EOG Resources (EOG) 10-K 24 Feb 22 2021 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Feb. 11, 2022	Jun. 30, 2021
Cover [Abstract]
Document Type	10-K
Entity Registrant Name	EOG RESOURCES, INC.
Document Annual Report	true
Document Transition Report	false
Entity Central Index Key	0000821189
Entity File Number	1-9743
Document Period End Date	Dec. 31, 2021
Current Fiscal Year End Date	--12-31
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2021
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
ICFR Auditor Attestation Flag	true
Entity Public Float			$ 48,608
Entity Common Stock, Shares Outstanding		585,419,164
Documents Incorporated by Reference	Documents incorporated by reference. Portions of the Definitive Proxy Statement for the registrant's 2022 Annual Meeting of Stockholders, to be filed within 120 days after December 31, 2021, are incorporated by reference into Part III of this report.

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2021
Auditor Information [Abstract]
Auditor Name	DELOITTE & TOUCHE LLP
Auditor Location	Houston, Texas
Auditor Firm ID	34

Consolidated Statements of Inco

Consolidated Statements of Income and Comprehensive Income - USD ($) shares in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2021		Dec. 31, 2020		Dec. 31, 2019
Operating Revenues and Other
Total		$ 18,642		$ 11,032		$ 17,380
Operating Expenses
Lease and Well		1,135		1,063		1,367
Transportation Costs	[1]	863		735		758
Gathering and Processing Costs		559	[1]	459	[1]	479
Exploration Costs		154		146		140
Dry Hole Costs	[1]	71		13		28
Impairments		376		2,100		518
Marketing Costs		4,173		2,698		5,352
Depreciation, Depletion and Amortization		3,651		3,400		3,750
General and Administrative		511		484		489
Taxes Other Than Income		1,047		478		800
Total		12,540		11,576		13,681
Operating Income (Loss)		6,102		(544)		3,699
Other Income, Net		9		10		31
Income (Loss) Before Interest Expense and Income Taxes		6,111		(534)		3,730
Interest Expense
Incurred		211		236		223
Capitalized		(33)		(31)		(38)
Net Interest Expense		178		205		185
Income (Loss) Before Income Taxes		5,933		(739)		3,545
Income Tax Provision (Benefit)		1,269		(134)		810
Net Income (Loss)		$ 4,664		$ (605)		$ 2,735
Net Income (Loss) Per Share
Basic		$ 8.03		$ (1.04)		$ 4.73
Diluted		$ 7.99		$ (1.04)		$ 4.71
Average Number of Common Shares [Abstract]
Basic (in shares)		581		579		578
Diluted (in shares)		584		579		581
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments		$ (1)		$ (7)		$ (3)
Other, Net of Tax		1		0		0
Other Comprehensive Loss		0		(7)		(3)
Comprehensive Income (Loss)		4,664		(612)		2,732
Crude Oil and Condensate
Operating Revenues and Other
Revenues		11,125		5,786		9,613
Natural Gas Liquids
Operating Revenues and Other
Revenues		1,812		668		785
Natural Gas
Operating Revenues and Other
Revenues		2,444		837		1,184
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts
Operating Revenues and Other
Revenues		(1,152)		1,145		180
Gathering, Processing and Marketing
Operating Revenues and Other
Revenues		4,288		2,583		5,360
Gains (Losses) on Asset Dispositions, Net
Operating Revenues and Other
Revenues		17		(47)		124
Other, Net
Operating Revenues and Other
Revenues		$ 108		$ 60		$ 134
[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, 2021.

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Current Assets
Cash and Cash Equivalents	$ 5,209	$ 3,329
Accounts Receivable, after Allowance for Credit Loss, Current	2,335	1,522
Inventories	584	629
Assets from Price Risk Management Activities	0	65
Income Taxes Receivable	0	23
Other	456	294
Total	8,584	5,862
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)	67,644	64,793
Other Property, Plant and Equipment	4,753	4,479
Total Property, Plant and Equipment	72,397	69,272
Less: Accumulated Depreciation, Depletion and Amortization	(43,971)	(40,673)
Total Property, Plant and Equipment, Net	28,426	28,599
Deferred Income Taxes	11	2
Other Assets	1,215	1,342
Total Assets	38,236	35,805
Current Liabilities
Accounts Payable	2,242	1,681
Accrued Taxes Payable	518	206
Dividends Payable	436	217
Liabilities from Price Risk Management Activities	269	0
Current Portion of Long-Term Debt	37	781
Current Portion of Operating Lease Liabilities	240	295
Other	300	280
Total	4,042	3,460
Long-Term Debt	5,072	5,035
Other Liabilities	2,193	2,149
Deferred Income Taxes	4,749	4,859
Commitments and Contingencies (Note 8)
Stockholders' Equity
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 585,521,512 Shares and 583,694,850 Shares Issued at December 31, 2021 and 2020, respectively	206	206
Additional Paid in Capital	6,087	5,945
Accumulated Other Comprehensive Loss	(12)	(12)
Retained Earnings	15,919	14,170
Common Stock Held in Treasury, 257,268 Shares and 124,265 Shares at December 31, 2021 and 2020, respectively	(20)	(7)
Total Stockholders' Equity	22,180	20,302
Total Liabilities and Stockholders' Equity	$ 38,236	$ 35,805

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2021	Dec. 31, 2020
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)	585,521,512	583,694,850
Treasury Stock
Common Stock Held in Treasury (in shares)	257,268	124,265

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity - USD ($) $ in Millions	Total	Common Stock	Additional Paid-in Capital	Accumulated Other Comprehensive Income (Loss)	Retained Earnings	Treasury Stock, Common
Balance at Dec. 31, 2018	$ 19,364	$ 206	$ 5,659	$ (2)	$ 13,543	$ (42)
Net Income (Loss)	2,735	0	0	0	2,735	0
Common Stock Issued Under Stock Plans	0	0	0	0	0	0
Common Stock Dividends Declared	(629)	0	0	0	(629)	0
Other Comprehensive Income (Loss)	(3)	0	0	(3)	0	0
Change in Treasury Stock - Stock Compensation Plans, Net	(8)	0	(11)	0	0	3
Restricted Stock and Restricted Stock Units, Net	0		(5)	0	0	5
Stock-Based Compensation Expenses	175	0	175	0	0	0
Treasury Stock Issued as Compensation	6	0	(1)	0	0	7
Balance at Dec. 31, 2019	$ 21,640	206	5,817	(5)	15,649	(27)
Common Stock Dividends Declared (in dollars per share)	$ 1.0825
Net Income (Loss)	$ (605)	0	0	0	(605)	0
Common Stock Issued Under Stock Plans	0	0	0	0	0	0
Common Stock Dividends Declared	(874)	0	0	0	(874)	0
Other Comprehensive Income (Loss)	(7)	0	0	(7)	0	0
Change in Treasury Stock - Stock Compensation Plans, Net	0	0	(9)	0	0	9
Restricted Stock and Restricted Stock Units, Net	0	0	(9)	0	0	9
Stock-Based Compensation Expenses	146	0	146	0	0	0
Treasury Stock Issued as Compensation	2	0	0	0	0	2
Balance at Dec. 31, 2020	$ 20,302	206	5,945	(12)	14,170	(7)
Common Stock Dividends Declared (in dollars per share)	$ 1.50
Net Income (Loss)	$ 4,664	0	0	0	4,664	0
Common Stock Issued Under Stock Plans	17	0	17	0	0	0
Common Stock Dividends Declared	(2,915)	0	0	0	(2,915)	0
Other Comprehensive Income (Loss)	0	0	0	0	0	0
Change in Treasury Stock - Stock Compensation Plans, Net	(40)	0	(22)	0	0	(18)
Restricted Stock and Restricted Stock Units, Net	0	0	(5)	0	0	5
Stock-Based Compensation Expenses	152	0	152	0	0	0
Treasury Stock Issued as Compensation	0	0	0	0	0	0
Balance at Dec. 31, 2021	$ 22,180	$ 206	$ 6,087	$ (12)	$ 15,919	$ (20)
Common Stock Dividends Declared (in dollars per share)	$ 4.9875

Consolidated Statements of St_2

Consolidated Statements of Stockholders' Equity (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Stockholders' Equity [Abstract]
Common Stock Dividends Declared	$ 2,915	$ 874	$ 629
Common Stock Dividends Declared (in dollars per share)	$ 4.9875	$ 1.50	$ 1.0825

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash Flows from Operating Activities
Net Income (Loss)		$ 4,664	$ (605)	$ 2,735
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization		3,651	3,400	3,750
Impairments		376	2,100	518
Stock-Based Compensation Expenses		152	146	175
Deferred Income Taxes		(122)	(186)	632
(Gains) Losses on Asset Dispositions, Net		(17)	47	(124)
Other, Net		13	12	4
Dry Hole Costs	[1]	71	13	28
Mark-to-Market Commodity Derivative Contracts
Total (Gains) Losses		1,152	(1,145)	(180)
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts		(638)	1,071	231
Other, Net		7	1	1
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		(821)	467	(92)
Inventories		(13)	123	90
Accounts Payable		456	(795)	169
Accrued Taxes Payable		312	(49)	40
Other Assets		(136)	325	358
Other Liabilities		(116)	8	(57)
Changes in Components of Working Capital Associated with Investing Activities		(200)	75	(115)
Net Cash Provided by Operating Activities		8,791	5,008	8,163
Investing Cash Flows
Additions to Oil and Gas Properties		(3,638)	(3,244)	(6,152)
Additions to Other Property, Plant and Equipment		(212)	(221)	(270)
Proceeds from Sales of Assets		231	192	140
Other Investing Activities		0	0	(10)
Changes in Components of Working Capital Associated with Investing Activities		200	(75)	115
Net Cash Used in Investing Activities		(3,419)	(3,348)	(6,177)
Financing Cash Flows
Long-Term Debt Borrowings		0	1,484	0
Long-Term Debt Repayments		(750)	(1,000)	(900)
Dividends Paid		(2,684)	(821)	(588)
Treasury Stock Purchased		(41)	(16)	(25)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan		19	16	18
Debt Issuance Costs		0	(3)	(5)
Repayment of Finance Lease Liabilities		(37)	(19)	(13)
Net Cash Used in Financing Activities		(3,493)	(359)	(1,513)
Effect of Exchange Rate Changes on Cash		1	0	(1)
Increase in Cash and Cash Equivalents		1,880	1,301	472
Cash and Cash Equivalents at Beginning of Year		3,329	2,028	1,556
Cash and Cash Equivalents at End of Year		$ 5,209	$ 3,329	$ 2,028
[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, 2021.

Summary of Significant Accounti

Summary of Significant Accounting Policies (Notes)	12 Months Ended
	Dec. 31, 2021
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Nature of Business. EOG Resources, Inc., a Delaware corporation organized in 1985, together with its subsidiaries (collectively, EOG), explores for, develops, produces and markets crude oil, natural gas liquids (NGLs) and natural gas primarily in major producing basins in the United States of America (United States or U.S.), The Republic of Trinidad and Tobago (Trinidad). EOG is making preparations to drill offshore Australia, as well as evaluating additional exploration, development and exploitation opportunities in these and other select international areas. In addition, EOG is in the process of exiting Block 36 and Block 49 in the Sultanate of Oman (Oman) and is executing an abandonment and reclamation program in Canada. EOG sold its operations in the China Sichuan Basin (China) in the second quarter of 2021. Principles of Consolidation. The consolidated financial statements of EOG include the accounts of all domestic and foreign subsidiaries. Investments in unconsolidated affiliates, in which EOG is able to exercise significant influence, are accounted for using the equity method. All intercompany accounts and transactions have been eliminated. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Financial Instruments. EOG's financial instruments consist of cash and cash equivalents, commodity derivative contracts, accounts receivable, accounts payable and current and long-term debt. The carrying values of cash and cash equivalents, commodity derivative contracts, accounts receivable and accounts payable approximate fair value (see Notes 2 and 12). Effective January 1, 2020, EOG adopted the provisions of Accounting Standards Update (ASU) 2016-13, "Measurement of Credit Losses on Financial Instruments" (ASU 2016-13). ASU 2016-13 changes the impairment model for financial assets and certain other instruments by requiring entities to adopt a forward-looking expected loss model that will result in earlier recognition of credit losses. EOG elected to adopt ASU 2016-13 using the modified retrospective approach with a cumulative effect adjustment to retained earnings as of the effective date. Financial results reported in periods prior to January 1, 2020, are unchanged. EOG assessed its applicable financial assets, which are primarily its accounts receivable from hydrocarbon sales and joint interest billings to partners in oil and gas operations, including foreign state-owned entities in the oil and gas industry. Based on its assessment and various potential remedies ensuring collection, EOG did not record an impact to retained earnings upon adoption and expects current and future credit losses to be immaterial. EOG continues to monitor the credit risk from third-party companies to determine if expected credit losses may become material. Cash and Cash Equivalents. EOG records as cash equivalents all highly liquid short-term investments with original maturities of three months or less. Oil and Gas Operations. EOG accounts for its crude oil and natural gas exploration and production activities under the successful efforts method of accounting. Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred. Oil and gas exploration costs, other than the costs of drilling exploratory wells, are expensed as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether EOG has discovered commercial quantities of proved reserves. If commercial quantities of proved reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether commercial quantities of proved reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the estimated reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made (see Note 16). Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account. Oil and gas properties are grouped in accordance with the provisions of the Extractive Industries - Oil and Gas Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC). The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. Amortization rates are updated quarterly to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions and/or property dispositions and 4) impairments. When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the group. If the expected undiscounted future cash flows, based on EOG's estimate of (and assumptions regarding) future crude oil, NGLs and natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach described in the Fair Value Measurement Topic of the ASC. In certain instances, EOG utilizes accepted offers from third-party purchasers as the basis for determining fair value. Other Property, Plant and Equipment . Other property, plant and equipment consists of gathering and processing assets, compressors, buildings and leasehold improvements, computer hardware and software, vehicles, and furniture and fixtures. Other property, plant and equipment is generally depreciated on a straight-line basis over the estimated useful lives of the property, plant and equipment, which range from 3 years to 45 years. Inventories. Inventories consist primarily of tubular goods, materials for completion operations, well equipment and gathering lines held for use in the exploration for, and development and production of, crude oil, NGLs and natural gas reserves. EOG accounts for inventories at the lower of cost and net realizable value with adjustments made, as appropriate, to recognize any reductions in value. Revenue Recognition. EOG presents disaggregated revenues by type of commodity within its Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) and by geographic areas defined as operating segments. See Note 11. Revenues are recognized for the sale of crude oil and condensate, NGLs and natural gas at the point control of the product is transferred to the customer, typically when production is delivered and title or risk of loss transfers to the customer. Arrangements for such sales are evidenced by signed contracts with prices typically based on stated market indices, with certain adjustments for product quality and geographic location. As EOG typically invoices customers shortly after performance obligations have been fulfilled, contract assets and contract liabilities are not recognized. The balances of accounts receivable from contracts with customers as of December 31, 2021 and 2020, were $2,130 million and $1,337 million, respectively, and were included in Accounts Receivable, Net on the Consolidated Balance Sheets. Losses incurred on receivables from contracts with customers are infrequent and have been immaterial. Certain arrangements provide for the sale of fixed quantities of commodities in future years with pricing mechanisms based on future market prices at time of delivery. EOG does not disclose the value of these obligations given the uncertainty of the future realized transaction price. Crude Oil and Condensate. EOG sells its crude oil and condensate production at the wellhead or further downstream at a contractually-specified delivery point. Revenue is recognized when control transfers to the customer based on contract terms which reflect prevailing market prices. Any costs incurred prior to the transfer of control, such as gathering and transportation, are recognized as Operating Expenses. Natural Gas Liquids. EOG delivers certain of its natural gas production to either EOG-owned processing facilities or third-party processing facilities, where extraction of NGLs occurs. For EOG-owned facilities, revenue is recognized after processing upon transfer of NGLs to a customer. For third-party facilities, extracted NGLs are sold to the owner of the processing facility at the tailgate, or EOG takes possession and sells the extracted NGLs at the tailgate or exercises its option to sell further downstream to various customers. Under typical arrangements for third-party facilities, revenue is recognized after processing upon the transfer of control of the NGLs, either at the tailgate of the processing plant or further downstream. EOG recognizes revenues based on contract terms which reflect prevailing market prices, with any costs prior to the transfer of control, such as processing, transportation and fractionation fees, recognized as Transportation Costs and Gathering and Processing Costs, as appropriate. Natural Gas. EOG sells its natural gas production either at the wellhead or further downstream at a contractually-specified delivery point. In connection with the extraction of NGLs, EOG sells residue gas under separate agreements. Typically, EOG takes possession of the natural gas at the tailgate of the processing facility and sells it at the tailgate or further downstream. In each case, EOG recognizes revenues when control transfers to the customer, based on contract terms which reflect prevailing market prices. Gathering, Processing and Marketing. Gathering, processing and marketing revenues represent sales of third-party crude oil and condensate, NGLs and natural gas, as well as fees associated with gathering and processing third-party natural gas and revenues from sales of EOG-owned sand. EOG evaluates whether it is the principal or agent under these transactions. As control of the underlying commodity is transferred to EOG prior to the gathering, processing and marketing activities, EOG considers itself the principal of these arrangements. Accordingly, EOG recognizes these transactions on a gross basis. Purchases of third-party commodities are recorded as Marketing Costs, with sales of third-party commodities and fees received for gathering and processing recorded as Gathering, Processing and Marketing revenues. Capitalized Interest Costs. Interest costs have been capitalized as a part of the historical cost of unproved oil and gas properties. The amount capitalized is an allocation of the interest cost incurred during the reporting period. Capitalized interest is computed only during the exploration and development phases and ceases once production begins. The interest rate used for capitalization purposes is based on the interest rates on EOG's outstanding borrowings. Accounting for Risk Management Activities. 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, 2021, EOG elected not to designate any of its financial commodity derivative instruments as accounting hedges and, accordingly, changes in the fair value of these outstanding derivative instruments are recognized as gains or losses in the period of change. The gains or losses are recorded as Gains (Losses) on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss). The related cash flow impact of settled contracts is reflected as cash flows from operating activities. EOG employs net presentation of derivative assets and liabilities for financial reporting purposes when such assets and liabilities are with the same counterparty and subject to a master netting arrangement. See Note 12. Income Taxes. Income taxes are accounted for using the asset and liability approach. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. EOG assesses the realizability of deferred tax assets and recognizes valuation allowances as appropriate. See Note 6. Effective January 1, 2021, EOG adopted the provisions of Accounting Standards Update (ASU), "Income Taxes (Topic 740) Simplifying the Accounting for Income Taxes" (ASU 2019-12). ASU 2019-12 amends certain aspects of accounting for income taxes, including the removal of specific exceptions within existing U.S. GAAP related to the incremental approach for intraperiod tax allocation and updates 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. The effects of ASU 2019-12 applicable to EOG were all required on a prospective basis. There was no impact upon adoption of ASU 2019-12 to EOG's consolidated financial statements or related disclosures. Foreign Currency Translation. The United States dollar is the functional currency for all of EOG's consolidated subsidiaries except for its Canadian subsidiaries, for which the functional currency is the Canadian dollar. For subsidiaries whose functional currency is deemed to be other than the United States dollar, asset and liability accounts are translated at year-end exchange rates and revenues and expenses are translated at average exchange rates prevailing during the year. Translation adjustments are included in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets. Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period. See Note 4. Net Income (Loss) Per Share. Basic net income (loss) per share is computed on the basis of the weighted-average number of common shares outstanding during the period. Diluted net income (loss) per share is computed based upon the weighted-average number of common shares outstanding during the period plus the assumed issuance of common shares for all potentially dilutive securities. See Note 9. Stock-Based Compensation . EOG measures the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. See Note 7. Leases. Effective January 1, 2019, EOG adopted the provisions of ASU 2016-02, "Leases (Topic 842)" (ASU 2016-02). ASU 2016-02 and other related ASUs require that lessees recognize a right-of-use (ROU) asset and related lease liability, representing the obligation to make lease payments for certain lease transactions, on the Consolidated Balance Sheets and disclose additional leasing information. EOG elected to adopt ASU 2016-02 and other related ASUs using the modified retrospective approach with a cumulative-effect adjustment to the opening balance of retained earnings as of the effective date. Financial results reported in periods prior to January 1, 2019, are unchanged. Additionally, EOG elected the package of practical expedients within ASU 2016-02 that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases, or (iii) initial direct costs for any existing leases, but did not elect the practical expedient of hindsight when determining the lease term of existing contracts at the effective date. EOG also elected the practical expedient under ASU 2018-01, "Leases (Topic 842) - Land Easement Practical Expedient for Transition to Topic 842," and did not evaluate existing or expired land easements not previously accounted for as leases prior to the January 1, 2019 effective date. There was no impact to retained earnings upon adoption of ASU 2016-02 and other related ASUs. In the ordinary course of business, EOG enters into contracts for drilling, fracturing, compression, real estate and other services which contain equipment and other assets and that meet the definition of a lease under ASU 2016-02. The lease term for these contracts, which includes any renewals at EOG's option that are reasonably certain to be exercised, ranges from one month to 30 years. ROU assets and related liabilities are recognized on the commencement date on the Consolidated Balance Sheets based on future lease payments, discounted based on the rate implicit in the contract, if readily determinable, or EOG's incremental borrowing rate commensurate with the lease term of the contract. EOG estimates its incremental borrowing rate based on the approximate rate required to borrow on a collateralized basis. Contracts with lease terms of less than 12 months are not recorded on the Consolidated Balance Sheets, but instead are disclosed as short-term lease cost. EOG has elected not to separate non-lease components from all leases, excluding those for fracturing services, real estate and salt water disposal, as lease payments under these contracts contain significant non-lease components, such as labor and operating costs. See Note 18. Recently Issued Accounting Standards. In March 2020, the FASB issued ASU 2020-04, "Reference Rate Reform (Topic 848)" (ASU 2020-04), which provides optional expedients and exceptions for accounting treatment of contracts which are affected by the anticipated discontinuation of the London InterBank Offered Rate (LIBOR) and other rates resulting from rate reform. Contract terms that are modified due to the replacement of a reference rate are not required to be remeasured or reassessed under relevant accounting standards. Early adoption is permitted. ASU 2020-04 covers certain contracts which reference these rates and that are entered into on or before December 31, 2022. EOG has evaluated the provisions of ASU 2020-04 and does not expect the application of ASU 2020-04 to have a material impact on its consolidated financial statements and related disclosures related to its $2.0 billion senior unsecured Revolving Credit Agreement.

Long-Term Debt (Notes)

Long-Term Debt (Notes)	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Long-Term Debt at December 31, 2021 and 2020 consisted of the following (in millions): 2021 2020 4.100% Senior Notes due 2021 $ — $ 750 2.625% Senior Notes due 2023 1,250 1,250 3.15% Senior Notes due 2025 500 500 4.15% Senior Notes due 2026 750 750 6.65% Senior Notes due 2028 140 140 4.375% Senior Notes due 2030 750 750 3.90% Senior Notes due 2035 500 500 5.10% Senior Notes due 2036 250 250 4.950% Senior Notes due 2050 750 750 Long-Term Debt 4,890 5,640 Finance Leases (see Note 18) 250 212 Less: Current Portion of Long-Term Debt 37 781 Unamortized Debt Discount 27 31 Debt Issuance Costs 4 5 Total Long-Term Debt $ 5,072 $ 5,035 The senior notes in the table above are senior, unsecured obligations that rank equally in right of payment with all of our other unsecured and unsubordinated outstanding debt. At December 31, 2021, the aggregate annual maturities of long-term debt (excluding finance lease obligations) were zero in 2022, $1.25 billion in 2023, zero in 2024, $500 million in 2025 and $750 million in 2026. At December 31, 2021 and 2020, EOG had no outstanding commercial paper borrowings and did not utilize any commercial paper borrowings during 2021 and 2020. On February 1, 2021, EOG repaid upon maturity the $750 million aggregate principal amount of its 4.100% Senior Notes due 2021. On June 1, 2020, EOG repaid upon maturity the $500 million aggregate principal amount of its 4.40% Senior Notes due 2020. On April 14, 2020, EOG closed on its offering of $750 million aggregate principal amount of its 4.375% Senior Notes due 2030 and $750 million aggregate principal amount of its 4.950% Senior Notes due 2050 (together, the Notes). Interest on the Notes is payable semi-annually in arrears on April 15 and October 15 of each year, beginning on October 15, 2020. EOG received net proceeds of $1.48 billion from the issuance of the Notes, which were used to repay the 4.40% Senior Notes due 2020 when they matured on June 1, 2020 (see above), and for general corporate purposes, including the funding of capital expenditures. On April 1, 2020, EOG repaid upon maturity the $500 million aggregate principal amount of its 2.45% Senior Notes due 2020.

Stockholder's Equity (Notes)

Stockholder's Equity (Notes)	12 Months Ended
	Dec. 31, 2021
Stockholders' Equity Note [Abstract]
Stockholder's Equity	Stockholders' Equity Common Stock. In September 2001, EOG's Board of Directors (Board) authorized the repurchase of an aggregate maximum of 10 million shares of common stock that superseded all previous authorizations (September 2001 Authorization). EOG last repurchased shares under the September 2001 Authorization in March 2003. As of November 3, 2021, 6,386,200 shares remained available for purchase under September 2001 Authorization. Effective November 4, 2021, the Board (i) established a new share repurchase authorization to allow for the repurchase by EOG of up to $5 billion of common stock (November 2021 Authorization) and (ii) revoked and terminated the September 2001 Authorization. EOG did not repurchase any shares under the November 2021 Authorization during the period from November 4, 2021 through December 31, 2021 and, accordingly, $5 billion remained available for purchase under the November 2021 Authorization as of December 31, 2021. Shares of common stock are from time to time withheld by, or returned to, EOG in satisfaction of tax withholding obligations arising upon the exercise of employee stock options or stock-settled stock appreciation rights (SARs), the vesting of restricted stock, restricted stock unit or performance unit grants or in payment of the exercise price of employee stock options. Such shares withheld or returned prior to November 4, 2021 have not counted against the September 2001 Authorization, and such shares withheld or returned on or subsequent to November 4, 2021 will not count against the November 2021 Authorization. Shares purchased, withheld and returned are held in treasury for, among other purposes, fulfilling any obligations arising under EOG's stock-based compensation plans and any other approved transactions or activities for which such shares of common stock may be required. On February 24, 2022, the Board declared a quarterly cash dividend on the common stock of $0.75 per share payable April 29, 2022, to stockholders of record as of April 15, 2022. The Board also declared a special dividend of $1.00 per share payable March 29, 2022, to stockholders of record as of March 15, 2022. On November 4, 2021, the Board (i) increased the quarterly cash dividend on the common stock from the previous $0.4125 per share to $0.75 per share, effective beginning with the dividend paid on January 28, 2022, to stockholders of record as of January 14, 2022 and (ii) declared a special cash dividend on the common stock of $2.00 per share, paid on December 30, 2021, to stockholders of record as of December 15, 2021. On May 6, 2021, the Board declared a special cash dividend on the common stock of $1.00 per share. The special cash dividend was paid on July 30, 2021 to stockholders of record as of July 16, 2021 (and was in addition to the quarterly cash dividend of $0.4125 per share also paid on July 30, 2021 to stockholders of record as of July 16, 2021). On February 25, 2021, the Board increased the quarterly cash dividend on the common stock from the previous $0.375 per share to $0.4125 per share, effective beginning with the dividend to be paid on April 30, 2021, to stockholders of record as of April 16, 2021. On February 27, 2020, the Board increased the quarterly cash dividend on the common stock from the previous $0.2875 per share to $0.375 per share, effective beginning with the dividend to be paid on April 30, 2020, to stockholders of record as of April 16, 2020. On May 2, 2019, the Board increased the quarterly cash dividend on the common stock from the previous $0.22 per share to $0.2875 per share, effective beginning with the dividend paid on July 31, 2019, to stockholders of record as of July 17, 2019. The following summarizes Common Stock activity for each of the years ended December 31, 2021, 2020 and 2019 (in thousands): Common Shares Issued Treasury Outstanding 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 117 107 224 Treasury Stock Issued Under Stock-Based Compensation Plans — 289 289 Balance at December 31, 2019 582,213 (299) 581,914 Common Stock Issued Under Stock-Based Compensation Plans 1,482 — 1,482 Treasury Stock Purchased (1) — (389) (389) Common Stock Issued Under Employee Stock Purchase Plan — 377 377 Treasury Stock Issued Under Stock-Based Compensation Plans — 187 187 Balance at December 31, 2020 583,695 (124) 583,571 Common Stock Issued Under Stock-Based Compensation Plans 1,511 — 1,511 Treasury Stock Purchased (1) — (504) (504) Common Stock Issued Under Employee Stock Purchase Plan 316 — 316 Treasury Stock Issued Under Stock-Based Compensation Plans — 371 371 Balance at December 31, 2021 585,522 (257) 585,265 (1) Represents shares that were withheld by or returned to EOG (i) in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or SARs or the vesting of restricted stock, restricted stock unit or performance unit grants or (ii) in payment of the exercise price of employee stock options. Preferred Stock . EOG currently has one authorized series of preferred stock. As of December 31, 2021, there were no shares of preferred stock outstanding.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Loss (Notes)	12 Months Ended
	Dec. 31, 2021
Equity [Abstract]
Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive Loss Accumulated other comprehensive loss includes certain transactions that have generally been reported in the Consolidated Statements of Stockholders' Equity. The components of Accumulated Other Comprehensive Loss at December 31, 2021 and 2020 consisted of the following (in millions): Foreign Currency Translation Adjustment Other Total December 31, 2019 $ (3) $ (2) $ (5) Other comprehensive loss before taxes (7) — (7) Tax effects — — — Other comprehensive loss (7) — (7) December 31, 2020 (10) (2) (12) Other comprehensive loss before taxes (1) 1 — Tax effects — — — Other comprehensive loss (1) 1 — December 31, 2021 $ (11) $ (1) $ (12) No significant amount was reclassified out of Accumulated Other Comprehensive Loss during the years ended December 31, 2021, 2020 and 2019.

Other Income, Net (Notes)

Other Income, Net (Notes)	12 Months Ended
	Dec. 31, 2021
Other Income and Expenses [Abstract]
Other Income, Net	Other Income, NetOther income, net for 2021 included equity income from investments in ammonia plants in Trinidad ($18 million) and interest income ($3 million), partially offset by an upward adjustment to deferred compensation expense ($13 million). Other income, net for 2020 included interest income ($12 million), partially offset by equity losses from investments in ammonia plants in Trinidad ($2 million). Other income, net for 2019 included interest income ($26 million) and net foreign currency transaction gains ($2 million).

Employee Benefit Plans (Notes)

Employee Benefit Plans (Notes)	12 Months Ended
	Dec. 31, 2021
Share-based Payment Arrangement [Abstract]
Employee Benefit Plans	Employee Benefit Plans Stock-Based Compensation During 2021, EOG maintained various stock-based compensation plans as discussed below. EOG recognizes compensation expense on grants of stock options, SARs, restricted stock and restricted stock units, performance units and grants made under the EOG Resources, Inc. Employee Stock Purchase Plan (ESPP). Stock-based compensation expense is calculated based upon the grant date estimated fair value of the awards, net of forfeitures, based upon EOG's historical employee turnover rate. Compensation expense is amortized over the shorter of the vesting period or the period from date of grant until the date the employee becomes eligible to retire without company approval. Stock-based compensation expense is included on the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) based upon the job functions of the employees receiving the grants. Compensation expense related to EOG's stock-based compensation plans for the years ended December 31, 2021, 2020 and 2019 was as follows (in millions): 2021 2020 2019 Lease and Well $ 49 $ 52 $ 56 Gathering and Processing Costs 3 1 1 Exploration Costs 20 21 26 General and Administrative 80 72 92 Total $ 152 $ 146 $ 175 The Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (2008 Plan) provided for grants of stock options, SARs, restricted stock and restricted stock units, performance units, and other stock-based awards. EOG's stockholders approved the EOG Resources, Inc. 2021 Omnibus Equity Compensation Plan (2021 Plan) at the 2021 Annual Meeting of Stockholders. Therefore, no further grants were made from the 2008 Plan from and after the April 29, 2021 effective date of the 2021 Plan. The 2021 Plan provides for grants of stock options, SARs, restricted stock and restricted stock units, restricted stock units with performance-based conditions (together with the performance units granted under the 2008 Plan, "Performance Units") and other stock-based awards, up to an aggregate maximum of 20 million shares of common stock, plus any shares that are subject to outstanding awards under the 2008 Plan as of April 29, 2021, that are subsequently canceled, forfeited, expire or are otherwise not issued or are settled in cash. Under the 2021 Plan, grants may be made to employees and non-employee members of EOG's Board of Directors (Board). The vesting schedules for grants of stock options, SARs, restricted stock and restricted stock units, and Performance Units are generally as follows: Grant Type Vesting Schedule Stock Options/SARs Vesting in increments of one-third on each of the first three anniversaries, respectively, of the date of grant Restricted Stock/Restricted Stock Units "Cliff" vesting three years from the date of grant Performance Units "Cliff" vesting on the February 28th following the three-year performance period and the Compensation and Human Resources Committee's certification of the applicable performance multiple At December 31, 2021, approximately 18 million common shares remained available for grant under the 2021 Plan. EOG's policy is to issue shares related to the 2021 Plan from previously authorized unissued shares or treasury shares to the extent treasury shares are available. During 2021, 2020 and 2019, EOG issued shares in connection with stock option/SAR exercises, restricted stock grants, restricted stock unit and Performance Unit releases and ESPP purchases. Net tax deficiencies recognized within the income tax provision were $(11) million, $(22) million and $(1) million for the years ended December 31, 2021, 2020 and 2019, respectively. Stock Options and Stock-Settled Stock Appreciation Rights and Employee Stock Purchase Plan. Participants in EOG's stock-based compensation plans (including the 2008 Plan and 2021 Plan) have been or may be granted options to purchase shares of Common Stock. In addition, participants in EOG's stock plans (including the 2008 Plan and 2021 Plan) have been or may be granted SARs, representing the right to receive shares of Common Stock based on the appreciation in the stock price from the date of grant on the number of SARs granted. Stock options and SARs are granted at a price not less than the market price of the Common Stock on the date of grant. Terms for stock options and SARs granted have generally not exceeded a maximum term of seven years. EOG'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 $48 million, $62 million and $63 million for the years ended December 31, 2021, 2020 and 2019, respectively. Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants for the years ended December 31, 2021, 2020 and 2019 were as follows: Stock Options/SARs ESPP 2021 2020 2019 2021 2020 2019 Weighted Average Fair Value of Grants $ 24.92 $ 11.06 $ 19.49 $ 18.12 $ 19.14 $ 22.83 Expected Volatility 42.24 % 44.47 % 32.02 % 51.27 % 53.48 % 34.78 % Risk-Free Interest Rate 0.50 % 0.21 % 1.69 % 0.07 % 0.90 % 2.27 % Dividend Yield 2.26 % 3.27 % 1.39 % 2.89 % 2.27 % 1.04 % Expected Life 5.2 years 5.2 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, 2021, 2020 and 2019 (stock options and SARs in thousands): 2021 2020 2019 Number Weighted Number Weighted Number Weighted Outstanding at January 1 10,186 $ 84.08 9,395 $ 94.53 8,310 $ 96.90 Granted 1,982 81.68 1,996 37.63 1,965 75.39 Exercised (1) (1,130) 63.98 (23) 69.59 (606) 61.43 Forfeited (1,069) 98.15 (1,182) 88.93 (274) 102.57 Outstanding at December 31 9,969 84.37 10,186 84.08 9,395 94.53 Stock Options/SARs Exercisable at December 31 6,197 95.33 6,343 96.41 5,275 94.21 (1) The total intrinsic value of stock options/SARs exercised during the years 2021, 2020 and 2019 was $27 million, $0.4 million and $14 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, 2021, there were 9.7 million stock options/SARs vested or expected to vest with a weighted average grant price of $84.97 per share, an intrinsic value of $120 million and a weighted average remaining contractual life of 4.1 years. The following table summarizes certain information for the stock options and SARs outstanding and exercisable at December 31, 2021 (stock options and SARs in thousands): Stock Options/SARs Outstanding Stock Options/SARs Exercisable Range of Stock Weighted Weighted Aggregate Intrinsic Value (1) Stock Weighted Weighted Aggregate Intrinsic Value (1) $ 34.00 to $ 52.99 1,640 6 $ 37.50 414 5 $ 37.46 53.00 to 75.99 1,906 4 73.68 1,313 3 73.11 76.00 to 90.99 1,976 7 81.86 33 2 83.71 91.00 to 95.99 1,114 2 94.95 1,109 2 94.96 96.00 to 101.99 1,657 3 96.34 1,652 3 96.33 102.00 to 129.99 1,676 4 126.51 1,676 4 126.51 9,969 4 84.37 $ 127 6,197 3 95.33 $ 42 (1) Based upon the difference between the closing market price of the Common Stock on the last trading day of the year and the grant price of in-the-money stock options and SARs, in millions. At December 31, 2021, unrecognized compensation expense related to non-vested stock option and SAR grants totaled $60 million. This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.1 years. At the 2018 Annual Meeting of Stockholders, EOG stockholders approved an amendment and restatement of the ESPP to (among other changes) increase the number of shares available for grant. At December 31, 2021, approximately 1.6 million shares of Common Stock remained available for grant under the ESPP. The following table summarizes ESPP activity for the years ended December 31, 2021, 2020 and 2019 (in thousands, except number of participants): 2021 2020 2019 Approximate Number of Participants 2,036 2,063 1,998 Shares Purchased 316 377 224 Aggregate Purchase Price $ 17,224 $ 16,103 $ 16,533 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 $89 million, $75 million and $97 million for the years ended December 31, 2021, 2020 and 2019, respectively. The following table sets forth the restricted stock and restricted stock unit transactions for the years ended December 31, 2021, 2020 and 2019 (shares and units in thousands): 2021 2020 2019 Number of Shares and Units Weighted Average Grant Date Fair Value Number of Shares and Units Weighted Average Grant Date Fair Value Number of Shares and Units Weighted Average Grant Date Fair Value Outstanding at January 1 4,742 $ 74.97 4,546 $ 90.16 3,792 $ 96.64 Granted 1,422 81.50 1,488 38.10 1,749 80.01 Released (1) (1,388) 101.00 (1,213) 85.92 (855) 96.93 Forfeited (96) 68.26 (79) 86.52 (140) 97.54 Outstanding at December 31 (2) 4,680 69.37 4,742 74.97 4,546 90.16 (1) (1) The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2021, 2020 and 2019 was $110 million, $48 million and $70 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date restricted stock and restricted stock units are released. (2) (2) The total intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2021, 2020 and 2019 was $416 million, $236 million and $381 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, 2021, unrecognized compensation expense related to restricted stock and restricted stock units totaled $199 million. Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 1.5 years. Performance Units. EOG has granted Performance Units 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 Units granted could be outstanding. The fair value of the Performance Units is estimated using a Monte Carlo simulation. Stock-based compensation expense related to the Performance Unit grants totaled $15 million, $9 million and $15 million for the years ended December 31, 2021, 2020 and 2019, respectively. Weighted average fair values and valuation assumptions used to value Performance Units during the years ended December 31, 2021, 2020 and 2019 were as follows: 2021 2020 2019 Weighted Average Fair Value of Grants $ 95.16 $ 42.77 $ 79.98 Expected Volatility 53.80 % 47.27 % 29.20 % Risk-Free Interest Rate 0.59 % 0.16 % 1.51 % Expected volatility is based on the term-matched historical volatility over the simulated term, which is calculated as the time between the grant date and the end of the Performance Period. The risk-free interest rate is derived from the Treasury Constant Maturities yield curve on the grant date. The following table sets forth the Performance Unit transactions for the years ended December 31, 2021, 2020 and 2019 (units in thousands): 2021 2020 2019 Number of Units Weighted Average Grant Date Fair Value Number of Units Weighted Average Grant Date Fair Value Number of Units Weighted Average Grant Date Fair Value Outstanding at January 1 613 $ 88.38 598 $ 103.91 539 $ 116.96 Granted 222 95.16 172 42.77 172 79.98 Granted for Performance Multiple (1) 19 113.81 66 119.10 72 80.64 Released (2) (175) 113.06 (223) 103.87 (185) 110.65 Forfeited — — — — — — Outstanding at December 31 (3) 679 (4) 84.97 613 88.38 598 103.91 (1) Upon completion of the Performance Period for the Performance Units granted in 2017, 2016 and 2015, a performance multiple of 125%, 150% and 200%, respectively, was applied to each of the grants resulting in additional grants of Performance Units in February 2021, 2020 and 2019. (2) The total intrinsic value of Performance Units released during the years ended December 31, 2021, 2020 and 2019 was $13 million, $13 million and $15 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date Performance Units are released. (3) The total intrinsic value of Performance Units outstanding at December 31, 2021, 2020 and 2019 was $60 million, $31 million and $50 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 zero and a maximum of 1,358 Performance Units could be outstanding. At December 31, 2021, unrecognized compensation expense related to Performance Units totaled $13 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 1.9 years. Upon completion of the Performance Period for the Performance Units granted in September 2018, a performance multiple of 50% was applied to the grants resulting in a forfeiture of 56,671 Performance Units in February 2022. 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 $52 million, $46 million and $51 million for 2021, 2020 and 2019, respectively. In addition, EOG's Trinidadian subsidiary maintains a contributory defined benefit pension plan and a matched savings plan. These pension plans are available to most employees of the Trinidadian subsidiary. EOG's combined contributions to these plans were $1 million, for each of 2021, 2020 and 2019, respectively. For the Trinidadian defined benefit pension plan, the benefit obligation, fair value of plan assets and (prepaid)/accrued benefit cost totaled $13 million, $14 million and $(0.1) million, respectively, at December 31, 2021, and $13 million, $12 million and $0.1 million, respectively, at December 31, 2020. 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.

Income Taxes (Notes)

Income Taxes (Notes)	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The principal components of EOG's total net deferred income tax liabilities at December 31, 2021 and 2020 were as follows (in millions): 2021 2020 Deferred Income Tax Assets (Liabilities) Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization $ (19) $ 25 Foreign Asset Retirement Obligations 51 — Foreign Accrued Expenses and Liabilities 15 — Foreign Net Operating Loss 80 74 Foreign Valuation Allowances (111) (97) Foreign Other (5) — Total Net Deferred Income Tax Assets $ 11 $ 2 Deferred Income Tax (Assets) Liabilities Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization $ 5,063 $ 5,028 Commodity Hedging Contracts (97) 15 Deferred Compensation Plans (57) (43) Equity Awards (86) (103) Undistributed Foreign Earnings — 10 Other (74) (48) Total Net Deferred Income Tax Liabilities $ 4,749 $ 4,859 Total Net Deferred Income Tax Liabilities $ 4,738 $ 4,857 The components of Income (Loss) Before Income Taxes for the years indicated below were as follows (in millions): 2021 2020 2019 United States $ 5,787 $ (756) $ 3,466 Foreign 146 17 79 Total $ 5,933 $ (739) $ 3,545 The principal components of EOG's Income Tax Provision (Benefit) for the years indicated below were as follows (in millions): 2021 2020 2019 Current: Federal $ 1,203 $ (108) $ (152) State 85 7 10 Foreign 105 40 81 Total 1,393 (61) (61) Deferred: Federal (41) (153) 627 State (62) (15) 33 Foreign (19) (18) (28) Total (122) (186) 632 Other Non-Current: (1) Federal — 113 245 Foreign (2) — (6) Total (2) 113 239 Income Tax Provision (Benefit) $ 1,269 $ (134) $ 810 (1) Includes changes in certain amounts that are expected to be paid or received beyond the next twelve months. The primary component in 2020 and 2019 is refundable alternative minimum tax (AMT) credits. The differences between taxes computed at the U.S. federal statutory tax rate and EOG's effective rate for the years indicated below were as follows: 2021 2020 2019 Statutory Federal Income Tax Rate 21.0 % 21.0 % 21.0 % State Income Tax, Net of Federal Benefit 0.3 0.9 1.0 Income Tax Provision Related to Foreign Operations 0.9 (0.1) 0.9 Income Tax Provision Related to Canadian Operations — (2.4) — Stock-Based Compensation 0.2 (2.9) — Other (1.0) 1.7 — Effective Income Tax Rate 21.4 % 18.2 % 22.9 % The net effective tax rate of 21% in 2021 was higher than the prior year rate of 18% mostly due to taxes attributable to EOG's foreign operations and stock-based compensation tax deficiencies increasing the effective tax rate on pretax income in 2021 and decreasing the effective tax rate on pretax loss in 2020. Deferred tax assets are recorded for future deductible amounts and certain other tax benefits, such as 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 millions): 2021 2020 2019 Beginning Balance $ 219 $ 201 $ 167 Increase (1) 15 25 31 Decrease (2) (14) (11) — Other (3) (1) 4 3 Ending Balance $ 219 $ 219 $ 201 (1) Increase in valuation allowance related to the generation of tax NOLs and other deferred tax assets. (2) Decrease in valuation allowance associated with adjustments to certain deferred tax assets and their related allowances. (3) Represents dispositions, revisions and/or foreign exchange rate variances and the effect of statutory income tax rate changes. As of December 31, 2021, EOG had state income tax NOLs of approximately $2 billion. Certain state NOLs have an indefinite carryforward and all others expire between 2022 and 2040. EOG also has Canadian NOLs of $297 million, some of which can be carried forward up to 20 years. As described previously, 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, 2021, was $9 million, resulting from the tax treatment of certain compensation deductions, of which the full amount may potentially have an earnings impact. EOG records interest and penalties related to unrecognized tax benefits to its income tax provision. No interest expense has been recognized in the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) related to the unrecognized tax benefits as these positions are immaterial or will be claimed either on amended returns or as self-proposed audit adjustments, which if sustained, will result in refunds. EOG anticipates that the amount of the unrecognized tax benefits may change due to favorable audit developments expected to occur 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 (2019), Canada (2017), Trinidad (2014) and Oman (2020). EOG's foreign subsidiaries' undistributed earnings are not considered to be permanently reinvested outside of the U.S. and deferred income taxes have been accrued on any such outside basis differences. Additionally, EOG’s foreign earnings may be subject to the U.S. federal "global intangible low-taxed income" (GILTI) inclusion. EOG records any GILTI tax as a period expense.

Commitments and Contingencies (

Commitments and Contingencies (Notes)	12 Months Ended
	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Letters of Credit and Guarantees. At December 31, 2021 and 2020, respectively, EOG had standby letters of credit and guarantees outstanding totaling approximately $831 million and $854 million, primarily representing guarantees of payment or performance obligations on behalf of subsidiaries. As of February 17, 2022, EOG had received no demands for payment under these guarantees. Minimum Commitments. At December 31, 2021, 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, 2021, were as follows (in millions): Total Minimum 2022 $ 1,335 2023 1,045 2024 823 2025 673 2026 579 2027 and beyond 2,133 $ 6,588 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.

Net Income (Loss) Per Share (No

Net Income (Loss) Per Share (Notes)	12 Months Ended
	Dec. 31, 2021
Earnings Per Share [Abstract]
Net Income (Loss) Per Share	Net Income (Loss) Per Share The following table sets forth the computation of Net Income (Loss) Per Share for the years ended December 31, 2021, 2020 and 2019 (in millions, except per share data): 2021 2020 2019 Numerator for Basic and Diluted Earnings per Share - Net Income (Loss) $ 4,664 $ (605) $ 2,735 Denominator for Basic Earnings per Share - Weighted Average Shares 581 579 578 Potential Dilutive Common Shares - Stock Options/SARs — — — Restricted Stock/Units and Performance Units 3 — 3 Denominator for Diluted Earnings per Share - Adjusted Diluted Weighted Average Shares 584 579 581 Net Income (Loss) Per Share Basic $ 8.03 $ (1.04) $ 4.73 Diluted $ 7.99 $ (1.04) $ 4.71 The diluted earnings per share calculation excludes stock option, SAR, restricted stock, restricted stock unit, Performance Unit and ESPP grants that were anti-dilutive. Shares underlying the excluded stock option, SAR and ESPP grants were 6 million, 10 million and 6 million for the years ended December 31, 2021, 2020 and 2019, respectively. For the year ended December 31, 2020, 5 million shares underlying grants of restricted stock, restricted stock units and Performance Units were excluded.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information (Notes)	12 Months Ended
	Dec. 31, 2021
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Supplemental Cash Flow Information Net cash paid for (received from) interest and income taxes was as follows for the years ended December 31, 2021, 2020 and 2019 (in millions): 2021 2020 2019 Interest, Net of Capitalized Interest $ 185 $ 205 $ 187 Income Taxes, Net of Refunds Received $ 1,114 $ (206) $ (292) EOG's accrued capital expenditures at December 31, 2021, 2020 and 2019 were $592 million, $414 million and $612 million, respectively. Non-cash investing activities for the year ended December 31, 2021, included additions of $50 million to EOG's oil and gas properties as a result of property exchanges and an addition of $74 million to EOG's other property, plant and equipment made in connection with finance lease transactions for storage facilities. Non-cash investing activities for the year ended December 31, 2020, included additions of $212 million to EOG's oil and gas properties as a result of property exchanges and an addition of $174 million to EOG's other property, plant and equipment made in connection with finance lease transactions for storage facilities. Non-cash investing activities for the year ended December 31, 2019, included additions of $150 million to EOG's oil and gas properties as a result of property exchanges. Cash paid for leases for the years ended December 31, 2021, 2020 and 2019, is disclosed in Note 18.

Business Segment Information (N

Business Segment Information (Notes)	12 Months Ended
	Dec. 31, 2021
Segment Reporting [Abstract]
Business Segment Information	Business Segment InformationEOG's operations are all crude oil, NGLs and natural gas exploration and production-related. The Segment Reporting Topic of the ASC establishes standards for reporting information about operating segments in annual financial statements. Operating segments are defined as components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker, or decision-making group, in deciding how to allocate resources and in assessing performance. EOG's chief operating decision-making process is informal and involves the Chief Executive Officer and other key officers. This group routinely reviews and makes operating decisions related to significant issues associated with each of EOG's major producing areas (including in the United States and in Trinidad) and its exploration programs both inside and outside the United States. For segment reporting purposes, the chief operating decision makers consider the major United States producing areas to be one operating segment. Financial information by reportable segment is presented below as of and for the years ended December 31, 2021, 2020 and 2019 (in millions): United Trinidad Other International (1) Total 2021 Crude Oil and Condensate $ 11,094 $ 31 $ — $ 11,125 Natural Gas Liquids 1,812 — — 1,812 Natural Gas 2,156 270 18 2,444 Losses on Mark-to-Market Commodity Derivative Contracts (1,152) — — (1,152) Gathering, Processing and Marketing 4,287 1 — 4,288 Gains (Losses) on Asset Dispositions, Net (40) (2) 59 17 Other, Net 108 — — 108 Operating Revenues and Other (2) 18,265 300 77 18,642 Depreciation, Depletion and Amortization 3,558 87 6 3,651 Operating Income (Loss) (3) 6,013 151 (62) 6,102 Interest Income 3 — — 3 Other Income (Expense) (14) 8 12 6 Net Interest Expense 178 — — 178 Income (Loss) Before Income Taxes 5,824 159 (50) 5,933 Income Tax Provision (Benefit) 1,247 66 (44) 1,269 Additions to Oil and Gas Properties, Excluding Dry Hole Costs 3,557 55 5 3,617 Total Property, Plant and Equipment, Net 28,213 204 9 28,426 Total Assets 37,436 637 163 38,236 2020 Crude Oil and Condensate $ 5,774 $ 11 $ 1 $ 5,786 Natural Gas Liquids 668 — — 668 Natural Gas 614 169 54 837 Gains on Mark-to-Market Commodity Derivative Contracts 1,145 — — 1,145 Gathering, Processing and Marketing 2,581 2 — 2,583 Losses on Asset Dispositions, Net (47) — — (47) Other, Net 60 — — 60 Operating Revenues and Other (4) 10,795 182 55 11,032 Depreciation, Depletion and Amortization 3,324 60 16 3,400 Operating Income (Loss) (5) (546) 75 (73) (544) Interest Income 11 1 — 12 Other Expense — (2) — (2) Net Interest Expense 205 — — 205 Income (Loss) Before Income Taxes (740) 74 (73) (739) Income Tax Provision (Benefit) (157) 15 8 (134) Additions to Oil and Gas Properties, Excluding Dry Hole Costs 3,318 83 42 3,443 Total Property, Plant and Equipment, Net 28,284 210 105 28,599 Total Assets 35,048 546 211 35,805 United Trinidad Other International (1) Total 2019 Crude Oil and Condensate $ 9,599 $ 11 $ 3 $ 9,613 Natural Gas Liquids 785 — — 785 Natural Gas 867 259 58 1,184 Gains on Mark-to-Market Commodity Derivative Contracts 180 — — 180 Gathering, Processing and Marketing 5,355 5 — 5,360 Gains (Losses) on Asset Dispositions, Net 132 (4) (4) 124 Other, Net 134 — — 134 Operating Revenues and Other (6) 17,052 271 57 17,380 Depreciation, Depletion and Amortization 3,652 80 18 3,750 Operating Income (Loss) 3,619 113 (33) 3,699 Interest Income 22 4 — 26 Other Income 3 1 1 5 Net Interest Expense (Income) 192 — (7) 185 Income (Loss) Before Income Taxes 3,452 118 (25) 3,545 Income Tax Provision 761 41 8 810 Additions to Oil and Gas Properties, Excluding Dry Hole Costs 6,209 53 12 6,274 Total Property, Plant and Equipment, Net 30,102 184 78 30,364 Total Assets 36,275 706 144 37,125 (1) Other International primarily consists of EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. EOG began exploration programs in Australia in the third quarter of 2021 and in Oman in the third quarter of 2020. The decision was reached in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman. (2) EOG had sales activity with two significant purchasers in 2021, one totaling $2.7 billion and the other totaling $2.6 billion of consolidated Operating Revenues and Other in the United States segment. (3) EOG recorded pretax impairment charges of $45 million and dry hole costs of $42 million in 2021 in the Other International segment related to its decision in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman. In addition, EOG recorded net gains of asset dispositions of $58 million in 2021 in the Other International segment during the second quarter of 2021 due to the sale of its China operations. See Notes 14 and 17, respectively. (4) EOG had sales activity with three significant purchasers in 2020, each totaling $1.1 billion of consolidated Operating Revenues and Other in the United States segment. (5) EOG recorded pretax impairment charges of $1,570 million in 2020 for proved oil and gas properties, leasehold costs and other assets due to the decline in commodity prices and revisions of asset retirement obligations for certain properties in the United States segment. In addition, EOG recorded pretax impairment charges of $228 million in 2020 for owned and leased sand and crude-by-rail assets, also in the United States segment. EOG recorded pretax impairment charges of $81 million in 2020 for proved oil and gas properties and firm commitment contracts related to its decision to exit the Horn River Basin in British Columbia, Canada, in the Other International segment. See Notes 13 and 14. (6) 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.

Risk Management Activities (Not

Risk Management Activities (Notes)	12 Months Ended
	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk Management Activities	Risk Management Activities Commodity Price Transactions. EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for crude oil, NGLs and natural gas. EOG utilizes financial commodity derivative instruments, primarily price swap, option, swaption, collar and basis swap contracts, as a means to manage this price risk. During 2021, 2020 and 2019, EOG elected not to designate any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounted for these financial commodity derivative contracts using the mark-to-market accounting method. Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as Gains (Losses) on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss). The related cash flow impact is reflected in Cash Flows from Operating Activities. During 2021, 2020 and 2019, EOG recognized net gains (losses) on the mark-to-market of financial commodity derivative contracts of $(1,152) million, $1,145 million and $180 million, respectively, which included cash received from (payments for) settlements of crude oil, NGLs and natural gas derivative contracts of $(638) million, $1,071 million and $231 million, respectively. Presented below is a comprehensive summary of EOG's financial commodity derivative contracts settled during the year ended December 31, 2021 (closed) and remaining for 2022 and thereafter, as of December 31, 2021. Crude oil and NGL volumes are presented in MBbld and prices are presented in $/Bbl. Natural gas volumes are presented in MMBtu per day (MMBtud) and prices are presented in dollars per MMBtu ($/MMBtu). Crude Oil Financial Price Swap Contracts Contracts Sold Period Settlement Index Volume Weighted Average Price January 2021 (closed) NYMEX West Texas Intermediate (WTI) 151 $ 50.06 February - March 2021 (closed) NYMEX WTI 201 51.29 April - June 2021 (closed) NYMEX WTI 150 51.68 July - September 2021 (closed) NYMEX WTI 150 52.71 January - March 2022 NYMEX WTI 140 65.58 April - June 2022 NYMEX WTI 140 65.62 July - September 2022 NYMEX WTI 140 65.59 October - December 2022 NYMEX WTI 140 65.68 January - March 2023 NYMEX WTI 150 67.92 April - June 2023 NYMEX WTI 120 67.79 July - September 2023 NYMEX WTI 20 68.04 Crude Oil Basis Swap Contracts Contracts Sold Period Settlement Index Volume Weighted Average Price Differential February 2021 (closed) NYMEX WTI Roll Differential (1) 30 $ 0.11 March - December 2021 (closed) NYMEX WTI Roll Differential (1) 125 0.17 January 2022 (closed) NYMEX WTI Roll Differential (1) 125 0.15 February - December 2022 NYMEX WTI Roll Differential (1) 125 0.15 (1) This settlement index is used to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month. NGL Financial Price Swap Contracts Contracts Sold Period Settlement Index Volume Weighted Average Price January - December 2021 (closed) Mont Belvieu Propane (non-Tet) 15 $ 29.44 Natural Gas Financial Price Swap Contracts Contracts Sold Contracts Purchased Period Settlement Index Volume Weighted Average Price ($/MMBtu) Volume (MMBtud in thousands) Weighted Average Price ($/MMBtu) January - March 2021 (closed) NYMEX Henry Hub 500 $ 2.99 500 $ 2.43 April - September 2021 (closed) NYMEX Henry Hub 500 2.99 570 2.81 October - December 2021 (closed) NYMEX Henry Hub 500 2.99 500 2.83 January - December 2022 (closed) (1) NYMEX Henry Hub 20 2.75 — — January - December 2022 NYMEX Henry Hub 725 3.57 — — January - December 2023 NYMEX Henry Hub 725 3.18 — — January - December 2024 NYMEX Henry Hub 725 3.07 — — January - December 2025 NYMEX Henry Hub 725 3.07 — — April - September 2021 (closed) Japan Korea Marker (JKM) 70 6.65 — — (1) In January 2021, EOG executed the early termination provision granting EOG the right to terminate all of its 2022 natural gas price swap contracts which were open at that time. EOG received net cash of $0.6 million for the settlement of these contracts. Natural Gas Basis Swap Contracts Contracts Sold Period Settlement Index Volume Weighted Average Price ($/MMBtu) January - December 2022 NYMEX Henry Hub Houston Ship Channel (HSC) Differential (1) 210 $ (0.01) January - December 2023 NYMEX Henry Hub HSC Differential (1) 135 (0.01) January - December 2024 NYMEX Henry Hub HSC Differential (1) 10 0.00 January - December 2025 NYMEX Henry Hub HSC Differential (1) 10 0.00 (1) This settlement index is used to fix the differential between pricing at the Houston Ship Channel and NYMEX Henry Hub prices. 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, 2021 and 2020, respectively. Certain amounts may be presented on a net basis on the consolidated financial statements when such amounts are with the same counterparty and subject to a master netting arrangement (in millions): Fair Value at December 31, Description Location on Balance Sheet 2021 2020 Asset Derivatives Crude oil, NGLs and natural gas derivative contracts - Current portion Assets from Price Risk Management Activities $ — $ 65 Noncurrent portion Other Assets (1) 6 1 Liability Derivatives Crude oil, NGLs and natural gas derivative contracts - Current portion Liabilities from Price Risk Management Activities (2) $ 269 $ — Noncurrent Portion Other Liabilities (3) 37 1 (1) The noncurrent portion of Assets from Price Risk Management Activities consists of gross assets of $7 million, partially offset by gross liabilities of $1 million, at December 31, 2021. (2) The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $421 million, partially offset by gross assets of $29 million and collateral posted with counterparties of $123 million, at December 31, 2021. (3) The noncurrent portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $64 million, partially offset by gross assets of $10 million and collateral posted with counterparties of $17 million, at December 31, 2021. 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, 2021, 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 2022. At December 31, 2020, EOG's net accounts receivable balance related to United States hydrocarbon sales included two receivable balances, each of which accounted for more than 10% of the total balance. The receivables were due from two petroleum refinery companies. The related amounts were collected during early 2021. In 2021 and 2020, all natural gas from EOG's Trinidad operations was sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary. In 2021 and 2020, all crude oil and condensate from EOG's Trinidad operations was sold to Heritage Petroleum Company Limited. Through May 2021, and in 2020, 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, 2021 and a net asset position at December 31, 2020. EOG had $140 million of collateral posted and no collateral held at December 31, 2021, and had no collateral posted or held at December 31, 2020. Due to higher commodity prices subsequent to December 31, 2021, EOG had $1.4 billion of collateral posted at February 18, 2022.

Fair Value Measurements (Notes)

Fair Value Measurements (Notes)	12 Months Ended
	Dec. 31, 2021
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value MeasurementsCertain of EOG's financial and nonfinancial assets and liabilities are reported at fair value on the Consolidated Balance Sheets. An established fair value hierarchy prioritizes the relative reliability of inputs used in fair value measurements. The hierarchy gives highest priority to Level 1 inputs that represent unadjusted quoted market prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are directly or indirectly observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs and have the lowest priority in the hierarchy. EOG gives consideration to the credit risk of its counterparties, as well as its own credit risk, when measuring financial assets and liabilities at fair value. Recurring Fair Value Measurements. The following table provides fair value measurement information within the fair value hierarchy for certain of EOG's financial assets and liabilities carried at fair value on a recurring basis at December 31, 2021 and 2020 (in millions): Fair Value Measurements Using: Quoted Significant Significant Total At December 31, 2021 Financial Assets: Natural Gas Swaps $ — $ 29 $ — $ 29 Natural Gas Basis Swaps — 2 — 2 Crude Oil Swaps — 15 — 15 Financial Liabilities: Crude Oil Roll Differential Swaps — 24 — 24 Natural Gas Swaps — 121 — 121 Crude Oil Swaps — 340 — 340 Natural Gas Basis Swaps — 1 — 1 At December 31, 2020 Financial Assets: Natural Gas Swaps $ — $ 66 $ — $ 66 Financial Liabilities: Crude Oil Roll Differential Swaps — 1 — 1 See Note 12 for the balance sheet amounts and classification of EOG's financial derivative instruments at December 31, 2021 and 2020. The estimated fair value of crude oil, NGLs and natural gas derivative contracts (including options/collars) was based upon forward commodity price curves based on quoted market prices. Commodity derivative contracts were valued by utilizing an independent third-party derivative valuation provider who uses various types of valuation models, as applicable. Non-Recurring Fair Value Measurements. The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs and reserve lives. A reconciliation of EOG's asset retirement obligations is presented in Note 15. When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the group. If the expected undiscounted future cash flows, based on EOG's estimate of (and assumptions regarding) significant Level 3 inputs, including future crude oil, NGLs and natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach described in the Fair Value Measurement Topic of the ASC. In certain instances, EOG utilizes accepted offers from third-party purchasers as the basis for determining fair value. During 2021, proved oil and gas properties with a carrying amount of $27 million were written down to their fair value of $7 million, resulting in pretax impairment charges of $20 million. During 2020, due to the decline in commodity prices and revisions of asset retirement obligations for certain properties, proved oil and gas properties with a carrying amount of $1,587 million were written down to their fair value of $319 million, resulting in pretax impairment charges of $1,268 million. In addition, EOG recorded pretax impairment charges in 2020 of $72 million for a commodity price-related write-down of other assets. During 2019, proved oil and gas properties 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. Included in the $207 million pretax impairment charges are $152 million of impairments of proved oil and gas properties for which EOG utilized an accepted offer from a third-party purchaser as the basis for determining fair value. In addition, EOG recorded pretax impairment charges in 2019 of $90 million for a commodity price-related write-down of other assets. EOG utilized average prices per acre from comparable market transactions and estimated discounted cash flows as the basis for determining the fair value of unproved and proved properties, respectively, received in non-cash property exchanges. See Note 10. Fair Value of Debt. At December 31, 2021 and 2020, respectively, EOG had outstanding $4,890 million and $5,640 million aggregate principal amount of senior notes, which had estimated fair values of approximately $5,577 million and $6,505 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.

Impairment Expense (Notes)

Impairment Expense (Notes)	12 Months Ended
	Dec. 31, 2021
Impairment Expense [Abstract]
Impairment Expense	Impairment Expense Impairment expense was as follows for the years ended December 31, 2021, 2020 and 2019 (in millions): 2021 2020 2019 Proved properties (1) $ 20 $ 1,268 $ 207 Unproved properties (2) 310 472 220 Other assets (3) 28 300 91 Inventories 13 — — Firm commitment contracts (4) 5 60 — Total $ 376 $ 2,100 $ 518 (1) Impairments to proved oil and gas properties in 2020 included legacy and non-core natural gas and crude oil and combo plays. Impairments to proved oil and gas properties in 2019 included domestic legacy natural gas assets. See Notes 1 and 13. (2) Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. Impairments of unproved oil and gas properties included $38 million in 2021 for the decision in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman. Impairments of unproved oil and gas properties included charges of $252 million in 2020 for certain leasehold costs that are no longer expected to be developed before expiration in the United States. See Note 1. (3) Includes impairment charges for owned and leased sand and crude-by-rail assets of $228 million in 2020 (see Note 18) and a commodity price-related write-down of other assets of $72 million and $90 million in 2020 and 2019, respectively (see Note 13). (4) Includes impairment charges of $60 million in 2020 for firm commitment contracts related to its decision to exit the Horn River Basin in British Columbia, Canada.

Asset Retirement Obligations (N

Asset Retirement Obligations (Notes)	12 Months Ended
	Dec. 31, 2021
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, 2021 and 2020 (in millions): 2021 2020 Carrying Amount at Beginning of Period $ 1,217 $ 1,111 Liabilities Incurred 81 58 Liabilities Settled (1) (131) (54) Accretion 44 47 Revisions 20 54 Foreign Currency Translations — 1 Carrying Amount at End of Period $ 1,231 $ 1,217 Current Portion $ 43 $ 50 Noncurrent Portion $ 1,188 $ 1,167 (1) Includes settlements related to asset sales and property exchanges. The current and noncurrent portions of EOG's asset retirement obligations are included in Current Liabilities - Other and Other Liabilities, respectively, on the Consolidated Balance Sheets.

Exploratory Well Costs (Notes)

Exploratory Well Costs (Notes)	12 Months Ended
	Dec. 31, 2021
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, 2021, 2020 and 2019 are presented below (in millions): 2021 2020 2019 Balance at January 1 $ 29 $ 26 $ 4 Additions Pending the Determination of Proved Reserves 73 108 83 Reclassifications to Proved Properties (41) (81) (39) Costs Charged to Expense (1) (54) (24) (22) Balance at December 31 $ 7 $ 29 $ 26 (1) Includes capitalized exploratory well costs charged to either dry hole costs or impairments. 2021 2020 2019 Capitalized exploratory well costs that have been capitalized for a period of one year or less $ 7 $ 26 $ 26 Capitalized exploratory well costs that have been capitalized for a period greater than one year (1) — 3 — Balance at December 31 $ 7 $ 29 $ 26 Number of exploratory wells that have been capitalized for a period greater than one year — 1 —

Acquisitions and Divestitures (

Acquisitions and Divestitures (Notes)	12 Months Ended
	Dec. 31, 2021
Business Combination and Asset Acquisition [Abstract]
Acquisitions and Divestitures	Acquisitions and Divestitures During 2021, EOG paid cash for property acquisitions of $95 million in the United States. Additionally during 2021, EOG recognized net gains on asset dispositions of $17 million and received proceeds of $231 million primarily due to the sale of the China assets and the disposition of the Northwest Shelf assets in New Mexico. Additionally, in the fourth quarter of 2021, EOG signed a purchase and sale agreement for the sale of primarily producing properties in the Rocky Mountain area. At December 31, 2021, the book value of the assets classified as held for sale and the related asset retirement obligations were $99 million and $105 million, respectively. During 2020, EOG paid cash for property acquisitions of $82 million in the United States and $38 million in Other International, primarily in Oman. Additionally during 2020, EOG recognized net losses on asset dispositions of $47 million primarily due to sales of proved properties and non-cash property exchanges of unproved leasehold in Texas and New Mexico and the disposition of the Marcellus Shale assets, and received proceeds of approximately $192 million.

Leases (Notes)

Leases (Notes)	12 Months Ended
	Dec. 31, 2021
Leases [Abstract]
Lessee Operating and Finance Leases [Text Block]	Leases Lease costs are classified by the function of the ROU asset. The lease costs related to exploration and development activities are initially included in the Oil and Gas Properties line on the Consolidated Balance Sheets and subsequently accounted for in accordance with the Extractive Industries - Oil and Gas Topic of the ASC. Variable lease cost represents costs incurred above the contractual minimum payments and other charges associated with leased equipment, primarily for drilling and fracturing contracts classified as operating leases. The components of lease cost for the years ended December 31, 2021, 2020 and 2019 were as follows (in millions): 2021 2020 2019 Operating Lease Cost (1) $ 295 $ 393 $ 497 Finance Lease Cost: Amortization of Lease Assets 39 21 13 Interest on Lease Liabilities 7 4 2 Variable Lease Cost 63 91 138 Short-Term Lease Cost 257 194 333 Total Lease Cost $ 661 $ 703 $ 983 (1) Operating lease cost includes impairment expenses of $35 million in 2020. The following table sets forth the amounts and classification of EOG's outstanding ROU assets and related lease liabilities at December 31, 2021 and 2020 and supplemental information for the years ended December 31, 2021 and 2020 (in millions, except lease terms and discount rates): Description Location on Balance Sheet 2021 2020 Assets Operating Leases Other Assets $ 743 $ 869 Finance Leases Property, Plant and Equipment, Net (1) 241 206 Total $ 984 $ 1,075 Liabilities Current Operating Leases Current Portion of Operating Lease Liabilities $ 240 $ 295 Finance Leases Current Portion of Long-Term Debt 37 31 Long-Term Operating Leases Other Liabilities 558 641 Finance Leases Long-Term Debt 213 181 Total $ 1,048 $ 1,148 (1) Finance lease assets are recorded net of accumulated amortization of $119 million and $81 million at December 31, 2021 and 2020, respectively. 2021 2020 Weighted Average Remaining Lease Term (in years): Operating Leases 5.3 5.3 Finance Leases 7.0 7.6 Weighted Average Discount Rate: Operating Leases 3.0 % 3.4 % Finance Leases 2.6 % 2.8 % Cash paid for leases for the years ended December 31, 2021, 2020 and 2019 was as follows (in millions): 2021 2020 2019 Repayment of Operating Lease Liabilities Associated with Operating Activities $ 207 $ 223 $ 225 Repayment of Operating Lease Liabilities Associated with Investing Activities 98 130 270 Repayment of Finance Lease Liabilities 37 19 13 Non-cash leasing activities for the year ended December 31, 2021, included the additions of $333 million of operating leases and $74 million of finance leases. Non-cash leasing activities for the year ended December 31, 2020, included the additions of $893 million of operating leases and $174 million of finance leases. Non-cash leasing activities for the year ended December 31, 2019, included the addition of $784 million of operating leases. Upon adoption of ASU 2016-02 effective January 1, 2019, EOG recognized operating lease ROU of $566 million. At December 31, 2021, the future minimum lease payments under non-cancellable leases were as follows (in millions): Operating Leases Finance Leases 2022 $ 262 $ 42 2023 188 37 2024 113 37 2025 80 36 2026 59 30 2027 and Beyond 172 94 Total Lease Payments 874 276 Less: Discount to Present Value 76 26 Total Lease Liabilities 798 250 Less: Current Portion of Lease Liabilities 240 37 Long-Term Lease Liabilities $ 558 $ 213 At December 31, 2021, EOG had additional leases of $98 million, which are expected to commence in 2022 with lease terms of three months to nine years.

Oil and Gas Exploration and Pro

Oil and Gas Exploration and Production Industries Disclosures (Notes)	12 Months Ended
	Dec. 31, 2021
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Oil and Gas Exploration and Production Industries Disclosures	Oil and Gas Producing Activities The following disclosures are made in accordance with Financial Accounting Standards Board Accounting Standards Update No. 2010-03 "Oil and Gas Reserve Estimation and Disclosures" and the United States Securities and Exchange Commission's (SEC) final rule on "Modernization of Oil and Gas Reporting." Oil and Gas Reserves. Users of this information should be aware that the process of estimating quantities of "proved," "proved developed" and "proved undeveloped" crude oil, natural gas liquids (NGLs) and natural gas reserves is complex, requiring significant subjective decisions in the evaluation of available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including, but not limited to, additional development activity; evolving production history; crude oil and condensate, NGL and natural gas prices; and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. Although reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. Proved reserves represent estimated quantities of crude oil, NGLs and natural gas, which, by analysis of geoscience and engineering data, can be estimated, with reasonable certainty, to be economically producible from a given date forward from known reservoirs under then-existing economic conditions, operating methods and government regulations before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Proved developed reserves are proved reserves expected to be recovered under operating methods being utilized at the time the estimates were made, through wells and equipment in place or if the cost of any required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves (PUDs) are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion or recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. PUDs can be recorded in respect of a particular undrilled location only if the location is scheduled, under the then-current drilling and development plan, to be drilled within five years from the date that the PUDs were recorded, unless specific factors (such as those described in interpretative guidance issued by the Staff of the SEC) justify a longer timeframe. Likewise, absent any such specific factors, PUDs associated with a particular undeveloped drilling location shall be removed from the estimates of proved reserves if the location is scheduled, under the then-current drilling and development plan, to be drilled on a date that is beyond five years from the date that the PUDs were recorded. EOG has formulated development plans for all drilling locations associated with its PUDs at December 31, 2021. Under these plans, each PUD location will be drilled within five years from the date it was recorded. Estimates for PUDs are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty. In making estimates of PUDs, EOG's technical staff, including engineers and geoscientists, perform detailed technical analysis of each potential drilling location within its inventory of prospects. In making a determination as to which of these locations would penetrate undrilled portions of the formation that can be judged, with reasonable certainty, to be continuous and contain economically producible crude oil, NGLs and natural gas, studies are conducted using numerous data elements and analysis techniques. EOG's technical staff estimates the hydrocarbons in place, by mapping the entirety of the play in question using seismic techniques, typically employing two-dimensional and three-dimensional data. This analysis is integrated with other static data, including, but not limited to, core analysis, mechanical properties of the formation, thermal maturity indicators, and well logs of existing penetrations. Highly specialized equipment is utilized to prepare rock samples in assessing microstructures which contribute to porosity and permeability. Analysis of dynamic data is then incorporated to arrive at the estimated fractional recovery of hydrocarbons in place. Data analysis techniques employed include, but are not limited to, well testing analysis, static bottom hole pressure analysis, flowing bottom hole pressure analysis, analysis of historical production trends, pressure transient analysis and rate transient analysis. Application of proprietary rate transient analysis techniques in low permeability rocks allow for quantification of estimates of contribution to production from both fractures and rock matrix. The impact of optimal completion techniques is a key factor in determining if the PUDs reflected in prospective locations are reasonably certain of being economically producible. EOG's technical staff estimates the recovery improvement that might be achieved when completing horizontal wells with multi-stage fracture stimulation. In the early stages of development of a play, EOG determines the optimal length of the horizontal lateral and multi-stage fracture stimulation using the aforementioned analysis techniques along with pilot drilling programs and gathering of microseismic data. The process of analyzing static and dynamic data, well completion optimization data and the results of early development activities provides the appropriate level of certainty as well as support for the economic producibility of the plays in which PUDs are reflected. EOG has found this approach to be effective based on successful application in analogous reservoirs in low permeability resource plays. Certain of EOG's Trinidad reserves are held under production sharing contracts where EOG's interest varies with prices and production volumes. Trinidad reserves, as presented on a net basis, assume prices in existence at the time the estimates were made and EOG's estimate of future production volumes. Future fluctuations in prices, production rates or changes in political or regulatory environments could cause EOG's share of future production from Trinidadian reserves to be materially different from that presented. Estimates of proved reserves at December 31, 2021, 2020 and 2019 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 18 professionals, all of whom hold, at a minimum, bachelor's degrees in engineering, and three 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 35 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, processing and applicable fractionation costs, future capital expenditures and EOG's net ownership percentages, are obtained from other departments within EOG. EOG's Internal Audit Department conducts testing with respect to such non-technical inputs. Additionally, EOG engages DeGolyer and MacNaughton (D&M), independent petroleum consultants, to perform independent reserves evaluation of select EOG properties comprising not less than 75% of EOG's estimates of proved reserves. EOG's Board of Directors requires that D&M's and EOG's reserve quantities for the properties evaluated by D&M vary by no more than 5% in the aggregate. Once completed, EOG's year-end reserves are presented to senior management, including the Chief Executive Officer; the President and 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, 2021, 2020 and 2019 covered producing areas containing 78%, 83% and 82%, 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 27, 2022, 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, 2021, 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, 2021, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2021, as estimated by the Engineering and Acquisitions Department of EOG: NET PROVED RESERVE SUMMARY United Trinidad Other International (1) Total NET PROVED RESERVES Crude Oil (MMBbl) (2) Net proved reserves at December 31, 2018 1,532 — — 1,532 Revisions of previous estimates (43) — — (43) Purchases in place 3 — — 3 Extensions, discoveries and other additions 370 — — 370 Sales in place (1) — — (1) Production (167) — — (167) Net proved reserves at December 31, 2019 1,694 — — 1,694 Revisions of previous estimates (225) — — (225) Purchases in place 2 — — 2 Extensions, discoveries and other additions 194 1 — 195 Sales in place (3) — — (3) Production (149) — — (149) Net proved reserves at December 31, 2020 1,513 1 — 1,514 Revisions of previous estimates (116) — — (116) Purchases in place 2 — — 2 Extensions, discoveries and other additions 311 1 — 312 Sales in place (2) — — (2) Production (162) — — (162) Net proved reserves at December 31, 2021 1,546 2 — 1,548 Natural Gas Liquids (MMBbl) (2) Net proved reserves at December 31, 2018 614 — — 614 Revisions of previous estimates 5 — — 5 Purchases in place 2 — — 2 Extensions, discoveries and other additions 168 — — 168 Sales in place (1) — — (1) Production (48) — — (48) Net proved reserves at December 31, 2019 740 — — 740 Revisions of previous estimates (60) — — (60) Purchases in place 4 — — 4 Extensions, discoveries and other additions 180 — — 180 Sales in place (1) — — (1) Production (50) — — (50) Net proved reserves at December 31, 2020 813 — — 813 Revisions of previous estimates (128) — — (128) Purchases in place 3 — — 3 Extensions, discoveries and other additions 194 — — 194 Sales in place — — — — Production (53) — — (53) Net proved reserves at December 31, 2021 829 — — 829 United Trinidad Other International (1) Total Natural Gas (Bcf) (3) Net proved reserves at December 31, 2018 4,391 237 59 4,687 Revisions of previous estimates (184) 47 3 (134) Purchases in place 72 — — 72 Extensions, discoveries and other additions 1,176 87 10 1,273 Sales in place (15) — — (15) Production (405) (95) (13) (513) Net proved reserves at December 31, 2019 5,035 276 59 5,370 Revisions of previous estimates (498) 5 1 (492) Purchases in place 26 — — 26 Extensions, discoveries and other additions 1,078 54 — 1,132 Sales in place (157) — — (157) Production (441) (66) (12) (519) Net proved reserves at December 31, 2020 5,043 269 48 5,360 Revisions of previous estimates 754 26 3 783 Purchases in place 23 — — 23 Extensions, discoveries and other additions 2,574 100 — 2,674 Sales in place (4) — (48) (52) Production (483) (80) (3) (566) Net proved reserves at December 31, 2021 7,907 315 — 8,222 Oil Equivalents (MMBoe) (2) Net proved reserves at December 31, 2018 2,878 40 10 2,928 Revisions of previous estimates (68) 8 — (60) Purchases in place 17 — — 17 Extensions, discoveries and other additions 734 14 2 750 Sales in place (5) — — (5) Production (283) (16) (2) (301) Net proved reserves at December 31, 2019 3,273 46 10 3,329 Revisions of previous estimates (368) 1 — (367) Purchases in place 10 — — 10 Extensions, discoveries and other additions 554 10 — 564 Sales in place (31) — — (31) Production (272) (11) (2) (285) Net proved reserves at December 31, 2020 3,166 46 8 3,220 Revisions of previous estimates (118) 4 — (114) Purchases in place 9 — — 9 Extensions, discoveries and other additions 934 18 — 952 Sales in place (3) — (8) (11) Production (295) (14) — (309) Net proved reserves at December 31, 2021 3,693 54 — 3,747 (1) Other International includes EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. (2) Million barrels or million barrels of oil equivalent, as applicable; oil equivalents include crude oil and condensate, NGLs and natural gas. Oil equivalents are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. (3) Billion cubic feet. During 2021, EOG added 952 million barrels of oil equivalent (MMBoe) of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin. Approximately 53% of the 2021 reserve additions were crude oil and condensate and NGLs, and substantially all were in the United States. Sales in place of 11 MMBoe were primarily related to the sale of the China assets and the sale or exchange of other producing assets. Revisions of previous estimates of negative 114 MMBoe for 2021 included an upward revision of 194 MMBoe primarily due to increases in the average crude oil, NGLs and natural gas prices used in the December 31, 2021, reserves estimation as compared to the prices used in the prior year estimate. The primary areas affected were the Permian Basin and the Rocky Mountain area. Revisions other than price of negative 308 MMBoe were primarily related to the removal from the five-year development plan of certain PUD locations. These locations were replaced with more economic locations in the Permian Basin and the Dorado gas play, and the related reserves from these locations were included as extensions, discoveries and other additions. Purchases in place of 9 MMBoe were primarily related to the Permian Basin and the purchase or exchange of other producing assets. During 2020, EOG added 564 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin. Approximately 67% of the 2020 reserve additions were crude oil and condensate and NGLs, and substantially all were in the United States. Sales in place of 31 MMBoe were primarily related to the sale of the Marcellus Shale assets and the sale or exchange of other producing assets. Revisions of previous estimates of negative 367 MMBoe for 2020 included a downward revision of 278 MMBoe primarily due to decreases in the average crude oil, NGLs and natural gas prices used in the December 31, 2020, reserves estimation as compared to the prices used in the prior year estimate. The primary areas affected were the Eagle Ford oil play and the Rocky Mountain area. Purchases in place of 10 MMBoe were primarily related to the Permian Basin and the purchase or exchange of other producing assets. During 2019, EOG added 750 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin, the Eagle Ford oil play 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. United Trinidad Other International (1) Total NET PROVED DEVELOPED RESERVES Crude Oil (MMBbl) December 31, 2018 713 — — 713 December 31, 2019 801 — — 801 December 31, 2020 792 1 — 793 December 31, 2021 886 — — 886 Natural Gas Liquids (MMBbl) December 31, 2018 341 — — 341 December 31, 2019 387 — — 387 December 31, 2020 392 — — 392 December 31, 2021 416 — — 416 Natural Gas (Bcf) December 31, 2018 2,699 224 41 2,964 December 31, 2019 2,974 178 42 3,194 December 31, 2020 2,586 171 32 2,789 December 31, 2021 3,743 131 — 3,874 Oil Equivalents (MMBoe) December 31, 2018 1,503 38 7 1,548 December 31, 2019 1,684 30 7 1,721 December 31, 2020 1,614 30 5 1,649 December 31, 2021 1,926 22 — 1,948 NET PROVED UNDEVELOPED RESERVES Crude Oil (MMBbl) December 31, 2018 819 — — 819 December 31, 2019 893 — — 893 December 31, 2020 721 — — 721 December 31, 2021 660 2 — 662 Natural Gas Liquids (MMBbl) December 31, 2018 273 — — 273 December 31, 2019 353 — — 353 December 31, 2020 421 — — 421 December 31, 2021 413 — — 413 Natural Gas (Bcf) December 31, 2018 1,692 13 18 1,723 December 31, 2019 2,061 98 17 2,176 December 31, 2020 2,457 98 16 2,571 December 31, 2021 4,164 184 — 4,348 Oil Equivalents (MMBoe) December 31, 2018 1,375 2 3 1,380 December 31, 2019 1,589 16 3 1,608 December 31, 2020 1,552 16 3 1,571 December 31, 2021 1,767 32 — 1,799 (1) Other International includes EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. Net Proved Undeveloped Reserves. The following table presents the changes in EOG's total PUDs during 2021, 2020 and 2019 (in MMBoe): 2021 2020 2019 Balance at January 1 1,571 1,608 1,380 Extensions and Discoveries 779 456 578 Revisions (305) (277) (50) Acquisition of Reserves — — 2 Sale of Reserves (3) (4) — Conversion to Proved Developed Reserves (243) (212) (302) Balance at December 31 1,799 1,571 1,608 For the twelve-month period ended December 31, 2021, total PUDs increased by 228 MMBoe to 1,799 MMBoe. EOG added approximately 40 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion. Based on the technology employed by EOG to identify and record PUDs (see discussion of technology employed on pages F-39 and F-40 of this Annual Report on Form 10-K), EOG added 739 MMBoe of PUDs. The PUD additions were primarily in the Permian Basin and 52% of the additions were crude oil and condensate and NGLs. During 2021, EOG drilled and transferred 243 MMBoe of PUDs to proved developed reserves at a total capital cost of $1,619 million. Revisions of previous estimates of negative 305 MMBoe of PUDs for 2021 included an upward price revision of 29 MMBoe due to increases in the average crude oil, NGLs and natural gas prices used in the December 31, 2021, reserves estimation as compared to the prices used in the prior year estimate. Revisions other than price of negative 334 MMBoe were primarily related to the removal from the five-year development plan of certain PUD locations. These locations were replaced with more economic locations in the Permian Basin and the Dorado gas play, and the related reserves from these locations were included as extensions and discoveries. 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, 2020, total PUDs decreased by 37 MMBoe to 1,571 MMBoe. EOG added approximately 7 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion. Based on the technology employed by EOG to identify and record PUDs, EOG added 449 MMBoe of PUDs. The PUD additions were primarily in the Permian Basin and 67% of the additions were crude oil and condensate and NGLs. During 2020, EOG drilled and transferred 212 MMBoe of PUDs to proved developed reserves at a total capital cost of $1,674 million. Revisions of previous estimates of negative 277 MMBoe of PUDs for 2020 included a downward price revision of 77 MMBoe due to decreases in the average crude oil, NGLs and natural gas prices used in the December 31, 2020, reserves estimation as compared to the prices used in the prior year estimate. Revisions other than price of negative 200 MMBoe were primarily related to the removal of PUD locations due to lower projected capital spending over the next five years as compared to the prior year projections. The primary areas affected were the Eagle Ford oil play and the Rocky Mountain area. For the twelve-month period ended December 31, 2019, total PUDs increased by 228 MMBoe to 1,608 MMBoe. EOG added approximately 38 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion. Based on the technology employed by EOG to identify and record PUDs, EOG added 540 MMBoe. The PUD additions were primarily in the Permian Basin, the Eagle Ford oil play 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. 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, 2021 and 2020: 2021 2020 Proved properties $ 64,876 $ 61,725 Unproved properties 2,768 3,068 Total 67,644 64,793 Accumulated depreciation, depletion and amortization (41,907) (38,751) Net capitalized costs $ 25,737 $ 26,042 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, 2021, 2020 and 2019: United Trinidad Other International (1) Total 2021 Acquisition Costs of Properties Unproved (2) $ 207 $ — $ 8 $ 215 Proved (3) 100 — — 100 Subtotal 307 — 8 315 Exploration Costs 296 7 51 354 Development Costs (4) 3,206 77 17 3,300 Total $ 3,809 $ 84 $ 76 $ 3,969 2020 Acquisition Costs of Properties Unproved (5) $ 265 $ — $ — $ 265 Proved (6) 97 — 38 135 Subtotal 362 — 38 400 Exploration Costs 203 81 12 296 Development Costs (7) 2,998 4 20 3,022 Total $ 3,563 $ 85 $ 70 $ 3,718 2019 Acquisition Costs of Properties Unproved (8) $ 276 $ — $ — $ 276 Proved (9) 380 — — 380 Subtotal 656 — — 656 Exploration Costs 214 47 12 273 Development Costs (10) 5,662 25 12 5,699 Total $ 6,532 $ 72 $ 24 $ 6,628 (1) Other International primarily consists of EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. EOG began exploration programs in Australia in the third quarter of 2021 and in Oman in the third quarter of 2020. The decision was reached in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman. (2) Includes non-cash unproved leasehold acquisition costs of $45 million related to property exchanges. (3) Includes non-cash proved property acquisition costs of $5 million related to property exchanges. (4) Includes Asset Retirement Costs of $86 million, $24 million and $17 million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment. (5) Includes non-cash unproved leasehold acquisition costs of $197 million related to property exchanges. (6) Includes non-cash proved property acquisition costs of $15 million related to property exchanges. (7) Includes Asset Retirement Costs of $97 million and $20 million for the United States and Other International, respectively. Excludes other property, plant and equipment. (8) Includes non-cash unproved leasehold acquisition costs of $98 million related to property exchanges. (9) Includes non-cash proved property acquisition costs of $52 million related to property exchanges. (10) 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. 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, 2021, 2020 and 2019: United Trinidad Other International (2) Total 2021 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues $ 15,062 $ 301 $ 18 $ 15,381 Other 108 — — 108 Total 15,170 301 18 15,489 Exploration Costs 137 5 12 154 Dry Hole Costs 29 — 42 71 Transportation Costs 863 — — 863 Gathering and Processing Costs 559 — — 559 Production Costs 2,108 39 8 2,155 Impairments 312 3 61 376 Depreciation, Depletion and Amortization 3,411 87 6 3,504 Income (Loss) Before Income Taxes 7,751 167 (111) 7,807 Income Tax Provision 1,690 73 (1) 1,762 Results of Operations $ 6,061 $ 94 $ (110) $ 6,045 2020 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues $ 7,056 $ 180 $ 55 $ 7,291 Other 60 — — 60 Total 7,116 180 55 7,351 Exploration Costs 136 2 8 146 Dry Hole Costs 13 — — 13 Transportation Costs 734 1 — 735 Gathering and Processing Costs 459 — — 459 Production Costs 1,480 27 10 1,517 Impairments 2,018 1 81 2,100 Depreciation, Depletion and Amortization 3,192 60 16 3,268 Income (Loss) Before Income Taxes (916) 89 (60) (887) Income Tax Provision (220) 24 3 (193) Results of Operations $ (696) $ 65 $ (63) $ (694) 2019 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues $ 11,251 $ 270 $ 61 $ 11,582 Other 134 — — 134 Total 11,385 270 61 11,716 Exploration Costs 130 4 6 140 Dry Hole Costs 11 13 4 28 Transportation Costs 753 4 1 758 Gathering and Processing Costs 479 — — 479 Production Costs 2,063 31 40 2,134 Impairments 511 6 1 518 Depreciation, Depletion and Amortization 3,561 79 18 3,658 Income (Loss) Before Income Taxes 3,877 133 (9) 4,001 Income Tax Provision 884 55 3 942 Results of Operations $ 2,993 $ 78 $ (12) $ 3,059 (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, 2021. (2) Other International primarily consists of EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. EOG began exploration programs in Australia in the third quarter of 2021 and in Oman in the third quarter of 2020. The decision was reached in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman. 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, 2021, 2020 and 2019: United Trinidad Other International (1) Composite Year Ended December 31, 2021 $ 3.71 $ 2.32 $ 16.13 $ 3.67 Year Ended December 31, 2020 $ 3.75 $ 2.33 $ 6.78 $ 3.72 Year Ended December 31, 2019 $ 4.59 $ 1.85 $ 18.26 $ 4.54 (1) Other International primarily consists of EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. 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 2021, 2020 and 2019. 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, 2021, 2020 and 2019: United Trinidad Other International (1) Total 2021 Future cash inflows (2) $ 166,316 $ 1,135 $ — $ 167,451 Future production costs (44,905) (258) — (45,163) Future development costs (13,885) (380) — (14,265) Future income taxes (22,831) (84) — (22,915) Future net cash flows 84,695 413 — 85,108 Discount to present value at 10% annual rate (38,834) (88) — (38,922) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 45,861 $ 325 $ — $ 46,186 2020 Future cash inflows (3) $ 73,727 $ 901 $ 281 $ 74,909 Future production costs (34,619) (153) (54) (34,826) Future development costs (15,159) (227) (18) (15,404) Future income taxes (4,337) (81) (24) (4,442) Future net cash flows 19,612 440 185 20,237 Discount to present value at 10% annual rate (8,410) (101) (36) (8,547) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 11,202 $ 339 $ 149 $ 11,690 2019 Future cash inflows (4) $ 120,360 $ 813 $ 305 $ 121,478 Future production costs (42,387) (166) (88) (42,641) Fu

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2021
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation. The consolidated financial statements of EOG include the accounts of all domestic and foreign subsidiaries. Investments in unconsolidated affiliates, in which EOG is able to exercise significant influence, are accounted for using the equity method. All intercompany accounts and transactions have been eliminated. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Financial Instruments	Financial Instruments. EOG's financial instruments consist of cash and cash equivalents, commodity derivative contracts, accounts receivable, accounts payable and current and long-term debt. The carrying values of cash and cash equivalents, commodity derivative contracts, accounts receivable and accounts payable approximate fair value (see Notes 2 and 12). Effective January 1, 2020, EOG adopted the provisions of Accounting Standards Update (ASU) 2016-13, "Measurement of Credit Losses on Financial Instruments" (ASU 2016-13). ASU 2016-13 changes the impairment model for financial assets and certain other instruments by requiring entities to adopt a forward-looking expected loss model that will result in earlier recognition of credit losses. EOG elected to adopt ASU 2016-13 using the modified retrospective approach with a cumulative effect adjustment to retained earnings as of the effective date. Financial results reported in periods prior to January 1, 2020, are unchanged. EOG assessed its applicable financial assets, which are primarily its accounts receivable from hydrocarbon sales and joint interest billings to partners in oil and gas operations, including foreign state-owned entities in the oil and gas industry. Based on its assessment and various potential remedies ensuring collection, EOG did not record an impact to retained earnings upon adoption and expects current and future credit losses to be immaterial. EOG continues to monitor the credit risk from third-party companies to determine if expected credit losses may become material.
Cash and Cash Equivalents	Cash and Cash Equivalents. EOG records as cash equivalents all highly liquid short-term investments with original maturities of three months or less.
Oil and Gas Operations	Oil and Gas Operations. EOG accounts for its crude oil and natural gas exploration and production activities under the successful efforts method of accounting. Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred. Oil and gas exploration costs, other than the costs of drilling exploratory wells, are expensed as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether EOG has discovered commercial quantities of proved reserves. If commercial quantities of proved reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether commercial quantities of proved reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the estimated reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made (see Note 16). Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account. Oil and gas properties are grouped in accordance with the provisions of the Extractive Industries - Oil and Gas Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC). The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. Amortization rates are updated quarterly to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions and/or property dispositions and 4) impairments. When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the group. If the expected undiscounted future cash flows, based on EOG's estimate of (and assumptions regarding) future crude oil, NGLs and natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach described in the Fair Value Measurement Topic of the ASC. In certain instances, EOG utilizes accepted offers from third-party purchasers as the basis for determining fair value.
Other Property, Plant and Equipment	Other Property, Plant and Equipment . Other property, plant and equipment consists of gathering and processing assets, compressors, buildings and leasehold improvements, computer hardware and software, vehicles, and furniture and fixtures. Other property, plant and equipment is generally depreciated on a straight-line basis over the estimated useful lives of the property, plant and equipment, which range from 3 years to 45 years.
Inventories	Inventories. Inventories consist primarily of tubular goods, materials for completion operations, well equipment and gathering lines held for use in the exploration for, and development and production of, crude oil, NGLs and natural gas reserves. EOG accounts for inventories at the lower of cost and net realizable value with adjustments made, as appropriate, to recognize any reductions in value.
Revenue Recognition	Revenue Recognition. EOG presents disaggregated revenues by type of commodity within its Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) and by geographic areas defined as operating segments. See Note 11. Revenues are recognized for the sale of crude oil and condensate, NGLs and natural gas at the point control of the product is transferred to the customer, typically when production is delivered and title or risk of loss transfers to the customer. Arrangements for such sales are evidenced by signed contracts with prices typically based on stated market indices, with certain adjustments for product quality and geographic location. As EOG typically invoices customers shortly after performance obligations have been fulfilled, contract assets and contract liabilities are not recognized. The balances of accounts receivable from contracts with customers as of December 31, 2021 and 2020, were $2,130 million and $1,337 million, respectively, and were included in Accounts Receivable, Net on the Consolidated Balance Sheets. Losses incurred on receivables from contracts with customers are infrequent and have been immaterial. Certain arrangements provide for the sale of fixed quantities of commodities in future years with pricing mechanisms based on future market prices at time of delivery. EOG does not disclose the value of these obligations given the uncertainty of the future realized transaction price. Crude Oil and Condensate. EOG sells its crude oil and condensate production at the wellhead or further downstream at a contractually-specified delivery point. Revenue is recognized when control transfers to the customer based on contract terms which reflect prevailing market prices. Any costs incurred prior to the transfer of control, such as gathering and transportation, are recognized as Operating Expenses. Natural Gas Liquids. EOG delivers certain of its natural gas production to either EOG-owned processing facilities or third-party processing facilities, where extraction of NGLs occurs. For EOG-owned facilities, revenue is recognized after processing upon transfer of NGLs to a customer. For third-party facilities, extracted NGLs are sold to the owner of the processing facility at the tailgate, or EOG takes possession and sells the extracted NGLs at the tailgate or exercises its option to sell further downstream to various customers. Under typical arrangements for third-party facilities, revenue is recognized after processing upon the transfer of control of the NGLs, either at the tailgate of the processing plant or further downstream. EOG recognizes revenues based on contract terms which reflect prevailing market prices, with any costs prior to the transfer of control, such as processing, transportation and fractionation fees, recognized as Transportation Costs and Gathering and Processing Costs, as appropriate. Natural Gas. EOG sells its natural gas production either at the wellhead or further downstream at a contractually-specified delivery point. In connection with the extraction of NGLs, EOG sells residue gas under separate agreements. Typically, EOG takes possession of the natural gas at the tailgate of the processing facility and sells it at the tailgate or further downstream. In each case, EOG recognizes revenues when control transfers to the customer, based on contract terms which reflect prevailing market prices. Gathering, Processing and Marketing. Gathering, processing and marketing revenues represent sales of third-party crude oil and condensate, NGLs and natural gas, as well as fees associated with gathering and processing third-party natural gas and revenues from sales of EOG-owned sand. EOG evaluates whether it is the principal or agent under these transactions. As control of the underlying commodity is transferred to EOG prior to the gathering, processing and marketing activities, EOG considers itself the principal of these arrangements. Accordingly, EOG recognizes these transactions on a gross basis. Purchases of third-party commodities are recorded as Marketing Costs, with sales of third-party commodities and fees received for gathering and processing recorded as Gathering, Processing and Marketing revenues.
Capitalized Interest Costs	Capitalized Interest Costs.  Interest costs have been capitalized as a part of the historical cost of unproved oil and gas properties.  The amount capitalized is an allocation of the interest cost incurred during the reporting period.  Capitalized interest is computed only during the exploration and development phases and ceases once production begins.  The interest rate used for capitalization purposes is based on the interest rates on EOG's outstanding borrowings.
Accounting for Risk Management Activities	Accounting for Risk Management Activities. 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, 2021, EOG elected not to designate any of its financial commodity derivative instruments as accounting hedges and, accordingly, changes in the fair value of these outstanding derivative instruments are recognized as gains or losses in the period of change. The gains or losses are recorded as Gains (Losses) on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss). The related cash flow impact of settled contracts is reflected as cash flows from operating activities. EOG employs net presentation of derivative assets and liabilities for financial reporting purposes when such assets and liabilities are with the same counterparty and subject to a master netting arrangement. See Note 12.
Income Taxes	Income Taxes. Income taxes are accounted for using the asset and liability approach. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. EOG assesses the realizability of deferred tax assets and recognizes valuation allowances as appropriate. See Note 6. Effective January 1, 2021, EOG adopted the provisions of Accounting Standards Update (ASU), "Income Taxes (Topic 740) Simplifying the Accounting for Income Taxes" (ASU 2019-12). ASU 2019-12 amends certain aspects of accounting for income taxes, including the removal of specific exceptions within existing U.S. GAAP related to the incremental approach for intraperiod tax allocation and updates 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. The effects of ASU 2019-12 applicable to EOG were all required on a prospective basis. There was no impact upon adoption of ASU 2019-12 to EOG's consolidated financial statements or related disclosures.
Foreign Currency Translation	Foreign Currency Translation. The United States dollar is the functional currency for all of EOG's consolidated subsidiaries except for its Canadian subsidiaries, for which the functional currency is the Canadian dollar. For subsidiaries whose functional currency is deemed to be other than the United States dollar, asset and liability accounts are translated at year-end exchange rates and revenues and expenses are translated at average exchange rates prevailing during the year. Translation adjustments are included in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets. Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period. See Note 4.
Net Income (Loss) Per Share	Net Income (Loss) Per Share. Basic net income (loss) per share is computed on the basis of the weighted-average number of common shares outstanding during the period. Diluted net income (loss) per share is computed based upon the weighted-average number of common shares outstanding during the period plus the assumed issuance of common shares for all potentially dilutive securities. See Note 9.
Stock-Based Compensation	Stock-Based Compensation . EOG measures the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. See Note 7.
Leases	Leases. Effective January 1, 2019, EOG adopted the provisions of ASU 2016-02, "Leases (Topic 842)" (ASU 2016-02). ASU 2016-02 and other related ASUs require that lessees recognize a right-of-use (ROU) asset and related lease liability, representing the obligation to make lease payments for certain lease transactions, on the Consolidated Balance Sheets and disclose additional leasing information. EOG elected to adopt ASU 2016-02 and other related ASUs using the modified retrospective approach with a cumulative-effect adjustment to the opening balance of retained earnings as of the effective date. Financial results reported in periods prior to January 1, 2019, are unchanged. Additionally, EOG elected the package of practical expedients within ASU 2016-02 that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases, or (iii) initial direct costs for any existing leases, but did not elect the practical expedient of hindsight when determining the lease term of existing contracts at the effective date. EOG also elected the practical expedient under ASU 2018-01, "Leases (Topic 842) - Land Easement Practical Expedient for Transition to Topic 842," and did not evaluate existing or expired land easements not previously accounted for as leases prior to the January 1, 2019 effective date. There was no impact to retained earnings upon adoption of ASU 2016-02 and other related ASUs. In the ordinary course of business, EOG enters into contracts for drilling, fracturing, compression, real estate and other services which contain equipment and other assets and that meet the definition of a lease under ASU 2016-02. The lease term for these contracts, which includes any renewals at EOG's option that are reasonably certain to be exercised, ranges from one month to 30 years. ROU assets and related liabilities are recognized on the commencement date on the Consolidated Balance Sheets based on future lease payments, discounted based on the rate implicit in the contract, if readily determinable, or EOG's incremental borrowing rate commensurate with the lease term of the contract. EOG estimates its incremental borrowing rate based on the approximate rate required to borrow on a collateralized basis. Contracts with lease terms of less than 12 months are not recorded on the Consolidated Balance Sheets, but instead are disclosed as short-term lease cost. EOG has elected not to separate non-lease components from all leases, excluding those for fracturing services, real estate and salt water disposal, as lease payments under these contracts contain significant non-lease components, such as labor and operating costs. See Note 18.
Recently Issued Accounting Standards	Recently Issued Accounting Standards. In March 2020, the FASB issued ASU 2020-04, "Reference Rate Reform (Topic 848)" (ASU 2020-04), which provides optional expedients and exceptions for accounting treatment of contracts which are affected by the anticipated discontinuation of the London InterBank Offered Rate (LIBOR) and other rates resulting from rate reform. Contract terms that are modified due to the replacement of a reference rate are not required to be remeasured or reassessed under relevant accounting standards. Early adoption is permitted. ASU 2020-04 covers certain contracts which reference these rates and that are entered into on or before December 31, 2022. EOG has evaluated the provisions of ASU 2020-04 and does not expect the application of ASU 2020-04 to have a material impact on its consolidated financial statements and related disclosures related to its $2.0 billion senior unsecured Revolving Credit Agreement.

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt at December 31, 2021 and 2020 consisted of the following (in millions): 2021 2020 4.100% Senior Notes due 2021 $ — $ 750 2.625% Senior Notes due 2023 1,250 1,250 3.15% Senior Notes due 2025 500 500 4.15% Senior Notes due 2026 750 750 6.65% Senior Notes due 2028 140 140 4.375% Senior Notes due 2030 750 750 3.90% Senior Notes due 2035 500 500 5.10% Senior Notes due 2036 250 250 4.950% Senior Notes due 2050 750 750 Long-Term Debt 4,890 5,640 Finance Leases (see Note 18) 250 212 Less: Current Portion of Long-Term Debt 37 781 Unamortized Debt Discount 27 31 Debt Issuance Costs 4 5 Total Long-Term Debt $ 5,072 $ 5,035

Stockholder's Equity (Tables)

Stockholder's Equity (Tables)	12 Months Ended
	Dec. 31, 2021
Stockholders' Equity Note [Abstract]
Common stock activity	The following summarizes Common Stock activity for each of the years ended December 31, 2021, 2020 and 2019 (in thousands): Common Shares Issued Treasury Outstanding 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 117 107 224 Treasury Stock Issued Under Stock-Based Compensation Plans — 289 289 Balance at December 31, 2019 582,213 (299) 581,914 Common Stock Issued Under Stock-Based Compensation Plans 1,482 — 1,482 Treasury Stock Purchased (1) — (389) (389) Common Stock Issued Under Employee Stock Purchase Plan — 377 377 Treasury Stock Issued Under Stock-Based Compensation Plans — 187 187 Balance at December 31, 2020 583,695 (124) 583,571 Common Stock Issued Under Stock-Based Compensation Plans 1,511 — 1,511 Treasury Stock Purchased (1) — (504) (504) Common Stock Issued Under Employee Stock Purchase Plan 316 — 316 Treasury Stock Issued Under Stock-Based Compensation Plans — 371 371 Balance at December 31, 2021 585,522 (257) 585,265

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Loss (Tables)	12 Months Ended
	Dec. 31, 2021
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss)	The components of Accumulated Other Comprehensive Loss at December 31, 2021 and 2020 consisted of the following (in millions): Foreign Currency Translation Adjustment Other Total December 31, 2019 $ (3) $ (2) $ (5) Other comprehensive loss before taxes (7) — (7) Tax effects — — — Other comprehensive loss (7) — (7) December 31, 2020 (10) (2) (12) Other comprehensive loss before taxes (1) 1 — Tax effects — — — Other comprehensive loss (1) 1 — December 31, 2021 $ (11) $ (1) $ (12)

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2021
Share-based Payment Arrangement [Abstract]
Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs	Stock-based compensation expense is included on the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) based upon the job functions of the employees receiving the grants. Compensation expense related to EOG's stock-based compensation plans for the years ended December 31, 2021, 2020 and 2019 was as follows (in millions): 2021 2020 2019 Lease and Well $ 49 $ 52 $ 56 Gathering and Processing Costs 3 1 1 Exploration Costs 20 21 26 General and Administrative 80 72 92 Total $ 152 $ 146 $ 175
Vesting Schedule	The vesting schedules for grants of stock options, SARs, restricted stock and restricted stock units, and Performance Units are generally as follows: Grant Type Vesting Schedule Stock Options/SARs Vesting in increments of one-third on each of the first three anniversaries, respectively, of the date of grant Restricted Stock/Restricted Stock Units "Cliff" vesting three years from the date of grant Performance Units "Cliff" vesting on the February 28th following the three-year performance period and the Compensation and Human Resources Committee's certification of the applicable performance multiple
Weighted Average Fair Values and Valuation Assumptions	Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants for the years ended December 31, 2021, 2020 and 2019 were as follows: Stock Options/SARs ESPP 2021 2020 2019 2021 2020 2019 Weighted Average Fair Value of Grants $ 24.92 $ 11.06 $ 19.49 $ 18.12 $ 19.14 $ 22.83 Expected Volatility 42.24 % 44.47 % 32.02 % 51.27 % 53.48 % 34.78 % Risk-Free Interest Rate 0.50 % 0.21 % 1.69 % 0.07 % 0.90 % 2.27 % Dividend Yield 2.26 % 3.27 % 1.39 % 2.89 % 2.27 % 1.04 % Expected Life 5.2 years 5.2 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, 2021, 2020 and 2019 (stock options and SARs in thousands): 2021 2020 2019 Number Weighted Number Weighted Number Weighted Outstanding at January 1 10,186 $ 84.08 9,395 $ 94.53 8,310 $ 96.90 Granted 1,982 81.68 1,996 37.63 1,965 75.39 Exercised (1) (1,130) 63.98 (23) 69.59 (606) 61.43 Forfeited (1,069) 98.15 (1,182) 88.93 (274) 102.57 Outstanding at December 31 9,969 84.37 10,186 84.08 9,395 94.53 Stock Options/SARs Exercisable at December 31 6,197 95.33 6,343 96.41 5,275 94.21 (1) The total intrinsic value of stock options/SARs exercised during the years 2021, 2020 and 2019 was $27 million, $0.4 million and $14 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, 2021 (stock options and SARs in thousands): Stock Options/SARs Outstanding Stock Options/SARs Exercisable Range of Stock Weighted Weighted Aggregate Intrinsic Value (1) Stock Weighted Weighted Aggregate Intrinsic Value (1) $ 34.00 to $ 52.99 1,640 6 $ 37.50 414 5 $ 37.46 53.00 to 75.99 1,906 4 73.68 1,313 3 73.11 76.00 to 90.99 1,976 7 81.86 33 2 83.71 91.00 to 95.99 1,114 2 94.95 1,109 2 94.96 96.00 to 101.99 1,657 3 96.34 1,652 3 96.33 102.00 to 129.99 1,676 4 126.51 1,676 4 126.51 9,969 4 84.37 $ 127 6,197 3 95.33 $ 42 (1) Based upon the difference between the closing market price of the Common Stock on the last trading day of the year and the grant price of in-the-money stock options and SARs, in millions.
ESPP Activity	The following table summarizes ESPP activity for the years ended December 31, 2021, 2020 and 2019 (in thousands, except number of participants): 2021 2020 2019 Approximate Number of Participants 2,036 2,063 1,998 Shares Purchased 316 377 224 Aggregate Purchase Price $ 17,224 $ 16,103 $ 16,533
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, 2021, 2020 and 2019 (shares and units in thousands): 2021 2020 2019 Number of Shares and Units Weighted Average Grant Date Fair Value Number of Shares and Units Weighted Average Grant Date Fair Value Number of Shares and Units Weighted Average Grant Date Fair Value Outstanding at January 1 4,742 $ 74.97 4,546 $ 90.16 3,792 $ 96.64 Granted 1,422 81.50 1,488 38.10 1,749 80.01 Released (1) (1,388) 101.00 (1,213) 85.92 (855) 96.93 Forfeited (96) 68.26 (79) 86.52 (140) 97.54 Outstanding at December 31 (2) 4,680 69.37 4,742 74.97 4,546 90.16 (1) (1) The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2021, 2020 and 2019 was $110 million, $48 million and $70 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date restricted stock and restricted stock units are released. (2) (2) The total intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2021, 2020 and 2019 was $416 million, $236 million and $381 million, respectively. The intrinsic value is based on the closing market price of the Common Stock on the last trading day of the year.
Weighted Average Fair Values and Valuation Assumptions for Performance Units/Stocks	Weighted average fair values and valuation assumptions used to value Performance Units during the years ended December 31, 2021, 2020 and 2019 were as follows: 2021 2020 2019 Weighted Average Fair Value of Grants $ 95.16 $ 42.77 $ 79.98 Expected Volatility 53.80 % 47.27 % 29.20 % Risk-Free Interest Rate 0.59 % 0.16 % 1.51 %
Performance Unit and Performance Stock Transactions	The following table sets forth the Performance Unit transactions for the years ended December 31, 2021, 2020 and 2019 (units in thousands): 2021 2020 2019 Number of Units Weighted Average Grant Date Fair Value Number of Units Weighted Average Grant Date Fair Value Number of Units Weighted Average Grant Date Fair Value Outstanding at January 1 613 $ 88.38 598 $ 103.91 539 $ 116.96 Granted 222 95.16 172 42.77 172 79.98 Granted for Performance Multiple (1) 19 113.81 66 119.10 72 80.64 Released (2) (175) 113.06 (223) 103.87 (185) 110.65 Forfeited — — — — — — Outstanding at December 31 (3) 679 (4) 84.97 613 88.38 598 103.91 (1) Upon completion of the Performance Period for the Performance Units granted in 2017, 2016 and 2015, a performance multiple of 125%, 150% and 200%, respectively, was applied to each of the grants resulting in additional grants of Performance Units in February 2021, 2020 and 2019. (2) The total intrinsic value of Performance Units released during the years ended December 31, 2021, 2020 and 2019 was $13 million, $13 million and $15 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date Performance Units are released. (3) The total intrinsic value of Performance Units outstanding at December 31, 2021, 2020 and 2019 was $60 million, $31 million and $50 million, respectively. The intrinsic value is based on the closing market price of the Common Stock on the last trading day of the year.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Deferred Income Tax Assets (Liabilities), Net	The principal components of EOG's total net deferred income tax liabilities at December 31, 2021 and 2020 were as follows (in millions): 2021 2020 Deferred Income Tax Assets (Liabilities) Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization $ (19) $ 25 Foreign Asset Retirement Obligations 51 — Foreign Accrued Expenses and Liabilities 15 — Foreign Net Operating Loss 80 74 Foreign Valuation Allowances (111) (97) Foreign Other (5) — Total Net Deferred Income Tax Assets $ 11 $ 2 Deferred Income Tax (Assets) Liabilities Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization $ 5,063 $ 5,028 Commodity Hedging Contracts (97) 15 Deferred Compensation Plans (57) (43) Equity Awards (86) (103) Undistributed Foreign Earnings — 10 Other (74) (48) Total Net Deferred Income Tax Liabilities $ 4,749 $ 4,859 Total Net Deferred Income Tax Liabilities $ 4,738 $ 4,857
Components of Income (Loss) Before Income Taxes	The components of Income (Loss) Before Income Taxes for the years indicated below were as follows (in millions): 2021 2020 2019 United States $ 5,787 $ (756) $ 3,466 Foreign 146 17 79 Total $ 5,933 $ (739) $ 3,545
Components of Income Tax Provision (Benefit)	The principal components of EOG's Income Tax Provision (Benefit) for the years indicated below were as follows (in millions): 2021 2020 2019 Current: Federal $ 1,203 $ (108) $ (152) State 85 7 10 Foreign 105 40 81 Total 1,393 (61) (61) Deferred: Federal (41) (153) 627 State (62) (15) 33 Foreign (19) (18) (28) Total (122) (186) 632 Other Non-Current: (1) Federal — 113 245 Foreign (2) — (6) Total (2) 113 239 Income Tax Provision (Benefit) $ 1,269 $ (134) $ 810 (1) Includes changes in certain amounts that are expected to be paid or received beyond the next twelve months. The primary component in 2020 and 2019 is refundable alternative minimum tax (AMT) credits.
Tax Rate Reconciliation	The differences between taxes computed at the U.S. federal statutory tax rate and EOG's effective rate for the years indicated below were as follows: 2021 2020 2019 Statutory Federal Income Tax Rate 21.0 % 21.0 % 21.0 % State Income Tax, Net of Federal Benefit 0.3 0.9 1.0 Income Tax Provision Related to Foreign Operations 0.9 (0.1) 0.9 Income Tax Provision Related to Canadian Operations — (2.4) — Stock-Based Compensation 0.2 (2.9) — Other (1.0) 1.7 — Effective Income Tax Rate 21.4 % 18.2 % 22.9 %
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 millions): 2021 2020 2019 Beginning Balance $ 219 $ 201 $ 167 Increase (1) 15 25 31 Decrease (2) (14) (11) — Other (3) (1) 4 3 Ending Balance $ 219 $ 219 $ 201 (1) Increase in valuation allowance related to the generation of tax NOLs and other deferred tax assets. (2) Decrease in valuation allowance associated with adjustments to certain deferred tax assets and their related allowances.

Commitments and Contingencies_2

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Minimum commitments for unrecorded unconditional purchase obligations	At December 31, 2021, 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, 2021, were as follows (in millions): Total Minimum 2022 $ 1,335 2023 1,045 2024 823 2025 673 2026 579 2027 and beyond 2,133 $ 6,588

Net Income (Loss) Per Share (Ta

Net Income (Loss) Per Share (Tables)	12 Months Ended
	Dec. 31, 2021
Earnings Per Share [Abstract]
Computation of Net Income (Loss) Per Share	The following table sets forth the computation of Net Income (Loss) Per Share for the years ended December 31, 2021, 2020 and 2019 (in millions, except per share data): 2021 2020 2019 Numerator for Basic and Diluted Earnings per Share - Net Income (Loss) $ 4,664 $ (605) $ 2,735 Denominator for Basic Earnings per Share - Weighted Average Shares 581 579 578 Potential Dilutive Common Shares - Stock Options/SARs — — — Restricted Stock/Units and Performance Units 3 — 3 Denominator for Diluted Earnings per Share - Adjusted Diluted Weighted Average Shares 584 579 581 Net Income (Loss) Per Share Basic $ 8.03 $ (1.04) $ 4.73 Diluted $ 7.99 $ (1.04) $ 4.71

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2021
Supplemental Cash Flow Information [Abstract]
Net Cash Paid For Interest and Income Taxes	Net cash paid for (received from) interest and income taxes was as follows for the years ended December 31, 2021, 2020 and 2019 (in millions): 2021 2020 2019 Interest, Net of Capitalized Interest $ 185 $ 205 $ 187 Income Taxes, Net of Refunds Received $ 1,114 $ (206) $ (292)

Business Segment Information (T

Business Segment Information (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021, 2020 and 2019 (in millions): United Trinidad Other International (1) Total 2021 Crude Oil and Condensate $ 11,094 $ 31 $ — $ 11,125 Natural Gas Liquids 1,812 — — 1,812 Natural Gas 2,156 270 18 2,444 Losses on Mark-to-Market Commodity Derivative Contracts (1,152) — — (1,152) Gathering, Processing and Marketing 4,287 1 — 4,288 Gains (Losses) on Asset Dispositions, Net (40) (2) 59 17 Other, Net 108 — — 108 Operating Revenues and Other (2) 18,265 300 77 18,642 Depreciation, Depletion and Amortization 3,558 87 6 3,651 Operating Income (Loss) (3) 6,013 151 (62) 6,102 Interest Income 3 — — 3 Other Income (Expense) (14) 8 12 6 Net Interest Expense 178 — — 178 Income (Loss) Before Income Taxes 5,824 159 (50) 5,933 Income Tax Provision (Benefit) 1,247 66 (44) 1,269 Additions to Oil and Gas Properties, Excluding Dry Hole Costs 3,557 55 5 3,617 Total Property, Plant and Equipment, Net 28,213 204 9 28,426 Total Assets 37,436 637 163 38,236 2020 Crude Oil and Condensate $ 5,774 $ 11 $ 1 $ 5,786 Natural Gas Liquids 668 — — 668 Natural Gas 614 169 54 837 Gains on Mark-to-Market Commodity Derivative Contracts 1,145 — — 1,145 Gathering, Processing and Marketing 2,581 2 — 2,583 Losses on Asset Dispositions, Net (47) — — (47) Other, Net 60 — — 60 Operating Revenues and Other (4) 10,795 182 55 11,032 Depreciation, Depletion and Amortization 3,324 60 16 3,400 Operating Income (Loss) (5) (546) 75 (73) (544) Interest Income 11 1 — 12 Other Expense — (2) — (2) Net Interest Expense 205 — — 205 Income (Loss) Before Income Taxes (740) 74 (73) (739) Income Tax Provision (Benefit) (157) 15 8 (134) Additions to Oil and Gas Properties, Excluding Dry Hole Costs 3,318 83 42 3,443 Total Property, Plant and Equipment, Net 28,284 210 105 28,599 Total Assets 35,048 546 211 35,805 United Trinidad Other International (1) Total 2019 Crude Oil and Condensate $ 9,599 $ 11 $ 3 $ 9,613 Natural Gas Liquids 785 — — 785 Natural Gas 867 259 58 1,184 Gains on Mark-to-Market Commodity Derivative Contracts 180 — — 180 Gathering, Processing and Marketing 5,355 5 — 5,360 Gains (Losses) on Asset Dispositions, Net 132 (4) (4) 124 Other, Net 134 — — 134 Operating Revenues and Other (6) 17,052 271 57 17,380 Depreciation, Depletion and Amortization 3,652 80 18 3,750 Operating Income (Loss) 3,619 113 (33) 3,699 Interest Income 22 4 — 26 Other Income 3 1 1 5 Net Interest Expense (Income) 192 — (7) 185 Income (Loss) Before Income Taxes 3,452 118 (25) 3,545 Income Tax Provision 761 41 8 810 Additions to Oil and Gas Properties, Excluding Dry Hole Costs 6,209 53 12 6,274 Total Property, Plant and Equipment, Net 30,102 184 78 30,364 Total Assets 36,275 706 144 37,125 (1) Other International primarily consists of EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. EOG began exploration programs in Australia in the third quarter of 2021 and in Oman in the third quarter of 2020. The decision was reached in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman. (2) EOG had sales activity with two significant purchasers in 2021, one totaling $2.7 billion and the other totaling $2.6 billion of consolidated Operating Revenues and Other in the United States segment. (3) EOG recorded pretax impairment charges of $45 million and dry hole costs of $42 million in 2021 in the Other International segment related to its decision in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman. In addition, EOG recorded net gains of asset dispositions of $58 million in 2021 in the Other International segment during the second quarter of 2021 due to the sale of its China operations. See Notes 14 and 17, respectively. (4) EOG had sales activity with three significant purchasers in 2020, each totaling $1.1 billion of consolidated Operating Revenues and Other in the United States segment. (5) EOG recorded pretax impairment charges of $1,570 million in 2020 for proved oil and gas properties, leasehold costs and other assets due to the decline in commodity prices and revisions of asset retirement obligations for certain properties in the United States segment. In addition, EOG recorded pretax impairment charges of $228 million in 2020 for owned and leased sand and crude-by-rail assets, also in the United States segment. EOG recorded pretax impairment charges of $81 million in 2020 for proved oil and gas properties and firm commitment contracts related to its decision to exit the Horn River Basin in British Columbia, Canada, in the Other International segment. See Notes 13 and 14. (6) 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.

Risk Management Activities (Tab

Risk Management Activities (Tables)	12 Months Ended
	Dec. 31, 2021
Price Risk Derivative [Member]
Derivatives, Fair Value [Line Items]
Schedule of Derivative Instruments In Statement Of Financial Position, Fair Value	The following table sets forth the amounts and classification of EOG's outstanding derivative financial instruments at December 31, 2021 and 2020, respectively. Certain amounts may be presented on a net basis on the consolidated financial statements when such amounts are with the same counterparty and subject to a master netting arrangement (in millions): Fair Value at December 31, Description Location on Balance Sheet 2021 2020 Asset Derivatives Crude oil, NGLs and natural gas derivative contracts - Current portion Assets from Price Risk Management Activities $ — $ 65 Noncurrent portion Other Assets (1) 6 1 Liability Derivatives Crude oil, NGLs and natural gas derivative contracts - Current portion Liabilities from Price Risk Management Activities (2) $ 269 $ — Noncurrent Portion Other Liabilities (3) 37 1 (1) The noncurrent portion of Assets from Price Risk Management Activities consists of gross assets of $7 million, partially offset by gross liabilities of $1 million, at December 31, 2021. (2) The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $421 million, partially offset by gross assets of $29 million and collateral posted with counterparties of $123 million, at December 31, 2021. (3) The noncurrent portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $64 million, partially offset by gross assets of $10 million and collateral posted with counterparties of $17 million, at December 31, 2021.
Crude Oil | Price Swaps
Derivatives, Fair Value [Line Items]
Schedule of Derivative Instruments	Presented below is a comprehensive summary of EOG's financial commodity derivative contracts settled during the year ended December 31, 2021 (closed) and remaining for 2022 and thereafter, as of December 31, 2021. Crude oil and NGL volumes are presented in MBbld and prices are presented in $/Bbl. Natural gas volumes are presented in MMBtu per day (MMBtud) and prices are presented in dollars per MMBtu ($/MMBtu). Crude Oil Financial Price Swap Contracts Contracts Sold Period Settlement Index Volume Weighted Average Price January 2021 (closed) NYMEX West Texas Intermediate (WTI) 151 $ 50.06 February - March 2021 (closed) NYMEX WTI 201 51.29 April - June 2021 (closed) NYMEX WTI 150 51.68 July - September 2021 (closed) NYMEX WTI 150 52.71 January - March 2022 NYMEX WTI 140 65.58 April - June 2022 NYMEX WTI 140 65.62 July - September 2022 NYMEX WTI 140 65.59 October - December 2022 NYMEX WTI 140 65.68 January - March 2023 NYMEX WTI 150 67.92 April - June 2023 NYMEX WTI 120 67.79 July - September 2023 NYMEX WTI 20 68.04
Crude Oil | Basis Swaps | Roll Differential Swap
Derivatives, Fair Value [Line Items]
Schedule of Derivative Instruments	Crude Oil Basis Swap Contracts Contracts Sold Period Settlement Index Volume Weighted Average Price Differential February 2021 (closed) NYMEX WTI Roll Differential (1) 30 $ 0.11 March - December 2021 (closed) NYMEX WTI Roll Differential (1) 125 0.17 January 2022 (closed) NYMEX WTI Roll Differential (1) 125 0.15 February - December 2022 NYMEX WTI Roll Differential (1) 125 0.15 (1) This settlement index is used to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month.
Natural Gas Liquids | Price Swaps
Derivatives, Fair Value [Line Items]
Schedule of Derivative Instruments	NGL Financial Price Swap Contracts Contracts Sold Period Settlement Index Volume Weighted Average Price January - December 2021 (closed) Mont Belvieu Propane (non-Tet) 15 $ 29.44
Natural Gas | Price Swaps
Derivatives, Fair Value [Line Items]
Schedule of Derivative Instruments	Natural Gas Financial Price Swap Contracts Contracts Sold Contracts Purchased Period Settlement Index Volume Weighted Average Price ($/MMBtu) Volume (MMBtud in thousands) Weighted Average Price ($/MMBtu) January - March 2021 (closed) NYMEX Henry Hub 500 $ 2.99 500 $ 2.43 April - September 2021 (closed) NYMEX Henry Hub 500 2.99 570 2.81 October - December 2021 (closed) NYMEX Henry Hub 500 2.99 500 2.83 January - December 2022 (closed) (1) NYMEX Henry Hub 20 2.75 — — January - December 2022 NYMEX Henry Hub 725 3.57 — — January - December 2023 NYMEX Henry Hub 725 3.18 — — January - December 2024 NYMEX Henry Hub 725 3.07 — — January - December 2025 NYMEX Henry Hub 725 3.07 — — April - September 2021 (closed) Japan Korea Marker (JKM) 70 6.65 — — (1) In January 2021, EOG executed the early termination provision granting EOG the right to terminate all of its 2022 natural gas price swap contracts which were open at that time. EOG received net cash of $0.6 million for the settlement of these contracts.
Natural Gas | Basis Swaps
Derivatives, Fair Value [Line Items]
Schedule of Derivative Instruments	Natural Gas Basis Swap Contracts Contracts Sold Period Settlement Index Volume Weighted Average Price ($/MMBtu) January - December 2022 NYMEX Henry Hub Houston Ship Channel (HSC) Differential (1) 210 $ (0.01) January - December 2023 NYMEX Henry Hub HSC Differential (1) 135 (0.01) January - December 2024 NYMEX Henry Hub HSC Differential (1) 10 0.00 January - December 2025 NYMEX Henry Hub HSC Differential (1) 10 0.00 (1) This settlement index is used to fix the differential between pricing at the Houston Ship Channel and NYMEX Henry Hub prices.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2021
Fair Value Disclosures [Abstract]
Recurring Fair Value Measurements	The following table provides fair value measurement information within the fair value hierarchy for certain of EOG's financial assets and liabilities carried at fair value on a recurring basis at December 31, 2021 and 2020 (in millions): Fair Value Measurements Using: Quoted Significant Significant Total At December 31, 2021 Financial Assets: Natural Gas Swaps $ — $ 29 $ — $ 29 Natural Gas Basis Swaps — 2 — 2 Crude Oil Swaps — 15 — 15 Financial Liabilities: Crude Oil Roll Differential Swaps — 24 — 24 Natural Gas Swaps — 121 — 121 Crude Oil Swaps — 340 — 340 Natural Gas Basis Swaps — 1 — 1 At December 31, 2020 Financial Assets: Natural Gas Swaps $ — $ 66 $ — $ 66 Financial Liabilities: Crude Oil Roll Differential Swaps — 1 — 1

Impairment Expense (Tables)

Impairment Expense (Tables)	12 Months Ended
	Dec. 31, 2021
Impairment Expense [Abstract]
Impairment Expenses	Impairment expense was as follows for the years ended December 31, 2021, 2020 and 2019 (in millions): 2021 2020 2019 Proved properties (1) $ 20 $ 1,268 $ 207 Unproved properties (2) 310 472 220 Other assets (3) 28 300 91 Inventories 13 — — Firm commitment contracts (4) 5 60 — Total $ 376 $ 2,100 $ 518 (1) Impairments to proved oil and gas properties in 2020 included legacy and non-core natural gas and crude oil and combo plays. Impairments to proved oil and gas properties in 2019 included domestic legacy natural gas assets. See Notes 1 and 13. (2) Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. Impairments of unproved oil and gas properties included $38 million in 2021 for the decision in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman. Impairments of unproved oil and gas properties included charges of $252 million in 2020 for certain leasehold costs that are no longer expected to be developed before expiration in the United States. See Note 1. (3) Includes impairment charges for owned and leased sand and crude-by-rail assets of $228 million in 2020 (see Note 18) and a commodity price-related write-down of other assets of $72 million and $90 million in 2020 and 2019, respectively (see Note 13). (4) Includes impairment charges of $60 million in 2020 for firm commitment contracts related to its decision to exit the Horn River Basin in British Columbia, Canada.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 and 2020 (in millions): 2021 2020 Carrying Amount at Beginning of Period $ 1,217 $ 1,111 Liabilities Incurred 81 58 Liabilities Settled (1) (131) (54) Accretion 44 47 Revisions 20 54 Foreign Currency Translations — 1 Carrying Amount at End of Period $ 1,231 $ 1,217 Current Portion $ 43 $ 50 Noncurrent Portion $ 1,188 $ 1,167 (1) Includes settlements related to asset sales and property exchanges.

Exploratory Well Costs (Tables)

Exploratory Well Costs (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021, 2020 and 2019 are presented below (in millions): 2021 2020 2019 Balance at January 1 $ 29 $ 26 $ 4 Additions Pending the Determination of Proved Reserves 73 108 83 Reclassifications to Proved Properties (41) (81) (39) Costs Charged to Expense (1) (54) (24) (22) Balance at December 31 $ 7 $ 29 $ 26 (1) Includes capitalized exploratory well costs charged to either dry hole costs or impairments.
Schedule of Aging of Capitalized Exploratory Well Costs	2021 2020 2019 Capitalized exploratory well costs that have been capitalized for a period of one year or less $ 7 $ 26 $ 26 Capitalized exploratory well costs that have been capitalized for a period greater than one year (1) — 3 — Balance at December 31 $ 7 $ 29 $ 26 Number of exploratory wells that have been capitalized for a period greater than one year — 1 —

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2021
Leases [Abstract]
Lease	The components of lease cost for the years ended December 31, 2021, 2020 and 2019 were as follows (in millions): 2021 2020 2019 Operating Lease Cost (1) $ 295 $ 393 $ 497 Finance Lease Cost: Amortization of Lease Assets 39 21 13 Interest on Lease Liabilities 7 4 2 Variable Lease Cost 63 91 138 Short-Term Lease Cost 257 194 333 Total Lease Cost $ 661 $ 703 $ 983 (1) Operating lease cost includes impairment expenses of $35 million in 2020.
Outstanding Lease Assets And Lease Liabilities	The following table sets forth the amounts and classification of EOG's outstanding ROU assets and related lease liabilities at December 31, 2021 and 2020 and supplemental information for the years ended December 31, 2021 and 2020 (in millions, except lease terms and discount rates): Description Location on Balance Sheet 2021 2020 Assets Operating Leases Other Assets $ 743 $ 869 Finance Leases Property, Plant and Equipment, Net (1) 241 206 Total $ 984 $ 1,075 Liabilities Current Operating Leases Current Portion of Operating Lease Liabilities $ 240 $ 295 Finance Leases Current Portion of Long-Term Debt 37 31 Long-Term Operating Leases Other Liabilities 558 641 Finance Leases Long-Term Debt 213 181 Total $ 1,048 $ 1,148 (1) Finance lease assets are recorded net of accumulated amortization of $119 million and $81 million at December 31, 2021 and 2020, respectively.
Weighted Average Remaining Lease Term And Discount Rate	2021 2020 Weighted Average Remaining Lease Term (in years): Operating Leases 5.3 5.3 Finance Leases 7.0 7.6 Weighted Average Discount Rate: Operating Leases 3.0 % 3.4 % Finance Leases 2.6 % 2.8 %
Cash Paid for Leases	Cash paid for leases for the years ended December 31, 2021, 2020 and 2019 was as follows (in millions): 2021 2020 2019 Repayment of Operating Lease Liabilities Associated with Operating Activities $ 207 $ 223 $ 225 Repayment of Operating Lease Liabilities Associated with Investing Activities 98 130 270 Repayment of Finance Lease Liabilities 37 19 13
Operating And Finance Non-Cancellable Leases Maturity	At December 31, 2021, the future minimum lease payments under non-cancellable leases were as follows (in millions): Operating Leases Finance Leases 2022 $ 262 $ 42 2023 188 37 2024 113 37 2025 80 36 2026 59 30 2027 and Beyond 172 94 Total Lease Payments 874 276 Less: Discount to Present Value 76 26 Total Lease Liabilities 798 250 Less: Current Portion of Lease Liabilities 240 37 Long-Term Lease Liabilities $ 558 $ 213

Oil and Gas Exploration and P_2

Oil and Gas Exploration and Production Industries Disclosures (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2021, as estimated by the Engineering and Acquisitions Department of EOG: NET PROVED RESERVE SUMMARY United Trinidad Other International (1) Total NET PROVED RESERVES Crude Oil (MMBbl) (2) Net proved reserves at December 31, 2018 1,532 — — 1,532 Revisions of previous estimates (43) — — (43) Purchases in place 3 — — 3 Extensions, discoveries and other additions 370 — — 370 Sales in place (1) — — (1) Production (167) — — (167) Net proved reserves at December 31, 2019 1,694 — — 1,694 Revisions of previous estimates (225) — — (225) Purchases in place 2 — — 2 Extensions, discoveries and other additions 194 1 — 195 Sales in place (3) — — (3) Production (149) — — (149) Net proved reserves at December 31, 2020 1,513 1 — 1,514 Revisions of previous estimates (116) — — (116) Purchases in place 2 — — 2 Extensions, discoveries and other additions 311 1 — 312 Sales in place (2) — — (2) Production (162) — — (162) Net proved reserves at December 31, 2021 1,546 2 — 1,548 Natural Gas Liquids (MMBbl) (2) Net proved reserves at December 31, 2018 614 — — 614 Revisions of previous estimates 5 — — 5 Purchases in place 2 — — 2 Extensions, discoveries and other additions 168 — — 168 Sales in place (1) — — (1) Production (48) — — (48) Net proved reserves at December 31, 2019 740 — — 740 Revisions of previous estimates (60) — — (60) Purchases in place 4 — — 4 Extensions, discoveries and other additions 180 — — 180 Sales in place (1) — — (1) Production (50) — — (50) Net proved reserves at December 31, 2020 813 — — 813 Revisions of previous estimates (128) — — (128) Purchases in place 3 — — 3 Extensions, discoveries and other additions 194 — — 194 Sales in place — — — — Production (53) — — (53) Net proved reserves at December 31, 2021 829 — — 829 United Trinidad Other International (1) Total Natural Gas (Bcf) (3) Net proved reserves at December 31, 2018 4,391 237 59 4,687 Revisions of previous estimates (184) 47 3 (134) Purchases in place 72 — — 72 Extensions, discoveries and other additions 1,176 87 10 1,273 Sales in place (15) — — (15) Production (405) (95) (13) (513) Net proved reserves at December 31, 2019 5,035 276 59 5,370 Revisions of previous estimates (498) 5 1 (492) Purchases in place 26 — — 26 Extensions, discoveries and other additions 1,078 54 — 1,132 Sales in place (157) — — (157) Production (441) (66) (12) (519) Net proved reserves at December 31, 2020 5,043 269 48 5,360 Revisions of previous estimates 754 26 3 783 Purchases in place 23 — — 23 Extensions, discoveries and other additions 2,574 100 — 2,674 Sales in place (4) — (48) (52) Production (483) (80) (3) (566) Net proved reserves at December 31, 2021 7,907 315 — 8,222 Oil Equivalents (MMBoe) (2) Net proved reserves at December 31, 2018 2,878 40 10 2,928 Revisions of previous estimates (68) 8 — (60) Purchases in place 17 — — 17 Extensions, discoveries and other additions 734 14 2 750 Sales in place (5) — — (5) Production (283) (16) (2) (301) Net proved reserves at December 31, 2019 3,273 46 10 3,329 Revisions of previous estimates (368) 1 — (367) Purchases in place 10 — — 10 Extensions, discoveries and other additions 554 10 — 564 Sales in place (31) — — (31) Production (272) (11) (2) (285) Net proved reserves at December 31, 2020 3,166 46 8 3,220 Revisions of previous estimates (118) 4 — (114) Purchases in place 9 — — 9 Extensions, discoveries and other additions 934 18 — 952 Sales in place (3) — (8) (11) Production (295) (14) — (309) Net proved reserves at December 31, 2021 3,693 54 — 3,747 (1) Other International includes EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. (2) Million barrels or million barrels of oil equivalent, as applicable; oil equivalents include crude oil and condensate, NGLs and natural gas. Oil equivalents are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. (3) Billion cubic feet.
Net Proved Developed and Net Proved Undeveloped Oil and Gas Reserve Quantities	United Trinidad Other International (1) Total NET PROVED DEVELOPED RESERVES Crude Oil (MMBbl) December 31, 2018 713 — — 713 December 31, 2019 801 — — 801 December 31, 2020 792 1 — 793 December 31, 2021 886 — — 886 Natural Gas Liquids (MMBbl) December 31, 2018 341 — — 341 December 31, 2019 387 — — 387 December 31, 2020 392 — — 392 December 31, 2021 416 — — 416 Natural Gas (Bcf) December 31, 2018 2,699 224 41 2,964 December 31, 2019 2,974 178 42 3,194 December 31, 2020 2,586 171 32 2,789 December 31, 2021 3,743 131 — 3,874 Oil Equivalents (MMBoe) December 31, 2018 1,503 38 7 1,548 December 31, 2019 1,684 30 7 1,721 December 31, 2020 1,614 30 5 1,649 December 31, 2021 1,926 22 — 1,948 NET PROVED UNDEVELOPED RESERVES Crude Oil (MMBbl) December 31, 2018 819 — — 819 December 31, 2019 893 — — 893 December 31, 2020 721 — — 721 December 31, 2021 660 2 — 662 Natural Gas Liquids (MMBbl) December 31, 2018 273 — — 273 December 31, 2019 353 — — 353 December 31, 2020 421 — — 421 December 31, 2021 413 — — 413 Natural Gas (Bcf) December 31, 2018 1,692 13 18 1,723 December 31, 2019 2,061 98 17 2,176 December 31, 2020 2,457 98 16 2,571 December 31, 2021 4,164 184 — 4,348 Oil Equivalents (MMBoe) December 31, 2018 1,375 2 3 1,380 December 31, 2019 1,589 16 3 1,608 December 31, 2020 1,552 16 3 1,571 December 31, 2021 1,767 32 — 1,799 (1) Other International includes EOG's China and Canada operations. The China operations were sold in the second quarter of 2021.
Net Proved Undeveloped Reserves	The following table presents the changes in EOG's total PUDs during 2021, 2020 and 2019 (in MMBoe): 2021 2020 2019 Balance at January 1 1,571 1,608 1,380 Extensions and Discoveries 779 456 578 Revisions (305) (277) (50) Acquisition of Reserves — — 2 Sale of Reserves (3) (4) — Conversion to Proved Developed Reserves (243) (212) (302) Balance at December 31 1,799 1,571 1,608
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, 2021 and 2020: 2021 2020 Proved properties $ 64,876 $ 61,725 Unproved properties 2,768 3,068 Total 67,644 64,793 Accumulated depreciation, depletion and amortization (41,907) (38,751) Net capitalized costs $ 25,737 $ 26,042
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, 2021, 2020 and 2019: United Trinidad Other International (1) Total 2021 Acquisition Costs of Properties Unproved (2) $ 207 $ — $ 8 $ 215 Proved (3) 100 — — 100 Subtotal 307 — 8 315 Exploration Costs 296 7 51 354 Development Costs (4) 3,206 77 17 3,300 Total $ 3,809 $ 84 $ 76 $ 3,969 2020 Acquisition Costs of Properties Unproved (5) $ 265 $ — $ — $ 265 Proved (6) 97 — 38 135 Subtotal 362 — 38 400 Exploration Costs 203 81 12 296 Development Costs (7) 2,998 4 20 3,022 Total $ 3,563 $ 85 $ 70 $ 3,718 2019 Acquisition Costs of Properties Unproved (8) $ 276 $ — $ — $ 276 Proved (9) 380 — — 380 Subtotal 656 — — 656 Exploration Costs 214 47 12 273 Development Costs (10) 5,662 25 12 5,699 Total $ 6,532 $ 72 $ 24 $ 6,628 (1) Other International primarily consists of EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. EOG began exploration programs in Australia in the third quarter of 2021 and in Oman in the third quarter of 2020. The decision was reached in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman. (2) Includes non-cash unproved leasehold acquisition costs of $45 million related to property exchanges. (3) Includes non-cash proved property acquisition costs of $5 million related to property exchanges. (4) Includes Asset Retirement Costs of $86 million, $24 million and $17 million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment. (5) Includes non-cash unproved leasehold acquisition costs of $197 million related to property exchanges. (6) Includes non-cash proved property acquisition costs of $15 million related to property exchanges. (7) Includes Asset Retirement Costs of $97 million and $20 million for the United States and Other International, respectively. Excludes other property, plant and equipment. (8) Includes non-cash unproved leasehold acquisition costs of $98 million related to property exchanges. (9) Includes non-cash proved property acquisition costs of $52 million related to property exchanges. (10) 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.
Results of Operations for Oil and Gas Producing Activities	esults of Operations for Oil and Gas Producing Activities (1) . The following table sets forth results of operations for oil and gas producing activities for the years ended December 31, 2021, 2020 and 2019: United Trinidad Other International (2) Total 2021 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues $ 15,062 $ 301 $ 18 $ 15,381 Other 108 — — 108 Total 15,170 301 18 15,489 Exploration Costs 137 5 12 154 Dry Hole Costs 29 — 42 71 Transportation Costs 863 — — 863 Gathering and Processing Costs 559 — — 559 Production Costs 2,108 39 8 2,155 Impairments 312 3 61 376 Depreciation, Depletion and Amortization 3,411 87 6 3,504 Income (Loss) Before Income Taxes 7,751 167 (111) 7,807 Income Tax Provision 1,690 73 (1) 1,762 Results of Operations $ 6,061 $ 94 $ (110) $ 6,045 2020 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues $ 7,056 $ 180 $ 55 $ 7,291 Other 60 — — 60 Total 7,116 180 55 7,351 Exploration Costs 136 2 8 146 Dry Hole Costs 13 — — 13 Transportation Costs 734 1 — 735 Gathering and Processing Costs 459 — — 459 Production Costs 1,480 27 10 1,517 Impairments 2,018 1 81 2,100 Depreciation, Depletion and Amortization 3,192 60 16 3,268 Income (Loss) Before Income Taxes (916) 89 (60) (887) Income Tax Provision (220) 24 3 (193) Results of Operations $ (696) $ 65 $ (63) $ (694) 2019 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues $ 11,251 $ 270 $ 61 $ 11,582 Other 134 — — 134 Total 11,385 270 61 11,716 Exploration Costs 130 4 6 140 Dry Hole Costs 11 13 4 28 Transportation Costs 753 4 1 758 Gathering and Processing Costs 479 — — 479 Production Costs 2,063 31 40 2,134 Impairments 511 6 1 518 Depreciation, Depletion and Amortization 3,561 79 18 3,658 Income (Loss) Before Income Taxes 3,877 133 (9) 4,001 Income Tax Provision 884 55 3 942 Results of Operations $ 2,993 $ 78 $ (12) $ 3,059 (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, 2021. (2) Other International primarily consists of EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. EOG began exploration programs in Australia in the third quarter of 2021 and in Oman in the third quarter of 2020. The decision was reached in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman.
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, 2021, 2020 and 2019: United Trinidad Other International (1) Composite Year Ended December 31, 2021 $ 3.71 $ 2.32 $ 16.13 $ 3.67 Year Ended December 31, 2020 $ 3.75 $ 2.33 $ 6.78 $ 3.72 Year Ended December 31, 2019 $ 4.59 $ 1.85 $ 18.26 $ 4.54 (1) Other International primarily consists of EOG's China and Canada operations. The China operations were sold in the second quarter of 2021.
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, 2021, 2020 and 2019: United Trinidad Other International (1) Total 2021 Future cash inflows (2) $ 166,316 $ 1,135 $ — $ 167,451 Future production costs (44,905) (258) — (45,163) Future development costs (13,885) (380) — (14,265) Future income taxes (22,831) (84) — (22,915) Future net cash flows 84,695 413 — 85,108 Discount to present value at 10% annual rate (38,834) (88) — (38,922) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 45,861 $ 325 $ — $ 46,186 2020 Future cash inflows (3) $ 73,727 $ 901 $ 281 $ 74,909 Future production costs (34,619) (153) (54) (34,826) Future development costs (15,159) (227) (18) (15,404) Future income taxes (4,337) (81) (24) (4,442) Future net cash flows 19,612 440 185 20,237 Discount to present value at 10% annual rate (8,410) (101) (36) (8,547) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 11,202 $ 339 $ 149 $ 11,690 2019 Future cash inflows (4) $ 120,360 $ 813 $ 305 $ 121,478 Future production costs (42,387) (166) (88) (42,641) Future development costs (20,356) (212) (18) (20,586) Future income taxes (11,460) (74) (32) (11,566) Future net cash flows 46,157 361 167 46,685 Discount to present value at 10% annual rate (21,043) (86) (35) (21,164) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 25,114 $ 275 $ 132 $ 25,521 (1) Other International includes EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. (2) Estimated crude oil prices used to calculate 2021 future cash inflows for the United States and Trinidad were $67.79 and $58.32, respectively. Estimated NGL price used to calculate 2021 future cash inflows for the United States was $30.28. Estimated natural gas prices used to calculate 2021 future cash inflows for the United States and Trinidad were $4.61 and $3.28, respectively. (3) Estimated crude oil prices used to calculate 2020 future cash inflows for the United States, Trinidad and Other International were $37.19, $26.75, and $41.87, respectively. Estimated NGL price used to calculate 2020 future cash inflows for the United States was $12.47. Estimated natural gas prices used to calculate 2020 future cash inflows for the United States, Trinidad and Other International were $1.45, $3.28, and $5.65, respectively. (4) 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.
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, 2021: United Trinidad Other International (1) Total December 31, 2018 $ 32,033 $ 266 $ 127 $ 32,426 Sales and transfers of oil and gas produced, net of production costs (7,955) (235) (20) (8,210) Net changes in prices and production costs (10,974) 66 28 (10,880) Extensions, discoveries, additions and improved recovery, net of related costs 5,608 85 16 5,709 Development costs incurred 3,004 23 6 3,033 Revisions of estimated development cost (599) (129) (11) (739) Revisions of previous quantity estimates (813) 116 1 (696) Accretion of discount 3,892 43 15 3,950 Net change in income taxes 1,454 94 1 1,549 Purchases of reserves in place 99 — — 99 Sales of reserves in place (51) — — (51) Changes in timing and other (584) (54) (31) (669) December 31, 2019 $ 25,114 $ 275 $ 132 $ 25,521 Sales and transfers of oil and gas produced, net of production costs (4,382) (152) (45) (4,579) Net changes in prices and production costs (18,625) 132 47 (18,446) Extensions, discoveries, additions and improved recovery, net of related costs 1,437 64 — 1,501 Development costs incurred 1,675 — — 1,675 Revisions of estimated development cost 4,149 (11) — 4,138 Revisions of previous quantity estimates (3,307) 12 (2) (3,297) Accretion of discount 3,055 34 15 3,104 Net change in income taxes 3,497 (12) 3 3,488 Purchases of reserves in place 49 — — 49 Sales of reserves in place (156) — — (156) Changes in timing and other (1,304) (3) (1) (1,308) December 31, 2020 $ 11,202 $ 339 $ 149 $ 11,690 Sales and transfers of oil and gas produced, net of production costs (11,532) (261) (16) (11,809) Net changes in prices and production costs 37,088 133 (1) 37,220 Extensions, discoveries, additions and improved recovery, net of related costs 12,154 71 — 12,225 Development costs incurred 1,619 16 — 1,635 Revisions of estimated development cost 2,773 (133) — 2,640 Revisions of previous quantity estimates (1,789) 73 — (1,716) Accretion of discount 1,313 42 17 1,372 Net change in income taxes (9,914) 27 17 (9,870) Purchases of reserves in place 151 — — 151 Sales of reserves in place (19) — (151) (170) Changes in timing and other 2,815 18 (15) 2,818 December 31, 2021 $ 45,861 $ 325 $ — $ 46,186

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Accounts Receivable From Contracts With Customers	$ 2,130	$ 1,337
Revolving Credit Agreement (New Facility)
Maximum borrowing capacity	$ 2,000

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Long-Term Debt	$ 4,890	$ 5,640
Finance Leases (see Note 18)	250	212
Less: Current Portion of Long-Term Debt	37	781
Unamortized Debt Discount	27	31
Debt Issuance Costs	4	5
Total Long-Term Debt	5,072	5,035
Proceeds from Debt, Net of Issuance Costs	1,480
Long-Term Debt by Maturity [Abstract]
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
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2024	0
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2025	500
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2026	750
Line of Credit Facility [Line Items]
Proceeds from Debt, Net of Issuance Costs	$ 1,480
Eurodollar [Member]
Line of Credit Facility [Line Items]
Effective Interest Rate (in hundredths)	1.00%
Base Rate [Member]
Line of Credit Facility [Line Items]
Effective Interest Rate (in hundredths)	3.25%
Commercial Paper
Line of Credit Facility [Line Items]
Current Borrowings Outstanding	$ 0	0
Revolving Credit Agreement (New Facility)
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 2,000
Senior Unsecured Revolving Credit Agreement Due 2024
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Date	Jun. 27, 2024
Line Of Credit Facility Increase Additional Borrowings	$ 3,000
Maximum total debt-to-total capitalization ratio allowed under financial covenant (in hundredths)	65.00%
4.100% Senior Notes due 2021
Debt Instrument [Line Items]
Long-Term Debt	$ 0	750
Debt Instrument Issuance Face Amount	$ 750
Debt Instrument Issuance Interest Rate	4.10%
2.625% Senior Notes due 2023
Debt Instrument [Line Items]
Long-Term Debt	$ 1,250	1,250
3.15% Senior Notes due 2025
Debt Instrument [Line Items]
Long-Term Debt	500	500
4.15% Senior Notes due 2026
Debt Instrument [Line Items]
Long-Term Debt	750	750
6.65% Senior Notes due 2028
Debt Instrument [Line Items]
Long-Term Debt	140	140
4.375% Senior Notes due 2030
Debt Instrument [Line Items]
Long-Term Debt	750	750
Debt Instrument Issuance Face Amount	$ 750
Debt Instrument Issuance Interest Rate	4.375%
3.90% Senior Notes due 2035
Debt Instrument [Line Items]
Long-Term Debt	$ 500	500
4.95% Senior Notes due 2050
Debt Instrument [Line Items]
Long-Term Debt	750	750
Debt Instrument Issuance Face Amount	$ 750
Debt Instrument Issuance Interest Rate	4.95%
Senior Notes Due 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument Issuance Face Amount	$ 500
Debt Instrument Issuance Interest Rate	2.45%
4.40% Senior Notes Due 2020
Debt Instrument [Line Items]
Debt Instrument Issuance Face Amount	$ 500
Debt Instrument Issuance Interest Rate	4.40%
5.10% Senior Notes due 2036
Debt Instrument [Line Items]
Long-Term Debt	$ 250	$ 250

Stockholder's Equity (Details)

Stockholder's Equity (Details) - USD ($) $ / shares in Units, $ in Billions		Feb. 24, 2022	Nov. 04, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	May 06, 2021
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
Stock Repurchase Program, Authorized Amount				$ 5
Stock Repurchase Program, Remaining Authorized Repurchase Amount				$ 5
Dividends Common Stock Declared Per Share		$ 0.75	$ 0.4125	$ 0.375	$ 0.2875	$ 0.22
Dividends Payable, Amount Per Share After Increase			0.75	$ 0.4125	$ 0.375	$ 0.2875
Common Stock Special Cash Dividends Per Share Declared		$ 1	$ 2				$ 1
Common Stock Activity [Line Items]
Beginning Balance (in shares)				583,694,850
Ending Balance (in shares)				585,521,512	583,694,850
Preferred Stock, Shares Outstanding				0
Common Shares, Outstanding
Common Stock Activity [Line Items]
Beginning Balance (in shares)				583,571,000	581,914,000	580,023,000
Common Stock Issued Under Stock-Based Compensation Plans (in shares)				1,511,000	1,482,000	1,688,000
Treasury Stock Purchased (1) (in shares)	[1]			(504,000)	(389,000)	(310,000)
Common Stock Issued Under Employee Stock Purchase Plan (in shares)				316,000	377,000	224,000
Treasury Stock Issued Under Stock-Based Compensation Plans (in shares)				371,000	187,000	289,000
Ending Balance (in shares)				585,265,000	583,571,000	581,914,000
Common Shares, Treasury
Common Stock Activity [Line Items]
Beginning Balance (in shares)				124,000	299,000	385,000
Common Stock Issued Under Stock-Based Compensation Plans (in shares)				0	0	0
Treasury Stock Purchased (1) (in shares)	[1]			(504,000)	(389,000)	(310,000)
Common Stock Issued Under Employee Stock Purchase Plan (in shares)				0	377,000	107,000
Treasury Stock Issued Under Stock-Based Compensation Plans (in shares)				371,000	187,000	289,000
Ending Balance (in shares)				257,000	124,000	299,000
Common Shares, Issued
Common Stock Activity [Line Items]
Beginning Balance (in shares)				583,695,000	582,213,000	580,408,000
Common Stock Issued Under Stock-Based Compensation Plans (in shares)				1,511,000	1,482,000	1,688,000
Treasury Stock Purchased (1) (in shares)	[1]			0	0	0
Common Stock Issued Under Employee Stock Purchase Plan (in shares)				316,000	0	117,000
Treasury Stock Issued Under Stock-Based Compensation Plans (in shares)				0	0	0
Ending Balance (in shares)				585,522,000	583,695,000	582,213,000
[1]	Represents shares that were withheld by or returned to EOG (i) in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or SARs or the vesting of restricted stock, restricted stock unit or performance unit grants or (ii) in payment of the exercise price of employee stock options.

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss)	$ (12)	$ (12)
Other Comprehensive Loss	0	(7)	$ (3)
Significant Amount Reclassified Out of AOCI	0	0	0
Foreign Currency Translation Adjustment
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss)	(11)	(10)	(3)
Other Comprehensive Income (Loss), before Reclassifications, before Tax	(1)	(7)
Tax Effects	0	0
Other Comprehensive Loss	(1)	(7)
Other
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss)	(1)	(2)	(2)
Other Comprehensive Income (Loss), before Reclassifications, before Tax	1	0
Tax Effects	0	0
Other Comprehensive Loss	1	0
Accumulated Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss)	(12)	(12)	(5)
Other Comprehensive Income (Loss), before Reclassifications, before Tax	0	(7)
Tax Effects	0	0
Other Comprehensive Loss	$ 0	$ (7)	$ (3)

Other Income, Net (Details)

Other Income, Net (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Other Income and Expenses [Abstract]
Equity income (loss) from investments in Trinidad	$ 18	$ (2)
Interest income	3	$ 12	$ 26
Adjustment to Deferred Compensation Expense	$ 13
Net Foreign Currency Transaction Gains (Losses)			$ 2

Employee Benefit Plans (Details

Employee Benefit Plans (Details) $ / shares in Units, $ in Thousands		Feb. 01, 2021shares	Dec. 31, 2021USD ($)participants$ / sharesshares		Dec. 31, 2020USD ($)participants$ / sharesshares		Dec. 31, 2019USD ($)participants$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense related to the company's stock-based compensation plans | $			$ 152,000		$ 146,000		$ 175,000
Aggregate Maximum of Common Shares			20,000,000
Common Shares Available for Grant			18,000,000
Share-based Payment Arrangement, Expense, Tax Deficiencies | $			$ (11,000)		(22,000)		(1,000)
Stock Options and Sars [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum term of stock options and SARs granted			7 years
Stock-Based Compensation Expense | $			$ 48,000		$ 62,000		$ 63,000
Unrecognized compensation expense | $			$ 60,000
Stock Options/SARs Vested or Expected to Vest (in shares)			9,700,000
Intrinsic value of stock options/SARs vested or expected to vest | $			$ 120,000
Weighted Average Remaining Contractual Life for Stock Options/SARs Vested or Expected to Vest			4 years 1 month 6 days
Weighted average period over which unrecognized compensation expense will be recognized			2 years 1 month 6 days
Weighted average grant price for stock options/SARs vested or expected to vest (per share) | $ / shares			$ 84.97
Stock Options and SARs Rollforward [Abstract]
Outstanding at January 1 (in shares)			10,186,000		9,395,000		8,310,000
Granted (in shares)			1,982,000		1,996,000		1,965,000
Exercised (1) (in shares)	[1]		(1,130,000)		(23,000)		(606,000)
Forfeited (in shares)			(1,069,000)		(1,182,000)		(274,000)
Outstanding at December 31 (in shares)			9,969,000		10,186,000		9,395,000
Stock Options/SARs Exercisable at December 31 (in shares)			6,197,000		6,343,000		5,275,000
Intrinsic Value Of Stock Options/SARs Exercised During The Period | $			$ 27,000		$ 400		$ 14,000
Weighted Average Grant Price Stock Option and SARs [Rollfoward]
Outstanding at January 1 (in dollars per share) | $ / shares			$ 84.08		$ 94.53		$ 96.90
Granted (in dollars per share) | $ / shares			81.68		37.63		75.39
Exercised (in dollars per share) | $ / shares	[1]		63.98		69.59		61.43
Forfeited (in dollars per share) | $ / shares			98.15		88.93		102.57
Outstanding at December 31 (in dollars per share) | $ / shares			84.37		84.08		94.53
Stock Options/SARs Exercisable at December 31 (in dollars per share) | $ / shares			95.33		96.41		94.21
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			$ 24.92		$ 11.06		$ 19.49
Expected Volatility (in hundredths)			42.24%		44.47%		32.02%
Risk-Free Interest Rate (in hundredths)			0.50%		0.21%		1.69%
Dividend Yield (in hundredths)			2.26%		3.27%		1.39%
Expected Life (in years)			5 years 2 months 12 days		5 years 2 months 12 days		5 years 1 month 6 days
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			9,969,000
Weighted Average Remaining Life for Outstanding Options and SARs			4 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 84.37
Aggregate Intrinsic Value For Outstanding Options and SARs | $	[2]		$ 127,000
Stock Options and SARs Exercisable			6,197,000
Weighted Average Remaining Life For Exercisable Units			3 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 95.33
Aggregate Intrinsic Value For Exercisable Units | $	[2]		$ 42,000
Stock Options and Sars [Member] | Vesting Schedule - First Anniversary [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period Increments (in hundredths)			33.30%
Stock Options and Sars [Member] | Vesting Schedule - Second Anniversary [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period Increments (in hundredths)			33.30%
Stock Options and Sars [Member] | Vesting Schedule - Third Anniversary [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period Increments (in hundredths)			33.40%
ESPP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common Shares Available for Grant			1,600,000
Maximum Percentage Of Employee Pay Eligible For Contribution To ESPP Percentage			10.00%
Percentage of fair market value at which employees may purchase company stock via the ESPP			85.00%
Employee Stock Purchase Plan (ESPP) Disclosures [Abstract]
Aggregate Purchase Price | $			$ 17,224		$ 16,103		$ 16,533
Shares Purchased			316,000		377,000		224,000
Approximate Number of Participants | participants			2,036		2,063		1,998
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			$ 18.12		$ 19.14		$ 22.83
Expected Volatility (in hundredths)			51.27%		53.48%		34.78%
Risk-Free Interest Rate (in hundredths)			0.07%		0.90%		2.27%
Dividend Yield (in hundredths)			2.89%		2.27%		1.04%
Expected Life (in years)			6 months		6 months		6 months
Restricted Stock and Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-Based Compensation Expense | $			$ 89,000		$ 75,000		$ 97,000
Intrinsic value released during the year | $			110,000		48,000		70,000
Aggregate intrinsic value of stock and unit outstanding | $			416,000		$ 236,000		$ 381,000
Unrecognized compensation expense | $			$ 199,000
Weighted average period over which unrecognized compensation expense will be recognized			1 year 6 months
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period			3 years
Number of Shares and Units [Roll Forward]
Outstanding at January 1 (in shares)			4,742,000	[3]	4,546,000	[3]	3,792,000
Granted (in shares)			1,422,000		1,488,000		1,749,000
Released (in shares)	[4]		(1,388,000)		(1,213,000)		(855,000)
Forfeited (in shares)			(96,000)		(79,000)		(140,000)
Outstanding at December 31 (in shares)	[3]		4,680,000		4,742,000		4,546,000
Weighted Average Grant Fair Value [Abstract]
Outstanding at January 1 (in dollars per share) | $ / shares			$ 74.97	[3]	$ 90.16	[3]	$ 96.64
Granted (in dollars per share) | $ / shares			81.50		38.10		80.01
Released (in dollars per share) | $ / shares	[4]		101		85.92		96.93
Forfeited (in dollars per share) | $ / shares			68.26		86.52		97.54
Outstanding at December 31 (in dollars per share) | $ / shares	[3]		$ 69.37		$ 74.97		$ 90.16
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense related to the company's stock-based compensation plans | $			$ 15,000		$ 9,000		$ 15,000
Intrinsic value released during the year | $			13,000		13,000		15,000
Aggregate intrinsic value of stock and unit outstanding | $			60,000		$ 31,000		$ 50,000
Unrecognized compensation expense | $			$ 13,000
Weighted average period over which unrecognized compensation expense will be recognized			1 year 10 months 24 days
Cliff Vesting Period			3 years 5 months 1 day
Number of Shares and Units [Roll Forward]
Outstanding at January 1 (in shares)			613,000	[5]	598,000	[5]	539,000
Granted (in shares)			222,000		172,000		172,000
Granted for Performance Multiple (1) (in shares)	[6]		19,000		66,000		72,000
Released (in shares)	[7]		(175,000)		(223,000)		(185,000)
Forfeited (in shares)			0		0		0
Outstanding at December 31 (in shares)	[5]		679,000	[8]	613,000		598,000
Weighted Average Grant Fair Value [Abstract]
Outstanding at January 1 (in dollars per share) | $ / shares			$ 88.38	[5]	$ 103.91	[5]	$ 116.96
Granted (in dollars per share) | $ / shares			95.16		42.77		79.98
Granted for Performance Multiple (1) (in dollars per share) | $ / shares	[6]		113.81		119.10		80.64
Released (in dollars per share) | $ / shares	[7]		113.06		103.87		110.65
Forfeited (in dollars per share) | $ / shares			0		0		0
Outstanding at December 31 (in dollars per share) | $ / shares	[5]		84.97		88.38		103.91
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			$ 95.16		$ 42.77		$ 79.98
Expected Volatility (in hundredths)			53.80%		47.27%		29.20%
Risk-Free Interest Rate (in hundredths)			0.59%		0.16%		1.51%
Performance Units and Performance Stock [Abstract]
performance period for performance units			3 years
Minimum Performance Multiple at the Completion Performance Period			0.00%
Maximum Performance Multiple at the Completion Performance Period			200.00%
Performance Multiple Applied at the Completion Period		50.00%	125.00%		150.00%		200.00%
Minimum Performance Units and Stock Allowed to be Outstanding			0
Maximum Performance Units and Stock Allowed to be Outstanding			1,358
Additional Performance Awards Granted		56,671
Pension Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total pension plan costs | $			$ 52,000		$ 46,000		$ 51,000
Company contributions to foreign pension plans | $			1,000		1,000		1,000
Defined Benefit Plan, Benefit Obligation | $			13,000		13,000
Fair value of foreign pension plan assets | $			14,000		12,000
Prepaid benefit cost | $			(100)
Accrued benefit cost | $					100
Lease And Well [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense related to the company's stock-based compensation plans | $			49,000		52,000		56,000
Gathering And Processing Costs [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense related to the company's stock-based compensation plans | $			3,000		1,000		1,000
Exploration Costs [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense related to the company's stock-based compensation plans | $			20,000		21,000		26,000
General And Administrative [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense related to the company's stock-based compensation plans | $			$ 80,000		$ 72,000		$ 92,000
$ 34.00 to $  52.99 | 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			1,640,000
Weighted Average Remaining Life for Outstanding Options and SARs			6 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 37.50
Stock Options and SARs Exercisable			414,000
Weighted Average Remaining Life For Exercisable Units			5 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 37.46
53.00 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			1,906,000
Weighted Average Remaining Life for Outstanding Options and SARs			4 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 73.68
Stock Options and SARs Exercisable			1,313,000
Weighted Average Remaining Life For Exercisable Units			3 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 73.11
76.00 to     90.99 | 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			1,976,000
Weighted Average Remaining Life for Outstanding Options and SARs			7 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 81.86
Stock Options and SARs Exercisable			33,000
Weighted Average Remaining Life For Exercisable Units			2 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 83.71
91.00 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			1,114,000
Weighted Average Remaining Life for Outstanding Options and SARs			2 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 94.95
Stock Options and SARs Exercisable			1,109,000
Weighted Average Remaining Life For Exercisable Units			2 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 94.96
96.00 to   101.99 | Stock Options and Sars [Member]
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items]
Stock Options and SARs Outstanding			1,657,000
Weighted Average Remaining Life for Outstanding Options and SARs			3 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 96.34
Stock Options and SARs Exercisable			1,652,000
Weighted Average Remaining Life For Exercisable Units			3 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 96.33
102.00 to   129.99 | Stock Options and Sars [Member]
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items]
Stock Options and SARs Outstanding			1,676,000
Weighted Average Remaining Life for Outstanding Options and SARs			4 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 126.51
Stock Options and SARs Exercisable			1,676,000
Weighted Average Remaining Life For Exercisable Units			4 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 126.51
[1]	The total intrinsic value of stock options/SARs exercised during the years 2021, 2020 and 2019 was $27 million, $0.4 million and $14 million, respectively.  The intrinsic value is based upon the difference between the market price of the Common Stock on the date of exercise and the grant price of the stock options/SARs.
[2]	Based upon the difference between the closing market price of the Common Stock on the last trading day of the year and the grant price of in-the-money stock options and SARs, in millions.
[3]	The total intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2021, 2020 and 2019 was $416 million, $236 million and $381 million, respectively. The intrinsic value is based on the closing market price of the Common Stock on the last trading day of the year.
[4]	The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2021, 2020 and 2019 was $110 million, $48 million and $70 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)
[5]	The total intrinsic value of Performance Units outstanding at December 31, 2021, 2020 and 2019 was $60 million, $31 million and $50 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 Units granted in 2017, 2016 and 2015, a performance multiple of 125%, 150% and 200%, respectively, was applied to each of the grants resulting in additional grants of Performance Units in February 2021, 2020 and 2019.
[7]	The total intrinsic value of Performance Units released during the years ended December 31, 2021, 2020 and 2019 was $13 million, $13 million and $15 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date Performance Units are released.
[8]	Upon the application of the relevant performance multiple at the completion of each of the remaining Performance Periods, a minimum of zero and a maximum of 1,358 Performance Units could be outstanding.

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Deferred Income Tax Assets (Liabilities)
Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization		$ (19)	$ 25
Foreign Asset Retirement Obligations		51	0
Foreign Accrued Expenses and Liabilities		15	0
Foreign Net Operating Loss		80	74
Foreign Valuation Allowances		(111)	(97)
Foreign Other		(5)	0
Total Net Deferred Income Tax Assets		11	2
Deferred Income Tax (Assets) Liabilities
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization		5,063	5,028
Commodity Hedging Contracts		(97)
Commodity Hedging Contracts			15
Deferred Compensation Plans		(57)	(43)
Equity Awards		(86)	(103)
Undistributed Foreign Earnings		0	10
Other		(74)	(48)
Total Net Deferred Income Tax Liabilities		4,749	4,859
Total Net Deferred Income Tax Liabilities		4,738	4,857
Components Income (Loss) Before Income Taxes [Abstract]
United States		5,787	(756)	$ 3,466
Foreign		146	17	79
Income (Loss) Before Income Taxes		5,933	(739)	3,545
Current income tax provision (benefit) [Abstract]
Federal		1,203	(108)	(152)
State		85	7	10
Foreign		105	40	81
Total		1,393	(61)	(61)
Deferred income tax provision (benefit) [Abstract]
Federal		(41)	(153)	627
State		(62)	(15)	33
Foreign		(19)	(18)	(28)
Total		(122)	(186)	632
Other Non-Current (1)
Federal	[1]	0	113	245
Foreign		(2)	0	(6)
Total		(2)	113	239
Income Tax Provision (Benefit)		$ 1,269	$ (134)	$ 810
Federal Statutory and Effective Income Tax Rates [Abstract]
Statutory Federal Income Tax Rate (in hundredths)		21.00%	21.00%	21.00%
State Income Tax, Net of Federal Benefit (in hundredths)		0.30%	0.90%	1.00%
Income Tax Provision Related to Foreign Operations (in hundredths)		0.90%	(0.10%)	0.90%
Income Tax Provision Related to Canadian Operations (in hundredths)		0.00%	(2.40%)	0.00%
Shared-Based Compensation (in hundredths)		0.20%	(2.90%)	0.00%
Other (in hundredths)		(1.00%)	1.70%	0.00%
Effective Income Tax Rate (in hundredths)		21.40%	18.20%	22.90%
Components of Valuation Allowance [Abstract]
Beginning Balance		$ 219	$ 201	$ 167
Increase	[2]	15	25	31
Decrease	[3]	(14)	(11)	0
Other	[4]	(1)	4	3
Ending Balance		219	$ 219	$ 201
Balance of state net operating loss expected to be carried forward		2,000
Canadian Net Operating Loss Carryforwards		297
Unrecognized Tax Benefits Balance		$ 9
[1]	Includes changes in certain amounts that are expected to be paid or received beyond the next twelve months. The primary component in 2020 and 2019 is refundable alternative minimum tax (AMT) credits.
[2]	Increase in valuation allowance related to the generation of tax NOLs and other deferred tax assets.
[3]	Decrease in valuation allowance associated with adjustments to certain deferred tax assets and their related allowances.
[4]	Represents dispositions, revisions and/or foreign exchange rate variances and the effect of statutory income tax rate changes.

Commitments and Contingencies_3

Commitments and Contingencies (Details) - USD ($)	Feb. 17, 2022	Dec. 31, 2021	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Standby letters of credit and guarantees outstanding		$ 831,000,000	$ 854,000,000
Total Minimum Commitments [Abstract]
2021		1,335,000,000
2022		1,045,000,000
2023		823,000,000
2024		673,000,000
2025		579,000,000
2026 and beyond		2,133,000,000
Total Minimum Commitments		$ 6,588,000,000
Subsequent Event
Subsequent Event [Line Items]
Subsidiary guarantees demand for payment	$ 0

Net Income (Loss) Per Share (De

Net Income (Loss) Per Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Numerator for Basic and Diluted Earnings per Share - [Abstract]
Net Income (Loss)	$ 4,664	$ (605)	$ 2,735
Denominator for Basic Earnings per Share - [Abstract]
Weighted Average Shares	581	579	578
Denominator for Diluted Earnings per Share - [Abstract]
Adjusted Diluted Weighted Average Shares	584	579	581
Antidilutive Securities Excluded from Computation of Earnings Per Share [Abstract]
Anti-dilutive Securities excluded from Diluted Earnings Per Share Calculation	6	10	6
Net Income (Loss) Per Share [Abstract]
Basic	$ 8.03	$ (1.04)	$ 4.73
Diluted	$ 7.99	$ (1.04)	$ 4.71
Stock Options and Sars [Member]
Potential Dilutive Common Shares -[Abstract]
Common Shares Attributable to Dilutive Effect of Share-Based Payment Arrangments	0	0	0
Restricted Stock/Units and Performance Units/Stock [Member]
Potential Dilutive Common Shares -[Abstract]
Common Shares Attributable to Dilutive Effect of Share-Based Payment Arrangments	3	0	3
Antidilutive Securities Excluded from Computation of Earnings Per Share [Abstract]
Anti-dilutive Securities excluded from Diluted Earnings Per Share Calculation		5

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Supplemental Cash Flow Information [Abstract]
Interest, Net of Capitalized Interest	$ 185	$ 205	$ 187
Income Taxes, Net of Refunds Received	1,114	(206)	(292)
Accrued Capital Expenditures	592	414	612
Non-cash investing and financing activities from property exchanges.	50	212	$ 150
Non-cash investing activities from other, property, plant and equipment	74	$ 174
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2025	$ 500

Business Segment Information (D

Business Segment Information (Details) - USD ($) $ in Millions		3 Months Ended	12 Months Ended
		Jun. 30, 2021	Dec. 31, 2021		Dec. 31, 2020		Dec. 31, 2019
Schedule of Segment Reporting Information By Segment [Abstract]
Operating Revenues and Other			$ 18,642		$ 11,032		$ 17,380
Depreciation, Depletion and Amortization			3,651		3,400		3,750
Operating Income (Loss)			6,102		(544)		3,699
Interest Income			3		12		26
Other Income (Expense)			6		(2)		5
Net Interest Expense (Income)			178		205		185
Income (Loss) Before Income Taxes			5,933		(739)		3,545
Income Tax Provision (Benefit)			1,269		(134)		810
Additions to Oil and Gas Properties, Excluding Dry Hole Costs			3,617		3,443		6,274
Total Property, Plant and Equipment, Net			28,426		28,599		30,364
Total Assets			38,236		35,805		37,125
Dry Hole Costs	[1]		71		13		28
Crude Oil and Condensate
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues			11,125		5,786		9,613
Natural Gas Liquids
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues			1,812		668		785
Natural Gas
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues			2,444		837		1,184
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues			(1,152)		1,145		180
Gathering, Processing and Marketing
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues			4,288		2,583		5,360
Gains (Losses) on Asset Dispositions, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues			17		(47)		124
Other, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues			108		60		134
United States
Schedule of Segment Reporting Information By Segment [Abstract]
Operating Revenues and Other			18,265	[2]	10,795	[3]	17,052	[4]
Depreciation, Depletion and Amortization			3,558		3,324		3,652
Operating Income (Loss)			6,013		(546)	[5]	3,619
Interest Income			3		11		22
Other Income (Expense)			(14)		0		3
Net Interest Expense (Income)			178		205		192
Income (Loss) Before Income Taxes			5,824		(740)		3,452
Income Tax Provision (Benefit)			1,247		(157)		761
Additions to Oil and Gas Properties, Excluding Dry Hole Costs			3,557		3,318		6,209
Total Property, Plant and Equipment, Net			28,213		28,284		30,102
Total Assets			37,436		35,048		36,275
Amount of sales with a single significant purchaser in the United States segment			2,700		1,100		2,400
Amount of sales with a second significant purchaser in the United States segment.			2,600				2,200
Pretax Impairment Charges For Proved Oil And Gas Properties And Other Property Plant And Equipment					1,570
Pretax Impairment Charges For Other Assets					228
United States | Crude Oil and Condensate
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues			11,094		5,774		9,599
United States | Natural Gas Liquids
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues			1,812		668		785
United States | Natural Gas
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues			2,156		614		867
United States | Gains (Losses) on Mark-to-Market Commodity Derivative Contracts
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues			(1,152)		1,145		180
United States | Gathering, Processing and Marketing
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues			4,287		2,581		5,355
United States | Gains (Losses) on Asset Dispositions, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues			(40)		(47)		132
United States | Other, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues			108		60		134
Trinidad
Schedule of Segment Reporting Information By Segment [Abstract]
Operating Revenues and Other			300		182		271
Depreciation, Depletion and Amortization			87		60		80
Operating Income (Loss)			151		75		113
Interest Income			0		1		4
Other Income (Expense)			8		(2)		1
Net Interest Expense (Income)			0		0		0
Income (Loss) Before Income Taxes			159		74		118
Income Tax Provision (Benefit)			66		15		41
Additions to Oil and Gas Properties, Excluding Dry Hole Costs			55		83		53
Total Property, Plant and Equipment, Net			204		210		184
Total Assets			637		546		706
Trinidad | Crude Oil and Condensate
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues			31		11		11
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			270		169		259
Trinidad | Gains (Losses) on Mark-to-Market Commodity Derivative Contracts
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues			0		0		0
Trinidad | Gathering, Processing and Marketing
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues			1		2		5
Trinidad | Gains (Losses) on Asset Dispositions, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues			(2)		0		(4)
Trinidad | Other, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues			0		0		0
Other International
Schedule of Segment Reporting Information By Segment [Abstract]
Operating Revenues and Other	[6]		77		55		57
Depreciation, Depletion and Amortization	[6]		6		16		18
Operating Income (Loss)	[6]		(62)	[7]	(73)	[5]	(33)
Interest Income	[6]		0		0		0
Other Income (Expense)			12		0	[6]	1	[6]
Net Interest Expense (Income)	[6]		0		0		(7)
Income (Loss) Before Income Taxes	[6]		(50)		(73)		(25)
Income Tax Provision (Benefit)	[6]		(44)		8		8
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	[6]		5		42		12
Total Property, Plant and Equipment, Net	[6]		9		105		78
Total Assets	[6]		163		211		144
Pretax Impairment Charges For Proved Oil And Gas Properties And Other Property Plant And Equipment			45		81
Dry Hole Costs			42
Other International | Crude Oil and Condensate
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues	[6]		0		1		3
Other International | Natural Gas Liquids
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues	[6]		0		0		0
Other International | Natural Gas
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues	[6]		18		54		58
Other International | Gains (Losses) on Mark-to-Market Commodity Derivative Contracts
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues	[6]		0		0		0
Other International | Gathering, Processing and Marketing
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues	[6]		0		0		0
Other International | Gains (Losses) on Asset Dispositions, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues		$ 58	59	[6]	0	[6]	(4)	[6]
Other International | Other, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues	[6]		$ 0		$ 0		$ 0
[1]	Excludes gains or losses on the mark-to-market of financial commodity derivative contracts, gains or losses on sales of reserves and related assets, interest charges and general corporate expenses for each of the three years in the period ended December 31, 2021.
[2]	EOG had sales activity with two significant purchasers in 2021, one totaling $2.7 billion and the other totaling $2.6 billion of consolidated Operating Revenues and Other in the United States segment.
[3]	EOG had sales activity with three significant purchasers in 2020, each totaling $1.1 billion of consolidated Operating Revenues and Other in the United States segment.
[4]	EOG had sales activity with two significant purchasers in 2019, one totaling $2.4 billion and the other totaling $2.2 billion of consolidated Operating Revenues and Other in the United States segment.
[5]	EOG recorded pretax impairment charges of $1,570 million in 2020 for proved oil and gas properties, leasehold costs and other assets due to the decline in commodity prices and revisions of asset retirement obligations for certain properties in the United States segment. In addition, EOG recorded pretax impairment charges of $228 million in 2020 for owned and leased sand and crude-by-rail assets, also in the United States segment. EOG recorded pretax impairment charges of $81 million in 2020 for proved oil and gas properties and firm commitment contracts related to its decision to exit the Horn River Basin in British Columbia, Canada, in the Other International segment. See Notes 13 and 14.
[6]	Other International primarily consists of EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. EOG began exploration programs in Australia in the third quarter of 2021 and in Oman in the third quarter of 2020. The decision was reached in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman.
[7]	EOG recorded pretax impairment charges of $45 million and dry hole costs of $42 million in 2021 in the Other International segment related to its decision in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman. In addition, EOG recorded net gains of asset dispositions of $58 million in 2021 in the Other International segment during the second quarter of 2021 due to the sale of its China operations. See Notes 14 and 17, respectively.

Risk Management Activities (Det

Risk Management Activities (Details) $ in Millions		12 Months Ended
		Dec. 31, 2021USD ($)BTU$ / bblbbl	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Feb. 18, 2022USD ($)
Derivatives, Fair Value [Line Items]
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts | $		$ (1,152)	$ 1,145	$ 180
Net Cash Received from (Payments for) Settlements of Commodity Derivatives Contracts | $		(638)	1,071	$ 231
Assets from Price Risk Management Activities | $		0	65
Liabilities from Price Risk Management Activities | $		$ 269	$ 0
Receivable Major Customer Percentage		10.00%	10.00%
Derivative Collateral [Abstract]
Collateral Already Posted on Derivative | $		$ 140	$ 0		$ 1,400
Collateral Held on Derivative | $		0	0
Price Risk Derivative [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Noncurrent | $	[1]	6	1
Derivative Liability, Noncurrent | $	[2]	37	1
Assets From Price Risk Management Activities [Member] | Price Risk Derivative [Member]
Derivatives, Fair Value [Line Items]
Assets from Price Risk Management Activities | $		0	65
Liabilities From Price Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset | $		29
Derivative Liability, Fair Value, Gross Liability | $		421
Derivative Collateral [Abstract]
Collateral Posted on Derivative | $		123
Liabilities From Price Risk Management Activities [Member] | Price Risk Derivative [Member]
Derivatives, Fair Value [Line Items]
Liabilities from Price Risk Management Activities | $	[3]	269	0
Other Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset | $		7
Derivative Liability, Fair Value, Gross Liability | $		1
Other Liabilities
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset | $		10
Derivative Liability, Fair Value, Gross Liability | $			$ 64
Derivative Collateral [Abstract]
Collateral Posted on Derivative | $		$ 17
Crude Oil | Derivative Contracts - January (closed) | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl		151
Weighted Average Price		50.06
Crude Oil | Derivative Contracts - February through March (closed) | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl		201
Weighted Average Price		51.29
Crude Oil | Derivative Contracts - April through June (closed) | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl		150
Weighted Average Price		51.68
Crude Oil | Derivative Contracts - July through September (closed) | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl		150
Weighted Average Price		52.71
Crude Oil | Derivative Contracts - Year Two - April through June | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl		140
Weighted Average Price		65.62
Crude Oil | Derivative Contracts - Year Two - July through September [Member] | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl		140
Weighted Average Price		65.59
Crude Oil | Derivative Contracts - Year Two - October through December | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl		140
Weighted Average Price		65.68
Crude Oil | Derivative Contracts - Year Three - January through March | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl		150
Weighted Average Price		67.92
Crude Oil | Derivative Contracts - Year Three - April through June | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl		120
Weighted Average Price		67.79
Crude Oil | Derivative Contracts - Year Three - July through September | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl		20
Weighted Average Price		68.04
Crude Oil | Derivative Contracts - February (closed) | Roll Differential Swap
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl	[4]	30
Weighted Average Price	[4]	0.11
Crude Oil | Derivative Contracts - March through December (closed) | Roll Differential Swap
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl	[4]	125
Weighted Average Price	[4]	0.17
Crude Oil | Derivative Contracts - Year Two - January (closed) | Roll Differential Swap
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl	[4]	125
Weighted Average Price	[4]	0.15
Crude Oil | Derivative Contracts - Year Two - February through December | Roll Differential Swap
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl	[4]	125
Weighted Average Price	[4]	0.15
Crude Oil | Derivative Contracts - Year Two - January through March | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl		140
Weighted Average Price		65.58
Natural Gas Liquids | Derivative Contracts - January through December (closed) [Member] | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl		15
Weighted Average Price		29.44
Natural Gas | Price Swaps
Derivatives, Fair Value [Line Items]
Cash Received For Early Termination Of Contracts | $		$ 0.6
Natural Gas | Derivative Contracts - January through March (closed) | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | BTU		500
Weighted Average Price (MMBtu)		2.99
Natural Gas | Derivative Contracts - April through September (closed) | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | BTU		500
Weighted Average Price (MMBtu)		2.99
Natural Gas | Derivative Contracts - April through September (closed) | Japan Korea Marker
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | BTU		70
Weighted Average Price (MMBtu)		6.65
Natural Gas | Derivative Contracts - October through December (closed) | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | BTU		500
Weighted Average Price (MMBtu)		2.99
Natural Gas | Derivative Contracts - Year Two - January through December (closed) | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | BTU	[5]	20
Weighted Average Price (MMBtu)	[5]	2.75
Natural Gas | Derivative Contracts - Year Two - January through December | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | BTU		725
Weighted Average Price (MMBtu)		3.57
Natural Gas | Derivative Contracts - Year Two - January through December | HSC Differential Basis Swaps [Member]
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | BTU	[6]	210
Weighted Average Price (MMBtu)	[6]	(0.01)
Natural Gas | Derivative Contracts - Year Three - January through December | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | BTU		725
Weighted Average Price (MMBtu)		3.18
Natural Gas | Derivative Contracts - Year Three - January through December | HSC Differential Basis Swaps [Member]
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | BTU	[6]	135
Weighted Average Price (MMBtu)	[6]	(0.01)
Natural Gas | Derivative Contracts - Year Four - January through December [Member] | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | BTU		725
Weighted Average Price (MMBtu)		3.07
Natural Gas | Derivative Contracts - Year Four - January through December [Member] | HSC Differential Basis Swaps [Member]
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | BTU	[6]	10
Weighted Average Price (MMBtu)	[6]	0
Natural Gas | Derivative Contracts - Year Five - January through December [Member] | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | BTU		725
Weighted Average Price (MMBtu)		3.07
Natural Gas | Derivative Contracts - Year Five - January through December [Member] | HSC Differential Basis Swaps [Member]
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | BTU	[6]	10
Weighted Average Price (MMBtu)	[6]	0
Natural Gas | OffSetting Derivative Contracts - January through March (closed) | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | BTU		500
Weighted Average Price (MMBtu)		2.43
Natural Gas | OffSetting Derivative Contracts - April through September (closed) | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | BTU		570
Weighted Average Price (MMBtu)		2.81
Natural Gas | OffSetting Derivative Contracts - April through September (closed) | Japan Korea Marker
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | BTU		0
Weighted Average Price (MMBtu)		0
Natural Gas | OffSetting Derivative Contracts - October through December (closed) | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | BTU		500
Weighted Average Price (MMBtu)		2.83
Natural Gas | Derivative Contracts - Year Two - January through March | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | BTU	[5]	0
Weighted Average Price (MMBtu)	[5]	0
Natural Gas | Offsetting Derivative Contracts - Year Two - January through December | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | BTU		0
Weighted Average Price (MMBtu)		0
Natural Gas | Offsetting Derivative Contracts - Year Three - January through December | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | BTU		0
Weighted Average Price (MMBtu)		0
Natural Gas | Offsetting Derivative Contracts - Year Four - January through December | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | BTU		0
Weighted Average Price (MMBtu)		0
Natural Gas | Offsetting Derivative Contracts - Year Five - January through December [Member] | Price Swaps
Derivatives, Fair Value [Line Items]
Volume (MMBTU) | BTU		0
Weighted Average Price (MMBtu)		0
[1]	The noncurrent portion of Assets from Price Risk Management Activities consists of gross assets of $7 million, partially offset by gross liabilities of $1 million, at December 31, 2021.
[2]	The noncurrent portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $64 million, partially offset by gross assets of $10 million and collateral posted with counterparties of $17 million, at December 31, 2021.
[3]	The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $421 million, partially offset by gross assets of $29 million and collateral posted with counterparties of $123 million, at December 31, 2021.
[4]	This settlement index is used to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month.
[5]	In January 2021, EOG executed the early termination provision granting EOG the right to terminate all of its 2022 natural gas price swap contracts which were open at that time. EOG received net cash of $0.6 million for the settlement of these contracts
[6]	This settlement index is used to fix the differential between pricing at the Houston Ship Channel and NYMEX Henry Hub prices.

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
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	$ 27	$ 1,587	$ 408
Proved oil and gas properties, other property, plant and equipment and other assets written down during the period - fair value at end of period	7	319	201
Pretax impairment charges for proved oil and gas properties, other property, plant and equipment and other assets	20	1,268	207
Pretax impairment charge for a commodity price-related write-down of other assets		72	90
Pretax impairment charges for proved oil and gas properties and other assets for firm commitment contracts			$ 152
Debt Disclosure [Abstract]
Aggregate Principal Amount of Current and Long-term Debt	4,890	5,640
Estimated Fair Value of Debt	5,577	6,505
Commodity Contract [Member] | Crude Oil | Price Swaps
Financial Assets:
Assets, Fair Value Disclosure	15
Financial Liabilities:
Liabilities, Fair Value Disclosure	340
Commodity Contract [Member] | Crude Oil | Price Swaps | Fair Value, Inputs, Level 1
Financial Assets:
Assets, Fair Value Disclosure	0
Financial Liabilities:
Liabilities, Fair Value Disclosure	0
Commodity Contract [Member] | Crude Oil | Price Swaps | Fair Value, Inputs, Level 2
Financial Assets:
Assets, Fair Value Disclosure	15
Financial Liabilities:
Liabilities, Fair Value Disclosure	340
Commodity Contract [Member] | Crude Oil | Price Swaps | Fair Value, Inputs, Level 3
Financial Assets:
Assets, Fair Value Disclosure	0
Financial Liabilities:
Liabilities, Fair Value Disclosure	0
Commodity Contract [Member] | Crude Oil | Roll Differential Swap
Financial Liabilities:
Liabilities, Fair Value Disclosure	24	1
Commodity Contract [Member] | Crude Oil | Roll Differential Swap | Fair Value, Inputs, Level 1
Financial Liabilities:
Liabilities, Fair Value Disclosure	0	0
Commodity Contract [Member] | Crude Oil | Roll Differential Swap | Fair Value, Inputs, Level 2
Financial Liabilities:
Liabilities, Fair Value Disclosure	24	1
Commodity Contract [Member] | Crude Oil | Roll Differential Swap | Fair Value, Inputs, Level 3
Financial Liabilities:
Liabilities, Fair Value Disclosure	0	0
Commodity Contract [Member] | Natural Gas | Price Swaps
Financial Assets:
Assets, Fair Value Disclosure	29	66
Financial Liabilities:
Liabilities, Fair Value Disclosure	121
Commodity Contract [Member] | Natural Gas | Price Swaps | Fair Value, Inputs, Level 1
Financial Assets:
Assets, Fair Value Disclosure	0	0
Financial Liabilities:
Liabilities, Fair Value Disclosure	0
Commodity Contract [Member] | Natural Gas | Price Swaps | Fair Value, Inputs, Level 2
Financial Assets:
Assets, Fair Value Disclosure	29	66
Financial Liabilities:
Liabilities, Fair Value Disclosure	121
Commodity Contract [Member] | Natural Gas | Price Swaps | Fair Value, Inputs, Level 3
Financial Assets:
Assets, Fair Value Disclosure	0	$ 0
Financial Liabilities:
Liabilities, Fair Value Disclosure	0
Commodity Contract [Member] | Natural Gas | Basis Swaps
Financial Assets:
Assets, Fair Value Disclosure	2
Financial Liabilities:
Liabilities, Fair Value Disclosure	1
Commodity Contract [Member] | Natural Gas | Basis Swaps | Fair Value, Inputs, Level 1
Financial Assets:
Assets, Fair Value Disclosure	0
Financial Liabilities:
Liabilities, Fair Value Disclosure	0
Commodity Contract [Member] | Natural Gas | Basis Swaps | Fair Value, Inputs, Level 2
Financial Assets:
Assets, Fair Value Disclosure	2
Financial Liabilities:
Liabilities, Fair Value Disclosure	1
Commodity Contract [Member] | Natural Gas | Basis Swaps | Fair Value, Inputs, Level 3
Financial Assets:
Assets, Fair Value Disclosure	0
Financial Liabilities:
Liabilities, Fair Value Disclosure	$ 0

Impairment Expense (Details)

Impairment Expense (Details) - USD ($) $ in Millions		3 Months Ended	12 Months Ended
		Dec. 31, 2021	Dec. 31, 2021		Dec. 31, 2020		Dec. 31, 2019
Impairment of Oil and Gas Properties [Line Items]
Impairment of Oil and Gas Properties			$ 376		$ 2,100		$ 518
Proved Properties
Impairment of Oil and Gas Properties [Line Items]
Impairment of Oil and Gas Properties	[1]		20		1,268		207
Unproved Properties
Impairment of Oil and Gas Properties [Line Items]
Impairment of Oil and Gas Properties		$ 38	310	[2]	472	[2]	220	[2]
Leasehold Costs of Impairments of Unproved Oil and Gas Properties					252
Other Assets
Impairment of Oil and Gas Properties [Line Items]
Other Assets Impairments Related to Commodity Price-Related Write-Down					72		90
Impairment of Oil and Gas Properties	[3]		28		300		91
Impairments for Owned and Leased Sand and Crude-by-Rail Assets					228
Inventories
Impairment of Oil and Gas Properties [Line Items]
Impairment of Oil and Gas Properties			13		0		0
Firm Commitments Contracts
Impairment of Oil and Gas Properties [Line Items]
Impairment of Oil and Gas Properties			$ 5	[4]	60		$ 0
Canadian Firm Commitment Contracts					$ 60
[1]	Impairments to proved oil and gas properties in 2020 included legacy and non-core natural gas and crude oil and combo plays. Impairments to proved oil and gas properties in 2019 included domestic legacy natural gas assets. See Notes 1 and 13.
[2]	Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. Impairments of unproved oil and gas properties included $38 million in 2021 for the decision in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman. Impairments of unproved oil and gas properties included charges of $252 million in 2020 for certain leasehold costs that are no longer expected to be developed before expiration in the United States. See Note 1.
[3]	Includes impairment charges for owned and leased sand and crude-by-rail assets of $228 million in 2020 (see Note 18) and a commodity price-related write-down of other assets of $72 million and $90 million in 2020 and 2019, respectively (see Note 13).
[4]	Includes impairment charges of $60 million in 2020 for firm commitment contracts related to its decision to exit the Horn River Basin in British Columbia, Canada.

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligations, Noncurrent [Abstract]
Carrying Amount at Beginning of Period		$ 1,217	$ 1,111
Liabilities Incurred		81	58
Liabilities Settled (1)	[1]	(131)	(54)
Accretion		44	47
Revisions		20	54
Foreign Currency Translations		0	1
Carrying Amount at End of Period		1,231	1,217
Current Portion		43	50
Noncurrent Portion		$ 1,188	$ 1,167
[1]	Includes settlements related to asset sales and property exchanges.

Exploratory Well Costs (Details

Exploratory Well Costs (Details) $ in Millions		12 Months Ended
		Dec. 31, 2021USD ($)well	Dec. 31, 2020USD ($)well		Dec. 31, 2019USD ($)well
Capitalized Exploratory Well Costs [Abstract]
Balance at January 1		$ 29	$ 26		$ 4
Additions Pending the Determination of Proved Reserves		73	108		83
Reclassifications to Proved Properties		(41)	(81)		(39)
Costs Charged to Expense (1)	[1]	(54)	(24)		(22)
Balance at December 31		$ 7	$ 29		$ 26
Projects that have Exploratory Well Costs that have been Capitalized for Period Greater than One Year, Number of Projects | well		0	1		0
Capitalized Exploratory Well Costs that Have Been Capitalized for Period of One Year or Less		$ 7	$ 26		$ 26
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year		$ 0	$ 3	[2]	$ 0
[1]	Includes capitalized exploratory well costs charged to either dry hole costs or impairments.
[2]	(1)    Consists of costs related to a project in the United States at December 31, 2020.

Acquisitions and Divestitures_2

Acquisitions and Divestitures (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Business Combination, Separately Recognized Transactions [Line Items]
Gains (Losses) on Asset Dispositions, Net	$ 17	$ (47)	$ 124
Proceeds from Sale of Oil and Gas Properties and Equipment	231	192	140
Book value of asset retirement obligations	105
Held-for-sale
Business Combination, Separately Recognized Transactions [Line Items]
Book value of assets held-for-sale	99
United States
Business Combination, Separately Recognized Transactions [Line Items]
Payments to Acquire Oil and Gas Property	$ 95	82	$ 328
Other International
Business Combination, Separately Recognized Transactions [Line Items]
Payments to Acquire Oil and Gas Property		$ 38

Leases (Details)

Leases (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020		Dec. 31, 2019	Dec. 31, 2018
Lease, Cost [Abstract]
Operating Lease Cost		$ 295	$ 393	[1]	$ 497
Amortization of Lease Assets		39	21		13
Interest on Lease Liabilities		7	4		2
Variable Lease Cost		63	91		138
Short-term Lease Cost		257	194		333
Total Lease Cost		661	703		983
Operating Lease, Impairment Expense			35
Lease Assets and Liabilities [Abstract]
Total		984	1,075
Current Portion of Operating Lease Liabilities		240	295
Total		$ 1,048	$ 1,148
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]		Other Assets, Noncurrent	Other Assets, Noncurrent
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]		Property, Plant and Equipment, Gross	Property, Plant and Equipment, Gross
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]		Current Portion of Long-Term Debt	Current Portion of Long-Term Debt
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]		Other Liabilities	Other Liabilities
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]		Long-Term Debt	Long-Term Debt
Cash Flow Operating And Financing Activities [Abstract]
Repayment of Finance Lease Liabilities		$ 37	$ 19		13
Operating Leases Non-Cash Leasing Activities		333	893		784
Finance Leases Non-Cash Leasing Activities		74	174
Operating And Finance Leases Future Minimum Payments [Abstract]
Total Lease Liabilities		250	$ 212
Operating And Finance Leases Not Yet Commenced		$ 98
Minimum Operating And Finance Leases Not Yet Commenced Lease Term		3 months
Maximum Operating And Finance Leases Not Yet Commenced Lease Term		9 years
Accounting Standards Update 2016-02
Lease Assets and Liabilities [Abstract]
Other Assets						$ 566
Operating Leases
Lease Assets and Liabilities [Abstract]
Current Portion of Operating Lease Liabilities		$ 240
Other Liabilities		$ 558
Weighted Average Remaining Lease Term And Discount Rate [Abstract]
Operating Lease Weighted Average Remaining Lease Term (in years)		5 years 3 months 18 days	5 years 3 months 18 days
Operating Lease Weighted Average Discount Rate (%)		3.00%	3.40%
Operating And Finance Leases Future Minimum Payments [Abstract]
2022		$ 262
2023		188
2024		113
2025		80
2026		59
2027 and Beyond		172
Total Lease Payments		874
Less: Discount to Present Value		76
Total Lease Liabilities		798
Operating Leases | Operating Activities
Cash Flow Operating And Financing Activities [Abstract]
Repayment of Operating Lease Liabilities Associated with Operating Activities		207	$ 223		225
Operating Leases | Investing Activities
Cash Flow Operating And Financing Activities [Abstract]
Repayment of Operating Lease Liabilities Associated with Operating Activities		98	$ 130		270
Finance Leases
Lease Assets and Liabilities [Abstract]
Current Portion of Long-Term Debt		37
Long-Term Debt		$ 213
Weighted Average Remaining Lease Term And Discount Rate [Abstract]
Finance Lease Weighted Average Remaining Lease Term (in years)		7 years	7 years 7 months 6 days
Finance Lease Weighted Average Discount Rate (%)		2.60%	2.80%
Cash Flow Operating And Financing Activities [Abstract]
Repayment of Finance Lease Liabilities		$ 37	$ 19		$ 13
Operating And Finance Leases Future Minimum Payments [Abstract]
2022		42
2023		37
2024		37
2025		36
2026		30
2027 and Beyond		94
Total Lease Payments		276
Less: Discount to Present Value		26
Total Lease Liabilities		250
Other Assets | Operating Leases
Lease Assets and Liabilities [Abstract]
Other Assets		743	869
Property, Plant and Equipment | Finance Leases
Lease Assets and Liabilities [Abstract]
Property, Plant and Equipment, Net (1)	[2]	241	206
Finance Lease, Right-of-Use Asset, Accumulated Amortization		119	81
Current Portion of Operating Lease Liabilities | Operating Leases
Lease Assets and Liabilities [Abstract]
Current Portion of Operating Lease Liabilities		240	295
Current Portion of Long-Term Debt | Finance Leases
Lease Assets and Liabilities [Abstract]
Current Portion of Long-Term Debt		37	31
Other Liabilities | Operating Leases
Lease Assets and Liabilities [Abstract]
Other Liabilities		558	641
Long-term Debt | Finance Leases
Lease Assets and Liabilities [Abstract]
Long-Term Debt		$ 213	$ 181
[1]	Operating lease cost includes impairment expenses of $35 million in 2020.
[2]	Finance lease assets are recorded net of accumulated amortization of $119 million and $81 million at December 31, 2021 and 2020, respectively.

Oil and Gas Exploration and P_3

Oil and Gas Exploration and Production Industries Disclosures (Details) $ in Millions		12 Months Ended
		Dec. 31, 2021USD ($)MMBoeMMBblsBcf	Dec. 31, 2021USD ($)MMBoeBcfMMBbls	Dec. 31, 2021USD ($)MMBoeBcfMMBbls	Dec. 31, 2020USD ($)MMBoeMMBblsBcf		Dec. 31, 2019MMBoeMMBblsBcf		Dec. 31, 2018MMBoeMMBblsBcf
Proved Developed Reserves [Rollforward]
Net proved reserves - end of period		1,548	8,222
Proved Developed Reserves (MMBoe) [Roll Forward]
Net proved reserves - end of period | MMBoe				3,747
Net proved developed reserves (MMBOE) | MMBoe		1,948	1,948	1,948	1,649		1,721		1,548
Net Proved Undeveloped Reserves (MMBOE) [Rollforward]
Balance at January 1 | MMBoe				1,571	1,608		1,380
Extensions and Discoveries | MMBoe				779	456		578
Revisions | MMBoe				(305)	(277)		(50)
Acquisition of Reserves | MMBoe				0	0		2
Sales of Reserves | MMBoe				(3)	(4)		0
Conversion to Proved Developed Reserves | MMBoe				(243)	(212)		(302)
Balance at December 31 | MMBoe				1,799	1,571		1,608
Capitalized Costs, Oil and Gas Producing Activities, Gross [Abstract]
Proved properties | $		$ 64,876	$ 64,876	$ 64,876	$ 61,725
Unproved properties | $		2,768	2,768	2,768	3,068
Total | $		67,644	67,644	67,644	64,793
Accumulated depreciation, depletion and amortization | $		(41,907)	(41,907)	(41,907)	(38,751)
Net capitalized costs | $		$ 25,737	$ 25,737	$ 25,737	$ 26,042
Crude Oil (MMBbl)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	1,514			1,694		1,532
Revisions of previous estimates	[1]	(116)			(225)		(43)
Purchases in place	[1]	2			2		3
Extensions, discoveries and other additions	[1]	312			195		370
Sales in place	[1]	(2)			(3)		(1)
Production	[1]	(162)			(149)		(167)
Net proved reserves - end of period	[1]				1,514		1,694
Proved Developed Reserves (MMBoe) [Roll Forward]
Net proved developed reserves		886	886	886	793		801		713
Net Proved Undeveloped Reserves (MMBOE) [Rollforward]
Net proved undeveloped reserves		662	662	662	721		893		819
Natural Gas Liquids (MMBbl)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	813			740		614
Revisions of previous estimates	[1]	(128)			(60)		5
Purchases in place	[1]	3			4		2
Extensions, discoveries and other additions	[1]	194			180		168
Sales in place	[1]	0			(1)		(1)
Production	[1]	(53)			(50)		(48)
Net proved reserves - end of period		829			813	[1]	740	[1]
Proved Developed Reserves (MMBoe) [Roll Forward]
Net proved developed reserves		416	416	416	392		387		341
Net Proved Undeveloped Reserves (MMBOE) [Rollforward]
Net proved undeveloped reserves		413	413	413	421		353		273
Natural Gas (Bcf)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period | Bcf	[2]		5,360		5,370		4,687
Revisions of previous estimates | Bcf	[2]		783		(492)		(134)
Purchases in place | Bcf	[2]		23		26		72
Extensions, discoveries and other additions | Bcf	[2]		2,674		1,132		1,273
Sales in place | Bcf	[2]		(52)		(157)		(15)
Production | Bcf	[2]		(566)		(519)		(513)
Net proved reserves - end of period | Bcf	[2]				5,360		5,370
Proved Developed Reserves (MMBoe) [Roll Forward]
Net proved developed reserves | Bcf		3,874	3,874	3,874	2,789		3,194		2,964
Net Proved Undeveloped Reserves (MMBOE) [Rollforward]
Net proved undeveloped reserves | Bcf		4,348	4,348	4,348	2,571		2,176		1,723
Oil Equivalents (MMBoe)
Proved Developed Reserves (MMBoe) [Roll Forward]
Net proved reserves - beginning of period | MMBoe	[1]			3,220	3,329		2,928
Revisions of previous estimates | MMBoe	[1]			(114)	(367)		(60)
Purchases in place | MMBoe	[1]			9	10		17
Extensions, discoveries and other additions | MMBoe	[1]			952	564		750
Sales in place | MMBoe	[1]			(11)	(31)		(5)
Production | MMBoe	[1]			(309)	(285)		(301)
Net proved reserves - end of period | MMBoe	[1]				3,220		3,329
Net Proved Undeveloped Reserves (MMBOE) [Rollforward]
Net proved undeveloped reserve (MMBOE) | MMBoe		1,799	1,799	1,799	1,571		1,608		1,380
United States
Proved Developed Reserves (MMBoe) [Roll Forward]
Net proved developed reserves (MMBOE) | MMBoe		1,926	1,926	1,926	1,614		1,684		1,503
United States | Crude Oil (MMBbl)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	1,513			1,694		1,532
Revisions of previous estimates	[1]	(116)			(225)		(43)
Purchases in place	[1]	2			2		3
Extensions, discoveries and other additions	[1]	311			194		370
Sales in place	[1]	(2)			(3)		(1)
Production	[1]	(162)			(149)		(167)
Net proved reserves - end of period	[1]	1,546			1,513		1,694
Proved Developed Reserves (MMBoe) [Roll Forward]
Net proved developed reserves		886	886	886	792		801		713
Net Proved Undeveloped Reserves (MMBOE) [Rollforward]
Net proved undeveloped reserves		660	660	660	721		893		819
United States | Natural Gas Liquids (MMBbl)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	813			740		614
Revisions of previous estimates	[1]	(128)			(60)		5
Purchases in place	[1]	3			4		2
Extensions, discoveries and other additions	[1]	194			180		168
Sales in place	[1]	0			(1)		(1)
Production	[1]	(53)			(50)		(48)
Net proved reserves - end of period	[1]	829			813		740
Proved Developed Reserves (MMBoe) [Roll Forward]
Net proved developed reserves		416	416	416	392		387		341
Net Proved Undeveloped Reserves (MMBOE) [Rollforward]
Net proved undeveloped reserves		413	413	413	421		353		273
United States | Natural Gas (Bcf)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period | Bcf	[2]		5,043		5,035		4,391
Revisions of previous estimates | Bcf	[2]		754		(498)		(184)
Purchases in place | Bcf	[2]		23		26		72
Extensions, discoveries and other additions | Bcf	[2]		2,574		1,078		1,176
Sales in place | Bcf	[2]		(4)		(157)		(15)
Production | Bcf	[2]		(483)		(441)		(405)
Net proved reserves - end of period | Bcf	[2]		7,907		5,043		5,035
Proved Developed Reserves (MMBoe) [Roll Forward]
Net proved developed reserves | Bcf		3,743	3,743	3,743	2,586		2,974		2,699
Net Proved Undeveloped Reserves (MMBOE) [Rollforward]
Net proved undeveloped reserves | Bcf		4,164	4,164	4,164	2,457		2,061		1,692
United States | Oil Equivalents (MMBoe)
Proved Developed Reserves (MMBoe) [Roll Forward]
Net proved reserves - beginning of period | MMBoe	[1]			3,166	3,273		2,878
Revisions of previous estimates | MMBoe	[1]			(118)	(368)		(68)
Purchases in place | MMBoe	[1]			9	10		17
Extensions, discoveries and other additions | MMBoe	[1]			934	554		734
Sales in place | MMBoe	[1]			(3)	(31)		(5)
Production | MMBoe	[1]			(295)	(272)		(283)
Net proved reserves - end of period | MMBoe	[1]			3,693	3,166		3,273
Net Proved Undeveloped Reserves (MMBOE) [Rollforward]
Net proved undeveloped reserve (MMBOE) | MMBoe		1,767	1,767	1,767	1,552		1,589		1,375
Trinidad
Proved Developed Reserves (MMBoe) [Roll Forward]
Net proved developed reserves (MMBOE) | MMBoe		22	22	22	30		30		38
Trinidad | Crude Oil (MMBbl)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	1			0		0
Revisions of previous estimates	[1]	0			0		0
Purchases in place	[1]	0			0		0
Extensions, discoveries and other additions	[1]	1			1		0
Sales in place	[1]	0			0		0
Production	[1]	0			0		0
Net proved reserves - end of period	[1]	2			1		0
Proved Developed Reserves (MMBoe) [Roll Forward]
Net proved developed reserves		0	0	0	1		0		0
Net Proved Undeveloped Reserves (MMBOE) [Rollforward]
Net proved undeveloped reserves		2	2	2	0		0		0
Trinidad | Natural Gas Liquids (MMBbl)
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 (MMBoe) [Roll Forward]
Net proved developed reserves		0	0	0	0		0		0
Net Proved Undeveloped Reserves (MMBOE) [Rollforward]
Net proved undeveloped reserves		0	0	0	0		0		0
Trinidad | Natural Gas (Bcf)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period | Bcf	[2]		269		276		237
Revisions of previous estimates | Bcf	[2]		26		5		47
Purchases in place | Bcf	[2]		0		0		0
Extensions, discoveries and other additions | Bcf	[2]		100		54		87
Sales in place | Bcf	[2]		0		0		0
Production | Bcf	[2]		(80)		(66)		(95)
Net proved reserves - end of period | Bcf	[2]		315		269		276
Proved Developed Reserves (MMBoe) [Roll Forward]
Net proved developed reserves | Bcf		131	131	131	171		178		224
Net Proved Undeveloped Reserves (MMBOE) [Rollforward]
Net proved undeveloped reserves | Bcf		184	184	184	98		98		13
Trinidad | Oil Equivalents (MMBoe)
Proved Developed Reserves (MMBoe) [Roll Forward]
Net proved reserves - beginning of period | MMBoe	[1]			46	46		40
Revisions of previous estimates | MMBoe	[1]			4	1		8
Purchases in place | MMBoe	[1]			0	0		0
Extensions, discoveries and other additions | MMBoe	[1]			18	10		14
Sales in place | MMBoe	[1]			0	0		0
Production | MMBoe	[1]			(14)	(11)		(16)
Net proved reserves - end of period | MMBoe	[1]			54	46		46
Net Proved Undeveloped Reserves (MMBOE) [Rollforward]
Net proved undeveloped reserve (MMBOE) | MMBoe		32	32	32	16		16		2
Other International
Proved Developed Reserves (MMBoe) [Roll Forward]
Net proved developed reserves (MMBOE) | MMBoe	[3]	0	0	0	5		7		7
Other International | Crude Oil (MMBbl)
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 (MMBoe) [Roll Forward]
Net proved developed reserves	[3]	0	0	0	0		0		0
Net Proved Undeveloped Reserves (MMBOE) [Rollforward]
Net proved undeveloped reserves	[3]	0	0	0	0		0		0
Other International | Natural Gas Liquids (MMBbl)
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 (MMBoe) [Roll Forward]
Net proved developed reserves	[3]	0	0	0	0		0		0
Net Proved Undeveloped Reserves (MMBOE) [Rollforward]
Net proved undeveloped reserves	[3]	0	0	0	0		0		0
Other International | Natural Gas (Bcf)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period | Bcf	[2],[3]		48		59		59
Revisions of previous estimates | Bcf	[2],[3]		3		1		3
Purchases in place | Bcf	[2],[3]		0		0		0
Extensions, discoveries and other additions | Bcf	[2],[3]		0		0		10
Sales in place | Bcf	[2],[3]		(48)		0		0
Production | Bcf	[2],[3]		(3)		(12)		(13)
Net proved reserves - end of period | Bcf	[2],[3]		0		48		59
Proved Developed Reserves (MMBoe) [Roll Forward]
Net proved developed reserves | Bcf	[3]	0	0	0	32		42		41
Net Proved Undeveloped Reserves (MMBOE) [Rollforward]
Net proved undeveloped reserves | Bcf	[3]	0	0	0	16		17		18
Other International | Oil Equivalents (MMBoe)
Proved Developed Reserves (MMBoe) [Roll Forward]
Net proved reserves - beginning of period | MMBoe	[1],[3]			8	10		10
Revisions of previous estimates | MMBoe	[1],[3]			0	0		0
Purchases in place | MMBoe	[1],[3]			0	0		0
Extensions, discoveries and other additions | MMBoe	[1],[3]			0	0		2
Sales in place | MMBoe	[1],[3]			(8)	0		0
Production | MMBoe	[1],[3]			0	(2)		(2)
Net proved reserves - end of period | MMBoe	[1],[3]			0	8		10
Net Proved Undeveloped Reserves (MMBOE) [Rollforward]
Net proved undeveloped reserve (MMBOE) | MMBoe	[3]	0	0	0	3		3		3
[1]	Million barrels or million barrels of oil equivalent, as applicable; oil equivalents include crude oil and condensate, NGLs and natural gas. Oil equivalents are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas.
[2]	Billion cubic feet.
[3]	Other International includes EOG's China and Canada operations. The China operations were sold in the second quarter of 2021.

Oil and Gas Exploration and P_4

Oil and Gas Exploration and Production Industries Disclosures, Costs Incurred (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021		Dec. 31, 2020		Dec. 31, 2019
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Unproved		$ 215	[1]	$ 265	[2]	$ 276	[3]
Acquisition Costs of Properties - Proved		100	[4]	135	[5]	380	[6]
Subtotal		315		400		656
Exploration Costs		354		296		273
Development Costs		3,300	[7]	3,022	[8]	5,699	[9]
Total		3,969		3,718		6,628
Non-Cash Unproved Leasehold Acquisition Costs Related to Property Exchanges		45		197		98
Non-Cash Proved Property Acquisition Costs Related to Property Exchanges		5		15		52
United States
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Unproved		207	[1]	265	[2]	276	[3]
Acquisition Costs of Properties - Proved		100	[4]	97	[5]	380	[6]
Subtotal		307		362		656
Exploration Costs		296		203		214
Development Costs		3,206	[7]	2,998	[8]	5,662	[9]
Total		3,809		3,563		6,532
Asset Retirement Costs Included In Development		86		97		181
Trinidad
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Unproved		0	[1]	0	[2]	0	[3]
Acquisition Costs of Properties - Proved		0	[4]	0	[5]	0	[6]
Subtotal		0		0		0
Exploration Costs		7		81		47
Development Costs		77	[7]	4	[8]	25	[9]
Total		84		85		72
Asset Retirement Costs Included In Development		24				1
Other International
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Unproved	[10]	8	[1]	0	[2]	0	[3]
Acquisition Costs of Properties - Proved	[10]	0	[4]	38	[5]	0	[6]
Subtotal	[10]	8		38		0
Exploration Costs	[10]	51		12		12
Development Costs	[10]	17	[7]	20	[8]	12	[9]
Total	[10]	76		70		24
Asset Retirement Costs Included In Development		$ 17		$ 20		$ 4
[1]	Includes non-cash unproved leasehold acquisition costs of $45 million related to property exchanges.
[2]	Includes non-cash unproved leasehold acquisition costs of $197 million related to property exchanges.
[3]	Includes non-cash unproved leasehold acquisition costs of $98 million related to property exchanges.
[4]	Includes non-cash proved property acquisition costs of $5 million related to property exchanges.
[5]	Includes non-cash proved property acquisition costs of $15 million related to property exchanges.
[6]	Includes non-cash proved property acquisition costs of $52 million related to property exchanges.
[7]	Includes Asset Retirement Costs of $86 million, $24 million and $17 million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment.
[8]	Includes Asset Retirement Costs of $97 million and $20 million for the United States and Other International, respectively. Excludes other property, plant and equipment.
[9]	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.
[10]	Other International primarily consists of EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. EOG began exploration programs in Australia in the third quarter of 2021 and in Oman in the third quarter of 2020. The decision was reached in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman.

Oil and Gas Exploration and P_5

Oil and Gas Exploration and Production Industries Disclosures, Results Of Operations (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021		Dec. 31, 2020		Dec. 31, 2019
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]	$ 15,381		$ 7,291		$ 11,582
Other	[1]	108		60		134
Total	[1]	15,489		7,351		11,716
Exploration Costs	[1]	154		146		140
Dry Hole Costs	[1]	71		13		28
Transportation Costs	[1]	863		735		758
Gathering and Processing Costs		559	[1]	459	[1]	479
Production Costs	[1]	2,155		1,517		2,134
Impairments	[1]	376		2,100		518
Depreciation, Depletion and Amortization	[1]	3,504		3,268		3,658
Income (Loss) Before Income Taxes	[1]	7,807		(887)		4,001
Income Tax Provision (Benefit)	[1]	1,762		(193)		942
Results of Operations	[1]	6,045		(694)		3,059
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]	15,062		7,056		11,251
Other	[1]	108		60		134
Total	[1]	15,170		7,116		11,385
Exploration Costs	[1]	137		136		130
Dry Hole Costs	[1]	29		13		11
Transportation Costs	[1]	863		734		753
Gathering and Processing Costs		559	[1]	459	[1]	479
Production Costs	[1]	2,108		1,480		2,063
Impairments	[1]	312		2,018		511
Depreciation, Depletion and Amortization	[1]	3,411		3,192		3,561
Income (Loss) Before Income Taxes	[1]	7,751		(916)		3,877
Income Tax Provision (Benefit)	[1]	1,690		(220)		884
Results of Operations	[1]	6,061		(696)		2,993
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]	301		180		270
Other	[1]	0		0		0
Total	[1]	301		180		270
Exploration Costs	[1]	5		2		4
Dry Hole Costs	[1]	0		0		13
Transportation Costs	[1]	0		1		4
Gathering and Processing Costs		0	[1]	0	[1]	0
Production Costs	[1]	39		27		31
Impairments	[1]	3		1		6
Depreciation, Depletion and Amortization	[1]	87		60		79
Income (Loss) Before Income Taxes	[1]	167		89		133
Income Tax Provision (Benefit)	[1]	73		24		55
Results of Operations	[1]	94		65		78
Other International
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	[1],[2]	18		55		61
Other	[1],[2]	0		0		0
Total	[1],[2]	18		55		61
Exploration Costs	[1],[2]	12		8		6
Dry Hole Costs	[1],[2]	42		0		4
Transportation Costs	[1],[2]	0		0		1
Gathering and Processing Costs		0	[1],[2]	0	[1],[2]	0
Production Costs	[1],[2]	8		10		40
Impairments	[1],[2]	61		81		1
Depreciation, Depletion and Amortization	[1],[2]	6		16		18
Income (Loss) Before Income Taxes	[1],[2]	(111)		(60)		(9)
Income Tax Provision (Benefit)	[1],[2]	(1)		3		3
Results of Operations	[1],[2]	$ (110)		$ (63)		$ (12)
[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, 2021.
[2]	Other International primarily consists of EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. EOG began exploration programs in Australia in the third quarter of 2021 and in Oman in the third quarter of 2020. The decision was reached in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman.

Oil and Gas Exploration and P_6

Oil and Gas Exploration and Production Industries Disclosures, Average Sales Price (Details) - $ / bbl		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent		3.67	3.72	4.54
United States
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent		3.71	3.75	4.59
Trinidad
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent		2.32	2.33	1.85
Other International
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent	[1]	16.13	6.78	18.26
[1]	Other International primarily consists of EOG's China and Canada operations. The China operations were sold in the second quarter of 2021.

Oil and Gas Exploration and P_7

Oil and Gas Exploration and Production Industries Disclosures, Discounted Future Net Cash Flows (Details) $ in Millions		12 Months Ended
		Dec. 31, 2021USD ($)		Dec. 31, 2020USD ($)		Dec. 31, 2019USD ($)
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows		$ 167,451	[1]	$ 74,909	[2]	$ 121,478
Future production costs		(45,163)		(34,826)		(42,641)
Future development costs		(14,265)		(15,404)		(20,586)
Future income taxes		(22,915)		(4,442)		(11,566)
Future net cash flows		85,108		20,237		46,685
Discount to present value at 10% annual rate		(38,922)		(8,547)		(21,164)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves		$ 46,186		$ 11,690		$ 25,521
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		$ 11,690		$ 25,521		$ 32,426
Sales and transfers of oil and gas produced, net of production costs		(11,809)		(4,579)		(8,210)
Net changes in prices and production costs		37,220		(18,446)		(10,880)
Extensions, discoveries, additions and improved recovery, net of related costs		12,225		1,501		5,709
Development costs incurred		1,635		1,675		3,033
Revisions of estimated development cost		2,640		4,138		(739)
Revisions of previous quantity estimates		(1,716)		(3,297)		(696)
Accretion of discount		1,372		3,104		3,950
Net change in income taxes		(9,870)		3,488		1,549
Purchases of reserves in place		151		49		99
Sales of reserves in place		(170)		(156)		(51)
Changes in timing and other		2,818		(1,308)		(669)
Balance at End of Period		46,186		11,690		25,521
United States
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows		166,316	[1]	73,727	[2]	120,360
Future production costs		(44,905)		(34,619)		(42,387)
Future development costs		(13,885)		(15,159)		(20,356)
Future income taxes		(22,831)		(4,337)		(11,460)
Future net cash flows		84,695		19,612		46,157
Discount to present value at 10% annual rate		(38,834)		(8,410)		(21,043)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves		45,861		11,202		25,114
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		11,202		25,114		32,033
Sales and transfers of oil and gas produced, net of production costs		(11,532)		(4,382)		(7,955)
Net changes in prices and production costs		37,088		(18,625)		(10,974)
Extensions, discoveries, additions and improved recovery, net of related costs		12,154		1,437		5,608
Development costs incurred		1,619		1,675		3,004
Revisions of estimated development cost		2,773		4,149		(599)
Revisions of previous quantity estimates		(1,789)		(3,307)		(813)
Accretion of discount		1,313		3,055		3,892
Net change in income taxes		(9,914)		3,497		1,454
Purchases of reserves in place		151		49		99
Sales of reserves in place		(19)		(156)		(51)
Changes in timing and other		2,815		(1,304)		(584)
Balance at End of Period		$ 45,861		$ 11,202		$ 25,114
United States | Crude Oil
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows		67.79		37.19		57.51
United States | Natural Gas Liquids (MMBbl)
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows		30.28		12.47		16.91
United States | Natural Gas
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows		4.61		1.45		2.07
Trinidad
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows		$ 1,135	[1]	$ 901	[2]	$ 813
Future production costs		(258)		(153)		(166)
Future development costs		(380)		(227)		(212)
Future income taxes		(84)		(81)		(74)
Future net cash flows		413		440		361
Discount to present value at 10% annual rate		(88)		(101)		(86)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves		325		339		275
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		339		275		266
Sales and transfers of oil and gas produced, net of production costs		(261)		(152)		(235)
Net changes in prices and production costs		133		132		66
Extensions, discoveries, additions and improved recovery, net of related costs		71		64		85
Development costs incurred		16		0		23
Revisions of estimated development cost		(133)		(11)		(129)
Revisions of previous quantity estimates		73		12		116
Accretion of discount		42		34		43
Net change in income taxes		27		(12)		94
Purchases of reserves in place		0		0		0
Sales of reserves in place		0		0		0
Changes in timing and other		18		(3)		(54)
Balance at End of Period		$ 325		$ 339		$ 275
Trinidad | Crude Oil
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows		58.32		26.75		46.77
Trinidad | Natural Gas
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows		3.28		3.28		2.90
Other International (1)
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	[3]	$ 0	[1]	$ 281	[2]	$ 305
Future production costs	[3]	0		(54)		(88)
Future development costs	[3]	0		(18)		(18)
Future income taxes	[3]	0		(24)		(32)
Future net cash flows	[3]	0		185		167
Discount to present value at 10% annual rate	[3]	0		(36)		(35)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	[3]	0		149		132
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	[3]	149		132		127
Sales and transfers of oil and gas produced, net of production costs	[3]	(16)		(45)		(20)
Net changes in prices and production costs	[3]	(1)		47		28
Extensions, discoveries, additions and improved recovery, net of related costs	[3]	0		0		16
Development costs incurred	[3]	0		0		6
Revisions of estimated development cost	[3]	0		0		(11)
Revisions of previous quantity estimates	[3]	0		(2)		1
Accretion of discount	[3]	17		15		15
Net change in income taxes	[3]	17		3		1
Purchases of reserves in place	[3]	0		0		0
Sales of reserves in place	[3]	(151)		0		0
Changes in timing and other	[3]	(15)		(1)		(31)
Balance at End of Period	[3]	$ 0		$ 149		$ 132
Other International (1) | Crude Oil
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows				41.87		57.22
Other International (1) | Natural Gas
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows				5.65		5.01
[1]	Estimated crude oil prices used to calculate 2020 future cash inflows for the United States, Trinidad and Other International were $37.19, $26.75, and $41.87, respectively. Estimated NGL price used to calculate 2020 future cash inflows for the United States was $12.47. Estimated natural gas prices used to calculate 2020 future cash inflows for the United States, Trinidad and Other International were $1.45, $3.28, and $5.65, respectively.
[2]	Estimated crude oil prices used to calculate 2019 future cash inflows for the United States, Trinidad and Other International were $57.51, $46.77 and $57.22, respectively. Estimated NGL price used to calculate 2019 future cash inflows for the United States was $16.91. Estimated natural gas prices used to calculate 2019 future cash inflows for the United States, Trinidad and Other International were $2.07, $2.90 and $5.01, respectively.
[3]	Other International includes EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. (2) Estimated crude oil prices used to calculate 2021 future cash inflows for the United States and Trinidad were $67.79 and $58.32, respectively. Estimated NGL price used to calculate 2021 future cash inflows for the United States was $30.28. Estimated natural gas prices used to calculate 2021 future cash inflows for the United States and Trinidad were $4.61 and $3.28, respectively.