EOG Resources (EOG) 10-K 27 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 16, 2018	Jun. 30, 2017
Document and Entity Information [Abstract]
Entity Registrant Name	EOG RESOURCES INC
Entity Central Index Key	821,189
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 52,112,000,000
Entity Common Stock, Shares Outstanding		578,636,343
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017

Consolidated Statements of Inco

Consolidated Statements of Income and Comprehensive Income - USD ($) shares in Thousands, $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Net Operating Revenues and Other
Crude Oil and Condensate		$ 6,256,396	$ 4,317,341	$ 4,934,562
Natural Gas Liquids		729,561	437,250	407,658
Natural Gas		921,934	742,152	1,061,038
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts		19,828	(99,608)	61,924
Gathering, Processing and Marketing		3,298,087	1,966,259	2,253,135
Gains (Losses) on Asset Dispositions, Net		(99,096)	205,835	(8,798)
Other, Net	[1]	81,610	81,403	47,909
Total		11,208,320	7,650,632	8,757,428
Operating Expenses
Lease and Well		1,044,847	927,452	1,182,282
Transportation Costs	[1]	740,352	764,106	849,319
Gathering and Processing Costs		148,775	122,901	146,156
Exploration Costs		145,342	124,953	149,494
Dry Hole Costs	[1]	4,609	10,657	14,746
Impairments		479,240	620,267	6,613,546
Marketing Costs		3,330,237	2,007,635	2,385,982
Depreciation, Depletion and Amortization		3,409,387	3,553,417	3,313,644
General and Administrative		434,467	394,815	366,594
Taxes Other Than Income		544,662	349,710	421,744
Total		10,281,918	8,875,913	15,443,507
Operating Income (Loss)		926,402	(1,225,281)	(6,686,079)
Other Income (Expense), Net		9,152	(50,543)	1,916
Income (Loss) Before Interest Expense and Income Taxes		935,554	(1,275,824)	(6,684,163)
Interest Expense
Incurred		301,801	313,341	279,234
Capitalized		(27,429)	(31,660)	(41,841)
Net Interest Expense		274,372	281,681	237,393
Income (Loss) Before Income Taxes		661,182	(1,557,505)	(6,921,556)
Income Tax Benefit		(1,921,397)	(460,819)	(2,397,041)
Net Income (Loss)		$ 2,582,579	$ (1,096,686)	$ (4,524,515)
Net Income (Loss) Per Share
Basic		$ 4.49	$ (1.98)	$ (8.29)
Diluted		4.46	(1.98)	(8.29)
Dividends Declared per Common Share		$ 0.670	$ 0.670	$ 0.670
Average Number of Common Shares [Abstract]
Basic (in shares)		574,620	553,384	545,697
Diluted		578,693	553,384	545,697
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments		$ 2,799	$ 12,097	$ (11,517)
Other, Net of Tax		(3,086)	2,231	1,235
Other Comprehensive Income (Loss)		(287)	14,328	(10,282)
Comprehensive Income (Loss)		$ 2,582,292	$ (1,082,358)	$ (4,534,797)
[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, 2017.

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Current Assets
Cash and Cash Equivalents		$ 834,228	$ 1,599,895
Accounts Receivable, Net		1,597,494	1,216,320
Inventories		483,865	350,017
Assets from Price Risk Management Activities		7,699	0
Income Taxes Receivable		113,357	12,305
Other		242,465	206,679
Total		3,279,108	3,385,216
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)		52,555,741	49,592,091
Other Property, Plant and Equipment		3,960,759	4,008,564
Total Property, Plant and Equipment		56,516,500	53,600,655
Less: Accumulated Depreciation, Depletion and Amortization		(30,851,463)	(27,893,577)
Total Property, Plant and Equipment, Net		25,665,037	25,707,078
Deferred Income Taxes		17,506	16,140
Other Assets		871,427	190,767
Total Assets		29,833,078	29,299,201	[1]
Current Liabilities
Accounts Payable		1,847,131	1,511,826
Accrued Taxes Payable		148,874	118,411
Dividends Payable		96,410	96,120
Liabilities from Price Risk Management Activities		50,429	61,817
Current Portion of Long-Term Debt		356,235	6,579
Other		226,463	232,538
Total		2,725,542	2,027,291
Long-Term Debt		6,030,836	6,979,779
Other Liabilities		1,275,213	1,282,142
Deferred Income Taxes	[2]	3,518,214	5,028,408	[3]
Commitments and Contingencies (Note 8)
Stockholders' Equity
Common Stock, $0.01 Par, 1,280,000,000 Shares and 640,000,000 Shares Authorized at December 31, 2017 and 2016, respectively, and 578,827,768 Shares and 576,950,272 Shares Issued at December 31, 2017 and 2016, respectively		205,788	205,770
Additional Paid in Capital		5,536,547	5,420,385
Accumulated Other Comprehensive Loss		(19,297)	(19,010)
Retained Earnings		10,593,533	8,398,118
Common Stock Held in Treasury, 350,961 Shares and 250,155 Shares at December 31, 2017 and 2016, respectively		(33,298)	(23,682)
Total Stockholders' Equity		16,283,273	13,981,581
Total Liabilities and Stockholders' Equity		$ 29,833,078	$ 29,299,201
[1]	EOG made a reclassification of $160 million from deferred tax liabilities to deferred tax assets for the year ended December 31, 2016, for the United States segment and in total.
[2]	United States federal deferred tax assets and liabilities tax effected at 21% and 35% for 2017 and 2016, respectively.
[3]	As described in Note 1, ASU 2015-17 eliminated the requirement to separate deferred tax assets and liabilities into current and noncurrent amounts.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Common Stock
Common Stock, Par Value (in dollars per share)	$ 0.01	$ 0.01
Common Stock, Shares Authorized (in shares)	1,280,000,000	640,000,000
Common Stock, Shares Issued (in shares)	578,827,768	576,950,272
Treasury Stock
Common Stock Held in Treasury (in shares)	350,961	250,155

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, 2014	$ 17,712,582	$ 205,492	$ 2,837,150	$ (23,056)	$ 14,763,098	$ (70,102)
Net Income (Loss)	(4,524,515)	0	0	0	(4,524,515)	0
Common Stock Issued Under Stock Plans	15,371	5	15,366	0	0	0
Dividends, Common Stock	$ (367,767)	0	0	0	(367,767)	0
Common Stock Dividends Declared (in dollars per share)	$ 0.670
Other Comprehensive Income (Loss)	$ (10,282)	0	0	(10,282)	0	0
Change in Treasury Stock - Stock Compensation Plans, Net	(41,471)	0	(41,342)	0	0	(129)
Excess Tax Benefit from Stock-Based Compensation	26,058	0	26,058	0	0	0
Restricted Stock and Restricted Stock Units, Net	0	5	(44,339)	0	0	44,334
Stock-Based Compensation Expenses	130,577	0	130,577	0	0	0
Treasury Stock Issued as Compensation	2,482	0	(9)	0	0	2,491
Balance at Dec. 31, 2015	12,943,035	205,502	2,923,461	(33,338)	9,870,816	(23,406)
Net Income (Loss)	(1,096,686)	0	0	0	(1,096,686)	0
Common Stock Issued for the Yates Transaction	2,397,887	252	2,397,635	0	0	0
Common Stock Issued Under Stock Plans	16,397	9	16,388	0	0	0
Dividends, Common Stock	$ (376,012)	0	0	0	(376,012)	0
Common Stock Dividends Declared (in dollars per share)	$ 0.670
Other Comprehensive Income (Loss)	$ 14,328	0	0	14,328	0	0
Change in Treasury Stock - Stock Compensation Plans, Net	(75,226)	0	(27,018)	0	0	(48,208)
Excess Tax Benefit from Stock-Based Compensation	29,357	0	29,357	0	0	0
Restricted Stock and Restricted Stock Units, Net	0	7	(47,509)	0	0	47,502
Stock-Based Compensation Expenses	128,090	0	128,090	0	0	0
Treasury Stock Issued as Compensation	411	0	(19)	0	0	430
Balance at Dec. 31, 2016	13,981,581	205,770	5,420,385	(19,010)	8,398,118	(23,682)
Net Income (Loss)	2,582,579	0	0	0	2,582,579
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)

Consolidated Statements of Sto6

Consolidated Statements of Stockholders' Equity (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Stockholders' Equity [Abstract]
Dividends, Common Stock	$ 387,164	$ 376,012	$ 367,767
Common Stock Dividends Declared (in dollars per share)	$ 0.670	$ 0.670	$ 0.670

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash Flows from Operating Activities
Net Income (Loss)		$ 2,582,579	$ (1,096,686)	$ (4,524,515)
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization		3,409,387	3,553,417	3,313,644
Impairments		479,240	620,267	6,613,546
Stock-Based Compensation Expenses		133,849	128,090	130,577
Deferred Income Taxes		(1,473,872)	(515,206)	(2,482,307)
Gains (Losses) on Asset Dispositions, Net		(99,096)	205,835	(8,798)
Other, Net		6,546	61,690	11,896
Dry Hole Costs	[1]	4,609	10,657	14,746
Mark-to-Market Commodity Derivative Contracts
Total (Gains) Losses		(19,828)	99,608	(61,924)
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts		7,438	(22,219)	730,114
Excess Tax Benefits from Stock-Based Compensation		0	(29,357)	(26,058)
Other, Net		1,204	10,971	12,532
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		(392,131)	(232,799)	641,412
Inventories		(174,548)	170,694	58,450
Accounts Payable		324,192	(74,048)	(1,409,197)
Accrued Taxes Payable		(63,937)	92,782	11,798
Other Assets		(658,609)	(40,636)	118,143
Other Liabilities		(89,871)	(16,225)	(66,257)
Changes in Components of Working Capital Associated with Investing and Financing Activities		89,992	(156,102)	499,767
Net Cash Provided by Operating Activities		4,265,336	2,359,063	3,595,165
Investing Cash Flows
Additions to Oil and Gas Properties		(3,950,918)	(2,489,756)	(4,725,150)
Additions to Other Property, Plant and Equipment		(173,324)	(93,039)	(288,013)
Proceeds from Sales of Assets		226,768	1,119,215	192,807
Payments to Acquire Businesses, Net of Cash Acquired		0	54,534	0
Changes in Components of Working Capital Associated with Investing Activities		(89,935)	156,102	(499,900)
Net Cash Used in Investing Activities		(3,987,409)	(1,252,944)	(5,320,256)
Financing Cash Flows
Net Commercial Paper (Repayments) Borrowings		0	(259,718)	259,718
Long-Term Debt Borrowings		0	991,097	990,225
Long-Term Debt Repayments		(600,000)	(563,829)	(500,000)
Dividends Paid		(386,531)	(372,845)	(367,005)
Excess Tax Benefits from Stock-Based Compensation		0	29,357	26,058
Treasury Stock Purchased		(63,408)	(82,125)	(48,791)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan		20,840	23,296	22,690
Debt Issuance Costs		0	(1,602)	(5,951)
Repayment of Capital Lease Obligation		(6,555)	(6,353)	(6,156)
Other, Net		(57)	0	133
Net Cash (Used in) Provided by Financing Activities		(1,035,711)	(242,722)	370,921
Effect of Exchange Rate Changes on Cash		(7,883)	17,992	(14,537)
Increase (Decrease) in Cash and Cash Equivalents		(765,667)	881,389	(1,368,707)
Cash and Cash Equivalents at Beginning of Year		1,599,895	718,506	2,087,213
Cash and Cash Equivalents at End of Year		$ 834,228	$ 1,599,895	$ 718,506
[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, 2017.

Summary of Significant Accounti

Summary of Significant Accounting Policies (Notes)	12 Months Ended
	Dec. 31, 2017
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 proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made (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 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 future crude oil and natural gas prices, operating costs, 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. If applicable, EOG utilizes accepted bids 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 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. Arrangements for sales of crude oil and condensate, natural gas liquids (NGLs) and natural gas are evidenced by signed contracts with determinable market prices, and revenues are recorded when production is delivered. A significant majority of these products are sold to purchasers who have investment-grade credit ratings and material credit losses have been rare. Revenues are recorded on the entitlement method based on EOG's percentage ownership of current production. Each working interest owner in a well generally has the right to a specific percentage of production, although actual production sold on that owner's behalf may differ from that owner's ownership percentage. Under entitlement accounting, a receivable is recorded when underproduction occurs and a payable is recorded when overproduction occurs. Gathering, processing and marketing revenues represent sales of third-party crude oil and condensate, NGLs and natural gas, as well as gathering fees associated with gathering third-party natural gas and revenues from sales of EOG-owned sand. 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, 2017, EOG elected not to designate any of its financial commodity derivative instruments as accounting hedges and, accordingly, changes in the fair value of these outstanding derivative instruments are recognized as gains or losses in the period of change. The gains or losses are recorded as Gains (Losses) on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss). The related cash flow impact of settled contracts is reflected as cash flows from operating activities. EOG employs net presentation of derivative assets and liabilities for financial reporting purposes when such assets and liabilities are with the same counterparty and subject to a master netting arrangement. See Note 12. Income Taxes. Income taxes are accounted for using the asset and liability approach. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. EOG assesses the realizability of deferred tax assets and recognizes valuation allowances as appropriate. In December 2017, the United States (U.S.) enacted the Tax Cuts and Jobs Act (TCJA), which made significant changes to U.S. federal income tax law. Shortly after enactment of the TCJA, the United States Securities and Exchange Commission's (SEC) staff issued Staff Accounting Bulletin No. 118 (SAB 118), which provides guidance on accounting for the impact of the TCJA. Under SAB 118, an entity would use a similar approach as the measurement period provided in the Business Combinations Topic of the ASC. An entity will recognize those matters for which the accounting can be completed. For matters that have not been completed, the entity would either (1) recognize provisional amounts to the extent that they are reasonably estimable and adjust them over time as more information becomes available or (2) for any specific income tax effects of the TCJA for which a reasonable estimate cannot be determined, continue to apply the Income Taxes Topic of the ASC on the basis of the provisions of the tax laws that were in effect immediately before the TCJA was signed into law. EOG has prepared its consolidated financial statements for the fiscal year ended December 31, 2017 in accordance with the Income Taxes Topic of the ASC as allowed by SAB 118. 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, for which the functional currency is 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 Income (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 (loss) in the current period. See Note 4. Net Income (Loss) Per Share. Basic net income (loss) per share is computed on the basis of the weighted-average number of common shares outstanding during the period. Diluted net income (loss) per share is computed based upon the weighted-average number of common shares outstanding during the period plus the assumed issuance of common shares for all potentially dilutive securities. See Note 9. Stock-Based Compensation . EOG measures the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. See Note 7. Recently Issued Accounting Standards. In February 2017, the FASB issued Accounting Standards Update (ASU) 2017-05, "Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20) - Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets" (ASU 2017-05). ASU 2017-05 clarifies the scope and application of ASC 610-20 to the sale or transfer of nonfinancial assets and, in substance, nonfinancial assets to noncustomers, including partial sales. ASU 2017-05 is effective for interim and annual periods beginning after December 15, 2017. EOG will adopt ASU 2017-05 in connection with the adoption of "Revenue From Contracts With Customers" (ASU 2014-09) effective January 1, 2018. In January 2017, the FASB issued ASU 2017-01 "Business Combinations (Topic 805): Clarifying the Definition of a Business" (ASU 2017-01), which clarifies the definition of a business to provide guidance in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 provides a screen to determine when a set of assets is not a business, requiring that when substantially all fair value of gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets, the set of assets is not a business. A framework is provided to assist in evaluating whether both an input and a substantive process are present for the set to be a business. ASU 2017-01 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. No disclosures are required at transition. The new standard may result in more transactions being accounted for as acquisitions (and dispositions) of assets rather than businesses. EOG will adopt ASU 2017-01 on a prospective basis effective January 1, 2018. In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230) - Classification of Certain Cash Receipts and Cash Payments” (ASU 2016-15). ASU 2016-15 reduces existing diversity in practice by providing guidance on the classification of eight specific cash receipts and cash payments transactions in the statement of cash flows. The new standard is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. EOG will adopt ASU 2016-15 on a retrospective basis on January 1, 2018. There will be no impact to the presentation of comparable periods upon adoption. In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" (ASU 2016-02), which significantly changes accounting for leases by requiring that lessees recognize a right-of-use asset and a related lease liability representing the obligation to make lease payments, for virtually all lease transactions. Additional disclosures about an entity's lease transactions will also be required. ASU 2016-02 defines a lease as "a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration." ASU 2016-02 is effective for interim and annual periods beginning after December 31, 2018 and early application is permitted. Lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented in the financial statements using a modified retrospective approach. EOG is continuing its assessment of ASU 2016-02 and has further developed its project plan, evaluated certain operational and corporate processes and selected certain contracts for additional review. In May 2014, the FASB issued ASU 2014-09, which will 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. ASU 2014-09 will supersede most current guidance related to revenue recognition when it becomes effective. The new standard also will require expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. ASU 2014-09 is effective for interim and annual reporting periods beginning after December 15, 2017. The new standard permits adoption through the use of either the full retrospective approach or a modified retrospective approach. In May 2016, the FASB issued ASU 2016-11, which rescinds certain SEC guidance in the related ASC, including guidance related to the use of the "entitlements" method of revenue recognition used by EOG. EOG will adopt ASU 2014-09 utilizing the modified retrospective approach effective January 1, 2018. Upon adoption of ASU 2014-09, EOG expects to prospectively present natural gas processing fees for certain processing and marketing agreements as Gathering and Processing Costs, instead of a deduction to Revenues within its Consolidated Statements of Income (Loss) and Comprehensive Income (Loss). EOG does not expect a material impact to operating income, net income or cash flows upon changes to the presentation of natural gas processing fees. Also, EOG does not expect a material impact to the financial statements upon elimination of the entitlements method and other adoption requirements. Upon adoption, EOG will also include additional disclosures as required by ASU 2014-09. Effective January 1, 2017, EOG adopted the provisions of ASU 2015-17, "Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes" (ASU 2015-17), which simplifies the presentation of deferred taxes in a classified balance sheet by eliminating the requirement to separate deferred income tax liabilities and assets into current and noncurrent amounts. Instead, ASU 2015-17 requires that all deferred tax liabilities and assets be shown as noncurrent in a classified balance sheet. In connection with the adoption of ASU 2015-17, EOG restated its December 31, 2016 balance sheet to reclassify $169 million of current deferred income tax assets as noncurrent. Effective January 1, 2017, EOG adopted the provisions of ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting" (ASU 2016-09), which amends certain aspects of accounting for share-based payment arrangements. ASU 2016-09 revises or provides alternative accounting for the tax impacts of share-based payment arrangements, forfeitures and minimum statutory tax withholdings and prescribes certain disclosures to be made in the period the new standard is adopted. There was no impact to retained earnings with respect to excess tax benefits. EOG began recognizing income tax associated with excess tax benefits and tax deficiencies as discrete benefits and expenses, respectively, in the income tax provision. Net excess tax benefits recognized within income tax provision was $32 million for the year ended December 31, 2017. The treatment of forfeitures did not change as EOG elected to continue the current process of estimating the number of forfeitures. As such, this had no cumulative effect on retained earnings. EOG elected to present changes to the statements of cash flows on a prospective transition method.

Long-Term Debt (Notes)

Long-Term Debt (Notes)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Long-Term Debt at December 31, 2017 and 2016 consisted of the following (in thousands): 2017 2016 5.875% Senior Notes due 2017 $ — $ 600,000 6.875% Senior Notes due 2018 350,000 350,000 5.625% Senior Notes due 2019 900,000 900,000 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 6,390,000 6,990,000 Capital Lease Obligation 32,155 38,710 Less: Current Portion of Long-Term Debt 356,235 6,579 Unamortized Debt Discount 30,564 36,915 Debt Issuance Costs 4,520 5,437 Total Long-Term Debt $ 6,030,836 $ 6,979,779 At December 31, 2017 , the aggregate annual maturities of long-term debt (excluding capital lease obligations) were $ 350 million in 2018, $ 900 million in 2019, $1 billion in 2020, $750 million in 2021 and zero in 2022. At December 31, 2017 and 2016 , EOG had no outstanding short-term borrowings under the commercial paper program and no outstanding borrowings under uncommitted credit facilities. During 2017 and 2016 , EOG utilized commercial paper bearing market interest rates, for various corporate financing purposes. EOG had no outstanding commercial paper borrowings at December 31, 2017. The average borrowings outstanding under the commercial paper program were $84 million and $130 million during the years ended December 31, 2017 and 2016, respectively. The weighted average interest rates for commercial paper borrowings were 1.44% and 0.76% for the years 2017 and 2016, respectively. On September 15, 2017, EOG repaid upon maturity the $600 million aggregate principal amount of its 5.875% Senior Notes due 2017. On February 1, 2016, EOG repaid upon maturity the $400 million aggregate principal amount of its 2.500% Senior Notes due 2016. On January 14, 2016, EOG closed its sale of $750 million aggregate principal amount of its 4.15% Senior Notes due 2026 and $250 million aggregate principal amount of its 5.10% Senior Notes due 2036 (collectively, the Notes). Interest on the Notes is payable semi-annually in arrears on January 15 and July 15 of each year, beginning on July 15, 2016. Net proceeds from the Notes offering totaled approximately $991 million and were used to repay EOG's 2.500% Senior Notes due 2016 and for general corporate purposes, including repayment of outstanding commercial paper borrowings and funding of future capital expenditures. EOG currently has a $2.0 billion senior unsecured Revolving Credit Agreement (Agreement) with domestic and foreign lenders. The Agreement has a scheduled maturity date of July 21, 2020 , 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. Advances under the Agreement 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 Agreement) plus an applicable margin. The Agreement contains representations, warranties, covenants and events of default that are customary for investment-grade, senior unsecured commercial bank credit agreements, including a financial covenant for the maintenance of a debt-to-total capitalization ratio of no greater than 65% . At December 31, 2017, EOG was in compliance with this financial covenant. At December 31, 2017 , there were no borrowings or letters of credit outstanding under the Agreement. The Eurodollar rate and applicable base rate, had there been any amounts borrowed under the Agreement, would have been 2.56% and 4.50% , respectively.

Stockholder's Equity (Notes)

Stockholder's Equity (Notes)	12 Months Ended
	Dec. 31, 2017
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, 2017 , 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 stock or performance unit grants or in payment of the exercise price of employee stock options. Such shares withheld or returned do not count against the Board authorization discussed above. Shares purchased, withheld and returned are held in treasury for, among other purposes, fulfilling any obligations arising under EOG's stock-based compensation plans and any other approved transactions or activities for which such shares of Common Stock may be required. On February 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. On October 4, 2016, EOG issued approximately 25 million shares of EOG common stock in connection with the Yates transaction. See Note 17. EOG declared and paid quarterly cash dividends of $0.1675 per share in 2017, 2016 and 2015. On February 27, 2018, EOG's Board increased the quarterly cash dividend on the common stock by 10% from the current $0.1675 per share to $0.1850 per share, effective beginning with the dividend to be paid on April 30, 2018, to stockholders of record as of April 16, 2018. The following summarizes Common Stock activity for each of the years ended December 31, 2015 , 2016 and 2017 (in thousands): Common Shares Issued Treasury Outstanding Balance at December 31, 2014 549,028 (733 ) 548,295 Common Stock Issued Under Stock-Based Compensation Plans 1,019 — 1,019 Treasury Stock Purchased (1) — (581 ) (581 ) Common Stock Issued Under Employee Stock Purchase Plan 104 121 225 Treasury Stock Issued Under Stock-Based Compensation Plans — 901 901 Balance at December 31, 2015 550,151 (292 ) 549,859 Common Stock Issued 25,204 — 25,204 Common Stock Issued Under Stock-Based Compensation Plans 1,500 — 1,500 Treasury Stock Purchased (1) — (922 ) (922 ) Common Stock Issued Under Employee Stock Purchase Plan 95 117 212 Treasury Stock Issued Under Stock-Based Compensation Plans — 847 847 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 (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 stock or performance unit grants or (ii) in payment of the exercise price of employee stock options. Preferred Stock . EOG currently has one authorized series of preferred stock. As of December 31, 2017 , there were no shares of preferred stock outstanding.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income (Loss) Accumulated other comprehensive income (loss) includes certain transactions that have generally been reported in the Consolidated Statements of Stockholders' Equity. The components of Accumulated Other Comprehensive Income (Loss) at December 31, 2017 and 2016 consisted of the following (in thousands): Foreign Currency Translation Adjustment Other Total December 31, 2015 $ (31,538 ) $ (1,800 ) $ (33,338 ) Other comprehensive loss before reclassifications 12,097 2,901 14,998 Tax effects — (670 ) (670 ) Other comprehensive income (loss) 12,097 2,231 14,328 December 31, 2016 (19,441 ) 431 (19,010 ) Other comprehensive income before reclassifications 2,799 (3,728 ) (929 ) Tax effects — 642 642 Other comprehensive income 2,799 (3,086 ) (287 ) December 31, 2017 $ (16,642 ) $ (2,655 ) $ (19,297 ) No significant amount was reclassified out of Accumulated Other Comprehensive Income (Loss) during the year ended December 31, 2017.

Other Income (Expense), Net (No

Other Income (Expense), Net (Notes)	12 Months Ended
	Dec. 31, 2017
Other Income and Expenses [Abstract]
Other Income (Expense), Net	Other Income (Expense), Net 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 ). Other expense, net for 2016 included net foreign currency transaction losses ( $(41) million ) and an upward adjustment to deferred compensation expense ( $(11) million ), partially offset by equity income from investments in ammonia plants in Trinidad ( $4 million ). Other income, net, for 2015 included equity income from investments in ammonia plants in Trinidad ( $9 million ), a downward adjustment to deferred compensation expense ( $6 million ), interest income ( $3 million ) and net foreign currency transaction losses ( $(17) million ).

Income Taxes (Notes)

Income Taxes (Notes)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes As previously discussed, the U.S. enacted the TCJA in December 2017. Under the Income Taxes Topic of the ASC, the effects of new legislation are recognized upon enactment. Accordingly, recognition of the tax effects of the TCJA is required in the consolidated financial statements for the fiscal year ended December 31, 2017. Shortly after enactment of the TCJA, the SEC staff issued SAB 118 addressing the application of U.S. GAAP in situations when the registrant does not have the necessary information available or analyzed in reasonable detail to complete the accounting for certain income tax effects of the TCJA. Under SAB 118, an entity would use a similar approach as the measurement period provided in the Business Combinations Topic of the ASC. An entity will recognize those matters for which the accounting can be completed. For matters that have not been completed, the entity would either (1) recognize provisional amounts to the extent that they are reasonably estimable and adjust them over time as more information becomes available or (2) for any specific income tax effects of the TCJA for which a reasonable estimate cannot be determined, continue to apply the Income Taxes Topic of the ASC on the basis of the provisions of the tax laws that were in effect immediately before the TCJA was signed into law. EOG has prepared its consolidated financial statements for the fiscal year ended December 31, 2017 in accordance with the Income Taxes Topic of the ASC as allowed by SAB 118. EOG has not completed the determination of the accounting impact of the TCJA on its tax accruals, but believes that it has made reasonable estimates of the effects of the TCJA with the information currently available. Following is a description of each of the principal changes enacted by the TCJA affecting EOG, the impact of such change on EOG's results of operations, cash flows and consolidated financial statements, and, to the extent that the amount is provisional, an explanation of the reasons the initial accounting is incomplete. The TCJA reduces the corporate income tax rate from 35% to 21% effective January 1, 2018. As provided in the Income Taxes Topic of the ASC, EOG remeasured its U.S. deferred tax assets and liabilities to reflect the effects of the tax rate change. EOG recorded a provisional reduction in the 2017 income tax provision in the amount of approximately $2.2 billion , most of which related to the decrease in the tax rate. However, this amount may change based on further analysis of tax elections available to EOG, as well as any additional clarification provided by the Internal Revenue Service (IRS). In addition, the TCJA repeals the corporate alternative minimum tax (AMT) for tax years beginning January 1, 2018, and provides that existing AMT credit carryovers from 2017 and prior years can be applied against regular tax liabilities beginning in 2018. To the extent that AMT credit carryovers are not used to offset regular tax liabilities, these credits are refundable over four years beginning in 2018. EOG estimates that its AMT credits being carried over to 2018 will total approximately $798 million (inclusive of the expected IRS settlement discussed below). The exact amount of the AMT credit carryover cannot be currently determined, however, due to a federal budgetary provision known as "sequestration," in which a portion of certain refunds are permanently withheld by the government. The sequestration rate, currently at 6.6% , is revised each year, and EOG cannot precisely estimate the rate that might be applicable during the next four years. In addition, the AMT credits may be applied against future regular tax liabilities, which would reduce the amount of AMT credit refunds, as well as the corresponding amount of the sequestration charge. In 2017, EOG recorded an accrual in the amount of $42 million related to the possible sequestration of refundable tax credits. The TCJA further provides for a tax on the deemed repatriation of accumulated foreign earnings for the year ended December 31, 2017. The deemed repatriation tax is based on the amount of post-1986 earnings and profits of EOG's foreign subsidiaries and the amount of foreign cash and cash equivalents. At the election of the taxpayer, the deemed repatriation tax liability can be paid over eight years beginning with 2017 on an interest-free basis. EOG expects that it will pay its estimated deemed repatriation tax of approximately $179 million under this election. EOG cannot finalize the amount of the repatriation tax due to the possible impact of certain tax elections that require further analysis, the completion of its foreign earnings and profits study, and further clarification provided by the IRS. Also, the TCJA makes fundamental changes to the taxation of multinational companies, including a shift beginning in 2018 to a so-called territorial system of taxation that features a participation exemption regime. EOG believes that under this new system it will not incur any significant amount of U.S. federal income taxes with respect to its foreign operating earnings. Prior to this change being enacted, EOG had accrued U.S. federal deferred income taxes in the amount of $260 million related to its accumulated foreign earnings. Due to this tax law change, EOG reversed this accrual in 2017, resulting in a provisional reduction in its 2017 federal tax provision of approximately $43 million , net of the earnings impact of the repatriation tax described above. However, although future foreign dividends should be exempt from U.S. federal income taxes, EOG must still account for the tax consequences of outside basis differences in its investments in non-U.S. subsidiaries. While EOG believes that no U.S. federal deferred income tax liabilities should be recorded for such outside basis differences, future IRS pronouncements may require that EOG make certain adjustments to the tax basis of its non-U.S. subsidiaries, resulting in EOG having to record additional U.S. federal deferred income tax liabilities. The TCJA also provides for 100% bonus depreciation on tangible personal property acquired and placed in service after September 27, 2017, and before December 31, 2023. It also provides for a phase down of bonus depreciation for the years 2023 through 2026. The impact of this provision will depend on EOG's future domestic capital spending, which cannot be precisely determined at this time, but it is expected to have a favorable effect on EOG's cash tax position prospectively. In addition, the TCJA includes certain limitations on the federal tax deductibility of interest expense, net operating losses and executive compensation. Although EOG does not currently believe that these changes will have a significant impact on EOG's tax provision in the foreseeable future, additional analysis is required. The IRS has recently issued several pronouncements addressing certain aspects of the TCJA and EOG expects that the IRS will continue providing clarifying guidance, some of which could have a significant impact on EOG's reported amounts. The principal components of EOG's net deferred income tax liabilities at December 31, 2017 and 2016 were as follows (in thousands): 2017 (1) 2016 (1) (2) Noncurrent Deferred Income Tax Assets (Liabilities) Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization $ (40,851 ) $ (39,852 ) Foreign Net Operating Loss 423,258 352,150 Foreign Valuation Allowances (365,379 ) (296,596 ) Foreign Other 478 438 Total Net Noncurrent Deferred Income Tax Assets $ 17,506 $ 16,140 Noncurrent Deferred Income Tax (Assets) Liabilities Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization $ 3,894,739 $ 5,899,533 Commodity Hedging Contracts (12,008 ) (22,206 ) Deferred Compensation Plans (35,832 ) (43,984 ) Accrued Expenses and Liabilities 12,094 (13,754 ) Net Operating Loss - Federal (69,262 ) — Non-Producing Leasehold Costs (47,981 ) (64,898 ) Seismic Costs Capitalized for Tax (109,423 ) (161,920 ) Equity Awards (92,696 ) (139,787 ) Capitalized Interest 51,345 86,504 Alternative Minimum Tax Credit Carryforward (3) (77,114 ) (757,631 ) Undistributed Foreign Earnings (4) 19,684 280,099 Other (15,332 ) (33,548 ) Total Net Noncurrent Deferred Income Tax Liabilities $ 3,518,214 $ 5,028,408 Total Net Deferred Income Tax Liabilities $ 3,500,708 $ 5,012,268 (1) United States federal deferred tax assets and liabilities tax effected at 21% and 35% for 2017 and 2016, respectively. (2) As described in Note 1, ASU 2015-17 eliminated the requirement to separate deferred tax assets and liabilities into current and noncurrent amounts. (3) Pursuant to the TCJA, $721 million of federal AMT credit carryforwards are expected to be refundable over four years and are presented as noncurrent tax receivables in Other Assets on the Consolidated Balance Sheet at December 31, 2017. (4) Undistributed foreign earnings have been deemed repatriated in 2017 in accordance with the TCJA. A portion of the associated federal taxes are now reflected as a noncurrent tax payable as a result of the eight year installment election. The components of Income (Loss) Before Income Taxes for the years indicated below were as follows (in thousands): 2017 2016 2015 United States $ 621,610 $ (1,520,573 ) $ (6,840,119 ) Foreign 39,572 (36,932 ) (81,437 ) Total $ 661,182 $ (1,557,505 ) $ (6,921,556 ) The principal components of EOG's Income Tax Benefit for the years indicated below were as follows (in thousands): 2017 2016 2015 Current: Federal $ 33,058 $ 11,567 $ 21,719 State (2,502 ) (8,369 ) 9,404 Foreign 35,323 51,189 54,143 Total 65,879 54,387 85,266 Deferred: Federal (1,504,288 ) (532,979 ) (2,362,926 ) State 26,942 4,876 (127,444 ) Foreign 3,474 12,897 8,063 Total (1,473,872 ) (515,206 ) (2,482,307 ) Other Non-Current: Federal (1) (513,404 ) — — Income Tax Benefit $ (1,921,397 ) $ (460,819 ) $ (2,397,041 ) (1) As described previously, under the TCJA, a deemed repatriation tax is to be paid over eight years beginning with respect to taxable year 2017. In addition, EOG expects to receive refunds of AMT credits over a four-year period beginning with respect to taxable year 2018. Other Non-Current includes the portion of these two items that relates to years after 2017. The differences between taxes computed at the U.S. federal statutory tax rate and EOG's effective rate were as follows: 2017 2016 2015 Statutory Federal Income Tax Rate 35.00 % 35.00 % 35.00 % State Income Tax, Net of Federal Benefit 3.38 0.15 1.11 Income Tax Provision Related to Foreign Operations (0.30 ) (1.23 ) (1.31 ) Income Tax Provision Related to Trinidad Operations — (3.71 ) — Income Tax Provision Related to United Kingdom Operations 1.78 — — Income Tax Provision Related to Canadian Operations 2.30 — — TCJA (1) (328.10 ) — — Share-Based Compensation (2) (4.63 ) — — Other (0.03 ) (0.62 ) (0.17 ) Effective Income Tax Rate (290.60 )% 29.59 % 34.63 % (1) Includes impact of federal tax rate reduction ( (327.8)% ), federal repatriation tax ( (6.6)% ), sequestration ( 6.4% ) and other tax reform impacts ( (0.1)% ). (2) As described in Note 1, ASU 2016-09, adopted by EOG in 2017, provides that share-based compensation tax benefits and deficiencies are recognized in the income tax provision. The effective tax rate of (291)% in 2017 was lower than the prior year rate of 30% primarily as a result of the remeasurement of the net U.S. deferred income tax liability at 21% due to the enactment of the TCJA previously discussed. Deferred tax assets are recorded for certain tax benefits, including tax net operating losses (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 were as follows (in thousands): 2017 2016 2015 Beginning Balance $ 383,221 $ 506,127 $ 463,018 Increase (1) 67,333 37,221 146,602 Decrease (2) (13,687 ) (12,667 ) (4,315 ) Other (3) 29,554 (147,460 ) (99,178 ) Ending Balance $ 466,421 $ 383,221 $ 506,127 (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/foreign exchange rate variances and the effect of statutory income tax rate changes. As of December 31, 2017, EOG had state income tax NOLs being carried forward of approximately $1.7 billion , which, if unused, expire between 2018 and 2036. During 2017, EOG's United Kingdom subsidiary incurred a tax NOL of approximately $72 million which, along with prior years' NOLs of $857 million , will be carried forward indefinitely. EOG also has United States federal and Canadian NOLs of $335 million and $158 million , respectively, with varying carryforward periods. EOG's remaining AMT credits total $798 million, resulting from AMT paid with respect to prior years and an increase of $41 million in 2017. As described above, these NOLs and credits, as well as other less significant future income 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. As further described above, significant changes were made by the TCJA to the corporate AMT that are favorable to EOG, including the refunding of AMT credit carryovers. Due to these legislative changes, EOG intends to settle certain uncertain tax positions related to AMT credits for taxable years 2011 through 2015, resulting in a decrease of uncertain tax positions of $40 million . The amount of unrecognized tax benefits at December 31, 2017, was $39 million , resulting from the tax treatment of its research and experimental expenditures related to certain innovations in its horizontal drilling and completion projects, which is not expected to have an earnings impact. EOG records interest and penalties related to unrecognized tax benefits to its income tax provision. EOG does not anticipate that the amount of the unrecognized tax benefits will increase during the next twelve months. EOG and its subsidiaries file income tax returns and are subject to tax audits in the United States and various state, local and foreign jurisdictions. EOG's earliest open tax years in its principal jurisdictions are as follows: United States federal (2011), Canada (2014), United Kingdom (2016), Trinidad (2011) and China (2008). EOG's foreign subsidiaries' undistributed earnings are no longer considered to be permanently reinvested outside the U.S. and, accordingly, EOG has cumulatively recorded $20 million of foreign and state deferred income taxes as of December 31, 2017.

Employee Benefit Plans (Notes)

Employee Benefit Plans (Notes)	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Employee Benefit Plans	Employee Benefit Plans Stock-Based Compensation During 2017 , EOG maintained various stock-based compensation plans as discussed below. EOG recognizes compensation expense on grants of stock options, SARs, restricted stock and restricted stock units, performance units and grants made under the EOG Resources, Inc. Employee Stock Purchase Plan (ESPP). Stock-based compensation expense is calculated based upon the grant date estimated fair value of the awards, net of forfeitures, based upon EOG's historical employee turnover rate. Compensation expense is amortized over the shorter of the vesting period or the period from date of grant until the date the employee becomes eligible to retire without company approval. Stock-based compensation expense is included on the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) based upon the job functions of the employees receiving the grants. Compensation expense related to EOG's stock-based compensation plans for the years ended December 31, 2017 , 2016 and 2015 was as follows (in millions): 2017 2016 2015 Lease and Well $ 41 $ 38 $ 44 Gathering and Processing Costs 1 1 1 Exploration Costs 23 21 26 General and Administrative 69 68 60 Total $ 134 $ 128 $ 131 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 stock and performance units, and other stock-based awards. Beginning with the grants made effective September 25, 2017, the Compensation Committee of the Board of Directors of EOG (Committee) approved revised vesting schedules for grants of stock options, SARs, restricted stock and restricted stock units, and performance units. These revised vesting schedules will apply to all future grants as well, until revised, amended or otherwise determined by the Committee. Grant Type Previous Vesting Schedule Revised Vesting Schedule Stock Options/SARs Vesting in 25% increments on each of the first four anniversaries of the date of grant 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 five years from the date of grant "Cliff" vesting three years from the date of grant Performance Units "Cliff" vesting five years from the date of grant (except for the December 2016 grant, which will "cliff" vest approximately three years from the date of grant) "Cliff" vesting approximately 41 months from the date of grant - specifically, on the February 28 th immediately following the Committee’s certifications contemplated by the form of award agreement governing grants of performance units At December 31, 2017 , approximately 17.3 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 2017 , 2016 and 2015 , EOG issued shares in connection with stock option/SAR exercises, restricted stock and performance stock grants, restricted stock unit and performance unit releases and ESPP purchases. Effective January 1, 2017, with the adoption of ASU 2016-09, EOG began recognizing income tax associated with excess tax benefits and tax deficiencies as discrete benefits and expenses, respectively, in the income tax provision. Net excess tax benefits recognized within the income tax provision was $32 million for the twelve months ended December 31, 2017. Prior to the adoption of ASU 2016-09, EOG recognized, as an adjustment to Additional Paid in Capital, federal income tax benefits of $29 million and $26 million for 2016 and 2015 , respectively, related to the exercise of stock options/SARs and the release of restricted stock, restricted stock units, performance stock and performance units. 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 $56 million , $57 million and $56 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants for the years ended December 31, 2017 , 2016 and 2015 were as follows: Stock Options/SARs ESPP 2017 2016 2015 2017 2016 2015 Weighted Average Fair Value of Grants $ 23.95 $ 25.78 $ 21.88 $ 22.20 $ 19.21 $ 21.21 Expected Volatility 28.28 % 31.54 % 38.03 % 27.12 % 36.55 % 32.08 % Risk-Free Interest Rate 1.52 % 0.78 % 0.83 % 0.88 % 0.44 % 0.12 % Dividend Yield 0.75 % 0.76 % 0.85 % 0.71 % 0.82 % 0.73 % Expected Life 5.1 years 5.4 years 5.3 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, 2017 , 2016 and 2015 (stock options and SARs in thousands): 2017 2016 2015 Number Weighted Average Grant Price Number Weighted Average Grant Price Number Weighted Average Grant Price Outstanding at January 1 9,850 $ 75.53 10,744 $ 67.98 10,493 $ 64.96 Granted 2,274 96.27 1,855 94.82 2,037 69.99 Exercised (1) (2,574 ) 61.12 (2,376 ) 54.56 (1,518 ) 47.64 Forfeited (447 ) 93.84 (373 ) 87.38 (268 ) 80.31 Outstanding at December 31 9,103 83.89 9,850 75.53 10,744 67.98 Stock Options/SARs Exercisable at December 31 4,510 75.76 5,613 66.48 5,993 57.96 (1) The total intrinsic value of stock options/SARs exercised during the years 2017 , 2016 and 2015 was $95 million , $84 million and $60 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, 2017 , there were 8.7 million stock options/SARs vested or expected to vest with a weighted average grant price of $83.56 per share, an intrinsic value of $213 million and a weighted average remaining contractual life of 4.3 years . The following table summarizes certain information for the stock options and SARs outstanding and exercisable at December 31, 2017 (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) $ 34.00 to $ 59.99 1,472 1 $ 49.63 1,472 1 $ 49.63 60.00 to 84.99 2,392 4 75.67 1,623 3 78.51 85.00 to 95.99 1,684 6 94.82 421 5 94.73 96.00 to 99.99 2,239 7 96.32 21 3 98.06 100.00 to 116.99 1,316 4 102.03 973 3 102.03 9,103 4 83.89 $ 218,696 4,510 3 75.76 $ 145,024 (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, 2017 , unrecognized compensation expense related to non-vested stock option and SAR grants totaled $98 million . This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.4 years . At December 31, 2017 , approximately 176,000 shares of Common Stock remained available for issuance under the ESPP. At its 2018 Annual Meeting of Stockholders, EOG will propose, for stockholder approval, an amendment and restatement of the ESPP to (among other changes) increase the number of shares available for issuance under the ESPP. The following table summarizes ESPP activities for the years ended December 31, 2017 , 2016 and 2015 (in thousands, except number of participants): 2017 2016 2015 Approximate Number of Participants 1,870 1,746 1,963 Shares Purchased 180 212 225 Aggregate Purchase Price $ 13,997 $ 13,787 $ 15,045 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 $68 million , $60 million and $69 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. The following table sets forth the restricted stock and restricted stock unit transactions for the years ended December 31, 2017 , 2016 and 2015 (shares and units in thousands): 2017 2016 2015 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 3,962 $ 79.63 4,908 $ 70.35 5,394 $ 64.39 Granted 1,095 97.34 853 88.01 1,044 77.94 Released (1) (929 ) 61.51 (1,465 ) 53.95 (1,331 ) 51.52 Forfeited (223 ) 85.45 (334 ) 77.29 (199 ) 74.56 Outstanding at December 31 (2) 3,905 88.57 3,962 79.63 4,908 70.35 (1) The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2017, 2016 and 2015 was $91 million , $124 million and $109 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, 2017, 2016 and 2015 was approximately $421 million , $401 million and $347 million , respectively. At December 31, 2017 , unrecognized compensation expense related to restricted stock and restricted stock units totaled $173 million . Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 2.4 years . Performance Units and Performance Stock. EOG has granted performance units and/or performance stock (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 $10 million , $11 million and $5 million for the years ended December 31, 2017, 2016 and 2015, respectively. Weighted average fair values and valuation assumptions used to value Performance Awards during the years ended December 31, 2017 , 2016 and 2015 were as follows: 2017 2016 2015 Weighted Average Fair Value of Grants $ 113.81 $ 119.10 $ 80.64 Expected Volatility 32.19 % 32.48 % 29.35 % Risk-Free Interest Rate 1.60 % 1.15 % 1.07 % 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 based on a 3.27 year term-matched zero-coupon risk-free interest rate derived from the Treasury Constant Maturities yield curve on the grant date. The following table sets forth the Performance Awards transactions for the years ended December 31, 2017 , 2016 and 2015 : 2017 2016 2015 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 1 545,290 $ 80.92 405,000 $ 74.93 333,195 $ 76.11 Granted 78,527 96.29 131,750 100.95 71,805 69.43 Granted for Performance Multiple (1) 118,834 84.43 142,556 56.21 — — Released (2) (240,320 ) 66.69 (134,016 ) 56.21 — — Forfeited — — — — — — Outstanding at December 31 (3) 502,331 (4 ) 90.96 545,290 80.92 405,000 74.93 (1) Upon completion of the Performance Period for the Performance Awards granted in 2013 and 2012, a performance multiple of 200% was applied to each of the grants resulting in additional grants of Performance Awards in February 2017 and 2016. (2) The total intrinsic value of Performance Awards released during the years ended December 31, 2017, 2016 and 2015 was approximately $24 million , $10 million and $0 , respectively. (3) The total intrinsic value of Performance Awards outstanding at December 31, 2017, 2016 and 2015 was approximately $54 million , $55 million and $29 million , respectively. (4) Upon the application of the relevant performance multiple at the completion of each of the remaining Performance Periods, a minimum of 148,444 and a maximum of 856,218 Performance Awards could be outstanding. The intrinsic value is based upon the closing price of EOG's common stock on the date Performance Awards are released. At December 31, 2017, unrecognized compensation expense related to Performance Awards totaled $8.3 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 2014, a performance multiple of 200% was applied to the 2014 grants resulting in an additional grant of 71,805 Performance Awards in February 2018. 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 $37 million , $34 million and $36 million for 2017 , 2016 and 2015 , respectively. In addition, EOG's Trinidadian subsidiary maintains a contributory defined benefit pension plan and a matched savings plan. EOG's United Kingdom subsidiary maintains a pension plan which includes 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 and United Kingdom subsidiaries. EOG's combined contributions to these plans were $1 million , $1 million and $1 million for 2017 , 2016 and 2015 , respectively. For the Trinidadian defined benefit pension plan, the benefit obligation, fair value of plan assets and accrued benefit cost totaled $10 million , $8 million and $0.2 million , respectively, at December 31, 2017 , and $8 million , $7 million and $0.3 million , respectively, at December 31, 2016 . In connection with the divestiture of substantially all of its Canadian assets in the fourth quarter of 2014, EOG has terminated the Canadian non-contributory defined benefit pension plan. 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.

Commitments and Contingencies (

Commitments and Contingencies (Notes)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Letters of Credit and Guarantees. At December 31, 2017 and 2016 , respectively, EOG had standby letters of credit and guarantees outstanding totaling approximately $174 million and $226 million , primarily representing guarantees of payment or performance obligations on behalf of subsidiaries. As of February 20, 2018, EOG had received no demands for payment under these guarantees. Minimum Commitments. At December 31, 2017 , total minimum commitments from long-term non-cancelable operating leases, drilling rig commitments, seismic purchase obligations, fracturing services obligations, other purchase obligations and transportation and storage service commitments, based on current transportation and storage rates and the foreign currency exchange rates used to convert Canadian dollars and British pounds into United States dollars at December 31, 2017 , were as follows (in thousands): Total Minimum Commitments 2018 $ 1,855,005 2019 1,068,994 2020 800,078 2021 567,840 2022 478,480 2023 and beyond 944,911 $ 5,715,308 Included in the table above are leases for buildings, facilities and equipment with varying expiration dates through 2042. Rental expenses associated with existing leases amounted to $200 million , $204 million , and $229 million for 2017 , 2016 and 2015 , respectively. Contingencies. There are currently various suits and claims pending against EOG that have arisen in the ordinary course of EOG's business, including contract disputes, personal injury and property damage claims and title disputes. While the ultimate outcome and impact on EOG cannot be predicted, management believes that the resolution of these suits and claims will not, individually or in the aggregate, have a material adverse effect on EOG's consolidated financial position, results of operations or cash flow. EOG records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

Net Income (Loss) Per Share (No

Net Income (Loss) Per Share (Notes)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Net Income (Loss) Per Share	Net Income (Loss) Per Share The following table sets forth the computation of Net Income (Loss) Per Share for the years ended December 31, 2017 , 2016 and 2015 (in thousands, except per share data): 2017 2016 2015 Numerator for Basic and Diluted Earnings per Share - Net Income (Loss) $ 2,582,579 $ (1,096,686 ) $ (4,524,515 ) Denominator for Basic Earnings per Share - Weighted Average Shares 574,620 553,384 545,697 Potential Dilutive Common Shares - Stock Options/SARs 1,466 — — Restricted Stock/Units and Performance Units/Stock 2,607 — — Denominator for Diluted Earnings per Share - Adjusted Diluted Weighted Average Shares 578,693 553,384 545,697 Net Income (Loss) Per Share Basic $ 4.49 $ (1.98 ) $ (8.29 ) Diluted $ 4.46 $ (1.98 ) $ (8.29 ) The diluted earnings per share calculation excludes stock options, SARs, restricted stock and units and performance units and stock that were anti-dilutive. Shares underlying the excluded stock options and SARs totaled 2.6 million , 10.3 million and 10.2 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. For the year ended December 31, 2016, 4.5 million shares of restricted stock and restricted stock units and performance units and performance stock were excluded.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information (Notes)	12 Months Ended
	Dec. 31, 2016
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Supplemental Cash Flow Information Net cash paid for interest and income taxes was as follows for the years ended December 31, 2017 , 2016 and 2015 (in thousands): 2017 2016 2015 Interest, Net of Capitalized Interest $ 275,305 $ 252,030 $ 222,088 Income Taxes, Net of Refunds Received $ 188,946 $ (39,293 ) $ 41,108 EOG's accrued capital expenditures at December 31, 2017 , 2016 and 2015 were $475 million , $388 million and $416 million , respectively. 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. Non-cash investing activities for the year ended December 31, 2016 included $3,834 million in non-cash additions to EOG's oil and gas properties related to the Yates transaction (see Note 17).

Business Segment Information (N

Business Segment Information (Notes)	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Business Segment Information	Business Segment Information EOG's operations are all crude oil 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, the United Kingdom 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, 2017 , 2016 and 2015 (in thousands): United States Trinidad Other International (1) Total 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 (Losses) on Mark-to-Market Commodity Derivative Contracts 19,828 — — 19,828 Gathering, Processing and Marketing 3,298,098 (11 ) — 3,298,087 Gains (Losses) on Asset Dispositions, Net (98,233 ) (8 ) (855 ) (99,096 ) Other, Net 81,610 59 (59 ) 81,610 Net Operating Revenues and Other (2) 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 United States Trinidad Other International (1) Total 2016 Crude Oil and Condensate $ 4,265,036 $ 9,600 $ 42,705 $ 4,317,341 Natural Gas Liquids 437,238 — 12 437,250 Natural Gas 475,715 234,108 32,329 742,152 Losses on Mark-to-Market Commodity Derivative Contracts (99,608 ) — — (99,608 ) Gathering, Processing and Marketing 1,967,390 (1,131 ) — 1,966,259 Gains (Losses) on Asset Dispositions, Net 196,043 (145 ) 9,937 205,835 Other, Net 81,386 (8 ) 25 81,403 Net Operating Revenues and Other (3) 7,323,200 242,424 85,008 7,650,632 Depreciation, Depletion and Amortization 3,365,390 145,591 42,436 3,553,417 Operating Income (Loss) (1,192,338 ) 46,473 (79,416 ) (1,225,281 ) Interest Income 358 932 1,329 2,619 Other Income (Expense) (15,703 ) 2,667 (40,126 ) (53,162 ) Net Interest Expense 298,125 — (16,444 ) 281,681 Income (Loss) Before Income Taxes (1,505,808 ) 50,072 (101,769 ) (1,557,505 ) Income Tax Provision (Benefit) (516,180 ) 64,281 (8,920 ) (460,819 ) Additions to Oil and Gas Properties, Excluding Dry Hole Costs 6,223,228 75,407 30,734 6,329,369 Total Property, Plant and Equipment, Net 25,221,517 274,850 210,711 25,707,078 Total Assets (4) 27,746,851 889,253 663,097 29,299,201 2015 Crude Oil and Condensate $ 4,917,731 $ 13,122 $ 3,709 $ 4,934,562 Natural Gas Liquids 407,570 — 88 407,658 Natural Gas 637,452 368,639 54,947 1,061,038 Gains on Mark-to-Market Commodity Derivative Contracts 61,924 — — 61,924 Gathering, Processing and Marketing 2,254,477 (1,342 ) — 2,253,135 Gains (Losses) on Asset Dispositions, Net (12,176 ) 393 2,985 (8,798 ) Other, Net 47,464 (3 ) 448 47,909 Net Operating Revenues and Other (5) 8,314,442 380,809 62,177 8,757,428 Depreciation, Depletion and Amortization 3,139,863 154,853 18,928 3,313,644 Operating Income (Loss) (6,566,282 ) 175,658 (295,455 ) (6,686,079 ) Interest Income 1,913 389 1,167 3,469 Other Income (Expense) 6,461 8,780 (16,794 ) (1,553 ) Net Interest Expense 274,606 1,400 (38,613 ) 237,393 Income (Loss) Before Income Taxes (6,832,514 ) 183,427 (272,469 ) (6,921,556 ) Income Tax Provision (Benefit) (2,463,213 ) 63,502 2,670 (2,397,041 ) Additions to Oil and Gas Properties, Excluding Dry Hole Costs 4,495,730 102,358 112,316 4,710,404 Total Property, Plant and Equipment, Net 23,593,995 350,766 265,960 24,210,721 Total Assets (6) 25,211,572 886,826 736,510 26,834,908 (1) Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016. (2) EOG had sales activity with two significant purchasers in 2017, one totaling $1.5 billion and the other totaling $1.3 billion of consolidated Net Operating Revenues and Other in the United States segment. (3) EOG had sales activity with three significant purchasers in 2016, one totaling $1.2 billion , one totaling $1.1 billion and one totaling $1.0 billion of consolidated Net Operating Revenues and Other in the United States segment. (4) EOG made a reclassification of $160 million from deferred tax liabilities to deferred tax assets for the year ended December 31, 2016, for the United States segment and in total. (5) EOG had sales activity with two significant purchasers in 2015, one totaling $1.7 billion and the other totaling $1.4 billion of consolidated Net Operating Revenues and Other in the United States segment. (6) EOG made a reclassification of $136 million from deferred tax liabilities to deferred tax assets for the year ended December 31, 2015, for the United States segment and in total.

Risk Management Activities (Not

Risk Management Activities (Notes)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk Management Activities	The following table sets forth the amounts and classification of EOG's outstanding derivative financial instruments at December 31, 2017 and 2016 , respectively. Certain amounts may be presented on a net basis on the consolidated financial statements when such amounts are with the same counterparty and subject to a master netting arrangement (in millions): Fair Value at December 31, Description Location on Balance Sheet 2017 2016 Asset Derivatives Crude oil and natural gas derivative contracts - Current portion Assets from Price Risk Management Activities $ 8 $ — Noncurrent portion Other Assets — 1 Liability Derivatives Crude oil and natural gas derivative contracts - Current portion Liabilities from Price Risk Management Activities (1) $ 50 $ 62 Noncurrent portion Other Liabilities 7 — (1) The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $55 million , partially offset by gross assets of $5 million , at December 31, 2017. 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 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 2017 , 2016 and 2015 , EOG elected not to designate any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounted for these financial commodity derivative contracts using the mark-to-market accounting method. Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as Gains (Losses) on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss). The related cash flow impact is reflected in Cash Flows from Operating Activities. During 2017 , 2016 and 2015 , EOG recognized net gains (losses) on the mark-to-market of financial commodity derivative contracts of $20 million , $(100) million and $62 million , respectively, which included cash received from (payments for) settlements of crude oil and natural gas derivative contracts of $7 million , $(22) million and $730 million , respectively. Commodity Derivative Contracts. Prices received by EOG for its crude oil production generally vary from U.S. New York Mercantile Exchange (NYMEX) West Texas Intermediate prices due to adjustments for delivery location (basis) and other factors. EOG has entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma (Midland Differential). Presented below is a comprehensive summary of EOG's Midland Differential basis swap contracts for the year ended December 31, 2017. The weighted average price differential expressed in dollars per barrel ($/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) 2018 January 2018 (closed) 15,000 $ 1.063 February 1, 2018 through December 31, 2018 15,000 1.063 2019 January 1, 2019 through December 31, 2019 20,000 $ 1.075 EOG has entered into additional 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, 2017. 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) 2018 January 2018 (closed) 37,000 $ 3.818 February 1, 2018 through December 31, 2018 37,000 3.818 On March 14, 2017, EOG executed the optional early termination provision granting EOG the right to terminate certain 2017 crude oil price swaps with notional volumes of 30,000 Bbld at a weighted average price of $50.05 per Bbl for the period March 1, 2017 through June 30, 2017. EOG received cash of $4.6 million for the early termination of these contracts, which are included in the table below. Presented below is a comprehensive summary of EOG's crude oil price swap contracts for the year ended December 31, 2017, with notional volumes expressed in Bbld and prices expressed in $/Bbl. Crude Oil Price Swap Contracts Volume (Bbld) Weighted Average Price ($/Bbl) 2017 January 1, 2017 through February 28, 2017 (closed) 35,000 $ 50.04 March 1, 2017 through June 30, 2017 (closed) 30,000 50.05 2018 January 1, 2018 through December 31, 2018 37,000 $ 56.48 On March 14, 2017, EOG entered into a crude oil price swap contract for the period March 1, 2017 through June 30, 2017, with notional volumes of 5,000 Bbld at a price of $48.81 per Bbl. This contract offset the remaining 2017 crude oil price swap contract for the same time period with notional volumes of 5,000 Bbld at a price of $50.00 per Bbl. The net cash EOG received for settling these contracts was $0.7 million . The offsetting contracts are excluded from the above table. Presented below is a comprehensive summary of EOG's natural gas price swap contracts for the year ended December 31, 2017, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu). Natural Gas Price Swap Contracts Volume (MMBtud) Weighted Average Price ($/MMBtu) 2017 March 1, 2017 through November 30, 2017 (closed) 30,000 $ 3.10 2018 March 1, 2018 through November 30, 2018 35,000 $ 3.00 EOG has sold call options which establish a ceiling price for the sale of notional volumes of natural gas as specified in the call option contracts. The call options require that EOG pay the difference between the call option strike price and either the average or last business day NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the call option strike price. In addition, EOG has purchased put options which establish a floor price for the sale of notional volumes of natural gas as specified in the put option contracts. The put options grant EOG the right to receive the difference between the put option strike price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the put option strike price. Presented below is a comprehensive summary of EOG's natural gas call and put option contracts for the year ended December 31, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. Natural Gas Option Contracts Call Options Sold Put Options Purchased Volume (MMBtud) Weighted Volume (MMBtud) Weighted 2017 March 1, 2017 through November 30, 2017 (closed) 213,750 $ 3.44 171,000 $ 2.92 2018 March 1, 2018 through November 30, 2018 120,000 $ 3.38 96,000 $ 2.94 EOG has also entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the Henry Hub Index Price in the event the Henry Hub Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price. Presented below is a comprehensive summary of EOG's natural gas collar contracts for the year ended December 31, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMbtu. Natural Gas Collar Contracts Weighted Average Price ($/MMbtu) Volume (MMBtud) Ceiling Price Floor Price 2017 March 1, 2017 through November 30, 2017 (closed) 80,000 $ 3.69 $ 3.20 The following table sets forth the amounts and classification of EOG's outstanding derivative financial instruments at December 31, 2017 and 2016 , respectively. Certain amounts may be presented on a net basis on the consolidated financial statements when such amounts are with the same counterparty and subject to a master netting arrangement (in millions): Fair Value at December 31, Description Location on Balance Sheet 2017 2016 Asset Derivatives Crude oil and natural gas derivative contracts - Current portion Assets from Price Risk Management Activities $ 8 $ — Noncurrent portion Other Assets — 1 Liability Derivatives Crude oil and natural gas derivative contracts - Current portion Liabilities from Price Risk Management Activities (1) $ 50 $ 62 Noncurrent portion Other Liabilities 7 — (1) The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $55 million , partially offset by gross assets of $5 million , at December 31, 2017. 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, 2017 , EOG's net accounts receivable balance related to United States, Canada and United Kingdom hydrocarbon sales included two receivable balances, each of which accounted for more than 10% of the total balance. The receivables were due from two petroleum refinery companies. The related amounts were collected during early 2018. At December 31, 2016 , EOG's net accounts receivable balance related to United States, Canada and United Kingdom hydrocarbon sales included three receivable balances, each of which accounted for more than 10% of the total balance. The receivables were due from two petroleum refinery companies and one multinational oil and gas company. The related amounts were collected during early 2017. In 2017 and 2016 , all natural gas from EOG's Trinidad operations was sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary; all crude oil and condensate from EOG's Trinidad operations was sold to the Petroleum Company of Trinidad and Tobago Limited; and 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, 2017 and 2016. EOG had no collateral posted and held no collateral at December 31, 2017 and 2016 . Substantially all of EOG's accounts receivable at December 31, 2017 and 2016 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 or joint interest owner, 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, 2017 , credit losses incurred on receivables by EOG have been immaterial.

Fair Value Measurements (Notes)

Fair Value Measurements (Notes)	12 Months Ended
	Dec. 31, 2017
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, 2017 and 2016. Amounts shown in millions. 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, 2017 Financial Assets: (1) Natural Gas Swaps $ — $ 2 $ — $ 2 Natural Gas Options/Collars — 6 — 6 Financial Liabilities: (2) Crude Oil Swaps $ — $ 38 $ — $ 38 Crude Oil Basis Swaps — 19 — 19 At December 31, 2016 Financial Assets: (1) Natural Gas Options/Collars $ — $ 1 $ — $ 1 Financial Liabilities: (2) Crude Oil Swaps $ — $ 36 $ — $ 36 Natural Gas Swaps — 4 — 4 Natural Gas Options/Collars — 22 — 22 (1) $8 million is included in "Assets from Price Risk Management Activities" at December 31, 2017, and $1 million is included in "Other Assets" at December 31, 2016, on the Consolidated Balance Sheets. (2) $50 million and $62 million is included in "Current Liabilities - Liabilities from Price Risk Management Activities" at December 31, 2017 and 2016, respectively, and $7 million is included in "Other Liabilities" at December 31, 2017, on the Consolidated Balance Sheets. The estimated fair value of crude oil 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 2017, proved oil and gas properties; other property, plant and equipment; and other assets with a carrying amount of $640 million were written down to their fair value of $372 million , resulting in pretax impairment charges of $268 million . Included in the $268 million pretax impairment charges are $217 million of impairments of proved oil and gas properties and other property, plant and equipment 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 2017 of $28 million for a commodity price-related write-down of other assets. During 2016, proved oil and gas properties; other property, plant and equipment; and other assets with a carrying amount of $778 million were written down to their fair value of $587 million , resulting in pretax impairment charges of $191 million . Included in the $191 million pretax impairment charges were $61 million of impairments of obsolete inventory. In addition, EOG recorded pretax impairment charges in 2016 of $138 million for firm commitment contracts related to divested Haynesville natural gas 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 and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. In certain instances, EOG utilized accepted offers from third-party purchasers as the basis for determining fair value. Fair Value of Debt. At December 31, 2017 and 2016 , respectively, EOG had outstanding $6,390 million and $6,990 million aggregate principal amount of senior notes, which had estimated fair values of approximately $6,602 million and $7,190 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, 2017
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 2017, proved oil and gas properties with a carrying amount of $370 million were written down to their fair value of $146 million , resulting in pretax impairment charges of $224 million . During 2016, proved oil and gas properties with a carrying amount of $643 million were written down to their fair value of $527 million , resulting in pretax impairment charges of $116 million . Impairments in 2017, 2016 and 2015 included domestic legacy natural gas assets. Amortization and impairments of unproved oil and gas property costs, including amortization of capitalized interest, were $211 million , $291 million and $288 million during 2017, 2016 and 2015, respectively.

Asset Retirement Obligations (N

Asset Retirement Obligations (Notes)	12 Months Ended
	Dec. 31, 2017
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, 2017 and 2016 (in thousands): 2017 2016 Carrying Amount at Beginning of Period $ 912,926 $ 811,554 Liabilities Incurred (1) 54,764 212,739 Liabilities Settled (2) (61,871 ) (94,800 ) Accretion 34,708 32,306 Revisions (9,818 ) (38,286 ) Foreign Currency Translations 16,139 (10,587 ) Carrying Amount at End of Period $ 946,848 $ 912,926 Current Portion $ 19,259 $ 18,516 Noncurrent Portion $ 927,589 $ 894,410 (1) Includes $164 million in 2016 related to Yates transaction (see Note 17). (2) 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, 2017
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, 2017 , 2016 and 2015 are presented below (in thousands): 2017 2016 2015 Balance at January 1 $ — $ 8,955 $ 17,253 Additions Pending the Determination of Proved Reserves 27,487 6,688 24,640 Reclassifications to Proved Properties (20,802 ) (5,274 ) (26,659 ) Costs Charged to Expense (1) (4,518 ) (10,369 ) (6,279 ) Balance at December 31 $ 2,167 $ — $ 8,955 (1) Includes capitalized exploratory well costs charged to either dry hole costs or impairments. At December 31, 2017 , 2016 and 2015 , 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, 2017
Business Combinations [Abstract]
Acquisitions and Divestitures	Acquisitions and Divestitures 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. Additionally, in the fourth quarter of 2017, EOG signed a purchase and sale agreement and an exchange agreement for the sale and exchange, respectively, of primarily producing properties in the Rocky Mountain area. At December 31, 2017, the book value of the assets classified as held for sale and the related asset retirement obligations were $188 million and $41 million , respectively. During 2017, EOG completed acquisitions of approximately $73 million to acquire producing properties in various areas in the United States. During 2016, EOG recognized a net gain on asset dispositions of $206 million and received proceeds of approximately $1,119 million primarily from sales of producing properties and acreage in Texas, Louisiana, the Rocky Mountain area and Oklahoma. Additionally, during the third quarter of 2016, EOG completed the sale of all its Argentina assets. During 2015, EOG completed acquisitions of approximately $481 million primarily to acquire proved crude oil properties and related assets in the Delaware Basin and gathering assets in the North Dakota Bakken. During 2015, EOG recognized a net loss on asset dispositions of $(9) million and received proceeds of approximately $193 million primarily from sales of gathering and processing assets and other assets. Yates Entities. On October 4, 2016, EOG completed its previously announced mergers and related asset purchase transactions with Yates Petroleum Corporation (YPC), Abo Petroleum Corporation (ABO), MYCO Industries, Inc. (MYCO) and certain affiliated entities (collectively with YPC, ABO and MYCO, the Yates Entities). Pursuant to these transactions, EOG issued to the shareholders of YPC, ABO and MYCO and to certain of the sellers under the related asset purchase transactions an aggregate of approximately 25 million shares of EOG common stock and paid to certain of the sellers under the asset purchase transactions an aggregate of approximately $16 million in cash for total consideration transferred of approximately $2.4 billion . In addition, under the terms of the transactions, EOG assumed and repaid approximately $164 million of debt owed by the Yates Entities, which was offset by approximately $70 million of cash of the Yates Entities. The assets of the Yates Entities include producing wells in addition to acreage in the Delaware Basin Core, the Powder River Basin, the Permian Basin Northwest Shelf and other Western basins. In connection with these mergers and related asset purchase transactions, EOG incurred acquisition-related costs in 2016 of approximately $5 million , all of which were expensed and recorded as General and Administrative on the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss). EOG accounted for the mergers with YPC, ABO and MYCO and the related asset purchase transactions as a business combination under the acquisition method with EOG as the acquirer. Under the acquisition method, the consideration transferred is allocated to the assets acquired and liabilities assumed based on their estimated fair values, with any excess of the consideration transferred over the estimated fair value of the identifiable net assets acquired recorded as goodwill. EOG did not record goodwill in connection with these transactions. In 2017, EOG finalized its purchase price allocation in respect of the transactions with the Yates Entities, which resulted in net decreases of $35 million in Oil and Gas Properties and $32 million in Deferred Income Taxes, along with other immaterial changes. The following table represents the final allocation of the total purchase price of the Yates Entities (in thousands). Current Assets Cash and Cash Equivalents $ 70,411 Accounts Receivable, Net 77,073 Inventories 10,955 Other 10,640 Total 169,079 Property, Plant and Equipment Oil and Gas Properties (Successful Efforts Method) 3,815,207 Other Property, Plant and Equipment 21,824 Total Property, Plant and Equipment, Net 3,837,031 Other Assets 22,706 Total Assets $ 4,028,816 Current Liabilities Accounts Payable $ 124,145 Accrued Taxes Payable 22,417 Other 743 Total 147,305 Long-Term Debt 163,829 Asset Retirement Obligations 163,144 Off-Market Transportation Contracts 39,720 Other Liabilities 28,645 Deferred Income Taxes 1,072,405 Total Liabilities $ 1,615,048 Total Consideration Transferred $ 2,413,768 The fair value measurements of Oil and Gas Properties and Asset Retirement Obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of Proved Oil and Gas Properties were measured using the income approach. Significant inputs to the valuation of Proved Oil and Gas Properties included EOG's estimate of future crude oil and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. Significant inputs to the valuation of Unproved Oil and Gas Properties included average prices per acre of comparable market transactions.

Oil and Gas Exploration and Pro

Oil and Gas Exploration and Production Industries Disclosures (Notes)	12 Months Ended
	Dec. 31, 2017
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 all 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 are to be 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, 2017 . 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 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 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, 2017 , 2016 and 2015 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 13 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 31 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 President; 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, 2017 , 2016 and 2015 covered producing areas containing 79%, 83% and 86%, 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 30, 2018, 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, 2017 , 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, 2017 , and the changes in the net proved reserves for each of the three years in the period ended December 31, 2017 , 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, 2014 1,129,682 1,339 8,729 1,139,750 Revisions of previous estimates (114,924 ) (1 ) — (114,925 ) Purchases in place 35,922 — — 35,922 Extensions, discoveries and other additions 141,310 63 13 141,386 Sales in place (730 ) — (10 ) (740 ) Production (103,400 ) (332 ) (65 ) (103,797 ) Net proved reserves at December 31, 2015 1,087,860 1,069 8,667 1,097,596 Revisions of previous estimates 42,040 54 861 42,955 Purchases in place 25,795 — — 25,795 Extensions, discoveries and other additions 123,441 — — 123,441 Sales in place (8,791 ) — — (8,791 ) Production (101,854 ) (284 ) (1,273 ) (103,411 ) 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 Natural Gas Liquids (MBbl) (2) Net proved reserves at December 31, 2014 466,930 — 138 467,068 Revisions of previous estimates (113,290 ) — 68 (113,222 ) Purchases in place 8,251 — — 8,251 Extensions, discoveries and other additions 49,147 — — 49,147 Sales in place (84 ) — (187 ) (271 ) Production (28,079 ) — (19 ) (28,098 ) Net proved reserves at December 31, 2015 382,875 — — 382,875 Revisions of previous estimates 53,771 — — 53,771 Purchases in place 1,284 — — 1,284 Extensions, discoveries and other additions 41,862 — — 41,862 Sales in place (33,548 ) — — (33,548 ) Production (29,878 ) — — (29,878 ) 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 United States Trinidad Other International (1) Total Natural Gas (Bcf) (3) Net proved reserves at December 31, 2014 4,905.5 405.6 31.5 5,342.6 Revisions of previous estimates (1,453.1 ) 16.8 5.6 (1,430.7 ) Purchases in place 72.3 — — 72.3 Extensions, discoveries and other additions 306.3 21.7 4.4 332.4 Sales in place (3.9 ) — (11.1 ) (15.0 ) Production (337.3 ) (127.5 ) (10.9 ) (475.7 ) Net proved reserves at December 31, 2015 3,489.8 316.6 19.5 3,825.9 Revisions of previous estimates 298.4 29.5 5.2 333.1 Purchases in place 91.5 — — 91.5 Extensions, discoveries and other additions 202.1 59.9 — 262.0 Sales in place (752.0 ) — — (752.0 ) Production (308.6 ) (125.1 ) (8.9 ) (442.6 ) 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 Oil Equivalents (MBoe) (2) Net proved reserves at December 31, 2014 2,414,202 68,937 14,117 2,497,256 Revisions of previous estimates (470,401 ) 2,802 995 (466,604 ) Purchases in place 56,215 — — 56,215 Extensions, discoveries and other additions 241,513 3,682 736 245,931 Sales in place (1,467 ) — (2,039 ) (3,506 ) Production (187,701 ) (21,578 ) (1,896 ) (211,175 ) Net proved reserves at December 31, 2015 2,052,361 53,843 11,913 2,118,117 Revisions of previous estimates 145,542 4,978 1,722 152,242 Purchases in place 42,330 — — 42,330 Extensions, discoveries and other additions 198,973 9,990 — 208,963 Sales in place (167,669 ) — — (167,669 ) Production (183,145 ) (21,150 ) (2,755 ) (207,050 ) 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 (1) Other International includes EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016. (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 2017, EOG added 421 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, 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 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. During 2016, EOG added 209 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin, the Rocky Mountain area and the Eagle Ford. Approximately 79% of the 2016 reserve additions were crude oil and condensate and NGLs, and 95% were in the United States. Sales in place of 168 MMBoe were primarily related to the disposition of certain producing natural gas assets in the Barnett Shale and Haynesville plays and marginal liquids plays in the Permian Basin and Rocky Mountain area. Revisions of previous estimates of 152 MMBoe for 2016 included a downward revision of 101 MMBoe primarily due to decreases in the average crude oil and natural gas prices used in the December 31, 2016, reserves estimation as compared to the prices used in the prior year estimate. The primary plays affected were the Eagle Ford, the Uinta basin in the Rocky Mountain area, the Permian Basin and the Barnett Shale. Positive revisions other than price of 253 MMBoe resulted primarily from lower production costs and improved performance in the Delaware Basin. Purchases in place of 42 MMBoe were primarily related to the Yates transaction. During 2015, EOG added 246 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin, the Rocky Mountain area and the Eagle Ford. Approximately 77% of the 2015 reserve additions were crude oil and condensate and NGLs, and 98% were in the United States. Sales in place of 4 MMBoe were primarily related to the disposition of certain producing natural gas assets in Canada, the Permian Basin and the Upper Gulf Coast. Negative revisions of previous estimates of 467 MMBoe for 2015 included a negative revision of 574 MMBoe primarily due to decreases in the average crude oil and natural gas prices used in the December 31, 2015, reserves estimation as compared to the prices used in the prior year estimate. The primary plays affected were the Uinta and Green River basins in the Rocky Mountain area, the Permian Basin and the Barnett Shale. Revisions other than price resulted primarily from improved recovery in the Eagle Ford. United States Trinidad Other International (1) Total NET PROVED DEVELOPED RESERVES Crude Oil (MBbl) December 31, 2014 493,694 1,339 115 495,148 December 31, 2015 444,070 1,069 63 445,202 December 31, 2016 507,531 839 8,255 516,625 December 31, 2017 605,405 898 7,933 614,236 Natural Gas Liquids (MBbl) December 31, 2014 264,611 — 138 264,749 December 31, 2015 205,898 — — 205,898 December 31, 2016 230,219 — — 230,219 December 31, 2017 286,872 — — 286,872 Natural Gas (Bcf) December 31, 2014 3,102.8 396.9 28.6 3,528.3 December 31, 2015 2,211.2 297.6 19.5 2,528.3 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 Oil Equivalents (MBoe) December 31, 2014 1,275,447 67,484 5,016 1,347,947 December 31, 2015 1,018,491 50,677 3,309 1,072,477 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 NET PROVED UNDEVELOPED RESERVES Crude Oil (MBbl) December 31, 2014 635,988 — 8,614 644,602 December 31, 2015 643,790 — 8,604 652,394 December 31, 2016 660,690 — — 660,690 December 31, 2017 698,666 — 71 698,737 Natural Gas Liquids (MBbl) December 31, 2014 202,319 — — 202,319 December 31, 2015 176,977 — — 176,977 December 31, 2016 186,147 — — 186,147 December 31, 2017 216,601 — — 216,601 Natural Gas (Bcf) December 31, 2014 1,802.7 8.7 2.9 1,814.3 December 31, 2015 1,278.6 19.0 — 1,297.6 December 31, 2016 1,216.8 18.7 — 1,235.5 December 31, 2017 1,447.7 14.2 21.9 1,483.8 Oil Equivalents (MBoe) December 31, 2014 1,138,755 1,453 9,101 1,149,309 December 31, 2015 1,033,870 3,166 8,604 1,045,640 December 31, 2016 1,049,909 3,118 — 1,053,027 December 31, 2017 1,156,544 2,363 3,728 1,162,635 (1) Other International includes EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016. Net Proved Undeveloped Reserves. The following table presents the changes in EOG's total proved undeveloped reserves during 2017 , 2016 and 2015 (in MBoe): 2017 2016 2015 Balance at January 1 1,053,027 1,045,640 1,149,309 Extensions and Discoveries 237,378 138,101 205,152 Revisions 33,127 64,413 (241,973 ) Acquisition of Reserves — — 54,458 Sale of Reserves (8,253 ) (45,917 ) — Conversion to Proved Developed Reserves (152,644 ) (149,210 ) (121,306 ) Balance at December 31 1,162,635 1,053,027 1,045,640 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 (see discussion of technology employed on pages F-38 and F-39 of this Annual Report on Form 10-K), 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. 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, 2016, total PUDs increased by 7 MMBoe to 1,053 MMBoe. EOG added approximately 21 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 117 MMBoe. The PUD additions were primarily in the Permian Basin and, to a lesser extent, the Rocky Mountain area, and 82% of the additions were crude oil and condensate and NGLs. During 2016, EOG drilled and transferred 149 MMBoe of PUDs to proved developed reserves at a total capital cost of $1,230 million. Revisions of PUDs totaled positive 64 MMBoe, primarily due to improved well performance, primarily in the Delaware Basin, and lower production costs, partially offset by the impact of decreases in the average crude oil and natural gas prices used in the December 31, 2016, reserves estimation as compared to the prices used in the prior year estimate. During 2016, EOG sold 46 MMBoe of PUDs primarily in the Haynesville play. All PUDs for 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, 2015, total PUDs decreased by 104 MMBoe to 1,046 MMBoe. EOG added approximately 52 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 153 MMBoe. The PUD additions were primarily in the Permian Basin and, to a lesser extent, the Eagle Ford and the Rocky Mountain area, and 80% of the additions were crude oil and condensate and NGLs. During 2015, EOG drilled and transferred 121 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,349 million . Revisions of PUDs totaled negative 242 MMBoe, primarily due to decreases in the average crude oil and natural gas prices used in the December 31, 2015, reserves estimation as compared to the prices used in the prior year estimate. During 2015, EOG did not sell any PUDs and acquired 54 MMBoe of PUDs. Capitalized Costs Relating to Oil and Gas Producing Activities. The following table sets forth the capitalized costs relating to EOG's crude oil and natural gas producing activities at December 31, 2017 and 2016 : 2017 2016 Proved properties $ 48,845,672 $ 45,751,965 Unproved properties 3,710,069 3,840,126 Total 52,555,741 49,592,091 Accumulated depreciation, depletion and amortization (29,191,247 ) (26,247,062 ) Net capitalized costs $ 23,364,494 $ 23,345,029 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, 2017 , 2016 and 2015 : United States Trinidad Other International (1) Total 2017 Acquisition Costs of Properties Unproved (2) $ 424,118 $ 2,422 $ — $ 426,540 Proved (3) 72,584 — — 72,584 Subtotal 496,702 2,422 — 499,124 Exploration Costs 144,499 62,547 16,553 223,599 Development Costs (4) 3,590,899 109,491 16,297 3,716,687 Total $ 4,232,100 $ 174,460 $ 32,850 $ 4,439,410 2016 Acquisition Costs of Properties Unproved (5) $ 3,216,598 $ — $ 36 $ 3,216,634 Proved (6) 749,023 — — 749,023 Subtotal 3,965,621 — 36 3,965,657 Exploration Costs 156,295 2,695 6,761 165,751 Development Costs (7) 2,252,713 72,147 (10,984 ) 2,313,876 Total $ 6,374,629 $ 74,842 $ (4,187 ) $ 6,445,284 2015 Acquisition Costs of Properties Unproved $ 133,801 $ — $ 56 $ 133,857 Proved 480,617 — — 480,617 Subtotal 614,418 — 56 614,474 Exploration Costs 206,814 22,837 23,041 252,692 Development Costs (8) 3,847,813 102,715 110,589 4,061,117 Total $ 4,669,045 $ 125,552 $ 133,686 $ 4,928,283 (1) Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016. (2) Includes non-cash unproved leasehold acquisition costs of $256 million related to property exchanges. (3) Includes non-cash proved property acquisition costs of $26 million related to property exchanges. (4) 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. (5) Includes non-cash unproved leasehold acquisition costs of $3,102 million related to the Yates transaction. (6) Includes non-cash proved property acquisition costs of $732 million related to the Yates transaction. (7) Includes Asset Retirement Costs of $25 million , $(3) million and $(42) million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment. (8) Includes Asset Retirement Costs of $32 million , $15 million and $6 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, 2017 , 2016 and 2015 : United States Trinidad Other International (2) Total 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 2016 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues $ 5,177,989 $ 243,708 $ 75,046 $ 5,496,743 Other 81,386 (8 ) 25 81,403 Total 5,259,375 243,700 75,071 5,578,146 Exploration Costs 115,990 2,647 6,316 124,953 Dry Hole Costs 10,529 — 128 10,657 Transportation Costs 753,791 1,181 9,134 764,106 Production Costs 1,163,827 27,113 63,073 1,254,013 Impairments 611,297 7,773 1,197 620,267 Depreciation, Depletion and Amortization 3,249,792 145,440 42,052 3,437,284 Income (Loss) Before Income Taxes (645,851 ) 59,546 (46,829 ) (633,134 ) Income Tax Provision (Benefit) (230,377 ) 5,526 (1,562 ) (226,413 ) Results of Operations $ (415,474 ) $ 54,020 $ (45,267 ) $ (406,721 ) 2015 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues $ 5,962,753 $ 381,761 $ 58,744 $ 6,403,258 Other 47,464 (3 ) 448 47,909 Total 6,010,217 381,758 59,192 6,451,167 Exploration Costs 139,753 2,071 7,670 149,494 Dry Hole Costs 956 5,635 8,155 14,746 Transportation Costs 838,428 1,290 9,601 849,319 Production Costs 1,486,189 28,862 66,080 1,581,131 Impairments 6,402,908 — 210,638 6,613,546 Depreciation, Depletion and Amortization 3,017,386 154,588 18,469 3,190,443 Income (Loss) Before Income Taxes (5,875,403 ) 189,312 (261,421 ) (5,947,512 ) Income Tax Provision (2,128,183 ) 43,739 (2,111 ) (2,086,555 ) Results of Operations $ (3,747,220 ) $ 145,573 $ (259,310 ) $ (3,860,957 ) (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, 2017 . (2) Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016. 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, 2017 , 2016 and 2015 : United States Trinidad Other International (1) Composite Year Ended December 31, 2017 $ 4.58 $ 1.39 $ 50.86 $ 4.66 Year Ended December 31, 2016 $ 4.58 $ 1.23 $ 22.43 $ 4.48 Year Ended December 31, 2015 $ 5.81 $ 1.29 $ 33.78 $ 5.85 (1) Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016. 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 2017 , 2016 and 2015 . 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 natura

Unaudited Quarterly Financial I

Unaudited Quarterly Financial Information (Notes)	12 Months Ended
	Dec. 31, 2017
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 2017 Net Operating Revenues and Other $ 2,610,565 $ 2,612,472 $ 2,644,844 $ 3,340,439 Operating Income $ 107,746 $ 127,908 $ 214,836 $ 475,912 Income Before Income Taxes $ 39,382 $ 62,467 $ 145,980 $ 413,353 Income Tax Provision (Benefit) (1) 10,865 39,414 45,439 (2,017,115 ) Net Income $ 28,517 $ 23,053 $ 100,541 $ 2,430,468 Net Income Per Share (2) Basic $ 0.05 $ 0.04 $ 0.17 $ 4.22 Diluted $ 0.05 $ 0.04 $ 0.17 $ 4.20 Average Number of Common Shares Basic 573,935 574,439 574,783 575,394 Diluted 578,593 578,483 578,736 579,203 2016 Net Operating Revenues and Other $ 1,354,349 $ 1,775,740 $ 2,118,504 $ 2,402,039 Operating Income (Loss) $ (638,141 ) $ (288,173 ) $ (193,480 ) $ (105,487 ) Loss Before Income Taxes $ (710,968 ) $ (380,277 ) $ (272,250 ) $ (194,010 ) Income Tax Benefit (239,192 ) (87,719 ) (82,250 ) (51,658 ) Net Income (Loss) $ (471,776 ) $ (292,558 ) $ (190,000 ) $ (142,352 ) Net Income (Loss) Per Share (2) Basic $ (0.86 ) $ (0.53 ) $ (0.35 ) $ (0.25 ) Diluted $ (0.86 ) $ (0.53 ) $ (0.35 ) $ (0.25 ) Average Number of Common Shares Basic 546,715 547,335 547,838 567,337 Diluted 546,715 547,335 547,838 567,337 (1) Includes an income tax benefit of approximately $2.2 billion for the quarter ended December 31, 2017, primarily due to the enactment of the Tax Cuts and Jobs Act in December 2017. See Note 6 to the Consolidated Financial Statements. (2) The sum of quarterly net income (loss) per share may not agree with total year net income (loss) per share as each quarterly computation is based on the weighted average of common shares outstanding.

Summary of Significant Accoun27

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
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 proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made (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 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 future crude oil and natural gas prices, operating costs, 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. If applicable, EOG utilizes accepted bids 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 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. Arrangements for sales of crude oil and condensate, natural gas liquids (NGLs) and natural gas are evidenced by signed contracts with determinable market prices, and revenues are recorded when production is delivered. A significant majority of these products are sold to purchasers who have investment-grade credit ratings and material credit losses have been rare. Revenues are recorded on the entitlement method based on EOG's percentage ownership of current production. Each working interest owner in a well generally has the right to a specific percentage of production, although actual production sold on that owner's behalf may differ from that owner's ownership percentage. Under entitlement accounting, a receivable is recorded when underproduction occurs and a payable is recorded when overproduction occurs. Gathering, processing and marketing revenues represent sales of third-party crude oil and condensate, NGLs and natural gas, as well as gathering fees associated with gathering third-party natural gas and revenues from sales of EOG-owned sand.
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, 2017, EOG elected not to designate any of its financial commodity derivative instruments as accounting hedges and, accordingly, changes in the fair value of these outstanding derivative instruments are recognized as gains or losses in the period of change. The gains or losses are recorded as Gains (Losses) on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss). The related cash flow impact of settled contracts is reflected as cash flows from operating activities. EOG employs net presentation of derivative assets and liabilities for financial reporting purposes when such assets and liabilities are with the same counterparty and subject to a master netting arrangement. See Note 12.
Income Taxes	Income Taxes. Income taxes are accounted for using the asset and liability approach. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. EOG assesses the realizability of deferred tax assets and recognizes valuation allowances as appropriate. In December 2017, the United States (U.S.) enacted the Tax Cuts and Jobs Act (TCJA), which made significant changes to U.S. federal income tax law. Shortly after enactment of the TCJA, the United States Securities and Exchange Commission's (SEC) staff issued Staff Accounting Bulletin No. 118 (SAB 118), which provides guidance on accounting for the impact of the TCJA. Under SAB 118, an entity would use a similar approach as the measurement period provided in the Business Combinations Topic of the ASC. An entity will recognize those matters for which the accounting can be completed. For matters that have not been completed, the entity would either (1) recognize provisional amounts to the extent that they are reasonably estimable and adjust them over time as more information becomes available or (2) for any specific income tax effects of the TCJA for which a reasonable estimate cannot be determined, continue to apply the Income Taxes Topic of the ASC on the basis of the provisions of the tax laws that were in effect immediately before the TCJA was signed into law. EOG has prepared its consolidated financial statements for the fiscal year ended December 31, 2017 in accordance with the Income Taxes Topic of the ASC as allowed by SAB 118. 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, for which the functional currency is 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 Income (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 (loss) in the current period. See Note 4.
Net Income (Loss) Per Share	Net Income (Loss) Per Share. Basic net income (loss) per share is computed on the basis of the weighted-average number of common shares outstanding during the period. Diluted net income (loss) per share is computed based upon the weighted-average number of common shares outstanding during the period plus the assumed issuance of common shares for all potentially dilutive securities. See Note 9.
Stock-Based Compensation	Stock-Based Compensation . EOG measures the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. See Note 7.
Recently Issued Accounting Standards and Developments	Recently Issued Accounting Standards. In February 2017, the FASB issued Accounting Standards Update (ASU) 2017-05, "Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20) - Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets" (ASU 2017-05). ASU 2017-05 clarifies the scope and application of ASC 610-20 to the sale or transfer of nonfinancial assets and, in substance, nonfinancial assets to noncustomers, including partial sales. ASU 2017-05 is effective for interim and annual periods beginning after December 15, 2017. EOG will adopt ASU 2017-05 in connection with the adoption of "Revenue From Contracts With Customers" (ASU 2014-09) effective January 1, 2018. In January 2017, the FASB issued ASU 2017-01 "Business Combinations (Topic 805): Clarifying the Definition of a Business" (ASU 2017-01), which clarifies the definition of a business to provide guidance in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 provides a screen to determine when a set of assets is not a business, requiring that when substantially all fair value of gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets, the set of assets is not a business. A framework is provided to assist in evaluating whether both an input and a substantive process are present for the set to be a business. ASU 2017-01 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. No disclosures are required at transition. The new standard may result in more transactions being accounted for as acquisitions (and dispositions) of assets rather than businesses. EOG will adopt ASU 2017-01 on a prospective basis effective January 1, 2018. In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230) - Classification of Certain Cash Receipts and Cash Payments” (ASU 2016-15). ASU 2016-15 reduces existing diversity in practice by providing guidance on the classification of eight specific cash receipts and cash payments transactions in the statement of cash flows. The new standard is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. EOG will adopt ASU 2016-15 on a retrospective basis on January 1, 2018. There will be no impact to the presentation of comparable periods upon adoption. In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" (ASU 2016-02), which significantly changes accounting for leases by requiring that lessees recognize a right-of-use asset and a related lease liability representing the obligation to make lease payments, for virtually all lease transactions. Additional disclosures about an entity's lease transactions will also be required. ASU 2016-02 defines a lease as "a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration." ASU 2016-02 is effective for interim and annual periods beginning after December 31, 2018 and early application is permitted. Lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented in the financial statements using a modified retrospective approach. EOG is continuing its assessment of ASU 2016-02 and has further developed its project plan, evaluated certain operational and corporate processes and selected certain contracts for additional review. In May 2014, the FASB issued ASU 2014-09, which will 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. ASU 2014-09 will supersede most current guidance related to revenue recognition when it becomes effective. The new standard also will require expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. ASU 2014-09 is effective for interim and annual reporting periods beginning after December 15, 2017. The new standard permits adoption through the use of either the full retrospective approach or a modified retrospective approach. In May 2016, the FASB issued ASU 2016-11, which rescinds certain SEC guidance in the related ASC, including guidance related to the use of the "entitlements" method of revenue recognition used by EOG. EOG will adopt ASU 2014-09 utilizing the modified retrospective approach effective January 1, 2018. Upon adoption of ASU 2014-09, EOG expects to prospectively present natural gas processing fees for certain processing and marketing agreements as Gathering and Processing Costs, instead of a deduction to Revenues within its Consolidated Statements of Income (Loss) and Comprehensive Income (Loss). EOG does not expect a material impact to operating income, net income or cash flows upon changes to the presentation of natural gas processing fees. Also, EOG does not expect a material impact to the financial statements upon elimination of the entitlements method and other adoption requirements. Upon adoption, EOG will also include additional disclosures as required by ASU 2014-09. Effective January 1, 2017, EOG adopted the provisions of ASU 2015-17, "Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes" (ASU 2015-17), which simplifies the presentation of deferred taxes in a classified balance sheet by eliminating the requirement to separate deferred income tax liabilities and assets into current and noncurrent amounts. Instead, ASU 2015-17 requires that all deferred tax liabilities and assets be shown as noncurrent in a classified balance sheet. In connection with the adoption of ASU 2015-17, EOG restated its December 31, 2016 balance sheet to reclassify $169 million of current deferred income tax assets as noncurrent. Effective January 1, 2017, EOG adopted the provisions of ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting" (ASU 2016-09), which amends certain aspects of accounting for share-based payment arrangements. ASU 2016-09 revises or provides alternative accounting for the tax impacts of share-based payment arrangements, forfeitures and minimum statutory tax withholdings and prescribes certain disclosures to be made in the period the new standard is adopted. There was no impact to retained earnings with respect to excess tax benefits. EOG began recognizing income tax associated with excess tax benefits and tax deficiencies as discrete benefits and expenses, respectively, in the income tax provision. Net excess tax benefits recognized within income tax provision was $32 million for the year ended December 31, 2017. The treatment of forfeitures did not change as EOG elected to continue the current process of estimating the number of forfeitures. As such, this had no cumulative effect on retained earnings. EOG elected to present changes to the statements of cash flows on a prospective transition method.

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt at December 31, 2017 and 2016 consisted of the following (in thousands): 2017 2016 5.875% Senior Notes due 2017 $ — $ 600,000 6.875% Senior Notes due 2018 350,000 350,000 5.625% Senior Notes due 2019 900,000 900,000 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 6,390,000 6,990,000 Capital Lease Obligation 32,155 38,710 Less: Current Portion of Long-Term Debt 356,235 6,579 Unamortized Debt Discount 30,564 36,915 Debt Issuance Costs 4,520 5,437 Total Long-Term Debt $ 6,030,836 $ 6,979,779

Stockholder's Equity (Tables)

Stockholder's Equity (Tables)	12 Months Ended
	Dec. 31, 2017
Stockholders' Equity Note [Abstract]
Common stock activity	The following summarizes Common Stock activity for each of the years ended December 31, 2015 , 2016 and 2017 (in thousands): Common Shares Issued Treasury Outstanding Balance at December 31, 2014 549,028 (733 ) 548,295 Common Stock Issued Under Stock-Based Compensation Plans 1,019 — 1,019 Treasury Stock Purchased (1) — (581 ) (581 ) Common Stock Issued Under Employee Stock Purchase Plan 104 121 225 Treasury Stock Issued Under Stock-Based Compensation Plans — 901 901 Balance at December 31, 2015 550,151 (292 ) 549,859 Common Stock Issued 25,204 — 25,204 Common Stock Issued Under Stock-Based Compensation Plans 1,500 — 1,500 Treasury Stock Purchased (1) — (922 ) (922 ) Common Stock Issued Under Employee Stock Purchase Plan 95 117 212 Treasury Stock Issued Under Stock-Based Compensation Plans — 847 847 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 (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 stock or performance unit grants or (ii) in payment of the exercise price of employee stock options.

Accumulated Other Comprehensi30

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss)	The components of Accumulated Other Comprehensive Income (Loss) at December 31, 2017 and 2016 consisted of the following (in thousands): Foreign Currency Translation Adjustment Other Total December 31, 2015 $ (31,538 ) $ (1,800 ) $ (33,338 ) Other comprehensive loss before reclassifications 12,097 2,901 14,998 Tax effects — (670 ) (670 ) Other comprehensive income (loss) 12,097 2,231 14,328 December 31, 2016 (19,441 ) 431 (19,010 ) Other comprehensive income before reclassifications 2,799 (3,728 ) (929 ) Tax effects — 642 642 Other comprehensive income 2,799 (3,086 ) (287 ) December 31, 2017 $ (16,642 ) $ (2,655 ) $ (19,297 )

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Deferred Income Tax Liabilities, Net	The principal components of EOG's net deferred income tax liabilities at December 31, 2017 and 2016 were as follows (in thousands): 2017 (1) 2016 (1) (2) Noncurrent Deferred Income Tax Assets (Liabilities) Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization $ (40,851 ) $ (39,852 ) Foreign Net Operating Loss 423,258 352,150 Foreign Valuation Allowances (365,379 ) (296,596 ) Foreign Other 478 438 Total Net Noncurrent Deferred Income Tax Assets $ 17,506 $ 16,140 Noncurrent Deferred Income Tax (Assets) Liabilities Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization $ 3,894,739 $ 5,899,533 Commodity Hedging Contracts (12,008 ) (22,206 ) Deferred Compensation Plans (35,832 ) (43,984 ) Accrued Expenses and Liabilities 12,094 (13,754 ) Net Operating Loss - Federal (69,262 ) — Non-Producing Leasehold Costs (47,981 ) (64,898 ) Seismic Costs Capitalized for Tax (109,423 ) (161,920 ) Equity Awards (92,696 ) (139,787 ) Capitalized Interest 51,345 86,504 Alternative Minimum Tax Credit Carryforward (3) (77,114 ) (757,631 ) Undistributed Foreign Earnings (4) 19,684 280,099 Other (15,332 ) (33,548 ) Total Net Noncurrent Deferred Income Tax Liabilities $ 3,518,214 $ 5,028,408 Total Net Deferred Income Tax Liabilities $ 3,500,708 $ 5,012,268 (1) United States federal deferred tax assets and liabilities tax effected at 21% and 35% for 2017 and 2016, respectively. (2) As described in Note 1, ASU 2015-17 eliminated the requirement to separate deferred tax assets and liabilities into current and noncurrent amounts. (3) Pursuant to the TCJA, $721 million of federal AMT credit carryforwards are expected to be refundable over four years and are presented as noncurrent tax receivables in Other Assets on the Consolidated Balance Sheet at December 31, 2017. (4) Undistributed foreign earnings have been deemed repatriated in 2017 in accordance with the TCJA. A portion of the associated federal taxes are now reflected as a noncurrent tax payable as a result of the eight year installment election.
Components of Income (Loss) Before Income Taxes	The components of Income (Loss) Before Income Taxes for the years indicated below were as follows (in thousands): 2017 2016 2015 United States $ 621,610 $ (1,520,573 ) $ (6,840,119 ) Foreign 39,572 (36,932 ) (81,437 ) Total $ 661,182 $ (1,557,505 ) $ (6,921,556 )
Components of Income Tax Provision (Benefit)	The principal components of EOG's Income Tax Benefit for the years indicated below were as follows (in thousands): 2017 2016 2015 Current: Federal $ 33,058 $ 11,567 $ 21,719 State (2,502 ) (8,369 ) 9,404 Foreign 35,323 51,189 54,143 Total 65,879 54,387 85,266 Deferred: Federal (1,504,288 ) (532,979 ) (2,362,926 ) State 26,942 4,876 (127,444 ) Foreign 3,474 12,897 8,063 Total (1,473,872 ) (515,206 ) (2,482,307 ) Other Non-Current: Federal (1) (513,404 ) — — Income Tax Benefit $ (1,921,397 ) $ (460,819 ) $ (2,397,041 ) (1) As described previously, under the TCJA, a deemed repatriation tax is to be paid over eight years beginning with respect to taxable year 2017. In addition, EOG expects to receive refunds of AMT credits over a four-year period beginning with respect to taxable year 2018. Other Non-Current includes the portion of these two items that relates to years after 2017.
Tax Rate Reconciliation	The differences between taxes computed at the U.S. federal statutory tax rate and EOG's effective rate were as follows: 2017 2016 2015 Statutory Federal Income Tax Rate 35.00 % 35.00 % 35.00 % State Income Tax, Net of Federal Benefit 3.38 0.15 1.11 Income Tax Provision Related to Foreign Operations (0.30 ) (1.23 ) (1.31 ) Income Tax Provision Related to Trinidad Operations — (3.71 ) — Income Tax Provision Related to United Kingdom Operations 1.78 — — Income Tax Provision Related to Canadian Operations 2.30 — — TCJA (1) (328.10 ) — — Share-Based Compensation (2) (4.63 ) — — Other (0.03 ) (0.62 ) (0.17 ) Effective Income Tax Rate (290.60 )% 29.59 % 34.63 % (1) Includes impact of federal tax rate reduction ( (327.8)% ), federal repatriation tax ( (6.6)% ), sequestration ( 6.4% ) and other tax reform impacts ( (0.1)% ). (2) As described in Note 1, ASU 2016-09, adopted by EOG in 2017, provides that share-based compensation tax benefits and deficiencies are recognized in the income tax provision.
Summary of Valuation Allowance	The principal components of EOG's rollforward of valuation allowances for deferred income tax assets were as follows (in thousands): 2017 2016 2015 Beginning Balance $ 383,221 $ 506,127 $ 463,018 Increase (1) 67,333 37,221 146,602 Decrease (2) (13,687 ) (12,667 ) (4,315 ) Other (3) 29,554 (147,460 ) (99,178 ) Ending Balance $ 466,421 $ 383,221 $ 506,127 (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/foreign exchange rate variances and the effect of statutory income tax rate changes.

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs	Stock-based compensation expense is included on the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) based upon the job functions of the employees receiving the grants. Compensation expense related to EOG's stock-based compensation plans for the years ended December 31, 2017 , 2016 and 2015 was as follows (in millions): 2017 2016 2015 Lease and Well $ 41 $ 38 $ 44 Gathering and Processing Costs 1 1 1 Exploration Costs 23 21 26 General and Administrative 69 68 60 Total $ 134 $ 128 $ 131
Vesting Schedule	These revised vesting schedules will apply to all future grants as well, until revised, amended or otherwise determined by the Committee. Grant Type Previous Vesting Schedule Revised Vesting Schedule Stock Options/SARs Vesting in 25% increments on each of the first four anniversaries of the date of grant 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 five years from the date of grant "Cliff" vesting three years from the date of grant Performance Units "Cliff" vesting five years from the date of grant (except for the December 2016 grant, which will "cliff" vest approximately three years from the date of grant) "Cliff" vesting approximately 41 months from the date of grant - specifically, on the February 28 th immediately following the Committee’s certifications contemplated by the form of award agreement governing grants 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, 2017 , 2016 and 2015 were as follows: Stock Options/SARs ESPP 2017 2016 2015 2017 2016 2015 Weighted Average Fair Value of Grants $ 23.95 $ 25.78 $ 21.88 $ 22.20 $ 19.21 $ 21.21 Expected Volatility 28.28 % 31.54 % 38.03 % 27.12 % 36.55 % 32.08 % Risk-Free Interest Rate 1.52 % 0.78 % 0.83 % 0.88 % 0.44 % 0.12 % Dividend Yield 0.75 % 0.76 % 0.85 % 0.71 % 0.82 % 0.73 % Expected Life 5.1 years 5.4 years 5.3 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, 2017 , 2016 and 2015 (stock options and SARs in thousands): 2017 2016 2015 Number Weighted Average Grant Price Number Weighted Average Grant Price Number Weighted Average Grant Price Outstanding at January 1 9,850 $ 75.53 10,744 $ 67.98 10,493 $ 64.96 Granted 2,274 96.27 1,855 94.82 2,037 69.99 Exercised (1) (2,574 ) 61.12 (2,376 ) 54.56 (1,518 ) 47.64 Forfeited (447 ) 93.84 (373 ) 87.38 (268 ) 80.31 Outstanding at December 31 9,103 83.89 9,850 75.53 10,744 67.98 Stock Options/SARs Exercisable at December 31 4,510 75.76 5,613 66.48 5,993 57.96 (1) The total intrinsic value of stock options/SARs exercised during the years 2017 , 2016 and 2015 was $95 million , $84 million and $60 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, 2017 (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) $ 34.00 to $ 59.99 1,472 1 $ 49.63 1,472 1 $ 49.63 60.00 to 84.99 2,392 4 75.67 1,623 3 78.51 85.00 to 95.99 1,684 6 94.82 421 5 94.73 96.00 to 99.99 2,239 7 96.32 21 3 98.06 100.00 to 116.99 1,316 4 102.03 973 3 102.03 9,103 4 83.89 $ 218,696 4,510 3 75.76 $ 145,024 (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 activities for the years ended December 31, 2017 , 2016 and 2015 (in thousands, except number of participants): 2017 2016 2015 Approximate Number of Participants 1,870 1,746 1,963 Shares Purchased 180 212 225 Aggregate Purchase Price $ 13,997 $ 13,787 $ 15,045
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, 2017 , 2016 and 2015 (shares and units in thousands): 2017 2016 2015 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 3,962 $ 79.63 4,908 $ 70.35 5,394 $ 64.39 Granted 1,095 97.34 853 88.01 1,044 77.94 Released (1) (929 ) 61.51 (1,465 ) 53.95 (1,331 ) 51.52 Forfeited (223 ) 85.45 (334 ) 77.29 (199 ) 74.56 Outstanding at December 31 (2) 3,905 88.57 3,962 79.63 4,908 70.35 (1) The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2017, 2016 and 2015 was $91 million , $124 million and $109 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, 2017, 2016 and 2015 was approximately $421 million , $401 million and $347 million , respectively.
Weighted Average Fair Values and Valuation Assumptions for Performance Units/Stocks	Weighted average fair values and valuation assumptions used to value Performance Awards during the years ended December 31, 2017 , 2016 and 2015 were as follows: 2017 2016 2015 Weighted Average Fair Value of Grants $ 113.81 $ 119.10 $ 80.64 Expected Volatility 32.19 % 32.48 % 29.35 % Risk-Free Interest Rate 1.60 % 1.15 % 1.07 %
Performance Unit and Performance Stock Transactions	The following table sets forth the Performance Awards transactions for the years ended December 31, 2017 , 2016 and 2015 : 2017 2016 2015 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 1 545,290 $ 80.92 405,000 $ 74.93 333,195 $ 76.11 Granted 78,527 96.29 131,750 100.95 71,805 69.43 Granted for Performance Multiple (1) 118,834 84.43 142,556 56.21 — — Released (2) (240,320 ) 66.69 (134,016 ) 56.21 — — Forfeited — — — — — — Outstanding at December 31 (3) 502,331 (4 ) 90.96 545,290 80.92 405,000 74.93 (1) Upon completion of the Performance Period for the Performance Awards granted in 2013 and 2012, a performance multiple of 200% was applied to each of the grants resulting in additional grants of Performance Awards in February 2017 and 2016. (2) The total intrinsic value of Performance Awards released during the years ended December 31, 2017, 2016 and 2015 was approximately $24 million , $10 million and $0 , respectively. (3) The total intrinsic value of Performance Awards outstanding at December 31, 2017, 2016 and 2015 was approximately $54 million , $55 million and $29 million , respectively. (4) Upon the application of the relevant performance multiple at the completion of each of the remaining Performance Periods, a minimum of 148,444 and a maximum of 856,218 Performance Awards could be outstanding. The intrinsic value is based upon the closing price of EOG's common stock on the date Performance Awards are released.

Commitments and Contingencies33

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Minimum commitments for unrecorded unconditional purchase obligations	At December 31, 2017 , total minimum commitments from long-term non-cancelable operating leases, drilling rig commitments, seismic purchase obligations, fracturing services obligations, other purchase obligations and transportation and storage service commitments, based on current transportation and storage rates and the foreign currency exchange rates used to convert Canadian dollars and British pounds into United States dollars at December 31, 2017 , were as follows (in thousands): Total Minimum Commitments 2018 $ 1,855,005 2019 1,068,994 2020 800,078 2021 567,840 2022 478,480 2023 and beyond 944,911 $ 5,715,308

Net Income (Loss) Per Share (Ta

Net Income (Loss) Per Share (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Computation of Net Income (Loss) Per Share	The following table sets forth the computation of Net Income (Loss) Per Share for the years ended December 31, 2017 , 2016 and 2015 (in thousands, except per share data): 2017 2016 2015 Numerator for Basic and Diluted Earnings per Share - Net Income (Loss) $ 2,582,579 $ (1,096,686 ) $ (4,524,515 ) Denominator for Basic Earnings per Share - Weighted Average Shares 574,620 553,384 545,697 Potential Dilutive Common Shares - Stock Options/SARs 1,466 — — Restricted Stock/Units and Performance Units/Stock 2,607 — — Denominator for Diluted Earnings per Share - Adjusted Diluted Weighted Average Shares 578,693 553,384 545,697 Net Income (Loss) Per Share Basic $ 4.49 $ (1.98 ) $ (8.29 ) Diluted $ 4.46 $ (1.98 ) $ (8.29 )

Supplemental Cash Flow Inform35

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2017
Supplemental Cash Flow Information [Abstract]
Net Cash Paid For Interest and Income Taxes	Net cash paid for interest and income taxes was as follows for the years ended December 31, 2017 , 2016 and 2015 (in thousands): 2017 2016 2015 Interest, Net of Capitalized Interest $ 275,305 $ 252,030 $ 222,088 Income Taxes, Net of Refunds Received $ 188,946 $ (39,293 ) $ 41,108

Business Segment Information (T

Business Segment Information (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 , 2016 and 2015 (in thousands): United States Trinidad Other International (1) Total 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 (Losses) on Mark-to-Market Commodity Derivative Contracts 19,828 — — 19,828 Gathering, Processing and Marketing 3,298,098 (11 ) — 3,298,087 Gains (Losses) on Asset Dispositions, Net (98,233 ) (8 ) (855 ) (99,096 ) Other, Net 81,610 59 (59 ) 81,610 Net Operating Revenues and Other (2) 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 United States Trinidad Other International (1) Total 2016 Crude Oil and Condensate $ 4,265,036 $ 9,600 $ 42,705 $ 4,317,341 Natural Gas Liquids 437,238 — 12 437,250 Natural Gas 475,715 234,108 32,329 742,152 Losses on Mark-to-Market Commodity Derivative Contracts (99,608 ) — — (99,608 ) Gathering, Processing and Marketing 1,967,390 (1,131 ) — 1,966,259 Gains (Losses) on Asset Dispositions, Net 196,043 (145 ) 9,937 205,835 Other, Net 81,386 (8 ) 25 81,403 Net Operating Revenues and Other (3) 7,323,200 242,424 85,008 7,650,632 Depreciation, Depletion and Amortization 3,365,390 145,591 42,436 3,553,417 Operating Income (Loss) (1,192,338 ) 46,473 (79,416 ) (1,225,281 ) Interest Income 358 932 1,329 2,619 Other Income (Expense) (15,703 ) 2,667 (40,126 ) (53,162 ) Net Interest Expense 298,125 — (16,444 ) 281,681 Income (Loss) Before Income Taxes (1,505,808 ) 50,072 (101,769 ) (1,557,505 ) Income Tax Provision (Benefit) (516,180 ) 64,281 (8,920 ) (460,819 ) Additions to Oil and Gas Properties, Excluding Dry Hole Costs 6,223,228 75,407 30,734 6,329,369 Total Property, Plant and Equipment, Net 25,221,517 274,850 210,711 25,707,078 Total Assets (4) 27,746,851 889,253 663,097 29,299,201 2015 Crude Oil and Condensate $ 4,917,731 $ 13,122 $ 3,709 $ 4,934,562 Natural Gas Liquids 407,570 — 88 407,658 Natural Gas 637,452 368,639 54,947 1,061,038 Gains on Mark-to-Market Commodity Derivative Contracts 61,924 — — 61,924 Gathering, Processing and Marketing 2,254,477 (1,342 ) — 2,253,135 Gains (Losses) on Asset Dispositions, Net (12,176 ) 393 2,985 (8,798 ) Other, Net 47,464 (3 ) 448 47,909 Net Operating Revenues and Other (5) 8,314,442 380,809 62,177 8,757,428 Depreciation, Depletion and Amortization 3,139,863 154,853 18,928 3,313,644 Operating Income (Loss) (6,566,282 ) 175,658 (295,455 ) (6,686,079 ) Interest Income 1,913 389 1,167 3,469 Other Income (Expense) 6,461 8,780 (16,794 ) (1,553 ) Net Interest Expense 274,606 1,400 (38,613 ) 237,393 Income (Loss) Before Income Taxes (6,832,514 ) 183,427 (272,469 ) (6,921,556 ) Income Tax Provision (Benefit) (2,463,213 ) 63,502 2,670 (2,397,041 ) Additions to Oil and Gas Properties, Excluding Dry Hole Costs 4,495,730 102,358 112,316 4,710,404 Total Property, Plant and Equipment, Net 23,593,995 350,766 265,960 24,210,721 Total Assets (6) 25,211,572 886,826 736,510 26,834,908 (1) Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016. (2) EOG had sales activity with two significant purchasers in 2017, one totaling $1.5 billion and the other totaling $1.3 billion of consolidated Net Operating Revenues and Other in the United States segment. (3) EOG had sales activity with three significant purchasers in 2016, one totaling $1.2 billion , one totaling $1.1 billion and one totaling $1.0 billion of consolidated Net Operating Revenues and Other in the United States segment. (4) EOG made a reclassification of $160 million from deferred tax liabilities to deferred tax assets for the year ended December 31, 2016, for the United States segment and in total. (5) EOG had sales activity with two significant purchasers in 2015, one totaling $1.7 billion and the other totaling $1.4 billion of consolidated Net Operating Revenues and Other in the United States segment. (6) EOG made a reclassification of $136 million from deferred tax liabilities to deferred tax assets for the year ended December 31, 2015, for the United States segment and in total.

Risk Management Activities (Tab

Risk Management Activities (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 and 2016 , respectively. Certain amounts may be presented on a net basis on the consolidated financial statements when such amounts are with the same counterparty and subject to a master netting arrangement (in millions): Fair Value at December 31, Description Location on Balance Sheet 2017 2016 Asset Derivatives Crude oil and natural gas derivative contracts - Current portion Assets from Price Risk Management Activities $ 8 $ — Noncurrent portion Other Assets — 1 Liability Derivatives Crude oil and natural gas derivative contracts - Current portion Liabilities from Price Risk Management Activities (1) $ 50 $ 62 Noncurrent portion Other Liabilities 7 — (1) The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $55 million , partially offset by gross assets of $5 million , at December 31, 2017.
Crude Oil [Member] | Midland Differential Basis Swap [Member]
Derivatives, Fair Value [Line Items]
Schedule of Derivative Instruments	Presented below is a comprehensive summary of EOG's Midland Differential basis swap contracts for the year ended December 31, 2017. The weighted average price differential expressed in dollars per barrel ($/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) 2018 January 2018 (closed) 15,000 $ 1.063 February 1, 2018 through December 31, 2018 15,000 1.063 2019 January 1, 2019 through December 31, 2019 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, 2017. 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) 2018 January 2018 (closed) 37,000 $ 3.818 February 1, 2018 through December 31, 2018 37,000 3.818
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, 2017, with notional volumes expressed in Bbld and prices expressed in $/Bbl. Crude Oil Price Swap Contracts Volume (Bbld) Weighted Average Price ($/Bbl) 2017 January 1, 2017 through February 28, 2017 (closed) 35,000 $ 50.04 March 1, 2017 through June 30, 2017 (closed) 30,000 50.05 2018 January 1, 2018 through December 31, 2018 37,000 $ 56.48
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, 2017, 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) 2017 March 1, 2017 through November 30, 2017 (closed) 30,000 $ 3.10 2018 March 1, 2018 through November 30, 2018 35,000 $ 3.00
Natural Gas [Member] | Options [Member]
Derivatives, Fair Value [Line Items]
Schedule of Derivative Instruments	Presented below is a comprehensive summary of EOG's natural gas call and put option contracts for the year ended December 31, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. Natural Gas Option Contracts Call Options Sold Put Options Purchased Volume (MMBtud) Weighted Volume (MMBtud) Weighted 2017 March 1, 2017 through November 30, 2017 (closed) 213,750 $ 3.44 171,000 $ 2.92 2018 March 1, 2018 through November 30, 2018 120,000 $ 3.38 96,000 $ 2.94
Natural Gas [Member] | Collars [Member]
Derivatives, Fair Value [Line Items]
Schedule of Derivative Instruments	Presented below is a comprehensive summary of EOG's natural gas collar contracts for the year ended December 31, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMbtu. Natural Gas Collar Contracts Weighted Average Price ($/MMbtu) Volume (MMBtud) Ceiling Price Floor Price 2017 March 1, 2017 through November 30, 2017 (closed) 80,000 $ 3.69 $ 3.20

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 and 2016. Amounts shown in millions. 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, 2017 Financial Assets: (1) Natural Gas Swaps $ — $ 2 $ — $ 2 Natural Gas Options/Collars — 6 — 6 Financial Liabilities: (2) Crude Oil Swaps $ — $ 38 $ — $ 38 Crude Oil Basis Swaps — 19 — 19 At December 31, 2016 Financial Assets: (1) Natural Gas Options/Collars $ — $ 1 $ — $ 1 Financial Liabilities: (2) Crude Oil Swaps $ — $ 36 $ — $ 36 Natural Gas Swaps — 4 — 4 Natural Gas Options/Collars — 22 — 22 (1) $8 million is included in "Assets from Price Risk Management Activities" at December 31, 2017, and $1 million is included in "Other Assets" at December 31, 2016, on the Consolidated Balance Sheets. (2) $50 million and $62 million is included in "Current Liabilities - Liabilities from Price Risk Management Activities" at December 31, 2017 and 2016, respectively, and $7 million is included in "Other Liabilities" at December 31, 2017, on the Consolidated Balance Sheets.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 and 2016 (in thousands): 2017 2016 Carrying Amount at Beginning of Period $ 912,926 $ 811,554 Liabilities Incurred (1) 54,764 212,739 Liabilities Settled (2) (61,871 ) (94,800 ) Accretion 34,708 32,306 Revisions (9,818 ) (38,286 ) Foreign Currency Translations 16,139 (10,587 ) Carrying Amount at End of Period $ 946,848 $ 912,926 Current Portion $ 19,259 $ 18,516 Noncurrent Portion $ 927,589 $ 894,410 (1) Includes $164 million in 2016 related to Yates transaction (see Note 17). (2) Includes settlements related to asset sales.

Exploratory Well Costs (Tables)

Exploratory Well Costs (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 , 2016 and 2015 are presented below (in thousands): 2017 2016 2015 Balance at January 1 $ — $ 8,955 $ 17,253 Additions Pending the Determination of Proved Reserves 27,487 6,688 24,640 Reclassifications to Proved Properties (20,802 ) (5,274 ) (26,659 ) Costs Charged to Expense (1) (4,518 ) (10,369 ) (6,279 ) Balance at December 31 $ 2,167 $ — $ 8,955 (1) Includes capitalized exploratory well costs charged to either dry hole costs or impairments.

Acquisitions and Divestitures A

Acquisitions and Divestitures Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2017
Acquisitions and Divestitures [Abstract]
Preliminary Allocation of Total Purchase Price	The following table represents the final allocation of the total purchase price of the Yates Entities (in thousands). Current Assets Cash and Cash Equivalents $ 70,411 Accounts Receivable, Net 77,073 Inventories 10,955 Other 10,640 Total 169,079 Property, Plant and Equipment Oil and Gas Properties (Successful Efforts Method) 3,815,207 Other Property, Plant and Equipment 21,824 Total Property, Plant and Equipment, Net 3,837,031 Other Assets 22,706 Total Assets $ 4,028,816 Current Liabilities Accounts Payable $ 124,145 Accrued Taxes Payable 22,417 Other 743 Total 147,305 Long-Term Debt 163,829 Asset Retirement Obligations 163,144 Off-Market Transportation Contracts 39,720 Other Liabilities 28,645 Deferred Income Taxes 1,072,405 Total Liabilities $ 1,615,048 Total Consideration Transferred $ 2,413,768

Oil and Gas Exploration and P42

Oil and Gas Exploration and Production Industries Disclosures (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 , and the changes in the net proved reserves for each of the three years in the period ended December 31, 2017 , 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, 2014 1,129,682 1,339 8,729 1,139,750 Revisions of previous estimates (114,924 ) (1 ) — (114,925 ) Purchases in place 35,922 — — 35,922 Extensions, discoveries and other additions 141,310 63 13 141,386 Sales in place (730 ) — (10 ) (740 ) Production (103,400 ) (332 ) (65 ) (103,797 ) Net proved reserves at December 31, 2015 1,087,860 1,069 8,667 1,097,596 Revisions of previous estimates 42,040 54 861 42,955 Purchases in place 25,795 — — 25,795 Extensions, discoveries and other additions 123,441 — — 123,441 Sales in place (8,791 ) — — (8,791 ) Production (101,854 ) (284 ) (1,273 ) (103,411 ) 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 Natural Gas Liquids (MBbl) (2) Net proved reserves at December 31, 2014 466,930 — 138 467,068 Revisions of previous estimates (113,290 ) — 68 (113,222 ) Purchases in place 8,251 — — 8,251 Extensions, discoveries and other additions 49,147 — — 49,147 Sales in place (84 ) — (187 ) (271 ) Production (28,079 ) — (19 ) (28,098 ) Net proved reserves at December 31, 2015 382,875 — — 382,875 Revisions of previous estimates 53,771 — — 53,771 Purchases in place 1,284 — — 1,284 Extensions, discoveries and other additions 41,862 — — 41,862 Sales in place (33,548 ) — — (33,548 ) Production (29,878 ) — — (29,878 ) 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 United States Trinidad Other International (1) Total Natural Gas (Bcf) (3) Net proved reserves at December 31, 2014 4,905.5 405.6 31.5 5,342.6 Revisions of previous estimates (1,453.1 ) 16.8 5.6 (1,430.7 ) Purchases in place 72.3 — — 72.3 Extensions, discoveries and other additions 306.3 21.7 4.4 332.4 Sales in place (3.9 ) — (11.1 ) (15.0 ) Production (337.3 ) (127.5 ) (10.9 ) (475.7 ) Net proved reserves at December 31, 2015 3,489.8 316.6 19.5 3,825.9 Revisions of previous estimates 298.4 29.5 5.2 333.1 Purchases in place 91.5 — — 91.5 Extensions, discoveries and other additions 202.1 59.9 — 262.0 Sales in place (752.0 ) — — (752.0 ) Production (308.6 ) (125.1 ) (8.9 ) (442.6 ) 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 Oil Equivalents (MBoe) (2) Net proved reserves at December 31, 2014 2,414,202 68,937 14,117 2,497,256 Revisions of previous estimates (470,401 ) 2,802 995 (466,604 ) Purchases in place 56,215 — — 56,215 Extensions, discoveries and other additions 241,513 3,682 736 245,931 Sales in place (1,467 ) — (2,039 ) (3,506 ) Production (187,701 ) (21,578 ) (1,896 ) (211,175 ) Net proved reserves at December 31, 2015 2,052,361 53,843 11,913 2,118,117 Revisions of previous estimates 145,542 4,978 1,722 152,242 Purchases in place 42,330 — — 42,330 Extensions, discoveries and other additions 198,973 9,990 — 208,963 Sales in place (167,669 ) — — (167,669 ) Production (183,145 ) (21,150 ) (2,755 ) (207,050 ) 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 (1) Other International includes EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016. (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, 2014 493,694 1,339 115 495,148 December 31, 2015 444,070 1,069 63 445,202 December 31, 2016 507,531 839 8,255 516,625 December 31, 2017 605,405 898 7,933 614,236 Natural Gas Liquids (MBbl) December 31, 2014 264,611 — 138 264,749 December 31, 2015 205,898 — — 205,898 December 31, 2016 230,219 — — 230,219 December 31, 2017 286,872 — — 286,872 Natural Gas (Bcf) December 31, 2014 3,102.8 396.9 28.6 3,528.3 December 31, 2015 2,211.2 297.6 19.5 2,528.3 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 Oil Equivalents (MBoe) December 31, 2014 1,275,447 67,484 5,016 1,347,947 December 31, 2015 1,018,491 50,677 3,309 1,072,477 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 NET PROVED UNDEVELOPED RESERVES Crude Oil (MBbl) December 31, 2014 635,988 — 8,614 644,602 December 31, 2015 643,790 — 8,604 652,394 December 31, 2016 660,690 — — 660,690 December 31, 2017 698,666 — 71 698,737 Natural Gas Liquids (MBbl) December 31, 2014 202,319 — — 202,319 December 31, 2015 176,977 — — 176,977 December 31, 2016 186,147 — — 186,147 December 31, 2017 216,601 — — 216,601 Natural Gas (Bcf) December 31, 2014 1,802.7 8.7 2.9 1,814.3 December 31, 2015 1,278.6 19.0 — 1,297.6 December 31, 2016 1,216.8 18.7 — 1,235.5 December 31, 2017 1,447.7 14.2 21.9 1,483.8 Oil Equivalents (MBoe) December 31, 2014 1,138,755 1,453 9,101 1,149,309 December 31, 2015 1,033,870 3,166 8,604 1,045,640 December 31, 2016 1,049,909 3,118 — 1,053,027 December 31, 2017 1,156,544 2,363 3,728 1,162,635 (1) Other International includes EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016.
Net Proved Undeveloped Reserves	The following table presents the changes in EOG's total proved undeveloped reserves during 2017 , 2016 and 2015 (in MBoe): 2017 2016 2015 Balance at January 1 1,053,027 1,045,640 1,149,309 Extensions and Discoveries 237,378 138,101 205,152 Revisions 33,127 64,413 (241,973 ) Acquisition of Reserves — — 54,458 Sale of Reserves (8,253 ) (45,917 ) — Conversion to Proved Developed Reserves (152,644 ) (149,210 ) (121,306 ) Balance at December 31 1,162,635 1,053,027 1,045,640
Capitalized Costs Relating to Oil and Gas Producing Activities	The following table sets forth the capitalized costs relating to EOG's crude oil and natural gas producing activities at December 31, 2017 and 2016 : 2017 2016 Proved properties $ 48,845,672 $ 45,751,965 Unproved properties 3,710,069 3,840,126 Total 52,555,741 49,592,091 Accumulated depreciation, depletion and amortization (29,191,247 ) (26,247,062 ) Net capitalized costs $ 23,364,494 $ 23,345,029
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, 2017 , 2016 and 2015 : United States Trinidad Other International (1) Total 2017 Acquisition Costs of Properties Unproved (2) $ 424,118 $ 2,422 $ — $ 426,540 Proved (3) 72,584 — — 72,584 Subtotal 496,702 2,422 — 499,124 Exploration Costs 144,499 62,547 16,553 223,599 Development Costs (4) 3,590,899 109,491 16,297 3,716,687 Total $ 4,232,100 $ 174,460 $ 32,850 $ 4,439,410 2016 Acquisition Costs of Properties Unproved (5) $ 3,216,598 $ — $ 36 $ 3,216,634 Proved (6) 749,023 — — 749,023 Subtotal 3,965,621 — 36 3,965,657 Exploration Costs 156,295 2,695 6,761 165,751 Development Costs (7) 2,252,713 72,147 (10,984 ) 2,313,876 Total $ 6,374,629 $ 74,842 $ (4,187 ) $ 6,445,284 2015 Acquisition Costs of Properties Unproved $ 133,801 $ — $ 56 $ 133,857 Proved 480,617 — — 480,617 Subtotal 614,418 — 56 614,474 Exploration Costs 206,814 22,837 23,041 252,692 Development Costs (8) 3,847,813 102,715 110,589 4,061,117 Total $ 4,669,045 $ 125,552 $ 133,686 $ 4,928,283 (1) Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016. (2) Includes non-cash unproved leasehold acquisition costs of $256 million related to property exchanges. (3) Includes non-cash proved property acquisition costs of $26 million related to property exchanges. (4) 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. (5) Includes non-cash unproved leasehold acquisition costs of $3,102 million related to the Yates transaction. (6) Includes non-cash proved property acquisition costs of $732 million related to the Yates transaction. (7) Includes Asset Retirement Costs of $25 million , $(3) million and $(42) million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment. (8) Includes Asset Retirement Costs of $32 million , $15 million and $6 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, 2017 , 2016 and 2015 : United States Trinidad Other International (2) Total 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 2016 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues $ 5,177,989 $ 243,708 $ 75,046 $ 5,496,743 Other 81,386 (8 ) 25 81,403 Total 5,259,375 243,700 75,071 5,578,146 Exploration Costs 115,990 2,647 6,316 124,953 Dry Hole Costs 10,529 — 128 10,657 Transportation Costs 753,791 1,181 9,134 764,106 Production Costs 1,163,827 27,113 63,073 1,254,013 Impairments 611,297 7,773 1,197 620,267 Depreciation, Depletion and Amortization 3,249,792 145,440 42,052 3,437,284 Income (Loss) Before Income Taxes (645,851 ) 59,546 (46,829 ) (633,134 ) Income Tax Provision (Benefit) (230,377 ) 5,526 (1,562 ) (226,413 ) Results of Operations $ (415,474 ) $ 54,020 $ (45,267 ) $ (406,721 ) 2015 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues $ 5,962,753 $ 381,761 $ 58,744 $ 6,403,258 Other 47,464 (3 ) 448 47,909 Total 6,010,217 381,758 59,192 6,451,167 Exploration Costs 139,753 2,071 7,670 149,494 Dry Hole Costs 956 5,635 8,155 14,746 Transportation Costs 838,428 1,290 9,601 849,319 Production Costs 1,486,189 28,862 66,080 1,581,131 Impairments 6,402,908 — 210,638 6,613,546 Depreciation, Depletion and Amortization 3,017,386 154,588 18,469 3,190,443 Income (Loss) Before Income Taxes (5,875,403 ) 189,312 (261,421 ) (5,947,512 ) Income Tax Provision (2,128,183 ) 43,739 (2,111 ) (2,086,555 ) Results of Operations $ (3,747,220 ) $ 145,573 $ (259,310 ) $ (3,860,957 ) (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, 2017 . (2) Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016.
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, 2017 , 2016 and 2015 : United States Trinidad Other International (1) Composite Year Ended December 31, 2017 $ 4.58 $ 1.39 $ 50.86 $ 4.66 Year Ended December 31, 2016 $ 4.58 $ 1.23 $ 22.43 $ 4.48 Year Ended December 31, 2015 $ 5.81 $ 1.29 $ 33.78 $ 5.85 (1) Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016.
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, 2017 , 2016 and 2015 : United States Trinidad Other International (1) Total 2017 Future cash inflows (2) $ 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 2016 Future cash inflows (3) $ 57,913,314 $ 524,523 $ 402,587 $ 58,840,424 Future production costs (27,625,833 ) (165,757 ) (227,293 ) (28,018,883 ) Future development costs (12,602,699 ) (103,631 ) (35,602 ) (12,741,932 ) Future income taxes (3,151,319 ) (60,001 ) — (3,211,320 ) Future net cash flows 14,533,463 195,134 139,692 14,868,289 Discount to present value at 10% annual rate (6,039,736 ) (9,384 ) (7,012 ) (6,056,132 ) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 8,493,727 $ 185,750 $ 132,680 $ 8,812,157 2015 Future cash inflows (4) $ 67,242,928 $ 954,779 $ 522,941 $ 68,720,648 Future production costs (31,707,743 ) (183,607 ) (169,505 ) (32,060,855 ) Future development costs (15,579,923 ) (140,541 ) (65,347 ) (15,785,811 ) Future income taxes (4,400,542 ) (215,659 ) — (4,616,201 ) Future net cash flows 15,554,720 414,972 288,089 16,257,781 Discount to present value at 10% annual rate (6,589,253 ) (33,848 ) (13,284 ) (6,636,385 ) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 8,965,467 $ 381,124 $ 274,805 $ 9,621,396 (1) Other International includes EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016. (2) 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. (3) Estimated crude oil prices used to calculate 2016 future cash inflows for the United States, Trinidad and Other International were $40.70 , $34.79 and $39.55 , respectively. Estimated NGL price used to calculate 2016 future cash inflows for the United States was $14.69 . Estimated natural gas prices used to calculate 2016 future cash inflows for the United States, Trinidad and Other International were $1.40 , $1.76 and $4.84 , respectively. (4) Estimated crude oil prices used to calculate 2015 future cash inflows for the United States, Trinidad and Other International were $49.58 , $38.83 and $47.76 , respectively. Estimated NGL price used to calculate 2015 future cash inflows for the United States was $15.17 . Estimated natural gas prices used to calculate 2015 future cash inflows for the United States, Trinidad and Other International were $2.15 , $2.88 and $5.60 , 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, 2017 : United States Trinidad Other International (1) Total December 31, 2014 $ 26,704,041 $ 682,536 $ 536,841 $ 27,923,418 Sales and transfers of oil and gas produced, net of production costs (3,685,600 ) (351,606 ) 16,489 (4,020,717 ) Net changes in prices and production costs (29,993,699 ) (370,503 ) (305,148 ) (30,669,350 ) Extensions, discoveries, additions and improved recovery, net of related costs 1,028,410 47,613 19,875 1,095,898 Development costs incurred 2,135,800 500 1,400 2,137,700 Revisions of estimated development cost 4,087,093 (34,647 ) 26,935 4,079,381 Revisions of previous quantity estimates (4,084,572 ) 33,285 (587 ) (4,051,874 ) Accretion of discount 3,699,330 104,464 53,685 3,857,479 Net change in income taxes 9,550,847 177,576 — 9,728,423 Purchases of reserves in place 123,542 — — 123,542 Sales of reserves in place (23,424 ) — (13,664 ) (37,088 ) Changes in timing and other (576,301 ) 91,906 (61,021 ) (545,416 ) December 31, 2015 8,965,467 381,124 274,805 9,621,396 Sales and transfers of oil and gas produced, net of production costs (3,260,372 ) (215,414 ) (2,839 ) (3,478,625 ) Net changes in prices and production costs (3,352,802 ) (182,876 ) (143,924 ) (3,679,602 ) Extensions, discoveries, additions and improved recovery, net of related costs 865,066 42,201 — 907,267 Development costs incurred 1,207,000 3,900 19,100 1,230,000 Revisions of estimated development cost 2,092,769 22,596 6,343 2,121,708 Revisions of previous quantity estimates 1,013,753 36,648 2,619 1,053,020 Accretion of discount 970,388 56,566 27,481 1,054,435 Net change in income taxes 738,416 129,622 — 868,038 Purchases of reserves in place 377,872 — — 377,872 Sales of reserves in place (375,793 ) — — (375,793 ) Changes in timing and other (748,037 ) (88,617 ) (50,905 ) (887,559 ) 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 (1) Other International includes EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016.

Unaudited Quarterly Financial43

Unaudited Quarterly Financial Information (Tables)	12 Months Ended
	Dec. 31, 2017
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 2017 Net Operating Revenues and Other $ 2,610,565 $ 2,612,472 $ 2,644,844 $ 3,340,439 Operating Income $ 107,746 $ 127,908 $ 214,836 $ 475,912 Income Before Income Taxes $ 39,382 $ 62,467 $ 145,980 $ 413,353 Income Tax Provision (Benefit) (1) 10,865 39,414 45,439 (2,017,115 ) Net Income $ 28,517 $ 23,053 $ 100,541 $ 2,430,468 Net Income Per Share (2) Basic $ 0.05 $ 0.04 $ 0.17 $ 4.22 Diluted $ 0.05 $ 0.04 $ 0.17 $ 4.20 Average Number of Common Shares Basic 573,935 574,439 574,783 575,394 Diluted 578,593 578,483 578,736 579,203 2016 Net Operating Revenues and Other $ 1,354,349 $ 1,775,740 $ 2,118,504 $ 2,402,039 Operating Income (Loss) $ (638,141 ) $ (288,173 ) $ (193,480 ) $ (105,487 ) Loss Before Income Taxes $ (710,968 ) $ (380,277 ) $ (272,250 ) $ (194,010 ) Income Tax Benefit (239,192 ) (87,719 ) (82,250 ) (51,658 ) Net Income (Loss) $ (471,776 ) $ (292,558 ) $ (190,000 ) $ (142,352 ) Net Income (Loss) Per Share (2) Basic $ (0.86 ) $ (0.53 ) $ (0.35 ) $ (0.25 ) Diluted $ (0.86 ) $ (0.53 ) $ (0.35 ) $ (0.25 ) Average Number of Common Shares Basic 546,715 547,335 547,838 567,337 Diluted 546,715 547,335 547,838 567,337 (1) Includes an income tax benefit of approximately $2.2 billion for the quarter ended December 31, 2017, primarily due to the enactment of the Tax Cuts and Jobs Act in December 2017. See Note 6 to the Consolidated Financial Statements. (2) The sum of quarterly net income (loss) per share may not agree with total year net income (loss) per share as each quarterly computation is based on the weighted average of common shares outstanding.

Summary of Significant Accoun44

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Deferred Tax Assets, Net, Current		$ 169
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense	$ 32

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument Table [Line Items]
Long-Term Debt	$ 6,390,000,000	$ 6,990,000,000
Capital Lease Obligation	32,155,000	38,710,000
Less: Current Portion of Long-Term Debt	356,235,000	6,579,000
Unamortized Debt Discount	30,564,000	36,915,000
Debt Issuance Costs	4,520,000	5,437,000
Total Long-Term Debt	6,030,836,000	6,979,779,000
Long-Term Debt by Maturity [Abstract]
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2018	350,000,000
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2019	900,000,000
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
Revolving Credit Agreement 2020
Line of Credit Facility [Line Items]
Current Borrowings Outstanding	0
Average Borrowings Outstanding	$ 0
Line of Credit Facility, Expiration Date	Jul. 21, 2020
Maximum borrowing capacity	$ 2,000,000,000
Maximum total debt-to-total capitalization ratio allowed under financial covenant (in hundredths)	65.00%
Revolving Credit Agreement 2020 | Eurodollar [Member]
Line of Credit Facility [Line Items]
Effective Interest Rate (in hundredths)	2.56%
Revolving Credit Agreement 2020 | Base Rate [Member]
Line of Credit Facility [Line Items]
Effective Interest Rate (in hundredths)	4.50%
Uncommitted Credit Facilities
Line of Credit Facility [Line Items]
Current Borrowings Outstanding	$ 0	0
Commercial Paper
Line of Credit Facility [Line Items]
Current Borrowings Outstanding	0	0
Long-term Commercial Paper, Noncurrent	0
Average Borrowings Outstanding	$ 84,000,000	$ 130,000,000
Short-term Debt, Weighted Average Interest Rate, over Time	1.44%	0.76%
5.10% Senior Notes Due 2036
Debt Instrument Table [Line Items]
Long-Term Debt	$ 250,000,000	$ 250,000,000
Debt Instrument Issuance [Abstract]
Debt Instrument Issuance Face Amount	$ 250,000,000
Debt Instrument Issuance Interest Rate	5.10%
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
Senior Notes Due 2026 [Member]
Debt Instrument Table [Line Items]
Long-Term Debt	750,000,000	750,000,000
Debt Instrument Issuance [Abstract]
Debt Instrument Issuance Face Amount	$ 750,000,000
Debt Instrument Issuance Interest Rate	4.15%
3.90% Senior Notes due 2035
Debt Instrument Table [Line Items]
Long-Term Debt	$ 500,000,000	500,000,000
2.500% Senior Notes due 2016
Debt Instrument Issuance [Abstract]
Debt Instrument Issuance Face Amount	$ 400,000,000
Debt Instrument Issuance Interest Rate	2.50%
5.875% Senior Notes due 2017
Debt Instrument Table [Line Items]
Long-Term Debt	$ 0	600,000,000
Debt Instrument Issuance [Abstract]
Debt Instrument Issuance Face Amount	$ 600,000,000
Debt Instrument Issuance Interest Rate	5.88%
6.875% Senior Notes due 2018
Debt Instrument Table [Line Items]
Long-Term Debt	$ 350,000,000	350,000,000
5.625% Senior Notes due 2019
Debt Instrument Table [Line Items]
Long-Term Debt	900,000,000	900,000,000
4.40% Senior Notes due 2020
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
6.65% Senior Notes due 2028
Debt Instrument Table [Line Items]
Long-Term Debt	140,000,000	$ 140,000,000
the New Notes
Debt Instrument Issuance [Abstract]
Net Proceeds From Issuance of Senior Long-Term Debt	$ 991,000,000

Stockholder's Equity (Details)

Stockholder's Equity (Details) - $ / shares		9 Months Ended	12 Months Ended
		Oct. 04, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
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
Common Stock, Shares Authorized			1,280,000,000	640,000,000
Common Stock, Dividends, Per Share, Cash Paid			$ 0.1675	$ 0.1675	$ 0.1675
Percentage increase of cash dividend on common stock			10.00%
Dividends Payable, Amount Per Share After Increase			$ 0.1850
Common Stock Activity [Line Items]
Balance (in shares)			576,950,272
Stock Issued During Period, Shares, Acquisitions (in shares)		25,000,000	25,000,000
Balance (in shares)			578,827,768	576,950,272
Preferred Stock, Shares Outstanding			0
Common Shares, Outstanding [Member]
Common Stock Activity [Line Items]
Balance (in shares)		549,859,000	576,700,000	549,859,000	548,295,000
Common Stock Issued Under Stock-Based Compensation Plans (in shares)			1,878,000	1,500,000	1,019,000
Treasury Stock Purchased (1) (in shares)	[1]		(686,000)	(922,000)	(581,000)
Common Stock Issued Under Employee Stock Purchase Plan (in shares)			180,000	212,000	225,000
Treasury Stock Issued Under Stock-Based Compensation Plans (in shares)			405,000	847,000	901,000
Stock Issued During Period, Shares, Acquisitions (in shares)				25,204,000
Balance (in shares)			578,477,000	576,700,000	549,859,000
Common Shares, Treasury [Member]
Common Stock Activity [Line Items]
Balance (in shares)		(292,000)	(250,000)	(292,000)	(733,000)
Common Stock Issued Under Stock-Based Compensation Plans (in shares)			0	0	0
Treasury Stock Purchased (1) (in shares)	[1]		(686,000)	(922,000)	(581,000)
Common Stock Issued Under Employee Stock Purchase Plan (in shares)			180,000	117,000	121,000
Treasury Stock Issued Under Stock-Based Compensation Plans (in shares)			405,000	847,000	901,000
Stock Issued During Period, Shares, Acquisitions (in shares)				0
Balance (in shares)			(351,000)	(250,000)	(292,000)
Common Shares, Issued [Member]
Common Stock Activity [Line Items]
Balance (in shares)		550,151,000	576,950,000	550,151,000	549,028,000
Common Stock Issued Under Stock-Based Compensation Plans (in shares)			1,878,000	1,500,000	1,019,000
Treasury Stock Purchased (1) (in shares)	[1]		0	0	0
Common Stock Issued Under Employee Stock Purchase Plan (in shares)			0	95,000	104,000
Treasury Stock Issued Under Stock-Based Compensation Plans (in shares)			0	0	0
Stock Issued During Period, Shares, Acquisitions (in shares)				25,204,000
Balance (in shares)			578,828,000	576,950,000	550,151,000
[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 stock or performance unit grants or (ii) in payment of the exercise price of employee stock options.

Accumulated Other Comprehensi47

Accumulated Other Comprehensive Income (Loss) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss)	$ (19,297,000)	$ (19,010,000)
Other Comprehensive Income (Loss)	(287,000)	14,328,000	$ (10,282,000)
Significant Amount Reclassified Out of AOCI	0
Foreign Currency Translation Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss)	(16,642,000)	(19,441,000)	(31,538,000)
Other Comprehensive Loss Before Reclassifications	2,799,000	12,097,000
Tax Effects	0	0
Other Comprehensive Income (Loss)	2,799,000	12,097,000
Other [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss)	(2,655,000)	431,000	(1,800,000)
Other Comprehensive Loss Before Reclassifications	(3,728,000)	2,901,000
Tax Effects	642,000	(670,000)
Other Comprehensive Income (Loss)	(3,086,000)	2,231,000
Accumulated Other Comprehensive Income (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss)	(19,297,000)	(19,010,000)	(33,338,000)
Other Comprehensive Loss Before Reclassifications	(929,000)	14,998,000
Tax Effects	642,000	(670,000)
Other Comprehensive Income (Loss)	$ (287,000)	$ 14,328,000	$ (10,282,000)

Other Income (Expense), Net (De

Other Income (Expense), Net (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Income and Expenses [Abstract]
Net Foreign Currency Transaction Gains (Losses)	$ 8	$ (41)	$ (17)
Interest income	8		3
Equity income from investments in Trinidad	3	4	9
Adjustment to Deferred Compensation Expense	$ (6)	$ (11)	$ 6

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017		Dec. 22, 2017	Dec. 21, 2017	Dec. 31, 2016		Dec. 31, 2015
Income Tax Disclosure [Abstract]
Provisional Reduction in the Income Tax Provision		$ 2,200,000
AMT Credit Carryovers Subject to Expiration		$ 798,000
Sequestration Rate Based On AMT Credits		6.60%
Sequestration Refundable Tax Credits		$ 42,000
Repatriation Tax Of Foreign Earnings		179,000
Deferred Taxes On Accumulated Foreign Earnings		260,000
Provisional Reduction In The Federal Tax Provision		$ 43,000
Bonus Depreciation on Tangible Personal Property		100.00%
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	[1]	$ (40,851)				$ (39,852)	[2]
Foreign Net Operating Loss	[1]	423,258				352,150	[2]
Foreign Valuation Allowances	[1]	(365,379)				(296,596)	[2]
Foreign Other	[1]	478				438	[2]
Total Net Noncurrent Deferred Income Tax Assets	[1]	17,506				16,140	[2]
Deferred Tax (Assets) Liabilities Net Noncurrent Classification [Abstract]
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization	[1]	3,894,739				5,899,533	[2]
Commodity Hedging Contracts	[1]	(12,008)				(22,206)	[2]
Deferred Compensation Plans	[1]	(35,832)				(43,984)	[2]
Accrued Expenses and Liabilities	[1]	12,094				(13,754)	[2]
Net Operating Loss - Federal	[1]	(69,262)				0	[2]
Non-Producing Leasehold Costs	[1]	(47,981)				(64,898)	[2]
Seismic Costs Capitalized for Tax	[1]	(109,423)				(161,920)	[2]
Equity Awards	[1]	(92,696)				(139,787)	[2]
Capitalized Interest	[1]	51,345				86,504	[2]
Alternative Minimum Tax Credit Carryforward (3)	[1],[3]	(77,114)				(757,631)	[2]
Undistributed Foreign Earnings (4)	[1],[4]	19,684				280,099	[2]
Other	[1]	(15,332)				(33,548)	[2]
Total Net Noncurrent Deferred Income Tax Liabilities	[1]	3,518,214				5,028,408	[2]
Total Net Deferred Income Tax Liabilities	[1]	3,500,708				5,012,268	[2]
Federal AMT Credit Carryforwards Expected To Be Refunded		721,000
Components Income Before Income Taxes [Abstract]
United States		621,610				(1,520,573)		$ (6,840,119)
Foreign		39,572				(36,932)		(81,437)
Income (Loss) Before Income Taxes		661,182				(1,557,505)		(6,921,556)
Deferred income tax provision (benefit) [Abstract]
Federal		(1,504,288)				(532,979)		(2,362,926)
State		26,942				4,876		(127,444)
Foreign		3,474				12,897		8,063
Total		(1,473,872)				(515,206)		(2,482,307)
Current income tax provision (benefit) [Abstract]
Federal		33,058				11,567		21,719
State		(2,502)				(8,369)		9,404
Foreign		35,323				51,189		54,143
Total		65,879				54,387		85,266
Other Non-Current [Abstract]
Federal (1)		(513,404)	[5]			0		0
Income Tax Benefit		$ (1,921,397)				$ (460,819)		$ (2,397,041)
Federal Statutory and Effective Income Tax Rates [Abstract]
Statutory Federal Income Tax Rate (in hundredths)		35.00%		21.00%	35.00%	35.00%		35.00%
State Income Tax, Net of Federal Benefit (in hundredths)		3.38%				0.15%		1.11%
Income Tax Provision Related to Foreign Operations (in hundredths)		(0.30%)				(1.23%)		(1.31%)
Income Tax Provision Related to Trinidad Operations (in hundredths)		0.00%				(3.71%)		0.00%
Income Tax Provision Related to United Kingdom Operations (in hundredths)		1.78%				0.00%		0.00%
Income Tax Provision Related to Canadian Operations (in hundredths)		2.30%				0.00%		0.00%
TCJA (in hundredths)	[6]	(328.10%)				0.00%		0.00%
Shared-Based Compensation (1) (in hundredths)	[7]	(4.63%)				0.00%		0.00%
Other (in hundredths)		(0.03%)				(0.62%)		(0.17%)
Effective Income Tax Rate (in hundredths)		(290.60%)				29.59%		34.63%
Federal Tax Rate Reduction (in hundredths)		(327.80%)
Federal Repatriation Tax (in hundredths)		(6.60%)
Sequestration (in hundredths)		6.40%
Other Tax Reform Impacts (in hundredths)		(0.10%)
Components of Valuation Allowance [Abstract]
Beginning Balance		$ 383,221		$ 383,221	$ 383,221	$ 506,127		$ 463,018
Increase	[8]	67,333				37,221		146,602
Decrease	[9]	(13,687)				(12,667)		(4,315)
Other	[10]	29,554				(147,460)		(99,178)
Ending Balance		466,421				$ 383,221		$ 506,127
Balance of state net operating loss expected to be carried forward		1,700,000
Tax net operating loss incurred in United Kingdom in current year		72,000
Balance of tax net operating loss incurred in the United Kingdom in prior years		857,000
U.S. Federal Net Operating Loss Carryforwards		335,000
Canadian Net Operating Loss Carryforwards		158,000
AMT Paid In Years Prior To Prior Reporting Period		41,000
Decrease in Uncertain Tax Positions Related to AMT Credits		40,000
Unrecognized Tax Benefits Balance		39,000
Foreign and State Deferred Income Taxes		$ 20,000
[1]	United States federal deferred tax assets and liabilities tax effected at 21% and 35% for 2017 and 2016, respectively.
[2]	As described in Note 1, ASU 2015-17 eliminated the requirement to separate deferred tax assets and liabilities into current and noncurrent amounts.
[3]	Pursuant to the TCJA, $721 million of federal AMT credit carryforwards are expected to be refundable over four years and are presented as noncurrent tax receivables in Other Assets on the Consolidated Balance Sheet at December 31, 2017.
[4]	Undistributed foreign earnings have been deemed repatriated in 2017 in accordance with the TCJA. A portion of the associated federal taxes are now reflected as a noncurrent tax payable as a result of the eight year installment election.
[5]	As described previously, under the TCJA, a deemed repatriation tax is to be paid over eight years beginning with respect to taxable year 2017. In addition, EOG expects to receive refunds of AMT credits over a four-year period beginning with respect to taxable year 2018. Other Non-Current includes the portion of these two items that relates to years after 2017.
[6]	Includes impact of federal tax rate reduction ((327.8)%), federal repatriation tax ((6.6)%), sequestration (6.4%) and other tax reform impacts ((0.1)%).
[7]	As described in Note 1, ASU 2016-09, adopted by EOG in 2017, provides that share-based compensation tax benefits and deficiencies are recognized in the income tax provision.
[8]	Increase in valuation allowance related to the generation of tax NOLs and other deferred tax assets.
[9]	Decrease in valuation allowance associated with adjustments to certain deferred tax assets and their related allowance.
[10]	Represents dispositions/revisions/foreign exchange rate variances and the effect of statutory income tax rate changes.

Employee Benefit Plans (Details

Employee Benefit Plans (Details)		12 Months Ended
		Dec. 31, 2017USD ($)$ / sharesshares		Dec. 31, 2016USD ($)$ / sharesshares		Dec. 31, 2015USD ($)$ / sharesshares
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items]
Common Shares Available for Grant		17,300,000
Federal income tax (expense) / benefit recognized from stock-based compensation | $		$ 32,000,000
Adjustments to Additional Paid in Capital, Income Tax Benefit from Share-based Compensation | $				$ 29,357,000		$ 26,058,000
Performance Units and Performance Stock [Abstract]
Compensation expense related to the company's stock-based compensation plans | $		133,849,000		128,090,000		130,577,000
Stock Options and Sars [Member]
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items]
Stock-based compensation expense related to stock options, SAR and ESPP grants | $		$ 56,000,000		$ 57,000,000		$ 56,000,000
Maximum term of stock options and SARs granted		7 years
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		$ 23.95		$ 25.78		$ 21.88
Expected Volatility (in hundredths)		28.28%		31.54%		38.03%
Risk-Free Interest Rate (in hundredths)		1.52%		0.78%		0.83%
Dividend Yield (in hundredths)		0.75%		0.76%		0.85%
Expected Life (in years)		5 years 1 month 6 days		5 years 4 months 24 days		5 years 3 months 18 days
Stock Options and SARs Rollforward [Abstract]
Outstanding at January 1 (in shares)		9,850,000		10,744,000		10,493,000
Granted (in shares)		2,274,000		1,855,000		2,037,000
Exercised (1) (in shares)	[1]	(2,574,000)		(2,376,000)		(1,518,000)
Forfeited (in shares)		(447,000)		(373,000)		(268,000)
Outstanding at December 31 (in shares)		9,103,000		9,850,000		10,744,000
Stock Options/SARs Exercisable at December 31 (in shares)		4,510,000		5,613,000		5,993,000
Stock Options/SARs Exercisable at December 31 (in dollars per share) | $ / shares		$ 75.76		$ 66.48		$ 57.96
Intrinsic value of stock options/SARs exercised during the period | $		$ 95,000,000		$ 84,000,000		$ 60,000,000
Stock Options/SARs Vested or Expected to Vest (in shares)		8,700,000
Weighted average grant price for stock options/SARs vested or expected to vest (per share) | $ / shares		$ 83.56
Intrinsic value of stock options/SARs vested or expected to vest | $		$ 213,000,000
Weighted Average Remaining Contractual Life for Stock Options/SARs Vested or Expected to Vest		4 years 3 months 18 days
Weighted Average Grant Price Stock Option and SARs [Rollfoward]
Outstanding at January 1 (in dollars per share) | $ / shares		$ 75.53		$ 67.98		$ 64.96
Exercised (in dollars per share) | $ / shares	[1]	61.12		54.56		47.64
Granted (in dollars per share) | $ / shares		96.27		94.82		69.99
Forfeited (in dollars per share) | $ / shares		93.84		87.38		80.31
Outstanding at December 31 (in dollars per share) | $ / shares		$ 83.89		75.53		67.98
Performance Units and Performance Stock [Abstract]
Unrecognized compensation expense | $		$ 98,000,000
Weighted average period over which unrecognized compensation expense will be recognized		2 years 4 months 24 days
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items]
Stock Options and SARs Outstanding		9,103,000
Weighted Average Remaining Life for Outstanding Options and SARs		4 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares		$ 83.89
Aggregate Intrinsic Value For Outstanding Options and SARs | $	[2]	$ 218,696
Stock Options and SARs Exercisable		4,510,000
Weighted Average Remaining Life For Exercisable Units		3 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares		$ 75.76
Aggregate Intrinsic Value For Exercisable Units | $	[2]	$ 145,024
ESPP [Member]
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items]
Common Shares Available for Grant		176,000
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		$ 22.20		$ 19.21		$ 21.21
Expected Volatility (in hundredths)		27.12%		36.55%		32.08%
Risk-Free Interest Rate (in hundredths)		0.88%		0.44%		0.12%
Dividend Yield (in hundredths)		0.71%		0.82%		0.73%
Expected Life (in years)		6 months		6 months		6 months
Stock Options and SARs Rollforward [Abstract]
Approximate Number of Participants		1,870		1,746		1,963
Shares Purchased		180,000		212,000		225,000
Aggregate Purchase Price | $		$ 13,997,000		$ 13,787,000		$ 15,045,000
Restricted Stock and Restricted Stock Units [Member]
Number of Shares and Units [Roll Forward]
Outstanding at January 1 (in shares)		3,962,000	[3]	4,908,000	[3]	5,394,000
Granted (in shares)		1,095,000		853,000		1,044,000
Released (in shares)	[4]	(929,000)		(1,465,000)		(1,331,000)
Forfeited (in shares)		(223,000)		(334,000)		(199,000)
Outstanding at December 31 (in shares)	[3]	3,905,000		3,962,000		4,908,000
Weighted Average Grant Fair Value [Abstract]
Outstanding at January 1 (in dollars per share) | $ / shares		$ 79.63	[3]	$ 70.35	[3]	$ 64.39
Granted (in dollars per share) | $ / shares		97.34		88.01		77.94
Released (in dollars per share) | $ / shares	[4]	61.51		53.95		51.52
Forfeited (in dollars per share) | $ / shares		85.45		77.29		74.56
Outstanding at December 31 (in dollars per share) | $ / shares	[3]	$ 88.57		$ 79.63		$ 70.35
Performance Units and Performance Stock [Abstract]
Unrecognized compensation expense | $		$ 173,000,000
Weighted average period over which unrecognized compensation expense will be recognized		2 years 4 months 24 days
Share Based Compensation Arrangement By Restricted Stock And Restricted Stock Units Compensation Cost | $		$ 68,000,000		$ 60,000,000		$ 69,000,000
Intrinsic value released during the year | $		91,000,000		124,000,000		109,000,000
Aggregate intrinsic value of stock and unit outstanding | $		$ 421,000,000		$ 401,000,000		$ 347,000,000
Performance Units and Performance Stock [Member]
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		$ 113.81		$ 119.10		$ 80.64
Expected Volatility (in hundredths)		32.19%		32.48%		29.35%
Risk-Free Interest Rate (in hundredths)		1.60%		1.15%		1.07%
Number of Shares and Units [Roll Forward]
Outstanding at January 1 (in shares)		545,290	[5]	405,000	[5]	333,000
Granted (in shares)		78,527		132,000		72,000
Granted for Performance Multiple (1) (in shares)		118,834		143,000	[6]	0	[6]
Released (in shares)		240,320		134,000	[7]	0	[7]
Forfeited (in shares)		0		0		0
Outstanding at December 31 (in shares)		502,331		545,290	[5]	405,000	[5]
Weighted Average Grant Fair Value [Abstract]
Outstanding at January 1 (in dollars per share) | $ / shares		$ 80.92	[5]	$ 74.93	[5]	$ 76.11
Granted (in dollars per share) | $ / shares		96.29		100.95		69.43
Granted for Performance Multiple (1) (in dollars per share) | $ / shares	[6]	84.43		56.21		0
Released (in dollars per share) | $ / shares	[7]	66.69		56.21		0
Forfeited (in dollars per share) | $ / shares		0		0		0
Outstanding at December 31 (in dollars per share) | $ / shares	[5]	$ 90.96		$ 80.92		$ 74.93
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%
Term of Zero-Coupon Risk-Free Interest Rate Derived from the Treasury Constant Maturities Yield Curve		3 years 3 months 7 days
Minimum Performance Units and Stock Allowed to be Outstanding		148,444
Maximum Performance Units and Stock Allowed to be Outstanding		856,218
Additional Performance Awards Granted		71,805
Compensation expense related to the company's stock-based compensation plans | $		$ 10,000,000		$ 11,000,000		$ 5,000,000
Unrecognized compensation expense | $		$ 8,300,000
Weighted average period over which unrecognized compensation expense will be recognized		2 years
Performance Period		3 years
Intrinsic value released during the year | $		$ 24,000,000		10,000,000		0
Aggregate intrinsic value of stock and unit outstanding | $		54,000,000		55,000,000		29,000,000
Lease And Well [Member]
Performance Units and Performance Stock [Abstract]
Compensation expense related to the company's stock-based compensation plans | $		41,000,000		38,000,000		44,000,000
Gathering And Processing Costs [Member]
Performance Units and Performance Stock [Abstract]
Compensation expense related to the company's stock-based compensation plans | $		1,000,000		1,000,000		1,000,000
Exploration Costs [Member]
Performance Units and Performance Stock [Abstract]
Compensation expense related to the company's stock-based compensation plans | $		23,000,000		21,000,000		26,000,000
General And Administrative [Member]
Performance Units and Performance Stock [Abstract]
Compensation expense related to the company's stock-based compensation plans | $		$ 69,000,000		68,000,000		60,000,000
$ 34.00 to $ 59.99 | 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		1,472,000
Weighted Average Remaining Life for Outstanding Options and SARs		1 year
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares		$ 49.63
Stock Options and SARs Exercisable		1,472,000
Weighted Average Remaining Life For Exercisable Units		1 year
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares		$ 49.63
60.00 to 84.99 | Stock Options and Sars [Member]
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items]
Stock Options and SARs Outstanding		2,392,000
Weighted Average Remaining Life for Outstanding Options and SARs		4 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares		$ 75.67
Stock Options and SARs Exercisable		1,623,000
Weighted Average Remaining Life For Exercisable Units		3 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares		$ 78.51
85.00 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		1,684,000
Weighted Average Remaining Life for Outstanding Options and SARs		6 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares		$ 94.82
Stock Options and SARs Exercisable		421,000
Weighted Average Remaining Life For Exercisable Units		5 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares		$ 94.73
96.00 to 99.99 | Stock Options and Sars [Member]
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items]
Stock Options and SARs Outstanding		2,239,000
Weighted Average Remaining Life for Outstanding Options and SARs		7 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares		$ 96.32
Stock Options and SARs Exercisable		21,000
Weighted Average Remaining Life For Exercisable Units		3 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares		$ 98.06
100.00 to 116.99 | 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		1,316,000
Weighted Average Remaining Life for Outstanding Options and SARs		4 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares		$ 102.03
Stock Options and SARs Exercisable		973,000
Weighted Average Remaining Life For Exercisable Units		3 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares		$ 102.03
Pension Plans [Member]
Defined Benefit and Defined Contribution Plan Disclosure [Line Items]
Total pension plan costs | $		$ 37,000,000		34,000,000		36,000,000
Company contributions to foreign pension plans | $		1,000,000		1,000,000		$ 1,000,000
Benefit obligation | $		10,000,000		8,000,000
Fair value of foreign pension plan assets | $		8,000,000		7,000,000
Accrued benefit cost | $		$ (200,000)		$ (300,000)
[1]	The total intrinsic value of stock options/SARs exercised during the years 2017, 2016 and 2015 was $95 million, $84 million and $60 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, 2017, 2016 and 2015 was approximately $421 million, $401 million and $347 million, respectively.
[4]	The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2017, 2016 and 2015 was $91 million, $124 million and $109 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, 2017, 2016 and 2015 was approximately $54 million, $55 million and $29 million, respectively.
[6]	Upon completion of the Performance Period for the Performance Awards granted in 2013 and 2012, a performance multiple of 200% was applied to each of the grants resulting in additional grants of Performance Awards in February 2017 and 2016.
[7]	The total intrinsic value of Performance Awards released during the years ended December 31, 2017, 2016 and 2015 was approximately $24 million, $10 million and $0, respectively.

Commitments and Contingencies51

Commitments and Contingencies (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Feb. 20, 2018
Commitments and Contingencies Disclosure [Abstract]
Standby letters of credit and guarantees outstanding	$ 174,000,000	$ 226,000,000
Subsidiary payment obligations demand for payment				$ 0
Total Minimum Commitments [Abstract]
2,018	1,855,005,000
2,019	1,068,994,000
2,020	800,078,000
2,021	567,840,000
2,022	478,480,000
2023 and beyond	944,911,000
Total Minimum Commitments	5,715,308,000
Rental expenses associated with existing leases	$ 200,000,000	$ 204,000,000	$ 229,000,000

Net Income (Loss) Per Share (De

Net Income (Loss) Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2017		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Numerator for Basic and Diluted Earnings per Share - [Abstract]
Net Income (Loss)	$ 2,430,468		$ 100,541		$ 23,053		$ 28,517		$ (142,352)		$ (190,000)		$ (292,558)		$ (471,776)		$ 2,582,579	$ (1,096,686)	$ (4,524,515)
Denominator for Basic Earnings per Share - [Abstract]
Weighted Average Shares	575,394		574,783		574,439		573,935		567,337		547,838		547,335		546,715		574,620	553,384	545,697
Denominator for Diluted Earnings per Share - [Abstract]
Adjusted Diluted Weighted Average Shares	579,203		578,736		578,483		578,593		567,337		547,838		547,335		546,715		578,693	553,384	545,697
Net Income (Loss) Per Share [Abstract]
Basic	$ 4.22	[1]	$ 0.17	[1]	$ 0.04	[1]	$ 0.05	[1]	$ (0.25)	[1]	$ (0.35)	[1]	$ (0.53)	[1]	$ (0.86)	[1]	$ 4.49	$ (1.98)	$ (8.29)
Diluted	$ 4.20	[1]	$ 0.17	[1]	$ 0.04	[1]	$ 0.05	[1]	$ (0.25)	[1]	$ (0.35)	[1]	$ (0.53)	[1]	$ (0.86)	[1]	$ 4.46	$ (1.98)	$ (8.29)
Stock Options and Sars [Member]
Potential Dilutive Common Shares -[Abstract]
Common Shares Attributable to Dilutive Effect of Share-Based Payment Arrangments																	1,466	0	0
Antidilutive Securities Excluded from Computation of Earnings Per Share [Abstract]
Anti-dilutive Securities excluded from Diluted Earnings Per Share Calculation																	2,600	10,300	10,200
Restricted Stock/Units and Performance Units/Stock [Member]
Potential Dilutive Common Shares -[Abstract]
Common Shares Attributable to Dilutive Effect of Share-Based Payment Arrangments																	2,607	0	0
Antidilutive Securities Excluded from Computation of Earnings Per Share [Abstract]
Anti-dilutive Securities excluded from Diluted Earnings Per Share Calculation																		4,500
[1]	The sum of quarterly net income (loss) per share may not agree with total year net income (loss) per share as each quarterly computation is based on the weighted average of common shares outstanding.

Supplemental Cash Flow Inform53

Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Supplemental Cash Flow Information [Abstract]
Interest, Net of Capitalized Interest	$ 275,305	$ 252,030	$ 222,088
Income Taxes, Net of Refunds Received	188,946	(39,293)	41,108
Accrued Capital Expenditures	475,000	388,000	$ 416,000
Non-cash investing and financing activities from property exchanges.	$ 282,000
Non-cash investing and financing activities from the Yates transaction		$ 3,834,000

Business Segment Information (D

Business Segment Information (Details) - USD ($) $ in Thousands		3 Months Ended													12 Months Ended
		Dec. 31, 2017		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2016		Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Schedule of Segment Reporting Information By Segment [Abstract]
Crude Oil and Condensate															$ 6,256,396		$ 4,317,341		$ 4,934,562
Natural Gas Liquids															729,561		437,250		407,658
Natural Gas															921,934		742,152		1,061,038
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts															19,828		(99,608)		61,924
Gathering, Processing and Marketing															3,298,087		1,966,259		2,253,135
Gains (Losses) on Asset Dispositions, Net															(99,096)		205,835		(8,798)
Other, Net	[1]														81,610		81,403		47,909
Net Operating Revenues and Other		$ 3,340,439		$ 2,644,844		$ 2,612,472		$ 2,610,565		$ 2,402,039		$ 2,118,504	$ 1,775,740	$ 1,354,349	11,208,320		7,650,632		8,757,428
Depreciation, Depletion and Amortization															3,409,387		3,553,417		3,313,644
Operating Income (Loss)		475,912		214,836		127,908		107,746		(105,487)		(193,480)	(288,173)	(638,141)	926,402		(1,225,281)		(6,686,079)
Interest Income															7,713		2,619		3,469
Other Income															1,439
Other Expense																	(53,162)		(1,553)
Net Interest Expense															274,372		281,681		237,393
Income (Loss) Before Income Taxes															661,182		(1,557,505)		(6,921,556)
Income Tax Provision (Benefit)		(2,017,115)	[2]	$ 45,439	[2]	$ 39,414	[2]	$ 10,865	[2]	(51,658)		$ (82,250)	$ (87,719)	$ (239,192)	(1,921,397)		(460,819)		(2,397,041)
Additions to Oil and Gas Properties, Excluding Dry Hole Costs															4,228,228		6,329,369		4,710,404
Total Property, Plant and Equipment, Net		25,665,037								25,707,078					25,665,037		25,707,078		24,210,721
Total Assets		29,833,078								29,299,201	[3]				29,833,078		29,299,201	[3]	26,834,908	[4]
Reclassification to Deferred Tax Assets		17,506								16,140					17,506		16,140
United States
Schedule of Segment Reporting Information By Segment [Abstract]
Crude Oil and Condensate															6,225,711		4,265,036		4,917,731
Natural Gas Liquids															729,545		437,238		407,570
Natural Gas															615,512		475,715		637,452
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts															19,828		(99,608)		61,924
Gathering, Processing and Marketing															3,298,098		1,967,390		2,254,477
Gains (Losses) on Asset Dispositions, Net															(98,233)		196,043		(12,176)
Other, Net															81,610		81,386		47,464
Net Operating Revenues and Other															10,872,071	[5]	7,323,200	[6]	8,314,442	[7]
Depreciation, Depletion and Amortization															3,269,196		3,365,390		3,139,863
Operating Income (Loss)															933,571		(1,192,338)		(6,566,282)
Interest Income															3,223		358		1,913
Other Income																			6,461
Other Expense															(9,659)		(15,703)
Net Interest Expense															303,941		298,125		274,606
Income (Loss) Before Income Taxes															623,194		(1,505,808)		(6,832,514)
Income Tax Provision (Benefit)															(1,964,343)		(516,180)		(2,463,213)
Additions to Oil and Gas Properties, Excluding Dry Hole Costs															4,067,359		6,223,228		4,495,730
Total Property, Plant and Equipment, Net		25,125,427								25,221,517					25,125,427		25,221,517		23,593,995
Total Assets		28,312,599								27,746,851	[3]				28,312,599		27,746,851	[3]	25,211,572	[4]
Amount of sales with a single significant purchaser in the United States segment															1,500,000		1,200,000		1,700,000
Amount of sales with a second significant purchaser in the United States segment.															1,300,000		1,100,000		1,400,000
Amount of sales with a third significant purchaser in the United States segment																	1,000,000
Reclassification to Deferred Tax Assets										160,000							160,000		136,000
Trinidad
Schedule of Segment Reporting Information By Segment [Abstract]
Crude Oil and Condensate															13,572		9,600		13,122
Natural Gas Liquids															0		0		0
Natural Gas															271,101		234,108		368,639
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts															0		0		0
Gathering, Processing and Marketing															(11)		(1,131)		(1,342)
Gains (Losses) on Asset Dispositions, Net															(8)		(145)		393
Other, Net															59		(8)		(3)
Net Operating Revenues and Other															284,713		242,424		380,809
Depreciation, Depletion and Amortization															115,321		145,591		154,853
Operating Income (Loss)															101,010		46,473		175,658
Interest Income															2,201		932		389
Other Income															3,337		2,667		8,780
Net Interest Expense															0		0		1,400
Income (Loss) Before Income Taxes															106,548		50,072		183,427
Income Tax Provision (Benefit)															38,798		64,281		63,502
Additions to Oil and Gas Properties, Excluding Dry Hole Costs															145,937		75,407		102,358
Total Property, Plant and Equipment, Net		313,357								274,850					313,357		274,850		350,766
Total Assets		974,477								889,253					974,477		889,253		886,826
Other International
Schedule of Segment Reporting Information By Segment [Abstract]
Crude Oil and Condensate	[8]														17,113		42,705		3,709
Natural Gas Liquids	[8]														16		12		88
Natural Gas	[8]														35,321		32,329		54,947
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts	[8]														0		0		0
Gathering, Processing and Marketing	[8]														0		0		0
Gains (Losses) on Asset Dispositions, Net	[8]														(855)		9,937		2,985
Other, Net	[8]														(59)		25		448
Net Operating Revenues and Other	[8]														51,536		85,008		62,177
Depreciation, Depletion and Amortization	[8]														24,870		42,436		18,928
Operating Income (Loss)	[8]														(108,179)		(79,416)		(295,455)
Interest Income	[8]														2,289		1,329		1,167
Other Income	[8]														7,761
Other Expense	[8]																(40,126)		(16,794)
Net Interest Expense	[8]														(29,569)		(16,444)		(38,613)
Income (Loss) Before Income Taxes	[8]														(68,560)		(101,769)		(272,469)
Income Tax Provision (Benefit)	[8]														4,148		(8,920)		2,670
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	[8]														14,932		30,734		112,316
Total Property, Plant and Equipment, Net	[8]	226,253								210,711					226,253		210,711		265,960
Total Assets	[8]	$ 546,002								$ 663,097					$ 546,002		$ 663,097		$ 736,510
[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, 2017.
[2]	Includes an income tax benefit of approximately $2.2 billion for the quarter ended December 31, 2017, primarily due to the enactment of the Tax Cuts and Jobs Act in December 2017. See Note 6 to the Consolidated Financial Statements.
[3]	EOG made a reclassification of $160 million from deferred tax liabilities to deferred tax assets for the year ended December 31, 2016, for the United States segment and in total.
[4]	EOG made a reclassification of $136 million from deferred tax liabilities to deferred tax assets for the year ended December 31, 2015, for the United States segment and in total.
[5]	EOG had sales activity with two significant purchasers in 2017, one totaling $1.5 billion and the other totaling $1.3 billion of consolidated Net Operating Revenues and Other in the United States segment.
[6]	EOG had sales activity with three significant purchasers in 2016, one totaling $1.2 billion, one totaling $1.1 billion and one totaling $1.0 billion of consolidated Net Operating Revenues and Other in the United States segment.
[7]	EOG had sales activity with two significant purchasers in 2015, one totaling $1.7 billion and the other totaling $1.4 billion of consolidated Net Operating Revenues and Other in the United States segment.
[8]	Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016.

Risk Management Activities (Det

Risk Management Activities (Details)	12 Months Ended
	Dec. 31, 2017USD ($)MMBTU$ / bbl$ / MMBTUbbl	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Derivatives, Fair Value [Line Items]
Assets from Price Risk Management Activities	$ 7,699,000	$ 0
Liabilities from Price Risk Management Activities	$ 50,429,000	$ 61,817,000
Receivable Major Customer Percentage	10.00%	10.00%
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts	$ 19,828,000	$ (99,608,000)	$ 61,924,000
Net Cash Received from (Payments for) Settlements of Commodity Derivatives Contracts	7,438,000	(22,219,000)	$ 730,114,000
Derivative Collateral [Abstract]
Collateral Held on Derivative	0	0
Collateral Had on Derivaitve	0	0
Assets [Member] | Price Risk Derivative [Member]
Derivatives, Fair Value [Line Items]
Assets from Price Risk Management Activities	8,000,000	0
Other Assets [Member] | Price Risk Derivative [Member]
Derivatives, Fair Value [Line Items]
Other Assets	0	1,000,000
Liabilities From Price Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Assets from Price Risk Management Activities	5,000,000
Liabilities from Price Risk Management Activities	55,000,000
Liabilities From Price Risk Management Activities [Member] | Price Risk Derivative [Member]
Derivatives, Fair Value [Line Items]
Liabilities from Price Risk Management Activities	50,000,000	62,000,000
Liability [Member] | Price Risk Derivative [Member]
Derivatives, Fair Value [Line Items]
Other Liabilities	$ 7,000,000	$ 0
Crude Oil [Member] | Midland Differential Basis Swap [Member] | Derivative Contracts Year Two - January (closed) [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl	15,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	1.063
Crude Oil [Member] | Midland Differential Basis Swap [Member] | Derivative Contracts Year Two - February through December [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl	15,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	1.063
Crude Oil [Member] | Midland Differential Basis Swap [Member] | Derivative Contracts Year Three January through December [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl	20,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	1.075
Crude Oil [Member] | Gulf Coast Differential Basis Swap [Member] | Derivative Contracts Year Two - January (closed) [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl	37,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	3.818
Crude Oil [Member] | Gulf Coast Differential Basis Swap [Member] | Derivative Contracts Year Two - February through December [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl	37,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	3.818
Crude Oil [Member] | Price Swap [Member] | Derivative Contracts January through February (closed) [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl	35,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	50.040
Crude Oil [Member] | Price Swap [Member] | Derivative Contracts March through June (closed) [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl	30,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	50.05
Crude Oil [Member] | Price Swap [Member] | Crude Oil Price Swap Contracts - March through June (closed) [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl	5,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	48.81
Derivative, Cash Received For Early Termination of Hedge	$ 4,600,000
Crude Oil [Member] | Price Swap [Member] | Derivative Contracts Year Two - January through December [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl	37,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	56.48
Crude Oil [Member] | Price Swap [Member] | Remaining Derivative Contracts - March through June (Closed) [Member]
Derivatives, Fair Value [Line Items]
Volume (Bbld) | bbl	5,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	50
Derivative, Cash Received on Hedge	$ 700,000
Natural Gas [Member] | Price Swap [Member] | Derivative Contracts - March through November (closed) [Member]
Derivatives, Fair Value [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	3.10
volume (MMBTU) | MMBTU	30,000
Natural Gas [Member] | Price Swap [Member] | Derivative Contracts Year Two - March through November [Member]
Derivatives, Fair Value [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	3
volume (MMBTU) | MMBTU	35,000
Natural Gas [Member] | Call Option [Member] | Derivative Contracts - March through November (closed) [Member]
Derivatives, Fair Value [Line Items]
volume (MMBTU) | MMBTU	213,750
Derivative, Average Price Risk Option Strike Price | $ / MMBTU	3.44
Natural Gas [Member] | Call Option [Member] | Derivative Contracts Year Two - March through November [Member]
Derivatives, Fair Value [Line Items]
volume (MMBTU) | MMBTU	120,000
Derivative, Average Price Risk Option Strike Price | $ / MMBTU	3.38
Natural Gas [Member] | Put Option [Member] | Derivative Contracts - March through November (closed) [Member]
Derivatives, Fair Value [Line Items]
volume (MMBTU) | MMBTU	171,000
Derivative, Average Price Risk Option Strike Price | $ / MMBTU	2.92
Natural Gas [Member] | Put Option [Member] | Derivative Contracts Year Two - March through November [Member]
Derivatives, Fair Value [Line Items]
volume (MMBTU) | MMBTU	96,000
Derivative, Average Price Risk Option Strike Price | $ / MMBTU	2.94
Natural Gas [Member] | Collars [Member] | Derivative Contracts - March through November (closed) [Member]
Derivatives, Fair Value [Line Items]
volume (MMBTU) | MMBTU	80,000
Derivative, Average Cap Price | $ / MMBTU	3.69
Derivative, Average Floor Price | $ / MMBTU	3.20

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
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	$ 640,000	$ 778,000
Proved oil and gas properties, other property, plant and equipment and other assets written down during the period - fair value at end of period	372,000	587,000
Pretax impairment charges for proved oil and gas properties and other assets, in which EOG utilized an accepted offer from a third-party purchaser	217,000
Pretax impairment charge for a commodity price-related write-down of other assets	28,000
Pretax impairment charges for proved oil and gas properties, other property, plant and equipment and other assets	268,000	191,000
Pretax impairment charges for obsolete inventory		61,000
Pretax impairment charges for firm commitment contracts		138,000
Debt Disclosure [Abstract]
Aggregate Principal Amount of Current and Long-Term Debt	6,390,000	6,990,000
Debt Instrument, Fair Value Disclosure	6,602,000	7,190,000
Other Liabilities [Member]
Financial Liabilities:
Liabilities, Fair Value Disclosure	7,000
Other Assets [Member]
Financial Assets:
Assets, Fair Value Disclosure	1,000
Assets From Price Risk Management Activities [Member]
Financial Assets:
Assets, Fair Value Disclosure	8,000
Liabilities From Price Risk Management Activities [Member]
Financial Liabilities:
Liabilities, Fair Value Disclosure	50,000	62,000
Commodity Contract [Member] | Crude Oil [Member] | Price Swap [Member]
Financial Liabilities:
Liabilities, Fair Value Disclosure	38,000	36,000
Commodity Contract [Member] | Crude Oil [Member] | Price Swap [Member] | Fair Value, Inputs, Level 1 [Member]
Financial Liabilities:
Liabilities, Fair Value Disclosure	0	0
Commodity Contract [Member] | Crude Oil [Member] | Price Swap [Member] | Fair Value, Inputs, Level 2 [Member]
Financial Liabilities:
Liabilities, Fair Value Disclosure	38,000	36,000
Commodity Contract [Member] | Crude Oil [Member] | Price Swap [Member] | Fair Value, Inputs, Level 3 [Member]
Financial Liabilities:
Liabilities, Fair Value Disclosure	0	0
Commodity Contract [Member] | Crude Oil [Member] | Basis Swaps [Member]
Financial Liabilities:
Liabilities, Fair Value Disclosure	19,000
Commodity Contract [Member] | Crude Oil [Member] | Basis Swaps [Member] | Fair Value, Inputs, Level 1 [Member]
Financial Liabilities:
Liabilities, Fair Value Disclosure	0
Commodity Contract [Member] | Crude Oil [Member] | Basis Swaps [Member] | Fair Value, Inputs, Level 2 [Member]
Financial Liabilities:
Liabilities, Fair Value Disclosure	19,000
Commodity Contract [Member] | Crude Oil [Member] | Basis Swaps [Member] | Fair Value, Inputs, Level 3 [Member]
Financial Liabilities:
Liabilities, Fair Value Disclosure	0
Commodity Contract [Member] | Natural Gas [Member] | Price Swap [Member]
Financial Assets:
Assets, Fair Value Disclosure	2,000
Financial Liabilities:
Liabilities, Fair Value Disclosure		4,000
Commodity Contract [Member] | Natural Gas [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] | Natural Gas [Member] | Price Swap [Member] | Fair Value, Inputs, Level 2 [Member]
Financial Assets:
Assets, Fair Value Disclosure	2,000
Financial Liabilities:
Liabilities, Fair Value Disclosure		4,000
Commodity Contract [Member] | Natural Gas [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 [Member] | Options/Collars [Member]
Financial Assets:
Assets, Fair Value Disclosure	6,000	1,000
Financial Liabilities:
Liabilities, Fair Value Disclosure		22,000
Commodity Contract [Member] | Natural Gas [Member] | Options/Collars [Member] | Fair Value, Inputs, Level 1 [Member]
Financial Assets:
Assets, Fair Value Disclosure	0	0
Financial Liabilities:
Liabilities, Fair Value Disclosure		0
Commodity Contract [Member] | Natural Gas [Member] | Options/Collars [Member] | Fair Value, Inputs, Level 2 [Member]
Financial Assets:
Assets, Fair Value Disclosure	6,000	1,000
Financial Liabilities:
Liabilities, Fair Value Disclosure		22,000
Commodity Contract [Member] | Natural Gas [Member] | Options/Collars [Member] | Fair Value, Inputs, Level 3 [Member]
Financial Assets:
Assets, Fair Value Disclosure	$ 0	0
Financial Liabilities:
Liabilities, Fair Value Disclosure		$ 0

Accounting For Certain Long-L57

Accounting For Certain Long-Lived Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule of Impaired Long-Lived Assets Held and Used [Line Items]
Proved oil and gas properties carrying amount	$ 370	$ 643
Proved oil and gas properties written down to fair value	146	527
Pretax impairment charges for proved oil and gas properties	224	116
Amortization and impairments of unproved oil and gas property costs including amortization of capitalized interest	$ 211	$ 291	$ 288

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Oct. 04, 2016
Asset Retirement Obligations, Noncurrent [Abstract]
Carrying Amount at Beginning of Period		$ 912,926	$ 811,554
Liabilities Incurred (1)	[1]	54,764	212,739
Liabilities Settled (2)	[2]	(61,871)	(94,800)
Accretion		34,708	32,306
Revisions		(9,818)	(38,286)
Foreign Currency Translations		16,139	(10,587)
Carrying Amount at End of Period		946,848	912,926
Current Portion		19,259	18,516
Noncurrent Portion		927,589	$ 894,410
Long-Term Debt Related to Yates Transaction		$ 163,829		$ 164,000
[1]	Includes $164 million in 2016 related to Yates transaction (see Note 17).
[2]	Includes settlements related to asset sales.

Exploratory Well Costs (Details

Exploratory Well Costs (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Capitalized Exploratory Well Costs [Abstract]
Balance at January 1		$ 0	$ 8,955	$ 17,253
Additions Pending the Determination of Proved Reserves		27,487	6,688	24,640
Reclassifications to Proved Properties		(20,802)	(5,274)	(26,659)
Costs Charged to Expense (1)	[1]	(4,518)	(10,369)	(6,279)
Balance at December 31		$ 2,167	$ 0	$ 8,955
[1]	Includes capitalized exploratory well costs charged to either dry hole costs or impairments.

Acquisitions and Divestitures60

Acquisitions and Divestitures (Details) - USD ($) $ in Thousands, shares in Millions	9 Months Ended	12 Months Ended
	Oct. 04, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Business Combinations [Abstract]
Proceeds from Sale of Producing Properties		$ 226,768	$ 1,119,215	$ 192,807
Book value of assets held-for-sale		188,000
Book value of asset retirement obligations		41,000
Proceeds from Sales of Producing Properties		$ 73,000
Aggregated Purchase Price to Acquire Proved Crude Oil Properties and Related Assets				481,000
Stock Issued During Period, Shares, Acquisitions (in shares)	25	25
Payments to Acquire Businesses, Gross	$ 16,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents	2,400,000
Cash Acquired from Acquisition	70,000
Purchase Price Allocation Net Decrease in Oil and Gas Properties		$ 35,000
Purchase Price Allocation Net Decrease in Deferred Income Taxes		32,000
Business Combination, Separately Recognized Transactions [Line Items]
Gain (Loss) on Disposition of Assets		(99,096)	$ 205,835	$ (8,798)
Business Combination, Separately Recognized Transactions, Additional Disclosures, Acquisition Cost Expensed		5,000
Cash and Equivalents		70,411
Accounts Receivable, Net		77,073
Inventories		10,955
Other		10,640
Total Current Assets		169,079
Oil and Gas Properties (Successful Efforts Method)		3,815,207
Other Property, Plant and Equipment		21,824
Total Property, Plant and Equipment, Net		3,837,031
Other Assets		22,706
Total Assets		4,028,816
Accounts Payable		124,145
Accrued Taxes Payable		22,417
Other		743
Total Current Liabilities		147,305
Long-Term Debt	$ 164,000	163,829
Asset Retirement Obligations		163,144
Off-Market Transportation Contracts		39,720
Other Liabilities		28,645
Deferred Income Taxes		1,072,405
Total Liabilities		1,615,048
Total Consideration Transferred		$ 2,413,768

Oil and Gas Exploration and P61

Oil and Gas Exploration and Production Industries Disclosures (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2017USD ($)MBoeMMcfMBbls	Dec. 31, 2016USD ($)MBoeMMcfMBbls	Dec. 31, 2015MBoeMMcfMBbls	Dec. 31, 2014MBoeMMcfMBbls
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Balance at January 1 | MBoe		1,053,027	1,045,640	1,149,309
Extensions and Discoveries | MBoe		237,378	138,101	205,152
Revisions | MBoe		33,127	64,413	(241,973)
Acquisition of Reserves | MBoe		0	0	54,458
Sales of Reserves | MBoe		(8,253)	(45,917)	0
Conversion to Proved Developed Reserves | MBoe		(152,644)	(149,210)	(121,306)
Balance at December 31 | MBoe		1,162,635	1,053,027	1,045,640
Net proved developed reserves (MBOE) | MBoe		1,364,335	1,093,906	1,072,477	1,347,947
Capitalized Costs, Oil and Gas Producing Activities, Gross [Abstract]
Proved properties | $		$ 48,845,672	$ 45,751,965
Unproved properties | $		3,710,069	3,840,126
Total | $		52,555,741	49,592,091
Accumulated depreciation, depletion and amortization | $		(29,191,247)	(26,247,062)
Net capitalized costs | $		$ 23,364,494	$ 23,345,029
Crude Oil (MBbl)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	1,177,585	1,097,596	1,139,750
Revisions of previous estimates	[1]	57,836	42,955	(114,925)
Purchases in place	[1]	1,111	25,795	35,922
Extensions, discoveries and other additions	[1]	207,557	123,441	141,386
Sales in place	[1]	(8,393)	(8,791)	(740)
Production	[1]	(122,723)	(103,411)	(103,797)
Net proved reserves - end of period	[1]	1,312,973	1,177,585	1,097,596
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved developed reserves		614,236	516,625	445,202	495,148
Net proved undeveloped reserves		698,737	660,690	652,394	644,602
Natural Gas Liquids (MBbl)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	416,366	382,875	467,068
Revisions of previous estimates	[1]	46,843	53,771	(113,222)
Purchases in place	[1]	421	1,284	8,251
Extensions, discoveries and other additions	[1]	75,003	41,862	49,147
Sales in place	[1]	(2,887)	(33,548)	(271)
Production	[1]	(32,273)	(29,878)	(28,098)
Net proved reserves - end of period	[1]	503,473	416,366	382,875
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved developed reserves		286,872	230,219	205,898	264,749
Net proved undeveloped reserves		216,601	186,147	176,977	202,319
Natural Gas (MMcf)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period | MMcf	[2]	3,317,900	3,825,900	5,342,600
Revisions of previous estimates | MMcf	[2]	584,000	333,100	(1,430,700)
Purchases in place | MMcf	[2]	4,800	91,500	72,300
Extensions, discoveries and other additions | MMcf	[2]	829,400	262,000	332,400
Sales in place | MMcf	[2]	(56,400)	(752,000)	(15,000)
Production | MMcf	[2]	(416,600)	(442,600)	(475,700)
Net proved reserves - end of period | MMcf	[2]	4,263,100	3,317,900	3,825,900
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved developed reserves | MMcf		2,779,300	2,082,400	2,528,300	3,528,300
Net proved undeveloped reserves | MMcf		1,483,800	1,235,500	1,297,600	1,814,300
Oil Equivalents (MBoe)
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved reserves - beginning of period | MBoe	[1]	2,146,933	2,118,117	2,497,256
Revisions of previous estimates | MBoe	[1]	202,018	152,242	(466,604)
Purchases in place | MBoe	[1]	2,332	42,330	56,215
Extensions, discoveries and other additions | MBoe	[1]	420,798	208,963	245,931
Sales in place | MBoe	[1]	(20,687)	(167,669)	(3,506)
Production | MBoe	[1]	(224,424)	(207,050)	(211,175)
Net proved reserves - end of period | MBoe	[1]	2,526,970	2,146,933	2,118,117
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserve (MBOE) | MBoe		1,162,635	1,053,027	1,045,640	1,149,309
United States
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved developed reserves (MBOE) | MBoe		1,300,758	1,038,483	1,018,491	1,275,447
United States | Crude Oil (MBbl)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	1,168,491	1,087,860	1,129,682
Revisions of previous estimates	[1]	57,935	42,040	(114,924)
Purchases in place	[1]	1,111	25,795	35,922
Extensions, discoveries and other additions	[1]	207,137	123,441	141,310
Sales in place	[1]	(8,393)	(8,791)	(730)
Production	[1]	(122,210)	(101,854)	(103,400)
Net proved reserves - end of period	[1]	1,304,071	1,168,491	1,087,860
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved developed reserves		605,405	507,531	444,070	493,694
Net proved undeveloped reserves		698,666	660,690	643,790	635,988
United States | Natural Gas Liquids (MBbl)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	416,366	382,875	466,930
Revisions of previous estimates	[1]	46,843	53,771	(113,290)
Purchases in place	[1]	421	1,284	8,251
Extensions, discoveries and other additions	[1]	75,003	41,862	49,147
Sales in place	[1]	(2,887)	(33,548)	(84)
Production	[1]	(32,273)	(29,878)	(28,079)
Net proved reserves - end of period	[1]	503,473	416,366	382,875
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved developed reserves		286,872	230,219	205,898	264,611
Net proved undeveloped reserves		216,601	186,147	176,977	202,319
United States | Natural Gas (MMcf)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period | MMcf	[2]	3,021,200	3,489,800	4,905,500
Revisions of previous estimates | MMcf	[2]	602,800	298,400	(1,453,100)
Purchases in place | MMcf	[2]	4,800	91,500	72,300
Extensions, discoveries and other additions | MMcf	[2]	619,300	202,100	306,300
Sales in place | MMcf	[2]	(56,400)	(752,000)	(3,900)
Production | MMcf	[2]	(293,200)	(308,600)	(337,300)
Net proved reserves - end of period | MMcf	[2]	3,898,500	3,021,200	3,489,800
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved developed reserves | MMcf		2,450,800	1,804,400	2,211,200	3,102,800
Net proved undeveloped reserves | MMcf		1,447,700	1,216,800	1,278,600	1,802,700
United States | Oil Equivalents (MBoe)
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved reserves - beginning of period | MBoe	[1]	2,088,392	2,052,361	2,414,202
Revisions of previous estimates | MBoe	[1]	205,262	145,542	(470,401)
Purchases in place | MBoe	[1]	2,332	42,330	56,215
Extensions, discoveries and other additions | MBoe	[1]	385,354	198,973	241,513
Sales in place | MBoe	[1]	(20,687)	(167,669)	(1,467)
Production | MBoe	[1]	(203,351)	(183,145)	(187,701)
Net proved reserves - end of period | MBoe	[1]	2,457,302	2,088,392	2,052,361
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserve (MBOE) | MBoe		1,156,544	1,049,909	1,033,870	1,138,755
Trinidad
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved developed reserves (MBOE) | MBoe		50,779	44,543	50,677	67,484
Trinidad | Crude Oil (MBbl)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	839	1,069	1,339
Revisions of previous estimates	[1]	80	54	(1)
Purchases in place	[1]	0	0	0
Extensions, discoveries and other additions	[1]	301	0	63
Sales in place	[1]	0	0	0
Production	[1]	(322)	(284)	(332)
Net proved reserves - end of period	[1]	898	839	1,069
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved developed reserves		898	839	1,069	1,339
Net proved undeveloped reserves		0	0	0	0
Trinidad | Natural Gas Liquids (MBbl)
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
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved developed reserves		0	0	0	0
Net proved undeveloped reserves		0	0	0	0
Trinidad | Natural Gas (MMcf)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period | MMcf	[2]	280,900	316,600	405,600
Revisions of previous estimates | MMcf	[2]	(27,400)	29,500	16,800
Purchases in place | MMcf	[2]	0	0	0
Extensions, discoveries and other additions | MMcf	[2]	174,200	59,900	21,700
Sales in place | MMcf	[2]	0	0	0
Production | MMcf	[2]	(114,300)	(125,100)	(127,500)
Net proved reserves - end of period | MMcf	[2]	313,400	280,900	316,600
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved developed reserves | MMcf		299,200	262,200	297,600	396,900
Net proved undeveloped reserves | MMcf		14,200	18,700	19,000	8,700
Trinidad | Oil Equivalents (MBoe)
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved reserves - beginning of period | MBoe	[1]	47,661	53,843	68,937
Revisions of previous estimates | MBoe	[1]	(4,493)	4,978	2,802
Purchases in place | MBoe	[1]	0	0	0
Extensions, discoveries and other additions | MBoe	[1]	29,340	9,990	3,682
Sales in place | MBoe	[1]	0	0	0
Production | MBoe	[1]	(19,366)	(21,150)	(21,578)
Net proved reserves - end of period | MBoe	[1]	53,142	47,661	53,843
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserve (MBOE) | MBoe		2,363	3,118	3,166	1,453
Other International
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved developed reserves (MBOE) | MBoe	[3]	12,798	10,880	3,309	5,016
Other International | Crude Oil (MBbl)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1],[3]	8,255	8,667	8,729
Revisions of previous estimates	[1],[3]	(179)	861	0
Purchases in place	[1],[3]	0	0	0
Extensions, discoveries and other additions	[1],[3]	119	0	13
Sales in place	[1],[3]	0	0	(10)
Production	[1],[3]	(191)	(1,273)	(65)
Net proved reserves - end of period	[1],[3]	8,004	8,255	8,667
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved developed reserves	[3]	7,933	8,255	63	115
Net proved undeveloped reserves	[3]	71	0	8,604	8,614
Other International | Natural Gas Liquids (MBbl)
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1],[3]	0	0	138
Revisions of previous estimates	[1],[3]	0	0	68
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	(187)
Production	[1],[3]	0	0	(19)
Net proved reserves - end of period	[1],[3]	0	0	0
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved developed reserves	[3]	0	0	0	138
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]	15,800	19,500	31,500
Revisions of previous estimates | MMcf	[2],[3]	8,600	5,200	5,600
Purchases in place | MMcf	[2],[3]	0	0	0
Extensions, discoveries and other additions | MMcf	[2],[3]	35,900	0	4,400
Sales in place | MMcf	[2],[3]	0	0	(11,100)
Production | MMcf	[2],[3]	(9,100)	(8,900)	(10,900)
Net proved reserves - end of period | MMcf	[2],[3]	51,200	15,800	19,500
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved developed reserves | MMcf	[3]	29,300	15,800	19,500	28,600
Net proved undeveloped reserves | MMcf	[3]	21,900	0	0	2,900
Other International | Oil Equivalents (MBoe)
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved reserves - beginning of period | MBoe	[1],[3]	10,880	11,913	14,117
Revisions of previous estimates | MBoe	[1],[3]	1,249	1,722	995
Purchases in place | MBoe	[1],[3]	0	0	0
Extensions, discoveries and other additions | MBoe	[1],[3]	6,104	0	736
Sales in place | MBoe	[1],[3]	0	0	(2,039)
Production | MBoe	[1],[3]	(1,707)	(2,755)	(1,896)
Net proved reserves - end of period | MBoe	[1],[3]	16,526	10,880	11,913
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Net proved undeveloped reserve (MBOE) | MBoe	[3]	3,728	0	8,604	9,101
[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, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016.

Oil and Gas Exploration and P62

Oil and Gas Exploration and Production Industries Disclosures, Costs Incurred (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Unproved		$ 426,540	[1]	$ 3,216,634	[2]	$ 133,857
Acquisition Costs of Properties - Proved		72,584	[3]	749,023	[4]	480,617
Subtotal		499,124		3,965,657		614,474
Exploration Costs		223,599		165,751		252,692
Development Costs		3,716,687	[5]	2,313,876	[6]	4,061,117	[7]
Total		4,439,410		6,445,284		4,928,283
Non-Cash Unproved Leasehold Acquisition Costs Related to Property Exchanges		256,000
Non-Cash Proved Property Acquisition Costs Related to Property Exchanges		26,000
Non-Cash Unproved Leasehold Acquisition Costs Related to Yates Transaction				3,102,000
Non-Cash Proved Property Acquisition Costs Related to Yates Transaction				732,000
United States
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Unproved		424,118	[1]	3,216,598	[2]	133,801
Acquisition Costs of Properties - Proved		72,584	[3]	749,023	[4]	480,617
Subtotal		496,702		3,965,621		614,418
Exploration Costs		144,499		156,295		206,814
Development Costs		3,590,899	[5]	2,252,713	[6]	3,847,813	[7]
Total		4,232,100		6,374,629		4,669,045
Asset Retirement Costs Included In Development		50,000		25,000		32,000
Trinidad
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Unproved		2,422	[1]	0		0
Acquisition Costs of Properties - Proved		0	[3]	0		0
Subtotal		2,422		0		0
Exploration Costs		62,547		2,695		22,837
Development Costs		109,491	[5]	72,147	[6]	102,715	[7]
Total		174,460		74,842		125,552
Asset Retirement Costs Included In Development		2,000		(3,000)		15,000
Other International
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Unproved	[8]	0	[1]	36		56
Acquisition Costs of Properties - Proved	[8]	0	[3]	0		0
Subtotal	[8]	0		36		56
Exploration Costs	[8]	16,553		6,761		23,041
Development Costs	[8]	16,297	[5]	(10,984)	[6]	110,589	[7]
Total	[8]	32,850		(4,187)		133,686
Asset Retirement Costs Included In Development		$ 4,000		$ (42,000)		$ 6,000
[1]	Includes non-cash unproved leasehold acquisition costs of $256 million related to property exchanges.
[2]	Includes non-cash unproved leasehold acquisition costs of $3,102 million related to the Yates transaction.
[3]	Includes non-cash proved property acquisition costs of $26 million related to property exchanges.
[4]	Includes non-cash proved property acquisition costs of $732 million related to the Yates transaction.
[5]	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.
[6]	Includes Asset Retirement Costs of $25 million, $(3) million and $(42) million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment.
[7]	Includes Asset Retirement Costs of $32 million, $15 million and $6 million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment.
[8]	Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016.

Oil and Gas Exploration and P63

Oil and Gas Exploration and Production Industries Disclosures, Results Of Operations (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	[1]	$ 7,907,891	$ 5,496,743	$ 6,403,258
Other	[1]	81,610	81,403	47,909
Total	[1]	7,989,501	5,578,146	6,451,167
Exploration Costs	[1]	145,342	124,953	149,494
Dry Hole Costs	[1]	4,609	10,657	14,746
Transportation Costs	[1]	740,352	764,106	849,319
Production Costs	[1]	1,562,210	1,254,013	1,581,131
Impairments	[1]	479,240	620,267	6,613,546
Depreciation, Depletion and Amortization	[1]	3,296,766	3,437,284	3,190,443
Income (Loss) Before Income Taxes	[1]	1,760,982	(633,134)	(5,947,512)
Income Tax Provision (Benefit)	[1]	649,102	(226,413)	(2,086,555)
Results of Operations	[1]	1,111,880	(406,721)	(3,860,957)
United States
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	[1]	7,570,768	5,177,989	5,962,753
Other	[1]	81,610	81,386	47,464
Total	[1]	7,652,378	5,259,375	6,010,217
Exploration Costs	[1]	113,334	115,990	139,753
Dry Hole Costs	[1]	91	10,529	956
Transportation Costs	[1]	737,403	753,791	838,428
Production Costs	[1]	1,446,333	1,163,827	1,486,189
Impairments	[1]	477,223	611,297	6,402,908
Depreciation, Depletion and Amortization	[1]	3,157,056	3,249,792	3,017,386
Income (Loss) Before Income Taxes	[1]	1,720,938	(645,851)	(5,875,403)
Income Tax Provision (Benefit)	[1]	625,562	(230,377)	(2,128,183)
Results of Operations	[1]	1,095,376	(415,474)	(3,747,220)
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]	284,673	243,708	381,761
Other	[1]	59	(8)	(3)
Total	[1]	284,732	243,700	381,758
Exploration Costs	[1]	26,245	2,647	2,071
Dry Hole Costs	[1]	0	0	5,635
Transportation Costs	[1]	1,885	1,181	1,290
Production Costs	[1]	27,839	27,113	28,862
Impairments	[1]	0	7,773	0
Depreciation, Depletion and Amortization	[1]	115,174	145,440	154,588
Income (Loss) Before Income Taxes	[1]	113,589	59,546	189,312
Income Tax Provision (Benefit)	[1]	24,882	5,526	43,739
Results of Operations	[1]	88,707	54,020	145,573
Other International
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	[1],[2]	52,450	75,046	58,744
Other	[1],[2]	(59)	25	448
Total	[1],[2]	52,391	75,071	59,192
Exploration Costs	[1],[2]	5,763	6,316	7,670
Dry Hole Costs	[1],[2]	4,518	128	8,155
Transportation Costs	[1],[2]	1,064	9,134	9,601
Production Costs	[1],[2]	88,038	63,073	66,080
Impairments	[1],[2]	2,017	1,197	210,638
Depreciation, Depletion and Amortization	[1],[2]	24,536	42,052	18,469
Income (Loss) Before Income Taxes	[1],[2]	(73,545)	(46,829)	(261,421)
Income Tax Provision (Benefit)	[1],[2]	(1,342)	(1,562)	(2,111)
Results of Operations	[1],[2]	$ (72,203)	$ (45,267)	$ (259,310)
[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, 2017.
[2]	Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016.

Oil and Gas Exploration and P64

Oil and Gas Exploration and Production Industries Disclosures, Average Sales Price (Details) - $ / bbl		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent		4.66	4.48	5.85
United States
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent		4.58	4.58	5.81
Trinidad
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent		1.39	1.23	1.29
Other International
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent	[1]	50.86	22.43	33.78
[1]	Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016.

Oil and Gas Exploration and P65

Oil and Gas Exploration and Production Industries Disclosures, Discounted Future Net Cash Flows (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2017USD ($)		Dec. 31, 2016USD ($)		Dec. 31, 2015USD ($)
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows					$ 85,221,064	[1]	$ 58,840,424	[2]	$ 68,720,648	[3]
Future production costs					(32,569,408)		(28,018,883)		(32,060,855)
Future development costs					(13,538,795)		(12,741,932)		(15,785,811)
Future income taxes					(6,160,541)		(3,211,320)		(4,616,201)
Future net cash flows					32,952,320		14,868,289		16,257,781
Discount to present value at 10% annual rate					(14,624,660)		(6,056,132)		(6,636,385)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves		$ 8,812,157	$ 9,621,396	$ 27,923,418	18,327,660		8,812,157		9,621,396
Annual Rate of Discount to Present Value		10.00%	10.00%	10.00%
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at Beginning of Period		$ 8,812,157	$ 9,621,396	$ 27,923,418
Sales and transfers of oil and gas produced, net of production costs		(5,605,330)	(3,478,625)	(4,020,717)
Net changes in prices and production costs		7,121,545	(3,679,602)	(30,669,350)
Extensions, discoveries, additions and improved recovery, net of related costs		3,958,248	907,267	1,095,898
Development costs incurred		1,440,300	1,230,000	2,137,700
Revisions of estimated development cost		(124,877)	2,121,708	4,079,381
Revisions of previous quantity estimates		2,438,271	1,053,020	(4,051,874)
Accretion of discount		886,707	1,054,435	3,857,479
Net change in income taxes		(2,043,663)	868,038	9,728,423
Purchases of reserves in place		30,362	377,872	123,542
Sales of reserves in place		(76,527)	(375,793)	(37,088)
Changes in timing and other		1,490,467	(887,559)	(545,416)
Balance at End of Period		18,327,660	8,812,157	9,621,396
United States
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows					83,652,363	[1]	57,913,314	[2]	67,242,928	[3]
Future production costs					(32,018,812)		(27,625,833)		(31,707,743)
Future development costs					(13,395,873)		(12,602,699)		(15,579,923)
Future income taxes					(5,948,453)		(3,151,319)		(4,400,542)
Future net cash flows					32,289,225		14,533,463		15,554,720
Discount to present value at 10% annual rate					(14,532,290)		(6,039,736)		(6,589,253)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves		8,493,727	8,965,467	26,704,041	$ 17,756,935		$ 8,493,727		$ 8,965,467
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at Beginning of Period		8,493,727	8,965,467	26,704,041
Sales and transfers of oil and gas produced, net of production costs		(5,387,031)	(3,260,372)	(3,685,600)
Net changes in prices and production costs		6,606,908	(3,352,802)	(29,993,699)
Extensions, discoveries, additions and improved recovery, net of related costs		3,644,041	865,066	1,028,410
Development costs incurred		1,435,600	1,207,000	2,135,800
Revisions of estimated development cost		(114,464)	2,092,769	4,087,093
Revisions of previous quantity estimates		2,460,498	1,013,753	(4,084,572)
Accretion of discount		849,373	970,388	3,699,330
Net change in income taxes		(1,918,989)	738,416	9,550,847
Purchases of reserves in place		30,362	377,872	123,542
Sales of reserves in place		(76,527)	(375,793)	(23,424)
Changes in timing and other		1,733,437	(748,037)	(576,301)
Balance at End of Period		17,756,935	8,493,727	8,965,467
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					49.21		40.70		49.58
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					23.51		14.69		15.17
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					1.96		1.40		2.15
Trinidad
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows					$ 904,141	[1]	$ 524,523	[2]	$ 954,779	[3]
Future production costs					(239,213)		(165,757)		(183,607)
Future development costs					(84,379)		(103,631)		(140,541)
Future income taxes					(195,855)		(60,001)		(215,659)
Future net cash flows					384,694		195,134		414,972
Discount to present value at 10% annual rate					(52,267)		(9,384)		(33,848)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves		185,750	381,124	682,536	$ 332,427		$ 185,750		$ 381,124
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at Beginning of Period		185,750	381,124	682,536
Sales and transfers of oil and gas produced, net of production costs		(254,948)	(215,414)	(351,606)
Net changes in prices and production costs		436,969	(182,876)	(370,503)
Extensions, discoveries, additions and improved recovery, net of related costs		270,255	42,201	47,613
Development costs incurred		4,700	3,900	500
Revisions of estimated development cost		9,683	22,596	(34,647)
Revisions of previous quantity estimates		(58,373)	36,648	33,285
Accretion of discount		24,066	56,566	104,464
Net change in income taxes		(114,575)	129,622	177,576
Purchases of reserves in place		0	0	0
Sales of reserves in place		0	0	0
Changes in timing and other		(171,100)	(88,617)	91,906
Balance at End of Period		332,427	185,750	381,124
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					41.87		34.79		38.83
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					2.76		1.76		2.88
Other International (1)
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	[4]				$ 664,560	[1]	$ 402,587	[2]	$ 522,941	[3]
Future production costs	[4]				(311,383)		(227,293)		(169,505)
Future development costs	[4]				(58,543)		(35,602)		(65,347)
Future income taxes	[4]				(16,233)		0		0
Future net cash flows	[4]				278,401		139,692		288,089
Discount to present value at 10% annual rate	[4]				(40,103)		(7,012)		(13,284)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	[4]	132,680	274,805	536,841	$ 238,298		$ 132,680		$ 274,805
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at Beginning of Period	[4]	132,680	274,805	536,841
Sales and transfers of oil and gas produced, net of production costs	[4]	36,649	(2,839)	16,489
Net changes in prices and production costs	[4]	77,668	(143,924)	(305,148)
Extensions, discoveries, additions and improved recovery, net of related costs	[4]	43,952	0	19,875
Development costs incurred	[4]	0	19,100	1,400
Revisions of estimated development cost	[4]	(20,096)	6,343	26,935
Revisions of previous quantity estimates	[4]	36,146	2,619	(587)
Accretion of discount	[4]	13,268	27,481	53,685
Net change in income taxes	[4]	(10,099)	0	0
Purchases of reserves in place	[4]	0	0	0
Sales of reserves in place	[4]	0	0	(13,664)
Changes in timing and other	[4]	(71,870)	(50,905)	(61,021)
Balance at End of Period	[4]	$ 238,298	$ 132,680	$ 274,805
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					50.06		39.55		47.76
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					5.16		4.84		5.60
[1]	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.
[2]	Estimated crude oil prices used to calculate 2016 future cash inflows for the United States, Trinidad and Other International were $40.70, $34.79 and $39.55, respectively. Estimated NGL price used to calculate 2016 future cash inflows for the United States was $14.69. Estimated natural gas prices used to calculate 2016 future cash inflows for the United States, Trinidad and Other International were $1.40, $1.76 and $4.84, respectively.
[3]	Estimated crude oil prices used to calculate 2015 future cash inflows for the United States, Trinidad and Other International were $49.58, $38.83 and $47.76, respectively. Estimated NGL price used to calculate 2015 future cash inflows for the United States was $15.17. Estimated natural gas prices used to calculate 2015 future cash inflows for the United States, Trinidad and Other International were $2.15, $2.88 and $5.60, respectively.
[4]	Other International includes EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016.

Unaudited Quarterly Financial66

Unaudited Quarterly Financial Information (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2017		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Net Operating Revenues	$ 3,340,439		$ 2,644,844		$ 2,612,472		$ 2,610,565		$ 2,402,039		$ 2,118,504		$ 1,775,740		$ 1,354,349		$ 11,208,320	$ 7,650,632	$ 8,757,428
Operating Income	475,912		214,836		127,908		107,746		(105,487)		(193,480)		(288,173)		(638,141)		926,402	(1,225,281)	(6,686,079)
Income (Loss) Before Income Taxes	413,353		145,980		62,467		39,382		(194,010)		(272,250)		(380,277)		(710,968)
Income Tax Provision (Benefit)	(2,017,115)	[1]	45,439	[1]	39,414	[1]	10,865	[1]	(51,658)		(82,250)		(87,719)		(239,192)		(1,921,397)	(460,819)	(2,397,041)
Net Income (Loss)	$ 2,430,468		$ 100,541		$ 23,053		$ 28,517		$ (142,352)		$ (190,000)		$ (292,558)		$ (471,776)		$ 2,582,579	$ (1,096,686)	$ (4,524,515)
Net Income (Loss) Per Share
Basic (in dollars per share)	$ 4.22	[2]	$ 0.17	[2]	$ 0.04	[2]	$ 0.05	[2]	$ (0.25)	[2]	$ (0.35)	[2]	$ (0.53)	[2]	$ (0.86)	[2]	$ 4.49	$ (1.98)	$ (8.29)
Diluted (in dollars per share)	$ 4.20	[2]	$ 0.17	[2]	$ 0.04	[2]	$ 0.05	[2]	$ (0.25)	[2]	$ (0.35)	[2]	$ (0.53)	[2]	$ (0.86)	[2]	$ 4.46	$ (1.98)	$ (8.29)
Average Number of Common Shares [Abstract]
Basic (in shares)	575,394		574,783		574,439		573,935		567,337		547,838		547,335		546,715		574,620	553,384	545,697
Diluted	579,203		578,736		578,483		578,593		567,337		547,838		547,335		546,715		578,693	553,384	545,697
Provisional Reduction in the Income Tax Provision																	$ 2,200,000
[1]	Includes an income tax benefit of approximately $2.2 billion for the quarter ended December 31, 2017, primarily due to the enactment of the Tax Cuts and Jobs Act in December 2017. See Note 6 to the Consolidated Financial Statements.
[2]	The sum of quarterly net income (loss) per share may not agree with total year net income (loss) per share as each quarterly computation is based on the weighted average of common shares outstanding.