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 ($) | Revolving Credit Agreement [Member] | Canadian Dollar Letter of Credit Facilities Due 2018 [Member] | Canadian Dollar Letter of Credit Facilities Due 2018 [Member] | Uncommitted Credit Facilities [Member] | Uncommitted Credit Facilities [Member] | Commercial Paper [Member] | Commercial Paper [Member] | 2.625% Senior Notes due 2023 | 2.625% Senior Notes due 2023 | Floating Rate Senior Notes due 2014 | Floating Rate Senior Notes due 2014 | 2.95% Senior Notes due 2015 | 2.95% Senior Notes due 2015 | 2.500% Senior Notes due 2016 | 2.500% Senior Notes due 2016 | 5.875% Senior Notes due 2017 | 5.875% Senior Notes due 2017 | 6.875% Senior Notes due 2018 | 6.875% Senior Notes due 2018 | 5.625% Senior Notes due 2019 | 5.625% Senior Notes due 2019 | 4.40% Senior Notes due 2020 | 4.40% Senior Notes due 2020 | 2.45% Senior Notes due 2020 | 2.45% Senior Notes due 2020 | 4.100% Senior Notes due 2021 | 4.100% Senior Notes due 2021 | 6.65% Senior Notes due 2028 | 6.65% Senior Notes due 2028 | 4.75% Subsidiary Debt due 2014 | 4.75% Subsidiary Debt due 2014 | |
USD ($) | USD ($) | CAD | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | 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. |