EOG Resources (EOG) 10-K 27 Feb 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 17, 2017	Jun. 30, 2016
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			$ 45,822,000,000
Entity Common Stock, Shares Outstanding		576,832,077
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016

Consolidated Statements of Inco

Consolidated Statements of Income and Comprehensive Income - USD ($) shares in Thousands, $ in Thousands		12 Months Ended
		Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Net Operating Revenues
Crude Oil and Condensate		$ 4,317,341		$ 4,934,562		$ 9,742,480
Natural Gas Liquids		437,250		407,658		934,051
Natural Gas		742,152		1,061,038		1,916,386
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts		(99,608)		61,924		834,273
Gathering, Processing and Marketing		1,966,259		2,253,135		4,046,316
Gains (Losses) on Asset Dispositions, Net		205,835		(8,798)		507,590
Other, Net		81,403		47,909		54,244
Total		7,650,632	[1]	8,757,428	[2]	18,035,340	[3]
Operating Expenses
Lease and Well		927,452		1,182,282		1,416,413
Transportation Costs		764,106		849,319		972,176
Gathering and Processing Costs		122,901		146,156		145,800
Exploration Costs		124,953		149,494		184,388
Dry Hole Costs	[4]	10,657		14,746		48,490
Impairments		620,267		6,613,546		743,575
Marketing Costs		2,007,635		2,385,982		4,126,060
Depreciation, Depletion and Amortization		3,553,417		3,313,644		3,997,041
General and Administrative		394,815		366,594		402,010
Taxes Other Than Income		349,710		421,744		757,564
Total		8,875,913		15,443,507		12,793,517
Operating Income (Loss)		(1,225,281)		(6,686,079)		5,241,823
Other (Expense) Income, Net		(50,543)		1,916		(45,050)
Income (Loss) Before Interest Expense and Income Taxes		(1,275,824)		(6,684,163)		5,196,773
Interest Expense
Incurred		313,341		279,234		258,628
Capitalized		(31,660)		(41,841)		(57,170)
Net Interest Expense		281,681		237,393		201,458
Income (Loss) Before Income Taxes		(1,557,505)		(6,921,556)		4,995,315
Income Tax (Benefit) Provision		(460,819)		(2,397,041)		2,079,828
Net Income (Loss)		$ (1,096,686)		$ (4,524,515)		$ 2,915,487
Net Income (Loss) Per Share
Basic (in dollars per share)		$ (1.98)		$ (8.29)		$ 5.36
Diluted (in dollars per share)		(1.98)		(8.29)		5.32
Dividends Declared per Common Share		$ 0.670		$ 0.670		$ 0.585
Average Number of Common Shares [Abstract]
Basic (in shares)		553,384		545,697		543,443
Diluted (in shares)		553,384		545,697		548,539
Statement Of Comprehensive Income [Abstract]
Net Income (Loss)		$ (1,096,686)		$ (4,524,515)		$ 2,915,487
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments		12,097		(11,517)		(437,728)
Other, Net of Tax		2,231		1,235		(1,162)
Other Comprehensive Income (Loss)		14,328		(10,282)		(438,890)
Comprehensive Income (Loss)		$ (1,082,358)		$ (4,534,797)		$ 2,476,597
[1]	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 in the United States segment.
[2]	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 in the United States segment.
[3]	EOG had sales activity with two significant purchasers in 2014, one totaling $4.0 billion and the other totaling $3.0 billion of consolidated Net Operating Revenues in the United States segment.
[4]	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, 2016.

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current Assets
Cash and Cash Equivalents	$ 1,599,895	$ 718,506
Accounts Receivable, Net	1,216,320	930,610
Inventories	350,017	598,935
Income Taxes Receivable	12,305	40,704
Deferred Income Taxes	169,387	147,812
Other	206,679	155,677
Total	3,554,603	2,592,244
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)	49,592,091	50,613,241
Other Property, Plant and Equipment	4,008,564	3,986,610
Total Property, Plant and Equipment	53,600,655	54,599,851
Less: Accumulated Depreciation, Depletion and Amortization	(27,893,577)	(30,389,130)
Total Property, Plant and Equipment, Net	25,707,078	24,210,721
Other Assets	197,752	167,505
Total Assets	29,459,433	26,970,470
Current Liabilities
Accounts Payable	1,511,826	1,471,953
Accrued Taxes Payable	118,411	93,618
Dividends Payable	96,120	91,546
Liabilities from Price Risk Management Activities	61,817	0
Current Portion of Long-Term Debt	6,579	6,579
Other	232,538	155,591
Total	2,027,291	1,819,287
Long-Term Debt	6,979,779	6,648,911
Other Liabilities	1,282,142	971,335
Deferred Income Taxes	5,188,640	4,587,902
Commitments and Contingencies (Note 8)
Stockholders' Equity
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 576,950,272 Shares and 550,150,823 Shares Issued at December 31, 2016 and 2015, respectively	205,770	205,502
Additional Paid in Capital	5,420,385	2,923,461
Accumulated Other Comprehensive Loss	(19,010)	(33,338)
Retained Earnings	8,398,118	9,870,816
Common Stock Held in Treasury, 250,155 Shares and 292,179 Shares at December 31, 2016 and 2015, respectively	(23,682)	(23,406)
Total Stockholders' Equity	13,981,581	12,943,035
Total Liabilities and Stockholders' Equity	$ 29,459,433	$ 26,970,470

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2016	Dec. 31, 2015
Common Stock
Common Stock, Par Value (in dollars per share)	$ 0.01	$ 0.01
Common Stock, Shares Authorized (in shares)	640,000,000	640,000,000
Common Stock, Shares Issued (in shares)	576,950,272	550,150,823
Treasury Stock
Common Stock Held in Treasury (in shares)	250,155	292,179

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock Held in Treasury [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Additional Paid-in Capital [Member]	Common Stock [Member]
Common Stock Dividends Declared (in dollars per share)	$ 0.585
Balance at Dec. 31, 2013	$ 15,418,459	$ (15,263)	$ 12,168,277	$ 415,834	$ 2,646,879	$ 202,732
Net Income (Loss)	2,915,487	0	2,915,487	0	0	0
Common Stock Issued Under Stock Plans	22,260	0	0	0	22,252	8
Dividends, Common Stock	(320,666)	0	320,666	0	0	0
Other Comprehensive Income (Loss)	(438,890)	0	0	(438,890)	0	0
Change in Treasury Stock - Stock Compensation Plans, Net	(127,432)	(96,962)	0	0	(30,470)	0
Excess Tax Benefit from Stock-Based Compensation	99,459	0	0	0	99,459	0
Restricted Stock and Restricted Stock Units, Net	0	43,091	0	0	(43,109)	18
Stock-Based Compensation Expenses	144,842	0	0	0	144,842	0
Common Stock Issued - Stock Split	0	0	0	0	(2,734)	2,734
Treasury Stock Issued as Compensation	(937)	(968)	0	0	31	0
Balance at Dec. 31, 2014	$ 17,712,582	(70,102)	14,763,098	(23,056)	2,837,150	205,492
Common Stock Dividends Declared (in dollars per share)	$ 0.670
Net Income (Loss)	$ (4,524,515)	0	(4,524,515)	0	0	0
Common Stock Issued Under Stock Plans	15,371	0	0	0	15,366	5
Dividends, Common Stock	(367,767)	0	367,767	0	0	0
Other Comprehensive Income (Loss)	(10,282)	0	0	(10,282)	0	0
Change in Treasury Stock - Stock Compensation Plans, Net	(41,471)	(129)	0	0	(41,342)	0
Excess Tax Benefit from Stock-Based Compensation	26,058	0	0	0	26,058	0
Restricted Stock and Restricted Stock Units, Net	0	44,334	0	0	(44,339)	5
Stock-Based Compensation Expenses	130,577	0	0	0	130,577	0
Treasury Stock Issued as Compensation	2,482	2,491	0	0	(9)	0
Balance at Dec. 31, 2015	$ 12,943,035	(23,406)	9,870,816	(33,338)	2,923,461	205,502
Common Stock Dividends Declared (in dollars per share)	$ 0.670
Net Income (Loss)	$ (1,096,686)	$ 0	$ (1,096,686)	$ 0	$ 0	$ 0
Common Stock Issued for the Yates Transaction	2,397,887	0	0	0	2,397,635	252
Common Stock Issued Under Stock Plans	$ 16,397	$ 0	$ 0	$ 0	$ 16,388	$ 9
Dividends, Common Stock	(376,012)	0	376,012	0	0	0
Other Comprehensive Income (Loss)	14,328	0	0	14,328	0	0
Change in Treasury Stock - Stock Compensation Plans, Net	(75,226)	(48,208)	0	0	(27,018)	0
Excess Tax Benefit from Stock-Based Compensation	29,357	0	0	0	29,357	0
Restricted Stock and Restricted Stock Units, Net	0	47,502	0	0	(47,509)	7
Stock-Based Compensation Expenses	128,090	0	0	0	128,090	0
Treasury Stock Issued as Compensation	411	430	0	0	(19)	0
Balance at Dec. 31, 2016	$ 13,981,581	$ (23,682)	$ 8,398,118	$ (19,010)	$ 5,420,385	$ 205,770

Consolidated Statements of Sto6

Consolidated Statements of Stockholders' Equity (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement of Stockholders' Equity [Abstract]
Dividends, Common Stock	$ 376,012	$ 367,767	$ 320,666
Common Stock Dividends Declared (in dollars per share)	$ 0.670	$ 0.670	$ 0.585

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash Flows from Operating Activities
Net Income (Loss)		$ (1,096,686)	$ (4,524,515)	$ 2,915,487
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization		3,553,417	3,313,644	3,997,041
Impairments		620,267	6,613,546	743,575
Stock-Based Compensation Expenses		128,090	130,577	145,086
Deferred Income Taxes		(515,206)	(2,482,307)	1,704,946
(Gains) Losses on Asset Dispositions, Net		(205,835)	8,798	(507,590)
Other, Net		61,690	11,896	48,138
Dry Hole Costs	[1]	10,657	14,746	48,490
Mark-to-Market Commodity Derivative Contracts
Total Losses (Gains)		99,608	(61,924)	(834,273)
Net Cash (Payments) Received from Settlements of Commodity Derivative Contracts		(22,219)	730,114	34,007
Excess Tax Benefits from Stock-Based Compensation		(29,357)	(26,058)	(99,459)
Other, Net		10,971	12,532	13,009
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable		(232,799)	641,412	84,982
Inventories		170,694	58,450	(161,958)
Accounts Payable		(74,048)	(1,409,197)	543,630
Accrued Taxes Payable		92,782	11,798	16,486
Other Assets		(40,636)	118,143	(14,448)
Other Liabilities		(16,225)	(66,257)	75,420
Changes in Components of Working Capital Associated with Investing and Financing Activities		(156,102)	499,767	(103,414)
Net Cash Provided by Operating Activities		2,359,063	3,595,165	8,649,155
Investing Cash Flows
Additions to Oil and Gas Properties		(2,489,756)	(4,725,150)	(7,519,667)
Additions to Other Property, Plant and Equipment		(93,039)	(288,013)	(727,138)
Proceeds from Sales of Assets		1,119,215	192,807	569,332
Changes in Restricted Cash		0	0	60,385
Payments to Acquire Businesses, Net of Cash Acquired		54,534	0	0
Changes in Components of Working Capital Associated with Investing Activities		156,102	(499,900)	103,523
Net Cash Used in Investing Activities		(1,252,944)	(5,320,256)	(7,513,565)
Financing Cash Flows
Repayments of Commercial Paper		(259,718)
Proceeds from Issuance of Commercial Paper			259,718	0
Long-Term Debt Borrowings		991,097	990,225	496,220
Long-Term Debt Repayments		(563,829)	(500,000)	(500,000)
Settlement of Foreign Currency Swap		0	0	(31,573)
Dividends Paid		(372,845)	(367,005)	(279,695)
Excess Tax Benefits from Stock-Based Compensation		29,357	26,058	99,459
Treasury Stock Purchased		(82,125)	(48,791)	(127,424)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan		23,296	22,690	22,249
Debt Issuance Costs		(1,602)	(5,951)	(895)
Repayment of Capital Lease Obligation		(6,353)	(6,156)	(5,966)
Other, Net		0	133	(109)
Net Cash (Used in) Provided by Financing Activities		(242,722)	370,921	(327,734)
Effect of Exchange Rate Changes on Cash		17,992	(14,537)	(38,852)
Increase (Decrease) in Cash and Cash Equivalents		881,389	(1,368,707)	769,004
Cash and Cash Equivalents at Beginning of Year		718,506	2,087,213	1,318,209
Cash and Cash Equivalents at End of Year		$ 1,599,895	$ 718,506	$ 2,087,213
[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, 2016.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
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. 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 cost 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. 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, 2016, EOG elected not to designate any of its financial commodity derivative instruments as accounting hedges and, accordingly, changes in the fair value of these outstanding derivative instruments are recognized as gains or losses in the period of change. The gains or losses are recorded as Gains (Losses) on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income and Comprehensive Income. The related cash flow impact of settled contracts is reflected as cash flows from operating activities. EOG was party to a foreign currency swap transaction and an interest rate swap transaction, both of which were accounted for using the hedge accounting method. EOG employs net presentation of derivative assets and liabilities for financial reporting purposes when such assets and liabilities are with the same counterparty and subject to a master netting arrangement. See Note 12. Income Taxes. Income taxes are accounted for using the asset and liability approach. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. EOG assesses the realizability of deferred tax assets and recognizes valuation allowances as appropriate (see Note 6). Foreign Currency Translation. The United States dollar is the functional currency for all of EOG's consolidated subsidiaries except for its Canadian subsidiaries, for which the functional currency is the Canadian dollar, and its United Kingdom subsidiary, 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 Loss on the Consolidated Balance Sheets. Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period. See Notes 4 and 17. Net Income (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 January 2017, the FASB issued Accounting Standards Update (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 and early adoption is permitted. EOG is evaluating ASU 2017-01 to determine the impact on its consolidated financial statements and related disclosures. 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. Early adoption is permitted. EOG does not intend to early adopt ASU 2016-15. EOG does not expect the adoption of ASU 2016-15 to have a material impact on its consolidated financial statements and related disclosures. In March 2016, the FASB issued 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. ASU 2016-09 is effective for interim and annual periods beginning after December 15, 2016, and early application is permitted. EOG will adopt ASU 2016-09 effective January 1, 2017. There will be no impact to retained earnings with respect to excess tax benefits. EOG will begin recognizing all excess benefits and tax deficiencies as income tax expense or benefit as discrete events. The treatment of forfeitures will not change as EOG is electing to continue the current process of estimating the number of forfeitures. As such, this will have no cumulative effect on retained earnings. EOG will elect to present changes to the cash flow statement on a prospective transition method. 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 reviewing the provisions of ASU 2016-02 to determine the impact on its consolidated financial statements and related disclosures. In November 2015, the FASB issued 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. ASU 2015-17 is effective for financial statements issued for interim and annual periods beginning after December 15, 2016, and early application is permitted. EOG will adopt ASU 2015-17 effective January 1, 2017, on a retrospective basis, resulting in a reclassification of current deferred taxes to noncurrent on the Consolidated Balance Sheets, which will increase noncurrent deferred tax assets $169 million with no impact on noncurrent deferred tax liabilities. Effective January 1, 2016, EOG adopted the provisions of ASU 2015-03, "Interest - Computation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03). ASU 2015-03 requires that debt issuance costs be presented in the balance sheet as a direct reduction from the related debt liability rather than as an asset. In connection with the adoption of ASU 2015-03, EOG restated its December 31, 2015 Consolidated Balance Sheet to reclassify $4.8 million of unamortized debt issuance costs from "Other Assets" to "Long-Term Debt." Debt issuance costs related to EOG's senior unsecured revolving credit facility remain classified as "Other Assets." In May 2014, the FASB issued ASU 2014-09, "Revenue From Contracts With Customers" (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, and early adoption is permitted. 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 ASC, including guidance related to the use of the "entitlements" method of revenue recognition. EOG does not intend to early-adopt ASU 2014-09. EOG will be required to change from the entitlements method of accounting to the sales method of accounting and does not anticipate the impact will be material to the Consolidated Statements of Income and Comprehensive Income. EOG is continuing to evaluate the remaining provisions of ASU 2014-09 and has not determined the full impact on its consolidated financial statements and related disclosures.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Long-Term Debt at December 31, 2016 and 2015 consisted of the following (in thousands): 2016 2015 Commercial Paper $ — $ 259,718 2.500% Senior Notes due 2016 — 400,000 5.875% Senior Notes due 2017 600,000 600,000 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 — 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 — Long-Term Debt 6,990,000 6,649,718 Capital Lease Obligation 38,710 45,064 Less: Current Portion of Long-Term Debt 6,579 6,579 Unamortized Debt Discount 36,915 34,518 Debt Issuance Costs 5,437 4,774 Total Long-Term Debt $ 6,979,779 $ 6,648,911 At December 31, 2016 , the aggregate annual maturities of long-term debt (excluding capital lease obligations) were $ 600 million in 2017, $ 350 million in 2018, $ 900 million in 2019, $1 billion in 2020 and $750 million in 2021. At December 31, 2016 and 2015 , EOG had zero and $260 million , respectively, of outstanding short-term borrowings under the commercial paper program and no outstanding borrowings under uncommitted credit facilities. During 2016 and 2015 , EOG utilized commercial paper bearing market interest rates, for various corporate financing purposes. EOG had no outstanding borrowings from commercial paper at December 31, 2016. The average borrowings outstanding under the commercial paper program were $130 million and $81 million during the years ended December 31, 2016 and 2015, respectively. The weighted average interest rates for commercial paper borrowings were 0.76% and 0.51% for the years 2016 and 2015, respectively. At December 31, 2016, the $600 million aggregate principal amount of EOG's 5.875% Senior Notes due 2017 were reclassified as long-term debt based upon its intent and ability to ultimately replace such amount with other long-term debt. 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 New Notes). Interest on the New 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 New Notes offering totaled approximately $991 million and were used to repay its 2.500% Senior Notes due 2016 when they matured on February 1, 2016 , and for general corporate purposes, including repayment of outstanding commercial paper borrowings and funding of future capital expenditures. On July 21, 2015, EOG entered into a new $2.0 billion senior unsecured Revolving Credit Agreement (2015 Agreement) with domestic and foreign lenders. The 2015 Agreement replaces EOG's $2.0 billion senior unsecured Revolving Credit Agreement, dated as of October 11, 2011, which had a scheduled maturity date of October 11, 2016 (2011 Agreement). There were no borrowings or letters of credit outstanding under the 2011 Agreement as of the closing of the 2015 Agreement and the termination of the 2011 Agreement. The 2015 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 2015 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 2015 Agreement) plus an applicable margin. Consistent with the terms of the 2011 Agreement, the 2015 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, 2016 , there were no borrowings or letters of credit outstanding under the 2015 Agreement. The Eurodollar rate and applicable base rate, had there been any amounts borrowed under the 2015 Agreement, would have been 1.77% and 3.75% , respectively. On February 1, 2016, EOG repaid upon maturity the $400 million aggregate principal amount of its 2.500% Senior Notes due 2016. On June 1, 2015, EOG repaid upon maturity the $500 million aggregate principal amount of its 2.95% Senior Notes due 2015. On March 17, 2015, EOG closed its sale of $500 million aggregate principal amount of its 3.15% Senior Notes due 2025 and $500 million aggregate principal amount of its 3.90% Senior Notes due 2035 (together, the Notes). Interest on the Notes is payable semi-annually in arrears on April 1 and October 1 of each year, beginning on October 1, 2015. Net proceeds from the Notes offering of approximately $990 million were used for general corporate purposes.

Stockholder's Equity

Stockholder's Equity	12 Months Ended
	Dec. 31, 2016
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, 2016 , 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 October 4, 2016, EOG issued approximately 25 million shares of EOG common stock in connection with the Yates transaction. (See Note 17.) On February 24, 2014, EOG's Board approved a two-for-one stock split in the form of a stock dividend, which was paid on March 31, 2014, to stockholders of record as of March 17, 2014. On August 5, 2014, the Board increased the quarterly cash dividend on the common stock by 34% to $0.1675 per share, effective beginning with the dividend paid on October 31, 2014, to stockholders of record as of October 17, 2014. On February 24, 2014, the Board increased the quarterly cash dividend on the common stock by 33 % to $0.125 per share, effective beginning with the dividend paid on April 30, 2014, to stockholders of record as of April 16, 2014. The following summarizes Common Stock activity for each of the years ended December 31, 2014 , 2015 and 2016 (in thousands): Common Shares Issued Treasury Outstanding Balance at December 31, 2013 546,378 (206 ) 546,172 Common Stock Issued Under Stock-Based Compensation Plans 2,448 — 2,448 Treasury Stock Purchased (1) — (1,209 ) (1,209 ) Common Stock Issued Under Employee Stock Purchase Plan 202 — 202 Treasury Stock Issued Under Stock-Based Compensation Plans — 682 682 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 (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, 2016 , there were no shares of preferred stock outstanding.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2016
Accumulated Other Comprehensive Income [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, 2016 and 2015 consisted of the following (in thousands): Foreign Currency Translation Adjustment Other Total December 31, 2014 $ (20,021 ) $ (3,035 ) $ (23,056 ) Other comprehensive loss before reclassifications (11,517 ) (129 ) (11,646 ) Amounts reclassified out of other comprehensive income (loss) — 1,572 (1) 1,572 Tax effects — (208 ) (208 ) Other comprehensive income (loss) (11,517 ) 1,235 (10,282 ) December 31, 2015 (31,538 ) (1,800 ) (33,338 ) Other comprehensive income before reclassifications 12,097 2,901 14,998 Tax effects — (670 ) (670 ) Other comprehensive income 12,097 2,231 14,328 December 31, 2016 $ (19,441 ) $ 431 $ (19,010 ) (1) Reclassified to Net Income (Loss) - General and Administrative. Related to certain EOG pension plans. See Note 7. No significant amount was reclassified out of Accumulated Other Comprehensive Income (Loss) during the year ended December 31, 2016.

Other Income (Expense), Net

Other Income (Expense), Net	12 Months Ended
	Dec. 31, 2016
Other Income and Expenses [Abstract]
Other Income (Expense), Net	Other Income (Expense), Net 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 ). Other expense, net, for 2014 included net foreign currency transaction losses ( $(34) million ), losses on dispositions of warehouse stock ($ (15) million ) and equity income from investments in ammonia plants in Trinidad ( $8 million ).

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The principal components of EOG's net deferred income tax liabilities at December 31, 2016 and 2015 were as follows (in thousands): 2016 2015 Current Deferred Income Tax Assets (Liabilities) Commodity Hedging Contracts $ 22,206 $ — Deferred Compensation Plans 43,984 38,559 Alternative Minimum Tax Credit Carryforward 84,426 93,316 Foreign Net Operating Loss 37,251 47,786 Foreign Valuation Allowance (28,097 ) (35,536 ) Accrued Expenses and Liabilities 13,754 — Other (4,137 ) 3,687 Total Net Current Deferred Income Tax Assets $ 169,387 $ 147,812 Noncurrent Deferred Income Tax Assets (Liabilities) Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization $ (39,852 ) $ (57,569 ) Foreign Net Operating Loss 314,899 443,010 Foreign Valuation Allowances (268,499 ) (380,104 ) Foreign Other 438 1,506 Total Net Noncurrent Deferred Income Tax Assets $ 6,986 $ 6,843 Noncurrent Deferred Income Tax (Assets) Liabilities Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization $ 5,899,533 $ 5,299,817 Non-Producing Leasehold Costs (64,898 ) (53,026 ) Seismic Costs Capitalized for Tax (161,920 ) (162,240 ) Equity Awards (139,787 ) (140,663 ) Capitalized Interest 86,504 98,242 Alternative Minimum Tax Credit Carryforward (673,205 ) (685,189 ) Undistributed Foreign Earnings 280,099 258,403 Other (37,686 ) (27,442 ) Total Net Noncurrent Deferred Income Tax Liabilities $ 5,188,640 $ 4,587,902 Total Net Deferred Income Tax Liabilities $ 5,012,267 $ 4,433,247 The components of Income (Loss) Before Income Taxes for the years indicated below were as follows (in thousands): 2016 2015 2014 United States $ (1,520,573 ) $ (6,840,119 ) $ 5,161,232 Foreign (36,932 ) (81,437 ) (165,917 ) Total $ (1,557,505 ) $ (6,921,556 ) $ 4,995,315 The principal components of EOG's Income Tax Provision (Benefit) for the years indicated below were as follows (in thousands): 2016 2015 2014 Current: Federal $ 11,567 $ 21,719 $ 269,326 State (8,369 ) 9,404 22,835 Foreign 51,189 54,143 82,721 Total 54,387 85,266 374,882 Deferred: Federal (532,979 ) (2,362,926 ) 1,608,706 State 4,876 (127,444 ) 29,056 Foreign 12,897 8,063 67,184 Total (515,206 ) (2,482,307 ) 1,704,946 Income Tax Provision (Benefit) $ (460,819 ) $ (2,397,041 ) $ 2,079,828 The differences between taxes computed at the United States federal statutory tax rate and EOG's effective rate were as follows: 2016 2015 2014 Statutory Federal Income Tax Rate 35.00 % 35.00 % 35.00 % State Income Tax, Net of Federal Benefit 0.15 1.11 0.68 Income Tax Provision Related to Foreign Operations (1.23 ) (1.31 ) (0.12 ) Income Tax Provision Related to Trinidad Operations (3.71 ) — — Canadian Divestiture — — (3.46 ) Undistributed Foreign Earnings — — 4.94 Foreign Valuation Allowances — — 6.47 Foreign Oil and Gas Impairments — — (1.90 ) Other (0.62 ) (0.17 ) 0.03 Effective Income Tax Rate 29.59 % 34.63 % 41.64 % The effective tax rate of 30% in 2016 was lower than the prior year rate of 35% primarily due to the effects of recording additional Trinidad taxes resulting from a tax settlement reached during the year. 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 tax assets were as follows (in thousands): 2016 2015 2014 Beginning Balance $ 506,127 $ 463,018 $ 223,599 Increase (1) 37,221 146,602 392,729 Decrease (2) (12,667 ) (4,315 ) (1,424 ) Other (3) (147,460 ) (99,178 ) (151,886 ) Ending Balance $ 383,221 $ 506,127 $ 463,018 (1) Increase in valuation allowance related to the generation of tax net operating losses 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. The balance of unrecognized tax benefits at December 31, 2016 , was $36 million , of which $2 million may potentially have an earnings impact. EOG records interest and penalties related to unrecognized tax benefits to its income tax provision. Currently, $2 million of interest has been recognized in the Consolidated Statements of Income and Comprehensive Income. EOG does not anticipate that the amount of the unrecognized tax benefits will significantly change 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 (2012), United Kingdom (2015), Trinidad (2010) and China (2008). EOG's foreign subsidiaries' undistributed earnings of approximately $2 billion at December 31, 2016 , are no longer considered to be permanently reinvested outside the United States and, accordingly, EOG has cumulatively recorded $280 million of United States federal, foreign and state deferred income taxes. EOG changed its permanent reinvestment assertion in 2014. In 2016 , EOG's alternative minimum tax (AMT) credits were reduced by $21 million mostly as a result of carry-back claims and certain elections. Remaining AMT credits of $758 million , resulting from AMT paid in prior years, will be carried forward indefinitely until they are used to offset regular income taxes in future periods. The ability of EOG to utilize these AMT credit carryforwards to reduce federal income taxes may become subject to various limitations under the Internal Revenue Code. Such limitations may arise if certain ownership changes (as defined for income tax purposes) were to occur. As of December 31, 2016 , EOG had state income tax net operating losses (NOLs) being carried forward of approximately $1.6 billion , which, if unused, expire between 2017 and 2035. During 2016 , EOG's United Kingdom subsidiary incurred a tax NOL of approximately $38 million which, along with prior years' NOLs of $740 million , will be carried forward indefinitely. As described above, these NOLs have been evaluated for the likelihood of future utilization, and valuation allowances have been established for the portion of these deferred tax assets that do not meet the "more likely than not" threshold.

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2016
Employee Benefit Plans [Abstract]
Employee Benefit Plans	Employee Benefit Plans Stock-Based Compensation During 2016 , 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 performance stock, and grants made under the EOG Resources, Inc. Employee Stock Purchase Plan (ESPP). Stock-based compensation expense is calculated based upon the grant date estimated fair value of the awards, net of forfeitures, based upon EOG's historical employee turnover rate. Compensation expense is amortized over the shorter of the vesting period or the period from date of grant until the date the employee becomes eligible to retire without company approval. Stock-based compensation expense is included on the Consolidated Statements of Income and Comprehensive Income based upon the job functions of the employees receiving the grants. Compensation expense related to EOG's stock-based compensation plans for the years ended December 31, 2016 , 2015 and 2014 was as follows (in millions): 2016 2015 2014 Lease and Well $ 38 $ 44 $ 41 Gathering and Processing Costs 1 1 1 Exploration Costs 21 26 27 General and Administrative 68 60 76 Total $ 128 $ 131 $ 145 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. At December 31, 2016 , approximately 21.5 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 2016 , 2015 and 2014 , 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. EOG recognized, as an adjustment to APIC, federal income tax benefits of $29 million , $26 million and $99 million for 2016 , 2015 and 2014 , 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. Stock options and SARs granted vest on a graded vesting schedule up to four years from the date of grant based on the nature of the grants and as defined in individual grant agreements. 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 $57 million , $56 million and $62 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants for the years ended December 31, 2016 , 2015 and 2014 were as follows: Stock Options/SARs ESPP 2016 2015 2014 2016 2015 2014 Weighted Average Fair Value of Grants $ 25.78 $ 21.88 $ 30.75 $ 19.21 $ 21.21 $ 21.65 Expected Volatility 31.54 % 38.03 % 35.28 % 36.55 % 32.08 % 25.03 % Risk-Free Interest Rate 0.78 % 0.83 % 0.95 % 0.44 % 0.12 % 0.08 % Dividend Yield 0.76 % 0.85 % 0.61 % 0.82 % 0.73 % 0.46 % Expected Life 5.4 years 5.3 years 5.2 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, 2016 , 2015 and 2014 (stock options and SARs in thousands): 2016 2015 2014 Number Weighted Average Grant Price Number Weighted Average Grant Price Number Weighted Average Grant Price Outstanding at January 1 10,744 $ 67.98 10,493 $ 64.96 10,452 $ 54.43 Granted 1,855 94.82 2,037 69.99 2,146 101.55 Exercised (1) (2,376 ) 54.56 (1,518 ) 47.64 (1,718 ) 45.68 Forfeited (373 ) 87.38 (268 ) 80.31 (387 ) 68.95 Outstanding at December 31 9,850 75.53 10,744 67.98 10,493 64.96 Stock Options/SARs Exercisable at December 31 5,613 66.48 5,993 57.96 5,287 49.40 (1) The total intrinsic value of stock options/SARs exercised during the years 2016 , 2015 and 2014 was $84 million, $60 million and $95 million, respectively. The intrinsic value is based upon the difference between the market price of the Common Stock on the date of exercise and the grant price of the stock options/SARs. At December 31, 2016 , there were 9.5 million stock options/SARs vested or expected to vest with a weighted average grant price of $75.12 per share, an intrinsic value of $249 million and a weighted average remaining contractual life of 3.8 years. The following table summarizes certain information for the stock options and SARs outstanding and exercisable at December 31, 2016 (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 $ 55.99 1,906 1 $ 43.68 1,906 1 $ 43.68 56.00 to 69.99 2,922 4 64.12 1,654 3 60.09 70.00 to 94.99 1,526 3 84.62 1,072 3 84.49 95.00 to 99.99 1,794 7 95.10 23 3 97.31 100.00 to 116.99 1,702 4 102.02 958 4 102.00 9,850 4 75.53 $ 253,400 5,613 3 66.48 $ 195,186 (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, 2016 , unrecognized compensation expense related to non-vested stock option and SAR grants totaled $95 million . This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.8 years . At December 31, 2016 , approximately 356,000 shares of Common Stock remained available for issuance under the ESPP. The following table summarizes ESPP activities for the years ended December 31, 2016 , 2015 and 2014 (in thousands, except number of participants): 2016 2015 2014 Approximate Number of Participants 1,746 1,963 1,991 Shares Purchased 212 225 202 Aggregate Purchase Price $ 13,787 $ 15,045 $ 14,927 Restricted Stock and Restricted Stock Units. Employees may be granted restricted (non-vested) stock and/or restricted stock units without cost to them. The restricted stock and restricted stock units generally vest five years after the date of grant, except for certain bonus grants, and as defined in individual grant agreements. 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 $60 million , $69 million and $74 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. The following table sets forth the restricted stock and restricted stock unit transactions for the years ended December 31, 2016 , 2015 and 2014 (shares and units in thousands): 2016 2015 2014 Number of Shares and Units Weighted Average Grant Date Fair Value Number of Shares and Units Weighted Average Grant Date Fair Value Number of Shares and Units Weighted Average Grant Date Fair Value Outstanding at January 1 4,908 $ 70.35 5,394 $ 64.39 7,358 $ 49.54 Granted 853 88.01 1,044 77.94 1,132 98.72 Released (1) (1,465 ) 53.95 (1,331 ) 51.52 (2,761 ) 105.24 Forfeited (334 ) 77.29 (199 ) 74.56 (335 ) 62.55 Outstanding at December 31 (2) 3,962 79.63 4,908 70.35 5,394 64.39 (1) The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2016 , 2015 and 2014 was $124 million, $109 million and $291 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, 2016 and 2015 was approximately $401 million and $347 million, respectively. At December 31, 2016 , unrecognized compensation expense related to restricted stock and restricted stock units totaled $153 million . Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 2.5 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. Subject to the termination provisions set forth in the grant agreements and the applicable performance multiple, the grants of Performance Awards will generally "cliff" vest five years from the date of grant. The fair value of the Performance Awards is estimated using a Monte Carlo simulation. Stock-based compensation expense related to the Performance Awards totaled $11 million , $5 million and $9 million for the years ended December 31, 2016, 2015 and 2014, respectively. At December 31, 2015, 405,000 Performance Awards were outstanding. Upon completion of the Performance Period for the Performance Awards granted in 2012, a performance multiple of 200% was applied to the 2012 grants resulting in an additional grant of 142,556 Performance Awards in February 2016. During the twelve-month period ended December 31, 2016, a total of 131,750 Performance Awards were granted. A total of 134,016 Performance Awards were released during the twelve months ended December 31, 2016, with a total intrinsic value of $9.7 million , based upon the closing price of EOG's common stock on the release date. Upon the application of the performance multiple at the completion of the remaining Performance Periods, a minimum of 151,096 and a maximum of 939,484 Performance Awards could be outstanding. There were 545,290 Performance Awards outstanding as of December 31, 2016. The total intrinsic value of Performance Awards outstanding at December 31, 2016 was $55.1 million . Upon completion of the performance period for the Performance Awards granted in 2013, a performance multiple of 200% was applied to the 2013 grants resulting in an additional grant of 118,834 Performance Awards in February 2017. Weighted average fair values and valuation assumptions used to value performance unit and performance stock grants during the years ended December 31, 2016 , 2015 and 2014 were as follows: 2016 2015 2014 Weighted Average Fair Value of Grants $ 119.10 $ 80.64 $ 119.27 Expected Volatility 32.48 % 29.35 % 32.18 % Risk-Free Interest Rate 1.15 % 1.07 % 1.18 % 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 3.25 year zero-coupon risk-free interest rate derived from the Treasury Constant Maturities yield curve on the grant date. At December 31, 2016 , unrecognized compensation expense related to performance units totaled $10 million . Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 3.0 years . 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 $34 million , $36 million and $41 million for 2016 , 2015 and 2014 , 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 $5 million for 2016 , 2015 and 2014 , respectively. For the Trinidadian defined benefit pension plan, the benefit obligation, fair value of plan assets and accrued benefit cost totaled $8 million , $7 million and $0.3 million , respectively, at December 31, 2016 , and $9 million , $7 million and $0.2 million , respectively, at December 31, 2015 . In connection with the divestiture of substantially all of its Canadian assets in the fourth quarter of 2014, EOG has elected to terminate 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	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Letters of Credit and Guarantees. At December 31, 2016 and 2015 , respectively, EOG had standby letters of credit and guarantees outstanding totaling approximately $226 million and $272 million , primarily representing guarantees of payment or performance obligations on behalf of subsidiaries. As of February 20, 2017, there were no demands for payment under these guarantees. Minimum Commitments. At December 31, 2016 , 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, 2016 , were as follows (in thousands): Total Minimum Commitments 2017 $ 1,201,092 2018 934,037 2019 673,452 2020 460,178 2021 334,601 2022 and beyond 674,287 $ 4,277,647 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 $204 million , $229 million and $237 million for 2016 , 2015 and 2014 , 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

Net Income (Loss) Per Share	12 Months Ended
	Dec. 31, 2016
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, 2016 , 2015 and 2014 (in thousands, except per share data): 2016 2015 2014 Numerator for Basic and Diluted Earnings per Share - Net Income (Loss) $ (1,096,686 ) $ (4,524,515 ) $ 2,915,487 Denominator for Basic Earnings per Share - Weighted Average Shares 553,384 545,697 543,443 Potential Dilutive Common Shares - Stock Options/SARs — — 2,526 Restricted Stock/Units and Performance Units/Stock — — 2,570 Denominator for Diluted Earnings per Share - Adjusted Diluted Weighted Average Shares 553,384 545,697 548,539 Net Income (Loss) Per Share Basic $ (1.98 ) $ (8.29 ) $ 5.36 Diluted $ (1.98 ) $ (8.29 ) $ 5.32 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 10.3 million , 10.2 million and 0.7 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. For the years ended December 31, 2016 and 2015, respectively, 4.5 million and 5.3 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	12 Months Ended
	Dec. 31, 2015
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, 2016 , 2015 and 2014 (in thousands): 2016 2015 2014 Interest, Net of Capitalized Interest $ 252,030 $ 222,088 $ 197,383 Income Taxes, Net of Refunds Received $ (39,293 ) $ 41,108 $ 342,741 EOG's accrued capital expenditures at December 31, 2016, 2015 and 2014 were $388 million , $416 million and $972 million , respectively. 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). Non-cash investing activities for the year ended December 31, 2014 included non-cash additions of $5 million to EOG's oil and gas properties as a result of property exchanges.

Business Segment Information

Business Segment Information	12 Months Ended
	Dec. 31, 2016
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. As previously reported, during the fourth quarter of 2014, EOG completed the sale of substantially all of its Canadian operations (see Note 17). As a result, information relating to EOG's remaining Canadian operations has been included in the Other International segment and prior year amounts have been reclassified to conform to current year presentation. Financial information by reportable segment is presented below as of and for the years ended December 31, 2016 , 2015 and 2014 (in thousands): 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 Gains (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 (2) 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 (Loss) Income (1,192,338 ) 46,473 (79,416 ) (1,225,281 ) Interest Income 358 932 1,329 2,619 Other (Expense) Income (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 27,907,083 889,253 663,097 29,459,433 United States Trinidad Other International (1) Total 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 (3) 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 (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 25,347,134 886,826 736,510 26,970,470 2014 Crude Oil and Condensate $ 9,526,149 $ 29,604 $ 186,727 $ 9,742,480 Natural Gas Liquids 924,454 — 9,597 934,051 Natural Gas 1,321,175 483,071 112,140 1,916,386 Gains on Mark-to-Market Commodity Derivative Contracts 834,273 — — 834,273 Gathering, Processing and Marketing 4,040,024 6,064 228 4,046,316 Gains on Asset Dispositions, Net 96,339 — 411,251 507,590 Other, Net 49,950 37 4,257 54,244 Net Operating Revenues (4) 16,792,364 518,776 724,200 18,035,340 Depreciation, Depletion and Amortization 3,684,943 188,592 123,506 3,997,041 Operating Income (Loss) 5,074,911 277,471 (110,559 ) 5,241,823 Interest Income 849 253 1,137 2,239 Other Income (Expense) (14,953 ) 8,712 (41,048 ) (47,289 ) Net Interest Expense 269,166 — (67,708 ) 201,458 Income (Loss) Before Income Taxes 4,791,641 286,436 (82,762 ) 4,995,315 Income Tax Provision 1,837,185 98,559 144,084 2,079,828 Additions to Oil and Gas Properties, Excluding Dry Hole Costs 7,133,727 76,138 261,312 7,471,177 Total Property, Plant and Equipment, Net 28,391,741 382,719 398,184 29,172,644 Total Assets 32,867,310 865,674 1,025,615 34,758,599 (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 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 in the United States segment. (3) 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 in the United States segment. (4) EOG had sales activity with two significant purchasers in 2014, one totaling $4.0 billion and the other totaling $3.0 billion of consolidated Net Operating Revenues in the United States segment.

Risk Management Activities

Risk Management Activities	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk Management Activities	Risk Management Activities Commodity Price Risks. EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for crude oil 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 2016 , 2015 and 2014 , EOG elected not to designate any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounted for these financial commodity derivative contracts using the mark-to-market accounting method. Under this accounting method, changes in the fair value of outstanding financial instruments are recognized as gains or losses in the period of change and are recorded as Gains (Losses) on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income and Comprehensive Income. The related cash flow impact is reflected in Cash Flows from Operating Activities. During 2016 , 2015 and 2014 , EOG recognized net gains (losses) on the mark-to-market of financial commodity derivative contracts of $(100) million , $62 million and $834 million , respectively, which included cash received from (payments for) settlements of crude oil and natural gas derivative contracts of $(22) million , $730 million and $34 million , respectively. Commodity Derivative Contracts. Presented below is a comprehensive summary of EOG's crude oil price swap contracts for the year ended December 31, 2016, with notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl). Crude Oil Price Swap Contracts Volume (Bbld) Weighted Average Price ($/Bbl) 2016 April 12, 2016 through April 30, 2016 (closed) 90,000 $ 42.30 May 1, 2016 through June 30, 2016 (closed) 128,000 42.56 2017 January 1, 2017 through June 30, 2017 35,000 $ 50.04 EOG has entered into crude oil collar contracts, which establish ceiling and floor prices for the sale of notional volumes of crude oil as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the average NYMEX West Texas Intermediate crude oil price for the contract month (Index Price) in the event the Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Index Price in the event the Index Price is below the floor price. Presented below is a comprehensive summary of EOG's crude oil collar contracts for the year ended December 31, 2016, with notional volumes expressed in Bbld and prices expressed in $/Bbl. Crude Oil Collar Contracts Weighted Average Price ($/Bbl) Volume (Bbld) Ceiling Price Floor Price 2016 September 1, 2016 through December 31, 2016 (closed) 70,000 $ 54.25 $ 45.00 Presented below is a comprehensive summary of EOG's natural gas price swap contracts for the year ended December 31, 2016, 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) 2016 March 1, 2016 through August 31, 2016 (closed) 60,000 $ 2.49 2017 March 1, 2017 through November 30, 2017 30,000 $ 3.10 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, 2016, 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 2016 September 2016 (closed) 56,250 $ 3.46 — $ — October 1, 2016 through November 30, 2016 (closed) 106,250 3.48 — — 2017 March 1, 2017 through November 30, 2017 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, 2016, 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 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, 2016 and 2015 , 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 2016 2015 Asset Derivatives Crude oil and natural gas derivative contracts - Noncurrent portion Other Assets $ 1 $ — Liability Derivatives Crude oil and natural gas derivative contracts - Current portion Liabilities from Price Risk Management Activities $ 62 $ — 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, 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. At December 31, 2015 , 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 2016. In 2016 and 2015 , all natural gas from EOG's Trinidad operations was sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary, 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, 2016. EOG had no collateral posted and held no collateral at December 31, 2016 and 2015 . Substantially all of EOG's accounts receivable at December 31, 2016 and 2015 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, 2016 , credit losses incurred on receivables by EOG have been immaterial.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2016
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, 2016 . There were no such amounts outstanding at December 31, 2015. 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, 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) At December 31, 2016, $1 million is included in "Other Assets" on the Consolidated Balance Sheets. (2) At December 31, 2016, $62 million is included in "Current Liabilities - Liabilities from Price Risk Management Activities" 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 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. During 2015 , proved oil and gas properties; other property, plant and equipment; and other assets with a carrying amount of $9,154 million were written down to their fair value of $2,828 million , resulting in pretax impairment charges of $6,326 million , $4,141 million net of tax. Impairments in 2015 included domestic legacy natural gas assets and marginal liquids plays and the Conwy crude oil project in the East Irish Sea. 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, 2016 and 2015 , respectively, EOG had outstanding $6,990 million and $6,390 million aggregate principal amount of senior notes, which had estimated fair values of approximately $7,190 million and $6,524 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	12 Months Ended
	Dec. 31, 2016
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 2016, proved oil and gas properties; other property, plant and equipment; and other assets with a carrying amount of $667 million were written down to their fair value of $537 million , resulting in pretax impairment charges of $130 million . During 2015, proved oil and gas properties and other assets with a carrying amount of $9,154 million were written down to their fair value of $2,828 million , resulting in pretax impairment charges of $6,326 million , $4,141 million net of tax. Impairments in 2016 and 2015 included domestic legacy natural gas assets. In addition, impairments in 2015 included marginal liquids plays and the Conwy crude oil project in the East Irish Sea. Amortization and impairments of unproved oil and gas property costs, including amortization of capitalized interest, were $291 million , $288 million and $168 million during 2016, 2015 and 2014, respectively.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 (in thousands): 2016 2015 Carrying Amount at Beginning of Period $ 811,554 $ 752,718 Liabilities Incurred (1) 212,739 63,844 Liabilities Settled (2) (94,800 ) (17,415 ) Accretion 32,306 31,956 Revisions (38,286 ) (13,356 ) Foreign Currency Translations (10,587 ) (6,193 ) Carrying Amount at End of Period $ 912,926 $ 811,554 Current Portion $ 18,516 $ 7,651 Noncurrent Portion $ 894,410 $ 803,903 (1) Includes $164 million 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

Exploratory Well Costs	12 Months Ended
	Dec. 31, 2016
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, 2016 , 2015 and 2014 are presented below (in thousands): 2016 2015 2014 Balance at January 1 $ 8,955 $ 17,253 $ 9,211 Additions Pending the Determination of Proved Reserves 6,688 24,640 32,080 Reclassifications to Proved Properties (5,274 ) (26,659 ) (15,946 ) Costs Charged to Expense (1) (10,369 ) (6,279 ) (8,092 ) Balance at December 31 $ — $ 8,955 $ 17,253 (1) Includes capitalized exploratory well costs charged to either dry hole costs or impairments. At December 31, 2016 , 2015 and 2014 , all exploratory well costs had been capitalized for periods of less than one year.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Acquisitions and Divestitures	Acquisitions and Divestitures 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). Subject to the terms of the agreements, 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. Revenues and Operating Income of $71 million and $8 million , respectively, of the Yates Entities were included in EOG's Consolidated Statements of Income and Comprehensive Income beginning October 4, 2016. 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 and Comprehensive Income. 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. Certain data necessary to complete the purchase price allocation is preliminary, and includes, but is not limited to, the final valuations of oil and gas properties, the valuation of off-market transportation contracts and the calculation of deferred taxes based upon the underlying tax basis of assets acquired and liabilities assumed. EOG believes the estimates used are reasonable but are subject to change as additional information becomes available. The following table represents the preliminary allocation of the total purchase price of the Yates Entities (in thousands). Current Assets Cash and Cash Equivalents $ 70,411 Accounts Receivable, Net 83,540 Inventories 10,955 Other 10,640 Total 175,546 Property, Plant and Equipment Oil and Gas Properties (Successful Efforts Method) 3,850,100 Other Property, Plant and Equipment 16,586 Total Property, Plant and Equipment, Net 3,866,686 Other Assets 22,706 Total Assets $ 4,064,938 Current Liabilities Accounts Payable $ 126,988 Accrued Taxes Payable 23,520 Other 743 Total 151,251 Long-Term Debt 163,829 Asset Retirement Obligations 163,144 Off-Market Transportation Contracts 39,720 Other Liabilities 28,645 Deferred Income Taxes 1,104,581 Total Liabilities $ 1,651,170 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. These inputs required significant judgments, assumptions and estimates by management at the time of the valuation and are the most sensitive and may be subject to change. Other. 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. During 2014, EOG recognized a net gain on asset dispositions of $508 million and received proceeds of approximately $569 million primarily from the divestiture of all its assets in Manitoba and the majority of its assets in Alberta (collectively, the Canadian Sales) and from sales of producing properties and acreage in the Upper Gulf Coast region, the Rocky Mountain area and the Mid-Continent area. The Canadian Sales that closed on or about December 1, 2014, occurred in two separate transactions, an asset sale and the sale of the stock of certain of EOG's Canadian subsidiaries. As these two transactions represented a substantially complete liquidation of EOG's Canadian operations, approximately $383 million of cumulative translation adjustments previously recorded on the Consolidated Balance Sheets was reclassified to the Consolidated Statements of Income and Comprehensive Income. The Canadian Sales also resulted in the release of approximately $150 million of restricted cash related to future abandonment liabilities.

Oil and Gas Exploration and Pro

Oil and Gas Exploration and Production Industries Disclosures	12 Months Ended
	Dec. 31, 2016
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." During the fourth quarter of 2014, EOG completed the sale of substantially all of its Canadian operations. As a result, information relating to EOG's remaining Canadian operations has been included in the Other International segment and prior year amounts have been reclassified to conform to current year presentation. 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. 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, 2016 . 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 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, 2016 , 2015 and 2014 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 16 professionals, all of whom hold, at a minimum, bachelor's degrees in engineering, and five 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 30 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 and Chief Operating Officer; the Executive Vice Presidents, Exploration and Production; and the Executive Vice President and Chief Financial Officer, for approval. Opinions by D&M for the years ended December 31, 2016 , 2015 and 2014 covered producing areas containing 83%, 86% and 76%, 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. 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, 2017, 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 23.2 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, 2016 , 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, 2016 , and the changes in the net proved reserves for each of the three years in the period ended December 31, 2016 , 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, 2013 880,049 1,590 18,901 900,540 Revisions of previous estimates 28,301 99 (378 ) 28,022 Purchases in place 9,705 — — 9,705 Extensions, discoveries and other additions 319,540 — 14 319,554 Sales in place (4,967 ) — (7,656 ) (12,623 ) Production (102,946 ) (350 ) (2,152 ) (105,448 ) 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 Natural Gas Liquids (MBbl) (2) Net proved reserves at December 31, 2013 376,002 — 1,204 377,206 Revisions of previous estimates 27,450 — (7 ) 27,443 Purchases in place 1,812 — — 1,812 Extensions, discoveries and other additions 91,683 — — 91,683 Sales in place (956 ) — (823 ) (1,779 ) Production (29,061 ) — (236 ) (29,297 ) 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 United States Trinidad Other International (1) Total Natural Gas (Bcf) (3) Net proved reserves at December 31, 2013 4,398.7 520.7 125.4 5,044.8 Revisions of previous estimates 252.2 12.9 5.5 270.6 Purchases in place 17.1 — — 17.1 Extensions, discoveries and other additions 638.3 4.5 4.7 647.5 Sales in place (52.4 ) — (78.7 ) (131.1 ) Production (348.4 ) (132.5 ) (25.4 ) (506.3 ) 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 Oil Equivalents (MBoe) (2) Net proved reserves at December 31, 2013 1,989,166 88,364 41,013 2,118,543 Revisions of previous estimates 97,782 2,245 541 100,568 Purchases in place 14,367 — — 14,367 Extensions, discoveries and other additions 517,613 758 796 519,167 Sales in place (14,661 ) — (21,602 ) (36,263 ) Production (190,065 ) (22,430 ) (6,631 ) (219,126 ) 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 (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 2016, EOG added 209 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 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. During 2014, EOG added 519 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Eagle Ford, Permian Basin and the Rocky Mountain area. Approximately 79% of the 2014 reserve additions were crude oil and condensate and NGLs, and nearly 100% were in the United States. Sales in place of 36 MMBoe were primarily related to the disposition of certain producing natural gas assets in Canada, the Upper Gulf Coast and other producing basins in the United States. Positive revisions of previous estimates of 101 MMBoe for 2014 included a positive revision of 52 MMBoe primarily due to an increase in the average natural gas price used in the December 31, 2014 reserves estimation as compared to the price used in the prior year estimate. The primary plays affected were the Barnett Shale, the Uinta and Green River basins in the Rocky Mountain area and the Haynesville Shale play. Revisions other than price resulted primarily from improved recovery in the Eagle Ford and improved recoveries and reduced operating costs in the Permian Basin. United States Trinidad Other International (1) Total NET PROVED DEVELOPED RESERVES Crude Oil (MBbl) December 31, 2013 382,517 1,505 7,034 391,056 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 Natural Gas Liquids (MBbl) December 31, 2013 199,964 — 896 200,860 December 31, 2014 264,611 — 138 264,749 December 31, 2015 205,898 — — 205,898 December 31, 2016 230,219 — — 230,219 Natural Gas (Bcf) December 31, 2013 2,597.3 494.6 121.5 3,213.4 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 Oil Equivalents (MBoe) December 31, 2013 1,015,359 83,933 28,184 1,127,476 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 NET PROVED UNDEVELOPED RESERVES Crude Oil (MBbl) December 31, 2013 497,532 85 11,867 509,484 December 31, 2014 635,988 — 8,614 644,602 December 31, 2015 643,790 — 8,604 652,394 December 31, 2016 660,960 — — 660,960 Natural Gas Liquids (MBbl) December 31, 2013 176,038 — 308 176,346 December 31, 2014 202,319 — — 202,319 December 31, 2015 176,977 — — 176,977 December 31, 2016 186,147 — — 186,147 Natural Gas (Bcf) December 31, 2013 1,801.4 26.1 3.9 1,831.4 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 Oil Equivalents (MBoe) December 31, 2013 973,807 4,431 12,829 991,067 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 (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 2016 , 2015 and 2014 (in MBoe): 2016 2015 2014 Balance at January 1 1,045,640 1,149,309 991,067 Extensions and Discoveries 138,101 205,152 403,713 Revisions 64,413 (241,973 ) (79,630 ) Acquisition of Reserves — 54,458 4,239 Sale of Reserves (45,917 ) — (10,176 ) Conversion to Proved Developed Reserves (149,210 ) (121,306 ) (159,904 ) Balance at December 31 1,053,027 1,045,640 1,149,309 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 (see discussion of technology employed on pages F-35 and F-36 of this Annual Report on Form 10-K), 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. For the twelve-month period ended December 31, 2014, total PUDs increased by 158 MMBoe to 1,149 MMBoe. EOG added approximately 50 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 354 MMBoe. The PUD additions were primarily in the Eagle Ford and Permian Basin, and 80% of the additions were crude oil and condensate and NGLs. During 2014, EOG drilled and transferred 160 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,655 million . Revisions of PUDs totaled negative 80 MMBoe, primarily due to removal of certain natural gas PUDs. During 2014, EOG sold 10 MMBoe and acquired 4 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, 2016 and 2015 : 2016 2015 Proved properties $ 45,751,965 $ 49,623,518 Unproved properties 3,840,126 989,723 Total 49,592,091 50,613,241 Accumulated depreciation, depletion and amortization (26,247,062 ) (28,877,593 ) Net capitalized costs $ 23,345,029 $ 21,735,648 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, 2016 , 2015 and 2014 : United States Trinidad Other International (1) Total 2016 Acquisition Costs of Properties Unproved (2) $ 3,216,598 $ — $ 36 $ 3,216,634 Proved (3) 749,023 — — 749,023 Subtotal 3,965,621 — 36 3,965,657 Exploration Costs 156,295 2,695 6,761 165,751 Development Costs (4) 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 (5) 3,847,813 102,715 110,589 4,061,117 Total $ 4,669,045 $ 125,552 $ 133,686 $ 4,928,283 2014 Acquisition Costs of Properties Unproved $ 365,915 $ — $ 4,499 $ 370,414 Proved 138,772 — 329 139,101 Subtotal 504,687 — 4,828 509,515 Exploration Costs 332,703 2,794 60,476 395,973 Development Costs (6) 6,638,192 89,555 271,534 6,999,281 Total $ 7,475,582 $ 92,349 $ 336,838 $ 7,904,769 (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 $3,102 million related to the Yates transaction. (3) Includes non-cash proved property acquisition costs of $732 million related to the Yates transaction. (4) 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. (5) 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. (6) Includes Asset Retirement Costs of $149 million , $14 million and $33 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, 2016 , 2015 and 2014 : United States Trinidad Other International (2) Total 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 (Benefit) (2,128,183 ) 43,739 (2,111 ) (2,086,555 ) Results of Operations $ (3,747,220 ) $ 145,573 $ (259,310 ) $ (3,860,957 ) 2014 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues $ 11,771,777 $ 512,675 $ 308,465 $ 12,592,917 Other 49,950 37 4,257 54,244 Total 11,821,727 512,712 312,722 12,647,161 Exploration Costs 162,434 2,185 19,769 184,388 Dry Hole Costs 25,408 — 23,082 48,490 Transportation Costs 957,522 617 14,037 972,176 Production Costs 1,940,074 38,301 171,652 2,150,027 Impairments 331,792 — 411,783 743,575 Depreciation, Depletion and Amortization 3,571,313 188,250 122,157 3,881,720 Income (Loss) Before Income Taxes 4,833,184 283,359 (449,758 ) 4,666,785 Income Tax Provision 1,722,914 74,588 23,602 1,821,104 Results of Operations $ 3,110,270 $ 208,771 $ (473,360 ) $ 2,845,681 (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, 2016 . (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, 2016 , 2015 and 2014 : United States Trinidad Other International (1) Composite 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 Year Ended December 31, 2014 $ 6.44 $ 1.34 $ 24.60 $ 6.46 (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 2016 , 2015 and 2014 . The following information may be useful for certain comparative purposes, but should not be solely relied upon in evaluating EOG or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of EOG. The future cash flows presented below are based on sales prices, cost rates and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil, NGL and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used. Management does not rely upon the following information in making inves

Unaudited Quarterly Financial I

Unaudited Quarterly Financial Information	12 Months Ended
	Dec. 31, 2016
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 2016 Net Operating Revenues $ 1,354,349 $ 1,775,740 $ 2,118,504 $ 2,402,039 Operating 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 Loss $ (471,776 ) $ (292,558 ) $ (190,000 ) $ (142,352 ) Net Loss Per Share (1) 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 2015 Net Operating Revenues $ 2,318,538 $ 2,469,701 $ 2,172,428 $ 1,796,761 Operating Income (Loss) $ (172,995 ) $ 39,626 $ (6,222,957 ) $ (329,753 ) Loss Before Income Taxes $ (236,331 ) $ (11,478 ) $ (6,274,921 ) $ (398,826 ) Income Tax Benefit (66,583 ) (16,746 ) (2,199,182 ) (114,530 ) Net Income (Loss) $ (169,748 ) $ 5,268 $ (4,075,739 ) $ (284,296 ) Net Income (Loss) Per Share (1) Basic $ (0.31 ) $ 0.01 $ (7.47 ) $ (0.52 ) Diluted $ (0.31 ) $ 0.01 $ (7.47 ) $ (0.52 ) Average Number of Common Shares Basic 544,998 545,504 545,920 546,432 Diluted 544,998 549,683 545,920 546,432 (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.

Summary of Significant Accoun27

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
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. 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 cost 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.
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, 2016, EOG elected not to designate any of its financial commodity derivative instruments as accounting hedges and, accordingly, changes in the fair value of these outstanding derivative instruments are recognized as gains or losses in the period of change. The gains or losses are recorded as Gains (Losses) on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income and Comprehensive Income. The related cash flow impact of settled contracts is reflected as cash flows from operating activities. EOG was party to a foreign currency swap transaction and an interest rate swap transaction, both of which were accounted for using the hedge accounting method. EOG employs net presentation of derivative assets and liabilities for financial reporting purposes when such assets and liabilities are with the same counterparty and subject to a master netting arrangement. See Note 12.
Income Taxes	Income Taxes. Income taxes are accounted for using the asset and liability approach. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. EOG assesses the realizability of deferred tax assets and recognizes valuation allowances as appropriate (see Note 6).
Foreign Currency Translation	Foreign Currency Translation. The United States dollar is the functional currency for all of EOG's consolidated subsidiaries except for its Canadian subsidiaries, for which the functional currency is the Canadian dollar, and its United Kingdom subsidiary, 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 Loss on the Consolidated Balance Sheets. Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period. See Notes 4 and 17.
Net Income (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 January 2017, the FASB issued Accounting Standards Update (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 and early adoption is permitted. EOG is evaluating ASU 2017-01 to determine the impact on its consolidated financial statements and related disclosures. 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. Early adoption is permitted. EOG does not intend to early adopt ASU 2016-15. EOG does not expect the adoption of ASU 2016-15 to have a material impact on its consolidated financial statements and related disclosures. In March 2016, the FASB issued 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. ASU 2016-09 is effective for interim and annual periods beginning after December 15, 2016, and early application is permitted. EOG will adopt ASU 2016-09 effective January 1, 2017. There will be no impact to retained earnings with respect to excess tax benefits. EOG will begin recognizing all excess benefits and tax deficiencies as income tax expense or benefit as discrete events. The treatment of forfeitures will not change as EOG is electing to continue the current process of estimating the number of forfeitures. As such, this will have no cumulative effect on retained earnings. EOG will elect to present changes to the cash flow statement on a prospective transition method. 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 reviewing the provisions of ASU 2016-02 to determine the impact on its consolidated financial statements and related disclosures. In November 2015, the FASB issued 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. ASU 2015-17 is effective for financial statements issued for interim and annual periods beginning after December 15, 2016, and early application is permitted. EOG will adopt ASU 2015-17 effective January 1, 2017, on a retrospective basis, resulting in a reclassification of current deferred taxes to noncurrent on the Consolidated Balance Sheets, which will increase noncurrent deferred tax assets $169 million with no impact on noncurrent deferred tax liabilities. Effective January 1, 2016, EOG adopted the provisions of ASU 2015-03, "Interest - Computation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03). ASU 2015-03 requires that debt issuance costs be presented in the balance sheet as a direct reduction from the related debt liability rather than as an asset. In connection with the adoption of ASU 2015-03, EOG restated its December 31, 2015 Consolidated Balance Sheet to reclassify $4.8 million of unamortized debt issuance costs from "Other Assets" to "Long-Term Debt." Debt issuance costs related to EOG's senior unsecured revolving credit facility remain classified as "Other Assets." In May 2014, the FASB issued ASU 2014-09, "Revenue From Contracts With Customers" (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, and early adoption is permitted. 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 ASC, including guidance related to the use of the "entitlements" method of revenue recognition. EOG does not intend to early-adopt ASU 2014-09. EOG will be required to change from the entitlements method of accounting to the sales method of accounting and does not anticipate the impact will be material to the Consolidated Statements of Income and Comprehensive Income. EOG is continuing to evaluate the remaining provisions of ASU 2014-09 and has not determined the full impact on its consolidated financial statements and related disclosures.

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt at December 31, 2016 and 2015 consisted of the following (in thousands): 2016 2015 Commercial Paper $ — $ 259,718 2.500% Senior Notes due 2016 — 400,000 5.875% Senior Notes due 2017 600,000 600,000 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 — 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 — Long-Term Debt 6,990,000 6,649,718 Capital Lease Obligation 38,710 45,064 Less: Current Portion of Long-Term Debt 6,579 6,579 Unamortized Debt Discount 36,915 34,518 Debt Issuance Costs 5,437 4,774 Total Long-Term Debt $ 6,979,779 $ 6,648,911

Stockholder's Equity (Tables)

Stockholder's Equity (Tables)	12 Months Ended
	Dec. 31, 2016
Stockholders' Equity Note [Abstract]
Common stock activity	The following summarizes Common Stock activity for each of the years ended December 31, 2014 , 2015 and 2016 (in thousands): Common Shares Issued Treasury Outstanding Balance at December 31, 2013 546,378 (206 ) 546,172 Common Stock Issued Under Stock-Based Compensation Plans 2,448 — 2,448 Treasury Stock Purchased (1) — (1,209 ) (1,209 ) Common Stock Issued Under Employee Stock Purchase Plan 202 — 202 Treasury Stock Issued Under Stock-Based Compensation Plans — 682 682 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 (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) Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2016
Accumulated Other Comprehensive Income [Abstract]
Accumulated Other Comprehensive Income (Loss)	The components of Accumulated Other Comprehensive Income (Loss) at December 31, 2016 and 2015 consisted of the following (in thousands): Foreign Currency Translation Adjustment Other Total December 31, 2014 $ (20,021 ) $ (3,035 ) $ (23,056 ) Other comprehensive loss before reclassifications (11,517 ) (129 ) (11,646 ) Amounts reclassified out of other comprehensive income (loss) — 1,572 (1) 1,572 Tax effects — (208 ) (208 ) Other comprehensive income (loss) (11,517 ) 1,235 (10,282 ) December 31, 2015 (31,538 ) (1,800 ) (33,338 ) Other comprehensive income before reclassifications 12,097 2,901 14,998 Tax effects — (670 ) (670 ) Other comprehensive income 12,097 2,231 14,328 December 31, 2016 $ (19,441 ) $ 431 $ (19,010 ) (1) Reclassified to Net Income (Loss) - General and Administrative. Related to certain EOG pension plans. See Note 7.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Deferred Income Tax Liabilities, Net	The principal components of EOG's net deferred income tax liabilities at December 31, 2016 and 2015 were as follows (in thousands): 2016 2015 Current Deferred Income Tax Assets (Liabilities) Commodity Hedging Contracts $ 22,206 $ — Deferred Compensation Plans 43,984 38,559 Alternative Minimum Tax Credit Carryforward 84,426 93,316 Foreign Net Operating Loss 37,251 47,786 Foreign Valuation Allowance (28,097 ) (35,536 ) Accrued Expenses and Liabilities 13,754 — Other (4,137 ) 3,687 Total Net Current Deferred Income Tax Assets $ 169,387 $ 147,812 Noncurrent Deferred Income Tax Assets (Liabilities) Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization $ (39,852 ) $ (57,569 ) Foreign Net Operating Loss 314,899 443,010 Foreign Valuation Allowances (268,499 ) (380,104 ) Foreign Other 438 1,506 Total Net Noncurrent Deferred Income Tax Assets $ 6,986 $ 6,843 Noncurrent Deferred Income Tax (Assets) Liabilities Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization $ 5,899,533 $ 5,299,817 Non-Producing Leasehold Costs (64,898 ) (53,026 ) Seismic Costs Capitalized for Tax (161,920 ) (162,240 ) Equity Awards (139,787 ) (140,663 ) Capitalized Interest 86,504 98,242 Alternative Minimum Tax Credit Carryforward (673,205 ) (685,189 ) Undistributed Foreign Earnings 280,099 258,403 Other (37,686 ) (27,442 ) Total Net Noncurrent Deferred Income Tax Liabilities $ 5,188,640 $ 4,587,902 Total Net Deferred Income Tax Liabilities $ 5,012,267 $ 4,433,247
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): 2016 2015 2014 United States $ (1,520,573 ) $ (6,840,119 ) $ 5,161,232 Foreign (36,932 ) (81,437 ) (165,917 ) Total $ (1,557,505 ) $ (6,921,556 ) $ 4,995,315
Components of Income Tax Provision (Benefit)	The principal components of EOG's Income Tax Provision (Benefit) for the years indicated below were as follows (in thousands): 2016 2015 2014 Current: Federal $ 11,567 $ 21,719 $ 269,326 State (8,369 ) 9,404 22,835 Foreign 51,189 54,143 82,721 Total 54,387 85,266 374,882 Deferred: Federal (532,979 ) (2,362,926 ) 1,608,706 State 4,876 (127,444 ) 29,056 Foreign 12,897 8,063 67,184 Total (515,206 ) (2,482,307 ) 1,704,946 Income Tax Provision (Benefit) $ (460,819 ) $ (2,397,041 ) $ 2,079,828
Tax Rate Reconciliation	The differences between taxes computed at the United States federal statutory tax rate and EOG's effective rate were as follows: 2016 2015 2014 Statutory Federal Income Tax Rate 35.00 % 35.00 % 35.00 % State Income Tax, Net of Federal Benefit 0.15 1.11 0.68 Income Tax Provision Related to Foreign Operations (1.23 ) (1.31 ) (0.12 ) Income Tax Provision Related to Trinidad Operations (3.71 ) — — Canadian Divestiture — — (3.46 ) Undistributed Foreign Earnings — — 4.94 Foreign Valuation Allowances — — 6.47 Foreign Oil and Gas Impairments — — (1.90 ) Other (0.62 ) (0.17 ) 0.03 Effective Income Tax Rate 29.59 % 34.63 % 41.64 %
Summary of Valuation Allowance	The principal components of EOG's rollforward of valuation allowances for deferred tax assets were as follows (in thousands): 2016 2015 2014 Beginning Balance $ 506,127 $ 463,018 $ 223,599 Increase (1) 37,221 146,602 392,729 Decrease (2) (12,667 ) (4,315 ) (1,424 ) Other (3) (147,460 ) (99,178 ) (151,886 ) Ending Balance $ 383,221 $ 506,127 $ 463,018 (1) Increase in valuation allowance related to the generation of tax net operating losses 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, 2016
Employee Benefit Plans [Abstract]
Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs	Stock-based compensation expense is included on the Consolidated Statements of Income and Comprehensive Income based upon the job functions of the employees receiving the grants. Compensation expense related to EOG's stock-based compensation plans for the years ended December 31, 2016 , 2015 and 2014 was as follows (in millions): 2016 2015 2014 Lease and Well $ 38 $ 44 $ 41 Gathering and Processing Costs 1 1 1 Exploration Costs 21 26 27 General and Administrative 68 60 76 Total $ 128 $ 131 $ 145
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, 2016 , 2015 and 2014 were as follows: Stock Options/SARs ESPP 2016 2015 2014 2016 2015 2014 Weighted Average Fair Value of Grants $ 25.78 $ 21.88 $ 30.75 $ 19.21 $ 21.21 $ 21.65 Expected Volatility 31.54 % 38.03 % 35.28 % 36.55 % 32.08 % 25.03 % Risk-Free Interest Rate 0.78 % 0.83 % 0.95 % 0.44 % 0.12 % 0.08 % Dividend Yield 0.76 % 0.85 % 0.61 % 0.82 % 0.73 % 0.46 % Expected Life 5.4 years 5.3 years 5.2 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, 2016 , 2015 and 2014 (stock options and SARs in thousands): 2016 2015 2014 Number Weighted Average Grant Price Number Weighted Average Grant Price Number Weighted Average Grant Price Outstanding at January 1 10,744 $ 67.98 10,493 $ 64.96 10,452 $ 54.43 Granted 1,855 94.82 2,037 69.99 2,146 101.55 Exercised (1) (2,376 ) 54.56 (1,518 ) 47.64 (1,718 ) 45.68 Forfeited (373 ) 87.38 (268 ) 80.31 (387 ) 68.95 Outstanding at December 31 9,850 75.53 10,744 67.98 10,493 64.96 Stock Options/SARs Exercisable at December 31 5,613 66.48 5,993 57.96 5,287 49.40 (1) The total intrinsic value of stock options/SARs exercised during the years 2016 , 2015 and 2014 was $84 million, $60 million and $95 million, respectively. The intrinsic value is based upon the difference between the market price of the Common Stock on the date of exercise and the grant price of the stock options/SARs.
Stock Options and SARs Outstanding and Exercisable	The following table summarizes certain information for the stock options and SARs outstanding and exercisable at December 31, 2016 (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 $ 55.99 1,906 1 $ 43.68 1,906 1 $ 43.68 56.00 to 69.99 2,922 4 64.12 1,654 3 60.09 70.00 to 94.99 1,526 3 84.62 1,072 3 84.49 95.00 to 99.99 1,794 7 95.10 23 3 97.31 100.00 to 116.99 1,702 4 102.02 958 4 102.00 9,850 4 75.53 $ 253,400 5,613 3 66.48 $ 195,186 (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	At December 31, 2016 , approximately 356,000 shares of Common Stock remained available for issuance under the ESPP. The following table summarizes ESPP activities for the years ended December 31, 2016 , 2015 and 2014 (in thousands, except number of participants): 2016 2015 2014 Approximate Number of Participants 1,746 1,963 1,991 Shares Purchased 212 225 202 Aggregate Purchase Price $ 13,787 $ 15,045 $ 14,927
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, 2016 , 2015 and 2014 (shares and units in thousands): 2016 2015 2014 Number of Shares and Units Weighted Average Grant Date Fair Value Number of Shares and Units Weighted Average Grant Date Fair Value Number of Shares and Units Weighted Average Grant Date Fair Value Outstanding at January 1 4,908 $ 70.35 5,394 $ 64.39 7,358 $ 49.54 Granted 853 88.01 1,044 77.94 1,132 98.72 Released (1) (1,465 ) 53.95 (1,331 ) 51.52 (2,761 ) 105.24 Forfeited (334 ) 77.29 (199 ) 74.56 (335 ) 62.55 Outstanding at December 31 (2) 3,962 79.63 4,908 70.35 5,394 64.39 (1) The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2016 , 2015 and 2014 was $124 million, $109 million and $291 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, 2016 and 2015 was approximately $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 unit and performance stock grants during the years ended December 31, 2016 , 2015 and 2014 were as follows: 2016 2015 2014 Weighted Average Fair Value of Grants $ 119.10 $ 80.64 $ 119.27 Expected Volatility 32.48 % 29.35 % 32.18 % Risk-Free Interest Rate 1.15 % 1.07 % 1.18 %

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Minimum commitments for unrecorded unconditional purchase obligations	At December 31, 2016 , 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, 2016 , were as follows (in thousands): Total Minimum Commitments 2017 $ 1,201,092 2018 934,037 2019 673,452 2020 460,178 2021 334,601 2022 and beyond 674,287 $ 4,277,647

Net Income (Loss) Per Share (Ta

Net Income (Loss) Per Share (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 , 2015 and 2014 (in thousands, except per share data): 2016 2015 2014 Numerator for Basic and Diluted Earnings per Share - Net Income (Loss) $ (1,096,686 ) $ (4,524,515 ) $ 2,915,487 Denominator for Basic Earnings per Share - Weighted Average Shares 553,384 545,697 543,443 Potential Dilutive Common Shares - Stock Options/SARs — — 2,526 Restricted Stock/Units and Performance Units/Stock — — 2,570 Denominator for Diluted Earnings per Share - Adjusted Diluted Weighted Average Shares 553,384 545,697 548,539 Net Income (Loss) Per Share Basic $ (1.98 ) $ (8.29 ) $ 5.36 Diluted $ (1.98 ) $ (8.29 ) $ 5.32

Supplemental Cash Flow Inform35

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 , 2015 and 2014 (in thousands): 2016 2015 2014 Interest, Net of Capitalized Interest $ 252,030 $ 222,088 $ 197,383 Income Taxes, Net of Refunds Received $ (39,293 ) $ 41,108 $ 342,741

Business Segment Information (T

Business Segment Information (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 , 2015 and 2014 (in thousands): 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 Gains (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 (2) 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 (Loss) Income (1,192,338 ) 46,473 (79,416 ) (1,225,281 ) Interest Income 358 932 1,329 2,619 Other (Expense) Income (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 27,907,083 889,253 663,097 29,459,433 United States Trinidad Other International (1) Total 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 (3) 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 (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 25,347,134 886,826 736,510 26,970,470 2014 Crude Oil and Condensate $ 9,526,149 $ 29,604 $ 186,727 $ 9,742,480 Natural Gas Liquids 924,454 — 9,597 934,051 Natural Gas 1,321,175 483,071 112,140 1,916,386 Gains on Mark-to-Market Commodity Derivative Contracts 834,273 — — 834,273 Gathering, Processing and Marketing 4,040,024 6,064 228 4,046,316 Gains on Asset Dispositions, Net 96,339 — 411,251 507,590 Other, Net 49,950 37 4,257 54,244 Net Operating Revenues (4) 16,792,364 518,776 724,200 18,035,340 Depreciation, Depletion and Amortization 3,684,943 188,592 123,506 3,997,041 Operating Income (Loss) 5,074,911 277,471 (110,559 ) 5,241,823 Interest Income 849 253 1,137 2,239 Other Income (Expense) (14,953 ) 8,712 (41,048 ) (47,289 ) Net Interest Expense 269,166 — (67,708 ) 201,458 Income (Loss) Before Income Taxes 4,791,641 286,436 (82,762 ) 4,995,315 Income Tax Provision 1,837,185 98,559 144,084 2,079,828 Additions to Oil and Gas Properties, Excluding Dry Hole Costs 7,133,727 76,138 261,312 7,471,177 Total Property, Plant and Equipment, Net 28,391,741 382,719 398,184 29,172,644 Total Assets 32,867,310 865,674 1,025,615 34,758,599 (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 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 in the United States segment. (3) 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 in the United States segment. (4) EOG had sales activity with two significant purchasers in 2014, one totaling $4.0 billion and the other totaling $3.0 billion of consolidated Net Operating Revenues in the United States segment.

Risk Management Activities (Tab

Risk Management Activities (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity Derivative Contracts - Crude Oil Price Swaps	Presented below is a comprehensive summary of EOG's crude oil price swap contracts for the year ended December 31, 2016, with notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl). Crude Oil Price Swap Contracts Volume (Bbld) Weighted Average Price ($/Bbl) 2016 April 12, 2016 through April 30, 2016 (closed) 90,000 $ 42.30 May 1, 2016 through June 30, 2016 (closed) 128,000 42.56 2017 January 1, 2017 through June 30, 2017 35,000 $ 50.04
Commodity Derivative Contracts - Crude Oil Collars	Presented below is a comprehensive summary of EOG's crude oil collar contracts for the year ended December 31, 2016, with notional volumes expressed in Bbld and prices expressed in $/Bbl. Crude Oil Collar Contracts Weighted Average Price ($/Bbl) Volume (Bbld) Ceiling Price Floor Price 2016 September 1, 2016 through December 31, 2016 (closed) 70,000 $ 54.25 $ 45.00
Commodity Derivative Contracts - Natural Gas Price Swaps	Presented below is a comprehensive summary of EOG's natural gas price swap contracts for the year ended December 31, 2016, 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) 2016 March 1, 2016 through August 31, 2016 (closed) 60,000 $ 2.49 2017 March 1, 2017 through November 30, 2017 30,000 $ 3.10
Commodity Derivative Contracts - Natural Gas Options	Presented below is a comprehensive summary of EOG's natural gas call and put option contracts for the year ended December 31, 2016, 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 2016 September 2016 (closed) 56,250 $ 3.46 — $ — October 1, 2016 through November 30, 2016 (closed) 106,250 3.48 — — 2017 March 1, 2017 through November 30, 2017 213,750 $ 3.44 171,000 $ 2.92 2018 March 1, 2018 through November 30, 2018 120,000 $ 3.38 96,000 $ 2.94
Commodity Derivative Contracts - Natural Gas Collars	Presented below is a comprehensive summary of EOG's natural gas collar contracts for the year ended December 31, 2016, 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 80,000 $ 3.69 $ 3.20
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, 2016 and 2015 , 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 2016 2015 Asset Derivatives Crude oil and natural gas derivative contracts - Noncurrent portion Other Assets $ 1 $ — Liability Derivatives Crude oil and natural gas derivative contracts - Current portion Liabilities from Price Risk Management Activities $ 62 $ —

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 . There were no such amounts outstanding at December 31, 2015. 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, 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) At December 31, 2016, $1 million is included in "Other Assets" on the Consolidated Balance Sheets. (2) At December 31, 2016, $62 million is included in "Current Liabilities - Liabilities from Price Risk Management Activities" on the Consolidated Balance Sheets.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 (in thousands): 2016 2015 Carrying Amount at Beginning of Period $ 811,554 $ 752,718 Liabilities Incurred (1) 212,739 63,844 Liabilities Settled (2) (94,800 ) (17,415 ) Accretion 32,306 31,956 Revisions (38,286 ) (13,356 ) Foreign Currency Translations (10,587 ) (6,193 ) Carrying Amount at End of Period $ 912,926 $ 811,554 Current Portion $ 18,516 $ 7,651 Noncurrent Portion $ 894,410 $ 803,903 (1) Includes $164 million 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, 2016
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, 2016 , 2015 and 2014 are presented below (in thousands): 2016 2015 2014 Balance at January 1 $ 8,955 $ 17,253 $ 9,211 Additions Pending the Determination of Proved Reserves 6,688 24,640 32,080 Reclassifications to Proved Properties (5,274 ) (26,659 ) (15,946 ) Costs Charged to Expense (1) (10,369 ) (6,279 ) (8,092 ) Balance at December 31 $ — $ 8,955 $ 17,253 (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, 2016
Acquisitions and Divestitures [Abstract]
Preliminary Allocation of Total Purchase Price	The following table represents the preliminary allocation of the total purchase price of the Yates Entities (in thousands). Current Assets Cash and Cash Equivalents $ 70,411 Accounts Receivable, Net 83,540 Inventories 10,955 Other 10,640 Total 175,546 Property, Plant and Equipment Oil and Gas Properties (Successful Efforts Method) 3,850,100 Other Property, Plant and Equipment 16,586 Total Property, Plant and Equipment, Net 3,866,686 Other Assets 22,706 Total Assets $ 4,064,938 Current Liabilities Accounts Payable $ 126,988 Accrued Taxes Payable 23,520 Other 743 Total 151,251 Long-Term Debt 163,829 Asset Retirement Obligations 163,144 Off-Market Transportation Contracts 39,720 Other Liabilities 28,645 Deferred Income Taxes 1,104,581 Total Liabilities $ 1,651,170 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, 2016
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, 2016 , and the changes in the net proved reserves for each of the three years in the period ended December 31, 2016 , 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, 2013 880,049 1,590 18,901 900,540 Revisions of previous estimates 28,301 99 (378 ) 28,022 Purchases in place 9,705 — — 9,705 Extensions, discoveries and other additions 319,540 — 14 319,554 Sales in place (4,967 ) — (7,656 ) (12,623 ) Production (102,946 ) (350 ) (2,152 ) (105,448 ) 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 Natural Gas Liquids (MBbl) (2) Net proved reserves at December 31, 2013 376,002 — 1,204 377,206 Revisions of previous estimates 27,450 — (7 ) 27,443 Purchases in place 1,812 — — 1,812 Extensions, discoveries and other additions 91,683 — — 91,683 Sales in place (956 ) — (823 ) (1,779 ) Production (29,061 ) — (236 ) (29,297 ) 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 United States Trinidad Other International (1) Total Natural Gas (Bcf) (3) Net proved reserves at December 31, 2013 4,398.7 520.7 125.4 5,044.8 Revisions of previous estimates 252.2 12.9 5.5 270.6 Purchases in place 17.1 — — 17.1 Extensions, discoveries and other additions 638.3 4.5 4.7 647.5 Sales in place (52.4 ) — (78.7 ) (131.1 ) Production (348.4 ) (132.5 ) (25.4 ) (506.3 ) 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 Oil Equivalents (MBoe) (2) Net proved reserves at December 31, 2013 1,989,166 88,364 41,013 2,118,543 Revisions of previous estimates 97,782 2,245 541 100,568 Purchases in place 14,367 — — 14,367 Extensions, discoveries and other additions 517,613 758 796 519,167 Sales in place (14,661 ) — (21,602 ) (36,263 ) Production (190,065 ) (22,430 ) (6,631 ) (219,126 ) 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 (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, 2013 382,517 1,505 7,034 391,056 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 Natural Gas Liquids (MBbl) December 31, 2013 199,964 — 896 200,860 December 31, 2014 264,611 — 138 264,749 December 31, 2015 205,898 — — 205,898 December 31, 2016 230,219 — — 230,219 Natural Gas (Bcf) December 31, 2013 2,597.3 494.6 121.5 3,213.4 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 Oil Equivalents (MBoe) December 31, 2013 1,015,359 83,933 28,184 1,127,476 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 NET PROVED UNDEVELOPED RESERVES Crude Oil (MBbl) December 31, 2013 497,532 85 11,867 509,484 December 31, 2014 635,988 — 8,614 644,602 December 31, 2015 643,790 — 8,604 652,394 December 31, 2016 660,960 — — 660,960 Natural Gas Liquids (MBbl) December 31, 2013 176,038 — 308 176,346 December 31, 2014 202,319 — — 202,319 December 31, 2015 176,977 — — 176,977 December 31, 2016 186,147 — — 186,147 Natural Gas (Bcf) December 31, 2013 1,801.4 26.1 3.9 1,831.4 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 Oil Equivalents (MBoe) December 31, 2013 973,807 4,431 12,829 991,067 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 (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 2016 , 2015 and 2014 (in MBoe): 2016 2015 2014 Balance at January 1 1,045,640 1,149,309 991,067 Extensions and Discoveries 138,101 205,152 403,713 Revisions 64,413 (241,973 ) (79,630 ) Acquisition of Reserves — 54,458 4,239 Sale of Reserves (45,917 ) — (10,176 ) Conversion to Proved Developed Reserves (149,210 ) (121,306 ) (159,904 ) Balance at December 31 1,053,027 1,045,640 1,149,309
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, 2016 and 2015 : 2016 2015 Proved properties $ 45,751,965 $ 49,623,518 Unproved properties 3,840,126 989,723 Total 49,592,091 50,613,241 Accumulated depreciation, depletion and amortization (26,247,062 ) (28,877,593 ) Net capitalized costs $ 23,345,029 $ 21,735,648
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, 2016 , 2015 and 2014 : United States Trinidad Other International (1) Total 2016 Acquisition Costs of Properties Unproved (2) $ 3,216,598 $ — $ 36 $ 3,216,634 Proved (3) 749,023 — — 749,023 Subtotal 3,965,621 — 36 3,965,657 Exploration Costs 156,295 2,695 6,761 165,751 Development Costs (4) 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 (5) 3,847,813 102,715 110,589 4,061,117 Total $ 4,669,045 $ 125,552 $ 133,686 $ 4,928,283 2014 Acquisition Costs of Properties Unproved $ 365,915 $ — $ 4,499 $ 370,414 Proved 138,772 — 329 139,101 Subtotal 504,687 — 4,828 509,515 Exploration Costs 332,703 2,794 60,476 395,973 Development Costs (6) 6,638,192 89,555 271,534 6,999,281 Total $ 7,475,582 $ 92,349 $ 336,838 $ 7,904,769 (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 $3,102 million related to the Yates transaction. (3) Includes non-cash proved property acquisition costs of $732 million related to the Yates transaction. (4) 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. (5) 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. (6) Includes Asset Retirement Costs of $149 million , $14 million and $33 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, 2016 , 2015 and 2014 : United States Trinidad Other International (2) Total 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 (Benefit) (2,128,183 ) 43,739 (2,111 ) (2,086,555 ) Results of Operations $ (3,747,220 ) $ 145,573 $ (259,310 ) $ (3,860,957 ) 2014 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues $ 11,771,777 $ 512,675 $ 308,465 $ 12,592,917 Other 49,950 37 4,257 54,244 Total 11,821,727 512,712 312,722 12,647,161 Exploration Costs 162,434 2,185 19,769 184,388 Dry Hole Costs 25,408 — 23,082 48,490 Transportation Costs 957,522 617 14,037 972,176 Production Costs 1,940,074 38,301 171,652 2,150,027 Impairments 331,792 — 411,783 743,575 Depreciation, Depletion and Amortization 3,571,313 188,250 122,157 3,881,720 Income (Loss) Before Income Taxes 4,833,184 283,359 (449,758 ) 4,666,785 Income Tax Provision 1,722,914 74,588 23,602 1,821,104 Results of Operations $ 3,110,270 $ 208,771 $ (473,360 ) $ 2,845,681 (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, 2016 . (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, 2016 , 2015 and 2014 : United States Trinidad Other International (1) Composite 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 Year Ended December 31, 2014 $ 6.44 $ 1.34 $ 24.60 $ 6.46 (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, 2016 , 2015 and 2014 : United States Trinidad Other International (1) Total 2016 Future cash inflows (2) $ 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 (3) $ 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 2014 Future cash inflows (4) $ 144,355,692 $ 1,615,280 $ 979,249 $ 146,950,221 Future production costs (51,112,604 ) (277,844 ) (242,845 ) (51,633,293 ) Future development costs (20,270,439 ) (84,576 ) (139,750 ) (20,494,765 ) Future income taxes (22,725,618 ) (460,096 ) — (23,185,714 ) Future net cash flows 50,247,031 792,764 596,654 51,636,449 Discount to present value at 10% annual rate (23,542,990 ) (110,228 ) (59,813 ) (23,713,031 ) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 26,704,041 $ 682,536 $ 536,841 $ 27,923,418 (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 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) Estimated crude oil prices used to calculate 2014 future cash inflows for the United States, Trinidad and Other International were $97.51 , $80.60 and $94.09 , respectively. Estimated NGL prices used to calculate 2014 future cash inflows for the United States and Other International were $34.29 and $27.03 , respectively. Estimated natural gas prices used to calculate 2014 future cash inflows for the United States, Trinidad and Other International were $3.71 , $3.71 and $5.14 , 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, 2016 : United States Trinidad Other International (1) Total December 31, 2013 $ 19,576,901 $ 876,640 $ 879,891 $ 21,333,432 Sales and transfers of oil and gas produced, net of production costs (8,874,180 ) (473,757 ) (122,777 ) (9,470,714 ) Net changes in prices and production costs 1,481,668 (12,079 ) (206,412 ) 1,263,177 Extensions, discoveries, additions and improved recovery, net of related costs 8,074,550 3,113 6,189 8,083,852 Development costs incurred 2,818,800 12,800 3,500 2,835,100 Revisions of estimated development cost 1,696,916 9,981 95,838 1,802,735 Revisions of previous quantity estimates 1,741,918 35,001 35,613 1,812,532 Accretion of discount 2,612,286 133,019 88,045 2,833,350 Net change in income taxes (3,743,300 ) 91,438 562 (3,651,300 ) Purchases of reserves in place 317,785 — — 317,785 Sales of reserves in place (189,808 ) — (289,071 ) (478,879 ) Changes in timing and other 1,190,505 6,380 45,463 1,242,348 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 (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, 2016
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 2016 Net Operating Revenues $ 1,354,349 $ 1,775,740 $ 2,118,504 $ 2,402,039 Operating 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 Loss $ (471,776 ) $ (292,558 ) $ (190,000 ) $ (142,352 ) Net Loss Per Share (1) 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 2015 Net Operating Revenues $ 2,318,538 $ 2,469,701 $ 2,172,428 $ 1,796,761 Operating Income (Loss) $ (172,995 ) $ 39,626 $ (6,222,957 ) $ (329,753 ) Loss Before Income Taxes $ (236,331 ) $ (11,478 ) $ (6,274,921 ) $ (398,826 ) Income Tax Benefit (66,583 ) (16,746 ) (2,199,182 ) (114,530 ) Net Income (Loss) $ (169,748 ) $ 5,268 $ (4,075,739 ) $ (284,296 ) Net Income (Loss) Per Share (1) Basic $ (0.31 ) $ 0.01 $ (7.47 ) $ (0.52 ) Diluted $ (0.31 ) $ 0.01 $ (7.47 ) $ (0.52 ) Average Number of Common Shares Basic 544,998 545,504 545,920 546,432 Diluted 544,998 549,683 545,920 546,432 (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.

Summary of Significant Accoun44

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Deferred Tax Assets, Net, Noncurrent	$ 169,000
Debt Issuance Costs, Net	$ 5,437	$ 4,774

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument Table [Line Items]
Long-Term Debt	$ 6,990,000,000	$ 6,649,718,000
Capital Lease Obligation	38,710,000	45,064,000
Less: Current Portion of Long-Term Debt	6,579,000	6,579,000
Unamortized Debt Discount	36,915,000	34,518,000
Debt Issuance Costs	5,437,000	4,774,000
Total Long-Term Debt	6,979,779,000	6,648,911,000
Long-Term Debt by Maturity [Abstract]
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2017	600,000,000
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
5.10% Senior Notes Due 2036
Debt Instrument Table [Line Items]
Long-Term Debt	250,000,000	0
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
Debt Instrument Issuance [Abstract]
Debt Instrument Issuance Face Amount	$ 500,000,000
Debt Instrument Issuance Interest Rate	3.15%
Senior Notes Due 2026 [Member]
Debt Instrument Table [Line Items]
Long-Term Debt	$ 750,000,000	0
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
Debt Instrument Issuance [Abstract]
Debt Instrument Issuance Face Amount	$ 500,000,000
Debt Instrument Issuance Interest Rate	3.90%
2.500% Senior Notes due 2016
Debt Instrument Table [Line Items]
Long-Term Debt	$ 0	400,000,000
Debt Instrument Issuance [Abstract]
Debt Instrument Issuance Face Amount	$ 400,000,000
Debt Instrument Issuance Interest Rate	2.50%
Debt Instrument, Maturity Date	Feb. 1, 2016
2.95% Senior Notes due 2015
Debt Instrument Issuance [Abstract]
Debt Instrument Issuance Face Amount	$ 500,000,000
Debt Instrument Issuance Interest Rate	2.95%
5.875% Senior Notes due 2017
Debt Instrument Table [Line Items]
Long-Term Debt	$ 600,000,000	600,000,000
Debt Instrument Issuance [Abstract]
Debt Instrument Issuance Face Amount	$ 600,000,000
Debt Instrument Issuance Interest Rate	5.875%
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 Notes
Debt Instrument Issuance [Abstract]
Net Proceeds From Issuance of Senior Long-Term Debt	990,000,000
the New Notes
Debt Instrument Issuance [Abstract]
Net Proceeds From Issuance of Senior Long-Term Debt	$ 991,000,000
Revolving Credit Agreement 2011
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Date	Oct. 11, 2016
Maximum borrowing capacity	$ 2,000,000,000
Current Borrowings Outstanding	$ 0
Revolving Credit Agreement 2015
Line of Credit Facility [Line Items]
Eurodollar rate at period end (in hundredths)	1.77%
Base rate at period end (in hundredths)	3.75%
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%
Letters of Credit Outstanding, Amount	$ 0
Current Borrowings Outstanding	0
Uncommitted Credit Facilities
Line of Credit Facility [Line Items]
Current Borrowings Outstanding	0
Commercial Paper
Debt Instrument Table [Line Items]
Long-term Commercial Paper, Noncurrent	0	259,718,000
Line of Credit Facility [Line Items]
Average Borrowings Outstanding	$ 130,000,000	$ 81,000,000
Weighted average interest rate (in hundredths)	0.76%	0.51%
Current Borrowings Outstanding	$ 0	$ 260,000,000

Stockholder's Equity (Details)

Stockholder's Equity (Details) - USD ($)		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Stockholders' Equity Note [Abstract]
An aggregate maximum of shares of common stock authorized for repurchase		10,000,000
Remaining shares available for purchase under share repurchase authorization		6,386,200
Dividends Common Stock Cash			$ 0.125
Percentage increase of cash dividend on common stock paid on October 31, 2014		34.00%
Percentage increase of cash dividend on common stock paid on April 30, 2014		33.00%
Dividends Payable, Amount Per Share After Increase		$ 0.1675
Common Stock Activity [Line Items]
Balance (in shares)		550,150,823
Stock Issued During Period, Shares, Acquisitions		25,000,000
Balance (in shares)		576,950,272	550,150,823
Preferred Stock, Shares Outstanding		0
Common Shares, Outstanding [Member]
Common Stock Activity [Line Items]
Balance (in shares)		549,859,000	548,295,000	546,172,000
Stock Issued During Period, Shares, Acquisitions		25,204,000
Common Stock Issued Under Equity Compensation Plans (in shares)		1,500,000	1,019,000	2,448,000
Treasury Stock Purchased (in shares)	[1]	(922,000)	(581,000)	(1,209,000)
Common Stock Issued Under Employee Stock Purchase Plan (in shares)		212,000	225,000	202,000
Treasury Stock Issued Under Equity Compensation Plans (in shares)		847,000	901,000	682,000
Balance (in shares)		576,700,000	549,859,000	548,295,000
Common Shares, Treasury [Member]
Common Stock Activity [Line Items]
Balance (in shares)		292,000	733,000	206,000
Stock Issued During Period, Shares, Acquisitions		0
Common Stock Issued Under Equity Compensation Plans (in shares)		0	0	0
Treasury Stock Purchased (in shares)	[1]	(922,000)	(581,000)	(1,209,000)
Common Stock Issued Under Employee Stock Purchase Plan (in shares)		117,000	121,000	0
Treasury Stock Issued Under Equity Compensation Plans (in shares)		847,000	901,000	682,000
Balance (in shares)		250,000	292,000	733,000
Common Shares, Issued [Member]
Common Stock Activity [Line Items]
Balance (in shares)		550,151,000	549,028,000	546,378,000
Stock Issued During Period, Shares, Acquisitions		25,204,000
Common Stock Issued Under Equity Compensation Plans (in shares)		1,500,000	1,019,000	2,448,000
Treasury Stock Purchased (in shares)	[1]	0	0	0
Common Stock Issued Under Employee Stock Purchase Plan (in shares)		95,000	104,000	202,000
Treasury Stock Issued Under Equity Compensation Plans (in shares)		0	0	0
Balance (in shares)		576,950,000	550,151,000	549,028,000
[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) Accumulated Other Comprehensive Income (Loss) (Details) - USD ($)		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss)		$ 14,328,000	$ (10,282,000)	$ (438,890,000)
Accumulated Other Comprehensive Income (Loss)		(19,010,000)	(33,338,000)
Significant amounts reclassified out of AOCI		0		0
Foreign Currency Translation Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), before Tax			(31,538,000)	(20,021,000)
Other Comprehensive Loss, before Reclassifications, before Tax		12,097,000	(11,517,000)
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax			0
Tax Effects		0	0
Other Comprehensive Income (Loss)		12,097,000	(11,517,000)
Accumulated Other Comprehensive Income (Loss)		(19,441,000)
Other [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), before Tax			(1,800,000)	(3,035,000)
Other Comprehensive Loss, before Reclassifications, before Tax		2,901,000	(129,000)
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax	[1]		1,572,000
Tax Effects		(670,000)	(208,000)
Other Comprehensive Income (Loss)		2,231,000	1,235,000
Accumulated Other Comprehensive Income (Loss)		431,000
Accumulated Other Comprehensive Income (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), before Tax			(33,338,000)	(23,056,000)
Other Comprehensive Loss, before Reclassifications, before Tax		14,998,000	(11,646,000)
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax			1,572,000
Tax Effects		(670,000)	(208,000)
Other Comprehensive Income (Loss)		14,328,000	$ (10,282,000)	$ (438,890,000)
Accumulated Other Comprehensive Income (Loss)		$ (19,010,000)
[1]	Reclassified to Net Income (Loss) - General and Administrative. Related to certain EOG pension plans. See Note 7.

Other Income (Expense), Net (De

Other Income (Expense), Net (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other Income and Expenses [Abstract]
Equity income from investments in Trinidad	$ 4	$ 9	$ 8
Adjustment to deferred compensation expense	(11)	6
Interest income		3
Net Foreign Currency Transaction Gains (Losses)	$ (41)	$ (17)	(34)
Losses on sales of warehouse stock			$ (15)

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Deferred Tax Assets (Liabilities), Net of Valuation Allowance, Current Classification [Abstract]
Commodity Hedging Contracts		$ 22,206				$ 0				$ 22,206	$ 0
Deferred Compensation Plans		43,984				38,559				43,984	38,559
Alternative Minimum Tax Credit Carryforward		84,426				93,316				84,426	93,316
Foreign Net Operating Loss		37,251				47,786				37,251	47,786
Deferred Tax Liability, Net of Valuation Allowance		(28,097)				(35,536)				(28,097)	(35,536)
Accrued Expenses and Liabilities		13,754				0				13,754	0
Other		(4,137)				3,687				(4,137)	3,687
Total Net Current Deferred Income Tax Assets		169,387				147,812				169,387	147,812
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		(39,852)				(57,569)				(39,852)	(57,569)
Foreign Net Operating Loss		314,899				443,010				314,899	443,010
Foreign Valuation Allowances		(268,499)				(380,104)				(268,499)	(380,104)
Foreign Other		438				1,506				438	1,506
Total Net Noncurrent Deferred Income Tax Assets		6,986				6,843				6,986	6,843
Deferred tax (assets) liabilities net noncurrent classification [Abstract]
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization		5,899,533				5,299,817				5,899,533	5,299,817
Non-Producing Leasehold Costs		(64,898)				(53,026)				(64,898)	(53,026)
Seismic Costs Capitalized for Tax		(161,920)				(162,240)				(161,920)	(162,240)
Equity Awards		(139,787)				(140,663)				(139,787)	(140,663)
Capitalized Interest		86,504				98,242				86,504	98,242
Alternative Minimum Tax Credit Carryforward		(673,205)				(685,189)				(673,205)	(685,189)
Undistributed Foreign Earnings		280,099				258,403				280,099	258,403
Total Net Noncurrent Deferred Income Tax Liabilities		5,188,640				4,587,902				5,188,640	4,587,902
Deferred Tax and Other Assets, Noncurrent		(37,686)				(27,442)				(37,686)	(27,442)
Deferred Tax Liabilities, Net		5,012,267				4,433,247				5,012,267	4,433,247
Income Before Income Taxes [Abstract]
United States										(1,520,573)	(6,840,119)	$ 5,161,232
Foreign										(36,932)	(81,437)	(165,917)
Income (Loss) Before Income Taxes		(194,010)	$ (272,250)	$ (380,277)	$ (710,968)	(398,826)	$ (6,274,921)	$ (11,478)	$ (236,331)	(1,557,505)	(6,921,556)	4,995,315
Current income tax provision (benefit) [Abstract]
Federal										11,567	21,719	269,326
State										(8,369)	9,404	22,835
Foreign										51,189	54,143	82,721
Total										54,387	85,266	374,882
Deferred income tax provision (benefit) [Abstract]
Federal										(532,979)	(2,362,926)	1,608,706
State										4,876	(127,444)	29,056
Foreign										12,897	8,063	67,184
Total										(515,206)	(2,482,307)	1,704,946
Income Tax Provision (Benefit)										$ (460,819)	$ (2,397,041)	$ 2,079,828
Effective income tax rate [Abstract]
Statutory Federal Income Tax Rate (in hundredths)										35.00%	35.00%	35.00%
State Income Tax, Net of Federal Benefit (in hundredths)										0.15%	1.11%	0.68%
Income Tax Provision Related to Foreign Operations (in hundredths)										(1.23%)	(1.31%)	(0.12%)
Income Tax Provision Related to Trinidad Operations (in hundredths)										(3.71%)	0.00%	0.00%
Canadian Divestiture (in hundredths)										0.00%	0.00%	(3.46%)
Undistributed Foreign Earnings (in hundredths)										0.00%	0.00%	4.94%
Foreign Valuation Allowances (in hundredths)										0.00%	0.00%	6.47%
Foreign Oil and Gas Impairments (in hundredths)										0.00%	0.00%	(1.90%)
Other (in hundredths)										(0.62%)	(0.17%)	0.03%
Effective Income Tax Rate (in hundredths)										29.59%	34.63%	41.64%
Valuation Allowance [Abstract]
Beginning Balance					$ 506,127				$ 463,018	$ 506,127	$ 463,018	$ 223,599
Increase	[1]									37,221	146,602	392,729
Decrease	[2]									(12,667)	(4,315)	(1,424)
Other	[3]									(147,460)	(99,178)	(151,886)
Ending Balance		383,221				$ 506,127				383,221	$ 506,127	$ 463,018
Unrecognized tax benefits balance		36,000								36,000
Unrecognized tax benefit earnings impact		2,000								2,000
Foreign subsidiaries' undistributed earnings		2,000,000								2,000,000
Balance of State net operating loss expected to be carried forward										1,600,000
Alternative minimum tax credits utilized										21,000
AMT Paid In Years Prior To Prior Reporting Period										758,000
Tax net operating loss incurred in United Kingdom in current year										38,000
Balance of tax net operating loss incurred in the United Kingdom in prior years										740,000
Unrecognized tax benefits interest or penalties		2,000								2,000
Federal and state deferred income taxes		$ 280,000								$ 280,000
[1]	Increase in valuation allowance related to the generation of tax net operating losses 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 (Details

Employee Benefit Plans (Details)		12 Months Ended
		Dec. 31, 2016USD ($)$ / sharesshares		Dec. 31, 2015USD ($)$ / sharesshares		Dec. 31, 2014USD ($)$ / sharesshares
Stock based compensation by job function [Line Items]
Stock-Based Compensation Expenses | $		$ 128,090,000		$ 130,577,000		$ 144,842,000
Federal income tax (expense) / benefit recognized from stock-based compensation | $		$ 29,000,000		$ 26,000,000		$ 99,000,000
Share-Based Compensation Arrangement By Share-Based Payment Award [Abstract]
Common Shares Available for Grant		21,500,000
Restricted Stock And Restricted Stock Units [Member]
Stock option and SAR Rollforward [Abstract]
Outstanding at January 1 (in shares)		4,908,000	[1]	5,394,000	[1]	7,358,000
Granted (in shares)		853,000		1,044,000		1,132,000
Exercised (in shares)	[2]	(1,465,000)		(1,331,000)		(2,761,000)
Forfeited (in shares)		(334,000)		(199,000)		(335,000)
Outstanding at December 31 (in shares)	[1]	3,962,000		4,908,000		5,394,000
Share-Based Compensation Arrangement By Share-Based Payment Award [Abstract]
Outstanding at January 1 (in dollars per share) | $ / shares		$ 70.35	[1]	$ 64.39	[1]	$ 49.54
Granted (in dollars per share) | $ / shares		88.01		77.94		98.72
Exercised (in dollars per share) | $ / shares	[2]	53.95		51.52		105.24
Forfeited (in dollars per share) | $ / shares		77.29		74.56		62.55
Outstanding at December 31 (in dollars per share) | $ / shares	[1]	$ 79.63		$ 70.35		$ 64.39
Weighted average period over which unrecognized compensation expense will be recognized		2 years 6 months
Unrecognized compensation expense | $		$ 153,000,000
Share Based Compensation Arrangement By Restricted Stock And Restricted Stock Units Compensation Cost | $		$ 60,000,000		$ 69,000,000		$ 74,000,000
Weighted Average Grant Fair Value [Abstract]
Maximum vest period from the date of grant		5 years
Stock Options And Sars [Member]
Stock based compensation by job function [Line Items]
Maximum term of stock options and SARs granted		7 years
Stock-based compensation expense related to stock options, SAR and ESPP grants | $		$ 57,000,000		$ 56,000,000		$ 62,000,000
Weighted Average Fair Value And Valuation Assumptions Used To Value Stock-Based Compensation [Abstract]
Weighted Average Fair Value of Grants | $ / shares		$ 25.78		$ 21.88		$ 30.75
Expected Volatility (in hundredths)		31.54%		38.03%		35.28%
Risk-Free Interest Rate (in hundredths)		0.78%		0.83%		0.95%
Dividend Yield (in hundredths)		0.76%		0.85%		0.61%
Expected Life (in years)		5 years 4 months 24 days		5 years 3 months 18 days		5 years 2 months 12 days
Stock option and SAR Rollforward [Abstract]
Outstanding at January 1 (in shares)		10,744,000		10,493,000		10,452,000
Granted (in shares)		1,855,000		2,037,000		2,146,000
Exercised (in shares)	[3]	(2,376,000)		(1,518,000)		(1,718,000)
Forfeited (in shares)		(373,000)		(268,000)		(387,000)
Outstanding at December 31 (in shares)		9,850,000		10,744,000		10,493,000
Share-Based Compensation Arrangement By Share-Based Payment Award [Abstract]
Outstanding at January 1 (in dollars per share) | $ / shares		$ 67.98		$ 64.96		$ 54.43
Granted (in dollars per share) | $ / shares		94.82		69.99		101.55
Exercised (in dollars per share) | $ / shares	[3]	54.56		47.64		45.68
Forfeited (in dollars per share) | $ / shares		87.38		80.31		68.95
Outstanding at December 31 (in dollars per share) | $ / shares		$ 75.53		$ 67.98		$ 64.96
Stock Options/SARs Exercisable at December 31 (in shares)		5,613,000		5,993,000		5,287,000
Stock Options/SARs Exercisable at December 31 (in dollars per share) | $ / shares		$ 66.48		$ 57.96		$ 49.40
Stock options/SARs vested or expected to vest (in shares)		9,500,000
Weighted average grant price for stock options/SARs vested or expected to vest (per share) | $ / shares		$ 75.12
Intrinsic value of stock options/SARs vested or expected to vest | $		$ 249,000,000
Weighted average period over which unrecognized compensation expense will be recognized		2 years 9 months 18 days
Unrecognized compensation expense | $		$ 95,000,000
Weighted Average Grant Fair Value [Abstract]
Maximum vest period from the date of grant		4 years
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		9,850,000
Weighted Average Remaining Life for Outstanding Options and SARs		4 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares		$ 75.53
Aggregate Intrinsic Value For Outstanding Options and SARs | $	[4]	$ 253,400
Stock Options and SARs Exercisable		5,613,000
Weighted Average Remaining Life For Exercisable Units		3 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares		$ 66.48
Aggregate Intrinsic Value For Exercisable Units | $	[4]	$ 195,186
Espp [Member]
Stock based compensation by job function [Line Items]
Maximum Percentage Of Employee Pay Eligible For Contribution To Espp Percentage		10.00%
Percentage of fair market value at which employees may purchase company stock via the ESPP		85.00%
Weighted Average Fair Value And Valuation Assumptions Used To Value Stock-Based Compensation [Abstract]
Weighted Average Fair Value of Grants | $ / shares		$ 19.21		$ 21.21		$ 21.65
Expected Volatility (in hundredths)		36.55%		32.08%		25.03%
Risk-Free Interest Rate (in hundredths)		0.44%		0.12%		0.08%
Dividend Yield (in hundredths)		0.82%		0.73%		0.46%
Expected Life (in years)		6 months		6 months		6 months
Share-Based Compensation Arrangement By Share-Based Payment Award [Abstract]
Common Shares Available for Grant		356,000
Approximate Number of Participants		1,746		1,963		1,991
Shares Purchased		212,000		225,000		202,000
Aggregate Purchase Price | $		$ 13,787,000		$ 15,045,000		$ 14,927,000
Performance Units and Performance Stock [Member]
Weighted Average Fair Value And Valuation Assumptions Used To Value Stock-Based Compensation [Abstract]
Weighted Average Fair Value of Grants | $ / shares		$ 119.10		$ 80.64		$ 119.27
Expected Volatility (in hundredths)		32.48%		29.35%		32.18%
Risk-Free Interest Rate (in hundredths)		1.15%		1.07%		1.18%
Share-Based Compensation Arrangement By Share-Based Payment Award [Abstract]
Weighted average period over which unrecognized compensation expense will be recognized		3 years
Unrecognized compensation expense | $		$ 10,000,000
Number of Shares and Units [Roll Forward]
Outstanding at January 1 (in shares)		405,000
Granted (in shares)		131,750
Released (in shares)		(134,016)
Outstanding at December 31 [1] (in shares)		545,290		405,000
Weighted Average Grant Fair Value [Abstract]
Intrinsic value of stock based compensation | $		$ 9,700,000
Performance Units and Performance Stock [Abstract]
Minimum Performance Multiple at the Completion Performance Period		0.00%
Maximum Performance Multiple at the Completion Performance Period		200.00%
Minimum Performance Units and Stock Allowed to be Outstanding		151,096
Maximum Performance Units and Stock Allowed to be Outstanding		939,484
Share Based Compensation Arrangement By Performance Units and Stock Compensation Cost | $		$ 11,000,000		$ 5,000,000		$ 9,000,000
Term of Zero-Coupon Risk-Free Interest Rate Derived from the Treasury Constant Maturities Yield Curve		3 years 3 months
Additional Performance Awards Granted		118,834		142,556
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items]
Aggregate Intrinsic Value For Outstanding Options and SARs | $		$ 55,100,000
Lease And Well [Member]
Stock based compensation by job function [Line Items]
Stock-Based Compensation Expenses | $		38,000,000		$ 44,000,000		41,000,000
Gathering And Processing Costs [Member]
Stock based compensation by job function [Line Items]
Stock-Based Compensation Expenses | $		1,000,000		1,000,000		1,000,000
Exploration Costs [Member]
Stock based compensation by job function [Line Items]
Stock-Based Compensation Expenses | $		21,000,000		26,000,000		27,000,000
General And Administrative [Member]
Stock based compensation by job function [Line Items]
Stock-Based Compensation Expenses | $		$ 68,000,000		60,000,000		76,000,000
$ 34.00 to $ 55.99 | Stock Options And Sars [Member]
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items]
Stock Options and SARs Outstanding		1,906,000
Weighted Average Remaining Life for Outstanding Options and SARs		1 year
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares		$ 43.68
Stock Options and SARs Exercisable		1,906,000
Weighted Average Remaining Life For Exercisable Units		1 year
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares		$ 43.68
56.00 to 69.99 | 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		2,922,000
Weighted Average Remaining Life for Outstanding Options and SARs		4 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares		$ 64.12
Stock Options and SARs Exercisable		1,654,000
Weighted Average Remaining Life For Exercisable Units		3 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares		$ 60.09
70.00 to 94.99 | 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		1,526,000
Weighted Average Remaining Life for Outstanding Options and SARs		3 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares		$ 84.62
Stock Options and SARs Exercisable		1,072,000
Weighted Average Remaining Life For Exercisable Units		3 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares		$ 84.49
95.00 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		1,794,000
Weighted Average Remaining Life for Outstanding Options and SARs		7 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares		$ 95.10
Stock Options and SARs Exercisable		23,000
Weighted Average Remaining Life For Exercisable Units		3 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares		$ 97.31
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		1,702,000
Weighted Average Remaining Life for Outstanding Options and SARs		4 years
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares		$ 102.02
Stock Options and SARs Exercisable		958,000
Weighted Average Remaining Life For Exercisable Units		4 years
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares		$ 102
Pension Plans [Member]
Defined Benefit and Defined Contribution Plan Disclosure [Line Items]
Total pension plan costs | $		$ 34,000,000		36,000,000		41,000,000
Company contributions to foreign pension plans | $		1,000,000		1,000,000		$ 5,000,000
Benefit obligation | $		8,000,000		9,000,000
Fair value of foreign pension plan assets | $		7,000,000		7,000,000
Accrued benefit cost | $		$ (300,000)		$ (200,000)
[1]	The total intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2016 and 2015 was approximately $401 million and $347 million, respectively.
[2]	The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2016, 2015 and 2014 was $124 million, $109 million and $291 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.
[3]	The total intrinsic value of stock options/SARs exercised during the years 2016, 2015 and 2014 was $84 million, $60 million and $95 million, respectively. The intrinsic value is based upon the difference between the market price of the Common Stock on the date of exercise and the grant price of the stock options/SARs.
[4]	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.

Commitments and Contingencies51

Commitments and Contingencies (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Feb. 25, 2016
Commitments and Contingencies Disclosure [Abstract]
Standby letters of credit and guarantees outstanding	$ 226,000,000	$ 272,000,000
Subsidiary payment obligations demand for payment				$ 0
Total Minimum Commitments [Abstract]
2,017	1,201,092,000
2,018	934,037,000
2,018	673,452,000
2,020	460,178,000
2,020	334,601,000
2022 and beyond	674,287,000
Total Minimum Commitments	4,277,647,000
Rental expenses associated with existing leases	$ 204,000,000	$ 229,000,000	$ 237,000,000

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, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Numerator for Basic and Diluted Earnings per Share - [Abstract]
Net Income (Loss)	$ (142,352)		$ (190,000)		$ (292,558)		$ (471,776)		$ (284,296)		$ (4,075,739)		$ 5,268		$ (169,748)		$ (1,096,686)	$ (4,524,515)	$ 2,915,487
Denominator for Basic Earnings per Share - [Abstract]
Weighted Average Shares (in shares)																	553,384	545,697	543,443
Potential Dilutive Common Shares -[Abstract]
Stock Options/SARs (in shares)																	0	0	2,526
Restricted Stock/Units and Performance Units/Stock (in shares)																	0	0	2,570
Denominator for Diluted Earnings per Share - [Abstract]
Adjusted Diluted Weighted Average Shares (in shares)	567,337		547,838		547,335		546,715		546,432		545,920		549,683		544,998		553,384	545,697	548,539
Net Income (Loss) Per Share [Abstract]
Basic (in dollars per share)	$ (0.25)	[1]	$ (0.35)	[1]	$ (0.53)	[1]	$ (0.86)	[1]	$ (0.52)	[1]	$ (7.47)	[1]	$ 0.01	[1]	$ (0.31)	[1]	$ (1.98)	$ (8.29)	$ 5.36
Diluted (in dollars per share)	$ (0.25)	[1]	$ (0.35)	[1]	$ (0.53)	[1]	$ (0.86)	[1]	$ (0.52)	[1]	$ (7.47)	[1]	$ 0.01	[1]	$ (0.31)	[1]	$ (1.98)	$ (8.29)	$ 5.32
Antidilutive Stock Options and SARs excluded from Diluted Earnings Per Share Calculation (in shares)																	10,300	10,200	700
Restricted Stock and Restricted Stock Units and Performance Units and Performance Stock Excluded from Calculation																	4,500	5,300
[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, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental Cash Flow Information [Abstract]
Interest, Net of Capitalized Interest	$ 252,030	$ 222,088	$ 197,383
Income Taxes, Net of Refunds Received	(39,293)	41,108	342,741
Accrued Capital Expenditures	388,000	$ 416,000	972,000
Non-cash investing and financing activities from property exchanges.			$ 5,000
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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Schedule of Segment Reporting Information By Segment [Abstract]
Crude Oil and Condensate										$ 4,317,341		$ 4,934,562		$ 9,742,480
Natural Gas Liquids										437,250		407,658		934,051
Natural Gas										742,152		1,061,038		1,916,386
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts										(99,608)		61,924		834,273
Gathering, Processing and Marketing										1,966,259		2,253,135		4,046,316
Gains (Losses) on Asset Dispositions, Net										205,835		(8,798)		507,590
Other, Net										81,403		47,909		54,244
Net Operating Revenues		$ 2,402,039	$ 2,118,504	$ 1,775,740	$ 1,354,349	$ 1,796,761	$ 2,172,428	$ 2,469,701	$ 2,318,538	7,650,632	[1]	8,757,428	[2]	18,035,340	[3]
Depreciation, Depletion and Amortization										3,553,417		3,313,644		3,997,041
Operating Income (Loss)		(105,487)	(193,480)	(288,173)	(638,141)	(329,753)	(6,222,957)	39,626	(172,995)	(1,225,281)		(6,686,079)		5,241,823
Interest Income										2,619		3,469		2,239
Other Income (Expense)										(53,162)		(1,553)		(47,289)
Net Interest Expense										281,681		237,393		201,458
Income (Loss) Before Income Taxes		(194,010)	(272,250)	(380,277)	(710,968)	(398,826)	(6,274,921)	(11,478)	(236,331)	(1,557,505)		(6,921,556)		4,995,315
Income Tax Provision (Benefit)		(51,658)	$ (82,250)	$ (87,719)	$ (239,192)	(114,530)	$ (2,199,182)	$ (16,746)	$ (66,583)	(460,819)		(2,397,041)		2,079,828
Additions to Oil and Gas Properties, Excluding Dry Hole Costs										6,329,369		4,710,404		7,471,177
Total Property, Plant and Equipment, Net		25,707,078				24,210,721				25,707,078		24,210,721		29,172,644
Total Assets		29,459,433				26,970,470				29,459,433		26,970,470		34,758,599
United States
Schedule of Segment Reporting Information By Segment [Abstract]
Crude Oil and Condensate										4,265,036		4,917,731		9,526,149
Natural Gas Liquids										437,238		407,570		924,454
Natural Gas										475,715		637,452		1,321,175
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts										(99,608)		61,924		834,273
Gathering, Processing and Marketing										1,967,390		2,254,477		4,040,024
Gains (Losses) on Asset Dispositions, Net										196,043		(12,176)		96,339
Other, Net										81,386		47,464		49,950
Net Operating Revenues										7,323,200	[1]	8,314,442	[2]	16,792,364	[3]
Depreciation, Depletion and Amortization										3,365,390		3,139,863		3,684,943
Operating Income (Loss)										(1,192,338)		(6,566,282)		5,074,911
Interest Income										358		1,913		849
Other Income (Expense)										(15,703)		6,461		(14,953)
Net Interest Expense										298,125		274,606		269,166
Income (Loss) Before Income Taxes										(1,505,808)		(6,832,514)		4,791,641
Income Tax Provision (Benefit)										(516,180)		(2,463,213)		1,837,185
Additions to Oil and Gas Properties, Excluding Dry Hole Costs										6,223,228		4,495,730		7,133,727
Total Property, Plant and Equipment, Net		25,221,517				23,593,995				25,221,517		23,593,995		28,391,741
Total Assets		27,907,083				25,347,134				27,907,083		25,347,134		32,867,310
Trinidad
Schedule of Segment Reporting Information By Segment [Abstract]
Crude Oil and Condensate										9,600		13,122		29,604
Natural Gas Liquids										0		0		0
Natural Gas										234,108		368,639		483,071
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts										0		0		0
Gathering, Processing and Marketing										(1,131)		(1,342)		6,064
Gains (Losses) on Asset Dispositions, Net										(145)		393		0
Other, Net										(8)		(3)		37
Net Operating Revenues										242,424	[1]	380,809	[2]	518,776	[3]
Depreciation, Depletion and Amortization										145,591		154,853		188,592
Operating Income (Loss)										46,473		175,658		277,471
Interest Income										932		389		253
Other Income (Expense)										2,667		8,780		8,712
Net Interest Expense										0		1,400		0
Income (Loss) Before Income Taxes										50,072		183,427		286,436
Income Tax Provision (Benefit)										64,281		63,502		98,559
Additions to Oil and Gas Properties, Excluding Dry Hole Costs										75,407		102,358		76,138
Total Property, Plant and Equipment, Net		274,850				350,766				274,850		350,766		382,719
Total Assets		889,253				886,826				889,253		886,826		865,674
Other International
Schedule of Segment Reporting Information By Segment [Abstract]
Crude Oil and Condensate	[4]									42,705		3,709		186,727
Natural Gas Liquids	[4]									12		88		9,597
Natural Gas	[4]									32,329		54,947		112,140
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts	[4]									0		0		0
Gathering, Processing and Marketing	[4]									0		0		228
Gains (Losses) on Asset Dispositions, Net	[4]									9,937		2,985		411,251
Other, Net	[4]									25		448		4,257
Net Operating Revenues	[4]									85,008	[1]	62,177	[2]	724,200	[3]
Depreciation, Depletion and Amortization	[4]									42,436		18,928		123,506
Operating Income (Loss)	[4]									(79,416)		(295,455)		(110,559)
Interest Income	[4]									1,329		1,167		1,137
Other Income (Expense)	[4]									(40,126)		(16,794)		(41,048)
Net Interest Expense	[4]									(16,444)		(38,613)		(67,708)
Income (Loss) Before Income Taxes	[4]									(101,769)		(272,469)		(82,762)
Income Tax Provision (Benefit)	[4]									(8,920)		2,670		144,084
Additions to Oil and Gas Properties, Excluding Dry Hole Costs	[4]									30,734		112,316		261,312
Total Property, Plant and Equipment, Net	[4]	210,711				265,960				210,711		265,960		398,184
Total Assets	[4]	$ 663,097				$ 736,510				$ 663,097		$ 736,510		$ 1,025,615
[1]	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 in the United States segment.
[2]	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 in the United States segment.
[3]	EOG had sales activity with two significant purchasers in 2014, one totaling $4.0 billion and the other totaling $3.0 billion of consolidated Net Operating Revenues in the United States segment.
[4]	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, 2016USD ($)$ / bbl$ / MMBTUMMBTUbbl	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Net (Gains) Losses on Mark-to-Market Commodity Derivative Contracts | $	$ 99,608,000	$ (61,924,000)	$ (834,273,000)
Net Cash Received from (Payments for) Settlements of Crude Oil and Natural Gas Derivative Contracts | $	$ (22,219,000)	$ 730,114,000	$ 34,007,000
Derivative [Line Items]
Derivative, Average Floor Price	3.20
Derivatives, Fair Value [Line Items]
Receivable Major Customer Percentage		10.00%
Derivative liabilities, current | $	$ 61,817,000	$ 0
Derivative Collateral [Abstract]
Collateral Held on Derivative | $	0	0
Collateral Had on Derivaitve | $	$ 0	0
Call Option [Member]
Derivative [Line Items]
Volume (MMBtud) | MMBTU	106,250
Natural Gas Collar Contracts Year Two - March through November
Derivative [Line Items]
Volume (MMBtud) | MMBTU	80,000
Derivative, Average Cap Price	3.69
Natural Gas Option Contracts Year Three - March through November | Put Option [Member]
Derivative [Line Items]
Volume (MMBtud) | MMBTU	96,000
Derivative, Average Price Risk Option Strike Price	2.94
Natural Gas Option Contracts Year Three - March through November | Call Option [Member]
Derivative [Line Items]
Volume (MMBtud) | MMBTU	120,000
Derivative, Average Price Risk Option Strike Price	3.38
Natural Gas Option Contracts Year Two - March through November | Put Option [Member]
Derivative [Line Items]
Volume (MMBtud) | MMBTU	171,000
Derivative, Average Price Risk Option Strike Price	2.92
Natural Gas Option Contracts Year Two - March through November | Call Option [Member]
Derivative [Line Items]
Volume (MMBtud) | MMBTU	213,750
Derivative, Average Price Risk Option Strike Price	3.44
Natural Gas Option Contracts - October through November (closed) | Put Option [Member]
Derivative [Line Items]
Volume (MMBtud) | MMBTU	0
Derivative, Average Price Risk Option Strike Price	0
Natural Gas Option Contracts - October through November (closed) | Call Option [Member]
Derivative [Line Items]
Derivative, Average Price Risk Option Strike Price	3.48
Natural Gas Options Contracts September (closed) | Put Option [Member]
Derivative [Line Items]
Volume (MMBtud) | MMBTU	0
Derivative, Average Price Risk Option Strike Price	0
Natural Gas Options Contracts September (closed) | Call Option [Member]
Derivative [Line Items]
Volume (MMBtud) | MMBTU	56,250
Derivative, Average Price Risk Option Strike Price	3.46
Natural Gas Price Swap Contracts Year Two - March through November
Derivative [Line Items]
Volume (MMBtud) | MMBTU	30,000
Derivative Weighted Average Price Natural Gas ($/MMBtu)	3.10
Natural Gas Price Swap Contracts - March through August (closed)
Derivative [Line Items]
Volume (MMBtud) | MMBTU	60,000
Derivative Weighted Average Price Natural Gas ($/MMBtu)	2.49
Crude Oil Collar Contracts - September through December (closed)
Derivative [Line Items]
Volume (Bbld) | bbl	70,000
Derivative, Average Cap Price | $ / bbl	54.25
Derivative, Average Floor Price | $ / bbl	45
Crude Oil Price Swap Contracts Year Two - January through June
Derivative [Line Items]
Volume (Bbld) | bbl	35,000
Derivative Weighted Average Price Crude Oil ($/Bbl) | $ / bbl	50.04
Crude Oil Price Swap Contracts May - June (closed)
Derivative [Line Items]
Volume (Bbld) | bbl	128,000
Derivative Weighted Average Price Crude Oil ($/Bbl) | $ / bbl	42.56
Crude Oil Price Swap Contracts - April (closed)
Derivative [Line Items]
Volume (Bbld) | bbl	90,000
Derivative Weighted Average Price Crude Oil ($/Bbl) | $ / bbl	42.30
Crude oil and natural gas derivative contracts - | Liabilities From Price Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities, current | $	$ 62,000,000	0
Crude oil and natural gas derivative contracts - | Other Assets [Member]
Derivatives, Fair Value [Line Items]
Other Assets | $	$ 1,000,000	$ 0

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Financial Assets:
Financial Assets: Natural Gas Options/Collars	[1]	$ 1,000
Financial Liabilities:
Financial Liabilities: Crude Oil Swaps	[2]	36,000
Financial Liabilities: Natural Gas Swaps	[2]	4,000
Financial Liabilities: Crude Oil Options/Swaptions	[2]	22,000
Proved oil and gas properties, other property, plant and equipment and other assets, carrying amount		778,000	$ 9,154,000
Proved oil and gas properties, other property, plant and equipment and other assets written down during the period - fair value at end of period		587,000	2,828,000
Pretax impairment charges for proved oil and gas properties, other property, plant and equipment and other assets		191,000	6,326,000
Pretax impairment charges for obsolete inventory		61,000
Pretax impairment charges for firm commitment contracts		138,000
Net of Tax Impairment Charges for Proved Oil and Gas Properties, Other Property, Plant and Equipment and Other Assets			4,141,000
Aggregate Principal Amount of Current and Long-Term Debt		6,990,000	6,390,000
Fair Value of Debt		7,190,000	$ 6,524,000
Fair Value, Inputs, Level 1 [Member]
Financial Assets:
Financial Assets: Natural Gas Options/Collars	[1]	0
Financial Liabilities:
Financial Liabilities: Crude Oil Swaps	[2]	0
Financial Liabilities: Natural Gas Swaps	[2]	0
Financial Liabilities: Crude Oil Options/Swaptions	[2]	0
Fair Value, Inputs, Level 2 [Member]
Financial Assets:
Financial Assets: Natural Gas Options/Collars	[1]	1,000
Financial Liabilities:
Financial Liabilities: Crude Oil Swaps	[2]	36,000
Financial Liabilities: Natural Gas Swaps	[2]	4,000
Financial Liabilities: Crude Oil Options/Swaptions	[2]	22,000
Fair Value, Inputs, Level 3 [Member]
Financial Assets:
Financial Assets: Natural Gas Options/Collars	[1]	0
Financial Liabilities:
Financial Liabilities: Crude Oil Swaps	[2]	0
Financial Liabilities: Natural Gas Swaps	[2]	0
Financial Liabilities: Crude Oil Options/Swaptions	[2]	$ 0
[1]	At December 31, 2016, $1 million is included in "Other Assets" on the Consolidated Balance Sheets.
[2]	At December 31, 2016, $62 million is included in "Current Liabilities - Liabilities from Price Risk Management Activities" on the Consolidated Balance Sheets.

Accounting For Certain Long-L57

Accounting For Certain Long-Lived Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Schedule of Impaired Long-Lived Assets Held and Used [Line Items]
Proved oil and gas properties, other property, plant and equipment and other assets carrying amount	$ 667	$ 9,154
Amortization and impairments of unproved oil and gas property costs including amortization of capitalized interest	291	288	$ 168
Proved oil and gas properties, other property, plant and equipment, and other assets written down to fair value	537	2,828
Pretax impairment charges for proved oil and gas properties, other property, plant and equipment and other assets	$ 130	6,326
Net of tax impairment charges for proved oil and gas properties, other property, plant and equipment and other assets		$ 4,141

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligations, Noncurrent [Abstract]
Carrying Amount at Beginning of Period		$ 811,554	$ 752,718
Liabilities Incurred	[1]	212,739	63,844
Liabilities Settled	[2]	(94,800)	(17,415)
Accretion		32,306	31,956
Revisions		(38,286)	(13,356)
Foreign Currency Translations		(10,587)	(6,193)
Carrying Amount at End of Period		912,926	811,554
Current Portion		18,516	7,651
Noncurrent Portion		$ 894,410	$ 803,903
[1]	Includes $164 million 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, 2016	Dec. 31, 2015	Dec. 31, 2014
Capitalized Exploratory Well Costs [Abstract]
Balance at January 1		$ 8,955	$ 17,253	$ 9,211
Additions Pending the Determination of Proved Reserves		6,688	24,640	32,080
Reclassifications to Proved Properties		(5,274)	(26,659)	(15,946)
Costs Charged to Expense (1)	[1]	(10,369)	(6,279)	(8,092)
Balance at December 31		$ 0	$ 8,955	$ 17,253
[1]	Includes capitalized exploratory well costs charged to either dry hole costs or impairments.

Acquisitions and Divestitures (

Acquisitions and Divestitures (Details) - USD ($) $ in Thousands, shares in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Business Combination, Separately Recognized Transactions [Line Items]
Business Combination, Separately Recognized Transactions, Additional Disclosures, Acquisition Cost Expensed	$ 5,000
Accounts Receivable, Net	83,540
Inventories	10,955
Other	10,640
Total Current Assets	175,546
Oil and Gas Properties (Successful Efforts Method)	3,850,100
Other Property, Plant and Equipment	16,586
Total Property, Plant and Equipment, Net	3,866,686
Other Assets	22,706
Total Assets	4,064,938
Accounts Payable	126,988
Accrued Taxes Payable	23,520
Other	743
Total Current Liabilities	151,251
Long-Term Debt	163,829
Asset Retirement Obligations	163,144
Off-Market Transportation Contracts	39,720
Other Liabilities	28,645
Deferred Income Taxes	1,104,581
Total Liabilities	1,651,170
Total Consideration Transferred	2,413,768
Gains (Losses) on Asset Dispositions, Net	205,835	$ (8,798)	$ 507,590
Proceeds from Sale of Producing Properties	$ 1,119,215	192,807	569,332
Stock Issued During Period, Shares, Acquisitions	25
Payments to Acquire Businesses, Gross	$ 16,000
Aggregated Purchase Price to Acquire Proved Crude Oil Properties and Related Assets		$ 481,000
Cumulative translation adjustments	383,000
Restricted cash related to future abandonment liabilities			$ 150,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents	2,400,000
Cash Acquired from Acquisition	70,411
Revenue [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Business Combination, Separately Recognized Transactions, Revenues and Gains Recognized	71,000
Operating Income [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Business Combination, Separately Recognized Transactions, Expenses and Losses Recognized	$ 8,000

Oil and Gas Exploration and P61

Oil and Gas Exploration and Production Industries Disclosures (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2016USD ($)MBoeMMcfMBbls	Dec. 31, 2015USD ($)MBoeMMcfMBbls	Dec. 31, 2014MBoeMMcfMBbls	Dec. 31, 2013MBoeMMcfMBbls
Reserve Quantities [Line Items]
Net proved developed reserves (MBOE) | MBoe		1,093,906	1,072,477	1,347,947	1,127,476
Net Proved Undeveloped Reserves (MBOE) [Rollforward]
Balance at January 1 | MBoe		1,045,640	1,149,309	991,067
Extensions and Discoveries | MBoe		138,101	205,152	403,713
Revisions | MBoe		64,413	(241,973)	(79,630)
Acquisition of Reserves | MBoe		0	54,458	4,239
Sales of Reserves | MBoe		(45,917)	0	(10,176)
Conversion to Proved Developed Reserves | MBoe		(149,210)	(121,306)	(159,904)
Balance at December 31 | MBoe		1,053,027	1,045,640	1,149,309
Capitalized Costs, Oil and Gas Producing Activities, Gross [Abstract]
Proved properties | $		$ 45,751,965	$ 49,623,518
Unproved properties | $		3,840,126	989,723
Total | $		49,592,091	50,613,241
Accumulated depreciation, depletion and amortization | $		(26,247,062)	(28,877,593)
Net capitalized costs | $		$ 23,345,029	$ 21,735,648
Crude Oil (MBbl)
Reserve Quantities [Line Items]
Net proved developed reserves		516,625	445,202	495,148	391,056
Net proved undeveloped reserves		660,960	652,394	644,602	509,484
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	1,097,596	1,139,750	900,540
Revisions of previous estimates	[1]	42,955	(114,925)	28,022
Purchases in place	[1]	25,795	35,922	9,705
Extensions, discoveries and other additions	[1]	123,441	141,386	319,554
Sales in place	[1]	(8,791)	(740)	(12,623)
Production	[1]	(103,411)	(103,797)	(105,448)
Net proved reserves - end of period	[1]	1,177,585	1,097,596	1,139,750
Natural Gas Liquids (MBbl)
Reserve Quantities [Line Items]
Net proved developed reserves		230,219	205,898	264,749	200,860
Net proved undeveloped reserves		186,147	176,977	202,319	176,346
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	382,875	467,068	377,206
Revisions of previous estimates	[1]	53,771	(113,222)	27,443
Purchases in place	[1]	1,284	8,251	1,812
Extensions, discoveries and other additions	[1]	41,862	49,147	91,683
Sales in place	[1]	(33,548)	(271)	(1,779)
Production	[1]	(29,878)	(28,098)	(29,297)
Net proved reserves - end of period	[1]	416,366	382,875	467,068
Natural Gas (MMcf)
Reserve Quantities [Line Items]
Net proved developed reserves | MMcf		2,082,400	2,528,300	3,528,300	3,213,400
Net proved undeveloped reserves | MMcf		1,235,500	1,297,600	1,814,300	1,831,400
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period | MMcf	[2]	3,825,900	5,342,600	5,044,800
Revisions of previous estimates | MMcf	[2]	333,100	(1,430,700)	270,600
Purchases in place | MMcf	[2]	91,500	72,300	17,100
Extensions, discoveries and other additions | MMcf	[2]	262,000	332,400	647,500
Sales in place | MMcf	[2]	(752,000)	(15,000)	(131,100)
Production | MMcf	[2]	(442,600)	(475,700)	(506,300)
Net proved reserves - end of period | MMcf	[2]	3,317,900	3,825,900	5,342,600
Oil Equivalents (MBoe)
Reserve Quantities [Line Items]
Net proved undeveloped reserve (MBOE) | MBoe		1,053,027	1,045,640	1,149,309	991,067
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved reserves - beginning of period | MBoe	[1]	2,118,117	2,497,256	2,118,543
Revisions of previous estimates | MBoe	[1]	152,242	(466,604)	100,568
Purchases in place | MBoe	[1]	42,330	56,215	14,367
Extensions, discoveries and other additions | MBoe	[1]	208,963	245,931	519,167
Sales in place | MBoe	[1]	(167,669)	(3,506)	(36,263)
Production | MBoe	[1]	(207,050)	(211,175)	(219,126)
Net proved reserves - end of period | MBoe	[1]	2,146,933	2,118,117	2,497,256
United States
Reserve Quantities [Line Items]
Net proved developed reserves (MBOE) | MBoe		1,038,483	1,018,491	1,275,447	1,015,359
United States | Crude Oil (MBbl)
Reserve Quantities [Line Items]
Net proved developed reserves		507,531	444,070	493,694	382,517
Net proved undeveloped reserves		660,960	643,790	635,988	497,532
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	1,087,860	1,129,682	880,049
Revisions of previous estimates	[1]	42,040	(114,924)	28,301
Purchases in place	[1]	25,795	35,922	9,705
Extensions, discoveries and other additions	[1]	123,441	141,310	319,540
Sales in place	[1]	(8,791)	(730)	(4,967)
Production	[1]	(101,854)	(103,400)	(102,946)
Net proved reserves - end of period	[1]	1,168,491	1,087,860	1,129,682
United States | Natural Gas Liquids (MBbl)
Reserve Quantities [Line Items]
Net proved developed reserves		230,219	205,898	264,611	199,964
Net proved undeveloped reserves		186,147	176,977	202,319	176,038
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	382,875	466,930	376,002
Revisions of previous estimates	[1]	53,771	(113,290)	27,450
Purchases in place	[1]	1,284	8,251	1,812
Extensions, discoveries and other additions	[1]	41,862	49,147	91,683
Sales in place	[1]	(33,548)	(84)	(956)
Production	[1]	(29,878)	(28,079)	(29,061)
Net proved reserves - end of period	[1]	416,366	382,875	466,930
United States | Natural Gas (MMcf)
Reserve Quantities [Line Items]
Net proved developed reserves | MMcf		1,804,400	2,211,200	3,102,800	2,597,300
Net proved undeveloped reserves | MMcf		1,216,800	1,278,600	1,802,700	1,801,400
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period | MMcf	[2]	3,489,800	4,905,500	4,398,700
Revisions of previous estimates | MMcf	[2]	298,400	(1,453,100)	252,200
Purchases in place | MMcf	[2]	91,500	72,300	17,100
Extensions, discoveries and other additions | MMcf	[2]	202,100	306,300	638,300
Sales in place | MMcf	[2]	(752,000)	(3,900)	(52,400)
Production | MMcf	[2]	(308,600)	(337,300)	(348,400)
Net proved reserves - end of period | MMcf	[2]	3,021,200	3,489,800	4,905,500
United States | Oil Equivalents (MBoe)
Reserve Quantities [Line Items]
Net proved undeveloped reserve (MBOE) | MBoe		1,049,909	1,033,870	1,138,755	973,807
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved reserves - beginning of period | MBoe	[1]	2,052,361	2,414,202	1,989,166
Revisions of previous estimates | MBoe	[1]	145,542	(470,401)	97,782
Purchases in place | MBoe	[1]	42,330	56,215	14,367
Extensions, discoveries and other additions | MBoe	[1]	198,973	241,513	517,613
Sales in place | MBoe	[1]	(167,669)	(1,467)	(14,661)
Production | MBoe	[1]	(183,145)	(187,701)	(190,065)
Net proved reserves - end of period | MBoe	[1]	2,088,392	2,052,361	2,414,202
Trinidad
Reserve Quantities [Line Items]
Net proved developed reserves (MBOE) | MBoe		44,543	50,677	67,484	83,933
Trinidad | Crude Oil (MBbl)
Reserve Quantities [Line Items]
Net proved developed reserves		839	1,069	1,339	1,505
Net proved undeveloped reserves		0	0	0	85
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1]	1,069	1,339	1,590
Revisions of previous estimates	[1]	54	(1)	99
Purchases in place	[1]	0	0	0
Extensions, discoveries and other additions	[1]	0	63	0
Sales in place	[1]	0	0	0
Production	[1]	(284)	(332)	(350)
Net proved reserves - end of period	[1]	839	1,069	1,339
Trinidad | Natural Gas Liquids (MBbl)
Reserve Quantities [Line Items]
Net proved developed reserves		0	0	0	0
Net proved undeveloped reserves		0	0	0	0
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
Trinidad | Natural Gas (MMcf)
Reserve Quantities [Line Items]
Net proved developed reserves | MMcf		262,200	297,600	396,900	494,600
Net proved undeveloped reserves | MMcf		18,700	19,000	8,700	26,100
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period | MMcf	[2]	316,600	405,600	520,700
Revisions of previous estimates | MMcf	[2]	29,500	16,800	12,900
Purchases in place | MMcf	[2]	0	0	0
Extensions, discoveries and other additions | MMcf	[2]	59,900	21,700	4,500
Sales in place | MMcf	[2]	0	0	0
Production | MMcf	[2]	(125,100)	(127,500)	(132,500)
Net proved reserves - end of period | MMcf	[2]	280,900	316,600	405,600
Trinidad | Oil Equivalents (MBoe)
Reserve Quantities [Line Items]
Net proved undeveloped reserve (MBOE) | MBoe		3,118	3,166	1,453	4,431
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved reserves - beginning of period | MBoe	[1]	53,843	68,937	88,364
Revisions of previous estimates | MBoe	[1]	4,978	2,802	2,245
Purchases in place | MBoe	[1]	0	0	0
Extensions, discoveries and other additions | MBoe	[1]	9,990	3,682	758
Sales in place | MBoe	[1]	0	0	0
Production | MBoe	[1]	(21,150)	(21,578)	(22,430)
Net proved reserves - end of period | MBoe	[1]	47,661	53,843	68,937
Other International
Reserve Quantities [Line Items]
Net proved developed reserves (MBOE) | MBoe	[3]	10,880	3,309	5,016	28,184
Other International | Crude Oil (MBbl)
Reserve Quantities [Line Items]
Net proved developed reserves	[3]	8,255	63	115	7,034
Net proved undeveloped reserves	[3]	0	8,604	8,614	11,867
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1],[3]	8,667	8,729	18,901
Revisions of previous estimates	[1],[3]	861	0	(378)
Purchases in place	[1],[3]	0	0	0
Extensions, discoveries and other additions	[1],[3]	0	13	14
Sales in place	[1],[3]	0	(10)	(7,656)
Production	[1],[3]	(1,273)	(65)	(2,152)
Net proved reserves - end of period	[1],[3]	8,255	8,667	8,729
Other International | Natural Gas Liquids (MBbl)
Reserve Quantities [Line Items]
Net proved developed reserves	[3]	0	0	138	896
Net proved undeveloped reserves	[3]	0	0	0	308
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period	[1],[3]	0	138	1,204
Revisions of previous estimates	[1],[3]	0	68	(7)
Purchases in place	[1],[3]	0	0	0
Extensions, discoveries and other additions	[1],[3]	0	0	0
Sales in place	[1],[3]	0	(187)	(823)
Production	[1],[3]	0	(19)	(236)
Net proved reserves - end of period	[1],[3]	0	0	138
Other International | Natural Gas (MMcf)
Reserve Quantities [Line Items]
Net proved developed reserves | MMcf	[3]	15,800	19,500	28,600	121,500
Net proved undeveloped reserves | MMcf	[3]	0	0	2,900	3,900
Proved Developed Reserves [Rollforward]
Net proved reserves - beginning of period | MMcf	[2],[3]	19,500	31,500	125,400
Revisions of previous estimates | MMcf	[2],[3]	5,200	5,600	5,500
Purchases in place | MMcf	[2],[3]	0	0	0
Extensions, discoveries and other additions | MMcf	[2],[3]	0	4,400	4,700
Sales in place | MMcf	[2],[3]	0	(11,100)	(78,700)
Production | MMcf	[2],[3]	(8,900)	(10,900)	(25,400)
Net proved reserves - end of period | MMcf	[2],[3]	15,800	19,500	31,500
Other International | Oil Equivalents (MBoe)
Reserve Quantities [Line Items]
Net proved undeveloped reserve (MBOE) | MBoe	[3]	0	8,604	9,101	12,829
Proved Developed Reserves (MBoe) [Roll Forward]
Net proved reserves - beginning of period | MBoe	[1],[3]	11,913	14,117	41,013
Revisions of previous estimates | MBoe	[1],[3]	1,722	995	541
Purchases in place | MBoe	[1],[3]	0	0	0
Extensions, discoveries and other additions | MBoe	[1],[3]	0	736	796
Sales in place | MBoe	[1],[3]	0	(2,039)	(21,602)
Production | MBoe	[1],[3]	(2,755)	(1,896)	(6,631)
Net proved reserves - end of period | MBoe	[1],[3]	10,880	11,913	14,117
[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, 2016		Dec. 31, 2015		Dec. 31, 2014
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Unproved		$ 3,216,634	[1]	$ 133,857		$ 370,414
Acquisition Costs of Properties - Proved		749,023	[2]	480,617		139,101
Subtotal		3,965,657		614,474		509,515
Exploration Costs		165,751		252,692		395,973
Development Costs		2,313,876	[3]	4,061,117	[4]	6,999,281	[5]
Total		6,445,284		4,928,283		7,904,769
United States
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Unproved		3,216,598	[1]	133,801		365,915
Acquisition Costs of Properties - Proved		749,023	[2]	480,617		138,772
Subtotal		3,965,621		614,418		504,687
Exploration Costs		156,295		206,814		332,703
Development Costs		2,252,713	[3]	3,847,813	[4]	6,638,192	[5]
Total		6,374,629		4,669,045		7,475,582
Trinidad
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Unproved		0	[1]	0		0
Acquisition Costs of Properties - Proved		0	[2]	0		0
Subtotal		0		0		0
Exploration Costs		2,695		22,837		2,794
Development Costs		72,147	[3]	102,715	[4]	89,555	[5]
Total		74,842		125,552		92,349
Other International
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Unproved	[6]	36	[1]	56		4,499
Acquisition Costs of Properties - Proved	[6]	0	[2]	0		329
Subtotal	[6]	36		56		4,828
Exploration Costs	[6]	6,761		23,041		60,476
Development Costs	[6]	(10,984)	[3]	110,589	[4]	271,534	[5]
Total	[6]	$ (4,187)		$ 133,686		$ 336,838
[1]	Includes non-cash unproved leasehold acquisition costs of $3,102 million related to the Yates transaction.
[2]	Includes non-cash proved property acquisition costs of $732 million related to the Yates transaction.
[3]	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.
[4]	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.
[5]	Includes Asset Retirement Costs of $149 million, $14 million and $33 million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment.
[6]	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, 2016	Dec. 31, 2015	Dec. 31, 2014
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]	$ 5,496,743	$ 6,403,258	$ 12,592,917
Other	[1]	81,403	47,909	54,244
Total	[1]	5,578,146	6,451,167	12,647,161
Exploration Costs	[1]	124,953	149,494	184,388
Dry Hole Costs	[1]	10,657	14,746	48,490
Transportation Costs	[1]	764,106	849,319	972,176
Production Costs	[1]	1,254,013	1,581,131	2,150,027
Impairments	[1]	620,267	6,613,546	743,575
Depreciation, Depletion and Amortization	[1]	3,437,284	3,190,443	3,881,720
Income (Loss) Before Income Taxes	[1]	(633,134)	(5,947,512)	4,666,785
Income Tax Provision (Benefit)	[1]	(226,413)	(2,086,555)	1,821,104
Results of Operations	[1]	(406,721)	(3,860,957)	2,845,681
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]	5,177,989	5,962,753	11,771,777
Other	[1]	81,386	47,464	49,950
Total	[1]	5,259,375	6,010,217	11,821,727
Exploration Costs	[1]	115,990	139,753	162,434
Dry Hole Costs	[1]	10,529	956	25,408
Transportation Costs	[1]	753,791	838,428	957,522
Production Costs	[1]	1,163,827	1,486,189	1,940,074
Impairments	[1]	611,297	6,402,908	331,792
Depreciation, Depletion and Amortization	[1]	3,249,792	3,017,386	3,571,313
Income (Loss) Before Income Taxes	[1]	(645,851)	(5,875,403)	4,833,184
Income Tax Provision (Benefit)	[1]	(230,377)	(2,128,183)	1,722,914
Results of Operations	[1]	(415,474)	(3,747,220)	3,110,270
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]	243,708	381,761	512,675
Other	[1]	(8)	(3)	37
Total	[1]	243,700	381,758	512,712
Exploration Costs	[1]	2,647	2,071	2,185
Dry Hole Costs	[1]	0	5,635	0
Transportation Costs	[1]	1,181	1,290	617
Production Costs	[1]	27,113	28,862	38,301
Impairments	[1]	7,773	0	0
Depreciation, Depletion and Amortization	[1]	145,440	154,588	188,250
Income (Loss) Before Income Taxes	[1]	59,546	189,312	283,359
Income Tax Provision (Benefit)	[1]	5,526	43,739	74,588
Results of Operations	[1]	54,020	145,573	208,771
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]	75,046	58,744	308,465
Other	[1],[2]	25	448	4,257
Total	[1],[2]	75,071	59,192	312,722
Exploration Costs	[1],[2]	6,316	7,670	19,769
Dry Hole Costs	[1],[2]	128	8,155	23,082
Transportation Costs	[1],[2]	9,134	9,601	14,037
Production Costs	[1],[2]	63,073	66,080	171,652
Impairments	[1],[2]	1,197	210,638	411,783
Depreciation, Depletion and Amortization	[1],[2]	42,052	18,469	122,157
Income (Loss) Before Income Taxes	[1],[2]	(46,829)	(261,421)	(449,758)
Income Tax Provision (Benefit)	[1],[2]	(1,562)	(2,111)	23,602
Results of Operations	[1],[2]	$ (45,267)	$ (259,310)	$ (473,360)
[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, 2016.
[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, 2016	Dec. 31, 2015	Dec. 31, 2014
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent		4.48	5.85	6.46
United States
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent		4.58	5.81	6.44
Trinidad
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent		1.23	1.29	1.34
Other International
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent	[1]	22.43	33.78	24.60
[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) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows					$ 58,840,424	[1]	$ 68,720,648	[2]	$ 146,950,221	[3]
Future production costs					(28,018,883)		(32,060,855)		(51,633,293)
Future development costs					(12,741,932)		(15,785,811)		(20,494,765)
Future income taxes					(3,211,320)		(4,616,201)		(23,185,714)
Future net cash flows					14,868,289		16,257,781		51,636,449
Discount to present value at 10% annual rate					(6,056,132)		(6,636,385)		(23,713,031)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves		$ 9,621,396	$ 27,923,418	$ 21,333,432	8,812,157		9,621,396		27,923,418
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		$ 9,621,396	$ 27,923,418	$ 21,333,432
Sales and transfers of oil and gas produced, net of production costs		(3,478,625)	(4,020,717)	(9,470,714)
Net changes in prices and production costs		(3,679,602)	(30,669,350)	1,263,177
Extensions, discoveries, additions and improved recovery, net of related costs		907,267	1,095,898	8,083,852
Development costs incurred		1,230,000	2,137,700	2,835,100
Revisions of estimated development cost		2,121,708	4,079,381	1,802,735
Revisions of previous quantity estimates		1,053,020	(4,051,874)	1,812,532
Accretion of discount		1,054,435	3,857,479	2,833,350
Net change in income taxes		868,038	9,728,423	(3,651,300)
Purchases of reserves in place		377,872	123,542	317,785
Sales of reserves in place		(375,793)	(37,088)	(478,879)
Changes in timing and other		(887,559)	(545,416)	1,242,348
Balance at End of Period		8,812,157	9,621,396	27,923,418
United States
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows					57,913,314	[1]	67,242,928	[2]	144,355,692	[3]
Future production costs					(27,625,833)		(31,707,743)		(51,112,604)
Future development costs					(12,602,699)		(15,579,923)		(20,270,439)
Future income taxes					(3,151,319)		(4,400,542)		(22,725,618)
Future net cash flows					14,533,463		15,554,720		50,247,031
Discount to present value at 10% annual rate					(6,039,736)		(6,589,253)		(23,542,990)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves		8,965,467	26,704,041	19,576,901	8,493,727		8,965,467		26,704,041
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		8,965,467	26,704,041	19,576,901
Sales and transfers of oil and gas produced, net of production costs		(3,260,372)	(3,685,600)	(8,874,180)
Net changes in prices and production costs		(3,352,802)	(29,993,699)	1,481,668
Extensions, discoveries, additions and improved recovery, net of related costs		865,066	1,028,410	8,074,550
Development costs incurred		1,207,000	2,135,800	2,818,800
Revisions of estimated development cost		2,092,769	4,087,093	1,696,916
Revisions of previous quantity estimates		1,013,753	(4,084,572)	1,741,918
Accretion of discount		970,388	3,699,330	2,612,286
Net change in income taxes		738,416	9,550,847	(3,743,300)
Purchases of reserves in place		377,872	123,542	317,785
Sales of reserves in place		(375,793)	(23,424)	(189,808)
Changes in timing and other		(748,037)	(576,301)	1,190,505
Balance at End of Period		8,493,727	8,965,467	26,704,041
Trinidad
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows					524,523	[1]	954,779	[2]	1,615,280	[3]
Future production costs					(165,757)		(183,607)		(277,844)
Future development costs					(103,631)		(140,541)		(84,576)
Future income taxes					(60,001)		(215,659)		(460,096)
Future net cash flows					195,134		414,972		792,764
Discount to present value at 10% annual rate					(9,384)		(33,848)		(110,228)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves		381,124	682,536	876,640	185,750		381,124		682,536
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		381,124	682,536	876,640
Sales and transfers of oil and gas produced, net of production costs		(215,414)	(351,606)	(473,757)
Net changes in prices and production costs		(182,876)	(370,503)	(12,079)
Extensions, discoveries, additions and improved recovery, net of related costs		42,201	47,613	3,113
Development costs incurred		3,900	500	12,800
Revisions of estimated development cost		22,596	(34,647)	9,981
Revisions of previous quantity estimates		36,648	33,285	35,001
Accretion of discount		56,566	104,464	133,019
Net change in income taxes		129,622	177,576	91,438
Purchases of reserves in place		0	0	0
Sales of reserves in place		0	0	0
Changes in timing and other		(88,617)	91,906	6,380
Balance at End of Period		185,750	381,124	682,536
Other International (1)
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	[4]				402,587	[1]	522,941	[2]	979,249	[3]
Future production costs	[4]				(227,293)		(169,505)		(242,845)
Future development costs	[4]				(35,602)		(65,347)		(139,750)
Future income taxes	[4]				0		0		0
Future net cash flows	[4]				139,692		288,089		596,654
Discount to present value at 10% annual rate	[4]				(7,012)		(13,284)		(59,813)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	[4]	274,805	536,841	879,891	$ 132,680		$ 274,805		$ 536,841
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]	274,805	536,841	879,891
Sales and transfers of oil and gas produced, net of production costs	[4]	(2,839)	16,489	(122,777)
Net changes in prices and production costs	[4]	(143,924)	(305,148)	(206,412)
Extensions, discoveries, additions and improved recovery, net of related costs	[4]	0	19,875	6,189
Development costs incurred	[4]	19,100	1,400	3,500
Revisions of estimated development cost	[4]	6,343	26,935	95,838
Revisions of previous quantity estimates	[4]	2,619	(587)	35,613
Accretion of discount	[4]	27,481	53,685	88,045
Net change in income taxes	[4]	0	0	562
Purchases of reserves in place	[4]	0	0	0
Sales of reserves in place	[4]	0	(13,664)	(289,071)
Changes in timing and other	[4]	(50,905)	(61,021)	45,463
Balance at End of Period	[4]	$ 132,680	$ 274,805	$ 536,841
[1]	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.
[2]	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.
[3]	Estimated crude oil prices used to calculate 2014 future cash inflows for the United States, Trinidad and Other International were $97.51, $80.60 and $94.09, respectively. Estimated NGL prices used to calculate 2014 future cash inflows for the United States and Other International were $34.29 and $27.03, respectively. Estimated natural gas prices used to calculate 2014 future cash inflows for the United States, Trinidad and Other International were $3.71, $3.71 and $5.14, 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, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Net Operating Revenues	$ 2,402,039		$ 2,118,504		$ 1,775,740		$ 1,354,349		$ 1,796,761		$ 2,172,428		$ 2,469,701		$ 2,318,538		$ 7,650,632	[1]	$ 8,757,428	[2]	$ 18,035,340	[3]
Operating Income	(105,487)		(193,480)		(288,173)		(638,141)		(329,753)		(6,222,957)		39,626		(172,995)		(1,225,281)		(6,686,079)		5,241,823
Income (Loss) Before Income Taxes	(194,010)		(272,250)		(380,277)		(710,968)		(398,826)		(6,274,921)		(11,478)		(236,331)		(1,557,505)		(6,921,556)		4,995,315
Income Tax (Benefit) Provision	(51,658)		(82,250)		(87,719)		(239,192)		(114,530)		(2,199,182)		(16,746)		(66,583)		(460,819)		(2,397,041)		2,079,828
Net Income (Loss)	$ (142,352)		$ (190,000)		$ (292,558)		$ (471,776)		$ (284,296)		$ (4,075,739)		$ 5,268		$ (169,748)		$ (1,096,686)		$ (4,524,515)		$ 2,915,487
Net Income (Loss) Per Share
Basic (in dollars per share)	$ (0.25)	[4]	$ (0.35)	[4]	$ (0.53)	[4]	$ (0.86)	[4]	$ (0.52)	[4]	$ (7.47)	[4]	$ 0.01	[4]	$ (0.31)	[4]	$ (1.98)		$ (8.29)		$ 5.36
Diluted (in dollars per share)	$ (0.25)	[4]	$ (0.35)	[4]	$ (0.53)	[4]	$ (0.86)	[4]	$ (0.52)	[4]	$ (7.47)	[4]	$ 0.01	[4]	$ (0.31)	[4]	$ (1.98)		$ (8.29)		$ 5.32
Average Number of Common Shares [Abstract]
Basic (in shares)	567,337		547,838		547,335		546,715		546,432		545,920		545,504		544,998		553,384		545,697		543,443
Diluted (in shares)	567,337		547,838		547,335		546,715		546,432		545,920		549,683		544,998		553,384		545,697		548,539
[1]	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 in the United States segment.
[2]	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 in the United States segment.
[3]	EOG had sales activity with two significant purchasers in 2014, one totaling $4.0 billion and the other totaling $3.0 billion of consolidated Net Operating Revenues in the United States segment.
[4]	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.