EOG Resources (EOG) 10-K 18 Feb 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Feb. 10, 2015	Jun. 30, 2014
Document and Entity Information [Abstract]
Entity Registrant Name	EOG RESOURCES INC
Entity Central Index Key	821189
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$63,532,000,000
Entity Common Stock, Shares Outstanding		548,445,003
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14

Consolidated_Statements_of_Inc

Consolidated Statements of Income and Comprehensive Income (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Net Operating Revenues
Crude Oil and Condensate	$9,742,480	$8,300,647	$5,659,437
Natural Gas Liquids	934,051	773,970	727,177
Natural Gas	1,916,386	1,681,029	1,571,762
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts	834,273	-166,349	393,744
Gathering, Processing and Marketing	4,046,316	3,643,749	3,096,694
Gains on Asset Dispositions, Net	507,590	197,565	192,660
Other, Net	54,244	56,507	41,162
Total	18,035,340	14,487,118	11,682,636
Operating Expenses
Lease and Well	1,416,413	1,105,978	1,000,052
Transportation Costs	972,176	853,044	601,431
Gathering and Processing Costs	145,800	107,871	97,945
Exploration Costs	184,388	161,346	185,569
Dry Hole Costs	48,490	74,655	14,970
Impairments	743,575	286,941	1,270,735
Marketing Costs	4,126,060	3,648,840	3,035,494
Depreciation, Depletion and Amortization	3,997,041	3,600,976	3,169,703
General and Administrative	402,010	348,312	331,545
Taxes Other Than Income	757,564	623,944	495,395
Total	12,793,517	10,811,907	10,202,839
Operating Income	5,241,823	3,675,211	1,479,797
Other Income (Expense), Net	-45,050	-2,865	14,495
Income Before Interest Expense and Income Taxes	5,196,773	3,672,346	1,494,292
Interest Expense
Incurred	258,628	284,599	263,254
Capitalized	-57,170	-49,139	-49,702
Net Interest Expense	201,458	235,460	213,552
Income Before Income Taxes	4,995,315	3,436,886	1,280,740
Income Tax Provision	2,079,828	1,239,777	710,461
Net Income	2,915,487	2,197,109	570,279
Net Income Per Share
Basic (in dollars per share)	$5.36	$4.07	$1.07
Diluted (in dollars per share)	$5.32	$4.02	$1.05
Dividends Declared per Common Share	$0.59	$0.38	$0.34
Average Number of Common Shares [Abstract]
Basic (in shares)	543,443	540,341	535,155
Diluted (in shares)	548,539	546,227	541,524
Statement Of Comprehensive Income [Abstract]
Net Income	2,915,487	2,197,109	570,279
Other Comprehensive Income (Loss)
Foreign Currency Translation Adjustments	-437,728	-29,395	37,739
Foreign Currency Swap Transaction	50	1,652	1,589
Income Tax Related to Foreign Currency Swap Transaction	-670	1	-404
Interest Rate Swap Transaction	777	2,737	-134
Income Tax Related to Interest Rate Swap Transaction	-281	-981	48
Other	-1,038	1,925	-689
Other Comprehensive Income (Loss)	-438,890	-24,061	38,149
Comprehensive Income	$2,476,597	$2,173,048	$608,428

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current Assets
Cash and Cash Equivalents	$2,087,213	$1,318,209
Accounts Receivable, Net	1,779,311	1,658,853
Inventories	706,597	563,268
Assets from Price Risk Management Activities	465,128	8,260
Income Taxes Receivable	71,621	4,797
Deferred Income Taxes	19,618	244,606
Other	286,533	274,022
Total	5,416,021	4,072,015
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method)	46,503,532	42,821,803
Other Property, Plant and Equipment	3,750,958	2,967,085
Total Property, Plant and Equipment	50,254,490	45,788,888
Less: Accumulated Depreciation, Depletion and Amortization	-21,081,846	-19,640,052
Total Property, Plant and Equipment, Net	29,172,644	26,148,836
Other Assets	174,022	353,387
Total Assets	34,762,687	30,574,238
Current Liabilities
Accounts Payable	2,860,548	2,254,418
Accrued Taxes Payable	140,098	159,365
Dividends Payable	91,594	50,795
Liabilities from Price Risk Management Activities	0	127,542
Deferred Income Taxes	110,743	0
Current Portion of Long-Term Debt	6,579	6,579
Other	174,746	263,017
Total	3,384,308	2,861,716
Long-Term Debt	5,903,354	5,906,642
Other Liabilities	939,497	865,067
Deferred Income Taxes	6,822,946	5,522,354
Commitments and Contingencies (Note 8)
Stockholders' Equity
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 549,028,374 Shares and 546,378,440 Shares Issued at December 31, 2014 and 2013, respectively	205,492	202,732
Additional Paid in Capital	2,837,150	2,646,879
Accumulated Other Comprehensive Income (Loss)	-23,056	415,834
Retained Earnings	14,763,098	12,168,277
Common Stock Held in Treasury, 733,517 Shares and 206,830 Shares at December 31, 2014 and 2013, respectively	-70,102	-15,263
Total Stockholders' Equity	17,712,582	15,418,459
Total Liabilities and Stockholders' Equity	$34,762,687	$30,574,238

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
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)	549,028,374	546,378,440
Treasury Stock
Common Stock Held in Treasury (in shares)	733,517	206,830

Consolidated_Statements_of_Sto

Consolidated Statements of Stockholders' Equity (USD $)	Total	Common Stock Held in Treasury [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Additional Paid-in Capital [Member]	Common Stock [Member]
In Thousands, except Per Share data
Balance at Dec. 31, 2011	$12,640,904	($24,932)	$9,789,345	$401,746	$2,272,052	$202,693
Common Stock Dividends Declared (in dollars per share)	$0.34
Net Income	570,279	0	570,279	0	0	0
Common Stock Issued Under Stock Plans	83,218	0	0	0	83,197	21
Dividends, Common Stock	-183,993	0	-183,993	0	0	0
Other Comprehensive Income (Loss)	38,149	0	0	38,149	0	0
Change in Treasury Stock - Stock Compensation Plans, Net	-58,588	-11,465	0	0	-47,123	0
Excess Tax Benefit from Stock-Based Compensation	67,035	0	0	0	67,035	0
Restricted Stock and Restricted Stock Units, Net	0	2,358	0	0	-2,364	6
Stock-Based Compensation Expenses	127,504	0	0	0	127,504	0
Treasury Stock Issued as Compensation	256	217	0	0	39	0
Balance at Dec. 31, 2012	13,284,764	-33,822	10,175,631	439,895	2,500,340	202,720
Common Stock Dividends Declared (in dollars per share)	$0.38
Net Income	2,197,109	0	2,197,109	0	0	0
Common Stock Issued Under Stock Plans	38,729	0	0	0	38,723	6
Dividends, Common Stock	-204,463		-204,463
Other Comprehensive Income (Loss)	-24,061	0	0	-24,061	0	0
Change in Treasury Stock - Stock Compensation Plans, Net	-32,214	47,427	0	0	-79,641	0
Excess Tax Benefit from Stock-Based Compensation	55,831	0	0	0	55,831	0
Restricted Stock and Restricted Stock Units, Net	-31,422	-28,454			-2,974	6
Stock-Based Compensation Expenses	134,467	0	0	0	134,467	0
Treasury Stock Issued as Compensation	-281	-414	0	0	133	0
Balance at Dec. 31, 2013	15,418,459	-15,263	12,168,277	415,834	2,646,879	202,732
Common Stock Dividends Declared (in dollars per share)	$0.59
Net Income	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

Consolidated_Statements_of_Sto1

Consolidated Statements of Stockholders' Equity (Parenthetical) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Stockholders' Equity [Abstract]
Dividends, Common Stock	($320,666)	($204,463)	($183,993)
Common Stock Dividends Declared (in dollars per share)	$0.59	$0.38	$0.34

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash Flows from Operating Activities
Net Income	$2,915,487	$2,197,109	$570,279
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization	3,997,041	3,600,976	3,169,703
Impairments	743,575	286,941	1,270,735
Stock-Based Compensation Expenses	145,086	134,055	127,778
Deferred Income Taxes	1,704,946	874,765	292,938
Gains on Asset Dispositions, Net	-507,590	-197,565	-192,660
Other, Net	48,138	11,072	672
Dry Hole Costs	48,490	74,655	14,970
Mark-to-Market Commodity Derivative Contracts
Total (Gains) Losses	-834,273	166,349	-393,744
Net Cash Received from Settlements of Commodity Derivative Contracts	34,007	116,361	711,479
Excess Tax Benefits from Stock-Based Compensation	-99,459	-55,831	-67,035
Other, Net	13,009	18,205	14,411
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable	84,982	-23,613	-178,683
Inventories	-161,958	53,402	-156,762
Accounts Payable	543,630	178,701	-17,150
Accrued Taxes Payable	16,486	75,142	78,094
Other Assets	-14,448	-109,567	-118,520
Other Liabilities	75,420	-20,382	36,114
Changes in Components of Working Capital Associated with Investing and Financing Activities	-103,414	-51,361	74,158
Net Cash Provided by Operating Activities	8,649,155	7,329,414	5,236,777
Investing Cash Flows
Additions to Oil and Gas Properties	-7,519,667	-6,697,091	-6,735,316
Additions to Other Property, Plant and Equipment	-727,138	-363,536	-619,800
Proceeds from Sales of Assets	569,332	760,557	1,309,776
Changes in Restricted Cash	60,385	-65,814	0
Changes in Components of Working Capital Associated with Investing Activities	103,523	51,106	-73,923
Net Cash Used in Investing Activities	-7,513,565	-6,314,778	-6,119,263
Financing Cash Flows
Long-Term Debt Borrowings	496,220	0	1,234,138
Long-Term Debt Repayments	-500,000	-400,000	0
Settlement of Foreign Currency Swap	-31,573	0	0
Dividends Paid	-279,695	-199,178	-181,080
Excess Tax Benefits from Stock-Based Compensation	99,459	55,831	67,035
Treasury Stock Purchased	-127,424	-63,784	-58,592
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan	22,249	38,730	82,887
Debt Issuance Costs	-895	0	-1,578
Repayment of Capital Lease Obligation	-5,966	-5,780	-2,824
Other, Net	-109	255	-235
Net Cash Provided by (Used in) Financing Activities	-327,734	-573,926	1,139,751
Effect of Exchange Rate Changes on Cash	-38,852	1,064	3,444
Increase in Cash and Cash Equivalents	769,004	441,774	260,709
Cash and Cash Equivalents at Beginning of Period	1,318,209	876,435	615,726
Cash and Cash Equivalents at End of Period	$2,087,213	$1,318,209	$876,435

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Summary of Significant Accounting Policies [Text Block]	1.  Summary of Significant Accounting Policies
	Principles of Consolidation.  The consolidated financial statements of EOG Resources, Inc. (EOG) include the accounts of all domestic and foreign subsidiaries.  Investments in unconsolidated affiliates, in which EOG is able to exercise significant influence, are accounted for using the equity method.  All intercompany accounts and transactions have been eliminated.
	The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.
	On February 24, 2014, EOG's Board of Directors (Board) approved a two-for-one stock split in the form of a stock dividend, payable to stockholders of record as of March 17, 2014, and paid on March 31, 2014. All share and per share amounts in the financial statements and these notes have been restated to reflect the two-for-one stock split.
	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, along with associated foreign currency and interest rate swaps.  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 charged to expense 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 (NGL) and natural gas are evidenced by signed contracts with determinable market prices, and revenues are recorded when production is delivered.  A significant majority of the purchasers of these products 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, NGL and natural gas, as well as gathering fees associated with gathering third-party natural gas.
	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, 2014, 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 certain of its Canadian subsidiaries, for which the functional currency is the Canadian dollar, and its United Kingdom subsidiary, for which the functional currency is the British pound.  For subsidiaries whose functional currency is deemed to be other than the United States dollar, asset and liability accounts are translated at year-end exchange rates and revenues and expenses are translated at average exchange rates prevailing during the year.  Translation adjustments are included in Accumulated Other Comprehensive Income on the Consolidated Balance Sheets.  Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period. See Note 17.
	Net Income Per Share.  Basic net income per share is computed on the basis of the weighted-average number of common shares outstanding during the period.  Diluted net income per share is computed based upon the weighted-average number of common shares outstanding during the period plus the assumed issuance of common shares for all potentially dilutive securities (see Note 9).
	Stock-Based Compensation. EOG measures the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (see Note 7).
	Recently Issued Accounting Standards. In April 2014, the FASB issued Accounting Standards Update (ASU) 2014-08, "Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity" (ASU 2014-08). ASU 2014-08 changes the criteria for reporting discontinued operations by requiring that in order for a disposal to qualify as a discontinued operation, the disposal must represent a strategic shift that has (or will have) a major effect on the entity's operations and financial results. ASU 2014-08 also requires additional disclosures both for discontinued operations and individually significant components of an entity that do not qualify as discontinued operations. ASU 2014-08 is effective for annual and interim periods beginning on or after December 15, 2014, with early adoption permitted. EOG has early-adopted the provisions of ASU 2014-08 and such adoption did not have a material impact on EOG's consolidated financial statements.
	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 will be effective for interim and annual reporting periods beginning after December 15, 2016, and permits adoption through the use of either the full retrospective approach or a modified retrospective approach.   Early application is not permitted. EOG has not determined which transition method it will use and is continuing to analyze ASU 2014-09 to determine what impact the new standard will have on its consolidated financial statements and related disclosures.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Long-Term Debt	2.  Long-Term Debt
	Long-Term Debt at December 31, 2014 and 2013 consisted of the following (in thousands):
		2014		2013
	Floating Rate Senior Notes due 2014	$	—	$	350,000
	2.95% Senior Notes due 2015	500,000		500,000
	2.500% Senior Notes due 2016	400,000		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		—
	4.100% Senior Notes due 2021	750,000		750,000
	2.625% Senior Notes due 2023	1,250,000		1,250,000
	6.65% Senior Notes due 2028	140,000		140,000
	4.75% Subsidiary Debt due 2014	—		150,000
	Total Long-Term Debt	5,890,000		5,890,000
	Capital Lease Obligation	51,221		57,187
	Less: Current Portion of Long-Term Debt	6,579		6,579
	Unamortized Debt Discount	31,288		33,966
	Total Long-Term Debt, Net	$	5,903,354	$	5,906,642
	At December 31, 2014, the aggregate annual maturities of long-term debt (excluding capital lease obligations) were $500 million in 2015, $400 million in 2016, $600 million in 2017, $350 million in 2018 and $900 million in 2019.  At December 31, 2014, $500 million aggregate principal amount of its 2.95% Senior Notes due 2015 were classified as long-term debt based upon EOG's intent and ability to ultimately replace such amounts with other long-term debt.
	During 2014 and 2013, EOG utilized commercial paper and short-term borrowings from uncommitted credit facilities, bearing market interest rates, for various corporate financing purposes.  EOG had no outstanding commercial paper borrowings or uncommitted credit facility borrowings at December 31, 2014 and 2013, respectively.  The average borrowings outstanding under the commercial paper program were $12 million and $37 million during the years ended December 31, 2014 and 2013, respectively.  The average borrowings outstanding under the uncommitted credit facilities were $0.1 million and zero during the years ended December 31, 2014 and 2013, respectively.  The weighted average interest rates for commercial paper borrowings were 0.25% and 0.30% for the years 2014 and 2013, respectively, and were 0.70% for uncommitted credit facility borrowings for the year 2014.
	EOG currently has a $2.0 billion senior unsecured Revolving Credit Agreement (Agreement) with domestic and foreign lenders.  The Agreement matures on October 11, 2016 and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods, subject to, among certain other terms and conditions, the consent of the lenders holding greater than 50% of the commitments then outstanding under the Agreement.  At December 31, 2014, there were no borrowings or letters of credit outstanding under the Agreement.  Advances under the Agreement accrue interest based, at EOG's option, on either the London InterBank Offered Rate (LIBOR) plus an applicable margin (Eurodollar rate), or the base rate (as defined in the Agreement) plus an applicable margin.  At December 31, 2014, the Eurodollar rate and applicable base rate, had there been any amounts borrowed under the Agreement, would have been 1.05% and 3.25%, respectively.
	The Agreement contains representations, warranties, covenants and events of default that are customary for investment grade, senior unsecured commercial bank credit agreements, including a financial covenant for the maintenance of a total debt-to-total capitalization ratio of no greater than 65%.  At December 31, 2014, and during the year then ended, EOG was in compliance with this financial debt covenant.
	On March 21, 2014, EOG closed its sale of the $500 million aggregate principal amount of its 2.45% Senior Notes due 2020 (Notes). Interest on the Notes is payable semi-annually in arrears on April 1 and October 1 of each year, beginning October 1, 2014. Net proceeds from the Notes offering of approximately $496 million were used for general corporate purposes.
	On March 17, 2014, EOG repaid upon maturity the $150 million aggregate principal amount of its 4.75% Subsidiary Debt due 2014 (Subsidiary Debt) and settled the foreign currency swap entered into contemporaneously with the issuance of the Subsidiary Debt for $32 million.
	On February 3, 2014, EOG repaid upon maturity the $350 million aggregate principal amount of its Floating Rate Senior Notes due 2014 (Floating Rate Notes). On the same date, EOG settled the interest rate swap entered into contemporaneously with the issuance of the Floating Rate Notes for $0.8 million.
	Restricted Cash. In order to comply with the Canadian Alberta Energy Regulator's requirements to post financial security for well abandonment obligations, former EOG subsidiary EOG Resources Canada Inc. (EOGRC) established a 160 million Canadian dollar letter of credit facility (subsequently increased to 190 million Canadian dollars), with Royal Bank of Canada (RBC) as the lender. The letter of credit facility required EOGRC to deposit cash, in an amount equal to all outstanding letters of credit under such facility, in a cash collateral account at RBC.  In connection with the sale of substantially all of EOG's Canadian assets in the fourth quarter of 2014, this letter of credit facility was amended and the then-outstanding cash collateral balance of 170 million Canadian dollars (approximately 150 million United States dollars) was released.  This letter of credit facility was transferred to the purchaser of the Alberta assets. See Note 17.

Stockholders_Equity

Stockholder's Equity	12 Months Ended
	Dec. 31, 2014
Stockholders' Equity Note [Abstract]
Stockholder's Equity	3.  Stockholders' Equity
	Common Stock.  In September 2001, EOG's Board of Directors (Board) authorized the purchase of an aggregate maximum of 10 million shares of Common Stock that superseded all previous authorizations.  At December 31, 2014, 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 or restricted stock unit grants or in payment of the exercise price of employee stock options.  Such shares withheld or returned do not count against the Board authorization discussed above.  Shares purchased, withheld and returned are held in treasury for, among other purposes, fulfilling any obligations arising under EOG's stock-based compensation plans and any other approved transactions or activities for which such shares of Common Stock may be required.
	On February 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 Board increased the quarterly cash dividend on the Common Stock to $0.0938 per share on February 13, 2013, effective beginning with the dividend paid on April 30, 2013, to stockholders of record as of April 16, 2013.
	The following summarizes Common Stock activity for each of the years ended December 31, 2012, 2013 and 2014 (in thousands):
		Common Shares
		Issued	Treasury		Outstanding
	Balance at December 31, 2011	538,646	(608	)	538,038
	Common Stock Issued Under Stock-Based Compensation Plans	4,942	—		4,942
	Treasury Stock Purchased (1)	—	(1,150	)	(1,150	)
	Common Stock Issued Under Employee Stock Purchase Plan	328	—		328
	Treasury Stock Issued Under Stock-Based Compensation Plans	—	1,106		1,106
	Balance at December 31, 2012	543,916	(652	)	543,264
	Common Stock Issued Under Stock-Based Compensation Plans	2,206	—		2,206
	Treasury Stock Purchased (1)	—	(854	)	(854	)
	Common Stock Issued Under Employee Stock Purchase Plan	256	—		256
	Treasury Stock Issued Under Stock-Based Compensation Plans	—	1,300		1,300
	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
	-1	Represents shares that were withheld by, or returned to, EOG in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or SARs, the vesting of restricted stock or restricted stock unit grants or 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, 2014, there were no shares of preferred stock outstanding.

Accumulated_Other_Comprehensiv

Accumulated Other Comprehensive Income	12 Months Ended
	Dec. 31, 2014
Accumulated Other Comprehensive Income [Abstract]
Accumulated Other Comprehensive Income	4.  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, 2014 and 2013 consisted of the following (in thousands):
		Foreign Currency Translation Adjustment				Foreign Currency Swap				Interest Rate Swap				Other (3)			Total
	31-Dec-13	$	417,707			$	620			$	(496	)		$	(1,997	)	$	415,834
	Other comprehensive loss before reclassifications	(54,484		)		—				—				(918		)	(55,402		)
	Amounts reclassified out of other comprehensive income (loss)	(383,244		)	(1)	(670		)	(2)	777			(2)	139			(382,998		)
	Tax effects	—				50				(281		)		(259		)	(490		)
	Other comprehensive income (loss)	(437,728		)		(620		)		496				(1,038		)	(438,890		)
	31-Dec-14	$	(20,021	)		$	—			$	—			$	(3,035	)	$	(23,056	)
	-1	Reclassified to Net Income - Gain on Asset Dispositions, Net. See Note 17.
	-2	Reclassified to Net Income - Interest Expense Incurred. See Note 2.
	-3	Related to certain EOG pension plans. See Note 7.
	No significant amounts were reclassified out of Accumulated Other Comprehensive Income (Loss) during the years ended December 31, 2013 and 2012.

Other_Income_Net

Other Income, Net	12 Months Ended
	Dec. 31, 2014
Other Income and Expenses [Abstract]
Other Income, Net	5.  Other Income (Expense), Net
	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).  Other income, net, for 2013 included net foreign currency transaction gains ($12 million), equity income from investments in ammonia plants in Trinidad ($11 million), interest income ($6 million) primarily related to sales and use tax refunds, and losses on dispositions of warehouse stock ($23 million).  Other income, net, for 2012 included equity income from investments in ammonia plants in Trinidad ($20 million), interest income ($9 million) primarily due to severance tax refunds, net foreign currency transaction gains ($7 million), losses on dispositions of warehouse stock ($10 million) and operating losses on EOG's investment in the proposed Pacific Trail Pipelines in Canada ($9 million).

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Taxes	6.  Income Taxes
	The principal components of EOG's net deferred income tax liabilities at December 31, 2014 and 2013 were as follows (in thousands):
		2014				2013
	Current Deferred Income Tax Assets (Liabilities)
	Commodity Hedging Contracts	$	—			$	29,582
	Deferred Compensation Plans	—				42,296
	Net Operating Loss	—				96,616
	Alternative Minimum Tax Credit Carryforward	—				72,297
	Foreign Net Operating Loss	49,865				—
	Foreign Valuation Allowance	(30,247		)		—
	Other	—				3,815
	Total Net Current Deferred Income Tax Assets	$	19,618			$	244,606
	Noncurrent Deferred Income Tax Assets (Liabilities)
	Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization	$	(141,643	)		$	(112,346	)
	Foreign Net Operating Loss	487,876				369,257
	Foreign Valuation Allowances	(349,704		)		(183,122		)
	Foreign Other	4,096				4,179
	Total Net Noncurrent Deferred Income Tax Assets	$	625			$	77,968
	Current Deferred Income Tax (Asset) Liabilities
	Commodity Hedging Contracts	$	166,109			$	—
	Deferred Compensation Plans	(48,207		)		—
	Accrued Expenses and Liabilities	(5,643		)		—
	Other	(1,516		)		—
	Total Net Current Deferred Income Tax Liabilities	$	110,743			$	—
	Noncurrent Deferred Income Tax (Assets) Liabilities
	Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization	$	7,634,297			$	6,287,541
	Non-Producing Leasehold Costs	(44,236		)		(50,581		)
	Seismic Costs Capitalized for Tax	(158,157		)		(136,964		)
	Equity Awards	(127,541		)		(122,665		)
	Capitalized Interest	97,739				101,006
	Alternative Minimum Tax Credit Carryforward	(793,126		)		(557,352		)
	Undistributed Foreign Earnings	249,861				—
	Other	(35,891		)		1,369
	Total Net Noncurrent Deferred Income Tax Liabilities	$	6,822,946			$	5,522,354
	Total Net Deferred Income Tax Liabilities	$	6,913,446			$	5,199,780
	The components of Income Before Income Taxes for the years indicated below were as follows (in thousands):
		2014				2013				2012
	United States	$	5,161,232			$	3,268,727			$	1,988,105
	Foreign	(165,917		)		168,159				(707,365		)
	Total	$	4,995,315			$	3,436,886			$	1,280,740
	The principal components of EOG's Income Tax Provision for the years indicated below were as follows (in thousands):
		2014				2013				2012
	Current:
	Federal	$	269,326			$	207,777			$	242,674
	State	22,835				22,856				22,573
	Foreign	82,721				134,379				152,276
	Total	374,882				365,012				417,523
	Deferred:
	Federal	1,608,706				915,994				454,173
	State	29,056				26,305				632
	Foreign	67,184				(67,534		)		(161,867		)
	Total	1,704,946				874,765				292,938
	Income Tax Provision	$	2,079,828			$	1,239,777			$	710,461
	The differences between taxes computed at the United States federal statutory tax rate and EOG's effective rate were as follows:
		2014			2013			2012
	Statutory Federal Income Tax Rate	35	%		35	%		35	%
	State Income Tax, Net of Federal Benefit	0.68			0.93			1.18
	Income Tax Provision Related to Foreign Operations	(0.12	)		0.23			1.11
	Canadian Divestiture	(3.46	)		—			—
	Undistributed Foreign Earnings	4.94			—			—
	Foreign Valuation Allowances	6.47			—			10.57
	Foreign Oil and Gas Impairments	(1.90	)		—			6.9
	Other	0.03			(0.09	)		0.71
	Effective Income Tax Rate	41.64	%		36.07	%		55.47	%
The effective tax rate of 42% in 2014 was higher than the prior year rate of 36% primarily due to valuation allowances in the United Kingdom and taxes on undistributed foreign earnings in the United States.
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, as of December 31, 2014, 2013 and 2012, cumulative valuation allowances of $463 million, $224 million and $200 million, respectively, have been recorded as EOG does not believe that certain foreign and state deferred tax assets are more likely than not to be realized.  Once established, these valuation allowances are subsequently adjusted for current year taxable profits or losses and future taxable income estimates.
The balance of unrecognized tax benefits at December 31, 2014, was zero. When applicable, EOG records interest and penalties related to unrecognized tax benefits to its income tax provision.  Currently, there are no amounts of interest or penalties recognized on the Consolidated Statements of Income and Comprehensive Income or on the Consolidated Balance Sheets.  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 in the United States and various state, local and foreign jurisdictions.  EOG is generally no longer subject to income tax examinations by tax authorities in the United States (federal), Canada, the United Kingdom, Trinidad and China for taxable years before 2011, 2010, 2013, 2002 and 2008, respectively.
EOG's foreign subsidiaries' undistributed earnings of approximately $1.8 billion at December 31, 2014, are no longer considered to be permanently reinvested outside the United States and, accordingly, EOG recorded $250 million of United States federal and state deferred income taxes in 2014.  EOG based its change in the permanent reinvestment assertion on a post-Canadian divestiture evaluation of its remaining foreign operations' capital requirements and projected foreign cash surpluses.
In 2014, EOG utilized a United States federal tax NOL of $940 million thereby fully exhausting the balance of federal tax NOLs carried forward from prior years.  However, as of December 31, 2014, EOG still had state income tax NOLs being carried forward of approximately $1.6 billion, which, if unused, expire between 2015 and 2034.  The Stock Compensation Topic of the ASC provides that when settlement of a stock award contributes to a NOL carryforward, neither the associated excess tax benefit nor the credit to Additional Paid in Capital (APIC) should be recorded until the stock award deduction reduces income taxes payable.  Due to the current-year utilization of the available NOLs, a benefit of $29 million was reflected in APIC.  In 2014, EOG paid alternative minimum tax (AMT) of $196 million.  The AMT paid in 2014, along with AMT of $597 million paid in prior years, will be carried forward indefinitely as a credit available to offset regular income taxes in future periods.
The ability of EOG to utilize the 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, 2014, management does not believe that an ownership change has occurred which would limit the carryforward.
During 2014, EOG's United Kingdom subsidiary incurred a tax NOL of approximately $246 million which, along with prior years' NOLs of $548 million, will be carried forward indefinitely. However, as a carryforward, the tax effect of these NOLs represent a future tax benefit (deferred tax asset) and must be evaluated for the likelihood of future utilization. Evaluations done in late 2014 indicate that not all of these NOLs may be utilized and therefore a valuation allowance was recorded in the fourth quarter of this year and is included in the aforementioned valuation allowance total.

Employee_Benefit_Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2014
Employee Benefit Plans [Abstract]
Employee Benefit Plans	7.  Employee Benefit Plans
	Stock-Based Compensation
	During 2014, 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 its 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, 2014, 2013 and 2012 was as follows (in millions):
		2014				2013				2012
	Lease and Well	$	41			$	35			$	35
	Gathering and Processing Costs	1				1				1
	Exploration Costs	27				27				27
	General and Administrative	76				71				65
	Total	$	145			$	134			$	128
	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, 2014, approximately 28.7 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 2014, 2013 and 2012, EOG issued shares in connection with stock option/SAR exercises, restricted stock and performance stock grants, restricted stock unit releases and ESPP purchases.  EOG recognized, as an adjustment to APIC, federal income tax benefits of $99 million, $56 million and $67 million for 2014, 2013 and 2012, respectively, related to the exercise of stock options/SARs and the release of restricted stock and restricted stock 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 not exceeded a maximum term of 10 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 $62 million, $53 million and $49 million for the years ended December 31, 2014, 2013 and 2012, respectively.
	Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants for the years ended December 31, 2014, 2013 and 2012 were as follows:
		Stock Options/SARs												ESPP
		2014				2013				2012				2014				2013				2012
	Weighted Average Fair Value of Grants	$	30.75			$	27.35			$	18.98			$	21.65			$	15.06			$	12.56
	Expected Volatility	35.28		%		35.86		%		39.68		%		25.03		%		29.89		%		40.92		%
	Risk-Free Interest Rate	0.95		%		0.78		%		0.45		%		0.08		%		0.11		%		0.11		%
	Dividend Yield	0.61		%		0.4		%		0.6		%		0.46		%		0.6		%		0.6		%
	Expected Life	5.2 years				5.5 years				5.6 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, 2014, 2013 and 2012 (stock options and SARs in thousands):
		2014							2013							2012
		Number			Weighted				Number			Weighted				Number			Weighted
		of Stock			Average				of Stock			Average				of Stock			Average
		Options/			Grant				Options/			Grant				Options/			Grant
		SARs			Price				SARs			Price				SARs			Price
	Outstanding at January 1	10,452			$	54.43			12,438			$	42.91			16,748			$	35.01
	Granted	2,146			101.55				2,268			83.7				2,480			55.99
	Exercised (1)	(1,718	)		45.68				(4,046	)		35.62				(6,492	)		27.4
	Forfeited	(387	)		68.95				(208	)		50.78				(298	)		45.59
	Outstanding at December 31	10,493			64.96				10,452			54.43				12,438			42.91
	Stock Options/SARs Exercisable at December 31	5,287			49.4				4,638			43.95				6,286			37.49
	-1	The total intrinsic value of stock options/SARs exercised during the years 2014, 2013 and 2012 was $95 million, $151 million and $185 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, 2014, there were 10.1 million stock options/SARs vested or expected to vest with a weighted average grant price of $64.29 per share, an intrinsic value of $299 million and a weighted average remaining contractual life of 4.3 years.
	The following table summarizes certain information for the stock options and SARs outstanding and exercisable at December 31, 2014 (stock options and SARs in thousands):
	Stock Options/SARs Outstanding															Stock Options/SARs Exercisable
	Range of		Stock			Weighted		Weighted								Stock			Weighted		Weighted
	Grant		Options/			Average		Average								Options/			Average		Average
	Prices		SARs			Remaining		Grant				Aggregate				SARs			Remaining		Grant				Aggregate
						Life		Price				Intrinsic							Life		Price				Intrinsic
						(Years)						Value(1)							(Years)						Value (1)
	$22.00 to $  42.99		2,682			3		$	40.74							2,129			3		$	40.5
	43.00 to     46.99		1,612			2		45.57								1,598			2		45.58
	47.00 to   56.99		2,014			4		55.8								995			4		55.57
	57.00 to    84.99		2,099			5		83.08								548			5		82.44
	85.00 to   116.99		2,086			7		101.7								17			3		97.77
			10,493			4		64.96				$	304,679			5,287			3		49.4				$	225,692
	-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, 2014, unrecognized compensation expense related to non-vested stock option and SAR grants totaled $112 million.  This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.7 years.
	At December 31, 2014, approximately 794,000 shares of Common Stock remained available for issuance under the ESPP.  The following table summarizes ESPP activities for the years ended December 31, 2014, 2013 and 2012 (in thousands, except number of participants):
		2014				2013				2012
	Approximate Number of Participants	1,991				1,844				1,705
	Shares Purchased	202				256				328
	Aggregate Purchase Price	$	14,927			$	14,015			$	12,522
	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 $74 million, $72 million and $72 million for the years ended December 31, 2014, 2013 and 2012, respectively.
	The following table sets forth the restricted stock and restricted stock unit transactions for the years ended December 31, 2014, 2013 and 2012 (shares and units in thousands):
		2014							2013							2012
		Number of			Weighted				Number of			Weighted				Number of			Weighted
		Shares and			Average				Shares and			Average				Shares and			Average
		Units			Grant Date				Units			Grant Date				Units			Grant Date
					Fair Value							Fair Value							Fair Value
Outstanding at January 1	7,358			$	49.54			7,636			$	45.53			8,480			$	41.47
Granted	1,132			98.72				1,294			76.04				1,534			56.09
Released (1)	(2,761	)		105.24				(1,368	)		52.39				(2,118	)		36.35
Forfeited	(335	)		62.55				(204	)		48.55				(260	)		42.68
Outstanding at December 31 (2)	5,394			64.39				7,358			49.54				7,636			45.53
-1	The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2014, 2013 and 2012 was $291 million, $101 million and $120 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, 2014 and 2013 was approximately $497 million and $617 million, respectively.
At December 31, 2014, unrecognized compensation expense related to restricted stock and restricted stock units totaled $178 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 grants performance units and/or performance stock to its executive officers.  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.  Upon the application of the performance multiple at the completion of the performance period, a minimum of zero and a maximum of 666,390 performance units/shares could be outstanding (based on the number of performance units/shares outstanding as of December 31, 2014).  Subject to the termination provisions set forth in the grant agreements and the applicable performance multiple, the grants of performance shares/units will "cliff" vest five years from the date of grant.  The fair value of the performance units and performance stock is estimated using a Monte Carlo simulation.  Stock-based compensation expense related to performance unit and performance stock grants totaled $9 million, $9 million and $7 million for the years ended December 31, 2014, 2013 and 2012, respectively.
Weighted average fair values and valuation assumptions used to value performance unit and performance stock grants during the years ended December 31, 2014, 2013 and 2012 were as follows:
	2014				2013				2012
Weighted Average Fair Value of Grants	$	119.27			$	100.34			$	67.05
Expected Volatility	32.18		%		33.63		%		36.39		%
Risk-Free Interest Rate	1.18		%		0.79		%		0.39		%
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 3.26 year zero-coupon risk-free interest rate derived from the Treasury Constant Maturities yield curve on the grant date.
The following table sets forth performance unit and performance stock transactions for the years ended December 31, 2014, 2013 and 2012 (shares and units in thousands):
	2014							2013							2012
	Number of			Weighted				Number of			Weighted				Number of			Weighted
	Shares and			Average				Shares and			Average				Shares and			Average
	Units			Grant Date				Units			Grant Date				Units			Grant Date
				Fair Value							Fair Value							Fair Value
Outstanding at January 1	261			$	82.18			142			$	67.05			—			—
Granted	72			119.27				119			100.34				142			67.05
Outstanding at December 31 (1)	333			$	90.17			261			$	82.18			142			$	67.05
-1	The total intrinsic value of performance units and performance stock outstanding at December 31, 2014 and 2013 was $30.7 million and $21.9 million, respectively.
At December 31, 2014, unrecognized compensation expense related to performance units and performance stock totaled $5 million.  Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 3.8 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 $41 million, $37 million and $36 million for 2014, 2013 and 2012, respectively.
In addition, at December 31, 2014, EOG's Canadian subsidiary maintained both a non-contributory defined benefit pension plan and a non-contributory defined contribution pension plan, as well as a matched defined contribution savings plan.  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.  With the exception of Canada's non-contributory defined benefit pension plan, which is closed to new employees, these pension plans are available to most employees of the Canadian, Trinidadian and United Kingdom subsidiaries.  EOG's combined contributions to these plans were $5 million, $4 million and $3 million for 2014, 2013 and 2012, respectively.
For the Canadian and Trinidadian defined benefit pension plans, the benefit obligation, fair value of plan assets and accrued benefit cost totaled $14 million, $12 million and $1 million, respectively, at December 31, 2014, and $13 million, $11 million and $1 million, respectively, at December 31, 2013. In connection with the divestiture of substantially all of its Canadian assets, 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, 2014
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	8.  Commitments and Contingencies
	Letters of Credit and Guarantees.  At December 31, 2014, EOG had standby letters of credit and guarantees outstanding totaling approximately $423 million primarily representing guarantees of payment or performance obligations on behalf of subsidiaries.  In connection with the divestiture of substantially all of EOG's Canadian assets, EOG's standby letters of credit and guarantees outstanding will ultimately decrease by approximately $71 million. At December 31, 2013, EOG had standby letters of credit and guarantees outstanding totaling approximately $711 million, of which $150 million represented a guarantee of subsidiary indebtedness (see Note 2) and $561 million primarily represented guarantees of payment or performance obligations on behalf of subsidiaries.  As of February 18, 2015, there were no demands for payment under these guarantees.
	Minimum Commitments.  At December 31, 2014, 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, 2014, were as follows (in thousands):
		Total Minimum
		Commitments
	2015	$	1,643,053
	2016 - 2017	1,981,982
	2018 - 2019	1,221,216
	2020 and beyond	974,073
		$	5,820,324
	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 $237 million, $191 million and $182 million for 2014, 2013 and 2012, 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_Per_Share

Net Income Per Share	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Net Income Per Share	9.  Net Income Per Share
	The following table sets forth the computation of Net Income Per Share for the years ended December 31, 2014, 2013 and 2012 (in thousands, except per share data):
		2014		2013		2012
	Numerator for Basic and Diluted Earnings per Share -
	Net Income	$	2,915,487	$	2,197,109	$	570,279
	Denominator for Basic Earnings per Share -
	Weighted Average Shares	543,443		540,341		535,155
	Potential Dilutive Common Shares -
	Stock Options/SARs	2,526		2,316		2,911
	Restricted Stock/Units and Performance Units/Stock	2,570		3,570		3,458
	Denominator for Diluted Earnings per Share -
	Adjusted Diluted Weighted Average Shares	548,539		546,227		541,524
	Net Income Per Share
	Basic	$	5.36	$	4.07	$	1.07
	Diluted	$	5.32	$	4.02	$	1.05
	The diluted earnings per share calculation excludes stock options and SARs that were anti-dilutive.  Shares underlying the excluded stock options and SARs totaled 0.7 million, 0.3 million and 0.5 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Supplemental_Cash_Flow_Informa

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2014
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	10.  Supplemental Cash Flow Information
	Net cash paid for interest and income taxes was as follows for the years ended December 31, 2014, 2013 and 2012 (in thousands):
		2014		2013		2012
	Interest, Net of Capitalized Interest	$	197,383	$	235,854	$	196,944
	Income Taxes, Net of Refunds Received	$	342,741	$	294,739	$	360,006
	EOG's accrued capital expenditures at December 31, 2014, 2013 and 2012 were $972 million, $731 million and $734 million, respectively.
	Non-cash investing activities for each of the years ended December 31, 2014 and 2013 included non-cash additions of $5 million to EOG's oil and gas properties as a result of property exchanges.
	Non-cash investing and financing activities for the year ended December 31, 2012, included non-cash additions of $66 million to EOG's other property, plant and equipment and related obligations in connection with a capital lease transaction and non-cash additions of $20 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, 2014
Segment Reporting [Abstract]
Business Segment Information	11.  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, Canada, Trinidad, the United Kingdom and China.  For segment reporting purposes, the chief operating decision maker considers the major United States producing areas to be one operating segment.
	Financial information by reportable segment is presented below as of and for the years ended December 31, 2014, 2013 and 2012 (in thousands):
		United			Canada			Trinidad		Other			Total
		States								International (1)
	2014
	Crude Oil and Condensate	$	9,526,149		$	184,420		$	29,604	$	2,307		$	9,742,480
	Natural Gas Liquids	924,454			9,597			—		—			934,051
	Natural Gas	1,321,175			96,274			483,071		15,866			1,916,386
	Gains on Mark-to-Market Commodity Derivative Contracts	834,273			—			—		—			834,273
	Gathering, Processing and Marketing	4,040,024			228			6,064		—			4,046,316
	Gains on Asset Dispositions, Net	96,339			411,251			—		—			507,590
	Other, Net	49,950			4,257			37		—			54,244
	Net Operating Revenues (2)	16,792,364			706,027			518,776		18,173			18,035,340
	Depreciation, Depletion and Amortization	3,684,943			105,274			188,592		18,232			3,997,041
	Operating Income (Loss)	5,074,911			360,114			277,471		(470,673		)	5,241,823
	Interest Income	849			847			253		290			2,239
	Other Income (Expense)	(14,953		)	(19,719		)	8,712		(21,329		)	(47,289		)
	Net Interest Expense	269,166			(20,681		)	—		(47,027		)	201,458
	Income (Loss) Before Income Taxes	4,791,641			361,923			286,436		(444,685		)	4,995,315
	Income Tax Provision	1,837,185			80,807			98,559		63,277			2,079,828
	Additions to Oil and Gas Properties, Excluding Dry Hole Costs	7,133,727			76,642			76,138		184,670			7,471,177
	Total Property, Plant and Equipment, Net	28,391,741			33,635			382,719		364,549			29,172,644
	Total Assets	32,871,398			182,250			865,674		843,365			34,762,687
		United			Canada			Trinidad		Other			Total
		States								International (1)
	2013
	Crude Oil and Condensate	$	8,035,358		$	221,999		$	40,379	$	2,911		$	8,300,647
	Natural Gas Liquids	761,535			12,435			—		—			773,970
	Natural Gas	1,100,808			85,446			477,103		17,672			1,681,029
	Losses on Mark-to-Market Commodity Derivative Contracts	(166,349		)	—			—		—			(166,349		)
	Gathering, Processing and Marketing	3,636,209			1,476			6,064		—			3,643,749
	Gains on Asset Dispositions, Net	93,876			102,570			1,119		—			197,565
	Other, Net	51,713			4,770			24		—			56,507
	Net Operating Revenues (3)	13,513,150			428,696			524,689		20,583			14,487,118
	Depreciation, Depletion and Amortization	3,223,596			180,836			181,990		14,554			3,600,976
	Operating Income (Loss)	3,543,841			(45,214		)	266,329		(89,745		)	3,675,211
	Interest Income	2,803			2,076			336		370			5,585
	Other Income (Expense)	(29,696		)	7,707			9,889		3,650			(8,450		)
	Net Interest Expense	283,209			(4,204		)	—		(43,545		)	235,460
	Income (Loss) Before Income Taxes	3,233,739			(31,227		)	276,554		(42,180		)	3,436,886
	Income Tax Provision (Benefit)	1,161,328			598			118,270		(40,419		)	1,239,777
	Additions to Oil and Gas Properties, Excluding Dry Hole Costs	6,133,894			137,920			132,984		217,638			6,622,436
	Total Property, Plant and Equipment, Net	24,456,383			602,333			476,174		613,946			26,148,836
	Total Assets	27,668,713			880,765			986,796		1,037,964			30,574,238
	2012
	Crude Oil and Condensate	$	5,383,612		$	221,556		$	50,708	$	3,561		$	5,659,437
	Natural Gas Liquids	713,497			13,680			—		—			727,177
	Natural Gas	951,463			86,361			514,322		19,616			1,571,762
	Gains on Mark-to-Market Commodity Derivative Contracts	393,744			—			—		—			393,744
	Gathering, Processing and Marketing	3,091,281			—			5,413		—			3,096,694
	Gains on Asset Dispositions, Net	166,201			26,459			—		—			192,660
	Other, Net	40,780			367			15		—			41,162
	Net Operating Revenues (4)	10,740,578			348,423			570,458		23,177			11,682,636
	Depreciation, Depletion and Amortization	2,780,563			223,689			147,062		18,389			3,169,703
	Operating Income (Loss)	2,233,911			(1,065,434		)	371,876		(60,556		)	1,479,797
	Interest Income	8,343			123			125		180			8,771
	Other Income (Expense)	(12,455		)	(8,689		)	20,482		6,386			5,724
	Net Interest Expense	242,138			6,589			238		(35,413		)	213,552
	Income (Loss) Before Income Taxes	1,987,661			(1,080,589		)	392,245		(18,577		)	1,280,740
	Income Tax Provision (Benefit)	707,401			(134,745		)	140,468		(2,663		)	710,461
	Additions to Oil and Gas Properties, Excluding Dry Hole Costs	6,198,267			302,851			49,376		169,852			6,720,346
	Total Property, Plant and Equipment, Net	21,560,998			877,996			535,405		363,282			23,337,681
	Total Assets	24,523,072			1,202,031			1,012,727		598,748			27,336,578
-1	Other International primarily consists of EOG's United Kingdom, China and Argentina operations.
-2	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.
-3	EOG had sales activity with two significant purchasers in 2013, one totaling $3.9 billion and the other totaling $2.0 billion of consolidated Net Operating Revenues in the United States segment.
-4	EOG had sales activity with a single significant purchaser in 2012 that totaled $2.2 billion of consolidated Net Operating Revenues in the United States segment.

Risk_Management_Activities

Risk Management Activities	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk Management Activities	12.  Risk Management Activities
	Commodity Price Risks.  EOG engages in price risk management activities from time to time.  These activities are intended to manage EOG's exposure to fluctuations in commodity prices for crude oil 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 2014, 2013 and 2012, 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 2014, 2013 and 2012, EOG recognized net gains (losses) on the mark-to-market of financial commodity derivative contracts of $834 million, $(166) million and $394 million, respectively, which included cash received from settlements of crude oil and natural gas derivative contracts of $34 million, $116 million and $711 million, respectively.
	Commodity Derivative Contracts.  Presented below is a comprehensive summary of EOG's crude oil derivative contracts at December 31, 2014, with notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl).
	Crude Oil Derivative Contracts
		Volume		Weighted
		(Bbld)		Average Price
				($/Bbl)
	2015 (1)
	January 1, 2015 through June 30, 2015	47,000		$	91.22
	July 1, 2015 through December 31, 2015	10,000		89.98
	-1	EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional six-month periods.  Options covering a notional volume of 37,000 Bbld are exercisable on June 30, 2015.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 37,000 Bbld at an average price of $91.56 per barrel for each month during the period July 1, 2015 through December 31, 2015.
	Presented below is a comprehensive summary of EOG's natural gas derivative contracts at December 31, 2014, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).
	Natural Gas Derivative Contracts
		Volume (MMBtud)		Weighted
				Average Price ($/MMBtu)
	2015 (1)
	January 2015 (closed)	235,000		$	4.47
	Feb-15	235,000		4.47
	Mar-15	225,000		4.48
	Apr-15	195,000		4.49
	May 1, 2015 through December 31, 2015	175,000		4.51
	-1	EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates.  All such options are exercisable monthly up until the settlement date of each monthly contract.  If the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 175,000 MMBtud at an average price of $4.51 per MMBtu for each month during the period February 1, 2015 through December 31, 2015.
	Foreign Currency Exchange Rate Derivative.  EOG was party to a foreign currency aggregate swap with multiple banks to eliminate any exchange rate impacts that may have resulted from the Subsidiary Debt.  The foreign currency swap agreement expired and was settled contemporaneously with the repayment upon maturity of the Subsidiary Debt on March 17, 2014 (see Note 2).
	Interest Rate Derivative.  EOG was party to an interest rate swap with a counterparty bank.  The interest rate swap was entered into in order to mitigate EOG's exposure to volatility in interest rates related to its Floating Rate Notes.  The interest rate swap expired and was settled contemporaneously with the repayment upon maturity of the Floating Rate Notes on February 3, 2014 (see Note 2).
	The following table sets forth the amounts and classification of EOG's outstanding derivative financial instruments at December 31, 2014 and 2013, 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	2014		2013
	Asset Derivatives
	Crude oil and natural gas derivative contracts -
	Current portion		Assets from Price Risk Management Activities (1)	$	465	$	8
	Liability Derivatives
	Crude oil and natural gas derivative contracts -
	Current portion		Liabilities from Price Risk Management Activities (2)	$	—	$	127
	Foreign currency swap - Current portion		Current Liabilities - Other	$	—	$	40
	Interest rate swap - Current portion		Current Liabilities - Other	$	—	$	1
	-1	The current portion of Assets from Price Risk Management Activities consists of gross assets of $477 million, partially offset by gross liabilities of $12 million, at December 31, 2014 and gross assets of $18 million, partially offset by gross liabilities of $10 million, at December 31, 2013.
	-2	The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $12 million, offset by gross assets of $12 million, at December 31, 2014 and gross liabilities of $137 million, partially offset by gross assets of $10 million, at December 31, 2013.
	Credit Risk.  Notional contract amounts are used to express the magnitude of commodity price, foreign currency and interest rate swap agreements.  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, 2014, EOG's net accounts receivable balance related to United States, Canada, Argentina and United Kingdom hydrocarbon sales included two receivable balances, each of which accounted for more than 10% of the total balance.  The receivables were due from two petroleum refinery companies.  The related amounts were collected during early 2015.  At December 31, 2013, EOG's net accounts receivable balance related to United States, Canada, Argentina 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 2014. In 2014 and 2013, all natural gas from EOG's Trinidad operations was sold to the National Gas Company of Trinidad and Tobago and its subsidiary, and all natural gas from EOG's China operations was sold to Petrochina Company Limited.
	All of EOG's outstanding 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, 2014 and 2013.  EOG had no collateral posted and held $278 million of collateral at December 31, 2014, and had no collateral posted and held no collateral at December 31, 2013.
	Substantially all of EOG's accounts receivable at December 31, 2014 and 2013 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, 2014, credit losses incurred on receivables by EOG have been immaterial.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Fair Value Measurements	13.  Fair Value Measurements
	Certain of EOG's financial and nonfinancial assets and liabilities are reported at fair value on the Consolidated Balance Sheets.  An established fair value hierarchy prioritizes the relative reliability of inputs used in fair value measurements.  The hierarchy gives highest priority to Level 1 inputs that represent unadjusted quoted market prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date.  Level 2 inputs are directly or indirectly observable inputs other than quoted prices included within Level 1.  Level 3 inputs are unobservable inputs and have the lowest priority in the hierarchy.  EOG gives consideration to the credit risk of its counterparties, as well as its own credit risk, when measuring financial assets and liabilities at fair value.
	The following table provides fair value measurement information within the fair value hierarchy for certain of EOG's financial assets and liabilities carried at fair value on a recurring basis at December 31, 2014 and 2013 (in millions):
		Fair Value Measurements Using:
		Quoted		Significant		Significant		Total
		Prices in		Other		Unobservable
		Active		Observable		Inputs
		Markets		Inputs		(Level 3)
		(Level 1)		(Level 2)
	At December 31, 2014
	Financial Assets:
	Natural Gas Options/Swaptions	$	—	$	100	$	—	$	100
	Crude Oil Swaps	—		121		—		121
	Crude Oil Options/Swaptions	—		244		—		244
	At December 31, 2013
	Financial Assets:
	Natural Gas Options/Swaptions	$	—	$	8	$	—	$	8
	Financial Liabilities:
	Crude Oil Swaps	$	—	$	17	$	—	$	17
	Crude Oil Options/Swaptions	—		110		—		110
	Foreign Currency Rate Swap	—		40		—		40
	Interest Rate Swap	—		1		—		1
	The estimated fair value of crude oil and natural gas derivative contracts (including options/swaptions) and the interest rate swap contract (see Note 12) was based upon forward commodity price and interest rate curves based on quoted market prices.  The estimated fair value of the foreign currency rate swap was based upon forward currency rates.  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 2014, proved oil and gas properties and other assets with a carrying amount of $968 million were written down to their fair value of $393 million, resulting in pretax impairment charges of $575 million.  Included in the $575 million pretax impairment charges are $58 million of impairments of proved oil and gas properties and other assets for which EOG utilized accepted offers from third-party purchasers as the basis for determining fair value.  During 2013, proved and unproved oil and gas properties and other assets with a carrying amount of $400 million were written down to their fair value of $228 million, resulting in pretax impairment charges of $172 million. Included in the $172 million pretax impairment charges are $58 million of impairments of proved oil and gas properties and other assets for which EOG utilized accepted offers from third-party purchasers as the basis for determining fair value.  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.
	Fair Value of Debt.  At both December 31, 2014 and 2013, EOG had outstanding $5,890 million aggregate principal amount of debt, which had estimated fair values of approximately $6,242 million and $6,222 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_LongLiv

Accounting For Certain Long-Lived Assets	12 Months Ended
	Dec. 31, 2014
Accounting For Certain Long-Lived Assets [Abstract]
Accounting For Certain Long-Lived Assets	14.  Accounting for Certain Long-Lived Assets
	EOG reviews its proved oil and gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the asset.  During 2014, 2013 and 2012, such reviews indicated that unamortized capitalized costs of certain properties were higher than their expected undiscounted future cash flows primarily due to lower commodity prices, downward reserve revisions, drilling of marginal or uneconomic wells, or development dry holes in certain producing fields.  Several impairments over this period were recognized in connection with the signing of purchase and sale agreements.  As a result, EOG recorded pretax charges of $171 million, $73 million and $171 million in the United States during 2014, 2013 and 2012, respectively, and $8 million, $76 million and $872 million in Canada during 2014, 2013 and 2012, respectively.  Additionally, EOG recorded pretax charges of $396 million and $9 million in Other International during 2014 and 2013, respectively, and $14 million in Trinidad during 2013.  The pretax charges are included in Impairments on the Consolidated Statements of Income and Comprehensive Income.  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 bids as the basis for determining fair value.  Amortization and impairments of unproved oil and gas property costs, including amortization of capitalized interest, were $168 million, $115 million and $228 million during 2014, 2013 and 2012, respectively.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligations, Noncurrent [Abstract]
Asset Retirement Obligations	15.  Asset Retirement Obligations
	The following table presents the reconciliation of the beginning and ending aggregate carrying amounts of short-term and long-term legal obligations associated with the retirement of property, plant and equipment for the years ended December 31, 2014 and 2013 (in thousands):
		2014			2013
	Carrying Amount at Beginning of Period	$	761,898		$	665,944
	Liabilities Incurred	123,849			103,284
	Liabilities Settled (1)	(247,422		)	(70,510		)
	Accretion	41,489			35,180
	Revisions	82,885			38,552
	Foreign Currency Translations	(9,981		)	(10,552		)
	Carrying Amount at End of Period	$	752,718		$	761,898
	Current Portion	$	11,814		$	43,857
	Noncurrent Portion	$	740,904		$	718,041
	-1	Includes settlements related to asset sales.
	The current and noncurrent portions of EOG's asset retirement obligations are included in Current Liabilities - Other and Other Liabilities, respectively, on the Consolidated Balance Sheets.

Exploratory_Well_Costs

Exploratory Well Costs	12 Months Ended
	Dec. 31, 2014
Capitalized Exploratory Well Costs [Abstract]
Exploratory Well Costs	16.  Exploratory Well Costs
	EOG's net changes in capitalized exploratory well costs for the years ended December 31, 2014, 2013 and 2012 are presented below (in thousands):
		2014			2013			2012
	Balance at January 1	$	9,211		$	49,116		$	61,111
	Additions Pending the Determination of Proved Reserves	32,080			52,099			73,332
	Reclassifications to Proved Properties	(15,946		)	(54,505		)	(69,462		)
	Costs Charged to Expense (1)	(8,092		)	(35,859		)	(17,115		)
	Foreign Currency Translations	—			(1,640		)	1,250
	Balance at December 31	$	17,253		$	9,211		$	49,116		(2)
	-1	Includes capitalized exploratory well costs charged to either dry hole costs or impairments.
	-2	At December 31, 2012, exploratory well costs totaling $21 million related to an outside operated offshore Central North Sea project in the United Kingdom that had been capitalized for more than one year.
	At December 31, 2014 and 2013, all exploratory well costs had been capitalized for periods of less than one year.

Divestitures

Divestitures	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Divestitures	17.  Divestitures
	During 2014, EOG 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 represent a substantially complete liquidation of EOG's Canadian operations, EOG reclassified approximately $383 million of cumulative translation adjustments previously recorded in Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheets to Net Income (Gains on Asset Dispositions, Net) on 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. During 2013, EOG received proceeds of approximately $761 million primarily from the sales of its entire interest in the planned Kitimat project in Canada, undeveloped acreage in the Horn River Basin in Canada and producing properties and acreage in the Permian Basin, the Mid-Continent area and the Upper Gulf Coast region.  During 2012, EOG received proceeds of approximately $1.3 billion from the sales of producing properties and acreage primarily in the Rocky Mountain area, the Upper Gulf Coast region and Canada.

Oil_and_Gas_Exploration_and_Pr

Oil and Gas Exploration and Production Industries Disclosures	12 Months Ended
	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Oil and Gas Exploration and Production Industries Disclosures	Oil and Gas Producing Activities
	The following disclosures are made in accordance with Financial Accounting Standards Board Accounting Standards Update No. 2010-03 "Oil and Gas Reserve Estimates and Disclosures" and the United States Securities and Exchange Commission's (SEC) final rule on "Modernization of Oil and Gas Reporting."
	Oil and Gas Reserves.  Users of this information should be aware that the process of estimating quantities of "proved," "proved developed" and "proved undeveloped" crude oil, natural gas liquids (NGL) 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 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, NGL and natural gas that geoscience and engineering data are used to estimate, with reasonable certainty, to be economically producible from a given day forward from known reservoirs under then-existing economic conditions, operating methods and government regulation 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 significant expenditure is required. 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, 2014.  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, 2014, 2013 and 2012 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 nine 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 29 years of experience in reserve evaluations and is a Registered Professional Engineer in the State of Texas.
	EOG's reserves estimation process is a collaborative effort coordinated by the Engineering and Acquisitions Department in compliance with EOG's internal controls for such process.  Reserve information as well as models used to estimate such reserves are stored on secured databases.  Non-technical inputs used in reserve estimation models, including crude oil, NGL and natural gas prices, production costs, transportation costs, future capital expenditures and EOG's net ownership percentages are obtained from other departments within EOG.  EOG's Internal Audit Department conducts testing with respect to such non-technical inputs.  Additionally, EOG engages DeGolyer and MacNaughton (D&M), independent petroleum consultants, to perform independent reserves evaluation of select EOG properties comprising not less than 75% of EOG's estimates of proved reserves.  EOG's Board of Directors requires that D&M's and EOG's reserve quantities for the properties evaluated by D&M vary by no more than 5% in the aggregate.  Once completed, EOG's year-end reserves are presented to senior management, including the Chairman of the Board and Chief Executive Officer; the Chief Operating Officer; the Executive Vice Presidents, Exploration and Production; and the Vice President and Chief Financial Officer, for approval.
	Opinions by D&M for the years ended December 31, 2014, 2013 and 2012 covered producing areas containing 76%, 82% and 87%, 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 23, 2015, 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, 2014, is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.
	The following tables set forth EOG's net proved and proved developed reserves at December 31 for each of the four years in the period ended December 31, 2014, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2014, as estimated by the Engineering and Acquisitions Department of EOG:
	NET PROVED AND PROVED DEVELOPED RESERVE SUMMARY
		United			Canada			Trinidad			Other		Total
		States									International (1)
	NET PROVED RESERVES
	Crude Oil (MBbl) (2)
	Net proved reserves at December 31, 2011	495,296			18,592			3,507			98		517,493
	Revisions of previous estimates	4,105			(2,493	)		71			5		1,688
	Purchases in place	1,010			—			—			—		1,010
	Extensions, discoveries and other additions	241,171			5,681			—			8,834		255,686
	Sales in place	(15,921	)		(1,343	)		—			—		(17,264	)
	Production	(54,632	)		(2,574	)		(550	)		(39	)	(57,795	)
	Net proved reserves at December 31, 2012	671,029			17,863			3,028			8,898		700,818
	Revisions of previous estimates	57,668			(5,866	)		(991	)		(142	)	50,669
	Purchases in place	1,097			—			—			—		1,097
	Extensions, discoveries and other additions	230,023			673			—			58		230,754
	Sales in place	(2,337	)		—			—			—		(2,337	)
	Production	(77,431	)		(2,550	)		(447	)		(33	)	(80,461	)
	Net proved reserves at December 31, 2013	880,049			10,120			1,590			8,781		900,540
	Revisions of previous estimates	28,301			(313	)		99			(65	)	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	)		(2,126	)		(350	)		(26	)	(105,448	)
	Net proved reserves at December 31, 2014	1,129,682			25			1,339			8,704		1,139,750
	Natural Gas Liquids (MBbl) (2)
	Net proved reserves at December 31, 2011	226,586			1,202			—			—		227,788
	Revisions of previous estimates	47,293			563			—			—		47,856
	Purchases in place	612			—			—			—		612
	Extensions, discoveries and other additions	71,396			178			—			—		71,574
	Sales in place	(7,300	)		(77	)		—			—		(7,377	)
	Production	(20,181	)		(309	)		—			—		(20,490	)
	Net proved reserves at December 31, 2012	318,406			1,557			—			—		319,963
	Revisions of previous estimates	12,157			(48	)		—			—		12,109
	Purchases in place	1,202			—			—			—		1,202
	Extensions, discoveries and other additions	69,187			10			—			—		69,197
	Sales in place	(1,471	)		—			—			—		(1,471	)
	Production	(23,479	)		(315	)		—			—		(23,794	)
	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
		United			Canada			Trinidad			Other		Total
		States									International (1)
	Natural Gas (Bcf) (3)
	Net proved reserves at December 31, 2011	6,045.80			1,035.90			750.7			18.5		7,850.90
Revisions of previous estimates	(1,736.0	)		(894.5	)		(24.1	)		1.6		(2,653.0	)
Purchases in place	14.8			—			—			—		14.8
Extensions, discoveries and other additions	477.8			—			—			0.3		478.1
Sales in place	(386.2	)		(8.5	)		—			—		(394.7	)
Production	(380.2	)		(34.6	)		(138.4	)		(3.4	)	(556.6	)
Net proved reserves at December 31, 2012	4,036.00			98.3			588.2			17		4,739.50
Revisions of previous estimates	264			31.4			(17.4	)		(0.7	)	277.3
Purchases in place	5.7			—			—			—		5.7
Extensions, discoveries and other additions	504.7			0.1			79.5			9.8		594.1
Sales in place	(69.4	)		—			—			—		(69.4	)
Production	(342.3	)		(27.7	)		(129.6	)		(2.8	)	(502.4	)
Net proved reserves at December 31, 2013	4,398.70			102.1			520.7			23.3		5,044.80
Revisions of previous estimates	252.2			9.8			12.9			(4.3	)	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	)		(22.3	)		(132.5	)		(3.1	)	(506.3	)
Net proved reserves at December 31, 2014	4,905.50			10.9			405.6			20.6		5,342.60
Oil Equivalents (MBoe) (2)
Net proved reserves at December 31, 2011	1,729,508			192,448			128,629			3,178		2,053,763
Revisions of previous estimates	(237,936	)		(151,015	)		(3,953	)		283		(392,621	)
Purchases in place	4,098			—			—			—		4,098
Extensions, discoveries and other additions	392,196			5,860			—			8,876		406,932
Sales in place	(87,588	)		(2,832	)		—			—		(90,420	)
Production	(138,170	)		(8,657	)		(23,616	)		(611	)	(171,054	)
Net proved reserves at December 31, 2012	1,662,108			35,804			101,060			11,726		1,810,698
Revisions of previous estimates	113,823			(676	)		(3,892	)		(265	)	108,990
Purchases in place	3,241			—			—			—		3,241
Extensions, discoveries and other additions	383,324			693			13,245			1,703		398,965
Sales in place	(15,375	)		—			—			—		(15,375	)
Production	(157,955	)		(7,482	)		(22,049	)		(490	)	(187,976	)
Net proved reserves at December 31, 2013	1,989,166			28,339			88,364			12,674		2,118,543
Revisions of previous estimates	97,782			1,316			2,245			(775	)	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	)		(6,080	)		(22,430	)		(551	)	(219,126	)
Net proved reserves at December 31, 2014	2,414,202			1,973			68,937			12,144		2,497,256
-1	Other International includes EOG's United Kingdom, China and Argentina operations.
-2	Thousand barrels or thousand barrels of oil equivalent, as applicable; oil equivalents include crude oil and condensate, NGL and natural gas. Oil equivalents are determined using the ratio of 1.0 barrel of crude oil and condensate or NGL to 6.0 thousand cubic feet of natural gas.
-3	Billion cubic feet.
During 2014, EOG added 519 million barrels of oil equivalent (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 NGL, 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.
During 2013, EOG added 399 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Eagle Ford, Bakken, Permian Basin and Barnett Combo shale plays.  Approximately 75% of the 2013 reserve additions were crude oil and condensate and NGL, and over 96% were in the United States.  Sales in place of 15 MMBoe were primarily related to the disposition of certain producing natural gas assets in South Texas, the Barnett Shale and the Permian Basin.  Positive revisions of previous estimates of 109 MMBoe for 2013 included a positive revision of 61 MMBoe primarily due to an increase in the average natural gas price used in the December 31, 2013 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.
During 2012, EOG added 407 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Eagle Ford, Permian Basin, Bakken and Barnett Combo shale plays.  Approximately 80% of the 2012 reserve additions were crude oil and condensate and NGL, and over 96% were in the United States.  Sales in place of 90 MMBoe were primarily related to the disposition of certain producing natural gas assets on the Gulf Coast, outside-operated crude oil properties in the Rocky Mountain area and other producing basins in the United States.  Negative revisions of previous estimates of 393 MMBoe for 2012 included a negative revision of 531 MMBoe primarily due to a decrease in the average natural gas price used in the December 31, 2012 reserves estimation as compared to the price used in the prior year estimate. The primary plays affected were the Horn River, Haynesville, Barnett Shale and Marcellus Shale.  Revisions other than price resulted from revisions for certain crude oil and natural gas properties in the United States.
	United			Canada			Trinidad			Other		Total
	States									International (1)
NET PROVED DEVELOPED RESERVES
Crude Oil (MBbl)
December 31, 2011	213,872			8,128			2,657			98		224,755
December 31, 2012	281,167			6,853			2,377			253		290,650
December 31, 2013	382,517			6,871			1,505			163		391,056
December 31, 2014	493,694			25			1,339			90		495,148
Natural Gas Liquids (MBbl)
December 31, 2011	124,271			1,092			—			—		125,363
December 31, 2012	161,482			1,111			—			—		162,593
December 31, 2013	199,964			896			—			—		200,860
December 31, 2014	264,611			138			—			—		264,749
Natural Gas (Bcf)
December 31, 2011	3,235.00			295.8			606.3			18.5		4,155.60
December 31, 2012	2,387.50			98.3			476.7			17		2,979.50
December 31, 2013	2,597.30			102.1			494.6			19.4		3,213.40
December 31, 2014	3,102.80			10.9			396.9			17.7		3,528.30
Oil Equivalents (MBoe)
December 31, 2011	877,301			58,524			103,710			3,178		1,042,713
December 31, 2012	840,564			24,348			81,826			3,081		949,819
December 31, 2013	1,015,359			24,782			83,933			3,402		1,127,476
December 31, 2014	1,275,447			1,973			67,484			3,043		1,347,947
NET PROVED UNDEVELOPED RESERVES
Crude Oil (MBbl)
December 31, 2011	281,424			10,464			850			—		292,738
December 31, 2012	389,862			11,010			651			8,645		410,168
December 31, 2013	497,532			3,249			85			8,618		509,484
December 31, 2014	635,988			—			—			8,614		644,602
Natural Gas Liquids (MBbl)
December 31, 2011	102,315			110			—			—		102,425
December 31, 2012	156,924			446			—			—		157,370
December 31, 2013	176,038			308			—			—		176,346
December 31, 2014	202,319			—			—			—		202,319
Natural Gas (Bcf)
December 31, 2011	2,810.80			740.1			144.4			—		3,695.30
December 31, 2012	1,648.50			—			111.5			—		1,760.00
December 31, 2013	1,801.40			—			26.1			3.9		1,831.40
December 31, 2014	1,802.70			—			8.7			2.9		1,814.30
Oil Equivalents (MBoe)
December 31, 2011	852,207			133,924			24,919			—		1,011,050
December 31, 2012	821,544			11,456			19,234			8,645		860,879
December 31, 2013	973,807			3,557			4,431			9,272		991,067
December 31, 2014	1,138,755			—			1,453			9,101		1,149,309
-1	Other International includes EOG's United Kingdom, China and Argentina operations.
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 (see discussion of technology employed on page F-32 of this Annual Report on Form 10-K), EOG added 354 MMBoe.  The PUD additions were primarily in the Eagle Ford and Permian Basin shale plays, and 80% of the additions were crude oil and condensate and NGL.  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.
For the twelve-month period ended December 31, 2013, total PUDs increased by 130 MMBoe to 991 MMBoe.  EOG added approximately 28 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 263 MMBoe.  The PUD additions were primarily in the Eagle Ford, Bakken and Permian Basin shale plays, and over 80% of the additions were crude oil and condensate and NGL.  During 2013, EOG drilled and transferred 160 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,874 million.  Revisions of PUDs totaled  negative 1 MMBoe.  During 2013, EOG did not sell any PUD reserves.
For the twelve-month period ended December 31, 2012, total PUDs decreased by 150 MMBoe to 861 MMBoe.  EOG added approximately 32 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 268 MMBoe.  The PUD additions were primarily in the Eagle Ford, Permian Basin, Bakken and Barnett Combo shale plays, and nearly 84% of the additions were crude oil and condensate and NGL.  During 2012, EOG drilled and transferred 138 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,764 million.  Revisions of PUDs totaled negative 293 MMBoe, primarily due to removal of certain natural gas PUDs due to lower average natural gas prices.  The primary plays affected were the Horn River, Haynesville, Barnett Shale and Marcellus Shale.  During 2012, EOG sold 19 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, 2014 and 2013:
	2014				2013
Proved properties	$	45,169,101			$	41,377,303
Unproved properties	1,334,431				1,444,500
Total	46,503,532				42,821,803
Accumulated depreciation, depletion and amortization	(20,212,748		)		(18,880,611		)
Net capitalized costs	$	26,290,784			$	23,941,192
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, 2014, 2013 and 2012:
	United				Canada				Trinidad			Other			Total
	States											International (1)
2014
Acquisition Costs of Properties
Unproved	$	365,915			$	4,499			$	—		$	—		$	370,414
Proved	138,772				349				—			(20		)	139,101
Subtotal	504,687				4,848				—			(20		)	509,515
Exploration Costs	332,703				13,010				2,794			47,466			395,973
Development Costs (2)	6,638,192				101,634				89,555			169,900			6,999,281
Total	$	7,475,582			$	119,492			$	92,349		$	217,346		$	7,904,769
2013
Acquisition Costs of Properties
Unproved	$	411,556			$	2,565			$	—		$	—		$	414,121
Proved	120,220				(6		)		—			—			120,214
Subtotal	531,776				2,559				—			—			534,335
Exploration Costs	273,788				19,660				16,060			67,671			377,179
Development Costs (3)	5,573,260				149,426				124,231			239,460			6,086,377
Total	$	6,378,824			$	171,645			$	140,291		$	307,131		$	6,997,891
2012
Acquisition Costs of Properties
Unproved	$	471,345			$	33,561			$	1,000		$	(603	)	$	505,303
Proved	739				—				—			—			739
Subtotal	472,084				33,561				1,000			(603		)	506,042
Exploration Costs	333,534				38,530				19,555			53,979			445,598
Development Costs (4)	5,657,378				278,995				32,609			147,568			6,116,550
Total	$	6,462,996			$	351,086			$	53,164		$	200,944		$	7,068,190
-1	Other International primarily consists of EOG's United Kingdom, China and Argentina operations.
-2	Includes Asset Retirement Costs of $149 million, $31 million, $14 million and $2 million for the United States, Canada, Trinidad and Other International, respectively.  Excludes other property, plant and equipment.
-3	Includes Asset Retirement Costs of $84 million, $13 million and $37 million for the United States, Canada and Other International, respectively.  Excludes other property, plant and equipment.
-4	Includes Asset Retirement Costs of $80 million, $33 million, $2 million and $12 million for the United States, Canada, 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, 2014, 2013 and 2012:
	United				Canada				Trinidad			Other			Total
	States											International (2)
2014
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	11,771,777			$	290,291			$	512,675		$	18,174		$	12,592,917
Other	49,950				4,257				37			—			54,244
Total	11,821,727				294,548				512,712			18,174			12,647,161
Exploration Costs	162,434				11,877				2,185			7,892			184,388
Dry Hole Costs	25,408				—				—			23,082			48,490
Transportation Costs	957,522				12,618				617			1,419			972,176
Production Costs	1,940,074				158,882				38,301			12,770			2,150,027
Impairments	331,792				15,879				—			395,904			743,575
Depreciation, Depletion and Amortization	3,571,313				104,462				188,250			17,695			3,881,720
Income (Loss) Before Income Taxes	4,833,184				(9,170		)		283,359			(440,588		)	4,666,785
Income Tax Provision (Benefit)	1,722,914				(2,360		)		74,588			25,962			1,821,104
Results of Operations	$	3,110,270			$	(6,810	)		$	208,771		$	(466,550	)	$	2,845,681
2013
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	9,897,701			$	319,880			$	517,482		$	20,583		$	10,755,646
Other	51,713				4,770				24			—			56,507
Total	9,949,414				324,650				517,506			20,583			10,812,153
Exploration Costs	141,286				11,203				2,345			6,512			161,346
Dry Hole Costs	14,276				9,579				4,478			46,322			74,655
Transportation Costs	841,567				9,694				659			1,124			853,044
Production Costs	1,494,791				154,947				43,279			13,205			1,706,222
Impairments	178,718				84,934				14,274			9,015			286,941
Depreciation, Depletion and Amortization	3,122,858				179,520				181,637			13,995			3,498,010
Income (Loss) Before Income Taxes	4,155,918				(125,227		)		270,834			(69,590		)	4,231,935
Income Tax Provision (Benefit)	1,486,445				(32,295		)		103,313			(66,931		)	1,490,532
Results of Operations	$	2,669,473			$	(92,932	)		$	167,521		$	(2,659	)	$	2,741,403
2012
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	7,048,572			$	321,597			$	565,030		$	23,177		$	7,958,376
Other	40,780				367				15			—			41,162
Total	7,089,352				321,964				565,045			23,177			7,999,538
Exploration Costs	162,152				13,350				2,262			7,805			185,569
Dry Hole Costs	1,772				1,570				—			11,628			14,970
Transportation Costs	591,547				7,511				1,104			1,269			601,431
Production Costs	1,264,633				154,509				37,792			11,694			1,468,628
Impairments	294,172				976,563				—			—			1,270,735
Depreciation, Depletion and Amortization	2,637,500				222,366				146,690			17,958			3,024,514
Income (Loss) Before Income Taxes	2,137,576				(1,053,905		)		377,197			(27,177		)	1,433,691
Income Tax Provision (Benefit)	761,459				(136,105		)		119,442			(21,890		)	722,906
Results of Operations	$	1,376,117			$	(917,800	)		$	257,755		$	(5,287	)	$	710,785
-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, 2014.
-2	Other International primarily consists of EOG's United Kingdom, China and Argentina operations.
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, 2014, 2013 and 2012:
	United				Canada				Trinidad			Other			Composite
	States											International (1)
Year Ended December 31, 2014	$	6.44			$	24.76			$	1.34		$	22.83		$	6.46
Year Ended December 31, 2013	$	5.78			$	19.98			$	1.36		$	26.77		$	5.88
Year Ended December 31, 2012	$	5.96			$	16.42			$	0.98		$	18.97		$	5.85
-1	Other International primarily consists of EOG's United Kingdom, China and Argentina operations.
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 2014, 2013 and 2012.  The following information  may be useful for certain comparison purposes, but should not be solely relied upon in evaluating EOG or its performance.  Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of EOG.
The future cash flows presented below are based on sales prices, cost rates and statutory income tax rates in existence as of the date of the projections.  It is expected that material revisions to some estimates of crude oil, NGL and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.
Management does not rely upon the following information in making investment and operating decisions.  Such decisions are based upon a wide range of factors, including estimates of probable and possible as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.
The following table sets forth the standardized measure of discounted future net cash flows from projected production of EOG's oil and gas reserves for the years ended December 31, 2014, 2013 and 2012:
	United				Canada				Trinidad			Other			Total
	States											International (1)
2014
Future cash inflows (2)	$	144,355,692			$	50,116			$	1,615,280		$	929,133		$	146,950,221
Future production costs	(51,112,604		)		(25,561		)		(277,844		)	(217,284		)	(51,633,293		)
Future development costs	(20,270,439		)		(32,016		)		(84,576		)	(107,734		)	(20,494,765		)
Future income taxes	(22,725,618		)		—				(460,096		)	—			(23,185,714		)
Future net cash flows	50,247,031				(7,461		)		792,764			604,115			51,636,449
Discount to present value at 10% annual rate	(23,542,990		)		11,217				(110,228		)	(71,030		)	(23,713,031		)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	26,704,041			$	3,756			$	682,536		$	533,085		$	27,923,418
2013
Future cash inflows (3)	$	119,644,713			$	1,199,251			$	2,082,195		$	1,073,340		$	123,999,499
Future production costs	(49,099,393		)		(540,188		)		(315,483		)	(211,424		)	(50,166,488		)
Future development costs	(17,753,860		)		(529,788		)		(112,050		)	(153,653		)	(18,549,351		)
Future income taxes	(15,763,089		)		—				(603,786		)	(49,512		)	(16,416,387		)
Future net cash flows	37,028,371				129,275				1,050,876			658,751			38,867,273
Discount to present value at 10% annual rate	(17,451,470		)		202,379				(174,236		)	(110,514		)	(17,533,841		)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	19,576,901			$	331,654			$	876,640		$	548,237		$	21,333,432
2012
Future cash inflows (4)	$	89,324,274			$	1,816,369			$	2,408,116		$	1,063,854		$	94,612,613
Future production costs	(35,892,997		)		(751,113		)		(342,113		)	(198,609		)	(37,184,832		)
Future development costs	(15,825,040		)		(813,061		)		(171,737		)	(221,893		)	(17,031,731		)
Future income taxes	(10,247,007		)		—				(691,109		)	(212,626		)	(11,150,742		)
Future net cash flows	27,359,230				252,195				1,203,157			430,726			29,245,308
Discount to present value at 10% annual rate	(12,177,896		)		146,954				(242,087		)	(56,807		)	(12,329,836		)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	15,181,334			$	399,149			$	961,070		$	373,919		$	16,915,472
-1	Other International includes EOG's United Kingdom, China and Argentina operations.
-2	Estimated crude oil prices used to calculate 2014 future cash inflows for the United States, Canada, Trinidad and Other International were $97.51, $95.11, $80.60 and $94.09, respectively. Estimated NGL prices used to calculate 2014 future cash inflows for the United States and Canada were $34.29 and $27.03, respectively. Estimated natural gas prices used to calculate 2014 future cash inflows for the United States, Canada, Trinidad and Other International were $3.71, $4.79, $3.71 and $5.34, respectively.
-3	Estimated crude oil prices used to calculate 2013 future cash inflows for the United States, Canada, Trinidad and Other International were $105.91, $91.47, $94.30 and $107.36, respectively. Estimated NGL prices used to calculate 2013 future cash inflows for the United States and Canada were $29.42 and $40.88, respectively.  Estimated natural gas prices used to calculate 2013 future cash inflows for the United States, Canada, Trinidad and Other International were $3.50, $2.95, $3.71 and $5.67, respectively.
-4	Estimated crude oil prices used to calculate 2012 future cash inflows for the United States, Canada, Trinidad and Other International were $99.78, $84.77, $94.46 and $109.94, respectively.  Estimated NGL prices used to calculate 2012 future cash inflows for the United States and Canada were $36.95 and $47.80, respectively. Estimated natural gas prices used to calculate 2012 future cash inflows for the United States, Canada, Trinidad and Other International were $2.63, $2.22, $3.61, and $5.04, respectively.
Changes in Standardized Measure of Discounted Future Net Cash Flows.  The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for each of the three years in the period ended December 31, 2014:
	United				Canada				Trinidad			Other			Total
	States											International
December 31, 2011	$	14,375,654			$	636,347			$	1,184,207		$	29,073		$	16,225,281
Sales and transfers of oil and gas produced, net of production costs	(5,192,392		)		(159,577		)		(526,134		)	(10,214		)	(5,888,317		)
Net changes in prices and production costs	(393,585		)		(67,964		)		162,600			(2,283		)	(301,232		)
Extensions, discoveries, additions and improved recovery, net of related costs	5,517,945				79,529				—			484,648			6,082,122
Development costs incurred	2,042,300				23,600				23,500			5,200			2,094,600
Revisions of estimated development cost	1,987,330				383,215				(28,835		)	(234		)	2,341,476
Revisions of previous quantity estimates	(3,286,943		)		(396,408		)		(62,285		)	2,809			(3,742,827		)
Accretion of discount	1,832,377				63,635				178,298			2,907			2,077,217
Net change in income taxes	174,418				—				88,853			(138,206		)	125,065
Purchases of reserves in place	64,317				—				—			5,623			69,940
Sales of reserves in place	(869,534		)		(44,227		)		—			—			(913,761		)
Changes in timing and other	(1,070,553		)		(119,001		)		(59,134		)	(5,404		)	(1,254,092		)
December 31, 2012	15,181,334				399,149				961,070			373,919			16,915,472
Sales and transfers of oil and gas produced, net of production costs	(7,561,343		)		(155,239		)		(473,544		)	(6,254		)	(8,196,380		)
Net changes in prices and production costs	1,734,058				(438,982		)		(12,050		)	(25,173		)	1,257,853
Extensions, discoveries, additions and improved recovery, net of related costs	5,449,531				33,901				—			—			5,483,432
Development costs incurred	2,792,400				95,400				67,100			1,000			2,955,900
Revisions of estimated development cost	892,803				48,906				(3,539		)	52,226			990,396
Revisions of previous quantity estimates	1,887,062				(23,915		)		(60,419		)	(8,530		)	1,794,198
Accretion of discount	1,895,503				39,915				147,099			51,212			2,133,729
Net change in income taxes	(2,772,267		)		—				56,373			137,644			(2,578,250		)
Purchases of reserves in place	66,359				—				—			—			66,359
Sales of reserves in place	(140,652		)		—				—			—			(140,652		)
Changes in timing and other	152,113				332,519				194,550			(27,807		)	651,375
December 31, 2013	19,576,901				331,654				876,640			548,237			21,333,432
Sales and transfers of oil and gas produced, net of production costs	(8,874,180		)		(118,791		)		(473,757		)	(3,986		)	(9,470,714		)
Net changes in prices and production costs	1,481,668				(94,315		)		(12,079		)	(112,097		)	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				200				12,800			3,300			2,835,100
Revisions of estimated development cost	1,696,916				63,978				9,981			31,860			1,802,735
Revisions of previous quantity estimates	1,741,918				42,000				35,001			(6,387		)	1,812,532
Accretion of discount	2,612,286				33,165				133,019			54,880			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				34,936				6,380			10,527			1,242,348
December 31, 2014	$	26,704,041			$	3,756			$	682,536		$	533,085		$	27,923,418

Unaudited_Quarterly_Financial_

Unaudited Quarterly Financial Information	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Unaudited Quarterly Financial Information [Text Block]	Unaudited Quarterly Financial Information
	(In Thousands, Except Per Share Data)
	Quarter Ended	31-Mar		30-Jun		30-Sep		31-Dec
	2014
	Net Operating Revenues	$	4,083,671	$	4,187,556	$	5,118,616	$	4,645,497
	Operating Income	$	1,084,279	$	1,144,730	$	1,786,162	$	1,226,652
	Income Before Income Taxes	$	1,030,789	$	1,100,813	$	1,715,120	$	1,148,593
	Income Tax Provision	369,861		394,460		611,502		704,005
	Net Income	$	660,928	$	706,353	$	1,103,618	$	444,588
	Net Income Per Share (1)
	Basic	$	1.22	$	1.3	$	2.03	$	0.82
	Diluted	$	1.21	$	1.29	$	2.01	$	0.81
	Average Number of Common Shares
	Basic	542,278		543,099		543,984		544,579
	Diluted	548,071		548,676		549,518		549,153
	2013
	Net Operating Revenues	$	3,356,514	$	3,840,185	$	3,541,396	$	3,749,023
	Operating Income	$	833,074	$	1,092,044	$	769,769	$	980,324
	Income Before Income Taxes	$	761,019	$	1,035,230	$	721,555	$	919,082
	Income Tax Provision	266,294		375,538		259,057		338,888
	Net Income	$	494,725	$	659,692	$	462,498	$	580,194
	Net Income Per Share (1)
	Basic	$	0.92	$	1.22	$	0.85	$	1.07
	Diluted	$	0.91	$	1.21	$	0.85	$	1.06
	Average Number of Common Shares
	Basic	538,717		540,033		540,941		541,857
	Diluted	544,526		545,477		547,152		547,966
	-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_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
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.
	On February 24, 2014, EOG's Board of Directors (Board) approved a two-for-one stock split in the form of a stock dividend, payable to stockholders of record as of March 17, 2014, and paid on March 31, 2014. All share and per share amounts in the financial statements and these notes have been restated to reflect the two-for-one stock split.
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, along with associated foreign currency and interest rate swaps.  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 charged to expense 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 (NGL) and natural gas are evidenced by signed contracts with determinable market prices, and revenues are recorded when production is delivered.  A significant majority of the purchasers of these products 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, NGL and natural gas, as well as gathering fees associated with gathering third-party natural gas.
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 [Text Block]	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, 2014, 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 certain of its Canadian subsidiaries, for which the functional currency is the Canadian dollar, and its United Kingdom subsidiary, for which the functional currency is the British pound.  For subsidiaries whose functional currency is deemed to be other than the United States dollar, asset and liability accounts are translated at year-end exchange rates and revenues and expenses are translated at average exchange rates prevailing during the year.  Translation adjustments are included in Accumulated Other Comprehensive Income on the Consolidated Balance Sheets.  Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period. See Note 17.
Net Income Per Share	Net Income Per Share.  Basic net income per share is computed on the basis of the weighted-average number of common shares outstanding during the period.  Diluted net income per share is computed based upon the weighted-average number of common shares outstanding during the period plus the assumed issuance of common shares for all potentially dilutive securities (see Note 9).
Stock-Based Compensation	Stock-Based Compensation. EOG measures the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (see Note 7).
Recently Issued Accounting Standards and Developments	Recently Issued Accounting Standards. In April 2014, the FASB issued Accounting Standards Update (ASU) 2014-08, "Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity" (ASU 2014-08). ASU 2014-08 changes the criteria for reporting discontinued operations by requiring that in order for a disposal to qualify as a discontinued operation, the disposal must represent a strategic shift that has (or will have) a major effect on the entity's operations and financial results. ASU 2014-08 also requires additional disclosures both for discontinued operations and individually significant components of an entity that do not qualify as discontinued operations. ASU 2014-08 is effective for annual and interim periods beginning on or after December 15, 2014, with early adoption permitted. EOG has early-adopted the provisions of ASU 2014-08 and such adoption did not have a material impact on EOG's consolidated financial statements.
	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 will be effective for interim and annual reporting periods beginning after December 15, 2016, and permits adoption through the use of either the full retrospective approach or a modified retrospective approach.   Early application is not permitted. EOG has not determined which transition method it will use and is continuing to analyze ASU 2014-09 to determine what impact the new standard will have on its consolidated financial statements and related disclosures.

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt at December 31, 2014 and 2013 consisted of the following (in thousands):
		2014		2013
	Floating Rate Senior Notes due 2014	$	—	$	350,000
	2.95% Senior Notes due 2015	500,000		500,000
	2.500% Senior Notes due 2016	400,000		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		—
	4.100% Senior Notes due 2021	750,000		750,000
	2.625% Senior Notes due 2023	1,250,000		1,250,000
	6.65% Senior Notes due 2028	140,000		140,000
	4.75% Subsidiary Debt due 2014	—		150,000
	Total Long-Term Debt	5,890,000		5,890,000
	Capital Lease Obligation	51,221		57,187
	Less: Current Portion of Long-Term Debt	6,579		6,579
	Unamortized Debt Discount	31,288		33,966
	Total Long-Term Debt, Net	$	5,903,354	$	5,906,642

Stockholders_Equity_Tables

Stockholder's Equity (Tables)	12 Months Ended
	Dec. 31, 2014
Stockholders' Equity Note [Abstract]
Common stock activity	The following summarizes Common Stock activity for each of the years ended December 31, 2012, 2013 and 2014 (in thousands):
		Common Shares
		Issued	Treasury		Outstanding
	Balance at December 31, 2011	538,646	(608	)	538,038
	Common Stock Issued Under Stock-Based Compensation Plans	4,942	—		4,942
	Treasury Stock Purchased (1)	—	(1,150	)	(1,150	)
	Common Stock Issued Under Employee Stock Purchase Plan	328	—		328
	Treasury Stock Issued Under Stock-Based Compensation Plans	—	1,106		1,106
	Balance at December 31, 2012	543,916	(652	)	543,264
	Common Stock Issued Under Stock-Based Compensation Plans	2,206	—		2,206
	Treasury Stock Purchased (1)	—	(854	)	(854	)
	Common Stock Issued Under Employee Stock Purchase Plan	256	—		256
	Treasury Stock Issued Under Stock-Based Compensation Plans	—	1,300		1,300
	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
	-1	Represents shares that were withheld by, or returned to, EOG in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or SARs, the vesting of restricted stock or restricted stock unit grants or in payment of the exercise price of employee stock options.

Accumulated_Other_Comprehensiv1

Accumulated Other Comprehensive Income Accumulated Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2014
Accumulated Other Comprehensive Income [Abstract]
Accumulated Other Comprehensive Income	The components of Accumulated Other Comprehensive Income (Loss) at December 31, 2014 and 2013 consisted of the following (in thousands):
		Foreign Currency Translation Adjustment				Foreign Currency Swap				Interest Rate Swap				Other (3)			Total
	31-Dec-13	$	417,707			$	620			$	(496	)		$	(1,997	)	$	415,834
	Other comprehensive loss before reclassifications	(54,484		)		—				—				(918		)	(55,402		)
	Amounts reclassified out of other comprehensive income (loss)	(383,244		)	(1)	(670		)	(2)	777			(2)	139			(382,998		)
	Tax effects	—				50				(281		)		(259		)	(490		)
	Other comprehensive income (loss)	(437,728		)		(620		)		496				(1,038		)	(438,890		)
	31-Dec-14	$	(20,021	)		$	—			$	—			$	(3,035	)	$	(23,056	)
	-1	Reclassified to Net Income - Gain on Asset Dispositions, Net. See Note 17.
	-2	Reclassified to Net Income - Interest Expense Incurred. See Note 2.
	-3	Related to certain EOG pension plans. See Note 7.

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Deferred Income Tax Liabilities, Net Table	The principal components of EOG's net deferred income tax liabilities at December 31, 2014 and 2013 were as follows (in thousands):
		2014				2013
	Current Deferred Income Tax Assets (Liabilities)
	Commodity Hedging Contracts	$	—			$	29,582
	Deferred Compensation Plans	—				42,296
	Net Operating Loss	—				96,616
	Alternative Minimum Tax Credit Carryforward	—				72,297
	Foreign Net Operating Loss	49,865				—
	Foreign Valuation Allowance	(30,247		)		—
	Other	—				3,815
	Total Net Current Deferred Income Tax Assets	$	19,618			$	244,606
	Noncurrent Deferred Income Tax Assets (Liabilities)
	Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization	$	(141,643	)		$	(112,346	)
	Foreign Net Operating Loss	487,876				369,257
	Foreign Valuation Allowances	(349,704		)		(183,122		)
	Foreign Other	4,096				4,179
	Total Net Noncurrent Deferred Income Tax Assets	$	625			$	77,968
	Current Deferred Income Tax (Asset) Liabilities
	Commodity Hedging Contracts	$	166,109			$	—
	Deferred Compensation Plans	(48,207		)		—
	Accrued Expenses and Liabilities	(5,643		)		—
	Other	(1,516		)		—
	Total Net Current Deferred Income Tax Liabilities	$	110,743			$	—
	Noncurrent Deferred Income Tax (Assets) Liabilities
	Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization	$	7,634,297			$	6,287,541
	Non-Producing Leasehold Costs	(44,236		)		(50,581		)
	Seismic Costs Capitalized for Tax	(158,157		)		(136,964		)
	Equity Awards	(127,541		)		(122,665		)
	Capitalized Interest	97,739				101,006
	Alternative Minimum Tax Credit Carryforward	(793,126		)		(557,352		)
	Undistributed Foreign Earnings	249,861				—
	Other	(35,891		)		1,369
	Total Net Noncurrent Deferred Income Tax Liabilities	$	6,822,946			$	5,522,354
	Total Net Deferred Income Tax Liabilities	$	6,913,446			$	5,199,780
Components of Income Before Income Taxes	The components of Income Before Income Taxes for the years indicated below were as follows (in thousands):
		2014				2013				2012
	United States	$	5,161,232			$	3,268,727			$	1,988,105
	Foreign	(165,917		)		168,159				(707,365		)
	Total	$	4,995,315			$	3,436,886			$	1,280,740
Components of Income Tax Provision	The principal components of EOG's Income Tax Provision for the years indicated below were as follows (in thousands):
		2014				2013				2012
	Current:
	Federal	$	269,326			$	207,777			$	242,674
	State	22,835				22,856				22,573
	Foreign	82,721				134,379				152,276
	Total	374,882				365,012				417,523
	Deferred:
	Federal	1,608,706				915,994				454,173
	State	29,056				26,305				632
	Foreign	67,184				(67,534		)		(161,867		)
	Total	1,704,946				874,765				292,938
	Income Tax Provision	$	2,079,828			$	1,239,777			$	710,461
Tax Rate Reconciliation	The differences between taxes computed at the United States federal statutory tax rate and EOG's effective rate were as follows:
		2014			2013			2012
	Statutory Federal Income Tax Rate	35	%		35	%		35	%
	State Income Tax, Net of Federal Benefit	0.68			0.93			1.18
	Income Tax Provision Related to Foreign Operations	(0.12	)		0.23			1.11
	Canadian Divestiture	(3.46	)		—			—
	Undistributed Foreign Earnings	4.94			—			—
	Foreign Valuation Allowances	6.47			—			10.57
	Foreign Oil and Gas Impairments	(1.90	)		—			6.9
	Other	0.03			(0.09	)		0.71
	Effective Income Tax Rate	41.64	%		36.07	%		55.47	%

Employee_Benefit_Plans_Tables

Employee Benefit Plans (Tables) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014																										Dec. 31, 2013
Employee Benefit Plans [Abstract]
Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs	tock-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, 2014, 2013 and 2012 was as follows (in millions):
		2014				2013				2012
	Lease and Well	$	41			$	35			$	35
	Gathering and Processing Costs	1				1				1
	Exploration Costs	27				27				27
	General and Administrative	76				71				65
	Total	$	145			$	134			$	128
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, 2014, 2013 and 2012 were as follows:
		Stock Options/SARs												ESPP
		2014				2013				2012				2014				2013				2012
	Weighted Average Fair Value of Grants	$	30.75			$	27.35			$	18.98			$	21.65			$	15.06			$	12.56
	Expected Volatility	35.28		%		35.86		%		39.68		%		25.03		%		29.89		%		40.92		%
	Risk-Free Interest Rate	0.95		%		0.78		%		0.45		%		0.08		%		0.11		%		0.11		%
	Dividend Yield	0.61		%		0.4		%		0.6		%		0.46		%		0.6		%		0.6		%
	Expected Life	5.2 years				5.5 years				5.6 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, 2014, 2013 and 2012 (stock options and SARs in thousands):
		2014							2013							2012
		Number			Weighted				Number			Weighted				Number			Weighted
		of Stock			Average				of Stock			Average				of Stock			Average
		Options/			Grant				Options/			Grant				Options/			Grant
		SARs			Price				SARs			Price				SARs			Price
	Outstanding at January 1	10,452			$	54.43			12,438			$	42.91			16,748			$	35.01
	Granted	2,146			101.55				2,268			83.7				2,480			55.99
	Exercised (1)	(1,718	)		45.68				(4,046	)		35.62				(6,492	)		27.4
	Forfeited	(387	)		68.95				(208	)		50.78				(298	)		45.59
	Outstanding at December 31	10,493			64.96				10,452			54.43				12,438			42.91
	Stock Options/SARs Exercisable at December 31	5,287			49.4				4,638			43.95				6,286			37.49
	-1	The total intrinsic value of stock options/SARs exercised during the years 2014, 2013 and 2012 was $95 million, $151 million and $185 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.
Subsidiary payment obligations guaranteed																											$561
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, 2014 (stock options and SARs in thousands):
	Stock Options/SARs Outstanding															Stock Options/SARs Exercisable
	Range of		Stock			Weighted		Weighted								Stock			Weighted		Weighted
	Grant		Options/			Average		Average								Options/			Average		Average
	Prices		SARs			Remaining		Grant				Aggregate				SARs			Remaining		Grant				Aggregate
						Life		Price				Intrinsic							Life		Price				Intrinsic
						(Years)						Value(1)							(Years)						Value (1)
	$22.00 to $  42.99		2,682			3		$	40.74							2,129			3		$	40.5
	43.00 to     46.99		1,612			2		45.57								1,598			2		45.58
	47.00 to   56.99		2,014			4		55.8								995			4		55.57
	57.00 to    84.99		2,099			5		83.08								548			5		82.44
	85.00 to   116.99		2,086			7		101.7								17			3		97.77
			10,493			4		64.96				$	304,679			5,287			3		49.4				$	225,692
	-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, 2014, approximately 794,000 shares of Common Stock remained available for issuance under the ESPP.  The following table summarizes ESPP activities for the years ended December 31, 2014, 2013 and 2012 (in thousands, except number of participants):
		2014				2013				2012
	Approximate Number of Participants	1,991				1,844				1,705
	Shares Purchased	202				256				328
	Aggregate Purchase Price	$	14,927			$	14,015			$	12,522
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, 2014, 2013 and 2012 (shares and units in thousands):
		2014							2013							2012
		Number of			Weighted				Number of			Weighted				Number of			Weighted
		Shares and			Average				Shares and			Average				Shares and			Average
		Units			Grant Date				Units			Grant Date				Units			Grant Date
					Fair Value							Fair Value							Fair Value
	Outstanding at January 1	7,358			$	49.54			7,636			$	45.53			8,480			$	41.47
	Granted	1,132			98.72				1,294			76.04				1,534			56.09
	Released (1)	(2,761	)		105.24				(1,368	)		52.39				(2,118	)		36.35
	Forfeited	(335	)		62.55				(204	)		48.55				(260	)		42.68
	Outstanding at December 31 (2)	5,394			64.39				7,358			49.54				7,636			45.53
	-1	The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2014, 2013 and 2012 was $291 million, $101 million and $120 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, 2014 and 2013 was approximately $497 million and $617 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, 2014, 2013 and 2012 were as follows:
		2014				2013				2012
	Weighted Average Fair Value of Grants	$	119.27			$	100.34			$	67.05
	Expected Volatility	32.18		%		33.63		%		36.39		%
	Risk-Free Interest Rate	1.18		%		0.79		%		0.39		%
Performance Unit and Performance Stock Transactions	The following table sets forth performance unit and performance stock transactions for the years ended December 31, 2014, 2013 and 2012 (shares and units in thousands):
		2014							2013							2012
		Number of			Weighted				Number of			Weighted				Number of			Weighted
		Shares and			Average				Shares and			Average				Shares and			Average
		Units			Grant Date				Units			Grant Date				Units			Grant Date
					Fair Value							Fair Value							Fair Value
	Outstanding at January 1	261			$	82.18			142			$	67.05			—			—
	Granted	72			119.27				119			100.34				142			67.05
	Outstanding at December 31 (1)	333			$	90.17			261			$	82.18			142			$	67.05
	-1	The total intrinsic value of performance units and performance stock outstanding at December 31, 2014 and 2013 was $30.7 million and $21.9 million, respectively.

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Minimum commitments for unrecorded unconditional purchase obligations [Table]	At December 31, 2014, 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, 2014, were as follows (in thousands):
		Total Minimum
		Commitments
	2015	$	1,643,053
	2016 - 2017	1,981,982
	2018 - 2019	1,221,216
	2020 and beyond	974,073
		$	5,820,324

Net_Income_Per_Share_Tables

Net Income Per Share (Tables)	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Computation of Net Income Per Share	The following table sets forth the computation of Net Income Per Share for the years ended December 31, 2014, 2013 and 2012 (in thousands, except per share data):
		2014		2013		2012
	Numerator for Basic and Diluted Earnings per Share -
	Net Income	$	2,915,487	$	2,197,109	$	570,279
	Denominator for Basic Earnings per Share -
	Weighted Average Shares	543,443		540,341		535,155
	Potential Dilutive Common Shares -
	Stock Options/SARs	2,526		2,316		2,911
	Restricted Stock/Units and Performance Units/Stock	2,570		3,570		3,458
	Denominator for Diluted Earnings per Share -
	Adjusted Diluted Weighted Average Shares	548,539		546,227		541,524
	Net Income Per Share
	Basic	$	5.36	$	4.07	$	1.07
	Diluted	$	5.32	$	4.02	$	1.05

Supplemental_Cash_Flow_Informa1

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014, 2013 and 2012 (in thousands):
		2014		2013		2012
	Interest, Net of Capitalized Interest	$	197,383	$	235,854	$	196,944
	Income Taxes, Net of Refunds Received	$	342,741	$	294,739	$	360,006

Business_Segment_Information_T

Business Segment Information (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014, 2013 and 2012 (in thousands):
		United			Canada			Trinidad		Other			Total
		States								International (1)
	2014
	Crude Oil and Condensate	$	9,526,149		$	184,420		$	29,604	$	2,307		$	9,742,480
	Natural Gas Liquids	924,454			9,597			—		—			934,051
	Natural Gas	1,321,175			96,274			483,071		15,866			1,916,386
	Gains on Mark-to-Market Commodity Derivative Contracts	834,273			—			—		—			834,273
	Gathering, Processing and Marketing	4,040,024			228			6,064		—			4,046,316
	Gains on Asset Dispositions, Net	96,339			411,251			—		—			507,590
	Other, Net	49,950			4,257			37		—			54,244
	Net Operating Revenues (2)	16,792,364			706,027			518,776		18,173			18,035,340
	Depreciation, Depletion and Amortization	3,684,943			105,274			188,592		18,232			3,997,041
	Operating Income (Loss)	5,074,911			360,114			277,471		(470,673		)	5,241,823
	Interest Income	849			847			253		290			2,239
	Other Income (Expense)	(14,953		)	(19,719		)	8,712		(21,329		)	(47,289		)
	Net Interest Expense	269,166			(20,681		)	—		(47,027		)	201,458
	Income (Loss) Before Income Taxes	4,791,641			361,923			286,436		(444,685		)	4,995,315
	Income Tax Provision	1,837,185			80,807			98,559		63,277			2,079,828
	Additions to Oil and Gas Properties, Excluding Dry Hole Costs	7,133,727			76,642			76,138		184,670			7,471,177
	Total Property, Plant and Equipment, Net	28,391,741			33,635			382,719		364,549			29,172,644
	Total Assets	32,871,398			182,250			865,674		843,365			34,762,687
		United			Canada			Trinidad		Other			Total
		States								International (1)
	2013
	Crude Oil and Condensate	$	8,035,358		$	221,999		$	40,379	$	2,911		$	8,300,647
	Natural Gas Liquids	761,535			12,435			—		—			773,970
	Natural Gas	1,100,808			85,446			477,103		17,672			1,681,029
	Losses on Mark-to-Market Commodity Derivative Contracts	(166,349		)	—			—		—			(166,349		)
	Gathering, Processing and Marketing	3,636,209			1,476			6,064		—			3,643,749
	Gains on Asset Dispositions, Net	93,876			102,570			1,119		—			197,565
	Other, Net	51,713			4,770			24		—			56,507
	Net Operating Revenues (3)	13,513,150			428,696			524,689		20,583			14,487,118
	Depreciation, Depletion and Amortization	3,223,596			180,836			181,990		14,554			3,600,976
	Operating Income (Loss)	3,543,841			(45,214		)	266,329		(89,745		)	3,675,211
	Interest Income	2,803			2,076			336		370			5,585
	Other Income (Expense)	(29,696		)	7,707			9,889		3,650			(8,450		)
	Net Interest Expense	283,209			(4,204		)	—		(43,545		)	235,460
	Income (Loss) Before Income Taxes	3,233,739			(31,227		)	276,554		(42,180		)	3,436,886
	Income Tax Provision (Benefit)	1,161,328			598			118,270		(40,419		)	1,239,777
	Additions to Oil and Gas Properties, Excluding Dry Hole Costs	6,133,894			137,920			132,984		217,638			6,622,436
	Total Property, Plant and Equipment, Net	24,456,383			602,333			476,174		613,946			26,148,836
	Total Assets	27,668,713			880,765			986,796		1,037,964			30,574,238
	2012
	Crude Oil and Condensate	$	5,383,612		$	221,556		$	50,708	$	3,561		$	5,659,437
	Natural Gas Liquids	713,497			13,680			—		—			727,177
	Natural Gas	951,463			86,361			514,322		19,616			1,571,762
	Gains on Mark-to-Market Commodity Derivative Contracts	393,744			—			—		—			393,744
	Gathering, Processing and Marketing	3,091,281			—			5,413		—			3,096,694
	Gains on Asset Dispositions, Net	166,201			26,459			—		—			192,660
	Other, Net	40,780			367			15		—			41,162
	Net Operating Revenues (4)	10,740,578			348,423			570,458		23,177			11,682,636
	Depreciation, Depletion and Amortization	2,780,563			223,689			147,062		18,389			3,169,703
	Operating Income (Loss)	2,233,911			(1,065,434		)	371,876		(60,556		)	1,479,797
	Interest Income	8,343			123			125		180			8,771
	Other Income (Expense)	(12,455		)	(8,689		)	20,482		6,386			5,724
	Net Interest Expense	242,138			6,589			238		(35,413		)	213,552
	Income (Loss) Before Income Taxes	1,987,661			(1,080,589		)	392,245		(18,577		)	1,280,740
	Income Tax Provision (Benefit)	707,401			(134,745		)	140,468		(2,663		)	710,461
	Additions to Oil and Gas Properties, Excluding Dry Hole Costs	6,198,267			302,851			49,376		169,852			6,720,346
	Total Property, Plant and Equipment, Net	21,560,998			877,996			535,405		363,282			23,337,681
	Total Assets	24,523,072			1,202,031			1,012,727		598,748			27,336,578
	-1	Other International primarily consists of EOG's United Kingdom, China and Argentina operations.
	-2	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.
-3	EOG had sales activity with two significant purchasers in 2013, one totaling $3.9 billion and the other totaling $2.0 billion of consolidated Net Operating Revenues in the United States segment.
-4	EOG had sales activity with a single significant purchaser in 2012 that totaled $2.2 billion of consolidated Net Operating Revenues in the United States segment.

Risk_Management_Activities_Tab

Risk Management Activities (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity Derivative Contracts - Crude Oil	Presented below is a comprehensive summary of EOG's crude oil derivative contracts at December 31, 2014, with notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl).
	Crude Oil Derivative Contracts
		Volume		Weighted
		(Bbld)		Average Price
				($/Bbl)
	2015 (1)
	January 1, 2015 through June 30, 2015	47,000		$	91.22
	July 1, 2015 through December 31, 2015	10,000		89.98
	-1	EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional six-month periods.  Options covering a notional volume of 37,000 Bbld are exercisable on June 30, 2015.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 37,000 Bbld at an average price of $91.56 per barrel for each month during the period July 1, 2015 through December 31, 2015.
Commodity Derivative Contracts - Natural Gas	Presented below is a comprehensive summary of EOG's natural gas derivative contracts at December 31, 2014, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).
	Natural Gas Derivative Contracts
		Volume (MMBtud)		Weighted
				Average Price ($/MMBtu)
	2015 (1)
	January 2015 (closed)	235,000		$	4.47
	Feb-15	235,000		4.47
	Mar-15	225,000		4.48
	Apr-15	195,000		4.49
	May 1, 2015 through December 31, 2015	175,000		4.51
	-1	EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates.  All such options are exercisable monthly up until the settlement date of each monthly contract.  If the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 175,000 MMBtud at an average price of $4.51 per MMBtu for each month during the period February 1, 2015 through December 31, 2015.
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, 2014 and 2013, 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	2014		2013
	Asset Derivatives
	Crude oil and natural gas derivative contracts -
	Current portion		Assets from Price Risk Management Activities (1)	$	465	$	8
	Liability Derivatives
	Crude oil and natural gas derivative contracts -
	Current portion		Liabilities from Price Risk Management Activities (2)	$	—	$	127
	Foreign currency swap - Current portion		Current Liabilities - Other	$	—	$	40
	Interest rate swap - Current portion		Current Liabilities - Other	$	—	$	1
	-1	The current portion of Assets from Price Risk Management Activities consists of gross assets of $477 million, partially offset by gross liabilities of $12 million, at December 31, 2014 and gross assets of $18 million, partially offset by gross liabilities of $10 million, at December 31, 2013.
	-2	The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $12 million, offset by gross assets of $12 million, at December 31, 2014 and gross liabilities of $137 million, partially offset by gross assets of $10 million, at December 31, 2013.

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014 and 2013 (in millions):
		Fair Value Measurements Using:
		Quoted		Significant		Significant		Total
		Prices in		Other		Unobservable
		Active		Observable		Inputs
		Markets		Inputs		(Level 3)
		(Level 1)		(Level 2)
	At December 31, 2014
	Financial Assets:
	Natural Gas Options/Swaptions	$	—	$	100	$	—	$	100
	Crude Oil Swaps	—		121		—		121
	Crude Oil Options/Swaptions	—		244		—		244
	At December 31, 2013
	Financial Assets:
	Natural Gas Options/Swaptions	$	—	$	8	$	—	$	8
	Financial Liabilities:
	Crude Oil Swaps	$	—	$	17	$	—	$	17
	Crude Oil Options/Swaptions	—		110		—		110
	Foreign Currency Rate Swap	—		40		—		40
	Interest Rate Swap	—		1		—		1

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014 and 2013 (in thousands):
		2014			2013
	Carrying Amount at Beginning of Period	$	761,898		$	665,944
	Liabilities Incurred	123,849			103,284
	Liabilities Settled (1)	(247,422		)	(70,510		)
	Accretion	41,489			35,180
	Revisions	82,885			38,552
	Foreign Currency Translations	(9,981		)	(10,552		)
	Carrying Amount at End of Period	$	752,718		$	761,898
	Current Portion	$	11,814		$	43,857
	Noncurrent Portion	$	740,904		$	718,041
	-1	Includes settlements related to asset sales.

Exploratory_Well_Costs_Tables

Exploratory Well Costs (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014, 2013 and 2012 are presented below (in thousands):
		2014			2013			2012
	Balance at January 1	$	9,211		$	49,116		$	61,111
	Additions Pending the Determination of Proved Reserves	32,080			52,099			73,332
	Reclassifications to Proved Properties	(15,946		)	(54,505		)	(69,462		)
	Costs Charged to Expense (1)	(8,092		)	(35,859		)	(17,115		)
	Foreign Currency Translations	—			(1,640		)	1,250
	Balance at December 31	$	17,253		$	9,211		$	49,116		(2)
	-1	Includes capitalized exploratory well costs charged to either dry hole costs or impairments.
	-2	At December 31, 2012, exploratory well costs totaling $21 million related to an outside operated offshore Central North Sea project in the United Kingdom that had been capitalized for more than one year.

Oil_and_Gas_Exploration_and_Pr1

Oil and Gas Exploration and Production Industries Disclosures (Tables)	12 Months Ended
	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Net Proved and Proved Developed Oil and Gas Reserve Quantities [Table Text Block]	The following tables set forth EOG's net proved and proved developed reserves at December 31 for each of the four years in the period ended December 31, 2014, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2014, as estimated by the Engineering and Acquisitions Department of EOG:
	NET PROVED AND PROVED DEVELOPED RESERVE SUMMARY
		United			Canada			Trinidad			Other		Total
		States									International (1)
	NET PROVED RESERVES
	Crude Oil (MBbl) (2)
	Net proved reserves at December 31, 2011	495,296			18,592			3,507			98		517,493
	Revisions of previous estimates	4,105			(2,493	)		71			5		1,688
	Purchases in place	1,010			—			—			—		1,010
	Extensions, discoveries and other additions	241,171			5,681			—			8,834		255,686
	Sales in place	(15,921	)		(1,343	)		—			—		(17,264	)
	Production	(54,632	)		(2,574	)		(550	)		(39	)	(57,795	)
	Net proved reserves at December 31, 2012	671,029			17,863			3,028			8,898		700,818
	Revisions of previous estimates	57,668			(5,866	)		(991	)		(142	)	50,669
	Purchases in place	1,097			—			—			—		1,097
	Extensions, discoveries and other additions	230,023			673			—			58		230,754
	Sales in place	(2,337	)		—			—			—		(2,337	)
	Production	(77,431	)		(2,550	)		(447	)		(33	)	(80,461	)
	Net proved reserves at December 31, 2013	880,049			10,120			1,590			8,781		900,540
	Revisions of previous estimates	28,301			(313	)		99			(65	)	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	)		(2,126	)		(350	)		(26	)	(105,448	)
	Net proved reserves at December 31, 2014	1,129,682			25			1,339			8,704		1,139,750
	Natural Gas Liquids (MBbl) (2)
	Net proved reserves at December 31, 2011	226,586			1,202			—			—		227,788
	Revisions of previous estimates	47,293			563			—			—		47,856
	Purchases in place	612			—			—			—		612
	Extensions, discoveries and other additions	71,396			178			—			—		71,574
	Sales in place	(7,300	)		(77	)		—			—		(7,377	)
	Production	(20,181	)		(309	)		—			—		(20,490	)
	Net proved reserves at December 31, 2012	318,406			1,557			—			—		319,963
	Revisions of previous estimates	12,157			(48	)		—			—		12,109
	Purchases in place	1,202			—			—			—		1,202
	Extensions, discoveries and other additions	69,187			10			—			—		69,197
	Sales in place	(1,471	)		—			—			—		(1,471	)
	Production	(23,479	)		(315	)		—			—		(23,794	)
	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
		United			Canada			Trinidad			Other		Total
		States									International (1)
	Natural Gas (Bcf) (3)
	Net proved reserves at December 31, 2011	6,045.80			1,035.90			750.7			18.5		7,850.90
	Revisions of previous estimates	(1,736.0	)		(894.5	)		(24.1	)		1.6		(2,653.0	)
	Purchases in place	14.8			—			—			—		14.8
	Extensions, discoveries and other additions	477.8			—			—			0.3		478.1
	Sales in place	(386.2	)		(8.5	)		—			—		(394.7	)
	Production	(380.2	)		(34.6	)		(138.4	)		(3.4	)	(556.6	)
	Net proved reserves at December 31, 2012	4,036.00			98.3			588.2			17		4,739.50
	Revisions of previous estimates	264			31.4			(17.4	)		(0.7	)	277.3
	Purchases in place	5.7			—			—			—		5.7
	Extensions, discoveries and other additions	504.7			0.1			79.5			9.8		594.1
	Sales in place	(69.4	)		—			—			—		(69.4	)
	Production	(342.3	)		(27.7	)		(129.6	)		(2.8	)	(502.4	)
	Net proved reserves at December 31, 2013	4,398.70			102.1			520.7			23.3		5,044.80
	Revisions of previous estimates	252.2			9.8			12.9			(4.3	)	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	)		(22.3	)		(132.5	)		(3.1	)	(506.3	)
Net proved reserves at December 31, 2014	4,905.50			10.9			405.6			20.6		5,342.60
Oil Equivalents (MBoe) (2)
Net proved reserves at December 31, 2011	1,729,508			192,448			128,629			3,178		2,053,763
Revisions of previous estimates	(237,936	)		(151,015	)		(3,953	)		283		(392,621	)
Purchases in place	4,098			—			—			—		4,098
Extensions, discoveries and other additions	392,196			5,860			—			8,876		406,932
Sales in place	(87,588	)		(2,832	)		—			—		(90,420	)
Production	(138,170	)		(8,657	)		(23,616	)		(611	)	(171,054	)
Net proved reserves at December 31, 2012	1,662,108			35,804			101,060			11,726		1,810,698
Revisions of previous estimates	113,823			(676	)		(3,892	)		(265	)	108,990
Purchases in place	3,241			—			—			—		3,241
Extensions, discoveries and other additions	383,324			693			13,245			1,703		398,965
Sales in place	(15,375	)		—			—			—		(15,375	)
Production	(157,955	)		(7,482	)		(22,049	)		(490	)	(187,976	)
Net proved reserves at December 31, 2013	1,989,166			28,339			88,364			12,674		2,118,543
Revisions of previous estimates	97,782			1,316			2,245			(775	)	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	)		(6,080	)		(22,430	)		(551	)	(219,126	)
Net proved reserves at December 31, 2014	2,414,202			1,973			68,937			12,144		2,497,256
-1	Other International includes EOG's United Kingdom, China and Argentina operations.
-2	Thousand barrels or thousand barrels of oil equivalent, as applicable; oil equivalents include crude oil and condensate, NGL and natural gas. Oil equivalents are determined using the ratio of 1.0 barrel of crude oil and condensate or NGL 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 [Table Text Block]
		United			Canada			Trinidad			Other		Total
		States									International (1)
	NET PROVED DEVELOPED RESERVES
	Crude Oil (MBbl)
	December 31, 2011	213,872			8,128			2,657			98		224,755
	December 31, 2012	281,167			6,853			2,377			253		290,650
	December 31, 2013	382,517			6,871			1,505			163		391,056
	December 31, 2014	493,694			25			1,339			90		495,148
	Natural Gas Liquids (MBbl)
	December 31, 2011	124,271			1,092			—			—		125,363
	December 31, 2012	161,482			1,111			—			—		162,593
	December 31, 2013	199,964			896			—			—		200,860
	December 31, 2014	264,611			138			—			—		264,749
	Natural Gas (Bcf)
	December 31, 2011	3,235.00			295.8			606.3			18.5		4,155.60
	December 31, 2012	2,387.50			98.3			476.7			17		2,979.50
	December 31, 2013	2,597.30			102.1			494.6			19.4		3,213.40
	December 31, 2014	3,102.80			10.9			396.9			17.7		3,528.30
	Oil Equivalents (MBoe)
	December 31, 2011	877,301			58,524			103,710			3,178		1,042,713
	December 31, 2012	840,564			24,348			81,826			3,081		949,819
	December 31, 2013	1,015,359			24,782			83,933			3,402		1,127,476
	December 31, 2014	1,275,447			1,973			67,484			3,043		1,347,947
	NET PROVED UNDEVELOPED RESERVES
	Crude Oil (MBbl)
	December 31, 2011	281,424			10,464			850			—		292,738
	December 31, 2012	389,862			11,010			651			8,645		410,168
	December 31, 2013	497,532			3,249			85			8,618		509,484
	December 31, 2014	635,988			—			—			8,614		644,602
	Natural Gas Liquids (MBbl)
	December 31, 2011	102,315			110			—			—		102,425
	December 31, 2012	156,924			446			—			—		157,370
	December 31, 2013	176,038			308			—			—		176,346
	December 31, 2014	202,319			—			—			—		202,319
	Natural Gas (Bcf)
	December 31, 2011	2,810.80			740.1			144.4			—		3,695.30
	December 31, 2012	1,648.50			—			111.5			—		1,760.00
	December 31, 2013	1,801.40			—			26.1			3.9		1,831.40
	December 31, 2014	1,802.70			—			8.7			2.9		1,814.30
	Oil Equivalents (MBoe)
	December 31, 2011	852,207			133,924			24,919			—		1,011,050
	December 31, 2012	821,544			11,456			19,234			8,645		860,879
	December 31, 2013	973,807			3,557			4,431			9,272		991,067
	December 31, 2014	1,138,755			—			1,453			9,101		1,149,309
	-1	Other International includes EOG's United Kingdom, China and Argentina operations.
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, 2014 and 2013:
		2014				2013
	Proved properties	$	45,169,101			$	41,377,303
	Unproved properties	1,334,431				1,444,500
	Total	46,503,532				42,821,803
	Accumulated depreciation, depletion and amortization	(20,212,748		)		(18,880,611		)
	Net capitalized costs	$	26,290,784			$	23,941,192
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, 2014, 2013 and 2012:
		United				Canada				Trinidad			Other			Total
		States											International (1)
	2014
	Acquisition Costs of Properties
	Unproved	$	365,915			$	4,499			$	—		$	—		$	370,414
	Proved	138,772				349				—			(20		)	139,101
	Subtotal	504,687				4,848				—			(20		)	509,515
	Exploration Costs	332,703				13,010				2,794			47,466			395,973
	Development Costs (2)	6,638,192				101,634				89,555			169,900			6,999,281
	Total	$	7,475,582			$	119,492			$	92,349		$	217,346		$	7,904,769
	2013
	Acquisition Costs of Properties
	Unproved	$	411,556			$	2,565			$	—		$	—		$	414,121
	Proved	120,220				(6		)		—			—			120,214
	Subtotal	531,776				2,559				—			—			534,335
	Exploration Costs	273,788				19,660				16,060			67,671			377,179
	Development Costs (3)	5,573,260				149,426				124,231			239,460			6,086,377
	Total	$	6,378,824			$	171,645			$	140,291		$	307,131		$	6,997,891
	2012
	Acquisition Costs of Properties
	Unproved	$	471,345			$	33,561			$	1,000		$	(603	)	$	505,303
	Proved	739				—				—			—			739
	Subtotal	472,084				33,561				1,000			(603		)	506,042
	Exploration Costs	333,534				38,530				19,555			53,979			445,598
	Development Costs (4)	5,657,378				278,995				32,609			147,568			6,116,550
	Total	$	6,462,996			$	351,086			$	53,164		$	200,944		$	7,068,190
	-1	Other International primarily consists of EOG's United Kingdom, China and Argentina operations.
	-2	Includes Asset Retirement Costs of $149 million, $31 million, $14 million and $2 million for the United States, Canada, Trinidad and Other International, respectively.  Excludes other property, plant and equipment.
	-3	Includes Asset Retirement Costs of $84 million, $13 million and $37 million for the United States, Canada and Other International, respectively.  Excludes other property, plant and equipment.
	-4	Includes Asset Retirement Costs of $80 million, $33 million, $2 million and $12 million for the United States, Canada, 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, 2014, 2013 and 2012:
		United				Canada				Trinidad			Other			Total
		States											International (2)
	2014
	Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	11,771,777			$	290,291			$	512,675		$	18,174		$	12,592,917
	Other	49,950				4,257				37			—			54,244
	Total	11,821,727				294,548				512,712			18,174			12,647,161
	Exploration Costs	162,434				11,877				2,185			7,892			184,388
	Dry Hole Costs	25,408				—				—			23,082			48,490
	Transportation Costs	957,522				12,618				617			1,419			972,176
	Production Costs	1,940,074				158,882				38,301			12,770			2,150,027
	Impairments	331,792				15,879				—			395,904			743,575
	Depreciation, Depletion and Amortization	3,571,313				104,462				188,250			17,695			3,881,720
	Income (Loss) Before Income Taxes	4,833,184				(9,170		)		283,359			(440,588		)	4,666,785
	Income Tax Provision (Benefit)	1,722,914				(2,360		)		74,588			25,962			1,821,104
	Results of Operations	$	3,110,270			$	(6,810	)		$	208,771		$	(466,550	)	$	2,845,681
	2013
	Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	9,897,701			$	319,880			$	517,482		$	20,583		$	10,755,646
	Other	51,713				4,770				24			—			56,507
	Total	9,949,414				324,650				517,506			20,583			10,812,153
	Exploration Costs	141,286				11,203				2,345			6,512			161,346
	Dry Hole Costs	14,276				9,579				4,478			46,322			74,655
	Transportation Costs	841,567				9,694				659			1,124			853,044
	Production Costs	1,494,791				154,947				43,279			13,205			1,706,222
	Impairments	178,718				84,934				14,274			9,015			286,941
	Depreciation, Depletion and Amortization	3,122,858				179,520				181,637			13,995			3,498,010
	Income (Loss) Before Income Taxes	4,155,918				(125,227		)		270,834			(69,590		)	4,231,935
	Income Tax Provision (Benefit)	1,486,445				(32,295		)		103,313			(66,931		)	1,490,532
	Results of Operations	$	2,669,473			$	(92,932	)		$	167,521		$	(2,659	)	$	2,741,403
	2012
	Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues	$	7,048,572			$	321,597			$	565,030		$	23,177		$	7,958,376
	Other	40,780				367				15			—			41,162
	Total	7,089,352				321,964				565,045			23,177			7,999,538
	Exploration Costs	162,152				13,350				2,262			7,805			185,569
	Dry Hole Costs	1,772				1,570				—			11,628			14,970
	Transportation Costs	591,547				7,511				1,104			1,269			601,431
	Production Costs	1,264,633				154,509				37,792			11,694			1,468,628
	Impairments	294,172				976,563				—			—			1,270,735
	Depreciation, Depletion and Amortization	2,637,500				222,366				146,690			17,958			3,024,514
	Income (Loss) Before Income Taxes	2,137,576				(1,053,905		)		377,197			(27,177		)	1,433,691
	Income Tax Provision (Benefit)	761,459				(136,105		)		119,442			(21,890		)	722,906
	Results of Operations	$	1,376,117			$	(917,800	)		$	257,755		$	(5,287	)	$	710,785
	-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, 2014.
	-2	Other International primarily consists of EOG's United Kingdom, China and Argentina operations.
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, 2014, 2013 and 2012:
		United				Canada				Trinidad			Other			Composite
		States											International (1)
	Year Ended December 31, 2014	$	6.44			$	24.76			$	1.34		$	22.83		$	6.46
	Year Ended December 31, 2013	$	5.78			$	19.98			$	1.36		$	26.77		$	5.88
	Year Ended December 31, 2012	$	5.96			$	16.42			$	0.98		$	18.97		$	5.85
	-1	Other International primarily consists of EOG's United Kingdom, China and Argentina operations.
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, 2014, 2013 and 2012:
		United				Canada				Trinidad			Other			Total
		States											International (1)
	2014
	Future cash inflows (2)	$	144,355,692			$	50,116			$	1,615,280		$	929,133		$	146,950,221
	Future production costs	(51,112,604		)		(25,561		)		(277,844		)	(217,284		)	(51,633,293		)
	Future development costs	(20,270,439		)		(32,016		)		(84,576		)	(107,734		)	(20,494,765		)
	Future income taxes	(22,725,618		)		—				(460,096		)	—			(23,185,714		)
	Future net cash flows	50,247,031				(7,461		)		792,764			604,115			51,636,449
	Discount to present value at 10% annual rate	(23,542,990		)		11,217				(110,228		)	(71,030		)	(23,713,031		)
	Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	26,704,041			$	3,756			$	682,536		$	533,085		$	27,923,418
	2013
	Future cash inflows (3)	$	119,644,713			$	1,199,251			$	2,082,195		$	1,073,340		$	123,999,499
	Future production costs	(49,099,393		)		(540,188		)		(315,483		)	(211,424		)	(50,166,488		)
	Future development costs	(17,753,860		)		(529,788		)		(112,050		)	(153,653		)	(18,549,351		)
	Future income taxes	(15,763,089		)		—				(603,786		)	(49,512		)	(16,416,387		)
	Future net cash flows	37,028,371				129,275				1,050,876			658,751			38,867,273
	Discount to present value at 10% annual rate	(17,451,470		)		202,379				(174,236		)	(110,514		)	(17,533,841		)
	Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	19,576,901			$	331,654			$	876,640		$	548,237		$	21,333,432
	2012
	Future cash inflows (4)	$	89,324,274			$	1,816,369			$	2,408,116		$	1,063,854		$	94,612,613
	Future production costs	(35,892,997		)		(751,113		)		(342,113		)	(198,609		)	(37,184,832		)
	Future development costs	(15,825,040		)		(813,061		)		(171,737		)	(221,893		)	(17,031,731		)
	Future income taxes	(10,247,007		)		—				(691,109		)	(212,626		)	(11,150,742		)
	Future net cash flows	27,359,230				252,195				1,203,157			430,726			29,245,308
	Discount to present value at 10% annual rate	(12,177,896		)		146,954				(242,087		)	(56,807		)	(12,329,836		)
	Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	15,181,334			$	399,149			$	961,070		$	373,919		$	16,915,472
	-1	Other International includes EOG's United Kingdom, China and Argentina operations.
	-2	Estimated crude oil prices used to calculate 2014 future cash inflows for the United States, Canada, Trinidad and Other International were $97.51, $95.11, $80.60 and $94.09, respectively. Estimated NGL prices used to calculate 2014 future cash inflows for the United States and Canada were $34.29 and $27.03, respectively. Estimated natural gas prices used to calculate 2014 future cash inflows for the United States, Canada, Trinidad and Other International were $3.71, $4.79, $3.71 and $5.34, respectively.
	-3	Estimated crude oil prices used to calculate 2013 future cash inflows for the United States, Canada, Trinidad and Other International were $105.91, $91.47, $94.30 and $107.36, respectively. Estimated NGL prices used to calculate 2013 future cash inflows for the United States and Canada were $29.42 and $40.88, respectively.  Estimated natural gas prices used to calculate 2013 future cash inflows for the United States, Canada, Trinidad and Other International were $3.50, $2.95, $3.71 and $5.67, respectively.
	-4	Estimated crude oil prices used to calculate 2012 future cash inflows for the United States, Canada, Trinidad and Other International were $99.78, $84.77, $94.46 and $109.94, respectively.  Estimated NGL prices used to calculate 2012 future cash inflows for the United States and Canada were $36.95 and $47.80, respectively. Estimated natural gas prices used to calculate 2012 future cash inflows for the United States, Canada, Trinidad and Other International were $2.63, $2.22, $3.61, and $5.04, respectively.
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves	Changes in Standardized Measure of Discounted Future Net Cash Flows.  The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for each of the three years in the period ended December 31, 2014:
		United				Canada				Trinidad			Other			Total
		States											International
	December 31, 2011	$	14,375,654			$	636,347			$	1,184,207		$	29,073		$	16,225,281
	Sales and transfers of oil and gas produced, net of production costs	(5,192,392		)		(159,577		)		(526,134		)	(10,214		)	(5,888,317		)
	Net changes in prices and production costs	(393,585		)		(67,964		)		162,600			(2,283		)	(301,232		)
	Extensions, discoveries, additions and improved recovery, net of related costs	5,517,945				79,529				—			484,648			6,082,122
	Development costs incurred	2,042,300				23,600				23,500			5,200			2,094,600
	Revisions of estimated development cost	1,987,330				383,215				(28,835		)	(234		)	2,341,476
	Revisions of previous quantity estimates	(3,286,943		)		(396,408		)		(62,285		)	2,809			(3,742,827		)
	Accretion of discount	1,832,377				63,635				178,298			2,907			2,077,217
	Net change in income taxes	174,418				—				88,853			(138,206		)	125,065
	Purchases of reserves in place	64,317				—				—			5,623			69,940
	Sales of reserves in place	(869,534		)		(44,227		)		—			—			(913,761		)
	Changes in timing and other	(1,070,553		)		(119,001		)		(59,134		)	(5,404		)	(1,254,092		)
	December 31, 2012	15,181,334				399,149				961,070			373,919			16,915,472
	Sales and transfers of oil and gas produced, net of production costs	(7,561,343		)		(155,239		)		(473,544		)	(6,254		)	(8,196,380		)
	Net changes in prices and production costs	1,734,058				(438,982		)		(12,050		)	(25,173		)	1,257,853
	Extensions, discoveries, additions and improved recovery, net of related costs	5,449,531				33,901				—			—			5,483,432
	Development costs incurred	2,792,400				95,400				67,100			1,000			2,955,900
	Revisions of estimated development cost	892,803				48,906				(3,539		)	52,226			990,396
	Revisions of previous quantity estimates	1,887,062				(23,915		)		(60,419		)	(8,530		)	1,794,198
	Accretion of discount	1,895,503				39,915				147,099			51,212			2,133,729
	Net change in income taxes	(2,772,267		)		—				56,373			137,644			(2,578,250		)
	Purchases of reserves in place	66,359				—				—			—			66,359
	Sales of reserves in place	(140,652		)		—				—			—			(140,652		)
	Changes in timing and other	152,113				332,519				194,550			(27,807		)	651,375
	December 31, 2013	19,576,901				331,654				876,640			548,237			21,333,432
	Sales and transfers of oil and gas produced, net of production costs	(8,874,180		)		(118,791		)		(473,757		)	(3,986		)	(9,470,714		)
	Net changes in prices and production costs	1,481,668				(94,315		)		(12,079		)	(112,097		)	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				200				12,800			3,300			2,835,100
	Revisions of estimated development cost	1,696,916				63,978				9,981			31,860			1,802,735
	Revisions of previous quantity estimates	1,741,918				42,000				35,001			(6,387		)	1,812,532
	Accretion of discount	2,612,286				33,165				133,019			54,880			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				34,936				6,380			10,527			1,242,348
	December 31, 2014	$	26,704,041			$	3,756			$	682,536		$	533,085		$	27,923,418

Unaudited_Quarterly_Financial_1

Unaudited Quarterly Financial Information (Tables)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Table - Unaudited Quarterly Financial Information	Unaudited Quarterly Financial Information
	(In Thousands, Except Per Share Data)
	Quarter Ended	31-Mar		30-Jun		30-Sep		31-Dec
	2014
	Net Operating Revenues	$	4,083,671	$	4,187,556	$	5,118,616	$	4,645,497
	Operating Income	$	1,084,279	$	1,144,730	$	1,786,162	$	1,226,652
	Income Before Income Taxes	$	1,030,789	$	1,100,813	$	1,715,120	$	1,148,593
	Income Tax Provision	369,861		394,460		611,502		704,005
	Net Income	$	660,928	$	706,353	$	1,103,618	$	444,588
	Net Income Per Share (1)
	Basic	$	1.22	$	1.3	$	2.03	$	0.82
	Diluted	$	1.21	$	1.29	$	2.01	$	0.81
	Average Number of Common Shares
	Basic	542,278		543,099		543,984		544,579
	Diluted	548,071		548,676		549,518		549,153
	2013
	Net Operating Revenues	$	3,356,514	$	3,840,185	$	3,541,396	$	3,749,023
	Operating Income	$	833,074	$	1,092,044	$	769,769	$	980,324
	Income Before Income Taxes	$	761,019	$	1,035,230	$	721,555	$	919,082
	Income Tax Provision	266,294		375,538		259,057		338,888
	Net Income	$	494,725	$	659,692	$	462,498	$	580,194
	Net Income Per Share (1)
	Basic	$	0.92	$	1.22	$	0.85	$	1.07
	Diluted	$	0.91	$	1.21	$	0.85	$	1.06
	Average Number of Common Shares
	Basic	538,717		540,033		540,941		541,857
	Diluted	544,526		545,477		547,152		547,966
	-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.

LongTerm_Debt_Details

Long-Term Debt (Details)

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2014

Dec. 31, 2014

Dec. 31, 2014

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

USD ($)

USD ($)

USD ($)

Revolving Credit Agreement [Member]

Canadian Dollar Letter of Credit Facilities Due 2018 [Member]

Canadian Dollar Letter of Credit Facilities Due 2018 [Member]

Uncommitted Credit Facilities [Member]

Uncommitted Credit Facilities [Member]

Commercial Paper [Member]

Commercial Paper [Member]

2.625% Senior Notes due 2023

2.625% Senior Notes due 2023

Floating Rate Senior Notes due 2014

Floating Rate Senior Notes due 2014

2.95% Senior Notes due 2015

2.95% Senior Notes due 2015

2.500% Senior Notes due 2016

2.500% Senior Notes due 2016

5.875% Senior Notes due 2017

5.875% Senior Notes due 2017

6.875% Senior Notes due 2018

6.875% Senior Notes due 2018

5.625% Senior Notes due 2019

5.625% Senior Notes due 2019

4.40% Senior Notes due 2020

4.40% Senior Notes due 2020

2.45% Senior Notes due 2020

2.45% Senior Notes due 2020

4.100% Senior Notes due 2021

4.100% Senior Notes due 2021

6.65% Senior Notes due 2028

6.65% Senior Notes due 2028

4.75% Subsidiary Debt due 2014

4.75% Subsidiary Debt due 2014

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CAD

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USD ($)

USD ($)

USD ($)

USD ($)

Debt Instrument Table [Line Items]

Total Long-Term Debt

$5,890,000,000

$5,890,000,000

$1,250,000,000

$1,250,000,000

$0

$350,000,000

$500,000,000

$500,000,000

$400,000,000

$400,000,000

$600,000,000

$600,000,000

$350,000,000

$350,000,000

$900,000,000

$900,000,000

$500,000,000

$500,000,000

$500,000,000

$0

$750,000,000

$750,000,000

$140,000,000

$140,000,000

$0

$150,000,000

Capital Lease Obligation

51,221,000

57,187,000

Less: Current Portion of Long-Term Debt

6,579,000

6,579,000

Unamortized Debt Discount

31,288,000

33,966,000

Total Long-Term Debt, Net

5,903,354,000

5,906,642,000

Debt Instrument Issuance [Abstract]

Debt Instrument Issuance Face Amount

350,000,000

500,000,000

150,000,000

Debt Instrument Issuance Interest Rate

2.95%

2.45%

4.75%

Debt Instrument, Maturity Years

2014

2020

Settlement of Foreign Currency

32,000,000

Settlement of Interest Rate Swap

800,000

Proceeds From Issuance of Senior Long-Term Debt

496,000,000

Long-Term Debt by Maturity [Abstract]

Aggregate annual maturity of long-term debt in 2014

500,000,000

Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2015

500,000,000

Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2016

400,000,000

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

Line of Credit Facility [Line Items]

Long-Term Debt Repayments

500,000,000

400,000,000

0

Average Borrowings Outstanding

100,000

0

12,000,000

37,000,000

Borrowings Outstanding

0

0

0

0

0

Weighted average interest rate (in hundredths)

0.70%

0.25%

0.30%

Eurodollar rate at period end (in hundredths)

1.05%

Base rate at period end (in hundredths)

3.25%

Line of Credit Facility, Expiration Date

11-Oct-16

Restricted Cash

150,000,000

170,000,000

Maximum borrowing capacity

$2,000,000,000

Maximum total debt-to-total capitalization ratio allowed under financial covenant (in hundredths)

65.00%

Stockholders_Equity_Details

Stockholder's Equity (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Stockholders' Equity Note [Abstract]
Common Stock, Par (in dollars per share)	0.01		0.01
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		0.0938
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)	546,378,440
Balance (in shares)	549,028,374		546,378,440
Preferred Stock, Shares Outstanding	0
Common Shares, Outstanding [Member]
Common Stock Activity [Line Items]
Balance (in shares)	546,172,000		543,264,000		538,038,000
Common Stock Issued Under Equity Compensation Plans (in shares)	2,448,000		2,206,000		4,942,000
Treasury Stock Purchased (in shares)	-1,209,000	[1]	-854,000	[1]	-1,150,000	[1]
Common Stock Issued Under Employee Stock Purchase Plan (in shares)	202,000		256,000		328,000
Treasury Stock Issued Under Other Equity Compensation Plans (in shares)	682,000		1,300,000		1,106,000
Balance (in shares)	548,295,000		546,172,000		543,264,000
Common Shares, Treasury [Member]
Common Stock Activity [Line Items]
Balance (in shares)	-206,000		-652,000		-608,000
Common Stock Issued Under Equity Compensation Plans (in shares)	0		0		0
Treasury Stock Purchased (in shares)	-1,209,000	[1]	-854,000	[1]	-1,150,000	[1]
Common Stock Issued Under Employee Stock Purchase Plan (in shares)	0		0		0
Treasury Stock Issued Under Other Equity Compensation Plans (in shares)	682,000		1,300,000		1,106,000
Balance (in shares)	-733,000		-206,000		-652,000
Common Shares, Issued [Member]
Common Stock Activity [Line Items]
Balance (in shares)	546,378,000		543,916,000		538,646,000
Common Stock Issued Under Equity Compensation Plans (in shares)	2,448,000		2,206,000		4,942,000
Treasury Stock Purchased (in shares)	0	[1]	0	[1]	0	[1]
Common Stock Issued Under Employee Stock Purchase Plan (in shares)	202,000		256,000		328,000
Treasury Stock Issued Under Other Equity Compensation Plans (in shares)	0		0		0
Balance (in shares)	549,028,000		546,378,000		543,916,000
[1]	Represents shares that were withheld by, or returned to, EOG in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or SARs, the vesting of restricted stock or restricted stock unit grants or in payment of the exercise price of employee stock options.

Accumulated_Other_Comprehensiv2

Accumulated Other Comprehensive Income Accumulated Other Comprehensive Income (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss)	($438,890,000)		($24,061,000)	$38,149,000
Accumulated Other Comprehensive Income (Loss)	-23,056,000		415,834,000
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			417,707,000
Other Comprehensive Loss, before Reclassifications, before Tax	-54,484,000
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax	-383,244,000	[1]
Tax Effects	0
Other Comprehensive Income (Loss)	-437,728,000
Accumulated Other Comprehensive Income (Loss)	-20,021,000
Foreign Currency Swap [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), before Tax			620,000
Other Comprehensive Loss, before Reclassifications, before Tax	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax	-670,000	[2]
Tax Effects	50,000
Other Comprehensive Income (Loss)	-620,000
Accumulated Other Comprehensive Income (Loss)	0
Interest Rate Swap [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), before Tax			-496,000
Other Comprehensive Loss, before Reclassifications, before Tax	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax	777,000
Tax Effects	-281,000
Other Comprehensive Income (Loss)	496,000
Accumulated Other Comprehensive Income (Loss)	0
Other [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), before Tax			-1,997,000
Other Comprehensive Loss, before Reclassifications, before Tax	-918,000
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax	139,000	[3]
Tax Effects	-259,000
Other Comprehensive Income (Loss)	-1,038,000
Accumulated Other Comprehensive Income (Loss)	-3,035,000
Accumulated Other Comprehensive Income (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), before Tax			415,834,000
Other Comprehensive Loss, before Reclassifications, before Tax	-55,402,000
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax	-382,998,000
Tax Effects	-490,000
Other Comprehensive Income (Loss)	-438,890,000		-24,061,000	38,149,000
Accumulated Other Comprehensive Income (Loss)	($23,056,000)
[1]	Reclassified to Net Income - Gain on Asset Dispositions, Net. See Note 17.
[2]	Reclassified to Net Income - Interest Expense Incurred. See Note 2.
[3]	Related to certain EOG pension plans. See Note 7.

Other_Income_Net_Details

Other Income, Net (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Other Income and Expenses [Abstract]
Equity income from investments in Trinidad	$8	$11	$20
Interest income		6	9
Net foreign currency transaction gains/(losses)	-34	12	7
Losses on sales of warehouse stock	15	23	10
Operating losses on EOG's investment in Pacific Trail Pipelines (PTP) in Canada			$9

Income_Taxes_Details

Income Taxes (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Deferred Tax Assets, Net of Valuation Allowance, Current Classification [Abstract]
Commodity Hedging Contracts	$0				$29,582,000				$0	$29,582,000
Deferred Compensation Plans	0				42,296,000				0	42,296,000
Net Operating Loss	0				96,616,000				0	96,616,000
Alternative Minimum Tax Credit Carryforward	0				72,297,000				0	72,297,000
Foreign Net Operating Loss	49,865,000				0				49,865,000	0
Foreign Valuation Allowance	-30,247,000				0				-30,247,000	0
Other	0				3,815,000				0	3,815,000
Total Net Current Deferred Income Tax Assets	19,618,000				244,606,000				19,618,000	244,606,000
Deferred tax assets net noncurrent classification [Abstract]
Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization	-141,643,000				-112,346,000				-141,643,000	-112,346,000
Foreign Net Operating Loss	487,876,000				369,257,000				487,876,000	369,257,000
Foreign Valuation Allowances	-349,704,000				-183,122,000				-349,704,000	-183,122,000
Foreign Other	4,096,000				4,179,000				4,096,000	4,179,000
Total Net Noncurrent Deferred Income Tax Assets	625,000				77,968,000				625,000	77,968,000
Deferred tax liabilities net current classification [Abstract]
Commodity Hedging Contracts	166,109,000				0				166,109,000	0
Deferred Compensation Plans	-48,207,000				0				-48,207,000	0
Accrued Expenses and Liabilities	-5,643,000				0				-5,643,000	0
Other	-1,516,000				0				-1,516,000	0
Total Net Current Deferred Income Tax Liabilities	110,743,000				0				110,743,000	0
Deferred tax liabilities net noncurrent classification [Abstract]
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization	7,634,297,000				6,287,541,000				7,634,297,000	6,287,541,000
Non-Producing Leasehold Costs	-44,236,000				-50,581,000				-44,236,000	-50,581,000
Seismic Costs Capitalized for Tax	-158,157,000				-136,964,000				-158,157,000	-136,964,000
Equity Awards	-127,541,000				-122,665,000				-127,541,000	-122,665,000
Capitalized Interest	97,739,000				101,006,000				97,739,000	101,006,000
Alternative Minimum Tax Credit Carryforward	-793,126,000				-557,352,000				-793,126,000	-557,352,000
Undistributed Foreign Earnings	249,861,000				0				249,861,000	0
Other	-35,891,000				1,369,000				-35,891,000	1,369,000
Total Net Noncurrent Deferred Income Tax Liabilities	6,822,946,000				5,522,354,000				6,822,946,000	5,522,354,000
Total Net Deferred Income Tax Liabilities	6,913,446,000				5,199,780,000				6,913,446,000	5,199,780,000
Income Before Income Taxes [Abstract]
United States									5,161,232,000	3,268,727,000	1,988,105,000
Foreign									-165,917,000	168,159,000	-707,365,000
Income (Loss) Before Income Taxes	1,148,593,000	1,715,120,000	1,100,813,000	1,030,789,000	919,082,000	721,555,000	1,035,230,000	761,019,000	4,995,315,000	3,436,886,000	1,280,740,000
Current income tax provision [Abstract]
Federal									269,326,000	207,777,000	242,674,000
State									22,835,000	22,856,000	22,573,000
Foreign									82,721,000	134,379,000	152,276,000
Total									374,882,000	365,012,000	417,523,000
Deferred income tax provision [Abstract]
Federal									1,608,706,000	915,994,000	454,173,000
State									29,056,000	26,305,000	632,000
Foreign									67,184,000	-67,534,000	-161,867,000
Total									1,704,946,000	874,765,000	292,938,000
Income Tax Provision									2,079,828,000	1,239,777,000	710,461,000
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)									0.68%	0.93%	1.18%
Income Tax Provision Related to Foreign Operations (in hundredths)									-0.12%	0.23%	1.11%
Canadian Divestiture (in hundredths)									-3.46%	0.00%	0.00%
Undistributed Foreign Earnings (in hundredths)									4.94%	0.00%	0.00%
Foreign Valuation Allowances (in hundredths)									6.47%	0.00%	10.57%
Foreign Oil and Gas Impairments (in hundredths)									-1.90%	0.00%	6.90%
Other (in hundredths)									0.03%	-0.09%	0.71%
Effective Income Tax Rate (in hundredths)									41.64%	36.07%	55.47%
Additional income tax provision related to valuation allowances recorded to reduce value of foreign deferred tax assets	463,000,000				224,000,000				463,000,000	224,000,000	200,000,000
Unrecognized tax benefits balance	0								0
Foreign subsidiaries' undistributed earnings	1,800,000,000								1,800,000,000
Regular tax net operating loss utilized									940,000,000
Balance of State net operating loss expected to be carried forward									1,600,000,000
Tax benefit reflected in additional paid-in-capital due to current year utilization of net operating losses	29,000,000								29,000,000
Alternative minimum tax paid									196,000,000
AMT Paid In Years Prior To Prior Reporting Period									597,000,000
Tax net operating loss incurred in United Kingdom in current year									246,000,000
Balance of tax net operating loss incurred in the United Kingdom in prior years									548,000,000
Unrecognized tax benefits interest or penalties	0								0
Federal and state deferred income taxes	$250,000,000								$250,000,000

Employee_Benefit_Plans_Details

Employee Benefit Plans (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Defined Benefit and Defined Contribution Plan Disclosure [Line Items]
Total pension plan costs	$41,000,000		$37,000,000		$36,000,000
Company contributions to foreign pension plans	5,000,000		4,000,000		3,000,000
Benefit obligation	14,000,000		13,000,000
Fair value of foreign pension plan assets	12,000,000		11,000,000
Accrued benefit cost	-1,000,000		-1,000,000
Stock based compensation by job function [Line Items]
Compensation expense related to the company's stock-based compensation plans	144,842,000		134,467,000		127,504,000
Federal income tax (expense) / benefit recognized from stock-based compensation	99,000,000		56,000,000		67,000,000
Maximum Percentage Of Employee Pay Eligible For Contribution To Espp Percentage	10.00%
Stock-based compensation expense related to stock options, SAR and ESPP grants	62,000,000		53,000,000		49,000,000
Percentage of fair market value at which employees may purchase company stock via the ESPP	85.00%
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	$119.27		$100.34		$67.05
Expected Volatility (in hundredths)	32.18%		33.63%		36.39%
Risk-Free Interest Rate (in hundredths)	1.18%		0.79%		0.39%
Share-Based Compensation Arrangement By Share-Based Payment Award [Abstract]
Weighted average period over which unrecognized compensation expense will be recognized	3 years 9 months 18 days
Unrecognized compensation expense	5,000,000
Number of Shares and Units [Roll Forward]
Outstanding at January 1 (in shares)	261,000	[1]	142,000	[1]	0
Granted (in shares)	72,000		119,000		142,000
Outstanding at December 31 (in shares)	333,000	[1]	261,000	[1]	142,000	[1]
Weighted Average Grant Fair Value [Abstract]
Outstanding at January 1 (in dollars per share)	$82.18	[1]	$67.05	[1]	$0
Granted (in dollars per share)	$119.27		$100.34		$67.05
Outstanding at December 31 (in dollars per share)	$90.17	[1]	$82.18	[1]	$67.05	[1]
Intrinsic value of stock based compensation	30,700,000		21,900,000
Maximum vest period from the date of grant	5 years
Performance Units and Performance Stock [Abstract]
Minimum Performance Units and Stock Allowed to be Outstanding	0
Maximum performance units and stock allowed to be outstanding	666,390
Share Based Compensation Arrangement By Performance Units and Stock Compensation Cost	9,000,000		9,000,000		7,000,000
Term of Zero-Coupon Risk-Free Interest Rate Derived from the Treasury Constant Maturities Yield Curve	3 years 3 months 4 days
Performance Period for Performance Units and Stock	3 years
ESPP [Member]
Weighted Average Fair Value And Valuation Assumptions Used To Value Stock-Based Compensation [Abstract]
Weighted Average Fair Value of Grants	$21.65		$15.06		$12.56
Expected Volatility (in hundredths)	25.03%		29.89%		40.92%
Risk-Free Interest Rate (in hundredths)	0.08%		0.11%		0.11%
Dividend Yield (in hundredths)	0.46%		0.60%		0.60%
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	794,000
Approximate Number of Participants	1,991		1,844		1,705
Shares Purchased	202,000		256,000		328,000
Aggregate Purchase Price	14,927,000		14,015,000		12,522,000
Stock Options and SARS [Member]
Stock based compensation by job function [Line Items]
Maximum term of stock options and SARs granted	10 years
Weighted Average Fair Value And Valuation Assumptions Used To Value Stock-Based Compensation [Abstract]
Weighted Average Fair Value of Grants	$30.75		$27.35		$18.98
Expected Volatility (in hundredths)	35.28%		35.86%		39.68%
Risk-Free Interest Rate (in hundredths)	0.95%		0.78%		0.45%
Dividend Yield (in hundredths)	0.61%		0.40%		0.60%
Expected Life (in years)	5 years 2 months 12 days		5 years 6 months		5 years 7 months 6 days
Stock option and SAR Rollforward [Abstract]
Outstanding at January 1 (in shares)	10,452,000		12,438,000		16,748,000
Granted (in shares)	2,146,000		2,268,000		2,480,000
Exercised (in shares)	-1,718,000	[2]	-4,046,000	[2]	-6,492,000	[2]
Forfeited (in shares)	-387,000		-208,000		-298,000
Outstanding at December 31 (in shares)	10,493,000		10,452,000		12,438,000
Share-Based Compensation Arrangement By Share-Based Payment Award [Abstract]
Outstanding at January 1 (in dollars per share)	$54.43		$42.91		$35.01
Granted (in dollars per share)	$101.55		$83.70		$55.99
Exercised (in dollars per share)	$45.68	[2]	$35.62	[2]	$27.40	[2]
Forfeited (in dollars per share)	$68.95		$50.78		$45.59
Outstanding at December 31 (in dollars per share)	$64.96		$54.43		$42.91
Stock Options/SARs Exercisable at December 31 (in shares)	5,287,000		4,638,000		6,286,000
Stock Options/SARs Exercisable at December 31 (in dollars per share)	$49.40		$43.95		$37.49
Intrinsic value of stock options/SARs exercised during the period	95,000,000	[2]	151,000,000	[2]	185,000,000	[2]
Stock options/SARs vested or expected to vest (in shares)	10,100,000
Weighted average grant price for stock options/SARs vested or expected to vest (per share)	$64.29
Intrinsic value of stock options/SARs vested or expected to vest	299,000,000
Weighted Average Remaining Contractual Life for Stock Options/SARs Vested or Expected to Vest	4 years 3 months 18 days
Common Shares Available for Grant	28,700,000
Weighted average period over which unrecognized compensation expense will be recognized	2 years 8 months 12 days
Unrecognized compensation expense	112,000,000
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	10,493,000
Weighted Average Remaining Life for Outstanding Options and SARs	4 years
Weighted Average Grant Price For Outstanding Options and SARs	$64.96
Aggregate Intrinsic Value For Outstanding Options and SARs	304,679	[3]
Stock Options and SARs Exercisable	5,287,000
Weighted Average Remaining Life For Exercisable Units	3 years
Weighted Average Grant Price For Exercisable Options and SARs	$49.40
Aggregate Intrinsic Value For Exercisable Units	225,692	[3]
Stock Options and SARS [Member] | $22.00 to $ 42.99
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	2,682,000
Weighted Average Remaining Life for Outstanding Options and SARs	3 years
Weighted Average Grant Price For Outstanding Options and SARs	$40.74
Stock Options and SARs Exercisable	2,129,000
Weighted Average Remaining Life For Exercisable Units	3 years
Weighted Average Grant Price For Exercisable Options and SARs	$40.50
Stock Options and SARS [Member] | 43.00 to 46.99
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	1,612,000
Weighted Average Remaining Life for Outstanding Options and SARs	2 years
Weighted Average Grant Price For Outstanding Options and SARs	$45.57
Stock Options and SARs Exercisable	1,598,000
Weighted Average Remaining Life For Exercisable Units	2 years
Weighted Average Grant Price For Exercisable Options and SARs	$45.58
Stock Options and SARS [Member] | 47.00 to 56.99
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	2,014,000
Weighted Average Remaining Life for Outstanding Options and SARs	4 years
Weighted Average Grant Price For Outstanding Options and SARs	$55.80
Stock Options and SARs Exercisable	995,000
Weighted Average Remaining Life For Exercisable Units	4 years
Weighted Average Grant Price For Exercisable Options and SARs	$55.57
Stock Options and SARS [Member] | 57.00 to 84.99
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	2,099,000
Weighted Average Remaining Life for Outstanding Options and SARs	5 years
Weighted Average Grant Price For Outstanding Options and SARs	$83.08
Stock Options and SARs Exercisable	548,000
Weighted Average Remaining Life For Exercisable Units	5 years
Weighted Average Grant Price For Exercisable Options and SARs	$82.44
Stock Options and SARS [Member] | 85.00 to 116.99
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	2,086,000
Weighted Average Remaining Life for Outstanding Options and SARs	7 years
Weighted Average Grant Price For Outstanding Options and SARs	$101.70
Stock Options and SARs Exercisable	17,000
Weighted Average Remaining Life For Exercisable Units	3 years
Weighted Average Grant Price For Exercisable Options and SARs	$97.77
Restricted Stock And Restricted Stock Units [Member]
Stock option and SAR Rollforward [Abstract]
Outstanding at January 1 (in shares)	7,358,000	[4]	7,636,000	[4]	8,480,000
Granted (in shares)	1,132,000		1,294,000		1,534,000
Exercised (in shares)	-2,761,000	[5]	-1,368,000	[5]	-2,118,000	[5]
Forfeited (in shares)	-335,000		-204,000		-260,000
Outstanding at December 31 (in shares)	5,394,000	[4]	7,358,000	[4]	7,636,000	[4]
Share-Based Compensation Arrangement By Share-Based Payment Award [Abstract]
Outstanding at January 1 (in dollars per share)	$49.54	[4]	$45.53		$41.47
Granted (in dollars per share)	$98.72		$76.04		$56.09
Exercised (in dollars per share)	$105.24	[5]	$52.39	[5]	$36.35	[5]
Forfeited (in dollars per share)	$62.55		$48.55		$42.68
Outstanding at December 31 (in dollars per share)	$64.39	[4]	$49.54	[4]	$45.53
Weighted average period over which unrecognized compensation expense will be recognized	2 years 6 months
Unrecognized compensation expense	178,000,000
Share Based Compensation Arrangement By Restricted Stock And Restricted Stock Units Compensation Cost	74,000,000		72,000,000		72,000,000
Weighted Average Grant Fair Value [Abstract]
Intrinsic value of stock based compensation	291,000,000		101,000,000		120,000,000
Intrinsic Value Of Restricted Stock And Restricted Stock Units Outstanding	497,000,000		617,000,000
Maximum vest period from the date of grant	5 years
Lease And Well [Member]
Stock based compensation by job function [Line Items]
Compensation expense related to the company's stock-based compensation plans	41,000,000		35,000,000		35,000,000
Gathering And Processing Costs [Member]
Stock based compensation by job function [Line Items]
Compensation expense related to the company's stock-based compensation plans	1,000,000		1,000,000		1,000,000
Exploration Costs [Member]
Stock based compensation by job function [Line Items]
Compensation expense related to the company's stock-based compensation plans	27,000,000		27,000,000		27,000,000
General And Administrative [Member]
Stock based compensation by job function [Line Items]
Compensation expense related to the company's stock-based compensation plans	$76,000,000		$71,000,000		$65,000,000
[1]	The total intrinsic value of performance units and performance stock outstanding at DecemberB 31, 2014 and 2013 was $30.7 million and $21.9 million, respectively.
[2]	The total intrinsic value of stock options/SARs exercised during the years 2014, 2013 and 2012 was $95 million, $151 million and $185 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.
[3]	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.
[4]	The total intrinsic value of restricted stock and restricted stock units outstanding at DecemberB 31, 2014 and 2013 was approximately $497 million and $617 million, respectively.
[5]	The total intrinsic value of restricted stock and restricted stock units released during the years ended DecemberB 31, 2014, 2013 and 2012 was $291 million, $101 million and $120 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.

Commitments_and_Contingencies_1

Commitments and Contingencies (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Feb. 18, 2015
Commitments and Contingencies Disclosure [Abstract]
Standby letters of credit and guarantees outstanding	$423,000,000	$711,000,000
Decrease in standby letters of credit and guarantees outstanding	71,000,000
Subsidiary indebtedness guaranteed		150,000,000
Subsidiary payment obligations guaranteed		561,000,000
Subsidiary payment obligations demand for payment				0
Total Minimum Commitments [Abstract]
2015	1,643,053,000
2016 - 2017	1,981,982,000
2018 - 2019	1,221,216,000
2020 and beyond	974,073,000
Total Minimum Commitments	5,820,324,000
Rental expenses associated with existing leases	$237,000,000	$191,000,000	$182,000,000

Net_Income_Per_Share_Details

Net Income Per Share (Details) (USD $)	3 Months Ended																12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Numerator for Basic and Diluted Earnings per Share - [Abstract]
Net Income	$444,588		$1,103,618		$706,353		$660,928		$580,194		$462,498		$659,692		$494,725		$2,915,487	$2,197,109	$570,279
Denominator for Basic Earnings per Share - [Abstract]
Weighted Average Shares (in shares)																	543,443,000	540,341,000	535,155,000
Potential Dilutive Common Shares -[Abstract]
Stock Options/SARs (in shares)																	2,526,000	2,316,000	2,911,000
Restricted Stock/Units and Performance Units/Stock (in shares)																	2,570,000	3,570,000	3,458,000
Denominator for Diluted Earnings per Share - [Abstract]
Adjusted Diluted Weighted Average Shares (in shares)	549,153,000		549,518,000		548,676,000		548,071,000		547,966,000		547,152,000		545,477,000		544,526,000		548,539,000	546,227,000	541,524,000
Net Income Per Share [Abstract]
Basic (in dollars per share)	$0.82	[1]	$2.03	[1]	$1.30	[1]	$1.22	[1]	$1.07	[1]	$0.85	[1]	$1.22	[1]	$0.92	[1]	$5.36	$4.07	$1.07
Diluted (in dollars per share)	$0.81	[1]	$2.01	[1]	$1.29	[1]	$1.21	[1]	$1.06	[1]	$0.85	[1]	$1.21	[1]	$0.91	[1]	$5.32	$4.02	$1.05
Antidilutive Stock Options and SARs excluded from Diluted Earnings Per Share Calculation (in shares)																	700,000	300,000	500,000
[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_Informa2

Supplemental Cash Flow Information (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Supplemental Cash Flow Information [Abstract]
Interest, Net of Capitalized Interest	$197,383,000	$235,854,000	$196,944,000
Income Taxes, Net of Refunds Received	342,741,000	294,739,000	360,006,000
Accrued Capital Expenditures	972,000,000	731,000,000	734,000,000
Non-cash investing and financing activities from property exchanges.	5,000,000	5,000,000	20,000,000
Non-cash capital lease obligations incurred			$66,000,000

Business_Segment_Information_D

Business Segment Information (Details) (USD $)	3 Months Ended										12 Months Ended
	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Schedule of Segment Reporting Information By Segment [Abstract]
Crude Oil and Condensate											$9,742,480,000		$8,300,647,000		$5,659,437,000
Natural Gas Liquids											934,051,000		773,970,000		727,177,000
Natural Gas											1,916,386,000		1,681,029,000		1,571,762,000
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts											834,273,000		-166,349,000		393,744,000
Gathering, Processing and Marketing											4,046,316,000		3,643,749,000		3,096,694,000
Gains on Asset Dispositions, Net											507,590,000		197,565,000		192,660,000
Other, Net											54,244,000		56,507,000		41,162,000
Net Operating Revenues	4,645,497,000		5,118,616,000	4,187,556,000	4,083,671,000	3,749,023,000		3,541,396,000	3,840,185,000	3,356,514,000	18,035,340,000		14,487,118,000		11,682,636,000
Depreciation, Depletion and Amortization											3,997,041,000		3,600,976,000		3,169,703,000
Operating Income (Loss)	1,226,652,000		1,786,162,000	1,144,730,000	1,084,279,000	980,324,000		769,769,000	1,092,044,000	833,074,000	5,241,823,000		3,675,211,000		1,479,797,000
Interest Income											2,239,000		5,585,000		8,771,000
Other Income (Expense)											-47,289,000		-8,450,000		5,724,000
Net Interest Expense											201,458,000		235,460,000		213,552,000
Income (Loss) Before Income Taxes	1,148,593,000		1,715,120,000	1,100,813,000	1,030,789,000	919,082,000		721,555,000	1,035,230,000	761,019,000	4,995,315,000		3,436,886,000		1,280,740,000
Income Tax Provision (Benefit)	704,005,000		611,502,000	394,460,000	369,861,000	338,888,000		259,057,000	375,538,000	266,294,000	2,079,828,000		1,239,777,000		710,461,000
Additions to Oil and Gas Properties, Excluding Dry Hole Costs											7,471,177,000		6,622,436,000		6,720,346,000
Total Property, Plant and Equipment, Net	29,172,644,000					26,148,836,000					29,172,644,000		26,148,836,000		23,337,681,000
Total Assets	34,762,687,000					30,574,238,000					34,762,687,000		30,574,238,000		27,336,578,000
United States [Member]
Schedule of Segment Reporting Information By Segment [Abstract]
Crude Oil and Condensate											9,526,149,000		8,035,358,000		5,383,612,000
Natural Gas Liquids											924,454,000		761,535,000		713,497,000
Natural Gas											1,321,175,000		1,100,808,000		951,463,000
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts											834,273,000		-166,349,000		393,744,000
Gathering, Processing and Marketing											4,040,024,000		3,636,209,000		3,091,281,000
Gains on Asset Dispositions, Net											96,339,000		93,876,000		166,201,000
Other, Net											49,950,000		51,713,000		40,780,000
Net Operating Revenues											16,792,364,000	[1]	13,513,150,000	[2]	10,740,578,000	[3]
Depreciation, Depletion and Amortization											3,684,943,000		3,223,596,000		2,780,563,000
Operating Income (Loss)											5,074,911,000		3,543,841,000		2,233,911,000
Interest Income											849,000		2,803,000		8,343,000
Other Income (Expense)											-14,953,000		-29,696,000		-12,455,000
Net Interest Expense											269,166,000		283,209,000		242,138,000
Income (Loss) Before Income Taxes											4,791,641,000		3,233,739,000		1,987,661,000
Income Tax Provision (Benefit)											1,837,185,000		1,161,328,000		707,401,000
Additions to Oil and Gas Properties, Excluding Dry Hole Costs											7,133,727,000		6,133,894,000		6,198,267,000
Total Property, Plant and Equipment, Net	28,391,741,000					24,456,383,000					28,391,741,000		24,456,383,000		21,560,998,000
Total Assets	32,871,398,000					27,668,713,000					32,871,398,000		27,668,713,000		24,523,072,000
Amount of sales with a single significant purchaser in the United States segment											4,000,000,000		3,900,000,000		2,200,000,000
Amount of sales with a second significant purchaser in the United States segment.											3,000,000,000		2,000,000,000
Canada [Member]
Schedule of Segment Reporting Information By Segment [Abstract]
Crude Oil and Condensate											184,420,000		221,999,000		221,556,000
Natural Gas Liquids											9,597,000		12,435,000		13,680,000
Natural Gas											96,274,000		85,446,000		86,361,000
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts											0		0		0
Gathering, Processing and Marketing											228,000		1,476,000		0
Gains on Asset Dispositions, Net											411,251,000		102,570,000		26,459,000
Other, Net											4,257,000		4,770,000		367,000
Net Operating Revenues											706,027,000	[1]	428,696,000	[2]	348,423,000	[3]
Depreciation, Depletion and Amortization											105,274,000		180,836,000		223,689,000
Operating Income (Loss)											360,114,000		-45,214,000		-1,065,434,000
Interest Income											847,000		2,076,000		123,000
Other Income (Expense)											-19,719,000		7,707,000		-8,689,000
Net Interest Expense											-20,681,000		-4,204,000		6,589,000
Income (Loss) Before Income Taxes											361,923,000		-31,227,000		-1,080,589,000
Income Tax Provision (Benefit)											80,807,000		598,000		-134,745,000
Additions to Oil and Gas Properties, Excluding Dry Hole Costs											76,642,000		137,920,000		302,851,000
Total Property, Plant and Equipment, Net	33,635,000					602,333,000					33,635,000		602,333,000		877,996,000
Total Assets	182,250,000					880,765,000					182,250,000		880,765,000		1,202,031,000
Trinidad [Member]
Schedule of Segment Reporting Information By Segment [Abstract]
Crude Oil and Condensate											29,604,000		40,379,000		50,708,000
Natural Gas Liquids											0		0		0
Natural Gas											483,071,000		477,103,000		514,322,000
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts											0		0		0
Gathering, Processing and Marketing											6,064,000		6,064,000		5,413,000
Gains on Asset Dispositions, Net											0		1,119,000		0
Other, Net											37,000		24,000		15,000
Net Operating Revenues											518,776,000	[1]	524,689,000	[2]	570,458,000	[3]
Depreciation, Depletion and Amortization											188,592,000		181,990,000		147,062,000
Operating Income (Loss)											277,471,000		266,329,000		371,876,000
Interest Income											253,000		336,000		125,000
Other Income (Expense)											8,712,000		9,889,000		20,482,000
Net Interest Expense											0		0		238,000
Income (Loss) Before Income Taxes											286,436,000		276,554,000		392,245,000
Income Tax Provision (Benefit)											98,559,000		118,270,000		140,468,000
Additions to Oil and Gas Properties, Excluding Dry Hole Costs											76,138,000		132,984,000		49,376,000
Total Property, Plant and Equipment, Net	382,719,000					476,174,000					382,719,000		476,174,000		535,405,000
Total Assets	865,674,000					986,796,000					865,674,000		986,796,000		1,012,727,000
Other International [Member]
Schedule of Segment Reporting Information By Segment [Abstract]
Crude Oil and Condensate											2,307,000	[4]	2,911,000	[4]	3,561,000	[4]
Natural Gas Liquids											0	[4]	0	[4]	0	[4]
Natural Gas											15,866,000	[4]	17,672,000	[4]	19,616,000	[4]
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts											0	[4]	0	[4]	0	[4]
Gathering, Processing and Marketing											0	[4]	0	[4]	0	[4]
Gains on Asset Dispositions, Net											0	[4]	0	[4]	0	[4]
Other, Net											0	[4]	0	[4]	0	[4]
Net Operating Revenues											18,173,000	[1],[4]	20,583,000	[2],[4]	23,177,000	[3],[4]
Depreciation, Depletion and Amortization											18,232,000	[4]	14,554,000	[4]	18,389,000	[4]
Operating Income (Loss)											-470,673,000	[4]	-89,745,000	[4]	-60,556,000	[4]
Interest Income											290,000	[4]	370,000	[4]	180,000	[4]
Other Income (Expense)											-21,329,000	[4]	3,650,000	[4]	6,386,000	[4]
Net Interest Expense											-47,027,000	[4]	-43,545,000	[4]	-35,413,000	[4]
Income (Loss) Before Income Taxes											-444,685,000	[4]	-42,180,000	[4]	-18,577,000	[4]
Income Tax Provision (Benefit)											63,277,000	[4]	-40,419,000	[4]	-2,663,000	[4]
Additions to Oil and Gas Properties, Excluding Dry Hole Costs											184,670,000	[4]	217,638,000	[4]	169,852,000	[4]
Total Property, Plant and Equipment, Net	364,549,000	[4]				613,946,000	[4]				364,549,000	[4]	613,946,000	[4]	363,282,000	[4]
Total Assets	$843,365,000	[4]				$1,037,964,000	[4]				$843,365,000	[4]	$1,037,964,000	[4]	$598,748,000	[4]
[1]	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.
[2]	EOG had sales activity with two significant purchasers in 2013, one totaling $3.9 billion and the other totaling $2.0 billion of consolidated Net Operating Revenues in the United States segment.
[3]	EOG had sales activity with a single significant purchaser in 2012 that totaled $2.2 billion of consolidated Net Operating Revenues in the United States segment.
[4]	Other International primarily consists of EOG's United Kingdom, China and Argentina operations.

Risk_Management_Activities_Det

Risk Management Activities (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Net (Gains) Losses on Mark-to-Market Commodity Derivative Contracts	($834,273,000)		$166,349,000		($393,744,000)
Net Cash Received from Settlements of Crude Oil and Natural Gas Derivative Contracts	34,007,000		116,361,000		711,479,000
Derivatives, Fair Value [Line Items]
Receivable Major Customer Percentage	10.00%		10.00%
Derivatives Assets, Current	465,128,000		8,260,000
Derivative Liabilities, Current	0		127,542,000
Derivative Collateral [Abstract]
Collateral Held on Derivative	278,000,000		0
Collateral Had on Derivaitve	0		0
Crude Oil and Natural Gas Derivative Contracts [Member] | Assets From Price Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives Assets, Current	465,000,000	[1]	8,000,000	[1]
Derivative asset, gross assets	477,000,000		18,000,000
Derivative asset, gross liabilities	12,000,000		10,000,000
Crude Oil and Natural Gas Derivative Contracts [Member] | Liabilities From Price Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities, Current	0	[2]	127,000,000	[2]
Derivative liabilities, gross liabilities	12,000,000		137,000,000
Derivative liabilities, gross assets	12,000,000		10,000,000
Interest Rate Swap [Member] | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities, Current	0		1,000,000
Foreign Currency Swap [Member] | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities, Current	$0		$40,000,000
January 1, 2015 through June 30, 2015
Derivative [Line Items]
Volume (Bbld)	47,000	[3]
Derivative Weighted Average Price Crude Oil ($/Bbl)	91.22	[3]
July 1, 2015 through December 31, 2015
Derivative [Line Items]
Volume (Bbld)	10,000
Volumes (Bbld) - Derivative Option Contracts	37,000
Derivative Weighted Average Price Crude Oil ($/Bbl)	89.98
Derivative Weighted Average Price Crude Oil (Options Exercised) ($/Bbl)	91.56
Apr-15
Derivative [Line Items]
Volume (MMBtud)	195,000	[4]
Derivative Weighted Average Price Natural Gas ($/MMBtu)	4.49	[4]
Mar-15
Derivative [Line Items]
Volume (MMBtud)	225,000	[4]
Derivative Weighted Average Price Natural Gas ($/MMBtu)	4.48	[4]
January 2015 (closed)
Derivative [Line Items]
Volume (MMBtud)	235,000
Derivative Weighted Average Price Natural Gas ($/MMBtu)	4.47
Feb-15
Derivative [Line Items]
Volume (MMBtud)	235,000	[4]
Derivative Weighted Average Price Natural Gas ($/MMBtu)	4.47	[4]
May 1, 2015 through December 31, 2015
Derivative [Line Items]
Volume (MMBtud)	175,000	[4]
Derivative Weighted Average Price Natural Gas ($/MMBtu)	4.51	[4]
February 1, 2015 through December 31, 2015 [Member]
Derivative [Line Items]
Volumes (MMBtud) - Derivative Option Contracts	175,000	[4]
Average Price ($/MMBtu) - Derivative Option Contracts	4.51	[4]
[1]	The current portion of Assets from Price Risk Management Activities consists of gross assets of $477 million, partially offset by gross liabilities of $12 million, at DecemberB 31, 2014 and gross assets of $18 million, partially offset by gross liabilities of $10 million, at DecemberB 31, 2013.
[2]	The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $12 million, offset by gross assets of $12 million, at DecemberB 31, 2014 and gross liabilities of $137 million, partially offset by gross assets of $10 million, at DecemberB 31, 2013.
[3]	EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional six-month periods. Options covering a notional volume of 37,000 Bbld are exercisable on June 30, 2015. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 37,000 Bbld at an average price of $91.56 per barrel for each month during the period July 1, 2015 through December 31, 2015.
[4]	EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates. All such options are exercisable monthly up until the settlement date of each monthly contract. If the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 175,000 MMBtud at an average price of $4.51 per MMBtu for each month during the period February 1, 2015 through December 31, 2015.

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Financial Assets:
Financial Assets: Crude Oil Swaps	$121,000,000
Financial Assets: Crude Oil Options/Swaptions	244,000,000
Financial Assets: Natural Gas Options/Swaptions	100,000,000	8,000,000
Financial Liabilities:
Financial Liabilities: Crude Oil Swaps		17,000,000
Financial Liabilities: Crude Oil Options/Swaptions		110,000,000
Financial Liabilities: Foreign Currency Rate Swap		40,000,000
Financial Liabilities: Interest Rate Swap		1,000,000
Proved and unproved oil and gas properties and other assets, carrying amount	968,000,000	400,000,000
Proved and unproved oil and gas properties and other assets written down during the period - fair value at end of period	393,000,000	228,000,000
Pretax impairment charges for proved oil and gas properties and other assets	575,000,000	172,000,000
Pretax impairment charges for proved oil and gas properties and other assets, in which EOG utilized an accepted offer from a third-party purchasers	58,000,000	58,000,000
Aggregate Principal Amount of Current and Long-Term Debt	5,890,000,000	5,890,000,000
Fair Value of Debt	6,242,000,000	6,222,000,000
Fair Value, Inputs, Level 1 [Member]
Financial Assets:
Financial Assets: Natural Gas Options/Swaptions	0	0
Financial Liabilities:
Financial Liabilities: Crude Oil Swaps	0	0
Financial Liabilities: Crude Oil Options/Swaptions	0	0
Financial Liabilities: Foreign Currency Rate Swap		0
Financial Liabilities: Interest Rate Swap		0
Fair Value, Inputs, Level 2 [Member]
Financial Assets:
Financial Assets: Crude Oil Swaps	121,000,000
Financial Assets: Crude Oil Options/Swaptions	244,000,000
Financial Assets: Natural Gas Options/Swaptions	100,000,000	8,000,000
Financial Liabilities:
Financial Liabilities: Crude Oil Swaps		17,000,000
Financial Liabilities: Crude Oil Options/Swaptions		110,000,000
Financial Liabilities: Foreign Currency Rate Swap		40,000,000
Financial Liabilities: Interest Rate Swap		1,000,000
Fair Value, Inputs, Level 3 [Member]
Financial Assets:
Financial Assets: Natural Gas Options/Swaptions	0	0
Financial Liabilities:
Financial Liabilities: Crude Oil Swaps	0	0
Financial Liabilities: Crude Oil Options/Swaptions	0	0
Financial Liabilities: Foreign Currency Rate Swap		0
Financial Liabilities: Interest Rate Swap		$0

Accounting_For_Certain_LongLiv1

Accounting For Certain Long-Lived Assets (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Schedule of Impaired Long-Lived Assets Held and Used [Line Items]
Amortization and impairments of unproved oil and gas property costs including amortization of capitalized interest	$168	$115	$228
United States [Member]
Schedule of Impaired Long-Lived Assets Held and Used [Line Items]
Pretax impairment charges on proved oil and gas properties, other property, plant and equipment and other assets	171	73	171
Canada [Member]
Schedule of Impaired Long-Lived Assets Held and Used [Line Items]
Pretax impairment charges on proved oil and gas properties, other property, plant and equipment and other assets	8	76	872
Trinidad [Member]
Schedule of Impaired Long-Lived Assets Held and Used [Line Items]
Pretax impairment charges on proved oil and gas properties, other property, plant and equipment and other assets		14
Other International [Member]
Schedule of Impaired Long-Lived Assets Held and Used [Line Items]
Pretax impairment charges on proved oil and gas properties, other property, plant and equipment and other assets	$396	$9

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Asset Retirement Obligations, Noncurrent [Abstract]
Carrying Amount at Beginning of Period	$761,898		$665,944
Liabilities Incurred	123,849		103,284
Liabilities Settled	-247,422	[1]	-70,510	[1]
Accretion	41,489		35,180
Revisions	82,885		38,552
Foreign Currency Translations	-9,981		-10,552
Carrying Amount at End of Period	752,718		761,898
Current Portion	11,814		43,857
Noncurrent Portion	$740,904		$718,041
[1]	(1)Includes capitalized exploratory well costs charged to either dry hole costs or impairments.

Exploratory_Well_Costs_Details

Exploratory Well Costs (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Capitalized Exploratory Well Costs [Abstract]
Balance at January 1	$9,211,000		$49,116,000	[1]	$61,111,000
Additions Pending the Determination of Proved Reserves	32,080,000		52,099,000		73,332,000
Reclassifications to Proved Properties	-15,946,000		-54,505,000		-69,462,000
Costs Charged to Expense (1)	-8,092,000	[2]	-35,859,000	[2]	-17,115,000	[2]
Foreign Currency Translations	0		-1,640,000		1,250,000
Balance at December 31	17,253,000		9,211,000		49,116,000	[1]
Exploratory well costs related to an outside operated, offshore Central North Sea project in the United Kingdom					$21,000,000
[1]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjI5ZmZlZTBlYzU1OTQ1ZWU4NGU2MjcxZTg5NmM2NzFifFRleHRTZWxlY3Rpb246RUVDMkRDOTE5REM5MDc0REVCQzZBNjNEQjU1QTFCMjIM}
[2]	(1)Includes capitalized exploratory well costs charged to either dry hole costs or impairments.

Divestitures_Details

Divestitures (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Business Combinations [Abstract]
Proceeds from Sales of Producing Properties, Acreage and Other Assets	$569	$761	$1,300
Cumulative translation adjustments	383
Restricted cash related to future abandonment liabilities	$150

Oil_and_Gas_Exploration_and_Pr2

Oil and Gas Exploration and Production Industries Disclosures (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
	MBoe		MBoe		MBoe		MBoe
Proved Developed And Undeveloped Reserves (MBoe) [Rollforward]
Net proved reserves - beginning of period (MBoe)	2,118,543		1,810,698		2,053,763
Revisions of previous estimates	100,568		108,990		-392,621
Purchases in place	14,367		3,241		4,098
Extensions, discoveries and other additions	519,167		398,965		406,932
Sales in place	-36,263		-15,375		-90,420
Production	-219,126		-187,976		-171,054
Net proved reserves - end of period (MBoe)	2,497,256		2,118,543		1,810,698
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves (MBOE)	1,347,947		1,127,476		949,819		1,042,713
Net proved undeveloped reserve (MBOE)	1,149,309		991,067		860,879		1,011,050
Revisions of previous estimates	100,568		108,990		-392,621
Capitalized Costs, Oil and Gas Producing Activities, Gross [Abstract]
Proved properties	$45,169,101		$41,377,303
Unproved properties	1,334,431		1,444,500
Total	46,503,532		42,821,803
Accumulated depreciation, depletion and amortization	-20,212,748		-18,880,611
Net capitalized costs	$26,290,784		$23,941,192
Crude Oil (MBbl) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	900,540		700,818		517,493
Revisions of previous estimates	28,022		50,669		1,688
Purchases in place	9,705		1,097		1,010
Extensions, discoveries and other additions	319,554		230,754		255,686
Sales in place	-12,623		-2,337		-17,264
Production	-105,448		-80,461		-57,795
Net proved reserves - end of period	1,139,750		900,540		700,818
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	495,148		391,056		290,650		224,755
Net proved undeveloped reserves	644,602		509,484		410,168		292,738
Natural Gas Liquids (MBbl) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	377,206		319,963		227,788
Revisions of previous estimates	27,443		12,109		47,856
Purchases in place	1,812		1,202		612
Extensions, discoveries and other additions	91,683		69,197		71,574
Sales in place	-1,779		-1,471		-7,377
Production	-29,297		-23,794		-20,490
Net proved reserves - end of period	467,068		377,206		319,963
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	264,749		200,860		162,593		125,363
Net proved undeveloped reserves	202,319		176,346		157,370		102,425
Natural Gas (MMcf) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	5,044,800		4,739,500		7,850,900
Revisions of previous estimates	270,600		277,300		-2,653,000
Purchases in place	17,100		5,700		14,800
Extensions, discoveries and other additions	647,500		594,100		478,100
Sales in place	-131,100		-69,400		-394,700
Production	-506,300		-502,400		-556,600
Net proved reserves - end of period	5,342,600		5,044,800		4,739,500
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	3,528,300		3,213,400		2,979,500		4,155,600
Net proved undeveloped reserves	1,814,300		1,831,400		1,760,000		3,695,300
United States [Member]
Proved Developed And Undeveloped Reserves (MBoe) [Rollforward]
Net proved reserves - beginning of period (MBoe)	1,989,166	[1]	1,662,108	[1]	1,729,508	[1]
Revisions of previous estimates	97,782	[1]	113,823	[1]	-237,936	[1]
Purchases in place	14,367	[1]	3,241	[1]	4,098	[1]
Extensions, discoveries and other additions	517,613	[1]	383,324	[1]	392,196	[1]
Sales in place	-14,661	[1]	-15,375	[1]	-87,588	[1]
Production	-190,065	[1]	-157,955	[1]	-138,170	[1]
Net proved reserves - end of period (MBoe)	2,414,202	[1]	1,989,166	[1]	1,662,108	[1]
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves (MBOE)	1,275,447		1,015,359		840,564		877,301
Net proved undeveloped reserve (MBOE)	1,138,755		973,807		821,544		852,207
Revisions of previous estimates	97,782	[1]	113,823	[1]	-237,936	[1]
United States [Member] | Crude Oil (MBbl) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	880,049	[1]	671,029	[1]	495,296	[1]
Revisions of previous estimates	28,301	[1]	57,668	[1]	4,105	[1]
Purchases in place	9,705	[1]	1,097	[1]	1,010	[1]
Extensions, discoveries and other additions	319,540	[1]	230,023	[1]	241,171	[1]
Sales in place	-4,967	[1]	-2,337	[1]	-15,921	[1]
Production	-102,946	[1]	-77,431	[1]	-54,632	[1]
Net proved reserves - end of period	1,129,682	[1]	880,049	[1]	671,029	[1]
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	493,694		382,517		281,167		213,872
Net proved undeveloped reserves	635,988		497,532		389,862		281,424
United States [Member] | Natural Gas Liquids (MBbl) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	376,002	[1]	318,406	[1]	226,586	[1]
Revisions of previous estimates	27,450	[1]	12,157	[1]	47,293	[1]
Purchases in place	1,812	[1]	1,202	[1]	612	[1]
Extensions, discoveries and other additions	91,683	[1]	69,187	[1]	71,396	[1]
Sales in place	-956	[1]	-1,471	[1]	-7,300	[1]
Production	-29,061	[1]	-23,479	[1]	-20,181	[1]
Net proved reserves - end of period	466,930	[1]	376,002	[1]	318,406	[1]
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	264,611		199,964		161,482		124,271
Net proved undeveloped reserves	202,319		176,038		156,924		102,315
United States [Member] | Natural Gas (MMcf) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	4,398,700	[2]	4,036,000	[2]	6,045,800	[2]
Revisions of previous estimates	252,200	[2]	264,000	[2]	-1,736,000	[2]
Purchases in place	17,100	[2]	5,700	[2]	14,800	[2]
Extensions, discoveries and other additions	638,300	[2]	504,700	[2]	477,800	[2]
Sales in place	-52,400	[2]	-69,400	[2]	-386,200	[2]
Production	-348,400	[2]	-342,300	[2]	-380,200	[2]
Net proved reserves - end of period	4,905,500	[2]	4,398,700	[2]	4,036,000	[2]
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	3,102,800		2,597,300		2,387,500		3,235,000
Net proved undeveloped reserves	1,802,700		1,801,400		1,648,500		2,810,800
Canada [Member]
Proved Developed And Undeveloped Reserves (MBoe) [Rollforward]
Net proved reserves - beginning of period (MBoe)	28,339	[1]	35,804	[1]	192,448	[1]
Revisions of previous estimates	1,316	[1]	-676	[1]	-151,015	[1]
Purchases in place	0	[1]	0	[1]	0	[1]
Extensions, discoveries and other additions	0	[1]	693	[1]	5,860	[1]
Sales in place	-21,602	[1]	0	[1]	-2,832	[1]
Production	-6,080	[1]	-7,482	[1]	-8,657	[1]
Net proved reserves - end of period (MBoe)	1,973	[1]	28,339	[1]	35,804	[1]
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves (MBOE)	1,973		24,782		24,348		58,524
Net proved undeveloped reserve (MBOE)	0		3,557		11,456		133,924
Revisions of previous estimates	1,316	[1]	-676	[1]	-151,015	[1]
Canada [Member] | Crude Oil (MBbl) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	10,120	[1]	17,863	[1]	18,592	[1]
Revisions of previous estimates	-313	[1]	-5,866	[1]	-2,493	[1]
Purchases in place	0	[1]	0	[1]	0	[1]
Extensions, discoveries and other additions	0	[1]	673	[1]	5,681	[1]
Sales in place	-7,656	[1]	0	[1]	-1,343	[1]
Production	-2,126	[1]	-2,550	[1]	-2,574	[1]
Net proved reserves - end of period	25	[1]	10,120	[1]	17,863	[1]
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	25		6,871		6,853		8,128
Net proved undeveloped reserves	0		3,249		11,010		10,464
Canada [Member] | Natural Gas Liquids (MBbl) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	1,204	[1]	1,557	[1]	1,202	[1]
Revisions of previous estimates	-7	[1]	-48	[1]	563	[1]
Purchases in place	0	[1]	0	[1]	0	[1]
Extensions, discoveries and other additions	0	[1]	10	[1]	178	[1]
Sales in place	-823	[1]	0	[1]	-77	[1]
Production	-236	[1]	-315	[1]	-309	[1]
Net proved reserves - end of period	138	[1]	1,204	[1]	1,557	[1]
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	138		896		1,111		1,092
Net proved undeveloped reserves	0		308		446		110
Canada [Member] | Natural Gas (MMcf) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	102,100	[2]	98,300	[2]	1,035,900	[2]
Revisions of previous estimates	9,800	[2]	31,400	[2]	-894,500	[2]
Purchases in place	0	[2]	0	[2]	0	[2]
Extensions, discoveries and other additions	0	[2]	100	[2]	0	[2]
Sales in place	-78,700	[2]	0	[2]	-8,500	[2]
Production	-22,300	[2]	-27,700	[2]	-34,600	[2]
Net proved reserves - end of period	10,900	[2]	102,100	[2]	98,300	[2]
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	10,900		102,100		98,300		295,800
Net proved undeveloped reserves	0		0		0		740,100
Trinidad [Member]
Proved Developed And Undeveloped Reserves (MBoe) [Rollforward]
Net proved reserves - beginning of period (MBoe)	88,364	[1]	101,060	[1]	128,629	[1]
Revisions of previous estimates	2,245	[1]	-3,892	[1]	-3,953	[1]
Purchases in place	0	[1]	0	[1]	0	[1]
Extensions, discoveries and other additions	758	[1]	13,245	[1]	0	[1]
Sales in place	0	[1]	0	[1]	0	[1]
Production	-22,430	[1]	-22,049	[1]	-23,616	[1]
Net proved reserves - end of period (MBoe)	68,937	[1]	88,364	[1]	101,060	[1]
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves (MBOE)	67,484		83,933		81,826		103,710
Net proved undeveloped reserve (MBOE)	1,453		4,431		19,234		24,919
Revisions of previous estimates	2,245	[1]	-3,892	[1]	-3,953	[1]
Trinidad [Member] | Crude Oil (MBbl) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	1,590	[1]	3,028	[1]	3,507	[1]
Revisions of previous estimates	99	[1]	-991	[1]	71	[1]
Purchases in place	0	[1]	0	[1]	0	[1]
Extensions, discoveries and other additions	0	[1]	0	[1]	0	[1]
Sales in place	0	[1]	0	[1]	0	[1]
Production	-350	[1]	-447	[1]	-550	[1]
Net proved reserves - end of period	1,339	[1]	1,590	[1]	3,028	[1]
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	1,339		1,505		2,377		2,657
Net proved undeveloped reserves	0		85		651		850
Trinidad [Member] | Natural Gas Liquids (MBbl) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	0	[1]	0	[1]	0	[1]
Revisions of previous estimates	0	[1]	0	[1]	0	[1]
Purchases in place	0	[1]	0	[1]	0	[1]
Extensions, discoveries and other additions	0	[1]	0	[1]	0	[1]
Sales in place	0	[1]	0	[1]	0	[1]
Production	0	[1]	0	[1]	0	[1]
Net proved reserves - end of period	0	[1]	0	[1]	0	[1]
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	0		0		0		0
Net proved undeveloped reserves	0		0		0		0
Trinidad [Member] | Natural Gas (MMcf) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	520,700	[2]	588,200	[2]	750,700	[2]
Revisions of previous estimates	12,900	[2]	-17,400	[2]	-24,100	[2]
Purchases in place	0	[2]	0	[2]	0	[2]
Extensions, discoveries and other additions	4,500	[2]	79,500	[2]	0	[2]
Sales in place	0	[2]	0	[2]	0	[2]
Production	-132,500	[2]	-129,600	[2]	-138,400	[2]
Net proved reserves - end of period	405,600	[2]	520,700	[2]	588,200	[2]
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	396,900		494,600		476,700		606,300
Net proved undeveloped reserves	8,700		26,100		111,500		144,400
Other International [Member]
Proved Developed And Undeveloped Reserves (MBoe) [Rollforward]
Net proved reserves - beginning of period (MBoe)	12,674	[1],[3]	11,726	[1],[3]	3,178	[1],[3]
Revisions of previous estimates	-775	[1],[3]	-265	[1],[3]	283	[1],[3]
Purchases in place	0	[1],[3]	0	[1],[3]	0	[1],[3]
Extensions, discoveries and other additions	796	[1],[3]	1,703	[1],[3]	8,876	[1],[3]
Sales in place	0	[1],[3]	0	[1],[3]	0	[1],[3]
Production	-551	[1],[3]	-490	[1],[3]	-611	[1],[3]
Net proved reserves - end of period (MBoe)	12,144	[1],[3]	12,674	[1],[3]	11,726	[1],[3]
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves (MBOE)	3,043	[3]	3,402	[3]	3,081	[3]	3,178	[3]
Net proved undeveloped reserve (MBOE)	9,101	[3]	9,272	[3]	8,645	[3]	0	[3]
Revisions of previous estimates	-775	[1],[3]	-265	[1],[3]	283	[1],[3]
Other International [Member] | Crude Oil (MBbl) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	8,781	[1],[3]	8,898	[1],[3]	98	[1],[3]
Revisions of previous estimates	-65	[1],[3]	-142	[1],[3]	5	[1],[3]
Purchases in place	0	[1],[3]	0	[1],[3]	0	[1],[3]
Extensions, discoveries and other additions	14	[1],[3]	58	[1],[3]	8,834	[1],[3]
Sales in place	0	[1],[3]	0	[1],[3]	0	[1],[3]
Production	-26	[1],[3]	-33	[1],[3]	-39	[1],[3]
Net proved reserves - end of period	8,704	[1],[3]	8,781	[1],[3]	8,898	[1],[3]
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	90	[3]	163	[3]	253	[3]	98	[3]
Net proved undeveloped reserves	8,614	[3]	8,618	[3]	8,645	[3]	0	[3]
Other International [Member] | Natural Gas Liquids (MBbl) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	0	[1],[3]	0	[1],[3]	0	[1],[3]
Revisions of previous estimates	0	[1],[3]	0	[1],[3]	0	[1],[3]
Purchases in place	0	[1],[3]	0	[1],[3]	0	[1],[3]
Extensions, discoveries and other additions	0	[1],[3]	0	[1],[3]	0	[1],[3]
Sales in place	0	[1],[3]	0	[1],[3]	0	[1],[3]
Production	0	[1],[3]	0	[1],[3]	0	[1],[3]
Net proved reserves - end of period	0	[1],[3]	0	[1],[3]	0	[1],[3]
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	0	[3]	0	[3]	0	[3]	0	[3]
Net proved undeveloped reserves	0	[3]	0	[3]	0	[3]	0	[3]
Other International [Member] | Natural Gas (MMcf) [Member]
Proved Developed and Undeveloped Reserves [Rollforward]
Net proved reserves - beginning of period	23,300	[2],[3]	17,000	[2],[3]	18,500	[2],[3]
Revisions of previous estimates	-4,300	[2],[3]	-700	[2],[3]	1,600	[2],[3]
Purchases in place	0	[2],[3]	0	[2],[3]	0	[2],[3]
Extensions, discoveries and other additions	4,700	[2],[3]	9,800	[2],[3]	300	[2],[3]
Sales in place	0	[2],[3]	0	[2],[3]	0	[2],[3]
Production	-3,100	[2],[3]	-2,800	[2],[3]	-3,400	[2],[3]
Net proved reserves - end of period	20,600	[2],[3]	23,300	[2],[3]	17,000	[2],[3]
Net Proved Developed and Undeveloped Reserves [Abstract]
Net proved developed reserves	17,700	[3]	19,400	[3]	17,000	[3]	18,500	[3]
Net proved undeveloped reserves	2,900	[3]	3,900	[3]	0	[3]	0	[3]
[1]	Thousand barrels or thousand barrels of oil equivalent, as applicable; oil equivalents include crude oil and condensate, NGL and natural gas. Oil equivalents are determined using the ratio of 1.0 barrel of crude oil and condensate or NGL to 6.0 thousand cubic feet of natural gas.
[2]	Billion cubic feet.
[3]	Other International includes EOG's United Kingdom, China and Argentina operations.

Oil_and_Gas_Exploration_and_Pr3

Oil and Gas Exploration and Production Industries Disclosures, Costs Incurred (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Unproved	$370,414,000		$414,121,000		$505,303,000
Acquisition Costs of Properties - Proved	139,101,000		120,214,000		739,000
Subtotal	509,515,000		534,335,000		506,042,000
Exploration Costs	395,973,000		377,179,000		445,598,000
Development Costs	6,999,281,000		6,086,377,000		6,116,550,000
Total	7,904,769,000		6,997,891,000		7,068,190,000
United States [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Unproved	365,915,000		411,556,000		471,345,000
Acquisition Costs of Properties - Proved	138,772,000		120,220,000		739,000
Subtotal	504,687,000		531,776,000		472,084,000
Exploration Costs	332,703,000		273,788,000		333,534,000
Development Costs	6,638,192,000	[1]	5,573,260,000	[2]	5,657,378,000	[3]
Total	7,475,582,000		6,378,824,000		6,462,996,000
Asset Retirement Costs Included In Development	149,000,000		84,000,000		80,000,000
Canada [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Unproved	4,499,000		2,565,000		33,561,000
Acquisition Costs of Properties - Proved	349,000		-6,000		0
Subtotal	4,848,000		2,559,000		33,561,000
Exploration Costs	13,010,000		19,660,000		38,530,000
Development Costs	101,634,000	[1]	149,426,000	[2]	278,995,000	[3]
Total	119,492,000		171,645,000		351,086,000
Asset Retirement Costs Included In Development	31,000,000		13,000,000		33,000,000
Trinidad [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Unproved	0		0		1,000,000
Acquisition Costs of Properties - Proved	0		0		0
Subtotal	0		0		1,000,000
Exploration Costs	2,794,000		16,060,000		19,555,000
Development Costs	89,555,000	[1]	124,231,000	[2]	32,609,000	[3]
Total	92,349,000		140,291,000		53,164,000
Asset Retirement Costs Included In Development	14,000,000				2,000,000
Other International [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Acquisition Costs of Properties - Unproved	0	[4]	0	[4]	-603,000	[4]
Acquisition Costs of Properties - Proved	-20,000	[4]	0	[4]	0	[4]
Subtotal	-20,000	[4]	0	[4]	-603,000	[4]
Exploration Costs	47,466,000	[4]	67,671,000	[4]	53,979,000	[4]
Development Costs	169,900,000	[1],[4]	239,460,000	[2],[4]	147,568,000	[3],[4]
Total	217,346,000	[4]	307,131,000	[4]	200,944,000	[4]
Asset Retirement Costs Included In Development	$2,000,000		$37,000,000		$12,000,000
[1]	Includes Asset Retirement Costs of $149 million, $31 million, $14 million and $2 million for the United States, Canada, Trinidad and Other International, respectively. Excludes other property, plant and equipment.
[2]	Includes Asset Retirement Costs of $84 million, $13 million and $37 million for the United States, Canada and Other International, respectively. Excludes other property, plant and equipment.
[3]	Includes Asset Retirement Costs of $80 million, $33 million, $2 million and $12 million for the United States, Canada, Trinidad and Other International, respectively. Excludes other property, plant and equipment.
[4]	Other International primarily consists of EOG's United Kingdom, China and Argentina operations.

Oil_and_Gas_Exploration_and_Pr4

Oil and Gas Exploration and Production Industries Disclosures, Results Of Operations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
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	$12,592,917		$10,755,646		$7,958,376
Other	54,244		56,507		41,162
Total	12,647,161		10,812,153		7,999,538
Exploration Costs	184,388		161,346		185,569
Dry Hole Costs	48,490		74,655		14,970
Transportation Costs	972,176		853,044		601,431
Production Costs	2,150,027		1,706,222		1,468,628
Impairments	743,575		286,941		1,270,735
Depreciation, Depletion and Amortization	3,881,720		3,498,010		3,024,514
Income (Loss) Before Income Taxes	4,666,785		4,231,935		1,433,691
Income Tax Provision (Benefit)	1,821,104		1,490,532		722,906
Results of Operations	2,845,681		2,741,403		710,785
United States [Member]
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	11,771,777	[1]	9,897,701	[1]	7,048,572	[1]
Other	49,950	[1]	51,713	[1]	40,780	[1]
Total	11,821,727	[1]	9,949,414	[1]	7,089,352	[1]
Exploration Costs	162,434	[1]	141,286	[1]	162,152	[1]
Dry Hole Costs	25,408	[1]	14,276	[1]	1,772	[1]
Transportation Costs	957,522	[1]	841,567	[1]	591,547	[1]
Production Costs	1,940,074	[1]	1,494,791	[1]	1,264,633	[1]
Impairments	331,792	[1]	178,718	[1]	294,172	[1]
Depreciation, Depletion and Amortization	3,571,313	[1]	3,122,858	[1]	2,637,500	[1]
Income (Loss) Before Income Taxes	4,833,184	[1]	4,155,918	[1]	2,137,576	[1]
Income Tax Provision (Benefit)	1,722,914	[1]	1,486,445	[1]	761,459	[1]
Results of Operations	3,110,270	[1]	2,669,473	[1]	1,376,117	[1]
Canada [Member]
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	290,291	[1]	319,880	[1]	321,597	[1]
Other	4,257	[1]	4,770	[1]	367	[1]
Total	294,548	[1]	324,650	[1]	321,964	[1]
Exploration Costs	11,877	[1]	11,203	[1]	13,350	[1]
Dry Hole Costs	0	[1]	9,579	[1]	1,570	[1]
Transportation Costs	12,618	[1]	9,694	[1]	7,511	[1]
Production Costs	158,882	[1]	154,947	[1]	154,509	[1]
Impairments	15,879	[1]	84,934	[1]	976,563	[1]
Depreciation, Depletion and Amortization	104,462	[1]	179,520	[1]	222,366	[1]
Income (Loss) Before Income Taxes	-9,170	[1]	-125,227	[1]	-1,053,905	[1]
Income Tax Provision (Benefit)	-2,360	[1]	-32,295	[1]	-136,105	[1]
Results of Operations	-6,810	[1]	-92,932	[1]	-917,800	[1]
Trinidad [Member]
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	512,675	[1]	517,482	[1]	565,030	[1]
Other	37	[1]	24	[1]	15	[1]
Total	512,712	[1]	517,506	[1]	565,045	[1]
Exploration Costs	2,185	[1]	2,345	[1]	2,262	[1]
Dry Hole Costs	0	[1]	4,478	[1]	0	[1]
Transportation Costs	617	[1]	659	[1]	1,104	[1]
Production Costs	38,301	[1]	43,279	[1]	37,792	[1]
Impairments	0	[1]	14,274	[1]	0	[1]
Depreciation, Depletion and Amortization	188,250	[1]	181,637	[1]	146,690	[1]
Income (Loss) Before Income Taxes	283,359	[1]	270,834	[1]	377,197	[1]
Income Tax Provision (Benefit)	74,588	[1]	103,313	[1]	119,442	[1]
Results of Operations	208,771	[1]	167,521	[1]	257,755	[1]
Other International [Member]
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	18,174	[1],[2]	20,583	[1],[2]	23,177	[1],[2]
Other	0	[1],[2]	0	[1],[2]	0	[1],[2]
Total	18,174	[1],[2]	20,583	[1],[2]	23,177	[1],[2]
Exploration Costs	7,892	[1],[2]	6,512	[1],[2]	7,805	[1],[2]
Dry Hole Costs	23,082	[1],[2]	46,322	[1],[2]	11,628	[1],[2]
Transportation Costs	1,419	[1],[2]	1,124	[1],[2]	1,269	[1],[2]
Production Costs	12,770	[1],[2]	13,205	[1],[2]	11,694	[1],[2]
Impairments	395,904	[1],[2]	9,015	[1],[2]	0	[1],[2]
Depreciation, Depletion and Amortization	17,695	[1],[2]	13,995	[1],[2]	17,958	[1],[2]
Income (Loss) Before Income Taxes	-440,588	[1],[2]	-69,590	[1],[2]	-27,177	[1],[2]
Income Tax Provision (Benefit)	25,962	[1],[2]	-66,931	[1],[2]	-21,890	[1],[2]
Results of Operations	($466,550)	[1],[2]	($2,659)	[1],[2]	($5,287)	[1],[2]
[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 DecemberB 31, 2014.
[2]	Other International primarily consists of EOG's United Kingdom, China and Argentina operations.

Oil_and_Gas_Exploration_and_Pr5

Oil and Gas Exploration and Production Industries Disclosures, Average Sales Price (Details)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent	6.46		5.88		5.85
United States [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent	6.44		5.78		5.96
Canada [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent	24.76		19.98		16.42
Trinidad [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent	1.34		1.36		0.98
Other International [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Production costs per barrel of oil equivalent	22.83	[1]	26.77	[1]	18.97	[1]
[1]	Other International primarily consists of EOG's United Kingdom, China and Argentina operations.

Oil_and_Gas_Exploration_and_Pr6

Oil and Gas Exploration and Production Industries Disclosures, Discounted Future Net Cash Flows (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$146,950,221		$123,999,499		$94,612,613
Future production costs	-51,633,293		-50,166,488		-37,184,832
Future development costs	-20,494,765		-18,549,351		-17,031,731
Future income taxes	-23,185,714		-16,416,387		-11,150,742
Future net cash flows	51,636,449		38,867,273		29,245,308
Discount to present value at 10% annual rate	-23,713,031		-17,533,841		-12,329,836
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	27,923,418		21,333,432		16,915,472
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	21,333,432		16,915,472		16,225,281
Sales and transfers of oil and gas produced, net of production costs	-9,470,714		-8,196,380		-5,888,317
Net changes in prices and production costs	1,263,177		1,257,853		-301,232
Extensions, discoveries, additions and improved recovery, net of related costs	8,083,852		5,483,432		6,082,122
Development costs incurred	2,835,100		2,955,900		2,094,600
Revisions of estimated development cost	1,802,735		990,396		2,341,476
Revisions of previous quantity estimates	1,812,532		1,794,198		-3,742,827
Accretion of discount	2,833,350		2,133,729		2,077,217
Net change in income taxes	-3,651,300		-2,578,250		125,065
Purchases of reserves in place	317,785		66,359		69,940
Sales of reserves in place	-478,879		-140,652		-913,761
Changes in timing and other	1,242,348		651,375		-1,254,092
Balance at End of Period	27,923,418		21,333,432		16,915,472
United States [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	144,355,692	[1]	119,644,713	[2]	89,324,274	[3]
Future production costs	-51,112,604		-49,099,393		-35,892,997
Future development costs	-20,270,439		-17,753,860		-15,825,040
Future income taxes	-22,725,618		-15,763,089		-10,247,007
Future net cash flows	50,247,031		37,028,371		27,359,230
Discount to present value at 10% annual rate	-23,542,990		-17,451,470		-12,177,896
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	26,704,041		19,576,901		15,181,334
Per unit price used to calculate future cash inflows - Crude Oil	97.51		105.91		99.78
Per unit price used to calculate future cash inflows - Natural Gas Liquids	34.29		29.42		36.95
Per unit price used to calculate future cash inflows - Natural Gas	3.71		3.5		2.63
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	19,576,901		15,181,334		14,375,654
Sales and transfers of oil and gas produced, net of production costs	-8,874,180		-7,561,343		-5,192,392
Net changes in prices and production costs	1,481,668		1,734,058		-393,585
Extensions, discoveries, additions and improved recovery, net of related costs	8,074,550		5,449,531		5,517,945
Development costs incurred	2,818,800		2,792,400		2,042,300
Revisions of estimated development cost	1,696,916		892,803		1,987,330
Revisions of previous quantity estimates	1,741,918		1,887,062		-3,286,943
Accretion of discount	2,612,286		1,895,503		1,832,377
Net change in income taxes	-3,743,300		-2,772,267		174,418
Purchases of reserves in place	317,785		66,359		64,317
Sales of reserves in place	-189,808		-140,652		-869,534
Changes in timing and other	1,190,505		152,113		-1,070,553
Balance at End of Period	26,704,041		19,576,901		15,181,334
Canada [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	50,116	[1]	1,199,251	[2]	1,816,369	[3]
Future production costs	-25,561		-540,188		-751,113
Future development costs	-32,016		-529,788		-813,061
Future income taxes	0		0		0
Future net cash flows	-7,461		129,275		252,195
Discount to present value at 10% annual rate	11,217		202,379		146,954
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	3,756		331,654		399,149
Per unit price used to calculate future cash inflows - Crude Oil	95.11		91.47		84.77
Per unit price used to calculate future cash inflows - Natural Gas Liquids	27.03		40.88		47.8
Per unit price used to calculate future cash inflows - Natural Gas	4.79		2.95		2.22
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	331,654		399,149		636,347
Sales and transfers of oil and gas produced, net of production costs	-118,791		-155,239		-159,577
Net changes in prices and production costs	-94,315		-438,982		-67,964
Extensions, discoveries, additions and improved recovery, net of related costs	0		33,901		79,529
Development costs incurred	200		95,400		23,600
Revisions of estimated development cost	63,978		48,906		383,215
Revisions of previous quantity estimates	42,000		-23,915		-396,408
Accretion of discount	33,165		39,915		63,635
Net change in income taxes	0		0		0
Purchases of reserves in place	0		0		0
Sales of reserves in place	-289,071		0		-44,227
Changes in timing and other	34,936		332,519		-119,001
Balance at End of Period	3,756		331,654		399,149
Trinidad [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	1,615,280	[1]	2,082,195	[2]	2,408,116	[3]
Future production costs	-277,844		-315,483		-342,113
Future development costs	-84,576		-112,050		-171,737
Future income taxes	-460,096		-603,786		-691,109
Future net cash flows	792,764		1,050,876		1,203,157
Discount to present value at 10% annual rate	-110,228		-174,236		-242,087
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	682,536		876,640		961,070
Per unit price used to calculate future cash inflows - Crude Oil	80.6		94.3		94.46
Per unit price used to calculate future cash inflows - Natural Gas	3.71		3.71		3.61
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	876,640		961,070		1,184,207
Sales and transfers of oil and gas produced, net of production costs	-473,757		-473,544		-526,134
Net changes in prices and production costs	-12,079		-12,050		162,600
Extensions, discoveries, additions and improved recovery, net of related costs	3,113		0		0
Development costs incurred	12,800		67,100		23,500
Revisions of estimated development cost	9,981		-3,539		-28,835
Revisions of previous quantity estimates	35,001		-60,419		-62,285
Accretion of discount	133,019		147,099		178,298
Net change in income taxes	91,438		56,373		88,853
Purchases of reserves in place	0		0		0
Sales of reserves in place	0		0		0
Changes in timing and other	6,380		194,550		-59,134
Balance at End of Period	682,536		876,640		961,070
Other International (1) [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	929,133	[1],[4]	1,073,340	[2],[4]	1,063,854	[3],[4]
Future production costs	-217,284	[4]	-211,424	[4]	-198,609	[4]
Future development costs	-107,734	[4]	-153,653	[4]	-221,893	[4]
Future income taxes	0	[4]	-49,512	[4]	-212,626	[4]
Future net cash flows	604,115	[4]	658,751	[4]	430,726	[4]
Discount to present value at 10% annual rate	-71,030	[4]	-110,514	[4]	-56,807	[4]
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	533,085	[4]	548,237	[4]	373,919	[4]
Per unit price used to calculate future cash inflows - Crude Oil	94.09		107.36		109.94
Per unit price used to calculate future cash inflows - Natural Gas	5.34		5.67		5.04
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	548,237		373,919		29,073
Sales and transfers of oil and gas produced, net of production costs	-3,986		-6,254		-10,214
Net changes in prices and production costs	-112,097		-25,173		-2,283
Extensions, discoveries, additions and improved recovery, net of related costs	6,189		0		484,648
Development costs incurred	3,300		1,000		5,200
Revisions of estimated development cost	31,860		52,226		-234
Revisions of previous quantity estimates	-6,387		-8,530		2,809
Accretion of discount	54,880		51,212		2,907
Net change in income taxes	562		137,644		-138,206
Purchases of reserves in place	0		0		5,623
Sales of reserves in place	0		0		0
Changes in timing and other	10,527		-27,807		-5,404
Balance at End of Period	$533,085		$548,237		$373,919
[1]	Estimated crude oil prices used to calculate 2014 future cash inflows for the United States, Canada, Trinidad and Other International were $97.51, $95.11, $80.60 and $94.09, respectively. Estimated NGL prices used to calculate 2014 future cash inflows for the United States and Canada were $34.29 and $27.03, respectively. Estimated natural gas prices used to calculate 2014 future cash inflows for the United States, Canada, Trinidad and Other International were $3.71, $4.79, $3.71 and $5.34, respectively.
[2]	Estimated crude oil prices used to calculate 2013 future cash inflows for the United States, Canada, Trinidad and Other International were $105.91, $91.47, $94.30 and $107.36, respectively. Estimated NGL prices used to calculate 2013 future cash inflows for the United States and Canada were $29.42 and $40.88, respectively. Estimated natural gas prices used to calculate 2013 future cash inflows for the United States, Canada, Trinidad and Other International were $3.50, $2.95, $3.71 and $5.67, respectively.
[3]	Estimated crude oil prices used to calculate 2012 future cash inflows for the United States, Canada, Trinidad and Other International were $99.78, $84.77, $94.46 and $109.94, respectively. Estimated NGL prices used to calculate 2012 future cash inflows for the United States and Canada were $36.95 and $47.80, respectively. Estimated natural gas prices used to calculate 2012 future cash inflows for the United States, Canada, Trinidad and Other International were $2.63, $2.22, $3.61, and $5.04, respectively.
[4]	Other International includes EOG's United Kingdom, China and Argentina operations.

Unaudited_Quarterly_Financial_2

Unaudited Quarterly Financial Information (Details) (USD $)	3 Months Ended																12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Net Operating Revenues	$4,645,497		$5,118,616		$4,187,556		$4,083,671		$3,749,023		$3,541,396		$3,840,185		$3,356,514		$18,035,340	$14,487,118	$11,682,636
Operating Income	1,226,652		1,786,162		1,144,730		1,084,279		980,324		769,769		1,092,044		833,074		5,241,823	3,675,211	1,479,797
Income Before Income Taxes	1,148,593		1,715,120		1,100,813		1,030,789		919,082		721,555		1,035,230		761,019		4,995,315	3,436,886	1,280,740
Income Tax Provision	704,005		611,502		394,460		369,861		338,888		259,057		375,538		266,294		2,079,828	1,239,777	710,461
Net Income	$444,588		$1,103,618		$706,353		$660,928		$580,194		$462,498		$659,692		$494,725		$2,915,487	$2,197,109	$570,279
Net Income Per Share
Basic (in dollars per share)	$0.82	[1]	$2.03	[1]	$1.30	[1]	$1.22	[1]	$1.07	[1]	$0.85	[1]	$1.22	[1]	$0.92	[1]	$5.36	$4.07	$1.07
Diluted (in dollars per share)	$0.81	[1]	$2.01	[1]	$1.29	[1]	$1.21	[1]	$1.06	[1]	$0.85	[1]	$1.21	[1]	$0.91	[1]	$5.32	$4.02	$1.05
Average Number of Common Shares [Abstract]
Basic (in shares)	544,579		543,984		543,099		542,278		541,857		540,941		540,033		538,717		543,443	540,341	535,155
Diluted (in shares)	549,153		549,518		548,676		548,071		547,966		547,152		545,477		544,526		548,539	546,227	541,524
[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.