Document_and_Entity_Informatio
Document and Entity Information (USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Feb. 14, 2014 | Jun. 28, 2013 | |
Document and Entity Information [Abstract] | ' | ' | ' |
Entity Registrant Name | 'EOG RESOURCES INC | ' | ' |
Entity Central Index Key | '0000821189 | ' | ' |
Current Fiscal Year End Date | '--12-31 | ' | ' |
Entity Well-known Seasoned Issuer | 'Yes | ' | ' |
Entity Voluntary Filers | 'No | ' | ' |
Entity Current Reporting Status | 'Yes | ' | ' |
Entity Filer Category | 'Large Accelerated Filer | ' | ' |
Entity Public Float | ' | ' | $35,668,000,000 |
Entity Common Stock, Shares Outstanding | ' | 273,119,572 | ' |
Document Fiscal Year Focus | '2013 | ' | ' |
Document Fiscal Period Focus | 'FY | ' | ' |
Document Type | '10-K | ' | ' |
Amendment Flag | 'false | ' | ' |
Document Period End Date | 31-Dec-13 | ' | ' |
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, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||
Net Operating Revenues | ' | ' | ' | |||
Crude Oil and Condensate | $8,300,647 | $5,659,437 | $3,838,284 | |||
Natural Gas Liquids | 773,970 | 727,177 | 779,364 | |||
Natural Gas | 1,681,029 | 1,571,762 | 2,240,540 | |||
(Losses) Gains on Mark-to-Market Commodity Derivative Contracts | -166,349 | 393,744 | 626,053 | |||
Gathering, Processing and Marketing | 3,643,749 | 3,096,694 | 2,115,792 | |||
Gains on Asset Dispositions, Net | 197,565 | 192,660 | 492,909 | |||
Other, Net | 56,507 | 41,162 | 33,173 | |||
Total | 14,487,118 | [1] | 11,682,636 | [2] | 10,126,115 | [3] |
Operating Expenses | ' | ' | ' | |||
Lease and Well | 1,105,978 | 1,000,052 | 941,954 | |||
Transportation Costs | 853,044 | 601,431 | 430,322 | |||
Gathering and Processing Costs | 107,871 | 97,945 | 80,727 | |||
Exploration Costs | 161,346 | 185,569 | 171,658 | |||
Dry Hole Costs | 74,655 | 14,970 | [4] | 53,230 | [4] | |
Impairments | 286,941 | 1,270,735 | 1,031,037 | |||
Marketing Costs | 3,648,840 | 3,035,494 | 2,072,137 | |||
Depreciation, Depletion and Amortization | 3,600,976 | 3,169,703 | 2,516,381 | |||
General and Administrative | 348,312 | 331,545 | 304,811 | |||
Taxes Other Than Income | 623,944 | 495,395 | 410,549 | |||
Total | 10,811,907 | 10,202,839 | 8,012,806 | |||
Operating Income | 3,675,211 | 1,479,797 | 2,113,309 | |||
Other Income, Net | -2,865 | 14,495 | 6,853 | |||
Income Before Interest Expense and Income Taxes | 3,672,346 | 1,494,292 | 2,120,162 | |||
Interest Expense | ' | ' | ' | |||
Incurred | 284,599 | 263,254 | 268,104 | |||
Capitalized | -49,139 | -49,702 | -57,741 | |||
Net Interest Expense | 235,460 | 213,552 | 210,363 | |||
Income (Loss) Before Income Taxes | 3,436,886 | 1,280,740 | 1,909,799 | |||
Income Tax Provision | 1,239,777 | 710,461 | 818,676 | |||
Net Income (Loss) | 2,197,109 | 570,279 | 1,091,123 | |||
Net Income Per Share | ' | ' | ' | |||
Basic (in dollars per share) | $8.13 | $2.13 | $4.15 | |||
Diluted (in dollars per share) | $8.04 | $2.11 | $4.10 | |||
Dividends Declared per Common Share | $0.75 | $0.68 | $0.64 | |||
Average Number of Common Shares [Abstract] | ' | ' | ' | |||
Basic (in dollars per share) | 270,170 | 267,577 | 262,735 | |||
Diluted (in dollars per share) | 273,114 | 270,762 | 266,268 | |||
Comprehensive Income | ' | ' | ' | |||
Net Income | 2,197,109 | 570,279 | 1,091,123 | |||
Other Comprehensive Income (Loss) | ' | ' | ' | |||
Foreign Currency Translation Adjustments | -29,395 | 37,739 | -32,597 | |||
Foreign Currency Swap Transaction | 1,652 | 1,589 | -1,571 | |||
Income Tax Related to Foreign Currency Swap Transaction | 1 | -404 | 404 | |||
Interest Rate Swap Transaction | 2,737 | -134 | -5,223 | |||
Income Tax Related to Interest Rate Swap Transaction | -981 | 48 | 1,878 | |||
Other | 1,925 | -689 | -1,216 | |||
Other Comprehensive Income (Loss) | -24,061 | 38,149 | -38,325 | |||
Comprehensive Income | $2,173,048 | $608,428 | $1,052,798 | |||
[1] | 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. | |||||
[2] | EOG had sales activity with a single significant purchaser in the United States segment in 2012 that totaled $2.2 billion of consolidated Net Operating Revenues. | |||||
[3] | EOG had no purchasers in 2011 whose sales totaled 10 percent or more of consolidated Net Operating Revenues. | |||||
[4] | Excludes gains or losses on the mark-to-market of financial commodity derivative contracts, gains or losses on sales of reserves and related assets, interest charges and general corporate expenses for each of the three years in the period ended December 31, 2013. |
Consolidated_Balance_Sheets
Consolidated Balance Sheets (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Current Assets | ' | ' |
Cash and Cash Equivalents | $1,318,209 | $876,435 |
Accounts Receivable, Net | 1,658,853 | 1,656,618 |
Inventories | 563,268 | 683,187 |
Assets from Price Risk Management Activities | 8,260 | 166,135 |
Income Taxes Receivable | 4,797 | 29,163 |
Total Net Current Deferred Income Tax Assets | 244,606 | 0 |
Other | 274,022 | 178,346 |
Total | 4,072,015 | 3,589,884 |
Property, Plant and Equipment | ' | ' |
Oil and Gas Properties (Successful Efforts Method) | 42,821,803 | 38,126,298 |
Other Property, Plant and Equipment | 2,967,085 | 2,740,619 |
Total Property, Plant and Equipment | 45,788,888 | 40,866,917 |
Less: Accumulated Depreciation, Depletion and Amortization | -19,640,052 | -17,529,236 |
Total Property, Plant and Equipment, Net | 26,148,836 | 23,337,681 |
Other Assets | 353,387 | 409,013 |
Total Assets | 30,574,238 | 27,336,578 |
Current Liabilities | ' | ' |
Accounts Payable | 2,254,418 | 2,078,948 |
Accrued Taxes Payable | 159,365 | 162,083 |
Dividends Payable | 50,795 | 45,802 |
Liabilities from Price Risk Management Activities | 127,542 | 7,617 |
Deferred Income Taxes | 0 | 22,838 |
Current Portion of Long-Term Debt | 6,579 | 406,579 |
Other | 263,017 | 200,191 |
Total | 2,861,716 | 2,924,058 |
Long-Term Debt | 5,906,642 | 5,905,602 |
Other Liabilities | 865,067 | 894,758 |
Deferred Income Taxes | 5,522,354 | 4,327,396 |
Commitments and Contingencies (Note 7) | ' | ' |
Stockholders' Equity | ' | ' |
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 273,189,220 Shares and 271,958,495 Shares Issued at December 31, 2013 and 2012, respectively | 202,732 | 202,720 |
Additional Paid in Capital | 2,646,879 | 2,500,340 |
Accumulated Other Comprehensive Income | 415,834 | 439,895 |
Retained Earnings | 12,168,277 | 10,175,631 |
Common Stock Held in Treasury, 103,415 Shares and 326,264 Shares at December 31, 2013 and 2012, respectively | -15,263 | -33,822 |
Total Stockholders' Equity | 15,418,459 | 13,284,764 |
Total Liabilities and Stockholders' Equity | $30,574,238 | $27,336,578 |
Consolidated_Balance_Sheets_Pa
Consolidated Balance Sheets (Parenthetical) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
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 dollars per share) | 273,189,220 | 271,958,495 |
Treasury Stock | ' | ' |
Common Stock Held in Treasury, Shares | 103,415 | 326,264 |
Consolidated_Statements_of_Sto
Consolidated Statements of Stockholders' Equity (USD $) | Common Stock [Member] | Additional Paid-in Capital [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | Retained Earnings [Member] | Common Stock Held in Treasury [Member] | Total |
In Thousands | ||||||
Balance at Dec. 31, 2010 | $202,542 | $729,992 | $440,071 | $8,870,179 | ($11,152) | $10,231,632 |
Net Income | 0 | 0 | 0 | 1,091,123 | 0 | 1,091,123 |
Common Stock Issued Under Stock Plans | 10 | 35,903 | 0 | 0 | 0 | 35,913 |
Common Stock Dividends Declared | 0 | 0 | 0 | -171,957 | 0 | -171,957 |
Other Comprehensive Income (Loss) | 0 | 0 | -38,325 | 0 | 0 | -38,325 |
Change in Treasury Stock - Stock Compensation Plans, Net | 0 | -18,622 | 0 | 0 | -5,413 | -24,035 |
Excess Tax Benefit from Stock-Based Compensation | 0 | 25 | 0 | 0 | 0 | 25 |
Restricted Stock and Restricted Stock Units, Net | 5 | 8,410 | 0 | 0 | -8,415 | 0 |
Stock-Based Compensation Expenses | 0 | 128,205 | 0 | 0 | 0 | 128,205 |
Common Stock Sold | 136 | 1,388,129 | 0 | 0 | 0 | 1,388,265 |
Treasury Stock Issued as Compensation | 0 | 10 | 0 | 0 | 48 | 58 |
Balance at Dec. 31, 2011 | 202,693 | 2,272,052 | 401,746 | 9,789,345 | -24,932 | 12,640,904 |
Net Income | 0 | 0 | 0 | 570,279 | 0 | 570,279 |
Common Stock Issued Under Stock Plans | 21 | 83,197 | 0 | 0 | 0 | 83,218 |
Common Stock Dividends Declared | 0 | 0 | 0 | -183,993 | 0 | -183,993 |
Other Comprehensive Income (Loss) | 0 | 0 | 38,149 | 0 | 0 | 38,149 |
Change in Treasury Stock - Stock Compensation Plans, Net | 0 | -47,123 | 0 | 0 | -11,465 | -58,588 |
Excess Tax Benefit from Stock-Based Compensation | 0 | 67,035 | 0 | 0 | 0 | 67,035 |
Restricted Stock and Restricted Stock Units, Net | 6 | -2,364 | 0 | 0 | 2,358 | 0 |
Stock-Based Compensation Expenses | 0 | 127,504 | 0 | 0 | 0 | 127,504 |
Treasury Stock Issued as Compensation | 0 | 39 | 0 | 0 | 217 | 256 |
Balance at Dec. 31, 2012 | 202,720 | 2,500,340 | 439,895 | 10,175,631 | -33,822 | 13,284,764 |
Net Income | 0 | 0 | 0 | 2,197,109 | 0 | 2,197,109 |
Common Stock Issued Under Stock Plans | 6 | 38,723 | 0 | 0 | 0 | 38,729 |
Common Stock Dividends Declared | 0 | 0 | 0 | -204,463 | 0 | -204,463 |
Other Comprehensive Income (Loss) | 0 | 0 | -24,061 | 0 | 0 | -24,061 |
Change in Treasury Stock - Stock Compensation Plans, Net | 0 | -79,641 | 0 | 0 | 47,427 | -32,214 |
Excess Tax Benefit from Stock-Based Compensation | 0 | 55,831 | 0 | 0 | 0 | 55,831 |
Restricted Stock and Restricted Stock Units, Net | 6 | -2,974 | 0 | 0 | -28,454 | -31,422 |
Stock-Based Compensation Expenses | 0 | 134,467 | 0 | 0 | 0 | 134,467 |
Treasury Stock Issued as Compensation | 0 | 133 | 0 | 0 | -414 | -281 |
Balance at Dec. 31, 2013 | $202,732 | $2,646,879 | $415,834 | $12,168,277 | ($15,263) | $15,418,459 |
Consolidated_Statements_of_Sto1
Consolidated Statements of Stockholders' Equity (Parenthetical) (USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Consolidated Statements of Stockholders' Equity [Abstract] | ' | ' | ' |
Common Stock Dividends Declared (in dollars per share) | $0.75 | $0.68 | $0.64 |
Consolidated_Statements_of_Cas
Consolidated Statements of Cash Flows (USD $) | 12 Months Ended | ||||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||
Cash Flows from Operating Activities | ' | ' | ' | ||
Net Income | $2,197,109 | $570,279 | $1,091,123 | ||
Items Not Requiring (Providing) Cash | ' | ' | ' | ||
Depreciation, Depletion and Amortization | 3,600,976 | 3,169,703 | 2,516,381 | ||
Impairments | 286,941 | 1,270,735 | 1,031,037 | ||
Stock-Based Compensation Expenses | 134,055 | 127,778 | 128,345 | ||
Deferred Income Taxes | 874,765 | 292,938 | 499,300 | ||
Gains on Asset Dispositions, Net | -197,565 | -192,660 | -492,909 | ||
Other, Net | 11,072 | 672 | 15,139 | ||
Dry Hole Costs | 74,655 | 14,970 | [1] | 53,230 | [1] |
Mark-to-Market Commodity Derivative Contracts | ' | ' | ' | ||
Total (Gains) Losses | 166,349 | -393,744 | -626,053 | ||
Realized Gains | 116,361 | 711,479 | 180,701 | ||
Excess Tax Benefits from Stock-Based Compensation | -55,831 | -67,035 | 0 | ||
Other, Net | 18,205 | 14,411 | 26,454 | ||
Changes in Components of Working Capital and Other Assets and Liabilities | ' | ' | ' | ||
Accounts Receivable | -23,613 | -178,683 | -339,780 | ||
Inventories | 53,402 | -156,762 | -176,623 | ||
Accounts Payable | 178,701 | -17,150 | 351,087 | ||
Accrued Taxes Payable | 75,142 | 78,094 | 92,589 | ||
Other Assets | -109,567 | -118,520 | -23,625 | ||
Other Liabilities | -20,382 | 36,114 | 14,986 | ||
Changes in Components of Working Capital Associated with Investing and Financing Activities | -51,361 | 74,158 | 237,028 | ||
Net Cash Provided by Operating Activities | 7,329,414 | 5,236,777 | 4,578,410 | ||
Investing Cash Flows | ' | ' | ' | ||
Additions to Oil and Gas Properties | -6,697,091 | -6,735,316 | -6,294,397 | ||
Additions to Other Property, Plant and Equipment | -363,536 | -619,800 | -656,415 | ||
Proceeds from Sales of Assets | 760,557 | 1,309,776 | 1,433,137 | ||
Changes in Restricted Cash | -65,814 | 0 | 0 | ||
Changes in Components of Working Capital Associated with Investing Activities | 51,106 | -73,923 | -237,267 | ||
Net Cash Used in Investing Activities | -6,314,778 | -6,119,263 | -5,754,942 | ||
Financing Cash Flows | ' | ' | ' | ||
Common Stock Sold | 0 | 0 | 1,388,265 | ||
Long-Term Debt Borrowings | 0 | 1,234,138 | 0 | ||
Long-Term Debt Repayments | -400,000 | 0 | -220,000 | ||
Dividends Paid | -199,178 | -181,080 | -167,169 | ||
Excess Tax Benefits from Stock-Based Compensation | 55,831 | 67,035 | 0 | ||
Treasury Stock Purchased | -63,784 | -58,592 | -23,922 | ||
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan | 38,730 | 82,887 | 35,913 | ||
Debt Issuance Costs | 0 | -1,578 | -4,787 | ||
Repayment of Capital Lease Obligation | -5,780 | -2,824 | 0 | ||
Other, Net | 255 | -235 | 239 | ||
Net Cash Provided by Financing Activities | -573,926 | 1,139,751 | 1,008,539 | ||
Effect of Exchange Rate Changes on Cash | 1,064 | 3,444 | -5,134 | ||
Increase (Decrease) in Cash and Cash Equivalents | 441,774 | 260,709 | -173,127 | ||
Cash and Cash Equivalents at Beginning of Period | 876,435 | 615,726 | 788,853 | ||
Cash and Cash Equivalents at End of Period | $1,318,209 | $876,435 | $615,726 | ||
[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, 2013. |
Summary_of_Significant_Account
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2013 | |
Summary of Significant 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. | |
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, foreign currency and interest rate swaps and accounts payable approximate fair value (see Notes 2 and 11). | |
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 15). Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. | |
Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account. | |
Oil and gas properties are grouped in accordance with the Extractive Industries - Oil and Gas Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC). The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. | |
Amortization rates are updated quarterly to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions and/or property dispositions and 4) impairments. | |
When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the asset. If the expected undiscounted future cash flows, based on EOG's estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach described in the Fair Value Measurement Topic of the ASC. If applicable, EOG utilizes accepted bids as the basis for determining fair value. | |
Inventories, consisting primarily of tubular goods, materials for completion operations and well equipment held for use in the exploration for, and development and production of, crude oil and natural gas reserves, are carried at cost with adjustments made, as appropriate, to recognize any reductions in value. | |
Arrangements for sales of crude oil and condensate, natural gas liquids (NGLs) and natural gas are evidenced by signed contracts with determinable market prices, and revenues are recorded when production is delivered. A significant majority of 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, NGLs 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, 2013, 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 is reflected as cash flows from operating activities. EOG is party to a foreign currency swap transaction and an interest rate swap transaction. 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 11. | |
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 5). | |
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. | |
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 8). | |
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 6). | |
Recently Issued Accounting Standards. In February 2013, the FASB issued Accounting Standards Update (ASU) 2013-02 "Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income" (ASU 2013-02). ASU 2013-02 amends ASU 2011-05 and requires that entities disclose additional information about amounts reclassified out of Accumulated Other Comprehensive Income (AOCI) by component. Significant amounts reclassified out of AOCI are required to be presented either on the face of the Consolidated Statements of Income and Comprehensive Income or in the notes to the financial statements. The requirements of ASU 2013-02 are effective for fiscal years and interim periods in those years beginning after December 15, 2012. The adoption of ASU 2013-02 did not have a material impact on EOG's financial statements. No significant amounts were reclassified out of AOCI during the years ended December 31, 2013, 2012 and 2011. | |
In July 2013, the FASB issued ASU 2013-11 "Presentation of an Unrecognized Tax Benefit when a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists" (ASU 2013-11). ASU 2013-11 includes specific guidance on financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The requirements of ASU 2013-11 are effective for fiscal years and interim periods in those years beginning after December 15, 2013. Early adoption is permitted. EOG does not expect a material impact on its financial statements from the adoption of ASU 2013-11. | |
LongTerm_Debt
Long-Term Debt | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
Long-Term Debt [Abstract] | ' | ||||||||
Long-Term Debt | ' | ||||||||
2. Long-Term Debt | |||||||||
Long-Term Debt at December 31, 2013 and 2012 consisted of the following (in thousands): | |||||||||
2013 | 2012 | ||||||||
6.125% Senior Notes due 2013 | $ | - | $ | 400,000 | |||||
Floating Rate Senior Notes due 2014 | 350,000 | 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 | |||||||
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 | 150,000 | |||||||
Total Long-Term Debt | 5,890,000 | 6,290,000 | |||||||
Capital Lease Obligation | 57,187 | 62,968 | |||||||
Less: Current Portion of Long-Term Debt | 6,579 | 406,579 | |||||||
Unamortized Debt Discount | 33,966 | 40,787 | |||||||
Total Long-Term Debt, Net | $ | 5,906,642 | $ | 5,905,602 | |||||
At December 31, 2013, the aggregate annual maturities of long-term debt (excluding capital lease obligations) were $500 million in 2014, $500 million in 2015, $400 million in 2016, $600 million in 2017 and $350 million in 2018. On October 1, 2013, EOG repaid at maturity $400 million principal amount of its 6.125% Senior Notes due 2013, plus accrued and unpaid interest. All subsidiary debt is guaranteed by EOG. At December 31, 2013, $350 million principal amount of Floating Rate Senior Notes due 2014 (Floating Rate Notes) and $150 million principal amount of 4.75% Subsidiary Debt due 2014 (4.75% Subsidiary Debt) were classified as long-term debt based upon EOG's intent and ability to ultimately replace such amounts with other long-term debt. | |||||||||
On February 3, 2014, EOG repaid upon maturity $350 million principal amount of its Floating Rate Notes. On the same date, EOG settled its interest rate swap agreement entered into contemporaneously with the issuance of the Floating Rate Notes. | |||||||||
During 2013 and 2012, 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 borrowings from commercial paper or uncommitted credit facilities at December 31, 2013 and 2012, respectively. The average borrowings outstanding under the commercial paper program were $37 million and $236 million during the years ended December 31, 2013 and 2012, respectively. The average borrowings outstanding under the uncommitted credit facilities were zero and $41 million during the years ended December 31, 2013 and 2012, respectively. The weighted average interest rates for commercial paper borrowings were 0.30% and 0.45% for the years 2013 and 2012, respectively, and were 0.70% for uncommitted credit facility borrowings for the year 2012. | |||||||||
On September 10, 2012, EOG closed its sale of $1.25 billion aggregate principal amount of its 2.625% Senior Notes due 2023 (Notes). Interest on the Notes is payable semi-annually in arrears on March 15 and September 15 of each year, beginning March 15, 2013. Net proceeds from the Notes offering of approximately $1,234 million were used for general corporate purposes, including repayment of outstanding commercial paper borrowings and funding of capital expenditures. The Notes were issued through a public offering with an effective interest rate of 2.784%. | |||||||||
EOG currently has a $2.0 billion senior unsecured Revolving Credit Agreement (Agreement) with domestic and foreign lenders. The Agreement has a scheduled maturity date of 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 banks holding greater than 50% of the commitments then outstanding under the Agreement. At December 31, 2013, 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, 2013, the Eurodollar rate and applicable base rate, had there been any amounts borrowed under the Agreement, would have been 1.04% 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, 2013, and during the year then ended, EOG believes that it was in compliance with this financial debt covenant. | |||||||||
EOG Resources Canada Inc. (EOGRC), a wholly-owned subsidiary of EOG, has outstanding the 4.75% Subsidiary Debt with a maturity date of March 15, 2014. In conjunction with the offering, EOG entered into a foreign currency swap transaction with multiple banks for the equivalent amount of the notes and related interest, which has in effect converted this indebtedness into $201.3 million Canadian dollars with a 5.275% interest rate. EOG accounts for the foreign currency swap transaction using the hedge accounting method (see Note 11). | |||||||||
Restricted Cash. In May 2013, the Canadian Alberta Energy Regulator (AER) made effective certain regulations affecting the Licensee Liability Rating program which requires well owners to post financial security for well abandonment obligations in amounts set forth by the AER. In order to comply with these requirements, EOGRC established a 160 million Canadian dollar letter of credit facility (maturing May 29, 2018) with Royal Bank of Canada (RBC) as the lender. The letter of credit facility requires EOGRC to deposit cash, in an amount equal to all outstanding letters of credit under such facility, in a cash collateral account at RBC. At December 31, 2013, the balance in this account was 70 million Canadian dollars (66 million United States dollars) and was included in Other Assets on the Consolidated Balance Sheets. |
Stockholders_Equity
Stockholder's Equity | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Stockholders' Equity [Abstract] | ' | ||||||||||||
Stockholder's Equity | ' | ||||||||||||
3. Stockholders' Equity | |||||||||||||
Common Stock. On March 7, 2011, EOG completed the public offering and sale of 13,570,000 shares of EOG common stock, par value $0.01 per share (Common Stock), at the public offering price of $105.50 per share. Net proceeds from the sale of the Common Stock were approximately $1,388 million after deducting the underwriting discount and offering expenses. Proceeds from the sale were used for general corporate purposes, including funding capital expenditures. | |||||||||||||
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, 2013, 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. | |||||||||||||
The Board increased the quarterly cash dividend on the Common Stock to $0.17 per share on February 16, 2012, and to $0.1875 on February 13, 2013. On February 24, 2014, EOG's Board approved a two-for-one stock split in the form of a stock dividend, payable on March 31, 2014, to stockholders of record as of March 17, 2014. Also on February 24, 2014, the Board increased the quarterly cash dividend on the common stock by 33% to $0.125 per share post-split ($0.25 per share pre-split), effective beginning with the dividend to be paid on April 30, 2014, to stockholders of record as of April 16, 2014. | |||||||||||||
The following summarizes Common Stock activity for each of the years ended December 31, 2011, 2012 and 2013 (in thousands): | |||||||||||||
Common Shares | |||||||||||||
Issued | Treasury | Outstanding | |||||||||||
Balance at December 31, 2010 | 254,223 | (146 | ) | 254,077 | |||||||||
Common Stock Issued Under Stock-Based Compensation Plans | 1,395 | - | 1,395 | ||||||||||
Treasury Stock Purchased (1) | - | (267 | ) | (267 | ) | ||||||||
Common Stock Issued Under Employee Stock Purchase Plan | 135 | - | 135 | ||||||||||
Treasury Stock Issued Under Stock-Based Compensation Plans | - | 109 | 109 | ||||||||||
Common Stock Sold | 13,570 | - | 13,570 | ||||||||||
Balance at December 31, 2011 | 269,323 | (304 | ) | 269,019 | |||||||||
Common Stock Issued Under Stock-Based Compensation Plans | 2,471 | - | 2,471 | ||||||||||
Treasury Stock Purchased (1) | - | (575 | ) | (575 | ) | ||||||||
Common Stock Issued Under Employee Stock Purchase Plan | 164 | - | 164 | ||||||||||
Treasury Stock Issued Under Stock-Based Compensation Plans | - | 553 | 553 | ||||||||||
Balance at December 31, 2012 | 271,958 | (326 | ) | 271,632 | |||||||||
Common Stock Issued Under Stock-Based Compensation Plans | 1,103 | - | 1,103 | ||||||||||
Treasury Stock Purchased (1) | - | (427 | ) | (427 | ) | ||||||||
Common Stock Issued Under Employee Stock Purchase Plan | 128 | - | 128 | ||||||||||
Treasury Stock Issued Under Stock-Based Compensation Plans | - | 650 | 650 | ||||||||||
Balance at December 31, 2013 | 273,189 | (103 | ) | 273,086 | |||||||||
-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, 2013, there were no shares of preferred stock outstanding. |
Other_Income_Net
Other Income, Net | 12 Months Ended |
Dec. 31, 2013 | |
Other Income, Net [Abstract] | ' |
Other Income, Net | ' |
4. Other Income, Net | |
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 sales and adjustments 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 related to severance tax refunds, net foreign currency transaction gains ($7 million), losses on sales of warehouse stock ($10 million) and operating losses on EOG's investment in the proposed Pacific Trail Pipelines (PTP) in Canada ($9 million). Other income, net, for 2011 included equity income from investments in ammonia plants in Trinidad ($17 million), operating losses on EOG's investment in the PTP in Canada ($5 million) and losses on sales of warehouse stock ($5 million). |
Income_Taxes
Income Taxes | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Income Taxes [Abstract] | ' | ||||||||||||
Income Taxes | ' | ||||||||||||
5. Income Taxes | |||||||||||||
The principal components of EOG's net deferred income tax liabilities at December 31, 2013 and 2012 were as follows (in thousands): | |||||||||||||
2013 | 2012 | ||||||||||||
Current Deferred Income Tax Assets (Liabilities) | |||||||||||||
Commodity Hedging Contracts | $ | 29,582 | $ | (57,754 | ) | ||||||||
Deferred Compensation Plans | 42,296 | 35,715 | |||||||||||
Net Operating Loss | 96,616 | - | |||||||||||
Alternative Minimum Tax Credit Carryforward | 72,297 | - | |||||||||||
Timing Differences Associated with Different Year-ends in Foreign Jurisdictions | - | (2,762 | ) | ||||||||||
Other | 3,815 | 1,963 | |||||||||||
Total Net Current Deferred Income Tax Assets (Liabilities) | $ | 244,606 | $ | (22,838 | ) | ||||||||
Noncurrent Deferred Income Tax Assets (Liabilities) | |||||||||||||
Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Over (Under) Book Depreciation, Depletion and Amortization | $ | (112,346 | ) | $ | 25,592 | ||||||||
Foreign Net Operating Loss | 369,257 | 164,829 | |||||||||||
Foreign Other | 4,179 | 1,607 | |||||||||||
Foreign Valuation Allowances | (183,122 | ) | (134,792 | ) | |||||||||
Total Net Noncurrent Deferred Income Tax Assets | $ | 77,968 | $ | 57,236 | |||||||||
Noncurrent Deferred Income Tax (Assets) Liabilities | |||||||||||||
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization | $ | 6,287,541 | $ | 5,300,115 | |||||||||
Non-Producing Leasehold Costs | (50,581 | ) | (61,512 | ) | |||||||||
Seismic Costs Capitalized for Tax | (136,964 | ) | (125,026 | ) | |||||||||
Equity Awards | (122,665 | ) | (116,666 | ) | |||||||||
Capitalized Interest | 101,006 | 102,677 | |||||||||||
Net Operating Loss | - | (308,154 | ) | ||||||||||
Alternative Minimum Tax Credit Carryforward | (557,352 | ) | (476,505 | ) | |||||||||
Other | 1,369 | 12,467 | |||||||||||
Total Net Noncurrent Deferred Income Tax Liabilities | $ | 5,522,354 | $ | 4,327,396 | |||||||||
Total Net Deferred Income Tax Liabilities | $ | 5,199,780 | $ | 4,292,998 | |||||||||
The components of Income Before Income Taxes for the years indicated below were as follows (in thousands): | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
United States | $ | 3,268,727 | $ | 1,988,105 | $ | 2,156,147 | |||||||
Foreign | 168,159 | (707,365 | ) | (246,348 | ) | ||||||||
Total | $ | 3,436,886 | $ | 1,280,740 | $ | 1,909,799 | |||||||
The principal components of EOG's Income Tax Provision for the years indicated below were as follows (in thousands): | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Current: | |||||||||||||
Federal | $ | 207,777 | $ | 242,674 | $ | 94,244 | |||||||
State | 22,856 | 22,573 | 1,083 | ||||||||||
Foreign | 134,379 | 152,276 | 224,049 | ||||||||||
Total | 365,012 | 417,523 | 319,376 | ||||||||||
Deferred: | |||||||||||||
Federal | 915,994 | 454,173 | 608,181 | ||||||||||
State | 26,305 | 632 | 40,321 | ||||||||||
Foreign | (67,534 | ) | (161,867 | ) | (149,202 | ) | |||||||
Total | 874,765 | 292,938 | 499,300 | ||||||||||
Income Tax Provision | $ | 1,239,777 | $ | 710,461 | $ | 818,676 | |||||||
The differences between taxes computed at the United States federal statutory tax rate and EOG's effective rate were as follows: | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Statutory Federal Income Tax Rate | 35.00% | 35.00% | 35.00% | ||||||||||
State Income Tax, Net of Federal Benefit | 0.93 | 1.18 | 1.41 | ||||||||||
Income Tax Provision Related to Foreign Operations | (0.20) | 1.38 | 0.88 | ||||||||||
Income Tax Provision Related to Trinidad Operations | 0.43 | (0.27) | 3.37 | ||||||||||
Canadian Valuation Allowances | - | 10.57 | - | ||||||||||
Canadian Natural Gas Impairments | - | 6.90 | 1.85 | ||||||||||
Other | (0.09) | 0.71 | 0.36 | ||||||||||
Effective Income Tax Rate | 36.07% | 55.47% | 42.87% | ||||||||||
The difference in the effective tax rate and the United States federal statutory rate of 35% is attributable principally to state and foreign income taxes. The effective tax rate of 36% in 2013 was lower than the prior year rate of 55% primarily due to the absence of certain 2012 Canadian impairments and valuation allowances (26% statutory rate). | |||||||||||||
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, 2013 and 2012, cumulative valuation allowances of $183 million and $158 million, respectively, have been recorded as EOG does not believe that certain foreign 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, 2013, was zero. The $33 million decrease from the prior year-end balance was the result of concluded income tax audits. However, there was no impact on the effective tax rate as the tax benefits were offset by a valuation allowance. 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 2010, 2009, 2012, 2002 and 2008, respectively. | |||||||||||||
EOG's foreign subsidiaries' undistributed earnings of approximately $2.7 billion at December 31, 2013, are considered to be indefinitely invested outside the United States and, accordingly, no United States federal or state income taxes have been provided thereon. Upon distribution of those earnings, EOG may be subject to both foreign withholding taxes and United States income taxes, net of allowable foreign tax credits. The amount of such additional taxes would be dependent on several factors, including the size and timing of the distribution, the particular foreign jurisdiction from which the distribution is made, and the availability of foreign tax credits. As a result, the determination of the potential amount of unrecognized withholding and deferred income taxes is not practicable, although additional taxes resulting from a repatriation of foreign earnings could be significant. | |||||||||||||
In 2013, EOG utilized a United States federal tax NOL of $787 million. Remaining NOLs of $314 million are expected to be carried forward and applied against regular taxable income in future periods. To the extent not utilized, these NOL carryforwards will begin to expire in 2031. Additionally, as of December 31, 2013, EOG had state income tax NOLs of approximately $700 million, which, if unused, expire between 2015 and 2033. 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 a portion of the available NOLs, a benefit of $15 million will be reflected in APIC. Future utilization of the remaining NOLs will result in an additional benefit of $16 million being reflected in APIC (related to 2011). In 2013, EOG paid alternative minimum tax (AMT) of $161 million. The AMT paid in 2013, along with AMT of $469 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 both the regular tax NOL carryforwards and 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, 2013, management does not believe that an ownership change has occurred which would limit either carryforward. | |||||||||||||
During 2013, EOG's United Kingdom subsidiary incurred a tax NOL of approximately $282 million which, along with prior years' NOLs of $267 million, will be carried forward indefinitely. | |||||||||||||
The American Taxpayer Relief Act of 2012 (ATRA) was enacted on January 2, 2013. Although ATRA principally affected individual taxpayers, the legislation included certain corporate tax incentives, notably the extension of bonus depreciation (additional depreciation expense of 50% for qualified domestic property additions), which had a favorable impact on EOG's tax position in 2013. |
Employee_Benefit_Plans
Employee Benefit Plans | 12 Months Ended | |||||||||||||||||||||||||||
Dec. 31, 2013 | ||||||||||||||||||||||||||||
Employee Benefit Plans [Abstract] | ' | |||||||||||||||||||||||||||
Employee Benefit Plans | ' | |||||||||||||||||||||||||||
6. Employee Benefit Plans | ||||||||||||||||||||||||||||
Stock-Based Compensation | ||||||||||||||||||||||||||||
During 2013, 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, 2013, 2012 and 2011 was as follows (in millions): | ||||||||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||||||||
Lease and Well | $ | 35 | $ | 35 | $ | 33 | ||||||||||||||||||||||
Gathering and Processing Costs | 1 | 1 | 1 | |||||||||||||||||||||||||
Exploration Costs | 27 | 27 | 26 | |||||||||||||||||||||||||
General and Administrative | 71 | 65 | 68 | |||||||||||||||||||||||||
Total | $ | 134 | $ | 128 | $ | 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 up to an aggregate maximum of 28.4 million shares. At December 31, 2013, approximately 16.6 million shares of Common Stock 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 2013, 2012 and 2011, 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 $56 million, $67 million and $25,000 for 2013, 2012 and 2011, 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 $53 million, $49 million and $48 million for the years ended December 31, 2013, 2012 and 2011, respectively. | ||||||||||||||||||||||||||||
Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants for the years ended December 31, 2013, 2012 and 2011 were as follows: | ||||||||||||||||||||||||||||
Stock Options/SARs | ESPP | |||||||||||||||||||||||||||
2013 | 2012 | 2011 | 2013 | 2012 | 2011 | |||||||||||||||||||||||
Weighted Average Fair Value of Grants | $ | 54.7 | $ | 37.95 | $ | 29.92 | $ | 30.12 | $ | 25.11 | $ | 22.75 | ||||||||||||||||
Expected Volatility | 35.86 | % | 39.68 | % | 40.96 | % | 29.89 | % | 40.92 | % | 29.82 | % | ||||||||||||||||
Risk-Free Interest Rate | 0.78 | % | 0.45 | % | 0.58 | % | 0.11 | % | 0.11 | % | 0.14 | % | ||||||||||||||||
Dividend Yield | 0.4 | % | 0.6 | % | 0.7 | % | 0.6 | % | 0.6 | % | 0.7 | % | ||||||||||||||||
Expected Life | 5.5 yrs | 5.6 yrs | 5.6 yrs | 0.5 yrs | 0.5 yrs | 0.5 yrs | ||||||||||||||||||||||
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, 2013, 2012 and 2011 (stock options and SARs in thousands): | ||||||||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||||||||
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 | 6,219 | $ | 85.81 | 8,374 | $ | 70.01 | 8,445 | $ | 64.49 | |||||||||||||||||||
Granted | 1,134 | 167.4 | 1,240 | 111.97 | 1,509 | 85.29 | ||||||||||||||||||||||
Exercised (1) | (2,023 | ) | 71.23 | (3,246 | ) | 54.8 | (1,399 | ) | 50.86 | |||||||||||||||||||
Forfeited | (104 | ) | 101.56 | (149 | ) | 91.18 | (181 | ) | 87.74 | |||||||||||||||||||
Outstanding at December 31 | 5,226 | 108.86 | 6,219 | 85.81 | 8,374 | 70.01 | ||||||||||||||||||||||
Stock Options/SARs Exercisable at December 31 | 2,319 | 87.9 | 3,143 | 74.98 | 5,148 | 59.19 | ||||||||||||||||||||||
-1 | The total intrinsic value of stock options/SARs exercised during the years 2013, 2012 and 2011 was $151 million, $185 million and $78 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, 2013, there were 5.0 million stock options/SARs vested or expected to vest with a weighted average grant price of $108.03 per share, an intrinsic value of $300 million and a weighted average remaining contractual life of 4.5 years. | ||||||||||||||||||||||||||||
The following table summarizes certain information for the stock options and SARs outstanding and exercisable at December 31, 2013 (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) | |||||||||||||||||||||||||
$ 26.00 to $ 81.99 | 764 | 2 | $ | 77.08 | 760 | 2 | $ | 77.13 | ||||||||||||||||||||
82.00 to 89.99 | 1,380 | 4 | 84.82 | 765 | 3 | 85.87 | ||||||||||||||||||||||
90.00 to 109.99 | 837 | 4 | 93.39 | 519 | 4 | 92.87 | ||||||||||||||||||||||
110.00 to 136.99 | 1,154 | 6 | 113.22 | 274 | 5 | 113.65 | ||||||||||||||||||||||
137.00 to 178.99 | 1,091 | 7 | 168.77 | 1 | 1 | 168.86 | ||||||||||||||||||||||
5,226 | 5 | 108.86 | $309,422 | 2,319 | 3 | 87.9 | $185,362 | |||||||||||||||||||||
-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, 2013, unrecognized compensation expense related to non-vested stock option and SAR grants totaled $103 million. This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.7 years. | ||||||||||||||||||||||||||||
At December 31, 2013, approximately 498,000 shares of Common Stock remained available for issuance under the ESPP. The following table summarizes ESPP activities for the years ended December 31, 2013, 2012 and 2011 (in thousands, except number of participants): | ||||||||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||||||||
Approximate Number of Participants | 1,844 | 1,705 | 1,525 | |||||||||||||||||||||||||
Shares Purchased | 128 | 164 | 135 | |||||||||||||||||||||||||
Aggregate Purchase Price | $ | 14,015 | $ | 12,522 | $ | 10,947 | ||||||||||||||||||||||
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 $72 million, $72 million and $80 million for the years ended December 31, 2013, 2012 and 2011, respectively. | ||||||||||||||||||||||||||||
The following table sets forth the restricted stock and restricted stock unit transactions for the years ended December 31, 2013, 2012 and 2011 (shares and units in thousands): | ||||||||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||||||||
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 | 3,818 | $ | 91.06 | 4,240 | $ | 82.93 | 4,009 | $ | 79.13 | |||||||||||||||||||
Granted | 647 | 152.07 | 767 | 112.17 | 932 | 90.87 | ||||||||||||||||||||||
Released (1) | (684 | ) | 104.78 | (1,059 | ) | 72.7 | (457 | ) | 66.1 | |||||||||||||||||||
Forfeited | (102 | ) | 97.1 | (130 | ) | 85.36 | (244 | ) | 82.45 | |||||||||||||||||||
Outstanding at December 31 (2) | 3,679 | 99.08 | 3,818 | 91.06 | 4,240 | 82.93 | ||||||||||||||||||||||
-1 | The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2013, 2012 and 2011 was $101 million, $120 million and $44 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 aggregate intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2013 and 2012 was approximately $617 million and $461 million, respectively. | |||||||||||||||||||||||||||
At December 31, 2013, unrecognized compensation expense related to restricted stock and restricted stock units totaled $154 million. Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 2.4 years. | ||||||||||||||||||||||||||||
Performance Units and Performance Stock. EOG 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 261,390 performance units/shares could be outstanding (based on the number of performance units/shares outstanding as of December 31, 2013). 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 and $7 million for the years ended December 31, 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, 2013 and 2012 are as follows: | ||||||||||||||||||||||||||||
2013 | 2012 | |||||||||||||||||||||||||||
Weighted Average Fair Value of Grants | $ | 200.68 | $ | 134.09 | ||||||||||||||||||||||||
Expected Volatility | 33.63 | % | 36.39 | % | ||||||||||||||||||||||||
Risk-Free Interest Rate | 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, 2013 and 2012 (shares and units in thousands): | ||||||||||||||||||||||||||||
2013 | 2012 | |||||||||||||||||||||||||||
Number of | Weighted | Number of | Weighted | |||||||||||||||||||||||||
Shares and | Average | Shares and | Average | |||||||||||||||||||||||||
Units | Grant Date | Units | Grant Date | |||||||||||||||||||||||||
Fair Value | Fair Value | |||||||||||||||||||||||||||
Outstanding at January 1 | 71 | $ | 134.09 | - | $ | - | ||||||||||||||||||||||
Granted | 60 | 200.68 | 71 | 134.09 | ||||||||||||||||||||||||
Released | - | - | - | - | ||||||||||||||||||||||||
Forfeited | - | - | - | - | ||||||||||||||||||||||||
Outstanding at December 31 (1) | 131 | $ | 164.36 | 71 | $ | 134.09 | ||||||||||||||||||||||
-1 | The total intrinsic value of performance units and performance stock outstanding at December 31, 2013 and 2012 was $21.9 million and $8.6 million, respectively. | |||||||||||||||||||||||||||
At December 31, 2013, unrecognized compensation expense related to performance units and performance stock totaled $6 million. Such unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.4 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 $37 million, $36 million and $27 million for 2013, 2012 and 2011, respectively. | ||||||||||||||||||||||||||||
In addition, EOG's Canadian subsidiary maintains 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 $4 million, $3 million and $3 million for 2013, 2012 and 2011, respectively. | ||||||||||||||||||||||||||||
For the Canadian and Trinidadian defined benefit pension plans, the benefit obligation, fair value of plan assets and accrued benefit cost totaled $13 million, $11 million and $1 million, respectively, at December 31, 2013, and $14 million, $10 million and $2 million, respectively, at December 31, 2012. | ||||||||||||||||||||||||||||
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, 2013 | ||||||
Commitments and Contingencies [Abstract] | ' | |||||
Commitments and Contingencies | ' | |||||
7. Commitments and Contingencies | ||||||
Letters of Credit. 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. At December 31, 2012, EOG had standby letters of credit and guarantees outstanding totaling approximately $636 million, of which $150 million represented a guarantee of subsidiary indebtedness (see Note 2) and $486 million primarily represented guarantees of payment or performance obligations on behalf of subsidiaries. As of February 24, 2014, there were no demands for payment under these guarantees. | ||||||
Minimum Commitments. At December 31, 2013, 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, 2013, were as follows (in thousands): | ||||||
Total Minimum | ||||||
Commitments | ||||||
2014 | $ | 1,777,014 | ||||
2015 - 2016 | 1,808,827 | |||||
2017 - 2018 | 1,272,578 | |||||
2019 and beyond | 1,176,230 | |||||
$ | 6,034,649 | |||||
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 $191 million, $182 million and $149 million for 2013, 2012 and 2011, 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, 2013 | |||||||||||||
Net Income Per Share [Abstract] | ' | ||||||||||||
Net Income Per Share | ' | ||||||||||||
8. Net Income Per Share | |||||||||||||
The following table sets forth the computation of Net Income Per Share for the years ended December 31, 2013, 2012 and 2011 (in thousands, except per share data): | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Numerator for Basic and Diluted Earnings per Share - | |||||||||||||
Net Income | $ | 2,197,109 | $ | 570,279 | $ | 1,091,123 | |||||||
Denominator for Basic Earnings per Share - | |||||||||||||
Weighted Average Shares | 270,170 | 267,577 | 262,735 | ||||||||||
Potential Dilutive Common Shares - | |||||||||||||
Stock Options/SARs | 1,159 | 1,456 | 1,707 | ||||||||||
Restricted Stock/Units and Performance Units/Stock | 1,785 | 1,729 | 1,826 | ||||||||||
Denominator for Diluted Earnings per Share - | |||||||||||||
Adjusted Diluted Weighted Average Shares | 273,114 | 270,762 | 266,268 | ||||||||||
Net Income Per Share | |||||||||||||
Basic | $ | 8.13 | $ | 2.13 | $ | 4.15 | |||||||
Diluted | $ | 8.04 | $ | 2.11 | $ | 4.1 | |||||||
The diluted earnings per share calculation excludes stock options and SARs that were anti-dilutive. Shares underlying the excluded stock options and SARs totaled 0.3 million, 0.5 million and 0.4 million for the years ended December 31, 2013, 2012 and 2011, respectively. |
Supplemental_Cash_Flow_Informa
Supplemental Cash Flow Information | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Supplemental Cash Flow Information [Abstract] | ' | ||||||||||||
Supplemental Cash Flow Information | ' | ||||||||||||
9. Supplemental Cash Flow Information | |||||||||||||
Net cash paid for interest and income taxes was as follows for the years ended December 31, 2013, 2012 and 2011 (in thousands): | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Interest, Net of Capitalized Interest | $ | 235,854 | $ | 196,944 | $ | 186,718 | |||||||
Income Taxes, Net of Refunds Received | $ | 294,739 | $ | 360,006 | $ | 260,224 | |||||||
EOG's accrued capital expenditures at December 31, 2013, 2012 and 2011 were $731 million, $734 million and $663 million, respectively. | |||||||||||||
Non-cash investing activities for the year ended December 31, 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, 2013 | |||||||||||||||||||||
Business Segment Information [Abstract] | ' | ||||||||||||||||||||
Business Segment Information | ' | ||||||||||||||||||||
10. 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, China and Argentina. 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, 2013, 2012 and 2011 (in thousands): | |||||||||||||||||||||
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 (2) | 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 | ||||||||||||||||
United | Other | ||||||||||||||||||||
States | Canada | Trinidad | International (1) | Total | |||||||||||||||||
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 (3) | 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 | ||||||||||||||||
2011 | |||||||||||||||||||||
Crude Oil and Condensate | $ | 3,458,248 | $ | 264,895 | $ | 112,554 | $ | 2,587 | $ | 3,838,284 | |||||||||||
Natural Gas Liquids | 762,730 | 16,634 | - | - | 779,364 | ||||||||||||||||
Natural Gas | 1,593,964 | 178,324 | 442,589 | 25,663 | 2,240,540 | ||||||||||||||||
Gains on Mark-to-Market Commodity Derivative Contracts | 626,053 | - | - | - | 626,053 | ||||||||||||||||
Gathering, Processing and Marketing | 2,115,768 | - | 24 | - | 2,115,792 | ||||||||||||||||
Gains on Asset Dispositions, Net | 475,878 | 17,033 | (2 | ) | - | 492,909 | |||||||||||||||
Other, Net | 32,329 | 258 | 586 | - | 33,173 | ||||||||||||||||
Net Operating Revenues (3) | 9,064,970 | 477,144 | 555,751 | 28,250 | 10,126,115 | ||||||||||||||||
Depreciation, Depletion and Amortization | 2,131,706 | 260,084 | 107,141 | 17,450 | 2,516,381 | ||||||||||||||||
Operating Income (Loss) | 2,252,508 | (459,520 | ) | 383,992 | (63,671 | ) | 2,113,309 | ||||||||||||||
Interest Income | 436 | 342 | 101 | 140 | 1,019 | ||||||||||||||||
Other Income (Expense) | (6,480 | ) | (2,375 | ) | 18,755 | (4,066 | ) | 5,834 | |||||||||||||
Net Interest Expense | 214,360 | 23,085 | - | (27,082 | ) | 210,363 | |||||||||||||||
Income (Loss) Before Income Taxes | 2,032,104 | (484,638 | ) | 402,848 | (40,515 | ) | 1,909,799 | ||||||||||||||
Income Tax Provision (Benefit) | 732,362 | (125,474 | ) | 204,698 | 7,090 | 818,676 | |||||||||||||||
Additions to Oil and Gas Properties, Excluding Dry Hole Costs | 5,790,590 | 259,634 | 132,159 | 58,784 | 6,241,167 | ||||||||||||||||
Total Property, Plant and Equipment, Net | 18,711,774 | 1,760,066 | 627,794 | 189,190 | 21,288,824 | ||||||||||||||||
Total Assets | 21,313,158 | 2,131,949 | 1,085,664 | 308,026 | 24,838,797 | ||||||||||||||||
-1 | Other International primarily includes EOG's United Kingdom, China and Argentina operations. | ||||||||||||||||||||
-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 the United States segment in 2012 that totaled $2.2 billion of consolidated Net Operating Revenues. | ||||||||||||||||||||
-4 | EOG had no purchasers in 2011 whose sales totaled 10 percent or more of consolidated Net Operating Revenues. | ||||||||||||||||||||
Risk_Management_Activities
Risk Management Activities | 12 Months Ended | ||||||||||
Dec. 31, 2013 | |||||||||||
Risk Management Activities [Abstract] | ' | ||||||||||
Risk Management Activities | ' | ||||||||||
11. 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 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. In addition to financial transactions, from time to time EOG is a party to various physical commodity contracts for the sale of hydrocarbons that cover varying periods of time and have varying pricing provisions. These physical commodity contracts qualify for the normal purchases and normal sales exception and, therefore, are not subject to hedge accounting or mark-to-market accounting. The financial impact of physical commodity contracts is included in revenues at the time of settlement, which in turn affects average realized hydrocarbon prices. | |||||||||||
During 2013, 2012 and 2011, 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 2013, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $166 million, which included net cash received from settlements of commodity derivative contracts of $116 million. During 2012 and 2011, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $394 million and $626 million, respectively, which included net cash received from settlements of commodity derivative contracts of $711 million and $181 million, respectively. | |||||||||||
Commodity Derivative Contracts. Presented below is a comprehensive summary of EOG's crude oil derivative contracts at December 31, 2013, with notional volumes expressed in barrels per day (Bbld) and prices expressed in dollars per barrel ($/Bbl) | |||||||||||
Crude Oil Derivative Contracts | |||||||||||
Volume | Weighted | ||||||||||
(Bbld) | Average Price | ||||||||||
($/Bbl) | |||||||||||
2014 (1) | |||||||||||
Jan-14 | 156,000 | $ | 96.3 | ||||||||
February 1, 2014 through March 31, 2014 | 171,000 | 96.35 | |||||||||
April 1, 2014 through June 30, 2014 | 161,000 | 96.33 | |||||||||
July 1, 2014 through December 31, 2014 | 64,000 | 95.18 | |||||||||
-1 | EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional six-month and nine-month periods. Options covering a notional volume of 10,000 Bbld are exercisable on or about March 31, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 10,000 Bbld at an average price of $96.60 per barrel for each month during the period April 1, 2014 through December 31, 2014. Options covering a notional volume of 118,000 Bbld are exercisable on or about June 30, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 118,000 Bbld at an average price of $96.64 per barrel for each month during the period July 1, 2014 through December 31, 2014. Options covering a notional volume of 69,000 Bbld are exercisable on or about December 31, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 69,000 Bbld at an average price of $95.20 per barrel for each month during the period January 1, 2015 through June 30, 2015. | ||||||||||
Presented below is a comprehensive summary of EOG's natural gas derivative contracts at December 31, 2013, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu). | |||||||||||
Natural Gas Derivative Contracts | |||||||||||
Volume (MMBtud) | Weighted | ||||||||||
Average Price ($/MMBtu) | |||||||||||
2014 (1) | |||||||||||
January 2014 (closed) | 230,000 | $ | 4.51 | ||||||||
February 1, 2014 through December 31, 2014 | 205,000 | $ | 4.52 | ||||||||
-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 355,000 MMBtud at an average price of $4.63 per MMBtu for each month during the period February 1, 2014 through December 31, 2014. | ||||||||||
Foreign Currency Exchange Rate Derivative. EOG is party to a foreign currency aggregate swap with multiple banks to eliminate any exchange rate impacts that may result from the 4.75% Subsidiary Debt issued by one of EOG's Canadian subsidiaries. The foreign currency swap agreement expires on March 15, 2014. EOG accounts for the foreign currency swap transaction using the hedge accounting method. Changes in the fair value of the foreign currency swap do not impact Net Income. The after-tax net impact from the foreign currency swap for the years ended December 31, 2013 and 2012 resulted in increases in Other Comprehensive Income (Loss) (OCI) of $2 million and $1 million, respectively, and for the year ended December 31, 2011 resulted in a decrease in OCI of $1 million. | |||||||||||
Interest Rate Derivative. EOG is a 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 the Floating Rate Notes. The interest rate swap has a notional amount of $350 million. EOG accounts for the interest rate swap transaction using the hedge accounting method. Changes in the fair value of the interest rate swap do not impact Net Income. The after-tax impact from the interest rate swap resulted in an increase in OCI of $2 million for the year ended December 31, 2013, and reductions in OCI of $0.1 million and $3 million for the years ended December 31, 2012 and 2011, respectively. On February 3, 2014, the interest rate swap was settled in conjunction with the maturity and repayment of the Floating Rate Notes. | |||||||||||
The following table sets forth the amounts and classification of EOG's outstanding derivative financial instruments at December 31, 2013 and 2012, 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 | 2013 | 2012 | ||||||||
Asset Derivatives | |||||||||||
Crude oil and natural gas derivative contracts - | |||||||||||
Current portion | Assets from Price Risk Management Activities (1) | $ | 8 | $ | 166 | ||||||
Liability Derivatives | |||||||||||
Crude oil and natural gas derivative contracts - | |||||||||||
Current portion | Liabilities from Price Risk Management Activities (2) | $ | 127 | $ | 8 | ||||||
Noncurrent portion | Other Liabilities (3) | $ | - | $ | 13 | ||||||
Foreign currency swap - | |||||||||||
Current portion | Current Liabilities - Other | $ | 40 | $ | - | ||||||
Noncurrent portion | Other Liabilities | $ | - | $ | 55 | ||||||
Interest rate swap - | |||||||||||
Current portion | Current Liabilities - Other | $ | 1 | $ | - | ||||||
Noncurrent portion | Other Liabilities | $ | - | $ | 4 | ||||||
-1 | The current portion of Assets from Price Risk Management Activities consists of gross assets of $18 million, partially offset by gross liabilities of $10 million, at December 31, 2013 and gross assets of $271 million, partially offset by gross liabilities of $105 million, at December 31, 2012. | ||||||||||
-2 | The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $137 million, partially offset by gross assets of $10 million, at December 31, 2013 and gross liabilities of $113 million, partially offset by gross assets of $105 million, at December 31, 2012. | ||||||||||
-3 | The noncurrent portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $13 million at December 31, 2012. | ||||||||||
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 12). EOG evaluates its exposure to significant counterparties on an ongoing basis, including those arising from physical and financial transactions. In some instances, EOG requires collateral, parent guarantees or letters of credit to minimize credit risk. At December 31, 2013, EOG's net accounts receivable balance related to United States, Canada, Argentina and United Kingdom hydrocarbon sales include three receivable balances, each of which accounted for more that 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. At December 31, 2012, EOG's net accounts receivable balance related to United States, Canada and United Kingdom hydrocarbon sales include one receivable balance which constituted 26% of the total balance. The receivable was due from a United States petroleum marketing company. The related amount was collected during early 2013. In 2013 and 2012, all natural gas from EOG's Trinidad operations was sold to the National Gas Company of Trinidad and Tobago 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 12 for the aggregate fair value of all derivative instruments that were in a net liability position at December 31, 2013 and 2012. EOG had no collateral posted and held no collateral at December 31, 2013, and had no collateral posted and held $6 million of collateral at December 31, 2012. | |||||||||||
Substantially all of EOG's accounts receivable at December 31, 2013 and 2012 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, 2013, credit losses incurred on receivables by EOG have been immaterial. |
Fair_Value_Measurements
Fair Value Measurements | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Fair Value Measurements [Abstract] | ' | ||||||||||||||||
Fair Value Measurements | ' | ||||||||||||||||
12. 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, 2013 and 2012 (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, 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 | |||||||||||||
At December 31, 2012 | |||||||||||||||||
Financial Assets: | |||||||||||||||||
Crude Oil Swaps | $ | - | $ | 65 | $ | - | $ | 65 | |||||||||
Crude Oil Options/Swaptions | - | 36 | - | 36 | |||||||||||||
Natural Gas Options/Swaptions | - | 65 | - | 65 | |||||||||||||
Financial Liabilities: | |||||||||||||||||
Crude Oil Options/Swaptions | $ | - | $ | 8 | $ | - | $ | 8 | |||||||||
Natural Gas Options/Swaptions | - | 13 | - | 13 | |||||||||||||
Foreign Currency Rate Swap | - | 55 | - | 55 | |||||||||||||
Interest Rate Swap | - | 4 | - | 4 | |||||||||||||
The estimated fair value of crude oil and natural gas derivative contracts (including options/swaptions) and the interest rate swap contract (see Note 11) 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 14. | |||||||||||||||||
During 2013, proved 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. During 2012, proved and unproved oil and gas properties and other assets with a carrying amount of $1,524 million were written down to their fair value of $391 million, resulting in pretax impairment charges of $1,133 million. Included in the $1,133 million pretax impairment charges are $60 million of impairments of proved oil and gas properties and other property, plant and equipment for which EOG utilized accepted offers from third-party purchasers as the basis for determining fair value. Significant Level 3 assumptions 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 December 31, 2013 and 2012, EOG had outstanding $5,890 million and $6,290 million, respectively, aggregate principal amount of debt, which had estimated fair values of approximately $6,222 million and $7,032 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, 2013 | |
Accounting For Certain Long-Lived Assets [Abstract] | ' |
Accounting For Certain Long-Lived Assets | ' |
13. 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 2013, 2012 and 2011, such reviews indicated that unamortized capitalized costs of certain properties were higher than their expected undiscounted future cash flows due primarily 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 $73 million, $171 million and $403 million in the United States during 2013, 2012 and 2011, respectively, and $76 million, $872 million and $428 million in Canada during 2013, 2012 and 2011, respectively. Additionally, EOG recorded pretax charges of $14 million in Trinidad during 2013 and $9 million and $3 million in Other International during 2013 and 2011, respectively. 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 $115 million, $228 million and $197 million during 2013, 2012 and 2011, respectively. |
Asset_Retirement_Obligations
Asset Retirement Obligations | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
Asset Retirement Obligations [Abstract] | ' | ||||||||
Asset Retirement Obligations | ' | ||||||||
14. 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, 2013 and 2012 (in thousands): | |||||||||
2013 | 2012 | ||||||||
Carrying Amount at Beginning of Period | $ | 665,944 | $ | 587,084 | |||||
Liabilities Incurred | 103,284 | 107,378 | |||||||
Liabilities Settled (1) | (70,510 | ) | (77,384 | ) | |||||
Accretion | 35,180 | 30,020 | |||||||
Revisions | 38,552 | 15,287 | |||||||
Foreign Currency Translations | (10,552 | ) | 3,559 | ||||||
Carrying Amount at End of Period | $ | 761,898 | $ | 665,944 | |||||
Current Portion | $ | 43,857 | $ | 30,127 | |||||
Noncurrent Portion | $ | 718,041 | $ | 635,817 | |||||
(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, 2013 | ||||||||||||||
Exploratory Well Costs [Abstract] | ' | |||||||||||||
Exploratory Well Costs | ' | |||||||||||||
15. Exploratory Well Costs | ||||||||||||||
EOG's net changes in capitalized exploratory well costs for the years ended December 31, 2013, 2012 and 2011 are presented below (in thousands): | ||||||||||||||
2013 | 2012 | 2011 | ||||||||||||
Balance at January 1 | $ | 49,116 | $ | 61,111 | $ | 99,801 | ||||||||
Additions Pending the Determination of Proved Reserves | 52,099 | 73,332 | 31,271 | |||||||||||
Reclassifications to Proved Properties | (54,505 | ) | (69,462 | ) | (29,227 | ) | ||||||||
Costs Charged to Expense (1) | (35,859 | ) | (17,115 | ) | (42,178 | ) | ||||||||
Foreign Currency Translations | (1,640 | ) | 1,250 | 1,444 | ||||||||||
Balance at December 31 | $ | 9,211 | $ | 49,116 | $ | 61,111 | ||||||||
(1) Includes capitalized exploratory well costs charged to either dry hole costs or impairments. | ||||||||||||||
The following table provides an aging of capitalized exploratory well costs at December 31, 2013, 2012 and 2011 (in thousands, except well count): | ||||||||||||||
2013 | 2012 | 2011 | ||||||||||||
Capitalized exploratory well costs that have been capitalized for a period less than one year | $ | 9,211 | $ | 28,319 | $ | 17,009 | ||||||||
Capitalized exploratory well costs that have been capitalized for a period greater than one year | - | 20,797 | 44,102 | (2) | ||||||||||
(1) | ||||||||||||||
Total | $ | 9,211 | $ | 49,116 | $ | 61,111 | ||||||||
Number of exploratory wells that have been capitalized for a period greater than one year | - | 1 | 4 | |||||||||||
-1 | Consists of costs related to an outside operated, offshore Central North Sea natural gas project in the United Kingdom (U.K.). | |||||||||||||
-2 | Consists of costs related to an outside operated, offshore Central North Sea project in the U.K. ($20 million), an East Irish Sea project in the U.K. ($9 million), a project in the Sichuan Basin, Sichuan Province, China ($9 million), and a shale project in British Columbia, Canada ($6 million). |
Divestitures
Divestitures | 12 Months Ended |
Dec. 31, 2013 | |
Divestitures [Abstract] | ' |
Divestitures | ' |
16. Divestitures | |
During 2013, EOG received proceeds of approximately $761 million primarily from the sales of its entire interest in the planned Kitimat liquefied natural gas export terminal (Kitimat LNG Terminal) and PTP, 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. During 2011, EOG received proceeds of approximately $1.4 billion from sales of producing properties and acreage and certain midstream assets, primarily in the Rocky Mountain area and Texas, and the sale of a portion of EOG's interest in the Kitimat LNG Terminal and PTP. | |
In December 2012, EOGRC signed a purchase and sale agreement for the sale of its entire interest in the Kitimat LNG Terminal and PTP, as well as undeveloped net acres in the Horn River Basin, to Chevron Canada Limited. The transaction closed in February 2013. Additionally in 2012, EOG signed purchase and sale agreements for the sale of certain properties in the United States. At December 31, 2012, the book value of these assets held for sale and the related liabilities were $310 million and $31 million, respectively. | |
Oil_and_Gas_Exploration_and_Pr
Oil and Gas Exploration and Production Industries Disclosures | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | ' | ||||||||||||||||||||
Oil and Gas Exploration and Production Industries Disclosures | ' | ||||||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||||||
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS | |||||||||||||||||||||
(In Thousands, Except Per Share Data Unless Otherwise Indicated) | |||||||||||||||||||||
(Unaudited) | |||||||||||||||||||||
Oil and Gas Producing Activities | |||||||||||||||||||||
The following disclosures are made in accordance with Financial Accounting Standards Board Accounting Standards Update No. 2010-03 "Oil and Gas Reserve Estimates and Disclosures" and the United States Securities and Exchange Commission's (SEC) final rule on "Modernization of Oil and Gas Reporting." | |||||||||||||||||||||
Oil and Gas Reserves. Users of this information should be aware that the process of estimating quantities of "proved," "proved developed" and "proved undeveloped" crude oil, natural gas liquids (NGLs) and natural gas reserves is complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. Although reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. See ITEM 1A. Risk Factors. | |||||||||||||||||||||
Proved reserves represent estimated quantities of crude oil, NGLs and natural gas that geoscience and engineering data can 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, 2013. Under EOG's current drilling and development plan, 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. | |||||||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||||||
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | |||||||||||||||||||||
In making estimates of PUDs, EOG's technical staff, including engineers and geoscientists, perform detailed technical analysis of each potential drilling location within its entire 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 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. | |||||||||||||||||||||
Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices, production volumes and the length of wells, both vertical and horizontal. Canadian reserves, as presented on a net basis, assume prices and legislated future royalty rates and EOG's estimate of future production volumes. Similarly, 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 Canadian and Trinidadian reserves to be materially different from that presented. | |||||||||||||||||||||
Estimates of proved reserves at December 31, 2013, 2012 and 2011 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 seven professionals, all of whom hold, at a minimum, bachelor's degrees in engineering, and two of whom are Registered Professional Engineers. The Manager, Engineering and Acquisitions is the manager of this department and is the primary technical person responsible for this process. The Manager, Engineering and Acquisitions holds a Bachelor of Science degree in Petroleum Engineering, has 28 years of experience in reserve evaluations and is a Registered Professional Engineer in the State of Texas. | |||||||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||||||
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | |||||||||||||||||||||
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, NGLs 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, 2013, 2012 and 2011 covered producing areas containing 82%, 87% and 85%, 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 31, 2014, 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, 2013, is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date. | |||||||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||||||
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | |||||||||||||||||||||
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, 2013, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2013, 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, 2010 | 355,457 | 25,636 | 4,731 | 98 | 385,922 | ||||||||||||||||
Revisions of previous estimates | (21,188 | ) | (4,611 | ) | 18 | 25 | (25,756 | ) | |||||||||||||
Purchases in place | 9 | - | - | - | 9 | ||||||||||||||||
Extensions, discoveries and other additions | 202,552 | 449 | - | - | 203,001 | ||||||||||||||||
Sales in place | (4,301 | ) | - | - | - | (4,301 | ) | ||||||||||||||
Production | (37,233 | ) | (2,882 | ) | (1,242 | ) | (25 | ) | (41,382 | ) | |||||||||||
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 | ||||||||||||||||
Natural Gas Liquids (MBbl) (2) | |||||||||||||||||||||
Net proved reserves at December 31, 2010 | 150,434 | 1,475 | - | - | 151,909 | ||||||||||||||||
Revisions of previous estimates | 35,999 | 43 | - | - | 36,042 | ||||||||||||||||
Purchases in place | 17 | - | - | - | 17 | ||||||||||||||||
Extensions, discoveries and other additions | 65,288 | - | - | - | 65,288 | ||||||||||||||||
Sales in place | (10,008 | ) | - | - | - | (10,008 | ) | ||||||||||||||
Production | (15,144 | ) | (316 | ) | - | - | (15,460 | ) | |||||||||||||
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 | ||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||||||
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | |||||||||||||||||||||
United | Canada | Trinidad | Other | Total | |||||||||||||||||
States | International (1) | ||||||||||||||||||||
Natural Gas (Bcf) (3) | |||||||||||||||||||||
Net proved reserves at December 31, 2010 | 6,491.50 | 1,133.80 | 827.6 | 17.3 | 8,470.20 | ||||||||||||||||
Revisions of previous estimates | (344.0 | ) | (49.8 | ) | (24.2 | ) | 1.3 | (416.7 | ) | ||||||||||||
Purchases in place | 3 | - | - | - | 3 | ||||||||||||||||
Extensions, discoveries and other additions | 634.6 | - | 74.7 | 4.5 | 713.8 | ||||||||||||||||
Sales in place | (323.6 | ) | - | - | - | (323.6 | ) | ||||||||||||||
Production | (415.7 | ) | (48.1 | ) | (127.4 | ) | (4.6 | ) | (595.8 | ) | |||||||||||
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 | ||||||||||||||||
Oil Equivalents (MBoe) (2) | |||||||||||||||||||||
Net proved reserves at December 31, 2010 | 1,587,806 | 216,084 | 142,669 | 2,976 | 1,949,535 | ||||||||||||||||
Revisions of previous estimates | (42,526 | ) | (12,865 | ) | (4,011 | ) | 239 | (59,163 | ) | ||||||||||||
Purchases in place | 521 | - | - | - | 521 | ||||||||||||||||
Extensions, discoveries and other additions | 373,602 | 448 | 12,455 | 750 | 387,255 | ||||||||||||||||
Sales in place | (68,247 | ) | - | - | - | (68,247 | ) | ||||||||||||||
Production | (121,648 | ) | (11,219 | ) | (22,484 | ) | (787 | ) | (156,138 | ) | |||||||||||
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 | ||||||||||||||||
-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, NGLs and natural gas. Oil equivalents are determined using the ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. | ||||||||||||||||||||
-3 | Billion cubic feet. | ||||||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||||||
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | |||||||||||||||||||||
During 2013, EOG added 399 million barrels of oil equivalent (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 NGLs 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. Revisions of previous estimates of positive 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 NGLs 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. Revisions of previous estimates of negative 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. | |||||||||||||||||||||
During 2011, EOG added 387 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Eagle Ford, Barnett Combo and Bakken shale plays. Approximately 69% of the 2011 reserve additions were crude oil and condensate and NGLs and over 96% were in the United States. Sales in place of 68 MMBoe were primarily related to the disposition of certain producing natural gas assets in East Texas, the Rocky Mountain area and other producing basins in the United States. Revisions of previous estimates of negative 59 MMBoe for 2011 included a negative revision of 16 MMBoe primarily due to a decrease in the average natural gas price used in the December 31, 2011 reserves estimation as compared to the price used in the prior year estimate. Revisions other than price resulted from negative revisions for certain crude oil and natural gas properties in the United States, Canada and Trinidad. | |||||||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||||||
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | |||||||||||||||||||||
United | Canada | Trinidad | Other | Total | |||||||||||||||||
States | International (1) | ||||||||||||||||||||
NET PROVED DEVELOPED RESERVES | |||||||||||||||||||||
Crude Oil (MBbl) | |||||||||||||||||||||
31-Dec-10 | 161,907 | 11,283 | 3,852 | 98 | 177,140 | ||||||||||||||||
31-Dec-11 | 213,872 | 8,128 | 2,657 | 98 | 224,755 | ||||||||||||||||
31-Dec-12 | 281,167 | 6,853 | 2,377 | 253 | 290,650 | ||||||||||||||||
31-Dec-13 | 382,517 | 6,871 | 1,505 | 163 | 391,056 | ||||||||||||||||
Natural Gas Liquids (MBbl) | |||||||||||||||||||||
31-Dec-10 | 91,401 | 1,475 | - | - | 92,876 | ||||||||||||||||
31-Dec-11 | 124,271 | 1,092 | - | - | 125,363 | ||||||||||||||||
31-Dec-12 | 161,482 | 1,111 | - | - | 162,593 | ||||||||||||||||
31-Dec-13 | 199,964 | 896 | - | - | 200,860 | ||||||||||||||||
Natural Gas (Bcf) | |||||||||||||||||||||
31-Dec-10 | 3,519.70 | 401.6 | 519.2 | 17.3 | 4,457.80 | ||||||||||||||||
31-Dec-11 | 3,235.00 | 295.8 | 606.3 | 18.5 | 4,155.60 | ||||||||||||||||
31-Dec-12 | 2,387.50 | 98.3 | 476.7 | 17 | 2,979.50 | ||||||||||||||||
31-Dec-13 | 2,597.30 | 102.1 | 494.6 | 19.4 | 3,213.40 | ||||||||||||||||
Oil Equivalents (MBoe) | |||||||||||||||||||||
31-Dec-10 | 839,928 | 79,701 | 90,382 | 2,976 | 1,012,987 | ||||||||||||||||
31-Dec-11 | 877,301 | 58,524 | 103,710 | 3,178 | 1,042,713 | ||||||||||||||||
31-Dec-12 | 840,564 | 24,348 | 81,826 | 3,081 | 949,819 | ||||||||||||||||
31-Dec-13 | 1,015,359 | 24,782 | 83,933 | 3,402 | 1,127,476 | ||||||||||||||||
NET PROVED UNDEVELOPED RESERVES | |||||||||||||||||||||
Crude Oil (MBbl) | |||||||||||||||||||||
31-Dec-10 | 193,550 | 14,353 | 879 | - | 208,782 | ||||||||||||||||
31-Dec-11 | 281,424 | 10,464 | 850 | - | 292,738 | ||||||||||||||||
31-Dec-12 | 389,862 | 11,010 | 651 | 8,645 | 410,168 | ||||||||||||||||
31-Dec-13 | 497,532 | 3,249 | 85 | 8,618 | 509,484 | ||||||||||||||||
Natural Gas Liquids (MBbl) | |||||||||||||||||||||
31-Dec-10 | 59,033 | - | - | - | 59,033 | ||||||||||||||||
31-Dec-11 | 102,315 | 110 | - | - | 102,425 | ||||||||||||||||
31-Dec-12 | 156,924 | 446 | - | - | 157,370 | ||||||||||||||||
31-Dec-13 | 176,038 | 308 | - | - | 176,346 | ||||||||||||||||
Natural Gas (Bcf) | |||||||||||||||||||||
31-Dec-10 | 2,971.80 | 732.2 | 308.4 | - | 4,012.40 | ||||||||||||||||
31-Dec-11 | 2,810.80 | 740.1 | 144.4 | - | 3,695.30 | ||||||||||||||||
31-Dec-12 | 1,648.50 | - | 111.5 | - | 1,760.00 | ||||||||||||||||
31-Dec-13 | 1,801.40 | - | 26.1 | 3.9 | 1,831.40 | ||||||||||||||||
Oil Equivalents (MBoe) | |||||||||||||||||||||
31-Dec-10 | 747,878 | 136,383 | 52,287 | - | 936,548 | ||||||||||||||||
31-Dec-11 | 852,207 | 133,924 | 24,919 | - | 1,011,050 | ||||||||||||||||
31-Dec-12 | 821,544 | 11,456 | 19,234 | 8,645 | 860,879 | ||||||||||||||||
31-Dec-13 | 973,807 | 3,557 | 4,431 | 9,272 | 991,067 | ||||||||||||||||
-1 | Other International includes EOG's United Kingdom, China and Argentina operations. | ||||||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||||||
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | |||||||||||||||||||||
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 (see discussion of technology employed on page F-36 of this Annual Report on Form 10-K), 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 NGLs. 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 NGLs. 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. | |||||||||||||||||||||
For the twelve-month period ended December 31, 2011, total PUDs increased by 75 MMBoe to 1,011 MMBoe. EOG added approximately 36 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion. Based on the technology employed by EOG to identify and record PUDs, EOG added 199 MMBoe. The PUD additions were primarily in the Eagle Ford and Barnett Combo shale plays, and over 78% of the additions were crude oil and condensate and NGLs. During 2011, EOG drilled and transferred 144 MMBoe of PUDs to proved developed reserves at a total capital cost of $1,619 million. Revisions of PUDs totaled negative 7 MMBoe, primarily due to removal of certain natural gas PUDs from the five-year drilling plan. During 2011, EOG sold 9 MMBoe of PUDs. | |||||||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||||||
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | |||||||||||||||||||||
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, 2013 and 2012: | |||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||
Proved properties | $ | 41,377,303 | $ | 36,872,434 | |||||||||||||||||
Unproved properties | 1,444,500 | 1,253,864 | |||||||||||||||||||
Total | 42,821,803 | 38,126,298 | |||||||||||||||||||
Accumulated depreciation, depletion and amortization | (18,880,611 | ) | (16,849,068 | ) | |||||||||||||||||
Net capitalized costs | $ | 23,941,192 | $ | 21,277,230 | |||||||||||||||||
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. | |||||||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||||||
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | |||||||||||||||||||||
The following table sets forth costs incurred related to EOG's oil and gas activities for the years ended December 31, 2013, 2012 and 2011: | |||||||||||||||||||||
United | Canada | Trinidad | Other | Total | |||||||||||||||||
States | International (1) | ||||||||||||||||||||
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 (2) | 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 (3) | 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 | |||||||||||
2011 | |||||||||||||||||||||
Acquisition Costs of Properties | |||||||||||||||||||||
Unproved | $ | 295,160 | $ | 6,216 | $ | - | $ | (604 | ) | $ | 300,772 | ||||||||||
Proved | 4,219 | 28 | - | - | 4,247 | ||||||||||||||||
Subtotal | 299,379 | 6,244 | - | (604 | ) | 305,019 | |||||||||||||||
Exploration Costs | 311,369 | 31,472 | 2,549 | 18,164 | 363,554 | ||||||||||||||||
Development Costs (4) | 5,410,378 | 302,564 | 138,905 | 78,744 | 5,930,591 | ||||||||||||||||
Total | $ | 6,021,126 | $ | 340,280 | $ | 141,454 | $ | 96,304 | $ | 6,599,164 | |||||||||||
-1 | Other International primarily consists of EOG's United Kingdom, China and Argentina operations. | ||||||||||||||||||||
-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 | Includes Asset Retirement Costs of $52 million, $70 million, $7 million and $4 million for the United States, Canada, Trinidad and Other International, respectively. Excludes other property, plant and equipment. | ||||||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||||||
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | |||||||||||||||||||||
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, 2013, 2012 and 2011: | |||||||||||||||||||||
United | Canada | Trinidad | Other | Total | |||||||||||||||||
States | International (2) | ||||||||||||||||||||
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 | |||||||||
2011 | |||||||||||||||||||||
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues | $ | 5,814,942 | $ | 459,853 | $ | 555,143 | $ | 28,250 | $ | 6,858,188 | |||||||||||
Other | 32,329 | 258 | 586 | - | 33,173 | ||||||||||||||||
Total | 5,847,271 | 460,111 | 555,729 | 28,250 | 6,891,361 | ||||||||||||||||
Exploration Costs | 148,199 | 10,479 | 2,520 | 10,460 | 171,658 | ||||||||||||||||
Dry Hole Costs | 30,521 | 432 | - | 22,277 | 53,230 | ||||||||||||||||
Transportation Costs | 421,060 | 5,969 | 1,620 | 1,673 | 430,322 | ||||||||||||||||
Production Costs | 1,096,955 | 174,973 | 49,318 | 10,964 | 1,332,210 | ||||||||||||||||
Impairments | 575,976 | 452,103 | - | 2,958 | 1,031,037 | ||||||||||||||||
Depreciation, Depletion and Amortization | 2,011,080 | 258,772 | 106,802 | 17,160 | 2,393,814 | ||||||||||||||||
Income (Loss) Before Income Taxes | 1,563,480 | (442,617 | ) | 395,469 | (37,242 | ) | 1,479,090 | ||||||||||||||
Income Tax Provision (Benefit) | 569,153 | (121,044 | ) | 202,815 | (13,056 | ) | 637,868 | ||||||||||||||
Results of Operations | $ | 994,327 | $ | (321,573 | ) | $ | 192,654 | $ | (24,186 | ) | $ | 841,222 | |||||||||
-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, 2013. | ||||||||||||||||||||
-2 | Other International primarily consists of EOG's United Kingdom, China and Argentina operations. | ||||||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||||||
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | |||||||||||||||||||||
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, 2013, 2012 and 2011: | |||||||||||||||||||||
United | Canada | Trinidad | Other | Composite | |||||||||||||||||
States | International (1) | ||||||||||||||||||||
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 | |||||||||||
Year Ended December 31, 2011 | $ | 6.19 | $ | 14.26 | $ | 0.78 | $ | 13.82 | $ | 6.03 | |||||||||||
(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, NGLs 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 2013, 2012 and 2011. 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, NGLs 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. | |||||||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||||||
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | |||||||||||||||||||||
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, 2013, 2012 and 2011: | |||||||||||||||||||||
United | Canada | Trinidad | Other | Total | |||||||||||||||||
States | International (1) | ||||||||||||||||||||
2013 | |||||||||||||||||||||
Future cash inflows (2) | $ | 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 (3) | $ | 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 | |||||||||||
2011 | |||||||||||||||||||||
Future cash inflows (4) | $ | 84,518,638 | $ | 5,056,501 | $ | 2,851,545 | $ | 103,853 | $ | 92,530,537 | |||||||||||
Future production costs | (33,294,343 | ) | (2,315,110 | ) | (388,199 | ) | (62,938 | ) | (36,060,590 | ) | |||||||||||
Future development costs | (13,811,449 | ) | (1,566,917 | ) | (149,884 | ) | (331 | ) | (15,528,581 | ) | |||||||||||
Future income taxes | (10,539,182 | ) | (81,590 | ) | (794,856 | ) | (2,457 | ) | (11,418,085 | ) | |||||||||||
Future net cash flows | 26,873,664 | 1,092,884 | 1,518,606 | 38,127 | 29,523,281 | ||||||||||||||||
Discount to present value at 10% annual rate | (12,498,010 | ) | (456,537 | ) | (334,399 | ) | (9,054 | ) | (13,298,000 | ) | |||||||||||
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves | $ | 14,375,654 | $ | 636,347 | $ | 1,184,207 | $ | 29,073 | $ | 16,225,281 | |||||||||||
-1 | Other International includes EOG's United Kingdom, China and Argentina operations. | ||||||||||||||||||||
-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 NGLs 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 NGLs 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 | Estimated crude oil prices used to calculate 2011 future cash inflows for the United States, Canada, Trinidad and Other International were $97.75, $90.70, $92.50 and $102.86, respectively. Estimated NGLs prices used to calculate 2011 future cash inflows for the United States and Canada were $51.77 and $46.97, respectively. Estimated natural gas prices used to calculate 2011 future cash inflows for the United States, Canada, Trinidad and Other International were $4.03, $3.28, $3.37 and $5.07, respectively. | ||||||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||||||
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | |||||||||||||||||||||
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, 2013: | |||||||||||||||||||||
United | Canada | Trinidad | Other | Total | |||||||||||||||||
States | International | ||||||||||||||||||||
31-Dec-10 | 10,628,924 | 746,235 | 988,866 | 27,799 | 12,391,824 | ||||||||||||||||
Sales and transfers of oil and gas produced, net of production costs | (4,296,926 | ) | (278,910 | ) | (504,205 | ) | (15,614 | ) | (5,095,655 | ) | |||||||||||
Net changes in prices and production costs | 716,682 | (57,545 | ) | 331,196 | 3,328 | 993,661 | |||||||||||||||
Extensions, discoveries, additions and improved recovery, net of related costs | 6,223,552 | 22,591 | 102,548 | - | 6,348,691 | ||||||||||||||||
Development costs incurred | 1,422,500 | 48,200 | 74,800 | - | 1,545,500 | ||||||||||||||||
Revisions of estimated development cost | (210,919 | ) | 64,001 | (14,074 | ) | 2 | (160,990 | ) | |||||||||||||
Revisions of previous quantity estimates | (482,496 | ) | (70,718 | ) | (56,884 | ) | 801 | (609,297 | ) | ||||||||||||
Accretion of discount | 1,352,740 | 62,725 | 159,715 | 2,782 | 1,577,962 | ||||||||||||||||
Net change in income taxes | (1,049,641 | ) | (118,988 | ) | 9,511 | 13 | (1,159,105 | ) | |||||||||||||
Purchases of reserves in place | 5,241 | - | - | - | 5,241 | ||||||||||||||||
Sales of reserves in place | (658,468 | ) | - | - | - | (658,468 | ) | ||||||||||||||
Changes in timing and other | 724,465 | 218,756 | 92,734 | 9,962 | 1,045,917 | ||||||||||||||||
31-Dec-11 | 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 | ) | |||||||||||
31-Dec-12 | 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 | |||||||||||||||
31-Dec-13 | $ | 19,576,901 | $ | 331,654 | $ | 876,640 | $ | 548,237 | $ | 21,333,432 | |||||||||||
Unaudited_Quarterly_Financial_
Unaudited Quarterly Financial Information | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Unaudited Quarterly Financial Information [Abstract] | ' | ||||||||||||||||
Unaudited Quarterly Financial Information [Text Block] | ' | ||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | |||||||||||||||||
Unaudited Quarterly Financial Information | |||||||||||||||||
(In Thousands, Except Per Share Data) | |||||||||||||||||
Quarter Ended | 31-Mar | 30-Jun | 30-Sep | 31-Dec | |||||||||||||
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 | $ | 1.84 | $ | 2.44 | $ | 1.71 | $ | 2.14 | |||||||||
Diluted | $ | 1.82 | $ | 2.42 | $ | 1.69 | $ | 2.12 | |||||||||
Average Number of Common Shares | |||||||||||||||||
Basic | 269,358 | 270,016 | 270,471 | 270,929 | |||||||||||||
Diluted | 272,263 | 272,739 | 273,576 | 273,983 | |||||||||||||
2012 | |||||||||||||||||
Net Operating Revenues | $ | 2,806,651 | $ | 2,909,319 | $ | 2,954,855 | $ | 3,011,811 | |||||||||
Operating Income (Loss) | $ | 559,772 | $ | 692,339 | $ | 605,747 | $ | (378,061 | ) | ||||||||
Income (Loss) Before Income Taxes | $ | 520,134 | $ | 646,239 | $ | 560,189 | $ | (445,822 | ) | ||||||||
Income Tax Provision | 196,125 | 250,461 | 204,698 | 59,177 | |||||||||||||
Net Income (Loss) (2) | $ | 324,009 | $ | 395,778 | $ | 355,491 | $ | (504,999 | ) | ||||||||
Net Income (Loss) Per Share (1) | |||||||||||||||||
Basic | $ | 1.22 | $ | 1.48 | $ | 1.33 | $ | (1.88 | ) | ||||||||
Diluted | $ | 1.2 | $ | 1.47 | $ | 1.31 | $ | (1.88 | ) | ||||||||
Average Number of Common Shares | |||||||||||||||||
Basic | 266,674 | 266,874 | 267,941 | 268,941 | |||||||||||||
Diluted | 270,242 | 269,985 | 270,982 | 268,941 | |||||||||||||
-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. | ||||||||||||||||
-2 | Fourth quarter 2012 results include the impact of pretax impairments of $1,020 million, primarily related to proved and unproved natural gas properties in Canada and the United States as well as an additional income tax provision of $135 million related to valuation allowances recorded to reduce the value of Canadian deferred tax assets. | ||||||||||||||||
Summary_of_Significant_Account1
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2013 | |
Summary of Significant Accounting Policies [Abstract] | ' |
Principles of Consolidation | ' |
Principles of Consolidation. The consolidated financial statements of EOG Resources, Inc. (EOG) include the accounts of all domestic and foreign subsidiaries. Investments in unconsolidated affiliates, in which EOG is able to exercise significant influence, are accounted for using the equity method. All intercompany accounts and transactions have been eliminated. | |
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. | |
Financial Instruments | ' |
Financial Instruments. EOG's financial instruments consist of cash and cash equivalents, commodity derivative contracts, accounts receivable, accounts payable and current and long-term debt, along with associated foreign currency and interest rate swaps. The carrying values of cash and cash equivalents, commodity derivative contracts, accounts receivable, foreign currency and interest rate swaps and accounts payable approximate fair value (see Notes 2 and 11). | |
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 15). Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. | |
Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account. | |
Oil and gas properties are grouped in accordance with the Extractive Industries - Oil and Gas Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC). The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. | |
Amortization rates are updated quarterly to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions and/or property dispositions and 4) impairments. | |
When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the asset. If the expected undiscounted future cash flows, based on EOG's estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach described in the Fair Value Measurement Topic of the ASC. If applicable, EOG utilizes accepted bids as the basis for determining fair value. | |
Inventories, consisting primarily of tubular goods, materials for completion operations and well equipment held for use in the exploration for, and development and production of, crude oil and natural gas reserves, are carried at cost with adjustments made, as appropriate, to recognize any reductions in value. | |
Arrangements for sales of crude oil and condensate, natural gas liquids (NGLs) and natural gas are evidenced by signed contracts with determinable market prices, and revenues are recorded when production is delivered. A significant majority of 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, NGLs 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, 2013, 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 is reflected as cash flows from operating activities. EOG is party to a foreign currency swap transaction and an interest rate swap transaction. 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 11. | |
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 5). | |
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. | |
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 8). | |
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 6). | |
Recently Issued Accounting Standards and Developments | ' |
Recently Issued Accounting Standards. In February 2013, the FASB issued Accounting Standards Update (ASU) 2013-02 "Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income" (ASU 2013-02). ASU 2013-02 amends ASU 2011-05 and requires that entities disclose additional information about amounts reclassified out of Accumulated Other Comprehensive Income (AOCI) by component. Significant amounts reclassified out of AOCI are required to be presented either on the face of the Consolidated Statements of Income and Comprehensive Income or in the notes to the financial statements. The requirements of ASU 2013-02 are effective for fiscal years and interim periods in those years beginning after December 15, 2012. The adoption of ASU 2013-02 did not have a material impact on EOG's financial statements. No significant amounts were reclassified out of AOCI during the years ended December 31, 2013, 2012 and 2011. | |
In July 2013, the FASB issued ASU 2013-11 "Presentation of an Unrecognized Tax Benefit when a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists" (ASU 2013-11). ASU 2013-11 includes specific guidance on financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The requirements of ASU 2013-11 are effective for fiscal years and interim periods in those years beginning after December 15, 2013. Early adoption is permitted. EOG does not expect a material impact on its financial statements from the adoption of ASU 2013-11. | |
LongTerm_Debt_Tables
Long-Term Debt (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
Long-Term Debt [Abstract] | ' | ||||||||
Long-Term Debt | ' | ||||||||
Long-Term Debt at December 31, 2013 and 2012 consisted of the following (in thousands): | |||||||||
2013 | 2012 | ||||||||
6.125% Senior Notes due 2013 | $ | - | $ | 400,000 | |||||
Floating Rate Senior Notes due 2014 | 350,000 | 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 | |||||||
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 | 150,000 | |||||||
Total Long-Term Debt | 5,890,000 | 6,290,000 | |||||||
Capital Lease Obligation | 57,187 | 62,968 | |||||||
Less: Current Portion of Long-Term Debt | 6,579 | 406,579 | |||||||
Unamortized Debt Discount | 33,966 | 40,787 | |||||||
Total Long-Term Debt, Net | $ | 5,906,642 | $ | 5,905,602 |
Stockholders_Equity_Tables
Stockholder's Equity (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Stockholders' Equity [Abstract] | ' | ||||||||||||
Common stock activity | ' | ||||||||||||
The following summarizes Common Stock activity for each of the years ended December 31, 2011, 2012 and 2013 (in thousands): | |||||||||||||
Common Shares | |||||||||||||
Issued | Treasury | Outstanding | |||||||||||
Balance at December 31, 2010 | 254,223 | (146 | ) | 254,077 | |||||||||
Common Stock Issued Under Stock-Based Compensation Plans | 1,395 | - | 1,395 | ||||||||||
Treasury Stock Purchased (1) | - | (267 | ) | (267 | ) | ||||||||
Common Stock Issued Under Employee Stock Purchase Plan | 135 | - | 135 | ||||||||||
Treasury Stock Issued Under Stock-Based Compensation Plans | - | 109 | 109 | ||||||||||
Common Stock Sold | 13,570 | - | 13,570 | ||||||||||
Balance at December 31, 2011 | 269,323 | (304 | ) | 269,019 | |||||||||
Common Stock Issued Under Stock-Based Compensation Plans | 2,471 | - | 2,471 | ||||||||||
Treasury Stock Purchased (1) | - | (575 | ) | (575 | ) | ||||||||
Common Stock Issued Under Employee Stock Purchase Plan | 164 | - | 164 | ||||||||||
Treasury Stock Issued Under Stock-Based Compensation Plans | - | 553 | 553 | ||||||||||
Balance at December 31, 2012 | 271,958 | (326 | ) | 271,632 | |||||||||
Common Stock Issued Under Stock-Based Compensation Plans | 1,103 | - | 1,103 | ||||||||||
Treasury Stock Purchased (1) | - | (427 | ) | (427 | ) | ||||||||
Common Stock Issued Under Employee Stock Purchase Plan | 128 | - | 128 | ||||||||||
Treasury Stock Issued Under Stock-Based Compensation Plans | - | 650 | 650 | ||||||||||
Balance at December 31, 2013 | 273,189 | (103 | ) | 273,086 | |||||||||
-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. | ||||||||||||
Income_Taxes_Tables
Income Taxes (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Income Taxes [Abstract] | ' | ||||||||||||
Deferred Income Tax Liabilities, Net Table | ' | ||||||||||||
The principal components of EOG's net deferred income tax liabilities at December 31, 2013 and 2012 were as follows (in thousands): | |||||||||||||
2013 | 2012 | ||||||||||||
Current Deferred Income Tax Assets (Liabilities) | |||||||||||||
Commodity Hedging Contracts | $ | 29,582 | $ | (57,754 | ) | ||||||||
Deferred Compensation Plans | 42,296 | 35,715 | |||||||||||
Net Operating Loss | 96,616 | - | |||||||||||
Alternative Minimum Tax Credit Carryforward | 72,297 | - | |||||||||||
Timing Differences Associated with Different Year-ends in Foreign Jurisdictions | - | (2,762 | ) | ||||||||||
Other | 3,815 | 1,963 | |||||||||||
Total Net Current Deferred Income Tax Assets (Liabilities) | $ | 244,606 | $ | (22,838 | ) | ||||||||
Noncurrent Deferred Income Tax Assets (Liabilities) | |||||||||||||
Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Over (Under) Book Depreciation, Depletion and Amortization | $ | (112,346 | ) | $ | 25,592 | ||||||||
Foreign Net Operating Loss | 369,257 | 164,829 | |||||||||||
Foreign Other | 4,179 | 1,607 | |||||||||||
Foreign Valuation Allowances | (183,122 | ) | (134,792 | ) | |||||||||
Total Net Noncurrent Deferred Income Tax Assets | $ | 77,968 | $ | 57,236 | |||||||||
Noncurrent Deferred Income Tax (Assets) Liabilities | |||||||||||||
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization | $ | 6,287,541 | $ | 5,300,115 | |||||||||
Non-Producing Leasehold Costs | (50,581 | ) | (61,512 | ) | |||||||||
Seismic Costs Capitalized for Tax | (136,964 | ) | (125,026 | ) | |||||||||
Equity Awards | (122,665 | ) | (116,666 | ) | |||||||||
Capitalized Interest | 101,006 | 102,677 | |||||||||||
Net Operating Loss | - | (308,154 | ) | ||||||||||
Alternative Minimum Tax Credit Carryforward | (557,352 | ) | (476,505 | ) | |||||||||
Other | 1,369 | 12,467 | |||||||||||
Total Net Noncurrent Deferred Income Tax Liabilities | $ | 5,522,354 | $ | 4,327,396 | |||||||||
Total Net Deferred Income Tax Liabilities | $ | 5,199,780 | $ | 4,292,998 | |||||||||
The components of Income Before Income Taxes for the years indicated below were as follows (in thousands): | |||||||||||||
Components of Income Before Income Taxes | ' | ||||||||||||
2013 | 2012 | 2011 | |||||||||||
United States | $ | 3,268,727 | $ | 1,988,105 | $ | 2,156,147 | |||||||
Foreign | 168,159 | (707,365 | ) | (246,348 | ) | ||||||||
Total | $ | 3,436,886 | $ | 1,280,740 | $ | 1,909,799 | |||||||
Components of Income Tax Provision | ' | ||||||||||||
The principal components of EOG's Income Tax Provision for the years indicated below were as follows (in thousands): | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Current: | |||||||||||||
Federal | $ | 207,777 | $ | 242,674 | $ | 94,244 | |||||||
State | 22,856 | 22,573 | 1,083 | ||||||||||
Foreign | 134,379 | 152,276 | 224,049 | ||||||||||
Total | 365,012 | 417,523 | 319,376 | ||||||||||
Deferred: | |||||||||||||
Federal | 915,994 | 454,173 | 608,181 | ||||||||||
State | 26,305 | 632 | 40,321 | ||||||||||
Foreign | (67,534 | ) | (161,867 | ) | (149,202 | ) | |||||||
Total | 874,765 | 292,938 | 499,300 | ||||||||||
Income Tax Provision | $ | 1,239,777 | $ | 710,461 | $ | 818,676 | |||||||
Tax Rate Reconciliation | ' | ||||||||||||
The differences between taxes computed at the United States federal statutory tax rate and EOG's effective rate were as follows: | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Statutory Federal Income Tax Rate | 35.00% | 35.00% | 35.00% | ||||||||||
State Income Tax, Net of Federal Benefit | 0.93 | 1.18 | 1.41 | ||||||||||
Income Tax Provision Related to Foreign Operations | (0.20) | 1.38 | 0.88 | ||||||||||
Income Tax Provision Related to Trinidad Operations | 0.43 | (0.27) | 3.37 | ||||||||||
Canadian Valuation Allowances | - | 10.57 | - | ||||||||||
Canadian Natural Gas Impairments | - | 6.90 | 1.85 | ||||||||||
Other | (0.09) | 0.71 | 0.36 | ||||||||||
Effective Income Tax Rate | 36.07% | 55.47% | 42.87% |
Employee_Benefit_Plans_Tables
Employee Benefit Plans (Tables) | 12 Months Ended | |||||||||||||||||||||||||||
Dec. 31, 2013 | ||||||||||||||||||||||||||||
Employee Benefit Plans [Abstract] | ' | |||||||||||||||||||||||||||
Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs | ' | |||||||||||||||||||||||||||
Stock-based compensation expense is included on the Consolidated Statements of Income and Comprehensive Income based upon the job functions of the employees receiving the grants. Compensation expense related to EOG's stock-based compensation plans for the years ended December 31, 2013, 2012 and 2011 was as follows (in millions): | ||||||||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||||||||
Lease and Well | $ | 35 | $ | 35 | $ | 33 | ||||||||||||||||||||||
Gathering and Processing Costs | 1 | 1 | 1 | |||||||||||||||||||||||||
Exploration Costs | 27 | 27 | 26 | |||||||||||||||||||||||||
General and Administrative | 71 | 65 | 68 | |||||||||||||||||||||||||
Total | $ | 134 | $ | 128 | $ | 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, 2013, 2012 and 2011 were as follows: | ||||||||||||||||||||||||||||
Stock Options/SARs | ESPP | |||||||||||||||||||||||||||
2013 | 2012 | 2011 | 2013 | 2012 | 2011 | |||||||||||||||||||||||
Weighted Average Fair Value of Grants | $ | 54.7 | $ | 37.95 | $ | 29.92 | $ | 30.12 | $ | 25.11 | $ | 22.75 | ||||||||||||||||
Expected Volatility | 35.86 | % | 39.68 | % | 40.96 | % | 29.89 | % | 40.92 | % | 29.82 | % | ||||||||||||||||
Risk-Free Interest Rate | 0.78 | % | 0.45 | % | 0.58 | % | 0.11 | % | 0.11 | % | 0.14 | % | ||||||||||||||||
Dividend Yield | 0.4 | % | 0.6 | % | 0.7 | % | 0.6 | % | 0.6 | % | 0.7 | % | ||||||||||||||||
Expected Life | 5.5 yrs | 5.6 yrs | 5.6 yrs | 0.5 yrs | 0.5 yrs | 0.5 yrs | ||||||||||||||||||||||
Weighted average fair values and valuation assumptions used to value performance unit and performance stock grants during the years ended December 31, 2013 and 2012 are as follows: | ||||||||||||||||||||||||||||
2013 | 2012 | |||||||||||||||||||||||||||
Weighted Average Fair Value of Grants | $ | 200.68 | $ | 134.09 | ||||||||||||||||||||||||
Expected Volatility | 33.63 | % | 36.39 | % | ||||||||||||||||||||||||
Risk-Free Interest Rate | 0.79 | % | 0.39 | % | ||||||||||||||||||||||||
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, 2013, 2012 and 2011 (stock options and SARs in thousands): | ||||||||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||||||||
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 | 6,219 | $ | 85.81 | 8,374 | $ | 70.01 | 8,445 | $ | 64.49 | |||||||||||||||||||
Granted | 1,134 | 167.4 | 1,240 | 111.97 | 1,509 | 85.29 | ||||||||||||||||||||||
Exercised (1) | (2,023 | ) | 71.23 | (3,246 | ) | 54.8 | (1,399 | ) | 50.86 | |||||||||||||||||||
Forfeited | (104 | ) | 101.56 | (149 | ) | 91.18 | (181 | ) | 87.74 | |||||||||||||||||||
Outstanding at December 31 | 5,226 | 108.86 | 6,219 | 85.81 | 8,374 | 70.01 | ||||||||||||||||||||||
Stock Options/SARs Exercisable at December 31 | 2,319 | 87.9 | 3,143 | 74.98 | 5,148 | 59.19 | ||||||||||||||||||||||
-1 | The total intrinsic value of stock options/SARs exercised during the years 2013, 2012 and 2011 was $151 million, $185 million and $78 million, respectively. The intrinsic value is based upon the difference between the market price of the Common Stock on the date of exercise and the grant price of the stock options/SARs. | |||||||||||||||||||||||||||
Stock Options and SARs Outstanding and Exercisable | ' | |||||||||||||||||||||||||||
The following table summarizes certain information for the stock options and SARs outstanding and exercisable at December 31, 2013 (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) | |||||||||||||||||||||||||
$ 26.00 to $ 81.99 | 764 | 2 | $ | 77.08 | 760 | 2 | $ | 77.13 | ||||||||||||||||||||
82.00 to 89.99 | 1,380 | 4 | 84.82 | 765 | 3 | 85.87 | ||||||||||||||||||||||
90.00 to 109.99 | 837 | 4 | 93.39 | 519 | 4 | 92.87 | ||||||||||||||||||||||
110.00 to 136.99 | 1,154 | 6 | 113.22 | 274 | 5 | 113.65 | ||||||||||||||||||||||
137.00 to 178.99 | 1,091 | 7 | 168.77 | 1 | 1 | 168.86 | ||||||||||||||||||||||
5,226 | 5 | 108.86 | $309,422 | 2,319 | 3 | 87.9 | $185,362 | |||||||||||||||||||||
-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, 2013, approximately 498,000 shares of Common Stock remained available for issuance under the ESPP. The following table summarizes ESPP activities for the years ended December 31, 2013, 2012 and 2011 (in thousands, except number of participants): | ||||||||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||||||||
Approximate Number of Participants | 1,844 | 1,705 | 1,525 | |||||||||||||||||||||||||
Shares Purchased | 128 | 164 | 135 | |||||||||||||||||||||||||
Aggregate Purchase Price | $ | 14,015 | $ | 12,522 | $ | 10,947 | ||||||||||||||||||||||
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, 2013, 2012 and 2011 (shares and units in thousands): | ||||||||||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||||||||||
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 | 3,818 | $ | 91.06 | 4,240 | $ | 82.93 | 4,009 | $ | 79.13 | |||||||||||||||||||
Granted | 647 | 152.07 | 767 | 112.17 | 932 | 90.87 | ||||||||||||||||||||||
Released (1) | (684 | ) | 104.78 | (1,059 | ) | 72.7 | (457 | ) | 66.1 | |||||||||||||||||||
Forfeited | (102 | ) | 97.1 | (130 | ) | 85.36 | (244 | ) | 82.45 | |||||||||||||||||||
Outstanding at December 31 (2) | 3,679 | 99.08 | 3,818 | 91.06 | 4,240 | 82.93 | ||||||||||||||||||||||
-1 | The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2013, 2012 and 2011 was $101 million, $120 million and $44 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 aggregate intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2013 and 2012 was approximately $617 million and $461 million, respectively. | |||||||||||||||||||||||||||
Table - Performance Unit and Performance Stock Transactions | ' | |||||||||||||||||||||||||||
The following table sets forth performance unit and performance stock transactions for the years ended December 31, 2013 and 2012 (shares and units in thousands): | ||||||||||||||||||||||||||||
2013 | 2012 | |||||||||||||||||||||||||||
Number of | Weighted | Number of | Weighted | |||||||||||||||||||||||||
Shares and | Average | Shares and | Average | |||||||||||||||||||||||||
Units | Grant Date | Units | Grant Date | |||||||||||||||||||||||||
Fair Value | Fair Value | |||||||||||||||||||||||||||
Outstanding at January 1 | 71 | $ | 134.09 | - | $ | - | ||||||||||||||||||||||
Granted | 60 | 200.68 | 71 | 134.09 | ||||||||||||||||||||||||
Released | - | - | - | - | ||||||||||||||||||||||||
Forfeited | - | - | - | - | ||||||||||||||||||||||||
Outstanding at December 31 (1) | 131 | $ | 164.36 | 71 | $ | 134.09 | ||||||||||||||||||||||
-1 | The total intrinsic value of performance units and performance stock outstanding at December 31, 2013 and 2012 was $21.9 million and $8.6 million, respectively. |
Commitments_and_Contingencies_
Commitments and Contingencies (Tables) | 12 Months Ended | |||||
Dec. 31, 2013 | ||||||
Commitments and Contingencies [Abstract] | ' | |||||
Minimum commitments for unrecorded unconditional purchase obligations [Text Block] | ' | |||||
Minimum Commitments. At December 31, 2013, 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, 2013, were as follows (in thousands): | ||||||
Total Minimum | ||||||
Commitments | ||||||
2014 | $ | 1,777,014 | ||||
2015 - 2016 | 1,808,827 | |||||
2017 - 2018 | 1,272,578 | |||||
2019 and beyond | 1,176,230 | |||||
$ | 6,034,649 |
Net_Income_Per_Share_Tables
Net Income Per Share (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Net Income 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, 2013, 2012 and 2011 (in thousands, except per share data): | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Numerator for Basic and Diluted Earnings per Share - | |||||||||||||
Net Income | $ | 2,197,109 | $ | 570,279 | $ | 1,091,123 | |||||||
Denominator for Basic Earnings per Share - | |||||||||||||
Weighted Average Shares | 270,170 | 267,577 | 262,735 | ||||||||||
Potential Dilutive Common Shares - | |||||||||||||
Stock Options/SARs | 1,159 | 1,456 | 1,707 | ||||||||||
Restricted Stock/Units and Performance Units/Stock | 1,785 | 1,729 | 1,826 | ||||||||||
Denominator for Diluted Earnings per Share - | |||||||||||||
Adjusted Diluted Weighted Average Shares | 273,114 | 270,762 | 266,268 | ||||||||||
Net Income Per Share | |||||||||||||
Basic | $ | 8.13 | $ | 2.13 | $ | 4.15 | |||||||
Diluted | $ | 8.04 | $ | 2.11 | $ | 4.1 |
Supplemental_Cash_Flow_Informa1
Supplemental Cash Flow Information (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
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, 2013, 2012 and 2011 (in thousands): | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Interest, Net of Capitalized Interest | $ | 235,854 | $ | 196,944 | $ | 186,718 | |||||||
Income Taxes, Net of Refunds Received | $ | 294,739 | $ | 360,006 | $ | 260,224 |
Business_Segment_Information_T
Business Segment Information (Tables) | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||
Business Segment Information [Abstract] | ' | ||||||||||||||||||||
Selected Financial Information by Reportable Segment | ' | ||||||||||||||||||||
Financial information by reportable segment is presented below as of and for the years ended December 31, 2013, 2012 and 2011 (in thousands): | |||||||||||||||||||||
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 (2) | 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 | ||||||||||||||||
United | Other | ||||||||||||||||||||
States | Canada | Trinidad | International (1) | Total | |||||||||||||||||
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 (3) | 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 | ||||||||||||||||
2011 | |||||||||||||||||||||
Crude Oil and Condensate | $ | 3,458,248 | $ | 264,895 | $ | 112,554 | $ | 2,587 | $ | 3,838,284 | |||||||||||
Natural Gas Liquids | 762,730 | 16,634 | - | - | 779,364 | ||||||||||||||||
Natural Gas | 1,593,964 | 178,324 | 442,589 | 25,663 | 2,240,540 | ||||||||||||||||
Gains on Mark-to-Market Commodity Derivative Contracts | 626,053 | - | - | - | 626,053 | ||||||||||||||||
Gathering, Processing and Marketing | 2,115,768 | - | 24 | - | 2,115,792 | ||||||||||||||||
Gains on Asset Dispositions, Net | 475,878 | 17,033 | (2 | ) | - | 492,909 | |||||||||||||||
Other, Net | 32,329 | 258 | 586 | - | 33,173 | ||||||||||||||||
Net Operating Revenues (3) | 9,064,970 | 477,144 | 555,751 | 28,250 | 10,126,115 | ||||||||||||||||
Depreciation, Depletion and Amortization | 2,131,706 | 260,084 | 107,141 | 17,450 | 2,516,381 | ||||||||||||||||
Operating Income (Loss) | 2,252,508 | (459,520 | ) | 383,992 | (63,671 | ) | 2,113,309 | ||||||||||||||
Interest Income | 436 | 342 | 101 | 140 | 1,019 | ||||||||||||||||
Other Income (Expense) | (6,480 | ) | (2,375 | ) | 18,755 | (4,066 | ) | 5,834 | |||||||||||||
Net Interest Expense | 214,360 | 23,085 | - | (27,082 | ) | 210,363 | |||||||||||||||
Income (Loss) Before Income Taxes | 2,032,104 | (484,638 | ) | 402,848 | (40,515 | ) | 1,909,799 | ||||||||||||||
Income Tax Provision (Benefit) | 732,362 | (125,474 | ) | 204,698 | 7,090 | 818,676 | |||||||||||||||
Additions to Oil and Gas Properties, Excluding Dry Hole Costs | 5,790,590 | 259,634 | 132,159 | 58,784 | 6,241,167 | ||||||||||||||||
Total Property, Plant and Equipment, Net | 18,711,774 | 1,760,066 | 627,794 | 189,190 | 21,288,824 | ||||||||||||||||
Total Assets | 21,313,158 | 2,131,949 | 1,085,664 | 308,026 | 24,838,797 | ||||||||||||||||
-1 | Other International primarily includes EOG's United Kingdom, China and Argentina operations. | ||||||||||||||||||||
-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 the United States segment in 2012 that totaled $2.2 billion of consolidated Net Operating Revenues. | ||||||||||||||||||||
-4 | EOG had no purchasers in 2011 whose sales totaled 10 percent or more of consolidated Net Operating Revenues. | ||||||||||||||||||||
Risk_Management_Activities_Tab
Risk Management Activities (Tables) | 12 Months Ended | ||||||||||
Dec. 31, 2013 | |||||||||||
Risk Management Activities [Abstract] | ' | ||||||||||
Commodity Derivative Contracts - Crude Oil | ' | ||||||||||
Crude Oil Derivative Contracts | |||||||||||
Volume | Weighted | ||||||||||
(Bbld) | Average Price | ||||||||||
($/Bbl) | |||||||||||
2014 (1) | |||||||||||
Jan-14 | 156,000 | $ | 96.3 | ||||||||
February 1, 2014 through March 31, 2014 | 171,000 | 96.35 | |||||||||
April 1, 2014 through June 30, 2014 | 161,000 | 96.33 | |||||||||
July 1, 2014 through December 31, 2014 | 64,000 | 95.18 | |||||||||
-1 | EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional six-month and nine-month periods. Options covering a notional volume of 10,000 Bbld are exercisable on or about March 31, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 10,000 Bbld at an average price of $96.60 per barrel for each month during the period April 1, 2014 through December 31, 2014. Options covering a notional volume of 118,000 Bbld are exercisable on or about June 30, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 118,000 Bbld at an average price of $96.64 per barrel for each month during the period July 1, 2014 through December 31, 2014. Options covering a notional volume of 69,000 Bbld are exercisable on or about December 31, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 69,000 Bbld at an average price of $95.20 per barrel for each month during the period January 1, 2015 through June 30, 2015. | ||||||||||
Commodity Derivative Contracts - Natural Gas | ' | ||||||||||
Presented below is a comprehensive summary of EOG's natural gas derivative contracts at December 31, 2013, with notional volumes expressed in million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu). | |||||||||||
Natural Gas Derivative Contracts | |||||||||||
Volume (MMBtud) | Weighted | ||||||||||
Average Price ($/MMBtu) | |||||||||||
2014 (1) | |||||||||||
January 2014 (closed) | 230,000 | $ | 4.51 | ||||||||
February 1, 2014 through December 31, 2014 | 205,000 | $ | 4.52 | ||||||||
-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 355,000 MMBtud at an average price of $4.63 per MMBtu for each month during the period February 1, 2014 through December 31, 2014. | ||||||||||
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, 2013 and 2012, 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 | 2013 | 2012 | ||||||||
Asset Derivatives | |||||||||||
Crude oil and natural gas derivative contracts - | |||||||||||
Current portion | Assets from Price Risk Management Activities (1) | $ | 8 | $ | 166 | ||||||
Liability Derivatives | |||||||||||
Crude oil and natural gas derivative contracts - | |||||||||||
Current portion | Liabilities from Price Risk Management Activities (2) | $ | 127 | $ | 8 | ||||||
Noncurrent portion | Other Liabilities (3) | $ | - | $ | 13 | ||||||
Foreign currency swap - | |||||||||||
Current portion | Current Liabilities - Other | $ | 40 | $ | - | ||||||
Noncurrent portion | Other Liabilities | $ | - | $ | 55 | ||||||
Interest rate swap - | |||||||||||
Current portion | Current Liabilities - Other | $ | 1 | $ | - | ||||||
Noncurrent portion | Other Liabilities | $ | - | $ | 4 | ||||||
-1 | The current portion of Assets from Price Risk Management Activities consists of gross assets of $18 million, partially offset by gross liabilities of $10 million, at December 31, 2013 and gross assets of $271 million, partially offset by gross liabilities of $105 million, at December 31, 2012. | ||||||||||
-2 | The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $137 million, partially offset by gross assets of $10 million, at December 31, 2013 and gross liabilities of $113 million, partially offset by gross assets of $105 million, at December 31, 2012. | ||||||||||
-3 | The noncurrent portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $13 million at December 31, 2012. |
Fair_Value_Measurements_Tables
Fair Value Measurements (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Fair Value Measurements [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, 2013 and 2012 (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, 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 | |||||||||||||
At December 31, 2012 | |||||||||||||||||
Financial Assets: | |||||||||||||||||
Crude Oil Swaps | $ | - | $ | 65 | $ | - | $ | 65 | |||||||||
Crude Oil Options/Swaptions | - | 36 | - | 36 | |||||||||||||
Natural Gas Options/Swaptions | - | 65 | - | 65 | |||||||||||||
Financial Liabilities: | |||||||||||||||||
Crude Oil Options/Swaptions | $ | - | $ | 8 | $ | - | $ | 8 | |||||||||
Natural Gas Options/Swaptions | - | 13 | - | 13 | |||||||||||||
Foreign Currency Rate Swap | - | 55 | - | 55 | |||||||||||||
Interest Rate Swap | - | 4 | - | 4 | |||||||||||||
Asset_Retirement_Obligations_T
Asset Retirement Obligations (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
Asset Retirement Obligations [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, 2013 and 2012 (in thousands): | |||||||||
2013 | 2012 | ||||||||
Carrying Amount at Beginning of Period | $ | 665,944 | $ | 587,084 | |||||
Liabilities Incurred | 103,284 | 107,378 | |||||||
Liabilities Settled (1) | (70,510 | ) | (77,384 | ) | |||||
Accretion | 35,180 | 30,020 | |||||||
Revisions | 38,552 | 15,287 | |||||||
Foreign Currency Translations | (10,552 | ) | 3,559 | ||||||
Carrying Amount at End of Period | $ | 761,898 | $ | 665,944 | |||||
Current Portion | $ | 43,857 | $ | 30,127 | |||||
Noncurrent Portion | $ | 718,041 | $ | 635,817 | |||||
(1) Includes settlements related to asset sales. | |||||||||
Exploratory_Well_Costs_Tables
Exploratory Well Costs (Tables) | 12 Months Ended | |||||||||||||
Dec. 31, 2013 | ||||||||||||||
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, 2013, 2012 and 2011 are presented below (in thousands): | ||||||||||||||
2013 | 2012 | 2011 | ||||||||||||
Balance at January 1 | $ | 49,116 | $ | 61,111 | $ | 99,801 | ||||||||
Additions Pending the Determination of Proved Reserves | 52,099 | 73,332 | 31,271 | |||||||||||
Reclassifications to Proved Properties | (54,505 | ) | (69,462 | ) | (29,227 | ) | ||||||||
Costs Charged to Expense (1) | (35,859 | ) | (17,115 | ) | (42,178 | ) | ||||||||
Foreign Currency Translations | (1,640 | ) | 1,250 | 1,444 | ||||||||||
Balance at December 31 | $ | 9,211 | $ | 49,116 | $ | 61,111 | ||||||||
(1) Includes capitalized exploratory well costs charged to either dry hole costs or impairments. | ||||||||||||||
Aging of Capitalized Exploratory Well Costs | ' | |||||||||||||
The following table provides an aging of capitalized exploratory well costs at December 31, 2013, 2012 and 2011 (in thousands, except well count): | ||||||||||||||
2013 | 2012 | 2011 | ||||||||||||
Capitalized exploratory well costs that have been capitalized for a period less than one year | $ | 9,211 | $ | 28,319 | $ | 17,009 | ||||||||
Capitalized exploratory well costs that have been capitalized for a period greater than one year | - | 20,797 | 44,102 | (2) | ||||||||||
(1) | ||||||||||||||
Total | $ | 9,211 | $ | 49,116 | $ | 61,111 | ||||||||
Number of exploratory wells that have been capitalized for a period greater than one year | - | 1 | 4 | |||||||||||
-1 | Consists of costs related to an outside operated, offshore Central North Sea natural gas project in the United Kingdom (U.K.). | |||||||||||||
-2 | Consists of costs related to an outside operated, offshore Central North Sea project in the U.K. ($20 million), an East Irish Sea project in the U.K. ($9 million), a project in the Sichuan Basin, Sichuan Province, China ($9 million), and a shale project in British Columbia, Canada ($6 million). |
Oil_and_Gas_Exploration_and_Pr1
Oil and Gas Exploration and Production Industries Disclosures (Tables) | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | ' | ||||||||||||||||||||
Net Proved and Proved Developed Oil and Gas Reserve Quantities [Table Text Block] | ' | ||||||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||||||
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | |||||||||||||||||||||
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, 2013, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2013, 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, 2010 | 355,457 | 25,636 | 4,731 | 98 | 385,922 | ||||||||||||||||
Revisions of previous estimates | (21,188 | ) | (4,611 | ) | 18 | 25 | (25,756 | ) | |||||||||||||
Purchases in place | 9 | - | - | - | 9 | ||||||||||||||||
Extensions, discoveries and other additions | 202,552 | 449 | - | - | 203,001 | ||||||||||||||||
Sales in place | (4,301 | ) | - | - | - | (4,301 | ) | ||||||||||||||
Production | (37,233 | ) | (2,882 | ) | (1,242 | ) | (25 | ) | (41,382 | ) | |||||||||||
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 | ||||||||||||||||
Natural Gas Liquids (MBbl) (2) | |||||||||||||||||||||
Net proved reserves at December 31, 2010 | 150,434 | 1,475 | - | - | 151,909 | ||||||||||||||||
Revisions of previous estimates | 35,999 | 43 | - | - | 36,042 | ||||||||||||||||
Purchases in place | 17 | - | - | - | 17 | ||||||||||||||||
Extensions, discoveries and other additions | 65,288 | - | - | - | 65,288 | ||||||||||||||||
Sales in place | (10,008 | ) | - | - | - | (10,008 | ) | ||||||||||||||
Production | (15,144 | ) | (316 | ) | - | - | (15,460 | ) | |||||||||||||
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 | ||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||||||
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | |||||||||||||||||||||
United | Canada | Trinidad | Other | Total | |||||||||||||||||
States | International (1) | ||||||||||||||||||||
Natural Gas (Bcf) (3) | |||||||||||||||||||||
Net proved reserves at December 31, 2010 | 6,491.50 | 1,133.80 | 827.6 | 17.3 | 8,470.20 | ||||||||||||||||
Revisions of previous estimates | (344.0 | ) | (49.8 | ) | (24.2 | ) | 1.3 | (416.7 | ) | ||||||||||||
Purchases in place | 3 | - | - | - | 3 | ||||||||||||||||
Extensions, discoveries and other additions | 634.6 | - | 74.7 | 4.5 | 713.8 | ||||||||||||||||
Sales in place | (323.6 | ) | - | - | - | (323.6 | ) | ||||||||||||||
Production | (415.7 | ) | (48.1 | ) | (127.4 | ) | (4.6 | ) | (595.8 | ) | |||||||||||
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 | ||||||||||||||||
Oil Equivalents (MBoe) (2) | |||||||||||||||||||||
Net proved reserves at December 31, 2010 | 1,587,806 | 216,084 | 142,669 | 2,976 | 1,949,535 | ||||||||||||||||
Revisions of previous estimates | (42,526 | ) | (12,865 | ) | (4,011 | ) | 239 | (59,163 | ) | ||||||||||||
Purchases in place | 521 | - | - | - | 521 | ||||||||||||||||
Extensions, discoveries and other additions | 373,602 | 448 | 12,455 | 750 | 387,255 | ||||||||||||||||
Sales in place | (68,247 | ) | - | - | - | (68,247 | ) | ||||||||||||||
Production | (121,648 | ) | (11,219 | ) | (22,484 | ) | (787 | ) | (156,138 | ) | |||||||||||
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 | ||||||||||||||||
-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, NGLs and natural gas. Oil equivalents are determined using the ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. | ||||||||||||||||||||
-3 | Billion cubic feet. | ||||||||||||||||||||
Net Proved Developed and Net Proved Undeveloped Oil and Gas Reserve Quantities [Table Text Block] | ' | ||||||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||||||
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | |||||||||||||||||||||
United | Canada | Trinidad | Other | Total | |||||||||||||||||
States | International (1) | ||||||||||||||||||||
NET PROVED DEVELOPED RESERVES | |||||||||||||||||||||
Crude Oil (MBbl) | |||||||||||||||||||||
31-Dec-10 | 161,907 | 11,283 | 3,852 | 98 | 177,140 | ||||||||||||||||
31-Dec-11 | 213,872 | 8,128 | 2,657 | 98 | 224,755 | ||||||||||||||||
31-Dec-12 | 281,167 | 6,853 | 2,377 | 253 | 290,650 | ||||||||||||||||
31-Dec-13 | 382,517 | 6,871 | 1,505 | 163 | 391,056 | ||||||||||||||||
Natural Gas Liquids (MBbl) | |||||||||||||||||||||
31-Dec-10 | 91,401 | 1,475 | - | - | 92,876 | ||||||||||||||||
31-Dec-11 | 124,271 | 1,092 | - | - | 125,363 | ||||||||||||||||
31-Dec-12 | 161,482 | 1,111 | - | - | 162,593 | ||||||||||||||||
31-Dec-13 | 199,964 | 896 | - | - | 200,860 | ||||||||||||||||
Natural Gas (Bcf) | |||||||||||||||||||||
31-Dec-10 | 3,519.70 | 401.6 | 519.2 | 17.3 | 4,457.80 | ||||||||||||||||
31-Dec-11 | 3,235.00 | 295.8 | 606.3 | 18.5 | 4,155.60 | ||||||||||||||||
31-Dec-12 | 2,387.50 | 98.3 | 476.7 | 17 | 2,979.50 | ||||||||||||||||
31-Dec-13 | 2,597.30 | 102.1 | 494.6 | 19.4 | 3,213.40 | ||||||||||||||||
Oil Equivalents (MBoe) | |||||||||||||||||||||
31-Dec-10 | 839,928 | 79,701 | 90,382 | 2,976 | 1,012,987 | ||||||||||||||||
31-Dec-11 | 877,301 | 58,524 | 103,710 | 3,178 | 1,042,713 | ||||||||||||||||
31-Dec-12 | 840,564 | 24,348 | 81,826 | 3,081 | 949,819 | ||||||||||||||||
31-Dec-13 | 1,015,359 | 24,782 | 83,933 | 3,402 | 1,127,476 | ||||||||||||||||
NET PROVED UNDEVELOPED RESERVES | |||||||||||||||||||||
Crude Oil (MBbl) | |||||||||||||||||||||
31-Dec-10 | 193,550 | 14,353 | 879 | - | 208,782 | ||||||||||||||||
31-Dec-11 | 281,424 | 10,464 | 850 | - | 292,738 | ||||||||||||||||
31-Dec-12 | 389,862 | 11,010 | 651 | 8,645 | 410,168 | ||||||||||||||||
31-Dec-13 | 497,532 | 3,249 | 85 | 8,618 | 509,484 | ||||||||||||||||
Natural Gas Liquids (MBbl) | |||||||||||||||||||||
31-Dec-10 | 59,033 | - | - | - | 59,033 | ||||||||||||||||
31-Dec-11 | 102,315 | 110 | - | - | 102,425 | ||||||||||||||||
31-Dec-12 | 156,924 | 446 | - | - | 157,370 | ||||||||||||||||
31-Dec-13 | 176,038 | 308 | - | - | 176,346 | ||||||||||||||||
Natural Gas (Bcf) | |||||||||||||||||||||
31-Dec-10 | 2,971.80 | 732.2 | 308.4 | - | 4,012.40 | ||||||||||||||||
31-Dec-11 | 2,810.80 | 740.1 | 144.4 | - | 3,695.30 | ||||||||||||||||
31-Dec-12 | 1,648.50 | - | 111.5 | - | 1,760.00 | ||||||||||||||||
31-Dec-13 | 1,801.40 | - | 26.1 | 3.9 | 1,831.40 | ||||||||||||||||
Oil Equivalents (MBoe) | |||||||||||||||||||||
31-Dec-10 | 747,878 | 136,383 | 52,287 | - | 936,548 | ||||||||||||||||
31-Dec-11 | 852,207 | 133,924 | 24,919 | - | 1,011,050 | ||||||||||||||||
31-Dec-12 | 821,544 | 11,456 | 19,234 | 8,645 | 860,879 | ||||||||||||||||
31-Dec-13 | 973,807 | 3,557 | 4,431 | 9,272 | 991,067 | ||||||||||||||||
-1 | Other International includes EOG's United Kingdom, China and Argentina operations. | ||||||||||||||||||||
Capitalized Costs Relating to Oil an d Gas Producing Activities | ' | ||||||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||||||
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | |||||||||||||||||||||
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, 2013 and 2012: | |||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||
Proved properties | $ | 41,377,303 | $ | 36,872,434 | |||||||||||||||||
Unproved properties | 1,444,500 | 1,253,864 | |||||||||||||||||||
Total | 42,821,803 | 38,126,298 | |||||||||||||||||||
Accumulated depreciation, depletion and amortization | (18,880,611 | ) | (16,849,068 | ) | |||||||||||||||||
Net capitalized costs | $ | 23,941,192 | $ | 21,277,230 | |||||||||||||||||
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities | ' | ||||||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||||||
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | |||||||||||||||||||||
The following table sets forth costs incurred related to EOG's oil and gas activities for the years ended December 31, 2013, 2012 and 2011: | |||||||||||||||||||||
United | Canada | Trinidad | Other | Total | |||||||||||||||||
States | International (1) | ||||||||||||||||||||
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 (2) | 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 (3) | 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 | |||||||||||
2011 | |||||||||||||||||||||
Acquisition Costs of Properties | |||||||||||||||||||||
Unproved | $ | 295,160 | $ | 6,216 | $ | - | $ | (604 | ) | $ | 300,772 | ||||||||||
Proved | 4,219 | 28 | - | - | 4,247 | ||||||||||||||||
Subtotal | 299,379 | 6,244 | - | (604 | ) | 305,019 | |||||||||||||||
Exploration Costs | 311,369 | 31,472 | 2,549 | 18,164 | 363,554 | ||||||||||||||||
Development Costs (4) | 5,410,378 | 302,564 | 138,905 | 78,744 | 5,930,591 | ||||||||||||||||
Total | $ | 6,021,126 | $ | 340,280 | $ | 141,454 | $ | 96,304 | $ | 6,599,164 | |||||||||||
-1 | Other International primarily consists of EOG's United Kingdom, China and Argentina operations. | ||||||||||||||||||||
-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 | Includes Asset Retirement Costs of $52 million, $70 million, $7 million and $4 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 | ' | ||||||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||||||
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | |||||||||||||||||||||
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, 2013, 2012 and 2011: | |||||||||||||||||||||
United | Canada | Trinidad | Other | Total | |||||||||||||||||
States | International (2) | ||||||||||||||||||||
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 | |||||||||
2011 | |||||||||||||||||||||
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues | $ | 5,814,942 | $ | 459,853 | $ | 555,143 | $ | 28,250 | $ | 6,858,188 | |||||||||||
Other | 32,329 | 258 | 586 | - | 33,173 | ||||||||||||||||
Total | 5,847,271 | 460,111 | 555,729 | 28,250 | 6,891,361 | ||||||||||||||||
Exploration Costs | 148,199 | 10,479 | 2,520 | 10,460 | 171,658 | ||||||||||||||||
Dry Hole Costs | 30,521 | 432 | - | 22,277 | 53,230 | ||||||||||||||||
Transportation Costs | 421,060 | 5,969 | 1,620 | 1,673 | 430,322 | ||||||||||||||||
Production Costs | 1,096,955 | 174,973 | 49,318 | 10,964 | 1,332,210 | ||||||||||||||||
Impairments | 575,976 | 452,103 | - | 2,958 | 1,031,037 | ||||||||||||||||
Depreciation, Depletion and Amortization | 2,011,080 | 258,772 | 106,802 | 17,160 | 2,393,814 | ||||||||||||||||
Income (Loss) Before Income Taxes | 1,563,480 | (442,617 | ) | 395,469 | (37,242 | ) | 1,479,090 | ||||||||||||||
Income Tax Provision (Benefit) | 569,153 | (121,044 | ) | 202,815 | (13,056 | ) | 637,868 | ||||||||||||||
Results of Operations | $ | 994,327 | $ | (321,573 | ) | $ | 192,654 | $ | (24,186 | ) | $ | 841,222 | |||||||||
-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, 2013. | ||||||||||||||||||||
-2 | Other International primarily consists of EOG's United Kingdom, China and Argentina operations. | ||||||||||||||||||||
Production Costs Per Barrel of Oil Equivalent | ' | ||||||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||||||
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | |||||||||||||||||||||
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, 2013, 2012 and 2011: | |||||||||||||||||||||
United | Canada | Trinidad | Other | Composite | |||||||||||||||||
States | International (1) | ||||||||||||||||||||
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 | |||||||||||
Year Ended December 31, 2011 | $ | 6.19 | $ | 14.26 | $ | 0.78 | $ | 13.82 | $ | 6.03 | |||||||||||
(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 | ' | ||||||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||||||
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | |||||||||||||||||||||
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, 2013, 2012 and 2011: | |||||||||||||||||||||
United | Canada | Trinidad | Other | Total | |||||||||||||||||
States | International (1) | ||||||||||||||||||||
2013 | |||||||||||||||||||||
Future cash inflows (2) | $ | 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 (3) | $ | 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 | |||||||||||
2011 | |||||||||||||||||||||
Future cash inflows (4) | $ | 84,518,638 | $ | 5,056,501 | $ | 2,851,545 | $ | 103,853 | $ | 92,530,537 | |||||||||||
Future production costs | (33,294,343 | ) | (2,315,110 | ) | (388,199 | ) | (62,938 | ) | (36,060,590 | ) | |||||||||||
Future development costs | (13,811,449 | ) | (1,566,917 | ) | (149,884 | ) | (331 | ) | (15,528,581 | ) | |||||||||||
Future income taxes | (10,539,182 | ) | (81,590 | ) | (794,856 | ) | (2,457 | ) | (11,418,085 | ) | |||||||||||
Future net cash flows | 26,873,664 | 1,092,884 | 1,518,606 | 38,127 | 29,523,281 | ||||||||||||||||
Discount to present value at 10% annual rate | (12,498,010 | ) | (456,537 | ) | (334,399 | ) | (9,054 | ) | (13,298,000 | ) | |||||||||||
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves | $ | 14,375,654 | $ | 636,347 | $ | 1,184,207 | $ | 29,073 | $ | 16,225,281 | |||||||||||
-1 | Other International includes EOG's United Kingdom, China and Argentina operations. | ||||||||||||||||||||
-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 NGLs 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 NGLs 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 | Estimated crude oil prices used to calculate 2011 future cash inflows for the United States, Canada, Trinidad and Other International were $97.75, $90.70, $92.50 and $102.86, respectively. Estimated NGLs prices used to calculate 2011 future cash inflows for the United States and Canada were $51.77 and $46.97, respectively. Estimated natural gas prices used to calculate 2011 future cash inflows for the United States, Canada, Trinidad and Other International were $4.03, $3.28, $3.37 and $5.07, respectively. | ||||||||||||||||||||
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves | ' | ||||||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||||||
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | |||||||||||||||||||||
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, 2013: | |||||||||||||||||||||
United | Canada | Trinidad | Other | Total | |||||||||||||||||
States | International | ||||||||||||||||||||
31-Dec-10 | 10,628,924 | 746,235 | 988,866 | 27,799 | 12,391,824 | ||||||||||||||||
Sales and transfers of oil and gas produced, net of production costs | (4,296,926 | ) | (278,910 | ) | (504,205 | ) | (15,614 | ) | (5,095,655 | ) | |||||||||||
Net changes in prices and production costs | 716,682 | (57,545 | ) | 331,196 | 3,328 | 993,661 | |||||||||||||||
Extensions, discoveries, additions and improved recovery, net of related costs | 6,223,552 | 22,591 | 102,548 | - | 6,348,691 | ||||||||||||||||
Development costs incurred | 1,422,500 | 48,200 | 74,800 | - | 1,545,500 | ||||||||||||||||
Revisions of estimated development cost | (210,919 | ) | 64,001 | (14,074 | ) | 2 | (160,990 | ) | |||||||||||||
Revisions of previous quantity estimates | (482,496 | ) | (70,718 | ) | (56,884 | ) | 801 | (609,297 | ) | ||||||||||||
Accretion of discount | 1,352,740 | 62,725 | 159,715 | 2,782 | 1,577,962 | ||||||||||||||||
Net change in income taxes | (1,049,641 | ) | (118,988 | ) | 9,511 | 13 | (1,159,105 | ) | |||||||||||||
Purchases of reserves in place | 5,241 | - | - | - | 5,241 | ||||||||||||||||
Sales of reserves in place | (658,468 | ) | - | - | - | (658,468 | ) | ||||||||||||||
Changes in timing and other | 724,465 | 218,756 | 92,734 | 9,962 | 1,045,917 | ||||||||||||||||
31-Dec-11 | 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 | ) | |||||||||||
31-Dec-12 | 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 | |||||||||||||||
31-Dec-13 | $ | 19,576,901 | $ | 331,654 | $ | 876,640 | $ | 548,237 | $ | 21,333,432 | |||||||||||
Unaudited_Quarterly_Financial_1
Unaudited Quarterly Financial Information (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Unaudited Quarterly Financial Information [Abstract] | ' | ||||||||||||||||
Table - Unaudited Quarterly Financial Information | ' | ||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) | |||||||||||||||||
Unaudited Quarterly Financial Information | |||||||||||||||||
(In Thousands, Except Per Share Data) | |||||||||||||||||
Quarter Ended | 31-Mar | 30-Jun | 30-Sep | 31-Dec | |||||||||||||
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 | $ | 1.84 | $ | 2.44 | $ | 1.71 | $ | 2.14 | |||||||||
Diluted | $ | 1.82 | $ | 2.42 | $ | 1.69 | $ | 2.12 | |||||||||
Average Number of Common Shares | |||||||||||||||||
Basic | 269,358 | 270,016 | 270,471 | 270,929 | |||||||||||||
Diluted | 272,263 | 272,739 | 273,576 | 273,983 | |||||||||||||
2012 | |||||||||||||||||
Net Operating Revenues | $ | 2,806,651 | $ | 2,909,319 | $ | 2,954,855 | $ | 3,011,811 | |||||||||
Operating Income (Loss) | $ | 559,772 | $ | 692,339 | $ | 605,747 | $ | (378,061 | ) | ||||||||
Income (Loss) Before Income Taxes | $ | 520,134 | $ | 646,239 | $ | 560,189 | $ | (445,822 | ) | ||||||||
Income Tax Provision | 196,125 | 250,461 | 204,698 | 59,177 | |||||||||||||
Net Income (Loss) (2) | $ | 324,009 | $ | 395,778 | $ | 355,491 | $ | (504,999 | ) | ||||||||
Net Income (Loss) Per Share (1) | |||||||||||||||||
Basic | $ | 1.22 | $ | 1.48 | $ | 1.33 | $ | (1.88 | ) | ||||||||
Diluted | $ | 1.2 | $ | 1.47 | $ | 1.31 | $ | (1.88 | ) | ||||||||
Average Number of Common Shares | |||||||||||||||||
Basic | 266,674 | 266,874 | 267,941 | 268,941 | |||||||||||||
Diluted | 270,242 | 269,985 | 270,982 | 268,941 | |||||||||||||
-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. | ||||||||||||||||
-2 | Fourth quarter 2012 results include the impact of pretax impairments of $1,020 million, primarily related to proved and unproved natural gas properties in Canada and the United States as well as an additional income tax provision of $135 million related to valuation allowances recorded to reduce the value of Canadian deferred tax assets. | ||||||||||||||||
LongTerm_Debt_Details
Long-Term Debt (Details) | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | ||||||||||||||||||||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | |
USD ($) | USD ($) | USD ($) | USD ($) | Canadian Dollar Letter of Credit Facility Due 2018 [Member] | Canadian Dollar Letter of Credit Facility Due 2018 [Member] | Uncommitted Credit Facility [Member] | Uncommitted Credit Facility [Member] | Commercial Paper [Member] | Commercial Paper [Member] | Revolving Credit Agreement 2011 [Member] | Senior Notes Due 2013 [Member] | Senior Notes Due 2013 [Member] | Floating Rate Senior Notes Due 2014 [Member] | Floating Rate Senior Notes Due 2014 [Member] | Senior Notes Due 2015 [Member] | Senior Notes Due 2015 [Member] | Senior Notes Due 2016 [Member] | Senior Notes Due 2016 [Member] | Senior Notes Due 2017 [Member] | Senior Notes Due 2017 [Member] | Senior Notes Due 2018 [Member] | Senior Notes Due 2018 [Member] | Senior Notes Due 2019 [Member] | Senior Notes Due 2019 [Member] | Senior Notes Due 2020 [Member] | Senior Notes Due 2020 [Member] | Senior Notes Due 2021 [Member] | Senior Notes Due 2021 [Member] | Senior Notes Due 2023 [Member] | Senior Notes Due 2023 [Member] | Senior Notes Due 2028 [Member] | Senior Notes Due 2028 [Member] | Subsidiary Debt Due 2014 [Member] | Subsidiary Debt Due 2014 [Member] | Subsidiary Debt Due 2014, Canadian Dollar Equivalent [Member] | |
USD ($) | 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 ($) | USD ($) | USD ($) | CAD | |||||
Debt Instrument Table [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Total Long-Term Debt | ' | $5,890,000,000 | $6,290,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | $0 | $400,000,000 | $350,000,000 | $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 | $750,000,000 | $750,000,000 | $1,250,000,000 | $1,250,000,000 | $140,000,000 | $140,000,000 | $150,000,000 | $150,000,000 | ' |
Capital Lease Obligation | ' | 57,187,000 | 62,968,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Less: Current Portion of Long-Term Debt | ' | 6,579,000 | 406,579,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Unamortized Debt Discount | ' | 33,966,000 | 40,787,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Subsidiary Debt Due 2014 (Canadian) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 201,300,000 |
Total Long-Term Debt, Net | ' | 5,906,642,000 | 5,905,602,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Interest Rate - Canadian Subsidiary Note | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5.28% |
Debt Instrument Issuance [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument Offering Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10-Sep-12 | ' | ' | ' | ' | ' | ' |
Debt Instrument, Maturity Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15-Mar-14 |
Debt Instrument Issuance Face Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,250,000,000 | ' | ' | ' | 150,000,000 | ' | ' |
Debt Instrument Issuance Interest Rate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6.13% | ' | ' | ' | 2.95% | ' | 2.50% | ' | 5.88% | ' | 6.88% | ' | 5.63% | ' | 4.40% | ' | 4.10% | ' | 2.63% | ' | 6.65% | ' | 4.75% | ' | ' |
Debt Instrument, Maturity Years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '2013 | ' | '2014 | ' | '2015 | ' | '2016 | ' | '2017 | ' | '2018 | ' | '2019 | ' | '2020 | ' | '2021 | ' | '2023 | ' | '2028 | ' | '2014 | ' | ' |
Debt Instrument Frequency of Periodic Payment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 'semi-annually | ' | ' | ' | ' | ' | ' |
Proceeds From Issuance of Senior Long-Term Debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,234,000,000 | ' | ' | ' | ' | ' | ' |
Effective Interest Rate (in hundredths) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2.78% | ' | ' | ' | ' | ' | ' |
Long-Term Debt by Maturity [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Aggregate annual maturity of long-term debt (excluding capital lease obligations) 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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Line of Credit Facility [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Long-Term Debt Repayments | 350,000,000 | 400,000,000 | 0 | 220,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Average Borrowings Outstanding | ' | ' | ' | ' | ' | ' | 0 | 41,000,000 | 37,000,000 | 236,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Weighted average interest rate (in hundredths) | ' | ' | ' | ' | ' | ' | ' | 0.70% | 0.30% | 0.45% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Line of Credit Facility, Expiration Date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11-Oct-16 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Restricted Cash | ' | ' | ' | ' | 66,000,000 | 70,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Maximum borrowing capacity | ' | ' | ' | ' | ' | 160,000,000 | ' | ' | ' | ' | $2,000,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Eurodollar rate at period end (in hundredths) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1.04% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Base rate at period end (in hundredths) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3.25% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Maximum total debt-to-total capitalization ratio allowed under financial covenant (in hundredths) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 65.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Stockholders_Equity_Details
Stockholder's Equity (Details) (USD $) | 1 Months Ended | 2 Months Ended | 12 Months Ended | 12 Months Ended | |||||||||||
Feb. 13, 2013 | Apr. 30, 2014 | Feb. 24, 2014 | Feb. 16, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Common Shares, Issued [Member] | Common Shares, Issued [Member] | Common Shares, Issued [Member] | Common Shares, Treasury [Member] | Common Shares, Treasury [Member] | Common Shares, Treasury [Member] | Common Shares, Outstanding [Member] | Common Shares, Outstanding [Member] | Common Shares, Outstanding [Member] | |||||||
Stockholders' Equity [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Shares of Common Stock Sold | ' | ' | ' | ' | 13,570,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Common Stock, Par (in dollars per share) | ' | ' | ' | ' | $0.01 | $0.01 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Offering Price of Common Stock Sold | ' | ' | ' | ' | $105.50 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Proceeds From Issuance Or Sale Of Equity | ' | ' | ' | ' | $1,388,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
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 | $0.19 | $0.13 | $0.25 | $0.17 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Percentage increase of cash dividend on common stock | ' | 33.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Common Stock Activity [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Balance (in shares) | ' | ' | 273,189,220 | ' | 271,958,495 | ' | 271,958,000 | 269,323,000 | 254,223,000 | -326,000 | -304,000 | -146,000 | 271,632,000 | 269,019,000 | 254,077,000 |
Common Stock Issued Under Equity Compensation Plans (in shares) | ' | ' | ' | ' | ' | ' | 1,103,000 | 2,471,000 | 1,395,000 | 0 | 0 | 0 | 1,103,000 | 2,471,000 | 1,395,000 |
Treasury Stock Purchased (in shares) | ' | ' | ' | ' | ' | ' | 0 | 0 | 0 | -427,000 | -575,000 | -267,000 | -427,000 | -575,000 | -267,000 |
Common Stock Issued Under Employee Stock Purchase Plan (in shares) | ' | ' | ' | ' | ' | ' | 128,000 | 164,000 | 135,000 | 0 | 0 | 0 | 128,000 | 164,000 | 135,000 |
Treasury Stock Issued Under Other Equity Compensation Plans (in shares) | ' | ' | ' | ' | ' | ' | 0 | 0 | 0 | 650,000 | 553,000 | 109,000 | 650,000 | 553,000 | 109,000 |
Common Stock Sold (in shares) | ' | ' | ' | ' | ' | ' | ' | ' | 13,570,000 | ' | ' | 0 | ' | ' | 13,570,000 |
Balance (in shares) | ' | ' | ' | ' | 273,189,220 | ' | 273,189,000 | 271,958,000 | 269,323,000 | -103,000 | -326,000 | -304,000 | 273,086,000 | 271,632,000 | 269,019,000 |
Other_Income_Net_Details
Other Income, Net (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Other Income, Net [Abstract] | ' | ' | ' |
Equity income from investments in Trinidad | $11 | $20 | $17 |
Interest income | 6 | 9 | ' |
Net foreign currency transaction gains | 12 | 7 | ' |
Losses on sales of warehouse stock | 23 | 10 | 5 |
Operating losses on EOG's investment in Pacific Trail Pipelines (PTP) in Canada | ' | $9 | $5 |
Income_Taxes_Details
Income Taxes (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Deferred tax assets net noncurrent classification [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Over (Under) Book Depreciation, Depletion and Amortization | ($112,346,000) | ' | ' | ' | $25,592,000 | ' | ' | ' | ($112,346,000) | $25,592,000 | ' |
Foreign Net Operating Loss | 369,257,000 | ' | ' | ' | 164,829,000 | ' | ' | ' | 369,257,000 | 164,829,000 | ' |
Foreign Other | 4,179,000 | ' | ' | ' | 1,607,000 | ' | ' | ' | 4,179,000 | 1,607,000 | ' |
Foreign Valuation Allowances | -183,122,000 | ' | ' | ' | -134,792,000 | ' | ' | ' | -183,122,000 | -134,792,000 | ' |
Total Net Noncurrent Deferred Income Tax Assets | 77,968,000 | ' | ' | ' | 57,236,000 | ' | ' | ' | 77,968,000 | 57,236,000 | ' |
Deferred tax liabilities net current classification [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Commodity Hedging Contracts | 29,582,000 | ' | ' | ' | -57,754,000 | ' | ' | ' | 29,582,000 | -57,754,000 | ' |
Deferred Compensation Plans | 42,296,000 | ' | ' | ' | 35,715,000 | ' | ' | ' | 42,296,000 | 35,715,000 | ' |
Net Operating Loss | 96,616,000 | ' | ' | ' | 0 | ' | ' | ' | 96,616,000 | 0 | ' |
Alternative Minimum Tax Credit Carryforward | 72,297,000 | ' | ' | ' | 0 | ' | ' | ' | 72,297,000 | 0 | ' |
Timing Differences Associated With Different Year-ends in Foreign Jurisdictions | 0 | ' | ' | ' | -2,762,000 | ' | ' | ' | 0 | -2,762,000 | ' |
Other | 3,815,000 | ' | ' | ' | 1,963,000 | ' | ' | ' | 3,815,000 | 1,963,000 | ' |
Total Net Current Deferred Income Tax Assets | 244,606,000 | ' | ' | ' | 0 | ' | ' | ' | 244,606,000 | 0 | ' |
Total Net Current Deferred Income Tax Liabilities | 0 | ' | ' | ' | -22,838,000 | ' | ' | ' | 0 | -22,838,000 | ' |
Deferred tax liabilities net noncurrent classification [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization | 6,287,541,000 | ' | ' | ' | 5,300,115,000 | ' | ' | ' | 6,287,541,000 | 5,300,115,000 | ' |
Non-Producing Leasehold Costs | -50,581,000 | ' | ' | ' | -61,512,000 | ' | ' | ' | -50,581,000 | -61,512,000 | ' |
Seismic Costs Capitalized for Tax | -136,964,000 | ' | ' | ' | -125,026,000 | ' | ' | ' | -136,964,000 | -125,026,000 | ' |
Equity Awards | -122,665,000 | ' | ' | ' | -116,666,000 | ' | ' | ' | -122,665,000 | -116,666,000 | ' |
Capitalized Interest | 101,006,000 | ' | ' | ' | 102,677,000 | ' | ' | ' | 101,006,000 | 102,677,000 | ' |
Net Operating Loss | 0 | ' | ' | ' | -308,154,000 | ' | ' | ' | 0 | -308,154,000 | ' |
Alternative Minimum Tax Credit Carryforward | -557,352,000 | ' | ' | ' | -476,505,000 | ' | ' | ' | -557,352,000 | -476,505,000 | ' |
Other | 1,369,000 | ' | ' | ' | 12,467,000 | ' | ' | ' | 1,369,000 | 12,467,000 | ' |
Total Net Noncurrent Deferred Income Tax Liabilities | 5,522,354,000 | ' | ' | ' | 4,327,396,000 | ' | ' | ' | 5,522,354,000 | 4,327,396,000 | ' |
Total Net Deferred Income Tax Liabilities | 5,199,780,000 | ' | ' | ' | 4,292,998,000 | ' | ' | ' | 5,199,780,000 | 4,292,998,000 | ' |
Income Before Income Taxes [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
United States | ' | ' | ' | ' | ' | ' | ' | ' | 3,268,727,000 | 1,988,105,000 | 2,156,147,000 |
Foreign | ' | ' | ' | ' | ' | ' | ' | ' | 168,159,000 | -707,365,000 | -246,348,000 |
Income (Loss) Before Income Taxes | 919,082,000 | 721,555,000 | 1,035,230,000 | 761,019,000 | -445,822,000 | 560,189,000 | 646,239,000 | 520,134,000 | 3,436,886,000 | 1,280,740,000 | 1,909,799,000 |
Current income tax provision [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Federal | ' | ' | ' | ' | ' | ' | ' | ' | 207,777,000 | 242,674,000 | 94,244,000 |
State | ' | ' | ' | ' | ' | ' | ' | ' | 22,856,000 | 22,573,000 | 1,083,000 |
Foreign | ' | ' | ' | ' | ' | ' | ' | ' | 134,379,000 | 152,276,000 | 224,049,000 |
Total | ' | ' | ' | ' | ' | ' | ' | ' | 365,012,000 | 417,523,000 | 319,376,000 |
Deferred income tax provision [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Federal | ' | ' | ' | ' | ' | ' | ' | ' | 915,994,000 | 454,173,000 | 608,181,000 |
State | ' | ' | ' | ' | ' | ' | ' | ' | 26,305,000 | 632,000 | 40,321,000 |
Foreign | ' | ' | ' | ' | ' | ' | ' | ' | -67,534,000 | -161,867,000 | -149,202,000 |
Total | ' | ' | ' | ' | ' | ' | ' | ' | 874,765,000 | 292,938,000 | 499,300,000 |
Income Tax Provision | ' | ' | ' | ' | ' | ' | ' | ' | 1,239,777,000 | 710,461,000 | 818,676,000 |
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) | ' | ' | ' | ' | ' | ' | ' | ' | 0.93% | 1.18% | 1.41% |
Income Tax Provision Related to Foreign Operations (in hundredths) | ' | ' | ' | ' | ' | ' | ' | ' | -0.20% | 1.38% | 0.88% |
Income Tax Provision Related to Trinidad Operations (in hundredths) | ' | ' | ' | ' | ' | ' | ' | ' | 0.43% | -0.27% | 3.37% |
Canadian Valuation Allowances (in hundredths) | ' | ' | ' | ' | ' | ' | ' | ' | 0.00% | 10.57% | 0.00% |
Canadian Natural Gas Impairments (in hundredths) | ' | ' | ' | ' | ' | ' | ' | ' | 0.00% | 6.90% | 1.85% |
Other (in hundredths) | ' | ' | ' | ' | ' | ' | ' | ' | -0.09% | 0.71% | 0.36% |
Effective Income Tax Rate (in hundredths) | ' | ' | ' | ' | ' | ' | ' | ' | 36.07% | 55.47% | 42.87% |
Canadian statutory rate (in hundredths) | ' | ' | ' | ' | ' | ' | ' | ' | ' | 26.00% | ' |
Additional income tax provision related to valuation allowances recorded to reduce value of foreign deferred tax assets | 183,000,000 | ' | ' | ' | 158,000,000 | ' | ' | ' | 183,000,000 | 158,000,000 | ' |
Unrecognized tax benefits balance | 0 | ' | ' | ' | 33,000,000 | ' | ' | ' | 0 | 33,000,000 | ' |
Foreign subsidiaries' undistributed earnings | 2,700,000,000 | ' | ' | ' | ' | ' | ' | ' | 2,700,000,000 | ' | ' |
Regular tax net operating loss utilized | ' | ' | ' | ' | ' | ' | ' | ' | 787,000,000 | ' | ' |
Balance of federal net operating loss expected to be carried forward | ' | ' | ' | ' | ' | ' | ' | ' | 314,000,000 | ' | ' |
State Income Tax Net Operating Losses | ' | ' | ' | ' | ' | ' | ' | ' | 700,000,000 | ' | ' |
Tax benefit reflected in additional paid-in-capital due to current year utilization of net operating losses | 15,000,000 | ' | ' | ' | ' | ' | ' | ' | 15,000,000 | ' | ' |
Additional tax benefit to be reflected in additional paid-in-capital due to future utilization of net operating losses | 16,000,000 | ' | ' | ' | ' | ' | ' | ' | 16,000,000 | ' | ' |
Alternative minimum tax paid | ' | ' | ' | ' | ' | ' | ' | ' | 161,000,000 | ' | ' |
AMT Paid In Years Prior To Prior Reporting Period | ' | ' | ' | ' | ' | ' | ' | ' | 469,000,000 | ' | ' |
Tax net operating loss incurred in United Kingdom in current year | ' | ' | ' | ' | ' | ' | ' | ' | 282,000,000 | ' | ' |
Balance of tax net operating loss incurred in the United Kingdom in prior years | ' | ' | ' | ' | ' | ' | ' | ' | $267,000,000 | ' | ' |
Employee_Benefit_Plans_Details
Employee Benefit Plans (Details) (USD $) | 12 Months Ended | |||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||
Stock based compensation by job function [Line Items] | ' | ' | ' | |||
Compensation expense related to the company's stock-based compensation plans | $134,467,000 | $127,504,000 | $128,205,000 | |||
Maximum shares of stock-based awards approved | 28,400,000 | ' | ' | |||
Federal income tax (expense) / benefit recognized from stock-based compensation | 56,000,000 | 67,000,000 | 25,000 | |||
Maximum term of stock options and SARs granted | '10 years | ' | ' | |||
Percentage of the fair market value at which employees may purchase company stock via the ESPP | '0.85 | ' | ' | |||
Maximum Percentage Of Employee Pay Eligible For Contribution To Espp Percentage | 10.00% | ' | ' | |||
Term of ESPP offering period description | 'two six-month offering periods | ' | ' | |||
Stock-based compensation expense related to stock options, SAR and ESPP grants | 53,000,000 | 49,000,000 | 48,000,000 | |||
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items] | ' | ' | ' | |||
Common Shares Available for Grant | 16,600,000 | ' | ' | |||
Share-Based Compensation Arrangement By Share-Based Payment Award [Abstract] | ' | ' | ' | |||
Stock options/SARs vested or expected to vest (in shares) | 5 | ' | ' | |||
Weighted average grant price for stock options/SARs vested or expected to vest (per share) | $108.03 | ' | ' | |||
Intrinsic value of stock options/SARs vested or expected to vest | 300,000,000 | ' | ' | |||
Weighted Average Remaining Contractual Life for Stock Options/SARs Vested or Expected to Vest | '4 years 6 months | ' | ' | |||
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 | 5,226,000 | ' | ' | |||
Weighted Average Remaining Life for Outstanding Options and SARs | '5 years | ' | ' | |||
Weighted Average Grant Price For Outstanding Options and SARs | $108.86 | ' | ' | |||
Aggregate Intrinsic Value For Outstanding Options and SARs | 309,422,000 | [1] | ' | ' | ||
Stock Options and SARs Exercisable | 2,319,000 | ' | ' | |||
Weighted Average Remaining Life For Exercisable Units | '3 years | ' | ' | |||
Weighted Average Grant Price For Exercisable Options and SARs | $87.90 | ' | ' | |||
Aggregate Intrinsic Value For Exercisable Units | 185,362,000 | [1] | ' | ' | ||
Grant Price Range 1 [Member] | ' | ' | ' | |||
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items] | ' | ' | ' | |||
Upper range of grant price (in dollars per share) | $26 | ' | ' | |||
Lower range of grant price (in dollars per share) | $81.99 | ' | ' | |||
Stock Options and SARs Outstanding | 764,000 | ' | ' | |||
Weighted Average Remaining Life for Outstanding Options and SARs | '2 years | ' | ' | |||
Weighted Average Grant Price For Outstanding Options and SARs | $77.08 | ' | ' | |||
Stock Options and SARs Exercisable | 760,000 | ' | ' | |||
Weighted Average Remaining Life For Exercisable Units | '2 years | ' | ' | |||
Weighted Average Grant Price For Exercisable Options and SARs | $77.13 | ' | ' | |||
Grant Price Range 2 [Member] | ' | ' | ' | |||
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items] | ' | ' | ' | |||
Upper range of grant price (in dollars per share) | $82 | ' | ' | |||
Lower range of grant price (in dollars per share) | $89.99 | ' | ' | |||
Stock Options and SARs Outstanding | 1,380,000 | ' | ' | |||
Weighted Average Remaining Life for Outstanding Options and SARs | '4 years | ' | ' | |||
Weighted Average Grant Price For Outstanding Options and SARs | $84.82 | ' | ' | |||
Stock Options and SARs Exercisable | 765,000 | ' | ' | |||
Weighted Average Remaining Life For Exercisable Units | '3 years | ' | ' | |||
Weighted Average Grant Price For Exercisable Options and SARs | $85.87 | ' | ' | |||
Grant Price Range 3 [Member] | ' | ' | ' | |||
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items] | ' | ' | ' | |||
Upper range of grant price (in dollars per share) | $90 | ' | ' | |||
Lower range of grant price (in dollars per share) | $109.99 | ' | ' | |||
Stock Options and SARs Outstanding | 837,000 | ' | ' | |||
Weighted Average Remaining Life for Outstanding Options and SARs | '4 years | ' | ' | |||
Weighted Average Grant Price For Outstanding Options and SARs | $93.39 | ' | ' | |||
Stock Options and SARs Exercisable | 519,000 | ' | ' | |||
Weighted Average Remaining Life For Exercisable Units | '4 years | ' | ' | |||
Weighted Average Grant Price For Exercisable Options and SARs | $92.87 | ' | ' | |||
Grant Price Range 4 [Member] | ' | ' | ' | |||
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items] | ' | ' | ' | |||
Upper range of grant price (in dollars per share) | $110 | ' | ' | |||
Lower range of grant price (in dollars per share) | $136.99 | ' | ' | |||
Stock Options and SARs Outstanding | 1,154,000 | ' | ' | |||
Weighted Average Remaining Life for Outstanding Options and SARs | '6 years | ' | ' | |||
Weighted Average Grant Price For Outstanding Options and SARs | $113.22 | ' | ' | |||
Stock Options and SARs Exercisable | 274,000 | ' | ' | |||
Weighted Average Remaining Life For Exercisable Units | '5 years | ' | ' | |||
Weighted Average Grant Price For Exercisable Options and SARs | $113.65 | ' | ' | |||
Grant Price Range 5 [Member] | ' | ' | ' | |||
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items] | ' | ' | ' | |||
Upper range of grant price (in dollars per share) | $137 | ' | ' | |||
Lower range of grant price (in dollars per share) | $178.99 | ' | ' | |||
Stock Options and SARs Outstanding | 1,091,000 | ' | ' | |||
Weighted Average Remaining Life for Outstanding Options and SARs | '7 years | ' | ' | |||
Weighted Average Grant Price For Outstanding Options and SARs | $168.77 | ' | ' | |||
Stock Options and SARs Exercisable | 1,000 | ' | ' | |||
Weighted Average Remaining Life For Exercisable Units | '1 year | ' | ' | |||
Weighted Average Grant Price For Exercisable Options and SARs | $168.86 | ' | ' | |||
Stock Options and SARS [Member] | ' | ' | ' | |||
Weighted Average Fair Value And Valuation Assumptions Used To Value Stock-Based Compensation [Abstract] | ' | ' | ' | |||
Weighted Average Fair Value of Grants | $54.70 | $37.95 | $29.92 | |||
Expected Volatility (in hundredths) | 35.86% | 39.68% | 40.96% | |||
Risk-Free Interest Rate (in hundredths) | 0.78% | 0.45% | 0.58% | |||
Dividend Yield (in hundredths) | 0.40% | 0.60% | 0.70% | |||
Expected Life (in years) | '5 years 6 months | '5 years 7 months 6 days | '5 years 6 months | |||
Stock option and SAR Rollforward [Abstract] | ' | ' | ' | |||
Outstanding at January 1 (in shares) | 6,219,000 | 8,374,000 | 8,445,000 | |||
Granted (in shares) | 1,134,000 | 1,240,000 | 1,509,000 | |||
Exercised (in shares) | -2,023,000 | [2] | -3,246,000 | [2] | -1,399,000 | [2] |
Forfeited (in shares) | -104,000 | -149,000 | -181,000 | |||
Outstanding at December 31 (in shares) | 5,226,000 | 6,219,000 | 8,374,000 | |||
Share-Based Compensation Arrangement By Share-Based Payment Award [Abstract] | ' | ' | ' | |||
Outstanding at January 1 (in dollars per share) | $85.81 | $70.01 | $64.49 | |||
Granted (in dollars per share) | $167.40 | $111.97 | $85.29 | |||
Exercised (in dollars per share) | $71.23 | [2] | $54.80 | [2] | $50.86 | [2] |
Forfeited (in dollars per share) | $101.56 | $91.18 | $87.74 | |||
Outstanding at December 31 (in dollars per share) | $108.86 | $85.81 | $70.01 | |||
Stock Options/SARs Exercisable at December 31 (in shares) | 2,319,000 | 3,143,000 | 5,148,000 | |||
Stock Options/SARs Exercisable at December 31 (in dollars per share) | $87.90 | $74.98 | $59.19 | |||
Intrinsic value of stock options/SARs exercised during the period | 151,000,000 | 185,000,000 | 78,000,000 | |||
Unrecognized compensation expense | 103,000,000 | ' | ' | |||
Weighted average period over which unrecognized compensation expense will be recognized | '2 years 8 months 12 days | ' | ' | |||
ESPP [Member] | ' | ' | ' | |||
Stock Options/SARs and Employee Stock Purchase Plan (ESPP) Disclosures [Line Items] | ' | ' | ' | |||
Common Shares Available for Grant | 498,000 | ' | ' | |||
Weighted Average Fair Value And Valuation Assumptions Used To Value Stock-Based Compensation [Abstract] | ' | ' | ' | |||
Weighted Average Fair Value of Grants | $30.12 | $25.11 | $22.75 | |||
Expected Volatility (in hundredths) | 29.89% | 40.92% | 29.82% | |||
Risk-Free Interest Rate (in hundredths) | 0.11% | 0.11% | 0.14% | |||
Dividend Yield (in hundredths) | 0.60% | 0.60% | 0.70% | |||
Expected Life (in years) | '0 years 6 months | '0 years 6 months | '0 years 6 months | |||
Share-Based Compensation Arrangement By Share-Based Payment Award [Abstract] | ' | ' | ' | |||
Approximate Number of Participants | 1,844 | 1,705 | 1,525 | |||
Shares Purchased | 128,000 | 164,000 | 135,000 | |||
Aggregate Purchase Price | 14,015,000 | 12,522,000 | 10,947,000 | |||
Restricted Stock And Restricted Stock Units [Member] | ' | ' | ' | |||
Share-Based Compensation Arrangement By Share-Based Payment Award [Abstract] | ' | ' | ' | |||
Vesting period | '5 years | ' | ' | |||
Unrecognized compensation expense | 154,000,000 | ' | ' | |||
Weighted average period over which unrecognized compensation expense will be recognized | '2 years 4 months 24 days | ' | ' | |||
Share Based Compensation Arrangement By Restricted Stock And Restricted Stock Units Compensation Cost | 72,000,000 | 72,000,000 | 80,000,000 | |||
Number of Shares and Units [Roll Forward] | ' | ' | ' | |||
Outstanding at January 1 (in shares) | 3,818,000 | [3] | 4,240,000 | [3] | 4,009,000 | |
Granted (in shares) | 647,000 | 767,000 | 932,000 | |||
Released (in shares) | -684,000 | [4] | -1,059,000 | [4] | -457,000 | [4] |
Forfeited (in shares) | -102,000 | -130,000 | -244,000 | |||
Outstanding at December 31 (in shares) | 3,679,000 | [3] | 3,818,000 | [3] | 4,240,000 | [3] |
Weighted Average Grant Fair Value [Abstract] | ' | ' | ' | |||
Outstanding at January 1 (in dollars per share) | $91.06 | [3] | $82.93 | [3] | $79.13 | |
Granted (in dollars per share) | $152.07 | $112.17 | $90.87 | |||
Released (in dollars per share) | $104.78 | [4] | $72.70 | [4] | $66.10 | [4] |
Forfeited (in dollars per share) | $97.10 | $85.36 | $82.45 | |||
Outstanding at December 31 (in dollars per share) | $99.08 | [3] | $91.06 | [3] | $82.93 | [3] |
Intrinsic value of stock based compensation | 101,000,000 | 120,000,000 | 44,000,000 | |||
Aggregate Intrinsic Value Of Restricted Stock And Restricted Stock Units | 617,000,000 | 461,000,000 | ' | |||
Performance Units and Performance Stock [Member] | ' | ' | ' | |||
Weighted Average Fair Value And Valuation Assumptions Used To Value Stock-Based Compensation [Abstract] | ' | ' | ' | |||
Weighted Average Fair Value of Grants | $200.68 | $134.09 | ' | |||
Expected Volatility (in hundredths) | 33.63% | 36.39% | ' | |||
Risk-Free Interest Rate (in hundredths) | 0.79% | 0.39% | ' | |||
Share-Based Compensation Arrangement By Share-Based Payment Award [Abstract] | ' | ' | ' | |||
Vesting period | '5 years | ' | ' | |||
Unrecognized compensation expense | 6,000,000 | ' | ' | |||
Weighted average period over which unrecognized compensation expense will be recognized | '2 years 4 months 24 days | ' | ' | |||
Number of Shares and Units [Roll Forward] | ' | ' | ' | |||
Outstanding at January 1 (in shares) | 71,000 | [5] | 0 | ' | ||
Granted (in shares) | 60,000 | 71,000 | ' | |||
Released (in shares) | 0 | 0 | ' | |||
Forfeited (in shares) | 0 | 0 | ' | |||
Outstanding at December 31 (in shares) | 131,000 | [5] | 71,000 | [5] | ' | |
Weighted Average Grant Fair Value [Abstract] | ' | ' | ' | |||
Outstanding at January 1 (in dollars per share) | $134.09 | [5] | $0 | ' | ||
Granted (in dollars per share) | $200.68 | $134.09 | ' | |||
Released (in dollars per share) | $0 | $0 | ' | |||
Forfeited (in dollars per share) | $0 | $0 | ' | |||
Outstanding at December 31 (in dollars per share) | $164.36 | [5] | $134.09 | [5] | ' | |
Intrinsic value of stock based compensation | 21,900,000 | 8,600,000 | ' | |||
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 | 261,390 | ' | ' | |||
Share Based Compensation Arrangement By Performance Units and Stock Compensation Cost | 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 | ' | ' | |||
Lease And Well [Member] | ' | ' | ' | |||
Stock based compensation by job function [Line Items] | ' | ' | ' | |||
Compensation expense related to the company's stock-based compensation plans | 35,000,000 | 35,000,000 | 33,000,000 | |||
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 | 26,000,000 | |||
General And Administrative [Member] | ' | ' | ' | |||
Stock based compensation by job function [Line Items] | ' | ' | ' | |||
Compensation expense related to the company's stock-based compensation plans | 71,000,000 | 65,000,000 | 68,000,000 | |||
Pension Plans Defined Benefit and Contribution [Member] | ' | ' | ' | |||
Defined Benefit and Defined Contribution Plan Disclosure [Line Items] | ' | ' | ' | |||
Total pension plan costs | 37,000,000 | 36,000,000 | 27,000,000 | |||
Company contributions to foreign pension plans | 4,000,000 | 3,000,000 | 3,000,000 | |||
Benefit obligation | 13,000,000 | 14,000,000 | ' | |||
Fair value of foreign pension plan assets | 11,000,000 | 10,000,000 | ' | |||
Accrued benefit cost | $1,000,000 | $2,000,000 | ' | |||
[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. | |||||
[2] | The total intrinsic value of stock options/SARs exercised during the years 2013, 2012 and 2011 was $151 million, $185 million and $78 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] | The aggregate intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2013 and 2012 was approximately $617 million and $461 million, respectively. | |||||
[4] | The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2013, 2012 and 2011 was $101 million, $120 million and $44 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date restricted stock and restricted stock units are released. | |||||
[5] | The total intrinsic value of performance units and performance stock outstanding at December 31, 2013 and 2012 was $21.9 million and $8.6 million, respectively. |
Commitments_and_Contingencies_1
Commitments and Contingencies (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Commitments and Contingencies [Abstract] | ' | ' | ' |
Standby letters of credit and guarantees outstanding | $711,000,000 | $636,000,000 | ' |
Subsidiary indebtedness guaranteed | 150,000,000 | 150,000,000 | ' |
Subsidiary payment obligations guaranteed | 561,000,000 | 486,000,000 | ' |
Total Minimum Commitments [Abstract] | ' | ' | ' |
2014 | 1,777,014,000 | ' | ' |
2015 - 2016 | 1,808,827,000 | ' | ' |
2017 - 2018 | 1,272,578,000 | ' | ' |
2019 and beyond | 1,176,230,000 | ' | ' |
Total Minimum Commitments | 6,034,649,000 | ' | ' |
Rental expenses associated with existing leases | $191,000,000 | $182,000,000 | $149,000,000 |
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, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||||||
Numerator for Basic and Diluted Earnings per Share - [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Net Income | $580,194 | [1] | $462,498 | [1] | $659,692 | [1] | $494,725 | [1] | ($504,999) | [1] | $355,491 | [1] | $395,778 | [1] | $324,009 | [1] | $2,197,109 | $570,279 | $1,091,123 |
Denominator for Basic Earnings per Share - [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Weighted Average Shares (in shares) | ' | ' | ' | ' | ' | ' | ' | ' | 270,170,000 | 267,577,000 | 262,735,000 | ||||||||
Potential Dilutive Common Shares -[Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Stock Options/SARs (in shares) | ' | ' | ' | ' | ' | ' | ' | ' | 1,159,000 | 1,456,000 | 1,707,000 | ||||||||
Restricted Stock/Units and Performance Units/Stock (in shares) | ' | ' | ' | ' | ' | ' | ' | ' | 1,785,000 | 1,729,000 | 1,826,000 | ||||||||
Denominator for Diluted Earnings per Share - [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Adjusted Diluted Weighted Average Shares (in shares) | 273,983,000 | 273,576,000 | 272,739,000 | 272,263,000 | 268,941,000 | 270,982,000 | 269,985,000 | 270,242,000 | 273,114,000 | 270,762,000 | 266,268,000 | ||||||||
Net Income Per Share [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Basic (in dollars per share) | $2.14 | [2] | $1.71 | [2] | $2.44 | [2] | $1.84 | [2] | ($1.88) | [2] | $1.33 | [2] | $1.48 | [2] | $1.22 | [2] | $8.13 | $2.13 | $4.15 |
Diluted (in dollars per share) | $2.12 | [2] | $1.69 | [2] | $2.42 | [2] | $1.82 | [2] | ($1.88) | [2] | $1.31 | [2] | $1.47 | [2] | $1.20 | [2] | $8.04 | $2.11 | $4.10 |
Antidilutive Stock Options and SARs excluded from Diluted Earnings Per Share Calculation (in shares) | ' | ' | ' | ' | ' | ' | ' | ' | 300,000 | 500,000 | 400,000 | ||||||||
[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. | ||||||||||||||||||
[2] | Fourth quarter 2012 results include the impact of pretax impairments of $1,020 million, primarily related to proved and unproved natural gas properties in Canada and the United States as well as an additional income tax provision of $135 million related to valuation allowances recorded to reduce the value of Canadian deferred tax assets. |
Supplemental_Cash_Flow_Informa2
Supplemental Cash Flow Information (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Supplemental Cash Flow Information [Abstract] | ' | ' | ' |
Interest, Net of Capitalized Interest | $235,854,000 | $196,944,000 | $186,718,000 |
Income Taxes, Net of Refunds Received | 294,739,000 | 360,006,000 | 260,224,000 |
Accrued Capital Expenditures | 731,000,000 | 734,000,000 | 663,000,000 |
Non-cash investing and financing activities from property exchanges. | 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, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||||
Schedule of Segment Reporting Information By Segment [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Crude Oil and Condensate | ' | ' | ' | ' | ' | ' | ' | ' | $8,300,647,000 | $5,659,437,000 | $3,838,284,000 | |||||
Natural Gas Liquids | ' | ' | ' | ' | ' | ' | ' | ' | 773,970,000 | 727,177,000 | 779,364,000 | |||||
Natural Gas | ' | ' | ' | ' | ' | ' | ' | ' | 1,681,029,000 | 1,571,762,000 | 2,240,540,000 | |||||
(Losses) Gains on Mark-to-Market Commodity Derivative Contracts | ' | ' | ' | ' | ' | ' | ' | ' | -166,349,000 | 393,744,000 | 626,053,000 | |||||
Gathering, Processing and Marketing | ' | ' | ' | ' | ' | ' | ' | ' | 3,643,749,000 | 3,096,694,000 | 2,115,792,000 | |||||
Gains on Asset Dispositions, Net | ' | ' | ' | ' | ' | ' | ' | ' | 197,565,000 | 192,660,000 | 492,909,000 | |||||
Other, Net | ' | ' | ' | ' | ' | ' | ' | ' | 56,507,000 | 41,162,000 | 33,173,000 | |||||
Net Operating Revenues | 3,749,023,000 | 3,541,396,000 | 3,840,185,000 | 3,356,514,000 | 3,011,811,000 | 2,954,855,000 | 2,909,319,000 | 2,806,651,000 | 14,487,118,000 | [1] | 11,682,636,000 | [2] | 10,126,115,000 | [3] | ||
Depreciation, Depletion and Amortization | ' | ' | ' | ' | ' | ' | ' | ' | 3,600,976,000 | 3,169,703,000 | 2,516,381,000 | |||||
Operating Income (Loss) | 980,324,000 | 769,769,000 | 1,092,044,000 | 833,074,000 | -378,061,000 | 605,747,000 | 692,339,000 | 559,772,000 | 3,675,211,000 | 1,479,797,000 | 2,113,309,000 | |||||
Interest Income | ' | ' | ' | ' | ' | ' | ' | ' | 5,585,000 | 8,771,000 | 1,019,000 | |||||
Other Income (Expense) | ' | ' | ' | ' | ' | ' | ' | ' | -8,450,000 | 5,724,000 | 5,834,000 | |||||
Net Interest Expense | ' | ' | ' | ' | ' | ' | ' | ' | 235,460,000 | 213,552,000 | 210,363,000 | |||||
Income (Loss) Before Income Taxes | 919,082,000 | 721,555,000 | 1,035,230,000 | 761,019,000 | -445,822,000 | 560,189,000 | 646,239,000 | 520,134,000 | 3,436,886,000 | 1,280,740,000 | 1,909,799,000 | |||||
Income Tax Provision (Benefit) | 338,888,000 | 259,057,000 | 375,538,000 | 266,294,000 | 59,177,000 | 204,698,000 | 250,461,000 | 196,125,000 | 1,239,777,000 | 710,461,000 | 818,676,000 | |||||
Additions to Oil and Gas Properties, Excluding Dry Hole Costs | ' | ' | ' | ' | ' | ' | ' | ' | 6,622,436,000 | 6,720,346,000 | 6,241,167,000 | |||||
Total Property, Plant and Equipment, Net | 26,148,836,000 | ' | ' | ' | 23,337,681,000 | ' | ' | ' | 26,148,836,000 | 23,337,681,000 | 21,288,824,000 | |||||
Total Assets | 30,574,238,000 | ' | ' | ' | 27,336,578,000 | ' | ' | ' | 30,574,238,000 | 27,336,578,000 | 24,838,797,000 | |||||
Percentage of revenues used to determine significant purchasers (in hundredths) | ' | ' | ' | ' | ' | ' | ' | ' | 10.00% | ' | ' | |||||
United States [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Schedule of Segment Reporting Information By Segment [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Crude Oil and Condensate | ' | ' | ' | ' | ' | ' | ' | ' | 8,035,358,000 | 5,383,612,000 | 3,458,248,000 | |||||
Natural Gas Liquids | ' | ' | ' | ' | ' | ' | ' | ' | 761,535,000 | 713,497,000 | 762,730,000 | |||||
Natural Gas | ' | ' | ' | ' | ' | ' | ' | ' | 1,100,808,000 | 951,463,000 | 1,593,964,000 | |||||
(Losses) Gains on Mark-to-Market Commodity Derivative Contracts | ' | ' | ' | ' | ' | ' | ' | ' | -166,349,000 | 393,744,000 | 626,053,000 | |||||
Gathering, Processing and Marketing | ' | ' | ' | ' | ' | ' | ' | ' | 3,636,209,000 | 3,091,281,000 | 2,115,768,000 | |||||
Gains on Asset Dispositions, Net | ' | ' | ' | ' | ' | ' | ' | ' | 93,876,000 | 166,201,000 | 475,878,000 | |||||
Other, Net | ' | ' | ' | ' | ' | ' | ' | ' | 51,713,000 | 40,780,000 | 32,329,000 | |||||
Net Operating Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 13,513,150,000 | [1] | 10,740,578,000 | [2] | 9,064,970,000 | [3] | ||
Depreciation, Depletion and Amortization | ' | ' | ' | ' | ' | ' | ' | ' | 3,223,596,000 | 2,780,563,000 | 2,131,706,000 | |||||
Operating Income (Loss) | ' | ' | ' | ' | ' | ' | ' | ' | 3,543,841,000 | 2,233,911,000 | 2,252,508,000 | |||||
Interest Income | ' | ' | ' | ' | ' | ' | ' | ' | 2,803,000 | 8,343,000 | 436,000 | |||||
Other Income (Expense) | ' | ' | ' | ' | ' | ' | ' | ' | -29,696,000 | -12,455,000 | -6,480,000 | |||||
Net Interest Expense | ' | ' | ' | ' | ' | ' | ' | ' | 283,209,000 | 242,138,000 | 214,360,000 | |||||
Income (Loss) Before Income Taxes | ' | ' | ' | ' | ' | ' | ' | ' | 3,233,739,000 | 1,987,661,000 | 2,032,104,000 | |||||
Income Tax Provision (Benefit) | ' | ' | ' | ' | ' | ' | ' | ' | 1,161,328,000 | 707,401,000 | 732,362,000 | |||||
Additions to Oil and Gas Properties, Excluding Dry Hole Costs | ' | ' | ' | ' | ' | ' | ' | ' | 6,133,894,000 | 6,198,267,000 | 5,790,590,000 | |||||
Total Property, Plant and Equipment, Net | 24,456,383,000 | ' | ' | ' | 21,560,998,000 | ' | ' | ' | 24,456,383,000 | 21,560,998,000 | 18,711,774,000 | |||||
Total Assets | 27,668,713,000 | ' | ' | ' | 24,523,072,000 | ' | ' | ' | 27,668,713,000 | 24,523,072,000 | 21,313,158,000 | |||||
Amount of sales with a single significant purchaser in the United States segment | ' | ' | ' | ' | ' | ' | ' | ' | 3,900,000,000 | 2,200,000,000 | ' | |||||
Amount of sales with a second significant purchaser in the United States segment. | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000,000 | ' | ' | |||||
Canada [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Schedule of Segment Reporting Information By Segment [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Crude Oil and Condensate | ' | ' | ' | ' | ' | ' | ' | ' | 221,999,000 | 221,556,000 | 264,895,000 | |||||
Natural Gas Liquids | ' | ' | ' | ' | ' | ' | ' | ' | 12,435,000 | 13,680,000 | 16,634,000 | |||||
Natural Gas | ' | ' | ' | ' | ' | ' | ' | ' | 85,446,000 | 86,361,000 | 178,324,000 | |||||
(Losses) Gains on Mark-to-Market Commodity Derivative Contracts | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 0 | |||||
Gathering, Processing and Marketing | ' | ' | ' | ' | ' | ' | ' | ' | 1,476,000 | 0 | 0 | |||||
Gains on Asset Dispositions, Net | ' | ' | ' | ' | ' | ' | ' | ' | 102,570,000 | 26,459,000 | 17,033,000 | |||||
Other, Net | ' | ' | ' | ' | ' | ' | ' | ' | 4,770,000 | 367,000 | 258,000 | |||||
Net Operating Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 428,696,000 | 348,423,000 | 477,144,000 | |||||
Depreciation, Depletion and Amortization | ' | ' | ' | ' | ' | ' | ' | ' | 180,836,000 | 223,689,000 | 260,084,000 | |||||
Operating Income (Loss) | ' | ' | ' | ' | ' | ' | ' | ' | -45,214,000 | -1,065,434,000 | -459,520,000 | |||||
Interest Income | ' | ' | ' | ' | ' | ' | ' | ' | 2,076,000 | 123,000 | 342,000 | |||||
Other Income (Expense) | ' | ' | ' | ' | ' | ' | ' | ' | 7,707,000 | -8,689,000 | -2,375,000 | |||||
Net Interest Expense | ' | ' | ' | ' | ' | ' | ' | ' | -4,204,000 | 6,589,000 | 23,085,000 | |||||
Income (Loss) Before Income Taxes | ' | ' | ' | ' | ' | ' | ' | ' | -31,227,000 | -1,080,589,000 | -484,638,000 | |||||
Income Tax Provision (Benefit) | ' | ' | ' | ' | ' | ' | ' | ' | 598,000 | -134,745,000 | -125,474,000 | |||||
Additions to Oil and Gas Properties, Excluding Dry Hole Costs | ' | ' | ' | ' | ' | ' | ' | ' | 137,920,000 | 302,851,000 | 259,634,000 | |||||
Total Property, Plant and Equipment, Net | 602,333,000 | ' | ' | ' | 877,996,000 | ' | ' | ' | 602,333,000 | 877,996,000 | 1,760,066,000 | |||||
Total Assets | 880,765,000 | ' | ' | ' | 1,202,031,000 | ' | ' | ' | 880,765,000 | 1,202,031,000 | 2,131,949,000 | |||||
Trinidad [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Schedule of Segment Reporting Information By Segment [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Crude Oil and Condensate | ' | ' | ' | ' | ' | ' | ' | ' | 40,379,000 | 50,708,000 | 112,554,000 | |||||
Natural Gas Liquids | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 0 | |||||
Natural Gas | ' | ' | ' | ' | ' | ' | ' | ' | 477,103,000 | 514,322,000 | 442,589,000 | |||||
(Losses) Gains on Mark-to-Market Commodity Derivative Contracts | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 0 | |||||
Gathering, Processing and Marketing | ' | ' | ' | ' | ' | ' | ' | ' | 6,064,000 | 5,413,000 | 24,000 | |||||
Gains on Asset Dispositions, Net | ' | ' | ' | ' | ' | ' | ' | ' | 1,119,000 | 0 | -2,000 | |||||
Other, Net | ' | ' | ' | ' | ' | ' | ' | ' | 24,000 | 15,000 | 586,000 | |||||
Net Operating Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 524,689,000 | 570,458,000 | 555,751,000 | |||||
Depreciation, Depletion and Amortization | ' | ' | ' | ' | ' | ' | ' | ' | 181,990,000 | 147,062,000 | 107,141,000 | |||||
Operating Income (Loss) | ' | ' | ' | ' | ' | ' | ' | ' | 266,329,000 | 371,876,000 | 383,992,000 | |||||
Interest Income | ' | ' | ' | ' | ' | ' | ' | ' | 336,000 | 125,000 | 101,000 | |||||
Other Income (Expense) | ' | ' | ' | ' | ' | ' | ' | ' | 9,889,000 | 20,482,000 | 18,755,000 | |||||
Net Interest Expense | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 238,000 | 0 | |||||
Income (Loss) Before Income Taxes | ' | ' | ' | ' | ' | ' | ' | ' | 276,554,000 | 392,245,000 | 402,848,000 | |||||
Income Tax Provision (Benefit) | ' | ' | ' | ' | ' | ' | ' | ' | 118,270,000 | 140,468,000 | 204,698,000 | |||||
Additions to Oil and Gas Properties, Excluding Dry Hole Costs | ' | ' | ' | ' | ' | ' | ' | ' | 132,984,000 | 49,376,000 | 132,159,000 | |||||
Total Property, Plant and Equipment, Net | 476,174,000 | ' | ' | ' | 535,405,000 | ' | ' | ' | 476,174,000 | 535,405,000 | 627,794,000 | |||||
Total Assets | 986,796,000 | ' | ' | ' | 1,012,727,000 | ' | ' | ' | 986,796,000 | 1,012,727,000 | 1,085,664,000 | |||||
Other International [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Schedule of Segment Reporting Information By Segment [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Crude Oil and Condensate | ' | ' | ' | ' | ' | ' | ' | ' | 2,911,000 | [4] | 3,561,000 | [4] | 2,587,000 | [4] | ||
Natural Gas Liquids | ' | ' | ' | ' | ' | ' | ' | ' | 0 | [4] | 0 | [4] | 0 | [4] | ||
Natural Gas | ' | ' | ' | ' | ' | ' | ' | ' | 17,672,000 | [4] | 19,616,000 | [4] | 25,663,000 | [4] | ||
(Losses) Gains 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 | ' | ' | ' | ' | ' | ' | ' | ' | 20,583,000 | [4] | 23,177,000 | [4] | 28,250,000 | [4] | ||
Depreciation, Depletion and Amortization | ' | ' | ' | ' | ' | ' | ' | ' | 14,554,000 | [4] | 18,389,000 | [4] | 17,450,000 | [4] | ||
Operating Income (Loss) | ' | ' | ' | ' | ' | ' | ' | ' | -89,745,000 | [4] | -60,556,000 | [4] | -63,671,000 | [4] | ||
Interest Income | ' | ' | ' | ' | ' | ' | ' | ' | 370,000 | [4] | 180,000 | [4] | 140,000 | [4] | ||
Other Income (Expense) | ' | ' | ' | ' | ' | ' | ' | ' | 3,650,000 | [4] | 6,386,000 | [4] | -4,066,000 | [4] | ||
Net Interest Expense | ' | ' | ' | ' | ' | ' | ' | ' | -43,545,000 | [4] | -35,413,000 | [4] | -27,082,000 | [4] | ||
Income (Loss) Before Income Taxes | ' | ' | ' | ' | ' | ' | ' | ' | -42,180,000 | [4] | -18,577,000 | [4] | -40,515,000 | [4] | ||
Income Tax Provision (Benefit) | ' | ' | ' | ' | ' | ' | ' | ' | -40,419,000 | [4] | -2,663,000 | [4] | 7,090,000 | [4] | ||
Additions to Oil and Gas Properties, Excluding Dry Hole Costs | ' | ' | ' | ' | ' | ' | ' | ' | 217,638,000 | [4] | 169,852,000 | [4] | 58,784,000 | [4] | ||
Total Property, Plant and Equipment, Net | 613,946,000 | [4] | ' | ' | ' | 363,282,000 | [4] | ' | ' | ' | 613,946,000 | [4] | 363,282,000 | [4] | 189,190,000 | [4] |
Total Assets | $1,037,964,000 | [4] | ' | ' | ' | $598,748,000 | [4] | ' | ' | ' | $1,037,964,000 | [4] | $598,748,000 | [4] | $308,026,000 | [4] |
[1] | 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. | |||||||||||||||
[2] | EOG had sales activity with a single significant purchaser in the United States segment in 2012 that totaled $2.2 billion of consolidated Net Operating Revenues. | |||||||||||||||
[3] | EOG had no purchasers in 2011 whose sales totaled 10 percent or more of consolidated Net Operating Revenues. | |||||||||||||||
[4] | Other International primarily includes EOG's United Kingdom, China and Argentina operations. |
Risk_Management_Activities_Det
Risk Management Activities (Details) (USD $) | 12 Months Ended | ||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||
Risk Management Activities [Abstract] | ' | ' | ' | ||
Net Gains (Losses) on Mark-to-Market Commodity Derivative Contracts | ($166,349,000) | $393,744,000 | $626,053,000 | ||
Net Cash Received from Settlements of Commodity Derivative Contracts | 116,361,000 | 711,479,000 | 180,701,000 | ||
Derivatives, Fair Value [Line Items] | ' | ' | ' | ||
Receivable Major Customer Percentage | 10.00% | 26.00% | ' | ||
Derivatives Assets, Current | 8,260,000 | 166,135,000 | ' | ||
Derivative Liabilities, Current | 127,542,000 | 7,617,000 | ' | ||
Foreign Currency Exchange Rate Derivative [Abstract] | ' | ' | ' | ||
After-Tax Net Impact Other Comprehensive Income Increase (Decrease) From The Foreign Currency Swap | 2,000,000 | 1,000,000 | -1,000,000 | ||
Interest Rate Derivative [Abstract] | ' | ' | ' | ||
Interest Rate Swap, Notional Amount | 350,000,000 | ' | ' | ||
After-Tax Net Impact Other Comprehensive Income Increase (Decrease) From Interest Rate Swap | 2,000,000 | -100,000 | -3,000,000 | ||
Derivative Collateral [Abstract] | ' | ' | ' | ||
Collateral Held on Derivative | 0 | 6,000,000 | ' | ||
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 | 8,000,000 | [1] | 166,000,000 | [1] | ' |
Derivative asset, gross assets | 18,000,000 | 271,000,000 | ' | ||
Derivative asset, gross liabilities | 10,000,000 | 105,000,000 | ' | ||
Crude Oil and Natural Gas Derivative Contracts [Member] | Liabilities From Price Risk Management Activities [Member] | ' | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ' | ||
Derivative Liabilities, Current | 127,000,000 | [2] | 8,000,000 | [2] | ' |
Derivative liabilities, gross liabilities | 137,000,000 | 113,000,000 | ' | ||
Derivative liabilities, gross assets | 10,000,000 | 105,000,000 | ' | ||
Crude Oil and Natural Gas Derivative Contracts [Member] | Other Liabilities [Member] | ' | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ' | ||
Other Liabilities | 0 | [3] | 13,000,000 | [3] | ' |
Derivative liabilities, gross liabilities | ' | 13,000,000 | ' | ||
Interest Rate Swap [Member] | Other Current Liabilities [Member] | ' | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ' | ||
Derivative Liabilities, Current | 1,000,000 | 0 | ' | ||
Interest Rate Swap [Member] | Other Liabilities [Member] | ' | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ' | ||
Other Liabilities | 0 | 4,000,000 | ' | ||
Foreign Currency Swap [Member] | Other Current Liabilities [Member] | ' | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ' | ||
Derivative Liabilities, Current | 40,000,000 | 0 | ' | ||
Foreign Currency Swap [Member] | Other Liabilities [Member] | ' | ' | ' | ||
Derivatives, Fair Value [Line Items] | ' | ' | ' | ||
Other Liabilities | $0 | $55,000,000 | ' | ||
Crude Oil Derivative Contracts January [Member] | ' | ' | ' | ||
Derivative [Line Items] | ' | ' | ' | ||
Volume (Bbld) | 156,000 | [4] | ' | ' | |
Derivative Weighted Average Price Crude Oil ($/Bbl) | 96.3 | [4] | ' | ' | |
Crude Oil Derivative Contracts February - March [Member] | ' | ' | ' | ||
Derivative [Line Items] | ' | ' | ' | ||
Volume (Bbld) | 171,000 | [4] | ' | ' | |
Derivative Weighted Average Price Crude Oil ($/Bbl) | 96.35 | [4] | ' | ' | |
Notional volume of option to extend certain derivative contracts | 10,000 | ' | ' | ||
Crude Oil Derivative Contracts April - June Year [Member] | ' | ' | ' | ||
Derivative [Line Items] | ' | ' | ' | ||
Volume (Bbld) | 161,000 | [4] | ' | ' | |
Derivative Weighted Average Price Crude Oil ($/Bbl) | 96.33 | [4] | ' | ' | |
Notional volume of option to extend certain derivative contracts | 118,000 | ' | ' | ||
Crude Oil Derivative Contracts April - December [Member] | ' | ' | ' | ||
Derivative [Line Items] | ' | ' | ' | ||
Derivative Weighted Average Price Crude Oil (Options Exercised) ($/Bbl) | 96.6 | ' | ' | ||
Increase in notional volume if counterparties exercise all options to extend derivative contracts | 10,000 | ' | ' | ||
Crude Oil Derivative Contracts July - December [Member] | ' | ' | ' | ||
Derivative [Line Items] | ' | ' | ' | ||
Volume (Bbld) | 64,000 | [4] | ' | ' | |
Derivative Weighted Average Price Crude Oil ($/Bbl) | 95.18 | [4] | ' | ' | |
Notional volume of option to extend certain derivative contracts | 69,000 | ' | ' | ||
Derivative Weighted Average Price Crude Oil (Options Exercised) ($/Bbl) | 96.64 | ' | ' | ||
Increase in notional volume if counterparties exercise all options to extend derivative contracts | 118,000 | ' | ' | ||
Crude Oil Derivative Contracts Year Two January - June [Member] | ' | ' | ' | ||
Derivative [Line Items] | ' | ' | ' | ||
Derivative Weighted Average Price Crude Oil (Options Exercised) ($/Bbl) | 95.2 | ' | ' | ||
Increase in notional volume if counterparties exercise all options to extend derivative contracts | 69,000 | ' | ' | ||
Natural Gas Derivative Contracts January (closed) [Member] | ' | ' | ' | ||
Derivative [Line Items] | ' | ' | ' | ||
Volume (MMBtud) | 230,000 | [5] | ' | ' | |
Derivative Weighted Average Price Natural Gas ($/MMBtud) | 4.51 | [5] | ' | ' | |
Natural Gas Derivative Contracts February - December [Member] | ' | ' | ' | ||
Derivative [Line Items] | ' | ' | ' | ||
Volume (MMBtud) | 205,000 | [5] | ' | ' | |
Derivative Weighted Average Price Natural Gas ($/MMBtud) | 4.52 | [5] | ' | ' | |
Volumes (MMBtud) - Derivative Option Contracts | 355,000 | [5] | ' | ' | |
Average Price ($/MMBtu) - Derivative Option Contracts | 4.63 | [5] | ' | ' | |
[1] | The current portion of Assets from Price Risk Management Activities consists of gross assets of $18 million, partially offset by gross liabilities of $10 million, at December 31, 2013 and gross assets of $271 million, partially offset by gross liabilities of $105 million at December 31, 2012. | ||||
[2] | The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $137 million, partially offset by gross assets of $10 million, at December 31, 2013 and gross liabilities of $113 million, partially offset by gross assets of $105 million, at December 31, 2012. | ||||
[3] | The noncurrent portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $13 million at December 31, 2012. | ||||
[4] | EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional six-month and nine-month periods. Options covering a notional volume of 10,000 Bbld are exercisable on or about March 31, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 10,000 Bbld at an average price of $96.60 per barrel for each month during the period April 1, 2014 through December 31, 2014. Options covering a notional volume of 118,000 Bbld are exercisable on or about June 30, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 118,000 Bbld at an average price of $96.64 per barrel for each month during the period July 1, 2014 through December 31, 2014. Options covering a notional volume of 69,000 Bbld are exercisable on or about December 31, 2014. If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 69,000 Bbld at an average price of $95.20 per barrel for each month during the period January 1, 2015 through June 30, 2015. | ||||
[5] | 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 355,000 MMBtud at an average price of $4.63 per MMBtu for each month during the period February 1, 2014 through December 31, 2014. |
Fair_Value_Measurements_Detail
Fair Value Measurements (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Financial Liabilities: | ' | ' | ' |
Proved and unproved oil and gas properties and other assets, carrying amount | $400,000,000 | $1,524,000,000 | ' |
Proved and unproved oil and gas properties and other property, plant and equipment written down during the period - fair value at end of period | 228,000,000 | 391,000,000 | ' |
Pretax impairment charges for proved oil and gas properties and other property, plant and equipment, in which EOG utilized an accepted offer from a third-party buyer | 58,000,000 | 60,000,000 | ' |
Pretax impairment charges for proved oil and gas properties and other property, plant and equipment | 172,000,000 | 1,133,000,000 | ' |
Aggregate Principal Amount of Current and Long-Term Debt | 5,890,000,000 | 6,290,000,000 | ' |
Fair Value of Debt | 6,222,000,000 | 7,032,000,000 | ' |
Recurring [Member] | ' | ' | ' |
Financial Assets: | ' | ' | ' |
Financial Assets: Crude Oil Swaps | ' | 65,000,000 | ' |
Financial Assets: Crude Oil Options/Swaptions | ' | 36,000,000 | ' |
Financial Assets: Natural Gas Options/Swaptions | 8,000,000 | 65,000,000 | ' |
Financial Liabilities: | ' | ' | ' |
Financial Liabilities: Crude Oil Swaps | 17,000,000 | ' | ' |
Financial Liabilities: Crude Oil Options/Swaptions | 110,000,000 | 8,000,000 | ' |
Financial Liabilities: Natural Gas Options/Swaptions | ' | 13,000,000 | ' |
Financial Liabilities: Foreign Currency Rate Swap | 40,000,000 | 55,000,000 | ' |
Financial Liabilities: Interest Rate Swap | 1,000,000 | 4,000,000 | ' |
Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | ' | ' | ' |
Financial Assets: | ' | ' | ' |
Financial Assets: Crude Oil Swaps | ' | 0 | ' |
Financial Assets: Crude Oil Options/Swaptions | ' | 0 | ' |
Financial Assets: Natural Gas Options/Swaptions | 0 | 0 | ' |
Financial Liabilities: | ' | ' | ' |
Financial Liabilities: Crude Oil Swaps | 0 | ' | ' |
Financial Liabilities: Crude Oil Options/Swaptions | 0 | 0 | ' |
Financial Liabilities: Natural Gas Options/Swaptions | ' | 0 | ' |
Financial Liabilities: Foreign Currency Rate Swap | 0 | 0 | ' |
Financial Liabilities: Interest Rate Swap | 0 | 0 | ' |
Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | ' | ' | ' |
Financial Assets: | ' | ' | ' |
Financial Assets: Crude Oil Swaps | ' | 65,000,000 | ' |
Financial Assets: Crude Oil Options/Swaptions | ' | 36,000,000 | ' |
Financial Assets: Natural Gas Options/Swaptions | 8,000,000 | 65,000,000 | ' |
Financial Liabilities: | ' | ' | ' |
Financial Liabilities: Crude Oil Swaps | 17,000,000 | ' | ' |
Financial Liabilities: Crude Oil Options/Swaptions | 110,000,000 | 8,000,000 | ' |
Financial Liabilities: Natural Gas Options/Swaptions | ' | 13,000,000 | ' |
Financial Liabilities: Foreign Currency Rate Swap | 40,000,000 | 55,000,000 | ' |
Financial Liabilities: Interest Rate Swap | 1,000,000 | 4,000,000 | ' |
Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | ' | ' | ' |
Financial Assets: | ' | ' | ' |
Financial Assets: Crude Oil Swaps | ' | 0 | ' |
Financial Assets: Crude Oil Options/Swaptions | ' | 0 | ' |
Financial Assets: Natural Gas Options/Swaptions | 0 | 0 | ' |
Financial Liabilities: | ' | ' | ' |
Financial Liabilities: Crude Oil Swaps | 0 | ' | ' |
Financial Liabilities: Crude Oil Options/Swaptions | 0 | 0 | ' |
Financial Liabilities: Natural Gas Options/Swaptions | ' | 0 | ' |
Financial Liabilities: Foreign Currency Rate Swap | 0 | 0 | ' |
Financial Liabilities: Interest Rate Swap | $0 | $0 | ' |
Accounting_For_Certain_LongLiv1
Accounting For Certain Long-Lived Assets (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Schedule of Impaired Long-Lived Assets Held and Used [Line Items] | ' | ' | ' |
Amortization and impairments of unproved oil and gas properties including capitalized interest | $115 | $228 | $197 |
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 | 73 | 171 | 403 |
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 | 76 | 872 | 428 |
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 | $9 | ' | $3 |
Asset_Retirement_Obligations_D
Asset Retirement Obligations (Details) (USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | ||
Asset Retirement Obligations [Abstract] | ' | ' | ||
Carrying Amount at Beginning of Period | $665,944 | $587,084 | ||
Liabilities Incurred | 103,284 | 107,378 | ||
Liabilities Settled | -70,510 | [1] | -77,384 | [1] |
Accretion | 35,180 | 30,020 | ||
Revisions | 38,552 | 15,287 | ||
Foreign Currency Translations | -10,552 | 3,559 | ||
Carrying Amount at End of Period | 761,898 | 665,944 | ||
Current Portion | 43,857 | 30,127 | ||
Noncurrent Portion | $718,041 | $635,817 | ||
[1] | Includes settlements related to asset sales. |
Exploratory_Well_Costs_Details
Exploratory Well Costs (Details) (USD $) | 12 Months Ended | |||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||
ExploratoryWell | ExploratoryWell | ExploratoryWell | ||||
Exploratory Well Costs [Abstract] | ' | ' | ' | |||
Balance at January 1 | $49,116,000 | $61,111,000 | $99,801,000 | |||
Additions Pending the Determination of Proved Reserves | 52,099,000 | 73,332,000 | 31,271,000 | |||
Reclassifications to Proved Properties | -54,505,000 | -69,462,000 | -29,227,000 | |||
Costs Charged to Expense (1) | -35,859,000 | [1] | -17,115,000 | [1] | -42,178,000 | [1] |
Foreign Currency Translations | -1,640,000 | 1,250,000 | 1,444,000 | |||
Balance at December 31 | 9,211,000 | 49,116,000 | 61,111,000 | |||
Capitalized exploratory well costs that have been capitalized for a period less than one year | 9,211,000 | 28,319,000 | 17,009,000 | |||
Capitalized exploratory well costs that have been capitalized for a period greater than one year | 0 | 20,797,000 | [2] | 44,102,000 | [3] | |
Number of exploratory wells that have been capitalized for a period greater than one year | 0 | 1 | 4 | |||
Exploratory well costs related to an outside operated, offshore Central North Sea project in the United Kingdom | ' | ' | 20,000,000 | |||
Exploratory well costs related to an East Irish Sea project in the United Kingdom | ' | ' | 9,000,000 | |||
Exploratory well costs related to a project in the Sichuan Basin, Sichuan Province, China | ' | ' | 9,000,000 | |||
Exploratory well costs related to a shale project in British Columbia, Canada | ' | ' | $6,000,000 | |||
[1] | Includes capitalized exploratory well costs charged to either dry hole costs or impairments. | |||||
[2] | Consists of costs related to an outside operated, offshore Central North Sea natural gas project in the United Kingdom (U.K.). | |||||
[3] | Consists of costs related to an outside operated, offshore Central North Sea project in the U.K. ($20 million), an East Irish Sea project in the U.K. ($9 million), a project in the Sichuan Basin, Sichuan Province, China ($9 million), and a shale project in British Columbia, Canada ($6 million). |
Divestitures_Details
Divestitures (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Divestitures [Abstract] | ' | ' | ' |
Proceeds from Sales of Producing Properties, Acreage and Other Assets | $761 | $1,300 | $1,400 |
Assets Held-for-Sale, at Carrying Value, Total | ' | 310 | ' |
Liabilities of Assets Held-for-Sale | ' | $31 | ' |
Oil_and_Gas_Exploration_and_Pr2
Oil and Gas Exploration and Production Industries Disclosures (Details) (USD $) | 12 Months Ended | |||||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2010 | |||||
Boe | Boe | Boe | Boe | |||||
Proved Developed And Undeveloped Reserves (Boe) [Rollforward] | ' | ' | ' | ' | ||||
Net proved reserves - beginning of period (Boe) | 1,810,698,000 | [1] | 2,053,763,000 | [1] | 1,949,535,000 | [1] | ' | |
Revisions of previous estimates | 108,990,000 | [1] | -392,621,000 | [1] | -59,163,000 | [1] | ' | |
Purchases in place | 3,241,000 | [1] | 4,098,000 | [1] | 521,000 | [1] | ' | |
Extensions, discoveries and other additions | 398,965,000 | [1] | 406,932,000 | [1] | 387,255,000 | [1] | ' | |
Sales in place | -15,375,000 | [1] | -90,420,000 | [1] | -68,247,000 | [1] | ' | |
Production | -187,976,000 | [1] | -171,054,000 | [1] | -156,138,000 | [1] | ' | |
Net proved reserves - end of period (Boe) | 2,118,543,000 | [1] | 1,810,698,000 | [1] | 2,053,763,000 | [1] | ' | |
Net Proved Developed and Undeveloped Reserves [Abstract] | ' | ' | ' | ' | ||||
Net proved developed reserves (BOE) | 1,127,476,000 | 949,819,000 | 1,042,713,000 | 1,012,987,000 | ||||
Net proved undeveloped reserve (BOE) | 991,067,000 | 860,879,000 | 1,011,050,000 | 936,548,000 | ||||
Revisions of previous estimates | 108,990,000 | [1] | -392,621,000 | [1] | -59,163,000 | [1] | ' | |
Revision of Proved Reserves Due to Decrease or Increase in the Average Natural Gas Price for the Year as Compared to Prior Year (stated in Boe) | 61,000,000 | -531,000,000 | -16,000,000 | ' | ||||
Revisions of Proved Undeveloped Reserves (stated in Boe) | -1,000,000 | -293,000,000 | -7,000,000 | ' | ||||
Sales in Place of Proved Undeveloped Reserves (stated in Boe) | ' | 19,000,000 | 9,000,000 | ' | ||||
Proved Undeveloped Reserves Drilled and Transferred to Proved Developed Reserves (stated in Boe) | 160,000,000 | 138,000,000 | 144,000,000 | ' | ||||
Capitalized Costs Related to Proved Undeveloped Reserves Drilled and Transferred to Proved Developed Reserves | $2,874,000,000 | $2,764,000,000 | $1,619,000,000 | ' | ||||
Capitalized Costs, Oil and Gas Producing Activities, Gross [Abstract] | ' | ' | ' | ' | ||||
Proved properties | 41,377,303,000 | 36,872,434,000 | ' | ' | ||||
Unproved properties | 1,444,500,000 | 1,253,864,000 | ' | ' | ||||
Total | 42,821,803,000 | 38,126,298,000 | ' | ' | ||||
Accumulated depreciation, depletion and amortization | -18,880,611,000 | -16,849,068,000 | ' | ' | ||||
Net capitalized costs | $23,941,192,000 | $21,277,230,000 | ' | ' | ||||
Crude Oil (Bbl) [Member] | ' | ' | ' | ' | ||||
Proved Developed and Undeveloped Reserves [Rollforward] | ' | ' | ' | ' | ||||
Net proved reserves - beginning of period | 700,818,000 | [1] | 517,493,000 | [1] | 385,922,000 | [1] | ' | |
Revisions of previous estimates | 50,669,000 | [1] | 1,688,000 | [1] | -25,756,000 | [1] | ' | |
Purchases in place | 1,097,000 | [1] | 1,010,000 | [1] | 9,000 | [1] | ' | |
Extensions, discoveries and other additions | 230,754,000 | [1] | 255,686,000 | [1] | 203,001,000 | [1] | ' | |
Sales in place | -2,337,000 | [1] | -17,264,000 | [1] | -4,301,000 | [1] | ' | |
Production | -80,461,000 | [1] | -57,795,000 | [1] | -41,382,000 | [1] | ' | |
Net proved reserves - end of period | 900,540,000 | [1] | 700,818,000 | [1] | 517,493,000 | [1] | ' | |
Proved Developed And Undeveloped Reserves (Boe) [Rollforward] | ' | ' | ' | ' | ||||
Sales in place | 15,000,000 | [1] | 90,000,000 | [1] | 68,000,000 | [1],[2] | ' | |
Additions of proved reserves from drilling activities and technical evaluation of major proved areas | 399,000,000 | [1] | 407,000,000 | [1] | 387,000,000 | [1],[2] | ' | |
Net Proved Developed and Undeveloped Reserves [Abstract] | ' | ' | ' | ' | ||||
Net proved developed reserves | 391,056,000 | 290,650,000 | 224,755,000 | 177,140,000 | ||||
Net proved undeveloped reserves | 509,484,000 | 410,168,000 | 292,738,000 | 208,782,000 | ||||
Natural Gas Liquids (Bbl) [Member] | ' | ' | ' | ' | ||||
Proved Developed and Undeveloped Reserves [Rollforward] | ' | ' | ' | ' | ||||
Net proved reserves - beginning of period | 319,963,000 | [1] | 227,788,000 | [1] | 151,909,000 | [1] | ' | |
Revisions of previous estimates | 12,109,000 | [1] | 47,856,000 | [1] | 36,042,000 | [1] | ' | |
Purchases in place | 1,202,000 | [1] | 612,000 | [1] | 17,000 | [1] | ' | |
Extensions, discoveries and other additions | 69,197,000 | [1] | 71,574,000 | [1] | 65,288,000 | [1] | ' | |
Sales in place | -1,471,000 | [1] | -7,377,000 | [1] | -10,008,000 | [1] | ' | |
Production | -23,794,000 | [1] | -20,490,000 | [1] | -15,460,000 | [1] | ' | |
Net proved reserves - end of period | 377,206,000 | [1] | 319,963,000 | [1] | 227,788,000 | [1] | ' | |
Net Proved Developed and Undeveloped Reserves [Abstract] | ' | ' | ' | ' | ||||
Net proved developed reserves | 200,860,000 | 162,593,000 | 125,363,000 | 92,876,000 | ||||
Net proved undeveloped reserves | 176,346,000 | 157,370,000 | 102,425,000 | 59,033,000 | ||||
Natural Gas (cf) [Member] | ' | ' | ' | ' | ||||
Proved Developed and Undeveloped Reserves [Rollforward] | ' | ' | ' | ' | ||||
Net proved reserves - beginning of period | 4,739,500,000,000 | [3] | 7,850,900,000,000 | [3] | 8,470,200,000,000 | [3] | ' | |
Revisions of previous estimates | 277,300,000,000 | [3] | -2,653,000,000,000 | [3] | -416,700,000,000 | [3] | ' | |
Purchases in place | 5,700,000,000 | [3] | 14,800,000,000 | [3] | 3,000,000,000 | [3] | ' | |
Extensions, discoveries and other additions | 594,100,000,000 | [3] | 478,100,000,000 | [3] | 713,800,000,000 | [3] | ' | |
Sales in place | -69,400,000,000 | [3] | -394,700,000,000 | [3] | -323,600,000,000 | [3] | ' | |
Production | -502,400,000,000 | [3] | -556,600,000,000 | [3] | -595,800,000,000 | [3] | ' | |
Net proved reserves - end of period | 5,044,800,000,000 | [3] | 4,739,500,000,000 | [3] | 7,850,900,000,000 | [3] | ' | |
Net Proved Developed and Undeveloped Reserves [Abstract] | ' | ' | ' | ' | ||||
Net proved developed reserves | 3,213,400 | 2,979,500 | 4,155,600 | 4,457,800 | ||||
Net proved undeveloped reserves | 1,831,400 | 1,760,000 | 3,695,300 | 4,012,400 | ||||
United States [Member] | ' | ' | ' | ' | ||||
Proved Developed And Undeveloped Reserves (Boe) [Rollforward] | ' | ' | ' | ' | ||||
Net proved reserves - beginning of period (Boe) | 1,662,108,000 | [1] | 1,729,508,000 | [1] | 1,587,806,000 | [1] | ' | |
Revisions of previous estimates | 113,823,000 | [1] | -237,936,000 | [1] | -42,526,000 | [1] | ' | |
Purchases in place | 3,241,000 | [1] | 4,098,000 | [1] | 521,000 | [1] | ' | |
Extensions, discoveries and other additions | 383,324,000 | [1] | 392,196,000 | [1] | 373,602,000 | [1] | ' | |
Sales in place | -15,375,000 | [1] | -87,588,000 | [1] | -68,247,000 | [1] | ' | |
Production | -157,955,000 | [1] | -138,170,000 | [1] | -121,648,000 | [1] | ' | |
Net proved reserves - end of period (Boe) | 1,989,166,000 | [1] | 1,662,108,000 | [1] | 1,729,508,000 | [1] | ' | |
Net Proved Developed and Undeveloped Reserves [Abstract] | ' | ' | ' | ' | ||||
Net proved developed reserves (BOE) | 1,015,359,000 | 840,564,000 | 877,301,000 | 839,928,000 | ||||
Net proved undeveloped reserve (BOE) | 973,807,000 | 821,544,000 | 852,207,000 | 747,878,000 | ||||
Revisions of previous estimates | 113,823,000 | [1] | -237,936,000 | [1] | -42,526,000 | [1] | ' | |
United States [Member] | Crude Oil (Bbl) [Member] | ' | ' | ' | ' | ||||
Proved Developed and Undeveloped Reserves [Rollforward] | ' | ' | ' | ' | ||||
Net proved reserves - beginning of period | 671,029,000 | [1] | 495,296,000 | [1] | 355,457,000 | [1] | ' | |
Revisions of previous estimates | 57,668,000 | [1] | 4,105,000 | [1] | -21,188,000 | [1] | ' | |
Purchases in place | 1,097,000 | [1] | 1,010,000 | [1] | 9,000 | [1] | ' | |
Extensions, discoveries and other additions | 230,023,000 | [1] | 241,171,000 | [1] | 202,552,000 | [1] | ' | |
Sales in place | -2,337,000 | [1] | -15,921,000 | [1] | -4,301,000 | [1] | ' | |
Production | -77,431,000 | [1] | -54,632,000 | [1] | -37,233,000 | [1] | ' | |
Net proved reserves - end of period | 880,049,000 | [1] | 671,029,000 | [1] | 495,296,000 | [1] | ' | |
Net Proved Developed and Undeveloped Reserves [Abstract] | ' | ' | ' | ' | ||||
Net proved developed reserves | 382,517,000 | 281,167,000 | 213,872,000 | 161,907,000 | ||||
Net proved undeveloped reserves | 497,532,000 | 389,862,000 | 281,424,000 | 193,550,000 | ||||
United States [Member] | Natural Gas Liquids (Bbl) [Member] | ' | ' | ' | ' | ||||
Proved Developed and Undeveloped Reserves [Rollforward] | ' | ' | ' | ' | ||||
Net proved reserves - beginning of period | 318,406,000 | [1] | 226,586,000 | [1] | 150,434,000 | [1] | ' | |
Revisions of previous estimates | 12,157,000 | [1] | 47,293,000 | [1] | 35,999,000 | [1] | ' | |
Purchases in place | 1,202,000 | [1] | 612,000 | [1] | 17,000 | [1] | ' | |
Extensions, discoveries and other additions | 69,187,000 | [1] | 71,396,000 | [1] | 65,288,000 | [1] | ' | |
Sales in place | -1,471,000 | [1] | -7,300,000 | [1] | -10,008,000 | [1] | ' | |
Production | -23,479,000 | [1] | -20,181,000 | [1] | -15,144,000 | [1] | ' | |
Net proved reserves - end of period | 376,002,000 | [1] | 318,406,000 | [1] | 226,586,000 | [1] | ' | |
Net Proved Developed and Undeveloped Reserves [Abstract] | ' | ' | ' | ' | ||||
Net proved developed reserves | 199,964,000 | 161,482,000 | 124,271,000 | 91,401,000 | ||||
Net proved undeveloped reserves | 176,038,000 | 156,924,000 | 102,315,000 | 59,033,000 | ||||
United States [Member] | Natural Gas (cf) [Member] | ' | ' | ' | ' | ||||
Proved Developed and Undeveloped Reserves [Rollforward] | ' | ' | ' | ' | ||||
Net proved reserves - beginning of period | 4,036,000,000,000 | [3] | 6,045,800,000,000 | [3] | 6,491,500,000,000 | [3] | ' | |
Revisions of previous estimates | 264,000,000,000 | [3] | -1,736,000,000,000 | [3] | -344,000,000,000 | [3] | ' | |
Purchases in place | 5,700,000,000 | [3] | 14,800,000,000 | [3] | 3,000,000,000 | [3] | ' | |
Extensions, discoveries and other additions | 504,700,000,000 | [3] | 477,800,000,000 | [3] | 634,600,000,000 | [3] | ' | |
Sales in place | -69,400,000,000 | [3] | -386,200,000,000 | [3] | -323,600,000,000 | [3] | ' | |
Production | -342,300,000,000 | [3] | -380,200,000,000 | [3] | -415,700,000,000 | [3] | ' | |
Net proved reserves - end of period | 4,398,700,000,000 | [3] | 4,036,000,000,000 | [3] | 6,045,800,000,000 | [3] | ' | |
Net Proved Developed and Undeveloped Reserves [Abstract] | ' | ' | ' | ' | ||||
Net proved developed reserves | 2,597,300 | 2,387,500 | 3,235,000 | 3,519,700 | ||||
Net proved undeveloped reserves | 1,801,400 | 1,648,500 | 2,810,800 | 2,971,800 | ||||
Canada [Member] | ' | ' | ' | ' | ||||
Proved Developed And Undeveloped Reserves (Boe) [Rollforward] | ' | ' | ' | ' | ||||
Net proved reserves - beginning of period (Boe) | 35,804,000 | [1] | 192,448,000 | [1] | 216,084,000 | [1] | ' | |
Revisions of previous estimates | -676,000 | [1] | -151,015,000 | [1] | -12,865,000 | [1] | ' | |
Purchases in place | 0 | [1] | 0 | [1] | 0 | [1] | ' | |
Extensions, discoveries and other additions | 693,000 | [1] | 5,860,000 | [1] | 448,000 | [1] | ' | |
Sales in place | 0 | [1] | -2,832,000 | [1] | 0 | [1] | ' | |
Production | -7,482,000 | [1] | -8,657,000 | [1] | -11,219,000 | [1] | ' | |
Net proved reserves - end of period (Boe) | 28,339,000 | [1] | 35,804,000 | [1] | 192,448,000 | [1] | ' | |
Net Proved Developed and Undeveloped Reserves [Abstract] | ' | ' | ' | ' | ||||
Net proved developed reserves (BOE) | 24,782,000 | 24,348,000 | 58,524,000 | 79,701,000 | ||||
Net proved undeveloped reserve (BOE) | 3,557,000 | 11,456,000 | 133,924,000 | 136,383,000 | ||||
Revisions of previous estimates | -676,000 | [1] | -151,015,000 | [1] | -12,865,000 | [1] | ' | |
Canada [Member] | Crude Oil (Bbl) [Member] | ' | ' | ' | ' | ||||
Proved Developed and Undeveloped Reserves [Rollforward] | ' | ' | ' | ' | ||||
Net proved reserves - beginning of period | 17,863,000 | [1] | 18,592,000 | [1] | 25,636,000 | [1] | ' | |
Revisions of previous estimates | -5,866,000 | [1] | -2,493,000 | [1] | -4,611,000 | [1] | ' | |
Purchases in place | 0 | [1] | 0 | [1] | 0 | [1] | ' | |
Extensions, discoveries and other additions | 673,000 | [1] | 5,681,000 | [1] | 449,000 | [1] | ' | |
Sales in place | 0 | [1] | -1,343,000 | [1] | 0 | [1] | ' | |
Production | -2,550,000 | [1] | -2,574,000 | [1] | -2,882,000 | [1] | ' | |
Net proved reserves - end of period | 10,120,000 | [1] | 17,863,000 | [1] | 18,592,000 | [1] | ' | |
Net Proved Developed and Undeveloped Reserves [Abstract] | ' | ' | ' | ' | ||||
Net proved developed reserves | 6,871,000 | 6,853,000 | 8,128,000 | 11,283,000 | ||||
Net proved undeveloped reserves | 3,249,000 | 11,010,000 | 10,464,000 | 14,353,000 | ||||
Canada [Member] | Natural Gas Liquids (Bbl) [Member] | ' | ' | ' | ' | ||||
Proved Developed and Undeveloped Reserves [Rollforward] | ' | ' | ' | ' | ||||
Net proved reserves - beginning of period | 1,557,000 | [1] | 1,202,000 | [1] | 1,475,000 | [1] | ' | |
Revisions of previous estimates | -48,000 | [1] | 563,000 | [1] | 43,000 | [1] | ' | |
Purchases in place | 0 | [1] | 0 | [1] | 0 | [1] | ' | |
Extensions, discoveries and other additions | 10,000 | [1] | 178,000 | [1] | 0 | [1] | ' | |
Sales in place | 0 | [1] | -77,000 | [1] | 0 | [1] | ' | |
Production | -315,000 | [1] | -309,000 | [1] | -316,000 | [1] | ' | |
Net proved reserves - end of period | 1,204,000 | [1] | 1,557,000 | [1] | 1,202,000 | [1] | ' | |
Net Proved Developed and Undeveloped Reserves [Abstract] | ' | ' | ' | ' | ||||
Net proved developed reserves | 896,000 | 1,111,000 | 1,092,000 | 1,475,000 | ||||
Net proved undeveloped reserves | 308,000 | 446,000 | 110,000 | 0 | ||||
Canada [Member] | Natural Gas (cf) [Member] | ' | ' | ' | ' | ||||
Proved Developed and Undeveloped Reserves [Rollforward] | ' | ' | ' | ' | ||||
Net proved reserves - beginning of period | 98,300,000,000 | [3] | 1,035,900,000,000 | [3] | 1,133,800,000,000 | [3] | ' | |
Revisions of previous estimates | 31,400,000,000 | [3] | -894,500,000,000 | [3] | -49,800,000,000 | [3] | ' | |
Purchases in place | 0 | [3] | 0 | [3] | 0 | [3] | ' | |
Extensions, discoveries and other additions | 100,000,000 | [3] | 0 | [3] | 0 | [3] | ' | |
Sales in place | 0 | [3] | -8,500,000,000 | [3] | 0 | [3] | ' | |
Production | -27,700,000,000 | [3] | -34,600,000,000 | [3] | -48,100,000,000 | [3] | ' | |
Net proved reserves - end of period | 102,100,000,000 | [3] | 98,300,000,000 | [3] | 1,035,900,000,000 | [3] | ' | |
Net Proved Developed and Undeveloped Reserves [Abstract] | ' | ' | ' | ' | ||||
Net proved developed reserves | 102,100 | 98,300 | 295,800 | 401,600 | ||||
Net proved undeveloped reserves | 0 | 0 | 740,100 | 732,200 | ||||
Trinidad [Member] | ' | ' | ' | ' | ||||
Proved Developed And Undeveloped Reserves (Boe) [Rollforward] | ' | ' | ' | ' | ||||
Net proved reserves - beginning of period (Boe) | 101,060,000 | [1] | 128,629,000 | [1] | 142,669,000 | [1] | ' | |
Revisions of previous estimates | -3,892,000 | [1] | -3,953,000 | [1] | -4,011,000 | [1] | ' | |
Purchases in place | 0 | [1] | 0 | [1] | 0 | [1] | ' | |
Extensions, discoveries and other additions | 13,245,000 | [1] | 0 | [1] | 12,455,000 | [1] | ' | |
Sales in place | 0 | [1] | 0 | [1] | 0 | [1] | ' | |
Production | -22,049,000 | [1] | -23,616,000 | [1] | -22,484,000 | [1] | ' | |
Net proved reserves - end of period (Boe) | 88,364,000 | [1] | 101,060,000 | [1] | 128,629,000 | [1] | ' | |
Net Proved Developed and Undeveloped Reserves [Abstract] | ' | ' | ' | ' | ||||
Net proved developed reserves (BOE) | 83,933,000 | 81,826,000 | 103,710,000 | 90,382,000 | ||||
Net proved undeveloped reserve (BOE) | 4,431,000 | 19,234,000 | 24,919,000 | 52,287,000 | ||||
Revisions of previous estimates | -3,892,000 | [1] | -3,953,000 | [1] | -4,011,000 | [1] | ' | |
Trinidad [Member] | Crude Oil (Bbl) [Member] | ' | ' | ' | ' | ||||
Proved Developed and Undeveloped Reserves [Rollforward] | ' | ' | ' | ' | ||||
Net proved reserves - beginning of period | 3,028,000 | [1] | 3,507,000 | [1] | 4,731,000 | [1] | ' | |
Revisions of previous estimates | -991,000 | [1] | 71,000 | [1] | 18,000 | [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 | -447,000 | [1] | -550,000 | [1] | -1,242,000 | [1] | ' | |
Net proved reserves - end of period | 1,590,000 | [1] | 3,028,000 | [1] | 3,507,000 | [1] | ' | |
Net Proved Developed and Undeveloped Reserves [Abstract] | ' | ' | ' | ' | ||||
Net proved developed reserves | 1,505,000 | 2,377,000 | 2,657,000 | 3,852,000 | ||||
Net proved undeveloped reserves | 85,000 | 651,000 | 850,000 | 879,000 | ||||
Trinidad [Member] | Natural Gas Liquids (Bbl) [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 (cf) [Member] | ' | ' | ' | ' | ||||
Proved Developed and Undeveloped Reserves [Rollforward] | ' | ' | ' | ' | ||||
Net proved reserves - beginning of period | 588,200,000,000 | [3] | 750,700,000,000 | [3] | 827,600,000,000 | [3] | ' | |
Revisions of previous estimates | -17,400,000,000 | [3] | -24,100,000,000 | [3] | -24,200,000,000 | [3] | ' | |
Purchases in place | 0 | [3] | 0 | [3] | 0 | [3] | ' | |
Extensions, discoveries and other additions | 79,500,000,000 | [3] | 0 | [3] | 74,700,000,000 | [3] | ' | |
Sales in place | 0 | [3] | 0 | [3] | 0 | [3] | ' | |
Production | -129,600,000,000 | [3] | -138,400,000,000 | [3] | -127,400,000,000 | [3] | ' | |
Net proved reserves - end of period | 520,700,000,000 | [3] | 588,200,000,000 | [3] | 750,700,000,000 | [3] | ' | |
Net Proved Developed and Undeveloped Reserves [Abstract] | ' | ' | ' | ' | ||||
Net proved developed reserves | 494,600 | 476,700 | 606,300 | 519,200 | ||||
Net proved undeveloped reserves | 26,100 | 111,500 | 144,400 | 308,400 | ||||
Other International [Member] | ' | ' | ' | ' | ||||
Proved Developed And Undeveloped Reserves (Boe) [Rollforward] | ' | ' | ' | ' | ||||
Net proved reserves - beginning of period (Boe) | 11,726,000 | [1],[2] | 3,178,000 | [1],[2] | 2,976,000 | [1],[2] | ' | |
Revisions of previous estimates | -265,000 | [1],[2] | 283,000 | [1],[2] | 239,000 | [1],[2] | ' | |
Purchases in place | 0 | [1],[2] | 0 | [1],[2] | 0 | [1],[2] | ' | |
Extensions, discoveries and other additions | 1,703,000 | [1],[2] | 8,876,000 | [1],[2] | 750,000 | [1],[2] | ' | |
Sales in place | 0 | [1],[2] | 0 | [1],[2] | 0 | [1],[2] | ' | |
Production | -490,000 | [1],[2] | -611,000 | [1],[2] | -787,000 | [1],[2] | ' | |
Net proved reserves - end of period (Boe) | 12,674,000 | [1],[2] | 11,726,000 | [1],[2] | 3,178,000 | [1],[2] | ' | |
Net Proved Developed and Undeveloped Reserves [Abstract] | ' | ' | ' | ' | ||||
Net proved developed reserves (BOE) | 3,402,000 | [2] | 3,081,000 | [2] | 3,178,000 | [2] | 2,976,000 | [2] |
Net proved undeveloped reserve (BOE) | 9,272,000 | [2] | 8,645,000 | [2] | 0 | [2] | 0 | [2] |
Revisions of previous estimates | -265,000 | [1],[2] | 283,000 | [1],[2] | 239,000 | [1],[2] | ' | |
Other International [Member] | Crude Oil (Bbl) [Member] | ' | ' | ' | ' | ||||
Proved Developed and Undeveloped Reserves [Rollforward] | ' | ' | ' | ' | ||||
Net proved reserves - beginning of period | 8,898,000 | [1],[2] | 98,000 | [1],[2] | 98,000 | [1],[2] | ' | |
Revisions of previous estimates | -142,000 | [1],[2] | 5,000 | [1],[2] | 25,000 | [1],[2] | ' | |
Purchases in place | 0 | [1],[2] | 0 | [1],[2] | 0 | [1],[2] | ' | |
Extensions, discoveries and other additions | 58,000 | [1],[2] | 8,834,000 | [1],[2] | 0 | [1],[2] | ' | |
Sales in place | 0 | [1],[2] | 0 | [1],[2] | 0 | [1],[2] | ' | |
Production | -33,000 | [1],[2] | -39,000 | [1],[2] | -25,000 | [1],[2] | ' | |
Net proved reserves - end of period | 8,781,000 | [1],[2] | 8,898,000 | [1],[2] | 98,000 | [1],[2] | ' | |
Net Proved Developed and Undeveloped Reserves [Abstract] | ' | ' | ' | ' | ||||
Net proved developed reserves | 163,000 | [2] | 253,000 | [2] | 98,000 | [2] | 98,000 | [2] |
Net proved undeveloped reserves | 8,618,000 | [2] | 8,645,000 | [2] | 0 | [2] | 0 | [2] |
Other International [Member] | Natural Gas Liquids (Bbl) [Member] | ' | ' | ' | ' | ||||
Proved Developed and Undeveloped Reserves [Rollforward] | ' | ' | ' | ' | ||||
Net proved reserves - beginning of period | 0 | [1],[2] | 0 | [1],[2] | 0 | [1],[2] | ' | |
Revisions of previous estimates | 0 | [1],[2] | 0 | [1],[2] | 0 | [1],[2] | ' | |
Purchases in place | 0 | [1],[2] | 0 | [1],[2] | 0 | [1],[2] | ' | |
Extensions, discoveries and other additions | 0 | [1],[2] | 0 | [1],[2] | 0 | [1],[2] | ' | |
Sales in place | 0 | [1],[2] | 0 | [1],[2] | 0 | [1],[2] | ' | |
Production | 0 | [1],[2] | 0 | [1],[2] | 0 | [1],[2] | ' | |
Net proved reserves - end of period | 0 | [1],[2] | 0 | [1],[2] | 0 | [1],[2] | ' | |
Net Proved Developed and Undeveloped Reserves [Abstract] | ' | ' | ' | ' | ||||
Net proved developed reserves | 0 | [2] | 0 | [2] | 0 | [2] | 0 | [2] |
Net proved undeveloped reserves | 0 | [2] | 0 | [2] | 0 | [2] | 0 | [2] |
Other International [Member] | Natural Gas (cf) [Member] | ' | ' | ' | ' | ||||
Proved Developed and Undeveloped Reserves [Rollforward] | ' | ' | ' | ' | ||||
Net proved reserves - beginning of period | 17,000,000,000 | [2],[3] | 18,500,000,000 | [2],[3] | 17,300,000,000 | [2],[3] | ' | |
Revisions of previous estimates | -700,000,000 | [2],[3] | 1,600,000,000 | [2],[3] | 1,300,000,000 | [2],[3] | ' | |
Purchases in place | 0 | [2],[3] | 0 | [2],[3] | 0 | [2],[3] | ' | |
Extensions, discoveries and other additions | 9,800,000,000 | [2],[3] | 300,000,000 | [2],[3] | 4,500,000,000 | [2],[3] | ' | |
Sales in place | 0 | [2],[3] | 0 | [2],[3] | 0 | [2],[3] | ' | |
Production | -2,800,000,000 | [2],[3] | -3,400,000,000 | [2],[3] | -4,600,000,000 | [2],[3] | ' | |
Net proved reserves - end of period | 23,300,000,000 | [2],[3] | 17,000,000,000 | [2],[3] | 18,500,000,000 | [2],[3] | ' | |
Net Proved Developed and Undeveloped Reserves [Abstract] | ' | ' | ' | ' | ||||
Net proved developed reserves | 19,400 | [2] | 17,000 | [2] | 18,500 | [2] | 17,300 | [2] |
Net proved undeveloped reserves | 3,900 | [2] | 0 | [2] | 0 | [2] | 0 | [2] |
[1] | Thousand barrels or thousand barrels of oil equivalent, as applicable; oil equivalents include crude oil and condensate, NGLs and natural gas. Oil equivalents are determined using the ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. | |||||||
[2] | Other International includes EOG's United Kingdom, China and Argentina operations. | |||||||
[3] | Billion cubic feet. |
Oil_and_Gas_Exploration_and_Pr3
Oil and Gas Exploration and Production Industries Disclosures, Costs Incurred (Details) (USD $) | 12 Months Ended | |||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ' | ' | ' | |||
Acquisition Costs of Properties - Unproved | $414,121,000 | $505,303,000 | $300,772,000 | |||
Acquisition Costs of Properties - Proved | 120,214,000 | 739,000 | 4,247,000 | |||
Subtotal | 534,335,000 | 506,042,000 | 305,019,000 | |||
Exploration Costs | 377,179,000 | 445,598,000 | 363,554,000 | |||
Development Costs | 6,086,377,000 | [1] | 6,116,550,000 | [2] | 5,930,591,000 | [3] |
Total | 6,997,891,000 | 7,068,190,000 | 6,599,164,000 | |||
United States [Member] | ' | ' | ' | |||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ' | ' | ' | |||
Acquisition Costs of Properties - Unproved | 411,556,000 | 471,345,000 | 295,160,000 | |||
Acquisition Costs of Properties - Proved | 120,220,000 | 739,000 | 4,219,000 | |||
Subtotal | 531,776,000 | 472,084,000 | 299,379,000 | |||
Exploration Costs | 273,788,000 | 333,534,000 | 311,369,000 | |||
Development Costs | 5,573,260,000 | [1] | 5,657,378,000 | [2] | 5,410,378,000 | [3] |
Total | 6,378,824,000 | 6,462,996,000 | 6,021,126,000 | |||
Asset Retirement Costs Included In Development | 84,000,000 | 80,000,000 | 52,000,000 | |||
Canada [Member] | ' | ' | ' | |||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ' | ' | ' | |||
Acquisition Costs of Properties - Unproved | 2,565,000 | 33,561,000 | 6,216,000 | |||
Acquisition Costs of Properties - Proved | -6,000 | 0 | 28,000 | |||
Subtotal | 2,559,000 | 33,561,000 | 6,244,000 | |||
Exploration Costs | 19,660,000 | 38,530,000 | 31,472,000 | |||
Development Costs | 149,426,000 | [1] | 278,995,000 | [2] | 302,564,000 | [3] |
Total | 171,645,000 | 351,086,000 | 340,280,000 | |||
Asset Retirement Costs Included In Development | 13,000,000 | 33,000,000 | 70,000,000 | |||
Trinidad [Member] | ' | ' | ' | |||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ' | ' | ' | |||
Acquisition Costs of Properties - Unproved | 0 | 1,000,000 | 0 | |||
Acquisition Costs of Properties - Proved | 0 | 0 | 0 | |||
Subtotal | 0 | 1,000,000 | 0 | |||
Exploration Costs | 16,060,000 | 19,555,000 | 2,549,000 | |||
Development Costs | 124,231,000 | [1] | 32,609,000 | [2] | 138,905,000 | [3] |
Total | 140,291,000 | 53,164,000 | 141,454,000 | |||
Asset Retirement Costs Included In Development | 0 | 2,000,000 | 7,000,000 | |||
Other International [Member] | ' | ' | ' | |||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ' | ' | ' | |||
Acquisition Costs of Properties - Unproved | 0 | [4] | -603,000 | [4] | -604,000 | [4] |
Acquisition Costs of Properties - Proved | 0 | [4] | 0 | [4] | 0 | [4] |
Subtotal | 0 | [4] | -603,000 | [4] | -604,000 | [4] |
Exploration Costs | 67,671,000 | [4] | 53,979,000 | [4] | 18,164,000 | [4] |
Development Costs | 239,460,000 | [1],[4] | 147,568,000 | [2],[4] | 78,744,000 | [3],[4] |
Total | 307,131,000 | [4] | 200,944,000 | [4] | 96,304,000 | [4] |
Asset Retirement Costs Included In Development | $37,000,000 | $12,000,000 | $4,000,000 | |||
[1] | 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. | |||||
[2] | 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. | |||||
[3] | Includes Asset Retirement Costs of $52 million, $70 million, $7 million and $4 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, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||
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 | $10,755,646 | [1] | $7,958,376 | [1] | $6,858,188 | [1] |
Other | 56,507 | [1] | 41,162 | [1] | 33,173 | [1] |
Total | 10,812,153 | [1] | 7,999,538 | [1] | 6,891,361 | [1] |
Exploration Costs | 161,346 | [1] | 185,569 | [1] | 171,658 | [1] |
Dry Hole Costs | 74,655 | 14,970 | [1] | 53,230 | [1] | |
Transportation Costs | 853,044 | [1] | 601,431 | [1] | 430,322 | [1] |
Production Costs | 1,706,222 | [1] | 1,468,628 | [1] | 1,332,210 | [1] |
Impairments | 286,941 | [1] | 1,270,735 | [1] | 1,031,037 | [1] |
Depreciation, Depletion and Amortization | 3,498,010 | [1] | 3,024,514 | [1] | 2,393,814 | [1] |
Income (Loss) Before Income Taxes | 4,231,935 | [1] | 1,433,691 | [1] | 1,479,090 | [1] |
Tax Provision (Benefit) | 1,490,532 | [1] | 722,906 | [1] | 637,868 | [1] |
Results of Operations | 2,741,403 | [1] | 710,785 | [1] | 841,222 | [1] |
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 | 9,897,701 | [1] | 7,048,572 | [1] | 5,814,942 | [1] |
Other | 51,713 | [1] | 40,780 | [1] | 32,329 | [1] |
Total | 9,949,414 | [1] | 7,089,352 | [1] | 5,847,271 | [1] |
Exploration Costs | 141,286 | [1] | 162,152 | [1] | 148,199 | [1] |
Dry Hole Costs | 14,276 | 1,772 | [1] | 30,521 | [1] | |
Transportation Costs | 841,567 | [1] | 591,547 | [1] | 421,060 | [1] |
Production Costs | 1,494,791 | [1] | 1,264,633 | [1] | 1,096,955 | [1] |
Impairments | 178,718 | [1] | 294,172 | [1] | 575,976 | [1] |
Depreciation, Depletion and Amortization | 3,122,858 | [1] | 2,637,500 | [1] | 2,011,080 | [1] |
Income (Loss) Before Income Taxes | 4,155,918 | [1] | 2,137,576 | [1] | 1,563,480 | [1] |
Tax Provision (Benefit) | 1,486,445 | [1] | 761,459 | [1] | 569,153 | [1] |
Results of Operations | 2,669,473 | [1] | 1,376,117 | [1] | 994,327 | [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 | 319,880 | [1] | 321,597 | [1] | 459,853 | [1] |
Other | 4,770 | [1] | 367 | [1] | 258 | [1] |
Total | 324,650 | [1] | 321,964 | [1] | 460,111 | [1] |
Exploration Costs | 11,203 | [1] | 13,350 | [1] | 10,479 | [1] |
Dry Hole Costs | 9,579 | 1,570 | [1] | 432 | [1] | |
Transportation Costs | 9,694 | [1] | 7,511 | [1] | 5,969 | [1] |
Production Costs | 154,947 | [1] | 154,509 | [1] | 174,973 | [1] |
Impairments | 84,934 | [1] | 976,563 | [1] | 452,103 | [1] |
Depreciation, Depletion and Amortization | 179,520 | [1] | 222,366 | [1] | 258,772 | [1] |
Income (Loss) Before Income Taxes | -125,227 | [1] | -1,053,905 | [1] | -442,617 | [1] |
Tax Provision (Benefit) | -32,295 | [1] | -136,105 | [1] | -121,044 | [1] |
Results of Operations | -92,932 | [1] | -917,800 | [1] | -321,573 | [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 | 517,482 | [1] | 565,030 | [1] | 555,143 | [1] |
Other | 24 | [1] | 15 | [1] | 586 | [1] |
Total | 517,506 | [1] | 565,045 | [1] | 555,729 | [1] |
Exploration Costs | 2,345 | [1] | 2,262 | [1] | 2,520 | [1] |
Dry Hole Costs | 4,478 | 0 | [1] | 0 | [1] | |
Transportation Costs | 659 | [1] | 1,104 | [1] | 1,620 | [1] |
Production Costs | 43,279 | [1] | 37,792 | [1] | 49,318 | [1] |
Impairments | 14,274 | [1] | 0 | [1] | 0 | [1] |
Depreciation, Depletion and Amortization | 181,637 | [1] | 146,690 | [1] | 106,802 | [1] |
Income (Loss) Before Income Taxes | 270,834 | [1] | 377,197 | [1] | 395,469 | [1] |
Tax Provision (Benefit) | 103,313 | [1] | 119,442 | [1] | 202,815 | [1] |
Results of Operations | 167,521 | [1] | 257,755 | [1] | 192,654 | [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 | 20,583 | [1],[2] | 23,177 | [1],[2] | 28,250 | [1],[2] |
Other | 0 | [1],[2] | 0 | [1],[2] | 0 | [1],[2] |
Total | 20,583 | [1],[2] | 23,177 | [1],[2] | 28,250 | [1],[2] |
Exploration Costs | 6,512 | [1],[2] | 7,805 | [1],[2] | 10,460 | [1],[2] |
Dry Hole Costs | 46,322 | [2] | 11,628 | [1],[2] | 22,277 | [1],[2] |
Transportation Costs | 1,124 | [1],[2] | 1,269 | [1],[2] | 1,673 | [1],[2] |
Production Costs | 13,205 | [1],[2] | 11,694 | [1],[2] | 10,964 | [1],[2] |
Impairments | 9,015 | [1],[2] | 0 | [1],[2] | 2,958 | [1],[2] |
Depreciation, Depletion and Amortization | 13,995 | [1],[2] | 17,958 | [1],[2] | 17,160 | [1],[2] |
Income (Loss) Before Income Taxes | -69,590 | [1],[2] | -27,177 | [1],[2] | -37,242 | [1],[2] |
Tax Provision (Benefit) | -66,931 | [1],[2] | -21,890 | [1],[2] | -13,056 | [1],[2] |
Results of Operations | ($2,659) | [1],[2] | ($5,287) | [1],[2] | ($24,186) | [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 December 31, 2013. | |||||
[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) (USD $) | 12 Months Ended | |||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ' | ' | ' | |||
Production costs per barrel of oil equivalent | $5.88 | $5.85 | $6.03 | |||
United States [Member] | ' | ' | ' | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ' | ' | ' | |||
Production costs per barrel of oil equivalent | $5.78 | $5.96 | $6.19 | |||
Canada [Member] | ' | ' | ' | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ' | ' | ' | |||
Production costs per barrel of oil equivalent | $19.98 | $16.42 | $14.26 | |||
Trinidad [Member] | ' | ' | ' | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ' | ' | ' | |||
Production costs per barrel of oil equivalent | $1.36 | $0.98 | $0.78 | |||
Other International [Member] | ' | ' | ' | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ' | ' | ' | |||
Production costs per barrel of oil equivalent | $26.77 | [1] | $18.97 | [1] | $13.82 | [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, except Per Share data, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ' | ' | ' | |||
Future cash inflows | $123,999,499 | [1] | $94,612,613 | [2] | $92,530,537 | [3] |
Future production costs | -50,166,488 | -37,184,832 | -36,060,590 | |||
Future development costs | -18,549,351 | -17,031,731 | -15,528,581 | |||
Future income taxes | -16,416,387 | -11,150,742 | -11,418,085 | |||
Future net cash flows | 38,867,273 | 29,245,308 | 29,523,281 | |||
Discount to present value at 10% annual rate | -17,533,841 | -12,329,836 | -13,298,000 | |||
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves | 21,333,432 | 16,915,472 | 16,225,281 | |||
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 | 16,915,472 | 16,225,281 | 12,391,824 | |||
Sales and transfers of oil and gas produced, net of production costs | -8,196,380 | -5,888,317 | -5,095,655 | |||
Net changes in prices and production costs | 1,257,853 | -301,232 | 993,661 | |||
Extensions, discoveries, additions and improved recovery, net of related costs | 5,483,432 | 6,082,122 | 6,348,691 | |||
Development costs incurred | 2,955,900 | 2,094,600 | 1,545,500 | |||
Revisions of estimated development cost | 990,396 | 2,341,476 | -160,990 | |||
Revisions of previous quantity estimates | 1,794,198 | -3,742,827 | -609,297 | |||
Accretion of discount | 2,133,729 | 2,077,217 | 1,577,962 | |||
Net change in income taxes | -2,578,250 | 125,065 | -1,159,105 | |||
Purchases of reserves in place | 66,359 | 69,940 | 5,241 | |||
Sales of reserves in place | -140,652 | -913,761 | -658,468 | |||
Changes in timing and other | 651,375 | -1,254,092 | 1,045,917 | |||
Balance at End of Period | 21,333,432 | 16,915,472 | 16,225,281 | |||
United States [Member] | ' | ' | ' | |||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ' | ' | ' | |||
Future cash inflows | 119,644,713 | [1] | 89,324,274 | [2] | 84,518,638 | [3] |
Future production costs | -49,099,393 | -35,892,997 | -33,294,343 | |||
Future development costs | -17,753,860 | -15,825,040 | -13,811,449 | |||
Future income taxes | -15,763,089 | -10,247,007 | -10,539,182 | |||
Future net cash flows | 37,028,371 | 27,359,230 | 26,873,664 | |||
Discount to present value at 10% annual rate | -17,451,470 | -12,177,896 | -12,498,010 | |||
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves | 19,576,901 | 15,181,334 | 14,375,654 | |||
Per unit price used to calculate future cash inflows - Crude Oil | $105.91 | $99.78 | $97.75 | |||
Per unit price used to calculate future cash inflows - Natural Gas Liquids | $29.42 | $36.95 | $51.77 | |||
Per unit price used to calculate future cash inflows - Natural Gas | $3.50 | $2.63 | $4.03 | |||
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 | 15,181,334 | 14,375,654 | 10,628,924 | |||
Sales and transfers of oil and gas produced, net of production costs | -7,561,343 | -5,192,392 | -4,296,926 | |||
Net changes in prices and production costs | 1,734,058 | -393,585 | 716,682 | |||
Extensions, discoveries, additions and improved recovery, net of related costs | 5,449,531 | 5,517,945 | 6,223,552 | |||
Development costs incurred | 2,792,400 | 2,042,300 | 1,422,500 | |||
Revisions of estimated development cost | 892,803 | 1,987,330 | -210,919 | |||
Revisions of previous quantity estimates | 1,887,062 | -3,286,943 | -482,496 | |||
Accretion of discount | 1,895,503 | 1,832,377 | 1,352,740 | |||
Net change in income taxes | -2,772,267 | 174,418 | -1,049,641 | |||
Purchases of reserves in place | 66,359 | 64,317 | 5,241 | |||
Sales of reserves in place | -140,652 | -869,534 | -658,468 | |||
Changes in timing and other | 152,113 | -1,070,553 | 724,465 | |||
Balance at End of Period | 19,576,901 | 15,181,334 | 14,375,654 | |||
Canada [Member] | ' | ' | ' | |||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ' | ' | ' | |||
Future cash inflows | 1,199,251 | [1] | 1,816,369 | [2] | 5,056,501 | [3] |
Future production costs | -540,188 | -751,113 | -2,315,110 | |||
Future development costs | -529,788 | -813,061 | -1,566,917 | |||
Future income taxes | 0 | 0 | -81,590 | |||
Future net cash flows | 129,275 | 252,195 | 1,092,884 | |||
Discount to present value at 10% annual rate | 202,379 | 146,954 | -456,537 | |||
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves | 331,654 | 399,149 | 636,347 | |||
Per unit price used to calculate future cash inflows - Crude Oil | $91.47 | $84.77 | $90.70 | |||
Per unit price used to calculate future cash inflows - Natural Gas Liquids | $40.88 | $47.80 | $46.97 | |||
Per unit price used to calculate future cash inflows - Natural Gas | $2.95 | $2.22 | $3.28 | |||
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 | 399,149 | 636,347 | 746,235 | |||
Sales and transfers of oil and gas produced, net of production costs | -155,239 | -159,577 | -278,910 | |||
Net changes in prices and production costs | -438,982 | -67,964 | -57,545 | |||
Extensions, discoveries, additions and improved recovery, net of related costs | 33,901 | 79,529 | 22,591 | |||
Development costs incurred | 95,400 | 23,600 | 48,200 | |||
Revisions of estimated development cost | 48,906 | 383,215 | 64,001 | |||
Revisions of previous quantity estimates | -23,915 | -396,408 | -70,718 | |||
Accretion of discount | 39,915 | 63,635 | 62,725 | |||
Net change in income taxes | 0 | 0 | -118,988 | |||
Purchases of reserves in place | 0 | 0 | 0 | |||
Sales of reserves in place | 0 | -44,227 | 0 | |||
Changes in timing and other | 332,519 | -119,001 | 218,756 | |||
Balance at End of Period | 331,654 | 399,149 | 636,347 | |||
Trinidad [Member] | ' | ' | ' | |||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ' | ' | ' | |||
Future cash inflows | 2,082,195 | [1] | 2,408,116 | [2] | 2,851,545 | [3] |
Future production costs | -315,483 | -342,113 | -388,199 | |||
Future development costs | -112,050 | -171,737 | -149,884 | |||
Future income taxes | -603,786 | -691,109 | -794,856 | |||
Future net cash flows | 1,050,876 | 1,203,157 | 1,518,606 | |||
Discount to present value at 10% annual rate | -174,236 | -242,087 | -334,399 | |||
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves | 876,640 | 961,070 | 1,184,207 | |||
Per unit price used to calculate future cash inflows - Crude Oil | $94.30 | $94.46 | $92.50 | |||
Per unit price used to calculate future cash inflows - Natural Gas | $3.71 | $3.61 | $3.37 | |||
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 | 961,070 | 1,184,207 | 988,866 | |||
Sales and transfers of oil and gas produced, net of production costs | -473,544 | -526,134 | -504,205 | |||
Net changes in prices and production costs | -12,050 | 162,600 | 331,196 | |||
Extensions, discoveries, additions and improved recovery, net of related costs | 0 | 0 | 102,548 | |||
Development costs incurred | 67,100 | 23,500 | 74,800 | |||
Revisions of estimated development cost | -3,539 | -28,835 | -14,074 | |||
Revisions of previous quantity estimates | -60,419 | -62,285 | -56,884 | |||
Accretion of discount | 147,099 | 178,298 | 159,715 | |||
Net change in income taxes | 56,373 | 88,853 | 9,511 | |||
Purchases of reserves in place | 0 | 0 | 0 | |||
Sales of reserves in place | 0 | 0 | 0 | |||
Changes in timing and other | 194,550 | -59,134 | 92,734 | |||
Balance at End of Period | 876,640 | 961,070 | 1,184,207 | |||
Other International (1) [Member] | ' | ' | ' | |||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ' | ' | ' | |||
Future cash inflows | 1,073,340 | [1],[4] | 1,063,854 | [2],[4] | 103,853 | [3],[4] |
Future production costs | -211,424 | [4] | -198,609 | [4] | -62,938 | [4] |
Future development costs | -153,653 | [4] | -221,893 | [4] | -331 | [4] |
Future income taxes | -49,512 | [4] | -212,626 | [4] | -2,457 | [4] |
Future net cash flows | 658,751 | [4] | 430,726 | [4] | 38,127 | [4] |
Discount to present value at 10% annual rate | -110,514 | [4] | -56,807 | [4] | -9,054 | [4] |
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves | 548,237 | [4] | 373,919 | [4] | 29,073 | [4] |
Per unit price used to calculate future cash inflows - Crude Oil | $107.36 | $109.94 | $102.86 | |||
Per unit price used to calculate future cash inflows - Natural Gas | $5.67 | $5.04 | $5.07 | |||
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 | 373,919 | 29,073 | 27,799 | |||
Sales and transfers of oil and gas produced, net of production costs | -6,254 | -10,214 | -15,614 | |||
Net changes in prices and production costs | -25,173 | -2,283 | 3,328 | |||
Extensions, discoveries, additions and improved recovery, net of related costs | 0 | 484,648 | 0 | |||
Development costs incurred | 1,000 | 5,200 | 0 | |||
Revisions of estimated development cost | 52,226 | -234 | 2 | |||
Revisions of previous quantity estimates | -8,530 | 2,809 | 801 | |||
Accretion of discount | 51,212 | 2,907 | 2,782 | |||
Net change in income taxes | 137,644 | -138,206 | 13 | |||
Purchases of reserves in place | 0 | 5,623 | 0 | |||
Sales of reserves in place | 0 | 0 | 0 | |||
Changes in timing and other | -27,807 | -5,404 | 9,962 | |||
Balance at End of Period | $548,237 | $373,919 | $29,073 | |||
[1] | 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 NGLs 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. | |||||
[2] | 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 NGLs 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. | |||||
[3] | Estimated crude oil prices used to calculate 2011 future cash inflows for the United States, Canada, Trinidad and Other International were $97.75, $90.70, $92.50 and $102.86, respectively. Estimated NGLs prices used to calculate 2011 future cash inflows for the United States and Canada were $51.77 and $46.97, respectively. Estimated natural gas prices used to calculate 2011 future cash inflows for the United States, Canada, Trinidad and Other International were $4.03, $3.28, $3.37 and $5.07, 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 | ||||||||||||||||||||
Share data in Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||||||||||
Unaudited Quarterly Financial Information [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||
Net Operating Revenues | $3,749,023,000 | $3,541,396,000 | $3,840,185,000 | $3,356,514,000 | $3,011,811,000 | $2,954,855,000 | $2,909,319,000 | $2,806,651,000 | $14,487,118,000 | [1] | $11,682,636,000 | [2] | $10,126,115,000 | [3] | ||||||||
Operating Income (Loss) | 980,324,000 | 769,769,000 | 1,092,044,000 | 833,074,000 | -378,061,000 | 605,747,000 | 692,339,000 | 559,772,000 | 3,675,211,000 | 1,479,797,000 | 2,113,309,000 | |||||||||||
Income (Loss) Before Income Taxes | 919,082,000 | 721,555,000 | 1,035,230,000 | 761,019,000 | -445,822,000 | 560,189,000 | 646,239,000 | 520,134,000 | 3,436,886,000 | 1,280,740,000 | 1,909,799,000 | |||||||||||
Income Tax Provision | 338,888,000 | 259,057,000 | 375,538,000 | 266,294,000 | 59,177,000 | 204,698,000 | 250,461,000 | 196,125,000 | 1,239,777,000 | 710,461,000 | 818,676,000 | |||||||||||
Net Income (Loss) | 580,194,000 | [4] | 462,498,000 | [4] | 659,692,000 | [4] | 494,725,000 | [4] | -504,999,000 | [4] | 355,491,000 | [4] | 395,778,000 | [4] | 324,009,000 | [4] | 2,197,109,000 | 570,279,000 | 1,091,123,000 | |||
Net Income (Loss) Per Share [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||
Basic (in dollars per share) | $2.14 | [5] | $1.71 | [5] | $2.44 | [5] | $1.84 | [5] | ($1.88) | [5] | $1.33 | [5] | $1.48 | [5] | $1.22 | [5] | $8.13 | $2.13 | $4.15 | |||
Diluted (in dollars per share) | $2.12 | [5] | $1.69 | [5] | $2.42 | [5] | $1.82 | [5] | ($1.88) | [5] | $1.31 | [5] | $1.47 | [5] | $1.20 | [5] | $8.04 | $2.11 | $4.10 | |||
Average Number of Common Shares [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||
Basic (in dollars per share) | 270,929 | 270,471 | 270,016 | 269,358 | 268,941 | 267,941 | 266,874 | 266,674 | 270,170 | 267,577 | 262,735 | |||||||||||
Diluted (in dollars per share) | 273,983 | 273,576 | 272,739 | 272,263 | 268,941 | 270,982 | 269,985 | 270,242 | 273,114 | 270,762 | 266,268 | |||||||||||
Pretax impairments primarily related to proved and unproved natural gas properties in Canada and United States | ' | ' | ' | ' | 1,020,000,000 | ' | ' | ' | ' | 1,020,000,000 | ' | |||||||||||
Additional income tax provision for the quarter related to valuation allowances recorded to reduce value of foreign deferred tax assets | ' | ' | ' | ' | $135,000,000 | ' | ' | ' | ' | $135,000,000 | ' | |||||||||||
[1] | 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. | |||||||||||||||||||||
[2] | EOG had sales activity with a single significant purchaser in the United States segment in 2012 that totaled $2.2 billion of consolidated Net Operating Revenues. | |||||||||||||||||||||
[3] | EOG had no purchasers in 2011 whose sales totaled 10 percent or more of consolidated Net Operating Revenues. | |||||||||||||||||||||
[4] | The sum of quarterly net income (loss) per share may not agree with total year net income (loss) per share as each quarterly computation is based on the weighted average of common shares outstanding. | |||||||||||||||||||||
[5] | Fourth quarter 2012 results include the impact of pretax impairments of $1,020 million, primarily related to proved and unproved natural gas properties in Canada and the United States as well as an additional income tax provision of $135 million related to valuation allowances recorded to reduce the value of Canadian deferred tax assets. |