.

In addition, as of December 31, 2019, 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, 2019.

EX-99.1

1

EXHIBIT 99.1

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

January 24, 2020

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, 2019, 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 24, 2020. The properties evaluated consist of working and royalty interests located in the States of Montana, New Mexico, North Dakota, and Texas; China; and offshore from Trinidad. EOG has represented that these properties account for 82.1 percent on a net equivalent barrel basis of EOG’s net proved reserves as of December 31, 2019, 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. We have reviewed information provided by EOG that it represents to be EOG’s estimates of the net reserves, as of December 31, 2019, 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, 2019. 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 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 of the properties 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.

(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.

3

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.

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).

4

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, 2019, 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 October 2019. Estimated cumulative production, as of December 31, 2019, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 2 months.

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. All gas reserves 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 reserves 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.

5

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. This conversion factor was provided by EOG.

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 $55.69 per barrel and held constant thereafter. The volume-weighted average price attributable to the estimated proved reserves over the lives of the properties was $58.18 per barrel of oil and condensate and $16.65 per barrel of NGL.

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 $2.578 per million Btu ($/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 $2.18 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 2019 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.

6

In our opinion, the information relating to estimated proved reserves of oil, condensate, NGL, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries - Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the FASB and Rules 4-10(a) (1)-(32) of Regulation S-X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S-K of the SEC; provided, however, that estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

Summary of Conclusions

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, 2019, attributable to these properties, which represent 82.1 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, 2019
Properties Evaluated by DeGolyer and MacNaughton	Oil and Condensate (Mbbl)	NGL (Mbbl)	Sales Gas (MMcf)	Oil Equivalent (Mboe)
Proved Developed	663,246	271,715	1,769,267	1,229,839
Proved Undeveloped	830,984	335,218	2,020,510	1,502,954
Total Proved	1,494,230	606,933	3,789,777	2,732,793
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, 2019, attributable to the properties evaluated herein were based on the definition of proved reserves of the SEC and are summarized as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and thousands of barrels of oil equivalent (Mboe):

	Estimated by DeGolyer and MacNaughton Net Proved Reserves as of December 31, 2019
Properties Evaluated by DeGolyer and MacNaughton	Oil and Condensate (Mbbl)	NGL (Mbbl)	Sales Gas (MMcf)	Oil Equivalent (Mboe)
Proved Developed	675,805	254,848	1,712,724	1,216,107
Proved Undeveloped	881,717	351,867	2,130,920	1,588,737
Total Proved	1,557,522	606,715	3,843,644	2,804,844
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.

7

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 2.6 percent when compared on the basis of net oil equivalent. It is DeGolyer and MacNaughton’s opinion that there is no material difference between the net proved reserves estimates prepared by EOG and those prepared by DeGolyer and MacNaughton for those properties DeGolyer and MacNaughton evaluated.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2019, 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/ GREGORY K. GRAVES

Gregory K. Graves, P.E.

Senior Vice President

DeGolyer and MacNaughton

8

CERTIFICATE of QUALIFICATION

I, Gregory K. Graves, 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 24, 2020, and that I, as Senior Vice President, was responsible for the preparation of this report of third party.

2. That I attended the University of Texas at Austin, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1984; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and that I have in excess of 35 years of experience in oil and gas reservoir studies and reserves evaluations.

/s/ GREGORY K. GRAVES

Gregory K. Graves, P.E.

Senior Vice President

XML

Asset Retirement Obligations (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligations, Noncurrent [Abstract]
Carrying Amount at Beginning of Period		$ 954,377	$ 946,848
Liabilities Incurred		98,874	79,057
Liabilities Settled (1)	[1]	(58,673)	(70,829)
Accretion		43,462	36,622
Revisions		72,425	(38,932)
Foreign Currency Translations		245	1,611
Carrying Amount at End of Period		1,110,710	954,377
Current Portion		37,127	26,214
Noncurrent Portion		$ 1,073,583	$ 928,163

[1] Includes settlements related to asset sales.

XML

Oil and Gas Exploration and Production Industries Disclosures (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2019 USD ($) MBoe MBbls MMcf	Dec. 31, 2018 USD ($) MBoe MBbls MMcf	Dec. 31, 2017 MBoe MBbls MMcf	Dec. 31, 2016 MBoe MBbls MMcf
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves (MBOE) | MBoe		1,721,212	1,548,137	1,364,335	1,093,906
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Balance at January 1 | MBoe		1,379,709	1,162,635	1,053,027
Extensions and Discoveries | MBoe		578,317	490,725	237,378
Revisions | MBoe		(49,837)	(8,244)	33,127
Acquisition of Reserves | MBoe		1,711	311	0
Sales of Reserves | MBoe		0	0	(8,253)
Conversion to Proved Developed Reserves | MBoe		(302,044)	(265,718)	(152,644)
Balance at December 31 | MBoe		1,607,856	1,379,709	1,162,635
Capitalized Costs, Oil and Gas Producing Activities, Gross [Abstract]
Proved properties | $		$ 59,229,686	$ 53,624,809
Unproved properties | $		3,600,729	3,705,207
Total | $		62,830,415	57,330,016
Accumulated depreciation, depletion and amortization | $		(35,033,085)	(31,674,085)
Net capitalized costs | $		$ 27,797,330	$ 25,655,931
Crude Oil (MBbl)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	1,532,312	1,312,973	1,177,585
Revisions of previous estimates	[1]	(42,882)	(13,376)	57,836
Purchases in place	[1]	2,859	2,743	1,111
Extensions, discoveries and other additions	[1]	369,996	383,018	207,557
Sales in place	[1]	(1,282)	(7,078)	(8,393)
Production	[1]	(166,586)	(145,968)	(122,723)
Net proved reserves - end of period	[1]	1,694,417	1,532,312	1,312,973
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves		801,598	712,785	614,236	516,625
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves		892,819	819,527	698,737	660,690
Natural Gas Liquids
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	614,329	503,473	416,366
Revisions of previous estimates	[1]	5,380	23,942	46,843
Purchases in place	[1]	1,948	2,006	421
Extensions, discoveries and other additions	[1]	167,782	127,409	75,003
Sales in place	[1]	(855)	(41)	(2,887)
Production	[1]	(48,892)	(42,460)	(32,273)
Net proved reserves - end of period	[1]	739,692	614,329	503,473
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves		387,253	341,386	286,872	230,219
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves		352,439	272,943	216,601	186,147
Natural Gas (MMcf)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period | MMcf	[2]	4,687,200	4,263,100	3,317,900
Revisions of previous estimates | MMcf	[2]	(134,800)	(91,500)	584,000.0
Purchases in place | MMcf	[2]	71,700	41,300	4,800
Extensions, discoveries and other additions | MMcf	[2]	1,273,100	956,000.0	829,400
Sales in place | MMcf	[2]	(14,500)	(22,200)	(56,400)
Production | MMcf	[2]	(513,000.0)	(459,500)	(416,600)
Net proved reserves - end of period | MMcf	[2]	5,369,700	4,687,200	4,263,100
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves | MMcf		3,194,100	2,963,800	2,779,300	2,082,400
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves | MMcf		2,175,600	1,723,400	1,483,800	1,235,500
Oil Equivalents (MBoe)
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved reserves - beginning of period | MBoe	[1]	2,927,846	2,526,970	2,146,933
Revisions of previous estimates | MBoe	[1]	(59,971)	(4,684)	202,018
Purchases in place | MBoe	[1]	16,761	11,640	2,332
Extensions, discoveries and other additions | MBoe	[1]	749,968	669,750	420,798
Sales in place | MBoe	[1]	(4,555)	(10,819)	(20,687)
Production | MBoe	[1]	(300,981)	(265,011)	(224,424)
Net proved reserves - end of period | MBoe	[1]	3,329,068	2,927,846	2,526,970
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserve (MBOE) | MBoe		1,607,856	1,379,709	1,162,635	1,053,027
United States
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves (MBOE) | MBoe		1,684,209	1,503,441	1,300,758	1,038,483
United States | Crude Oil (MBbl)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	1,531,684	1,304,071	1,168,491
Revisions of previous estimates	[1]	(42,959)	(13,237)	57,935
Purchases in place	[1]	2,859	2,743	1,111
Extensions, discoveries and other additions	[1]	369,968	383,003	207,137
Sales in place	[1]	(1,282)	(768)	(8,393)
Production	[1]	(166,310)	(144,128)	(122,210)
Net proved reserves - end of period	[1]	1,693,960	1,531,684	1,304,071
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves		801,189	712,218	605,405	507,531
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves		892,771	819,466	698,666	660,690
United States | Natural Gas Liquids
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	614,329	503,473	416,366
Revisions of previous estimates	[1]	5,380	23,942	46,843
Purchases in place	[1]	1,948	2,006	421
Extensions, discoveries and other additions	[1]	167,782	127,409	75,003
Sales in place	[1]	(855)	(41)	(2,887)
Production	[1]	(48,892)	(42,460)	(32,273)
Net proved reserves - end of period	[1]	739,692	614,329	503,473
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves		387,253	341,386	286,872	230,219
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves		352,439	272,943	216,601	186,147
United States | Natural Gas (MMcf)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period | MMcf	[2]	4,390,600	3,898,500	3,021,200
Revisions of previous estimates | MMcf	[2]	(184,400)	(127,200)	602,800
Purchases in place | MMcf	[2]	71,700	41,300	4,800
Extensions, discoveries and other additions | MMcf	[2]	1,175,900	951,400	619,300
Sales in place | MMcf	[2]	(14,500)	(22,200)	(56,400)
Production | MMcf	[2]	(404,500)	(351,200)	(293,200)
Net proved reserves - end of period | MMcf	[2]	5,034,800	4,390,600	3,898,500
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves | MMcf		2,974,600	2,699,000.0	2,450,800	1,804,400
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves | MMcf		2,060,200	1,691,600	1,447,700	1,216,800
United States | Oil Equivalents (MBoe)
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved reserves - beginning of period | MBoe	[1]	2,877,778	2,457,302	2,088,392
Revisions of previous estimates | MBoe	[1]	(68,317)	(10,500)	205,262
Purchases in place | MBoe	[1]	16,761	11,640	2,332
Extensions, discoveries and other additions | MBoe	[1]	733,730	668,972	385,354
Sales in place | MBoe	[1]	(4,555)	(4,509)	(20,687)
Production | MBoe	[1]	(282,619)	(245,127)	(203,351)
Net proved reserves - end of period | MBoe	[1]	3,272,778	2,877,778	2,457,302
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserve (MBOE) | MBoe		1,588,569	1,374,337	1,156,544	1,049,909
Trinidad
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves (MBOE) | MBoe		29,886	37,746	50,779	44,543
Trinidad | Crude Oil (MBbl)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	417	898	839
Revisions of previous estimates	[1]	85	(183)	80
Purchases in place	[1]	0	0	0
Extensions, discoveries and other additions	[1]	0	0	301
Sales in place	[1]	0	0	0
Production	[1]	(236)	(298)	(322)
Net proved reserves - end of period	[1]	266	417	898
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves		266	417	898	839
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]	237,000.0	313,400	280,900
Revisions of previous estimates | MMcf	[2]	47,000.0	20,700	(27,400)
Purchases in place | MMcf	[2]	0	0	0
Extensions, discoveries and other additions | MMcf	[2]	87,500	0	174,200
Sales in place | MMcf	[2]	0	0	0
Production | MMcf	[2]	(95,400)	(97,100)	(114,300)
Net proved reserves - end of period | MMcf	[2]	276,100	237,000.0	313,400
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves | MMcf		177,700	223,900	299,200	262,200
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves | MMcf		98,400	13,100	14,200	18,700
Trinidad | Oil Equivalents (MBoe)
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved reserves - beginning of period | MBoe	[1]	39,936	53,142	47,661
Revisions of previous estimates | MBoe	[1]	7,915	3,272	(4,493)
Purchases in place | MBoe	[1]	0	0	0
Extensions, discoveries and other additions | MBoe	[1]	14,577	0	29,340
Sales in place | MBoe	[1]	0	0	0
Production | MBoe	[1]	(16,130)	(16,478)	(19,366)
Net proved reserves - end of period | MBoe	[1]	46,298	39,936	53,142
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserve (MBOE) | MBoe		16,412	2,190	2,363	3,118
Other International
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves (MBOE) | MBoe	[3]	7,117	6,950	12,798	10,880
Other International | Crude Oil (MBbl)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1],[3]	211	8,004	8,255
Revisions of previous estimates	[1],[3]	(8)	44	(179)
Purchases in place	[1],[3]	0	0	0
Extensions, discoveries and other additions	[1],[3]	28	15	119
Sales in place	[1],[3]	0	(6,310)	0
Production	[1],[3]	(40)	(1,542)	(191)
Net proved reserves - end of period	[1],[3]	191	211	8,004
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves	[3]	143	150	7,933	8,255
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves	[3]	48	61	71	0
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]	59,600	51,200	15,800
Revisions of previous estimates | MMcf	[2],[3]	2,600	15,000.0	8,600
Purchases in place | MMcf	[2],[3]	0	0	0
Extensions, discoveries and other additions | MMcf	[2],[3]	9,700	4,600	35,900
Sales in place | MMcf	[2],[3]	0	0	0
Production | MMcf	[2],[3]	(13,100)	(11,200)	(9,100)
Net proved reserves - end of period | MMcf	[2],[3]	58,800	59,600	51,200
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves | MMcf	[3]	41,800	40,900	29,300	15,800
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves | MMcf	[3]	17,000.0	18,700	21,900	0
Other International | Oil Equivalents (MBoe)
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved reserves - beginning of period | MBoe	[1],[3]	10,132	16,526	10,880
Revisions of previous estimates | MBoe	[1],[3]	431	2,544	1,249
Purchases in place | MBoe	[1],[3]	0	0	0
Extensions, discoveries and other additions | MBoe	[1],[3]	1,661	778	6,104
Sales in place | MBoe	[1],[3]	0	(6,310)	0
Production | MBoe	[1],[3]	(2,232)	(3,406)	(1,707)
Net proved reserves - end of period | MBoe	[1],[3]	9,992	10,132	16,526
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserve (MBOE) | MBoe	[3]	2,875	3,182	3,728	0

[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, Discounted Future Net Cash Flows (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2019 USD ($)		Dec. 31, 2018 USD ($)		Dec. 31, 2017 USD ($)
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows					$ 121,478,362	[1]	$ 134,119,690	[2]	$ 85,221,064	[3]
Future production costs					(42,641,887)		(42,654,642)		(32,569,408)
Future development costs					(20,586,449)		(16,667,893)		(13,538,795)
Future income taxes					(11,565,498)		(14,962,141)		(6,160,541)
Future net cash flows					46,684,528		59,835,014		32,952,320
Discount to present value at 10% annual rate					(21,163,763)		(27,409,059)		(14,624,660)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves		$ 25,520,765	$ 18,327,660	$ 8,812,157	25,520,765		32,425,955		18,327,660
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		$ 32,425,955	$ 18,327,660	$ 8,812,157
Sales and transfers of oil and gas produced, net of production costs		(8,210,438)	(8,734,622)	(5,605,330)
Net changes in prices and production costs		(10,880,447)	12,856,429	7,121,545
Extensions, discoveries, additions and improved recovery, net of related costs		5,709,558	8,430,953	3,958,248
Development costs incurred		3,032,150	2,745,160	1,440,300
Revisions of estimated development cost		(738,024)	(410,525)	(124,877)
Revisions of previous quantity estimates		(695,521)	(101,726)	2,438,271
Accretion of discount		3,949,758	2,042,622	886,707
Net change in income taxes		1,548,707	(4,973,058)	(2,043,663)
Purchases of reserves in place		98,539	116,887	30,362
Sales of reserves in place		(50,651)	(117,932)	(76,527)
Changes in timing and other		(668,821)	2,244,107	1,490,467
Balance at End of Period		25,520,765	32,425,955	18,327,660
United States
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows					120,359,769	[1]	133,066,375	[2]	83,652,363	[3]
Future production costs					(42,387,801)		(42,351,174)		(32,018,812)
Future development costs					(20,355,746)		(16,577,794)		(13,395,873)
Future income taxes					(11,459,567)		(14,756,011)		(5,948,453)
Future net cash flows					46,156,655		59,381,396		32,289,225
Discount to present value at 10% annual rate					(21,042,593)		(27,348,744)		(14,532,290)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves		32,032,652	17,756,935	8,493,727	$ 25,114,062		$ 32,032,652		$ 17,756,935
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		32,032,652	17,756,935	8,493,727
Sales and transfers of oil and gas produced, net of production costs		(7,955,115)	(8,416,853)	(5,387,031)
Net changes in prices and production costs		(10,973,981)	12,750,466	6,606,908
Extensions, discoveries, additions and improved recovery, net of related costs		5,608,038	8,418,666	3,644,041
Development costs incurred		3,003,510	2,732,560	1,435,600
Revisions of estimated development cost		(597,869)	(410,741)	(114,464)
Revisions of previous quantity estimates		(812,781)	(173,084)	2,460,498
Accretion of discount		3,891,701	1,967,592	849,373
Net change in income taxes		1,454,050	(4,965,373)	(1,918,989)
Purchases of reserves in place		98,539	116,887	30,362
Sales of reserves in place		(50,651)	(35,874)	(76,527)
Changes in timing and other		(584,031)	2,291,471	1,733,437
Balance at End of Period		25,114,062	32,032,652	17,756,935
United States | Crude Oil [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows					57.51		68.54		49.21
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					16.91		27.83		23.51
United States | Natural Gas [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows					2.07		2.50		1.96
Trinidad
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows					$ 813,102	[1]	$ 749,695	[2]	$ 904,141	[3]
Future production costs					(166,705)		(204,444)		(239,213)
Future development costs					(212,303)		(78,199)		(84,379)
Future income taxes					(73,508)		(174,382)		(195,855)
Future net cash flows					360,586		292,670		384,694
Discount to present value at 10% annual rate					(86,009)		(26,832)		(52,267)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves		265,838	265,838	332,427	$ 274,577		$ 265,838		$ 332,427
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		265,838	332,427	185,750
Sales and transfers of oil and gas produced, net of production costs		(235,404)	(265,370)	(254,948)
Net changes in prices and production costs		65,962	84,353	436,969
Extensions, discoveries, additions and improved recovery, net of related costs		85,233	0	270,255
Development costs incurred		22,820	0	4,700
Revisions of estimated development cost		(129,047)	4,030	9,683
Revisions of previous quantity estimates		116,062	39,608	(58,373)
Accretion of discount		43,148	50,191	24,066
Net change in income taxes		93,975	3,844	(114,575)
Purchases of reserves in place		0	0	0
Sales of reserves in place		0	0	0
Changes in timing and other		(54,010)	16,755	(171,100)
Balance at End of Period		274,577	265,838	332,427
Trinidad | Crude Oil [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows					46.77		55.66		41.87
Trinidad | Natural Gas [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows					2.90		3.06		2.76
Other International (1)
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	[4]				$ 305,491	[1]	$ 303,620	[2]	$ 664,560	[3]
Future production costs	[4]				(87,381)		(99,024)		(311,383)
Future development costs	[4]				(18,400)		(11,900)		(58,543)
Future income taxes	[4]				(32,423)		(31,748)		(16,233)
Future net cash flows	[4]				167,287		160,948		278,401
Discount to present value at 10% annual rate	[4]				(35,161)		(33,483)		(40,103)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	[4]	127,465	238,298	238,298	$ 132,126		$ 127,465		$ 238,298
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]	127,465	238,298	132,680
Sales and transfers of oil and gas produced, net of production costs	[4]	(19,919)	(52,399)	36,649
Net changes in prices and production costs	[4]	27,572	21,610	77,668
Extensions, discoveries, additions and improved recovery, net of related costs	[4]	16,287	12,287	43,952
Development costs incurred	[4]	5,820	12,600	0
Revisions of estimated development cost	[4]	(11,108)	(3,814)	(20,096)
Revisions of previous quantity estimates	[4]	1,198	31,750	36,146
Accretion of discount	[4]	14,909	24,839	13,268
Net change in income taxes	[4]	682	(11,529)	(10,099)
Purchases of reserves in place	[4]	0	0	0
Sales of reserves in place	[4]	0	(82,058)	0
Changes in timing and other	[4]	(30,780)	(64,119)	(71,870)
Balance at End of Period	[4]	$ 132,126	$ 127,465	$ 238,298
Other International (1) | Crude Oil [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows					57.22		61.66		50.06
Other International (1) | Natural Gas [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows					5.01		4.88		5.16

[1] 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.

[2] 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.

[3] Estimated crude oil prices used to calculate 2017 future cash inflows for the United States, Trinidad and Other International were $49.21, $41.87 and $50.06, respectively. Estimated NGL price used to calculate 2017 future cash inflows for the United States was $23.51. Estimated natural gas prices used to calculate 2017 future cash inflows for the United States, Trinidad and Other International were $1.96, $2.76 and $5.16, 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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Long-Term Debt (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument Table [Line Items]
Long-Term Debt	$ 5,140,000,000	$ 6,040,000,000
Capital Lease Obligation	57,900,000	71,571,000
Less: Current Portion of Long-Term Debt	1,014,524,000	913,093,000
Unamortized Debt Discount	19,528,000	24,640,000
Debt Issuance Costs	2,929,000	3,669,000
Total Long-Term Debt	4,160,919,000	5,170,169,000
Long-Term Debt by Maturity [Abstract]
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2020	1,000,000,000
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2021	750,000,000
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	1,250,000,000
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2024	0
Revolving Credit Agreement 2020
Line of Credit Facility [Line Items]
Average Borrowings Outstanding	$ 0
Line of Credit Facility, Expiration Date	Jun. 27, 2024
Line Of Credit Facility Increase Additional Borrowings	$ 3,000,000,000.0
Maximum borrowing capacity	$ 2,000,000,000.0
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
Revolving Credit Agreement 2020 | Eurodollar [Member]
Line of Credit Facility [Line Items]
Effective Interest Rate (in hundredths)	2.66%
Revolving Credit Agreement 2020 | Base Rate [Member]
Line of Credit Facility [Line Items]
Effective Interest Rate (in hundredths)	4.75%
Senior Unsecured Revolving Credit Agreement Due 2020 [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Date	Jul. 21, 2020
Maximum borrowing capacity	$ 2,000,000,000.0
Line of Credit Facility, Maximum Amount Outstanding During Period		$ 0
Uncommitted Credit Facilities
Line of Credit Facility [Line Items]
Current Borrowings Outstanding			$ 0
Commercial Paper
Line of Credit Facility [Line Items]
Current Borrowings Outstanding			$ 0
Short-term Debt, Weighted Average Interest Rate, over Time		1.97%
Line of Credit Facility, Maximum Amount Outstanding During Period	0	$ 8,000,000
6.875% Senior Notes due 2018
Debt Instrument Issuance [Abstract]
Debt Instrument Issuance Face Amount		$ 350,000,000
Debt Instrument Issuance Interest Rate		6.875%
5.625% Senior Notes due 2019
Debt Instrument Table [Line Items]
Long-Term Debt	0	$ 900,000,000
Debt Instrument Issuance [Abstract]
Debt Instrument Issuance Face Amount	$ 900,000,000
Debt Instrument Issuance Interest Rate	5.625%
4.40% Senior Notes Due 2020 [Member]
Debt Instrument Table [Line Items]
Long-Term Debt	$ 500,000,000	500,000,000
2.45% Senior Notes due 2020
Debt Instrument Table [Line Items]
Long-Term Debt	500,000,000	500,000,000
4.100% Senior Notes due 2021
Debt Instrument Table [Line Items]
Long-Term Debt	750,000,000	750,000,000
2.625% Senior Notes due 2023
Debt Instrument Table [Line Items]
Long-Term Debt	1,250,000,000	1,250,000,000
3.15% Senior Notes due 2025
Debt Instrument Table [Line Items]
Long-Term Debt	500,000,000	500,000,000
4.15% Senior Notes due 2026
Debt Instrument Table [Line Items]
Long-Term Debt	750,000,000	750,000,000
6.65% Senior Notes due 2028
Debt Instrument Table [Line Items]
Long-Term Debt	140,000,000	140,000,000
3.90% Senior Notes due 2035
Debt Instrument Table [Line Items]
Long-Term Debt	500,000,000	500,000,000
5.10% Senior Notes Due 2036
Debt Instrument Table [Line Items]
Long-Term Debt	$ 250,000,000	$ 250,000,000

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Leases (Tables)

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

Lease

The components of lease cost for the year ended December 31, 2019, were as follows (in millions):

	Year Ended December 31, 2019
Operating Lease Cost	$	497
Finance Lease Cost:
Amortization of Lease Assets	13
Interest on Lease Liabilities	2
Variable Lease Cost	138
Short-Term Lease Cost	333
Total Lease Cost	$	983

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 and supplemental information at December 31, 2019 (in millions, except lease terms and discount rates):

Description	Location on Balance Sheet	Amount
Assets
Operating Leases	Other Assets	$	773
Finance Leases	Property, Plant and Equipment, Net (1)	53
Total		$	826
Liabilities
Current
Operating Leases	Current Portion of Operating Lease Liabilities	$	369
Finance Leases	Current Portion of Long-Term Debt	15
Long-Term
Operating Leases	Other Liabilities	430
Finance Leases	Long-Term Debt	43
Total		$	857

(1)

Finance lease assets are recorded net of accumulated amortization of $60 million at December 31, 2019.

Weighted Average Remaining Lease Term And Discount Rate

	Year Ended December 31, 2019
Weighted Average Remaining Lease Term (in years):
Operating Leases	3.2
Finance Leases	4.7
Weighted Average Discount Rate:
Operating Leases	3.5	%
Finance Leases	3.0	%

Cash Paid for Leases

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

	Year Ended December 31, 2019
Repayment of Operating Lease Liabilities Associated with Operating Activities	$	225
Repayment of Operating Lease Liabilities Associated with Investing Activities	270
Repayment of Finance Lease Liabilities	13

Operating And Finance Non-Cancellable Leases Maturity

At December 31, 2019, the future minimum lease payments under non-cancellable leases were as follows (in millions):

	Operating Leases		Finance Leases
2020	$	390	$	15
2021	209		15
2022	126		12
2023	56		8
2024	29		8
2025 and Beyond	40		6
Total Lease Payments	850		64
Less: Discount to Present Value	51		6
Total Lease Liabilities	799		58
Less: Current Portion of Lease Liabilities	369		15
Long-Term Lease Liabilities	$	430	$	43

Prior To Adoption Operating And Finance Non-Cancellable Leases Maturity

At December 31, 2018 and 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, 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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Asset Retirement Obligations (Notes)

12 Months Ended

Dec. 31, 2019

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, 2019 and 2018 (in thousands):

	2019			2018
Carrying Amount at Beginning of Period	$	954,377		$	946,848
Liabilities Incurred	98,874			79,057
Liabilities Settled (1)	(58,673		)	(70,829		)
Accretion	43,462			36,622
Revisions	72,425			(38,932		)
Foreign Currency Translations	245			1,611
Carrying Amount at End of Period	$	1,110,710		$	954,377
Current Portion	$	37,127		$	26,214
Noncurrent Portion	$	1,073,583		$	928,163

(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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Oil and Gas Exploration and Production Industries Disclosures (Notes)

12 Months Ended

Dec. 31, 2019

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 Estimates 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 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, 2019.  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 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, 2019, 2018 and 2017 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 33 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 Executive Vice Presidents, Exploration and Production; and the Executive Vice President and Chief Financial Officer, for approval.

Opinions by D&M for the years ended December 31, 2019, 2018 and 2017 covered producing areas containing 82%, 79% 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 24, 2020, 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, 2019, 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, 2019, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2019, 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, 2016	1,168,491		839		8,255		1,177,585
Revisions of previous estimates	57,935		80		(179	)	57,836
Purchases in place	1,111		—		—		1,111
Extensions, discoveries and other additions	207,137		301		119		207,557
Sales in place	(8,393	)	—		—		(8,393	)
Production	(122,210	)	(322	)	(191	)	(122,723	)
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
Natural Gas Liquids (MBbl) (2)
Net proved reserves at December 31, 2016	416,366		—		—		416,366
Revisions of previous estimates	46,843		—		—		46,843
Purchases in place	421		—		—		421
Extensions, discoveries and other additions	75,003		—		—		75,003
Sales in place	(2,887	)	—		—		(2,887	)
Production	(32,273	)	—		—		(32,273	)
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

	United States		Trinidad		Other International (1)		Total
Natural Gas (Bcf) (3)
Net proved reserves at December 31, 2016	3,021.2		280.9		15.8		3,317.9
Revisions of previous estimates	602.8		(27.4	)	8.6		584.0
Purchases in place	4.8		—		—		4.8
Extensions, discoveries and other additions	619.3		174.2		35.9		829.4
Sales in place	(56.4	)	—		—		(56.4	)
Production	(293.2	)	(114.3	)	(9.1	)	(416.6	)
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
Oil Equivalents (MBoe) (2)
Net proved reserves at December 31, 2016	2,088,392		47,661		10,880		2,146,933
Revisions of previous estimates	205,262		(4,493	)	1,249		202,018
Purchases in place	2,332		—		—		2,332
Extensions, discoveries and other additions	385,354		29,340		6,104		420,798
Sales in place	(20,687	)	—		—		(20,687	)
Production	(203,351	)	(19,366	)	(1,707	)	(224,424	)
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

(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 2019, EOG added 750 million barrels of oil equivalent (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.

During 2017, EOG added 421 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 Trinidad.  Approximately 67% of the 2017 reserve additions were crude oil and condensate and NGLs, and 92% were in the United States.  Sales in place of 21 MMBoe were primarily related to the sale or exchange of certain producing assets. Revisions of previous estimates of 202 MMBoe for 2017 included an upward revision of 154 MMBoe primarily due to increases in the average crude oil, NGLs and natural gas prices used in the December 31, 2017, reserves estimation as compared to the prices used in the prior year estimate. The primary plays affected were in the Rocky Mountain area, the Eagle Ford and the Permian Basin. Positive revisions other than price of 48 MMBoe resulted primarily from improved well performance in the Permian Basin and lower production costs. Purchases in place of 2 MMBoe were primarily related to the Permian Basin.

	United States	Trinidad	Other International (1)	Total
NET PROVED DEVELOPED RESERVES
Crude Oil (MBbl)
December 31, 2016	507,531	839	8,255	516,625
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
Natural Gas Liquids (MBbl)
December 31, 2016	230,219	—	—	230,219
December 31, 2017	286,872	—	—	286,872
December 31, 2018	341,386	—	—	341,386
December 31, 2019	387,253	—	—	387,253
Natural Gas (Bcf)
December 31, 2016	1,804.4	262.2	15.8	2,082.4
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
Oil Equivalents (MBoe)
December 31, 2016	1,038,483	44,543	10,880	1,093,906
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
NET PROVED UNDEVELOPED RESERVES
Crude Oil (MBbl)
December 31, 2016	660,690	—	—	660,690
December 31, 2017	698,666	—	71	698,737
December 31, 2018	819,466	—	61	819,527
December 31, 2019	892,771	—	48	892,819
Natural Gas Liquids (MBbl)
December 31, 2016	186,147	—	—	186,147
December 31, 2017	216,601	—	—	216,601
December 31, 2018	272,943	—	—	272,943
December 31, 2019	352,439	—	—	352,439
Natural Gas (Bcf)
December 31, 2016	1,216.8	18.7	—	1,235.5
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
Oil Equivalents (MBoe)
December 31, 2016	1,049,909	3,118	—	1,053,027
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

(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 proved undeveloped reserves during 2019, 2018 and 2017 (in MBoe):

	2019		2018		2017
Balance at January 1	1,379,709		1,162,635		1,053,027
Extensions and Discoveries	578,317		490,725		237,378
Revisions	(49,837	)	(8,244	)	33,127
Acquisition of Reserves	1,711		311		—
Sale of Reserves	—		—		(8,253	)
Conversion to Proved Developed Reserves	(302,044	)	(265,718	)	(152,644	)
Balance at December 31	1,607,856		1,379,709		1,162,635

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 (see discussion of technology employed on pages F-39 and F-40 of this Annual Report on Form 10-K), 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.  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, 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. 

For the twelve-month period ended December 31, 2017, total PUDs increased by 110 MMBoe to 1,163 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 199 MMBoe.  The PUD additions were primarily in the Permian Basin and, to a lesser extent, the Eagle Ford and the Rocky Mountain area, and 74% of the additions were crude oil and condensate and NGLs.  During 2017, EOG drilled and transferred 153 MMBoe of PUDs to proved developed reserves at a total capital cost of $1,440 million.  Revisions of PUDs totaled positive 33 MMBoe, primarily due to updated type curves resulting from improved performance of offsetting wells in the Permian Basin, the impact of increases in the average crude oil and natural gas prices used in the December 31, 2017, reserves estimation as compared to the prices used in the prior year estimate, and lower costs.  During 2017, EOG sold or exchanged 8 MMBoe of PUDs primarily in the Permian Basin.

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, 2019 and 2018:

	2019			2018
Proved properties	$	59,229,686		$	53,624,809
Unproved properties	3,600,729			3,705,207
Total	62,830,415			57,330,016
Accumulated depreciation, depletion and amortization	(35,033,085		)	(31,674,085		)
Net capitalized costs	$	27,797,330		$	25,655,931

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, 2019, 2018 and 2017:

	United States		Trinidad			Other International (1)		Total
2019
Acquisition Costs of Properties
Unproved (2)	$	276,092	$	—		$	—	$	276,092
Proved (3)	379,938		—			—		379,938
Subtotal	656,030		—			—		656,030
Exploration Costs	213,505		46,616			13,218		273,339
Development Costs (4)	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 (5)	$	486,081	$	1,258		$	—	$	487,339
Proved (6)	123,684		—			—		123,684
Subtotal	609,765		1,258			—		611,023
Exploration Costs	157,222		22,511			13,895		193,628
Development Costs (7)	5,605,264		(12,863		)	22,628		5,615,029
Total	$	6,372,251	$	10,906		$	36,523	$	6,419,680
2017
Acquisition Costs of Properties
Unproved (8)	$	424,118	$	2,422		$	—	$	426,540
Proved (9)	72,584		—			—		72,584
Subtotal	496,702		2,422			—		499,124
Exploration Costs	144,499		62,547			16,553		223,599
Development Costs (10)	3,590,899		109,491			16,297		3,716,687
Total	$	4,232,100	$	174,460		$	32,850	$	4,439,410

(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.

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

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

(4) 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.

(5) Includes non-cash unproved leasehold acquisition costs of $291 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 $90 million, $(12) million and $(8) 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 $256 million related to property exchanges.

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

(10) Includes Asset Retirement Costs of $50 million, $2 million and $4 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, 2019, 2018 and 2017:

	United States		Trinidad			Other International (2)			Total
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
2017
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	7,570,768	$	284,673		$	52,450		$	7,907,891
Other	81,610		59			(59		)	81,610
Total	7,652,378		284,732			52,391			7,989,501
Exploration Costs	113,334		26,245			5,763			145,342
Dry Hole Costs	91		—			4,518			4,609
Transportation Costs	737,403		1,885			1,064			740,352
Production Costs	1,446,333		27,839			88,038			1,562,210
Impairments	477,223		—			2,017			479,240
Depreciation, Depletion and Amortization	3,157,056		115,174			24,536			3,296,766
Income (Loss) Before Income Taxes	1,720,938		113,589			(73,545		)	1,760,982
Income Tax Provision (Benefit)	625,562		24,882			(1,342		)	649,102
Results of Operations	$	1,095,376	$	88,707		$	(72,203	)	$	1,111,880

(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, 2019.

(2) 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.

(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, 2019, 2018 and 2017:

	United States		Trinidad		Other International (1)		Composite
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
Year Ended December 31, 2017	$	4.58	$	1.39	$	50.86	$	4.66

(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 2019, 2018 and 2017.  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, 2019, 2018 and 2017:

	United States			Trinidad			Other International (1)			Total
2019
Future cash inflows (2)	$	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 (3)	$	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
2017
Future cash inflows (4)	$	83,652,363		$	904,141		$	664,560		$	85,221,064
Future production costs	(32,018,812		)	(239,213		)	(311,383		)	(32,569,408		)
Future development costs	(13,395,873		)	(84,379		)	(58,543		)	(13,538,795		)
Future income taxes	(5,948,453		)	(195,855		)	(16,233		)	(6,160,541		)
Future net cash flows	32,289,225			384,694			278,401			32,952,320
Discount to present value at 10% annual rate	(14,532,290		)	(52,267		)	(40,103		)	(14,624,660		)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	17,756,935		$	332,427		$	238,298		$	18,327,660

(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 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) Estimated crude oil prices used to calculate 2017 future cash inflows for the United States, Trinidad and Other International were $49.21, $41.87 and $50.06, respectively. Estimated NGL price used to calculate 2017 future cash inflows for the United States was $23.51. Estimated natural gas prices used to calculate 2017 future cash inflows for the United States, Trinidad and Other International were $1.96, $2.76 and $5.16, 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, 2019:

	United States			Trinidad			Other International (1)			Total
December 31, 2016	$	8,493,727		$	185,750		$	132,680		$	8,812,157
Sales and transfers of oil and gas produced, net of production costs	(5,387,031		)	(254,948		)	36,649			(5,605,330		)
Net changes in prices and production costs	6,606,908			436,969			77,668			7,121,545
Extensions, discoveries, additions and improved recovery, net of related costs	3,644,041			270,255			43,952			3,958,248
Development costs incurred	1,435,600			4,700			—			1,440,300
Revisions of estimated development cost	(114,464		)	9,683			(20,096		)	(124,877		)
Revisions of previous quantity estimates	2,460,498			(58,373		)	36,146			2,438,271
Accretion of discount	849,373			24,066			13,268			886,707
Net change in income taxes	(1,918,989		)	(114,575		)	(10,099		)	(2,043,663		)
Purchases of reserves in place	30,362			—			—			30,362
Sales of reserves in place	(76,527		)	—			—			(76,527		)
Changes in timing and other	1,733,437			(171,100		)	(71,870		)	1,490,467
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

(1)

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

XML

Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2019

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, 2019, 2018 and 2017 (in thousands):

	2019			2018		2017
Interest, Net of Capitalized Interest	$	186,546		$	243,279	$	275,305
Income Taxes, Net of Refunds Received	$	(291,849	)	$	75,634	$	188,946

XML

Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2019

Share-based Payment Arrangement [Abstract]

Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs

Stock-based compensation expense is included on the Consolidated Statements of Income and Comprehensive Income based upon the job functions of the employees receiving the grants.  Compensation expense related to EOG's stock-based compensation plans for the years ended December 31, 2019, 2018 and 2017 was as follows (in millions):

	2019		2018		2017
Lease and Well	$	56	$	51	$	41
Gathering and Processing Costs	1		1		1
Exploration Costs	26		25		23
General and Administrative	92		78		69
Total	$	175	$	155	$	134

Vesting Schedule

Grant Type	Vesting Schedule
Stock Options/SARs	Vesting in increments of 33%, 33% and 34% 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 approximately 41 months from the date of grant - specifically, on the February 28th immediately following the Compensation Committee's certifications contemplated by the form of award agreement governing such grant of performance units

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, 2019, 2018 and 2017 were as follows:

	Stock Options/SARs									ESPP
	2019			2018			2017			2019			2018			2017
Weighted Average Fair Value of Grants	$	19.49		$	33.46		$	23.95		$	22.83		$	25.75		$	22.20
Expected Volatility	32.02		%	28.23		%	28.28		%	34.78		%	24.59		%	27.12		%
Risk-Free Interest Rate	1.69		%	2.68		%	1.52		%	2.27		%	1.89		%	0.88		%
Dividend Yield	1.39		%	0.72		%	0.75		%	1.04		%	0.64		%	0.71		%
Expected Life	5.1 years			5.0 years			5.1 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, 2019, 2018 and 2017 (stock options and SARs in thousands):

	2019				2018				2017
	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	8,310		$	96.90	9,103		$	83.89	9,850		$	75.53
Granted	1,965		75.39		1,906		126.49		2,274		96.27
Exercised (1)	(606	)	61.43		(2,493	)	72.21		(2,574	)	61.12
Forfeited	(274	)	102.57		(206	)	94.43		(447	)	93.84
Outstanding at December 31	9,395		94.53		8,310		96.90		9,103		83.89
Stock Options/SARs Exercisable at December 31	5,275		94.21		3,969		85.82		4,510		75.76

(1)

The total intrinsic value of stock options/SARs exercised during the years 2019, 2018 and 2017 was $14 million, $118 million and $95 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, 2019 (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)
$ 59.00 to $  74.99	979	3	$	69.43			953	3	$	69.37
75.00 to    75.99	1,894	7	75.09				8	1	75.09
76.00 to     95.99	1,979	3	91.35				1,607	2	90.67
96.00 to     96.99	1,871	4	96.29				1,234	4	96.29
97.00 to   125.99	923	2	102.72				862	2	102.20
126.00 to   129.99	1,749	6	127.01				611	5	127.01
	9,395	4	94.53		$	30,534	5,275	3	94.21		$	13,839

(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.

ESPP Activity

The following table summarizes ESPP activity for the years ended December 31, 2019, 2018 and 2017 (in thousands, except number of participants):

	2019		2018		2017
Approximate Number of Participants	1,998		1,934		1,870
Shares Purchased	224		180		180
Aggregate Purchase Price	$	16,533	$	14,887	$	13,997

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, 2019, 2018 and 2017 (shares and units in thousands):

	2019				2018				2017
	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	3,792		$	96.64	3,905		$	88.57	3,962		$	79.63
Granted	1,749		80.01		812		117.55		1,095		97.34
Released (1)	(855	)	96.93		(740	)	78.16		(929	)	61.51
Forfeited	(140	)	97.54		(185	)	92.12		(223	)	85.45
Outstanding at December 31 (2)	4,546		90.16		3,792		96.64		3,905		88.57

(1) The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2019, 2018 and 2017 was $70 million, $84 million and $91 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, 2019, 2018 and 2017 was $381 million, $331 million and $421 million, respectively.

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, 2019, 2018 and 2017 were as follows:

	2019			2018			2017
Weighted Average Fair Value of Grants	$	79.98		$	136.74		$	113.81
Expected Volatility	29.20		%	29.92		%	32.19		%
Risk-Free Interest Rate	1.51		%	2.85		%	1.60		%

Performance Unit and Performance Stock Transactions

The following table sets forth the Performance Award transactions for the years ended December 31, 2019, 2018 and 2017 (shares and units in thousands):

	2019						2018				2017
	Number of Units and Shares				Weighted Average Price per Grant Date		Number of Units and Shares		Weighted Average Price per Grant Date		Number of Units and Shares		Weighted Average Price per Grant Date
Outstanding at January 1	539				$	101.53	502		$	90.96	545		$	80.92
Granted	172				75.09		113		125.73		78		96.29
Granted for Performance Multiple (1)	72				69.43		72		101.87		119		84.43
Released (2)	(185	)			94.63		(148	)	84.43		(240	)	66.69
Forfeited	—				—		—		—		—		—
Outstanding at December 31 (3)	598		(4	)	92.19		539		101.53		502		90.96

(1) Upon completion of the Performance Period for the Performance Awards granted in 2015, 2014 and 2013, a performance multiple of 200% was applied to each of the grants resulting in additional grants of Performance Awards in February 2019, 2018 and 2017.

(2) The total intrinsic value of Performance Awards released during the years ended December 31, 2019, 2018 and 2017 was $15 million, $18 million and $24 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, 2019, 2018 and 2017 was $50 million, $47 million and $54 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 102 and a maximum of 1,094 Performance Awards could be outstanding.

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Stockholder's Equity (Notes)

12 Months Ended

Dec. 31, 2019

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, 2019, 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, 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 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 by 19% 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, EOG's Board increased the quarterly cash dividend on the common stock by 10% 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. EOG declared and paid quarterly cash dividends of $0.1675 per share in 2017.

On February 15, 2017, the Board approved an amendment to EOG's Restated Certificate of Incorporation to increase the number of EOG's authorized shares of common stock from 640 million to 1,280 million. EOG's stockholders approved the increase at the Annual Meeting of Stockholders on April 27, 2017, and the amendment was filed with the Delaware Secretary of State on April 28, 2017.

The following summarizes Common Stock activity for each of the years ended December 31, 2017, 2018 and 2019 (in thousands):

	Common Shares
	Issued	Treasury		Outstanding
Balance at December 31, 2016	576,950	(250	)	576,700
Common Stock Issued Under Stock-Based Compensation Plans	1,878	—		1,878
Treasury Stock Purchased (1)	—	(686	)	(686	)
Common Stock Issued Under Employee Stock Purchase Plan	—	180		180
Treasury Stock Issued Under Stock-Based Compensation Plans	—	405		405
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

(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, 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, 2019, there were no shares of preferred stock outstanding.

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Income Taxes (Notes)

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The principal components of EOG's total net deferred income tax liabilities at December 31, 2019 and 2018 were as follows (in thousands):

	2019			2018
Deferred Income Tax Assets (Liabilities)
Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization	$	5,825		$	4,359
Foreign Net Operating Loss	66,675			55,175
Foreign Valuation Allowances	(70,455		)	(58,932		)
Foreign Other	318			175
Total Net Deferred Income Tax Assets	$	2,363		$	777
Deferred Income Tax (Assets) Liabilities
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization	$	5,277,550		$	4,583,517		(1)
Commodity Hedging Contracts	(4,699		)	4,883
Deferred Compensation Plans	(47,650		)	(39,086		)
Accrued Expenses and Liabilities	(8,502		)	(19,097		)
Equity Awards	(108,324		)	(93,977		)
Alternative Minimum Tax Credit Carryforward	(31,904		)	—
Undistributed Foreign Earnings	15,746			22,945
Other	(46,116		)	(45,787		)
Total Net Deferred Income Tax Liabilities	$	5,046,101		$	4,413,398
Total Net Deferred Income Tax Liabilities	$	5,043,738		$	4,412,621

(1) The 2018 presentation has been changed to conform with current year presentation.

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

	2019		2018		2017
United States	$	3,466,578	$	4,084,156	$	621,610
Foreign	78,689		156,842		39,572
Total	$	3,545,267	$	4,240,998	$	661,182

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

	2019			2018			2017
Current:
Federal	$	(152,258	)	$	(303,853	)	$	33,058
State	10,819			17,048			(2,502		)
Foreign	81,426			65,615			35,323
Total	(60,013		)	(221,190		)	65,879
Deferred:
Federal	626,901			862,075			(1,504,288		)
State	32,541			43,293			26,942
Foreign	(27,784		)	(11,212		)	3,474
Total	631,658			894,156			(1,473,872		)
Other Non-Current: (1)
Federal	245,125			148,992			(513,404		)
Foreign	(6,413		)	—			—
Total	238,712			148,992			(513,404		)
Income Tax Provision (Benefit)	$	810,357		$	821,958		$	(1,921,397	)

(1) Includes changes in certain amounts that are expected to be paid or received beyond the next twelve months. The primary components are refundable alternative minimum tax (AMT) credits and the 2017 repatriation tax. See the following statutory-to-effective tax rate reconciliation for additional details.

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:

	2019		2018			2017
Statutory Federal Income Tax Rate	21.00	%	21.00	%		35.00	%
State Income Tax, Net of Federal Benefit	0.97		1.12			3.38
Income Tax Provision Related to Foreign Operations	0.87		0.51			(0.30	)
Income Tax Provision Related to United Kingdom Operations	—		—			1.78
Income Tax Provision Related to Canadian Operations	—		—			2.30
TCJA (1)	—		(2.60	)	(2)	(328.10	)	(3)
Share-Based Compensation	0.02		(0.47	)		(4.63	)
Other	—		(0.18	)		(0.03	)
Effective Income Tax Rate	22.86	%	19.38	%		(290.60	)%

(1) The enactment of the Tax Cuts and Jobs Act (TCJA) by the United States in 2017 made numerous changes to federal tax law. Several changes which had a significant impact on EOG include the corporate income tax rate reduction from 35% to 21%, the imposition of a one-time repatriation tax on undistributed foreign earnings and the repeal of the corporate AMT regime (AMT credit carryforwards became refundable over the following four years and were initially subject to a federal sequestration charge). In 2017, EOG revalued its federal deferred income tax assets and liabilities resulting in an earnings benefit of over $2 billion and a substantial reduction of the 2017 effective tax rate. The TCJA measurement-period adjustments were recorded in 2018.

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

(3) Includes impact of the federal rate reduction ((327.8)%), federal repatriation tax ((6.6)%), sequestration ((6.4)%) and other tax reform impacts ((0.1)%).

The net effective tax rate of 23% in 2019 was higher than the prior year rate of 19% primarily due to the absence of tax benefits from certain tax reform measurement-period adjustments.

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):

	2019			2018			2017
Beginning Balance	$	167,142		$	466,421		$	383,221
Increase (1)	30,673			23,062			67,333
Decrease (2)	(75		)	(26,219		)	(13,687		)
Other (3)	3,091			(296,122		)	29,554
Ending Balance	$	200,831		$	167,142		$	466,421

(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 allowance.

(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, 2019, EOG had state income tax NOLs of approximately $2.1 billion, which, if unused, expire between 2020 and 2038. EOG also has Canadian NOLs of $225 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, 2019, was $39 million, resulting from the tax treatment of research and experimental expenditures related to certain innovations in EOG's horizontal drilling and completion projects and tax treatment of certain compensation deductions, of which $25 million may potentially have an earnings impact. EOG records interest and penalties related to unrecognized tax benefits to its income tax provision. Cumulatively, $4 million of interest has been recognized in the Consolidated Statements of Income and Comprehensive Income. 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 (2015), Trinidad (2013) and China (2009).

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, 2019, EOG has cumulatively recorded $16 million of deferred foreign income taxes for withholdings on its undistributed foreign earnings. Additionally, for tax years beginning in 2018 and later, 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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Business Segment Information (Notes)

12 Months Ended

Dec. 31, 2019

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, 2019, 2018 and 2017 (in thousands):

	United States		Trinidad			Other International (1)			Total
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 (2)	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
Losses 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 (3)	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
2017
Crude Oil and Condensate	$	6,225,711		$	13,572		$	17,113		$	6,256,396
Natural Gas Liquids	729,545			—			16			729,561
Natural Gas	615,512			271,101			35,321			921,934
Gains on Mark-to-Market Commodity Derivative Contracts	19,828			—			—			19,828
Gathering, Processing and Marketing	3,298,098			(11		)	—			3,298,087
Losses on Asset Dispositions, Net	(98,233		)	(8		)	(855		)	(99,096		)
Other, Net	81,610			59			(59		)	81,610
Operating Revenues and Other (4)	10,872,071			284,713			51,536			11,208,320
Depreciation, Depletion and Amortization	3,269,196			115,321			24,870			3,409,387
Operating Income (Loss)	933,571			101,010			(108,179		)	926,402
Interest Income	3,223			2,201			2,289			7,713
Other Income (Expense)	(9,659		)	3,337			7,761			1,439
Net Interest Expense	303,941			—			(29,569		)	274,372
Income (Loss) Before Income Taxes	623,194			106,548			(68,560		)	661,182
Income Tax Provision (Benefit)	(1,964,343		)	38,798			4,148			(1,921,397		)
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	4,067,359			145,937			14,932			4,228,228
Total Property, Plant and Equipment, Net	25,125,427			313,357			226,253			25,665,037
Total Assets	28,312,599			974,477			546,002			29,833,078

(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.

(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)

EOG had sales activity with two significant purchasers in 2017, one totaling $1.5 billion and the other totaling $1.3 billion of consolidated Operating Revenues and Other in the United States segment.

Business Segment Information

Business Segment Information

EOG's operations are all crude oil, NGLs and natural gas exploration and production related. The Segment Reporting Topic of the ASC establishes standards for reporting information about operating segments in annual financial statements.  Operating segments are defined as components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker, or decision-making group, in deciding how to allocate resources and in assessing performance.  EOG's chief operating decision-making process is informal and involves the Chairman of the Board and Chief Executive Officer and other key officers.  This group routinely reviews and makes operating decisions related to significant issues associated with each of EOG's major producing areas in the United States, Trinidad and China.  For segment reporting purposes, the chief operating decision maker considers 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, 2019, 2018 and 2017 (in thousands):

	United States		Trinidad			Other International (1)			Total
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 (2)	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
Losses 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 (3)	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
2017
Crude Oil and Condensate	$	6,225,711		$	13,572		$	17,113		$	6,256,396
Natural Gas Liquids	729,545			—			16			729,561
Natural Gas	615,512			271,101			35,321			921,934
Gains on Mark-to-Market Commodity Derivative Contracts	19,828			—			—			19,828
Gathering, Processing and Marketing	3,298,098			(11		)	—			3,298,087
Losses on Asset Dispositions, Net	(98,233		)	(8		)	(855		)	(99,096		)
Other, Net	81,610			59			(59		)	81,610
Operating Revenues and Other (4)	10,872,071			284,713			51,536			11,208,320
Depreciation, Depletion and Amortization	3,269,196			115,321			24,870			3,409,387
Operating Income (Loss)	933,571			101,010			(108,179		)	926,402
Interest Income	3,223			2,201			2,289			7,713
Other Income (Expense)	(9,659		)	3,337			7,761			1,439
Net Interest Expense	303,941			—			(29,569		)	274,372
Income (Loss) Before Income Taxes	623,194			106,548			(68,560		)	661,182
Income Tax Provision (Benefit)	(1,964,343		)	38,798			4,148			(1,921,397		)
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	4,067,359			145,937			14,932			4,228,228
Total Property, Plant and Equipment, Net	25,125,427			313,357			226,253			25,665,037
Total Assets	28,312,599			974,477			546,002			29,833,078

(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.

(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)

EOG had sales activity with two significant purchasers in 2017, one totaling $1.5 billion and the other totaling $1.3 billion of consolidated Operating Revenues and Other in the United States segment.

XML

Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Retained Earnings [Member]	Treasury Stock, Common [Member]
Balance at Dec. 31, 2016	$ 13,981,581	$ 205,770	$ 5,420,385	$ (19,010)	$ 8,398,118	$ (23,682)
Net Income	2,582,579	0	0	0	2,582,579	0
Common Stock Issued Under Stock Plans	7,089	7	7,082	0	0	0
Dividends, Common Stock	$ (387,164)	0	0	0	(387,164)	0
Common Stock Dividends Declared (in dollars per share)	$ 0.670
Other Comprehensive Income (Loss)	$ (287)	0	0	(287)	0	0
Change in Treasury Stock - Stock Compensation Plans, Net	(36,743)	0	(27,348)	0	0	(9,395)
Restricted Stock and Restricted Stock Units, Net	0	11	2,552	0	0	(2,563)
Stock-Based Compensation Expenses	133,849	0	133,849	0	0	0
Treasury Stock Issued as Compensation	2,369	0	27	0	0	2,342
Balance at Dec. 31, 2017	16,283,273	205,788	5,536,547	(19,297)	10,593,533	(33,298)
Net Income	3,419,040	0	0	0	3,419,040	0
Common Stock Issued Under Stock Plans	5,620	8	5,612	0	0	0
Dividends, Common Stock	$ (469,443)	0	0	0	(469,443)	0
Common Stock Dividends Declared (in dollars per share)	$ 0.810
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)
Net Income	2,734,910	0	0	0	2,734,910	0
Common Stock Issued Under Stock Plans	(8)	1	(9)	0	0	0
Dividends, Common Stock	$ 629,169	0	0	0	629,169	0
Common Stock Dividends Declared (in dollars per share)	$ 1.083
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
Balance at Dec. 31, 2019	21,640,716	205,822	5,817,475	(4,652)	15,648,604	(26,533)
Cumulative Effect of Accounting Changes	$ 0	$ 0	$ 0	$ 267	$ (267)	$ 0

XML

Document and Entity Information - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2019

Feb. 13, 2020

Jun. 30, 2019

Cover page.

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, 2019

Document Fiscal Period Focus

FY

Document Fiscal Year Focus

2019

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

$ 54,011

Entity Common Stock, Shares Outstanding

582,054,451

Documents Incorporated by Reference

Documents incorporated by reference.  Portions of the Definitive Proxy Statement for the registrant's 2020 Annual Meeting of Stockholders, to be filed within 120 days after December 31, 2019, are incorporated by reference into Part III of this report.

XML

Long-Term Debt (Notes)

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

Long-Term Debt at December 31, 2019 and 2018 consisted of the following (in thousands):

	2019		2018
5.625% Senior Notes due 2019	$	—	$	900,000
4.40% Senior Notes due 2020	500,000		500,000
2.45% Senior Notes due 2020	500,000		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
3.90% Senior Notes due 2035	500,000		500,000
5.10% Senior Notes due 2036	250,000		250,000
Long-Term Debt	5,140,000		6,040,000
Finance Leases (see Note 18)	57,900		71,571
Less: Current Portion of Long-Term Debt	1,014,524		913,093
Unamortized Debt Discount	19,528		24,640
Debt Issuance Costs	2,929		3,669
Total Long-Term Debt	$	4,160,919	$	5,170,169

At December 31, 2019, the aggregate annual maturities of long-term debt (excluding finance lease obligations) were $1 billion in 2020, $750 million in 2021, zero in 2022, $1.25 billion in 2023 and zero in 2024. 

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

On October 1, 2018, EOG repaid upon maturity the $350 million aggregate principal amount of its 6.875% Senior Notes due 2018.

At December 31, 2019 and 2018, EOG had no outstanding short-term borrowings under its commercial paper program and did not utilize any such borrowings during 2019. During 2018, EOG utilized commercial paper borrowings, bearing market interest rates, for various corporate financing purposes. The average borrowings outstanding under the commercial paper program were $8 million during the year ended December 31, 2018. The weighted average interest rate for commercial paper borrowings during the year ended December 31, 2018, was 1.97%.

On June 27, 2019, EOG entered into a new $2.0 billion senior unsecured Revolving Credit Agreement (New Facility) with domestic and foreign lenders (Banks). The New Facility replaced EOG's $2.0 billion senior unsecured Revolving Credit Agreement, dated as of July 21, 2015, with domestic and foreign lenders (2015 Facility), 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 completion of the New Facility.

The New Facility 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 New Facility (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 New Facility will accrue interest based, at EOG’s option, on either the London InterBank Offered Rate plus an applicable margin (Eurodollar Rate) or the Base Rate (as defined in the New Facility) plus an applicable margin. The applicable margin used in connection with interest rates and fees will be based on EOG’s credit rating for its senior unsecured long-term debt at the applicable time.

Consistent with the terms of the 2015 Facility, the New Facility contains representations, warranties, covenants and events of default that we believe are customary for investment grade, senior unsecured commercial bank credit agreements, including a financial covenant for the maintenance of a ratio of total debt-to-total capitalization (as such terms are defined in the New Facility) of no greater than 65%. At December 31, 2019, EOG was in compliance with this financial covenant.

There were no borrowings or letters of credit outstanding under the 2015 Facility as of (i) December 31, 2018 or (ii) the June 27, 2019 effective date of the closing of the New Facility and termination of the 2015 Facility. Further, at December 31, 2019, there were no borrowings or letters of credit outstanding under the New Facility. The Eurodollar Rate and Base Rate (inclusive of the applicable margin), had there been any amounts borrowed under the New Facility at December 31, 2019, would have been 2.66% and 4.75%, respectively.

XML

Income Taxes (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Deferred Tax Assets (Liabilities) Net Noncurrent Classification [Abstract]
Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization		$ 5,825		$ 4,359
Foreign Net Operating Loss		66,675		55,175
Foreign Valuation Allowances		(70,455)		(58,932)
Foreign Other		318		175
Total Net Noncurrent Deferred Income Tax Assets		2,363		777
Deferred Tax (Assets) Liabilities Net Noncurrent Classification [Abstract]
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization		5,277,550		4,583,517	[1]
Commodity Hedging Contracts		(4,699)		4,883
Deferred Compensation Plans		(47,650)		(39,086)
Accrued Expenses and Liabilities		(8,502)		(19,097)
Equity Awards		(108,324)		(93,977)
Alternative Minimum Tax Credit Carryforward		(31,904)		0
Undistributed Foreign Earnings		15,746		22,945
Other		(46,116)		(45,787)
Total Net Noncurrent Deferred Income Tax Liabilities		5,046,101		4,413,398
Total Net Deferred Income Tax Liabilities		5,043,738		4,412,621
Components Income (Loss) Before Income Taxes [Abstract]
United States		3,466,578		4,084,156		$ 621,610
Foreign		78,689		156,842		39,572
Income Before Income Taxes		3,545,267		4,240,998		661,182
Current income tax provision (benefit) [Abstract]
Federal		(152,258)		(303,853)		33,058
State		10,819		17,048		(2,502)
Foreign		81,426		65,615		35,323
Total		(60,013)		(221,190)		65,879
Deferred income tax provision (benefit) [Abstract]
Federal		626,901		862,075		(1,504,288)
State		32,541		43,293		26,942
Foreign		(27,784)		(11,212)		3,474
Total		631,658		894,156		(1,473,872)
Other Non-Current (1)
Federal		245,125	[2]	148,992	[3]	(513,404)	[2]
Other Noncurrent Foreign Income Tax		(6,413)		0		0
Total		238,712		148,992		(513,404)
Income Tax Provision (Benefit)		$ 810,357		$ 821,958		$ (1,921,397)
Federal Statutory and Effective Income Tax Rates [Abstract]
Statutory Federal Income Tax Rate (in hundredths)		21.00%		21.00%		35.00%
State Income Tax, Net of Federal Benefit (in hundredths)		0.97%		1.12%		3.38%
Income Tax Provision Related to Foreign Operations (in hundredths)		0.87%		0.51%		(0.30%)
Income Tax Provision Related to United Kingdom Operations (in hundredths)		0.00%		0.00%		1.78%
Income Tax Provision Related to Canadian Operations (in hundredths)		0.00%		0.00%		2.30%
TCJA (in hundredths)		0.00%		(2.60%)	[4],[5]	(328.10%)	[5],[6]
Shared-Based Compensation (in hundredths)		0.02%		(0.47%)		(4.63%)
Other (in hundredths)		0.00%		(0.18%)		(0.03%)
Effective Income Tax Rate (in hundredths)		22.86%		19.38%		(290.60%)
Provisional Reduction in the Income Tax Provision						$ 2,000,000
Tax NOLs (in hundredths)				(1.20%)
Sequestration (in hundredths)				(1.00%)		(6.40%)
Other Tax Reform Impacts (in hundredths)				(0.40%)		(0.10%)
Federal Tax Rate Reduction (in hundredths)						(327.80%)
Federal Repatriation Tax (in hundredths)						(6.60%)
Components of Valuation Allowance [Abstract]
Beginning Balance		$ 167,142		$ 466,421		$ 383,221
Increase	[7]	30,673		23,062		67,333
Decrease	[8]	(75)		(26,219)		(13,687)
Other	[9]	3,091		(296,122)		29,554
Ending Balance		200,831		$ 167,142		$ 466,421
Balance of state net operating loss expected to be carried forward		2,100,000
Canadian Net Operating Loss Carryforwards		225,000
Unrecognized Tax Benefits Balance		39,000
Unrecognized Tax Benefits that Would Impact On Earnings		25,000
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense		4,000
Foreign and State Deferred Income Taxes		$ 16,000

[1] The 2018 presentation has been changed to conform with current year presentation.

[2] Includes changes in certain amounts that are expected to be paid or received beyond the next twelve months. The primary components are refundable alternative minimum tax (AMT) credits and the 2017 repatriation tax. See the following statutory-to-effective tax rate reconciliation for additional details.

[3] Includes changes in certain amounts that are expected to be paid or received beyond the next twelve months. The primary components are refundable alternative minimum tax (AMT) credits and the 2017 repatriation tax. See the following statutory-to-effective tax rate reconciliation for additional details.

[4] Includes impact of utilizing certain tax net operating losses (NOLs) ((1.2)%), the reversal of sequestration ((1.0)%) and other tax reform impacts ((0.4)%).

[5] The enactment of the Tax Cuts and Jobs Act (TCJA) by the United States in 2017 made numerous changes to federal tax law. Several changes which had a significant impact on EOG include the corporate income tax rate reduction from 35% to 21%, the imposition of a one-time repatriation tax on undistributed foreign earnings and the repeal of the corporate AMT regime (AMT credit carryforwards became refundable over the following four years and were initially subject to a federal sequestration charge). In 2017, EOG revalued its federal deferred income tax assets and liabilities resulting in an earnings benefit of over $2 billion and a substantial reduction of the 2017 effective tax rate. The TCJA measurement-period adjustments were recorded in 2018.

[6] Includes impact of the federal rate reduction ((327.8)%), federal repatriation tax ((6.6)%), sequestration ((6.4)%) and other tax reform impacts ((0.1)%).

[7] Increase in valuation allowance related to the generation of tax NOLs and other deferred tax assets.

[8] Decrease in valuation allowance associated with adjustments to certain deferred tax assets and their related allowance.

[9] 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.

XML

Business Segment Information (Details) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Schedule of Segment Reporting Information By Segment [Abstract]
Operating Revenues and Other		$ 4,320,246	$ 4,303,455	$ 4,697,630	$ 4,058,642	$ 4,574,536	$ 4,781,624	$ 4,238,077	$ 3,681,162	$ 17,379,973		$ 17,275,399		$ 11,208,320
Depreciation, Depletion and Amortization										3,749,704		3,435,408		3,409,387
Operating Income (Loss)		863,751	827,959	1,130,771	876,530	1,123,140	1,506,687	964,931	874,588	3,699,011		4,469,346		926,402
Interest Income										26,026		11,546		7,713
Other Income										5,359		5,158		1,439
Net Interest Expense										185,129		245,052		274,372
Income (Loss) Before Income Taxes										3,545,267		4,240,998		661,182
Income Tax Provision (Benefit)		194,687	$ 182,335	$ 241,525	$ 191,810	195,572	$ 255,411	$ 196,205	$ 174,770	810,357		821,958		(1,921,397)
Additions to Oil and Gas Properties, Excluding Dry Hole Costs										6,273,952		6,195,330		4,228,228
Total Property, Plant and Equipment, Net		30,364,595				28,075,519				30,364,595		28,075,519		25,665,037
Total Assets		37,124,608				33,934,474				37,124,608		33,934,474		29,833,078
Crude Oil and Condensate
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										9,612,532		9,517,440		6,256,396
Natural Gas Liquids
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										784,818		1,127,510		729,561
Natural Gas
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										1,184,095		1,301,537		921,934
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										180,275		(165,640)		19,828
Gathering, Processing and Marketing
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										5,360,282		5,230,355		3,298,087
Gains (Losses) on Asset Dispositions, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										123,613		174,562		(99,096)
Other, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										134,358		89,635		81,610
United States
Schedule of Segment Reporting Information By Segment [Abstract]
Operating Revenues and Other										17,052,363	[1]	16,794,591	[2]	10,872,071	[3]
Depreciation, Depletion and Amortization										3,652,294		3,296,499		3,269,196
Operating Income (Loss)										3,618,907		4,334,364		933,571
Interest Income										22,122		9,326		3,223
Other Income										3,235		9,580
Other Expense														(9,659)
Net Interest Expense										192,587		253,352		303,941
Income (Loss) Before Income Taxes										3,451,677		4,099,918		623,194
Income Tax Provision (Benefit)										760,881		765,986		(1,964,343)
Additions to Oil and Gas Properties, Excluding Dry Hole Costs										6,208,394		6,155,874		4,067,359
Total Property, Plant and Equipment, Net		30,101,857				27,786,086				30,101,857		27,786,086		25,125,427
Total Assets		36,274,942				33,178,733				36,274,942		33,178,733		28,312,599
Amount of sales with a single significant purchaser in the United States segment										2,400,000		2,600,000		1,500,000
Amount of sales with a second significant purchaser in the United States segment.										2,200,000		2,300,000		1,300,000
United States | Crude Oil and Condensate
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										9,599,125		9,390,244		6,225,711
United States | Natural Gas Liquids
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										784,818		1,127,510		729,545
United States | Natural Gas
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										866,911		970,866		615,512
United States | Gains (Losses) on Mark-to-Market Commodity Derivative Contracts
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										180,275		(165,640)		19,828
United States | Gathering, Processing and Marketing
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										5,355,463		5,227,051		3,298,098
United States | Gains (Losses) on Asset Dispositions, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										131,446		154,852		(98,233)
United States | Other, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										134,325		89,708		81,610
Trinidad
Schedule of Segment Reporting Information By Segment [Abstract]
Operating Revenues and Other										271,106		309,860		284,713
Depreciation, Depletion and Amortization										79,389		91,971		115,321
Operating Income (Loss)										112,790		147,240		101,010
Interest Income										3,686		1,612		2,201
Other Income										727		2,436		3,337
Net Interest Expense										0		0		0
Income (Loss) Before Income Taxes										117,203		151,288		106,548
Income Tax Provision (Benefit)										40,901		54,272		38,798
Additions to Oil and Gas Properties, Excluding Dry Hole Costs										53,325		1,618		145,937
Total Property, Plant and Equipment, Net		184,606				210,183				184,606		210,183		313,357
Total Assets		705,747				629,633				705,747		629,633		974,477
Trinidad | Crude Oil and Condensate
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										11,138		17,059		13,572
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										258,819		285,053		271,101
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										4,819		3,304		(11)
Trinidad | Gains (Losses) on Asset Dispositions, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										(3,688)		4,493		(8)
Trinidad | Other, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										18		(49)		59
Other International
Schedule of Segment Reporting Information By Segment [Abstract]
Operating Revenues and Other	[4]									56,504		170,948		51,536
Depreciation, Depletion and Amortization	[4]									18,021		46,938		24,870
Operating Income (Loss)	[4]									(32,686)		(12,258)		(108,179)
Interest Income	[4]									218		608		2,289
Other Income										1,397				7,761	[4]
Other Expense	[4]											(6,858)
Net Interest Expense	[4]									(7,458)		(8,300)		(29,569)
Income (Loss) Before Income Taxes	[4]									(23,613)		(10,208)		(68,560)
Income Tax Provision (Benefit)	[4]									8,575		1,700		4,148
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	[4]									12,233		37,838		14,932
Total Property, Plant and Equipment, Net	[4]	78,132				79,250				78,132		79,250		226,253
Total Assets	[4]	$ 143,919				$ 126,108				143,919		126,108		546,002
Other International | Crude Oil and Condensate
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues	[4]									2,269		110,137		17,113
Other International | Natural Gas Liquids
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues	[4]									0		0		16
Other International | Natural Gas
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues	[4]									58,365		45,618		35,321
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]									(4,145)		15,217		(855)
Other International | Other, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues	[4]									$ 15		$ (24)		$ (59)

[1] 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.

[2] 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.

[3] EOG had sales activity with two significant purchasers in 2017, one totaling $1.5 billion and the other totaling $1.3 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. The United Kingdom operations were sold in the fourth quarter of 2018.

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Net Income Per Share (Tables)

12 Months Ended

Dec. 31, 2019

Earnings Per Share [Abstract]

Computation of Net Income (Loss) Per Share

The following table sets forth the computation of Net Income Per Share for the years ended December 31, 2019, 2018 and 2017 (in thousands, except per share data):

	2019		2018		2017
Numerator for Basic and Diluted Earnings per Share -
Net Income	$	2,734,910	$	3,419,040	$	2,582,579
Denominator for Basic Earnings per Share -
Weighted Average Shares	577,670		576,578		574,620
Potential Dilutive Common Shares -
Stock Options/SARs	258		1,137		1,466
Restricted Stock/Units and Performance Units	2,849		2,726		2,607
Denominator for Diluted Earnings per Share -
Adjusted Diluted Weighted Average Shares	580,777		580,441		578,693
Net Income Per Share
Basic	$	4.73	$	5.93	$	4.49
Diluted	$	4.71	$	5.89	$	4.46

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Accumulated Other Comprehensive Income (Loss) (Tables)

12 Months Ended

Dec. 31, 2019

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

The components of Accumulated Other Comprehensive Loss at December 31, 2019 and 2018 consisted of the following (in thousands):

	Foreign Currency Translation Adjustment			Other			Total
December 31, 2017	$	(16,642	)	$	(2,655	)	$	(19,297	)
Other comprehensive income before reclassifications	2,451			1,131			3,582
Amounts reclassified out of other comprehensive income (loss) (1)	14,365			—			14,365
Tax effects	—			(8		)	(8		)
Other comprehensive income	16,816			1,123			17,939
December 31, 2018	174			(1,532		)	(1,358		)
Cumulative effect of accounting changes	—			267			267
Other comprehensive loss before reclassifications	(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	)

(1) Reclassified to Net Income - Gains (Losses) on Asset Dispositions, Net. See Note 17.

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Risk Management Activities (Notes)

12 Months Ended

Dec. 31, 2019

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 2019, 2018 and 2017, 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 and Comprehensive Income.  The related cash flow impact is reflected in Cash Flows from Operating Activities.  During 2019, 2018 and 2017, EOG recognized net gains (losses) on the mark-to-market of financial commodity derivative contracts of $180 million, $(166) million and $20 million, respectively, which included cash received from (payments for) settlements of crude oil and natural gas derivative contracts of $231 million, $(259) million and $7 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 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 pricing in Midland, Texas, and Cushing, Oklahoma (Midland Differential). Presented below is a comprehensive summary of EOG's Midland Differential basis swap contracts for the year ended December 31, 2019. The weighted average price differential expressed in dollars per barrel ($/Bbl) represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in barrels per day (Bbld) covered by the basis swap contracts.

Midland Differential Basis Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)
2019
January 1, 2019 through December 31, 2019 (closed)	20,000	$	1.075

EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in the U.S. Gulf Coast and Cushing, Oklahoma (Gulf Coast Differential). Presented below is a comprehensive summary of EOG's Gulf Coast Differential basis swap contracts for the year ended December 31, 2019. 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.

Gulf Coast Differential Basis Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)
2019
January 1, 2019 through December 31, 2019 (closed)	13,000	$	5.572

Presented below is a comprehensive summary of EOG's crude oil price swap contracts for the year ended December 31, 2019, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

Crude Oil Price Swap Contracts
	Volume (Bbld)	Weighted Average Price ($/Bbl)
2019
April 2019 (closed)	25,000	$	60.00
May 1, 2019 through December 31, 2019 (closed)	150,000	62.50
2020
January 1, 2020 through March 31, 2020	200,000	$	59.33
April 1, 2020 through June 30, 2020	150,000	59.03
July 1, 2020 through September 30, 2020	50,000	58.32

NGLs Derivative Contracts. Presented below is a comprehensive summary of EOG's Mont Belvieu propane (non-TET) price swap contracts for the year ended December 31, 2019, 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 December 31, 2020	4,000	$	21.34

Natural Gas Derivative Contracts. Presented below is a comprehensive summary of EOG's natural gas price swap contracts for the year ended December 31, 2019, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).

Natural Gas Price Swap Contracts
	Volume (MMBtud)	Weighted Average Price ($/MMBtu)
2019
April 1, 2019 through October 31, 2019 (closed)	250,000	$	2.90

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 for the year ended December 31, 2019. 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	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). Presented below is a comprehensive summary of EOG's HSC Differential basis swap contracts for the year ended December 31, 2019. 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	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 for the year ended December 31, 2019. 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 December 31, 2020	50,000	$	1.40

 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, 2019 and 2018, 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	2019		2018
Asset Derivatives
Crude oil, NGLs and natural gas derivative contracts -
Current portion	Assets from Price Risk Management Activities (1)	$	1,299	$	23,806
Liability Derivatives
Crude oil, NGLs and natural gas derivative contracts -
Current portion	Liabilities from Price Risk Management Activities (2)	$	20,194	$	—

(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, 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.  At December 31, 2018, 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 2019.

In 2019 and 2018, all natural gas from EOG's Trinidad operations was sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary. In 2019, all crude oil and condensate from EOG's Trinidad operations was sold to Heritage Petroleum Company Limited (Heritage). In 2018, all crude oil and condensate from EOG's Trinidad operations was sold to Heritage and its predecessor, the Petroleum Company of Trinidad and Tobago Limited. In 2019 and 2018, 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 liability position at December 31, 2019.  EOG had no collateral posted and held no collateral at December 31, 2019 and 2018.

Substantially all of EOG's accounts receivable at December 31, 2019 and 2018 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, 2019, credit losses incurred on receivables by EOG have been immaterial.

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Accumulated Other Comprehensive Income (Loss)

12 Months Ended

Dec. 31, 2019

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

Accumulated Other Comprehensive Income (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, 2019 and 2018 consisted of the following (in thousands):

	Foreign Currency Translation Adjustment			Other			Total
December 31, 2017	$	(16,642	)	$	(2,655	)	$	(19,297	)
Other comprehensive income before reclassifications	2,451			1,131			3,582
Amounts reclassified out of other comprehensive income (loss) (1)	14,365			—			14,365
Tax effects	—			(8		)	(8		)
Other comprehensive income	16,816			1,123			17,939
December 31, 2018	174			(1,532		)	(1,358		)
Cumulative effect of accounting changes	—			267			267
Other comprehensive loss before reclassifications	(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	)

(1) Reclassified to Net Income - Gains (Losses) on Asset Dispositions, Net. See Note 17.

No significant amount was reclassified out of Accumulated Other Comprehensive Loss during the year ended December 31, 2019.

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Commitments and Contingencies (Notes)

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Letters of Credit and Guarantees.  At December 31, 2019 and 2018, respectively, EOG had standby letters of credit and guarantees outstanding totaling $902 million and $294 million, primarily representing guarantees of payment or performance obligations on behalf of subsidiaries. As of February 19, 2020, EOG had received no demands for payment under these guarantees.

Minimum Commitments.  At December 31, 2019, 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, 2019, were as follows (in millions):

	Total Minimum Commitments
2020	$	1,312
2021	1,103
2022	1,027
2023	764
2024	519
2025 and beyond	2,531
	$	7,256

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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Summary of Significant Accounting Policies (Notes)

12 Months Ended

Dec. 31, 2019

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).

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 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 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, natural gas liquids (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 Accounting Standards Update (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 and Comprehensive Income 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 and Comprehensive Income. 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 on January 1, 2019 and December 31, 2019, were $1,460 million and $1,619 million, respectively, and are included in Accounts Receivable, Net on the Consolidated Balance Sheets. Losses incurred on receivables from contracts with customers are infrequent and have been immaterial.

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, crude-by-rail assets, sand mine and 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, 2019, 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 and Comprehensive Income.  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 Per Share.  Basic net income per share is computed on the basis of the weighted-average number of common shares outstanding during the period.  Diluted net income per share is computed based upon the weighted-average number of common shares outstanding during the period plus the assumed issuance of common shares for all potentially dilutive securities. See Note 9.

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

Leases. 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 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 is continuing to evaluate the provisions of ASU 2019-12 and has not determined the full impact on its consolidated financial statements and related disclosures.

In June 2016, the FASB issued 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. ASU 2016-13 requires adoption through the use of a modified retrospective approach at the effective date by recognizing a cumulative-effect adjustment to the opening balance of retained earnings. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019, and early adoption is permitted. EOG has assessed its applicable financial assets, which are primarily its accounts receivable from hydrocarbon sales and joint interest billings to third-party companies, including state-owned entities in the oil and gas industry. Based on its assessment and various potential remedies ensuring collection, EOG does not expect the impact from forward-looking expected losses will be material. EOG will apply the provisions of ASU 2016-13 on the adoption date, January 1, 2020.

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Commitments and Contingencies (Details) - USD ($)	Feb. 19, 2020	Dec. 31, 2019	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Standby letters of credit and guarantees outstanding		$ 902,000,000	$ 294,000,000
Total Minimum Commitments [Abstract]
2020		1,312,000,000
2021		1,103,000,000
2022		1,027,000,000
2023		764,000,000
2024		519,000,000
2025 and beyond		2,531,000,000
Total Minimum Commitments		$ 7,256,000,000
Subsidiary guarantees demand for payment	$ 0

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Risk Management Activities (Details)		12 Months Ended
		Dec. 31, 2019 USD ($) MMBTU $ / bbl $ / MMBTU MBbls bbl	Dec. 31, 2018 USD ($) $ / bbl	Dec. 31, 2017 USD ($)
Derivatives, Fair Value [Line Items]
Assets from Price Risk Management Activities		$ 1,299,000	$ 23,806,000
Liabilities from Price Risk Management Activities		$ 20,194,000	$ 0
Receivable Major Customer Percentage		10.00%	10.00%
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts		$ 180,275,000	$ (165,640,000)	$ 19,828,000
Net Cash Received from (Payments for) Settlements of Commodity Derivatives Contracts		231,229,000	(258,906,000)	7,438,000
Derivative Collateral [Abstract]
Collateral Held on Derivative		0		0
Collateral Had on Derivaitve		0		0
Assets [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 [Member] | Price Risk Derivative [Member]
Derivatives, Fair Value [Line Items]
Assets from Price Risk Management Activities	[1]		1,299,000	23,806,000
Liability [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	[2]		$ 20,194,000	$ 0
Crude Oil [Member] | Midland Differential Basis Swap [Member] | Derivative Contracts - January through December (closed) [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld) | MBbls		20,000
Derivative, Swap Type, Average Fixed Price | $ / bbl			1.075
Crude Oil [Member] | Gulf Coast Differential Basis Swap [Member] | Derivative Contracts - January through December (closed) [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl		13,000
Derivative, Swap Type, Average Fixed Price | $ / bbl		5.572
Crude Oil [Member] | Price Swap [Member] | Derivative Contracts - April (closed) [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl		25,000
Derivative, Swap Type, Average Fixed Price | $ / bbl		60.00
Crude Oil [Member] | Price Swap [Member] | Derivative Contracts - May through December (closed) [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl		150,000
Derivative, Swap Type, Average Fixed Price | $ / bbl		62.50
Crude Oil [Member] | Price Swap [Member] | Derivative Contracts - Year Two - January through March [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl		200,000
Derivative, Swap Type, Average Fixed Price | $ / bbl		59.33
Crude Oil [Member] | Price Swap [Member] | Derivative Contracts - Year Two - April through June [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl		150,000
Derivative, Swap Type, Average Fixed Price | $ / bbl		59.03
Crude Oil [Member] | Price Swap [Member] | Derivative Contracts - Year Two - July through September [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl		50,000
Derivative, Swap Type, Average Fixed Price | $ / bbl		58.32
Mont Belvieu Propane Price Swap [Member] | Price Swap [Member] | Derivative Contracts - Year Two - January through December [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl		4,000
Derivative, Swap Type, Average Fixed Price | $ / bbl		21.34
Natural Gas [Member] | Rockies Differential Basis Swaps [Member] | Derivative Contracts - Year Two - January through December [Member]
Derivatives, Fair Value [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU		0.55
Volume (MMBTU) | MMBTU		30,000
Natural Gas [Member] | HSC Differential Basis Swaps [Member] | Derivative Contracts - Year Two - January through December [Member]
Derivatives, Fair Value [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU		0.05
Volume (MMBTU) | MMBTU		60,000
Natural Gas [Member] | Waha Differential Basis Swaps [Member] | Derivative Contracts - Year Two - January through December [Member]
Derivatives, Fair Value [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU		1.40
Volume (MMBTU) | MMBTU		50,000
Natural Gas [Member] | Price Swap [Member] | Derivative Contracts - Year Two - January through December [Member]
Derivatives, Fair Value [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU		2.90
Volume (MMBTU) | MMBTU		250,000

[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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Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2019	Dec. 31, 2018
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)	582,213,016	580,408,117
Treasury Stock
Common Stock Held in Treasury (in shares)	298,820	385,042

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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, 2019		Sep. 30, 2019		Jun. 30, 2019		Mar. 31, 2019		Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Operating Revenues and Other	$ 4,320,246		$ 4,303,455		$ 4,697,630		$ 4,058,642		$ 4,574,536		$ 4,781,624		$ 4,238,077		$ 3,681,162		$ 17,379,973	$ 17,275,399	$ 11,208,320
Operating Income	863,751		827,959		1,130,771		876,530		1,123,140		1,506,687		964,931		874,588		3,699,011	4,469,346	926,402
Income (Loss) Before Income Taxes	831,208		797,457		1,089,366		827,236		1,088,340		1,446,363		892,936		813,359
Income Tax Provision (Benefit)	194,687		182,335		241,525		191,810		195,572		255,411		196,205		174,770		810,357	821,958	(1,921,397)
Net Income (Loss)	$ 636,521		$ 615,122		$ 847,841		$ 635,426		$ 892,768		$ 1,190,952		$ 696,731		$ 638,589		$ 2,734,910	$ 3,419,040	$ 2,582,579
Net Income (Loss) Per Share
Basic (in dollars per share)	$ 1.10	[1]	$ 1.06	[1]	$ 1.47	[1]	$ 1.10	[1]	$ 1.55	[1]	$ 2.06	[1]	$ 1.21	[1]	$ 1.11	[1]	$ 4.73	$ 5.93	$ 4.49
Diluted (in dollars per share)	$ 1.10	[1]	$ 1.06	[1]	$ 1.46	[1]	$ 1.10	[1]	$ 1.54	[1]	$ 2.05	[1]	$ 1.20	[1]	$ 1.10	[1]	$ 4.71	$ 5.89	$ 4.46
Average Number of Common Shares [Abstract]
Basic (in shares)	578,219		577,839		577,460		577,207		577,035		577,254		576,135		575,775		577,670	576,578	574,620
Diluted (in shares)	580,849		581,271		580,247		580,222		580,288		581,559		580,375		579,726		580,777	580,441	578,693

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

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Exploratory Well Costs (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Capitalized Exploratory Well Costs [Abstract]
Balance at January 1		$ 4,121	$ 2,167	$ 0
Additions Pending the Determination of Proved Reserves		83,175	10,304	27,487
Reclassifications to Proved Properties		(39,325)	(7,917)	(20,802)
Costs Charged to Expense (1)	[1]	(22,074)	(433)	(4,518)
Balance at December 31		$ 25,897	$ 4,121	$ 2,167

[1] Includes capitalized exploratory well costs charged to either dry hole costs or impairments.

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Oil and Gas Exploration and Production Industries Disclosures, Costs Incurred (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Unproved		$ 276,092	[1]	$ 487,339	[2]	$ 426,540	[3]
Acquisition Costs of Properties - Proved		379,938	[4]	123,684	[5]	72,584	[6]
Subtotal		656,030		611,023		499,124
Exploration Costs		273,339		193,628		223,599
Development Costs		5,698,856	[7]	5,615,029	[8]	3,716,687	[9]
Total		6,628,225		6,419,680		4,439,410
Non-Cash Unproved Leasehold Acquisition Costs Related to Property Exchanges		98,000		291,000		256,000
Non-Cash Proved Property Acquisition Costs Related to Property Exchanges		52,000		71,000		26,000
United States
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Unproved		276,092	[1]	486,081	[2]	424,118	[3]
Acquisition Costs of Properties - Proved		379,938	[4]	123,684	[5]	72,584	[6]
Subtotal		656,030		609,765		496,702
Exploration Costs		213,505		157,222		144,499
Development Costs		5,661,753	[7]	5,605,264	[8]	3,590,899	[9]
Total		6,531,288		6,372,251		4,232,100
Asset Retirement Costs Included In Development		181,000		90,000		50,000
Trinidad
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Unproved		0	[1]	1,258	[2]	2,422	[3]
Acquisition Costs of Properties - Proved		0	[4]	0	[5]	0	[6]
Subtotal		0		1,258		2,422
Exploration Costs		46,616		22,511		62,547
Development Costs		25,007	[7]	(12,863)	[8]	109,491	[9]
Total		71,623		10,906		174,460
Asset Retirement Costs Included In Development		1,000		(12,000)		2,000
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]	0	[4]	0	[5]	0	[6]
Subtotal	[10]	0		0		0
Exploration Costs	[10]	13,218		13,895		16,553
Development Costs	[10]	12,096	[7]	22,628	[8]	16,297	[9]
Total	[10]	25,314		36,523		32,850
Asset Retirement Costs Included In Development		$ 4,000		$ (8,000)		$ 4,000

[1] Includes non-cash unproved leasehold acquisition costs of $98 million related to property exchanges.

[2] Includes non-cash unproved leasehold acquisition costs of $291 million related to property exchanges.

[3] Includes non-cash unproved leasehold acquisition costs of $256 million related to property exchanges.

[4] Includes non-cash proved property acquisition costs of $52 million related to property exchanges.

[5] Includes non-cash proved property acquisition costs of $71 million related to property exchanges.

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

[7] Includes Asset Retirement Costs of $181 million, $1 million and $4 million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment.

[8] 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.

[9] Includes Asset Retirement Costs of $50 million, $2 million and $4 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. The United Kingdom operations were sold in the fourth quarter of 2018.

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Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Total Operating Revenues and Other	$ 4,320,246	$ 4,303,455	$ 4,697,630	$ 4,058,642	$ 4,574,536	$ 4,781,624	$ 4,238,077	$ 3,681,162	$ 17,379,973		$ 17,275,399		$ 11,208,320
Gathering and Processing Costs									479,102	[1],[2]	436,973	[1],[2]	148,775
Marketing Costs									5,351,524		5,203,243		3,330,237
Total Operating Expenses									13,680,962		12,806,053		10,281,918
Operating Income	863,751	$ 827,959	$ 1,130,771	$ 876,530	1,123,140	$ 1,506,687	$ 964,931	$ 874,588	3,699,011		4,469,346		926,402
Accounts Receivable From Contracts With Customers	$ 1,619,000				$ 1,460,000				1,619,000		1,460,000
Crude Oil and Condensate
Revenues									9,612,532		9,517,440		6,256,396
Natural Gas Liquids
Revenues									784,818		1,127,510		729,561
Natural Gas
Revenues									1,184,095		1,301,537		921,934
Gathering, Processing and Marketing
Revenues									$ 5,360,282		5,230,355		$ 3,298,087
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] 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).

[2] 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, 2019.

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Exploratory Well Costs (Tables)

12 Months Ended

Dec. 31, 2019

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, 2019, 2018 and 2017 are presented below (in thousands):

	2019			2018			2017
Balance at January 1	$	4,121		$	2,167		$	—
Additions Pending the Determination of Proved Reserves	83,175			10,304			27,487
Reclassifications to Proved Properties	(39,325		)	(7,917		)	(20,802		)
Costs Charged to Expense (1)	(22,074		)	(433		)	(4,518		)
Balance at December 31	$	25,897		$	4,121		$	2,167

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

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Exploratory Well Costs (Notes)

12 Months Ended

Dec. 31, 2019

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, 2019, 2018 and 2017 are presented below (in thousands):

	2019			2018			2017
Balance at January 1	$	4,121		$	2,167		$	—
Additions Pending the Determination of Proved Reserves	83,175			10,304			27,487
Reclassifications to Proved Properties	(39,325		)	(7,917		)	(20,802		)
Costs Charged to Expense (1)	(22,074		)	(433		)	(4,518		)
Balance at December 31	$	25,897		$	4,121		$	2,167

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

At December 31, 2019, 2018 and 2017, all exploratory well costs had been capitalized for periods of less than one year.

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Unaudited Quarterly Financial Information (Notes)

12 Months Ended

Dec. 31, 2019

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
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
2018
Operating Revenues and Other	$	3,681,162	$	4,238,077	$	4,781,624	$	4,574,536
Operating Income	$	874,588	$	964,931	$	1,506,687	$	1,123,140
Income Before Income Taxes	$	813,359	$	892,936	$	1,446,363	$	1,088,340
Income Tax Provision	174,770		196,205		255,411		195,572
Net Income	$	638,589	$	696,731	$	1,190,952	$	892,768
Net Income Per Share (1)
Basic	$	1.11	$	1.21	$	2.06	$	1.55
Diluted	$	1.10	$	1.20	$	2.05	$	1.54
Average Number of Common Shares
Basic	575,775		576,135		577,254		577,035
Diluted	579,726		580,375		581,559		580,288

(1)

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

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Employee Benefit Plans (Notes)

12 Months Ended

Dec. 31, 2019

Share-based Payment Arrangement [Abstract]

Employee Benefit Plans

Employee Benefit Plans

Stock-Based Compensation

During 2019, 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 and Comprehensive Income based upon the job functions of the employees receiving the grants.  Compensation expense related to EOG's stock-based compensation plans for the years ended December 31, 2019, 2018 and 2017 was as follows (in millions):

	2019		2018		2017
Lease and Well	$	56	$	51	$	41
Gathering and Processing Costs	1		1		1
Exploration Costs	26		25		23
General and Administrative	92		78		69
Total	$	175	$	155	$	134

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 as follows:

Grant Type	Vesting Schedule
Stock Options/SARs	Vesting in increments of 33%, 33% and 34% 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 approximately 41 months from the date of grant - specifically, on the February 28th immediately following the Compensation Committee's certifications contemplated by the form of award agreement governing such grant of performance units

At December 31, 2019, approximately 6.8 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 2019, 2018 and 2017, EOG issued shares in connection with stock option/SAR exercises, restricted stock and performance unit 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 $(1) million, $20 million and $32 million for the twelve months ended December 31, 2019, 2018 and 2017, 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 $63 million, $60 million and $56 million for the years ended December 31, 2019, 2018 and 2017, respectively.

Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants for the years ended December 31, 2019, 2018 and 2017 were as follows:

	Stock Options/SARs									ESPP
	2019			2018			2017			2019			2018			2017
Weighted Average Fair Value of Grants	$	19.49		$	33.46		$	23.95		$	22.83		$	25.75		$	22.20
Expected Volatility	32.02		%	28.23		%	28.28		%	34.78		%	24.59		%	27.12		%
Risk-Free Interest Rate	1.69		%	2.68		%	1.52		%	2.27		%	1.89		%	0.88		%
Dividend Yield	1.39		%	0.72		%	0.75		%	1.04		%	0.64		%	0.71		%
Expected Life	5.1 years			5.0 years			5.1 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, 2019, 2018 and 2017 (stock options and SARs in thousands):

	2019				2018				2017
	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	8,310		$	96.90	9,103		$	83.89	9,850		$	75.53
Granted	1,965		75.39		1,906		126.49		2,274		96.27
Exercised (1)	(606	)	61.43		(2,493	)	72.21		(2,574	)	61.12
Forfeited	(274	)	102.57		(206	)	94.43		(447	)	93.84
Outstanding at December 31	9,395		94.53		8,310		96.90		9,103		83.89
Stock Options/SARs Exercisable at December 31	5,275		94.21		3,969		85.82		4,510		75.76

(1) The total intrinsic value of stock options/SARs exercised during the years 2019, 2018 and 2017 was $14 million, $118 million and $95 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, 2019, there were 9.1 million stock options/SARs vested or expected to vest with a weighted average grant price of $94.52 per share, an intrinsic value of $29.1 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, 2019 (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)
$ 59.00 to $  74.99	979	3	$	69.43			953	3	$	69.37
75.00 to    75.99	1,894	7	75.09				8	1	75.09
76.00 to     95.99	1,979	3	91.35				1,607	2	90.67
96.00 to     96.99	1,871	4	96.29				1,234	4	96.29
97.00 to   125.99	923	2	102.72				862	2	102.20
126.00 to   129.99	1,749	6	127.01				611	5	127.01
	9,395	4	94.53		$	30,534	5,275	3	94.21		$	13,839

(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.

At December 31, 2019, unrecognized compensation expense related to non-vested stock option and SAR grants totaled $86 million.  This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.0 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, 2019, approximately 2.3 million shares of Common Stock remained available for grant under the ESPP.  The following table summarizes ESPP activity for the years ended December 31, 2019, 2018 and 2017 (in thousands, except number of participants):

	2019		2018		2017
Approximate Number of Participants	1,998		1,934		1,870
Shares Purchased	224		180		180
Aggregate Purchase Price	$	16,533	$	14,887	$	13,997

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 $97 million, $81 million and $68 million for the years ended December 31, 2019, 2018 and 2017, respectively.

The following table sets forth the restricted stock and restricted stock unit transactions for the years ended December 31, 2019, 2018 and 2017 (shares and units in thousands):

	2019				2018				2017
	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	3,792		$	96.64	3,905		$	88.57	3,962		$	79.63
Granted	1,749		80.01		812		117.55		1,095		97.34
Released (1)	(855	)	96.93		(740	)	78.16		(929	)	61.51
Forfeited	(140	)	97.54		(185	)	92.12		(223	)	85.45
Outstanding at December 31 (2)	4,546		90.16		3,792		96.64		3,905		88.57

(1) The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2019, 2018 and 2017 was $70 million, $84 million and $91 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, 2019, 2018 and 2017 was $381 million, $331 million and $421 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, 2019, unrecognized compensation expense related to restricted stock and restricted stock units totaled $202 million. Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 1.8 years.

Performance Units.  EOG has granted performance units (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 $15 million, $14 million and $10 million for the years ended December 31, 2019, 2018 and 2017, respectively.

      Weighted average fair values and valuation assumptions used to value Performance Awards during the years ended December 31, 2019, 2018 and 2017 were as follows:

	2019			2018			2017
Weighted Average Fair Value of Grants	$	79.98		$	136.74		$	113.81
Expected Volatility	29.20		%	29.92		%	32.19		%
Risk-Free Interest Rate	1.51		%	2.85		%	1.60		%

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, 2019, 2018 and 2017 (shares and units in thousands):

	2019						2018				2017
	Number of Units and Shares				Weighted Average Price per Grant Date		Number of Units and Shares		Weighted Average Price per Grant Date		Number of Units and Shares		Weighted Average Price per Grant Date
Outstanding at January 1	539				$	101.53	502		$	90.96	545		$	80.92
Granted	172				75.09		113		125.73		78		96.29
Granted for Performance Multiple (1)	72				69.43		72		101.87		119		84.43
Released (2)	(185	)			94.63		(148	)	84.43		(240	)	66.69
Forfeited	—				—		—		—		—		—
Outstanding at December 31 (3)	598		(4	)	92.19		539		101.53		502		90.96

(1) Upon completion of the Performance Period for the Performance Awards granted in 2015, 2014 and 2013, a performance multiple of 200% was applied to each of the grants resulting in additional grants of Performance Awards in February 2019, 2018 and 2017.

(2) The total intrinsic value of Performance Awards released during the years ended December 31, 2019, 2018 and 2017 was $15 million, $18 million and $24 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, 2019, 2018 and 2017 was $50 million, $47 million and $54 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 102 and a maximum of 1,094 Performance Awards could be outstanding.

At December 31, 2019, unrecognized compensation expense related to Performance Awards totaled $9 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.0 years.

Upon completion of the Performance Period for the Performance Awards granted in September 2016 and December 2016, a performance multiple of 150% was applied to the grants resulting in an additional grant of 65,872 Performance Awards in February 2020.

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 $51 million, $43 million and $37 million for 2019, 2018 and 2017, respectively.

In addition, EOG's Trinidadian subsidiary maintains a contributory defined benefit pension plan and a matched savings plan.  EOG's United Kingdom subsidiary maintained a pension plan which included a non-contributory defined contribution pension plan and a matched defined contribution savings plan.  These pension plans are available to most employees of the Trinidadian subsidiary and were available to most employees of the United Kingdom subsidiary.  EOG's combined contributions to these plans were $1 million, for each of 2019, 2018 and 2017, respectively. The United Kingdom operations were sold in the fourth quarter of 2018.

For the Trinidadian defined benefit pension plan, the benefit obligation, fair value of plan assets and accrued benefit cost totaled $12 million, $10 million and $0.1 million, respectively, at December 31, 2019, and $11 million, $9 million and $0.2 million, respectively, at December 31, 2018.

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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Supplemental Cash Flow Information (Notes)

12 Months Ended

Dec. 31, 2019

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, 2019, 2018 and 2017 (in thousands):

	2019			2018		2017
Interest, Net of Capitalized Interest	$	186,546		$	243,279	$	275,305
Income Taxes, Net of Refunds Received	$	(291,849	)	$	75,634	$	188,946

EOG's accrued capital expenditures at December 31, 2019, 2018 and 2017 were $612 million, $592 million and $475 million, respectively.

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.

Non-cash investing activities for the year ended December 31, 2017, included non-cash additions of $282 million to EOG's oil and gas properties as a result of property exchanges.

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

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Business Segment Information (Tables)

12 Months Ended

Dec. 31, 2019

Segment Reporting [Abstract]

Selected Financial Information by Reportable Segment

Financial information by reportable segment is presented below as of and for the years ended December 31, 2019, 2018 and 2017 (in thousands):

	United States		Trinidad			Other International (1)			Total
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 (2)	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
Losses 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 (3)	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
2017
Crude Oil and Condensate	$	6,225,711		$	13,572		$	17,113		$	6,256,396
Natural Gas Liquids	729,545			—			16			729,561
Natural Gas	615,512			271,101			35,321			921,934
Gains on Mark-to-Market Commodity Derivative Contracts	19,828			—			—			19,828
Gathering, Processing and Marketing	3,298,098			(11		)	—			3,298,087
Losses on Asset Dispositions, Net	(98,233		)	(8		)	(855		)	(99,096		)
Other, Net	81,610			59			(59		)	81,610
Operating Revenues and Other (4)	10,872,071			284,713			51,536			11,208,320
Depreciation, Depletion and Amortization	3,269,196			115,321			24,870			3,409,387
Operating Income (Loss)	933,571			101,010			(108,179		)	926,402
Interest Income	3,223			2,201			2,289			7,713
Other Income (Expense)	(9,659		)	3,337			7,761			1,439
Net Interest Expense	303,941			—			(29,569		)	274,372
Income (Loss) Before Income Taxes	623,194			106,548			(68,560		)	661,182
Income Tax Provision (Benefit)	(1,964,343		)	38,798			4,148			(1,921,397		)
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	4,067,359			145,937			14,932			4,228,228
Total Property, Plant and Equipment, Net	25,125,427			313,357			226,253			25,665,037
Total Assets	28,312,599			974,477			546,002			29,833,078

(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.

(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)

EOG had sales activity with two significant purchasers in 2017, one totaling $1.5 billion and the other totaling $1.3 billion of consolidated Operating Revenues and Other in the United States segment.

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Deferred Income Tax Liabilities, Net

The principal components of EOG's total net deferred income tax liabilities at December 31, 2019 and 2018 were as follows (in thousands):

	2019			2018
Deferred Income Tax Assets (Liabilities)
Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization	$	5,825		$	4,359
Foreign Net Operating Loss	66,675			55,175
Foreign Valuation Allowances	(70,455		)	(58,932		)
Foreign Other	318			175
Total Net Deferred Income Tax Assets	$	2,363		$	777
Deferred Income Tax (Assets) Liabilities
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization	$	5,277,550		$	4,583,517		(1)
Commodity Hedging Contracts	(4,699		)	4,883
Deferred Compensation Plans	(47,650		)	(39,086		)
Accrued Expenses and Liabilities	(8,502		)	(19,097		)
Equity Awards	(108,324		)	(93,977		)
Alternative Minimum Tax Credit Carryforward	(31,904		)	—
Undistributed Foreign Earnings	15,746			22,945
Other	(46,116		)	(45,787		)
Total Net Deferred Income Tax Liabilities	$	5,046,101		$	4,413,398
Total Net Deferred Income Tax Liabilities	$	5,043,738		$	4,412,621

Components of Income (Loss) Before Income Taxes

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

	2019		2018		2017
United States	$	3,466,578	$	4,084,156	$	621,610
Foreign	78,689		156,842		39,572
Total	$	3,545,267	$	4,240,998	$	661,182

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):

	2019			2018			2017
Current:
Federal	$	(152,258	)	$	(303,853	)	$	33,058
State	10,819			17,048			(2,502		)
Foreign	81,426			65,615			35,323
Total	(60,013		)	(221,190		)	65,879
Deferred:
Federal	626,901			862,075			(1,504,288		)
State	32,541			43,293			26,942
Foreign	(27,784		)	(11,212		)	3,474
Total	631,658			894,156			(1,473,872		)
Other Non-Current: (1)
Federal	245,125			148,992			(513,404		)
Foreign	(6,413		)	—			—
Total	238,712			148,992			(513,404		)
Income Tax Provision (Benefit)	$	810,357		$	821,958		$	(1,921,397	)

(1)

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:

	2019		2018			2017
Statutory Federal Income Tax Rate	21.00	%	21.00	%		35.00	%
State Income Tax, Net of Federal Benefit	0.97		1.12			3.38
Income Tax Provision Related to Foreign Operations	0.87		0.51			(0.30	)
Income Tax Provision Related to United Kingdom Operations	—		—			1.78
Income Tax Provision Related to Canadian Operations	—		—			2.30
TCJA (1)	—		(2.60	)	(2)	(328.10	)	(3)
Share-Based Compensation	0.02		(0.47	)		(4.63	)
Other	—		(0.18	)		(0.03	)
Effective Income Tax Rate	22.86	%	19.38	%		(290.60	)%

(1) The enactment of the Tax Cuts and Jobs Act (TCJA) by the United States in 2017 made numerous changes to federal tax law. Several changes which had a significant impact on EOG include the corporate income tax rate reduction from 35% to 21%, the imposition of a one-time repatriation tax on undistributed foreign earnings and the repeal of the corporate AMT regime (AMT credit carryforwards became refundable over the following four years and were initially subject to a federal sequestration charge). In 2017, EOG revalued its federal deferred income tax assets and liabilities resulting in an earnings benefit of over $2 billion and a substantial reduction of the 2017 effective tax rate. The TCJA measurement-period adjustments were recorded in 2018.

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

(3) Includes impact of the federal rate reduction ((327.8)%), federal repatriation tax ((6.6)%), sequestration ((6.4)%) and other tax reform impacts ((0.1)%).

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):

	2019			2018			2017
Beginning Balance	$	167,142		$	466,421		$	383,221
Increase (1)	30,673			23,062			67,333
Decrease (2)	(75		)	(26,219		)	(13,687		)
Other (3)	3,091			(296,122		)	29,554
Ending Balance	$	200,831		$	167,142		$	466,421

(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 allowance.

(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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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt at December 31, 2019 and 2018 consisted of the following (in thousands):

	2019		2018
5.625% Senior Notes due 2019	$	—	$	900,000
4.40% Senior Notes due 2020	500,000		500,000
2.45% Senior Notes due 2020	500,000		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
3.90% Senior Notes due 2035	500,000		500,000
5.10% Senior Notes due 2036	250,000		250,000
Long-Term Debt	5,140,000		6,040,000
Finance Leases (see Note 18)	57,900		71,571
Less: Current Portion of Long-Term Debt	1,014,524		913,093
Unamortized Debt Discount	19,528		24,640
Debt Issuance Costs	2,929		3,669
Total Long-Term Debt	$	4,160,919	$	5,170,169

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Employee Benefit Plans (Details)			12 Months Ended
		Feb. 27, 2020 shares	Dec. 31, 2019 USD ($) $ / shares shares		Dec. 31, 2018 USD ($) $ / shares shares		Dec. 31, 2017 USD ($) $ / shares shares	Feb. 19, 2020 USD ($)
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items]
Subsidiary guarantees demand for payment | $								$ 0
Common Shares Available for Grant			6,800,000
Share-based Payment Arrangement, Expense, Tax Benefit | $			$ (1,000,000)		$ 20,000,000		$ 32,000,000
Compensation expense related to the company's stock-based compensation plans | $			$ 174,738,000		155,337,000		133,849,000
Stock Options and Sars [Member]
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items]
Maximum term of stock options and SARs granted			7 years
Share-based Compensation Expense Related To Stock Options, SAR and ESPP Grants | $			$ 63,000,000		60,000,000		56,000,000
Stock Options/SARs Vested or Expected to Vest (in shares)			9,100,000
Weighted average grant price for stock options/SARs vested or expected to vest (per share) | $ / shares			$ 94.52
Intrinsic value of stock options/SARs vested or expected to vest | $			$ 29,100,000
Weighted Average Remaining Contractual Life for Stock Options/SARs Vested or Expected to Vest			4 years 2 months 12 days
Unrecognized compensation expense | $			$ 86,000,000
Weighted average period over which unrecognized compensation expense will be recognized			2 years
Intrinsic Value Of Stock Options/SARs Exercised During The Period | $			$ 14,000,000		$ 118,000,000		$ 95,000,000
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			$ 19.49		$ 33.46		$ 23.95
Expected Volatility (in hundredths)			32.02%		28.23%		28.28%
Risk-Free Interest Rate (in hundredths)			1.69%		2.68%		1.52%
Dividend Yield (in hundredths)			1.39%		0.72%		0.75%
Expected Life (in years)			5 years 1 month 6 days		5 years		5 years 1 month 6 days
Stock Options and SARs Rollforward [Abstract]
Outstanding at January 1 (in shares)			8,310,000		9,103,000		9,850,000
Granted (in shares)			1,965,000		1,906,000		2,274,000
Exercised (1) (in shares)	[1]		(606,000)		(2,493,000)		(2,574,000)
Forfeited (in shares)			(274,000)		(206,000)		(447,000)
Outstanding at December 31 (in shares)			9,395,000		8,310,000		9,103,000
Stock Options/SARs Exercisable at December 31 (in shares)			5,275,000		3,969,000		4,510,000
Weighted Average Grant Price Stock Option and SARs [Rollfoward]
Outstanding at January 1 (in dollars per share) | $ / shares			$ 96.90		$ 83.89		$ 75.53
Granted (in dollars per share) | $ / shares			75.39		126.49		96.27
Exercised (in dollars per share) | $ / shares	[1]		61.43		72.21		61.12
Forfeited (in dollars per share) | $ / shares			102.57		94.43		93.84
Outstanding at December 31 (in dollars per share) | $ / shares			94.53		96.90		83.89
Stock Options/SARs Exercisable at December 31 (in dollars per share) | $ / shares			$ 94.21		85.82		75.76
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			9,395,000
Weighted Average Remaining Life for Outstanding Options and SARs			4 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 94.53
Aggregate Intrinsic Value For Outstanding Options and SARs | $	[2]		$ 30,534
Stock Options and SARs Exercisable			5,275,000
Weighted Average Remaining Life For Exercisable Units			3 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 94.21
Aggregate Intrinsic Value For Exercisable Units | $	[2]		$ 13,839
Stock Options and Sars [Member] | Vesting Schedule - First Anniversary [Member]
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items]
Vesting Period Increments (in hundredths)			33.00%
Stock Options and Sars [Member] | Vesting Schedule - Second Anniversary [Member]
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items]
Vesting Period Increments (in hundredths)			33.00%
Stock Options and Sars [Member] | Vesting Schedule - Third Anniversary [Member]
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items]
Vesting Period Increments (in hundredths)			34.00%
ESPP [Member]
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items]
Common Shares Available for Grant			2,300,000
Percentage of fair market value at which employees may purchase company stock via the ESPP			85.00%
Maximum Percentage Of Employee Pay Eligible For Contribution To ESPP Percentage			10.00%
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			$ 22.83		$ 25.75		$ 22.20
Expected Volatility (in hundredths)			34.78%		24.59%		27.12%
Risk-Free Interest Rate (in hundredths)			2.27%		1.89%		0.88%
Dividend Yield (in hundredths)			1.04%		0.64%		0.71%
Expected Life (in years)			15 days		15 days		15 days
Stock Options and SARs Rollforward [Abstract]
Approximate Number of Participants			1,998		1,934		1,870
Shares Purchased			224,000		180,000		180,000
Aggregate Purchase Price | $			$ 16,533,000		$ 14,887,000		$ 13,997,000
Restricted Stock and Restricted Stock Units [Member]
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items]
Adjustments to Additional Paid in Capital, Income Tax Benefit from Share-based Compensation | $			97,000,000		81,000,000		68,000,000
Unrecognized compensation expense | $			$ 202,000,000
Weighted average period over which unrecognized compensation expense will be recognized			1 year 9 months 18 days
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period			3 years
Intrinsic value released during the year | $			$ 70,000,000		84,000,000		91,000,000
Aggregate intrinsic value of stock and unit outstanding | $			$ 381,000,000		$ 331,000,000		$ 421,000,000
Number of Shares and Units [Roll Forward]
Outstanding at January 1 (in shares)			3,792,000	[3]	3,905,000	[3]	3,962,000
Granted (in shares)			1,749,000		812,000		1,095,000
Released (in shares)	[4]		(855,000)		(740,000)		(929,000)
Forfeited (in shares)			(140,000)		(185,000)		(223,000)
Outstanding at December 31 (in shares)	[3]		4,546,000		3,792,000		3,905,000
Weighted Average Grant Fair Value [Abstract]
Outstanding at January 1 (in dollars per share) | $ / shares			$ 96.64	[3]	$ 88.57	[3]	$ 79.63
Granted (in dollars per share) | $ / shares			80.01		117.55		97.34
Released (in dollars per share) | $ / shares	[4]		96.93		78.16		61.51
Forfeited (in dollars per share) | $ / shares			97.54		92.12		85.45
Outstanding at December 31 (in dollars per share) | $ / shares	[3]		$ 90.16		$ 96.64		$ 88.57
Performance Units [Member]
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items]
Unrecognized compensation expense | $			$ 9,000,000
Weighted average period over which unrecognized compensation expense will be recognized			2 years
Cliff Vesting Period			41 months
Compensation expense related to the company's stock-based compensation plans | $			$ 15,000,000		$ 14,000,000		$ 10,000,000
Intrinsic value released during the year | $			15,000,000		18,000,000		24,000,000
Aggregate intrinsic value of stock and unit outstanding | $			$ 50,000,000		$ 47,000,000		$ 54,000,000
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			$ 79.98		$ 136.74		$ 113.81
Expected Volatility (in hundredths)			29.20%		29.92%		32.19%
Risk-Free Interest Rate (in hundredths)			1.51%		2.85%		1.60%
Number of Shares and Units [Roll Forward]
Outstanding at January 1 (in shares)			539,000	[5]	502,000	[5]	545,000
Granted (in shares)			172,000		113,000		78,000
Granted for Performance Multiple (1) (in shares)	[6]		72,000		72,000		119,000
Released (in shares)	[7]		(185,000)		(148,000)		(240,000)
Forfeited (in shares)			0		0		0
Outstanding at December 31 (in shares)	[5]		598,000	[8]	539,000		502,000
Weighted Average Grant Fair Value [Abstract]
Outstanding at January 1 (in dollars per share) | $ / shares			$ 101.53	[5]	$ 90.96	[5]	$ 80.92
Granted (in dollars per share) | $ / shares			75.09		125.73		96.29
Granted for Performance Multiple (1) (in dollars per share) | $ / shares	[6]		69.43		101.87		84.43
Released (in dollars per share) | $ / shares	[7]		94.63		84.43		66.69
Forfeited (in dollars per share) | $ / shares			0		0		0
Outstanding at December 31 (in dollars per share) | $ / shares	[5]		$ 92.19		$ 101.53		$ 90.96
Performance Units and Performance Stock [Abstract]
Minimum Performance Multiple at the Completion Performance Period			0.00%
Maximum Performance Multiple at the Completion Performance Period			200.00%
Minimum Performance Units and Stock Allowed to be Outstanding			102
Maximum Performance Units and Stock Allowed to be Outstanding			1,094
Performance Multiple Applied at the Completion Period		150.00%	200.00%		200.00%		200.00%
Additional Performance Awards Granted		65,872
Pension Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total pension plan costs | $			$ 51,000,000		$ 43,000,000		$ 37,000,000
Company contributions to foreign pension plans | $			1,000,000		1,000,000		1,000,000
Defined Benefit Plan, Benefit Obligation | $			12,000,000		11,000,000
Fair value of foreign pension plan assets | $			10,000,000		9,000,000
Accrued benefit cost | $			(100,000)		(200,000)
Lease And Well [Member]
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items]
Compensation expense related to the company's stock-based compensation plans | $			56,000,000		51,000,000		41,000,000
Gathering And Processing Costs [Member]
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [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]
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items]
Compensation expense related to the company's stock-based compensation plans | $			26,000,000		25,000,000		23,000,000
General And Administrative [Member]
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items]
Compensation expense related to the company's stock-based compensation plans | $			$ 92,000,000		$ 78,000,000		$ 69,000,000
$ 59.00 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			979,000
Weighted Average Remaining Life for Outstanding Options and SARs			3 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 69.43
Stock Options and SARs Exercisable			953,000
Weighted Average Remaining Life For Exercisable Units			3 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 69.37
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			1,894,000
Weighted Average Remaining Life for Outstanding Options and SARs			7 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 75.09
Stock Options and SARs Exercisable			8,000
Weighted Average Remaining Life For Exercisable Units			1 year
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			1,979,000
Weighted Average Remaining Life for Outstanding Options and SARs			3 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 91.35
Stock Options and SARs Exercisable			1,607,000
Weighted Average Remaining Life For Exercisable Units			2 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 90.67
96.00 to 96.99 | 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			1,871,000
Weighted Average Remaining Life for Outstanding Options and SARs			4 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 96.29
Stock Options and SARs Exercisable			1,234,000
Weighted Average Remaining Life For Exercisable Units			4 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 96.29
97.00 to 125.99 | 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			923,000
Weighted Average Remaining Life for Outstanding Options and SARs			2 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 102.72
Stock Options and SARs Exercisable			862,000
Weighted Average Remaining Life For Exercisable Units			2 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 102.20
126.00 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			1,749,000
Weighted Average Remaining Life for Outstanding Options and SARs			6 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 127.01
Stock Options and SARs Exercisable			611,000
Weighted Average Remaining Life For Exercisable Units			5 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 127.01

[1] The total intrinsic value of stock options/SARs exercised during the years 2019, 2018 and 2017 was $14 million, $118 million and $95 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.

[3] The total intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2019, 2018 and 2017 was $381 million, $331 million and $421 million, respectively.

[4] The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2019, 2018 and 2017 was $70 million, $84 million and $91 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, 2019, 2018 and 2017 was $50 million, $47 million and $54 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 2015, 2014 and 2013, a performance multiple of 200% was applied to each of the grants resulting in additional grants of Performance Awards in February 2019, 2018 and 2017.

[7] The total intrinsic value of Performance Awards released during the years ended December 31, 2019, 2018 and 2017 was $15 million, $18 million and $24 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 102 and a maximum of 1,094 Performance Awards could be outstanding.

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Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Supplemental Cash Flow Information [Abstract]
Interest, Net of Capitalized Interest	$ 186,546	$ 243,279	$ 275,305
Income Taxes, Net of Refunds Received	(291,849)	75,634	188,946
Accrued Capital Expenditures	612,000	592,000	475,000
Non-cash investing and financing activities from property exchanges.	$ 150,000	362,000	$ 282,000
Non-cash investing activities from other, property, plant and equipment		$ 49,000

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Consolidated Statements of Stockholders' Equity (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Stockholders' Equity [Abstract]
Dividends, Common Stock	$ (629,169)	$ 469,443	$ 387,164
Common Stock Dividends Declared (in dollars per share)	$ 1.083	$ 0.810	$ 0.670

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Consolidated Statements of Income and Comprehensive Income - USD ($) shares in Thousands, $ in Thousands		12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Operating Revenues and Other
Total		$ 17,379,973		$ 17,275,399		$ 11,208,320
Operating Expenses
Lease and Well		1,366,993		1,282,678		1,044,847
Transportation Costs	[1]	758,300		746,876		740,352
Gathering and Processing Costs		479,102	[1],[2]	436,973	[1],[2]	148,775
Exploration Costs		139,881		148,999		145,342
Dry Hole Costs	[1]	28,001		5,405		4,609
Impairments		517,896		347,021		479,240
Marketing Costs		5,351,524		5,203,243		3,330,237
Depreciation, Depletion and Amortization		3,749,704		3,435,408		3,409,387
General and Administrative		489,397		426,969		434,467
Taxes Other Than Income		800,164		772,481		544,662
Total		13,680,962		12,806,053		10,281,918
Operating Income		3,699,011		4,469,346		926,402
Other Income, Net		31,385		16,704		9,152
Income Before Interest Expense and Income Taxes		3,730,396		4,486,050		935,554
Interest Expense
Incurred		223,421		269,549		301,801
Capitalized		(38,292)		(24,497)		(27,429)
Net Interest Expense		185,129		245,052		274,372
Income Before Income Taxes		3,545,267		4,240,998		661,182
Income Tax Provision (Benefit)		810,357		821,958		(1,921,397)
Net Income		$ 2,734,910		$ 3,419,040		$ 2,582,579
Net Income (Loss) Per Share
Basic		$ 4.73		$ 5.93		$ 4.49
Diluted		$ 4.71		$ 5.89		$ 4.46
Average Number of Common Shares [Abstract]
Basic (in shares)		577,670		576,578		574,620
Diluted (in shares)		580,777		580,441		578,693
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments		$ (2,883)		$ 16,816		$ 2,799
Other, Net of Tax		(678)		1,123		(3,086)
Other Comprehensive Income (Loss)		(3,561)		17,939		(287)
Comprehensive Income		2,731,349		3,436,979		2,582,292
Crude Oil and Condensate
Operating Revenues and Other
Revenues		9,612,532		9,517,440		6,256,396
Natural Gas Liquids
Operating Revenues and Other
Revenues		784,818		1,127,510		729,561
Natural Gas
Operating Revenues and Other
Revenues		1,184,095		1,301,537		921,934
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts
Operating Revenues and Other
Revenues		180,275		(165,640)		19,828
Gathering, Processing and Marketing
Operating Revenues and Other
Revenues		5,360,282		5,230,355		3,298,087
Gains (Losses) on Asset Dispositions, Net
Operating Revenues and Other
Revenues		123,613		174,562		(99,096)
Other, Net
Operating Revenues and Other
Revenues		$ 134,358		$ 89,635		$ 81,610

[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, 2019.

[2] 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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Accounting For Certain Long-Lived Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Schedule of Impaired Long-Lived Assets Held and Used [Line Items]
Proved oil and gas properties carrying amount	$ 408	$ 139
Proved oil and gas properties, other property, plant and equipment, and other assets written down to fair value	201	18
Pretax impairment chages for proved oil and gas properties, other property, plant and equipment and other assets	207	121
Amortization and Impairments of Unproved Oil and Gas Property Including Amortization of Capitalized Interest	$ 220	$ 173	$ 211

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Stockholder's Equity (Details) - $ / shares			12 Months Ended
		Feb. 27, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
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		$ 0.2875	$ 0.22	$ 0.1850
Dividends Payable, Amount Per Share After Increase		$ 0.375	$ 0.2875	$ 0.22	$ 0.1675
Common Stock, Shares Authorized			1,280,000,000	1,280,000,000	1,280,000,000	640,000,000
Percentage increase of cash dividend on common stock				19.00%	10.00%
Common Stock Activity [Line Items]
Balance (in shares)			580,408,117
Balance (in shares)			582,213,016	580,408,117
Preferred Stock, Shares Outstanding			0
Common Shares, Outstanding [Member]
Common Stock Activity [Line Items]
Balance (in shares)			580,023,000	578,477,000	576,700,000
Common Stock Issued Under Stock-Based Compensation Plans (in shares)			1,688,000	1,580,000	1,878,000
Treasury Stock Purchased (1) (in shares)	[1]		(310,000)	(539,000)	(686,000)
Common Stock Issued Under Employee Stock Purchase Plan (in shares)			223,000	180,000	180,000
Treasury Stock Issued Under Stock-Based Compensation Plans (in shares)			290,000	325,000	405,000
Balance (in shares)			581,914,000	580,023,000	578,477,000
Common Shares, Treasury [Member]
Common Stock Activity [Line Items]
Balance (in shares)			(385,000)	(351,000)	(250,000)
Common Stock Issued Under Stock-Based Compensation Plans (in shares)			0	0	0
Treasury Stock Purchased (1) (in shares)	[1]		(310,000)	(539,000)	(686,000)
Common Stock Issued Under Employee Stock Purchase Plan (in shares)			106,000	180,000	180,000
Treasury Stock Issued Under Stock-Based Compensation Plans (in shares)			290,000	325,000	405,000
Balance (in shares)			(299,000)	(385,000)	(351,000)
Common Shares, Issued [Member]
Common Stock Activity [Line Items]
Balance (in shares)			580,408,000	578,828,000	576,950,000
Common Stock Issued Under Stock-Based Compensation Plans (in shares)			1,688,000	1,580,000	1,878,000
Treasury Stock Purchased (1) (in shares)	[1]		0	0	0
Common Stock Issued Under Employee Stock Purchase Plan (in shares)			117,000	0	0
Treasury Stock Issued Under Stock-Based Compensation Plans (in shares)			0	0	0
Balance (in shares)			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, performance unit grants or (ii) in payment of the exercise price of employee stock options.

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Oil and Gas Exploration and Production Industries Disclosures (Tables)

12 Months Ended

Dec. 31, 2019

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, 2019, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2019, 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, 2016	1,168,491		839		8,255		1,177,585
Revisions of previous estimates	57,935		80		(179	)	57,836
Purchases in place	1,111		—		—		1,111
Extensions, discoveries and other additions	207,137		301		119		207,557
Sales in place	(8,393	)	—		—		(8,393	)
Production	(122,210	)	(322	)	(191	)	(122,723	)
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
Natural Gas Liquids (MBbl) (2)
Net proved reserves at December 31, 2016	416,366		—		—		416,366
Revisions of previous estimates	46,843		—		—		46,843
Purchases in place	421		—		—		421
Extensions, discoveries and other additions	75,003		—		—		75,003
Sales in place	(2,887	)	—		—		(2,887	)
Production	(32,273	)	—		—		(32,273	)
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

	United States		Trinidad		Other International (1)		Total
Natural Gas (Bcf) (3)
Net proved reserves at December 31, 2016	3,021.2		280.9		15.8		3,317.9
Revisions of previous estimates	602.8		(27.4	)	8.6		584.0
Purchases in place	4.8		—		—		4.8
Extensions, discoveries and other additions	619.3		174.2		35.9		829.4
Sales in place	(56.4	)	—		—		(56.4	)
Production	(293.2	)	(114.3	)	(9.1	)	(416.6	)
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
Oil Equivalents (MBoe) (2)
Net proved reserves at December 31, 2016	2,088,392		47,661		10,880		2,146,933
Revisions of previous estimates	205,262		(4,493	)	1,249		202,018
Purchases in place	2,332		—		—		2,332
Extensions, discoveries and other additions	385,354		29,340		6,104		420,798
Sales in place	(20,687	)	—		—		(20,687	)
Production	(203,351	)	(19,366	)	(1,707	)	(224,424	)
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

(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, 2016	507,531	839	8,255	516,625
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
Natural Gas Liquids (MBbl)
December 31, 2016	230,219	—	—	230,219
December 31, 2017	286,872	—	—	286,872
December 31, 2018	341,386	—	—	341,386
December 31, 2019	387,253	—	—	387,253
Natural Gas (Bcf)
December 31, 2016	1,804.4	262.2	15.8	2,082.4
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
Oil Equivalents (MBoe)
December 31, 2016	1,038,483	44,543	10,880	1,093,906
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
NET PROVED UNDEVELOPED RESERVES
Crude Oil (MBbl)
December 31, 2016	660,690	—	—	660,690
December 31, 2017	698,666	—	71	698,737
December 31, 2018	819,466	—	61	819,527
December 31, 2019	892,771	—	48	892,819
Natural Gas Liquids (MBbl)
December 31, 2016	186,147	—	—	186,147
December 31, 2017	216,601	—	—	216,601
December 31, 2018	272,943	—	—	272,943
December 31, 2019	352,439	—	—	352,439
Natural Gas (Bcf)
December 31, 2016	1,216.8	18.7	—	1,235.5
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
Oil Equivalents (MBoe)
December 31, 2016	1,049,909	3,118	—	1,053,027
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

(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 proved undeveloped reserves during 2019, 2018 and 2017 (in MBoe):

	2019		2018		2017
Balance at January 1	1,379,709		1,162,635		1,053,027
Extensions and Discoveries	578,317		490,725		237,378
Revisions	(49,837	)	(8,244	)	33,127
Acquisition of Reserves	1,711		311		—
Sale of Reserves	—		—		(8,253	)
Conversion to Proved Developed Reserves	(302,044	)	(265,718	)	(152,644	)
Balance at December 31	1,607,856		1,379,709		1,162,635

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, 2019 and 2018:

	2019			2018
Proved properties	$	59,229,686		$	53,624,809
Unproved properties	3,600,729			3,705,207
Total	62,830,415			57,330,016
Accumulated depreciation, depletion and amortization	(35,033,085		)	(31,674,085		)
Net capitalized costs	$	27,797,330		$	25,655,931

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, 2019, 2018 and 2017:

	United States		Trinidad			Other International (1)		Total
2019
Acquisition Costs of Properties
Unproved (2)	$	276,092	$	—		$	—	$	276,092
Proved (3)	379,938		—			—		379,938
Subtotal	656,030		—			—		656,030
Exploration Costs	213,505		46,616			13,218		273,339
Development Costs (4)	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 (5)	$	486,081	$	1,258		$	—	$	487,339
Proved (6)	123,684		—			—		123,684
Subtotal	609,765		1,258			—		611,023
Exploration Costs	157,222		22,511			13,895		193,628
Development Costs (7)	5,605,264		(12,863		)	22,628		5,615,029
Total	$	6,372,251	$	10,906		$	36,523	$	6,419,680
2017
Acquisition Costs of Properties
Unproved (8)	$	424,118	$	2,422		$	—	$	426,540
Proved (9)	72,584		—			—		72,584
Subtotal	496,702		2,422			—		499,124
Exploration Costs	144,499		62,547			16,553		223,599
Development Costs (10)	3,590,899		109,491			16,297		3,716,687
Total	$	4,232,100	$	174,460		$	32,850	$	4,439,410

(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.

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

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

(4) 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.

(5) Includes non-cash unproved leasehold acquisition costs of $291 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 $90 million, $(12) million and $(8) 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 $256 million related to property exchanges.

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

(10) Includes Asset Retirement Costs of $50 million, $2 million and $4 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

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, 2019, 2018 and 2017:

	United States		Trinidad			Other International (2)			Total
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
2017
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	7,570,768	$	284,673		$	52,450		$	7,907,891
Other	81,610		59			(59		)	81,610
Total	7,652,378		284,732			52,391			7,989,501
Exploration Costs	113,334		26,245			5,763			145,342
Dry Hole Costs	91		—			4,518			4,609
Transportation Costs	737,403		1,885			1,064			740,352
Production Costs	1,446,333		27,839			88,038			1,562,210
Impairments	477,223		—			2,017			479,240
Depreciation, Depletion and Amortization	3,157,056		115,174			24,536			3,296,766
Income (Loss) Before Income Taxes	1,720,938		113,589			(73,545		)	1,760,982
Income Tax Provision (Benefit)	625,562		24,882			(1,342		)	649,102
Results of Operations	$	1,095,376	$	88,707		$	(72,203	)	$	1,111,880

(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, 2019.

(2) 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.

(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, 2019, 2018 and 2017:

	United States		Trinidad		Other International (1)		Composite
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
Year Ended December 31, 2017	$	4.58	$	1.39	$	50.86	$	4.66

(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, 2019, 2018 and 2017:

	United States			Trinidad			Other International (1)			Total
2019
Future cash inflows (2)	$	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 (3)	$	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
2017
Future cash inflows (4)	$	83,652,363		$	904,141		$	664,560		$	85,221,064
Future production costs	(32,018,812		)	(239,213		)	(311,383		)	(32,569,408		)
Future development costs	(13,395,873		)	(84,379		)	(58,543		)	(13,538,795		)
Future income taxes	(5,948,453		)	(195,855		)	(16,233		)	(6,160,541		)
Future net cash flows	32,289,225			384,694			278,401			32,952,320
Discount to present value at 10% annual rate	(14,532,290		)	(52,267		)	(40,103		)	(14,624,660		)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	17,756,935		$	332,427		$	238,298		$	18,327,660

(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 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) Estimated crude oil prices used to calculate 2017 future cash inflows for the United States, Trinidad and Other International were $49.21, $41.87 and $50.06, respectively. Estimated NGL price used to calculate 2017 future cash inflows for the United States was $23.51. Estimated natural gas prices used to calculate 2017 future cash inflows for the United States, Trinidad and Other International were $1.96, $2.76 and $5.16, 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, 2019:

	United States			Trinidad			Other International (1)			Total
December 31, 2016	$	8,493,727		$	185,750		$	132,680		$	8,812,157
Sales and transfers of oil and gas produced, net of production costs	(5,387,031		)	(254,948		)	36,649			(5,605,330		)
Net changes in prices and production costs	6,606,908			436,969			77,668			7,121,545
Extensions, discoveries, additions and improved recovery, net of related costs	3,644,041			270,255			43,952			3,958,248
Development costs incurred	1,435,600			4,700			—			1,440,300
Revisions of estimated development cost	(114,464		)	9,683			(20,096		)	(124,877		)
Revisions of previous quantity estimates	2,460,498			(58,373		)	36,146			2,438,271
Accretion of discount	849,373			24,066			13,268			886,707
Net change in income taxes	(1,918,989		)	(114,575		)	(10,099		)	(2,043,663		)
Purchases of reserves in place	30,362			—			—			30,362
Sales of reserves in place	(76,527		)	—			—			(76,527		)
Changes in timing and other	1,733,437			(171,100		)	(71,870		)	1,490,467
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

(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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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2019

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, 2019 and 2018. 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, 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
At December 31, 2018
Financial Assets (1):
Crude Oil Swaps	$	—	$	23,806	$	—	$	23,806

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Leases (Details) - USD ($) $ in Thousands	12 Months Ended
	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	$ 497,000
Amortization of Lease Assets	13,000
Interest on Lease Liabilities	2,000
Variable Lease Cost	138,000
Total Lease Cost	983,000
Lease Assets and Liabilities [Abstract]
Total	826,000
Current Liability	369,365	0
Total	857,000
Finance Lease Net of Accumulated Depreciation	36,938,066	33,475,162
Cash Flow Operating And Financing Activities [Abstract]
Operating Leases Non-Cash Leasing Activities	784,000
Operating And Finance Leases Future Minimum Payments [Abstract]
Operating And Finance Leases Not Yet Commenced	699,000
Operating And Finance Leases Liabilities Not Yet Commenced Due 2020	521,000
Operating And Finance Leases Liabilities Not Yet Commenced Due 2021	178,000
Capital Leases Future Minimum Payments Due [Abstract]
Short-term Lease Cost	333,000
Finance Leases
Lease Assets and Liabilities [Abstract]
Current Liability	15,000
Long-Term Liability	$ 43,000
Weighted Average Remaining Lease Term And Discount Rate [Abstract]
Finance Lease Weighted Average Remaining Lease Term (in years)	4 years 8 months 12 days
Finance Lease Weighted Average Discount Rate (%)	3.00%
Cash Flow Operating And Financing Activities [Abstract]
Repayment of Finance Lease Liabilities	$ 13,000
Operating And Finance Leases Future Minimum Payments [Abstract]
2020	15,000
2021	15,000
2022	12,000
2023	8,000
2024	8,000
2025 and Beyond	6,000
Total Lease Payments	64,000
Less: Discount to Present Value	6,000
Total Lease Liabilities	58,000
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	369,000
Long-Term Liability	$ 430,000
Weighted Average Remaining Lease Term And Discount Rate [Abstract]
Operating Lease Weighted Average Remaining Lease Term (in years)	3 years 2 months 12 days
Operating Lease Weighted Average Discount Rate (%)	3.50%
Operating And Finance Leases Future Minimum Payments [Abstract]
2020	$ 390,000
2021	209,000
2022	126,000
2023	56,000
2024	29,000
2025 and Beyond	40,000
Total Lease Payments	850,000
Less: Discount to Present Value	51,000
Total Lease Liabilities	799,000
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	225,000
Operating Leases [Member] | Investing Activities
Cash Flow Operating And Financing Activities [Abstract]
Repayment of Operating Lease Liabilities	$ 270,000
Maximum
Operating And Finance Leases Future Minimum Payments [Abstract]
Operating And Finance Leases Not Yet Commenced Lease Term	10 years
Property, Plant and Equipment
Lease Assets and Liabilities [Abstract]
Finance Lease Net of Accumulated Depreciation	$ 60,000
Property, Plant and Equipment | Finance Leases
Operating and Finance Leases [Line Items]
Operating Lease, Right-of-Use Asset	773,000
Lease Assets and Liabilities [Abstract]
Right-of-Use Asset	53,000
Current Portion of Operating Lease Liabilities | Operating Leases [Member]
Lease Assets and Liabilities [Abstract]
Current Liability	369,000
Current Portion of Long-Term Debt | Finance Leases
Lease Assets and Liabilities [Abstract]
Current Liability	15,000
Other Liabilities | Operating Leases [Member]
Lease Assets and Liabilities [Abstract]
Long-Term Liability	430,000
Long-term Debt [Member] | Finance Leases
Lease Assets and Liabilities [Abstract]
Long-Term Liability	$ 43,000

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Oil and Gas Exploration and Production Industries Disclosures, Average Sales Price (Details) - $ / bbl		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent		4.54	4.84	4.66
United States
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent		4.59	4.84	4.58
Trinidad
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent		1.85	1.67	1.39
Other International
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent	[1]	18.26	20.19	50.86

[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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Accounting For Certain Long-Lived Assets (Notes)

12 Months Ended

Dec. 31, 2019

Accounting For Certain Long-Lived Assets [Abstract]

Accounting For Certain Long-Lived Assets

Accounting for Certain Long-Lived Assets

EOG reviews its proved oil and gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the asset.  The carrying values for assets determined to be impaired were adjusted to estimated fair value 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 2019, proved oil and gas properties with a carrying amount of $408 million were written down to their fair value of $201 million, resulting in pretax impairment charges of $207 million. During 2018, proved oil and gas properties with a carrying amount of $139 million were written down to their fair value of $18 million, resulting in pretax impairment charges of $121 million. Impairments in 2019, 2018 and 2017 included domestic legacy natural gas assets. Amortization and impairments of unproved oil and gas property costs, including amortization of capitalized interest, were $220 million, $173 million and $211 million during 2019, 2018 and 2017, respectively.

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Leases (Notes)

12 Months Ended

Dec. 31, 2019

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 year ended December 31, 2019, were as follows (in millions):

	Year Ended December 31, 2019
Operating Lease Cost	$	497
Finance Lease Cost:
Amortization of Lease Assets	13
Interest on Lease Liabilities	2
Variable Lease Cost	138
Short-Term Lease Cost	333
Total Lease Cost	$	983

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

Description	Location on Balance Sheet	Amount
Assets
Operating Leases	Other Assets	$	773
Finance Leases	Property, Plant and Equipment, Net (1)	53
Total		$	826
Liabilities
Current
Operating Leases	Current Portion of Operating Lease Liabilities	$	369
Finance Leases	Current Portion of Long-Term Debt	15
Long-Term
Operating Leases	Other Liabilities	430
Finance Leases	Long-Term Debt	43
Total		$	857

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

	Year Ended December 31, 2019
Weighted Average Remaining Lease Term (in years):
Operating Leases	3.2
Finance Leases	4.7
Weighted Average Discount Rate:
Operating Leases	3.5	%
Finance Leases	3.0	%

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

	Year Ended December 31, 2019
Repayment of Operating Lease Liabilities Associated with Operating Activities	$	225
Repayment of Operating Lease Liabilities Associated with Investing Activities	270
Repayment of Finance Lease Liabilities	13

Upon adoption of ASU 2016-02 effective January 1, 2019, EOG recognized operating lease ROU assets of $566 million. Non-cash leasing activities for the twelve months ended December 31, 2019, included the addition of $784 million of operating leases.

At December 31, 2019, the future minimum lease payments under non-cancellable leases were as follows (in millions):

	Operating Leases		Finance Leases
2020	$	390	$	15
2021	209		15
2022	126		12
2023	56		8
2024	29		8
2025 and Beyond	40		6
Total Lease Payments	850		64
Less: Discount to Present Value	51		6
Total Lease Liabilities	799		58
Less: Current Portion of Lease Liabilities	369		15
Long-Term Lease Liabilities	$	430	$	43

At December 31, 2019, EOG had additional leases of $699 million, of which $521 million and $178 million were expected to commence in 2020 and 2021, respectively, with lease terms of one month to 10 years.

At December 31, 2018 and 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, 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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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Schedule of Impact of Adoption of New Accounting Revenue Recognition Standard (Tables)

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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Unaudited Quarterly Financial Information (Tables)

12 Months Ended

Dec. 31, 2019

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
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
2018
Operating Revenues and Other	$	3,681,162	$	4,238,077	$	4,781,624	$	4,574,536
Operating Income	$	874,588	$	964,931	$	1,506,687	$	1,123,140
Income Before Income Taxes	$	813,359	$	892,936	$	1,446,363	$	1,088,340
Income Tax Provision	174,770		196,205		255,411		195,572
Net Income	$	638,589	$	696,731	$	1,190,952	$	892,768
Net Income Per Share (1)
Basic	$	1.11	$	1.21	$	2.06	$	1.55
Diluted	$	1.10	$	1.20	$	2.05	$	1.54
Average Number of Common Shares
Basic	575,775		576,135		577,254		577,035
Diluted	579,726		580,375		581,559		580,288

(1)

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

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2019

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, 2019 and 2018 (in thousands):

	2019			2018
Carrying Amount at Beginning of Period	$	954,377		$	946,848
Liabilities Incurred	98,874			79,057
Liabilities Settled (1)	(58,673		)	(70,829		)
Accretion	43,462			36,622
Revisions	72,425			(38,932		)
Foreign Currency Translations	245			1,611
Carrying Amount at End of Period	$	1,110,710		$	954,377
Current Portion	$	37,127		$	26,214
Noncurrent Portion	$	1,073,583		$	928,163

(1) Includes settlements related to asset sales.

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Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss)		$ (4,652)	$ (1,358)
Cumulative Effect of Accounting Changes		0
Other Comprehensive Income (Loss)		(3,561)	17,939	$ (287)
Foreign Currency Translation Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss)		(2,709)	174	(16,642)
Cumulative Effect of Accounting Changes		0
Other Comprehensive Loss Before Reclassifications		(2,883)	2,451
Tax Effects		0	0
Other Comprehensive Income (Loss)		(2,883)	16,816
Significant Amount Reclassified Out of AOCI	[1]		14,365
Other [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss)		(1,943)	(1,532)	(2,655)
Cumulative Effect of Accounting Changes		267
Other Comprehensive Loss Before Reclassifications		(533)	1,131
Tax Effects		(145)	(8)
Other Comprehensive Income (Loss)		(678)	1,123
Significant Amount Reclassified Out of AOCI	[1]		0
Accumulated Other Comprehensive Income (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss)		(4,652)	(1,358)	(19,297)
Cumulative Effect of Accounting Changes		267
Other Comprehensive Loss Before Reclassifications		(3,416)	3,582
Tax Effects		(145)	(8)
Other Comprehensive Income (Loss)		$ (3,561)	17,939	$ (287)
Significant Amount Reclassified Out of AOCI	[1]		$ 14,365

[1] Reclassified to Net Income - Gains (Losses) on Asset Dispositions, Net. See Note 17.

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Acquisitions and Divestitures (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Business Combinations [Abstract]
Proceeds from Sale of Producing Properties	$ 140,292	$ 227,446	$ 226,768
Business Combination, Separately Recognized Transactions [Line Items]
Payments to Acquire Oil and Gas Property	328,000		73,000
Gains (Losses) on Asset Dispositions, Net	$ 123,613	$ 174,562	$ (99,096)

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Oil and Gas Exploration and Production Industries Disclosures, Results Of Operations (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
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]	$ 11,581,445		$ 11,946,487		$ 7,907,891
Other	[1]	134,358		89,635		81,610
Total	[1]	11,715,803		12,036,122		7,989,501
Exploration Costs	[1]	139,881		148,999		145,342
Dry Hole Costs	[1]	28,001		5,405		4,609
Transportation Costs	[1]	758,300		746,876		740,352
Gathering and Processing Costs		479,102	[1],[2]	436,973	[1],[2]	148,775
Production Costs	[1]	2,133,986		2,028,083		1,562,210
Impairments	[1]	517,896		347,021		479,240
Depreciation, Depletion and Amortization	[1]	3,657,597		3,320,276		3,296,766
Income (Loss) Before Income Taxes	[1]	4,001,040		5,002,489		1,760,982
Income Tax Provision (Benefit)	[1]	942,582		1,100,145		649,102
Results of Operations	[1]	3,058,458		3,902,344		1,111,880
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]	11,250,853		11,488,620		7,570,768
Other	[1]	134,325		89,708		81,610
Total	[1]	11,385,178		11,578,328		7,652,378
Exploration Costs	[1]	130,302		121,572		113,334
Dry Hole Costs	[1]	11,133		4,983		91
Transportation Costs	[1]	753,558		742,792		737,403
Gathering and Processing Costs	[1],[2]	479,102		404,471
Production Costs	[1]	2,063,078		1,924,504		1,446,333
Impairments	[1]	510,948		344,595		477,223
Depreciation, Depletion and Amortization	[1]	3,560,609		3,181,801		3,157,056
Income (Loss) Before Income Taxes	[1]	3,876,448		4,853,610		1,720,938
Income Tax Provision (Benefit)	[1]	884,450		1,086,077		625,562
Results of Operations	[1]	2,991,998		3,767,533		1,095,376
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]	269,957		302,112		284,673
Other	[1]	18		(49)		59
Total	[1]	269,975		302,063		284,732
Exploration Costs	[1]	4,290		21,402		26,245
Dry Hole Costs	[1]	13,033		0		0
Transportation Costs	[1]	4,014		3,236		1,885
Gathering and Processing Costs	[1],[2]	0		0
Production Costs	[1]	30,539		33,506		27,839
Impairments	[1]	5,713		0		0
Depreciation, Depletion and Amortization	[1]	79,156		91,788		115,174
Income (Loss) Before Income Taxes	[1]	133,230		152,131		113,589
Income Tax Provision (Benefit)	[1]	54,980		12,170		24,882
Results of Operations	[1]	78,250		139,961		88,707
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],[3]	60,635		155,755		52,450
Other	[1],[3]	15		(24)		(59)
Total	[1],[3]	60,650		155,731		52,391
Exploration Costs	[1],[3]	5,289		6,025		5,763
Dry Hole Costs	[1],[3]	3,835		422		4,518
Transportation Costs	[1],[3]	728		848		1,064
Gathering and Processing Costs	[1],[2],[3]	0		32,502
Production Costs	[1],[3]	40,369		70,073		88,038
Impairments	[1],[3]	1,235		2,426		2,017
Depreciation, Depletion and Amortization	[1],[3]	17,832		46,687		24,536
Income (Loss) Before Income Taxes	[1],[3]	(8,638)		(3,252)		(73,545)
Income Tax Provision (Benefit)	[1],[3]	3,152		1,898		(1,342)
Results of Operations	[1],[3]	$ (11,790)		$ (5,150)		$ (72,203)

[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, 2019.

[2] 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).

[3] 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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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2019

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).

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 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 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, natural gas liquids (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 Accounting Standards Update (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 and Comprehensive Income 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 and Comprehensive Income. 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		—

Revenue Recognition

Revenue Recognition. Effective January 1, 2018, EOG adopted the provisions of Accounting Standards Update (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 and Comprehensive Income 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 and Comprehensive Income. 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 on January 1, 2019 and December 31, 2019, were $1,460 million and $1,619 million, respectively, and are included in Accounts Receivable, Net on the Consolidated Balance Sheets. Losses incurred on receivables from contracts with customers are infrequent and have been immaterial.

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, crude-by-rail assets, sand mine and 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, 2019, 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 and Comprehensive Income.  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 Per Share

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

Stock-Based Compensation

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

Leases

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 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 is continuing to evaluate the provisions of ASU 2019-12 and has not determined the full impact on its consolidated financial statements and related disclosures.

In June 2016, the FASB issued 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. ASU 2016-13 requires adoption through the use of a modified retrospective approach at the effective date by recognizing a cumulative-effect adjustment to the opening balance of retained earnings. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019, and early adoption is permitted. EOG has assessed its applicable financial assets, which are primarily its accounts receivable from hydrocarbon sales and joint interest billings to third-party companies, including state-owned entities in the oil and gas industry. Based on its assessment and various potential remedies ensuring collection, EOG does not expect the impact from forward-looking expected losses will be material. EOG will apply the provisions of ASU 2016-13 on the adoption date, January 1, 2020.

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Fair Value Measurements (Notes)

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

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

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, 2019 and 2018. 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, 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
At December 31, 2018
Financial Assets (1):
Crude Oil Swaps	$	—	$	23,806	$	—	$	23,806

(1) $1 million and $24 million are included in "Current Assets - Assets from Price Risk Management Activities" at December 31, 2019 and 2018, respectively, on the Consolidated Balance Sheets.

(2) $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.

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.

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 impairment charges in 2019 of $90 million for a commodity price-related write-down of other assets.

During 2018, proved oil and gas properties; other property, plant and equipment; and other assets with a carrying amount of $482 million were written down to their fair value of $308 million, resulting in pretax impairment charges of $174 million. Included in the $174 million pretax impairment charges are $104 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 2018 of $49 million for a commodity price-related write-down of other assets.

Significant Level 3 inputs associated with the calculation of discounted cash flows used in the impairment analysis include EOG's estimate of future crude oil, NGLs and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data.

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, 2019 and 2018, respectively, EOG had outstanding $5,140 million and $6,040 million aggregate principal amount of senior notes, which had estimated fair values of approximately $5,452 million and $6,027 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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Acquisitions and Divestitures (Notes)

12 Months Ended

Dec. 31, 2019

Business Combinations [Abstract]

Acquisitions and Divestitures

Acquisitions and Divestitures

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 a net gain 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.

During 2017, EOG recognized a net loss on asset dispositions of $99 million and received proceeds of approximately $227 million primarily from sales of producing properties, other assets and acreage in Texas and Oklahoma.

Also during 2017, EOG completed acquisitions of approximately $73 million to acquire producing properties in various areas in the United States.

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Other Income, Net (Notes)

12 Months Ended

Dec. 31, 2019

Other Income and Expenses [Abstract]

Other Income, Net

Other Income, NetOther 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). Other income, net for 2017 included net foreign currency transaction gains ($8 million), interest income ($8 million) and equity income from investments in ammonia plants in Trinidad ($3 million), partially offset by an upward adjustment to deferred compensation expense ($6 million).

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Net Income Per Share (Notes)

12 Months Ended

Dec. 31, 2019

Earnings Per Share [Abstract]

Net Income (Loss) Per Share

Net Income Per Share

The following table sets forth the computation of Net Income Per Share for the years ended December 31, 2019, 2018 and 2017 (in thousands, except per share data):

	2019		2018		2017
Numerator for Basic and Diluted Earnings per Share -
Net Income	$	2,734,910	$	3,419,040	$	2,582,579
Denominator for Basic Earnings per Share -
Weighted Average Shares	577,670		576,578		574,620
Potential Dilutive Common Shares -
Stock Options/SARs	258		1,137		1,466
Restricted Stock/Units and Performance Units	2,849		2,726		2,607
Denominator for Diluted Earnings per Share -
Adjusted Diluted Weighted Average Shares	580,777		580,441		578,693
Net Income Per Share
Basic	$	4.73	$	5.93	$	4.49
Diluted	$	4.71	$	5.89	$	4.46

The diluted earnings per share calculation excludes stock options, SARs, restricted stock and units and performance units that were anti-dilutive.  Shares underlying the excluded stock options and SARs totaled 6.1 million, 0.6 million and 2.6 million for the years ended December 31, 2019, 2018 and 2017, respectively.

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Minimum commitments for unrecorded unconditional purchase obligations

At December 31, 2019, 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, 2019, were as follows (in millions):

	Total Minimum Commitments
2020	$	1,312
2021	1,103
2022	1,027
2023	764
2024	519
2025 and beyond	2,531
	$	7,256

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Stockholder's Equity (Tables)

12 Months Ended

Dec. 31, 2019

Stockholders' Equity Note [Abstract]

Common stock activity

The following summarizes Common Stock activity for each of the years ended December 31, 2017, 2018 and 2019 (in thousands):

	Common Shares
	Issued	Treasury		Outstanding
Balance at December 31, 2016	576,950	(250	)	576,700
Common Stock Issued Under Stock-Based Compensation Plans	1,878	—		1,878
Treasury Stock Purchased (1)	—	(686	)	(686	)
Common Stock Issued Under Employee Stock Purchase Plan	—	180		180
Treasury Stock Issued Under Stock-Based Compensation Plans	—	405		405
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

(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, performance unit grants or (ii) in payment of the exercise price of employee stock options.

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Risk Management Activities (Tables)

12 Months Ended

Dec. 31, 2019

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, 2019 and 2018, 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	2019		2018
Asset Derivatives
Crude oil, NGLs and natural gas derivative contracts -
Current portion	Assets from Price Risk Management Activities (1)	$	1,299	$	23,806
Liability Derivatives
Crude oil, NGLs and natural gas derivative contracts -
Current portion	Liabilities from Price Risk Management Activities (2)	$	20,194	$	—

(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 [Member] | Midland Differential Basis Swap [Member]

Derivatives, Fair Value [Line Items]

Schedule of Derivative Instruments

Presented below is a comprehensive summary of EOG's Midland Differential basis swap contracts for the year ended December 31, 2019. The weighted average price differential expressed in dollars per barrel ($/Bbl) represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in barrels per day (Bbld) covered by the basis swap contracts.

Midland Differential Basis Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)
2019
January 1, 2019 through December 31, 2019 (closed)	20,000	$	1.075

Crude Oil [Member] | Gulf Coast Differential Basis Swap [Member]

Derivatives, Fair Value [Line Items]

Schedule of Derivative Instruments

Presented below is a comprehensive summary of EOG's Gulf Coast Differential basis swap contracts for the year ended December 31, 2019. 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.

Gulf Coast Differential Basis Swap Contracts
	Volume (Bbld)	Weighted Average Price Differential ($/Bbl)
2019
January 1, 2019 through December 31, 2019 (closed)	13,000	$	5.572

Crude Oil [Member] | Price Swap [Member]

Derivatives, Fair Value [Line Items]

Schedule of Derivative Instruments

Presented below is a comprehensive summary of EOG's crude oil price swap contracts for the year ended December 31, 2019, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

Crude Oil Price Swap Contracts
	Volume (Bbld)	Weighted Average Price ($/Bbl)
2019
April 2019 (closed)	25,000	$	60.00
May 1, 2019 through December 31, 2019 (closed)	150,000	62.50
2020
January 1, 2020 through March 31, 2020	200,000	$	59.33
April 1, 2020 through June 30, 2020	150,000	59.03
July 1, 2020 through September 30, 2020	50,000	58.32

Mont Belvieu Propane Price Swap [Member] | Price Swap [Member]

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 for the year ended December 31, 2019, 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 December 31, 2020	4,000	$	21.34

Natural Gas [Member] | Price Swap [Member]

Derivatives, Fair Value [Line Items]

Schedule of Derivative Instruments

Presented below is a comprehensive summary of EOG's natural gas price swap contracts for the year ended December 31, 2019, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).

Natural Gas Price Swap Contracts
	Volume (MMBtud)	Weighted Average Price ($/MMBtu)
2019
April 1, 2019 through October 31, 2019 (closed)	250,000	$	2.90

Natural Gas [Member] | Rockies Differential Basis Swaps [Member]

Derivatives, Fair Value [Line Items]

Schedule of Derivative Instruments

Presented below is a comprehensive summary of EOG's Rockies Differential basis swap contracts for the year ended December 31, 2019. 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	30,000	$	0.55

Natural Gas [Member] | HSC Differential Basis Swaps [Member]

Derivatives, Fair Value [Line Items]

Schedule of Derivative Instruments

Presented below is a comprehensive summary of EOG's HSC Differential basis swap contracts for the year ended December 31, 2019. 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	60,000	$	0.05

Natural Gas [Member] | Waha Differential Basis Swaps [Member]

Derivatives, Fair Value [Line Items]

Schedule of Derivative Instruments

Presented below is a comprehensive summary of EOG's Waha Differential basis swap contracts for the year ended December 31, 2019. 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 December 31, 2020	50,000	$	1.40

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Consolidated Statements of Cash Flows - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash Flows from Operating Activities
Net Income		$ 2,734,910	$ 3,419,040	$ 2,582,579
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization		3,749,704	3,435,408	3,409,387
Impairments		517,896	347,021	479,240
Stock-Based Compensation Expenses		174,738	155,337	133,849
Deferred Income Taxes		631,658	894,156	(1,473,872)
(Gains) Losses on Asset Dispositions, Net		(123,613)	(174,562)	99,096
Other, Net		4,496	7,066	6,546
Dry Hole Costs	[1]	28,001	5,405	4,609
Mark-to-Market Commodity Derivative Contracts
Total (Gains) Losses		(180,275)	165,640	(19,828)
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts		231,229	(258,906)	7,438
Other, Net		962	3,108	1,204
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		(91,792)	(368,180)	(392,131)
Inventories		90,284	(395,408)	(174,548)
Accounts Payable		168,539	439,347	324,192
Accrued Taxes Payable		40,122	(92,461)	(63,937)
Other Assets		358,001	(125,435)	(658,609)
Other Liabilities		(56,619)	10,949	(89,871)
Changes in Components of Working Capital Associated with Investing and Financing Activities		(115,061)	301,083	89,992
Net Cash Provided by Operating Activities		8,163,180	7,768,608	4,265,336
Investing Cash Flows
Additions to Oil and Gas Properties		(6,151,885)	(5,839,294)	(3,950,918)
Additions to Other Property, Plant and Equipment		(270,641)	(237,181)	(173,324)
Proceeds from Sales of Assets		140,292	227,446	226,768
Payments for (Proceeds from) Other Investing Activities		(10,000)	(19,993)	0
Changes in Components of Working Capital Associated with Investing Activities		115,061	(301,140)	(89,935)
Net Cash Used in Investing Activities		(6,177,173)	(6,170,162)	(3,987,409)
Financing Cash Flows
Long-Term Debt Repayments		(900,000)	(350,000)	(600,000)
Dividends Paid		(588,200)	(438,045)	(386,531)
Treasury Stock Purchased		(25,152)	(63,456)	(63,408)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan		17,946	20,560	20,840
Debt Issuance Costs		(5,016)	0	0
Repayment of Capital Lease Obligation		(12,899)	(8,219)	(6,555)
Other, Net		0	57	(57)
Net Cash Used in Financing Activities		(1,513,321)	(839,103)	(1,035,711)
Effect of Exchange Rate Changes on Cash		(348)	(37,937)	(7,883)
Increase (Decrease) in Cash and Cash Equivalents		472,338	721,406	(765,667)
Cash and Cash Equivalents at Beginning of Year		1,555,634	834,228	1,599,895
Cash and Cash Equivalents at End of Year		$ 2,027,972	$ 1,555,634	$ 834,228

[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, 2019.

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Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current Assets
Cash and Cash Equivalents	$ 2,027,972	$ 1,555,634
Accounts Receivable, Net	2,001,658	1,915,215
Inventories	767,297	859,359
Assets from Price Risk Management Activities	1,299	23,806
Income Taxes Receivable	151,665	427,909
Other	323,448	275,467
Total	5,273,339	5,057,390
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)	62,830,415	57,330,016
Other Property, Plant and Equipment	4,472,246	4,220,665
Total Property, Plant and Equipment	67,302,661	61,550,681
Less: Accumulated Depreciation, Depletion and Amortization	(36,938,066)	(33,475,162)
Total Property, Plant and Equipment, Net	30,364,595	28,075,519
Deferred Income Taxes	2,363	777
Other Assets	1,484,311	800,788
Total Assets	37,124,608	33,934,474
Current Liabilities
Accounts Payable	2,429,127	2,239,850
Accrued Taxes Payable	254,850	214,726
Dividends Payable	166,273	126,971
Liabilities from Price Risk Management Activities	20,194	0
Current Portion of Long-Term Debt	1,014,524	913,093
Operating Lease, Liability, Current	369,365	0
Other	232,655	233,724
Total	4,486,988	3,728,364
Long-Term Debt	4,160,919	5,170,169
Other Liabilities	1,789,884	1,258,355
Deferred Income Taxes	5,046,101	4,413,398
Commitments and Contingencies (Note 8)
Stockholders' Equity
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 582,213,016 Shares and 580,408,117 Shares Issued at December 31, 2019 and 2018, respectively	205,822	205,804
Additional Paid in Capital	5,817,475	5,658,794
Accumulated Other Comprehensive Loss	(4,652)	(1,358)
Retained Earnings	15,648,604	13,543,130
Common Stock Held in Treasury, 298,820 Shares and 385,042 Shares at December 31, 2019 and 2018, respectively	(26,533)	(42,182)
Total Stockholders' Equity	21,640,716	19,364,188
Total Liabilities and Stockholders' Equity	37,124,608	$ 33,934,474
Property, Plant and Equipment [Member]
Property, Plant and Equipment
Less: Accumulated Depreciation, Depletion and Amortization	$ (60,000)

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Fair Value Measurements (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
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	$ 998,000	$ 482,000
Proved oil and gas properties, other property, plant and equipment and other assets written down during the period - fair value at end of period	701,000	308,000
Pretax impairment charges for proved oil and gas properties and other assets, in which EOG utilized an accepted offer from a third-party purchaser	152,000	104,000
Pretax impairment charge for a commodity price-related write-down of other assets	90,000	49,000
Pretax impairment charges for proved oil and gas properties, other property, plant and equipment and other assets	297,000	174,000
Debt Disclosure [Abstract]
Aggregate Principal Amount of Current and Long-Term Debt	5,140,000	6,040,000
Debt Instrument, Fair Value Disclosure	5,452,000	6,027,000
Assets From Price Risk Management Activities [Member]
Financial Assets:
Assets, Fair Value Disclosure	1,000	24,000
Liabilities From Price Risk Management Activities [Member]
Financial Liabilities:
Liabilities, Fair Value Disclosure	20,000
Commodity Contract [Member] | Crude Oil [Member] | Price Swap [Member]
Financial Assets:
Assets, Fair Value Disclosure		23,806
Financial Liabilities:
Liabilities, Fair Value Disclosure	23,266
Commodity Contract [Member] | Crude Oil [Member] | Price Swap [Member] | Fair Value, Inputs, Level 1 [Member]
Financial Assets:
Assets, Fair Value Disclosure		0
Financial Liabilities:
Liabilities, Fair Value Disclosure	0
Commodity Contract [Member] | Crude Oil [Member] | Price Swap [Member] | Fair Value, Inputs, Level 2 [Member]
Financial Assets:
Assets, Fair Value Disclosure		23,806
Financial Liabilities:
Liabilities, Fair Value Disclosure	23,266
Commodity Contract [Member] | Crude Oil [Member] | Price Swap [Member] | Fair Value, Inputs, Level 3 [Member]
Financial Assets:
Assets, Fair Value Disclosure		$ 0
Financial Liabilities:
Liabilities, Fair Value Disclosure	0
Commodity Contract [Member] | Natural Gas Liquids | Price Swap [Member]
Financial Assets:
Assets, Fair Value Disclosure	3,401
Commodity Contract [Member] | Natural Gas Liquids | Price Swap [Member] | Fair Value, Inputs, Level 1 [Member]
Financial Assets:
Assets, Fair Value Disclosure	0
Commodity Contract [Member] | Natural Gas Liquids | Price Swap [Member] | Fair Value, Inputs, Level 2 [Member]
Financial Assets:
Assets, Fair Value Disclosure	3,401
Commodity Contract [Member] | Natural Gas Liquids | Price Swap [Member] | Fair Value, Inputs, Level 3 [Member]
Financial Assets:
Assets, Fair Value Disclosure	0
Commodity Contract [Member] | Natural Gas [Member] | Basis Swaps [Member]
Financial Assets:
Assets, Fair Value Disclosure	970
Commodity Contract [Member] | Natural Gas [Member] | Basis Swaps [Member] | Fair Value, Inputs, Level 1 [Member]
Financial Assets:
Assets, Fair Value Disclosure	0
Commodity Contract [Member] | Natural Gas [Member] | Basis Swaps [Member] | Fair Value, Inputs, Level 2 [Member]
Financial Assets:
Assets, Fair Value Disclosure	970
Commodity Contract [Member] | Natural Gas [Member] | Basis Swaps [Member] | Fair Value, Inputs, Level 3 [Member]
Financial Assets:
Assets, Fair Value Disclosure	$ 0

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Other Income, Net (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Other Income and Expenses [Abstract]
Interest income	$ 26	$ 12	$ 8
Adjustment to Deferred Compensation Expense		6	(6)
Net Foreign Currency Transaction Gains (Losses)	$ 2	(7)	8
Equity income from investments in Trinidad		$ 2	$ 3

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Net Income Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2019		Sep. 30, 2019		Jun. 30, 2019		Mar. 31, 2019		Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Numerator for Basic and Diluted Earnings per Share - [Abstract]
Net Income	$ 636,521		$ 615,122		$ 847,841		$ 635,426		$ 892,768		$ 1,190,952		$ 696,731		$ 638,589		$ 2,734,910	$ 3,419,040	$ 2,582,579
Denominator for Basic Earnings per Share - [Abstract]
Weighted Average Shares	578,219		577,839		577,460		577,207		577,035		577,254		576,135		575,775		577,670	576,578	574,620
Denominator for Diluted Earnings per Share - [Abstract]
Adjusted Diluted Weighted Average Shares	580,849		581,271		580,247		580,222		580,288		581,559		580,375		579,726		580,777	580,441	578,693
Antidilutive Securities Excluded from Computation of Earnings Per Share [Abstract]
Anti-dilutive Securities excluded from Diluted Earnings Per Share Calculation																	6,100	600	2,600
Net Income (Loss) Per Share [Abstract]
Basic	$ 1.10	[1]	$ 1.06	[1]	$ 1.47	[1]	$ 1.10	[1]	$ 1.55	[1]	$ 2.06	[1]	$ 1.21	[1]	$ 1.11	[1]	$ 4.73	$ 5.93	$ 4.49
Diluted	$ 1.10	[1]	$ 1.06	[1]	$ 1.46	[1]	$ 1.10	[1]	$ 1.54	[1]	$ 2.05	[1]	$ 1.20	[1]	$ 1.10	[1]	$ 4.71	$ 5.89	$ 4.46
Stock Options and Sars [Member]
Potential Dilutive Common Shares -[Abstract]
Common Shares Attributable to Dilutive Effect of Share-Based Payment Arrangments																	258	1,137	1,466
Restricted Stock/Units and Performance Units/Stock [Member]
Potential Dilutive Common Shares -[Abstract]
Common Shares Attributable to Dilutive Effect of Share-Based Payment Arrangments																	2,849	2,726	2,607

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