EOG Resources (EOG) 10-K 27 Feb 20 2019 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Feb. 13, 2020	Jun. 30, 2019
Cover page.
Document Type	10-K
Entity Registrant Name	EOG RESOURCES, INC.
Document Annual Report	true
Document Transition Report	false
Entity Central Index Key	0000821189
Entity File Number	1-9743
Current Fiscal Year End Date	--12-31
Document Period End Date	Dec. 31, 2019
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2019
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	47-0684736
Entity Address, Address Line One	1111 Bagby
Entity Address, Address Line Two	Sky Lobby 2
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	713
Local Phone Number	651-7000
Title of 12(b) Security	Common Stock, par value $0.01 per share
Trading Symbol	EOG
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Amendment Flag	false
Entity Public Float			$ 54,011
Entity Common Stock, Shares Outstanding		582,054,451
Documents Incorporated by Reference	Documents incorporated by reference. Portions of the Definitive Proxy Statement for the registrant's 2020 Annual Meeting of Stockholders, to be filed within 120 days after December 31, 2019 , are incorporated by reference into Part III of this report.

Consolidated Statements of Inco

Consolidated Statements of Income and Comprehensive Income - USD ($) shares in Thousands, $ in Thousands		12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Operating Revenues and Other
Total		$ 17,379,973		$ 17,275,399		$ 11,208,320
Operating Expenses
Lease and Well		1,366,993		1,282,678		1,044,847
Transportation Costs	[1]	758,300		746,876		740,352
Gathering and Processing Costs		479,102	[1],[2]	436,973	[1],[2]	148,775
Exploration Costs		139,881		148,999		145,342
Dry Hole Costs	[1]	28,001		5,405		4,609
Impairments		517,896		347,021		479,240
Marketing Costs		5,351,524		5,203,243		3,330,237
Depreciation, Depletion and Amortization		3,749,704		3,435,408		3,409,387
General and Administrative		489,397		426,969		434,467
Taxes Other Than Income		800,164		772,481		544,662
Total		13,680,962		12,806,053		10,281,918
Operating Income		3,699,011		4,469,346		926,402
Other Income, Net		31,385		16,704		9,152
Income Before Interest Expense and Income Taxes		3,730,396		4,486,050		935,554
Interest Expense
Incurred		223,421		269,549		301,801
Capitalized		(38,292)		(24,497)		(27,429)
Net Interest Expense		185,129		245,052		274,372
Income Before Income Taxes		3,545,267		4,240,998		661,182
Income Tax Provision (Benefit)		810,357		821,958		(1,921,397)
Net Income		$ 2,734,910		$ 3,419,040		$ 2,582,579
Net Income (Loss) Per Share
Basic		$ 4.73		$ 5.93		$ 4.49
Diluted		$ 4.71		$ 5.89		$ 4.46
Average Number of Common Shares [Abstract]
Basic (in shares)		577,670		576,578		574,620
Diluted (in shares)		580,777		580,441		578,693
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments		$ (2,883)		$ 16,816		$ 2,799
Other, Net of Tax		(678)		1,123		(3,086)
Other Comprehensive Income (Loss)		(3,561)		17,939		(287)
Comprehensive Income		2,731,349		3,436,979		2,582,292
Crude Oil and Condensate
Operating Revenues and Other
Revenues		9,612,532		9,517,440		6,256,396
Natural Gas Liquids
Operating Revenues and Other
Revenues		784,818		1,127,510		729,561
Natural Gas
Operating Revenues and Other
Revenues		1,184,095		1,301,537		921,934
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts
Operating Revenues and Other
Revenues		180,275		(165,640)		19,828
Gathering, Processing and Marketing
Operating Revenues and Other
Revenues		5,360,282		5,230,355		3,298,087
Gains (Losses) on Asset Dispositions, Net
Operating Revenues and Other
Revenues		123,613		174,562		(99,096)
Other, Net
Operating Revenues and Other
Revenues		$ 134,358		$ 89,635		$ 81,610
[1]	Excludes gains or losses on the mark-to-market of financial commodity derivative contracts, gains or losses on sales of reserves and related assets, interest charges and general corporate expenses for each of the three years in the period ended December 31, 2019 .
[2]	Effective January 1, 2018, EOG adopted the provisions of Accounting Standards Update (ASU) 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements within its United States segment as Gathering and Processing Costs instead of as a deduction to Natural Gas Revenues. There was no impact to operating income or net income resulting from changes to the presentation of natural gas processing fees (see Note 1 to Consolidated Financial Statements).

Consolidated Balance Sheets

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

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2019	Dec. 31, 2018
Common Stock
Common Stock, Par Value (in dollars per share)	$ 0.01	$ 0.01
Common Stock, Shares Authorized (in shares)	1,280,000,000	1,280,000,000
Common Stock, Shares Issued (in shares)	582,213,016	580,408,117
Treasury Stock
Common Stock Held in Treasury (in shares)	298,820	385,042

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Retained Earnings [Member]	Treasury Stock, Common [Member]
Balance at Dec. 31, 2016	$ 13,981,581	$ 205,770	$ 5,420,385	$ (19,010)	$ 8,398,118	$ (23,682)
Net Income	2,582,579	0	0	0	2,582,579	0
Common Stock Issued Under Stock Plans	7,089	7	7,082	0	0	0
Dividends, Common Stock	$ (387,164)	0	0	0	(387,164)	0
Common Stock Dividends Declared (in dollars per share)	$ 0.670
Other Comprehensive Income (Loss)	$ (287)	0	0	(287)	0	0
Change in Treasury Stock - Stock Compensation Plans, Net	(36,743)	0	(27,348)	0	0	(9,395)
Restricted Stock and Restricted Stock Units, Net	0	11	2,552	0	0	(2,563)
Stock-Based Compensation Expenses	133,849	0	133,849	0	0	0
Treasury Stock Issued as Compensation	2,369	0	27	0	0	2,342
Balance at Dec. 31, 2017	16,283,273	205,788	5,536,547	(19,297)	10,593,533	(33,298)
Net Income	3,419,040	0	0	0	3,419,040	0
Common Stock Issued Under Stock Plans	5,620	8	5,612	0	0	0
Dividends, Common Stock	$ (469,443)	0	0	0	(469,443)	0
Common Stock Dividends Declared (in dollars per share)	$ 0.810
Other Comprehensive Income (Loss)	$ 17,939	0	0	17,939	0	0
Change in Treasury Stock - Stock Compensation Plans, Net	(48,454)	0	(35,118)	0	0	(13,336)
Restricted Stock and Restricted Stock Units, Net	0	8	(3,891)	0	0	3,883
Stock-Based Compensation Expenses	155,337	0	155,337	0	0	0
Treasury Stock Issued as Compensation	876	0	307	0	0	569
Balance at Dec. 31, 2018	19,364,188	205,804	5,658,794	(1,358)	13,543,130	(42,182)
Net Income	2,734,910	0	0	0	2,734,910	0
Common Stock Issued Under Stock Plans	(8)	1	(9)	0	0	0
Dividends, Common Stock	$ 629,169	0	0	0	629,169	0
Common Stock Dividends Declared (in dollars per share)	$ 1.083
Other Comprehensive Income (Loss)	$ (3,561)	0	0	(3,561)	0	0
Change in Treasury Stock - Stock Compensation Plans, Net	(6,853)	0	(10,637)	0	0	3,784
Restricted Stock and Restricted Stock Units, Net	0	17	(4,566)	0	0	4,549
Stock-Based Compensation Expenses	174,738	0	174,738	0	0	0
Treasury Stock Issued as Compensation	6,471	0	(845)	0	0	7,316
Balance at Dec. 31, 2019	21,640,716	205,822	5,817,475	(4,652)	15,648,604	(26,533)
Cumulative Effect of Accounting Changes	$ 0	$ 0	$ 0	$ 267	$ (267)	$ 0

Consolidated Statements of St_2

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

Consolidated Statements of Cash

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

Summary of Significant Accounti

Summary of Significant Accounting Policies (Notes)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Principles of Consolidation. The consolidated financial statements of EOG Resources, Inc. (EOG) include the accounts of all domestic and foreign subsidiaries. Investments in unconsolidated affiliates, in which EOG is able to exercise significant influence, are accounted for using the equity method. All intercompany accounts and transactions have been eliminated. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Financial Instruments. EOG's financial instruments consist of cash and cash equivalents, commodity derivative contracts, accounts receivable, accounts payable and current and long-term debt. The carrying values of cash and cash equivalents, commodity derivative contracts, accounts receivable and accounts payable approximate fair value (see Notes 2 and 12). Cash and Cash Equivalents. EOG records as cash equivalents all highly liquid short-term investments with original maturities of three months or less. Oil and Gas Operations. EOG accounts for its crude oil and natural gas exploration and production activities under the successful efforts method of accounting. Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred. Oil and gas exploration costs, other than the costs of drilling exploratory wells, are expensed as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether EOG has discovered commercial quantities of proved reserves. If commercial quantities of proved reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether commercial quantities of proved reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made (see Note 16). Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account. Oil and gas properties are grouped in accordance with the provisions of the Extractive Industries - Oil and Gas Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC). The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. Amortization rates are updated quarterly to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions and/or property dispositions and 4) impairments. When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the asset. If the expected undiscounted future cash flows, based on EOG's estimate of (and assumptions regarding) future crude oil and natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach described in the Fair Value Measurement Topic of the ASC. In certain instances, EOG utilizes accepted offers from third-party purchasers as the basis for determining fair value. Inventories, consisting primarily of tubular goods, materials for completion operations and well equipment held for use in the exploration for, and development and production of, crude oil, natural gas liquids (NGLs) and natural gas reserves, are carried at the lower of cost and net realizable value with adjustments made, as appropriate, to recognize any reductions in value. Revenue Recognition. Effective January 1, 2018, EOG adopted the provisions of Accounting Standards Update (ASU) 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09). ASU 2014-09 and other related ASUs require entities to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. EOG elected to adopt ASU 2014-09 using the modified retrospective approach, which required EOG to recognize in retained earnings the cumulative effect at the date of adoption for all existing contracts with customers which were not substantially complete as of January 1, 2018. There was no impact to retained earnings upon adoption of ASU 2014-09. EOG presents disaggregated revenues by type of commodity within its Consolidated Statements of Income and Comprehensive Income and by geographic areas defined as operating segments. See Note 11. In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements within its United States segment as Gathering and Processing Costs, instead of as a deduction to Revenues within its Consolidated Statements of Income and Comprehensive Income. There was no impact to operating income, net income or cash flows resulting from changes to the presentation of natural gas processing fees. The impacts of the adoption of ASU 2014-09 for the year ended December 31, 2018, were as follows (in thousands): As Reported Amounts Without Adoption of ASU 2014-09 Effect of Change Operating Revenues and Other Crude Oil and Condensate $ 9,517,440 $ 9,517,440 $ — Natural Gas Liquids 1,127,510 1,121,237 6,273 Natural Gas 1,301,537 1,104,095 197,442 Gathering, Processing and Marketing 5,230,355 5,211,136 19,219 Total Operating Revenues and Other 17,275,399 17,052,465 222,934 Operating Expenses Gathering and Processing Costs 436,973 233,258 203,715 Marketing Costs 5,203,243 5,184,024 19,219 Total Operating Expenses 12,806,053 12,583,119 222,934 Operating Income 4,469,346 4,469,346 — Revenues are recognized for the sale of crude oil and condensate, NGLs and natural gas at the point control of the product is transferred to the customer, typically when production is delivered and title or risk of loss transfers to the customer. Arrangements for such sales are evidenced by signed contracts with prices typically based on stated market indices, with certain adjustments for product quality and geographic location. As EOG typically invoices customers shortly after performance obligations have been fulfilled, contract assets and contract liabilities are not recognized. The balances of accounts receivable from contracts with customers on January 1, 2019 and December 31, 2019, were $1,460 million and $1,619 million , respectively, and are included in Accounts Receivable, Net on the Consolidated Balance Sheets. Losses incurred on receivables from contracts with customers are infrequent and have been immaterial. Crude Oil and Condensate. EOG sells its crude oil and condensate production at the wellhead or further downstream at a contractually-specified delivery point. Revenue is recognized when control transfers to the customer based on contract terms which reflect prevailing market prices. Any costs incurred prior to the transfer of control, such as gathering and transportation, are recognized as Operating Expenses. Natural Gas Liquids. EOG delivers certain of its natural gas production to either EOG-owned processing facilities or third-party processing facilities, where extraction of NGLs occurs. For EOG-owned facilities, revenue is recognized after processing upon transfer of NGLs to a customer. For third-party facilities, extracted NGLs are sold to the owner of the processing facility at the tailgate, or EOG takes possession and sells the extracted NGLs at the tailgate or exercises its option to sell further downstream to various customers. Under typical arrangements for third-party facilities, revenue is recognized after processing upon the transfer of control of the NGLs, either at the tailgate of the processing plant or further downstream. EOG recognizes revenues based on contract terms which reflect prevailing market prices, with processing fees recognized as Gathering and Processing Costs. Natural Gas. EOG sells its natural gas production either at the wellhead or further downstream at a contractually-specified delivery point. In connection with the extraction of NGLs, EOG sells residue gas under separate agreements. Typically, EOG takes possession of the natural gas at the tailgate of the processing facility and sells it at the tailgate or further downstream. In each case, EOG recognizes revenues when control transfers to the customer, based on contract terms which reflect prevailing market prices. Gathering, Processing and Marketing. Gathering, processing and marketing revenues represent sales of third-party crude oil and condensate, NGLs and natural gas, as well as fees associated with gathering and processing third-party natural gas and revenues from sales of EOG-owned sand. EOG evaluates whether it is the principal or agent under these transactions. As control of the underlying commodity is transferred to EOG prior to the gathering, processing and marketing activities, EOG considers itself the principal of these arrangements. Accordingly, EOG recognizes these transactions on a gross basis. Purchases of third-party commodities are recorded as Marketing Costs, with sales of third-party commodities and fees received for gathering and processing recorded as Gathering, Processing and Marketing revenues. Other Property, Plant and Equipment . Other property, plant and equipment consists of gathering and processing assets, compressors, buildings and leasehold improvements, crude-by-rail assets, sand mine and sand processing assets, computer hardware and software, vehicles, and furniture and fixtures. Other property, plant and equipment is generally depreciated on a straight-line basis over the estimated useful lives of the property, plant and equipment, which range from 3 years to 45 years. Capitalized Interest Costs. Interest costs have been capitalized as a part of the historical cost of unproved oil and gas properties. The amount capitalized is an allocation of the interest cost incurred during the reporting period. Capitalized interest is computed only during the exploration and development phases and ceases once production begins. The interest rate used for capitalization purposes is based on the interest rates on EOG's outstanding borrowings. The capitalization of interest is excluded on significant acquisitions of unproved oil and gas properties financed through non-interest-bearing instruments, such as the issuance of shares of Common Stock, or through non-cash property exchanges. Accounting for Risk Management Activities. Derivative instruments are recorded on the balance sheet as either an asset or liability measured at fair value, and changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met. During the three-year period ended December 31, 2019, EOG elected not to designate any of its financial commodity derivative instruments as accounting hedges and, accordingly, changes in the fair value of these outstanding derivative instruments are recognized as gains or losses in the period of change. The gains or losses are recorded as Gains (Losses) on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income and Comprehensive Income. The related cash flow impact of settled contracts is reflected as cash flows from operating activities. EOG employs net presentation of derivative assets and liabilities for financial reporting purposes when such assets and liabilities are with the same counterparty and subject to a master netting arrangement. See Note 12. Income Taxes. Income taxes are accounted for using the asset and liability approach. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. EOG assesses the realizability of deferred tax assets and recognizes valuation allowances as appropriate. See Note 6. Foreign Currency Translation. The United States dollar is the functional currency for all of EOG's consolidated subsidiaries except for its Canadian subsidiaries, for which the functional currency is the Canadian dollar, and its United Kingdom subsidiary (which was sold in the fourth quarter of 2018), for which the functional currency was the British pound. For subsidiaries whose functional currency is deemed to be other than the United States dollar, asset and liability accounts are translated at year-end exchange rates and revenues and expenses are translated at average exchange rates prevailing during the year. Translation adjustments are included in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets. Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period. See Notes 4 and 17. Net Income Per Share. Basic net income per share is computed on the basis of the weighted-average number of common shares outstanding during the period. Diluted net income per share is computed based upon the weighted-average number of common shares outstanding during the period plus the assumed issuance of common shares for all potentially dilutive securities. See Note 9. Stock-Based Compensation . EOG measures the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. See Note 7. Leases. Effective January 1, 2019, EOG adopted the provisions of ASU 2016-02, "Leases (Topic 842)" (ASU 2016-02). ASU 2016-02 and other related ASUs require that lessees recognize a right-of-use (ROU) asset and related lease liability, representing the obligation to make lease payments for certain lease transactions, on the Consolidated Balance Sheets and disclose additional leasing information. EOG elected to adopt ASU 2016-02 and other related ASUs using the modified retrospective approach with a cumulative-effect adjustment to the opening balance of retained earnings as of the effective date. Financial results reported in periods prior to January 1, 2019, are unchanged. Additionally, EOG elected the package of practical expedients within ASU 2016-02 that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases, or (iii) initial direct costs for any existing leases, but did not elect the practical expedient of hindsight when determining the lease term of existing contracts at the effective date. EOG also elected the practical expedient under ASU 2018-01, "Leases (Topic 842) - Land Easement Practical Expedient for Transition to Topic 842," and did not evaluate existing or expired land easements not previously accounted for as leases prior to the January 1, 2019 effective date. There was no impact to retained earnings upon adoption of ASU 2016-02 and other related ASUs. In the ordinary course of business, EOG enters into contracts for drilling, fracturing, compression, real estate and other services which contain equipment and other assets and that meet the definition of a lease under ASU 2016-02. The lease term for these contracts, which includes any renewals at EOG's option that are reasonably certain to be exercised, ranges from one month to 30 years. ROU assets and related liabilities are recognized on the commencement date on the Consolidated Balance Sheets based on future lease payments, discounted based on the rate implicit in the contract, if readily determinable, or EOG's incremental borrowing rate commensurate with the lease term of the contract. EOG estimates its incremental borrowing rate based on the approximate rate required to borrow on a collateralized basis. Contracts with lease terms of less than 12 months are not recorded on the Consolidated Balance Sheets, but instead are disclosed as short-term lease cost. EOG has elected not to separate non-lease components from all leases, excluding those for fracturing services, real estate and salt water disposal, as lease payments under these contracts contain significant non-lease components, such as labor and operating costs. See Note 18. Recently Issued Accounting Standards. In December 2019, the FASB issued ASU 2019-12, "Income Taxes (Topic 740) ‑ Simplifying the Accounting for Income Taxes" (ASU 2019-12), which amends certain aspects of accounting for income taxes. ASU 2019-12 removes specific exceptions within existing U.S. GAAP related to the incremental approach for intraperiod tax allocation and to the general methodology for calculating income taxes in interim periods, among other changes. ASU 2019-12 also requires an entity to reflect the effect of an enacted change in tax laws or rates in the annual effective tax rate computation in the interim period that includes the enactment date, among other requirements. ASU 2019-12 is effective for interim and annual periods beginning after December 15, 2020, and early adoption is permitted. EOG is continuing to evaluate the provisions of ASU 2019-12 and has not determined the full impact on its consolidated financial statements and related disclosures. In June 2016, the FASB issued ASU 2016-13 "Measurement of Credit Losses on Financial Instruments" (ASU 2016-13). ASU 2016-13 changes the impairment model for financial assets and certain other instruments by requiring entities to adopt a forward-looking expected loss model that will result in earlier recognition of credit losses. ASU 2016-13 requires adoption through the use of a modified retrospective approach at the effective date by recognizing a cumulative-effect adjustment to the opening balance of retained earnings. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019, and early adoption is permitted. EOG has assessed its applicable financial assets, which are primarily its accounts receivable from hydrocarbon sales and joint interest billings to third-party companies, including state-owned entities in the oil and gas industry. Based on its assessment and various potential remedies ensuring collection, EOG does not expect the impact from forward-looking expected losses will be material. EOG will apply the provisions of ASU 2016-13 on the adoption date, January 1, 2020.

Long-Term Debt (Notes)

Long-Term Debt (Notes)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Long-Term Debt at December 31, 2019 and 2018 consisted of the following (in thousands): 2019 2018 5.625% Senior Notes due 2019 $ — $ 900,000 4.40% Senior Notes due 2020 500,000 500,000 2.45% Senior Notes due 2020 500,000 500,000 4.100% Senior Notes due 2021 750,000 750,000 2.625% Senior Notes due 2023 1,250,000 1,250,000 3.15% Senior Notes due 2025 500,000 500,000 4.15% Senior Notes due 2026 750,000 750,000 6.65% Senior Notes due 2028 140,000 140,000 3.90% Senior Notes due 2035 500,000 500,000 5.10% Senior Notes due 2036 250,000 250,000 Long-Term Debt 5,140,000 6,040,000 Finance Leases (see Note 18) 57,900 71,571 Less: Current Portion of Long-Term Debt 1,014,524 913,093 Unamortized Debt Discount 19,528 24,640 Debt Issuance Costs 2,929 3,669 Total Long-Term Debt $ 4,160,919 $ 5,170,169 At December 31, 2019, the aggregate annual maturities of long-term debt (excluding finance lease obligations) were $1 billion in 2020, $750 million in 2021, zero in 2022, $1.25 billion in 2023 and zero in 2024. On June 3, 2019, EOG repaid upon maturity the $900 million aggregate principal amount of its 5.625% Senior Notes due 2019. On October 1, 2018, EOG repaid upon maturity the $350 million aggregate principal amount of its 6.875% Senior Notes due 2018. At December 31, 2019 and 2018, EOG had no outstanding short-term borrowings under its commercial paper program and did not utilize any such borrowings during 2019. During 2018, EOG utilized commercial paper borrowings, bearing market interest rates, for various corporate financing purposes. The average borrowings outstanding under the commercial paper program were $8 million during the year ended December 31, 2018. The weighted average interest rate for commercial paper borrowings during the year ended December 31, 2018, was 1.97% . On June 27, 2019, EOG entered into a new $2.0 billion senior unsecured Revolving Credit Agreement (New Facility) with domestic and foreign lenders (Banks). The New Facility replaced EOG's $2.0 billion senior unsecured Revolving Credit Agreement, dated as of July 21, 2015, with domestic and foreign lenders (2015 Facility), which had a scheduled maturity date of July 21, 2020 and which was terminated by EOG (without penalty), effective as of June 27, 2019, in connection with the completion of the New Facility. The New Facility has a scheduled maturity date of June 27, 2024 , and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods subject to certain terms and conditions. The New Facility (i) commits the Banks to provide advances up to an aggregate principal amount of $2.0 billion at any one time outstanding, with an option for EOG to request increases in the aggregate commitments to an amount not to exceed $3.0 billion , subject to certain terms and conditions, and (ii) includes a swingline subfacility and a letter of credit subfacility. Advances under the New Facility will accrue interest based, at EOG’s option, on either the London InterBank Offered Rate plus an applicable margin (Eurodollar Rate) or the Base Rate (as defined in the New Facility) plus an applicable margin. The applicable margin used in connection with interest rates and fees will be based on EOG’s credit rating for its senior unsecured long-term debt at the applicable time. Consistent with the terms of the 2015 Facility, the New Facility contains representations, warranties, covenants and events of default that we believe are customary for investment grade, senior unsecured commercial bank credit agreements, including a financial covenant for the maintenance of a ratio of total debt-to-total capitalization (as such terms are defined in the New Facility) of no greater than 65% . At December 31, 2019, EOG was in compliance with this financial covenant. There were no borrowings or letters of credit outstanding under the 2015 Facility as of (i) December 31, 2018 or (ii) the June 27, 2019 effective date of the closing of the New Facility and termination of the 2015 Facility. Further, at December 31, 2019, there were no borrowings or letters of credit outstanding under the New Facility. The Eurodollar Rate and Base Rate (inclusive of the applicable margin), had there been any amounts borrowed under the New Facility at December 31, 2019, would have been 2.66% and 4.75% , respectively.

Stockholder's Equity (Notes)

Stockholder's Equity (Notes)	12 Months Ended
	Dec. 31, 2019
Stockholders' Equity Note [Abstract]
Stockholder's Equity	Stockholders' Equity Common Stock. In September 2001, EOG's Board of Directors (Board) authorized the purchase of an aggregate maximum of 10 million shares of Common Stock that superseded all previous authorizations. At December 31, 2019 , 6,386,200 shares remained available for purchase under this authorization. EOG last purchased shares of its Common Stock under this authorization in March 2003. In addition, shares of Common Stock are from time to time withheld by, or returned to, EOG in satisfaction of tax withholding obligations arising upon the exercise of employee stock options or stock-settled stock appreciation rights (SARs), the vesting of restricted stock, restricted stock unit, performance unit grants or in payment of the exercise price of employee stock options. Such shares withheld or returned do not count against the Board authorization discussed above. Shares purchased, withheld and returned are held in treasury for, among other purposes, fulfilling any obligations arising under EOG's stock-based compensation plans and any other approved transactions or activities for which such shares of Common Stock may be required. On February 27, 2020, the Board increased the quarterly cash dividend on the common stock from the previous $0.2875 per share to $0.375 per share, effective beginning with the dividend to be paid on April 30, 2020, to stockholders of record as of April 16, 2020. On May 2, 2019, the Board increased the quarterly cash dividend on the common stock from the previous $0.22 per share to $0.2875 per share, effective beginning with the dividend paid on July 31, 2019, to stockholders of record as of July 17, 2019. On August 2, 2018, the Board increased the quarterly cash dividend on the common stock by 19% from the previous $0.1850 per share to $0.22 per share, effective beginning with the dividend paid on October 31, 2018, to stockholders of record as of October 17, 2018. On February 27, 2018, EOG's Board increased the quarterly cash dividend on the common stock by 10% from the previous $0.1675 per share to $0.1850 per share, effective beginning with the dividend paid on April 30, 2018, to stockholders of record as of April 16, 2018. EOG declared and paid quarterly cash dividends of $0.1675 per share in 2017. On February 15, 2017, the Board approved an amendment to EOG's Restated Certificate of Incorporation to increase the number of EOG's authorized shares of common stock from 640 million to 1,280 million . EOG's stockholders approved the increase at the Annual Meeting of Stockholders on April 27, 2017, and the amendment was filed with the Delaware Secretary of State on April 28, 2017. The following summarizes Common Stock activity for each of the years ended December 31, 2017 , 2018 and 2019 (in thousands): Common Shares Issued Treasury Outstanding Balance at December 31, 2016 576,950 (250 ) 576,700 Common Stock Issued Under Stock-Based Compensation Plans 1,878 — 1,878 Treasury Stock Purchased (1) — (686 ) (686 ) Common Stock Issued Under Employee Stock Purchase Plan — 180 180 Treasury Stock Issued Under Stock-Based Compensation Plans — 405 405 Balance at December 31, 2017 578,828 (351 ) 578,477 Common Stock Issued Under Stock-Based Compensation Plans 1,580 — 1,580 Treasury Stock Purchased (1) — (539 ) (539 ) Common Stock Issued Under Employee Stock Purchase Plan — 180 180 Treasury Stock Issued Under Stock-Based Compensation Plans — 325 325 Balance at December 31, 2018 580,408 (385 ) 580,023 Common Stock Issued Under Stock-Based Compensation Plans 1,688 — 1,688 Treasury Stock Purchased (1) — (310 ) (310 ) Common Stock Issued Under Employee Stock Purchase Plan 117 106 223 Treasury Stock Issued Under Stock-Based Compensation Plans — 290 290 Balance at December 31, 2019 582,213 (299 ) 581,914 (1) Represents shares that were withheld by or returned to EOG (i) in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or SARs or the vesting of restricted stock, restricted stock unit, performance unit grants or (ii) in payment of the exercise price of employee stock options. Preferred Stock . EOG currently has one authorized series of preferred stock. As of December 31, 2019 , there were no shares of preferred stock outstanding.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income (Loss) Accumulated other comprehensive loss includes certain transactions that have generally been reported in the Consolidated Statements of Stockholders' Equity. The components of Accumulated Other Comprehensive Loss at December 31, 2019 and 2018 consisted of the following (in thousands): Foreign Currency Translation Adjustment Other Total December 31, 2017 $ (16,642 ) $ (2,655 ) $ (19,297 ) Other comprehensive income before reclassifications 2,451 1,131 3,582 Amounts reclassified out of other comprehensive income (loss) (1) 14,365 — 14,365 Tax effects — (8 ) (8 ) Other comprehensive income 16,816 1,123 17,939 December 31, 2018 174 (1,532 ) (1,358 ) Cumulative effect of accounting changes — 267 267 Other comprehensive loss before reclassifications (2,883 ) (533 ) (3,416 ) Tax effects — (145 ) (145 ) Other comprehensive loss (2,883 ) (678 ) (3,561 ) December 31, 2019 $ (2,709 ) $ (1,943 ) $ (4,652 ) (1) Reclassified to Net Income - Gains (Losses) on Asset Dispositions, Net. See Note 17. No significant amount was reclassified out of Accumulated Other Comprehensive Loss during the year ended December 31, 2019.

Other Income, Net (Notes)

Other Income, Net (Notes)	12 Months Ended
	Dec. 31, 2019
Other Income and Expenses [Abstract]
Other Income, Net	Other Income, Net Other income, net for 2019 included interest income ( $26 million ) and net foreign currency transaction gains ( $2 million ). Other income, net for 2018 included interest income ( $12 million ), a downward adjustment to deferred compensation expense ( $6 million ) and equity income from investments in ammonia plants in Trinidad ( $2 million ), partially offset by net foreign currency transaction losses ( $7 million ). Other income, net for 2017 included net foreign currency transaction gains ( $8 million ), interest income ( $8 million ) and equity income from investments in ammonia plants in Trinidad ( $3 million ), partially offset by an upward adjustment to deferred compensation expense ( $6 million

Employee Benefit Plans (Notes)

Employee Benefit Plans (Notes)	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Employee Benefit Plans	Employee Benefit Plans Stock-Based Compensation During 2019 , EOG maintained various stock-based compensation plans as discussed below. EOG recognizes compensation expense on grants of stock options, SARs, restricted stock and restricted stock units, performance units and grants made under the EOG Resources, Inc. Employee Stock Purchase Plan (ESPP). Stock-based compensation expense is calculated based upon the grant date estimated fair value of the awards, net of forfeitures, based upon EOG's historical employee turnover rate. Compensation expense is amortized over the shorter of the vesting period or the period from date of grant until the date the employee becomes eligible to retire without company approval. Stock-based compensation expense is included on the Consolidated Statements of Income and Comprehensive Income based upon the job functions of the employees receiving the grants. Compensation expense related to EOG's stock-based compensation plans for the years ended December 31, 2019 , 2018 and 2017 was as follows (in millions): 2019 2018 2017 Lease and Well $ 56 $ 51 $ 41 Gathering and Processing Costs 1 1 1 Exploration Costs 26 25 23 General and Administrative 92 78 69 Total $ 175 $ 155 $ 134 The Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (2008 Plan) provides for grants of stock options, SARs, restricted stock and restricted stock units, performance units, and other stock-based awards. The vesting schedules for grants of stock options, SARs, restricted stock and restricted stock units, and performance units are as follows: Grant Type Vesting Schedule Stock Options/SARs Vesting in increments of 33%, 33% and 34% on each of the first three anniversaries, respectively, of the date of grant Restricted Stock/Restricted Stock Units "Cliff" vesting three years from the date of grant Performance Units "Cliff" vesting approximately 41 months from the date of grant - specifically, on the February 28 th immediately following the Compensation Committee's certifications contemplated by the form of award agreement governing such grant of performance units At December 31, 2019 , approximately 6.8 million common shares remained available for grant under the 2008 Plan. EOG's policy is to issue shares related to the 2008 Plan from previously authorized unissued shares or treasury shares to the extent treasury shares are available. During 2019 , 2018 and 2017 , EOG issued shares in connection with stock option/SAR exercises, restricted stock and performance unit grants, restricted stock unit and performance unit releases and ESPP purchases. Net tax deficiencies and excess tax benefits recognized within the income tax provision were $(1) million , $20 million and $32 million for the twelve months ended December 31, 2019 , 2018 and 2017 , respectively. Stock Options and Stock-Settled Stock Appreciation Rights and Employee Stock Purchase Plan. Participants in EOG's stock-based compensation plans (including the 2008 Plan) have been or may be granted options to purchase shares of Common Stock. In addition, participants in EOG's stock plans (including the 2008 Plan) have been or may be granted SARs, representing the right to receive shares of Common Stock based on the appreciation in the stock price from the date of grant on the number of SARs granted. Stock options and SARs are granted at a price not less than the market price of the Common Stock on the date of grant. Terms for stock options and SARs granted have generally not exceeded a maximum term of seven years . EOG's ESPP allows eligible employees to semi-annually purchase, through payroll deductions, shares of Common Stock at 85 percent of the fair market value at specified dates. Contributions to the ESPP are limited to 10 percent of the employee's pay (subject to certain ESPP limits) during each of the two six-month offering periods each year. The fair value of stock option grants and SAR grants is estimated using the Hull-White II binomial option pricing model. The fair value of ESPP grants is estimated using the Black-Scholes-Merton model. Stock-based compensation expense related to stock option, SAR and ESPP grants totaled $63 million , $60 million and $56 million for the years ended December 31, 2019 , 2018 and 2017 , respectively. Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants for the years ended December 31, 2019 , 2018 and 2017 were as follows: Stock Options/SARs ESPP 2019 2018 2017 2019 2018 2017 Weighted Average Fair Value of Grants $ 19.49 $ 33.46 $ 23.95 $ 22.83 $ 25.75 $ 22.20 Expected Volatility 32.02 % 28.23 % 28.28 % 34.78 % 24.59 % 27.12 % Risk-Free Interest Rate 1.69 % 2.68 % 1.52 % 2.27 % 1.89 % 0.88 % Dividend Yield 1.39 % 0.72 % 0.75 % 1.04 % 0.64 % 0.71 % Expected Life 5.1 years 5.0 years 5.1 years 0.5 years 0.5 years 0.5 years Expected volatility is based on an equal weighting of historical volatility and implied volatility from traded options in EOG's Common Stock. The risk-free interest rate is based upon United States Treasury yields in effect at the time of grant. The expected life is based upon historical experience and contractual terms of stock option, SAR and ESPP grants. The following table sets forth the stock option and SAR transactions for the years ended December 31, 2019 , 2018 and 2017 (stock options and SARs in thousands): 2019 2018 2017 Number Weighted Average Grant Price Number Weighted Average Grant Price Number Weighted Average Grant Price Outstanding at January 1 8,310 $ 96.90 9,103 $ 83.89 9,850 $ 75.53 Granted 1,965 75.39 1,906 126.49 2,274 96.27 Exercised (1) (606 ) 61.43 (2,493 ) 72.21 (2,574 ) 61.12 Forfeited (274 ) 102.57 (206 ) 94.43 (447 ) 93.84 Outstanding at December 31 9,395 94.53 8,310 96.90 9,103 83.89 Stock Options/SARs Exercisable at December 31 5,275 94.21 3,969 85.82 4,510 75.76 (1) The total intrinsic value of stock options/SARs exercised during the years 2019 , 2018 and 2017 was $14 million , $118 million and $95 million , respectively. The intrinsic value is based upon the difference between the market price of the Common Stock on the date of exercise and the grant price of the stock options/SARs. At December 31, 2019 , there were 9.1 million stock options/SARs vested or expected to vest with a weighted average grant price of $94.52 per share, an intrinsic value of $29.1 million and a weighted average remaining contractual life of 4.2 years . The following table summarizes certain information for the stock options and SARs outstanding and exercisable at December 31, 2019 (stock options and SARs in thousands): Stock Options/SARs Outstanding Stock Options/SARs Exercisable Range of Grant Prices Stock Weighted Average Remaining Life (Years) Weighted Average Grant Price Aggregate Intrinsic Value (1) Stock Weighted Average Remaining Life (Years) Weighted Average Grant Price Aggregate Intrinsic Value (1) $ 59.00 to $ 74.99 979 3 $ 69.43 953 3 $ 69.37 75.00 to 75.99 1,894 7 75.09 8 1 75.09 76.00 to 95.99 1,979 3 91.35 1,607 2 90.67 96.00 to 96.99 1,871 4 96.29 1,234 4 96.29 97.00 to 125.99 923 2 102.72 862 2 102.20 126.00 to 129.99 1,749 6 127.01 611 5 127.01 9,395 4 94.53 $ 30,534 5,275 3 94.21 $ 13,839 (1) Based upon the difference between the closing market price of the Common Stock on the last trading day of the year and the grant price of in-the-money stock options and SARs. At December 31, 2019 , unrecognized compensation expense related to non-vested stock option and SAR grants totaled $86 million . This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.0 years . At the 2018 Annual Meeting of Stockholders, EOG stockholders approved an amendment and restatement of the ESPP to (among other changes) increase the number of shares available for grant. At December 31, 2019 , approximately 2.3 million shares of Common Stock remained available for grant under the ESPP. The following table summarizes ESPP activity for the years ended December 31, 2019 , 2018 and 2017 (in thousands, except number of participants): 2019 2018 2017 Approximate Number of Participants 1,998 1,934 1,870 Shares Purchased 224 180 180 Aggregate Purchase Price $ 16,533 $ 14,887 $ 13,997 Restricted Stock and Restricted Stock Units. Employees may be granted restricted (non-vested) stock and/or restricted stock units without cost to them. Upon vesting of restricted stock, shares of Common Stock are released to the employee. Upon vesting, restricted stock units are converted into shares of Common Stock and released to the employee. Stock-based compensation expense related to restricted stock and restricted stock units totaled $97 million , $81 million and $68 million for the years ended December 31, 2019 , 2018 and 2017 , respectively. The following table sets forth the restricted stock and restricted stock unit transactions for the years ended December 31, 2019 , 2018 and 2017 (shares and units in thousands): 2019 2018 2017 Number of Shares and Units Weighted Average Grant Date Fair Value Number of Shares and Units Weighted Average Grant Date Fair Value Number of Shares and Units Weighted Average Grant Date Fair Value Outstanding at January 1 3,792 $ 96.64 3,905 $ 88.57 3,962 $ 79.63 Granted 1,749 80.01 812 117.55 1,095 97.34 Released (1) (855 ) 96.93 (740 ) 78.16 (929 ) 61.51 Forfeited (140 ) 97.54 (185 ) 92.12 (223 ) 85.45 Outstanding at December 31 (2) 4,546 90.16 3,792 96.64 3,905 88.57 (1) The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2019, 2018 and 2017 was $70 million , $84 million and $91 million , respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date restricted stock and restricted stock units are released. (2) The total intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2019, 2018 and 2017 was $381 million , $331 million and $421 million , respectively. The intrinsic value is based on the closing market price of the Common Stock on the last trading day of the year. At December 31, 2019 , unrecognized compensation expense related to restricted stock and restricted stock units totaled $202 million . Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 1.8 years . Performance Units. EOG has granted performance units (Performance Awards) to its executive officers annually since 2012. As more fully discussed in the grant agreements, the performance metric applicable to these performance-based grants is EOG's total shareholder return over a three-year performance period relative to the total shareholder return of a designated group of peer companies (Performance Period). Upon the application of the performance multiple at the completion of the Performance Period, a minimum of 0% and a maximum of 200% of the Performance Awards granted could be outstanding. The fair value of the Performance Awards is estimated using a Monte Carlo simulation. Stock-based compensation expense related to the Performance Award grants totaled $15 million , $14 million and $10 million for the years ended December 31, 2019, 2018 and 2017, respectively. Weighted average fair values and valuation assumptions used to value Performance Awards during the years ended December 31, 2019 , 2018 and 2017 were as follows: 2019 2018 2017 Weighted Average Fair Value of Grants $ 79.98 $ 136.74 $ 113.81 Expected Volatility 29.20 % 29.92 % 32.19 % Risk-Free Interest Rate 1.51 % 2.85 % 1.60 % Expected volatility is based on the term-matched historical volatility over the simulated term, which is calculated as the time between the grant date and the end of the Performance Period. The risk-free interest rate is derived from the Treasury Constant Maturities yield curve on the grant date. The following table sets forth the Performance Award transactions for the years ended December 31, 2019 , 2018 and 2017 (shares and units in thousands): 2019 2018 2017 Number of Units and Shares Weighted Average Price per Grant Date Number of Units and Shares Weighted Average Price per Grant Date Number of Units and Shares Weighted Average Price per Grant Date Outstanding at January 1 539 $ 101.53 502 $ 90.96 545 $ 80.92 Granted 172 75.09 113 125.73 78 96.29 Granted for Performance Multiple (1) 72 69.43 72 101.87 119 84.43 Released (2) (185 ) 94.63 (148 ) 84.43 (240 ) 66.69 Forfeited — — — — — — Outstanding at December 31 (3) 598 (4 ) 92.19 539 101.53 502 90.96 (1) Upon completion of the Performance Period for the Performance Awards granted in 2015, 2014 and 2013, a performance multiple of 200% was applied to each of the grants resulting in additional grants of Performance Awards in February 2019, 2018 and 2017. (2) The total intrinsic value of Performance Awards released during the years ended December 31, 2019, 2018 and 2017 was $15 million , $18 million and $24 million , respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date Performance Awards are released. (3) The total intrinsic value of Performance Awards outstanding at December 31, 2019, 2018 and 2017 was $50 million , $47 million and $54 million , respectively. The intrinsic value is based on the closing market price of the Common Stock on the last trading day of the year. (4) Upon the application of the relevant performance multiple at the completion of each of the remaining Performance Periods, a minimum of 102 and a maximum of 1,094 Performance Awards could be outstanding. At December 31, 2019, unrecognized compensation expense related to Performance Awards totaled $9 million . Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.0 years . Upon completion of the Performance Period for the Performance Awards granted in September 2016 and December 2016, a performance multiple of 150% was applied to the grants resulting in an additional grant of 65,872 Performance Awards in February 2020. Pension Plans. EOG has a defined contribution pension plan in place for most of its employees in the United States. EOG's contributions to the pension plan are based on various percentages of compensation and, in some instances, are based upon the amount of the employees' contributions. EOG's total costs recognized for the plan were $51 million , $43 million and $37 million for 2019 , 2018 and 2017 , respectively. In addition, EOG's Trinidadian subsidiary maintains a contributory defined benefit pension plan and a matched savings plan. EOG's United Kingdom subsidiary maintained a pension plan which included a non-contributory defined contribution pension plan and a matched defined contribution savings plan. These pension plans are available to most employees of the Trinidadian subsidiary and were available to most employees of the United Kingdom subsidiary. EOG's combined contributions to these plans were $1 million , for each of 2019 , 2018 and 2017 , respectively. The United Kingdom operations were sold in the fourth quarter of 2018. For the Trinidadian defined benefit pension plan, the benefit obligation, fair value of plan assets and accrued benefit cost totaled $12 million , $10 million and $0.1 million , respectively, at December 31, 2019 , and $11 million , $9 million and $0.2 million , respectively, at December 31, 2018 . Postretirement Health Care. EOG has postretirement medical and dental benefits in place for eligible United States and Trinidad employees and their eligible dependents, the costs of which are not material.

Income Taxes (Notes)

Income Taxes (Notes)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The principal components of EOG's total net deferred income tax liabilities at December 31, 2019 and 2018 were as follows (in thousands): 2019 2018 Deferred Income Tax Assets (Liabilities) Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization $ 5,825 $ 4,359 Foreign Net Operating Loss 66,675 55,175 Foreign Valuation Allowances (70,455 ) (58,932 ) Foreign Other 318 175 Total Net Deferred Income Tax Assets $ 2,363 $ 777 Deferred Income Tax (Assets) Liabilities Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization $ 5,277,550 $ 4,583,517 (1) Commodity Hedging Contracts (4,699 ) 4,883 Deferred Compensation Plans (47,650 ) (39,086 ) Accrued Expenses and Liabilities (8,502 ) (19,097 ) Equity Awards (108,324 ) (93,977 ) Alternative Minimum Tax Credit Carryforward (31,904 ) — Undistributed Foreign Earnings 15,746 22,945 Other (46,116 ) (45,787 ) Total Net Deferred Income Tax Liabilities $ 5,046,101 $ 4,413,398 Total Net Deferred Income Tax Liabilities $ 5,043,738 $ 4,412,621 (1) The 2018 presentation has been changed to conform with current year presentation. The components of Income Before Income Taxes for the years indicated below were as follows (in thousands): 2019 2018 2017 United States $ 3,466,578 $ 4,084,156 $ 621,610 Foreign 78,689 156,842 39,572 Total $ 3,545,267 $ 4,240,998 $ 661,182 The principal components of EOG's Income Tax Provision (Benefit) for the years indicated below were as follows (in thousands): 2019 2018 2017 Current: Federal $ (152,258 ) $ (303,853 ) $ 33,058 State 10,819 17,048 (2,502 ) Foreign 81,426 65,615 35,323 Total (60,013 ) (221,190 ) 65,879 Deferred: Federal 626,901 862,075 (1,504,288 ) State 32,541 43,293 26,942 Foreign (27,784 ) (11,212 ) 3,474 Total 631,658 894,156 (1,473,872 ) Other Non-Current: (1) Federal 245,125 148,992 (513,404 ) Foreign (6,413 ) — — Total 238,712 148,992 (513,404 ) Income Tax Provision (Benefit) $ 810,357 $ 821,958 $ (1,921,397 ) (1) Includes changes in certain amounts that are expected to be paid or received beyond the next twelve months. The primary components are refundable alternative minimum tax (AMT) credits and the 2017 repatriation tax. See the following statutory-to-effective tax rate reconciliation for additional details. The differences between taxes computed at the U.S. federal statutory tax rate and EOG's effective rate for the years indicated below were as follows: 2019 2018 2017 Statutory Federal Income Tax Rate 21.00 % 21.00 % 35.00 % State Income Tax, Net of Federal Benefit 0.97 1.12 3.38 Income Tax Provision Related to Foreign Operations 0.87 0.51 (0.30 ) Income Tax Provision Related to United Kingdom Operations — — 1.78 Income Tax Provision Related to Canadian Operations — — 2.30 TCJA (1) — (2.60 ) (2) (328.10 ) (3) Share-Based Compensation 0.02 (0.47 ) (4.63 ) Other — (0.18 ) (0.03 ) Effective Income Tax Rate 22.86 % 19.38 % (290.60 )% (1) The enactment of the Tax Cuts and Jobs Act (TCJA) by the United States in 2017 made numerous changes to federal tax law. Several changes which had a significant impact on EOG include the corporate income tax rate reduction from 35% to 21%, the imposition of a one-time repatriation tax on undistributed foreign earnings and the repeal of the corporate AMT regime (AMT credit carryforwards became refundable over the following four years and were initially subject to a federal sequestration charge). In 2017, EOG revalued its federal deferred income tax assets and liabilities resulting in an earnings benefit of over $2 billion and a substantial reduction of the 2017 effective tax rate. The TCJA measurement-period adjustments were recorded in 2018. (2) Includes impact of utilizing certain tax net operating losses (NOLs) ( (1.2)% ), the reversal of sequestration ( (1.0)% ) and other tax reform impacts ( (0.4)% ). (3) Includes impact of the federal rate reduction ( (327.8)% ), federal repatriation tax ( (6.6)% ), sequestration ( (6.4)% ) and other tax reform impacts ( (0.1)% ). The net effective tax rate of 23% in 2019 was higher than the prior year rate of 19% primarily due to the absence of tax benefits from certain tax reform measurement-period adjustments. Deferred tax assets are recorded for certain tax benefits, including tax NOLs and tax credit carryforwards, provided that management assesses the utilization of such assets to be "more likely than not." Management assesses the available positive and negative evidence to estimate if sufficient future taxable income will be generated to use the existing deferred tax assets. On the basis of this evaluation, EOG has recorded valuation allowances for the portion of certain foreign and state deferred tax assets that management does not believe are more likely than not to be realized. The principal components of EOG's rollforward of valuation allowances for deferred income tax assets for the years indicated below were as follows (in thousands): 2019 2018 2017 Beginning Balance $ 167,142 $ 466,421 $ 383,221 Increase (1) 30,673 23,062 67,333 Decrease (2) (75 ) (26,219 ) (13,687 ) Other (3) 3,091 (296,122 ) 29,554 Ending Balance $ 200,831 $ 167,142 $ 466,421 (1) Increase in valuation allowance related to the generation of tax NOLs and other deferred tax assets. (2) Decrease in valuation allowance associated with adjustments to certain deferred tax assets and their related allowance. (3) Represents dispositions, revisions and/or foreign exchange rate variances and the effect of statutory income tax rate changes. The United Kingdom operations were sold in the fourth quarter of 2018. As of December 31, 2019, EOG had state income tax NOLs of approximately $2.1 billion , which, if unused, expire between 2020 and 2038. EOG also has Canadian NOLs of $225 million , some of which can be carried forward up to 20 years. As described above, these NOLs and other less significant tax benefits have been evaluated for the likelihood of utilization, and valuation allowances have been established for the portion of these deferred income tax assets that do not meet the “more likely than not” threshold. The total balance of unrecognized tax benefits for all jurisdictions at December 31, 2019, was $39 million , resulting from the tax treatment of research and experimental expenditures related to certain innovations in EOG's horizontal drilling and completion projects and tax treatment of certain compensation deductions, of which $25 million may potentially have an earnings impact. EOG records interest and penalties related to unrecognized tax benefits to its income tax provision. Cumulatively, $4 million of interest has been recognized in the Consolidated Statements of Income and Comprehensive Income. EOG does not anticipate that the amount of the unrecognized tax benefits will change materially during the next twelve months. EOG and its subsidiaries file income tax returns and are subject to tax audits in the U.S. and various state, local and foreign jurisdictions. EOG's earliest open tax years in its principal jurisdictions are as follows: U.S. federal (2016), Canada (2015), Trinidad (2013) and China (2009). EOG's foreign subsidiaries' undistributed earnings are not considered to be permanently reinvested outside of the U.S. Accordingly, EOG may be required to accrue certain U.S. federal, state, and foreign deferred income taxes on these undistributed earnings as well as on any other outside basis differences related to its investments in these subsidiaries. As of December 31, 2019, EOG has cumulatively recorded $16 million of deferred foreign income taxes for withholdings on its undistributed foreign earnings. Additionally, for tax years beginning in 2018 and later, EOG's foreign earnings may be subject to the U.S. federal "global intangible low-taxed income" (GILTI) inclusion. EOG records any GILTI tax as a period expense.

Commitments and Contingencies (

Commitments and Contingencies (Notes)	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Letters of Credit and Guarantees. At December 31, 2019 and 2018 , respectively, EOG had standby letters of credit and guarantees outstanding totaling $902 million and $294 million , primarily representing guarantees of payment or performance obligations on behalf of subsidiaries. As of February 19, 2020, EOG had received no demands for payment under these guarantees. Minimum Commitments. At December 31, 2019 , total minimum commitments from purchase and service obligations and transportation and storage service commitments not qualifying as leases, based on current transportation and storage rates and the foreign currency exchange rates used to convert Canadian dollars into United States dollars at December 31, 2019 , were as follows (in millions): Total Minimum Commitments 2020 $ 1,312 2021 1,103 2022 1,027 2023 764 2024 519 2025 and beyond 2,531 $ 7,256 Contingencies. There are currently various suits and claims pending against EOG that have arisen in the ordinary course of EOG's business, including contract disputes, personal injury and property damage claims and title disputes. While the ultimate outcome and impact on EOG cannot be predicted, management believes that the resolution of these suits and claims will not, individually or in the aggregate, have a material adverse effect on EOG's consolidated financial position, results of operations or cash flow. EOG records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

Net Income Per Share (Notes)

Net Income Per Share (Notes)	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
Net Income (Loss) Per Share	Net Income Per Share The following table sets forth the computation of Net Income Per Share for the years ended December 31, 2019 , 2018 and 2017 (in thousands, except per share data): 2019 2018 2017 Numerator for Basic and Diluted Earnings per Share - Net Income $ 2,734,910 $ 3,419,040 $ 2,582,579 Denominator for Basic Earnings per Share - Weighted Average Shares 577,670 576,578 574,620 Potential Dilutive Common Shares - Stock Options/SARs 258 1,137 1,466 Restricted Stock/Units and Performance Units 2,849 2,726 2,607 Denominator for Diluted Earnings per Share - Adjusted Diluted Weighted Average Shares 580,777 580,441 578,693 Net Income Per Share Basic $ 4.73 $ 5.93 $ 4.49 Diluted $ 4.71 $ 5.89 $ 4.46 The diluted earnings per share calculation excludes stock options, SARs, restricted stock and units and performance units that were anti-dilutive. Shares underlying the excluded stock options and SARs totaled 6.1 million , 0.6 million and 2.6 million for the years ended December 31, 2019 , 2018 and 2017 , respectively.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information (Notes)	12 Months Ended
	Dec. 31, 2019
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Supplemental Cash Flow Information Net cash paid (received) for interest and income taxes was as follows for the years ended December 31, 2019, 2018 and 2017 (in thousands): 2019 2018 2017 Interest, Net of Capitalized Interest $ 186,546 $ 243,279 $ 275,305 Income Taxes, Net of Refunds Received $ (291,849 ) $ 75,634 $ 188,946 EOG's accrued capital expenditures at December 31, 2019, 2018 and 2017 were $612 million , $592 million and $475 million , respectively. Non-cash investing activities for the year ended December 31, 2019, included additions of $150 million to EOG's oil and gas properties as a result of property exchanges. Non-cash investing activities for the year ended December 31, 2018, included additions of $362 million to EOG's oil and gas properties as a result of property exchanges and an addition of $49 million to EOG's other property, plant and equipment primarily in connection with a finance lease transaction in the Permian Basin. Non-cash investing activities for the year ended December 31, 2017, included non-cash additions of $282 million to EOG's oil and gas properties as a result of property exchanges. Cash paid for leases for the year ended December 31, 2019, is disclosed in Note 18.

Business Segment Information (N

Business Segment Information (Notes)	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	Financial information by reportable segment is presented below as of and for the years ended December 31, 2019, 2018 and 2017 (in thousands): United States Trinidad Other International (1) Total 2019 Crude Oil and Condensate $ 9,599,125 $ 11,138 $ 2,269 $ 9,612,532 Natural Gas Liquids 784,818 — — 784,818 Natural Gas 866,911 258,819 58,365 1,184,095 Gains on Mark-to-Market Commodity Derivative Contracts 180,275 — — 180,275 Gathering, Processing and Marketing 5,355,463 4,819 — 5,360,282 Gains (Losses) on Asset Dispositions, Net 131,446 (3,688 ) (4,145 ) 123,613 Other, Net 134,325 18 15 134,358 Operating Revenues and Other (2) 17,052,363 271,106 56,504 17,379,973 Depreciation, Depletion and Amortization 3,652,294 79,389 18,021 3,749,704 Operating Income (Loss) 3,618,907 112,790 (32,686 ) 3,699,011 Interest Income 22,122 3,686 218 26,026 Other Income 3,235 727 1,397 5,359 Net Interest Expense 192,587 — (7,458 ) 185,129 Income (Loss) Before Income Taxes 3,451,677 117,203 (23,613 ) 3,545,267 Income Tax Provision 760,881 40,901 8,575 810,357 Additions to Oil and Gas Properties, Excluding Dry Hole Costs 6,208,394 53,325 12,233 6,273,952 Total Property, Plant and Equipment, Net 30,101,857 184,606 78,132 30,364,595 Total Assets 36,274,942 705,747 143,919 37,124,608 United States Trinidad Other International (1) Total 2018 Crude Oil and Condensate $ 9,390,244 $ 17,059 $ 110,137 $ 9,517,440 Natural Gas Liquids 1,127,510 — — 1,127,510 Natural Gas 970,866 285,053 45,618 1,301,537 Losses on Mark-to-Market Commodity Derivative Contracts (165,640 ) — — (165,640 ) Gathering, Processing and Marketing 5,227,051 3,304 — 5,230,355 Gains on Asset Dispositions, Net 154,852 4,493 15,217 174,562 Other, Net 89,708 (49 ) (24 ) 89,635 Operating Revenues and Other (3) 16,794,591 309,860 170,948 17,275,399 Depreciation, Depletion and Amortization 3,296,499 91,971 46,938 3,435,408 Operating Income (Loss) 4,334,364 147,240 (12,258 ) 4,469,346 Interest Income 9,326 1,612 608 11,546 Other Income (Expense) 9,580 2,436 (6,858 ) 5,158 Net Interest Expense 253,352 — (8,300 ) 245,052 Income (Loss) Before Income Taxes 4,099,918 151,288 (10,208 ) 4,240,998 Income Tax Provision 765,986 54,272 1,700 821,958 Additions to Oil and Gas Properties, Excluding Dry Hole Costs 6,155,874 1,618 37,838 6,195,330 Total Property, Plant and Equipment, Net 27,786,086 210,183 79,250 28,075,519 Total Assets 33,178,733 629,633 126,108 33,934,474 2017 Crude Oil and Condensate $ 6,225,711 $ 13,572 $ 17,113 $ 6,256,396 Natural Gas Liquids 729,545 — 16 729,561 Natural Gas 615,512 271,101 35,321 921,934 Gains on Mark-to-Market Commodity Derivative Contracts 19,828 — — 19,828 Gathering, Processing and Marketing 3,298,098 (11 ) — 3,298,087 Losses on Asset Dispositions, Net (98,233 ) (8 ) (855 ) (99,096 ) Other, Net 81,610 59 (59 ) 81,610 Operating Revenues and Other (4) 10,872,071 284,713 51,536 11,208,320 Depreciation, Depletion and Amortization 3,269,196 115,321 24,870 3,409,387 Operating Income (Loss) 933,571 101,010 (108,179 ) 926,402 Interest Income 3,223 2,201 2,289 7,713 Other Income (Expense) (9,659 ) 3,337 7,761 1,439 Net Interest Expense 303,941 — (29,569 ) 274,372 Income (Loss) Before Income Taxes 623,194 106,548 (68,560 ) 661,182 Income Tax Provision (Benefit) (1,964,343 ) 38,798 4,148 (1,921,397 ) Additions to Oil and Gas Properties, Excluding Dry Hole Costs 4,067,359 145,937 14,932 4,228,228 Total Property, Plant and Equipment, Net 25,125,427 313,357 226,253 25,665,037 Total Assets 28,312,599 974,477 546,002 29,833,078 (1) Other International primarily consists of EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018. (2) EOG had sales activity with two significant purchasers in 2019, one totaling $2.4 billion , and the other totaling $2.2 billion of consolidated Operating Revenues and Other in the United States segment. (3) EOG had sales activity with two significant purchasers in 2018, one totaling $2.6 billion and the other totaling $2.3 billion of consolidated Operating Revenues and Other in the United States segment. (4) EOG had sales activity with two significant purchasers in 2017, one totaling $1.5 billion and the other totaling $1.3 billion of consolidated Operating Revenues and Other in the United States segment.
Business Segment Information	Business Segment Information EOG's operations are all crude oil, NGLs and natural gas exploration and production related. The Segment Reporting Topic of the ASC establishes standards for reporting information about operating segments in annual financial statements. Operating segments are defined as components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker, or decision-making group, in deciding how to allocate resources and in assessing performance. EOG's chief operating decision-making process is informal and involves the Chairman of the Board and Chief Executive Officer and other key officers. This group routinely reviews and makes operating decisions related to significant issues associated with each of EOG's major producing areas in the United States, Trinidad and China. For segment reporting purposes, the chief operating decision maker considers the major United States producing areas to be one operating segment. Financial information by reportable segment is presented below as of and for the years ended December 31, 2019, 2018 and 2017 (in thousands): United States Trinidad Other International (1) Total 2019 Crude Oil and Condensate $ 9,599,125 $ 11,138 $ 2,269 $ 9,612,532 Natural Gas Liquids 784,818 — — 784,818 Natural Gas 866,911 258,819 58,365 1,184,095 Gains on Mark-to-Market Commodity Derivative Contracts 180,275 — — 180,275 Gathering, Processing and Marketing 5,355,463 4,819 — 5,360,282 Gains (Losses) on Asset Dispositions, Net 131,446 (3,688 ) (4,145 ) 123,613 Other, Net 134,325 18 15 134,358 Operating Revenues and Other (2) 17,052,363 271,106 56,504 17,379,973 Depreciation, Depletion and Amortization 3,652,294 79,389 18,021 3,749,704 Operating Income (Loss) 3,618,907 112,790 (32,686 ) 3,699,011 Interest Income 22,122 3,686 218 26,026 Other Income 3,235 727 1,397 5,359 Net Interest Expense 192,587 — (7,458 ) 185,129 Income (Loss) Before Income Taxes 3,451,677 117,203 (23,613 ) 3,545,267 Income Tax Provision 760,881 40,901 8,575 810,357 Additions to Oil and Gas Properties, Excluding Dry Hole Costs 6,208,394 53,325 12,233 6,273,952 Total Property, Plant and Equipment, Net 30,101,857 184,606 78,132 30,364,595 Total Assets 36,274,942 705,747 143,919 37,124,608 United States Trinidad Other International (1) Total 2018 Crude Oil and Condensate $ 9,390,244 $ 17,059 $ 110,137 $ 9,517,440 Natural Gas Liquids 1,127,510 — — 1,127,510 Natural Gas 970,866 285,053 45,618 1,301,537 Losses on Mark-to-Market Commodity Derivative Contracts (165,640 ) — — (165,640 ) Gathering, Processing and Marketing 5,227,051 3,304 — 5,230,355 Gains on Asset Dispositions, Net 154,852 4,493 15,217 174,562 Other, Net 89,708 (49 ) (24 ) 89,635 Operating Revenues and Other (3) 16,794,591 309,860 170,948 17,275,399 Depreciation, Depletion and Amortization 3,296,499 91,971 46,938 3,435,408 Operating Income (Loss) 4,334,364 147,240 (12,258 ) 4,469,346 Interest Income 9,326 1,612 608 11,546 Other Income (Expense) 9,580 2,436 (6,858 ) 5,158 Net Interest Expense 253,352 — (8,300 ) 245,052 Income (Loss) Before Income Taxes 4,099,918 151,288 (10,208 ) 4,240,998 Income Tax Provision 765,986 54,272 1,700 821,958 Additions to Oil and Gas Properties, Excluding Dry Hole Costs 6,155,874 1,618 37,838 6,195,330 Total Property, Plant and Equipment, Net 27,786,086 210,183 79,250 28,075,519 Total Assets 33,178,733 629,633 126,108 33,934,474 2017 Crude Oil and Condensate $ 6,225,711 $ 13,572 $ 17,113 $ 6,256,396 Natural Gas Liquids 729,545 — 16 729,561 Natural Gas 615,512 271,101 35,321 921,934 Gains on Mark-to-Market Commodity Derivative Contracts 19,828 — — 19,828 Gathering, Processing and Marketing 3,298,098 (11 ) — 3,298,087 Losses on Asset Dispositions, Net (98,233 ) (8 ) (855 ) (99,096 ) Other, Net 81,610 59 (59 ) 81,610 Operating Revenues and Other (4) 10,872,071 284,713 51,536 11,208,320 Depreciation, Depletion and Amortization 3,269,196 115,321 24,870 3,409,387 Operating Income (Loss) 933,571 101,010 (108,179 ) 926,402 Interest Income 3,223 2,201 2,289 7,713 Other Income (Expense) (9,659 ) 3,337 7,761 1,439 Net Interest Expense 303,941 — (29,569 ) 274,372 Income (Loss) Before Income Taxes 623,194 106,548 (68,560 ) 661,182 Income Tax Provision (Benefit) (1,964,343 ) 38,798 4,148 (1,921,397 ) Additions to Oil and Gas Properties, Excluding Dry Hole Costs 4,067,359 145,937 14,932 4,228,228 Total Property, Plant and Equipment, Net 25,125,427 313,357 226,253 25,665,037 Total Assets 28,312,599 974,477 546,002 29,833,078 (1) Other International primarily consists of EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018. (2) EOG had sales activity with two significant purchasers in 2019, one totaling $2.4 billion , and the other totaling $2.2 billion of consolidated Operating Revenues and Other in the United States segment. (3) EOG had sales activity with two significant purchasers in 2018, one totaling $2.6 billion and the other totaling $2.3 billion of consolidated Operating Revenues and Other in the United States segment. (4) EOG had sales activity with two significant purchasers in 2017, one totaling $1.5 billion and the other totaling $1.3 billion of consolidated Operating Revenues and Other in the United States segment.

Risk Management Activities (Not

Risk Management Activities (Notes)	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk Management Activities	Risk Management Activities Commodity Price Risks. EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for crude oil, NGLs and natural gas. EOG utilizes financial commodity derivative instruments, primarily price swap, option, swaption, collar and basis swap contracts, as a means to manage this price risk. During 2019 , 2018 and 2017 , EOG elected not to designate any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounted for these financial commodity derivative contracts using the mark-to-market accounting method. Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as Gains (Losses) on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income and Comprehensive Income. The related cash flow impact is reflected in Cash Flows from Operating Activities. During 2019 , 2018 and 2017 , EOG recognized net gains (losses) on the mark-to-market of financial commodity derivative contracts of $180 million , $(166) million and $20 million , respectively, which included cash received from (payments for) settlements of crude oil and natural gas derivative contracts of $231 million , $(259) million and $7 million , respectively. Crude Oil Derivative Contracts. Prices received by EOG for its crude oil production generally vary from U.S. New York Mercantile Exchange (NYMEX) West Texas Intermediate prices due to adjustments for delivery location (basis) and other factors. EOG has entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma (Midland Differential). Presented below is a comprehensive summary of EOG's Midland Differential basis swap contracts for the year ended December 31, 2019. The weighted average price differential expressed in dollars per barrel ($/Bbl) represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in barrels per day (Bbld) covered by the basis swap contracts. Midland Differential Basis Swap Contracts Volume (Bbld) Weighted Average Price Differential ($/Bbl) 2019 January 1, 2019 through December 31, 2019 (closed) 20,000 $ 1.075 EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in the U.S. Gulf Coast and Cushing, Oklahoma (Gulf Coast Differential). Presented below is a comprehensive summary of EOG's Gulf Coast Differential basis swap contracts for the year ended December 31, 2019. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. Gulf Coast Differential Basis Swap Contracts Volume (Bbld) Weighted Average Price Differential ($/Bbl) 2019 January 1, 2019 through December 31, 2019 (closed) 13,000 $ 5.572 Presented below is a comprehensive summary of EOG's crude oil price swap contracts for the year ended December 31, 2019, with notional volumes expressed in Bbld and prices expressed in $/Bbl. Crude Oil Price Swap Contracts Volume (Bbld) Weighted Average Price ($/Bbl) 2019 April 2019 (closed) 25,000 $ 60.00 May 1, 2019 through December 31, 2019 (closed) 150,000 62.50 2020 January 1, 2020 through March 31, 2020 200,000 $ 59.33 April 1, 2020 through June 30, 2020 150,000 59.03 July 1, 2020 through September 30, 2020 50,000 58.32 NGLs Derivative Contracts. Presented below is a comprehensive summary of EOG's Mont Belvieu propane (non-TET) price swap contracts for the year ended December 31, 2019, with notional volumes expressed in Bbld and prices expressed in $/Bbl. Mont Belvieu Propane Price Swap Contracts Volume (Bbld) Weighted Average Price ($/Bbl) 2020 January 1, 2020 through December 31, 2020 4,000 $ 21.34 Natural Gas Derivative Contracts. Presented below is a comprehensive summary of EOG's natural gas price swap contracts for the year ended December 31, 2019, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu). Natural Gas Price Swap Contracts Volume (MMBtud) Weighted Average Price ($/MMBtu) 2019 April 1, 2019 through October 31, 2019 (closed) 250,000 $ 2.90 Prices received by EOG for its natural gas production generally vary from NYMEX Henry Hub prices due to adjustments for delivery location (basis) and other factors. EOG has entered into natural gas basis swap contracts in order to fix the differential between pricing in the Rocky Mountain area and NYMEX Henry Hub prices (Rockies Differential). Presented below is a comprehensive summary of EOG's Rockies Differential basis swap contracts for the year ended December 31, 2019. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts. Rockies Differential Basis Swap Contracts Volume (MMBtud) Weighted Average Price Differential ($/MMBtu) 2020 January 1, 2020 through December 31, 2020 30,000 $ 0.55 EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Houston Ship Channel (HSC) and NYMEX Henry Hub prices (HSC Differential). Presented below is a comprehensive summary of EOG's HSC Differential basis swap contracts for the year ended December 31, 2019. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts. HSC Differential Basis Swap Contracts Volume (MMBtud) Weighted Average Price Differential ($/MMBtu) 2020 January 1, 2020 through December 31, 2020 60,000 $ 0.05 EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Waha Hub in West Texas and NYMEX Henry Hub prices (Waha Differential). Presented below is a comprehensive summary of EOG's Waha Differential basis swap contracts for the year ended December 31, 2019. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts. Waha Differential Basis Swap Contracts Volume (MMBtud) Weighted Average Price Differential ($/MMBtu) 2020 January 1, 2020 through December 31, 2020 50,000 $ 1.40 Commodity Derivatives Location on Balance Sheet. The following table sets forth the amounts and classification of EOG's outstanding derivative financial instruments at December 31, 2019 and 2018 , respectively. Certain amounts may be presented on a net basis on the consolidated financial statements when such amounts are with the same counterparty and subject to a master netting arrangement (in thousands): Fair Value at December 31, Description Location on Balance Sheet 2019 2018 Asset Derivatives Crude oil, NGLs and natural gas derivative contracts - Current portion Assets from Price Risk Management Activities (1) $ 1,299 $ 23,806 Liability Derivatives Crude oil, NGLs and natural gas derivative contracts - Current portion Liabilities from Price Risk Management Activities (2) $ 20,194 $ — (1) The current portion of Assets from Price Risk Management Activities consists of gross assets of $3 million , partially offset by gross liabilities of $2 million , at December 31, 2019. (2) The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $23 million , partially offset by gross assets of $3 million at December 31, 2019. Credit Risk. Notional contract amounts are used to express the magnitude of a financial derivative. The amounts potentially subject to credit risk, in the event of nonperformance by the counterparties, are equal to the fair value of such contracts (see Note 13). EOG evaluates its exposure to significant counterparties on an ongoing basis, including those arising from physical and financial transactions. In some instances, EOG renegotiates payment terms and/or requires collateral, parent guarantees or letters of credit to minimize credit risk. At December 31, 2019 , EOG's net accounts receivable balance related to United States hydrocarbon sales included three receivable balances, each of which accounted for more than 10% of the total balance. The receivables were due from three petroleum refinery companies. The related amounts were collected during early 2020. At December 31, 2018 , EOG's net accounts receivable balance related to United States hydrocarbon sales included three receivable balances, each of which accounted for more than 10% of the total balance. The receivables were due from three petroleum refinery companies. The related amounts were collected during early 2019. In 2019 and 2018 , all natural gas from EOG's Trinidad operations was sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary. In 2019, all crude oil and condensate from EOG's Trinidad operations was sold to Heritage Petroleum Company Limited (Heritage). In 2018, all crude oil and condensate from EOG's Trinidad operations was sold to Heritage and its predecessor, the Petroleum Company of Trinidad and Tobago Limited. In 2019 and 2018, all natural gas from EOG's China operations was sold to Petrochina Company Limited. All of EOG's derivative instruments are covered by International Swap Dealers Association Master Agreements (ISDAs) with counterparties. The ISDAs may contain provisions that require EOG, if it is the party in a net liability position, to post collateral when the amount of the net liability exceeds the threshold level specified for EOG's then-current credit ratings. In addition, the ISDAs may also provide that as a result of certain circumstances, including certain events that cause EOG's credit ratings to become materially weaker than its then-current ratings, the counterparty may require all outstanding derivatives under the ISDA to be settled immediately. See Note 13 for the aggregate fair value of all derivative instruments that were in a net liability position at December 31, 2019. EOG had no collateral posted and held no collateral at December 31, 2019 and 2018 . Substantially all of EOG's accounts receivable at December 31, 2019 and 2018 resulted from hydrocarbon sales and/or joint interest billings to third-party companies, including foreign state-owned entities in the oil and gas industry. This concentration of customers and joint interest owners may impact EOG's overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. In determining whether or not to require collateral or other credit enhancements from a customer, EOG typically analyzes the entity's net worth, cash flows, earnings and credit ratings. Receivables are generally not collateralized. During the three-year period ended December 31, 2019

Fair Value Measurements (Notes)

Fair Value Measurements (Notes)	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements Certain of EOG's financial and nonfinancial assets and liabilities are reported at fair value on the Consolidated Balance Sheets. An established fair value hierarchy prioritizes the relative reliability of inputs used in fair value measurements. The hierarchy gives highest priority to Level 1 inputs that represent unadjusted quoted market prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are directly or indirectly observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs and have the lowest priority in the hierarchy. EOG gives consideration to the credit risk of its counterparties, as well as its own credit risk, when measuring financial assets and liabilities at fair value. The following table provides fair value measurement information within the fair value hierarchy for certain of EOG's financial assets and liabilities carried at fair value on a recurring basis at December 31, 2019 and 2018 . Amounts shown in thousands. Fair Value Measurements Using: Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total At December 31, 2019 Financial Assets (1) : Natural Gas Liquids Swaps $ — $ 3,401 $ — $ 3,401 Natural Gas Basis Swaps — 970 — 970 Financial Liabilities (2) : Crude Oil Swaps — 23,266 — 23,266 At December 31, 2018 Financial Assets (1) : Crude Oil Swaps $ — $ 23,806 $ — $ 23,806 (1) $1 million and $24 million are included in "Current Assets - Assets from Price Risk Management Activities" at December 31, 2019 and 2018, respectively, on the Consolidated Balance Sheets. (2) $20 million is included in "Current Liabilities - Liabilities from Price Risk Management Activities" at December 31, 2019, on the Consolidated Balance Sheets. The estimated fair value of crude oil, NGLs and natural gas derivative contracts (including options/collars) was based upon forward commodity price curves based on quoted market prices. Commodity derivative contracts were valued by utilizing an independent third-party derivative valuation provider who uses various types of valuation models, as applicable. The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs and reserve lives. A reconciliation of EOG's asset retirement obligations is presented in Note 15. During 2019 , proved oil and gas properties; other property, plant and equipment; and other assets with a carrying amount of $998 million were written down to their fair value of $701 million , resulting in pretax impairment charges of $297 million . Included in the $297 million pretax impairment charges are $152 million of impairments of proved oil and gas properties for which EOG utilized an accepted offer from a third-party purchaser as the basis for determining fair value. In addition, EOG recorded impairment charges in 2019 of $90 million for a commodity price-related write-down of other assets. During 2018 , proved oil and gas properties; other property, plant and equipment; and other assets with a carrying amount of $482 million were written down to their fair value of $308 million , resulting in pretax impairment charges of $174 million . Included in the $174 million pretax impairment charges are $104 million of impairments of proved oil and gas properties for which EOG utilized an accepted offer from a third-party purchaser as the basis for determining fair value. In addition, EOG recorded pretax impairment charges in 2018 of $49 million for a commodity price-related write-down of other assets. Significant Level 3 inputs associated with the calculation of discounted cash flows used in the impairment analysis include EOG's estimate of future crude oil, NGLs and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. EOG utilized average prices per acre from comparable market transactions and estimated discounted cash flows as the basis for determining the fair value of unproved and proved properties, respectively, received in non-cash property exchanges. See Note 10. Fair Value of Debt. At December 31, 2019 and 2018 , respectively, EOG had outstanding $5,140 million and $6,040 million aggregate principal amount of senior notes, which had estimated fair values of approximately $5,452 million and $6,027 million , respectively. The estimated fair value of debt was based upon quoted market prices and, where such prices were not available, other observable (Level 2) inputs regarding interest rates available to EOG at year-end.

Accounting For Certain Long-Liv

Accounting For Certain Long-Lived Assets (Notes)	12 Months Ended
	Dec. 31, 2019
Accounting For Certain Long-Lived Assets [Abstract]
Accounting For Certain Long-Lived Assets	Accounting for Certain Long-Lived Assets EOG reviews its proved oil and gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the asset. The carrying values for assets determined to be impaired were adjusted to estimated fair value using the Income Approach described in the Fair Value Measurement Topic of the ASC. In certain instances, EOG utilizes accepted offers from third-party purchasers as the basis for determining fair value. During 2019 , proved oil and gas properties with a carrying amount of $408 million were written down to their fair value of $201 million , resulting in pretax impairment charges of $207 million . During 2018 , proved oil and gas properties with a carrying amount of $139 million were written down to their fair value of $18 million , resulting in pretax impairment charges of $121 million . Im p airments in 2019 , 2018 and 2017 included domestic legacy natural gas assets. Amortization and impairments of unproved oil and gas property costs, including amortization of capitalized interest, were $220 million , $173 million and $211 million during 2019 , 2018 and 2017 , respectively.

Asset Retirement Obligations (N

Asset Retirement Obligations (Notes)	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligations, Noncurrent [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations The following table presents the reconciliation of the beginning and ending aggregate carrying amounts of short-term and long-term legal obligations associated with the retirement of property, plant and equipment for the years ended December 31, 2019 and 2018 (in thousands): 2019 2018 Carrying Amount at Beginning of Period $ 954,377 $ 946,848 Liabilities Incurred 98,874 79,057 Liabilities Settled (1) (58,673 ) (70,829 ) Accretion 43,462 36,622 Revisions 72,425 (38,932 ) Foreign Currency Translations 245 1,611 Carrying Amount at End of Period $ 1,110,710 $ 954,377 Current Portion $ 37,127 $ 26,214 Noncurrent Portion $ 1,073,583 $ 928,163 (1) Includes settlements related to asset sales. The current and noncurrent portions of EOG's asset retirement obligations are included in Current Liabilities - Other and Other Liabilities, respectively, on the Consolidated Balance Sheets.

Exploratory Well Costs (Notes)

Exploratory Well Costs (Notes)	12 Months Ended
	Dec. 31, 2019
Capitalized Exploratory Well Costs [Abstract]
Exploratory Well Costs	Exploratory Well Costs EOG's net changes in capitalized exploratory well costs for the years ended December 31, 2019, 2018 and 2017 are presented below (in thousands): 2019 2018 2017 Balance at January 1 $ 4,121 $ 2,167 $ — Additions Pending the Determination of Proved Reserves 83,175 10,304 27,487 Reclassifications to Proved Properties (39,325 ) (7,917 ) (20,802 ) Costs Charged to Expense (1) (22,074 ) (433 ) (4,518 ) Balance at December 31 $ 25,897 $ 4,121 $ 2,167 (1) Includes capitalized exploratory well costs charged to either dry hole costs or impairments. At December 31, 2019, 2018 and 2017, all exploratory well costs had been capitalized for periods of less than one year.

Acquisitions and Divestitures (

Acquisitions and Divestitures (Notes)	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
Acquisitions and Divestitures	Acquisitions and Divestitures During 2019, EOG paid cash for property acquisitions of $328 million in the United States. Additionally during 2019 , EOG recognized net gains on asset dispositions of $124 million primarily due to sales of producing properties, acreage and other assets, as well as non-cash property exchanges in New Mexico, and received proceeds of approximately $140 million . During 2018, EOG recognized a net gain on asset dispositions of $175 million primarily due to non-cash property exchanges in Texas, New Mexico and Wyoming. Additionally, EOG received proceeds in 2018 of approximately $227 million primarily due to the sale of its United Kingdom operations in the fourth quarter of 2018. During 2017, EOG recognized a net loss on asset dispositions of $99 million and received proceeds of approximately $227 million primarily from sales of producing properties, other assets and acreage in Texas and Oklahoma. Also during 2017, EOG completed acquisitions of approximately $73 million to acquire producing properties in various areas in the United States.

Leases (Notes)

Leases (Notes)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Lessee Operating and Finance Leases [Text Block]	Leases Lease costs are classified by the function of the ROU asset. The lease costs related to exploration and development activities are initially included in the Oil and Gas Properties line on the Consolidated Balance Sheets and subsequently accounted for in accordance with the Extractive Industries - Oil and Gas Topic of the ASC. Variable lease cost represents costs incurred above the contractual minimum payments and other charges associated with leased equipment, primarily for drilling and fracturing contracts classified as operating leases. The components of lease cost for the year ended December 31, 2019, were as follows (in millions): Year Ended December 31, 2019 Operating Lease Cost $ 497 Finance Lease Cost: Amortization of Lease Assets 13 Interest on Lease Liabilities 2 Variable Lease Cost 138 Short-Term Lease Cost 333 Total Lease Cost $ 983 The following table sets forth the amounts and classification of EOG's outstanding ROU assets and related lease liabilities and supplemental information at December 31, 2019 (in millions, except lease terms and discount rates): Description Location on Balance Sheet Amount Assets Operating Leases Other Assets $ 773 Finance Leases Property, Plant and Equipment, Net (1) 53 Total $ 826 Liabilities Current Operating Leases Current Portion of Operating Lease Liabilities $ 369 Finance Leases Current Portion of Long-Term Debt 15 Long-Term Operating Leases Other Liabilities 430 Finance Leases Long-Term Debt 43 Total $ 857 (1) Finance lease assets are recorded net of accumulated amortization of $60 million at December 31, 2019. Year Ended December 31, 2019 Weighted Average Remaining Lease Term (in years): Operating Leases 3.2 Finance Leases 4.7 Weighted Average Discount Rate: Operating Leases 3.5 % Finance Leases 3.0 % Cash paid for leases was as follows for the year ended December 31, 2019 (in millions): Year Ended December 31, 2019 Repayment of Operating Lease Liabilities Associated with Operating Activities $ 225 Repayment of Operating Lease Liabilities Associated with Investing Activities 270 Repayment of Finance Lease Liabilities 13 Upon adoption of ASU 2016-02 effective January 1, 2019, EOG recognized operating lease ROU assets of $566 million . Non-cash leasing activities for the twelve months ended December 31, 2019, included the addition of $784 million of operating leases. At December 31, 2019, the future minimum lease payments under non-cancellable leases were as follows (in millions): Operating Leases Finance Leases 2020 $ 390 $ 15 2021 209 15 2022 126 12 2023 56 8 2024 29 8 2025 and Beyond 40 6 Total Lease Payments 850 64 Less: Discount to Present Value 51 6 Total Lease Liabilities 799 58 Less: Current Portion of Lease Liabilities 369 15 Long-Term Lease Liabilities $ 430 $ 43 At December 31, 2019, EOG had additional leases of $699 million , of which $521 million and $178 million were expected to commence in 2020 and 2021, respectively, with lease terms of one month to 10 years . At December 31, 2018 and prior to the adoption of ASU 2016-02 and other related ASUs, the future minimum commitments under non-cancellable leases, including non-lease components and excluding contracts with lease terms of less than 12 months, were as follows (in millions): Operating Leases Finance Leases 2019 $ 380 $ 15 2020 213 15 2021 86 15 2022 39 12 2023 30 8 2024 and Beyond 62 14 Total Lease Payments $ 810 $ 79

Oil and Gas Exploration and Pro

Oil and Gas Exploration and Production Industries Disclosures (Notes)	12 Months Ended
	Dec. 31, 2019
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Oil and Gas Exploration and Production Industries Disclosures	Oil and Gas Producing Activities The following disclosures are made in accordance with Financial Accounting Standards Board Accounting Standards Update No. 2010-03 "Oil and Gas Reserve Estimates and Disclosures" and the United States Securities and Exchange Commission's (SEC) final rule on "Modernization of Oil and Gas Reporting." Oil and Gas Reserves. Users of this information should be aware that the process of estimating quantities of "proved," "proved developed" and "proved undeveloped" crude oil, natural gas liquids (NGLs) and natural gas reserves is complex, requiring significant subjective decisions in the evaluation of available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including, but not limited to, additional development activity; evolving production history; crude oil and condensate, NGL and natural gas prices; and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. Although reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. For related discussion, see ITEM 1A, Risk Factors. Proved reserves represent estimated quantities of crude oil, NGLs and natural gas, which, by analysis of geoscience and engineering data, can be estimated, with reasonable certainty, to be economically producible from a given date forward from known reservoirs under then-existing economic conditions, operating methods and government regulations before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Proved developed reserves are proved reserves expected to be recovered under operating methods being utilized at the time the estimates were made, through wells and equipment in place or if the cost of any required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves (PUDs) are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. PUDs can be recorded in respect of a particular undrilled location only if the location is scheduled, under the then-current drilling and development plan, to be drilled within five years from the date that the PUDs were recorded, unless specific factors (such as those described in interpretative guidance issued by the Staff of the SEC) justify a longer timeframe. Likewise, absent any such specific factors, PUDs associated with a particular undeveloped drilling location shall be removed from the estimates of proved reserves if the location is scheduled, under the then-current drilling and development plan, to be drilled on a date that is beyond five years from the date that the PUDs were recorded. EOG has formulated development plans for all drilling locations associated with its PUDs at December 31, 2019 . Under these plans, each PUD location will be drilled within five years from the date it was recorded. Estimates for PUDs are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty. In making estimates of PUDs, EOG's technical staff, including engineers and geoscientists, perform detailed technical analysis of each potential drilling location within its inventory of prospects. In making a determination as to which of these locations would penetrate undrilled portions of the formation that can be judged, with reasonable certainty, to be continuous and contain economically producible crude oil, NGLs and natural gas, studies are conducted using numerous data elements and analysis techniques. EOG's technical staff estimates the hydrocarbons in place, by mapping the entirety of the play in question using seismic techniques, typically employing two-dimensional and three-dimensional data. This analysis is integrated with other static data, including, but not limited to, core analysis, mechanical properties of the formation, thermal maturity indicators, and well logs of existing penetrations. Highly specialized equipment is utilized to prepare rock samples in assessing microstructures which contribute to porosity and permeability. Analysis of dynamic data is then incorporated to arrive at the estimated fractional recovery of hydrocarbons in place. Data analysis techniques employed include, but are not limited to, well testing analysis, static bottom hole pressure analysis, flowing bottom hole pressure analysis, analysis of historical production trends, pressure transient analysis and rate transient analysis. Application of proprietary rate transient analysis techniques in low permeability rocks allow for quantification of estimates of contribution to production from both fractures and rock matrix. The impact of optimal completion techniques is a key factor in determining if the PUDs reflected in prospective locations are reasonably certain of being economically producible. EOG's technical staff estimates the recovery improvement that might be achieved when completing horizontal wells with multi-stage fracture stimulation. In the early stages of development of a play, EOG determines the optimal length of the horizontal lateral and multi-stage fracture stimulation using the aforementioned analysis techniques along with pilot drilling programs and gathering of microseismic data. The process of analyzing static and dynamic data, well completion optimization and the results of early development activities provides the appropriate level of certainty as well as support for the economic producibility of the plays in which PUDs are reflected. EOG has found this approach to be effective based on successful application in analogous reservoirs in low permeability resource plays. Certain of EOG's Trinidad reserves are held under production sharing contracts where EOG's interest varies with prices and production volumes. Trinidad reserves, as presented on a net basis, assume prices in existence at the time the estimates were made and EOG's estimate of future production volumes. Future fluctuations in prices, production rates or changes in political or regulatory environments could cause EOG's share of future production from Trinidadian reserves to be materially different from that presented. Estimates of proved reserves at December 31, 2019 , 2018 and 2017 were based on studies performed by the engineering staff of EOG. The Engineering and Acquisitions Department is directly responsible for EOG's reserve evaluation process and consists of 17 professionals, all of whom hold, at a minimum, bachelor's degrees in engineering, and four of whom are Registered Professional Engineers. The Vice President, Engineering and Acquisitions is the manager of this department and is the primary technical person responsible for this process. The Vice President, Engineering and Acquisitions holds a Bachelor of Science degree in Petroleum Engineering, has 33 years of experience in reserve evaluations and is a Registered Professional Engineer. EOG's reserves estimation process is a collaborative effort coordinated by the Engineering and Acquisitions Department in compliance with EOG's internal controls for such process. Reserve information as well as models used to estimate such reserves are stored on secured databases. Non-technical inputs used in reserve estimation models, including crude oil, NGL and natural gas prices, production costs, transportation costs, future capital expenditures and EOG's net ownership percentages, are obtained from other departments within EOG. EOG's Internal Audit Department conducts testing with respect to such non-technical inputs. Additionally, EOG engages DeGolyer and MacNaughton (D&M), independent petroleum consultants, to perform independent reserves evaluation of select EOG properties comprising not less than 75% of EOG's estimates of proved reserves. EOG's Board of Directors requires that D&M's and EOG's reserve quantities for the properties evaluated by D&M vary by no more than 5% in the aggregate. Once completed, EOG's year-end reserves are presented to senior management, including the Chairman of the Board and Chief Executive Officer; the Chief Operating Officer; the Executive Vice Presidents, Exploration and Production; and the Executive Vice President and Chief Financial Officer, for approval. Opinions by D&M for the years ended December 31, 2019 , 2018 and 2017 covered producing areas containing 82%, 79% and 79%, respectively, of proved reserves of EOG on a net-equivalent-barrel-of-oil basis. D&M's opinions indicate that the estimates of proved reserves prepared by EOG's Engineering and Acquisitions Department for the properties reviewed by D&M, when compared in total on a net-equivalent-barrel-of-oil basis, do not differ materially from the estimates prepared by D&M. Specifically, such estimates by D&M in the aggregate varied by not more than 5% from those prepared by the Engineering and Acquisitions Department of EOG. All reports by D&M were developed utilizing geological and engineering data provided by EOG. The report of D&M dated January 24, 2020, which contains further discussion of the reserve estimates and evaluations prepared by D&M, as well as the qualifications of D&M's technical person primarily responsible for overseeing such estimates and evaluations, is attached as Exhibit 99.1 to this Annual Report on Form 10-K and incorporated herein by reference. No major discovery or other favorable or adverse event subsequent to December 31, 2019 , is believed to have caused a material change in the estimates of net proved reserves as of that date. The following tables set forth EOG's net proved reserves at December 31 for each of the four years in the period ended December 31, 2019 , and the changes in the net proved reserves for each of the three years in the period ended December 31, 2019 , as estimated by the Engineering and Acquisitions Department of EOG: NET PROVED RESERVE SUMMARY United States Trinidad Other International (1) Total NET PROVED RESERVES Crude Oil (MBbl) (2) Net proved reserves at December 31, 2016 1,168,491 839 8,255 1,177,585 Revisions of previous estimates 57,935 80 (179 ) 57,836 Purchases in place 1,111 — — 1,111 Extensions, discoveries and other additions 207,137 301 119 207,557 Sales in place (8,393 ) — — (8,393 ) Production (122,210 ) (322 ) (191 ) (122,723 ) Net proved reserves at December 31, 2017 1,304,071 898 8,004 1,312,973 Revisions of previous estimates (13,237 ) (183 ) 44 (13,376 ) Purchases in place 2,743 — — 2,743 Extensions, discoveries and other additions 383,003 — 15 383,018 Sales in place (768 ) — (6,310 ) (7,078 ) Production (144,128 ) (298 ) (1,542 ) (145,968 ) Net proved reserves at December 31, 2018 1,531,684 417 211 1,532,312 Revisions of previous estimates (42,959 ) 85 (8 ) (42,882 ) Purchases in place 2,859 — — 2,859 Extensions, discoveries and other additions 369,968 — 28 369,996 Sales in place (1,282 ) — — (1,282 ) Production (166,310 ) (236 ) (40 ) (166,586 ) Net proved reserves at December 31, 2019 1,693,960 266 191 1,694,417 Natural Gas Liquids (MBbl) (2) Net proved reserves at December 31, 2016 416,366 — — 416,366 Revisions of previous estimates 46,843 — — 46,843 Purchases in place 421 — — 421 Extensions, discoveries and other additions 75,003 — — 75,003 Sales in place (2,887 ) — — (2,887 ) Production (32,273 ) — — (32,273 ) Net proved reserves at December 31, 2017 503,473 — — 503,473 Revisions of previous estimates 23,942 — — 23,942 Purchases in place 2,006 — — 2,006 Extensions, discoveries and other additions 127,409 — — 127,409 Sales in place (41 ) — — (41 ) Production (42,460 ) — — (42,460 ) Net proved reserves at December 31, 2018 614,329 — — 614,329 Revisions of previous estimates 5,380 — — 5,380 Purchases in place 1,948 — — 1,948 Extensions, discoveries and other additions 167,782 — — 167,782 Sales in place (855 ) — — (855 ) Production (48,892 ) — — (48,892 ) Net proved reserves at December 31, 2019 739,692 — — 739,692 United States Trinidad Other International (1) Total Natural Gas (Bcf) (3) Net proved reserves at December 31, 2016 3,021.2 280.9 15.8 3,317.9 Revisions of previous estimates 602.8 (27.4 ) 8.6 584.0 Purchases in place 4.8 — — 4.8 Extensions, discoveries and other additions 619.3 174.2 35.9 829.4 Sales in place (56.4 ) — — (56.4 ) Production (293.2 ) (114.3 ) (9.1 ) (416.6 ) Net proved reserves at December 31, 2017 3,898.5 313.4 51.2 4,263.1 Revisions of previous estimates (127.2 ) 20.7 15.0 (91.5 ) Purchases in place 41.3 — — 41.3 Extensions, discoveries and other additions 951.4 — 4.6 956.0 Sales in place (22.2 ) — — (22.2 ) Production (351.2 ) (97.1 ) (11.2 ) (459.5 ) Net proved reserves at December 31, 2018 4,390.6 237.0 59.6 4,687.2 Revisions of previous estimates (184.4 ) 47.0 2.6 (134.8 ) Purchases in place 71.7 — — 71.7 Extensions, discoveries and other additions 1,175.9 87.5 9.7 1,273.1 Sales in place (14.5 ) — — (14.5 ) Production (404.5 ) (95.4 ) (13.1 ) (513.0 ) Net proved reserves at December 31, 2019 5,034.8 276.1 58.8 5,369.7 Oil Equivalents (MBoe) (2) Net proved reserves at December 31, 2016 2,088,392 47,661 10,880 2,146,933 Revisions of previous estimates 205,262 (4,493 ) 1,249 202,018 Purchases in place 2,332 — — 2,332 Extensions, discoveries and other additions 385,354 29,340 6,104 420,798 Sales in place (20,687 ) — — (20,687 ) Production (203,351 ) (19,366 ) (1,707 ) (224,424 ) Net proved reserves at December 31, 2017 2,457,302 53,142 16,526 2,526,970 Revisions of previous estimates (10,500 ) 3,272 2,544 (4,684 ) Purchases in place 11,640 — — 11,640 Extensions, discoveries and other additions 668,972 — 778 669,750 Sales in place (4,509 ) — (6,310 ) (10,819 ) Production (245,127 ) (16,478 ) (3,406 ) (265,011 ) Net proved reserves at December 31, 2018 2,877,778 39,936 10,132 2,927,846 Revisions of previous estimates (68,317 ) 7,915 431 (59,971 ) Purchases in place 16,761 — — 16,761 Extensions, discoveries and other additions 733,730 14,577 1,661 749,968 Sales in place (4,555 ) — — (4,555 ) Production (282,619 ) (16,130 ) (2,232 ) (300,981 ) Net proved reserves at December 31, 2019 3,272,778 46,298 9,992 3,329,068 (1) Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018. (2) Thousand barrels or thousand barrels of oil equivalent, as applicable; oil equivalents include crude oil and condensate, NGLs and natural gas. Oil equivalents are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. (3) Billion cubic feet. During 2019, EOG added 750 million barrels of oil equivalent (MMBoe) of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin, the Eagle Ford and the Rocky Mountain area. Approximately 72% of the 2019 reserve additions were crude oil and condensate and NGLs, and substantially all were in the United States. Sales in place of 5 MMBoe were primarily related to the sale of certain South Texas Area operations and the sale or exchange of other producing assets. Revisions of previous estimates of negative 60 MMBoe for 2019 included a decrease in the average crude oil, NGLs and natural gas prices used in the December 31, 2019, reserves estimation as compared to the prices used in the prior year estimate. The primary area affected was the Rocky Mountain area. Purchases in place of 17 MMBoe were primarily related to the South Texas Area. During 2018, EOG added 670 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin, the Eagle Ford, the Rocky Mountain area and the Mid-Continent area. Approximately 76% of the 2018 reserve additions were crude oil and condensate and NGLs, and substantially all were in the United States. Sales in place of 11 MMBoe were primarily related to the sale of the United Kingdom operations and the sale or exchange of other producing assets. Revisions of previous estimates of negative 5 MMBoe for 2018 included an upward revision of 35 MMBoe primarily due to increases in the average crude oil, NGLs and natural gas prices used in the December 31, 2018, reserves estimation as compared to the prices used in the prior year estimate. The primary areas affected were in the Rocky Mountain area, the Eagle Ford and the Permian Basin. Downward revisions other than price of 40 MMBoe resulted primarily from changes in production forecasts and higher production costs. Purchases in place of 12 MMBoe were primarily related to the South Texas Area. During 2017, EOG added 421 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin, the Eagle Ford, the Rocky Mountain area and Trinidad. Approximately 67% of the 2017 reserve additions were crude oil and condensate and NGLs, and 92% were in the United States. Sales in place of 21 MMBoe were primarily related to the sale or exchange of certain producing assets. Revisions of previous estimates of 202 MMBoe for 2017 included an upward revision of 154 MMBoe primarily due to increases in the average crude oil, NGLs and natural gas prices used in the December 31, 2017, reserves estimation as compared to the prices used in the prior year estimate. The primary plays affected were in the Rocky Mountain area, the Eagle Ford and the Permian Basin. Positive revisions other than price of 48 MMBoe resulted primarily from improved well performance in the Permian Basin and lower production costs. Purchases in place of 2 MMBoe were primarily related to the Permian Basin. United States Trinidad Other International (1) Total NET PROVED DEVELOPED RESERVES Crude Oil (MBbl) December 31, 2016 507,531 839 8,255 516,625 December 31, 2017 605,405 898 7,933 614,236 December 31, 2018 712,218 417 150 712,785 December 31, 2019 801,189 266 143 801,598 Natural Gas Liquids (MBbl) December 31, 2016 230,219 — — 230,219 December 31, 2017 286,872 — — 286,872 December 31, 2018 341,386 — — 341,386 December 31, 2019 387,253 — — 387,253 Natural Gas (Bcf) December 31, 2016 1,804.4 262.2 15.8 2,082.4 December 31, 2017 2,450.8 299.2 29.3 2,779.3 December 31, 2018 2,699.0 223.9 40.9 2,963.8 December 31, 2019 2,974.6 177.7 41.8 3,194.1 Oil Equivalents (MBoe) December 31, 2016 1,038,483 44,543 10,880 1,093,906 December 31, 2017 1,300,758 50,779 12,798 1,364,335 December 31, 2018 1,503,441 37,746 6,950 1,548,137 December 31, 2019 1,684,209 29,886 7,117 1,721,212 NET PROVED UNDEVELOPED RESERVES Crude Oil (MBbl) December 31, 2016 660,690 — — 660,690 December 31, 2017 698,666 — 71 698,737 December 31, 2018 819,466 — 61 819,527 December 31, 2019 892,771 — 48 892,819 Natural Gas Liquids (MBbl) December 31, 2016 186,147 — — 186,147 December 31, 2017 216,601 — — 216,601 December 31, 2018 272,943 — — 272,943 December 31, 2019 352,439 — — 352,439 Natural Gas (Bcf) December 31, 2016 1,216.8 18.7 — 1,235.5 December 31, 2017 1,447.7 14.2 21.9 1,483.8 December 31, 2018 1,691.6 13.1 18.7 1,723.4 December 31, 2019 2,060.2 98.4 17.0 2,175.6 Oil Equivalents (MBoe) December 31, 2016 1,049,909 3,118 — 1,053,027 December 31, 2017 1,156,544 2,363 3,728 1,162,635 December 31, 2018 1,374,337 2,190 3,182 1,379,709 December 31, 2019 1,588,569 16,412 2,875 1,607,856 (1) Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018. Net Proved Undeveloped Reserves. The following table presents the changes in EOG's total proved undeveloped reserves during 2019 , 2018 and 2017 (in MBoe): 2019 2018 2017 Balance at January 1 1,379,709 1,162,635 1,053,027 Extensions and Discoveries 578,317 490,725 237,378 Revisions (49,837 ) (8,244 ) 33,127 Acquisition of Reserves 1,711 311 — Sale of Reserves — — (8,253 ) Conversion to Proved Developed Reserves (302,044 ) (265,718 ) (152,644 ) Balance at December 31 1,607,856 1,379,709 1,162,635 For the twelve-month period ended December 31, 2019, total PUDs increased by 228 MMBoe to 1,608 MMBoe. EOG added approximately 38 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion. Based on the technology employed by EOG to identify and record PUDs (see discussion of technology employed on pages F-39 and F-40 of this Annual Report on Form 10-K), EOG added 540 MMBoe. The PUD additions were primarily in the Permian Basin, the Eagle Ford and, to a lesser extent, the Rocky Mountain area, and 73% of the additions were crude oil and condensate and NGLs. During 2019, EOG drilled and transferred 302 MMBoe of PUDs to proved developed reserves at a total capital cost of $3,032 million. All PUDs, including drilled but uncompleted wells (DUCs), are scheduled for completion within five years of the original reserve booking. For the twelve-month period ended December 31, 2018, total PUDs increased by 217 MMBoe to 1,380 MMBoe. EOG added approximately 31 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion. Based on the technology employed by EOG to identify and record PUDs, EOG added 460 MMBoe. The PUD additions were primarily in the Permian Basin, Anadarko Basin, the Eagle Ford and, to a lesser extent, the Rocky Mountain area, and 80% of the additions were crude oil and condensate and NGLs. During 2018, EOG drilled and transferred 266 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,745 million. For the twelve-month period ended December 31, 2017, total PUDs increased by 110 MMBoe to 1,163 MMBoe. EOG added approximately 38 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion. Based on the technology employed by EOG to identify and record PUDs, EOG added 199 MMBoe. The PUD additions were primarily in the Permian Basin and, to a lesser extent, the Eagle Ford and the Rocky Mountain area, and 74% of the additions were crude oil and condensate and NGLs. During 2017, EOG drilled and transferred 153 MMBoe of PUDs to proved developed reserves at a total capital cost of $1,440 million. Revisions of PUDs totaled positive 33 MMBoe, primarily due to updated type curves resulting from improved performance of offsetting wells in the Permian Basin, the impact of increases in the average crude oil and natural gas prices used in the December 31, 2017, reserves estimation as compared to the prices used in the prior year estimate, and lower costs. During 2017, EOG sold or exchanged 8 MMBoe of PUDs primarily in the Permian Basin. Capitalized Costs Relating to Oil and Gas Producing Activities. The following table sets forth the capitalized costs relating to EOG's crude oil, NGLs and natural gas producing activities at December 31, 2019 and 2018 : 2019 2018 Proved properties $ 59,229,686 $ 53,624,809 Unproved properties 3,600,729 3,705,207 Total 62,830,415 57,330,016 Accumulated depreciation, depletion and amortization (35,033,085 ) (31,674,085 ) Net capitalized costs $ 27,797,330 $ 25,655,931 Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities. The acquisition, exploration and development costs disclosed in the following tables are in accordance with definitions in the Extractive Industries - Oil and Gas Topic of the Accounting Standards Codification (ASC). Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Exploration costs include additions to exploratory wells, including those in progress, and exploration expenses. Development costs include additions to production facilities and equipment and additions to development wells, including those in progress. The following table sets forth costs incurred related to EOG's oil and gas activities for the years ended December 31, 2019 , 2018 and 2017 : United States Trinidad Other International (1) Total 2019 Acquisition Costs of Properties Unproved (2) $ 276,092 $ — $ — $ 276,092 Proved (3) 379,938 — — 379,938 Subtotal 656,030 — — 656,030 Exploration Costs 213,505 46,616 13,218 273,339 Development Costs (4) 5,661,753 25,007 12,096 5,698,856 Total $ 6,531,288 $ 71,623 $ 25,314 $ 6,628,225 2018 Acquisition Costs of Properties Unproved (5) $ 486,081 $ 1,258 $ — $ 487,339 Proved (6) 123,684 — — 123,684 Subtotal 609,765 1,258 — 611,023 Exploration Costs 157,222 22,511 13,895 193,628 Development Costs (7) 5,605,264 (12,863 ) 22,628 5,615,029 Total $ 6,372,251 $ 10,906 $ 36,523 $ 6,419,680 2017 Acquisition Costs of Properties Unproved (8) $ 424,118 $ 2,422 $ — $ 426,540 Proved (9) 72,584 — — 72,584 Subtotal 496,702 2,422 — 499,124 Exploration Costs 144,499 62,547 16,553 223,599 Development Costs (10) 3,590,899 109,491 16,297 3,716,687 Total $ 4,232,100 $ 174,460 $ 32,850 $ 4,439,410 (1) Other International primarily consists of EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018. (2) Includes non-cash unproved leasehold acquisition costs of $98 million related to property exchanges. (3) Includes non-cash proved property acquisition costs of $52 million related to property exchanges. (4) Includes Asset Retirement Costs of $181 million, $1 million and $4 million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment. (5) Includes non-cash unproved leasehold acquisition costs of $291 million related to property exchanges. (6) Includes non-cash proved property acquisition costs of $71 million related to property exchanges. (7) Includes Asset Retirement Costs of $90 million, $(12) million and $(8) million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment. (8) Includes non-cash unproved leasehold acquisition costs of $256 million related to property exchanges. (9) Includes non-cash proved property acquisition costs of $26 million related to property exchanges. (10) Includes Asset Retirement Costs of $50 million, $2 million and $4 million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment. Results of Operations for Oil and Gas Producing Activities (1) . The following table sets forth results of operations for oil and gas producing activities for the years ended December 31, 2019 , 2018 and 2017 : United States Trinidad Other International (2) Total 2019 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues $ 11,250,853 $ 269,957 $ 60,635 $ 11,581,445 Other 134,325 18 15 134,358 Total 11,385,178 269,975 60,650 11,715,803 Exploration Costs 130,302 4,290 5,289 139,881 Dry Hole Costs 11,133 13,033 3,835 28,001 Transportation Costs 753,558 4,014 728 758,300 Gathering and Processing Costs 479,102 — — 479,102 Production Costs 2,063,078 30,539 40,369 2,133,986 Impairments 510,948 5,713 1,235 517,896 Depreciation, Depletion and Amortization 3,560,609 79,156 17,832 3,657,597 Income (Loss) Before Income Taxes 3,876,448 133,230 (8,638 ) 4,001,040 Income Tax Provision 884,450 54,980 3,152 942,582 Results of Operations $ 2,991,998 $ 78,250 $ (11,790 ) $ 3,058,458 2018 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues $ 11,488,620 $ 302,112 $ 155,755 $ 11,946,487 Other 89,708 (49 ) (24 ) 89,635 Total 11,578,328 302,063 155,731 12,036,122 Exploration Costs 121,572 21,402 6,025 148,999 Dry Hole Costs 4,983 — 422 5,405 Transportation Costs 742,792 3,236 848 746,876 Gathering and Processing Costs (3) 404,471 — 32,502 436,973 Production Costs 1,924,504 33,506 70,073 2,028,083 Impairments 344,595 — 2,426 347,021 Depreciation, Depletion and Amortization 3,181,801 91,788 46,687 3,320,276 Income (Loss) Before Income Taxes 4,853,610 152,131 (3,252 ) 5,002,489 Income Tax Provision 1,086,077 12,170 1,898 1,100,145 Results of Operations $ 3,767,533 $ 139,961 $ (5,150 ) $ 3,902,344 2017 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues $ 7,570,768 $ 284,673 $ 52,450 $ 7,907,891 Other 81,610 59 (59 ) 81,610 Total 7,652,378 284,732 52,391 7,989,501 Exploration Costs 113,334 26,245 5,763 145,342 Dry Hole Costs 91 — 4,518 4,609 Transportation Costs 737,403 1,885 1,064 740,352 Production Costs 1,446,333 27,839 88,038 1,562,210 Impairments 477,223 — 2,017 479,240 Depreciation, Depletion and Amortization 3,157,056 115,174 24,536 3,296,766 Income (Loss) Before Income Taxes 1,720,938 113,589 (73,545 ) 1,760,982 Income Tax Provision (Benefit) 625,562 24,882 (1,342 ) 649,102 Results of Operations $ 1,095,376 $ 88,707 $ (72,203 ) $ 1,111,880 (1) Excludes gains or losses on the mark-to-market of financial commodity derivative contracts, gains or losses on sales of reserves and related assets, interest charges and general corporate expenses for each of the three years in the period ended December 31, 2019 . (2) Other International primarily consists of EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018. (3) Effective January 1, 2018, EOG adopted the provisions of Accounting Standards Update (ASU) 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements within its United States segment as Gathering and Processing Costs instead of as a deduction to Natural Gas Revenues. There was no impact to operating income or net income resulting from changes to the presentation of natural gas processing fees (see Note 1 to Consolidated Financial Statements). The following table sets forth production costs per barrel of oil equivalent, excluding severance/production and ad valorem taxes, for the years ended December 31, 2019 , 2018 and 2017 : United States Trinidad Other International (1) Composite Year Ended December 31, 2019 $ 4.59 $ 1.85 $ 18.26 $ 4.54 Year Ended December 31, 2018 $ 4.84 $ 1.67 $ 20.19 $ 4.84 Year Ended December 31, 2017 $ 4.58 $ 1.39 $ 50.86 $ 4.66 (1) Other International primarily consists of EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves. The following information has been developed utilizing procedures prescribed by the Extractive Industries - Oil and Gas Topic of the ASC and based on crude oil, NGL and natural gas reserves and production volumes estimated by the Engineering and Acquisitions Department of EOG. The estimates were based on a 12-month average for commodity prices for the years 2019 , 2018 and 2017 . The following information may be useful for certain comparative purposes, but should not be solely relied upon in evaluating EOG or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of EOG. The future cash flows presented below are based on sales prices, cost rates and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil, NGL and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.

Unaudited Quarterly Financial I

Unaudited Quarterly Financial Information (Notes)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Unaudited Quarterly Financial Information	Unaudited Quarterly Financial Information (In Thousands, Except Per Share Data) Quarter Ended Mar 31 Jun 30 Sep 30 Dec 31 2019 Operating Revenues and Other $ 4,058,642 $ 4,697,630 $ 4,303,455 $ 4,320,246 Operating Income $ 876,530 $ 1,130,771 $ 827,959 $ 863,751 Income Before Income Taxes $ 827,236 $ 1,089,366 $ 797,457 $ 831,208 Income Tax Provision 191,810 241,525 182,335 194,687 Net Income $ 635,426 $ 847,841 $ 615,122 $ 636,521 Net Income Per Share (1) Basic $ 1.10 $ 1.47 $ 1.06 $ 1.10 Diluted $ 1.10 $ 1.46 $ 1.06 $ 1.10 Average Number of Common Shares Basic 577,207 577,460 577,839 578,219 Diluted 580,222 580,247 581,271 580,849 2018 Operating Revenues and Other $ 3,681,162 $ 4,238,077 $ 4,781,624 $ 4,574,536 Operating Income $ 874,588 $ 964,931 $ 1,506,687 $ 1,123,140 Income Before Income Taxes $ 813,359 $ 892,936 $ 1,446,363 $ 1,088,340 Income Tax Provision 174,770 196,205 255,411 195,572 Net Income $ 638,589 $ 696,731 $ 1,190,952 $ 892,768 Net Income Per Share (1) Basic $ 1.11 $ 1.21 $ 2.06 $ 1.55 Diluted $ 1.10 $ 1.20 $ 2.05 $ 1.54 Average Number of Common Shares Basic 575,775 576,135 577,254 577,035 Diluted 579,726 580,375 581,559 580,288 (1) The sum of quarterly net income per share may not agree with total year net income per share as each quarterly computation is based on the weighted average of common shares outstanding.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation. The consolidated financial statements of EOG Resources, Inc. (EOG) include the accounts of all domestic and foreign subsidiaries. Investments in unconsolidated affiliates, in which EOG is able to exercise significant influence, are accounted for using the equity method. All intercompany accounts and transactions have been eliminated. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Financial Instruments	Financial Instruments. EOG's financial instruments consist of cash and cash equivalents, commodity derivative contracts, accounts receivable, accounts payable and current and long-term debt. The carrying values of cash and cash equivalents, commodity derivative contracts, accounts receivable and accounts payable approximate fair value (see Notes 2 and 12).
Cash and Cash Equivalents	Cash and Cash Equivalents. EOG records as cash equivalents all highly liquid short-term investments with original maturities of three months or less.
Oil and Gas Operations	Oil and Gas Operations. EOG accounts for its crude oil and natural gas exploration and production activities under the successful efforts method of accounting. Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred. Oil and gas exploration costs, other than the costs of drilling exploratory wells, are expensed as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether EOG has discovered commercial quantities of proved reserves. If commercial quantities of proved reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether commercial quantities of proved reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made (see Note 16). Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account. Oil and gas properties are grouped in accordance with the provisions of the Extractive Industries - Oil and Gas Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC). The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. Amortization rates are updated quarterly to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions and/or property dispositions and 4) impairments. When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the asset. If the expected undiscounted future cash flows, based on EOG's estimate of (and assumptions regarding) future crude oil and natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach described in the Fair Value Measurement Topic of the ASC. In certain instances, EOG utilizes accepted offers from third-party purchasers as the basis for determining fair value. Inventories, consisting primarily of tubular goods, materials for completion operations and well equipment held for use in the exploration for, and development and production of, crude oil, natural gas liquids (NGLs) and natural gas reserves, are carried at the lower of cost and net realizable value with adjustments made, as appropriate, to recognize any reductions in value. Revenue Recognition. Effective January 1, 2018, EOG adopted the provisions of Accounting Standards Update (ASU) 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09). ASU 2014-09 and other related ASUs require entities to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. EOG elected to adopt ASU 2014-09 using the modified retrospective approach, which required EOG to recognize in retained earnings the cumulative effect at the date of adoption for all existing contracts with customers which were not substantially complete as of January 1, 2018. There was no impact to retained earnings upon adoption of ASU 2014-09. EOG presents disaggregated revenues by type of commodity within its Consolidated Statements of Income and Comprehensive Income and by geographic areas defined as operating segments. See Note 11. In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements within its United States segment as Gathering and Processing Costs, instead of as a deduction to Revenues within its Consolidated Statements of Income and Comprehensive Income. There was no impact to operating income, net income or cash flows resulting from changes to the presentation of natural gas processing fees. The impacts of the adoption of ASU 2014-09 for the year ended December 31, 2018, were as follows (in thousands): As Reported Amounts Without Adoption of ASU 2014-09 Effect of Change Operating Revenues and Other Crude Oil and Condensate $ 9,517,440 $ 9,517,440 $ — Natural Gas Liquids 1,127,510 1,121,237 6,273 Natural Gas 1,301,537 1,104,095 197,442 Gathering, Processing and Marketing 5,230,355 5,211,136 19,219 Total Operating Revenues and Other 17,275,399 17,052,465 222,934 Operating Expenses Gathering and Processing Costs 436,973 233,258 203,715 Marketing Costs 5,203,243 5,184,024 19,219 Total Operating Expenses 12,806,053 12,583,119 222,934 Operating Income 4,469,346 4,469,346 —
Revenue Recognition	Revenue Recognition. Effective January 1, 2018, EOG adopted the provisions of Accounting Standards Update (ASU) 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09). ASU 2014-09 and other related ASUs require entities to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. EOG elected to adopt ASU 2014-09 using the modified retrospective approach, which required EOG to recognize in retained earnings the cumulative effect at the date of adoption for all existing contracts with customers which were not substantially complete as of January 1, 2018. There was no impact to retained earnings upon adoption of ASU 2014-09. EOG presents disaggregated revenues by type of commodity within its Consolidated Statements of Income and Comprehensive Income and by geographic areas defined as operating segments. See Note 11. In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements within its United States segment as Gathering and Processing Costs, instead of as a deduction to Revenues within its Consolidated Statements of Income and Comprehensive Income. There was no impact to operating income, net income or cash flows resulting from changes to the presentation of natural gas processing fees. The impacts of the adoption of ASU 2014-09 for the year ended December 31, 2018, were as follows (in thousands): As Reported Amounts Without Adoption of ASU 2014-09 Effect of Change Operating Revenues and Other Crude Oil and Condensate $ 9,517,440 $ 9,517,440 $ — Natural Gas Liquids 1,127,510 1,121,237 6,273 Natural Gas 1,301,537 1,104,095 197,442 Gathering, Processing and Marketing 5,230,355 5,211,136 19,219 Total Operating Revenues and Other 17,275,399 17,052,465 222,934 Operating Expenses Gathering and Processing Costs 436,973 233,258 203,715 Marketing Costs 5,203,243 5,184,024 19,219 Total Operating Expenses 12,806,053 12,583,119 222,934 Operating Income 4,469,346 4,469,346 — Revenues are recognized for the sale of crude oil and condensate, NGLs and natural gas at the point control of the product is transferred to the customer, typically when production is delivered and title or risk of loss transfers to the customer. Arrangements for such sales are evidenced by signed contracts with prices typically based on stated market indices, with certain adjustments for product quality and geographic location. As EOG typically invoices customers shortly after performance obligations have been fulfilled, contract assets and contract liabilities are not recognized. The balances of accounts receivable from contracts with customers on January 1, 2019 and December 31, 2019, were $1,460 million and $1,619 million , respectively, and are included in Accounts Receivable, Net on the Consolidated Balance Sheets. Losses incurred on receivables from contracts with customers are infrequent and have been immaterial. Crude Oil and Condensate. EOG sells its crude oil and condensate production at the wellhead or further downstream at a contractually-specified delivery point. Revenue is recognized when control transfers to the customer based on contract terms which reflect prevailing market prices. Any costs incurred prior to the transfer of control, such as gathering and transportation, are recognized as Operating Expenses. Natural Gas Liquids. EOG delivers certain of its natural gas production to either EOG-owned processing facilities or third-party processing facilities, where extraction of NGLs occurs. For EOG-owned facilities, revenue is recognized after processing upon transfer of NGLs to a customer. For third-party facilities, extracted NGLs are sold to the owner of the processing facility at the tailgate, or EOG takes possession and sells the extracted NGLs at the tailgate or exercises its option to sell further downstream to various customers. Under typical arrangements for third-party facilities, revenue is recognized after processing upon the transfer of control of the NGLs, either at the tailgate of the processing plant or further downstream. EOG recognizes revenues based on contract terms which reflect prevailing market prices, with processing fees recognized as Gathering and Processing Costs. Natural Gas. EOG sells its natural gas production either at the wellhead or further downstream at a contractually-specified delivery point. In connection with the extraction of NGLs, EOG sells residue gas under separate agreements. Typically, EOG takes possession of the natural gas at the tailgate of the processing facility and sells it at the tailgate or further downstream. In each case, EOG recognizes revenues when control transfers to the customer, based on contract terms which reflect prevailing market prices. Gathering, Processing and Marketing. Gathering, processing and marketing revenues represent sales of third-party crude oil and condensate, NGLs and natural gas, as well as fees associated with gathering and processing third-party natural gas and revenues from sales of EOG-owned sand. EOG evaluates whether it is the principal or agent under these transactions. As control of the underlying commodity is transferred to EOG prior to the gathering, processing and marketing activities, EOG considers itself the principal of these arrangements. Accordingly, EOG recognizes these transactions on a gross basis. Purchases of third-party commodities are recorded as Marketing Costs, with sales of third-party commodities and fees received for gathering and processing recorded as Gathering, Processing and Marketing revenues.
Other Property, Plant and Equipment	Other Property, Plant and Equipment . Other property, plant and equipment consists of gathering and processing assets, compressors, buildings and leasehold improvements, crude-by-rail assets, sand mine and sand processing assets, computer hardware and software, vehicles, and furniture and fixtures. Other property, plant and equipment is generally depreciated on a straight-line basis over the estimated useful lives of the property, plant and equipment, which range from 3 years to 45 years.
Capitalized Interest Costs	Capitalized Interest Costs. Interest costs have been capitalized as a part of the historical cost of unproved oil and gas properties. The amount capitalized is an allocation of the interest cost incurred during the reporting period. Capitalized interest is computed only during the exploration and development phases and ceases once production begins. The interest rate used for capitalization purposes is based on the interest rates on EOG's outstanding borrowings. The capitalization of interest is excluded on significant acquisitions of unproved oil and gas properties financed through non-interest-bearing instruments, such as the issuance of shares of Common Stock, or through non-cash property exchanges.
Accounting for Risk Management Activities	Accounting for Risk Management Activities. Derivative instruments are recorded on the balance sheet as either an asset or liability measured at fair value, and changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met. During the three-year period ended December 31, 2019, EOG elected not to designate any of its financial commodity derivative instruments as accounting hedges and, accordingly, changes in the fair value of these outstanding derivative instruments are recognized as gains or losses in the period of change. The gains or losses are recorded as Gains (Losses) on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income and Comprehensive Income. The related cash flow impact of settled contracts is reflected as cash flows from operating activities. EOG employs net presentation of derivative assets and liabilities for financial reporting purposes when such assets and liabilities are with the same counterparty and subject to a master netting arrangement. See Note 12.
Income Taxes	Income Taxes. Income taxes are accounted for using the asset and liability approach. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. EOG assesses the realizability of deferred tax assets and recognizes valuation allowances as appropriate. See Note 6.
Foreign Currency Translation	Foreign Currency Translation. The United States dollar is the functional currency for all of EOG's consolidated subsidiaries except for its Canadian subsidiaries, for which the functional currency is the Canadian dollar, and its United Kingdom subsidiary (which was sold in the fourth quarter of 2018), for which the functional currency was the British pound. For subsidiaries whose functional currency is deemed to be other than the United States dollar, asset and liability accounts are translated at year-end exchange rates and revenues and expenses are translated at average exchange rates prevailing during the year. Translation adjustments are included in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets. Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period. See Notes 4 and 17.
Net Income Per Share	Net Income Per Share. Basic net income per share is computed on the basis of the weighted-average number of common shares outstanding during the period. Diluted net income per share is computed based upon the weighted-average number of common shares outstanding during the period plus the assumed issuance of common shares for all potentially dilutive securities. See Note 9.
Stock-Based Compensation	Stock-Based Compensation . EOG measures the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. See Note 7.
Leases	Effective January 1, 2019, EOG adopted the provisions of ASU 2016-02, "Leases (Topic 842)" (ASU 2016-02). ASU 2016-02 and other related ASUs require that lessees recognize a right-of-use (ROU) asset and related lease liability, representing the obligation to make lease payments for certain lease transactions, on the Consolidated Balance Sheets and disclose additional leasing information. EOG elected to adopt ASU 2016-02 and other related ASUs using the modified retrospective approach with a cumulative-effect adjustment to the opening balance of retained earnings as of the effective date. Financial results reported in periods prior to January 1, 2019, are unchanged. Additionally, EOG elected the package of practical expedients within ASU 2016-02 that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases, or (iii) initial direct costs for any existing leases, but did not elect the practical expedient of hindsight when determining the lease term of existing contracts at the effective date. EOG also elected the practical expedient under ASU 2018-01, "Leases (Topic 842) - Land Easement Practical Expedient for Transition to Topic 842," and did not evaluate existing or expired land easements not previously accounted for as leases prior to the January 1, 2019 effective date. There was no impact to retained earnings upon adoption of ASU 2016-02 and other related ASUs. In the ordinary course of business, EOG enters into contracts for drilling, fracturing, compression, real estate and other services which contain equipment and other assets and that meet the definition of a lease under ASU 2016-02. The lease term for these contracts, which includes any renewals at EOG's option that are reasonably certain to be exercised, ranges from one month to 30 years. ROU assets and related liabilities are recognized on the commencement date on the Consolidated Balance Sheets based on future lease payments, discounted based on the rate implicit in the contract, if readily determinable, or EOG's incremental borrowing rate commensurate with the lease term of the contract. EOG estimates its incremental borrowing rate based on the approximate rate required to borrow on a collateralized basis. Contracts with lease terms of less than 12 months are not recorded on the Consolidated Balance Sheets, but instead are disclosed as short-term lease cost. EOG has elected not to separate non-lease components from all leases, excluding those for fracturing services, real estate and salt water disposal, as lease payments under these contracts contain significant non-lease components, such as labor and operating costs. See Note 18.
Recently Issued Accounting Standards and Developments	Recently Issued Accounting Standards. In December 2019, the FASB issued ASU 2019-12, "Income Taxes (Topic 740) ‑ Simplifying the Accounting for Income Taxes" (ASU 2019-12), which amends certain aspects of accounting for income taxes. ASU 2019-12 removes specific exceptions within existing U.S. GAAP related to the incremental approach for intraperiod tax allocation and to the general methodology for calculating income taxes in interim periods, among other changes. ASU 2019-12 also requires an entity to reflect the effect of an enacted change in tax laws or rates in the annual effective tax rate computation in the interim period that includes the enactment date, among other requirements. ASU 2019-12 is effective for interim and annual periods beginning after December 15, 2020, and early adoption is permitted. EOG is continuing to evaluate the provisions of ASU 2019-12 and has not determined the full impact on its consolidated financial statements and related disclosures. In June 2016, the FASB issued ASU 2016-13 "Measurement of Credit Losses on Financial Instruments" (ASU 2016-13). ASU 2016-13 changes the impairment model for financial assets and certain other instruments by requiring entities to adopt a forward-looking expected loss model that will result in earlier recognition of credit losses. ASU 2016-13 requires adoption through the use of a modified retrospective approach at the effective date by recognizing a cumulative-effect adjustment to the opening balance of retained earnings. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019, and early adoption is permitted. EOG has assessed its applicable financial assets, which are primarily its accounts receivable from hydrocarbon sales and joint interest billings to third-party companies, including state-owned entities in the oil and gas industry. Based on its assessment and various potential remedies ensuring collection, EOG does not expect the impact from forward-looking expected losses will be material. EOG will apply the provisions of ASU 2016-13 on the adoption date, January 1, 2020.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Schedule of Impact of Adoption of New Accounting Revenue Recognition Standard (Tables)	The impacts of the adoption of ASU 2014-09 for the year ended December 31, 2018, were as follows (in thousands): As Reported Amounts Without Adoption of ASU 2014-09 Effect of Change Operating Revenues and Other Crude Oil and Condensate $ 9,517,440 $ 9,517,440 $ — Natural Gas Liquids 1,127,510 1,121,237 6,273 Natural Gas 1,301,537 1,104,095 197,442 Gathering, Processing and Marketing 5,230,355 5,211,136 19,219 Total Operating Revenues and Other 17,275,399 17,052,465 222,934 Operating Expenses Gathering and Processing Costs 436,973 233,258 203,715 Marketing Costs 5,203,243 5,184,024 19,219 Total Operating Expenses 12,806,053 12,583,119 222,934 Operating Income 4,469,346 4,469,346 —

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt at December 31, 2019 and 2018 consisted of the following (in thousands): 2019 2018 5.625% Senior Notes due 2019 $ — $ 900,000 4.40% Senior Notes due 2020 500,000 500,000 2.45% Senior Notes due 2020 500,000 500,000 4.100% Senior Notes due 2021 750,000 750,000 2.625% Senior Notes due 2023 1,250,000 1,250,000 3.15% Senior Notes due 2025 500,000 500,000 4.15% Senior Notes due 2026 750,000 750,000 6.65% Senior Notes due 2028 140,000 140,000 3.90% Senior Notes due 2035 500,000 500,000 5.10% Senior Notes due 2036 250,000 250,000 Long-Term Debt 5,140,000 6,040,000 Finance Leases (see Note 18) 57,900 71,571 Less: Current Portion of Long-Term Debt 1,014,524 913,093 Unamortized Debt Discount 19,528 24,640 Debt Issuance Costs 2,929 3,669 Total Long-Term Debt $ 4,160,919 $ 5,170,169

Stockholder's Equity (Tables)

Stockholder's Equity (Tables)	12 Months Ended
	Dec. 31, 2019
Stockholders' Equity Note [Abstract]
Common stock activity	The following summarizes Common Stock activity for each of the years ended December 31, 2017 , 2018 and 2019 (in thousands): Common Shares Issued Treasury Outstanding Balance at December 31, 2016 576,950 (250 ) 576,700 Common Stock Issued Under Stock-Based Compensation Plans 1,878 — 1,878 Treasury Stock Purchased (1) — (686 ) (686 ) Common Stock Issued Under Employee Stock Purchase Plan — 180 180 Treasury Stock Issued Under Stock-Based Compensation Plans — 405 405 Balance at December 31, 2017 578,828 (351 ) 578,477 Common Stock Issued Under Stock-Based Compensation Plans 1,580 — 1,580 Treasury Stock Purchased (1) — (539 ) (539 ) Common Stock Issued Under Employee Stock Purchase Plan — 180 180 Treasury Stock Issued Under Stock-Based Compensation Plans — 325 325 Balance at December 31, 2018 580,408 (385 ) 580,023 Common Stock Issued Under Stock-Based Compensation Plans 1,688 — 1,688 Treasury Stock Purchased (1) — (310 ) (310 ) Common Stock Issued Under Employee Stock Purchase Plan 117 106 223 Treasury Stock Issued Under Stock-Based Compensation Plans — 290 290 Balance at December 31, 2019 582,213 (299 ) 581,914 (1)

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss)	The components of Accumulated Other Comprehensive Loss at December 31, 2019 and 2018 consisted of the following (in thousands): Foreign Currency Translation Adjustment Other Total December 31, 2017 $ (16,642 ) $ (2,655 ) $ (19,297 ) Other comprehensive income before reclassifications 2,451 1,131 3,582 Amounts reclassified out of other comprehensive income (loss) (1) 14,365 — 14,365 Tax effects — (8 ) (8 ) Other comprehensive income 16,816 1,123 17,939 December 31, 2018 174 (1,532 ) (1,358 ) Cumulative effect of accounting changes — 267 267 Other comprehensive loss before reclassifications (2,883 ) (533 ) (3,416 ) Tax effects — (145 ) (145 ) Other comprehensive loss (2,883 ) (678 ) (3,561 ) December 31, 2019 $ (2,709 ) $ (1,943 ) $ (4,652 ) (1) Reclassified to Net Income - Gains (Losses) on Asset Dispositions, Net. See Note 17.

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs	Stock-based compensation expense is included on the Consolidated Statements of Income and Comprehensive Income based upon the job functions of the employees receiving the grants. Compensation expense related to EOG's stock-based compensation plans for the years ended December 31, 2019 , 2018 and 2017 was as follows (in millions): 2019 2018 2017 Lease and Well $ 56 $ 51 $ 41 Gathering and Processing Costs 1 1 1 Exploration Costs 26 25 23 General and Administrative 92 78 69 Total $ 175 $ 155 $ 134
Vesting Schedule	Grant Type Vesting Schedule Stock Options/SARs Vesting in increments of 33%, 33% and 34% on each of the first three anniversaries, respectively, of the date of grant Restricted Stock/Restricted Stock Units "Cliff" vesting three years from the date of grant Performance Units "Cliff" vesting approximately 41 months from the date of grant - specifically, on the February 28 th immediately following the Compensation Committee's certifications contemplated by the form of award agreement governing such grant of performance units
Weighted Average Fair Values and Valuation Assumptions	Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants for the years ended December 31, 2019 , 2018 and 2017 were as follows: Stock Options/SARs ESPP 2019 2018 2017 2019 2018 2017 Weighted Average Fair Value of Grants $ 19.49 $ 33.46 $ 23.95 $ 22.83 $ 25.75 $ 22.20 Expected Volatility 32.02 % 28.23 % 28.28 % 34.78 % 24.59 % 27.12 % Risk-Free Interest Rate 1.69 % 2.68 % 1.52 % 2.27 % 1.89 % 0.88 % Dividend Yield 1.39 % 0.72 % 0.75 % 1.04 % 0.64 % 0.71 % Expected Life 5.1 years 5.0 years 5.1 years 0.5 years 0.5 years 0.5 years
Schedule of Share Based Compensation Arrangement By Share Based Payment Award	The following table sets forth the stock option and SAR transactions for the years ended December 31, 2019 , 2018 and 2017 (stock options and SARs in thousands): 2019 2018 2017 Number Weighted Average Grant Price Number Weighted Average Grant Price Number Weighted Average Grant Price Outstanding at January 1 8,310 $ 96.90 9,103 $ 83.89 9,850 $ 75.53 Granted 1,965 75.39 1,906 126.49 2,274 96.27 Exercised (1) (606 ) 61.43 (2,493 ) 72.21 (2,574 ) 61.12 Forfeited (274 ) 102.57 (206 ) 94.43 (447 ) 93.84 Outstanding at December 31 9,395 94.53 8,310 96.90 9,103 83.89 Stock Options/SARs Exercisable at December 31 5,275 94.21 3,969 85.82 4,510 75.76 (1) The total intrinsic value of stock options/SARs exercised during the years 2019 , 2018 and 2017 was $14 million , $118 million and $95 million , respectively. The intrinsic value is based upon the difference between the market price of the Common Stock on the date of exercise and the grant price of the stock options/SARs.
Stock Options and SARs Outstanding and Exercisable	The following table summarizes certain information for the stock options and SARs outstanding and exercisable at December 31, 2019 (stock options and SARs in thousands): Stock Options/SARs Outstanding Stock Options/SARs Exercisable Range of Grant Prices Stock Weighted Average Remaining Life (Years) Weighted Average Grant Price Aggregate Intrinsic Value (1) Stock Weighted Average Remaining Life (Years) Weighted Average Grant Price Aggregate Intrinsic Value (1) $ 59.00 to $ 74.99 979 3 $ 69.43 953 3 $ 69.37 75.00 to 75.99 1,894 7 75.09 8 1 75.09 76.00 to 95.99 1,979 3 91.35 1,607 2 90.67 96.00 to 96.99 1,871 4 96.29 1,234 4 96.29 97.00 to 125.99 923 2 102.72 862 2 102.20 126.00 to 129.99 1,749 6 127.01 611 5 127.01 9,395 4 94.53 $ 30,534 5,275 3 94.21 $ 13,839 (1) Based upon the difference between the closing market price of the Common Stock on the last trading day of the year and the grant price of in-the-money stock options and SARs.
ESPP Activity	The following table summarizes ESPP activity for the years ended December 31, 2019 , 2018 and 2017 (in thousands, except number of participants): 2019 2018 2017 Approximate Number of Participants 1,998 1,934 1,870 Shares Purchased 224 180 180 Aggregate Purchase Price $ 16,533 $ 14,887 $ 13,997
Restricted Stock and Restricted Stock Unit Transactions	The following table sets forth the restricted stock and restricted stock unit transactions for the years ended December 31, 2019 , 2018 and 2017 (shares and units in thousands): 2019 2018 2017 Number of Shares and Units Weighted Average Grant Date Fair Value Number of Shares and Units Weighted Average Grant Date Fair Value Number of Shares and Units Weighted Average Grant Date Fair Value Outstanding at January 1 3,792 $ 96.64 3,905 $ 88.57 3,962 $ 79.63 Granted 1,749 80.01 812 117.55 1,095 97.34 Released (1) (855 ) 96.93 (740 ) 78.16 (929 ) 61.51 Forfeited (140 ) 97.54 (185 ) 92.12 (223 ) 85.45 Outstanding at December 31 (2) 4,546 90.16 3,792 96.64 3,905 88.57 (1) The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2019, 2018 and 2017 was $70 million , $84 million and $91 million , respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date restricted stock and restricted stock units are released. (2) The total intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2019, 2018 and 2017 was $381 million , $331 million and $421 million
Weighted Average Fair Values and Valuation Assumptions for Performance Units/Stocks	Weighted average fair values and valuation assumptions used to value Performance Awards during the years ended December 31, 2019 , 2018 and 2017 were as follows: 2019 2018 2017 Weighted Average Fair Value of Grants $ 79.98 $ 136.74 $ 113.81 Expected Volatility 29.20 % 29.92 % 32.19 % Risk-Free Interest Rate 1.51 % 2.85 % 1.60 %
Performance Unit and Performance Stock Transactions	The following table sets forth the Performance Award transactions for the years ended December 31, 2019 , 2018 and 2017 (shares and units in thousands): 2019 2018 2017 Number of Units and Shares Weighted Average Price per Grant Date Number of Units and Shares Weighted Average Price per Grant Date Number of Units and Shares Weighted Average Price per Grant Date Outstanding at January 1 539 $ 101.53 502 $ 90.96 545 $ 80.92 Granted 172 75.09 113 125.73 78 96.29 Granted for Performance Multiple (1) 72 69.43 72 101.87 119 84.43 Released (2) (185 ) 94.63 (148 ) 84.43 (240 ) 66.69 Forfeited — — — — — — Outstanding at December 31 (3) 598 (4 ) 92.19 539 101.53 502 90.96 (1) Upon completion of the Performance Period for the Performance Awards granted in 2015, 2014 and 2013, a performance multiple of 200% was applied to each of the grants resulting in additional grants of Performance Awards in February 2019, 2018 and 2017. (2) The total intrinsic value of Performance Awards released during the years ended December 31, 2019, 2018 and 2017 was $15 million , $18 million and $24 million , respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date Performance Awards are released. (3) The total intrinsic value of Performance Awards outstanding at December 31, 2019, 2018 and 2017 was $50 million , $47 million and $54 million , respectively. The intrinsic value is based on the closing market price of the Common Stock on the last trading day of the year. (4) Upon the application of the relevant performance multiple at the completion of each of the remaining Performance Periods, a minimum of 102 and a maximum of 1,094 Performance Awards could be outstanding.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Deferred Income Tax Liabilities, Net	The principal components of EOG's total net deferred income tax liabilities at December 31, 2019 and 2018 were as follows (in thousands): 2019 2018 Deferred Income Tax Assets (Liabilities) Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization $ 5,825 $ 4,359 Foreign Net Operating Loss 66,675 55,175 Foreign Valuation Allowances (70,455 ) (58,932 ) Foreign Other 318 175 Total Net Deferred Income Tax Assets $ 2,363 $ 777 Deferred Income Tax (Assets) Liabilities Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization $ 5,277,550 $ 4,583,517 (1) Commodity Hedging Contracts (4,699 ) 4,883 Deferred Compensation Plans (47,650 ) (39,086 ) Accrued Expenses and Liabilities (8,502 ) (19,097 ) Equity Awards (108,324 ) (93,977 ) Alternative Minimum Tax Credit Carryforward (31,904 ) — Undistributed Foreign Earnings 15,746 22,945 Other (46,116 ) (45,787 ) Total Net Deferred Income Tax Liabilities $ 5,046,101 $ 4,413,398 Total Net Deferred Income Tax Liabilities $ 5,043,738 $ 4,412,621
Components of Income (Loss) Before Income Taxes	he components of Income Before Income Taxes for the years indicated below were as follows (in thousands): 2019 2018 2017 United States $ 3,466,578 $ 4,084,156 $ 621,610 Foreign 78,689 156,842 39,572 Total $ 3,545,267 $ 4,240,998 $ 661,182
Components of Income Tax Provision (Benefit)	The principal components of EOG's Income Tax Provision (Benefit) for the years indicated below were as follows (in thousands): 2019 2018 2017 Current: Federal $ (152,258 ) $ (303,853 ) $ 33,058 State 10,819 17,048 (2,502 ) Foreign 81,426 65,615 35,323 Total (60,013 ) (221,190 ) 65,879 Deferred: Federal 626,901 862,075 (1,504,288 ) State 32,541 43,293 26,942 Foreign (27,784 ) (11,212 ) 3,474 Total 631,658 894,156 (1,473,872 ) Other Non-Current: (1) Federal 245,125 148,992 (513,404 ) Foreign (6,413 ) — — Total 238,712 148,992 (513,404 ) Income Tax Provision (Benefit) $ 810,357 $ 821,958 $ (1,921,397 ) (1)
Tax Rate Reconciliation	The differences between taxes computed at the U.S. federal statutory tax rate and EOG's effective rate for the years indicated below were as follows: 2019 2018 2017 Statutory Federal Income Tax Rate 21.00 % 21.00 % 35.00 % State Income Tax, Net of Federal Benefit 0.97 1.12 3.38 Income Tax Provision Related to Foreign Operations 0.87 0.51 (0.30 ) Income Tax Provision Related to United Kingdom Operations — — 1.78 Income Tax Provision Related to Canadian Operations — — 2.30 TCJA (1) — (2.60 ) (2) (328.10 ) (3) Share-Based Compensation 0.02 (0.47 ) (4.63 ) Other — (0.18 ) (0.03 ) Effective Income Tax Rate 22.86 % 19.38 % (290.60 )% (1) The enactment of the Tax Cuts and Jobs Act (TCJA) by the United States in 2017 made numerous changes to federal tax law. Several changes which had a significant impact on EOG include the corporate income tax rate reduction from 35% to 21%, the imposition of a one-time repatriation tax on undistributed foreign earnings and the repeal of the corporate AMT regime (AMT credit carryforwards became refundable over the following four years and were initially subject to a federal sequestration charge). In 2017, EOG revalued its federal deferred income tax assets and liabilities resulting in an earnings benefit of over $2 billion and a substantial reduction of the 2017 effective tax rate. The TCJA measurement-period adjustments were recorded in 2018. (2) Includes impact of utilizing certain tax net operating losses (NOLs) ( (1.2)% ), the reversal of sequestration ( (1.0)% ) and other tax reform impacts ( (0.4)% ). (3) Includes impact of the federal rate reduction ( (327.8)% ), federal repatriation tax ( (6.6)% ), sequestration ( (6.4)% ) and other tax reform impacts ( (0.1)% ).
Summary of Valuation Allowance	The principal components of EOG's rollforward of valuation allowances for deferred income tax assets for the years indicated below were as follows (in thousands): 2019 2018 2017 Beginning Balance $ 167,142 $ 466,421 $ 383,221 Increase (1) 30,673 23,062 67,333 Decrease (2) (75 ) (26,219 ) (13,687 ) Other (3) 3,091 (296,122 ) 29,554 Ending Balance $ 200,831 $ 167,142 $ 466,421 (1) Increase in valuation allowance related to the generation of tax NOLs and other deferred tax assets. (2) Decrease in valuation allowance associated with adjustments to certain deferred tax assets and their related allowance. (3) Represents dispositions, revisions and/or foreign exchange rate variances and the effect of statutory income tax rate changes. The United Kingdom operations were sold in the fourth quarter of 2018.

Commitments and Contingencies_2

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Minimum commitments for unrecorded unconditional purchase obligations	At December 31, 2019 , total minimum commitments from purchase and service obligations and transportation and storage service commitments not qualifying as leases, based on current transportation and storage rates and the foreign currency exchange rates used to convert Canadian dollars into United States dollars at December 31, 2019 , were as follows (in millions): Total Minimum Commitments 2020 $ 1,312 2021 1,103 2022 1,027 2023 764 2024 519 2025 and beyond 2,531 $ 7,256

Net Income Per Share (Tables)

Net Income Per Share (Tables)	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
Computation of Net Income (Loss) Per Share	The following table sets forth the computation of Net Income Per Share for the years ended December 31, 2019 , 2018 and 2017 (in thousands, except per share data): 2019 2018 2017 Numerator for Basic and Diluted Earnings per Share - Net Income $ 2,734,910 $ 3,419,040 $ 2,582,579 Denominator for Basic Earnings per Share - Weighted Average Shares 577,670 576,578 574,620 Potential Dilutive Common Shares - Stock Options/SARs 258 1,137 1,466 Restricted Stock/Units and Performance Units 2,849 2,726 2,607 Denominator for Diluted Earnings per Share - Adjusted Diluted Weighted Average Shares 580,777 580,441 578,693 Net Income Per Share Basic $ 4.73 $ 5.93 $ 4.49 Diluted $ 4.71 $ 5.89 $ 4.46

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2019
Supplemental Cash Flow Information [Abstract]
Net Cash Paid For Interest and Income Taxes	Net cash paid (received) for interest and income taxes was as follows for the years ended December 31, 2019, 2018 and 2017 (in thousands): 2019 2018 2017 Interest, Net of Capitalized Interest $ 186,546 $ 243,279 $ 275,305 Income Taxes, Net of Refunds Received $ (291,849 ) $ 75,634 $ 188,946

Business Segment Information (T

Business Segment Information (Tables)	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
Selected Financial Information by Reportable Segment	Financial information by reportable segment is presented below as of and for the years ended December 31, 2019, 2018 and 2017 (in thousands): United States Trinidad Other International (1) Total 2019 Crude Oil and Condensate $ 9,599,125 $ 11,138 $ 2,269 $ 9,612,532 Natural Gas Liquids 784,818 — — 784,818 Natural Gas 866,911 258,819 58,365 1,184,095 Gains on Mark-to-Market Commodity Derivative Contracts 180,275 — — 180,275 Gathering, Processing and Marketing 5,355,463 4,819 — 5,360,282 Gains (Losses) on Asset Dispositions, Net 131,446 (3,688 ) (4,145 ) 123,613 Other, Net 134,325 18 15 134,358 Operating Revenues and Other (2) 17,052,363 271,106 56,504 17,379,973 Depreciation, Depletion and Amortization 3,652,294 79,389 18,021 3,749,704 Operating Income (Loss) 3,618,907 112,790 (32,686 ) 3,699,011 Interest Income 22,122 3,686 218 26,026 Other Income 3,235 727 1,397 5,359 Net Interest Expense 192,587 — (7,458 ) 185,129 Income (Loss) Before Income Taxes 3,451,677 117,203 (23,613 ) 3,545,267 Income Tax Provision 760,881 40,901 8,575 810,357 Additions to Oil and Gas Properties, Excluding Dry Hole Costs 6,208,394 53,325 12,233 6,273,952 Total Property, Plant and Equipment, Net 30,101,857 184,606 78,132 30,364,595 Total Assets 36,274,942 705,747 143,919 37,124,608 United States Trinidad Other International (1) Total 2018 Crude Oil and Condensate $ 9,390,244 $ 17,059 $ 110,137 $ 9,517,440 Natural Gas Liquids 1,127,510 — — 1,127,510 Natural Gas 970,866 285,053 45,618 1,301,537 Losses on Mark-to-Market Commodity Derivative Contracts (165,640 ) — — (165,640 ) Gathering, Processing and Marketing 5,227,051 3,304 — 5,230,355 Gains on Asset Dispositions, Net 154,852 4,493 15,217 174,562 Other, Net 89,708 (49 ) (24 ) 89,635 Operating Revenues and Other (3) 16,794,591 309,860 170,948 17,275,399 Depreciation, Depletion and Amortization 3,296,499 91,971 46,938 3,435,408 Operating Income (Loss) 4,334,364 147,240 (12,258 ) 4,469,346 Interest Income 9,326 1,612 608 11,546 Other Income (Expense) 9,580 2,436 (6,858 ) 5,158 Net Interest Expense 253,352 — (8,300 ) 245,052 Income (Loss) Before Income Taxes 4,099,918 151,288 (10,208 ) 4,240,998 Income Tax Provision 765,986 54,272 1,700 821,958 Additions to Oil and Gas Properties, Excluding Dry Hole Costs 6,155,874 1,618 37,838 6,195,330 Total Property, Plant and Equipment, Net 27,786,086 210,183 79,250 28,075,519 Total Assets 33,178,733 629,633 126,108 33,934,474 2017 Crude Oil and Condensate $ 6,225,711 $ 13,572 $ 17,113 $ 6,256,396 Natural Gas Liquids 729,545 — 16 729,561 Natural Gas 615,512 271,101 35,321 921,934 Gains on Mark-to-Market Commodity Derivative Contracts 19,828 — — 19,828 Gathering, Processing and Marketing 3,298,098 (11 ) — 3,298,087 Losses on Asset Dispositions, Net (98,233 ) (8 ) (855 ) (99,096 ) Other, Net 81,610 59 (59 ) 81,610 Operating Revenues and Other (4) 10,872,071 284,713 51,536 11,208,320 Depreciation, Depletion and Amortization 3,269,196 115,321 24,870 3,409,387 Operating Income (Loss) 933,571 101,010 (108,179 ) 926,402 Interest Income 3,223 2,201 2,289 7,713 Other Income (Expense) (9,659 ) 3,337 7,761 1,439 Net Interest Expense 303,941 — (29,569 ) 274,372 Income (Loss) Before Income Taxes 623,194 106,548 (68,560 ) 661,182 Income Tax Provision (Benefit) (1,964,343 ) 38,798 4,148 (1,921,397 ) Additions to Oil and Gas Properties, Excluding Dry Hole Costs 4,067,359 145,937 14,932 4,228,228 Total Property, Plant and Equipment, Net 25,125,427 313,357 226,253 25,665,037 Total Assets 28,312,599 974,477 546,002 29,833,078 (1) Other International primarily consists of EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018. (2) EOG had sales activity with two significant purchasers in 2019, one totaling $2.4 billion , and the other totaling $2.2 billion of consolidated Operating Revenues and Other in the United States segment. (3) EOG had sales activity with two significant purchasers in 2018, one totaling $2.6 billion and the other totaling $2.3 billion of consolidated Operating Revenues and Other in the United States segment. (4) EOG had sales activity with two significant purchasers in 2017, one totaling $1.5 billion and the other totaling $1.3 billion of consolidated Operating Revenues and Other in the United States segment.

Risk Management Activities (Tab

Risk Management Activities (Tables)	12 Months Ended
	Dec. 31, 2019
Derivatives, Fair Value [Line Items]
Schedule of Derivative Instruments In Statement Of Financial Position, Fair Value	The following table sets forth the amounts and classification of EOG's outstanding derivative financial instruments at December 31, 2019 and 2018 , respectively. Certain amounts may be presented on a net basis on the consolidated financial statements when such amounts are with the same counterparty and subject to a master netting arrangement (in thousands): Fair Value at December 31, Description Location on Balance Sheet 2019 2018 Asset Derivatives Crude oil, NGLs and natural gas derivative contracts - Current portion Assets from Price Risk Management Activities (1) $ 1,299 $ 23,806 Liability Derivatives Crude oil, NGLs and natural gas derivative contracts - Current portion Liabilities from Price Risk Management Activities (2) $ 20,194 $ — (1) The current portion of Assets from Price Risk Management Activities consists of gross assets of $3 million , partially offset by gross liabilities of $2 million , at December 31, 2019. (2) The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $23 million , partially offset by gross assets of $3 million at December 31, 2019.
Crude Oil [Member] | Midland Differential Basis Swap [Member]
Derivatives, Fair Value [Line Items]
Schedule of Derivative Instruments	Presented below is a comprehensive summary of EOG's Midland Differential basis swap contracts for the year ended December 31, 2019. The weighted average price differential expressed in dollars per barrel ($/Bbl) represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in barrels per day (Bbld) covered by the basis swap contracts. Midland Differential Basis Swap Contracts Volume (Bbld) Weighted Average Price Differential ($/Bbl) 2019 January 1, 2019 through December 31, 2019 (closed) 20,000 $ 1.075
Crude Oil [Member] | Gulf Coast Differential Basis Swap [Member]
Derivatives, Fair Value [Line Items]
Schedule of Derivative Instruments	Presented below is a comprehensive summary of EOG's Gulf Coast Differential basis swap contracts for the year ended December 31, 2019. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. Gulf Coast Differential Basis Swap Contracts Volume (Bbld) Weighted Average Price Differential ($/Bbl) 2019 January 1, 2019 through December 31, 2019 (closed) 13,000 $ 5.572
Crude Oil [Member] | Price Swap [Member]
Derivatives, Fair Value [Line Items]
Schedule of Derivative Instruments	Presented below is a comprehensive summary of EOG's crude oil price swap contracts for the year ended December 31, 2019, with notional volumes expressed in Bbld and prices expressed in $/Bbl. Crude Oil Price Swap Contracts Volume (Bbld) Weighted Average Price ($/Bbl) 2019 April 2019 (closed) 25,000 $ 60.00 May 1, 2019 through December 31, 2019 (closed) 150,000 62.50 2020 January 1, 2020 through March 31, 2020 200,000 $ 59.33 April 1, 2020 through June 30, 2020 150,000 59.03 July 1, 2020 through September 30, 2020 50,000 58.32
Mont Belvieu Propane Price Swap [Member] | Price Swap [Member]
Derivatives, Fair Value [Line Items]
Schedule of Derivative Instruments	Presented below is a comprehensive summary of EOG's Mont Belvieu propane (non-TET) price swap contracts for the year ended December 31, 2019, with notional volumes expressed in Bbld and prices expressed in $/Bbl. Mont Belvieu Propane Price Swap Contracts Volume (Bbld) Weighted Average Price ($/Bbl) 2020 January 1, 2020 through December 31, 2020 4,000 $ 21.34
Natural Gas [Member] | Price Swap [Member]
Derivatives, Fair Value [Line Items]
Schedule of Derivative Instruments	Presented below is a comprehensive summary of EOG's natural gas price swap contracts for the year ended December 31, 2019, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu). Natural Gas Price Swap Contracts Volume (MMBtud) Weighted Average Price ($/MMBtu) 2019 April 1, 2019 through October 31, 2019 (closed) 250,000 $ 2.90
Natural Gas [Member] | Rockies Differential Basis Swaps [Member]
Derivatives, Fair Value [Line Items]
Schedule of Derivative Instruments	Presented below is a comprehensive summary of EOG's Rockies Differential basis swap contracts for the year ended December 31, 2019. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts. Rockies Differential Basis Swap Contracts Volume (MMBtud) Weighted Average Price Differential ($/MMBtu) 2020 January 1, 2020 through December 31, 2020 30,000 $ 0.55
Natural Gas [Member] | HSC Differential Basis Swaps [Member]
Derivatives, Fair Value [Line Items]
Schedule of Derivative Instruments	Presented below is a comprehensive summary of EOG's HSC Differential basis swap contracts for the year ended December 31, 2019. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts. HSC Differential Basis Swap Contracts Volume (MMBtud) Weighted Average Price Differential ($/MMBtu) 2020 January 1, 2020 through December 31, 2020 60,000 $ 0.05
Natural Gas [Member] | Waha Differential Basis Swaps [Member]
Derivatives, Fair Value [Line Items]
Schedule of Derivative Instruments	Presented below is a comprehensive summary of EOG's Waha Differential basis swap contracts for the year ended December 31, 2019. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts. Waha Differential Basis Swap Contracts Volume (MMBtud) Weighted Average Price Differential ($/MMBtu) 2020 January 1, 2020 through December 31, 2020 50,000 $ 1.40

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value Assets and Liabilities Measured On Recurring Basis	The following table provides fair value measurement information within the fair value hierarchy for certain of EOG's financial assets and liabilities carried at fair value on a recurring basis at December 31, 2019 and 2018 . Amounts shown in thousands. Fair Value Measurements Using: Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total At December 31, 2019 Financial Assets (1) : Natural Gas Liquids Swaps $ — $ 3,401 $ — $ 3,401 Natural Gas Basis Swaps — 970 — 970 Financial Liabilities (2) : Crude Oil Swaps — 23,266 — 23,266 At December 31, 2018 Financial Assets (1) : Crude Oil Swaps $ — $ 23,806 $ — $ 23,806

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligations, Noncurrent [Abstract]
Asset Retirement Obligation Rollforward Analysis	The following table presents the reconciliation of the beginning and ending aggregate carrying amounts of short-term and long-term legal obligations associated with the retirement of property, plant and equipment for the years ended December 31, 2019 and 2018 (in thousands): 2019 2018 Carrying Amount at Beginning of Period $ 954,377 $ 946,848 Liabilities Incurred 98,874 79,057 Liabilities Settled (1) (58,673 ) (70,829 ) Accretion 43,462 36,622 Revisions 72,425 (38,932 ) Foreign Currency Translations 245 1,611 Carrying Amount at End of Period $ 1,110,710 $ 954,377 Current Portion $ 37,127 $ 26,214 Noncurrent Portion $ 1,073,583 $ 928,163 (1) Includes settlements related to asset sales.

Exploratory Well Costs (Tables)

Exploratory Well Costs (Tables)	12 Months Ended
	Dec. 31, 2019
Capitalized Exploratory Well Costs [Abstract]
Net Changes in Capitalized Exploratory Well Costs	EOG's net changes in capitalized exploratory well costs for the years ended December 31, 2019, 2018 and 2017 are presented below (in thousands): 2019 2018 2017 Balance at January 1 $ 4,121 $ 2,167 $ — Additions Pending the Determination of Proved Reserves 83,175 10,304 27,487 Reclassifications to Proved Properties (39,325 ) (7,917 ) (20,802 ) Costs Charged to Expense (1) (22,074 ) (433 ) (4,518 ) Balance at December 31 $ 25,897 $ 4,121 $ 2,167 (1) Includes capitalized exploratory well costs charged to either dry hole costs or impairments.

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Lease	The components of lease cost for the year ended December 31, 2019, were as follows (in millions): Year Ended December 31, 2019 Operating Lease Cost $ 497 Finance Lease Cost: Amortization of Lease Assets 13 Interest on Lease Liabilities 2 Variable Lease Cost 138 Short-Term Lease Cost 333 Total Lease Cost $ 983
Outstanding Lease Assets And Lease Liabilities	The following table sets forth the amounts and classification of EOG's outstanding ROU assets and related lease liabilities and supplemental information at December 31, 2019 (in millions, except lease terms and discount rates): Description Location on Balance Sheet Amount Assets Operating Leases Other Assets $ 773 Finance Leases Property, Plant and Equipment, Net (1) 53 Total $ 826 Liabilities Current Operating Leases Current Portion of Operating Lease Liabilities $ 369 Finance Leases Current Portion of Long-Term Debt 15 Long-Term Operating Leases Other Liabilities 430 Finance Leases Long-Term Debt 43 Total $ 857 (1) Finance lease assets are recorded net of accumulated amortization of $60 million at December 31, 2019.
Weighted Average Remaining Lease Term And Discount Rate	Year Ended December 31, 2019 Weighted Average Remaining Lease Term (in years): Operating Leases 3.2 Finance Leases 4.7 Weighted Average Discount Rate: Operating Leases 3.5 % Finance Leases 3.0 %
Cash Paid for Leases	Cash paid for leases was as follows for the year ended December 31, 2019 (in millions): Year Ended December 31, 2019 Repayment of Operating Lease Liabilities Associated with Operating Activities $ 225 Repayment of Operating Lease Liabilities Associated with Investing Activities 270 Repayment of Finance Lease Liabilities 13
Operating And Finance Non-Cancellable Leases Maturity	At December 31, 2019, the future minimum lease payments under non-cancellable leases were as follows (in millions): Operating Leases Finance Leases 2020 $ 390 $ 15 2021 209 15 2022 126 12 2023 56 8 2024 29 8 2025 and Beyond 40 6 Total Lease Payments 850 64 Less: Discount to Present Value 51 6 Total Lease Liabilities 799 58 Less: Current Portion of Lease Liabilities 369 15 Long-Term Lease Liabilities $ 430 $ 43
Prior To Adoption Operating And Finance Non-Cancellable Leases Maturity	At December 31, 2018 and prior to the adoption of ASU 2016-02 and other related ASUs, the future minimum commitments under non-cancellable leases, including non-lease components and excluding contracts with lease terms of less than 12 months, were as follows (in millions): Operating Leases Finance Leases 2019 $ 380 $ 15 2020 213 15 2021 86 15 2022 39 12 2023 30 8 2024 and Beyond 62 14 Total Lease Payments $ 810 $ 79

Oil and Gas Exploration and P_2

Oil and Gas Exploration and Production Industries Disclosures (Tables)	12 Months Ended
	Dec. 31, 2019
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Net Proved and Proved Developed Oil and Gas Reserve Quantities	The following tables set forth EOG's net proved reserves at December 31 for each of the four years in the period ended December 31, 2019 , and the changes in the net proved reserves for each of the three years in the period ended December 31, 2019 , as estimated by the Engineering and Acquisitions Department of EOG: NET PROVED RESERVE SUMMARY United States Trinidad Other International (1) Total NET PROVED RESERVES Crude Oil (MBbl) (2) Net proved reserves at December 31, 2016 1,168,491 839 8,255 1,177,585 Revisions of previous estimates 57,935 80 (179 ) 57,836 Purchases in place 1,111 — — 1,111 Extensions, discoveries and other additions 207,137 301 119 207,557 Sales in place (8,393 ) — — (8,393 ) Production (122,210 ) (322 ) (191 ) (122,723 ) Net proved reserves at December 31, 2017 1,304,071 898 8,004 1,312,973 Revisions of previous estimates (13,237 ) (183 ) 44 (13,376 ) Purchases in place 2,743 — — 2,743 Extensions, discoveries and other additions 383,003 — 15 383,018 Sales in place (768 ) — (6,310 ) (7,078 ) Production (144,128 ) (298 ) (1,542 ) (145,968 ) Net proved reserves at December 31, 2018 1,531,684 417 211 1,532,312 Revisions of previous estimates (42,959 ) 85 (8 ) (42,882 ) Purchases in place 2,859 — — 2,859 Extensions, discoveries and other additions 369,968 — 28 369,996 Sales in place (1,282 ) — — (1,282 ) Production (166,310 ) (236 ) (40 ) (166,586 ) Net proved reserves at December 31, 2019 1,693,960 266 191 1,694,417 Natural Gas Liquids (MBbl) (2) Net proved reserves at December 31, 2016 416,366 — — 416,366 Revisions of previous estimates 46,843 — — 46,843 Purchases in place 421 — — 421 Extensions, discoveries and other additions 75,003 — — 75,003 Sales in place (2,887 ) — — (2,887 ) Production (32,273 ) — — (32,273 ) Net proved reserves at December 31, 2017 503,473 — — 503,473 Revisions of previous estimates 23,942 — — 23,942 Purchases in place 2,006 — — 2,006 Extensions, discoveries and other additions 127,409 — — 127,409 Sales in place (41 ) — — (41 ) Production (42,460 ) — — (42,460 ) Net proved reserves at December 31, 2018 614,329 — — 614,329 Revisions of previous estimates 5,380 — — 5,380 Purchases in place 1,948 — — 1,948 Extensions, discoveries and other additions 167,782 — — 167,782 Sales in place (855 ) — — (855 ) Production (48,892 ) — — (48,892 ) Net proved reserves at December 31, 2019 739,692 — — 739,692 United States Trinidad Other International (1) Total Natural Gas (Bcf) (3) Net proved reserves at December 31, 2016 3,021.2 280.9 15.8 3,317.9 Revisions of previous estimates 602.8 (27.4 ) 8.6 584.0 Purchases in place 4.8 — — 4.8 Extensions, discoveries and other additions 619.3 174.2 35.9 829.4 Sales in place (56.4 ) — — (56.4 ) Production (293.2 ) (114.3 ) (9.1 ) (416.6 ) Net proved reserves at December 31, 2017 3,898.5 313.4 51.2 4,263.1 Revisions of previous estimates (127.2 ) 20.7 15.0 (91.5 ) Purchases in place 41.3 — — 41.3 Extensions, discoveries and other additions 951.4 — 4.6 956.0 Sales in place (22.2 ) — — (22.2 ) Production (351.2 ) (97.1 ) (11.2 ) (459.5 ) Net proved reserves at December 31, 2018 4,390.6 237.0 59.6 4,687.2 Revisions of previous estimates (184.4 ) 47.0 2.6 (134.8 ) Purchases in place 71.7 — — 71.7 Extensions, discoveries and other additions 1,175.9 87.5 9.7 1,273.1 Sales in place (14.5 ) — — (14.5 ) Production (404.5 ) (95.4 ) (13.1 ) (513.0 ) Net proved reserves at December 31, 2019 5,034.8 276.1 58.8 5,369.7 Oil Equivalents (MBoe) (2) Net proved reserves at December 31, 2016 2,088,392 47,661 10,880 2,146,933 Revisions of previous estimates 205,262 (4,493 ) 1,249 202,018 Purchases in place 2,332 — — 2,332 Extensions, discoveries and other additions 385,354 29,340 6,104 420,798 Sales in place (20,687 ) — — (20,687 ) Production (203,351 ) (19,366 ) (1,707 ) (224,424 ) Net proved reserves at December 31, 2017 2,457,302 53,142 16,526 2,526,970 Revisions of previous estimates (10,500 ) 3,272 2,544 (4,684 ) Purchases in place 11,640 — — 11,640 Extensions, discoveries and other additions 668,972 — 778 669,750 Sales in place (4,509 ) — (6,310 ) (10,819 ) Production (245,127 ) (16,478 ) (3,406 ) (265,011 ) Net proved reserves at December 31, 2018 2,877,778 39,936 10,132 2,927,846 Revisions of previous estimates (68,317 ) 7,915 431 (59,971 ) Purchases in place 16,761 — — 16,761 Extensions, discoveries and other additions 733,730 14,577 1,661 749,968 Sales in place (4,555 ) — — (4,555 ) Production (282,619 ) (16,130 ) (2,232 ) (300,981 ) Net proved reserves at December 31, 2019 3,272,778 46,298 9,992 3,329,068 (1) Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018. (2) Thousand barrels or thousand barrels of oil equivalent, as applicable; oil equivalents include crude oil and condensate, NGLs and natural gas. Oil equivalents are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. (3) Billion cubic feet.
Net Proved Developed and Net Proved Undeveloped Oil and Gas Reserve Quantities	United States Trinidad Other International (1) Total NET PROVED DEVELOPED RESERVES Crude Oil (MBbl) December 31, 2016 507,531 839 8,255 516,625 December 31, 2017 605,405 898 7,933 614,236 December 31, 2018 712,218 417 150 712,785 December 31, 2019 801,189 266 143 801,598 Natural Gas Liquids (MBbl) December 31, 2016 230,219 — — 230,219 December 31, 2017 286,872 — — 286,872 December 31, 2018 341,386 — — 341,386 December 31, 2019 387,253 — — 387,253 Natural Gas (Bcf) December 31, 2016 1,804.4 262.2 15.8 2,082.4 December 31, 2017 2,450.8 299.2 29.3 2,779.3 December 31, 2018 2,699.0 223.9 40.9 2,963.8 December 31, 2019 2,974.6 177.7 41.8 3,194.1 Oil Equivalents (MBoe) December 31, 2016 1,038,483 44,543 10,880 1,093,906 December 31, 2017 1,300,758 50,779 12,798 1,364,335 December 31, 2018 1,503,441 37,746 6,950 1,548,137 December 31, 2019 1,684,209 29,886 7,117 1,721,212 NET PROVED UNDEVELOPED RESERVES Crude Oil (MBbl) December 31, 2016 660,690 — — 660,690 December 31, 2017 698,666 — 71 698,737 December 31, 2018 819,466 — 61 819,527 December 31, 2019 892,771 — 48 892,819 Natural Gas Liquids (MBbl) December 31, 2016 186,147 — — 186,147 December 31, 2017 216,601 — — 216,601 December 31, 2018 272,943 — — 272,943 December 31, 2019 352,439 — — 352,439 Natural Gas (Bcf) December 31, 2016 1,216.8 18.7 — 1,235.5 December 31, 2017 1,447.7 14.2 21.9 1,483.8 December 31, 2018 1,691.6 13.1 18.7 1,723.4 December 31, 2019 2,060.2 98.4 17.0 2,175.6 Oil Equivalents (MBoe) December 31, 2016 1,049,909 3,118 — 1,053,027 December 31, 2017 1,156,544 2,363 3,728 1,162,635 December 31, 2018 1,374,337 2,190 3,182 1,379,709 December 31, 2019 1,588,569 16,412 2,875 1,607,856 (1) Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.
Net Proved Undeveloped Reserves	The following table presents the changes in EOG's total proved undeveloped reserves during 2019 , 2018 and 2017 (in MBoe): 2019 2018 2017 Balance at January 1 1,379,709 1,162,635 1,053,027 Extensions and Discoveries 578,317 490,725 237,378 Revisions (49,837 ) (8,244 ) 33,127 Acquisition of Reserves 1,711 311 — Sale of Reserves — — (8,253 ) Conversion to Proved Developed Reserves (302,044 ) (265,718 ) (152,644 ) Balance at December 31 1,607,856 1,379,709 1,162,635
Capitalized Costs Relating to Oil and Gas Producing Activities	The following table sets forth the capitalized costs relating to EOG's crude oil, NGLs and natural gas producing activities at December 31, 2019 and 2018 : 2019 2018 Proved properties $ 59,229,686 $ 53,624,809 Unproved properties 3,600,729 3,705,207 Total 62,830,415 57,330,016 Accumulated depreciation, depletion and amortization (35,033,085 ) (31,674,085 ) Net capitalized costs $ 27,797,330 $ 25,655,931
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities	The following table sets forth costs incurred related to EOG's oil and gas activities for the years ended December 31, 2019 , 2018 and 2017 : United States Trinidad Other International (1) Total 2019 Acquisition Costs of Properties Unproved (2) $ 276,092 $ — $ — $ 276,092 Proved (3) 379,938 — — 379,938 Subtotal 656,030 — — 656,030 Exploration Costs 213,505 46,616 13,218 273,339 Development Costs (4) 5,661,753 25,007 12,096 5,698,856 Total $ 6,531,288 $ 71,623 $ 25,314 $ 6,628,225 2018 Acquisition Costs of Properties Unproved (5) $ 486,081 $ 1,258 $ — $ 487,339 Proved (6) 123,684 — — 123,684 Subtotal 609,765 1,258 — 611,023 Exploration Costs 157,222 22,511 13,895 193,628 Development Costs (7) 5,605,264 (12,863 ) 22,628 5,615,029 Total $ 6,372,251 $ 10,906 $ 36,523 $ 6,419,680 2017 Acquisition Costs of Properties Unproved (8) $ 424,118 $ 2,422 $ — $ 426,540 Proved (9) 72,584 — — 72,584 Subtotal 496,702 2,422 — 499,124 Exploration Costs 144,499 62,547 16,553 223,599 Development Costs (10) 3,590,899 109,491 16,297 3,716,687 Total $ 4,232,100 $ 174,460 $ 32,850 $ 4,439,410 (1) Other International primarily consists of EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018. (2) Includes non-cash unproved leasehold acquisition costs of $98 million related to property exchanges. (3) Includes non-cash proved property acquisition costs of $52 million related to property exchanges. (4) Includes Asset Retirement Costs of $181 million, $1 million and $4 million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment. (5) Includes non-cash unproved leasehold acquisition costs of $291 million related to property exchanges. (6) Includes non-cash proved property acquisition costs of $71 million related to property exchanges. (7) Includes Asset Retirement Costs of $90 million, $(12) million and $(8) million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment. (8) Includes non-cash unproved leasehold acquisition costs of $256 million related to property exchanges. (9) Includes non-cash proved property acquisition costs of $26 million related to property exchanges. (10) Includes Asset Retirement Costs of $50 million, $2 million and $4 million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment.
Results of Operations for Oil and Gas Producing Activities	Results of Operations for Oil and Gas Producing Activities (1) . The following table sets forth results of operations for oil and gas producing activities for the years ended December 31, 2019 , 2018 and 2017 : United States Trinidad Other International (2) Total 2019 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues $ 11,250,853 $ 269,957 $ 60,635 $ 11,581,445 Other 134,325 18 15 134,358 Total 11,385,178 269,975 60,650 11,715,803 Exploration Costs 130,302 4,290 5,289 139,881 Dry Hole Costs 11,133 13,033 3,835 28,001 Transportation Costs 753,558 4,014 728 758,300 Gathering and Processing Costs 479,102 — — 479,102 Production Costs 2,063,078 30,539 40,369 2,133,986 Impairments 510,948 5,713 1,235 517,896 Depreciation, Depletion and Amortization 3,560,609 79,156 17,832 3,657,597 Income (Loss) Before Income Taxes 3,876,448 133,230 (8,638 ) 4,001,040 Income Tax Provision 884,450 54,980 3,152 942,582 Results of Operations $ 2,991,998 $ 78,250 $ (11,790 ) $ 3,058,458 2018 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues $ 11,488,620 $ 302,112 $ 155,755 $ 11,946,487 Other 89,708 (49 ) (24 ) 89,635 Total 11,578,328 302,063 155,731 12,036,122 Exploration Costs 121,572 21,402 6,025 148,999 Dry Hole Costs 4,983 — 422 5,405 Transportation Costs 742,792 3,236 848 746,876 Gathering and Processing Costs (3) 404,471 — 32,502 436,973 Production Costs 1,924,504 33,506 70,073 2,028,083 Impairments 344,595 — 2,426 347,021 Depreciation, Depletion and Amortization 3,181,801 91,788 46,687 3,320,276 Income (Loss) Before Income Taxes 4,853,610 152,131 (3,252 ) 5,002,489 Income Tax Provision 1,086,077 12,170 1,898 1,100,145 Results of Operations $ 3,767,533 $ 139,961 $ (5,150 ) $ 3,902,344 2017 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues $ 7,570,768 $ 284,673 $ 52,450 $ 7,907,891 Other 81,610 59 (59 ) 81,610 Total 7,652,378 284,732 52,391 7,989,501 Exploration Costs 113,334 26,245 5,763 145,342 Dry Hole Costs 91 — 4,518 4,609 Transportation Costs 737,403 1,885 1,064 740,352 Production Costs 1,446,333 27,839 88,038 1,562,210 Impairments 477,223 — 2,017 479,240 Depreciation, Depletion and Amortization 3,157,056 115,174 24,536 3,296,766 Income (Loss) Before Income Taxes 1,720,938 113,589 (73,545 ) 1,760,982 Income Tax Provision (Benefit) 625,562 24,882 (1,342 ) 649,102 Results of Operations $ 1,095,376 $ 88,707 $ (72,203 ) $ 1,111,880 (1) Excludes gains or losses on the mark-to-market of financial commodity derivative contracts, gains or losses on sales of reserves and related assets, interest charges and general corporate expenses for each of the three years in the period ended December 31, 2019 . (2) Other International primarily consists of EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018. (3) Effective January 1, 2018, EOG adopted the provisions of Accounting Standards Update (ASU) 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements within its United States segment as Gathering and Processing Costs instead of as a deduction to Natural Gas Revenues. There was no impact to operating income or net income resulting from changes to the presentation of natural gas processing fees (see Note 1 to Consolidated Financial Statements).
Production Costs Per Barrel of Oil Equivalent	The following table sets forth production costs per barrel of oil equivalent, excluding severance/production and ad valorem taxes, for the years ended December 31, 2019 , 2018 and 2017 : United States Trinidad Other International (1) Composite Year Ended December 31, 2019 $ 4.59 $ 1.85 $ 18.26 $ 4.54 Year Ended December 31, 2018 $ 4.84 $ 1.67 $ 20.19 $ 4.84 Year Ended December 31, 2017 $ 4.58 $ 1.39 $ 50.86 $ 4.66 (1) Other International primarily consists of EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Table	The following table sets forth the standardized measure of discounted future net cash flows from projected production of EOG's oil and gas reserves for the years ended December 31, 2019 , 2018 and 2017 : United States Trinidad Other International (1) Total 2019 Future cash inflows (2) $ 120,359,769 $ 813,102 $ 305,491 $ 121,478,362 Future production costs (42,387,801 ) (166,705 ) (87,381 ) (42,641,887 ) Future development costs (20,355,746 ) (212,303 ) (18,400 ) (20,586,449 ) Future income taxes (11,459,567 ) (73,508 ) (32,423 ) (11,565,498 ) Future net cash flows 46,156,655 360,586 167,287 46,684,528 Discount to present value at 10% annual rate (21,042,593 ) (86,009 ) (35,161 ) (21,163,763 ) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 25,114,062 $ 274,577 $ 132,126 $ 25,520,765 2018 Future cash inflows (3) $ 133,066,375 $ 749,695 $ 303,620 $ 134,119,690 Future production costs (42,351,174 ) (204,444 ) (99,024 ) (42,654,642 ) Future development costs (16,577,794 ) (78,199 ) (11,900 ) (16,667,893 ) Future income taxes (14,756,011 ) (174,382 ) (31,748 ) (14,962,141 ) Future net cash flows 59,381,396 292,670 160,948 59,835,014 Discount to present value at 10% annual rate (27,348,744 ) (26,832 ) (33,483 ) (27,409,059 ) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 32,032,652 $ 265,838 $ 127,465 $ 32,425,955 2017 Future cash inflows (4) $ 83,652,363 $ 904,141 $ 664,560 $ 85,221,064 Future production costs (32,018,812 ) (239,213 ) (311,383 ) (32,569,408 ) Future development costs (13,395,873 ) (84,379 ) (58,543 ) (13,538,795 ) Future income taxes (5,948,453 ) (195,855 ) (16,233 ) (6,160,541 ) Future net cash flows 32,289,225 384,694 278,401 32,952,320 Discount to present value at 10% annual rate (14,532,290 ) (52,267 ) (40,103 ) (14,624,660 ) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 17,756,935 $ 332,427 $ 238,298 $ 18,327,660 (1) Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018. (2) Estimated crude oil prices used to calculate 2019 future cash inflows for the United States, Trinidad and Other International were $57.51 , $46.77 , and $57.22 , respectively. Estimated NGL price used to calculate 2019 future cash inflows for the United States was $16.91 . Estimated natural gas prices used to calculate 2019 future cash inflows for the United States, Trinidad and Other International were $2.07 , $2.90 , and $5.01 , respectively. (3) Estimated crude oil prices used to calculate 2018 future cash inflows for the United States, Trinidad and Other International were $68.54 , $55.66 and $61.66 , respectively. Estimated NGL price used to calculate 2018 future cash inflows for the United States was $27.83 . Estimated natural gas prices used to calculate 2018 future cash inflows for the United States, Trinidad and Other International were $2.50 , $3.06 and $4.88 , respectively. (4) Estimated crude oil prices used to calculate 2017 future cash inflows for the United States, Trinidad and Other International were $49.21 , $41.87 and $50.06 , respectively. Estimated NGL price used to calculate 2017 future cash inflows for the United States was $23.51 . Estimated natural gas prices used to calculate 2017 future cash inflows for the United States, Trinidad and Other International were $1.96 , $2.76 and $5.16 , respectively.
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves	The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for each of the three years in the period ended December 31, 2019 : United States Trinidad Other International (1) Total December 31, 2016 $ 8,493,727 $ 185,750 $ 132,680 $ 8,812,157 Sales and transfers of oil and gas produced, net of production costs (5,387,031 ) (254,948 ) 36,649 (5,605,330 ) Net changes in prices and production costs 6,606,908 436,969 77,668 7,121,545 Extensions, discoveries, additions and improved recovery, net of related costs 3,644,041 270,255 43,952 3,958,248 Development costs incurred 1,435,600 4,700 — 1,440,300 Revisions of estimated development cost (114,464 ) 9,683 (20,096 ) (124,877 ) Revisions of previous quantity estimates 2,460,498 (58,373 ) 36,146 2,438,271 Accretion of discount 849,373 24,066 13,268 886,707 Net change in income taxes (1,918,989 ) (114,575 ) (10,099 ) (2,043,663 ) Purchases of reserves in place 30,362 — — 30,362 Sales of reserves in place (76,527 ) — — (76,527 ) Changes in timing and other 1,733,437 (171,100 ) (71,870 ) 1,490,467 December 31, 2017 17,756,935 332,427 238,298 18,327,660 Sales and transfers of oil and gas produced, net of production costs (8,416,853 ) (265,370 ) (52,399 ) (8,734,622 ) Net changes in prices and production costs 12,750,466 84,353 21,610 12,856,429 Extensions, discoveries, additions and improved recovery, net of related costs 8,418,666 — 12,287 8,430,953 Development costs incurred 2,732,560 — 12,600 2,745,160 Revisions of estimated development cost (410,741 ) 4,030 (3,814 ) (410,525 ) Revisions of previous quantity estimates (173,084 ) 39,608 31,750 (101,726 ) Accretion of discount 1,967,592 50,191 24,839 2,042,622 Net change in income taxes (4,965,373 ) 3,844 (11,529 ) (4,973,058 ) Purchases of reserves in place 116,887 — — 116,887 Sales of reserves in place (35,874 ) — (82,058 ) (117,932 ) Changes in timing and other 2,291,471 16,755 (64,119 ) 2,244,107 December 31, 2018 32,032,652 265,838 127,465 32,425,955 Sales and transfers of oil and gas produced, net of production costs (7,955,115 ) (235,404 ) (19,919 ) (8,210,438 ) Net changes in prices and production costs (10,973,981 ) 65,962 27,572 (10,880,447 ) Extensions, discoveries, additions and improved recovery, net of related costs 5,608,038 85,233 16,287 5,709,558 Development costs incurred 3,003,510 22,820 5,820 3,032,150 Revisions of estimated development cost (597,869 ) (129,047 ) (11,108 ) (738,024 ) Revisions of previous quantity estimates (812,781 ) 116,062 1,198 (695,521 ) Accretion of discount 3,891,701 43,148 14,909 3,949,758 Net change in income taxes 1,454,050 93,975 682 1,548,707 Purchases of reserves in place 98,539 — — 98,539 Sales of reserves in place (50,651 ) — — (50,651 ) Changes in timing and other (584,031 ) (54,010 ) (30,780 ) (668,821 ) December 31, 2019 $ 25,114,062 $ 274,577 $ 132,126 $ 25,520,765 (1)

Unaudited Quarterly Financial_2

Unaudited Quarterly Financial Information (Tables)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Unaudited Quarterly Financial Information	Unaudited Quarterly Financial Information (In Thousands, Except Per Share Data) Quarter Ended Mar 31 Jun 30 Sep 30 Dec 31 2019 Operating Revenues and Other $ 4,058,642 $ 4,697,630 $ 4,303,455 $ 4,320,246 Operating Income $ 876,530 $ 1,130,771 $ 827,959 $ 863,751 Income Before Income Taxes $ 827,236 $ 1,089,366 $ 797,457 $ 831,208 Income Tax Provision 191,810 241,525 182,335 194,687 Net Income $ 635,426 $ 847,841 $ 615,122 $ 636,521 Net Income Per Share (1) Basic $ 1.10 $ 1.47 $ 1.06 $ 1.10 Diluted $ 1.10 $ 1.46 $ 1.06 $ 1.10 Average Number of Common Shares Basic 577,207 577,460 577,839 578,219 Diluted 580,222 580,247 581,271 580,849 2018 Operating Revenues and Other $ 3,681,162 $ 4,238,077 $ 4,781,624 $ 4,574,536 Operating Income $ 874,588 $ 964,931 $ 1,506,687 $ 1,123,140 Income Before Income Taxes $ 813,359 $ 892,936 $ 1,446,363 $ 1,088,340 Income Tax Provision 174,770 196,205 255,411 195,572 Net Income $ 638,589 $ 696,731 $ 1,190,952 $ 892,768 Net Income Per Share (1) Basic $ 1.11 $ 1.21 $ 2.06 $ 1.55 Diluted $ 1.10 $ 1.20 $ 2.05 $ 1.54 Average Number of Common Shares Basic 575,775 576,135 577,254 577,035 Diluted 579,726 580,375 581,559 580,288 (1) The sum of quarterly net income per share may not agree with total year net income per share as each quarterly computation is based on the weighted average of common shares outstanding.

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Total Operating Revenues and Other	$ 4,320,246	$ 4,303,455	$ 4,697,630	$ 4,058,642	$ 4,574,536	$ 4,781,624	$ 4,238,077	$ 3,681,162	$ 17,379,973		$ 17,275,399		$ 11,208,320
Gathering and Processing Costs									479,102	[1],[2]	436,973	[1],[2]	148,775
Marketing Costs									5,351,524		5,203,243		3,330,237
Total Operating Expenses									13,680,962		12,806,053		10,281,918
Operating Income	863,751	$ 827,959	$ 1,130,771	$ 876,530	1,123,140	$ 1,506,687	$ 964,931	$ 874,588	3,699,011		4,469,346		926,402
Accounts Receivable From Contracts With Customers	$ 1,619,000				$ 1,460,000				1,619,000		1,460,000
Crude Oil and Condensate
Revenues									9,612,532		9,517,440		6,256,396
Natural Gas Liquids
Revenues									784,818		1,127,510		729,561
Natural Gas
Revenues									1,184,095		1,301,537		921,934
Gathering, Processing and Marketing
Revenues									$ 5,360,282		5,230,355		$ 3,298,087
Accounting Standards Update 2014-09 [Member]
Total Operating Revenues and Other											17,052,465
Gathering and Processing Costs											233,258
Marketing Costs											5,184,024
Total Operating Expenses											12,583,119
Operating Income											4,469,346
Accounting Standards Update 2014-09 [Member] | Crude Oil and Condensate
Revenues											9,517,440
Accounting Standards Update 2014-09 [Member] | Natural Gas Liquids
Revenues											1,121,237
Accounting Standards Update 2014-09 [Member] | Natural Gas
Revenues											1,104,095
Accounting Standards Update 2014-09 [Member] | Gathering, Processing and Marketing
Revenues											5,211,136
Effect of Change [Member]
Total Operating Revenues and Other											222,934
Gathering and Processing Costs											203,715
Marketing Costs											19,219
Total Operating Expenses											222,934
Operating Income											0
Effect of Change [Member] | Crude Oil and Condensate
Revenues											0
Effect of Change [Member] | Natural Gas Liquids
Revenues											6,273
Effect of Change [Member] | Natural Gas
Revenues											197,442
Effect of Change [Member] | Gathering, Processing and Marketing
Revenues											$ 19,219
[1]	Effective January 1, 2018, EOG adopted the provisions of Accounting Standards Update (ASU) 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements within its United States segment as Gathering and Processing Costs instead of as a deduction to Natural Gas Revenues. There was no impact to operating income or net income resulting from changes to the presentation of natural gas processing fees (see Note 1 to Consolidated Financial Statements).
[2]	Excludes gains or losses on the mark-to-market of financial commodity derivative contracts, gains or losses on sales of reserves and related assets, interest charges and general corporate expenses for each of the three years in the period ended December 31, 2019 .

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument Table [Line Items]
Long-Term Debt	$ 5,140,000,000	$ 6,040,000,000
Capital Lease Obligation	57,900,000	71,571,000
Less: Current Portion of Long-Term Debt	1,014,524,000	913,093,000
Unamortized Debt Discount	19,528,000	24,640,000
Debt Issuance Costs	2,929,000	3,669,000
Total Long-Term Debt	4,160,919,000	5,170,169,000
Long-Term Debt by Maturity [Abstract]
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2020	1,000,000,000
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2021	750,000,000
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2022	0
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2023	1,250,000,000
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2024	0
Revolving Credit Agreement 2020
Line of Credit Facility [Line Items]
Average Borrowings Outstanding	$ 0
Line of Credit Facility, Expiration Date	Jun. 27, 2024
Line Of Credit Facility Increase Additional Borrowings	$ 3,000,000,000
Maximum borrowing capacity	$ 2,000,000,000
Maximum total debt-to-total capitalization ratio allowed under financial covenant (in hundredths)	65.00%
Line of Credit Facility, Maximum Amount Outstanding During Period	$ 0
Revolving Credit Agreement 2020 | Eurodollar [Member]
Line of Credit Facility [Line Items]
Effective Interest Rate (in hundredths)	2.66%
Revolving Credit Agreement 2020 | Base Rate [Member]
Line of Credit Facility [Line Items]
Effective Interest Rate (in hundredths)	4.75%
Senior Unsecured Revolving Credit Agreement Due 2020 [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Date	Jul. 21, 2020
Maximum borrowing capacity	$ 2,000,000,000
Line of Credit Facility, Maximum Amount Outstanding During Period		$ 0
Uncommitted Credit Facilities
Line of Credit Facility [Line Items]
Current Borrowings Outstanding			$ 0
Commercial Paper
Line of Credit Facility [Line Items]
Current Borrowings Outstanding			$ 0
Short-term Debt, Weighted Average Interest Rate, over Time		1.97%
Line of Credit Facility, Maximum Amount Outstanding During Period	0	$ 8,000,000
6.875% Senior Notes due 2018
Debt Instrument Issuance [Abstract]
Debt Instrument Issuance Face Amount		$ 350,000,000
Debt Instrument Issuance Interest Rate		6.875%
5.625% Senior Notes due 2019
Debt Instrument Table [Line Items]
Long-Term Debt	0	$ 900,000,000
Debt Instrument Issuance [Abstract]
Debt Instrument Issuance Face Amount	$ 900,000,000
Debt Instrument Issuance Interest Rate	5.625%
4.40% Senior Notes Due 2020 [Member]
Debt Instrument Table [Line Items]
Long-Term Debt	$ 500,000,000	500,000,000
2.45% Senior Notes due 2020
Debt Instrument Table [Line Items]
Long-Term Debt	500,000,000	500,000,000
4.100% Senior Notes due 2021
Debt Instrument Table [Line Items]
Long-Term Debt	750,000,000	750,000,000
2.625% Senior Notes due 2023
Debt Instrument Table [Line Items]
Long-Term Debt	1,250,000,000	1,250,000,000
3.15% Senior Notes due 2025
Debt Instrument Table [Line Items]
Long-Term Debt	500,000,000	500,000,000
4.15% Senior Notes due 2026
Debt Instrument Table [Line Items]
Long-Term Debt	750,000,000	750,000,000
6.65% Senior Notes due 2028
Debt Instrument Table [Line Items]
Long-Term Debt	140,000,000	140,000,000
3.90% Senior Notes due 2035
Debt Instrument Table [Line Items]
Long-Term Debt	500,000,000	500,000,000
5.10% Senior Notes Due 2036
Debt Instrument Table [Line Items]
Long-Term Debt	$ 250,000,000	$ 250,000,000

Stockholder's Equity (Details)

Stockholder's Equity (Details) - $ / shares		Feb. 27, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Stockholders' Equity Note [Abstract]
An aggregate maximum of shares of common stock authorized for repurchase			10,000,000
Remaining shares available for purchase under share repurchase authorization			6,386,200
Dividends Common Stock Declared Per Share		$ 0.2875	$ 0.22	$ 0.1850
Dividends Payable, Amount Per Share After Increase		$ 0.375	$ 0.2875	$ 0.22	$ 0.1675
Common Stock, Shares Authorized			1,280,000,000	1,280,000,000	1,280,000,000	640,000,000
Percentage increase of cash dividend on common stock				19.00%	10.00%
Common Stock Activity [Line Items]
Balance (in shares)			580,408,117
Balance (in shares)			582,213,016	580,408,117
Preferred Stock, Shares Outstanding			0
Common Shares, Outstanding [Member]
Common Stock Activity [Line Items]
Balance (in shares)			580,023,000	578,477,000	576,700,000
Common Stock Issued Under Stock-Based Compensation Plans (in shares)			1,688,000	1,580,000	1,878,000
Treasury Stock Purchased (1) (in shares)	[1]		(310,000)	(539,000)	(686,000)
Common Stock Issued Under Employee Stock Purchase Plan (in shares)			223,000	180,000	180,000
Treasury Stock Issued Under Stock-Based Compensation Plans (in shares)			290,000	325,000	405,000
Balance (in shares)			581,914,000	580,023,000	578,477,000
Common Shares, Treasury [Member]
Common Stock Activity [Line Items]
Balance (in shares)			(385,000)	(351,000)	(250,000)
Common Stock Issued Under Stock-Based Compensation Plans (in shares)			0	0	0
Treasury Stock Purchased (1) (in shares)	[1]		(310,000)	(539,000)	(686,000)
Common Stock Issued Under Employee Stock Purchase Plan (in shares)			106,000	180,000	180,000
Treasury Stock Issued Under Stock-Based Compensation Plans (in shares)			290,000	325,000	405,000
Balance (in shares)			(299,000)	(385,000)	(351,000)
Common Shares, Issued [Member]
Common Stock Activity [Line Items]
Balance (in shares)			580,408,000	578,828,000	576,950,000
Common Stock Issued Under Stock-Based Compensation Plans (in shares)			1,688,000	1,580,000	1,878,000
Treasury Stock Purchased (1) (in shares)	[1]		0	0	0
Common Stock Issued Under Employee Stock Purchase Plan (in shares)			117,000	0	0
Treasury Stock Issued Under Stock-Based Compensation Plans (in shares)			0	0	0
Balance (in shares)			582,213,000	580,408,000	578,828,000
[1]	Represents shares that were withheld by or returned to EOG (i) in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or SARs or the vesting of restricted stock, restricted stock unit, performance unit grants or (ii) in payment of the exercise price of employee stock options.

Accumulated Other Comprehensi_3

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

Other Income, Net (Details)

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

Employee Benefit Plans (Details

Employee Benefit Plans (Details)		Feb. 27, 2020shares	Dec. 31, 2019USD ($)$ / sharesshares		Dec. 31, 2018USD ($)$ / sharesshares		Dec. 31, 2017USD ($)$ / sharesshares	Feb. 19, 2020USD ($)
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items]
Subsidiary guarantees demand for payment | $								$ 0
Common Shares Available for Grant			6,800,000
Share-based Payment Arrangement, Expense, Tax Benefit | $			$ (1,000,000)		$ 20,000,000		$ 32,000,000
Compensation expense related to the company's stock-based compensation plans | $			$ 174,738,000		155,337,000		133,849,000
Stock Options and Sars [Member]
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items]
Maximum term of stock options and SARs granted			7 years
Share-based Compensation Expense Related To Stock Options, SAR and ESPP Grants | $			$ 63,000,000		60,000,000		56,000,000
Stock Options/SARs Vested or Expected to Vest (in shares)			9,100,000
Weighted average grant price for stock options/SARs vested or expected to vest (per share) | $ / shares			$ 94.52
Intrinsic value of stock options/SARs vested or expected to vest | $			$ 29,100,000
Weighted Average Remaining Contractual Life for Stock Options/SARs Vested or Expected to Vest			4 years 2 months 12 days
Unrecognized compensation expense | $			$ 86,000,000
Weighted average period over which unrecognized compensation expense will be recognized			2 years
Intrinsic Value Of Stock Options/SARs Exercised During The Period | $			$ 14,000,000		$ 118,000,000		$ 95,000,000
Weighted Average Fair Value And Valuation Assumptions Used To Value Stock Options/SARs, ESPP, and Performance Units/Stock-Based Compensation [Abstract]
Weighted Average Fair Value of Grants (price per share) | $ / shares			$ 19.49		$ 33.46		$ 23.95
Expected Volatility (in hundredths)			32.02%		28.23%		28.28%
Risk-Free Interest Rate (in hundredths)			1.69%		2.68%		1.52%
Dividend Yield (in hundredths)			1.39%		0.72%		0.75%
Expected Life (in years)			5 years 1 month 6 days		5 years		5 years 1 month 6 days
Stock Options and SARs Rollforward [Abstract]
Outstanding at January 1 (in shares)			8,310,000		9,103,000		9,850,000
Granted (in shares)			1,965,000		1,906,000		2,274,000
Exercised (1) (in shares)	[1]		(606,000)		(2,493,000)		(2,574,000)
Forfeited (in shares)			(274,000)		(206,000)		(447,000)
Outstanding at December 31 (in shares)			9,395,000		8,310,000		9,103,000
Stock Options/SARs Exercisable at December 31 (in shares)			5,275,000		3,969,000		4,510,000
Weighted Average Grant Price Stock Option and SARs [Rollfoward]
Outstanding at January 1 (in dollars per share) | $ / shares			$ 96.90		$ 83.89		$ 75.53
Granted (in dollars per share) | $ / shares			75.39		126.49		96.27
Exercised (in dollars per share) | $ / shares	[1]		61.43		72.21		61.12
Forfeited (in dollars per share) | $ / shares			102.57		94.43		93.84
Outstanding at December 31 (in dollars per share) | $ / shares			94.53		96.90		83.89
Stock Options/SARs Exercisable at December 31 (in dollars per share) | $ / shares			$ 94.21		85.82		75.76
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items]
Stock Options and SARs Outstanding			9,395,000
Weighted Average Remaining Life for Outstanding Options and SARs			4 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 94.53
Aggregate Intrinsic Value For Outstanding Options and SARs | $	[2]		$ 30,534
Stock Options and SARs Exercisable			5,275,000
Weighted Average Remaining Life For Exercisable Units			3 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 94.21
Aggregate Intrinsic Value For Exercisable Units | $	[2]		$ 13,839
Stock Options and Sars [Member] | Vesting Schedule - First Anniversary [Member]
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items]
Vesting Period Increments (in hundredths)			33.00%
Stock Options and Sars [Member] | Vesting Schedule - Second Anniversary [Member]
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items]
Vesting Period Increments (in hundredths)			33.00%
Stock Options and Sars [Member] | Vesting Schedule - Third Anniversary [Member]
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items]
Vesting Period Increments (in hundredths)			34.00%
ESPP [Member]
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items]
Common Shares Available for Grant			2,300,000
Percentage of fair market value at which employees may purchase company stock via the ESPP			85.00%
Maximum Percentage Of Employee Pay Eligible For Contribution To ESPP Percentage			10.00%
Weighted Average Fair Value And Valuation Assumptions Used To Value Stock Options/SARs, ESPP, and Performance Units/Stock-Based Compensation [Abstract]
Weighted Average Fair Value of Grants (price per share) | $ / shares			$ 22.83		$ 25.75		$ 22.20
Expected Volatility (in hundredths)			34.78%		24.59%		27.12%
Risk-Free Interest Rate (in hundredths)			2.27%		1.89%		0.88%
Dividend Yield (in hundredths)			1.04%		0.64%		0.71%
Expected Life (in years)			15 days		15 days		15 days
Stock Options and SARs Rollforward [Abstract]
Approximate Number of Participants			1,998		1,934		1,870
Shares Purchased			224,000		180,000		180,000
Aggregate Purchase Price | $			$ 16,533,000		$ 14,887,000		$ 13,997,000
Restricted Stock and Restricted Stock Units [Member]
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items]
Adjustments to Additional Paid in Capital, Income Tax Benefit from Share-based Compensation | $			97,000,000		81,000,000		68,000,000
Unrecognized compensation expense | $			$ 202,000,000
Weighted average period over which unrecognized compensation expense will be recognized			1 year 9 months 18 days
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period			3 years
Intrinsic value released during the year | $			$ 70,000,000		84,000,000		91,000,000
Aggregate intrinsic value of stock and unit outstanding | $			$ 381,000,000		$ 331,000,000		$ 421,000,000
Number of Shares and Units [Roll Forward]
Outstanding at January 1 (in shares)			3,792,000	[3]	3,905,000	[3]	3,962,000
Granted (in shares)			1,749,000		812,000		1,095,000
Released (in shares)	[4]		(855,000)		(740,000)		(929,000)
Forfeited (in shares)			(140,000)		(185,000)		(223,000)
Outstanding at December 31 (in shares)	[3]		4,546,000		3,792,000		3,905,000
Weighted Average Grant Fair Value [Abstract]
Outstanding at January 1 (in dollars per share) | $ / shares			$ 96.64	[3]	$ 88.57	[3]	$ 79.63
Granted (in dollars per share) | $ / shares			80.01		117.55		97.34
Released (in dollars per share) | $ / shares	[4]		96.93		78.16		61.51
Forfeited (in dollars per share) | $ / shares			97.54		92.12		85.45
Outstanding at December 31 (in dollars per share) | $ / shares	[3]		$ 90.16		$ 96.64		$ 88.57
Performance Units [Member]
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items]
Unrecognized compensation expense | $			$ 9,000,000
Weighted average period over which unrecognized compensation expense will be recognized			2 years
Cliff Vesting Period			41 months
Compensation expense related to the company's stock-based compensation plans | $			$ 15,000,000		$ 14,000,000		$ 10,000,000
Intrinsic value released during the year | $			15,000,000		18,000,000		24,000,000
Aggregate intrinsic value of stock and unit outstanding | $			$ 50,000,000		$ 47,000,000		$ 54,000,000
Weighted Average Fair Value And Valuation Assumptions Used To Value Stock Options/SARs, ESPP, and Performance Units/Stock-Based Compensation [Abstract]
Weighted Average Fair Value of Grants (price per share) | $ / shares			$ 79.98		$ 136.74		$ 113.81
Expected Volatility (in hundredths)			29.20%		29.92%		32.19%
Risk-Free Interest Rate (in hundredths)			1.51%		2.85%		1.60%
Number of Shares and Units [Roll Forward]
Outstanding at January 1 (in shares)			539,000	[5]	502,000	[5]	545,000
Granted (in shares)			172,000		113,000		78,000
Granted for Performance Multiple (1) (in shares)	[6]		72,000		72,000		119,000
Released (in shares)	[7]		(185,000)		(148,000)		(240,000)
Forfeited (in shares)			0		0		0
Outstanding at December 31 (in shares)	[5]		598,000	[8]	539,000		502,000
Weighted Average Grant Fair Value [Abstract]
Outstanding at January 1 (in dollars per share) | $ / shares			$ 101.53	[5]	$ 90.96	[5]	$ 80.92
Granted (in dollars per share) | $ / shares			75.09		125.73		96.29
Granted for Performance Multiple (1) (in dollars per share) | $ / shares	[6]		69.43		101.87		84.43
Released (in dollars per share) | $ / shares	[7]		94.63		84.43		66.69
Forfeited (in dollars per share) | $ / shares			0		0		0
Outstanding at December 31 (in dollars per share) | $ / shares	[5]		$ 92.19		$ 101.53		$ 90.96
Performance Units and Performance Stock [Abstract]
Minimum Performance Multiple at the Completion Performance Period			0.00%
Maximum Performance Multiple at the Completion Performance Period			200.00%
Minimum Performance Units and Stock Allowed to be Outstanding			102
Maximum Performance Units and Stock Allowed to be Outstanding			1,094
Performance Multiple Applied at the Completion Period		150.00%	200.00%		200.00%		200.00%
Additional Performance Awards Granted		65,872
Pension Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total pension plan costs | $			$ 51,000,000		$ 43,000,000		$ 37,000,000
Company contributions to foreign pension plans | $			1,000,000		1,000,000		1,000,000
Defined Benefit Plan, Benefit Obligation | $			12,000,000		11,000,000
Fair value of foreign pension plan assets | $			10,000,000		9,000,000
Accrued benefit cost | $			(100,000)		(200,000)
Lease And Well [Member]
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items]
Compensation expense related to the company's stock-based compensation plans | $			56,000,000		51,000,000		41,000,000
Gathering And Processing Costs [Member]
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items]
Compensation expense related to the company's stock-based compensation plans | $			1,000,000		1,000,000		1,000,000
Exploration Costs [Member]
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items]
Compensation expense related to the company's stock-based compensation plans | $			26,000,000		25,000,000		23,000,000
General And Administrative [Member]
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items]
Compensation expense related to the company's stock-based compensation plans | $			$ 92,000,000		$ 78,000,000		$ 69,000,000
$ 59.00 to $ 74.99 | Stock Options and Sars [Member]
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items]
Stock Options and SARs Outstanding			979,000
Weighted Average Remaining Life for Outstanding Options and SARs			3 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 69.43
Stock Options and SARs Exercisable			953,000
Weighted Average Remaining Life For Exercisable Units			3 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 69.37
75.00 to 75.99 | Stock Options and Sars [Member]
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items]
Stock Options and SARs Outstanding			1,894,000
Weighted Average Remaining Life for Outstanding Options and SARs			7 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 75.09
Stock Options and SARs Exercisable			8,000
Weighted Average Remaining Life For Exercisable Units			1 year
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 75.09
76.00 to 95.99 | Stock Options and Sars [Member]
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items]
Stock Options and SARs Outstanding			1,979,000
Weighted Average Remaining Life for Outstanding Options and SARs			3 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 91.35
Stock Options and SARs Exercisable			1,607,000
Weighted Average Remaining Life For Exercisable Units			2 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 90.67
96.00 to 96.99 | Stock Options and Sars [Member]
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items]
Stock Options and SARs Outstanding			1,871,000
Weighted Average Remaining Life for Outstanding Options and SARs			4 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 96.29
Stock Options and SARs Exercisable			1,234,000
Weighted Average Remaining Life For Exercisable Units			4 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 96.29
97.00 to 125.99 | Stock Options and Sars [Member]
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items]
Stock Options and SARs Outstanding			923,000
Weighted Average Remaining Life for Outstanding Options and SARs			2 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 102.72
Stock Options and SARs Exercisable			862,000
Weighted Average Remaining Life For Exercisable Units			2 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 102.20
126.00 to 129.99 | Stock Options and Sars [Member]
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items]
Stock Options and SARs Outstanding			1,749,000
Weighted Average Remaining Life for Outstanding Options and SARs			6 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares			$ 127.01
Stock Options and SARs Exercisable			611,000
Weighted Average Remaining Life For Exercisable Units			5 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares			$ 127.01
[1]	The total intrinsic value of stock options/SARs exercised during the years 2019 , 2018 and 2017 was $14 million , $118 million and $95 million , respectively. The intrinsic value is based upon the difference between the market price of the Common Stock on the date of exercise and the grant price of the stock options/SARs.
[2]	Based upon the difference between the closing market price of the Common Stock on the last trading day of the year and the grant price of in-the-money stock options and SARs.
[3]	The total intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2019, 2018 and 2017 was $381 million , $331 million and $421 million
[4]	The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2019, 2018 and 2017 was $70 million , $84 million and $91 million , respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date restricted stock and restricted stock units are released.
[5]	The total intrinsic value of Performance Awards outstanding at December 31, 2019, 2018 and 2017 was $50 million , $47 million and $54 million , respectively. The intrinsic value is based on the closing market price of the Common Stock on the last trading day of the year.
[6]	Upon completion of the Performance Period for the Performance Awards granted in 2015, 2014 and 2013, a performance multiple of 200% was applied to each of the grants resulting in additional grants of Performance Awards in February 2019, 2018 and 2017.
[7]	The total intrinsic value of Performance Awards released during the years ended December 31, 2019, 2018 and 2017 was $15 million , $18 million and $24 million , respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date Performance Awards are released.
[8]	Upon the application of the relevant performance multiple at the completion of each of the remaining Performance Periods, a minimum of 102 and a maximum of 1,094 Performance Awards could be outstanding.

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Deferred Tax Assets (Liabilities) Net Noncurrent Classification [Abstract]
Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization		$ 5,825		$ 4,359
Foreign Net Operating Loss		66,675		55,175
Foreign Valuation Allowances		(70,455)		(58,932)
Foreign Other		318		175
Total Net Noncurrent Deferred Income Tax Assets		2,363		777
Deferred Tax (Assets) Liabilities Net Noncurrent Classification [Abstract]
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization		5,277,550		4,583,517	[1]
Commodity Hedging Contracts		(4,699)		4,883
Deferred Compensation Plans		(47,650)		(39,086)
Accrued Expenses and Liabilities		(8,502)		(19,097)
Equity Awards		(108,324)		(93,977)
Alternative Minimum Tax Credit Carryforward		(31,904)		0
Undistributed Foreign Earnings		15,746		22,945
Other		(46,116)		(45,787)
Total Net Noncurrent Deferred Income Tax Liabilities		5,046,101		4,413,398
Total Net Deferred Income Tax Liabilities		5,043,738		4,412,621
Components Income (Loss) Before Income Taxes [Abstract]
United States		3,466,578		4,084,156		$ 621,610
Foreign		78,689		156,842		39,572
Income Before Income Taxes		3,545,267		4,240,998		661,182
Current income tax provision (benefit) [Abstract]
Federal		(152,258)		(303,853)		33,058
State		10,819		17,048		(2,502)
Foreign		81,426		65,615		35,323
Total		(60,013)		(221,190)		65,879
Deferred income tax provision (benefit) [Abstract]
Federal		626,901		862,075		(1,504,288)
State		32,541		43,293		26,942
Foreign		(27,784)		(11,212)		3,474
Total		631,658		894,156		(1,473,872)
Other Non-Current (1)
Federal		245,125	[2]	148,992	[3]	(513,404)	[2]
Other Noncurrent Foreign Income Tax		(6,413)		0		0
Total		238,712		148,992		(513,404)
Income Tax Provision (Benefit)		$ 810,357		$ 821,958		$ (1,921,397)
Federal Statutory and Effective Income Tax Rates [Abstract]
Statutory Federal Income Tax Rate (in hundredths)		21.00%		21.00%		35.00%
State Income Tax, Net of Federal Benefit (in hundredths)		0.97%		1.12%		3.38%
Income Tax Provision Related to Foreign Operations (in hundredths)		0.87%		0.51%		(0.30%)
Income Tax Provision Related to United Kingdom Operations (in hundredths)		0.00%		0.00%		1.78%
Income Tax Provision Related to Canadian Operations (in hundredths)		0.00%		0.00%		2.30%
TCJA (in hundredths)		0.00%		(2.60%)	[4],[5]	(328.10%)	[5],[6]
Shared-Based Compensation (in hundredths)		0.02%		(0.47%)		(4.63%)
Other (in hundredths)		0.00%		(0.18%)		(0.03%)
Effective Income Tax Rate (in hundredths)		22.86%		19.38%		(290.60%)
Provisional Reduction in the Income Tax Provision						$ 2,000,000
Tax NOLs (in hundredths)				(1.20%)
Sequestration (in hundredths)				(1.00%)		(6.40%)
Other Tax Reform Impacts (in hundredths)				(0.40%)		(0.10%)
Federal Tax Rate Reduction (in hundredths)						(327.80%)
Federal Repatriation Tax (in hundredths)						(6.60%)
Components of Valuation Allowance [Abstract]
Beginning Balance		$ 167,142		$ 466,421		$ 383,221
Increase	[7]	30,673		23,062		67,333
Decrease	[8]	(75)		(26,219)		(13,687)
Other	[9]	3,091		(296,122)		29,554
Ending Balance		200,831		$ 167,142		$ 466,421
Balance of state net operating loss expected to be carried forward		2,100,000
Canadian Net Operating Loss Carryforwards		225,000
Unrecognized Tax Benefits Balance		39,000
Unrecognized Tax Benefits that Would Impact On Earnings		25,000
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense		4,000
Foreign and State Deferred Income Taxes		$ 16,000
[1]	The 2018 presentation has been changed to conform with current year presentation.
[2]	Includes changes in certain amounts that are expected to be paid or received beyond the next twelve months. The primary components are refundable alternative minimum tax (AMT) credits and the 2017 repatriation tax. See the following statutory-to-effective tax rate reconciliation for additional details.
[3]	Includes changes in certain amounts that are expected to be paid or received beyond the next twelve months. The primary components are refundable alternative minimum tax (AMT) credits and the 2017 repatriation tax. See the following statutory-to-effective tax rate reconciliation for additional details.
[4]	Includes impact of utilizing certain tax net operating losses (NOLs) ( (1.2)% ), the reversal of sequestration ( (1.0)% ) and other tax reform impacts ( (0.4)% ).
[5]	The enactment of the Tax Cuts and Jobs Act (TCJA) by the United States in 2017 made numerous changes to federal tax law. Several changes which had a significant impact on EOG include the corporate income tax rate reduction from 35% to 21%, the imposition of a one-time repatriation tax on undistributed foreign earnings and the repeal of the corporate AMT regime (AMT credit carryforwards became refundable over the following four years and were initially subject to a federal sequestration charge). In 2017, EOG revalued its federal deferred income tax assets and liabilities resulting in an earnings benefit of over $2 billion and a substantial reduction of the 2017 effective tax rate. The TCJA measurement-period adjustments were recorded in 2018.
[6]	Includes impact of the federal rate reduction ( (327.8)% ), federal repatriation tax ( (6.6)% ), sequestration ( (6.4)% ) and other tax reform impacts ( (0.1)% ).
[7]	Increase in valuation allowance related to the generation of tax NOLs and other deferred tax assets.
[8]	Decrease in valuation allowance associated with adjustments to certain deferred tax assets and their related allowance.
[9]	Represents dispositions, revisions and/or foreign exchange rate variances and the effect of statutory income tax rate changes. The United Kingdom operations were sold in the fourth quarter of 2018.

Commitments and Contingencies_3

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

Net Income Per Share (Details)

Net Income Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2019		Sep. 30, 2019		Jun. 30, 2019		Mar. 31, 2019		Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Numerator for Basic and Diluted Earnings per Share - [Abstract]
Net Income	$ 636,521		$ 615,122		$ 847,841		$ 635,426		$ 892,768		$ 1,190,952		$ 696,731		$ 638,589		$ 2,734,910	$ 3,419,040	$ 2,582,579
Denominator for Basic Earnings per Share - [Abstract]
Weighted Average Shares	578,219		577,839		577,460		577,207		577,035		577,254		576,135		575,775		577,670	576,578	574,620
Denominator for Diluted Earnings per Share - [Abstract]
Adjusted Diluted Weighted Average Shares	580,849		581,271		580,247		580,222		580,288		581,559		580,375		579,726		580,777	580,441	578,693
Antidilutive Securities Excluded from Computation of Earnings Per Share [Abstract]
Anti-dilutive Securities excluded from Diluted Earnings Per Share Calculation																	6,100	600	2,600
Net Income (Loss) Per Share [Abstract]
Basic	$ 1.10	[1]	$ 1.06	[1]	$ 1.47	[1]	$ 1.10	[1]	$ 1.55	[1]	$ 2.06	[1]	$ 1.21	[1]	$ 1.11	[1]	$ 4.73	$ 5.93	$ 4.49
Diluted	$ 1.10	[1]	$ 1.06	[1]	$ 1.46	[1]	$ 1.10	[1]	$ 1.54	[1]	$ 2.05	[1]	$ 1.20	[1]	$ 1.10	[1]	$ 4.71	$ 5.89	$ 4.46
Stock Options and Sars [Member]
Potential Dilutive Common Shares -[Abstract]
Common Shares Attributable to Dilutive Effect of Share-Based Payment Arrangments																	258	1,137	1,466
Restricted Stock/Units and Performance Units/Stock [Member]
Potential Dilutive Common Shares -[Abstract]
Common Shares Attributable to Dilutive Effect of Share-Based Payment Arrangments																	2,849	2,726	2,607
[1]	The sum of quarterly net income per share may not agree with total year net income per share as each quarterly computation is based on the weighted average of common shares outstanding.

Supplemental Cash Flow Inform_3

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

Business Segment Information (D

Business Segment Information (Details) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Schedule of Segment Reporting Information By Segment [Abstract]
Operating Revenues and Other		$ 4,320,246	$ 4,303,455	$ 4,697,630	$ 4,058,642	$ 4,574,536	$ 4,781,624	$ 4,238,077	$ 3,681,162	$ 17,379,973		$ 17,275,399		$ 11,208,320
Depreciation, Depletion and Amortization										3,749,704		3,435,408		3,409,387
Operating Income (Loss)		863,751	827,959	1,130,771	876,530	1,123,140	1,506,687	964,931	874,588	3,699,011		4,469,346		926,402
Interest Income										26,026		11,546		7,713
Other Income										5,359		5,158		1,439
Net Interest Expense										185,129		245,052		274,372
Income (Loss) Before Income Taxes										3,545,267		4,240,998		661,182
Income Tax Provision (Benefit)		194,687	$ 182,335	$ 241,525	$ 191,810	195,572	$ 255,411	$ 196,205	$ 174,770	810,357		821,958		(1,921,397)
Additions to Oil and Gas Properties, Excluding Dry Hole Costs										6,273,952		6,195,330		4,228,228
Total Property, Plant and Equipment, Net		30,364,595				28,075,519				30,364,595		28,075,519		25,665,037
Total Assets		37,124,608				33,934,474				37,124,608		33,934,474		29,833,078
Crude Oil and Condensate
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										9,612,532		9,517,440		6,256,396
Natural Gas Liquids
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										784,818		1,127,510		729,561
Natural Gas
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										1,184,095		1,301,537		921,934
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										180,275		(165,640)		19,828
Gathering, Processing and Marketing
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										5,360,282		5,230,355		3,298,087
Gains (Losses) on Asset Dispositions, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										123,613		174,562		(99,096)
Other, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										134,358		89,635		81,610
United States
Schedule of Segment Reporting Information By Segment [Abstract]
Operating Revenues and Other										17,052,363	[1]	16,794,591	[2]	10,872,071	[3]
Depreciation, Depletion and Amortization										3,652,294		3,296,499		3,269,196
Operating Income (Loss)										3,618,907		4,334,364		933,571
Interest Income										22,122		9,326		3,223
Other Income										3,235		9,580
Other Expense														(9,659)
Net Interest Expense										192,587		253,352		303,941
Income (Loss) Before Income Taxes										3,451,677		4,099,918		623,194
Income Tax Provision (Benefit)										760,881		765,986		(1,964,343)
Additions to Oil and Gas Properties, Excluding Dry Hole Costs										6,208,394		6,155,874		4,067,359
Total Property, Plant and Equipment, Net		30,101,857				27,786,086				30,101,857		27,786,086		25,125,427
Total Assets		36,274,942				33,178,733				36,274,942		33,178,733		28,312,599
Amount of sales with a single significant purchaser in the United States segment										2,400,000		2,600,000		1,500,000
Amount of sales with a second significant purchaser in the United States segment.										2,200,000		2,300,000		1,300,000
United States | Crude Oil and Condensate
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										9,599,125		9,390,244		6,225,711
United States | Natural Gas Liquids
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										784,818		1,127,510		729,545
United States | Natural Gas
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										866,911		970,866		615,512
United States | Gains (Losses) on Mark-to-Market Commodity Derivative Contracts
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										180,275		(165,640)		19,828
United States | Gathering, Processing and Marketing
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										5,355,463		5,227,051		3,298,098
United States | Gains (Losses) on Asset Dispositions, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										131,446		154,852		(98,233)
United States | Other, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										134,325		89,708		81,610
Trinidad
Schedule of Segment Reporting Information By Segment [Abstract]
Operating Revenues and Other										271,106		309,860		284,713
Depreciation, Depletion and Amortization										79,389		91,971		115,321
Operating Income (Loss)										112,790		147,240		101,010
Interest Income										3,686		1,612		2,201
Other Income										727		2,436		3,337
Net Interest Expense										0		0		0
Income (Loss) Before Income Taxes										117,203		151,288		106,548
Income Tax Provision (Benefit)										40,901		54,272		38,798
Additions to Oil and Gas Properties, Excluding Dry Hole Costs										53,325		1,618		145,937
Total Property, Plant and Equipment, Net		184,606				210,183				184,606		210,183		313,357
Total Assets		705,747				629,633				705,747		629,633		974,477
Trinidad | Crude Oil and Condensate
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										11,138		17,059		13,572
Trinidad | Natural Gas Liquids
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										0		0		0
Trinidad | Natural Gas
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										258,819		285,053		271,101
Trinidad | Gains (Losses) on Mark-to-Market Commodity Derivative Contracts
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										0		0		0
Trinidad | Gathering, Processing and Marketing
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										4,819		3,304		(11)
Trinidad | Gains (Losses) on Asset Dispositions, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										(3,688)		4,493		(8)
Trinidad | Other, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues										18		(49)		59
Other International
Schedule of Segment Reporting Information By Segment [Abstract]
Operating Revenues and Other	[4]									56,504		170,948		51,536
Depreciation, Depletion and Amortization	[4]									18,021		46,938		24,870
Operating Income (Loss)	[4]									(32,686)		(12,258)		(108,179)
Interest Income	[4]									218		608		2,289
Other Income										1,397				7,761	[4]
Other Expense	[4]											(6,858)
Net Interest Expense	[4]									(7,458)		(8,300)		(29,569)
Income (Loss) Before Income Taxes	[4]									(23,613)		(10,208)		(68,560)
Income Tax Provision (Benefit)	[4]									8,575		1,700		4,148
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	[4]									12,233		37,838		14,932
Total Property, Plant and Equipment, Net	[4]	78,132				79,250				78,132		79,250		226,253
Total Assets	[4]	$ 143,919				$ 126,108				143,919		126,108		546,002
Other International | Crude Oil and Condensate
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues	[4]									2,269		110,137		17,113
Other International | Natural Gas Liquids
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues	[4]									0		0		16
Other International | Natural Gas
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues	[4]									58,365		45,618		35,321
Other International | Gains (Losses) on Mark-to-Market Commodity Derivative Contracts
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues	[4]									0		0		0
Other International | Gathering, Processing and Marketing
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues	[4]									0		0		0
Other International | Gains (Losses) on Asset Dispositions, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues	[4]									(4,145)		15,217		(855)
Other International | Other, Net
Schedule of Segment Reporting Information By Segment [Abstract]
Revenues	[4]									$ 15		$ (24)		$ (59)
[1]	EOG had sales activity with two significant purchasers in 2019, one totaling $2.4 billion , and the other totaling $2.2 billion of consolidated Operating Revenues and Other in the United States segment.
[2]	EOG had sales activity with two significant purchasers in 2018, one totaling $2.6 billion and the other totaling $2.3 billion of consolidated Operating Revenues and Other in the United States segment.
[3]	EOG had sales activity with two significant purchasers in 2017, one totaling $1.5 billion and the other totaling $1.3 billion of consolidated Operating Revenues and Other in the United States segment.
[4]	Other International primarily consists of EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.

Risk Management Activities (Det

Risk Management Activities (Details)		12 Months Ended
		Dec. 31, 2019USD ($)MMBTU$ / bbl$ / MMBTUMBblsbbl	Dec. 31, 2018USD ($)$ / bbl	Dec. 31, 2017USD ($)
Derivatives, Fair Value [Line Items]
Assets from Price Risk Management Activities		$ 1,299,000	$ 23,806,000
Liabilities from Price Risk Management Activities		$ 20,194,000	$ 0
Receivable Major Customer Percentage		10.00%	10.00%
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts		$ 180,275,000	$ (165,640,000)	$ 19,828,000
Net Cash Received from (Payments for) Settlements of Commodity Derivatives Contracts		231,229,000	(258,906,000)	7,438,000
Derivative Collateral [Abstract]
Collateral Held on Derivative		0		0
Collateral Had on Derivaitve		0		0
Assets [Member]
Derivatives, Fair Value [Line Items]
Assets from Price Risk Management Activities		3,000,000
Liabilities from Price Risk Management Activities		2,000,000
Assets [Member] | Price Risk Derivative [Member]
Derivatives, Fair Value [Line Items]
Assets from Price Risk Management Activities	[1]		1,299,000	23,806,000
Liability [Member]
Derivatives, Fair Value [Line Items]
Assets from Price Risk Management Activities		3,000,000
Liabilities from Price Risk Management Activities		$ 23,000,000
Liabilities From Price Risk Management Activities [Member] | Price Risk Derivative [Member]
Derivatives, Fair Value [Line Items]
Liabilities from Price Risk Management Activities	[2]		$ 20,194,000	$ 0
Crude Oil [Member] | Midland Differential Basis Swap [Member] | Derivative Contracts - January through December (closed) [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld) | MBbls		20,000
Derivative, Swap Type, Average Fixed Price | $ / bbl			1.075
Crude Oil [Member] | Gulf Coast Differential Basis Swap [Member] | Derivative Contracts - January through December (closed) [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl		13,000
Derivative, Swap Type, Average Fixed Price | $ / bbl		5.572
Crude Oil [Member] | Price Swap [Member] | Derivative Contracts - April (closed) [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl		25,000
Derivative, Swap Type, Average Fixed Price | $ / bbl		60
Crude Oil [Member] | Price Swap [Member] | Derivative Contracts - May through December (closed) [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl		150,000
Derivative, Swap Type, Average Fixed Price | $ / bbl		62.50
Crude Oil [Member] | Price Swap [Member] | Derivative Contracts - Year Two - January through March [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl		200,000
Derivative, Swap Type, Average Fixed Price | $ / bbl		59.33
Crude Oil [Member] | Price Swap [Member] | Derivative Contracts - Year Two - April through June [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl		150,000
Derivative, Swap Type, Average Fixed Price | $ / bbl		59.03
Crude Oil [Member] | Price Swap [Member] | Derivative Contracts - Year Two - July through September [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl		50,000
Derivative, Swap Type, Average Fixed Price | $ / bbl		58.32
Mont Belvieu Propane Price Swap [Member] | Price Swap [Member] | Derivative Contracts - Year Two - January through December [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl		4,000
Derivative, Swap Type, Average Fixed Price | $ / bbl		21.34
Natural Gas [Member] | Rockies Differential Basis Swaps [Member] | Derivative Contracts - Year Two - January through December [Member]
Derivatives, Fair Value [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU		0.55
Volume (MMBTU) | MMBTU		30,000
Natural Gas [Member] | HSC Differential Basis Swaps [Member] | Derivative Contracts - Year Two - January through December [Member]
Derivatives, Fair Value [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU		0.05
Volume (MMBTU) | MMBTU		60,000
Natural Gas [Member] | Waha Differential Basis Swaps [Member] | Derivative Contracts - Year Two - January through December [Member]
Derivatives, Fair Value [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU		1.40
Volume (MMBTU) | MMBTU		50,000
Natural Gas [Member] | Price Swap [Member] | Derivative Contracts - Year Two - January through December [Member]
Derivatives, Fair Value [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU		2.90
Volume (MMBTU) | MMBTU		250,000
[1]	The current portion of Assets from Price Risk Management Activities consists of gross assets of $3 million , partially offset by gross liabilities of $2 million , at December 31, 2019.
[2]	The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $23 million , partially offset by gross assets of $3 million at December 31, 2019.

Fair Value Measurements (Detail

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

Accounting For Certain Long-L_2

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

Asset Retirement Obligations (D

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

Exploratory Well Costs (Details

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

Acquisitions and Divestitures_2

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

Leases (Details)

Leases (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Operating and Finance Leases [Line Items]
Operating Lease, Right-of-Use Asset		$ 566,000
Lease, Cost [Abstract]
Operating Lease Cost	$ 497,000
Amortization of Lease Assets	13,000
Interest on Lease Liabilities	2,000
Variable Lease Cost	138,000
Total Lease Cost	983,000
Lease Assets and Liabilities [Abstract]
Total	826,000
Current Liability	369,365	0
Total	857,000
Finance Lease Net of Accumulated Depreciation	36,938,066	33,475,162
Cash Flow Operating And Financing Activities [Abstract]
Operating Leases Non-Cash Leasing Activities	784,000
Operating And Finance Leases Future Minimum Payments [Abstract]
Operating And Finance Leases Not Yet Commenced	699,000
Operating And Finance Leases Liabilities Not Yet Commenced Due 2020	521,000
Operating And Finance Leases Liabilities Not Yet Commenced Due 2021	178,000
Capital Leases Future Minimum Payments Due [Abstract]
Short-term Lease Cost	333,000
Finance Leases
Lease Assets and Liabilities [Abstract]
Current Liability	15,000
Long-Term Liability	$ 43,000
Weighted Average Remaining Lease Term And Discount Rate [Abstract]
Finance Lease Weighted Average Remaining Lease Term (in years)	4 years 8 months 12 days
Finance Lease Weighted Average Discount Rate (%)	3.00%
Cash Flow Operating And Financing Activities [Abstract]
Repayment of Finance Lease Liabilities	$ 13,000
Operating And Finance Leases Future Minimum Payments [Abstract]
2020	15,000
2021	15,000
2022	12,000
2023	8,000
2024	8,000
2025 and Beyond	6,000
Total Lease Payments	64,000
Less: Discount to Present Value	6,000
Total Lease Liabilities	58,000
Capital Leases Future Minimum Payments Due [Abstract]
2019		15,000
2020		15,000
2021		15,000
2022		12,000
2023		8,000
2024 and Beyond		14,000
Total Leases Payments		79,000
Operating Leases [Member]
Lease Assets and Liabilities [Abstract]
Current Liability	369,000
Long-Term Liability	$ 430,000
Weighted Average Remaining Lease Term And Discount Rate [Abstract]
Operating Lease Weighted Average Remaining Lease Term (in years)	3 years 2 months 12 days
Operating Lease Weighted Average Discount Rate (%)	3.50%
Operating And Finance Leases Future Minimum Payments [Abstract]
2020	$ 390,000
2021	209,000
2022	126,000
2023	56,000
2024	29,000
2025 and Beyond	40,000
Total Lease Payments	850,000
Less: Discount to Present Value	51,000
Total Lease Liabilities	799,000
Operating Leases Future Minimum Payments Due [Abstract]
2019		380,000
2020		213,000
2021		86,000
2022		39,000
2023		30,000
2024 and Beyond		62,000
Total Leases Payments		$ 810,000
Operating Leases [Member] | Operating Activities
Cash Flow Operating And Financing Activities [Abstract]
Repayment of Operating Lease Liabilities	225,000
Operating Leases [Member] | Investing Activities
Cash Flow Operating And Financing Activities [Abstract]
Repayment of Operating Lease Liabilities	$ 270,000
Maximum
Operating And Finance Leases Future Minimum Payments [Abstract]
Operating And Finance Leases Not Yet Commenced Lease Term	10 years
Property, Plant and Equipment
Lease Assets and Liabilities [Abstract]
Finance Lease Net of Accumulated Depreciation	$ 60,000
Property, Plant and Equipment | Finance Leases
Operating and Finance Leases [Line Items]
Operating Lease, Right-of-Use Asset	773,000
Lease Assets and Liabilities [Abstract]
Right-of-Use Asset	53,000
Current Portion of Operating Lease Liabilities | Operating Leases [Member]
Lease Assets and Liabilities [Abstract]
Current Liability	369,000
Current Portion of Long-Term Debt | Finance Leases
Lease Assets and Liabilities [Abstract]
Current Liability	15,000
Other Liabilities | Operating Leases [Member]
Lease Assets and Liabilities [Abstract]
Long-Term Liability	430,000
Long-term Debt [Member] | Finance Leases
Lease Assets and Liabilities [Abstract]
Long-Term Liability	$ 43,000

Oil and Gas Exploration and P_3

Oil and Gas Exploration and Production Industries Disclosures (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2019USD ($)MBoeMBblsMMcf	Dec. 31, 2018USD ($)MBoeMBblsMMcf	Dec. 31, 2017MBoeMBblsMMcf	Dec. 31, 2016MBoeMBblsMMcf
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves (MBOE) | MBoe		1,721,212	1,548,137	1,364,335	1,093,906
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Balance at January 1 | MBoe		1,379,709	1,162,635	1,053,027
Extensions and Discoveries | MBoe		578,317	490,725	237,378
Revisions | MBoe		(49,837)	(8,244)	33,127
Acquisition of Reserves | MBoe		1,711	311	0
Sales of Reserves | MBoe		0	0	(8,253)
Conversion to Proved Developed Reserves | MBoe		(302,044)	(265,718)	(152,644)
Balance at December 31 | MBoe		1,607,856	1,379,709	1,162,635
Capitalized Costs, Oil and Gas Producing Activities, Gross [Abstract]
Proved properties | $		$ 59,229,686	$ 53,624,809
Unproved properties | $		3,600,729	3,705,207
Total | $		62,830,415	57,330,016
Accumulated depreciation, depletion and amortization | $		(35,033,085)	(31,674,085)
Net capitalized costs | $		$ 27,797,330	$ 25,655,931
Crude Oil (MBbl)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	1,532,312	1,312,973	1,177,585
Revisions of previous estimates	[1]	(42,882)	(13,376)	57,836
Purchases in place	[1]	2,859	2,743	1,111
Extensions, discoveries and other additions	[1]	369,996	383,018	207,557
Sales in place	[1]	(1,282)	(7,078)	(8,393)
Production	[1]	(166,586)	(145,968)	(122,723)
Net proved reserves - end of period	[1]	1,694,417	1,532,312	1,312,973
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves		801,598	712,785	614,236	516,625
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves		892,819	819,527	698,737	660,690
Natural Gas Liquids
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	614,329	503,473	416,366
Revisions of previous estimates	[1]	5,380	23,942	46,843
Purchases in place	[1]	1,948	2,006	421
Extensions, discoveries and other additions	[1]	167,782	127,409	75,003
Sales in place	[1]	(855)	(41)	(2,887)
Production	[1]	(48,892)	(42,460)	(32,273)
Net proved reserves - end of period	[1]	739,692	614,329	503,473
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves		387,253	341,386	286,872	230,219
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves		352,439	272,943	216,601	186,147
Natural Gas (MMcf)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period | MMcf	[2]	4,687,200	4,263,100	3,317,900
Revisions of previous estimates | MMcf	[2]	(134,800)	(91,500)	584,000
Purchases in place | MMcf	[2]	71,700	41,300	4,800
Extensions, discoveries and other additions | MMcf	[2]	1,273,100	956,000	829,400
Sales in place | MMcf	[2]	(14,500)	(22,200)	(56,400)
Production | MMcf	[2]	(513,000)	(459,500)	(416,600)
Net proved reserves - end of period | MMcf	[2]	5,369,700	4,687,200	4,263,100
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves | MMcf		3,194,100	2,963,800	2,779,300	2,082,400
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves | MMcf		2,175,600	1,723,400	1,483,800	1,235,500
Oil Equivalents (MBoe)
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved reserves - beginning of period | MBoe	[1]	2,927,846	2,526,970	2,146,933
Revisions of previous estimates | MBoe	[1]	(59,971)	(4,684)	202,018
Purchases in place | MBoe	[1]	16,761	11,640	2,332
Extensions, discoveries and other additions | MBoe	[1]	749,968	669,750	420,798
Sales in place | MBoe	[1]	(4,555)	(10,819)	(20,687)
Production | MBoe	[1]	(300,981)	(265,011)	(224,424)
Net proved reserves - end of period | MBoe	[1]	3,329,068	2,927,846	2,526,970
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserve (MBOE) | MBoe		1,607,856	1,379,709	1,162,635	1,053,027
United States
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves (MBOE) | MBoe		1,684,209	1,503,441	1,300,758	1,038,483
United States | Crude Oil (MBbl)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	1,531,684	1,304,071	1,168,491
Revisions of previous estimates	[1]	(42,959)	(13,237)	57,935
Purchases in place	[1]	2,859	2,743	1,111
Extensions, discoveries and other additions	[1]	369,968	383,003	207,137
Sales in place	[1]	(1,282)	(768)	(8,393)
Production	[1]	(166,310)	(144,128)	(122,210)
Net proved reserves - end of period	[1]	1,693,960	1,531,684	1,304,071
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves		801,189	712,218	605,405	507,531
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves		892,771	819,466	698,666	660,690
United States | Natural Gas Liquids
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	614,329	503,473	416,366
Revisions of previous estimates	[1]	5,380	23,942	46,843
Purchases in place	[1]	1,948	2,006	421
Extensions, discoveries and other additions	[1]	167,782	127,409	75,003
Sales in place	[1]	(855)	(41)	(2,887)
Production	[1]	(48,892)	(42,460)	(32,273)
Net proved reserves - end of period	[1]	739,692	614,329	503,473
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves		387,253	341,386	286,872	230,219
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves		352,439	272,943	216,601	186,147
United States | Natural Gas (MMcf)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period | MMcf	[2]	4,390,600	3,898,500	3,021,200
Revisions of previous estimates | MMcf	[2]	(184,400)	(127,200)	602,800
Purchases in place | MMcf	[2]	71,700	41,300	4,800
Extensions, discoveries and other additions | MMcf	[2]	1,175,900	951,400	619,300
Sales in place | MMcf	[2]	(14,500)	(22,200)	(56,400)
Production | MMcf	[2]	(404,500)	(351,200)	(293,200)
Net proved reserves - end of period | MMcf	[2]	5,034,800	4,390,600	3,898,500
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves | MMcf		2,974,600	2,699,000	2,450,800	1,804,400
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves | MMcf		2,060,200	1,691,600	1,447,700	1,216,800
United States | Oil Equivalents (MBoe)
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved reserves - beginning of period | MBoe	[1]	2,877,778	2,457,302	2,088,392
Revisions of previous estimates | MBoe	[1]	(68,317)	(10,500)	205,262
Purchases in place | MBoe	[1]	16,761	11,640	2,332
Extensions, discoveries and other additions | MBoe	[1]	733,730	668,972	385,354
Sales in place | MBoe	[1]	(4,555)	(4,509)	(20,687)
Production | MBoe	[1]	(282,619)	(245,127)	(203,351)
Net proved reserves - end of period | MBoe	[1]	3,272,778	2,877,778	2,457,302
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserve (MBOE) | MBoe		1,588,569	1,374,337	1,156,544	1,049,909
Trinidad
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves (MBOE) | MBoe		29,886	37,746	50,779	44,543
Trinidad | Crude Oil (MBbl)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	417	898	839
Revisions of previous estimates	[1]	85	(183)	80
Purchases in place	[1]	0	0	0
Extensions, discoveries and other additions	[1]	0	0	301
Sales in place	[1]	0	0	0
Production	[1]	(236)	(298)	(322)
Net proved reserves - end of period	[1]	266	417	898
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves		266	417	898	839
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves		0	0	0	0
Trinidad | Natural Gas Liquids
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	0	0	0
Revisions of previous estimates	[1]	0	0	0
Purchases in place	[1]	0	0	0
Extensions, discoveries and other additions	[1]	0	0	0
Sales in place	[1]	0	0	0
Production	[1]	0	0	0
Net proved reserves - end of period	[1]	0	0	0
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves		0	0	0	0
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves		0	0	0	0
Trinidad | Natural Gas (MMcf)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period | MMcf	[2]	237,000	313,400	280,900
Revisions of previous estimates | MMcf	[2]	47,000	20,700	(27,400)
Purchases in place | MMcf	[2]	0	0	0
Extensions, discoveries and other additions | MMcf	[2]	87,500	0	174,200
Sales in place | MMcf	[2]	0	0	0
Production | MMcf	[2]	(95,400)	(97,100)	(114,300)
Net proved reserves - end of period | MMcf	[2]	276,100	237,000	313,400
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves | MMcf		177,700	223,900	299,200	262,200
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves | MMcf		98,400	13,100	14,200	18,700
Trinidad | Oil Equivalents (MBoe)
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved reserves - beginning of period | MBoe	[1]	39,936	53,142	47,661
Revisions of previous estimates | MBoe	[1]	7,915	3,272	(4,493)
Purchases in place | MBoe	[1]	0	0	0
Extensions, discoveries and other additions | MBoe	[1]	14,577	0	29,340
Sales in place | MBoe	[1]	0	0	0
Production | MBoe	[1]	(16,130)	(16,478)	(19,366)
Net proved reserves - end of period | MBoe	[1]	46,298	39,936	53,142
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserve (MBOE) | MBoe		16,412	2,190	2,363	3,118
Other International
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves (MBOE) | MBoe	[3]	7,117	6,950	12,798	10,880
Other International | Crude Oil (MBbl)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1],[3]	211	8,004	8,255
Revisions of previous estimates	[1],[3]	(8)	44	(179)
Purchases in place	[1],[3]	0	0	0
Extensions, discoveries and other additions	[1],[3]	28	15	119
Sales in place	[1],[3]	0	(6,310)	0
Production	[1],[3]	(40)	(1,542)	(191)
Net proved reserves - end of period	[1],[3]	191	211	8,004
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves	[3]	143	150	7,933	8,255
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves	[3]	48	61	71	0
Other International | Natural Gas Liquids
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1],[3]	0	0	0
Revisions of previous estimates	[1],[3]	0	0	0
Purchases in place	[1],[3]	0	0	0
Extensions, discoveries and other additions	[1],[3]	0	0	0
Sales in place	[1],[3]	0	0	0
Production	[1],[3]	0	0	0
Net proved reserves - end of period	[1],[3]	0	0	0
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves	[3]	0	0	0	0
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves	[3]	0	0	0	0
Other International | Natural Gas (MMcf)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period | MMcf	[2],[3]	59,600	51,200	15,800
Revisions of previous estimates | MMcf	[2],[3]	2,600	15,000	8,600
Purchases in place | MMcf	[2],[3]	0	0	0
Extensions, discoveries and other additions | MMcf	[2],[3]	9,700	4,600	35,900
Sales in place | MMcf	[2],[3]	0	0	0
Production | MMcf	[2],[3]	(13,100)	(11,200)	(9,100)
Net proved reserves - end of period | MMcf	[2],[3]	58,800	59,600	51,200
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved developed reserves | MMcf	[3]	41,800	40,900	29,300	15,800
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserves | MMcf	[3]	17,000	18,700	21,900	0
Other International | Oil Equivalents (MBoe)
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved reserves - beginning of period | MBoe	[1],[3]	10,132	16,526	10,880
Revisions of previous estimates | MBoe	[1],[3]	431	2,544	1,249
Purchases in place | MBoe	[1],[3]	0	0	0
Extensions, discoveries and other additions | MBoe	[1],[3]	1,661	778	6,104
Sales in place | MBoe	[1],[3]	0	(6,310)	0
Production | MBoe	[1],[3]	(2,232)	(3,406)	(1,707)
Net proved reserves - end of period | MBoe	[1],[3]	9,992	10,132	16,526
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserve (MBOE) | MBoe	[3]	2,875	3,182	3,728	0
[1]	Thousand barrels or thousand barrels of oil equivalent, as applicable; oil equivalents include crude oil and condensate, NGLs and natural gas. Oil equivalents are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas.
[2]	Billion cubic feet.
[3]	Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.

Oil and Gas Exploration and P_4

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

Oil and Gas Exploration and P_5

Oil and Gas Exploration and Production Industries Disclosures, Results Of Operations (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	[1]	$ 11,581,445		$ 11,946,487		$ 7,907,891
Other	[1]	134,358		89,635		81,610
Total	[1]	11,715,803		12,036,122		7,989,501
Exploration Costs	[1]	139,881		148,999		145,342
Dry Hole Costs	[1]	28,001		5,405		4,609
Transportation Costs	[1]	758,300		746,876		740,352
Gathering and Processing Costs		479,102	[1],[2]	436,973	[1],[2]	148,775
Production Costs	[1]	2,133,986		2,028,083		1,562,210
Impairments	[1]	517,896		347,021		479,240
Depreciation, Depletion and Amortization	[1]	3,657,597		3,320,276		3,296,766
Income (Loss) Before Income Taxes	[1]	4,001,040		5,002,489		1,760,982
Income Tax Provision (Benefit)	[1]	942,582		1,100,145		649,102
Results of Operations	[1]	3,058,458		3,902,344		1,111,880
United States
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	[1]	11,250,853		11,488,620		7,570,768
Other	[1]	134,325		89,708		81,610
Total	[1]	11,385,178		11,578,328		7,652,378
Exploration Costs	[1]	130,302		121,572		113,334
Dry Hole Costs	[1]	11,133		4,983		91
Transportation Costs	[1]	753,558		742,792		737,403
Gathering and Processing Costs	[1],[2]	479,102		404,471
Production Costs	[1]	2,063,078		1,924,504		1,446,333
Impairments	[1]	510,948		344,595		477,223
Depreciation, Depletion and Amortization	[1]	3,560,609		3,181,801		3,157,056
Income (Loss) Before Income Taxes	[1]	3,876,448		4,853,610		1,720,938
Income Tax Provision (Benefit)	[1]	884,450		1,086,077		625,562
Results of Operations	[1]	2,991,998		3,767,533		1,095,376
Trinidad
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	[1]	269,957		302,112		284,673
Other	[1]	18		(49)		59
Total	[1]	269,975		302,063		284,732
Exploration Costs	[1]	4,290		21,402		26,245
Dry Hole Costs	[1]	13,033		0		0
Transportation Costs	[1]	4,014		3,236		1,885
Gathering and Processing Costs	[1],[2]	0		0
Production Costs	[1]	30,539		33,506		27,839
Impairments	[1]	5,713		0		0
Depreciation, Depletion and Amortization	[1]	79,156		91,788		115,174
Income (Loss) Before Income Taxes	[1]	133,230		152,131		113,589
Income Tax Provision (Benefit)	[1]	54,980		12,170		24,882
Results of Operations	[1]	78,250		139,961		88,707
Other International
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	[1],[3]	60,635		155,755		52,450
Other	[1],[3]	15		(24)		(59)
Total	[1],[3]	60,650		155,731		52,391
Exploration Costs	[1],[3]	5,289		6,025		5,763
Dry Hole Costs	[1],[3]	3,835		422		4,518
Transportation Costs	[1],[3]	728		848		1,064
Gathering and Processing Costs	[1],[2],[3]	0		32,502
Production Costs	[1],[3]	40,369		70,073		88,038
Impairments	[1],[3]	1,235		2,426		2,017
Depreciation, Depletion and Amortization	[1],[3]	17,832		46,687		24,536
Income (Loss) Before Income Taxes	[1],[3]	(8,638)		(3,252)		(73,545)
Income Tax Provision (Benefit)	[1],[3]	3,152		1,898		(1,342)
Results of Operations	[1],[3]	$ (11,790)		$ (5,150)		$ (72,203)
[1]	Excludes gains or losses on the mark-to-market of financial commodity derivative contracts, gains or losses on sales of reserves and related assets, interest charges and general corporate expenses for each of the three years in the period ended December 31, 2019 .
[2]	Effective January 1, 2018, EOG adopted the provisions of Accounting Standards Update (ASU) 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements within its United States segment as Gathering and Processing Costs instead of as a deduction to Natural Gas Revenues. There was no impact to operating income or net income resulting from changes to the presentation of natural gas processing fees (see Note 1 to Consolidated Financial Statements).
[3]	Other International primarily consists of EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.

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, 2019	Dec. 31, 2018	Dec. 31, 2017
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent		4.54	4.84	4.66
United States
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent		4.59	4.84	4.58
Trinidad
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent		1.85	1.67	1.39
Other International
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent	[1]	18.26	20.19	50.86
[1]	Other International primarily consists of EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.

Oil and Gas Exploration and P_7

Oil and Gas Exploration and Production Industries Disclosures, Discounted Future Net Cash Flows (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2019USD ($)		Dec. 31, 2018USD ($)		Dec. 31, 2017USD ($)
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows					$ 121,478,362	[1]	$ 134,119,690	[2]	$ 85,221,064	[3]
Future production costs					(42,641,887)		(42,654,642)		(32,569,408)
Future development costs					(20,586,449)		(16,667,893)		(13,538,795)
Future income taxes					(11,565,498)		(14,962,141)		(6,160,541)
Future net cash flows					46,684,528		59,835,014		32,952,320
Discount to present value at 10% annual rate					(21,163,763)		(27,409,059)		(14,624,660)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves		$ 25,520,765	$ 18,327,660	$ 8,812,157	25,520,765		32,425,955		18,327,660
Annual Rate of Discount to Present Value		10.00%	10.00%	10.00%
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at Beginning of Period		$ 32,425,955	$ 18,327,660	$ 8,812,157
Sales and transfers of oil and gas produced, net of production costs		(8,210,438)	(8,734,622)	(5,605,330)
Net changes in prices and production costs		(10,880,447)	12,856,429	7,121,545
Extensions, discoveries, additions and improved recovery, net of related costs		5,709,558	8,430,953	3,958,248
Development costs incurred		3,032,150	2,745,160	1,440,300
Revisions of estimated development cost		(738,024)	(410,525)	(124,877)
Revisions of previous quantity estimates		(695,521)	(101,726)	2,438,271
Accretion of discount		3,949,758	2,042,622	886,707
Net change in income taxes		1,548,707	(4,973,058)	(2,043,663)
Purchases of reserves in place		98,539	116,887	30,362
Sales of reserves in place		(50,651)	(117,932)	(76,527)
Changes in timing and other		(668,821)	2,244,107	1,490,467
Balance at End of Period		25,520,765	32,425,955	18,327,660
United States
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows					120,359,769	[1]	133,066,375	[2]	83,652,363	[3]
Future production costs					(42,387,801)		(42,351,174)		(32,018,812)
Future development costs					(20,355,746)		(16,577,794)		(13,395,873)
Future income taxes					(11,459,567)		(14,756,011)		(5,948,453)
Future net cash flows					46,156,655		59,381,396		32,289,225
Discount to present value at 10% annual rate					(21,042,593)		(27,348,744)		(14,532,290)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves		32,032,652	17,756,935	8,493,727	$ 25,114,062		$ 32,032,652		$ 17,756,935
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at Beginning of Period		32,032,652	17,756,935	8,493,727
Sales and transfers of oil and gas produced, net of production costs		(7,955,115)	(8,416,853)	(5,387,031)
Net changes in prices and production costs		(10,973,981)	12,750,466	6,606,908
Extensions, discoveries, additions and improved recovery, net of related costs		5,608,038	8,418,666	3,644,041
Development costs incurred		3,003,510	2,732,560	1,435,600
Revisions of estimated development cost		(597,869)	(410,741)	(114,464)
Revisions of previous quantity estimates		(812,781)	(173,084)	2,460,498
Accretion of discount		3,891,701	1,967,592	849,373
Net change in income taxes		1,454,050	(4,965,373)	(1,918,989)
Purchases of reserves in place		98,539	116,887	30,362
Sales of reserves in place		(50,651)	(35,874)	(76,527)
Changes in timing and other		(584,031)	2,291,471	1,733,437
Balance at End of Period		25,114,062	32,032,652	17,756,935
United States | Crude Oil [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows					57.51		68.54		49.21
United States | Natural Gas Liquids [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows					16.91		27.83		23.51
United States | Natural Gas [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows					2.07		2.50		1.96
Trinidad
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows					$ 813,102	[1]	$ 749,695	[2]	$ 904,141	[3]
Future production costs					(166,705)		(204,444)		(239,213)
Future development costs					(212,303)		(78,199)		(84,379)
Future income taxes					(73,508)		(174,382)		(195,855)
Future net cash flows					360,586		292,670		384,694
Discount to present value at 10% annual rate					(86,009)		(26,832)		(52,267)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves		265,838	265,838	332,427	$ 274,577		$ 265,838		$ 332,427
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at Beginning of Period		265,838	332,427	185,750
Sales and transfers of oil and gas produced, net of production costs		(235,404)	(265,370)	(254,948)
Net changes in prices and production costs		65,962	84,353	436,969
Extensions, discoveries, additions and improved recovery, net of related costs		85,233	0	270,255
Development costs incurred		22,820	0	4,700
Revisions of estimated development cost		(129,047)	4,030	9,683
Revisions of previous quantity estimates		116,062	39,608	(58,373)
Accretion of discount		43,148	50,191	24,066
Net change in income taxes		93,975	3,844	(114,575)
Purchases of reserves in place		0	0	0
Sales of reserves in place		0	0	0
Changes in timing and other		(54,010)	16,755	(171,100)
Balance at End of Period		274,577	265,838	332,427
Trinidad | Crude Oil [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows					46.77		55.66		41.87
Trinidad | Natural Gas [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows					2.90		3.06		2.76
Other International (1)
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	[4]				$ 305,491	[1]	$ 303,620	[2]	$ 664,560	[3]
Future production costs	[4]				(87,381)		(99,024)		(311,383)
Future development costs	[4]				(18,400)		(11,900)		(58,543)
Future income taxes	[4]				(32,423)		(31,748)		(16,233)
Future net cash flows	[4]				167,287		160,948		278,401
Discount to present value at 10% annual rate	[4]				(35,161)		(33,483)		(40,103)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	[4]	127,465	238,298	238,298	$ 132,126		$ 127,465		$ 238,298
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at Beginning of Period	[4]	127,465	238,298	132,680
Sales and transfers of oil and gas produced, net of production costs	[4]	(19,919)	(52,399)	36,649
Net changes in prices and production costs	[4]	27,572	21,610	77,668
Extensions, discoveries, additions and improved recovery, net of related costs	[4]	16,287	12,287	43,952
Development costs incurred	[4]	5,820	12,600	0
Revisions of estimated development cost	[4]	(11,108)	(3,814)	(20,096)
Revisions of previous quantity estimates	[4]	1,198	31,750	36,146
Accretion of discount	[4]	14,909	24,839	13,268
Net change in income taxes	[4]	682	(11,529)	(10,099)
Purchases of reserves in place	[4]	0	0	0
Sales of reserves in place	[4]	0	(82,058)	0
Changes in timing and other	[4]	(30,780)	(64,119)	(71,870)
Balance at End of Period	[4]	$ 132,126	$ 127,465	$ 238,298
Other International (1) | Crude Oil [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows					57.22		61.66		50.06
Other International (1) | Natural Gas [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Per unit price used to calculate future cash inflows					5.01		4.88		5.16
[1]	Estimated crude oil prices used to calculate 2019 future cash inflows for the United States, Trinidad and Other International were $57.51 , $46.77 , and $57.22 , respectively. Estimated NGL price used to calculate 2019 future cash inflows for the United States was $16.91 . Estimated natural gas prices used to calculate 2019 future cash inflows for the United States, Trinidad and Other International were $2.07 , $2.90 , and $5.01 , respectively.
[2]	Estimated crude oil prices used to calculate 2018 future cash inflows for the United States, Trinidad and Other International were $68.54 , $55.66 and $61.66 , respectively. Estimated NGL price used to calculate 2018 future cash inflows for the United States was $27.83 . Estimated natural gas prices used to calculate 2018 future cash inflows for the United States, Trinidad and Other International were $2.50 , $3.06 and $4.88 , respectively.
[3]	Estimated crude oil prices used to calculate 2017 future cash inflows for the United States, Trinidad and Other International were $49.21 , $41.87 and $50.06 , respectively. Estimated NGL price used to calculate 2017 future cash inflows for the United States was $23.51 . Estimated natural gas prices used to calculate 2017 future cash inflows for the United States, Trinidad and Other International were $1.96 , $2.76 and $5.16 , respectively.
[4]	Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.

Unaudited Quarterly Financial_3

Unaudited Quarterly Financial Information (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2019		Sep. 30, 2019		Jun. 30, 2019		Mar. 31, 2019		Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Operating Revenues and Other	$ 4,320,246		$ 4,303,455		$ 4,697,630		$ 4,058,642		$ 4,574,536		$ 4,781,624		$ 4,238,077		$ 3,681,162		$ 17,379,973	$ 17,275,399	$ 11,208,320
Operating Income	863,751		827,959		1,130,771		876,530		1,123,140		1,506,687		964,931		874,588		3,699,011	4,469,346	926,402
Income (Loss) Before Income Taxes	831,208		797,457		1,089,366		827,236		1,088,340		1,446,363		892,936		813,359
Income Tax Provision (Benefit)	194,687		182,335		241,525		191,810		195,572		255,411		196,205		174,770		810,357	821,958	(1,921,397)
Net Income (Loss)	$ 636,521		$ 615,122		$ 847,841		$ 635,426		$ 892,768		$ 1,190,952		$ 696,731		$ 638,589		$ 2,734,910	$ 3,419,040	$ 2,582,579
Net Income (Loss) Per Share
Basic (in dollars per share)	$ 1.10	[1]	$ 1.06	[1]	$ 1.47	[1]	$ 1.10	[1]	$ 1.55	[1]	$ 2.06	[1]	$ 1.21	[1]	$ 1.11	[1]	$ 4.73	$ 5.93	$ 4.49
Diluted (in dollars per share)	$ 1.10	[1]	$ 1.06	[1]	$ 1.46	[1]	$ 1.10	[1]	$ 1.54	[1]	$ 2.05	[1]	$ 1.20	[1]	$ 1.10	[1]	$ 4.71	$ 5.89	$ 4.46
Average Number of Common Shares [Abstract]
Basic (in shares)	578,219		577,839		577,460		577,207		577,035		577,254		576,135		575,775		577,670	576,578	574,620
Diluted (in shares)	580,849		581,271		580,247		580,222		580,288		581,559		580,375		579,726		580,777	580,441	578,693
[1]	The sum of quarterly net income per share may not agree with total year net income per share as each quarterly computation is based on the weighted average of common shares outstanding.