Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Feb. 18, 2016 | Jun. 30, 2015 | |
Document and Entity Information [Abstract] | |||
Entity Registrant Name | EOG RESOURCES INC | ||
Entity Central Index Key | 821,189 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Public Float | $ 63,532,000,000 | ||
Entity Common Stock, Shares Outstanding | 549,883,390 | ||
Document Fiscal Year Focus | 2,015 | ||
Document Fiscal Period Focus | FY | ||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2015 |
Consolidated Statements of Inco
Consolidated Statements of Income and Comprehensive Income - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |||||
Net Operating Revenues | |||||||
Crude Oil and Condensate | $ 4,934,562 | $ 9,742,480 | $ 8,300,647 | ||||
Natural Gas Liquids | 407,658 | 934,051 | 773,970 | ||||
Natural Gas | 1,061,038 | 1,916,386 | 1,681,029 | ||||
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts | 61,924 | 834,273 | (166,349) | ||||
Gathering, Processing and Marketing | 2,253,135 | 4,046,316 | 3,643,749 | ||||
Gains (Losses) on Asset Dispositions, Net | (8,798) | 507,590 | 197,565 | ||||
Other, Net | 47,909 | 54,244 | 56,507 | ||||
Total | 8,757,428 | [1] | 18,035,340 | [2] | 14,487,118 | [3] | |
Operating Expenses | |||||||
Lease and Well | 1,182,282 | 1,416,413 | 1,105,978 | ||||
Transportation Costs | 849,319 | 972,176 | 853,044 | ||||
Gathering and Processing Costs | 146,156 | 145,800 | 107,871 | ||||
Exploration Costs | 149,494 | 184,388 | 161,346 | ||||
Dry Hole Costs | [4] | 14,746 | 48,490 | 74,655 | |||
Impairments | 6,613,546 | 743,575 | 286,941 | ||||
Marketing Costs | 2,385,982 | 4,126,060 | 3,648,840 | ||||
Depreciation, Depletion and Amortization | 3,313,644 | 3,997,041 | 3,600,976 | ||||
General and Administrative | 366,594 | 402,010 | 348,312 | ||||
Taxes Other Than Income | 421,744 | 757,564 | 623,944 | ||||
Total | 15,443,507 | 12,793,517 | 10,811,907 | ||||
Operating Income (Loss) | (6,686,079) | 5,241,823 | 3,675,211 | ||||
Other Income (Expense), Net | 1,916 | (45,050) | (2,865) | ||||
Income (Loss) Before Interest Expense and Income Taxes | (6,684,163) | 5,196,773 | 3,672,346 | ||||
Interest Expense | |||||||
Incurred | 279,234 | 258,628 | 284,599 | ||||
Capitalized | (41,841) | (57,170) | (49,139) | ||||
Net Interest Expense | 237,393 | 201,458 | 235,460 | ||||
Income (Loss) Before Income Taxes | (6,921,556) | 4,995,315 | 3,436,886 | ||||
Income Tax Provision | (2,397,041) | 2,079,828 | 1,239,777 | ||||
Net Income (Loss) | $ (4,524,515) | $ 2,915,487 | $ 2,197,109 | ||||
Net Income (Loss) Per Share | |||||||
Basic (in dollars per share) | $ (8.29) | $ 5.36 | $ 4.07 | ||||
Diluted (in dollars per share) | (8.29) | 5.32 | 4.02 | ||||
Dividends Declared per Common Share | $ 0.670 | $ 0.585 | $ 0.375 | ||||
Average Number of Common Shares [Abstract] | |||||||
Basic (in shares) | 545,697 | 543,443 | 540,341 | ||||
Diluted (in shares) | 545,697 | 548,539 | 546,227 | ||||
Statement Of Comprehensive Income [Abstract] | |||||||
Net Income (Loss) | $ (4,524,515) | $ 2,915,487 | $ 2,197,109 | ||||
Other Comprehensive Income (Loss) | |||||||
Foreign Currency Translation Adjustments | (11,517) | (437,728) | (29,395) | ||||
Other | 1,235 | (1,162) | 5,334 | ||||
Other Comprehensive Income (Loss) | (10,282) | (438,890) | (24,061) | ||||
Comprehensive Income (Loss) | $ (4,534,797) | $ 2,476,597 | $ 2,173,048 | ||||
[1] | EOG had sales activity with two significant purchasers in 2015, one totaling $1.7 billion and the other totaling $1.4 billion of consolidated Net Operating Revenues in the United States segment. | ||||||
[2] | EOG had sales activity with two significant purchasers in 2014, one totaling $4.0 billion and the other totaling $3.0 billion of consolidated Net Operating Revenues in the United States segment. | ||||||
[3] | EOG had sales activity with two significant purchasers in 2013, one totaling $3.9 billion and the other totaling $2.0 billion of consolidated Net Operating Revenues in the United States segment. | ||||||
[4] | Excludes gains or losses on the mark-to-market of financial commodity derivative contracts, gains or losses on sales of reserves and related assets, interest charges and general corporate expenses for each of the three years in the period ended December 31, 2015. |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Current Assets | ||
Cash and Cash Equivalents | $ 718,506 | $ 2,087,213 |
Accounts Receivable, Net | 930,610 | 1,779,311 |
Inventories | 598,935 | 706,597 |
Assets from Price Risk Management Activities | 0 | 465,128 |
Income Taxes Receivable | 40,704 | 71,621 |
Deferred Income Taxes | 147,812 | 19,618 |
Other | 155,677 | 286,533 |
Total | 2,592,244 | 5,416,021 |
Property, Plant and Equipment | ||
Oil and Gas Properties (Successful Efforts Method) | 50,613,241 | 46,503,532 |
Other Property, Plant and Equipment | 3,986,610 | 3,750,958 |
Total Property, Plant and Equipment | 54,599,851 | 50,254,490 |
Less: Accumulated Depreciation, Depletion and Amortization | (30,389,130) | (21,081,846) |
Total Property, Plant and Equipment, Net | 24,210,721 | 29,172,644 |
Other Assets | 172,279 | 174,022 |
Total Assets | 26,975,244 | 34,762,687 |
Current Liabilities | ||
Accounts Payable | 1,471,953 | 2,860,548 |
Accrued Taxes Payable | 93,618 | 140,098 |
Dividends Payable | 91,546 | 91,594 |
Deferred Income Taxes | 0 | 110,743 |
Current Portion of Long-Term Debt | 6,579 | 6,579 |
Other | 155,591 | 174,746 |
Total | 1,819,287 | 3,384,308 |
Long-Term Debt | 6,653,685 | 5,903,354 |
Other Liabilities | 971,335 | 939,497 |
Deferred Income Taxes | 4,587,902 | $ 6,822,946 |
Commitments and Contingencies (Note 8) | ||
Stockholders' Equity | ||
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 550,150,823 Shares and 549,028,374 Shares Issued at December 31, 2015 and 2014, respectively | 205,502 | $ 205,492 |
Additional Paid in Capital | 2,923,461 | 2,837,150 |
Accumulated Other Comprehensive Income (Loss) | (33,338) | (23,056) |
Retained Earnings | 9,870,816 | 14,763,098 |
Common Stock Held in Treasury, 292,179 Shares and 733,517 Shares at December 31, 2015 and 2014, respectively | (23,406) | (70,102) |
Total Stockholders' Equity | 12,943,035 | 17,712,582 |
Total Liabilities and Stockholders' Equity | $ 26,975,244 | $ 34,762,687 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2015 | Dec. 31, 2014 |
Common Stock | ||
Common Stock, Par Value (in dollars per share) | $ 0.01 | $ 0.01 |
Common Stock, Shares Authorized (in shares) | 640,000,000 | 640,000,000 |
Common Stock, Shares Issued (in shares) | 550,150,823 | 549,028,374 |
Treasury Stock | ||
Common Stock Held in Treasury (in shares) | 292,179 | 733,517 |
Consolidated Statements of Stoc
Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands | Total | Common Stock Held in Treasury [Member] | Retained Earnings [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | Additional Paid-in Capital [Member] | Common Stock [Member] |
Common Stock Dividends Declared (in dollars per share) | $ 0.375 | |||||
Balance at Dec. 31, 2012 | $ 13,284,764 | $ (33,822) | $ 10,175,631 | $ 439,895 | $ 2,500,340 | $ 202,720 |
Net Income (Loss) | 2,197,109 | 0 | 2,197,109 | 0 | 0 | 0 |
Common Stock Issued Under Stock Plans | 38,729 | 0 | 0 | 0 | 38,723 | 6 |
Dividends, Common Stock | (204,463) | 0 | (204,463) | 0 | 0 | 0 |
Other Comprehensive Income (Loss) | (24,061) | 0 | 0 | (24,061) | 0 | 0 |
Change in Treasury Stock - Stock Compensation Plans, Net | (32,214) | 47,427 | 0 | 0 | (79,641) | 0 |
Excess Tax Benefit from Stock-Based Compensation | 55,831 | 0 | 0 | 0 | 55,831 | 0 |
Restricted Stock and Restricted Stock Units, Net | (31,422) | (28,454) | 0 | 0 | (2,974) | 6 |
Stock-Based Compensation Expenses | 134,467 | 0 | 0 | 0 | 134,467 | 0 |
Treasury Stock Issued as Compensation | (281) | (414) | 0 | 0 | 133 | 0 |
Balance at Dec. 31, 2013 | $ 15,418,459 | (15,263) | 12,168,277 | 415,834 | 2,646,879 | 202,732 |
Common Stock Dividends Declared (in dollars per share) | $ 0.585 | |||||
Net Income (Loss) | $ 2,915,487 | 0 | 2,915,487 | 0 | 0 | 0 |
Common Stock Issued Under Stock Plans | 22,260 | 0 | 0 | 0 | 22,252 | 8 |
Dividends, Common Stock | (320,666) | 0 | (320,666) | 0 | 0 | 0 |
Other Comprehensive Income (Loss) | (438,890) | 0 | 0 | (438,890) | 0 | 0 |
Change in Treasury Stock - Stock Compensation Plans, Net | (127,432) | (96,962) | 0 | 0 | (30,470) | 0 |
Excess Tax Benefit from Stock-Based Compensation | 99,459 | 0 | 0 | 0 | 99,459 | 0 |
Restricted Stock and Restricted Stock Units, Net | 0 | 43,091 | 0 | 0 | (43,109) | 18 |
Stock-Based Compensation Expenses | 144,842 | 0 | 0 | 0 | 144,842 | 0 |
Common Stock Issued - Stock Split | 0 | 0 | 0 | 0 | (2,734) | 2,734 |
Treasury Stock Issued as Compensation | (937) | (968) | 0 | 0 | 31 | 0 |
Balance at Dec. 31, 2014 | $ 17,712,582 | (70,102) | 14,763,098 | (23,056) | 2,837,150 | 205,492 |
Common Stock Dividends Declared (in dollars per share) | $ 0.670 | |||||
Net Income (Loss) | $ (4,524,515) | 0 | (4,524,515) | 0 | 0 | 0 |
Common Stock Issued Under Stock Plans | 15,371 | 0 | 0 | 0 | 15,366 | 5 |
Dividends, Common Stock | (367,767) | 0 | (367,767) | 0 | 0 | 0 |
Other Comprehensive Income (Loss) | (10,282) | 0 | 0 | (10,282) | 0 | 0 |
Change in Treasury Stock - Stock Compensation Plans, Net | (41,471) | (129) | 0 | 0 | (41,342) | 0 |
Excess Tax Benefit from Stock-Based Compensation | 26,058 | 0 | 0 | 0 | 26,058 | 0 |
Restricted Stock and Restricted Stock Units, Net | 0 | 44,334 | 0 | 0 | (44,339) | 5 |
Stock-Based Compensation Expenses | 130,577 | 0 | 0 | 0 | 130,577 | 0 |
Treasury Stock Issued as Compensation | 2,482 | 2,491 | 0 | 0 | (9) | 0 |
Balance at Dec. 31, 2015 | $ 12,943,035 | $ (23,406) | $ 9,870,816 | $ (33,338) | $ 2,923,461 | $ 205,502 |
Consolidated Statements of Sto6
Consolidated Statements of Stockholders' Equity (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Statement of Stockholders' Equity [Abstract] | |||
Dividends, Common Stock | $ (367,767) | $ (320,666) | $ (204,463) |
Common Stock Dividends Declared (in dollars per share) | $ 0.670 | $ 0.585 | $ 0.375 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Cash Flows from Operating Activities | ||||
Net Income (Loss) | $ (4,524,515) | $ 2,915,487 | $ 2,197,109 | |
Items Not Requiring (Providing) Cash | ||||
Depreciation, Depletion and Amortization | 3,313,644 | 3,997,041 | 3,600,976 | |
Impairments | 6,613,546 | 743,575 | 286,941 | |
Stock-Based Compensation Expenses | 130,577 | 145,086 | 134,055 | |
Deferred Income Taxes | (2,482,307) | 1,704,946 | 874,765 | |
(Gains) Losses on Asset Dispositions, Net | 8,798 | (507,590) | (197,565) | |
Other, Net | 11,896 | 48,138 | 11,072 | |
Dry Hole Costs | [1] | 14,746 | 48,490 | 74,655 |
Mark-to-Market Commodity Derivative Contracts | ||||
Total (Gains) Losses | (61,924) | (834,273) | 166,349 | |
Net Cash Received from Settlements of Commodity Derivative Contracts | 730,114 | 34,007 | 116,361 | |
Excess Tax Benefits from Stock-Based Compensation | (26,058) | (99,459) | (55,831) | |
Other, Net | 12,532 | 13,009 | 18,205 | |
Changes in Components of Working Capital and Other Assets and Liabilities | ||||
Accounts Receivable | 641,412 | 84,982 | (23,613) | |
Inventories | 58,450 | (161,958) | 53,402 | |
Accounts Payable | (1,409,197) | 543,630 | 178,701 | |
Accrued Taxes Payable | 11,798 | 16,486 | 75,142 | |
Other Assets | 118,143 | (14,448) | (109,567) | |
Other Liabilities | (66,257) | 75,420 | (20,382) | |
Changes in Components of Working Capital Associated with Investing and Financing Activities | 499,767 | (103,414) | (51,361) | |
Net Cash Provided by Operating Activities | 3,595,165 | 8,649,155 | 7,329,414 | |
Investing Cash Flows | ||||
Additions to Oil and Gas Properties | (4,725,150) | (7,519,667) | (6,697,091) | |
Additions to Other Property, Plant and Equipment | (288,013) | (727,138) | (363,536) | |
Proceeds from Sales of Assets | 192,807 | 569,332 | 760,557 | |
Changes in Restricted Cash | 0 | 60,385 | (65,814) | |
Changes in Components of Working Capital Associated with Investing Activities | (499,900) | 103,523 | 51,106 | |
Net Cash Used in Investing Activities | (5,320,256) | (7,513,565) | (6,314,778) | |
Financing Cash Flows | ||||
Proceeds from Issuance of Commercial Paper | 259,718 | 0 | 0 | |
Long-Term Debt Borrowings | 990,225 | 496,220 | 0 | |
Long-Term Debt Repayments | (500,000) | (500,000) | (400,000) | |
Settlement of Foreign Currency Swap | 0 | (31,573) | 0 | |
Dividends Paid | (367,005) | (279,695) | (199,178) | |
Excess Tax Benefits from Stock-Based Compensation | 26,058 | 99,459 | 55,831 | |
Treasury Stock Purchased | (48,791) | (127,424) | (63,784) | |
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan | 22,690 | 22,249 | 38,730 | |
Debt Issuance Costs | (5,951) | (895) | 0 | |
Repayment of Capital Lease Obligation | (6,156) | (5,966) | (5,780) | |
Other, Net | 133 | (109) | 255 | |
Net Cash Provided by (Used in) Financing Activities | 370,921 | (327,734) | (573,926) | |
Effect of Exchange Rate Changes on Cash | (14,537) | (38,852) | 1,064 | |
Increase (Decrease) in Cash and Cash Equivalents | (1,368,707) | 769,004 | 441,774 | |
Cash and Cash Equivalents at Beginning of Year | 2,087,213 | 1,318,209 | 876,435 | |
Cash and Cash Equivalents at End of Year | $ 718,506 | $ 2,087,213 | $ 1,318,209 | |
[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, 2015. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies Principles of Consolidation. The consolidated financial statements of EOG Resources, Inc. (EOG) include the accounts of all domestic and foreign subsidiaries. Investments in unconsolidated affiliates, in which EOG is able to exercise significant influence, are accounted for using the equity method. All intercompany accounts and transactions have been eliminated. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Financial Instruments. EOG's financial instruments consist of cash and cash equivalents, commodity derivative contracts, accounts receivable, accounts payable and current and long-term debt. The carrying values of cash and cash equivalents, commodity derivative contracts, accounts receivable and accounts payable approximate fair value (see Notes 2 and 12). Cash and Cash Equivalents. EOG records as cash equivalents all highly liquid short-term investments with original maturities of three months or less. Oil and Gas Operations. EOG accounts for its crude oil and natural gas exploration and production activities under the successful efforts method of accounting. Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred. Oil and gas exploration costs, other than the costs of drilling exploratory wells, are expensed as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether EOG has discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made (see Note 16). Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account. Oil and gas properties are grouped in accordance with the Extractive Industries - Oil and Gas Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC). The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. Amortization rates are updated quarterly to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions and/or property dispositions and 4) impairments. When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the asset. If the expected undiscounted future cash flows, based on EOG's estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach described in the Fair Value Measurement Topic of the ASC. If applicable, EOG utilizes accepted bids as the basis for determining fair value. Inventories, consisting primarily of tubular goods, materials for completion operations and well equipment held for use in the exploration for, and development and production of, crude oil and natural gas reserves, are carried at cost with adjustments made, as appropriate, to recognize any reductions in value. Arrangements for sales of crude oil and condensate, natural gas liquids (NGLs) and natural gas are evidenced by signed contracts with determinable market prices, and revenues are recorded when production is delivered. A significant majority of these products are sold to purchasers who have investment-grade credit ratings and material credit losses have been rare. Revenues are recorded on the entitlement method based on EOG's percentage ownership of current production. Each working interest owner in a well generally has the right to a specific percentage of production, although actual production sold on that owner's behalf may differ from that owner's ownership percentage. Under entitlement accounting, a receivable is recorded when underproduction occurs and a payable is recorded when overproduction occurs. Gathering, processing and marketing revenues represent sales of third-party crude oil and condensate, NGLs and natural gas, as well as gathering fees associated with gathering third-party natural gas and revenues from sales of EOG-owned sand. Other Property, Plant and Equipment . Other property, plant and equipment consists of gathering and processing assets, compressors, buildings and leasehold improvements, crude-by-rail assets, sand mine and sand processing assets, computer hardware and software, vehicles, and furniture and fixtures. Other property, plant and equipment is generally depreciated on a straight-line basis over the estimated useful lives of the property, plant and equipment, which range from 3 years to 45 years. Capitalized Interest Costs. Interest costs have been capitalized as a part of the historical cost of unproved oil and gas properties. The amount capitalized is an allocation of the interest cost incurred during the reporting period. Capitalized interest is computed only during the exploration and development phases and ceases once production begins. The interest rate used for capitalization purposes is based on the interest rates on EOG's outstanding borrowings. Accounting for Risk Management Activities. Derivative instruments are recorded on the balance sheet as either an asset or liability measured at fair value, and changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met. During the three-year period ended December 31, 2015, EOG elected not to designate any of its financial commodity derivative instruments as accounting hedges and, accordingly, changes in the fair value of these outstanding derivative instruments are recognized as gains or losses in the period of change. The gains or losses are recorded as Gains (Losses) on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income and Comprehensive Income. The related cash flow impact of settled contracts is reflected as cash flows from operating activities. EOG was party to a foreign currency swap transaction and an interest rate swap transaction, both of which were accounted for using the hedge accounting method. EOG employs net presentation of derivative assets and liabilities for financial reporting purposes when such assets and liabilities are with the same counterparty and subject to a master netting arrangement. See Note 12. Income Taxes. Income taxes are accounted for using the asset and liability approach. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. EOG assesses the realizability of deferred tax assets and recognizes valuation allowances as appropriate (see Note 6). Foreign Currency Translation. The United States dollar is the functional currency for all of EOG's consolidated subsidiaries except for its Canadian subsidiaries, for which the functional currency is the Canadian dollar, and its United Kingdom subsidiary, for which the functional currency is the British pound. For subsidiaries whose functional currency is deemed to be other than the United States dollar, asset and liability accounts are translated at year-end exchange rates and revenues and expenses are translated at average exchange rates prevailing during the year. Translation adjustments are included in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets. Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period. See Notes 4 and 17. Net Income (Loss) Per Share. Basic net income (loss) per share is computed on the basis of the weighted-average number of common shares outstanding during the period. Diluted net income (loss) per share is computed based upon the weighted-average number of common shares outstanding during the period plus the assumed issuance of common shares for all potentially dilutive securities (see Note 9). Stock-Based Compensation . EOG measures the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (see Note 7). Recently Issued Accounting Standards. In November 2015, the FASB issued Accounting Standards Update (ASU) 2015-17, "Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes " (ASU 2015-17), which simplifies the presentation of deferred taxes in a classified balance sheet by eliminating the requirement to separate deferred income tax liabilities and assets into current and noncurrent amounts. Instead, ASU 2015-17 requires that all deferred tax liabilities and assets be shown as noncurrent in a classified balance sheet. ASU 2015-17 is effective for financial statements issued for interim and annual periods beginning after December 15, 2016, and early adoption is permitted. EOG does not intend to early-adopt ASU 2015-17 and does not expect the new standard to have a material impact on its consolidated financial statements and related disclosures. In July 2015, the FASB issued ASU 2015-11, "Accounting for Inventory" (ASU 2015-11), which requires entities to measure most inventory at lower of cost or net realizable value. ASU 2015-11 defines net realizable value as "the estimated selling prices in the ordinary course of business, less reasonably predictable cost of completion, disposal and transportation." ASU 2015-11 is effective prospectively for interim and annual periods beginning after December 15, 2016. EOG is reviewing the requirements of the new standard and does not believe that the adoption of ASU 2015-11 will have a material impact on its consolidated financial statements and related disclosures. In April 2015, the FASB issued ASU 2015-03, "Interest - Computation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs" (ASU 2015-03), which changes the presentation of debt issuance costs in financial statements. Under ASU 2015-03, an entity will present debt issuance costs in the balance sheet as a direct reduction from the related debt liability rather than as an asset. Amortization of such costs will be presented as a component of interest expense. ASU 2015-03 is effective for interim and annual reporting periods beginning after December 15, 2015. Early adoption is permitted. Because ASU 2015-03 does not address debt issuance costs related to line-of-credit arrangements, in August 2015, the FASB issued ASU 2015-15 "Interest - Computation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements" (ASU 2015-15). ASU 2015-15 provides that, in the absence of authoritative guidance in ASU 2015-03, the United States Securities and Exchange Commission would not object to an entity deferring and presenting debt issuance costs related to a line-of-credit arrangement as an asset and subsequently amortizing the deferred debt issuance costs over the term of the line-of-credit arrangement. EOG does not expect the adoption of ASU 2015-03 and ASU 2015-15 to have a material impact on its consolidated financial statements and related disclosures. In May 2014, the FASB issued ASU 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09), which will require entities to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will supersede most current guidance related to revenue recognition when it becomes effective. The new standard also will require expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. The FASB originally intended ASU 2014-09 to be effective for interim and annual reporting periods beginning after December 15, 2016, and permits adoption through the use of either the full retrospective approach or a modified retrospective approach. In July 2015, the FASB issued an update which delays by one year the effective date of ASU 2014-09 and allows for early adoption as of the original effective date. EOG does not intend to early-adopt ASU 2014-09 and has not determined which transition method it will use. EOG continues to analyze ASU 2014-09 to determine what impact the new standard will have on its consolidated financial statements and related disclosures. |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | Long-Term Debt Long-Term Debt at December 31, 2015 and 2014 consisted of the following (in thousands): 2015 2014 Commercial Paper $ 259,718 $ — 2.95% Senior Notes due 2015 — 500,000 2.500% Senior Notes due 2016 400,000 400,000 5.875% Senior Notes due 2017 600,000 600,000 6.875% Senior Notes due 2018 350,000 350,000 5.625% Senior Notes due 2019 900,000 900,000 4.40% Senior Notes due 2020 500,000 500,000 2.45% Senior Notes due 2020 500,000 500,000 4.100% Senior Notes due 2021 750,000 750,000 2.625% Senior Notes due 2023 1,250,000 1,250,000 3.15% Senior Notes due 2025 500,000 — 6.65% Senior Notes due 2028 140,000 140,000 3.90% Senior Notes due 2035 500,000 — Long-Term Debt 6,649,718 5,890,000 Capital Lease Obligation 45,064 51,221 Less: Current Portion of Long-Term Debt 6,579 6,579 Unamortized Debt Discount 34,518 31,288 Total Long-Term Debt $ 6,653,685 $ 5,903,354 At December 31, 2015 , the aggregate annual maturities of long-term debt (excluding capital lease obligations) were $ 400 million in 2016, $ 600 million in 2017, $ 350 million in 2018, $ 900 million in 2019 and $1 billion in 2020. At December 31, 2015 and 2014 , EOG had $260 million and zero , respectively, of outstanding short-term borrowings under the commercial paper program and no outstanding borrowings under uncommitted credit facilities. During 2015 and 2014 , EOG utilized commercial paper and short-term borrowings under uncommitted credit facilities, bearing market interest rates, for various corporate financing purposes. The average borrowings outstanding under the commercial paper program were $81 million and $12 million during the years ended December 31, 2015 and 2014 , respectively. The average borrowings outstanding under the uncommitted credit facilities were zero and $0.1 million during the years ended December 31, 2015 and 2014 , respectively. The weighted average interest rates for commercial paper borrowings were 0.51% and 0.25% for the years 2015 and 2014 , respectively, and were 0.70% for uncommitted credit facility borrowings for the year 2014 . At December 31, 2015 , the $400 million aggregate principal amount of its 2.500% Senior Notes due 2016 (2016 Notes) and $260 million aggregate principal amount of commercial paper borrowings were classified as long-term debt based upon EOG's intent and ability to ultimately replace such amount with other long-term debt. On January 14, 2016, EOG closed its sale of $750 million aggregate principal amount of its 4.15% Senior Notes due 2026 and $250 million aggregate principal amount of its 5.10% Senior Notes due 2036 (collectively, the New Notes). Interest on the New Notes is payable semi-annually in arrears on January 15 and July 15 of each year beginning on July 15, 2016. Net proceeds from the New Notes offering totaled approximately $991 million and were used to repay the 2016 Notes when they matured on February 1, 2016, and for general corporate purposes, including repayment of outstanding commercial paper borrowings and funding of future capital expenditures. On July 21, 2015, EOG entered into a new $2.0 billion senior unsecured Revolving Credit Agreement (2015 Agreement) with domestic and foreign lenders. The 2015 Agreement replaces EOG's $2.0 billion senior unsecured Revolving Credit Agreement, dated as of October 11, 2011, which had a scheduled maturity date of October 11, 2016 (2011 Agreement). There were no borrowings or letters of credit outstanding under the 2011 Agreement as of the closing of the 2015 Agreement and the termination of the 2011 Agreement. The 2015 Agreement has a scheduled maturity date of July 21, 2020 , and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods subject to certain terms and conditions. Advances under the 2015 Agreement will accrue interest based, at EOG's option, on either the London InterBank Offered Rate plus an applicable margin (Eurodollar rate) or the base rate (as defined in the 2015 Agreement) plus an applicable margin. Consistent with the terms of the 2011 Agreement, the 2015 Agreement contains representations, warranties, covenants and events of default that are customary for investment-grade, senior unsecured commercial bank credit agreements, including a financial covenant for the maintenance of a debt-to-total capitalization ratio of no greater than 65% . At December 31, 2015 , there were no borrowings or letters of credit outstanding under the 2015 Agreement. The Eurodollar rate and applicable base rate, had there been any amounts borrowed under the 2015 Agreement, would have been 1.33% and 3.50% , respectively. On June 1, 2015, EOG repaid upon maturity the $500 million aggregate principal amount of its 2.95% Senior Notes due 2015. On March 17, 2015, EOG closed its sale of $500 million aggregate principal amount of its 3.15% Senior Notes due 2025 and $500 million aggregate principal amount of its 3.90% Senior Notes due 2035 (together, the Notes). Interest on the Notes is payable semi-annually in arrears on April 1 and October 1 of each year, beginning on October 1, 2015. Net proceeds from the Notes offering of approximately $990 million were used for general corporate purposes. |
Stockholder's Equity
Stockholder's Equity | 12 Months Ended |
Dec. 31, 2015 | |
Stockholders' Equity Note [Abstract] | |
Stockholder's Equity | Stockholders' Equity Common Stock. In September 2001, EOG's Board of Directors (Board) authorized the purchase of an aggregate maximum of 10 million shares of Common Stock that superseded all previous authorizations. At December 31, 2015 , 6,386,200 shares remained available for purchase under this authorization. EOG last purchased shares of its Common Stock under this authorization in March 2003. In addition, shares of Common Stock are from time to time withheld by, or returned to, EOG in satisfaction of tax withholding obligations arising upon the exercise of employee stock options or stock-settled stock appreciation rights (SARs), the vesting of restricted stock or restricted stock unit grants or in payment of the exercise price of employee stock options. Such shares withheld or returned do not count against the Board authorization discussed above. Shares purchased, withheld and returned are held in treasury for, among other purposes, fulfilling any obligations arising under EOG's stock-based compensation plans and any other approved transactions or activities for which such shares of Common Stock may be required. On February 24, 2014, EOG's Board approved a two-for-one stock split in the form of a stock dividend, which was paid on March 31, 2014, to stockholders of record as of March 17, 2014. On August 5, 2014, the Board increased the quarterly cash dividend on the common stock by 34% to $0.1675 per share, effective beginning with the dividend paid on October 31, 2014, to stockholders of record as of October 17, 2014. On February 24, 2014, the Board increased the quarterly cash dividend on the common stock by 33 % to $0.125 per share, effective beginning with the dividend paid on April 30, 2014, to stockholders of record as of April 16, 2014. The Board increased the quarterly cash dividend on the Common Stock to $0.0938 per share on February 13, 2013, effective beginning with the dividend paid on April 30, 2013, to stockholders of record as of April 16, 2013. The following summarizes Common Stock activity for each of the years ended December 31, 2013 , 2014 and 2015 (in thousands): Common Shares Issued Treasury Outstanding Balance at December 31, 2012 543,916 (652 ) 543,264 Common Stock Issued Under Stock-Based Compensation Plans 2,206 — 2,206 Treasury Stock Purchased (1) — (854 ) (854 ) Common Stock Issued Under Employee Stock Purchase Plan 256 — 256 Treasury Stock Issued Under Stock-Based Compensation Plans — 1,300 1,300 Balance at December 31, 2013 546,378 (206 ) 546,172 Common Stock Issued Under Stock-Based Compensation Plans 2,448 — 2,448 Treasury Stock Purchased (1) — (1,209 ) (1,209 ) Common Stock Issued Under Employee Stock Purchase Plan 202 — 202 Treasury Stock Issued Under Stock-Based Compensation Plans — 682 682 Balance at December 31, 2014 549,028 (733 ) 548,295 Common Stock Issued Under Stock-Based Compensation Plans 1,019 — 1,019 Treasury Stock Purchased (1) — (581 ) (581 ) Common Stock Issued Under Employee Stock Purchase Plan 104 121 225 Treasury Stock Issued Under Stock-Based Compensation Plans — 901 901 Balance at December 31, 2015 550,151 (292 ) 549,859 (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, 2015 , there were no shares of preferred stock outstanding. |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income (Loss) | 12 Months Ended |
Dec. 31, 2015 | |
Accumulated Other Comprehensive Income [Abstract] | |
Accumulated Other Comprehensive Income (Loss) | Accumulated Other Comprehensive Income (Loss) Accumulated other comprehensive income (loss) includes certain transactions that have generally been reported in the Consolidated Statements of Stockholders' Equity. The components of Accumulated Other Comprehensive Income (Loss) at December 31, 2015 and 2014 consisted of the following (in thousands): Foreign Currency Translation Adjustment Other Total December 31, 2013 $ 417,707 $ (1,873 ) $ 415,834 Other comprehensive loss before reclassifications (54,484 ) (918 ) (55,402 ) Amounts reclassified out of other comprehensive income (loss) (383,244 ) (1) 246 (2) (382,998 ) Tax effects — (490 ) (490 ) Other comprehensive income (loss) (437,728 ) (1,162 ) (438,890 ) December 31, 2014 (20,021 ) (3,035 ) (23,056 ) Other comprehensive loss before reclassifications (11,517 ) (129 ) (11,646 ) Amounts reclassified out of other comprehensive income (loss) — 1,572 (3) 1,572 Tax effects — (208 ) (208 ) Other comprehensive income (loss) (11,517 ) 1,235 (10,282 ) December 31, 2015 $ (31,538 ) $ (1,800 ) $ (33,338 ) (1) Reclassified to Net Income (Loss) - Gains (Losses) on Asset Dispositions, Net. See Note 17. (2) Includes $107 thousand reclassified to Net Income (Loss) - Interest Expense in connection with the settlement of a foreign currency swap and an interest rate swap and $139 thousand reclassified to Net Income (Loss) - General and Administrative related to certain EOG pension plans (see Note 7). (3) Reclassified to Net Income (Loss) - General and Administrative. Related to certain EOG pension plans. See Note 7. No significant amount was reclassified out of Accumulated Other Comprehensive Income (Loss) during the year ended December 31, 2013. |
Other Income (Expense), Net
Other Income (Expense), Net | 12 Months Ended |
Dec. 31, 2015 | |
Other Income and Expenses [Abstract] | |
Other Income (Expense), Net | Other Income (Expense), Net Other income, net, for 2015 included equity income from investments in ammonia plants in Trinidad ( $9 million ), a downward adjustment to deferred compensation expense ( $6 million ), interest income ( $3 million ) and net foreign currency transaction losses ( $(17) million ). Other expense, net, for 2014 included net foreign currency transaction losses ( $(34) million ), losses on dispositions of warehouse stock ( $15 million ) and equity income from investments in ammonia plants in Trinidad ( $8 million ). Other expense, net, for 2013 included losses on dispositions of warehouse stock ( $23 million ), net foreign currency transaction gains ( $12 million ), equity income from investments in ammonia plants in Trinidad ( $11 million ) and interest income ( $6 million ) primarily related to sales and use tax refunds. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes The principal components of EOG's net deferred income tax liabilities at December 31, 2015 and 2014 were as follows (in thousands): 2015 2014 Current Deferred Income Tax Assets (Liabilities) Deferred Compensation Plans $ 38,559 $ — Alternative Minimum Tax Credit Carryforward 93,316 — Foreign Net Operating Loss 47,786 49,865 Foreign Valuation Allowance (35,536 ) (30,247 ) Other 3,687 — Total Net Current Deferred Income Tax Assets $ 147,812 $ 19,618 Noncurrent Deferred Income Tax Assets (Liabilities) Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization $ (57,569 ) $ (141,643 ) Foreign Net Operating Loss 443,010 487,876 Foreign Valuation Allowances (380,104 ) (349,704 ) Foreign Other 1,506 4,096 Total Net Noncurrent Deferred Income Tax Assets $ 6,843 $ 625 Current Deferred Income Tax (Asset) Liabilities Commodity Hedging Contracts $ — $ 166,109 Deferred Compensation Plans — (48,207 ) Accrued Expenses and Liabilities — (5,643 ) Other — (1,516 ) Total Net Current Deferred Income Tax Liabilities $ — $ 110,743 Noncurrent Deferred Income Tax (Assets) Liabilities Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization $ 5,299,817 $ 7,634,297 Non-Producing Leasehold Costs (53,026 ) (44,236 ) Seismic Costs Capitalized for Tax (162,240 ) (158,157 ) Equity Awards (140,663 ) (127,541 ) Capitalized Interest 98,242 97,739 Alternative Minimum Tax Credit Carryforward (685,189 ) (793,126 ) Undistributed Foreign Earnings 258,403 249,861 Other (27,442 ) (35,891 ) Total Net Noncurrent Deferred Income Tax Liabilities $ 4,587,902 $ 6,822,946 Total Net Deferred Income Tax Liabilities $ 4,433,247 $ 6,913,446 The components of Income (Loss) Before Income Taxes for the years indicated below were as follows (in thousands): 2015 2014 2013 United States $ (6,840,119 ) $ 5,161,232 $ 3,268,727 Foreign (81,437 ) (165,917 ) 168,159 Total $ (6,921,556 ) $ 4,995,315 $ 3,436,886 The principal components of EOG's Income Tax Provision (Benefit) for the years indicated below were as follows (in thousands): 2015 2014 2013 Current: Federal $ 21,719 $ 269,326 $ 207,777 State 9,404 22,835 22,856 Foreign 54,143 82,721 134,379 Total 85,266 374,882 365,012 Deferred: Federal (2,362,926 ) 1,608,706 915,994 State (127,444 ) 29,056 26,305 Foreign 8,063 67,184 (67,534 ) Total (2,482,307 ) 1,704,946 874,765 Income Tax Provision (Benefit) $ (2,397,041 ) $ 2,079,828 $ 1,239,777 The differences between taxes computed at the United States federal statutory tax rate and EOG's effective rate were as follows: 2015 2014 2013 Statutory Federal Income Tax Rate 35.00 % 35.00 % 35.00 % State Income Tax, Net of Federal Benefit 1.11 0.68 0.93 Income Tax Provision Related to Foreign Operations (1.31 ) (0.12 ) 0.23 Canadian Divestiture — (3.46 ) — Undistributed Foreign Earnings — 4.94 — Foreign Valuation Allowances — 6.47 — Foreign Oil and Gas Impairments — (1.90 ) — Other (0.17 ) 0.03 (0.09 ) Effective Income Tax Rate 34.63 % 41.64 % 36.07 % The effective tax rate of 35% in 2015 was lower than the prior year rate of 42% primarily due to the effects of recording valuation allowances in the United Kingdom and deferred taxes in the United States on undistributed foreign earnings in 2014. Deferred tax assets are recorded for certain tax benefits, including tax net operating losses (NOLs) and tax credit carryforwards, provided that management assesses the utilization of such assets to be "more likely than not." Management assesses the available positive and negative evidence to estimate if sufficient future taxable income will be generated to use the existing deferred tax assets. On the basis of this evaluation, EOG has recorded valuation allowances for the portion of certain foreign and state deferred tax assets that management does not believe are more likely than not to be realized. The principal components of EOG's rollforward of valuation allowances for deferred tax assets were as follows (in thousands): 2015 2014 2013 Beginning Balance $ 463,018 $ 223,599 $ 199,743 Increase (1) 146,602 392,729 43,422 Decrease (2) (4,315 ) (1,424 ) (4,967 ) Other (3) (99,178 ) (151,886 ) (14,599 ) Ending Balance $ 506,127 $ 463,018 $ 223,599 (1) Increase in valuation allowance related to the generation of tax net operating losses and other deferred tax assets. (2) Decrease in valuation allowance associated with adjustments to certain deferred tax assets and their related allowance. (3) Represents dispositions/revisions/foreign exchange rate variances and the effect of statutory income tax rate changes. The balance of unrecognized tax benefits at December 31, 2015 , was zero . When applicable, EOG records interest and penalties related to unrecognized tax benefits to its income tax provision. Currently, there are no amounts of interest or penalties recognized on the Consolidated Statements of Income and Comprehensive Income or on the Consolidated Balance Sheets. EOG does not anticipate that the amount of the unrecognized tax benefits will significantly change during the next twelve months. EOG and its subsidiaries file income tax returns and are subject to tax audits in the United States and various state, local and foreign jurisdictions. EOG's earliest open tax years in its principal jurisdictions are as follows: United States federal (2011), Canada (2011), United Kingdom (2014), Trinidad (2002) and China (2008). EOG's foreign subsidiaries' undistributed earnings of approximately $2 billion at December 31, 2015 , are no longer considered to be permanently reinvested outside the United States and, accordingly, EOG has cumulatively recorded $258 million of United States federal and state deferred income taxes. EOG changed its permanent reinvestment assertion in 2014. In 2015 , EOG utilized alternative minimum tax (AMT) credits of $4 million . Additional AMT credits of $779 million , resulting from AMT paid in prior years, will be carried forward indefinitely until they are used to offset regular income taxes in future periods. The ability of EOG to utilize these AMT credit carryforwards to reduce federal income taxes may become subject to various limitations under the Internal Revenue Code. Such limitations may arise if certain ownership changes (as defined for income tax purposes) were to occur. As of December 31, 2015 , management does not believe that an ownership change has occurred which would limit these carryforwards. As of December 31, 2015 , EOG had state income tax NOLs being carried forward of approximately $1.7 billion , which, if unused, expire between 2016 and 2034. During 2015 , EOG's United Kingdom subsidiary incurred a tax NOL of approximately $153 million which, along with prior years' NOLs of $764 million , will be carried forward indefinitely. As described above, these NOLs have been evaluated for the likelihood of future utilization, and valuation allowances have been established for the portion of these deferred tax assets that do not meet the "more likely than not" threshold. The Protecting Americans from Tax Hikes Act of 2015 (PATH) was enacted on December 18, 2015. PATH retroactively extended various temporary individual and business tax incentives for 2015 and in some instances extended certain incentives through 2019. Bonus tax depreciation, a favorable tax incentive for EOG, was extended from 2015 through 2019. |
Employee Benefit Plans
Employee Benefit Plans | 12 Months Ended |
Dec. 31, 2015 | |
Employee Benefit Plans [Abstract] | |
Employee Benefit Plans | Employee Benefit Plans Stock-Based Compensation During 2015 , EOG maintained various stock-based compensation plans as discussed below. EOG recognizes compensation expense on grants of stock options, SARs, restricted stock and restricted stock units, performance units and performance stock, and grants made under the EOG Resources, Inc. Employee Stock Purchase Plan (ESPP). Stock-based compensation expense is calculated based upon the grant date estimated fair value of the awards, net of forfeitures, based upon EOG's historical employee turnover rate. Compensation expense is amortized over the shorter of the vesting period or the period from date of grant until the date the employee becomes eligible to retire without company approval. Stock-based compensation expense is included on the Consolidated Statements of Income and Comprehensive Income based upon the job functions of the employees receiving the grants. Compensation expense related to EOG's stock-based compensation plans for the years ended December 31, 2015 , 2014 and 2013 was as follows (in millions): 2015 2014 2013 Lease and Well $ 44 $ 41 $ 35 Gathering and Processing Costs 1 1 1 Exploration Costs 26 27 27 General and Administrative 60 76 71 Total $ 131 $ 145 $ 134 The Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (2008 Plan) provides for grants of stock options, SARs, restricted stock and restricted stock units, performance stock and performance units, and other stock-based awards. At December 31, 2015 , approximately 24.7 million common shares remained available for grant under the 2008 Plan. EOG's policy is to issue shares related to the 2008 Plan from previously authorized unissued shares or treasury shares to the extent treasury shares are available. During 2015 , 2014 and 2013 , EOG issued shares in connection with stock option/SAR exercises, restricted stock grants, restricted stock unit releases and ESPP purchases. EOG recognized, as an adjustment to APIC, federal income tax benefits of $26 million , $99 million and $56 million for 2015 , 2014 and 2013 , 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 seven years . EOG's ESPP allows eligible employees to semi-annually purchase, through payroll deductions, shares of Common Stock at 85 percent of the fair market value at specified dates. Contributions to the ESPP are limited to 10 percent of the employee's pay (subject to certain ESPP limits) during each of the two six-month offering periods each year. The fair value of stock option grants and SAR grants is estimated using the Hull-White II binomial option pricing model. The fair value of ESPP grants is estimated using the Black-Scholes-Merton model. Stock-based compensation expense related to stock option, SAR and ESPP grants totaled $56 million , $62 million and $53 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Weighted average fair values and valuation assumptions used to value stock option, SAR and ESPP grants for the years ended December 31, 2015 , 2014 and 2013 were as follows: Stock Options/SARs ESPP 2015 2014 2013 2015 2014 2013 Weighted Average Fair Value of Grants $ 21.88 $ 30.75 $ 27.35 $ 21.21 $ 21.65 $ 15.06 Expected Volatility 38.03 % 35.28 % 35.86 % 32.08 % 25.03 % 29.89 % Risk-Free Interest Rate 0.83 % 0.95 % 0.78 % 0.12 % 0.08 % 0.11 % Dividend Yield 0.85 % 0.61 % 0.40 % 0.73 % 0.46 % 0.60 % Expected Life 5.3 years 5.2 years 5.5 years 0.5 years 0.5 years 0.5 years Expected volatility is based on an equal weighting of historical volatility and implied volatility from traded options in EOG's Common Stock. The risk-free interest rate is based upon United States Treasury yields in effect at the time of grant. The expected life is based upon historical experience and contractual terms of stock option, SAR and ESPP grants. The following table sets forth the stock option and SAR transactions for the years ended December 31, 2015 , 2014 and 2013 (stock options and SARs in thousands): 2015 2014 2013 Number Weighted Average Grant Price Number Weighted Average Grant Price Number Weighted Average Grant Price Outstanding at January 1 10,493 $ 64.96 10,452 $ 54.43 12,438 $ 42.91 Granted 2,037 69.99 2,146 101.55 2,268 83.70 Exercised (1) (1,518 ) 47.64 (1,718 ) 45.68 (4,046 ) 35.62 Forfeited (268 ) 80.31 (387 ) 68.95 (208 ) 50.78 Outstanding at December 31 10,744 67.98 10,493 64.96 10,452 54.43 Stock Options/SARs Exercisable at December 31 5,993 57.96 5,287 49.40 4,638 43.95 (1) The total intrinsic value of stock options/SARs exercised during the years 2015 , 2014 and 2013 was $60 million , $95 million and $151 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, 2015 , there were 10.4 million stock options/SARs vested or expected to vest with a weighted average grant price of $67.52 per share, an intrinsic value of $52 million and a weighted average remaining contractual life of 4.1 years . The following table summarizes certain information for the stock options and SARs outstanding and exercisable at December 31, 2015 (stock options and SARs in thousands): Stock Options/SARs Outstanding Stock Options/SARs Exercisable Range of Grant Prices Stock Weighted Average Remaining Life (Years) Weighted Average Grant Price Aggregate Intrinsic Value (1) Stock Weighted Average Remaining Life (Years) Weighted Average Grant Price Aggregate Intrinsic Value (1) $22.00 to $ 44.99 2,184 2 $ 41.08 2,182 2 $ 41.08 45.00 to 56.99 2,672 3 52.37 2,229 3 51.64 57.00 to 69.99 2,019 7 69.13 51 4 62.11 70.00 to 84.99 1,832 4 84.25 936 4 84.36 85.00 to 116.99 2,037 5 101.49 595 5 101.61 10,744 4 67.98 $ 117,424 5,993 3 57.96 $ 107,950 (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, 2015 , unrecognized compensation expense related to non-vested stock option and SAR grants totaled $100 million . This unrecognized expense will be amortized on a straight-line basis over a weighted average period of 2.8 years . At December 31, 2015 , approximately 568,000 shares of Common Stock remained available for issuance under the ESPP. The following table summarizes ESPP activities for the years ended December 31, 2015 , 2014 and 2013 (in thousands, except number of participants): 2015 2014 2013 Approximate Number of Participants 1,963 1,991 1,844 Shares Purchased 225 202 256 Aggregate Purchase Price $ 15,045 $ 14,927 $ 14,015 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 $69 million , $74 million and $72 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. The following table sets forth the restricted stock and restricted stock unit transactions for the years ended December 31, 2015 , 2014 and 2013 (shares and units in thousands): 2015 2014 2013 Number of Shares and Units Weighted Average Grant Date Fair Value Number of Shares and Units Weighted Average Grant Date Fair Value Number of Shares and Units Weighted Average Grant Date Fair Value Outstanding at January 1 5,394 $ 64.39 7,358 $ 49.54 7,636 $ 45.53 Granted 1,044 77.94 1,132 98.72 1,294 76.04 Released (1) (1,331 ) 51.52 (2,761 ) 105.24 (1,368 ) 52.39 Forfeited (199 ) 74.56 (335 ) 62.55 (204 ) 48.55 Outstanding at December 31 (2) 4,908 70.35 5,394 64.39 7,358 49.54 (1) The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2015 , 2014 and 2013 was $109 million , $291 million and $101 million , respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date restricted stock and restricted stock units are released. (2) The total intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2015 and 2014 was approximately $347 million and $497 million , respectively. At December 31, 2015 , unrecognized compensation expense related to restricted stock and restricted stock units totaled $156 million . Such unrecognized expense will be recognized on a straight-line basis over a weighted average period of 2.5 years . Performance Units and Performance Stock. EOG grants performance units and/or performance stock to its executive officers. As more fully discussed in the grant agreements, the performance metric applicable to these performance-based grants is EOG's total shareholder return over a three -year performance period relative to the total shareholder return of a designated group of peer companies. Upon the application of the performance multiple at the completion of the performance period, a minimum of zero and a maximum of 810,000 performance units/shares could be outstanding (based on the number of performance units/shares outstanding as of December 31, 2015 ). Subject to the termination provisions set forth in the grant agreements and the applicable performance multiple, the grants of performance units/shares 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 $5 million , $9 million and $9 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Weighted average fair values and valuation assumptions used to value performance unit and performance stock grants during the years ended December 31, 2015 , 2014 and 2013 were as follows: 2015 2014 2013 Weighted Average Fair Value of Grants $ 80.64 $ 119.27 $ 100.34 Expected Volatility 29.35 % 32.18 % 33.63 % Risk-Free Interest Rate 1.07 % 1.18 % 0.79 % 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, 2015 , 2014 and 2013 (units and shares in thousands): 2015 2014 2013 Number of Shares and Units Weighted Average Grant Date Fair Value Number of Shares and Units Weighted Average Grant Date Fair Value Number of Shares and Units Weighted Average Grant Date Fair Value Outstanding at January 1 333 $ 90.17 261 $ 82.18 142 $ 67.05 Granted 72 80.64 72 119.27 119 100.34 Outstanding at December 31 (1) 405 88.48 333 90.17 261 82.18 (1) The total intrinsic value of performance units and performance stock outstanding at December 31, 2015 and 2014 was $29 million and $31 million , respectively. At December 31, 2015 , 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 3.3 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 $36 million , $41 million and $37 million for 2015 , 2014 and 2013 , respectively. In addition, EOG's Trinidadian subsidiary maintains a contributory defined benefit pension plan and a matched savings plan. EOG's United Kingdom subsidiary maintains a pension plan which includes a non-contributory defined contribution pension plan and a matched defined contribution savings plan. These pension plans are available to most employees of the Trinidadian and United Kingdom subsidiaries. EOG's combined contributions to these plans were $1 million , $5 million and $4 million for 2015 , 2014 and 2013 , respectively. For the Trinidadian defined benefit pension plan, the benefit obligation, fair value of plan assets and accrued benefit cost totaled $9 million , $7 million and $0.2 million , respectively, at December 31, 2015 , and $14 million , $12 million and $1 million , respectively, at December 31, 2014 . In connection with the divestiture of substantially all of its Canadian assets in the fourth quarter of 2014, EOG has elected to terminate the Canadian non-contributory defined benefit pension plan. Postretirement Health Care. EOG has postretirement medical and dental benefits in place for eligible United States and Trinidad employees and their eligible dependents, the costs of which are not material. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Letters of Credit and Guarantees. At December 31, 2015 and 2014 , respectively, EOG had standby letters of credit and guarantees outstanding totaling approximately $272 million and $423 million , primarily representing guarantees of payment or performance obligations on behalf of subsidiaries. As of February 25, 2016, there were no demands for payment under these guarantees. Minimum Commitments. At December 31, 2015 , 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, 2015 , were as follows (in thousands): Total Minimum Commitments 2016 $ 1,275,650 2017 994,328 2018 781,299 2019 547,299 2020 431,221 2021 and beyond 900,961 $ 4,930,758 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 $ 229 million , $237 million and $191 million for 2015 , 2014 and 2013 , respectively. Contingencies. There are currently various suits and claims pending against EOG that have arisen in the ordinary course of EOG's business, including contract disputes, personal injury and property damage claims and title disputes. While the ultimate outcome and impact on EOG cannot be predicted, management believes that the resolution of these suits and claims will not, individually or in the aggregate, have a material adverse effect on EOG's consolidated financial position, results of operations or cash flow. EOG records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated. |
Net Income (Loss) Per Share
Net Income (Loss) Per Share | 12 Months Ended |
Dec. 31, 2015 | |
Earnings Per Share [Abstract] | |
Net Income (Loss) Per Share | Net Income (Loss) Per Share The following table sets forth the computation of Net Income (Loss) Per Share for the years ended December 31, 2015 , 2014 and 2013 (in thousands, except per share data): 2015 2014 2013 Numerator for Basic and Diluted Earnings per Share - Net Income (Loss) $ (4,524,515 ) $ 2,915,487 $ 2,197,109 Denominator for Basic Earnings per Share - Weighted Average Shares 545,697 543,443 540,341 Potential Dilutive Common Shares - Stock Options/SARs — 2,526 2,316 Restricted Stock/Units and Performance Units/Stock — 2,570 3,570 Denominator for Diluted Earnings per Share - Adjusted Diluted Weighted Average Shares 545,697 548,539 546,227 Net Income (Loss) Per Share Basic $ (8.29 ) $ 5.36 $ 4.07 Diluted $ (8.29 ) $ 5.32 $ 4.02 The diluted earnings per share calculation excludes stock options, SARs, restricted stock and units and performance units and stock that were anti-dilutive. Shares underlying the excluded stock options and SARs totaled 10.2 million , 0.7 million and 0.3 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. For the year ended December 31, 2015, 5.3 million shares of restricted stock and restricted stock units and performance units and performance stock were excluded. |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2014 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flow Information | Supplemental Cash Flow Information Net cash paid for interest and income taxes was as follows for the years ended December 31, 2015 , 2014 and 2013 (in thousands): 2015 2014 2013 Interest, Net of Capitalized Interest $ 222,088 $ 197,383 $ 235,854 Income Taxes, Net of Refunds Received $ 41,108 $ 342,741 $ 294,739 EOG's accrued capital expenditures at December 31, 2015 , 2014 and 2013 were $416 million , $972 million and $731 million , respectively. Non-cash investing activities for each of the years ended December 31, 2014 and 2013 included non-cash additions of $5 million to EOG's oil and gas properties as a result of property exchanges. |
Business Segment Information
Business Segment Information | 12 Months Ended |
Dec. 31, 2015 | |
Segment Reporting [Abstract] | |
Business Segment Information | Business Segment Information EOG's operations are all crude oil and natural gas exploration and production related. The Segment Reporting Topic of the ASC establishes standards for reporting information about operating segments in annual financial statements. Operating segments are defined as components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker, or decision-making group, in deciding how to allocate resources and in assessing performance. EOG's chief operating decision-making process is informal and involves the Chairman of the Board and Chief Executive Officer and other key officers. This group routinely reviews and makes operating decisions related to significant issues associated with each of EOG's major producing areas in the United States, Trinidad, the United Kingdom, China and Canada. For segment reporting purposes, the chief operating decision maker considers the major United States producing areas to be one operating segment. As previously reported, during the fourth quarter of 2014, EOG completed the sale of substantially all of its Canadian operations (see Note 17). As a result, information relating to EOG's remaining Canadian operations has been included in the Other International segment and prior year amounts have been reclassified to conform to current year presentation. Financial information by reportable segment is presented below as of and for the years ended December 31, 2015 , 2014 and 2013 (in thousands): United States Trinidad Other International (1) Total 2015 Crude Oil and Condensate $ 4,917,731 $ 13,122 $ 3,709 $ 4,934,562 Natural Gas Liquids 407,570 — 88 407,658 Natural Gas 637,452 368,639 54,947 1,061,038 Gains on Mark-to-Market Commodity Derivative Contracts 61,924 — — 61,924 Gathering, Processing and Marketing 2,254,477 (1,342 ) — 2,253,135 Gains (Losses) on Asset Dispositions, Net (12,176 ) 393 2,985 (8,798 ) Other, Net 47,464 (3 ) 448 47,909 Net Operating Revenues (2) 8,314,442 380,809 62,177 8,757,428 Depreciation, Depletion and Amortization 3,139,863 154,853 18,928 3,313,644 Operating Income (Loss) (6,566,282 ) 175,658 (295,455 ) (6,686,079 ) Interest Income 1,913 389 1,167 3,469 Other Income (Expense) 6,461 8,780 (16,794 ) (1,553 ) Net Interest Expense 274,606 1,400 (38,613 ) 237,393 Income (Loss) Before Income Taxes (6,832,514 ) 183,427 (272,469 ) (6,921,556 ) Income Tax Provision (Benefit) (2,463,213 ) 63,502 2,670 (2,397,041 ) Additions to Oil and Gas Properties, Excluding Dry Hole Costs 4,495,730 102,358 112,316 4,710,404 Total Property, Plant and Equipment, Net 23,593,995 350,766 265,960 24,210,721 Total Assets 25,351,908 886,826 736,510 26,975,244 United States Trinidad Other International (1) Total 2014 Crude Oil and Condensate $ 9,526,149 $ 29,604 $ 186,727 $ 9,742,480 Natural Gas Liquids 924,454 — 9,597 934,051 Natural Gas 1,321,175 483,071 112,140 1,916,386 Gains on Mark-to-Market Commodity Derivative Contracts 834,273 — — 834,273 Gathering, Processing and Marketing 4,040,024 6,064 228 4,046,316 Gains on Asset Dispositions, Net 96,339 — 411,251 507,590 Other, Net 49,950 37 4,257 54,244 Net Operating Revenues (3) 16,792,364 518,776 724,200 18,035,340 Depreciation, Depletion and Amortization 3,684,943 188,592 123,506 3,997,041 Operating Income (Loss) 5,074,911 277,471 (110,559 ) 5,241,823 Interest Income 849 253 1,137 2,239 Other Income (Expense) (14,953 ) 8,712 (41,048 ) (47,289 ) Net Interest Expense 269,166 — (67,708 ) 201,458 Income (Loss) Before Income Taxes 4,791,641 286,436 (82,762 ) 4,995,315 Income Tax Provision 1,837,185 98,559 144,084 2,079,828 Additions to Oil and Gas Properties, Excluding Dry Hole Costs 7,133,727 76,138 261,312 7,471,177 Total Property, Plant and Equipment, Net 28,391,741 382,719 398,184 29,172,644 Total Assets 32,871,398 865,674 1,025,615 34,762,687 2013 Crude Oil and Condensate $ 8,035,358 $ 40,379 $ 224,910 $ 8,300,647 Natural Gas Liquids 761,535 — 12,435 773,970 Natural Gas 1,100,808 477,103 103,118 1,681,029 Losses on Mark-to-Market Commodity Derivative Contracts (166,349 ) — — (166,349 ) Gathering, Processing and Marketing 3,636,209 6,064 1,476 3,643,749 Gains on Asset Dispositions, Net 93,876 1,119 102,570 197,565 Other, Net 51,713 24 4,770 56,507 Net Operating Revenues (4) 13,513,150 524,689 449,279 14,487,118 Depreciation, Depletion and Amortization 3,223,596 181,990 195,390 3,600,976 Operating Income (Loss) 3,543,841 266,329 (134,959 ) 3,675,211 Interest Income 2,803 336 2,446 5,585 Other Income (Expense) (29,696 ) 9,889 11,357 (8,450 ) Net Interest Expense 283,209 — (47,749 ) 235,460 Income (Loss) Before Income Taxes 3,233,739 276,554 (73,407 ) 3,436,886 Income Tax Provision (Benefit) 1,161,328 118,270 (39,821 ) 1,239,777 Additions to Oil and Gas Properties, Excluding Dry Hole Costs 6,133,894 132,984 355,558 6,622,436 Total Property, Plant and Equipment, Net 24,456,383 476,174 1,216,279 26,148,836 Total Assets 27,668,713 986,796 1,918,729 30,574,238 (1) Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. (2) EOG had sales activity with two significant purchasers in 2015 , one totaling $1.7 billion and the other totaling $1.4 billion of consolidated Net Operating Revenues in the United States segment. (3) EOG had sales activity with two significant purchasers in 2014 , one totaling $4.0 billion and the other totaling $3.0 billion of consolidated Net Operating Revenues in the United States segment. (4) 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. |
Risk Management Activities
Risk Management Activities | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Risk Management Activities | Risk Management Activities Commodity Price Risks. EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for crude oil and natural gas. EOG utilizes financial commodity derivative instruments, primarily price swap, option, swaption, collar and basis swap contracts, as a means to manage this price risk. During 2015 , 2014 and 2013 , 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 2015 , 2014 and 2013 , EOG recognized net gains (losses) on the mark-to-market of financial commodity derivative contracts of $62 million , $834 million and $(166) million , respectively, which included cash received from settlements of crude oil and natural gas derivative contracts of $730 million , $34 million and $116 million , respectively. At December 31, 2015, EOG had no outstanding crude oil or natural gas commodity derivative contracts. The following table sets forth the amounts and classification of EOG's outstanding derivative financial instruments at December 31, 2015 and 2014 , 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 2015 2014 Asset Derivatives Crude oil and natural gas derivative contracts - Current portion Assets from Price Risk Management Activities (1) $ — $ 465 Liability Derivatives Crude oil and natural gas derivative contracts - Current portion Liabilities from Price Risk Management Activities (2) $ — $ — (1) The current portion of Assets from Price Risk Management Activities consists of gross assets of $477 million , partially offset by gross liabilities of $12 million , at December 31, 2014 . (2) The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $12 million , offset by gross assets of $12 million , at December 31, 2014. Credit Risk. Notional contract amounts are used to express the magnitude of a financial derivative. The amounts potentially subject to credit risk, in the event of nonperformance by the counterparties, are equal to the fair value of such contracts (see Note 13). EOG evaluates its exposure to significant counterparties on an ongoing basis, including those arising from physical and financial transactions. In some instances, EOG renegotiates payment terms and/or requires collateral, parent guarantees or letters of credit to minimize credit risk. At December 31, 2015 , EOG's net accounts receivable balance related to United States, Canada and United Kingdom hydrocarbon sales included three receivable balances, each of which accounted for more than 10% of the total balance. The receivables were due from two petroleum refinery companies and one multinational oil and gas company. The related amounts were collected during early 2016. At December 31, 2014 , EOG's net accounts receivable balance related to United States, Canada, Argentina and United Kingdom hydrocarbon sales included two receivable balances, each of which accounted for more than 10% of the total balance. The receivables were due from two petroleum refinery companies. The related amounts were collected during early 2015. In 2015 and 2014 , all natural gas from EOG's Trinidad operations was sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary, and all natural gas from EOG's China operations was sold to Petrochina Company Limited. All of EOG's derivative instruments are covered by International Swap Dealers Association Master Agreements (ISDAs) with counterparties. The ISDAs may contain provisions that require EOG, if it is the party in a net liability position, to post collateral when the amount of the net liability exceeds the threshold level specified for EOG's then-current credit ratings. In addition, the ISDAs may also provide that as a result of certain circumstances, including certain events that cause EOG's credit ratings to become materially weaker than its then-current ratings, the counterparty may require all outstanding derivatives under the ISDA to be settled immediately. See Note 13 for the aggregate fair value of all derivative instruments that were in a net liability position at December 31, 2014 . EOG had no collateral posted and held no collateral at December 31, 2015 and had no collateral posted and held $278 million of collateral at December 31, 2014 . Substantially all of EOG's accounts receivable at December 31, 2015 and 2014 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, 2015 , credit losses incurred on receivables by EOG have been immaterial. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value Measurements Certain of EOG's financial and nonfinancial assets and liabilities are reported at fair value on the Consolidated Balance Sheets. An established fair value hierarchy prioritizes the relative reliability of inputs used in fair value measurements. The hierarchy gives highest priority to Level 1 inputs that represent unadjusted quoted market prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are directly or indirectly observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs and have the lowest priority in the hierarchy. EOG gives consideration to the credit risk of its counterparties, as well as its own credit risk, when measuring financial assets and liabilities at fair value. The following table provides fair value measurement information within the fair value hierarchy for certain of EOG's financial assets and liabilities carried at fair value on a recurring basis at December 31, 2014 . There were no such amounts outstanding at December 31, 2015. Amounts shown in millions. Fair Value Measurements Using: Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total At December 31, 2014 Financial Assets: Natural Gas Options/Swaptions $ — $ 100 $ — $ 100 Crude Oil Swaps — 121 — 121 Crude Oil Options/Swaptions — 244 — 244 The estimated fair value of crude oil and natural gas derivative contracts (including options/swaptions) was based upon forward commodity price curves based on quoted market prices. Commodity derivative contracts were valued by utilizing an independent third-party derivative valuation provider who uses various types of valuation models, as applicable. The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs and reserve lives. A reconciliation of EOG's asset retirement obligations is presented in Note 15. During 2015 , due to the decline in commodity prices, proved oil and gas properties, other property, plant and equipment and other assets with a carrying amount of $9,154 million were written down to their fair value of $2,828 million , resulting in pretax impairment charges of $6,326 million , $4,141 million net of tax. Impairments included domestic legacy natural gas assets and marginal liquids plays and the Conwy crude oil project in the East Irish Sea. During 2014 , proved oil and gas properties and other assets with a carrying amount of $968 million were written down to their fair value of $393 million , resulting in pretax impairment charges of $575 million . Included in the $575 million pretax impairment charges were $58 million of impairments of proved oil and gas properties and other assets for which EOG utilized accepted offers from third-party purchasers as the basis for determining fair value. Significant Level 3 inputs associated with the calculation of discounted cash flows used in the impairment analysis include EOG's estimate of future crude oil and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. Fair Value of Debt. At December 31, 2015 and 2014 , respectively, EOG had outstanding $6,390 million and $5,890 million aggregate principal amount of senior notes, which had estimated fair values of approximately $6,524 million and $6,242 million , respectively. The estimated fair value of debt was based upon quoted market prices and, where such prices were not available, other observable (Level 2) inputs regarding interest rates available to EOG at year-end. |
Accounting For Certain Long-Liv
Accounting For Certain Long-Lived Assets | 12 Months Ended |
Dec. 31, 2015 | |
Accounting For Certain Long-Lived Assets [Abstract] | |
Accounting For Certain Long-Lived Assets | Accounting for Certain Long-Lived Assets EOG reviews its proved oil and gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the asset. During 2015 , 2014 and 2013 , such reviews indicated that unamortized capitalized costs of certain properties were higher than their expected undiscounted future cash flows primarily due to lower commodity prices and, to a lesser extent, 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 $6,130 million , $171 million and $73 million in the United States during 2015 , 2014 and 2013 , respectively, and $196 million , $404 million and $85 million in Other International during 2015 , 2014 and 2013 , respectively. Additionally, EOG recorded pretax charges of $14 million in Trinidad during 2013. The pretax charges are included in Impairments on the Consolidated Statements of Income and Comprehensive Income. The carrying values for assets determined to be impaired were adjusted to estimated fair value using the Income Approach described in the Fair Value Measurement Topic of the ASC. In certain instances, EOG utilizes accepted bids as the basis for determining fair value. Amortization and impairments of unproved oil and gas property costs, including amortization of capitalized interest, were $288 million , $168 million and $115 million during 2015 , 2014 and 2013 , respectively. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligations, Noncurrent [Abstract] | |
Asset Retirement Obligations | Asset Retirement Obligations The following table presents the reconciliation of the beginning and ending aggregate carrying amounts of short-term and long-term legal obligations associated with the retirement of property, plant and equipment for the years ended December 31, 2015 and 2014 (in thousands): 2015 2014 Carrying Amount at Beginning of Period $ 752,718 $ 761,898 Liabilities Incurred 63,844 123,849 Liabilities Settled (1) (17,415 ) (247,422 ) Accretion 31,956 41,489 Revisions (13,356 ) 82,885 Foreign Currency Translations (6,193 ) (9,981 ) Carrying Amount at End of Period $ 811,554 $ 752,718 Current Portion $ 7,651 $ 11,814 Noncurrent Portion $ 803,903 $ 740,904 (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, 2015 | |
Capitalized Exploratory Well Costs [Abstract] | |
Exploratory Well Costs | Exploratory Well Costs EOG's net changes in capitalized exploratory well costs for the years ended December 31, 2015 , 2014 and 2013 are presented below (in thousands): 2015 2014 2013 Balance at January 1 $ 17,253 $ 9,211 $ 49,116 Additions Pending the Determination of Proved Reserves 24,640 32,080 52,099 Reclassifications to Proved Properties (26,659 ) (15,946 ) (54,505 ) Costs Charged to Expense (1) (6,279 ) (8,092 ) (35,859 ) Foreign Currency Translations — — (1,640 ) Balance at December 31 $ 8,955 $ 17,253 $ 9,211 (1) Includes capitalized exploratory well costs charged to either dry hole costs or impairments. At December 31, 2015 , 2014 and 2013 , all exploratory well costs had been capitalized for periods of less than one year. |
Acquisitions and Divestitures
Acquisitions and Divestitures | 12 Months Ended |
Dec. 31, 2015 | |
Business Combinations [Abstract] | |
Acquisitions and Divestitures | Acquisitions and Divestitures During 2015 , EOG completed acquisitions of approximately $481 million primarily to acquire proved crude oil properties and related assets in the Delaware Basin and gathering assets in the North Dakota Bakken. During 2015 , EOG received proceeds of approximately $193 million primarily from sales of gathering and processing assets and other assets. During 2014 , EOG received proceeds of approximately $569 million primarily from the divestiture of all its assets in Manitoba and the majority of its assets in Alberta (collectively, the Canadian Sales) and from sales of producing properties and acreage in the Upper Gulf Coast region, the Rocky Mountain area and the Mid-Continent area. The Canadian Sales that closed on or about December 1, 2014, occurred in two separate transactions, an asset sale and the sale of the stock of certain of EOG's Canadian subsidiaries. As these two transactions represented a substantially complete liquidation of EOG's Canadian operations, approximately $383 million of cumulative translation adjustments previously recorded on the Consolidated Balance Sheets was reclassified to the Consolidated Statements of Income and Comprehensive Income. The Canadian Sales also resulted in the release of approximately $150 million of restricted cash related to future abandonment liabilities. |
Oil and Gas Exploration and Pro
Oil and Gas Exploration and Production Industries Disclosures | 12 Months Ended |
Dec. 31, 2015 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Oil and Gas Exploration and Production Industries Disclosures | Oil and Gas Producing Activities The following disclosures are made in accordance with Financial Accounting Standards Board Accounting Standards Update No. 2010-03 "Oil and Gas Reserve Estimates and Disclosures" and the United States Securities and Exchange Commission's (SEC) final rule on "Modernization of Oil and Gas Reporting." During the fourth quarter of 2014, EOG completed the sale of substantially all of its Canadian operations. As a result, information relating to EOG's remaining Canadian operations has been included in the Other International segment and prior year amounts have been reclassified to conform to current year presentation. Oil and Gas Reserves. Users of this information should be aware that the process of estimating quantities of "proved," "proved developed" and "proved undeveloped" crude oil, natural gas liquids (NGLs) and natural gas reserves is complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. Although reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. See ITEM 1A, Risk Factors. Proved reserves represent estimated quantities of crude oil, NGLs and natural gas, which, by analysis of geoscience and engineering data, can be estimated, with reasonable certainty, to be economically producible from a given date forward from known reservoirs under then-existing economic conditions, operating methods and government regulations before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Proved developed reserves are proved reserves expected to be recovered under operating methods being utilized at the time the estimates were made, through wells and equipment in place or if the cost of any required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves (PUDs) are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. PUDs can be recorded in respect of a particular undrilled location only if the location is scheduled, under the then-current drilling and development plan, to be drilled within five years from the date that the PUDs are to be recorded, unless specific factors (such as those described in interpretative guidance issued by the Staff of the SEC) justify a longer timeframe. Likewise, absent any such specific factors, PUDs associated with a particular undeveloped drilling location shall be removed from the estimates of proved reserves if the location is scheduled, under the then-current drilling and development plan, to be drilled on a date that is beyond five years from the date that the PUDs were recorded. EOG has formulated development plans for all drilling locations associated with its PUDs at December 31, 2015 . Under these plans, each PUD location will be drilled within five years from the date it was recorded. Estimates for PUDs are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty. In making estimates of PUDs, EOG's technical staff, including engineers and geoscientists, perform detailed technical analysis of each potential drilling location within its inventory of prospects. In making a determination as to which of these locations would penetrate undrilled portions of the formation that can be judged, with reasonable certainty, to be continuous and contain economically producible crude oil and natural gas, studies are conducted using numerous data elements and analysis techniques. EOG's technical staff estimates the hydrocarbons in place, by mapping the entirety of the play in question using seismic techniques, typically employing two-dimensional and three-dimensional data. This analysis is integrated with other static data, including, but not limited to, core analysis, mechanical properties of the formation, thermal maturity indicators, and well logs of existing penetrations. Highly specialized equipment is utilized to prepare rock samples in assessing microstructures which contribute to porosity and permeability. Analysis of dynamic data is then incorporated to arrive at the estimated fractional recovery of hydrocarbons in place. Data analysis techniques employed include, but are not limited to, well testing analysis, static bottom hole pressure analysis, flowing bottom hole pressure analysis, analysis of historical production trends, pressure transient analysis and rate transient analysis. Application of proprietary rate transient analysis techniques in low permeability rocks allow for quantification of estimates of contribution to production from both fractures and rock matrix. The impact of optimal completion techniques is a key factor in determining if prospective locations are reasonably certain of being economically producible. EOG's technical staff estimates recovery improvement that might be achieved when completing horizontal wells with multi-stage fracture stimulation. In the early stages of development of a play, EOG determines the optimal length of the horizontal lateral and multi-stage fracture stimulation using the aforementioned analysis techniques along with pilot drilling programs and gathering of microseismic data. The process of analyzing static and dynamic data, well completion optimization and the results of early development activities provides the appropriate level of certainty as well as support for the economic producibility of the plays in which PUDs are reflected. EOG has found this approach to be effective based on successful application in analogous reservoirs in low permeability resource plays. Certain of EOG's Trinidad reserves are held under production sharing contracts where EOG's interest varies with prices and production volumes. Trinidad reserves, as presented on a net basis, assume prices in existence at the time the estimates were made and EOG's estimate of future production volumes. Future fluctuations in prices, production rates or changes in political or regulatory environments could cause EOG's share of future production from Trinidadian reserves to be materially different from that presented. Estimates of proved reserves at December 31, 2015 , 2014 and 2013 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 11 professionals, all of whom hold, at a minimum, bachelor's degrees in engineering, and five of whom are Registered Professional Engineers. The Vice President, Engineering and Acquisitions is the manager of this department and is the primary technical person responsible for this process. The Vice President, Engineering and Acquisitions holds a Bachelor of Science degree in Petroleum Engineering, has 30 years of experience in reserve evaluations and is a Registered Professional Engineer. EOG's reserves estimation process is a collaborative effort coordinated by the Engineering and Acquisitions Department in compliance with EOG's internal controls for such process. Reserve information as well as models used to estimate such reserves are stored on secured databases. Non-technical inputs used in reserve estimation models, including crude oil, NGL and natural gas prices, production costs, transportation costs, future capital expenditures and EOG's net ownership percentages are obtained from other departments within EOG. EOG's Internal Audit Department conducts testing with respect to such non-technical inputs. Additionally, EOG engages DeGolyer and MacNaughton (D&M), independent petroleum consultants, to perform independent reserves evaluation of select EOG properties comprising not less than 75% of EOG's estimates of proved reserves. EOG's Board of Directors requires that D&M's and EOG's reserve quantities for the properties evaluated by D&M vary by no more than 5% in the aggregate. Once completed, EOG's year-end reserves are presented to senior management, including the Chairman of the Board and Chief Executive Officer; the President and Chief Operating Officer; the Executive Vice Presidents, Exploration and Production; and the Vice President and Chief Financial Officer, for approval. Opinions by D&M for the years ended December 31, 2015 , 2014 and 2013 covered producing areas containing 86%, 76% and 82%, 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 February 1, 2016, 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, 2015 , is believed to have caused a material change in the estimates of net proved reserves as of that date. The following tables set forth EOG's net proved reserves at December 31 for each of the four years in the period ended December 31, 2015 , and the changes in the net proved reserves for each of the three years in the period ended December 31, 2015 , as estimated by the Engineering and Acquisitions Department of EOG: NET PROVED RESERVE SUMMARY United States Trinidad Other International (1) Total NET PROVED RESERVES Crude Oil (MBbl) (2) Net proved reserves at December 31, 2012 671,029 3,028 26,761 700,818 Revisions of previous estimates 57,668 (991 ) (6,008 ) 50,669 Purchases in place 1,097 — — 1,097 Extensions, discoveries and other additions 230,023 — 731 230,754 Sales in place (2,337 ) — — (2,337 ) Production (77,431 ) (447 ) (2,583 ) (80,461 ) Net proved reserves at December 31, 2013 880,049 1,590 18,901 900,540 Revisions of previous estimates 28,301 99 (378 ) 28,022 Purchases in place 9,705 — — 9,705 Extensions, discoveries and other additions 319,540 — 14 319,554 Sales in place (4,967 ) — (7,656 ) (12,623 ) Production (102,946 ) (350 ) (2,152 ) (105,448 ) Net proved reserves at December 31, 2014 1,129,682 1,339 8,729 1,139,750 Revisions of previous estimates (114,924 ) (1 ) — (114,925 ) Purchases in place 35,922 — — 35,922 Extensions, discoveries and other additions 141,310 63 13 141,386 Sales in place (730 ) — (10 ) (740 ) Production (103,400 ) (332 ) (65 ) (103,797 ) Net proved reserves at December 31, 2015 1,087,860 1,069 8,667 1,097,596 Natural Gas Liquids (MBbl) (2) Net proved reserves at December 31, 2012 318,406 — 1,557 319,963 Revisions of previous estimates 12,157 — (48 ) 12,109 Purchases in place 1,202 — — 1,202 Extensions, discoveries and other additions 69,187 — 10 69,197 Sales in place (1,471 ) — — (1,471 ) Production (23,479 ) — (315 ) (23,794 ) Net proved reserves at December 31, 2013 376,002 — 1,204 377,206 Revisions of previous estimates 27,450 — (7 ) 27,443 Purchases in place 1,812 — — 1,812 Extensions, discoveries and other additions 91,683 — — 91,683 Sales in place (956 ) — (823 ) (1,779 ) Production (29,061 ) — (236 ) (29,297 ) Net proved reserves at December 31, 2014 466,930 — 138 467,068 Revisions of previous estimates (113,290 ) — 68 (113,222 ) Purchases in place 8,251 — — 8,251 Extensions, discoveries and other additions 49,147 — — 49,147 Sales in place (84 ) — (187 ) (271 ) Production (28,079 ) — (19 ) (28,098 ) Net proved reserves at December 31, 2015 382,875 — — 382,875 United States Trinidad Other International (1) Total Natural Gas (Bcf) (3) Net proved reserves at December 31, 2012 4,036.0 588.2 115.3 4,739.5 Revisions of previous estimates 264.0 (17.4 ) 30.7 277.3 Purchases in place 5.7 — — 5.7 Extensions, discoveries and other additions 504.7 79.5 9.9 594.1 Sales in place (69.4 ) — — (69.4 ) Production (342.3 ) (129.6 ) (30.5 ) (502.4 ) Net proved reserves at December 31, 2013 4,398.7 520.7 125.4 5,044.8 Revisions of previous estimates 252.2 12.9 5.5 270.6 Purchases in place 17.1 — — 17.1 Extensions, discoveries and other additions 638.3 4.5 4.7 647.5 Sales in place (52.4 ) — (78.7 ) (131.1 ) Production (348.4 ) (132.5 ) (25.4 ) (506.3 ) Net proved reserves at December 31, 2014 4,905.5 405.6 31.5 5,342.6 Revisions of previous estimates (1,453.1 ) 16.8 5.6 (1,430.7 ) Purchases in place 72.3 — — 72.3 Extensions, discoveries and other additions 306.3 21.7 4.4 332.4 Sales in place (3.9 ) — (11.1 ) (15.0 ) Production (337.3 ) (127.5 ) (10.9 ) (475.7 ) Net proved reserves at December 31, 2015 3,489.8 316.6 19.5 3,825.9 Oil Equivalents (MBoe) (2) Net proved reserves at December 31, 2012 1,662,108 101,060 47,530 1,810,698 Revisions of previous estimates 113,823 (3,892 ) (941 ) 108,990 Purchases in place 3,241 — — 3,241 Extensions, discoveries and other additions 383,324 13,245 2,396 398,965 Sales in place (15,375 ) — — (15,375 ) Production (157,955 ) (22,049 ) (7,972 ) (187,976 ) Net proved reserves at December 31, 2013 1,989,166 88,364 41,013 2,118,543 Revisions of previous estimates 97,782 2,245 541 100,568 Purchases in place 14,367 — — 14,367 Extensions, discoveries and other additions 517,613 758 796 519,167 Sales in place (14,661 ) — (21,602 ) (36,263 ) Production (190,065 ) (22,430 ) (6,631 ) (219,126 ) Net proved reserves at December 31, 2014 2,414,202 68,937 14,117 2,497,256 Revisions of previous estimates (470,401 ) 2,802 995 (466,604 ) Purchases in place 56,215 — — 56,215 Extensions, discoveries and other additions 241,513 3,682 736 245,931 Sales in place (1,467 ) — (2,039 ) (3,506 ) Production (187,701 ) (21,578 ) (1,896 ) (211,175 ) Net proved reserves at December 31, 2015 2,052,361 53,843 11,913 2,118,117 (1) Other International includes EOG's United Kingdom, China, Canada 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 a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. (3) Billion cubic feet. During 2015, EOG added 246 million barrels of oil equivalent (MMBoe) of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin, the Rocky Mountain area and the Eagle Ford. Approximately 77% of the 2015 reserve additions were crude oil and condensate and NGLs, and 98% were in the United States. Sales in place of 4 MMBoe were primarily related to the disposition of certain producing natural gas assets in Canada, the Permian Basin and the Upper Gulf Coast. Negative revisions of previous estimates of 467 MMBoe for 2015 included a negative revision of 574 MMBoe primarily due to decreases in the average crude oil and natural gas prices used in the December 31, 2015, reserves estimation as compared to the prices used in the prior year estimate. The primary plays affected were the Uinta and Green River basins in the Rocky Mountain area, the Permian Basin and the Barnett Shale. Revisions other than price resulted primarily from improved recovery in the Eagle Ford. During 2014, EOG added 519 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Eagle Ford, Permian Basin and the Rocky Mountain area. Approximately 79% of the 2014 reserve additions were crude oil and condensate and NGLs, and nearly 100% were in the United States. Sales in place of 36 MMBoe were primarily related to the disposition of certain producing natural gas assets in Canada, the Upper Gulf Coast and other producing basins in the United States. Positive revisions of previous estimates of 101 MMBoe for 2014 included a positive revision of 52 MMBoe primarily due to an increase in the average natural gas price used in the December 31, 2014 reserves estimation as compared to the price used in the prior year estimate. The primary plays affected were the Barnett Shale, the Uinta and Green River basins in the Rocky Mountain area and the Haynesville Shale play. Revisions other than price resulted primarily from improved recovery in the Eagle Ford and improved recoveries and reduced operating costs in the Permian Basin. During 2013, EOG added 399 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Eagle Ford, Bakken, Permian Basin and Barnett Combo shale plays. Approximately 75% of the 2013 reserve additions were crude oil and condensate and 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. Positive revisions of previous estimates of 109 MMBoe for 2013 included a positive revision of 61 MMBoe primarily due to an increase in the average natural gas price used in the December 31, 2013 reserves estimation as compared to the price used in the prior year estimate. The primary plays affected were the Barnett Shale, the Uinta and Green River basins in the Rocky Mountain area and the Haynesville Shale play. Revisions other than price resulted primarily from improved recovery in the Eagle Ford. United States Trinidad Other International (1) Total NET PROVED DEVELOPED RESERVES Crude Oil (MBbl) December 31, 2012 281,167 2,377 7,106 290,650 December 31, 2013 382,517 1,505 7,034 391,056 December 31, 2014 493,694 1,339 115 495,148 December 31, 2015 444,070 1,069 63 445,202 Natural Gas Liquids (MBbl) December 31, 2012 161,482 — 1,111 162,593 December 31, 2013 199,964 — 896 200,860 December 31, 2014 264,611 — 138 264,749 December 31, 2015 205,898 — — 205,898 Natural Gas (Bcf) December 31, 2012 2,387.5 476.7 115.3 2,979.5 December 31, 2013 2,597.3 494.6 121.5 3,213.4 December 31, 2014 3,102.8 396.9 28.6 3,528.3 December 31, 2015 2,211.2 297.6 19.5 2,528.3 Oil Equivalents (MBoe) December 31, 2012 840,564 81,826 27,429 949,819 December 31, 2013 1,015,359 83,933 28,184 1,127,476 December 31, 2014 1,275,447 67,484 5,016 1,347,947 December 31, 2015 1,018,491 50,677 3,309 1,072,477 NET PROVED UNDEVELOPED RESERVES Crude Oil (MBbl) December 31, 2012 389,862 651 19,655 410,168 December 31, 2013 497,532 85 11,867 509,484 December 31, 2014 635,988 — 8,614 644,602 December 31, 2015 643,790 — 8,604 652,394 Natural Gas Liquids (MBbl) December 31, 2012 156,924 — 446 157,370 December 31, 2013 176,038 — 308 176,346 December 31, 2014 202,319 — — 202,319 December 31, 2015 176,977 — — 176,977 Natural Gas (Bcf) December 31, 2012 1,648.5 111.5 — 1,760.0 December 31, 2013 1,801.4 26.1 3.9 1,831.4 December 31, 2014 1,802.7 8.7 2.9 1,814.3 December 31, 2015 1,278.6 19.0 — 1,297.6 Oil Equivalents (MBoe) December 31, 2012 821,544 19,234 20,101 860,879 December 31, 2013 973,807 4,431 12,829 991,067 December 31, 2014 1,138,755 1,453 9,101 1,149,309 December 31, 2015 1,033,870 3,166 8,604 1,045,640 (1) Other International includes EOG's United Kingdom, China, Canada and Argentina operations. Net Proved Undeveloped Reserves. The following table presents the changes in EOG's total proved undeveloped reserves during 2015 , 2014 and 2013 (in MBoe): 2015 2014 2013 Balance at January 1 1,149,309 991,067 860,879 Extensions and Discoveries 205,152 403,713 291,345 Revisions (241,973 ) (79,630 ) (855 ) Acquisition of Reserves 54,458 4,239 — Sale of Reserves — (10,176 ) — Conversion to Proved Developed Reserves (121,306 ) (159,904 ) (160,302 ) Balance at December 31 1,045,640 1,149,309 991,067 For the twelve-month period ended December 31, 2015, total PUDs decreased by 104 MMBoe to 1,046 MMBoe. EOG added approximately 52 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion. Based on the technology employed by EOG to identify and record PUDs (see discussion of technology employed on pages F-30 and F-31 of this Annual Report on Form 10-K), EOG added 153 MMBoe. The PUD additions were primarily in the Permian Basin and, to a lesser extent, the Eagle Ford and the Rocky Mountain area, and 80% of the additions were crude oil and condensate and NGLs. During 2015, EOG drilled and transferred 121 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,349 million . Revisions of PUDs totaled negative 242 MMBoe, primarily due to decreases in the average crude oil and natural gas prices used in the December 31, 2015, reserves estimation as compared to the prices used in the prior year estimate. During 2015, EOG did not sell any PUDs and acquired 54 MMBoe of PUDs. For the twelve-month period ended December 31, 2014, total PUDs increased by 158 MMBoe to 1,149 MMBoe. EOG added approximately 50 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion. Based on the technology employed by EOG to identify and record PUDs, EOG added 354 MMBoe. The PUD additions were primarily in the Eagle Ford and Permian Basin, and 80% of the additions were crude oil and condensate and NGLs. During 2014, EOG drilled and transferred 160 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,655 million . Revisions of PUDs totaled negative 80 MMBoe, primarily due to removal of certain natural gas PUDs. During 2014, EOG sold 10 MMBoe and acquired 4 MMBoe of PUDs. For the twelve-month period ended December 31, 2013, total PUDs increased by 130 MMBoe to 991 MMBoe. EOG added approximately 28 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion. Based on the technology employed by EOG to identify and record PUDs, EOG added 263 MMBoe. The PUD additions were primarily in the Eagle Ford, Bakken and Permian Basin, 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. 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, 2015 and 2014 : 2015 2014 Proved properties $ 49,623,518 $ 45,169,101 Unproved properties 989,723 1,334,431 Total 50,613,241 46,503,532 Accumulated depreciation, depletion and amortization (28,877,593 ) (20,212,748 ) Net capitalized costs $ 21,735,648 $ 26,290,784 Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities. The acquisition, exploration and development costs disclosed in the following tables are in accordance with definitions in the Extractive Industries - Oil and Gas Topic of the Accounting Standards Codification (ASC). Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Exploration costs include additions to exploratory wells, including those in progress, and exploration expenses. Development costs include additions to production facilities and equipment and additions to development wells, including those in progress. The following table sets forth costs incurred related to EOG's oil and gas activities for the years ended December 31, 2015 , 2014 and 2013 : United States Trinidad Other International (1) Total 2015 Acquisition Costs of Properties Unproved $ 133,801 $ — $ 56 $ 133,857 Proved 480,617 — — 480,617 Subtotal 614,418 — 56 614,474 Exploration Costs 206,814 22,837 23,041 252,692 Development Costs (2) 3,847,813 102,715 110,589 4,061,117 Total $ 4,669,045 $ 125,552 $ 133,686 $ 4,928,283 2014 Acquisition Costs of Properties Unproved $ 365,915 $ — $ 4,499 $ 370,414 Proved 138,772 — 329 139,101 Subtotal 504,687 — 4,828 509,515 Exploration Costs 332,703 2,794 60,476 395,973 Development Costs (3) 6,638,192 89,555 271,534 6,999,281 Total $ 7,475,582 $ 92,349 $ 336,838 $ 7,904,769 2013 Acquisition Costs of Properties Unproved $ 411,556 $ — $ 2,565 $ 414,121 Proved 120,220 — (6 ) 120,214 Subtotal 531,776 — 2,559 534,335 Exploration Costs 273,788 16,060 87,331 377,179 Development Costs (4) 5,573,260 124,231 388,886 6,086,377 Total $ 6,378,824 $ 140,291 $ 478,776 $ 6,997,891 (1) Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. (2) Includes Asset Retirement Costs of $32 million , $15 million and $6 million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment. (3) Includes Asset Retirement Costs of $149 million , $14 million and $33 million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment. (4) Includes Asset Retirement Costs of $84 million and $50 million for the United States and Other International, respectively. Excludes other property, plant and equipment. Results of Operations for Oil and Gas Producing Activities (1) . The following table sets forth results of operations for oil and gas producing activities for the years ended December 31, 2015 , 2014 and 2013 : United States Trinidad Other International (2) Total 2015 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues $ 5,962,753 $ 381,761 $ 58,744 $ 6,403,258 Other 47,464 (3 ) 448 47,909 Total 6,010,217 381,758 59,192 6,451,167 Exploration Costs 139,753 2,071 7,670 149,494 Dry Hole Costs 956 5,635 8,155 14,746 Transportation Costs 838,428 1,290 9,601 849,319 Production Costs 1,486,189 28,862 66,080 1,581,131 Impairments 6,402,908 — 210,638 6,613,546 Depreciation, Depletion and Amortization 3,017,386 154,588 18,469 3,190,443 Income (Loss) Before Income Taxes (5,875,403 ) 189,312 (261,421 ) (5,947,512 ) Income Tax Provision (Benefit) (2,128,183 ) 43,739 (2,111 ) (2,086,555 ) Results of Operations $ (3,747,220 ) $ 145,573 $ (259,310 ) $ (3,860,957 ) 2014 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues $ 11,771,777 $ 512,675 $ 308,465 $ 12,592,917 Other 49,950 37 4,257 54,244 Total 11,821,727 512,712 312,722 12,647,161 Exploration Costs 162,434 2,185 19,769 184,388 Dry Hole Costs 25,408 — 23,082 48,490 Transportation Costs 957,522 617 14,037 972,176 Production Costs 1,940,074 38,301 171,652 2,150,027 Impairments 331,792 — 411,783 743,575 Depreciation, Depletion and Amortization 3,571,313 188,250 122,157 3,881,720 Income (Loss) Before Income Taxes 4,833,184 283,359 (449,758 ) 4,666,785 Income Tax Provision 1,722,914 74,588 23,602 1,821,104 Results of Operations $ 3,110,270 $ 208,771 $ (473,360 ) $ 2,845,681 2013 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues $ 9,897,701 $ 517,482 $ 340,463 $ 10,755,646 Other 51,713 24 4,770 56,507 Total 9,949,414 517,506 345,233 10,812,153 Exploration Costs 141,286 2,345 17,715 161,346 Dry Hole Costs 14,276 4,478 55,901 74,655 Transportation Costs 841,567 659 10,818 853,044 Production Costs 1,494,791 43,279 168,152 1,706,222 Impairments 178,718 14,274 93,949 286,941 Depreciation, Depletion and Amortization 3,122,858 181,637 193,515 3,498,010 Income (Loss) Before Income Taxes 4,155,918 270,834 (194,817 ) 4,231,935 Income Tax Provision (Benefit) 1,486,445 103,313 (99,226 ) 1,490,532 Results of Operations $ 2,669,473 $ 167,521 $ (95,591 ) $ 2,741,403 (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, 2015 . (2) Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. The following table sets forth production costs per barrel of oil equivalent, excluding severance/production and ad valorem taxes, for the years ended December 31, 2015 , 2014 and 2013 : United States Trinidad Other International (1) Composite Year Ended December 31, 2015 $ 5.81 $ 1.29 $ 33.78 $ 5.85 Year Ended December 31, 2014 $ 6.44 $ 1.34 $ 24.60 $ 6.46 Year Ended December 31, 2013 $ 5.78 $ 1.36 $ 20.40 $ 5.88 (1) Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves. The following information has been developed utilizing procedures prescribed by the Extractive Industries - Oil and Gas Topic of the ASC and based on crude oil, NGL and natural gas reserves and production volumes estimated by the Engineering and Acquisitions Department of EOG. The estimates were based on a 12-month average for commodity prices for the years 2015 , 2014 and 2013 . The following information may be useful for certain comparative purposes, but should not be solely relied upon in evaluating EOG or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of EOG. The future cash flows presented below are based on sales prices, cost rates and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil, NGL and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used. Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible reserves as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated. The following table sets forth the standardized measure of discounted future net cash flows from projected production of EOG's oil and gas reserves for the years ended December 31, 2015 , 2014 and 2013 : United States Trinidad Other International (1) Total 2015 Future cash inflows (2) $ 67,242,928 $ 954,779 $ 522,941 $ 68,720,648 Future production costs (31,707,743 ) (183,607 ) (169,505 ) (32,060,855 ) Future development costs (15,579,923 ) (140,541 ) (65,347 ) (15,785,811 ) Future income taxes (4,400,542 ) (215,659 ) — (4,616,201 ) Future net cash flows 15,554,720 414,972 288,089 16,257,781 Discount to present value at 10% annual rate (6,589,253 ) (33,848 ) (13,284 ) (6,636,385 ) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 8,965,467 $ 381,124 $ 274,805 $ 9,621,396 2014 Future cash inflows (3) $ 144,355,692 $ 1,615,280 $ 979,249 $ 146,950,221 Future production costs (51,112,604 ) (277 |
Unaudited Quarterly Financial I
Unaudited Quarterly Financial Information | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |
Unaudited Quarterly Financial Information | Unaudited Quarterly Financial Information (In Thousands, Except Per Share Data) Quarter Ended Mar 31 Jun 30 Sep 30 Dec 31 2015 Net Operating Revenues $ 2,318,538 $ 2,469,701 $ 2,172,428 $ 1,796,761 Operating Income (Loss) $ (172,995 ) $ 39,626 $ (6,222,957 ) $ (329,753 ) Income (Loss) Before Income Taxes $ (236,331 ) $ (11,478 ) $ (6,274,921 ) $ (398,826 ) Income Tax Benefit (66,583 ) (16,746 ) (2,199,182 ) (114,530 ) Net Income (Loss) $ (169,748 ) $ 5,268 $ (4,075,739 ) $ (284,296 ) Net Income (Loss) Per Share (1) Basic $ (0.31 ) $ 0.01 $ (7.47 ) $ (0.52 ) Diluted $ (0.31 ) $ 0.01 $ (7.47 ) $ (0.52 ) Average Number of Common Shares Basic 544,998 545,504 545,920 546,432 Diluted 544,998 549,683 545,920 546,432 2014 Net Operating Revenues $ 4,083,671 $ 4,187,556 $ 5,118,616 $ 4,645,497 Operating Income $ 1,084,279 $ 1,144,730 $ 1,786,162 $ 1,226,652 Income Before Income Taxes $ 1,030,789 $ 1,100,813 $ 1,715,120 $ 1,148,593 Income Tax Provision 369,861 394,460 611,502 704,005 Net Income $ 660,928 $ 706,353 $ 1,103,618 $ 444,588 Net Income Per Share (1) Basic $ 1.22 $ 1.30 $ 2.03 $ 0.82 Diluted $ 1.21 $ 1.29 $ 2.01 $ 0.81 Average Number of Common Shares Basic 542,278 543,099 543,984 544,579 Diluted 548,071 548,676 549,518 549,153 (1) The sum of quarterly net income (loss) per share may not agree with total year net income (loss) per share as each quarterly computation is based on the weighted average of common shares outstanding. |
Summary of Significant Accoun27
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Principles of Consolidation | Principles of Consolidation. The consolidated financial statements of EOG Resources, Inc. (EOG) include the accounts of all domestic and foreign subsidiaries. Investments in unconsolidated affiliates, in which EOG is able to exercise significant influence, are accounted for using the equity method. All intercompany accounts and transactions have been eliminated. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. |
Financial Instruments | Financial Instruments. EOG's financial instruments consist of cash and cash equivalents, commodity derivative contracts, accounts receivable, accounts payable and current and long-term debt. The carrying values of cash and cash equivalents, commodity derivative contracts, accounts receivable and accounts payable approximate fair value (see Notes 2 and 12). |
Cash and Cash Equivalents | Cash and Cash Equivalents. EOG records as cash equivalents all highly liquid short-term investments with original maturities of three months or less. |
Oil and Gas Operations | Oil and Gas Operations. EOG accounts for its crude oil and natural gas exploration and production activities under the successful efforts method of accounting. Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred. Oil and gas exploration costs, other than the costs of drilling exploratory wells, are expensed as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether EOG has discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made (see Note 16). Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account. Oil and gas properties are grouped in accordance with the Extractive Industries - Oil and Gas Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC). The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. Amortization rates are updated quarterly to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions and/or property dispositions and 4) impairments. When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the asset. If the expected undiscounted future cash flows, based on EOG's estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach described in the Fair Value Measurement Topic of the ASC. If applicable, EOG utilizes accepted bids as the basis for determining fair value. Inventories, consisting primarily of tubular goods, materials for completion operations and well equipment held for use in the exploration for, and development and production of, crude oil and natural gas reserves, are carried at cost with adjustments made, as appropriate, to recognize any reductions in value. Arrangements for sales of crude oil and condensate, natural gas liquids (NGLs) and natural gas are evidenced by signed contracts with determinable market prices, and revenues are recorded when production is delivered. A significant majority of these products are sold to purchasers who have investment-grade credit ratings and material credit losses have been rare. Revenues are recorded on the entitlement method based on EOG's percentage ownership of current production. Each working interest owner in a well generally has the right to a specific percentage of production, although actual production sold on that owner's behalf may differ from that owner's ownership percentage. Under entitlement accounting, a receivable is recorded when underproduction occurs and a payable is recorded when overproduction occurs. Gathering, processing and marketing revenues represent sales of third-party crude oil and condensate, NGLs and natural gas, as well as gathering fees associated with gathering third-party natural gas and revenues from sales of EOG-owned sand. |
Other Property, Plant and Equipment | Other Property, Plant and Equipment . Other property, plant and equipment consists of gathering and processing assets, compressors, buildings and leasehold improvements, crude-by-rail assets, sand mine and sand processing assets, computer hardware and software, vehicles, and furniture and fixtures. Other property, plant and equipment is generally depreciated on a straight-line basis over the estimated useful lives of the property, plant and equipment, which range from 3 years to 45 years. |
Capitalized Interest Costs | Capitalized Interest Costs. Interest costs have been capitalized as a part of the historical cost of unproved oil and gas properties. The amount capitalized is an allocation of the interest cost incurred during the reporting period. Capitalized interest is computed only during the exploration and development phases and ceases once production begins. The interest rate used for capitalization purposes is based on the interest rates on EOG's outstanding borrowings. |
Accounting for Risk Management Activities | Accounting for Risk Management Activities. Derivative instruments are recorded on the balance sheet as either an asset or liability measured at fair value, and changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met. During the three-year period ended December 31, 2015, EOG elected not to designate any of its financial commodity derivative instruments as accounting hedges and, accordingly, changes in the fair value of these outstanding derivative instruments are recognized as gains or losses in the period of change. The gains or losses are recorded as Gains (Losses) on Mark-to-Market Commodity Derivative Contracts on the Consolidated Statements of Income and Comprehensive Income. The related cash flow impact of settled contracts is reflected as cash flows from operating activities. EOG was party to a foreign currency swap transaction and an interest rate swap transaction, both of which were accounted for using the hedge accounting method. EOG employs net presentation of derivative assets and liabilities for financial reporting purposes when such assets and liabilities are with the same counterparty and subject to a master netting arrangement. See Note 12. |
Income Taxes | Income Taxes. Income taxes are accounted for using the asset and liability approach. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. EOG assesses the realizability of deferred tax assets and recognizes valuation allowances as appropriate (see Note 6). |
Foreign Currency Translation | Foreign Currency Translation. The United States dollar is the functional currency for all of EOG's consolidated subsidiaries except for its Canadian subsidiaries, for which the functional currency is the Canadian dollar, and its United Kingdom subsidiary, for which the functional currency is the British pound. For subsidiaries whose functional currency is deemed to be other than the United States dollar, asset and liability accounts are translated at year-end exchange rates and revenues and expenses are translated at average exchange rates prevailing during the year. Translation adjustments are included in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets. Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period. See Notes 4 and 17. |
Net Income (Loss) Per Share | Net Income (Loss) Per Share. Basic net income (loss) per share is computed on the basis of the weighted-average number of common shares outstanding during the period. Diluted net income (loss) per share is computed based upon the weighted-average number of common shares outstanding during the period plus the assumed issuance of common shares for all potentially dilutive securities (see Note 9). |
Stock-Based Compensation | Stock-Based Compensation . EOG measures the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (see Note 7). |
Recently Issued Accounting Standards and Developments | Recently Issued Accounting Standards. In November 2015, the FASB issued Accounting Standards Update (ASU) 2015-17, "Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes " (ASU 2015-17), which simplifies the presentation of deferred taxes in a classified balance sheet by eliminating the requirement to separate deferred income tax liabilities and assets into current and noncurrent amounts. Instead, ASU 2015-17 requires that all deferred tax liabilities and assets be shown as noncurrent in a classified balance sheet. ASU 2015-17 is effective for financial statements issued for interim and annual periods beginning after December 15, 2016, and early adoption is permitted. EOG does not intend to early-adopt ASU 2015-17 and does not expect the new standard to have a material impact on its consolidated financial statements and related disclosures. In July 2015, the FASB issued ASU 2015-11, "Accounting for Inventory" (ASU 2015-11), which requires entities to measure most inventory at lower of cost or net realizable value. ASU 2015-11 defines net realizable value as "the estimated selling prices in the ordinary course of business, less reasonably predictable cost of completion, disposal and transportation." ASU 2015-11 is effective prospectively for interim and annual periods beginning after December 15, 2016. EOG is reviewing the requirements of the new standard and does not believe that the adoption of ASU 2015-11 will have a material impact on its consolidated financial statements and related disclosures. In April 2015, the FASB issued ASU 2015-03, "Interest - Computation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs" (ASU 2015-03), which changes the presentation of debt issuance costs in financial statements. Under ASU 2015-03, an entity will present debt issuance costs in the balance sheet as a direct reduction from the related debt liability rather than as an asset. Amortization of such costs will be presented as a component of interest expense. ASU 2015-03 is effective for interim and annual reporting periods beginning after December 15, 2015. Early adoption is permitted. Because ASU 2015-03 does not address debt issuance costs related to line-of-credit arrangements, in August 2015, the FASB issued ASU 2015-15 "Interest - Computation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements" (ASU 2015-15). ASU 2015-15 provides that, in the absence of authoritative guidance in ASU 2015-03, the United States Securities and Exchange Commission would not object to an entity deferring and presenting debt issuance costs related to a line-of-credit arrangement as an asset and subsequently amortizing the deferred debt issuance costs over the term of the line-of-credit arrangement. EOG does not expect the adoption of ASU 2015-03 and ASU 2015-15 to have a material impact on its consolidated financial statements and related disclosures. In May 2014, the FASB issued ASU 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09), which will require entities to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will supersede most current guidance related to revenue recognition when it becomes effective. The new standard also will require expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. The FASB originally intended ASU 2014-09 to be effective for interim and annual reporting periods beginning after December 15, 2016, and permits adoption through the use of either the full retrospective approach or a modified retrospective approach. In July 2015, the FASB issued an update which delays by one year the effective date of ASU 2014-09 and allows for early adoption as of the original effective date. EOG does not intend to early-adopt ASU 2014-09 and has not determined which transition method it will use. EOG continues to analyze ASU 2014-09 to determine what impact the new standard will have on its consolidated financial statements and related disclosures. |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | Long-Term Debt at December 31, 2015 and 2014 consisted of the following (in thousands): 2015 2014 Commercial Paper $ 259,718 $ — 2.95% Senior Notes due 2015 — 500,000 2.500% Senior Notes due 2016 400,000 400,000 5.875% Senior Notes due 2017 600,000 600,000 6.875% Senior Notes due 2018 350,000 350,000 5.625% Senior Notes due 2019 900,000 900,000 4.40% Senior Notes due 2020 500,000 500,000 2.45% Senior Notes due 2020 500,000 500,000 4.100% Senior Notes due 2021 750,000 750,000 2.625% Senior Notes due 2023 1,250,000 1,250,000 3.15% Senior Notes due 2025 500,000 — 6.65% Senior Notes due 2028 140,000 140,000 3.90% Senior Notes due 2035 500,000 — Long-Term Debt 6,649,718 5,890,000 Capital Lease Obligation 45,064 51,221 Less: Current Portion of Long-Term Debt 6,579 6,579 Unamortized Debt Discount 34,518 31,288 Total Long-Term Debt $ 6,653,685 $ 5,903,354 |
Stockholder's Equity (Tables)
Stockholder's Equity (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Stockholders' Equity Note [Abstract] | |
Common stock activity | The following summarizes Common Stock activity for each of the years ended December 31, 2013 , 2014 and 2015 (in thousands): Common Shares Issued Treasury Outstanding Balance at December 31, 2012 543,916 (652 ) 543,264 Common Stock Issued Under Stock-Based Compensation Plans 2,206 — 2,206 Treasury Stock Purchased (1) — (854 ) (854 ) Common Stock Issued Under Employee Stock Purchase Plan 256 — 256 Treasury Stock Issued Under Stock-Based Compensation Plans — 1,300 1,300 Balance at December 31, 2013 546,378 (206 ) 546,172 Common Stock Issued Under Stock-Based Compensation Plans 2,448 — 2,448 Treasury Stock Purchased (1) — (1,209 ) (1,209 ) Common Stock Issued Under Employee Stock Purchase Plan 202 — 202 Treasury Stock Issued Under Stock-Based Compensation Plans — 682 682 Balance at December 31, 2014 549,028 (733 ) 548,295 Common Stock Issued Under Stock-Based Compensation Plans 1,019 — 1,019 Treasury Stock Purchased (1) — (581 ) (581 ) Common Stock Issued Under Employee Stock Purchase Plan 104 121 225 Treasury Stock Issued Under Stock-Based Compensation Plans — 901 901 Balance at December 31, 2015 550,151 (292 ) 549,859 (1) Represents shares that were withheld by, or returned to, EOG in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or SARs, the vesting of restricted stock or restricted stock unit grants or in payment of the exercise price of employee stock options. |
Accumulated Other Comprehensi30
Accumulated Other Comprehensive Income (Loss) Accumulated Other Comprehensive Income (Loss) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Accumulated Other Comprehensive Income [Abstract] | |
Accumulated Other Comprehensive Income (Loss) | The components of Accumulated Other Comprehensive Income (Loss) at December 31, 2015 and 2014 consisted of the following (in thousands): Foreign Currency Translation Adjustment Other Total December 31, 2013 $ 417,707 $ (1,873 ) $ 415,834 Other comprehensive loss before reclassifications (54,484 ) (918 ) (55,402 ) Amounts reclassified out of other comprehensive income (loss) (383,244 ) (1) 246 (2) (382,998 ) Tax effects — (490 ) (490 ) Other comprehensive income (loss) (437,728 ) (1,162 ) (438,890 ) December 31, 2014 (20,021 ) (3,035 ) (23,056 ) Other comprehensive loss before reclassifications (11,517 ) (129 ) (11,646 ) Amounts reclassified out of other comprehensive income (loss) — 1,572 (3) 1,572 Tax effects — (208 ) (208 ) Other comprehensive income (loss) (11,517 ) 1,235 (10,282 ) December 31, 2015 $ (31,538 ) $ (1,800 ) $ (33,338 ) (1) Reclassified to Net Income (Loss) - Gains (Losses) on Asset Dispositions, Net. See Note 17. (2) Includes $107 thousand reclassified to Net Income (Loss) - Interest Expense in connection with the settlement of a foreign currency swap and an interest rate swap and $139 thousand reclassified to Net Income (Loss) - General and Administrative related to certain EOG pension plans (see Note 7). (3) Reclassified to Net Income (Loss) - General and Administrative. Related to certain EOG pension plans. See Note 7. |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Deferred Income Tax Liabilities, Net | The principal components of EOG's net deferred income tax liabilities at December 31, 2015 and 2014 were as follows (in thousands): 2015 2014 Current Deferred Income Tax Assets (Liabilities) Deferred Compensation Plans $ 38,559 $ — Alternative Minimum Tax Credit Carryforward 93,316 — Foreign Net Operating Loss 47,786 49,865 Foreign Valuation Allowance (35,536 ) (30,247 ) Other 3,687 — Total Net Current Deferred Income Tax Assets $ 147,812 $ 19,618 Noncurrent Deferred Income Tax Assets (Liabilities) Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization $ (57,569 ) $ (141,643 ) Foreign Net Operating Loss 443,010 487,876 Foreign Valuation Allowances (380,104 ) (349,704 ) Foreign Other 1,506 4,096 Total Net Noncurrent Deferred Income Tax Assets $ 6,843 $ 625 Current Deferred Income Tax (Asset) Liabilities Commodity Hedging Contracts $ — $ 166,109 Deferred Compensation Plans — (48,207 ) Accrued Expenses and Liabilities — (5,643 ) Other — (1,516 ) Total Net Current Deferred Income Tax Liabilities $ — $ 110,743 Noncurrent Deferred Income Tax (Assets) Liabilities Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization $ 5,299,817 $ 7,634,297 Non-Producing Leasehold Costs (53,026 ) (44,236 ) Seismic Costs Capitalized for Tax (162,240 ) (158,157 ) Equity Awards (140,663 ) (127,541 ) Capitalized Interest 98,242 97,739 Alternative Minimum Tax Credit Carryforward (685,189 ) (793,126 ) Undistributed Foreign Earnings 258,403 249,861 Other (27,442 ) (35,891 ) Total Net Noncurrent Deferred Income Tax Liabilities $ 4,587,902 $ 6,822,946 Total Net Deferred Income Tax Liabilities $ 4,433,247 $ 6,913,446 |
Components of Income (Loss) Before Income Taxes | The components of Income (Loss) Before Income Taxes for the years indicated below were as follows (in thousands): 2015 2014 2013 United States $ (6,840,119 ) $ 5,161,232 $ 3,268,727 Foreign (81,437 ) (165,917 ) 168,159 Total $ (6,921,556 ) $ 4,995,315 $ 3,436,886 |
Components of Income Tax Provision (Benefit) | The principal components of EOG's Income Tax Provision (Benefit) for the years indicated below were as follows (in thousands): 2015 2014 2013 Current: Federal $ 21,719 $ 269,326 $ 207,777 State 9,404 22,835 22,856 Foreign 54,143 82,721 134,379 Total 85,266 374,882 365,012 Deferred: Federal (2,362,926 ) 1,608,706 915,994 State (127,444 ) 29,056 26,305 Foreign 8,063 67,184 (67,534 ) Total (2,482,307 ) 1,704,946 874,765 Income Tax Provision (Benefit) $ (2,397,041 ) $ 2,079,828 $ 1,239,777 |
Tax Rate Reconciliation | The differences between taxes computed at the United States federal statutory tax rate and EOG's effective rate were as follows: 2015 2014 2013 Statutory Federal Income Tax Rate 35.00 % 35.00 % 35.00 % State Income Tax, Net of Federal Benefit 1.11 0.68 0.93 Income Tax Provision Related to Foreign Operations (1.31 ) (0.12 ) 0.23 Canadian Divestiture — (3.46 ) — Undistributed Foreign Earnings — 4.94 — Foreign Valuation Allowances — 6.47 — Foreign Oil and Gas Impairments — (1.90 ) — Other (0.17 ) 0.03 (0.09 ) Effective Income Tax Rate 34.63 % 41.64 % 36.07 % |
Summary of Valuation Allowance | The principal components of EOG's rollforward of valuation allowances for deferred tax assets were as follows (in thousands): 2015 2014 2013 Beginning Balance $ 463,018 $ 223,599 $ 199,743 Increase (1) 146,602 392,729 43,422 Decrease (2) (4,315 ) (1,424 ) (4,967 ) Other (3) (99,178 ) (151,886 ) (14,599 ) Ending Balance $ 506,127 $ 463,018 $ 223,599 (1) Increase in valuation allowance related to the generation of tax net operating losses and other deferred tax assets. (2) Decrease in valuation allowance associated with adjustments to certain deferred tax assets and their related allowance. (3) Represents dispositions/revisions/foreign exchange rate variances and the effect of statutory income tax rate changes. |
Employee Benefit Plans (Tables)
Employee Benefit Plans (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 , 2014 and 2013 was as follows (in millions): 2015 2014 2013 Lease and Well $ 44 $ 41 $ 35 Gathering and Processing Costs 1 1 1 Exploration Costs 26 27 27 General and Administrative 60 76 71 Total $ 131 $ 145 $ 134 |
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, 2015 , 2014 and 2013 were as follows: Stock Options/SARs ESPP 2015 2014 2013 2015 2014 2013 Weighted Average Fair Value of Grants $ 21.88 $ 30.75 $ 27.35 $ 21.21 $ 21.65 $ 15.06 Expected Volatility 38.03 % 35.28 % 35.86 % 32.08 % 25.03 % 29.89 % Risk-Free Interest Rate 0.83 % 0.95 % 0.78 % 0.12 % 0.08 % 0.11 % Dividend Yield 0.85 % 0.61 % 0.40 % 0.73 % 0.46 % 0.60 % Expected Life 5.3 years 5.2 years 5.5 years 0.5 years 0.5 years 0.5 years |
Schedule of Share Based Compensation Arrangement By Share Based Payment Award | The following table sets forth the stock option and SAR transactions for the years ended December 31, 2015 , 2014 and 2013 (stock options and SARs in thousands): 2015 2014 2013 Number Weighted Average Grant Price Number Weighted Average Grant Price Number Weighted Average Grant Price Outstanding at January 1 10,493 $ 64.96 10,452 $ 54.43 12,438 $ 42.91 Granted 2,037 69.99 2,146 101.55 2,268 83.70 Exercised (1) (1,518 ) 47.64 (1,718 ) 45.68 (4,046 ) 35.62 Forfeited (268 ) 80.31 (387 ) 68.95 (208 ) 50.78 Outstanding at December 31 10,744 67.98 10,493 64.96 10,452 54.43 Stock Options/SARs Exercisable at December 31 5,993 57.96 5,287 49.40 4,638 43.95 (1) The total intrinsic value of stock options/SARs exercised during the years 2015 , 2014 and 2013 was $60 million , $95 million and $151 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, 2015 (stock options and SARs in thousands): Stock Options/SARs Outstanding Stock Options/SARs Exercisable Range of Grant Prices Stock Weighted Average Remaining Life (Years) Weighted Average Grant Price Aggregate Intrinsic Value (1) Stock Weighted Average Remaining Life (Years) Weighted Average Grant Price Aggregate Intrinsic Value (1) $22.00 to $ 44.99 2,184 2 $ 41.08 2,182 2 $ 41.08 45.00 to 56.99 2,672 3 52.37 2,229 3 51.64 57.00 to 69.99 2,019 7 69.13 51 4 62.11 70.00 to 84.99 1,832 4 84.25 936 4 84.36 85.00 to 116.99 2,037 5 101.49 595 5 101.61 10,744 4 67.98 $ 117,424 5,993 3 57.96 $ 107,950 (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, 2015 , approximately 568,000 shares of Common Stock remained available for issuance under the ESPP. The following table summarizes ESPP activities for the years ended December 31, 2015 , 2014 and 2013 (in thousands, except number of participants): 2015 2014 2013 Approximate Number of Participants 1,963 1,991 1,844 Shares Purchased 225 202 256 Aggregate Purchase Price $ 15,045 $ 14,927 $ 14,015 |
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, 2015 , 2014 and 2013 (shares and units in thousands): 2015 2014 2013 Number of Shares and Units Weighted Average Grant Date Fair Value Number of Shares and Units Weighted Average Grant Date Fair Value Number of Shares and Units Weighted Average Grant Date Fair Value Outstanding at January 1 5,394 $ 64.39 7,358 $ 49.54 7,636 $ 45.53 Granted 1,044 77.94 1,132 98.72 1,294 76.04 Released (1) (1,331 ) 51.52 (2,761 ) 105.24 (1,368 ) 52.39 Forfeited (199 ) 74.56 (335 ) 62.55 (204 ) 48.55 Outstanding at December 31 (2) 4,908 70.35 5,394 64.39 7,358 49.54 (1) The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2015 , 2014 and 2013 was $109 million , $291 million and $101 million , respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date restricted stock and restricted stock units are released. (2) The total intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2015 and 2014 was approximately $347 million and $497 million , respectively. |
Weighted Average Fair Values and Valuation Assumptions for Performance Units/Stocks | Weighted average fair values and valuation assumptions used to value performance unit and performance stock grants during the years ended December 31, 2015 , 2014 and 2013 were as follows: 2015 2014 2013 Weighted Average Fair Value of Grants $ 80.64 $ 119.27 $ 100.34 Expected Volatility 29.35 % 32.18 % 33.63 % Risk-Free Interest Rate 1.07 % 1.18 % 0.79 % |
Performance Unit and Performance Stock Transactions | The following table sets forth performance unit and performance stock transactions for the years ended December 31, 2015 , 2014 and 2013 (units and shares in thousands): 2015 2014 2013 Number of Shares and Units Weighted Average Grant Date Fair Value Number of Shares and Units Weighted Average Grant Date Fair Value Number of Shares and Units Weighted Average Grant Date Fair Value Outstanding at January 1 333 $ 90.17 261 $ 82.18 142 $ 67.05 Granted 72 80.64 72 119.27 119 100.34 Outstanding at December 31 (1) 405 88.48 333 90.17 261 82.18 (1) The total intrinsic value of performance units and performance stock outstanding at December 31, 2015 and 2014 was $29 million and $31 million , respectively. |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Minimum commitments for unrecorded unconditional purchase obligations | At December 31, 2015 , 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, 2015 , were as follows (in thousands): Total Minimum Commitments 2016 $ 1,275,650 2017 994,328 2018 781,299 2019 547,299 2020 431,221 2021 and beyond 900,961 $ 4,930,758 |
Net Income (Loss) Per Share (Ta
Net Income (Loss) Per Share (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Earnings Per Share [Abstract] | |
Computation of Net Income (Loss) Per Share | The following table sets forth the computation of Net Income (Loss) Per Share for the years ended December 31, 2015 , 2014 and 2013 (in thousands, except per share data): 2015 2014 2013 Numerator for Basic and Diluted Earnings per Share - Net Income (Loss) $ (4,524,515 ) $ 2,915,487 $ 2,197,109 Denominator for Basic Earnings per Share - Weighted Average Shares 545,697 543,443 540,341 Potential Dilutive Common Shares - Stock Options/SARs — 2,526 2,316 Restricted Stock/Units and Performance Units/Stock — 2,570 3,570 Denominator for Diluted Earnings per Share - Adjusted Diluted Weighted Average Shares 545,697 548,539 546,227 Net Income (Loss) Per Share Basic $ (8.29 ) $ 5.36 $ 4.07 Diluted $ (8.29 ) $ 5.32 $ 4.02 |
Supplemental Cash Flow Inform35
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 , 2014 and 2013 (in thousands): 2015 2014 2013 Interest, Net of Capitalized Interest $ 222,088 $ 197,383 $ 235,854 Income Taxes, Net of Refunds Received $ 41,108 $ 342,741 $ 294,739 |
Business Segment Information (T
Business Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Segment Reporting [Abstract] | |
Selected Financial Information by Reportable Segment | Financial information by reportable segment is presented below as of and for the years ended December 31, 2015 , 2014 and 2013 (in thousands): United States Trinidad Other International (1) Total 2015 Crude Oil and Condensate $ 4,917,731 $ 13,122 $ 3,709 $ 4,934,562 Natural Gas Liquids 407,570 — 88 407,658 Natural Gas 637,452 368,639 54,947 1,061,038 Gains on Mark-to-Market Commodity Derivative Contracts 61,924 — — 61,924 Gathering, Processing and Marketing 2,254,477 (1,342 ) — 2,253,135 Gains (Losses) on Asset Dispositions, Net (12,176 ) 393 2,985 (8,798 ) Other, Net 47,464 (3 ) 448 47,909 Net Operating Revenues (2) 8,314,442 380,809 62,177 8,757,428 Depreciation, Depletion and Amortization 3,139,863 154,853 18,928 3,313,644 Operating Income (Loss) (6,566,282 ) 175,658 (295,455 ) (6,686,079 ) Interest Income 1,913 389 1,167 3,469 Other Income (Expense) 6,461 8,780 (16,794 ) (1,553 ) Net Interest Expense 274,606 1,400 (38,613 ) 237,393 Income (Loss) Before Income Taxes (6,832,514 ) 183,427 (272,469 ) (6,921,556 ) Income Tax Provision (Benefit) (2,463,213 ) 63,502 2,670 (2,397,041 ) Additions to Oil and Gas Properties, Excluding Dry Hole Costs 4,495,730 102,358 112,316 4,710,404 Total Property, Plant and Equipment, Net 23,593,995 350,766 265,960 24,210,721 Total Assets 25,351,908 886,826 736,510 26,975,244 United States Trinidad Other International (1) Total 2014 Crude Oil and Condensate $ 9,526,149 $ 29,604 $ 186,727 $ 9,742,480 Natural Gas Liquids 924,454 — 9,597 934,051 Natural Gas 1,321,175 483,071 112,140 1,916,386 Gains on Mark-to-Market Commodity Derivative Contracts 834,273 — — 834,273 Gathering, Processing and Marketing 4,040,024 6,064 228 4,046,316 Gains on Asset Dispositions, Net 96,339 — 411,251 507,590 Other, Net 49,950 37 4,257 54,244 Net Operating Revenues (3) 16,792,364 518,776 724,200 18,035,340 Depreciation, Depletion and Amortization 3,684,943 188,592 123,506 3,997,041 Operating Income (Loss) 5,074,911 277,471 (110,559 ) 5,241,823 Interest Income 849 253 1,137 2,239 Other Income (Expense) (14,953 ) 8,712 (41,048 ) (47,289 ) Net Interest Expense 269,166 — (67,708 ) 201,458 Income (Loss) Before Income Taxes 4,791,641 286,436 (82,762 ) 4,995,315 Income Tax Provision 1,837,185 98,559 144,084 2,079,828 Additions to Oil and Gas Properties, Excluding Dry Hole Costs 7,133,727 76,138 261,312 7,471,177 Total Property, Plant and Equipment, Net 28,391,741 382,719 398,184 29,172,644 Total Assets 32,871,398 865,674 1,025,615 34,762,687 2013 Crude Oil and Condensate $ 8,035,358 $ 40,379 $ 224,910 $ 8,300,647 Natural Gas Liquids 761,535 — 12,435 773,970 Natural Gas 1,100,808 477,103 103,118 1,681,029 Losses on Mark-to-Market Commodity Derivative Contracts (166,349 ) — — (166,349 ) Gathering, Processing and Marketing 3,636,209 6,064 1,476 3,643,749 Gains on Asset Dispositions, Net 93,876 1,119 102,570 197,565 Other, Net 51,713 24 4,770 56,507 Net Operating Revenues (4) 13,513,150 524,689 449,279 14,487,118 Depreciation, Depletion and Amortization 3,223,596 181,990 195,390 3,600,976 Operating Income (Loss) 3,543,841 266,329 (134,959 ) 3,675,211 Interest Income 2,803 336 2,446 5,585 Other Income (Expense) (29,696 ) 9,889 11,357 (8,450 ) Net Interest Expense 283,209 — (47,749 ) 235,460 Income (Loss) Before Income Taxes 3,233,739 276,554 (73,407 ) 3,436,886 Income Tax Provision (Benefit) 1,161,328 118,270 (39,821 ) 1,239,777 Additions to Oil and Gas Properties, Excluding Dry Hole Costs 6,133,894 132,984 355,558 6,622,436 Total Property, Plant and Equipment, Net 24,456,383 476,174 1,216,279 26,148,836 Total Assets 27,668,713 986,796 1,918,729 30,574,238 (1) Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. (2) EOG had sales activity with two significant purchasers in 2015 , one totaling $1.7 billion and the other totaling $1.4 billion of consolidated Net Operating Revenues in the United States segment. (3) EOG had sales activity with two significant purchasers in 2014 , one totaling $4.0 billion and the other totaling $3.0 billion of consolidated Net Operating Revenues in the United States segment. (4) 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. |
Risk Management Activities (Tab
Risk Management Activities (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
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, 2015 and 2014 , 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 2015 2014 Asset Derivatives Crude oil and natural gas derivative contracts - Current portion Assets from Price Risk Management Activities (1) $ — $ 465 Liability Derivatives Crude oil and natural gas derivative contracts - Current portion Liabilities from Price Risk Management Activities (2) $ — $ — (1) The current portion of Assets from Price Risk Management Activities consists of gross assets of $477 million , partially offset by gross liabilities of $12 million , at December 31, 2014 . (2) The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $12 million , offset by gross assets of $12 million , at December 31, 2014. |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Fair Value Assets and Liabilities Measured On Recurring Basis | The following table provides fair value measurement information within the fair value hierarchy for certain of EOG's financial assets and liabilities carried at fair value on a recurring basis at December 31, 2014 . There were no such amounts outstanding at December 31, 2015. Amounts shown in millions. Fair Value Measurements Using: Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total At December 31, 2014 Financial Assets: Natural Gas Options/Swaptions $ — $ 100 $ — $ 100 Crude Oil Swaps — 121 — 121 Crude Oil Options/Swaptions — 244 — 244 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligations, Noncurrent [Abstract] | |
Asset Retirement Obligation Rollforward Analysis | The following table presents the reconciliation of the beginning and ending aggregate carrying amounts of short-term and long-term legal obligations associated with the retirement of property, plant and equipment for the years ended December 31, 2015 and 2014 (in thousands): 2015 2014 Carrying Amount at Beginning of Period $ 752,718 $ 761,898 Liabilities Incurred 63,844 123,849 Liabilities Settled (1) (17,415 ) (247,422 ) Accretion 31,956 41,489 Revisions (13,356 ) 82,885 Foreign Currency Translations (6,193 ) (9,981 ) Carrying Amount at End of Period $ 811,554 $ 752,718 Current Portion $ 7,651 $ 11,814 Noncurrent Portion $ 803,903 $ 740,904 (1) Includes settlements related to asset sales. |
Exploratory Well Costs (Tables)
Exploratory Well Costs (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Capitalized Exploratory Well Costs [Abstract] | |
Net Changes in Capitalized Exploratory Well Costs | EOG's net changes in capitalized exploratory well costs for the years ended December 31, 2015 , 2014 and 2013 are presented below (in thousands): 2015 2014 2013 Balance at January 1 $ 17,253 $ 9,211 $ 49,116 Additions Pending the Determination of Proved Reserves 24,640 32,080 52,099 Reclassifications to Proved Properties (26,659 ) (15,946 ) (54,505 ) Costs Charged to Expense (1) (6,279 ) (8,092 ) (35,859 ) Foreign Currency Translations — — (1,640 ) Balance at December 31 $ 8,955 $ 17,253 $ 9,211 (1) Includes capitalized exploratory well costs charged to either dry hole costs or impairments. |
Oil and Gas Exploration and P41
Oil and Gas Exploration and Production Industries Disclosures (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Net Proved and Proved Developed Oil and Gas Reserve Quantities | The following tables set forth EOG's net proved reserves at December 31 for each of the four years in the period ended December 31, 2015 , and the changes in the net proved reserves for each of the three years in the period ended December 31, 2015 , as estimated by the Engineering and Acquisitions Department of EOG: NET PROVED RESERVE SUMMARY United States Trinidad Other International (1) Total NET PROVED RESERVES Crude Oil (MBbl) (2) Net proved reserves at December 31, 2012 671,029 3,028 26,761 700,818 Revisions of previous estimates 57,668 (991 ) (6,008 ) 50,669 Purchases in place 1,097 — — 1,097 Extensions, discoveries and other additions 230,023 — 731 230,754 Sales in place (2,337 ) — — (2,337 ) Production (77,431 ) (447 ) (2,583 ) (80,461 ) Net proved reserves at December 31, 2013 880,049 1,590 18,901 900,540 Revisions of previous estimates 28,301 99 (378 ) 28,022 Purchases in place 9,705 — — 9,705 Extensions, discoveries and other additions 319,540 — 14 319,554 Sales in place (4,967 ) — (7,656 ) (12,623 ) Production (102,946 ) (350 ) (2,152 ) (105,448 ) Net proved reserves at December 31, 2014 1,129,682 1,339 8,729 1,139,750 Revisions of previous estimates (114,924 ) (1 ) — (114,925 ) Purchases in place 35,922 — — 35,922 Extensions, discoveries and other additions 141,310 63 13 141,386 Sales in place (730 ) — (10 ) (740 ) Production (103,400 ) (332 ) (65 ) (103,797 ) Net proved reserves at December 31, 2015 1,087,860 1,069 8,667 1,097,596 Natural Gas Liquids (MBbl) (2) Net proved reserves at December 31, 2012 318,406 — 1,557 319,963 Revisions of previous estimates 12,157 — (48 ) 12,109 Purchases in place 1,202 — — 1,202 Extensions, discoveries and other additions 69,187 — 10 69,197 Sales in place (1,471 ) — — (1,471 ) Production (23,479 ) — (315 ) (23,794 ) Net proved reserves at December 31, 2013 376,002 — 1,204 377,206 Revisions of previous estimates 27,450 — (7 ) 27,443 Purchases in place 1,812 — — 1,812 Extensions, discoveries and other additions 91,683 — — 91,683 Sales in place (956 ) — (823 ) (1,779 ) Production (29,061 ) — (236 ) (29,297 ) Net proved reserves at December 31, 2014 466,930 — 138 467,068 Revisions of previous estimates (113,290 ) — 68 (113,222 ) Purchases in place 8,251 — — 8,251 Extensions, discoveries and other additions 49,147 — — 49,147 Sales in place (84 ) — (187 ) (271 ) Production (28,079 ) — (19 ) (28,098 ) Net proved reserves at December 31, 2015 382,875 — — 382,875 United States Trinidad Other International (1) Total Natural Gas (Bcf) (3) Net proved reserves at December 31, 2012 4,036.0 588.2 115.3 4,739.5 Revisions of previous estimates 264.0 (17.4 ) 30.7 277.3 Purchases in place 5.7 — — 5.7 Extensions, discoveries and other additions 504.7 79.5 9.9 594.1 Sales in place (69.4 ) — — (69.4 ) Production (342.3 ) (129.6 ) (30.5 ) (502.4 ) Net proved reserves at December 31, 2013 4,398.7 520.7 125.4 5,044.8 Revisions of previous estimates 252.2 12.9 5.5 270.6 Purchases in place 17.1 — — 17.1 Extensions, discoveries and other additions 638.3 4.5 4.7 647.5 Sales in place (52.4 ) — (78.7 ) (131.1 ) Production (348.4 ) (132.5 ) (25.4 ) (506.3 ) Net proved reserves at December 31, 2014 4,905.5 405.6 31.5 5,342.6 Revisions of previous estimates (1,453.1 ) 16.8 5.6 (1,430.7 ) Purchases in place 72.3 — — 72.3 Extensions, discoveries and other additions 306.3 21.7 4.4 332.4 Sales in place (3.9 ) — (11.1 ) (15.0 ) Production (337.3 ) (127.5 ) (10.9 ) (475.7 ) Net proved reserves at December 31, 2015 3,489.8 316.6 19.5 3,825.9 Oil Equivalents (MBoe) (2) Net proved reserves at December 31, 2012 1,662,108 101,060 47,530 1,810,698 Revisions of previous estimates 113,823 (3,892 ) (941 ) 108,990 Purchases in place 3,241 — — 3,241 Extensions, discoveries and other additions 383,324 13,245 2,396 398,965 Sales in place (15,375 ) — — (15,375 ) Production (157,955 ) (22,049 ) (7,972 ) (187,976 ) Net proved reserves at December 31, 2013 1,989,166 88,364 41,013 2,118,543 Revisions of previous estimates 97,782 2,245 541 100,568 Purchases in place 14,367 — — 14,367 Extensions, discoveries and other additions 517,613 758 796 519,167 Sales in place (14,661 ) — (21,602 ) (36,263 ) Production (190,065 ) (22,430 ) (6,631 ) (219,126 ) Net proved reserves at December 31, 2014 2,414,202 68,937 14,117 2,497,256 Revisions of previous estimates (470,401 ) 2,802 995 (466,604 ) Purchases in place 56,215 — — 56,215 Extensions, discoveries and other additions 241,513 3,682 736 245,931 Sales in place (1,467 ) — (2,039 ) (3,506 ) Production (187,701 ) (21,578 ) (1,896 ) (211,175 ) Net proved reserves at December 31, 2015 2,052,361 53,843 11,913 2,118,117 (1) Other International includes EOG's United Kingdom, China, Canada 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 a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. (3) Billion cubic feet. |
Net Proved Developed and Net Proved Undeveloped Oil and Gas Reserve Quantities | United States Trinidad Other International (1) Total NET PROVED DEVELOPED RESERVES Crude Oil (MBbl) December 31, 2012 281,167 2,377 7,106 290,650 December 31, 2013 382,517 1,505 7,034 391,056 December 31, 2014 493,694 1,339 115 495,148 December 31, 2015 444,070 1,069 63 445,202 Natural Gas Liquids (MBbl) December 31, 2012 161,482 — 1,111 162,593 December 31, 2013 199,964 — 896 200,860 December 31, 2014 264,611 — 138 264,749 December 31, 2015 205,898 — — 205,898 Natural Gas (Bcf) December 31, 2012 2,387.5 476.7 115.3 2,979.5 December 31, 2013 2,597.3 494.6 121.5 3,213.4 December 31, 2014 3,102.8 396.9 28.6 3,528.3 December 31, 2015 2,211.2 297.6 19.5 2,528.3 Oil Equivalents (MBoe) December 31, 2012 840,564 81,826 27,429 949,819 December 31, 2013 1,015,359 83,933 28,184 1,127,476 December 31, 2014 1,275,447 67,484 5,016 1,347,947 December 31, 2015 1,018,491 50,677 3,309 1,072,477 NET PROVED UNDEVELOPED RESERVES Crude Oil (MBbl) December 31, 2012 389,862 651 19,655 410,168 December 31, 2013 497,532 85 11,867 509,484 December 31, 2014 635,988 — 8,614 644,602 December 31, 2015 643,790 — 8,604 652,394 Natural Gas Liquids (MBbl) December 31, 2012 156,924 — 446 157,370 December 31, 2013 176,038 — 308 176,346 December 31, 2014 202,319 — — 202,319 December 31, 2015 176,977 — — 176,977 Natural Gas (Bcf) December 31, 2012 1,648.5 111.5 — 1,760.0 December 31, 2013 1,801.4 26.1 3.9 1,831.4 December 31, 2014 1,802.7 8.7 2.9 1,814.3 December 31, 2015 1,278.6 19.0 — 1,297.6 Oil Equivalents (MBoe) December 31, 2012 821,544 19,234 20,101 860,879 December 31, 2013 973,807 4,431 12,829 991,067 December 31, 2014 1,138,755 1,453 9,101 1,149,309 December 31, 2015 1,033,870 3,166 8,604 1,045,640 (1) Other International includes EOG's United Kingdom, China, Canada and Argentina operations. |
Net Proved Undeveloped Reserves | The following table presents the changes in EOG's total proved undeveloped reserves during 2015 , 2014 and 2013 (in MBoe): 2015 2014 2013 Balance at January 1 1,149,309 991,067 860,879 Extensions and Discoveries 205,152 403,713 291,345 Revisions (241,973 ) (79,630 ) (855 ) Acquisition of Reserves 54,458 4,239 — Sale of Reserves — (10,176 ) — Conversion to Proved Developed Reserves (121,306 ) (159,904 ) (160,302 ) Balance at December 31 1,045,640 1,149,309 991,067 |
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, 2015 and 2014 : 2015 2014 Proved properties $ 49,623,518 $ 45,169,101 Unproved properties 989,723 1,334,431 Total 50,613,241 46,503,532 Accumulated depreciation, depletion and amortization (28,877,593 ) (20,212,748 ) Net capitalized costs $ 21,735,648 $ 26,290,784 |
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities | The following table sets forth costs incurred related to EOG's oil and gas activities for the years ended December 31, 2015 , 2014 and 2013 : United States Trinidad Other International (1) Total 2015 Acquisition Costs of Properties Unproved $ 133,801 $ — $ 56 $ 133,857 Proved 480,617 — — 480,617 Subtotal 614,418 — 56 614,474 Exploration Costs 206,814 22,837 23,041 252,692 Development Costs (2) 3,847,813 102,715 110,589 4,061,117 Total $ 4,669,045 $ 125,552 $ 133,686 $ 4,928,283 2014 Acquisition Costs of Properties Unproved $ 365,915 $ — $ 4,499 $ 370,414 Proved 138,772 — 329 139,101 Subtotal 504,687 — 4,828 509,515 Exploration Costs 332,703 2,794 60,476 395,973 Development Costs (3) 6,638,192 89,555 271,534 6,999,281 Total $ 7,475,582 $ 92,349 $ 336,838 $ 7,904,769 2013 Acquisition Costs of Properties Unproved $ 411,556 $ — $ 2,565 $ 414,121 Proved 120,220 — (6 ) 120,214 Subtotal 531,776 — 2,559 534,335 Exploration Costs 273,788 16,060 87,331 377,179 Development Costs (4) 5,573,260 124,231 388,886 6,086,377 Total $ 6,378,824 $ 140,291 $ 478,776 $ 6,997,891 (1) Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. (2) Includes Asset Retirement Costs of $32 million , $15 million and $6 million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment. (3) Includes Asset Retirement Costs of $149 million , $14 million and $33 million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment. (4) Includes Asset Retirement Costs of $84 million and $50 million for the United States and Other International, respectively. Excludes other property, plant and equipment. |
Results of Operations for Oil and Gas Producing Activities | Results of Operations for Oil and Gas Producing Activities (1) . The following table sets forth results of operations for oil and gas producing activities for the years ended December 31, 2015 , 2014 and 2013 : United States Trinidad Other International (2) Total 2015 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues $ 5,962,753 $ 381,761 $ 58,744 $ 6,403,258 Other 47,464 (3 ) 448 47,909 Total 6,010,217 381,758 59,192 6,451,167 Exploration Costs 139,753 2,071 7,670 149,494 Dry Hole Costs 956 5,635 8,155 14,746 Transportation Costs 838,428 1,290 9,601 849,319 Production Costs 1,486,189 28,862 66,080 1,581,131 Impairments 6,402,908 — 210,638 6,613,546 Depreciation, Depletion and Amortization 3,017,386 154,588 18,469 3,190,443 Income (Loss) Before Income Taxes (5,875,403 ) 189,312 (261,421 ) (5,947,512 ) Income Tax Provision (Benefit) (2,128,183 ) 43,739 (2,111 ) (2,086,555 ) Results of Operations $ (3,747,220 ) $ 145,573 $ (259,310 ) $ (3,860,957 ) 2014 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues $ 11,771,777 $ 512,675 $ 308,465 $ 12,592,917 Other 49,950 37 4,257 54,244 Total 11,821,727 512,712 312,722 12,647,161 Exploration Costs 162,434 2,185 19,769 184,388 Dry Hole Costs 25,408 — 23,082 48,490 Transportation Costs 957,522 617 14,037 972,176 Production Costs 1,940,074 38,301 171,652 2,150,027 Impairments 331,792 — 411,783 743,575 Depreciation, Depletion and Amortization 3,571,313 188,250 122,157 3,881,720 Income (Loss) Before Income Taxes 4,833,184 283,359 (449,758 ) 4,666,785 Income Tax Provision 1,722,914 74,588 23,602 1,821,104 Results of Operations $ 3,110,270 $ 208,771 $ (473,360 ) $ 2,845,681 2013 Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues $ 9,897,701 $ 517,482 $ 340,463 $ 10,755,646 Other 51,713 24 4,770 56,507 Total 9,949,414 517,506 345,233 10,812,153 Exploration Costs 141,286 2,345 17,715 161,346 Dry Hole Costs 14,276 4,478 55,901 74,655 Transportation Costs 841,567 659 10,818 853,044 Production Costs 1,494,791 43,279 168,152 1,706,222 Impairments 178,718 14,274 93,949 286,941 Depreciation, Depletion and Amortization 3,122,858 181,637 193,515 3,498,010 Income (Loss) Before Income Taxes 4,155,918 270,834 (194,817 ) 4,231,935 Income Tax Provision (Benefit) 1,486,445 103,313 (99,226 ) 1,490,532 Results of Operations $ 2,669,473 $ 167,521 $ (95,591 ) $ 2,741,403 (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, 2015 . (2) Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. |
Production Costs Per Barrel of Oil Equivalent | The following table sets forth production costs per barrel of oil equivalent, excluding severance/production and ad valorem taxes, for the years ended December 31, 2015 , 2014 and 2013 : United States Trinidad Other International (1) Composite Year Ended December 31, 2015 $ 5.81 $ 1.29 $ 33.78 $ 5.85 Year Ended December 31, 2014 $ 6.44 $ 1.34 $ 24.60 $ 6.46 Year Ended December 31, 2013 $ 5.78 $ 1.36 $ 20.40 $ 5.88 (1) Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Table | The following table sets forth the standardized measure of discounted future net cash flows from projected production of EOG's oil and gas reserves for the years ended December 31, 2015 , 2014 and 2013 : United States Trinidad Other International (1) Total 2015 Future cash inflows (2) $ 67,242,928 $ 954,779 $ 522,941 $ 68,720,648 Future production costs (31,707,743 ) (183,607 ) (169,505 ) (32,060,855 ) Future development costs (15,579,923 ) (140,541 ) (65,347 ) (15,785,811 ) Future income taxes (4,400,542 ) (215,659 ) — (4,616,201 ) Future net cash flows 15,554,720 414,972 288,089 16,257,781 Discount to present value at 10% annual rate (6,589,253 ) (33,848 ) (13,284 ) (6,636,385 ) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 8,965,467 $ 381,124 $ 274,805 $ 9,621,396 2014 Future cash inflows (3) $ 144,355,692 $ 1,615,280 $ 979,249 $ 146,950,221 Future production costs (51,112,604 ) (277,844 ) (242,845 ) (51,633,293 ) Future development costs (20,270,439 ) (84,576 ) (139,750 ) (20,494,765 ) Future income taxes (22,725,618 ) (460,096 ) — (23,185,714 ) Future net cash flows 50,247,031 792,764 596,654 51,636,449 Discount to present value at 10% annual rate (23,542,990 ) (110,228 ) (59,813 ) (23,713,031 ) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 26,704,041 $ 682,536 $ 536,841 $ 27,923,418 2013 Future cash inflows (4) $ 119,644,713 $ 2,082,195 $ 2,272,591 $ 123,999,499 Future production costs (49,099,393 ) (315,483 ) (751,612 ) (50,166,488 ) Future development costs (17,753,860 ) (112,050 ) (683,441 ) (18,549,351 ) Future income taxes (15,763,089 ) (603,786 ) (49,512 ) (16,416,387 ) Future net cash flows 37,028,371 1,050,876 788,026 38,867,273 Discount to present value at 10% annual rate (17,451,470 ) (174,236 ) 91,865 (17,533,841 ) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 19,576,901 $ 876,640 $ 879,891 $ 21,333,432 (1) Other International includes EOG's United Kingdom, China, Canada and Argentina operations. (2) Estimated crude oil prices used to calculate 2015 future cash inflows for the United States, Trinidad and Other International were $49.58 , $38.83 and $47.76 , respectively. Estimated NGL price used to calculate 2015 future cash inflows for the United States was $15.17 . Estimated natural gas prices used to calculate 2015 future cash inflows for the United States, Trinidad and Other International were $2.15 , $2.88 and $5.60 , respectively. (3) Estimated crude oil prices used to calculate 2014 future cash inflows for the United States, Trinidad and Other International were $97.51 , $80.60 and $94.09 , respectively. Estimated NGL prices used to calculate 2014 future cash inflows for the United States and Other International were $34.29 and $27.03 , respectively. Estimated natural gas prices used to calculate 2014 future cash inflows for the United States, Trinidad and Other International were $3.71 , $3.71 and $5.14 , respectively. (4) Estimated crude oil prices used to calculate 2013 future cash inflows for the United States, Trinidad and Other International were $105.91 , $94.30 and $98.85 , respectively. Estimated NGL prices used to calculate 2013 future cash inflows for the United States and Other International were $29.42 and $40.88 , respectively. Estimated natural gas prices used to calculate 2013 future cash inflows for the United States, Trinidad and Other International were $3.50 , $3.71 and $3.45 , respectively |
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves | Changes in Standardized Measure of Discounted Future Net Cash Flows. The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for each of the three years in the period ended December 31, 2015 : United States Trinidad Other International (1) Total December 31, 2012 $ 15,181,334 $ 961,070 $ 773,068 $ 16,915,472 Sales and transfers of oil and gas produced, net of production costs (7,561,343 ) (473,544 ) (161,493 ) (8,196,380 ) Net changes in prices and production costs 1,734,058 (12,050 ) (464,155 ) 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 67,100 96,400 2,955,900 Revisions of estimated development cost 892,803 (3,539 ) 101,132 990,396 Revisions of previous quantity estimates 1,887,062 (60,419 ) (32,445 ) 1,794,198 Accretion of discount 1,895,503 147,099 91,127 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 152,113 194,550 304,712 651,375 December 31, 2013 19,576,901 876,640 879,891 21,333,432 Sales and transfers of oil and gas produced, net of production costs (8,874,180 ) (473,757 ) (122,777 ) (9,470,714 ) Net changes in prices and production costs 1,481,668 (12,079 ) (206,412 ) 1,263,177 Extensions, discoveries, additions and improved recovery, net of related costs 8,074,550 3,113 6,189 8,083,852 Development costs incurred 2,818,800 12,800 3,500 2,835,100 Revisions of estimated development cost 1,696,916 9,981 95,838 1,802,735 Revisions of previous quantity estimates 1,741,918 35,001 35,613 1,812,532 Accretion of discount 2,612,286 133,019 88,045 2,833,350 Net change in income taxes (3,743,300 ) 91,438 562 (3,651,300 ) Purchases of reserves in place 317,785 — — 317,785 Sales of reserves in place (189,808 ) — (289,071 ) (478,879 ) Changes in timing and other 1,190,505 6,380 45,463 1,242,348 December 31, 2014 26,704,041 682,536 536,841 27,923,418 Sales and transfers of oil and gas produced, net of production costs (3,685,600 ) (351,606 ) 16,489 (4,020,717 ) Net changes in prices and production costs (29,993,699 ) (370,503 ) (305,148 ) (30,669,350 ) Extensions, discoveries, additions and improved recovery, net of related costs 1,028,410 47,613 19,875 1,095,898 Development costs incurred 2,135,800 500 1,400 2,137,700 Revisions of estimated development cost 4,087,093 (34,647 ) 26,935 4,079,381 Revisions of previous quantity estimates (4,084,572 ) 33,285 (587 ) (4,051,874 ) Accretion of discount 3,699,330 104,464 53,685 3,857,479 Net change in income taxes 9,550,847 177,576 — 9,728,423 Purchases of reserves in place 123,542 — — 123,542 Sales of reserves in place (23,424 ) — (13,664 ) (37,088 ) Changes in timing and other (576,301 ) 91,906 (61,021 ) (545,416 ) December 31, 2015 $ 8,965,467 $ 381,124 $ 274,805 $ 9,621,396 (1) Other International includes EOG's United Kingdom, China, Canada and Argentina operations. |
Unaudited Quarterly Financial42
Unaudited Quarterly Financial Information (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |
Unaudited Quarterly Financial Information | Unaudited Quarterly Financial Information (In Thousands, Except Per Share Data) Quarter Ended Mar 31 Jun 30 Sep 30 Dec 31 2015 Net Operating Revenues $ 2,318,538 $ 2,469,701 $ 2,172,428 $ 1,796,761 Operating Income (Loss) $ (172,995 ) $ 39,626 $ (6,222,957 ) $ (329,753 ) Income (Loss) Before Income Taxes $ (236,331 ) $ (11,478 ) $ (6,274,921 ) $ (398,826 ) Income Tax Benefit (66,583 ) (16,746 ) (2,199,182 ) (114,530 ) Net Income (Loss) $ (169,748 ) $ 5,268 $ (4,075,739 ) $ (284,296 ) Net Income (Loss) Per Share (1) Basic $ (0.31 ) $ 0.01 $ (7.47 ) $ (0.52 ) Diluted $ (0.31 ) $ 0.01 $ (7.47 ) $ (0.52 ) Average Number of Common Shares Basic 544,998 545,504 545,920 546,432 Diluted 544,998 549,683 545,920 546,432 2014 Net Operating Revenues $ 4,083,671 $ 4,187,556 $ 5,118,616 $ 4,645,497 Operating Income $ 1,084,279 $ 1,144,730 $ 1,786,162 $ 1,226,652 Income Before Income Taxes $ 1,030,789 $ 1,100,813 $ 1,715,120 $ 1,148,593 Income Tax Provision 369,861 394,460 611,502 704,005 Net Income $ 660,928 $ 706,353 $ 1,103,618 $ 444,588 Net Income Per Share (1) Basic $ 1.22 $ 1.30 $ 2.03 $ 0.82 Diluted $ 1.21 $ 1.29 $ 2.01 $ 0.81 Average Number of Common Shares Basic 542,278 543,099 543,984 544,579 Diluted 548,071 548,676 549,518 549,153 (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. |
Long-Term Debt (Details)
Long-Term Debt (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Debt Instrument Table [Line Items] | |||
Long-term Commercial Paper, Noncurrent | $ 259,718,000 | $ 0 | |
Long-Term Debt | 6,649,718,000 | 5,890,000,000 | |
Capital Lease Obligation | 45,064,000 | 51,221,000 | |
Less: Current Portion of Long-Term Debt | 6,579,000 | 6,579,000 | |
Unamortized Debt Discount | 34,518,000 | 31,288,000 | |
Total Long-Term Debt | 6,653,685,000 | 5,903,354,000 | |
Debt Instrument Issuance [Abstract] | |||
Long-Term Debt Repayments | 500,000,000 | 500,000,000 | $ 400,000,000 |
Long-Term Debt by Maturity [Abstract] | |||
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2016 | 400,000,000 | ||
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2017 | 600,000,000 | ||
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2018 | 350,000,000 | ||
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2019 | 900,000,000 | ||
Aggregate annual maturity of long-term debt (excluding capital lease obligations) in 2020 | $ 1,000,000,000 | ||
Revolving Credit Agreement 2011 | |||
Line of Credit Facility [Line Items] | |||
Line of Credit Facility, Expiration Date | Oct. 11, 2016 | ||
Maximum borrowing capacity | $ 2,000,000,000 | ||
Revolving Credit Agreement 2015 | |||
Line of Credit Facility [Line Items] | |||
Eurodollar rate at period end (in hundredths) | 1.33% | ||
Base rate at period end (in hundredths) | 3.50% | ||
Current Borrowings Outstanding | $ 0 | ||
Line of Credit Facility, Expiration Date | Jul. 21, 2020 | ||
Maximum borrowing capacity | $ 2,000,000,000 | ||
Maximum total debt-to-total capitalization ratio allowed under financial covenant (in hundredths) | 65.00% | ||
Letters of Credit Outstanding, Amount | $ 0 | ||
Uncommitted Credit Facilities | |||
Line of Credit Facility [Line Items] | |||
Average Borrowings Outstanding | 0 | $ 100,000 | |
Weighted average interest rate (in hundredths) | 0.70% | ||
Current Borrowings Outstanding | 0 | $ 0 | |
Commercial Paper | |||
Line of Credit Facility [Line Items] | |||
Average Borrowings Outstanding | $ 81,000,000 | $ 12,000,000 | |
Weighted average interest rate (in hundredths) | 0.51% | 0.25% | |
Current Borrowings Outstanding | $ 260,000,000 | $ 0 | |
5.10% Senior Notes Due 2036 | |||
Debt Instrument Issuance [Abstract] | |||
Debt Instrument Issuance Face Amount | $ 250,000,000 | ||
Debt Instrument Issuance Interest Rate | 5.10% | ||
4.15% Senior Notes Due 2026 | |||
Debt Instrument Issuance [Abstract] | |||
Debt Instrument Issuance Face Amount | $ 750,000,000 | ||
Debt Instrument Issuance Interest Rate | 4.15% | ||
2.625% Senior Notes due 2023 | |||
Debt Instrument Table [Line Items] | |||
Long-Term Debt | $ 1,250,000,000 | 1,250,000,000 | |
3.15% Senior Notes due 2025 | |||
Debt Instrument Table [Line Items] | |||
Long-Term Debt | 500,000,000 | 0 | |
Debt Instrument Issuance [Abstract] | |||
Debt Instrument Issuance Face Amount | $ 500,000,000 | ||
Debt Instrument Issuance Interest Rate | 3.15% | ||
3.90% Senior Notes due 2035 | |||
Debt Instrument Table [Line Items] | |||
Long-Term Debt | $ 500,000,000 | 0 | |
Debt Instrument Issuance [Abstract] | |||
Debt Instrument Issuance Face Amount | $ 500,000,000 | ||
Debt Instrument Issuance Interest Rate | 3.90% | ||
2.95% Senior Notes due 2015 | |||
Debt Instrument Table [Line Items] | |||
Long-Term Debt | $ 0 | 500,000,000 | |
Debt Instrument Issuance [Abstract] | |||
Debt Instrument Issuance Interest Rate | 2.95% | ||
Long-Term Debt Repayments | $ 500,000,000 | ||
2.500% Senior Notes due 2016 | |||
Debt Instrument Table [Line Items] | |||
Long-Term Debt | $ 400,000,000 | 400,000,000 | |
Debt Instrument Issuance [Abstract] | |||
Debt Instrument Issuance Interest Rate | 2.50% | ||
Long-Term Debt by Maturity [Abstract] | |||
Aggregate annual maturity of long-term debt in 2015 | $ 400,000,000 | ||
5.875% Senior Notes due 2017 | |||
Debt Instrument Table [Line Items] | |||
Long-Term Debt | 600,000,000 | 600,000,000 | |
6.875% Senior Notes due 2018 | |||
Debt Instrument Table [Line Items] | |||
Long-Term Debt | 350,000,000 | 350,000,000 | |
5.625% Senior Notes due 2019 | |||
Debt Instrument Table [Line Items] | |||
Long-Term Debt | 900,000,000 | 900,000,000 | |
4.40% Senior Notes due 2020 | |||
Debt Instrument Table [Line Items] | |||
Long-Term Debt | 500,000,000 | 500,000,000 | |
2.45% Senior Notes due 2020 | |||
Debt Instrument Table [Line Items] | |||
Long-Term Debt | 500,000,000 | 500,000,000 | |
4.100% Senior Notes due 2021 | |||
Debt Instrument Table [Line Items] | |||
Long-Term Debt | 750,000,000 | 750,000,000 | |
6.65% Senior Notes due 2028 | |||
Debt Instrument Table [Line Items] | |||
Long-Term Debt | 140,000,000 | $ 140,000,000 | |
the Notes | |||
Debt Instrument Issuance [Abstract] | |||
Net Proceeds From Issuance of Senior Long-Term Debt | 990,000,000 | ||
the New Notes | |||
Debt Instrument Issuance [Abstract] | |||
Net Proceeds From Issuance of Senior Long-Term Debt | $ 991,000,000 |
Stockholder's Equity (Details)
Stockholder's Equity (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Stockholders' Equity Note [Abstract] | ||||
Common Stock, Par (in dollars per share) | $ 0.01 | $ 0.01 | ||
An aggregate maximum of shares of common stock authorized for repurchase | 10,000,000 | |||
Remaining shares available for purchase under share repurchase authorization | 6,386,200 | |||
Dividends Common Stock Cash | $ 0.125 | $ 0.0938 | ||
Percentage increase of cash dividend on common stock paid on October 31, 2014 | 34.00% | |||
Percentage increase of cash dividend on common stock paid on April 30, 2014 | 33.00% | |||
Dividends Payable, Amount Per Share After Increase | $ 0.1675 | |||
Common Stock Activity [Line Items] | ||||
Balance (in shares) | 549,028,374 | |||
Balance (in shares) | 550,150,823 | 549,028,374 | ||
Preferred Stock, Shares Outstanding | 0 | |||
Common Shares, Outstanding [Member] | ||||
Common Stock Activity [Line Items] | ||||
Balance (in shares) | 548,295,000 | 546,172,000 | 543,264,000 | |
Common Stock Issued Under Equity Compensation Plans (in shares) | 1,019,000 | 2,448,000 | 2,206,000 | |
Treasury Stock Purchased (in shares) | [1] | (581,000) | (1,209,000) | (854,000) |
Common Stock Issued Under Employee Stock Purchase Plan (in shares) | 225,000 | 202,000 | 256,000 | |
Treasury Stock Issued Under Equity Compensation Plans (in shares) | 901,000 | 682,000 | 1,300,000 | |
Balance (in shares) | 549,859,000 | 548,295,000 | 546,172,000 | |
Common Shares, Treasury [Member] | ||||
Common Stock Activity [Line Items] | ||||
Balance (in shares) | (733,000) | (206,000) | (652,000) | |
Common Stock Issued Under Equity Compensation Plans (in shares) | 0 | 0 | 0 | |
Treasury Stock Purchased (in shares) | [1] | (581,000) | (1,209,000) | (854,000) |
Common Stock Issued Under Employee Stock Purchase Plan (in shares) | 121,000 | 0 | 0 | |
Treasury Stock Issued Under Equity Compensation Plans (in shares) | 901,000 | 682,000 | 1,300,000 | |
Balance (in shares) | (292,000) | (733,000) | (206,000) | |
Common Shares, Issued [Member] | ||||
Common Stock Activity [Line Items] | ||||
Balance (in shares) | 549,028,000 | 546,378,000 | 543,916,000 | |
Common Stock Issued Under Equity Compensation Plans (in shares) | 1,019,000 | 2,448,000 | 2,206,000 | |
Treasury Stock Purchased (in shares) | [1] | 0 | 0 | 0 |
Common Stock Issued Under Employee Stock Purchase Plan (in shares) | 104,000 | 202,000 | 256,000 | |
Treasury Stock Issued Under Equity Compensation Plans (in shares) | 0 | 0 | 0 | |
Balance (in shares) | 550,151,000 | 549,028,000 | 546,378,000 | |
[1] | Represents shares that were withheld by, or returned to, EOG in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or SARs, the vesting of restricted stock or restricted stock unit grants or in payment of the exercise price of employee stock options. |
Accumulated Other Comprehensi45
Accumulated Other Comprehensive Income (Loss) Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Other Comprehensive Income (Loss) | $ (10,282,000) | $ (438,890,000) | $ (24,061,000) | |
Accumulated Other Comprehensive Income (Loss) | (33,338,000) | (23,056,000) | ||
Significant amounts reclassified out of AOCI | 0 | |||
Foreign Currency Translation Adjustment [Member] | ||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Accumulated Other Comprehensive Income (Loss), before Tax | (20,021,000) | 417,707,000 | ||
Other Comprehensive Loss, before Reclassifications, before Tax | (11,517,000) | (54,484,000) | ||
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax | [1] | 0 | (383,244,000) | |
Tax Effects | 0 | 0 | ||
Other Comprehensive Income (Loss) | (11,517,000) | (437,728,000) | ||
Accumulated Other Comprehensive Income (Loss) | (31,538,000) | |||
Other [Member] | ||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Accumulated Other Comprehensive Income (Loss), before Tax | (3,035,000) | (1,873,000) | ||
Other Comprehensive Loss, before Reclassifications, before Tax | (129,000) | (918,000) | ||
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax | [2] | 1,572,000 | 246,000 | |
Tax Effects | (208,000) | (490,000) | ||
Other Comprehensive Income (Loss) | 1,235,000 | (1,162,000) | ||
Accumulated Other Comprehensive Income (Loss) | (1,800,000) | |||
Accumulated Other Comprehensive Income (Loss) [Member] | ||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Accumulated Other Comprehensive Income (Loss), before Tax | (23,056,000) | 415,834,000 | ||
Other Comprehensive Loss, before Reclassifications, before Tax | (11,646,000) | (55,402,000) | ||
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax | 1,572,000 | (382,998,000) | ||
Tax Effects | (208,000) | (490,000) | ||
Other Comprehensive Income (Loss) | (10,282,000) | $ (438,890,000) | $ (24,061,000) | |
Accumulated Other Comprehensive Income (Loss) | $ (33,338,000) | |||
[1] | Reclassified to Net Income (Loss) - Gains (Losses) on Asset Dispositions, Net. See Note 17. | |||
[2] | Related to certain EOG pension plans. See Note 7. |
Other Income (Expense), Net (De
Other Income (Expense), Net (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Other Income and Expenses [Abstract] | |||
Equity income from investments in Trinidad | $ 9 | $ 8 | $ 11 |
Adjustment to deferred compensation expense | 6 | ||
Interest income | 3 | 6 | |
Net Foreign Currency Transaction Gains (Losses) | $ (17) | (34) | 12 |
Losses on sales of warehouse stock | $ 15 | $ 23 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Deferred Tax Assets, Net of Valuation Allowance, Current Classification [Abstract] | |||||||||||
Deferred Compensation Plans | $ 38,559,000 | $ 0 | $ 38,559,000 | $ 0 | |||||||
Alternative Minimum Tax Credit Carryforward | 93,316,000 | 0 | 93,316,000 | 0 | |||||||
Foreign Net Operating Loss | 47,786,000 | 49,865,000 | 47,786,000 | 49,865,000 | |||||||
Foreign Valuation Allowance | (35,536,000) | (30,247,000) | (35,536,000) | (30,247,000) | |||||||
Other | 3,687,000 | 0 | 3,687,000 | 0 | |||||||
Total Net Current Deferred Income Tax Assets | 147,812,000 | 19,618,000 | 147,812,000 | 19,618,000 | |||||||
Deferred tax assets net noncurrent classification [Abstract] | |||||||||||
Foreign Oil and Gas Exploration and Development Costs Deducted for Tax Under Book Depreciation, Depletion and Amortization | (57,569,000) | (141,643,000) | (57,569,000) | (141,643,000) | |||||||
Foreign Net Operating Loss | 443,010,000 | 487,876,000 | 443,010,000 | 487,876,000 | |||||||
Foreign Valuation Allowances | (380,104,000) | (349,704,000) | (380,104,000) | (349,704,000) | |||||||
Foreign Other | 1,506,000 | 4,096,000 | 1,506,000 | 4,096,000 | |||||||
Total Net Noncurrent Deferred Income Tax Assets | 6,843,000 | 625,000 | 6,843,000 | 625,000 | |||||||
Deferred tax liabilities net current classification [Abstract] | |||||||||||
Commodity Hedging Contracts | 0 | 166,109,000 | 0 | 166,109,000 | |||||||
Deferred Compensation Plans | 0 | (48,207,000) | 0 | (48,207,000) | |||||||
Accrued Expenses and Liabilities | 0 | (5,643,000) | 0 | (5,643,000) | |||||||
Other | 0 | (1,516,000) | 0 | (1,516,000) | |||||||
Total Net Current Deferred Income Tax Liabilities | 0 | 110,743,000 | 0 | 110,743,000 | |||||||
Deferred tax liabilities net noncurrent classification [Abstract] | |||||||||||
Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization | 5,299,817,000 | 7,634,297,000 | 5,299,817,000 | 7,634,297,000 | |||||||
Non-Producing Leasehold Costs | (53,026,000) | (44,236,000) | (53,026,000) | (44,236,000) | |||||||
Seismic Costs Capitalized for Tax | (162,240,000) | (158,157,000) | (162,240,000) | (158,157,000) | |||||||
Equity Awards | (140,663,000) | (127,541,000) | (140,663,000) | (127,541,000) | |||||||
Capitalized Interest | 98,242,000 | 97,739,000 | 98,242,000 | 97,739,000 | |||||||
Alternative Minimum Tax Credit Carryforward | (685,189,000) | (793,126,000) | (685,189,000) | (793,126,000) | |||||||
Undistributed Foreign Earnings | 258,403,000 | 249,861,000 | 258,403,000 | 249,861,000 | |||||||
Other | (27,442,000) | (35,891,000) | (27,442,000) | (35,891,000) | |||||||
Total Net Noncurrent Deferred Income Tax Liabilities | 4,587,902,000 | 6,822,946,000 | 4,587,902,000 | 6,822,946,000 | |||||||
Total Net Deferred Income Tax Liabilities | 4,433,247,000 | 6,913,446,000 | 4,433,247,000 | 6,913,446,000 | |||||||
Income Before Income Taxes [Abstract] | |||||||||||
United States | (6,840,119,000) | 5,161,232,000 | $ 3,268,727,000 | ||||||||
Foreign | (81,437,000) | (165,917,000) | 168,159,000 | ||||||||
Income (Loss) Before Income Taxes | (398,826,000) | $ (6,274,921,000) | $ (11,478,000) | $ (236,331,000) | 1,148,593,000 | $ 1,715,120,000 | $ 1,100,813,000 | $ 1,030,789,000 | (6,921,556,000) | 4,995,315,000 | 3,436,886,000 |
Current income tax provision [Abstract] | |||||||||||
Federal | 21,719,000 | 269,326,000 | 207,777,000 | ||||||||
State | 9,404,000 | 22,835,000 | 22,856,000 | ||||||||
Foreign | 54,143,000 | 82,721,000 | 134,379,000 | ||||||||
Total | 85,266,000 | 374,882,000 | 365,012,000 | ||||||||
Deferred income tax provision [Abstract] | |||||||||||
Federal | (2,362,926,000) | 1,608,706,000 | 915,994,000 | ||||||||
State | (127,444,000) | 29,056,000 | 26,305,000 | ||||||||
Foreign | 8,063,000 | 67,184,000 | (67,534,000) | ||||||||
Total | (2,482,307,000) | 1,704,946,000 | 874,765,000 | ||||||||
Income Tax Provision | $ (2,397,041,000) | $ 2,079,828,000 | $ 1,239,777,000 | ||||||||
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) | 1.11% | 0.68% | 0.93% | ||||||||
Income Tax Provision Related to Foreign Operations (in hundredths) | (1.31%) | (0.12%) | 0.23% | ||||||||
Canadian Divestiture (in hundredths) | 0.00% | (3.46%) | 0.00% | ||||||||
Undistributed Foreign Earnings (in hundredths) | 0.00% | 4.94% | 0.00% | ||||||||
Foreign Valuation Allowances (in hundredths) | 0.00% | 6.47% | 0.00% | ||||||||
Foreign Oil and Gas Impairments (in hundredths) | 0.00% | (1.90%) | 0.00% | ||||||||
Other (in hundredths) | (0.17%) | 0.03% | (0.09%) | ||||||||
Effective Income Tax Rate (in hundredths) | 34.63% | 41.64% | 36.07% | ||||||||
Valuation Allowance [Abstract] | |||||||||||
Beginning Balance | $ 463,018,000 | $ 223,599,000 | $ 463,018,000 | $ 223,599,000 | $ 199,743,000 | ||||||
Increase | 146,602,000 | 392,729,000 | 43,422,000 | ||||||||
Decrease | (4,315,000) | (1,424,000) | (4,967,000) | ||||||||
Other | (99,178,000) | (151,886,000) | (14,599,000) | ||||||||
Ending Balance | 506,127,000 | $ 463,018,000 | 506,127,000 | $ 463,018,000 | $ 223,599,000 | ||||||
Unrecognized tax benefits balance | 0 | 0 | |||||||||
Foreign subsidiaries' undistributed earnings | 2,000,000,000 | 2,000,000,000 | |||||||||
Balance of State net operating loss expected to be carried forward | 1,700,000,000 | ||||||||||
Alternative minimum tax credits utilized | 4,000,000 | ||||||||||
AMT Paid In Years Prior To Prior Reporting Period | 779,000,000 | ||||||||||
Tax net operating loss incurred in United Kingdom in current year | 153,000,000 | ||||||||||
Balance of tax net operating loss incurred in the United Kingdom in prior years | 764,000,000 | ||||||||||
Unrecognized tax benefits interest or penalties | 0 | 0 | |||||||||
Federal and state deferred income taxes | $ 258,000,000 | $ 258,000,000 |
Employee Benefit Plans (Details
Employee Benefit Plans (Details) | 12 Months Ended | |||||
Dec. 31, 2015USD ($)$ / sharesshares | Dec. 31, 2014USD ($)$ / sharesshares | Dec. 31, 2013USD ($)$ / sharesshares | ||||
Defined Benefit and Defined Contribution Plan Disclosure [Line Items] | ||||||
Total pension plan costs | $ | $ 36,000,000 | $ 41,000,000 | $ 37,000,000 | |||
Company contributions to foreign pension plans | $ | 1,000,000 | 5,000,000 | 4,000,000 | |||
Benefit obligation | $ | 9,000,000 | 14,000,000 | ||||
Fair value of foreign pension plan assets | $ | 7,000,000 | 12,000,000 | ||||
Accrued benefit cost | $ | (200,000) | (1,000,000) | ||||
Stock based compensation by job function [Line Items] | ||||||
Compensation expense related to the company's stock-based compensation plans | $ | 130,577,000 | 144,842,000 | 134,467,000 | |||
Federal income tax (expense) / benefit recognized from stock-based compensation | $ | 26,000,000 | 99,000,000 | 56,000,000 | |||
Stock-based compensation expense related to stock options, SAR and ESPP grants | $ | $ 56,000,000 | $ 62,000,000 | $ 53,000,000 | |||
Share-Based Compensation Arrangement By Share-Based Payment Award [Abstract] | ||||||
Common Shares Available for Grant | 24,700,000 | |||||
Performance Units and Performance Stock [Member] | ||||||
Weighted Average Fair Value And Valuation Assumptions Used To Value Stock-Based Compensation [Abstract] | ||||||
Weighted Average Fair Value of Grants | $ / shares | $ 80.64 | $ 119.27 | $ 100.34 | |||
Expected Volatility (in hundredths) | 29.35% | 32.18% | 33.63% | |||
Risk-Free Interest Rate (in hundredths) | 1.07% | 1.18% | 0.79% | |||
Share-Based Compensation Arrangement By Share-Based Payment Award [Abstract] | ||||||
Weighted average period over which unrecognized compensation expense will be recognized | 3 years 3 months 18 days | |||||
Unrecognized compensation expense | $ | $ 6,000,000 | |||||
Number of Shares and Units [Roll Forward] | ||||||
Outstanding at January 1 (in shares) | 333,000 | [1] | 261,000 | [1] | 142,000 | |
Granted (in shares) | 72,000 | 72,000 | 119,000 | |||
Outstanding at December 31 [1] (in shares) | [1] | 405,000 | 333,000 | 261,000 | ||
Weighted Average Grant Fair Value [Abstract] | ||||||
Outstanding at January 1 (in dollars per share) | $ / shares | $ 90.17 | [1] | $ 82.18 | [1] | $ 67.05 | |
Granted (in dollars per share) | $ / shares | 80.64 | 119.27 | 100.34 | |||
Outstanding at December 31 [1] (in dollars per share) | $ / shares | [1] | $ 88.48 | $ 90.17 | $ 82.18 | ||
Intrinsic value of stock based compensation | $ | $ 29,000,000 | $ 31,000,000 | ||||
Maximum vest period from the date of grant | 5 years | |||||
Performance Units and Performance Stock [Abstract] | ||||||
Minimum Performance Units and Stock Allowed to be Outstanding | 0 | |||||
Maximum performance units and stock allowed to be outstanding | 810,000 | |||||
Share Based Compensation Arrangement By Performance Units and Stock Compensation Cost | $ | $ 5,000,000 | $ 9,000,000 | $ 9,000,000 | |||
Term of Zero-Coupon Risk-Free Interest Rate Derived from the Treasury Constant Maturities Yield Curve | 3 years 3 months 4 days | |||||
Performance Period for Performance Units and Stock | 3 years | |||||
ESPP [Member] | ||||||
Stock based compensation by job function [Line Items] | ||||||
Maximum Percentage Of Employee Pay Eligible For Contribution To Espp Percentage | 10.00% | |||||
Percentage of fair market value at which employees may purchase company stock via the ESPP | 85.00% | |||||
Weighted Average Fair Value And Valuation Assumptions Used To Value Stock-Based Compensation [Abstract] | ||||||
Weighted Average Fair Value of Grants | $ / shares | $ 21.21 | $ 21.65 | $ 15.06 | |||
Expected Volatility (in hundredths) | 32.08% | 25.03% | 29.89% | |||
Risk-Free Interest Rate (in hundredths) | 0.12% | 0.08% | 0.11% | |||
Dividend Yield (in hundredths) | 0.73% | 0.46% | 0.60% | |||
Expected Life (in years) | 6 months | 6 months | 6 months | |||
Share-Based Compensation Arrangement By Share-Based Payment Award [Abstract] | ||||||
Common Shares Available for Grant | 568,000 | |||||
Approximate Number of Participants | 1,963 | 1,991 | 1,844 | |||
Shares Purchased | 225,000 | 202,000 | 256,000 | |||
Aggregate Purchase Price | $ | $ 15,045,000 | $ 14,927,000 | $ 14,015,000 | |||
Stock Options and SARS [Member] | ||||||
Stock based compensation by job function [Line Items] | ||||||
Maximum term of stock options and SARs granted | 7 years | |||||
Weighted Average Fair Value And Valuation Assumptions Used To Value Stock-Based Compensation [Abstract] | ||||||
Weighted Average Fair Value of Grants | $ / shares | $ 21.88 | $ 30.75 | $ 27.35 | |||
Expected Volatility (in hundredths) | 38.03% | 35.28% | 35.86% | |||
Risk-Free Interest Rate (in hundredths) | 0.83% | 0.95% | 0.78% | |||
Dividend Yield (in hundredths) | 0.85% | 0.61% | 0.40% | |||
Expected Life (in years) | 5 years 3 months 18 days | 5 years 2 months 12 days | 5 years 6 months | |||
Stock option and SAR Rollforward [Abstract] | ||||||
Outstanding at January 1 (in shares) | 10,493,000 | 10,452,000 | 12,438,000 | |||
Granted (in shares) | 2,037,000 | 2,146,000 | 2,268,000 | |||
Exercised (in shares) | [2] | (1,518,000) | (1,718,000) | (4,046,000) | ||
Forfeited (in shares) | (268,000) | (387,000) | (208,000) | |||
Outstanding at December 31 (in shares) | 10,744,000 | 10,493,000 | 10,452,000 | |||
Share-Based Compensation Arrangement By Share-Based Payment Award [Abstract] | ||||||
Outstanding at January 1 (in dollars per share) | $ / shares | $ 64.96 | $ 54.43 | $ 42.91 | |||
Granted (in dollars per share) | $ / shares | 69.99 | 101.55 | 83.70 | |||
Exercised (in dollars per share) | $ / shares | [2] | 47.64 | 45.68 | 35.62 | ||
Forfeited (in dollars per share) | $ / shares | 80.31 | 68.95 | 50.78 | |||
Outstanding at December 31 (in dollars per share) | $ / shares | $ 67.98 | $ 64.96 | $ 54.43 | |||
Stock Options/SARs Exercisable at December 31 (in shares) | 5,993,000 | 5,287,000 | 4,638,000 | |||
Stock Options/SARs Exercisable at December 31 (in dollars per share) | $ / shares | $ 57.96 | $ 49.40 | $ 43.95 | |||
Intrinsic value of stock options/SARs exercised during the period | $ | [2] | $ 60,000,000 | $ 95,000,000 | $ 151,000,000 | ||
Stock options/SARs vested or expected to vest (in shares) | 10,400,000 | |||||
Weighted average grant price for stock options/SARs vested or expected to vest (per share) | $ / shares | $ 67.52 | |||||
Intrinsic value of stock options/SARs vested or expected to vest | $ | $ 52,000,000 | |||||
Weighted Average Remaining Contractual Life for Stock Options/SARs Vested or Expected to Vest | 4 years 1 month 6 days | |||||
Weighted average period over which unrecognized compensation expense will be recognized | 2 years 9 months 18 days | |||||
Unrecognized compensation expense | $ | $ 100,000,000 | |||||
Weighted Average Grant Fair Value [Abstract] | ||||||
Maximum vest period from the date of grant | 4 years | |||||
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items] | ||||||
Stock Options and SARs Outstanding | 10,744,000 | |||||
Weighted Average Remaining Life for Outstanding Options and SARs | 4 years | |||||
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares | $ 67.98 | |||||
Aggregate Intrinsic Value For Outstanding Options and SARs | $ | [3] | $ 117,424 | ||||
Stock Options and SARs Exercisable | 5,993,000 | |||||
Weighted Average Remaining Life For Exercisable Units | 3 years | |||||
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares | $ 57.96 | |||||
Aggregate Intrinsic Value For Exercisable Units | $ | [3] | $ 107,950 | ||||
Restricted Stock And Restricted Stock Units [Member] | ||||||
Stock option and SAR Rollforward [Abstract] | ||||||
Outstanding at January 1 (in shares) | 5,394,000 | [4] | 7,358,000 | [4] | 7,636,000 | |
Granted (in shares) | 1,044,000 | 1,132,000 | 1,294,000 | |||
Exercised (in shares) | [5] | (1,331,000) | (2,761,000) | (1,368,000) | ||
Forfeited (in shares) | (199,000) | (335,000) | (204,000) | |||
Outstanding at December 31 (in shares) | [4] | 4,908,000 | 5,394,000 | 7,358,000 | ||
Share-Based Compensation Arrangement By Share-Based Payment Award [Abstract] | ||||||
Outstanding at January 1 (in dollars per share) | $ / shares | $ 64.39 | [4] | $ 49.54 | [4] | $ 45.53 | |
Granted (in dollars per share) | $ / shares | 77.94 | 98.72 | 76.04 | |||
Exercised (in dollars per share) | $ / shares | [5] | 51.52 | 105.24 | 52.39 | ||
Forfeited (in dollars per share) | $ / shares | 74.56 | 62.55 | 48.55 | |||
Outstanding at December 31 (in dollars per share) | $ / shares | [4] | $ 70.35 | $ 64.39 | $ 49.54 | ||
Weighted average period over which unrecognized compensation expense will be recognized | 2 years 6 months | |||||
Unrecognized compensation expense | $ | $ 156,000,000 | |||||
Share Based Compensation Arrangement By Restricted Stock And Restricted Stock Units Compensation Cost | $ | 69,000,000 | $ 74,000,000 | $ 72,000,000 | |||
Weighted Average Grant Fair Value [Abstract] | ||||||
Intrinsic value of stock based compensation | $ | 109,000,000 | 291,000,000 | 101,000,000 | |||
Intrinsic Value Of Restricted Stock And Restricted Stock Units Outstanding | $ | $ 347,000,000 | 497,000,000 | ||||
Maximum vest period from the date of grant | 5 years | |||||
Lease And Well [Member] | ||||||
Stock based compensation by job function [Line Items] | ||||||
Compensation expense related to the company's stock-based compensation plans | $ | $ 44,000,000 | 41,000,000 | 35,000,000 | |||
Gathering And Processing Costs [Member] | ||||||
Stock based compensation by job function [Line Items] | ||||||
Compensation expense related to the company's stock-based compensation plans | $ | 1,000,000 | 1,000,000 | 1,000,000 | |||
Exploration Costs [Member] | ||||||
Stock based compensation by job function [Line Items] | ||||||
Compensation expense related to the company's stock-based compensation plans | $ | 26,000,000 | 27,000,000 | 27,000,000 | |||
General And Administrative [Member] | ||||||
Stock based compensation by job function [Line Items] | ||||||
Compensation expense related to the company's stock-based compensation plans | $ | $ 60,000,000 | $ 76,000,000 | $ 71,000,000 | |||
$22.00 to $ 44.99 | Stock Options and SARS [Member] | ||||||
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items] | ||||||
Stock Options and SARs Outstanding | 2,184,000 | |||||
Weighted Average Remaining Life for Outstanding Options and SARs | 2 years | |||||
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares | $ 41.08 | |||||
Stock Options and SARs Exercisable | 2,182,000 | |||||
Weighted Average Remaining Life For Exercisable Units | 2 years | |||||
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares | $ 41.08 | |||||
45.00 to 56.99 | Stock Options and SARS [Member] | ||||||
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items] | ||||||
Stock Options and SARs Outstanding | 2,672,000 | |||||
Weighted Average Remaining Life for Outstanding Options and SARs | 3 years | |||||
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares | $ 52.37 | |||||
Stock Options and SARs Exercisable | 2,229,000 | |||||
Weighted Average Remaining Life For Exercisable Units | 3 years | |||||
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares | $ 51.64 | |||||
57.00 to 69.99 | Stock Options and SARS [Member] | ||||||
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items] | ||||||
Stock Options and SARs Outstanding | 2,019,000 | |||||
Weighted Average Remaining Life for Outstanding Options and SARs | 7 years | |||||
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares | $ 69.13 | |||||
Stock Options and SARs Exercisable | 51,000 | |||||
Weighted Average Remaining Life For Exercisable Units | 4 years | |||||
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares | $ 62.11 | |||||
70.00 to 84.99 | Stock Options and SARS [Member] | ||||||
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items] | ||||||
Stock Options and SARs Outstanding | 1,832,000 | |||||
Weighted Average Remaining Life for Outstanding Options and SARs | 4 years | |||||
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares | $ 84.25 | |||||
Stock Options and SARs Exercisable | 936,000 | |||||
Weighted Average Remaining Life For Exercisable Units | 4 years | |||||
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares | $ 84.36 | |||||
85.00 to 116.99 | Stock Options and SARS [Member] | ||||||
Summary Information By Grant Price Range For Stock Options And SARs Outstanding And Exercisable At End Of Period [Line Items] | ||||||
Stock Options and SARs Outstanding | 2,037,000 | |||||
Weighted Average Remaining Life for Outstanding Options and SARs | 5 years | |||||
Weighted Average Grant Price For Outstanding Options and SARs | $ / shares | $ 101.49 | |||||
Stock Options and SARs Exercisable | 595,000 | |||||
Weighted Average Remaining Life For Exercisable Units | 5 years | |||||
Weighted Average Grant Price For Exercisable Options and SARs | $ / shares | $ 101.61 | |||||
[1] | The total intrinsic value of performance units and performance stock outstanding at December 31, 2015 and 2014 was $29 million and $31 million, respectively. | |||||
[2] | The total intrinsic value of stock options/SARs exercised during the years 2015, 2014 and 2013 was $60 million, $95 million and $151 million, respectively. The intrinsic value is based upon the difference between the market price of the Common Stock on the date of exercise and the grant price of the stock options/SARs. | |||||
[3] | Based upon the difference between the closing market price of the Common Stock on the last trading day of the year and the grant price of in-the-money stock options and SARs. | |||||
[4] | The total intrinsic value of restricted stock and restricted stock units outstanding at December 31, 2015 and 2014 was approximately $347 million and $497 million, respectively. | |||||
[5] | The total intrinsic value of restricted stock and restricted stock units released during the years ended December 31, 2015, 2014 and 2013 was $109 million, $291 million and $101 million, respectively. The intrinsic value is based upon the closing price of EOG's common stock on the date restricted stock and restricted stock units are released. |
Commitments and Contingencies49
Commitments and Contingencies (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Feb. 25, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | ||||
Standby letters of credit and guarantees outstanding | $ 272,000,000 | $ 423,000,000 | ||
Subsidiary payment obligations demand for payment | $ 0 | |||
Total Minimum Commitments [Abstract] | ||||
2,016 | 1,275,650,000 | |||
2,017 | 994,328,000 | |||
2,018 | 781,299,000 | |||
2,019 | 547,299,000 | |||
2,020 | 431,221,000 | |||
2021 and beyond | 900,961,000 | |||
Total Minimum Commitments | 4,930,758,000 | |||
Rental expenses associated with existing leases | $ 229,000,000 | $ 237,000,000 | $ 191,000,000 |
Net Income (Loss) Per Share (De
Net Income (Loss) Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |||||||||
Numerator for Basic and Diluted Earnings per Share - [Abstract] | |||||||||||||||||||
Net Income (Loss) | $ (284,296) | $ (4,075,739) | $ 5,268 | $ (169,748) | $ 444,588 | $ 1,103,618 | $ 706,353 | $ 660,928 | $ (4,524,515) | $ 2,915,487 | $ 2,197,109 | ||||||||
Denominator for Basic Earnings per Share - [Abstract] | |||||||||||||||||||
Weighted Average Shares (in shares) | 545,697 | 543,443 | 540,341 | ||||||||||||||||
Potential Dilutive Common Shares -[Abstract] | |||||||||||||||||||
Stock Options/SARs (in shares) | 0 | 2,526 | 2,316 | ||||||||||||||||
Restricted Stock/Units and Performance Units/Stock (in shares) | 0 | 2,570 | 3,570 | ||||||||||||||||
Denominator for Diluted Earnings per Share - [Abstract] | |||||||||||||||||||
Adjusted Diluted Weighted Average Shares (in shares) | 546,432 | 545,920 | 549,683 | 544,998 | 549,153 | 549,518 | 548,676 | 548,071 | 545,697 | 548,539 | 546,227 | ||||||||
Net Income (Loss) Per Share [Abstract] | |||||||||||||||||||
Basic (in dollars per share) | $ (0.52) | [1] | $ (7.47) | [1] | $ 0.01 | [1] | $ (0.31) | [1] | $ 0.82 | [1] | $ 2.03 | [1] | $ 1.30 | [1] | $ 1.22 | [1] | $ (8.29) | $ 5.36 | $ 4.07 |
Diluted (in dollars per share) | $ (0.52) | [1] | $ (7.47) | [1] | $ 0.01 | [1] | $ (0.31) | [1] | $ 0.81 | [1] | $ 2.01 | [1] | $ 1.29 | [1] | $ 1.21 | [1] | $ (8.29) | $ 5.32 | $ 4.02 |
Antidilutive Stock Options and SARs excluded from Diluted Earnings Per Share Calculation (in shares) | 10,200 | 700 | 300 | ||||||||||||||||
Restricted Stock and Restricted Stock Units and Performance Units and Performance Stock Excluded from Calculation | 5,300 | ||||||||||||||||||
[1] | The sum of quarterly net income (loss) per share may not agree with total year net income (loss) per share as each quarterly computation is based on the weighted average of common shares outstanding. |
Supplemental Cash Flow Inform51
Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Supplemental Cash Flow Information [Abstract] | |||
Interest, Net of Capitalized Interest | $ 222,088 | $ 197,383 | $ 235,854 |
Income Taxes, Net of Refunds Received | 41,108 | 342,741 | 294,739 |
Accrued Capital Expenditures | $ 416,000 | 972,000 | 731,000 |
Non-cash investing and financing activities from property exchanges. | $ 5,000 | $ 5,000 |
Business Segment Information (D
Business Segment Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |||||
Schedule of Segment Reporting Information By Segment [Abstract] | |||||||||||||||
Crude Oil and Condensate | $ 4,934,562 | $ 9,742,480 | $ 8,300,647 | ||||||||||||
Natural Gas Liquids | 407,658 | 934,051 | 773,970 | ||||||||||||
Natural Gas | 1,061,038 | 1,916,386 | 1,681,029 | ||||||||||||
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts | 61,924 | 834,273 | (166,349) | ||||||||||||
Gathering, Processing and Marketing | 2,253,135 | 4,046,316 | 3,643,749 | ||||||||||||
Gains (Losses) on Asset Dispositions, Net | (8,798) | 507,590 | 197,565 | ||||||||||||
Other, Net | 47,909 | 54,244 | 56,507 | ||||||||||||
Net Operating Revenues | $ 1,796,761 | $ 2,172,428 | $ 2,469,701 | $ 2,318,538 | $ 4,645,497 | $ 5,118,616 | $ 4,187,556 | $ 4,083,671 | 8,757,428 | [1] | 18,035,340 | [2] | 14,487,118 | [3] | |
Depreciation, Depletion and Amortization | 3,313,644 | 3,997,041 | 3,600,976 | ||||||||||||
Operating Income (Loss) | (329,753) | (6,222,957) | 39,626 | (172,995) | 1,226,652 | 1,786,162 | 1,144,730 | 1,084,279 | (6,686,079) | 5,241,823 | 3,675,211 | ||||
Interest Income | 3,469 | 2,239 | 5,585 | ||||||||||||
Other Income (Expense) | (1,553) | (47,289) | (8,450) | ||||||||||||
Net Interest Expense | 237,393 | 201,458 | 235,460 | ||||||||||||
Income (Loss) Before Income Taxes | (398,826) | (6,274,921) | (11,478) | (236,331) | 1,148,593 | 1,715,120 | 1,100,813 | 1,030,789 | (6,921,556) | 4,995,315 | 3,436,886 | ||||
Income Tax Provision (Benefit) | (114,530) | $ (2,199,182) | $ (16,746) | $ (66,583) | 704,005 | $ 611,502 | $ 394,460 | $ 369,861 | (2,397,041) | 2,079,828 | 1,239,777 | ||||
Additions to Oil and Gas Properties, Excluding Dry Hole Costs | 4,710,404 | 7,471,177 | 6,622,436 | ||||||||||||
Total Property, Plant and Equipment, Net | 24,210,721 | 29,172,644 | 24,210,721 | 29,172,644 | 26,148,836 | ||||||||||
Total Assets | 26,975,244 | 34,762,687 | 26,975,244 | 34,762,687 | 30,574,238 | ||||||||||
United States | |||||||||||||||
Schedule of Segment Reporting Information By Segment [Abstract] | |||||||||||||||
Crude Oil and Condensate | 4,917,731 | 9,526,149 | 8,035,358 | ||||||||||||
Natural Gas Liquids | 407,570 | 924,454 | 761,535 | ||||||||||||
Natural Gas | 637,452 | 1,321,175 | 1,100,808 | ||||||||||||
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts | 61,924 | 834,273 | (166,349) | ||||||||||||
Gathering, Processing and Marketing | 2,254,477 | 4,040,024 | 3,636,209 | ||||||||||||
Gains (Losses) on Asset Dispositions, Net | (12,176) | 96,339 | 93,876 | ||||||||||||
Other, Net | 47,464 | 49,950 | 51,713 | ||||||||||||
Net Operating Revenues | 8,314,442 | [1] | 16,792,364 | [2] | 13,513,150 | [3] | |||||||||
Depreciation, Depletion and Amortization | 3,139,863 | 3,684,943 | 3,223,596 | ||||||||||||
Operating Income (Loss) | (6,566,282) | 5,074,911 | 3,543,841 | ||||||||||||
Interest Income | 1,913 | 849 | 2,803 | ||||||||||||
Other Income (Expense) | 6,461 | (14,953) | (29,696) | ||||||||||||
Net Interest Expense | 274,606 | 269,166 | 283,209 | ||||||||||||
Income (Loss) Before Income Taxes | (6,832,514) | 4,791,641 | 3,233,739 | ||||||||||||
Income Tax Provision (Benefit) | (2,463,213) | 1,837,185 | 1,161,328 | ||||||||||||
Additions to Oil and Gas Properties, Excluding Dry Hole Costs | 4,495,730 | 7,133,727 | 6,133,894 | ||||||||||||
Total Property, Plant and Equipment, Net | 23,593,995 | 28,391,741 | 23,593,995 | 28,391,741 | 24,456,383 | ||||||||||
Total Assets | 25,351,908 | 32,871,398 | 25,351,908 | 32,871,398 | 27,668,713 | ||||||||||
Amount of sales with a single significant purchaser in the United States segment | 1,700,000 | 4,000,000 | 3,900,000 | ||||||||||||
Amount of sales with a second significant purchaser in the United States segment. | 1,400,000 | 3,000,000 | 2,000,000 | ||||||||||||
Trinidad | |||||||||||||||
Schedule of Segment Reporting Information By Segment [Abstract] | |||||||||||||||
Crude Oil and Condensate | 13,122 | 29,604 | 40,379 | ||||||||||||
Natural Gas Liquids | 0 | 0 | 0 | ||||||||||||
Natural Gas | 368,639 | 483,071 | 477,103 | ||||||||||||
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts | 0 | 0 | 0 | ||||||||||||
Gathering, Processing and Marketing | (1,342) | 6,064 | 6,064 | ||||||||||||
Gains (Losses) on Asset Dispositions, Net | 393 | 0 | 1,119 | ||||||||||||
Other, Net | (3) | 37 | 24 | ||||||||||||
Net Operating Revenues | 380,809 | [1] | 518,776 | [2] | 524,689 | [3] | |||||||||
Depreciation, Depletion and Amortization | 154,853 | 188,592 | 181,990 | ||||||||||||
Operating Income (Loss) | 175,658 | 277,471 | 266,329 | ||||||||||||
Interest Income | 389 | 253 | 336 | ||||||||||||
Other Income (Expense) | 8,780 | 8,712 | 9,889 | ||||||||||||
Net Interest Expense | 1,400 | 0 | 0 | ||||||||||||
Income (Loss) Before Income Taxes | 183,427 | 286,436 | 276,554 | ||||||||||||
Income Tax Provision (Benefit) | 63,502 | 98,559 | 118,270 | ||||||||||||
Additions to Oil and Gas Properties, Excluding Dry Hole Costs | 102,358 | 76,138 | 132,984 | ||||||||||||
Total Property, Plant and Equipment, Net | 350,766 | 382,719 | 350,766 | 382,719 | 476,174 | ||||||||||
Total Assets | 886,826 | 865,674 | 886,826 | 865,674 | 986,796 | ||||||||||
Other International | |||||||||||||||
Schedule of Segment Reporting Information By Segment [Abstract] | |||||||||||||||
Crude Oil and Condensate | [4] | 3,709 | 186,727 | 224,910 | |||||||||||
Natural Gas Liquids | [4] | 88 | 9,597 | 12,435 | |||||||||||
Natural Gas | [4] | 54,947 | 112,140 | 103,118 | |||||||||||
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts | [4] | 0 | 0 | 0 | |||||||||||
Gathering, Processing and Marketing | [4] | 0 | 228 | 1,476 | |||||||||||
Gains (Losses) on Asset Dispositions, Net | [4] | 2,985 | 411,251 | 102,570 | |||||||||||
Other, Net | [4] | 448 | 4,257 | 4,770 | |||||||||||
Net Operating Revenues | [4] | 62,177 | [1] | 724,200 | [2] | 449,279 | [3] | ||||||||
Depreciation, Depletion and Amortization | [4] | 18,928 | 123,506 | 195,390 | |||||||||||
Operating Income (Loss) | [4] | (295,455) | (110,559) | (134,959) | |||||||||||
Interest Income | [4] | 1,167 | 1,137 | 2,446 | |||||||||||
Other Income (Expense) | [4] | (16,794) | (41,048) | 11,357 | |||||||||||
Net Interest Expense | [4] | (38,613) | (67,708) | (47,749) | |||||||||||
Income (Loss) Before Income Taxes | [4] | (272,469) | (82,762) | (73,407) | |||||||||||
Income Tax Provision (Benefit) | [4] | 2,670 | 144,084 | (39,821) | |||||||||||
Additions to Oil and Gas Properties, Excluding Dry Hole Costs | [4] | 112,316 | 261,312 | 355,558 | |||||||||||
Total Property, Plant and Equipment, Net | [4] | 265,960 | 398,184 | 265,960 | 398,184 | 1,216,279 | |||||||||
Total Assets | [4] | $ 736,510 | $ 1,025,615 | $ 736,510 | $ 1,025,615 | $ 1,918,729 | |||||||||
[1] | EOG had sales activity with two significant purchasers in 2015, one totaling $1.7 billion and the other totaling $1.4 billion of consolidated Net Operating Revenues in the United States segment. | ||||||||||||||
[2] | EOG had sales activity with two significant purchasers in 2014, one totaling $4.0 billion and the other totaling $3.0 billion of consolidated Net Operating Revenues in the United States segment. | ||||||||||||||
[3] | EOG had sales activity with two significant purchasers in 2013, one totaling $3.9 billion and the other totaling $2.0 billion of consolidated Net Operating Revenues in the United States segment. | ||||||||||||||
[4] | Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. |
Risk Management Activities (Det
Risk Management Activities (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||||
Net (Gains) Losses on Mark-to-Market Commodity Derivative Contracts | $ (61,924,000) | $ (834,273,000) | $ 166,349,000 | |
Net Cash Received from Settlements of Crude Oil and Natural Gas Derivative Contracts | $ 730,114,000 | $ 34,007,000 | $ 116,361,000 | |
Derivatives, Fair Value [Line Items] | ||||
Receivable Major Customer Percentage | 10.00% | 10.00% | ||
Derivatives assets, current | $ 0 | $ 465,128,000 | ||
Derivative Collateral [Abstract] | ||||
Collateral Held on Derivative | 0 | 278,000,000 | ||
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 | [1] | 0 | 465,000,000 | |
Derivative asset, gross assets | 477,000,000 | |||
Derivative asset, gross liabilities | 12,000,000 | |||
Crude Oil and Natural Gas Derivative Contracts [Member] | Liabilities From Price Risk Management Activities [Member] | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative liabilities, current | [2] | $ 0 | 0 | |
Derivative liabilities, gross liabilities | 12,000,000 | |||
Derivative liabilities, gross assets | $ 12,000,000 | |||
[1] | The current portion of Assets from Price Risk Management Activities consists of gross assets of $477 million, partially offset by gross liabilities of $12 million, at December 31, 2014. | |||
[2] | The current portion of Liabilities from Price Risk Management Activities consists of gross liabilities of $12 million, offset by gross assets of $12 million, at December 31, 2014. |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Financial Assets: | ||
Financial Assets: Crude Oil Swaps | $ 100 | |
Financial Liabilities: | ||
Financial Liabilities: Crude Oil Swaps | 121 | |
Financial Liabilities: Crude Oil Options/Swaptions | 244 | |
Proved oil and gas properties, other property, plant and equipment and other assets, carrying amount | $ 9,154 | 968 |
Proved oil and gas properties, other property, plant and equipment and other assets written down during the period - fair value at end of period | 2,828 | 393 |
Pretax impairment charges for proved oil and gas properties, other property, plant and equipment and other assets | 6,326 | 575 |
Net of Tax Impairment Charges for Proved Oil and Gas Properties, Other Property, Plant and Equipment and Other Assets | 4,141 | |
Pretax impairment charges for proved oil and gas properties and other assets, in which EOG utilized an accepted offer from a third-party purchaser | 58 | |
Aggregate Principal Amount of Current and Long-Term Debt | 6,390 | 5,890 |
Fair Value of Debt | $ 6,524 | 6,242 |
Fair Value, Inputs, Level 1 [Member] | ||
Financial Assets: | ||
Financial Assets: Crude Oil Swaps | 0 | |
Financial Liabilities: | ||
Financial Liabilities: Crude Oil Swaps | 0 | |
Financial Liabilities: Crude Oil Options/Swaptions | 0 | |
Fair Value, Inputs, Level 2 [Member] | ||
Financial Assets: | ||
Financial Assets: Crude Oil Swaps | 100 | |
Financial Liabilities: | ||
Financial Liabilities: Crude Oil Swaps | 121 | |
Financial Liabilities: Crude Oil Options/Swaptions | 244 | |
Fair Value, Inputs, Level 3 [Member] | ||
Financial Assets: | ||
Financial Assets: Crude Oil Swaps | 0 | |
Financial Liabilities: | ||
Financial Liabilities: Crude Oil Swaps | 0 | |
Financial Liabilities: Crude Oil Options/Swaptions | $ 0 |
Accounting For Certain Long-L55
Accounting For Certain Long-Lived Assets (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Schedule of Impaired Long-Lived Assets Held and Used [Line Items] | |||
Amortization and impairments of unproved oil and gas property costs including amortization of capitalized interest | $ 288 | $ 168 | $ 115 |
United States | |||
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 | 6,130 | 171 | 73 |
Trinidad | |||
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 | $ 196 | $ 404 | $ 85 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | ||
Asset Retirement Obligations, Noncurrent [Abstract] | |||
Carrying Amount at Beginning of Period | $ 752,718 | $ 761,898 | |
Liabilities Incurred | 63,844 | 123,849 | |
Liabilities Settled | [1] | (17,415) | (247,422) |
Accretion | 31,956 | 41,489 | |
Revisions | (13,356) | 82,885 | |
Foreign Currency Translations | (6,193) | (9,981) | |
Carrying Amount at End of Period | 811,554 | 752,718 | |
Current Portion | 7,651 | 11,814 | |
Noncurrent Portion | $ 803,903 | $ 740,904 | |
[1] | Includes capitalized exploratory well costs charged to either dry hole costs or impairments. |
Exploratory Well Costs (Details
Exploratory Well Costs (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Capitalized Exploratory Well Costs [Abstract] | ||||
Balance at January 1 | $ 17,253 | $ 9,211 | $ 49,116 | |
Additions Pending the Determination of Proved Reserves | 24,640 | 32,080 | 52,099 | |
Reclassifications to Proved Properties | (26,659) | (15,946) | (54,505) | |
Costs Charged to Expense (1) | [1] | (6,279) | (8,092) | (35,859) |
Foreign Currency Translations | 0 | 0 | (1,640) | |
Balance at December 31 | $ 8,955 | $ 17,253 | $ 9,211 | |
[1] | Includes capitalized exploratory well costs charged to either dry hole costs or impairments. |
Acquisitions and Divestitures (
Acquisitions and Divestitures (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Business Combinations [Abstract] | ||
Aggregated Purchase Price to Acquire Proved Crude Oil Properties and Related Assets | $ 481 | |
Proceeds from Sales of Producing Properties, Acreage and Other Assets | $ 193 | $ 569 |
Cumulative translation adjustments | 383 | |
Restricted cash related to future abandonment liabilities | $ 150 |
Oil and Gas Exploration and P59
Oil and Gas Exploration and Production Industries Disclosures (Details) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2015USD ($)MBoeMBblsMMcf | Dec. 31, 2014USD ($)MBoeMBblsMMcf | Dec. 31, 2013MBoeMBblsMMcf | Dec. 31, 2012MBoeMBblsMMcf | ||
Reserve Quantities [Line Items] | |||||
Net proved developed reserves (MBOE) | MBoe | 1,072,477 | 1,347,947 | 1,127,476 | 949,819 | |
Net Proved Undeveloped Reserves (MBOE) [Rollforward] | |||||
Balance at January 1 | MBoe | 1,149,309 | 991,067 | 860,879 | ||
Extensions and Discoveries | MBoe | 205,152 | 403,713 | 291,345 | ||
Revisions | MBoe | (241,973) | (79,630) | (855) | ||
Acquisition of Reserves | MBoe | 54,458 | 4,239 | 0 | ||
Sales of Reserves | MBoe | 0 | (10,176) | 0 | ||
Conversion to Proved Developed Reserves | MBoe | (121,306) | (159,904) | (160,302) | ||
Balance at December 31 | MBoe | 1,045,640 | 1,149,309 | 991,067 | ||
Capitalized Costs, Oil and Gas Producing Activities, Gross [Abstract] | |||||
Proved properties | $ | $ 49,623,518 | $ 45,169,101 | |||
Unproved properties | $ | 989,723 | 1,334,431 | |||
Total | $ | 50,613,241 | 46,503,532 | |||
Accumulated depreciation, depletion and amortization | $ | (28,877,593) | (20,212,748) | |||
Net capitalized costs | $ | $ 21,735,648 | $ 26,290,784 | |||
Crude Oil (MBbl) | |||||
Reserve Quantities [Line Items] | |||||
Net proved developed reserves | 445,202 | 495,148 | 391,056 | 290,650 | |
Net proved undeveloped reserves | 652,394 | 644,602 | 509,484 | 410,168 | |
Proved Developed Reserves [Rollforward] | |||||
Net proved reserves - beginning of period | [1] | 1,139,750 | 900,540 | 700,818 | |
Revisions of previous estimates | [1] | (114,925) | 28,022 | 50,669 | |
Purchases in place | [1] | 35,922 | 9,705 | 1,097 | |
Extensions, discoveries and other additions | [1] | 141,386 | 319,554 | 230,754 | |
Sales in place | [1] | (740) | (12,623) | (2,337) | |
Production | [1] | (103,797) | (105,448) | (80,461) | |
Net proved reserves - end of period | [1] | 1,097,596 | 1,139,750 | 900,540 | |
Natural Gas Liquids (MBbl) | |||||
Reserve Quantities [Line Items] | |||||
Net proved developed reserves | 205,898 | 264,749 | 200,860 | 162,593 | |
Net proved undeveloped reserves | 176,977 | 202,319 | 176,346 | 157,370 | |
Proved Developed Reserves [Rollforward] | |||||
Net proved reserves - beginning of period | [1] | 467,068 | 377,206 | 319,963 | |
Revisions of previous estimates | [1] | (113,222) | 27,443 | 12,109 | |
Purchases in place | [1] | 8,251 | 1,812 | 1,202 | |
Extensions, discoveries and other additions | [1] | 49,147 | 91,683 | 69,197 | |
Sales in place | [1] | (271) | (1,779) | (1,471) | |
Production | [1] | (28,098) | (29,297) | (23,794) | |
Net proved reserves - end of period | [1] | 382,875 | 467,068 | 377,206 | |
Natural Gas (MMcf) | |||||
Reserve Quantities [Line Items] | |||||
Net proved developed reserves | MMcf | 2,528,300 | 3,528,300 | 3,213,400 | 2,979,500 | |
Net proved undeveloped reserves | MMcf | 1,297,600 | 1,814,300 | 1,831,400 | 1,760,000 | |
Proved Developed Reserves [Rollforward] | |||||
Net proved reserves - beginning of period | MMcf | [2] | 5,342,600 | 5,044,800 | 4,739,500 | |
Revisions of previous estimates | MMcf | [2] | (1,430,700) | 270,600 | 277,300 | |
Purchases in place | MMcf | [2] | 72,300 | 17,100 | 5,700 | |
Extensions, discoveries and other additions | MMcf | [2] | 332,400 | 647,500 | 594,100 | |
Sales in place | MMcf | [2] | (15,000) | (131,100) | (69,400) | |
Production | MMcf | [2] | (475,700) | (506,300) | (502,400) | |
Net proved reserves - end of period | MMcf | [2] | 3,825,900 | 5,342,600 | 5,044,800 | |
Oil Equivalents (MBoe) | |||||
Reserve Quantities [Line Items] | |||||
Net proved undeveloped reserve (MBOE) | MBoe | 1,045,640 | 1,149,309 | 991,067 | 860,879 | |
Proved Developed Reserves (MBoe) [Roll Forward] | |||||
Net proved reserves - beginning of period | MBoe | [1] | 2,497,256 | 2,118,543 | 1,810,698 | |
Revisions of previous estimates | MBoe | [1] | (466,604) | 100,568 | 108,990 | |
Purchases in place | MBoe | [1] | 56,215 | 14,367 | 3,241 | |
Extensions, discoveries and other additions | MBoe | [1] | 245,931 | 519,167 | 398,965 | |
Sales in place | MBoe | [1] | (3,506) | (36,263) | (15,375) | |
Production | MBoe | [1] | (211,175) | (219,126) | (187,976) | |
Net proved reserves - end of period | MBoe | [1] | 2,118,117 | 2,497,256 | 2,118,543 | |
United States | |||||
Reserve Quantities [Line Items] | |||||
Net proved developed reserves (MBOE) | MBoe | 1,018,491 | 1,275,447 | 1,015,359 | 840,564 | |
United States | Crude Oil (MBbl) | |||||
Reserve Quantities [Line Items] | |||||
Net proved developed reserves | 444,070 | 493,694 | 382,517 | 281,167 | |
Net proved undeveloped reserves | 643,790 | 635,988 | 497,532 | 389,862 | |
Proved Developed Reserves [Rollforward] | |||||
Net proved reserves - beginning of period | [1] | 1,129,682 | 880,049 | 671,029 | |
Revisions of previous estimates | [1] | (114,924) | 28,301 | 57,668 | |
Purchases in place | [1] | 35,922 | 9,705 | 1,097 | |
Extensions, discoveries and other additions | [1] | 141,310 | 319,540 | 230,023 | |
Sales in place | [1] | (730) | (4,967) | (2,337) | |
Production | [1] | (103,400) | (102,946) | (77,431) | |
Net proved reserves - end of period | [1] | 1,087,860 | 1,129,682 | 880,049 | |
United States | Natural Gas Liquids (MBbl) | |||||
Reserve Quantities [Line Items] | |||||
Net proved developed reserves | 205,898 | 264,611 | 199,964 | 161,482 | |
Net proved undeveloped reserves | 176,977 | 202,319 | 176,038 | 156,924 | |
Proved Developed Reserves [Rollforward] | |||||
Net proved reserves - beginning of period | [1] | 466,930 | 376,002 | 318,406 | |
Revisions of previous estimates | [1] | (113,290) | 27,450 | 12,157 | |
Purchases in place | [1] | 8,251 | 1,812 | 1,202 | |
Extensions, discoveries and other additions | [1] | 49,147 | 91,683 | 69,187 | |
Sales in place | [1] | (84) | (956) | (1,471) | |
Production | [1] | (28,079) | (29,061) | (23,479) | |
Net proved reserves - end of period | [1] | 382,875 | 466,930 | 376,002 | |
United States | Natural Gas (MMcf) | |||||
Reserve Quantities [Line Items] | |||||
Net proved developed reserves | MMcf | 2,211,200 | 3,102,800 | 2,597,300 | 2,387,500 | |
Net proved undeveloped reserves | MMcf | 1,278,600 | 1,802,700 | 1,801,400 | 1,648,500 | |
Proved Developed Reserves [Rollforward] | |||||
Net proved reserves - beginning of period | MMcf | [2] | 4,905,500 | 4,398,700 | 4,036,000 | |
Revisions of previous estimates | MMcf | [2] | (1,453,100) | 252,200 | 264,000 | |
Purchases in place | MMcf | [2] | 72,300 | 17,100 | 5,700 | |
Extensions, discoveries and other additions | MMcf | [2] | 306,300 | 638,300 | 504,700 | |
Sales in place | MMcf | [2] | (3,900) | (52,400) | (69,400) | |
Production | MMcf | [2] | (337,300) | (348,400) | (342,300) | |
Net proved reserves - end of period | MMcf | [2] | 3,489,800 | 4,905,500 | 4,398,700 | |
United States | Oil Equivalents (MBoe) | |||||
Reserve Quantities [Line Items] | |||||
Net proved undeveloped reserve (MBOE) | MBoe | 1,033,870 | 1,138,755 | 973,807 | 821,544 | |
Proved Developed Reserves (MBoe) [Roll Forward] | |||||
Net proved reserves - beginning of period | MBoe | [1] | 2,414,202 | 1,989,166 | 1,662,108 | |
Revisions of previous estimates | MBoe | [1] | (470,401) | 97,782 | 113,823 | |
Purchases in place | MBoe | [1] | 56,215 | 14,367 | 3,241 | |
Extensions, discoveries and other additions | MBoe | [1] | 241,513 | 517,613 | 383,324 | |
Sales in place | MBoe | [1] | (1,467) | (14,661) | (15,375) | |
Production | MBoe | [1] | (187,701) | (190,065) | (157,955) | |
Net proved reserves - end of period | MBoe | [1] | 2,052,361 | 2,414,202 | 1,989,166 | |
Trinidad | |||||
Reserve Quantities [Line Items] | |||||
Net proved developed reserves (MBOE) | MBoe | 50,677 | 67,484 | 83,933 | 81,826 | |
Trinidad | Crude Oil (MBbl) | |||||
Reserve Quantities [Line Items] | |||||
Net proved developed reserves | 1,069 | 1,339 | 1,505 | 2,377 | |
Net proved undeveloped reserves | 0 | 0 | 85 | 651 | |
Proved Developed Reserves [Rollforward] | |||||
Net proved reserves - beginning of period | [1] | 1,339 | 1,590 | 3,028 | |
Revisions of previous estimates | [1] | (1) | 99 | (991) | |
Purchases in place | [1] | 0 | 0 | 0 | |
Extensions, discoveries and other additions | [1] | 63 | 0 | 0 | |
Sales in place | [1] | 0 | 0 | 0 | |
Production | [1] | (332) | (350) | (447) | |
Net proved reserves - end of period | [1] | 1,069 | 1,339 | 1,590 | |
Trinidad | Natural Gas Liquids (MBbl) | |||||
Reserve Quantities [Line Items] | |||||
Net proved developed reserves | 0 | 0 | 0 | 0 | |
Net proved undeveloped reserves | 0 | 0 | 0 | 0 | |
Proved Developed Reserves [Rollforward] | |||||
Net proved reserves - beginning of period | [1] | 0 | 0 | 0 | |
Revisions of previous estimates | [1] | 0 | 0 | 0 | |
Purchases in place | [1] | 0 | 0 | 0 | |
Extensions, discoveries and other additions | [1] | 0 | 0 | 0 | |
Sales in place | [1] | 0 | 0 | 0 | |
Production | [1] | 0 | 0 | 0 | |
Net proved reserves - end of period | [1] | 0 | 0 | 0 | |
Trinidad | Natural Gas (MMcf) | |||||
Reserve Quantities [Line Items] | |||||
Net proved developed reserves | MMcf | 297,600 | 396,900 | 494,600 | 476,700 | |
Net proved undeveloped reserves | MMcf | 19,000 | 8,700 | 26,100 | 111,500 | |
Proved Developed Reserves [Rollforward] | |||||
Net proved reserves - beginning of period | MMcf | [2] | 405,600 | 520,700 | 588,200 | |
Revisions of previous estimates | MMcf | [2] | 16,800 | 12,900 | (17,400) | |
Purchases in place | MMcf | [2] | 0 | 0 | 0 | |
Extensions, discoveries and other additions | MMcf | [2] | 21,700 | 4,500 | 79,500 | |
Sales in place | MMcf | [2] | 0 | 0 | 0 | |
Production | MMcf | [2] | (127,500) | (132,500) | (129,600) | |
Net proved reserves - end of period | MMcf | [2] | 316,600 | 405,600 | 520,700 | |
Trinidad | Oil Equivalents (MBoe) | |||||
Reserve Quantities [Line Items] | |||||
Net proved undeveloped reserve (MBOE) | MBoe | 3,166 | 1,453 | 4,431 | 19,234 | |
Proved Developed Reserves (MBoe) [Roll Forward] | |||||
Net proved reserves - beginning of period | MBoe | [1] | 68,937 | 88,364 | 101,060 | |
Revisions of previous estimates | MBoe | [1] | 2,802 | 2,245 | (3,892) | |
Purchases in place | MBoe | [1] | 0 | 0 | 0 | |
Extensions, discoveries and other additions | MBoe | [1] | 3,682 | 758 | 13,245 | |
Sales in place | MBoe | [1] | 0 | 0 | 0 | |
Production | MBoe | [1] | (21,578) | (22,430) | (22,049) | |
Net proved reserves - end of period | MBoe | [1] | 53,843 | 68,937 | 88,364 | |
Other International | |||||
Reserve Quantities [Line Items] | |||||
Net proved developed reserves (MBOE) | MBoe | [3] | 3,309 | 5,016 | 28,184 | 27,429 |
Other International | Crude Oil (MBbl) | |||||
Reserve Quantities [Line Items] | |||||
Net proved developed reserves | [3] | 63 | 115 | 7,034 | 7,106 |
Net proved undeveloped reserves | [3] | 8,604 | 8,614 | 11,867 | 19,655 |
Proved Developed Reserves [Rollforward] | |||||
Net proved reserves - beginning of period | [1],[3] | 8,729 | 18,901 | 26,761 | |
Revisions of previous estimates | [1],[3] | 0 | (378) | (6,008) | |
Purchases in place | [1],[3] | 0 | 0 | 0 | |
Extensions, discoveries and other additions | [1],[3] | 13 | 14 | 731 | |
Sales in place | [1],[3] | (10) | (7,656) | 0 | |
Production | [1],[3] | (65) | (2,152) | (2,583) | |
Net proved reserves - end of period | [1],[3] | 8,667 | 8,729 | 18,901 | |
Other International | Natural Gas Liquids (MBbl) | |||||
Reserve Quantities [Line Items] | |||||
Net proved developed reserves | [3] | 0 | 138 | 896 | 1,111 |
Net proved undeveloped reserves | [3] | 0 | 0 | 308 | 446 |
Proved Developed Reserves [Rollforward] | |||||
Net proved reserves - beginning of period | [1],[3] | 138 | 1,204 | 1,557 | |
Revisions of previous estimates | [1],[3] | 68 | (7) | (48) | |
Purchases in place | [1],[3] | 0 | 0 | 0 | |
Extensions, discoveries and other additions | [1],[3] | 0 | 0 | 10 | |
Sales in place | [1],[3] | (187) | (823) | 0 | |
Production | [1],[3] | (19) | (236) | (315) | |
Net proved reserves - end of period | [1],[3] | 0 | 138 | 1,204 | |
Other International | Natural Gas (MMcf) | |||||
Reserve Quantities [Line Items] | |||||
Net proved developed reserves | MMcf | [3] | 19,500 | 28,600 | 121,500 | 115,300 |
Net proved undeveloped reserves | MMcf | [3] | 0 | 2,900 | 3,900 | 0 |
Proved Developed Reserves [Rollforward] | |||||
Net proved reserves - beginning of period | MMcf | [2],[3] | 31,500 | 125,400 | 115,300 | |
Revisions of previous estimates | MMcf | [2],[3] | 5,600 | 5,500 | 30,700 | |
Purchases in place | MMcf | [2],[3] | 0 | 0 | 0 | |
Extensions, discoveries and other additions | MMcf | [2],[3] | 4,400 | 4,700 | 9,900 | |
Sales in place | MMcf | [2],[3] | (11,100) | (78,700) | 0 | |
Production | MMcf | [2],[3] | (10,900) | (25,400) | (30,500) | |
Net proved reserves - end of period | MMcf | [2],[3] | 19,500 | 31,500 | 125,400 | |
Other International | Oil Equivalents (MBoe) | |||||
Reserve Quantities [Line Items] | |||||
Net proved undeveloped reserve (MBOE) | MBoe | [3] | 8,604 | 9,101 | 12,829 | 20,101 |
Proved Developed Reserves (MBoe) [Roll Forward] | |||||
Net proved reserves - beginning of period | MBoe | [1],[3] | 14,117 | 41,013 | 47,530 | |
Revisions of previous estimates | MBoe | [1],[3] | 995 | 541 | (941) | |
Purchases in place | MBoe | [1],[3] | 0 | 0 | 0 | |
Extensions, discoveries and other additions | MBoe | [1],[3] | 736 | 796 | 2,396 | |
Sales in place | MBoe | [1],[3] | (2,039) | (21,602) | 0 | |
Production | MBoe | [1],[3] | (1,896) | (6,631) | (7,972) | |
Net proved reserves - end of period | MBoe | [1],[3] | 11,913 | 14,117 | 41,013 | |
[1] | Thousand barrels or thousand barrels of oil equivalent, as applicable; oil equivalents include crude oil and condensate, NGLs and natural gas. Oil equivalents are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. | ||||
[2] | Billion cubic feet. | ||||
[3] | Other International includes EOG's United Kingdom, China, Canada and Argentina operations. |
Oil and Gas Exploration and P60
Oil and Gas Exploration and Production Industries Disclosures, Costs Incurred (Details) - USD ($) $ in Thousands | 12 Months Ended | ||||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |||||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||||||
Acquisition Costs of Properties - Unproved | $ 133,857 | $ 370,414 | $ 414,121 | ||||
Acquisition Costs of Properties - Proved | 480,617 | 139,101 | 120,214 | ||||
Subtotal | 614,474 | 509,515 | 534,335 | ||||
Exploration Costs | 252,692 | 395,973 | 377,179 | ||||
Development Costs | 4,061,117 | 6,999,281 | 6,086,377 | ||||
Total | 4,928,283 | 7,904,769 | 6,997,891 | ||||
United States | |||||||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||||||
Acquisition Costs of Properties - Unproved | 133,801 | 365,915 | 411,556 | ||||
Acquisition Costs of Properties - Proved | 480,617 | 138,772 | 120,220 | ||||
Subtotal | 614,418 | 504,687 | 531,776 | ||||
Exploration Costs | 206,814 | 332,703 | 273,788 | ||||
Development Costs | 3,847,813 | [1] | 6,638,192 | [2] | 5,573,260 | [3] | |
Total | 4,669,045 | 7,475,582 | 6,378,824 | ||||
Trinidad | |||||||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||||||
Acquisition Costs of Properties - Unproved | 0 | 0 | 0 | ||||
Acquisition Costs of Properties - Proved | 0 | 0 | 0 | ||||
Subtotal | 0 | 0 | 0 | ||||
Exploration Costs | 22,837 | 2,794 | 16,060 | ||||
Development Costs | 102,715 | [1] | 89,555 | [2] | 124,231 | [3] | |
Total | 125,552 | 92,349 | 140,291 | ||||
Other International | |||||||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||||||
Acquisition Costs of Properties - Unproved | [4] | 56 | 4,499 | 2,565 | |||
Acquisition Costs of Properties - Proved | [4] | 0 | 329 | (6) | |||
Subtotal | [4] | 56 | 4,828 | 2,559 | |||
Exploration Costs | [4] | 23,041 | 60,476 | 87,331 | |||
Development Costs | [4] | 110,589 | [1] | 271,534 | [2] | 388,886 | [3] |
Total | [4] | $ 133,686 | $ 336,838 | $ 478,776 | |||
[1] | Includes Asset Retirement Costs of $32 million, $15 million and $6 million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment. | ||||||
[2] | Includes Asset Retirement Costs of $149 million, $14 million and $33 million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment. | ||||||
[3] | Includes Asset Retirement Costs of $84 million and $50 million for the United States and Other International, respectively. Excludes other property, plant and equipment. | ||||||
[4] | Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. |
Oil and Gas Exploration and P61
Oil and Gas Exploration and Production Industries Disclosures, Results Of Operations (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | ||||
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues | [1] | $ 6,403,258 | $ 12,592,917 | $ 10,755,646 |
Other | [1] | 47,909 | 54,244 | 56,507 |
Total | [1] | 6,451,167 | 12,647,161 | 10,812,153 |
Exploration Costs | [1] | 149,494 | 184,388 | 161,346 |
Dry Hole Costs | [1] | 14,746 | 48,490 | 74,655 |
Transportation Costs | [1] | 849,319 | 972,176 | 853,044 |
Production Costs | [1] | 1,581,131 | 2,150,027 | 1,706,222 |
Impairments | [1] | 6,613,546 | 743,575 | 286,941 |
Depreciation, Depletion and Amortization | [1] | 3,190,443 | 3,881,720 | 3,498,010 |
Income (Loss) Before Income Taxes | [1] | (5,947,512) | 4,666,785 | 4,231,935 |
Income Tax Provision (Benefit) | [1] | (2,086,555) | 1,821,104 | 1,490,532 |
Results of Operations | [1] | (3,860,957) | 2,845,681 | 2,741,403 |
United States | ||||
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | ||||
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues | [1] | 5,962,753 | 11,771,777 | 9,897,701 |
Other | [1] | 47,464 | 49,950 | 51,713 |
Total | [1] | 6,010,217 | 11,821,727 | 9,949,414 |
Exploration Costs | [1] | 139,753 | 162,434 | 141,286 |
Dry Hole Costs | [1] | 956 | 25,408 | 14,276 |
Transportation Costs | [1] | 838,428 | 957,522 | 841,567 |
Production Costs | [1] | 1,486,189 | 1,940,074 | 1,494,791 |
Impairments | [1] | 6,402,908 | 331,792 | 178,718 |
Depreciation, Depletion and Amortization | [1] | 3,017,386 | 3,571,313 | 3,122,858 |
Income (Loss) Before Income Taxes | [1] | (5,875,403) | 4,833,184 | 4,155,918 |
Income Tax Provision (Benefit) | [1] | (2,128,183) | 1,722,914 | 1,486,445 |
Results of Operations | [1] | (3,747,220) | 3,110,270 | 2,669,473 |
Trinidad | ||||
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | ||||
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues | [1] | 381,761 | 512,675 | 517,482 |
Other | [1] | (3) | 37 | 24 |
Total | [1] | 381,758 | 512,712 | 517,506 |
Exploration Costs | [1] | 2,071 | 2,185 | 2,345 |
Dry Hole Costs | [1] | 5,635 | 0 | 4,478 |
Transportation Costs | [1] | 1,290 | 617 | 659 |
Production Costs | [1] | 28,862 | 38,301 | 43,279 |
Impairments | [1] | 0 | 0 | 14,274 |
Depreciation, Depletion and Amortization | [1] | 154,588 | 188,250 | 181,637 |
Income (Loss) Before Income Taxes | [1] | 189,312 | 283,359 | 270,834 |
Income Tax Provision (Benefit) | [1] | 43,739 | 74,588 | 103,313 |
Results of Operations | [1] | 145,573 | 208,771 | 167,521 |
Other International | ||||
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | ||||
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues | [1],[2] | 58,744 | 308,465 | 340,463 |
Other | [1],[2] | 448 | 4,257 | 4,770 |
Total | [1],[2] | 59,192 | 312,722 | 345,233 |
Exploration Costs | [1],[2] | 7,670 | 19,769 | 17,715 |
Dry Hole Costs | [1],[2] | 8,155 | 23,082 | 55,901 |
Transportation Costs | [1],[2] | 9,601 | 14,037 | 10,818 |
Production Costs | [1],[2] | 66,080 | 171,652 | 168,152 |
Impairments | [1],[2] | 210,638 | 411,783 | 93,949 |
Depreciation, Depletion and Amortization | [1],[2] | 18,469 | 122,157 | 193,515 |
Income (Loss) Before Income Taxes | [1],[2] | (261,421) | (449,758) | (194,817) |
Income Tax Provision (Benefit) | [1],[2] | (2,111) | 23,602 | (99,226) |
Results of Operations | [1],[2] | $ (259,310) | $ (473,360) | $ (95,591) |
[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, 2015. | |||
[2] | Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. |
Oil and Gas Exploration and P62
Oil and Gas Exploration and Production Industries Disclosures, Average Sales Price (Details) - $ / bbl | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ||||
Production costs per barrel of oil equivalent | 5.85 | 6.46 | 5.88 | |
United States | ||||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ||||
Production costs per barrel of oil equivalent | 5.81 | 6.44 | 5.78 | |
Trinidad | ||||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ||||
Production costs per barrel of oil equivalent | 1.29 | 1.34 | 1.36 | |
Other International | ||||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ||||
Production costs per barrel of oil equivalent | [1] | 33.78 | 24.60 | 20.40 |
[1] | Other International primarily consists of EOG's United Kingdom, China, Canada and Argentina operations. |
Oil and Gas Exploration and P63
Oil and Gas Exploration and Production Industries Disclosures, Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands | 12 Months Ended | |||||||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |||||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||||||||
Future cash inflows | $ 68,720,648 | $ 146,950,221 | $ 123,999,499 | |||||||
Future production costs | (32,060,855) | (51,633,293) | (50,166,488) | |||||||
Future development costs | (15,785,811) | (20,494,765) | (18,549,351) | |||||||
Future income taxes | (4,616,201) | (23,185,714) | (16,416,387) | |||||||
Future net cash flows | 16,257,781 | 51,636,449 | 38,867,273 | |||||||
Discount to present value at 10% annual rate | (6,636,385) | (23,713,031) | (17,533,841) | |||||||
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves | $ 27,923,418 | $ 21,333,432 | $ 16,915,472 | 9,621,396 | 27,923,418 | 21,333,432 | ||||
Annual Rate of Discount to Present Value | 10.00% | 10.00% | 10.00% | |||||||
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward] | ||||||||||
Balance at Beginning of Period | $ 27,923,418 | $ 21,333,432 | $ 16,915,472 | |||||||
Sales and transfers of oil and gas produced, net of production costs | (4,020,717) | (9,470,714) | (8,196,380) | |||||||
Net changes in prices and production costs | (30,669,350) | 1,263,177 | 1,257,853 | |||||||
Extensions, discoveries, additions and improved recovery, net of related costs | 1,095,898 | 8,083,852 | 5,483,432 | |||||||
Development costs incurred | 2,137,700 | 2,835,100 | 2,955,900 | |||||||
Revisions of estimated development cost | 4,079,381 | 1,802,735 | 990,396 | |||||||
Revisions of previous quantity estimates | (4,051,874) | 1,812,532 | 1,794,198 | |||||||
Accretion of discount | 3,857,479 | 2,833,350 | 2,133,729 | |||||||
Net change in income taxes | 9,728,423 | (3,651,300) | (2,578,250) | |||||||
Purchases of reserves in place | 123,542 | 317,785 | 66,359 | |||||||
Sales of reserves in place | (37,088) | (478,879) | (140,652) | |||||||
Changes in timing and other | (545,416) | 1,242,348 | 651,375 | |||||||
Balance at End of Period | 9,621,396 | 27,923,418 | 21,333,432 | |||||||
United States | ||||||||||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||||||||
Future cash inflows | 67,242,928 | [1] | 144,355,692 | [2] | 119,644,713 | [3] | ||||
Future production costs | (31,707,743) | (51,112,604) | (49,099,393) | |||||||
Future development costs | (15,579,923) | (20,270,439) | (17,753,860) | |||||||
Future income taxes | (4,400,542) | (22,725,618) | (15,763,089) | |||||||
Future net cash flows | 15,554,720 | 50,247,031 | 37,028,371 | |||||||
Discount to present value at 10% annual rate | (6,589,253) | (23,542,990) | (17,451,470) | |||||||
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves | 26,704,041 | 19,576,901 | 15,181,334 | 8,965,467 | 26,704,041 | 19,576,901 | ||||
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 | 26,704,041 | 19,576,901 | 15,181,334 | |||||||
Sales and transfers of oil and gas produced, net of production costs | (3,685,600) | (8,874,180) | (7,561,343) | |||||||
Net changes in prices and production costs | (29,993,699) | 1,481,668 | 1,734,058 | |||||||
Extensions, discoveries, additions and improved recovery, net of related costs | 1,028,410 | 8,074,550 | 5,449,531 | |||||||
Development costs incurred | 2,135,800 | 2,818,800 | 2,792,400 | |||||||
Revisions of estimated development cost | 4,087,093 | 1,696,916 | 892,803 | |||||||
Revisions of previous quantity estimates | (4,084,572) | 1,741,918 | 1,887,062 | |||||||
Accretion of discount | 3,699,330 | 2,612,286 | 1,895,503 | |||||||
Net change in income taxes | 9,550,847 | (3,743,300) | (2,772,267) | |||||||
Purchases of reserves in place | 123,542 | 317,785 | 66,359 | |||||||
Sales of reserves in place | (23,424) | (189,808) | (140,652) | |||||||
Changes in timing and other | (576,301) | 1,190,505 | 152,113 | |||||||
Balance at End of Period | 8,965,467 | 26,704,041 | 19,576,901 | |||||||
Trinidad | ||||||||||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||||||||
Future cash inflows | 954,779 | [1] | 1,615,280 | [2] | 2,082,195 | [3] | ||||
Future production costs | (183,607) | (277,844) | (315,483) | |||||||
Future development costs | (140,541) | (84,576) | (112,050) | |||||||
Future income taxes | (215,659) | (460,096) | (603,786) | |||||||
Future net cash flows | 414,972 | 792,764 | 1,050,876 | |||||||
Discount to present value at 10% annual rate | (33,848) | (110,228) | (174,236) | |||||||
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves | 682,536 | 876,640 | 961,070 | 381,124 | 682,536 | 876,640 | ||||
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 | 682,536 | 876,640 | 961,070 | |||||||
Sales and transfers of oil and gas produced, net of production costs | (351,606) | (473,757) | (473,544) | |||||||
Net changes in prices and production costs | (370,503) | (12,079) | (12,050) | |||||||
Extensions, discoveries, additions and improved recovery, net of related costs | 47,613 | 3,113 | 0 | |||||||
Development costs incurred | 500 | 12,800 | 67,100 | |||||||
Revisions of estimated development cost | (34,647) | 9,981 | (3,539) | |||||||
Revisions of previous quantity estimates | 33,285 | 35,001 | (60,419) | |||||||
Accretion of discount | 104,464 | 133,019 | 147,099 | |||||||
Net change in income taxes | 177,576 | 91,438 | 56,373 | |||||||
Purchases of reserves in place | 0 | 0 | 0 | |||||||
Sales of reserves in place | 0 | 0 | 0 | |||||||
Changes in timing and other | 91,906 | 6,380 | 194,550 | |||||||
Balance at End of Period | 381,124 | 682,536 | 876,640 | |||||||
Other International (1) | ||||||||||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||||||||
Future cash inflows | [4] | 522,941 | [1] | 979,249 | [2] | 2,272,591 | [3] | |||
Future production costs | [4] | (169,505) | (242,845) | (751,612) | ||||||
Future development costs | [4] | (65,347) | (139,750) | (683,441) | ||||||
Future income taxes | [4] | 0 | 0 | (49,512) | ||||||
Future net cash flows | [4] | 288,089 | 596,654 | 788,026 | ||||||
Discount to present value at 10% annual rate | [4] | (13,284) | (59,813) | 91,865 | ||||||
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves | [4] | 536,841 | 879,891 | 773,068 | $ 274,805 | $ 536,841 | $ 879,891 | |||
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward] | ||||||||||
Balance at Beginning of Period | [4] | 536,841 | 879,891 | 773,068 | ||||||
Sales and transfers of oil and gas produced, net of production costs | [4] | 16,489 | (122,777) | (161,493) | ||||||
Net changes in prices and production costs | [4] | (305,148) | (206,412) | (464,155) | ||||||
Extensions, discoveries, additions and improved recovery, net of related costs | [4] | 19,875 | 6,189 | 33,901 | ||||||
Development costs incurred | [4] | 1,400 | 3,500 | 96,400 | ||||||
Revisions of estimated development cost | [4] | 26,935 | 95,838 | 101,132 | ||||||
Revisions of previous quantity estimates | [4] | (587) | 35,613 | (32,445) | ||||||
Accretion of discount | [4] | 53,685 | 88,045 | 91,127 | ||||||
Net change in income taxes | [4] | 0 | 562 | 137,644 | ||||||
Purchases of reserves in place | [4] | 0 | 0 | 0 | ||||||
Sales of reserves in place | [4] | (13,664) | (289,071) | 0 | ||||||
Changes in timing and other | [4] | (61,021) | 45,463 | 304,712 | ||||||
Balance at End of Period | [4] | $ 274,805 | $ 536,841 | $ 879,891 | ||||||
[1] | Estimated crude oil prices used to calculate 2015 future cash inflows for the United States, Trinidad and Other International were $49.58, $38.83 and $47.76, respectively. Estimated NGL price used to calculate 2015 future cash inflows for the United States was $15.17. Estimated natural gas prices used to calculate 2015 future cash inflows for the United States, Trinidad and Other International were $2.15, $2.88 and $5.60, respectively. | |||||||||
[2] | Estimated crude oil prices used to calculate 2014 future cash inflows for the United States, Trinidad and Other International were $97.51, $80.60 and $94.09, respectively. Estimated NGL prices used to calculate 2014 future cash inflows for the United States and Other International were $34.29 and $27.03, respectively. Estimated natural gas prices used to calculate 2014 future cash inflows for the United States, Trinidad and Other International were $3.71, $3.71 and $5.14, respectively. | |||||||||
[3] | Estimated crude oil prices used to calculate 2013 future cash inflows for the United States, Trinidad and Other International were $105.91, $94.30 and $98.85, respectively. Estimated NGL prices used to calculate 2013 future cash inflows for the United States and Other International were $29.42 and $40.88, respectively. Estimated natural gas prices used to calculate 2013 future cash inflows for the United States, Trinidad and Other International were $3.50, $3.71 and $3.45, respectively | |||||||||
[4] | Other International includes EOG's United Kingdom, China, Canada and Argentina operations. |
Unaudited Quarterly Financial64
Unaudited Quarterly Financial Information (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||||||||||||
Quarterly Financial Information Disclosure [Abstract] | ||||||||||||||||||||||
Net Operating Revenues | $ 1,796,761 | $ 2,172,428 | $ 2,469,701 | $ 2,318,538 | $ 4,645,497 | $ 5,118,616 | $ 4,187,556 | $ 4,083,671 | $ 8,757,428 | [1] | $ 18,035,340 | [2] | $ 14,487,118 | [3] | ||||||||
Operating Income | (329,753) | (6,222,957) | 39,626 | (172,995) | 1,226,652 | 1,786,162 | 1,144,730 | 1,084,279 | (6,686,079) | 5,241,823 | 3,675,211 | |||||||||||
Income (Loss) Before Income Taxes | (398,826) | (6,274,921) | (11,478) | (236,331) | 1,148,593 | 1,715,120 | 1,100,813 | 1,030,789 | (6,921,556) | 4,995,315 | 3,436,886 | |||||||||||
Income Tax Provision | (114,530) | (2,199,182) | (16,746) | (66,583) | 704,005 | 611,502 | 394,460 | 369,861 | (2,397,041) | 2,079,828 | 1,239,777 | |||||||||||
Net Income (Loss) | $ (284,296) | $ (4,075,739) | $ 5,268 | $ (169,748) | $ 444,588 | $ 1,103,618 | $ 706,353 | $ 660,928 | $ (4,524,515) | $ 2,915,487 | $ 2,197,109 | |||||||||||
Net Income (Loss) Per Share | ||||||||||||||||||||||
Basic (in dollars per share) | $ (0.52) | [4] | $ (7.47) | [4] | $ 0.01 | [4] | $ (0.31) | [4] | $ 0.82 | [4] | $ 2.03 | [4] | $ 1.30 | [4] | $ 1.22 | [4] | $ (8.29) | $ 5.36 | $ 4.07 | |||
Diluted (in dollars per share) | $ (0.52) | [4] | $ (7.47) | [4] | $ 0.01 | [4] | $ (0.31) | [4] | $ 0.81 | [4] | $ 2.01 | [4] | $ 1.29 | [4] | $ 1.21 | [4] | $ (8.29) | $ 5.32 | $ 4.02 | |||
Average Number of Common Shares [Abstract] | ||||||||||||||||||||||
Basic (in shares) | 546,432 | 545,920 | 545,504 | 544,998 | 544,579 | 543,984 | 543,099 | 542,278 | 545,697 | 543,443 | 540,341 | |||||||||||
Diluted (in shares) | 546,432 | 545,920 | 549,683 | 544,998 | 549,153 | 549,518 | 548,676 | 548,071 | 545,697 | 548,539 | 546,227 | |||||||||||
[1] | EOG had sales activity with two significant purchasers in 2015, one totaling $1.7 billion and the other totaling $1.4 billion of consolidated Net Operating Revenues in the United States segment. | |||||||||||||||||||||
[2] | EOG had sales activity with two significant purchasers in 2014, one totaling $4.0 billion and the other totaling $3.0 billion of consolidated Net Operating Revenues in the United States segment. | |||||||||||||||||||||
[3] | EOG had sales activity with two significant purchasers in 2013, one totaling $3.9 billion and the other totaling $2.0 billion of consolidated Net Operating Revenues in the United States segment. | |||||||||||||||||||||
[4] | 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. |