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Document and Entity Information $ in Millions	12 Months Ended
Document and Entity Information $ in Millions	Dec. 31, 2011 USD ($) shares
Document and Entity Information [Abstract]
Document Type	10-K
Document Period End Date	Dec. 31, 2011
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2011
Amendment Flag	false
Entity Registrant Name	Marathon Oil Corporation
Entity Central Index Key	0000101778
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Well Known Seasoned Issuer	Yes
Entity Common Stock Shares Outstanding \| shares	703,925,642
Entity Public Float \| $	$ 22,773

Consolidated Statements of Income - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Revenues and other income:
Sales and other operating revenues	$ 14,603	$ 11,634	$ 8,465
Sales to related parties	60	56	59
Income (loss) from equity method investments	462	344	268
Net gain on disposal of assets	103	766	202
Other income	54	73	90
Total revenues and other income	15,282	12,873	9,084
Costs and expenses:
Cost of revenues (excludes items below)	6,225	4,786	3,170
Purchases from related parties	250	172	146
Depreciation, depletion and amortization	2,266	2,056	1,934
Impairments	310	447	18
General and administrative expenses	544	491	451
Other taxes	230	199	173
Exploration expenses	644	498	307
Total costs and expenses	10,469	8,649	6,199
Income from operations	4,813	4,224	2,885
Net interest and other	(107)	(75)	(122)
Loss on early extinguishment of debt	(279)	(92)	0
Income from continuing operations before income taxes	4,427	4,057	2,763
Provision for income taxes	2,720	2,175	2,047
Income from continuing operations	1,707	1,882	716
Discontinued operations	1,239	686	747
Net income	$ 2,946	$ 2,568	$ 1,463
Basic:
Income from continuing operations, per basic share	$ 2.40	$ 2.65	$ 1.01
Discontinued operations, per basic share	1.75	0.97	1.05
Net income, per basic share	4.15	3.62	2.06
Diluted:
Income from continuing operations, per diluted share	2.39	2.65	1.01
Discontinued operations, per diluted share	1.74	0.96	1.05
Net income, per diluted share	4.13	3.61	2.06
Dividends paid, per share	$ 0.80	$ 0.99	$ 0.96
Weighted average common shares outstanding, basic	710	710	709
Weighted average common shares outstanding, diluted	714	712	711

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Consolidated Statements of Comprehensive Income
Net income	$ 2,946	$ 2,568	$ 1,463
Post retirement and post employment plans
Change in actuarial loss	16	(76)	(564)
Spin off downstream business	968
Income tax benefit on post retirement and post employment plans	(357)	7	208
Post retirement and post-employment plans, net of tax	627	(69)	(356)
Derivative hedges
Net unrecognized gain (loss)	9	5	24
Spin off downstream business	(7)
Income tax benefit (provision) on derivatives hedges	(1)	1	(12)
Derivative hedges, net of tax	1	6	12
Foreign currency translation and other
Unrealized gain (loss)	(1)	0	4
Income tax benefit (provision) on foreign currency translation and other	0	0	(1)
Foreign currency translation and other, net of tax	(1)	0	3
Other comprehensive income (loss)	627	(63)	(341)
Comprehensive income	$ 3,573	$ 2,505	$ 1,122

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Current assets:
Cash and cash equivalents	$ 493	$ 3,951
Receivables, less allowance for doubtful accounts of $0 and $7	1,917	5,972
Receivables from related parties	35	58
Inventories	361	3,453
Prepayments	96	92
Deferred tax assets, current	99
Other current assets	223	303
Total current assets	3,224	13,829
Equity method investments	1,383	1,802
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $17,248 and $19,805	25,324	32,222
Goodwill	536	1,380
Other noncurrent assets	904	781
Total assets	31,371	50,014
Current liabilities:
Accounts payable	1,864	8,000
Payables to related parties	18	49
Payroll and benefits payable	193	418
Accrued taxes	2,015	1,447
Deferred tax liabilities, current	5	324
Other current liabilities	158	580
Long-term debt due within one year	141	295
Total current liabilities	4,394	11,113
Long-term debt	4,674	7,601
Deferred tax liabilities, noncurrent	2,544	3,569
Defined benefit postretirement plan obligations	789	2,171
Asset retirement obligations	1,510	1,354
Deferred credits and other liabilities, noncurrent	301	435
Total liabilities	14,212	26,243
Stockholders' Equity
Preferred stock no shares issued oroutstanding (no par value, 26 million shares authorized)	0	0
Common stock issued - 770 million and 770 million shares (par value $1 per share, 1.1 billion shares authorized)	770	770
Common stock, securities exchangeable into common stock - no shares issued or outstanding (no par value, 29 million shares authorized)	0	0
Held in treasury, at cost - 66 million and 60 million shares	(2,716)	(2,665)
Additional paid-in capital	6,680	6,756
Retained earnings	12,788	19,907
Accumulated other comprehensive loss	(370)	(997)
Noncontrolling interest	7	0
Total equity of Marathon Oil stockholders	17,152	23,771
Total stockholders' equity	17,159	23,771
Total liabilities and stockholders' equity	$ 31,371	$ 50,014

Consolidated Balance Sheets Parentheticals - USD ($) shares in Millions, $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Consolidated Balance Sheets Parenthetical [Abstract]
Allowance for doubtful accounts	$ 0	$ (7)
Less accumulated depreciation, depletion and amortization	$ (17,248)	$ (19,805)
Preferred stock, no par value	$ 0	$ 0
Preferred stock shares authorized	26	26
Preferred stock shares issued	0	0
Preferred stock shares outstanding	0	0
Common stock, par value per share	$ 1	$ 1
Common stock shares authorized	1,100	1,100
Common stock, shares issued	770	770
Common stock, securities exchangeable, no par value	$ 0	$ 0
Common stock, securities exchangeable, shares authorized	29	29
Common stock, securities exchangeable, shares issued	0	0
Common stock, securities exchangeable, shares outstanding	0	0
Held in treasury, shares	66	60

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Net cash provided by continuing operatons:
Net income	$ 2,946	$ 2,568	$ 1,463
Adjustments to reconcile net income to net cash provided by operating activities:
Discontinued operations	(1,239)	(686)	(747)
Loss on early extinguishment of debt	279	92	0
Deferred income taxes	(182)	(489)	546
Depreciation, depletion and amortization	2,266	2,056	1,934
Impairments	310	447	18
Pension and other postretirement benefits, net	64	31	(17)
Exploratory dry well costs and unproved property impairments	357	225	81
Net gain on disposal of assets	(103)	(766)	(202)
Equity method investments, net	47	56	34
Changes in operating capital:
Changes in current receivables	8	(409)	(188)
Changes in inventories	33	(71)	(104)
Changes in current accounts payable and accrued liabilities	485	1,018	308
All other operating, net	163	122	46
Net cash provided by continuing operations	5,434	4,194	3,172
Net cash provided by discontinued operations	1,090	1,676	2,096
Net cash provided by operating activities	6,524	5,870	5,268
Investing activities:
Acquisitions	(4,470)
Additions to property, plant and equipment	(3,295)	(3,536)	(3,349)
Disposal of assets	518	1,368	812
Investments - return of capital	59	58	59
Investing activities of discontinued operations	(493)	(464)	(2,879)
All other investing, net	14	(47)	119
Net cash used in investing activities	(7,667)	(2,621)	(5,238)
Financing activities:
Borrowings	0	0	1,491
Debt issuance costs	0	0	(11)
Debt repayments	(2,877)	(653)	(68)
Purchases of common stock	(300)	0	0
Issuance of common stock	77	12	4
Dividends paid	(567)	(704)	(679)
Financing activities of discontinued operations	2,916	(12)	(13)
Distribution in spin off	(1,622)
All other financing, net	78	2	0
Net cash provided by (used in) financing activities	(2,295)	(1,355)	724
Effect of exchange rate changes on cash:
Total effect of exchange rate changes on cash	(20)	0	18
Net increase (decrease) in cash and cash equivalents	(3,458)	1,894	772
Cash and cash equivalents at beginning of period	3,951	2,057	1,285
Cash and cash equivalents at end of period	$ 493	$ 3,951	$ 2,057

Consolidated Statements of Stockholders Equity - USD ($) shares in Millions, $ in Millions	Total	Preferred Stock [Member]	Common Stock [Member]	Common Stock Securities Exchangable [Member]	Treasury Stock [Member]	Additional Paid In Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interest
Balance as of at Dec. 31, 2008	$ 21,409	$ 0	$ 767	$ 0	$ (2,720)	$ 6,696	$ 17,259	$ (593)	$ 0
Shares Balance as of at Dec. 31, 2008		3	767	3	(61)
Shares issued - stock based compensation	11				$ 20	(9)
Shares exchanged	0		$ 2			(2)
Shares exchanged, shares		(2)	2	(2)
Shares repurchased	(6)				(6)
Stock-based compensation	53					53
Net income	1,463						1,463
Other comprehensive loss	(341)							(341)
Dividends paid	(679)						(679)
Balance as of at Dec. 31, 2009	21,910	$ 0	$ 769	$ 0	$ (2,706)	6,738	18,043	(934)	0
Shares Balance as of at Dec. 31, 2009		1	769	1	(61)
Shares issued - stock based compensation	34				$ 46	(12)
Shares issued - stock based compensation, shares					1
Shares exchanged	0		$ 1			(1)
Shares exchanged, shares		(1)	1	(1)
Shares repurchased	(5)				$ (5)
Stock-based compensation	31					31
Net income	2,568						2,568
Other comprehensive loss	(63)							(63)
Dividends paid	(704)						(704)
Balance as of at Dec. 31, 2010	23,771	$ 0	$ 770	$ 0	$ (2,665)	6,756	19,907	(997)	0
Shares Balance as of at Dec. 31, 2010		0	770	0	(60)
Shares issued - stock based compensation	172				$ 257	(85)
Shares issued - stock based compensation, shares					6
Shares repurchased	$ (308)				$ (308)
Shares repurchased, shares	12				12
Stock-based compensation	$ 4					4
Net income	2,946						2,946
Other comprehensive loss	40							40
Dividends paid	(567)						(567)
Balance as of at Dec. 31, 2011	17,159	$ 0	$ 770	$ 0	$ (2,716)	6,680	12,788	(370)	7
Shares Balance as of at Dec. 31, 2011		0	770	0	(66)
Purchase of subsidiary shares from noncontrolling interest	7								$ 7
Distribution related to spin-off of downstream business	$ (8,906)					$ 5	$ (9,498)	$ 587

Summary of Principal Accounting Policies

12 Months Ended

Dec. 31, 2011

Accounting Policies [Abstract]

Significant Accounting Policies

1. Summary of Principal Accounting Policies

We are engaged in worldwide exploration, production and marketing of liquid hydrocarbons and natural gas; oil sands mining and bitumen transportation and upgrading in Canada; and production and marketing of products manufactured from natural gas, such as LNG and methanol in EG.

Principles applied in consolidation - These consolidated financial statements include the accounts of our majority-owned, controlled subsidiaries and variable interest entities for which we are the primary beneficiary.

Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting. This includes entities in which we hold majority ownership but the minority shareholders have substantive participating rights in the investee. Income from equity method investments represents our proportionate share of net income generated by the equity method investees.

Equity method investments are carried at our share of net assets plus loans and advances. Such investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other than temporary. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in net income. Differences in the basis of the investments and the separate net asset value of the investees, if any, are amortized into net income over the remaining useful lives of the underlying assets, except for the excess related to goodwill.

Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis.

As a result of the spin-off of our downstream business (see Note 3), the results of operations and cash flows for the downstream business have been classified as discontinued operations for all periods presented. The disclosures in this report related to results of operations and cash flows are presented on the basis of continuing operations unless otherwise stated.

Environmental costs - Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. We provide for remediation costs and penalties when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. The timing of remediation accruals coincides with completion of a feasibility study or the commitment to a formal plan of action. Remediation liabilities are accrued based on estimates of known environmental exposure and are discounted when the estimated amounts are reasonably fixed and determinable.

Asset retirement obligations - The fair value of asset retirement obligations is recognized in the period in which the obligations are incurred if a reasonable estimate of fair value can be made. Our asset retirement obligations primarily relate to the abandonment of oil and gas producing facilities, which include our bitumen mining facilities. Asset retirement obligations for such facilities include costs to dismantle and relocate or dispose of production platforms, mine assets, gathering systems, wells and related structures and restoration costs of land and seabed, including those leased. Estimates of these costs are developed for each property based on the type of production structure, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering professionals. Asset retirement obligations have not been recognized for certain of our international oil and gas producing facilities as we currently do not have a legal obligation associated with the retirement of those facilities. Asset retirement obligations have not been recognized for the removal of materials and equipment from or the closure of certain bitumen upgrading assets because the fair value cannot be reasonably estimated since the settlement dates of the obligations are indeterminate.

Current inflation rates and credit-adjusted-risk-free interest rates are used to estimate the fair value of asset retirement obligations. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is generally determined on a units-of-production basis for oil and gas production facilities, which include our bitumen mining facilities, while accretion escalates over the lives of the assets.

Deferred income taxes - Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax bases as reported in our filings with the respective taxing authorities. Deferred tax assets are recorded when it is more likely than not that they will be realized. The realization of deferred tax assets is assessed periodically based on several interrelated factors. These factors include our expectation to generate sufficient future taxable income including future foreign source income, tax credits, operating loss carryforwards and management's intent regarding the permanent reinvestment of the income from certain foreign subsidiaries.

Stock based compensation arrangements - The fair value of stock options, stock options with tandem stock appreciation rights (“SARs”) and stock-settled SARs (“stock option awards”) is estimated on the date of grant using the Black-Scholes option pricing model. The model employs various assumptions, based on management's best estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the life of the stock option award. Of the required assumptions, the expected life of the stock option award and the expected volatility of our stock price have the most significant impact on the fair value calculation. We have utilized historical data and analyzed current information which reasonably support these assumptions.

The fair value of our restricted stock awards and common stock units is determined based on the fair market value of our common stock on the date of grant.

Our stock-based compensation expense is recognized based on management's best estimate of the awards that are expected to vest, using the straight-line attribution method for all service-based awards with a graded vesting feature. If actual forfeiture results are different than expected, adjustments to recognized compensation expense may be required in future periods. Unearned stock-based compensation is charged to stockholders' equity when restricted stock awards are granted. Compensation expense is recognized over the vesting period and is adjusted if conditions of the restricted stock award are not met. Options with tandem SARs are classified as a liability and are remeasured at fair value each reporting period until settlement.

Derivatives not designated as hedges - Derivatives that are not designated as hedges may include commodity derivatives used primarily to manage price risk on the forecasted sale of crude oil, natural gas and synthetic crude oil that we produce. Changes in the fair value of derivatives not designated as hedges are recognized immediately in net income.

Concentrations of credit risk - All of our financial instruments, including derivatives, involve elements of credit and market risk. The most significant portion of our credit risk relates to nonperformance by counterparties. The counterparties to our financial instruments consist primarily of major financial institutions and companies within the energy industry. To manage counterparty risk associated with financial instruments, we select and monitor counterparties based on our assessment of their financial strength and on credit ratings, if available. Additionally, we limit the level of exposure with any single counterparty.

Property, plant and equipment - We use the successful efforts method of accounting for oil and gas producing activities, which include our bitumen mining and upgrading.

Property acquisition costs - Costs to acquire mineral interests in traditional oil and natural gas properties or in oil sands mines, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells and to construct or expand oil sand mines and upgrading facilities are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves but cannot yet be classified as proved are capitalized if (1) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (2) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. The status of suspended well costs is monitored continuously and reviewed at least quarterly.

Depreciation, depletion and amortization - Capitalized costs to acquire oil and natural gas properties, which include our bitumen mining and upgrading facilities, are depreciated and depleted on a units-of-production basis based on estimated proved reserves. Capitalized costs of exploratory wells and development costs are depreciated and depleted on a units-of-production basis based on estimated proved developed reserves. Support equipment and other property, plant and equipment related to oil and gas producing activities are depreciated on a straight-line basis over their estimated useful lives which range from 3 to 43 years.

Property, plant and equipment unrelated to oil and gas producing activities is recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets, which range from 3 to 40 years.

Impairments - We evaluate our oil and gas producing properties, including capitalized costs of exploratory wells, development costs and our bitumen mining and upgrading facilities, for impairment of value whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. Oil and gas producing properties are reviewed for impairment on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure. Impairment of proved properties is required when the carrying value exceeds the related undiscounted future net cash flows based on proved and probable reserves. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows or, if available, comparable market value. We evaluate our unproved property investment and record impairment based on time or geologic factors in addition to the use of an undiscounted future net cash flow approach. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage are also considered. Unproved property investments deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows. Impairment expense for unproved oil and natural gas properties is reported in exploration expenses.

Dispositions - When property, plant and equipment depreciated on an individual basis are sold or otherwise disposed of, any gains or losses are reported in net income. Gains on the disposal of property, plant and equipment are recognized when earned, which is generally at the time of closing. If a loss on disposal is expected, such losses are recognized when the assets are classified as held for sale. Proceeds from the disposal of property, plant and equipment depreciated on a group basis are credited to accumulated depreciation, depletion and amortization with no immediate effect on net income until net book value is reduced to zero.

Goodwill - Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Such goodwill is not amortized, but rather is tested for impairment annually and when events or changes in circumstances indicate that the fair value of a reporting unit with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then the recorded goodwill is impaired to its implied fair value with a charge to operating expense.

Major maintenance activities - Costs for planned major maintenance are expensed in the period incurred. These types of costs include contractor repair services, materials and supplies, equipment rentals and our labor costs.

Use of estimates - The preparation of financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods.

Foreign currency transactions - The U.S. dollar is the functional currency of our foreign operating subsidiaries. Foreign currency transaction gains and losses are included in net income.

Revenue recognition - Revenues are recognized when products are shipped or services are provided to customers, title is transferred, the sales price is fixed or determinable and collectability is reasonably assured. Costs associated with revenues are recorded in cost of revenues.

In the lower 48 states of the U.S., production volumes of liquid hydrocarbons and natural gas are sold immediately and transported to market. In Alaska and international locations, liquid hydrocarbon and natural gas production volumes may be stored as inventory and sold at a later time. In Canada, mined bitumen is first processed through an upgrader and then sold as synthetic crude oil. Both bitumen and synthetic crude oil may be stored as inventory.

We follow the sales method of accounting for crude oil and natural gas production imbalances and would recognize a liability if our existing proved reserves were not adequate to cover an imbalance. Imbalances have not been significant in the periods presented.

Cash and cash equivalents - Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with original maturities of three months or less.

Accounts receivable - The majority of our receivables are from joint interest owners in properties we operate, or purchasers of liquid hydrocarbons, are recorded at invoiced amounts and do not bear interest. We determine the allowance for doubtful accounts based on historical write-off experience. Past-due balances over 180 days are reviewed individually for collectability..

Inventories - Inventories are carried at the lower of cost or market value. The majority of our inventories are recorded at average cost. The last-in, first-out (“LIFO”) method is used for domestic natural gas inventory.

We may enter into a contract to sell a particular quantity and quality of crude oil at a specified location and date to a particular counterparty, and simultaneously agree to buy a particular quantity and quality of the same commodity at a specified location on the same or another specified date from the same counterparty. We account for such matching buy/sell arrangements as exchanges of inventory.

Derivative instruments - We may use derivatives to manage a portion of our exposure to commodity price risk, interest rate risk and foreign currency exchange rate risk. All derivative instruments are recorded at fair value. Commodity derivatives are reflected on our consolidated balance sheet on a net basis by brokerage firm, as they are governed by master netting agreements. Cash flows related to derivatives used to manage commodity price risk, interest rate risk and foreign currency exchange rate risk related to operating expenditures are classified in operating activities with the underlying transactions. Cash flows related to derivatives used to manage exchange rate risk related to capital expenditures denominated in foreign currencies are classified in investing activities with the underlying transactions. Our derivative instruments contain no significant contingent credit features.

Cash flow hedges - We may use foreign currency forwards and options to manage foreign currency risk associated with anticipated transactions, primarily expenditures for capital projects denominated in certain foreign currencies, and designate them as cash flow hedges. The effective portion of changes in fair value is recognized in other comprehensive income (“OCI”) and is reclassified to net income when the underlying forecasted transaction is recognized in net income. Any ineffective portion is recognized in net interest and other as it occurs. For a discontinued cash flow hedge, prospective changes in the fair value of the derivative are recognized in net income. The accumulated gain or loss recognized in OCI at the time a hedge is discontinued continues to be deferred until the original forecasted transaction occurs. However, if it is determined that the likelihood of the original forecasted transaction occurring is no longer probable, the entire accumulated gain or loss recognized in OCI is immediately reclassified into net income.

We may use interest rate derivative instruments to manage the risk of interest rate changes during the period prior to anticipated borrowings and designate them as cash flow hedges. No such derivatives were outstanding at December 31, 2011 and 2010.

Fair value hedges - We may use interest rate swaps to manage our exposure to interest rate risk associated with fixed interest rate debt in our portfolio and we may use commodity derivative instruments to manage the price risk on natural gas that we purchase to be marketed with our natural gas production. Changes in the fair values of both the hedged item and the related derivative are recognized immediately in net income with an offsetting effect included in the basis of the hedged item. The net effect is to report in net income the extent to which the hedge is not effective in achieving offsetting changes in fair value.

Accounting Standards

12 Months Ended

Dec. 31, 2011

Accounting Standards Disclosure [Abstract]

Accounting Standards

2. Accounting Standards

Not Yet Adopted

The FASB and the IASB issued joint disclosure requirements in December 2011 designed to enhance disclosures about offsetting assets and liabilities that will enable financial statement users to evaluate the effect or potential effect of netting arrangements on an entity's financial position. Entities are required to disclose both gross information and net information about financial instruments and derivative instruments that are either offset in the statement of financial position or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset. These disclosures are effective for us beginning the first quarter of 2013 and must be made retrospectively for comparable periods. Adoption of this amendment will not have a significant impact on our consolidated results of operations, financial position or cash flows.

In September 2011, the FASB amended accounting standards to simplify how entities test goodwill for impairment. The amendment reduces complexity by allowing an entity the option to make a qualitative evaluation of whether it is necessary to perform the two-step goodwill impairment test. The amendment is effective for our interim and annual periods beginning with the first quarter of 2012. Early adoption is permitted, but we were unable to do so because our 2011 annual goodwill impairment testing was completed prior to the issuance of the amendment. Adoption of this amendment will not have a significant impact on our consolidated results of operations, financial position or cash flows.

The FASB amended the reporting standards for comprehensive income in June 2011 to eliminate the option to present the components of OCI as part of the statement of changes in stockholders' equity. All non-owner changes in stockholders' equity are required to be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In the two statement approach, the first statement should present total net income and its components followed consecutively by a second statement that should present total other comprehensive income, the components of OCI, and the total of comprehensive income. The presentation of items that are reclassified from OCI to net income on the income statement is also required. The amendments did not change the items that must be reported in OCI or when an item of OCI must be reclassified to net income. The amendments are effective for us beginning with the first quarter of 2012, except for the presentation of reclassifications, which has been deferred. Adoption of this amendment will not have a significant impact on our consolidated results of operations, financial position or cash flows.

In May 2011, the FASB issued an update amending the accounting standards for fair value measurement and disclosure, resulting in common principles and requirements under U.S. GAAP and IFRS. The amendments change the wording used to describe certain of the U.S. GAAP requirements either to clarify the intent of existing requirements, to change measurement or expand disclosure principles or to conform to the wording used in IFRS. The amendments are to be applied prospectively and will be effective for our interim and annual periods beginning with the first quarter of 2012. Early application is not permitted. We do not expect adoption of these amendments to have a significant impact on our consolidated results of operations, financial position or cash flows.

Recently Adopted

Oil and Gas Reserve Estimation and Disclosure standards were issued by the FASB in January 2010, which align the FASB's reporting requirements with the below requirements of the SEC. The FASB also addressed the impact of changes in the SEC's rules and definitions on accounting for oil and gas producing activities. Similar to the SEC requirements, the FASB requirements were effective for periods ending on or after December 31, 2009. Initial adoption did not have an impact on our consolidated results of operations, financial position or cash flows. The effect on depreciation, depletion and amortization expense subsequent to adoption, as compared to prior periods, was not significant. The required disclosures are presented in Supplementary Information on Oil and Gas Producing Activities (Unaudited).

In December 2008, the SEC announced that it had approved revisions to its oil and gas reporting disclosures. The new disclosure requirements include provisions that:

Introduce a new definition of oil and gas producing activities. This new definition allows companies to include volumes in their reserve base from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.
Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end prices.
Permit companies to disclose their probable and possible reserves on a voluntary basis.
Require companies to provide additional disclosure regarding the aging of proved undeveloped reserves.
Permit the use of reliable technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.

Replace the existing "certainty" test for areas beyond one offsetting drilling unit from a productive well with a "reasonable certainty" test.
Require additional disclosures regarding the qualifications of the chief technical person who oversees the company's overall reserve estimation process. Additionally, disclosures regarding internal controls surrounding reserve estimation, as well as a report addressing the independence and qualifications of its reserves preparer or auditor are required.
Require separate disclosure of reserves in foreign countries if they represent 15 percent or more of total proved reserves, based on barrels of oil equivalent.

As with the FASB standards described above, adoption did not have an impact on our consolidated results of operations, financial position or cash flows. The additional disclosures required by the SEC can be found in Item 1. Business – Reserves.

Spin-Off

12 Months Ended

Dec. 31, 2011

Spin Off Disclosure [Abstract]

Spin Off Disclosure [Text Block]

3. Spin-off of Downstream Business

On June 30, 2011, the spin-off of the downstream business was completed, creating two independent energy companies: Marathon Oil and MPC. On June 30, 2011, stockholders of record as of 5:00 p.m. Eastern Daylight Savings time on June 27, 2011 (the “Record Date”) received one common share of MPC stock for every two common shares of Marathon stock held as of the Record Date.

In order to affect the spin-off and govern our relationship with MPC after the spin-off, we entered into a Separation and Distribution Agreement, a Tax Sharing Agreement, an Employee Matters Agreement and a Transition Services Agreement. The Separation and Distribution Agreement governed the separation of the downstream business, the distribution of MPC's shares of common stock to our stockholders, transfer of assets and intellectual property, and other matters related to our relationship with MPC. The Separation and Distribution Agreement provides for cross-indemnities between Marathon Oil and MPC. In general, we have agreed to indemnify MPC for any liabilities relating to our historical oil and gas exploration and production operations, oil sands mining operations and integrated gas operations, and MPC has agreed to indemnify us for any liabilities relating to the historical downstream operations.

The Tax Sharing Agreement governs the respective rights, responsibilities and obligations of Marathon Oil and MPC with respect to taxes and tax benefits, the filing of tax returns, the control of audits and other tax matters. In addition, the Tax Sharing Agreement reflects each company's rights and obligations related to taxes that are attributable to periods prior to and including the Separation date and taxes resulting from transactions effected in connection with the Separation. In general, under the Tax Sharing Agreement, Marathon Oil is responsible for all U.S. federal, state, local and foreign income taxes attributable to Marathon Oil or any of its subsidiaries for any tax period that begins after the date of the spin-off, and MPC is responsible for all taxes attributable to it or its subsidiaries, whether accruing before, on or after the spin-off. The Tax Sharing Agreement contains covenants intended to protect the tax-free status of the spin-off. These covenants may restrict the ability of Marathon Oil and MPC to pursue strategic or other transactions that otherwise could maximize the values of their respective businesses and may discourage or delay a change of control of either company.

The Employee Matters Agreement contains provisions concerning benefit protection for employees who became MPC employees prior to December 31, 2011, treatment of holders of Marathon stock options, stock appreciation rights, restricted stock and restricted stock units, and cooperation between Marathon Oil and MPC in the sharing of employee information and maintenance of confidentiality. Unvested equity-based compensation awards were converted to awards of the entity where the employee holding them is working post-separation. For vested equity-based compensation awards, employees received both Marathon Oil and MPC awards.

Under the Transition Services Agreement, Marathon Oil and MPC are providing and/or making available various administrative services and assets to each other, for up to a one-year period beginning on the distribution date of the spin-off. The services include: administrative services; accounting services; audit services; health, environmental and safety services; human resource services; information technology services; legal services; natural gas administration services; tax services; and treasury services. In consideration for such services, the companies are paying fees to the other for the services provided, and these fees are generally in amounts intended to allow the party providing services to recover all of its direct and indirect costs incurred in providing these services.

The following table presents the carrying value of assets and liabilities of MPC, immediately preceding the June 30, 2011 spin-off.

(In millions)
Current assets:
	Cash and cash equivalents		$	1,622
	Receivables			5,041
	Inventories			3,679
	Other current assets			170
		Total current assets of discontinued operations		10,512
Equity method investments				323
Property, plant and equipment				11,935
Goodwill				847
Other noncurrent assets				351
		Total assets of discontinued operations	$	23,968

Current liabilities:
	Accounts payable		$	7,329
	Payroll and benefits payable			222
	Accrued and deferred taxes			443
	Other current liabilities			461
	Long-term debt due within one year			12
		Total current liabilities of discontinued operations		8,467
Long-term debt				3,262
Deferred income taxes				1,568
Defined benefit postretirement plan obligations				1,489
Deferred credits and other liabilities				276
		Total liabilities of discontinued operations	$	15,062

The results of operations of our downstream business have been reported as discontinued operations. The table below shows selected financial information reported in discontinued operations related to the spin-off.

(In millions)	2011		2010		2009
Revenues applicable to discontinued operations	$	38,602	$	62,488	$	45,529
Pretax income from discontinued operations	$	2,012	$	1,065	$	894

Variable Interest Entities

12 Months Ended

Dec. 31, 2011

Variable Interest Entities Disclosure [Abstract]

Variable Interest Entities [Text Block]

4. Variable Interest Entities

The owners of the AOSP, in which we hold a 20 percent undivided interest, contracted with a wholly owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg River mine, the Scotford upgrader and markets in Edmonton. The contract, originally signed in 1999 by a company we acquired, allows each holder of an undivided interest in the AOSP to ship materials in accordance with its undivided interest. Costs under this contract are accrued and recorded on a monthly basis, with a $3 million current liability recorded at December 31, 2011. Under this agreement, the AOSP absorbs all of the operating and capital costs of the pipeline. Currently, no third-party shippers use the pipeline. Should shipments be suspended, by choice or due to force majeure, we remain responsible for the portion of the payments related to our undivided interest for all remaining periods. The contract expires in 2029; however, the shippers can extend its term perpetually. This contract qualifies as a variable interest contractual arrangement and the Corridor Pipeline qualifies as a variable interest entity (“VIE”). We hold a variable interest but are not the primary beneficiary because our shipments are only 20 percent of the total; therefore the Corridor Pipeline is not consolidated. Our maximum exposure to loss as a result of our involvement with this VIE is the amount we expect to pay over the contract term, which was $715 million as of December 31, 2011. The liability on our books related to this contract at any given time will reflect amounts due for the immediately previous month's activity, which is substantially less than the maximum exposure over the contract term. We have not provided financial assistance to Corridor Pipeline and we do not have any guarantees of such assistance in the future.

Acquisitions

12 Months Ended

Dec. 31, 2011

Significant Acquisitions Disclosure [Abstract]

Significant Acquisitions Disclosure [Text Block]

5. Acquisitions

During the fourth quarter of 2011, we closed a series of transactions in the Eagle Ford shale formation in south Texas that were accounted for as a business combination. The most significant of these transactions was the acquisition of Hilcorp Resources, LLC. The total consideration paid for all the transactions including approximately 167,000 net acres and a gathering system, was $4.5 billion which was funded from existing cash. All Eagle Ford properties are included in our E&P segment.

The following table summarizes the amounts allocated to the assets acquired and liabilities assumed based upon their fair values at the acquisition dates:

(In millions)
Current assets:
	Receivables			$	40
	Inventories				4
	Other current assets				30
		Total current assets acquired			74
Property, plant and equipment					4,501
Other noncurrent assets					21
		Total assets acquired		$	4,596
Current liabilities:
	Accounts payable			$	101
	Other current liabilities				20
		Total current liabilities assumed			121
Asset retirement obligations					5
		Total liabilities assumed			126
			Net assets acquired	$	4,470

The fair values of assets acquired and liabilities assumed were measured primarily using an income approach, specifically utilizing a discounted cash flow analysis. The estimated fair values were based on significant inputs not observable in the market, and therefore represent Level 3 measurements. Significant inputs included estimated reserve volumes, the expected future production profile, estimated commodity prices and assumptions regarding future operating and development costs. A discount rate of approximately 11 percent was used in the discounted cash flow analysis. The accounting for this transaction is complete.

The pro forma impact of this business combination is not material to our consolidated statement of income for 2011 and 2010.

In addition, during 2011, we acquired approximately 108,000 net acres in the Eagle Ford shale for approximately $265 million. These transactions were funded from existing cash and were accounted for as asset acquisitions.

Dispositions

12 Months Ended

Dec. 31, 2011

Dispositions Disclosure [Abstract]

Dispositions

6. Dispositions

2012 pipelines - In October 2011, we entered into definitive agreements to sell our E&P segment's interests in several Gulf of Mexico crude oil pipeline systems. This includes our equity method interests in Poseidon Oil Pipeline Company, L.L.C. and Odyssey Pipeline L.L.C., as well as certain other oil pipeline interests, including the Eugene Island pipeline system. The value of this transaction is approximately $205 million, net of debt assumed by the buyer. The carrying value of these assets was $38 million as of December 31, 2011. This transaction closed on January 3, 2012.

2011

Burns Point gas plant - During the fourth quarter of 2011, we sold our E&P segment's 50 percent interest in the Burns Point gas plant, a cryogenic processing plant located in St. Mary Parish, Louisiana, for total consideration of $36 million and a pretax gain of $34 million was booked.

Alaska LNG facility - During the third quarter of 2011, we sold our Integrated Gas segment's equity interest in a LNG processing facility in Alaska and a pretax gain on the transaction of $8 million was recorded.

DJ Basin - In April 2011, we assigned a 30 percent undivided working interest in our E&P segment's approximately 180,000 acres in the Niobrara shale play located within the DJ Basin of southeast Wyoming and northern Colorado for total consideration of $270 million, recording a pretax gain of $37 million. We remain operator of this jointly owned leasehold.

2010

Angola - During 2010, we closed the sale of a 20 percent outside-operated interest in our E&P segment's Production Sharing Contract and Joint Operating Agreement in Block 32 offshore Angola. We received net proceeds of $1.3 billion and recorded a pretax gain on the sale of $811 million. We retained a 10 percent outside-operated interest in Block 32.

Gudrun - In March 2011, we closed the sale of our outside-operated interests in the Gudrun field development and the Brynhild and Eirin exploration areas offshore Norway for net proceeds of $85 million, excluding working capital adjustments. A $64 million pretax loss on this disposition was recorded in the fourth quarter 2010.

2009

Gabon - In December 2009, we closed the sale of our operated fields offshore Gabon, receiving net proceeds of $269 million, after closing adjustments. A $232 million pretax gain on this disposition was reported in discontinued operations for 2009.

Permian Basin - In June 2009, we closed the sale of our E&P segment's operated and a portion of our outside-operated Permian Basin producing assets in New Mexico and west Texas for net proceeds after closing adjustments of $293 million. A $196 million pretax gain on the sale was recorded.

Ireland - In April 2009, we closed the sale of our operated properties in Ireland for net proceeds of $84 million, after adjusting for cash held by the sold subsidiary. A $158 million pretax gain on the sale was recorded. As a result of this sale, we terminated our pension plan in Ireland, incurring a charge of $18 million.

In June 2009, we entered into an agreement to sell the subsidiary holding our 19 percent outside-operated interest in the Corrib natural gas development offshore Ireland. An initial $100 million payment was received at closing. Additional fixed proceeds of $135 million will be received at the earlier of first commercial gas or December 31, 2012. A $154 million impairment was recognized in discontinued operations in the second quarter of 2009.

Our Irish and our Gabonese businesses, which had been reported in our E&P segment, have been reported as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows. Revenues and pretax income related to these businesses are shown in the table below.

(In millions)	2009
Revenues applicable to discontinued operations	$	188
Pretax income from discontinued operations	$	80

- Definition

The entire disclosure for the facts and circumstances leading to the completed or expected disposal, manner and timing of disposal, the gain (loss) recognized in the income statement and the income statement caption that includes that gain (loss), amounts of revenues and pretax profit or loss reported in discontinued operations, the segment in which the disposal group was reported, and the classification (whether sold or classified as held for sale) and carrying value of the assets and liabilities comprising the disposal group. Includes all disposal groups, including those classified as components of the entity (discontinued operations).

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 144
-Paragraph 43-48
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Income per Common Share

12 Months Ended

Dec. 31, 2011

Income Per Common Share Disclosure [Abstract]

Income Per Common Share

7. Income per Common Share

Basic income per share is based on the weighted average number of common shares outstanding, including securities exchangeable into common shares. Diluted income per share assumes exercise of stock options and stock appreciation rights, provided the effect is not antidilutive.

	2011				2010				2009
(In millions, except per share data)		Basic		Diluted		Basic		Diluted		Basic		Diluted
Income from continuing operations	$	1,707	$	1,707	$	1,882	$	1,882	$	716	$	716
Discontinued operations		1,239		1,239		686		686		747		747

Net income	$	2,946	$	2,946	$	2,568	$	2,568	$	1,463	$	1,463
Weighted average common
shares outstanding		710		710		710		710		709		709
Effect of dilutive securities		-		4		-		2		-		2

Weighted average common shares,
including dilutive effect		710		714		710		712		709		711
Per share:
Income from continuing operations	$	2.40	$	2.39	$	2.65	$	2.65	$	1.01	$	1.01

Discontinued operations	$	1.75	$	1.74	$	0.97	$	0.96	$	1.05	$	1.05

Net income	$	4.15	$	4.13	$	3.62	$	3.61	$	2.06	$	2.06

The per share calculations above exclude 7 million, 13 million and 10 million stock options and stock appreciation rights in 2011, 2010 and 2009 that were antidilutive.

Segment Information

12 Months Ended

Dec. 31, 2011

Segment Information Disclosure [Abstract]

Segment Information

8. Segment Information

We have three reportable operating segments: Exploration and Production; Oil Sands Mining; and Integrated Gas. Each of these segments is organized and managed based upon the nature of the products and services they offer.

E&P – explores for, produces and markets liquid hydrocarbons and natural gas on a worldwide basis.
OSM – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.
IG – produces and markets products manufactured from natural gas, such as LNG and methanol, in EG.

Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”). Segment income represents income from continuing operations, net of income taxes, attributable to the operating segments. Our corporate general and administrative costs are not allocated to the operating segments. These costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate activities, net of associated income tax effects. Foreign currency remeasurement and transaction gains or losses are not allocated to operating segments. Non-cash gains and losses on two natural gas sales contracts in the United Kingdom that were accounted for as derivative instruments, impairments, gains or losses on disposal of assets or other items that affect comparability (as determined by the CODM) also are not allocated to operating segments.

As discussed in Note 6, our downstream business was spun-off on June 30, 2011 and has been reported as discontinued operations in all periods presented. Sales to MPC previously reported as Intersegment revenues are now reported as Customer revenues because such sales are expected to continue subsequent to the spin-off. Such sales were $1.4 billion in the first six months of 2011, $1.8 billion in 2010 and $534 million in 2009.

In 2011 and 2010, MPC accounted for approximately 18 percent and 16 percent of total revenues. In 2010 and 2009, the Libyan National Oil Company accounted for approximately 13 percent and 13 percent of total revenues.

Differences between segment totals for income from equity method investments, taxes and depreciation, depletion and amortization and our consolidated totals represent amounts related to corporate administrative activities and other unallocated items and are included in “Items not allocated to segments, net of income taxes” in the reconciliation below. Capital expenditures include accruals but not corporate administrative activities. As discussed in Notes 3 and 6, discontinued operations for our downstream business in all periods and our Irish and Gabonese businesses in 2009 have been excluded from segment results.

(In millions)	E&P		OSM		IG		Total
2011
Revenues:
Customer	$	12,922	$	1,588	$	93	$	14,603
Intersegment		47		0		0		47
Related parties		60		0		0		60
Segment revenues		13,029		1,588		93		14,710
Elimination of intersegment revenues		(47)		0		0		(47)
Total revenues	$	12,982	$	1,588	$	93	$	14,663

Segment income	$	2,157	$	256	$	178	$	2,591
Income from equity method investments		249		0		213		462
Depreciation, depletion and amortization		2,028		196		3		2,227
Income tax provision		2,808		82		74		2,964
Capital expenditures		3,038		308		2		3,348

(In millions)	E&P		OSM		IG		Total
2010
Revenues:
Customer	$	10,651	$	833	$	150	$	11,634
Intersegment		75		0		0		75
Related parties		56		0		0		56
Segment revenues		10,782		833		150		11,765
Elimination of intersegment revenues		(75)		0		0		(75)
Total revenues	$	10,707	$	833	$	150	$	11,690

Segment income (loss)	$	1,941	$	(50)	$	142	$	2,033
Income from equity method investments		188		0		181		369
Depreciation, depletion and amortization		1,911		105		2		2,018
Income tax provision (benefit)		2,266		(12)		73		2,327
Capital expenditures		2,474		874		2		3,350

(In millions)	E&P		OSM		IG		Total
2009
Revenues:
Customer	$	7,651	$	692	$	50	$	8,393
Intersegment		28		0		0		28
Related parties		59		0		0		59
Segment revenues		7,738		692		50		8,480
Elimination of intersegment revenues		(28)		0		0		(28)
Gain on U.K. natural gas contracts^{a}		72		0		0		72^{a}
Total revenues	$	7,782	$	692	$	50	$	8,524

Segment income	$	1,218	$	44	$	90	$	1,352
Income from equity method investments		125		0		143		268
Depreciation, depletion and amortization		1,776		124		3		1,903
Income tax provision		1,560		6		39		1,605
Capital expenditures		2,162		1,115		2		3,279

The U.K. natural gas contracts expired in September 2009.

The following reconciles segment income to net income as reported in the consolidated statements of income.

(In millions)	2011		2010		2009
Segment income	$	2,591	$	2,033	$	1,352
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items		(326)		(202)		(431)
Foreign currency remeasurement of taxes		9		32		(319)
Impairments^{a}		(195)		(286)		(45)
Loss on early extinguishment of debt		(176)		(57)		0
Tax effect of subsidiary restructuring		(122)		0		0
Deferred income taxes		(61)		(45)		0
Water abatement - Oil Sands		(48)		0		0
Eagle Ford transaction costs		(10)		0		0
Gain on dispositions^{b}		45		407		122
Gain on U.K. natural gas contracts		0		0		37
Income from continuing operations		1,707		1,882		716
Discontinued operations		1,239		686		747
Net income	$	2,946	$	2,568	$	1,463

(a) Significant impairments are further discussed, on a pretax basis, in Note 15.

(b) Significant dispositions are further discussed, on a pretax basis, in Note 6.

The following reconciles total revenues to sales and other operating revenues reported in continuing operations in the consolidated statements of income.

(In millions)	2011		2010		2009
Total revenues	$	14,663	$	11,690	$	8,524
Less: Sales to related parties		60		56		59
Sales and other operating revenues	$	14,603	$	11,634	$	8,465

Revenues from external customers are attributed to geographic areas based upon selling location. The following summarizes revenues from external customers reported in continuing operations by geographic area.

(In millions)	2011		2010		2009
United States	$	6,971	$	5,363	$	3,326
United Kingdom		1,546		1,063		1,143
Libya^{a}		216		1,473		1,139
Norway		3,386		2,243		1,617
Canada		1,588		833		692
Other international		956		715		607
Total revenues	$	14,663	$	11,690	$	8,524

See Note 13 for discussion of Libya operations.

The following summarizes certain long-lived assets by geographic area, including property, plant and equipment and equity investments.

(In millions)	2011		2010
United States	$	10,928	$	18,415
Canada		9,711		9,564
Equatorial Guinea		2,214		2,389
Norway		1,133		1,353
Other international		2,721		2,399
Total long-lived assets	$	26,707	$	34,120

Revenues by product line were:

(In millions)	2011		2010		2009
Liquid hydrocarbons	$	13,298	$	10,312	$	7,343
Natural gas		1,291		1,295		1,126
Transportation & other		74		83		55
Total revenues	$	14,663	$	11,690	$	8,524

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 131
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Publisher FASB
-Name Accounting Standards Codification
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+ Details

Other Items

12 Months Ended

Dec. 31, 2011

Other Items Disclosure [Abstract]

Other Items

9. Other Items

Net interest and other, related to continuing operations

(In millions)	2011		2010		2009
Interest:
Interest income	$	12	$	11	$	8
Interest expense^{a}		(281)		(375)		(262)
Income on interest rate swaps		10		26		17
Interest capitalized		151		297		214
Total interest		(108)		(41)		(23)

Other:
Net foreign currency gains (losses)		24		(21)		(28)
Write-off of contingent proceeds^{b}		(7)		(15)		(70)
Other		(16)		2		(1)
Total other		1		(34)		(99)
Net interest and other	$	(107)	$	(75)	$	(122)

(a) Excludes $10 million, $16 million and $27 million paid by United States Steel in 2011, 2010 and 2009 on assumed debt.

(b) A portion of the contingent proceeds from the sale of the Corrib natural gas development was written off in the fourth quarter of 2009 on the basis of new public information regarding the pipeline that would transport gas from the Corrib development. The remaining carrying value of this contingent receivable was written off in 2010.

Foreign currency transactions - Aggregate foreign currency gains (losses) related to continuing operations were included in the consolidated statements of income as follows:

(In millions)	2011		2010		2009
Net interest and other	$	24	$	(21)	$	(28)
Provision for income taxes		(57)		(1)		(319)

Aggregate foreign currency losses	$	(33)	$	(22)	$	(347)

Income Taxes

12 Months Ended

Dec. 31, 2011

Income Taxes Disclosure [Abstract]

Income Taxes

10. Income Taxes

Income tax provisions (benefits) related to continuing operations were:

		2011						2010						2009
(In millions)		Current		Deferred		Total		Current		Deferred		Total		Current		Deferred		Total
Federal		$	(210)	$	(206)	$	(416)	$	(279)	$	(267)	$	(546)	$	40	$	(329)	$	(289)
State and local			24		82		106		2		(10)		(8)		(19)		5		(14)
Foreign			3,088		(58)		3,030		2,941		(212)		2,729		1,480		870		2,350
	Total	$	2,902	$	(182)	$	2,720	$	2,664	$	(489)	$	2,175	$	1,501	$	546	$	2,047

A reconciliation of the federal statutory income tax rate applied to income from continuing operations before income taxes to the provision for income taxes follows:

	2011		2010			2009
Statutory rate applied to income from continuing operations before income taxes	35	%		35	%		35	%
Effects of foreign operations, including foreign tax credits	6			20			16
Change in permanent reinvestment assertion	5			-			-
Foreign currency remeasurement	-			-			11
Adjustments to valuation allowances	14			(2)			10
Tax law changes	1			1			-
Other	-			-			2
Effective income tax rate on continuing operations	61	%		54	%		74	%

Effects of foreign operations - The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income, the relative magnitude of these sources of income, and foreign currency remeasurement effects. The provision for income taxes is allocated on a discrete, stand-alone basis to pretax segment income and to individual items not allocated to segments. The difference between the total provision and the sum of the amounts allocated to segments and to individual items not allocated to segments is reported in “Corporate and other unallocated items” shown in Note 8.

The effects of foreign operations on our effective tax rate decreased in 2011 as compared to 2010, primarily due to the suspension of all production operations in Libya in the first quarter of 2011, where the statutory tax rate is in excess of 90 percent.

Change in permanent reinvestment assertion - In the second quarter of 2011, we recorded $716 million of deferred U.S. tax on undistributed earnings of $2,046 million that we previously intended to permanently reinvest in foreign operations. Offsetting this tax expense were associated foreign tax credits of $488 million. In addition, we reduced our valuation allowance related to foreign tax credits by $228 million due to recognizing deferred U.S. tax on previously undistributed earnings.

Adjustments to valuation allowances - In 2009, it was determined that we may not be able to realize all recorded foreign tax credit benefits and therefore a valuation allowance was recorded against these benefits. In 2011, we increased the valuation allowance against foreign tax credits because it is more likely than not that we will be unable to realize all U.S. benefits on foreign taxes accrued in 2011.

Tax law changes - In July 2011, the U.K. enacted the Finance Bill 2011 which increased the rate of the supplementary charge levied on profits from U.K. oil and gas production from 20 percent to 32 percent. As a result of this legislation, we recorded deferred tax expense of $10 million in 2011.

On May 25, 2011, Michigan enacted legislation that replaced the Michigan Business Tax (“MBT”) with a corporate income tax (“CIT”), effective January 1, 2012. The new CIT legislation eliminates the “book-tax difference deduction” that was provided under the MBT to mitigate the net increase in a taxpayer's deferred tax liability resulting when Michigan moved from the Single Business Tax, a non-income tax, to the MBT, an income tax, on July 12, 2007. Such a change in the tax law must be recognized in earnings in the period enacted regardless of the effective date. The total effect of tax law changes on deferred tax balances is recorded as income tax expense related to continuing operations in the period the law is enacted, even if a portion of the deferred tax balances relates to discontinued operations. As a result of the new CIT legislation, we recorded deferred tax expense of $32 million in the second quarter of 2011.

The Patient Protection and Affordable Care Act (“PPACA”) and the Health Care and Education Reconciliation Act of 2010 (“HCERA”), (together, the “Acts”) were signed in to law in March 2010. The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the “MPDIMA”). Under the MPDIMA, the federal subsidy does not reduce our income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually. Beginning in 2013, under the Acts, our income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Such a change in the tax law must be recognized in earnings in the period enacted regardless of the effective date. The total effect of tax law changes on deferred tax balances is recorded as income tax expense related to continuing operations in the period the law is enacted, even if a portion of the deferred tax balances relates to discontinued operations. As a result, we recorded deferred tax expense of $45 million in the first quarter of 2010 for the write-off of deferred tax assets to reflect the change in the tax treatment of the federal subsidy.

Deferred tax assets and liabilities resulted from the following:

	December 31,
(In millions)	2011		2010
Deferred tax assets:
Employee benefits	$	413	$	1,079
Operating loss carryforwards^{a}		376		285
Foreign tax credits		3,005		2,045
Other		88		141
Valuation allowances
Federal		(791)		(206)
State		(61)		(48)
Foreign^{a}		(194)		(142)
Total deferred tax assets		2,836		3,154
Deferred tax liabilities
Property, plant and equipment^{a}		3,283		5,292
Inventories		0		597
Investments in subsidiaries and affiliates		1,286		1,116
Other		43		42
Total deferred tax liabilities		4,612		7,047
Net deferred tax liabilities	$	1,776	$	3,893

(a) Certain 2010 amounts were reclassified to conform to the current period's presentation.

Operating loss carryforwards - At December 31, 2011, our operating loss carryforwards include $811 million of Canadian operating loss carryforwards that expire from 2013 through 2031 and $245 million of Indonesian operating loss carryforwards that do not have expiration dates. State operating loss carryforwards of $915 million expire in 2012 through 2031.

Valuation allowances - The ability to realize the benefit of foreign tax credits is based on certain estimates concerning future operating conditions (particularly as related to prevailing liquid hydrocarbon, natural gas and synthetic crude oil prices), future financial conditions, income generated from foreign sources and our tax profile in the years that such credits may be claimed. Federal valuation allowances increased $585 million in 2011, decreased $74 million in 2010 and increased $280 million in 2009 due to changes in the expected realizability of foreign tax credits.

Foreign valuation allowances increased $52 million and $40 million in 2011 and 2010, primarily due to net operating loss carryforwards generated in Indonesia. Foreign valuation allowances decreased $79 million in 2009, primarily due to the reduction of net operating loss carryforwards as a result of the disposition of exploration and production businesses in Ireland.

Net deferred tax liabilities were classified in the consolidated balance sheets as follows:

			December 31,
(In millions)			2011		2010
Assets:
	Current deferred tax assets		$	99	$	-
	Other noncurrent assets			674		-
Liabilities:
	Current deferred tax liabilities			5		324
	Noncurrent deferred tax liabilities			2,544		3,569
		Net deferred tax liabilities	$	1,776	$	3,893

We are continuously undergoing examination of our U.S. federal income tax returns by the Internal Revenue Service. Such audits have been completed through the 2007 tax year. We believe adequate provision has been made for federal income taxes and interest which may become payable for years not yet settled. Further, we are routinely involved in U.S. state income tax audits and foreign jurisdiction tax audits. We believe all other audits will be resolved within the amounts paid and/or provided for these liabilities. As of December 31, 2011, our income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated:

United States^{a}	2004 - 2010
Canada	2006 - 2010
Equatorial Guinea	2006 - 2010
Libya	2006 - 2009
Norway	2008 - 2010
United Kingdom	2008 - 2010

(a) Includes federal and state jurisdictions

The following table summarizes the activity in unrecognized tax benefits

(In millions)	2011		2010		2009
Beginning balance	$	103	$	75	$	39
Additions for tax positions related to the current year		4		28		30
Reductions for tax positions related to the current year		0		(1)		(2)
Additions for tax positions of prior years		87		25		30
Reductions for tax positions of prior years		(29)		(12)		(15)
Settlements		(8)		(12)		(7)
Ending balance	$	157	$	103	$	75

If the unrecognized tax benefits as of December 31, 2011 were recognized, $103 million would affect our effective income tax rate. There were $19 million of uncertain tax positions as of December 31, 2011 for which it is reasonably possible that the amount of unrecognized tax benefits would significantly increase or decrease during the next twelve months.

Interest and penalties are recorded as part of the tax provision, and related to unrecognized tax benefits were $13 million, $5 million and less than $1 million in 2011, 2010 and 2009. As of December 31, 2011 and 2010, $27 million and $15 million of interest and penalties were accrued related to income taxes.

Pretax income from continuing operations included amounts attributable to foreign sources of $4,869 million, $4,563 million and $2,947 million in 2011, 2010 and 2009.

Undistributed income of certain consolidated foreign subsidiaries at December 31, 2011 amounted to $235 million for which no U.S. deferred income tax provision has been recorded because we intend to permanently reinvest such income in those foreign operations. If such income was not permanently reinvested, income tax expense of approximately $82 million would be recorded, not including potential utilization of foreign tax credits.

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 136, 172
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 43, 44, 45, 46, 47, 48, 49
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32718-109319

Reference 5: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-SubTopic 10
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(h))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
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-Topic 740
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-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32559-109319

+ Details

Inventories

12 Months Ended

Dec. 31, 2011

Inventories Disclosure [Abstract]

Inventories

11. Inventories

Inventories are carried at the lower of cost or market value. A significant portion of our inventories at December 31, 2010 were related to our downstream business (see Note 3).

	December 31,
(In millions)	2011		2010
Liquid hydrocarbons, natural gas and bitumen	$	147	$	1,275
Refined products and merchandise		0		1,774
Supplies and sundry items		214		404
Inventories at cost	$	361	$	3,453

The LIFO method accounted for 16 percent and 85 percent of total inventory value at December 31, 2011 and 2010. Current acquisition costs were estimated to exceed the LIFO inventory value at December 31, 2011 and 2010 by $74 million and $4,166 million.

Equity Method Investments and Related Party Transactions

12 Months Ended

Dec. 31, 2011

Equity Method Investments And Related Party Transactions Disclosure [Abstract]

Equity Method Investments And Related Party Transactions Disclosure [Text Block]

12. Equity Method Investments and Related Party Transactions

During 2011, 2010 and 2009 only our equity method investees were considered related parties. The following were included in continuing operations:

Alba Plant LLC, in which we have a 52 percent noncontrolling interest. Alba Plant LLC processes LPG.
AMPCO, in which we have a 45 percent interest. AMPCO is engaged in methanol production activity.
EGHoldings, in which we have a 60 percent noncontrolling interest. EGHoldings is engaged in LNG production activities.

Our equity method investments are summarized in the following table:

	Ownership as of		December 31,
(In millions)	December 31, 2011		2011		2010
EGHoldings	60	%	$	875	$	927
Alba Plant LLC	52	%		272		303
AMPCO	45	%		191		210
Downstream business investments				0		311
Other investments				45		51
Total			$	1,383	$	1,802

As of December 31, 2011, the carrying value of our equity method investments was $155 million higher than the underlying net assets of investees. This basis difference is being amortized into net income over the remaining estimated useful lives of the underlying net assets.

Dividends and partnership distributions received from equity method investees (excluding distributions that represented a return of capital previously contributed) reported in continuing operations were $509 million in 2011, $400 million in 2010 and $302 million in 2009.

Summarized financial information for equity method investees is as follows:

(In millions)	2011^{a}		2010		2009
Income data – year:
Revenues and other income	$	1,544	$	2,243	$	1,916
Income from operations		942		999		677
Net income		820		841		576
Balance sheet data – December 31:
Current assets	$	688	$	898
Noncurrent assets		2,079		3,371
Current liabilities		504		513
Noncurrent liabilities		115		832

Values in 2011 are lower than in previous years due to the spin-off of our downstream business on June 30, 2011.

Almost all of our related party purchases are liquid hydrocarbons acquired from Alba Plant LLC. Approximately 75 percent of our sales to related parties in all periods are associated with sales of natural gas to EGHoldings.

- Definition

The entire disclosure for equity investment, or group of investments, for which combined disclosure is appropriate and the entire disclosure for related party transactions. Equity method disclosures can include: (a) the name of each investee and percentage of ownership of common stock, (b) accounting policies for investments in common stock, (c) difference between the amount at which the investment is carried and the amount of underlying equity in net assets and the accounting treatment of the difference, (d) the total fair value of each identified investment for which a market value is available, (e) summarized information as to assets, liabilities, and results of operations of the investees (for investments in unconsolidated subsidiaries, common stock of joint ventures, or other investments using the equity method), and (f) material effects of possible conversions, exercises, or contingent issuances of the investee. Other disclosures include (a) the names of any investee in which the investor owns 20 percent or more of the voting stock and investment is not accounted for using the equity method, and the reasons why not, and (b) the names of any investee in which the investor owns less than 20 percent% of the voting stock and the investment is accounted for using the equity method, and the reasons why it is. Related party transaction disclosures can include the nature of the relationship(s), a description of the transactions, the amount of the transactions, the effects of any change in the method of establishing the terms of the transaction from the previous period, stated interest rate, expiration date, terms and manner of settlement per the agreement with the related party, and amounts due to or from related parties. If the entity and one or more other entities are under common ownership or management control and this control affects the operating results or financial position, disclosure includes the nature of the control relationship even if there are no transactions between the entities. Disclosure may also include the aggregate amount of current and deferred tax expense for each statement of earnings presented where the entity is a member of a group that files a consolidated tax return, the amount of any tax related balances due to or from affiliates as of the date of each statement of financial position presented, the principal provisions of the method by which the consolidated amount of current and deferred tax expense is allocated to the members of the group and the nature and effect of any changes in that method. Examples of related party transactions include transactions between (a) a parent company and its subsidiary; (b) subsidiaries of a common parent; (c) and entity and its principal owners; and (d) affiliates.

+ References + Details

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2011

Property Plant And Equipment Disclosure [Abstract]

Property, Plant and Equipment

13. Property, Plant and Equipment

	December 31,
(In millions)	2011		2010
E&P
United States	$	19,679	$	13,532
International		12,579		11,736
Total E&P		32,258		25,268
OSM		9,936		9,631
IG		37		47
Downstream business		-		16,624
Corporate		341		457
Total property, plant and equipment	$	42,572	$	52,027
Less accumulated depreciation, depletion and amortization		(17,248)		(19,805)
Net property, plant and equipment	$	25,324	$	32,222

During the first quarter 2011, all production operations in Libya were suspended. In the fourth quarter of 2011, limited production resumed from the Waha concessions, but we made no deliveries of hydrocarbons. Sales are expected in the first quarter of 2012. The return of our operations in Libya to pre-conflict levels is unknown at this time; however, we and our partners in the Waha concession are assessing the condition of our assets and determining when the full resumption of operations will be viable. As of December 31, 2011, our net property, plant and equipment investment in Libya is approximately $756 million and our net proved reserves in Libya are 239 mmboe.

Property, plant and equipment includes gross assets acquired under capital leases of $13 million and $272 million at December 31, 2011 and 2010, with related amounts in accumulated depreciation, depletion and amortization of $1 million and $48 million at December 31, 2011 and 2010.

Deferred exploratory well costs were as follows:

	December 31,
(In millions)	2011		2010		2009
Amounts capitalized less than one year after completion of drilling	$	482	$	334	$	679
Amounts capitalized greater than one year after completion of drilling		222		323		150
Total deferred exploratory well costs	$	704	$	657	$	829
Number of projects with costs capitalized greater than one year
after completion of drilling		5		7		3

(In millions)		2011		2010		2009
Beginning balance		$	657	$	829	$	917
	Additions		670		329		155
	Dry well expense		(268)		(83)		(32)
	Transfers to development		(279)		(54)		(211)
	Dispositions		(76)		(364)		-
Ending balance		$	704	$	657	$	829

Exploratory well costs capitalized greater than one year after completion of drilling as of December 31, 2011 are summarized by geographical area below:

(In millions)
Gulf of Mexico	$	73
Angola		124
Other International		25
Total	$	222

Well costs that have been suspended for longer than one year are associated with five projects. Exploration on Angola Block 31 began in 2004, with costs accumulating through 2009. Development alternatives are being evaluated and optimization efforts continue for this block. Costs for two offshore Gulf of Mexico projects were incurred in 2009 and 2010. Drilling is expected to resume on the Innsbruck prospect in the second half of 2012, while evaluation of the outside-operated Shenandoah prospect is ongoing with an appraisal well expected in 2012. Two international projects had costs incurred in 2004 and 2009 and have the potential to tie-back to current production facilities. Development will be pursued when the additional production is required to feed our Equatorial Guinea and Norway operations. Management believes these projects with suspended exploratory drilling costs exhibit sufficient quantities of hydrocarbons to justify potential development.

- Definition

The entire disclosure for long-lived, physical assets that are used in the normal conduct of business to produce goods and services and not intended for resale. Examples include land, buildings, machinery and equipment, and other types of furniture and equipment including, but not limited to, office equipment, furniture and fixtures, and computer equipment and software. This disclosure may include property plant and equipment accounting policies and methodology, a schedule of property, plant and equipment gross, additions, deletions, transfers and other changes, depreciation, depletion and amortization expense, net, accumulated depreciation, depletion and amortization expense and useful lives, income statement disclosures, assets held for sale and public utility disclosures.

+ References + Details

Goodwill

12 Months Ended

Dec. 31, 2011

Goodwill Disclosure [Abstract]

Goodwill Disclosure [Text Block]

14. Goodwill

Goodwill is tested for impairment on an annual basis, or when events or changes in circumstances indicate the fair value of a reporting unit with goodwill has been reduced below the carrying value. We performed our annual impairment tests during 2011, 2010 and 2009 and no impairment was required. The fair value of each of our reporting units exceeded the book value appreciably; however, should market conditions deteriorate or commodity prices decline significantly, an impairment may be necessary.

The changes in the carrying amount of goodwill for the years ended December 31, 2011, and 2010 were as follows:

(In millions)		E&P		OSM		Downstream business		Total
2010
Beginning balance, gross		$	537	$	1,412	$	885	$	2,834
	Less: accumulated impairment		-		(1,412)		-		(1,412)
Beginning balance, net			537		-		885		1,422
	Contingent consideration adjustment		-		-		(1)		(1)
	Purchase price adjustment		-		-		(7)		(7)
	Dispositions		-		-		(34)		(34)
Ending balance, net			537		-		843		1,380
2011
Beginning balance, gross			537		1,412		843		2,792
	Less: accumulated impairments		-		(1,412)		-		(1,412)
Beginning balance, net			537		-		843		1,380
	Dispositions		(1)		-		(2)		(3)
	Contingent consideration adjustment		-		-		(3)		(3)
	Purchase price adjustment		-		-		9		9
	Spin-off downstream business		-		-		(847)		(847)
Ending balance, net		$	536	$	-	$	-	$	536

Fair Value Measurements

12 Months Ended

Dec. 31, 2011

Fair Value Measurements Disclosure [Abstract]

Fair Value Disclosures [Text Block]

15. Fair Value Measurements

Fair Values - Recurring

As of December 31, 2011, balances related to interest rate swaps accounted for at fair value on a recurring basis were noncurrent assets of $5 million measured at fair value using actionable broker quotes which are Level 2 inputs. There were no other significant recurring fair value measurements as of December 31, 2011.

The following table presents assets and liabilities accounted for at fair value on a recurring basis as of December 31, 2010 by fair value hierarchy level. The majority of commodity derivatives outstanding at December 31, 2010 related to our downstream business.

	December 31, 2010
(In millions)		Level 1		Level 2		Level 3		Collateral		Total
Derivative instruments, assets
Commodity	$	58	$	-	$	1	$	81	$	140
Interest rate		-		32		-		-		32
Derivative instruments, assets		58		32		1		81		172
Derivative instruments, liabilities
Commodity	$	(102)	$	-	$	(3)	$	-	$	(105)
Derivative instruments, liabilities		(102)		-		(3)		-		(105)

As of December 31, 2010, commodity derivatives in Level 1 were exchange-traded contracts for crude oil, natural gas and refined products measured at fair value with a market approach using the close-of-day settlement prices for the market. Interest rate swaps were in Level 2 of the fair value hierarchy because they were measured at fair value with a market approach using market price quotes or a price obtained from third-party services such as Bloomberg L.P. which were corroborated with data from active markets for similar assets and liabilities. Collateral deposits related to commodity derivatives are in broker accounts covered by master netting agreements.

Commodity derivatives in Level 3 are measured at fair value with a market approach using prices obtained from third-party services such as Platt's and price assessments from other independent brokers.

The following is a reconciliation of the net beginning and ending balances recorded for derivative instruments classified as Level 3 in the fair value hierarchy.

(In millions)	2011		2010		2009
Beginning balance	$	(2)	$	9	$	(26)
Total realized and unrealized gains (losses):
Included in net income		-		23		68
Included in other comprehensive income		-		4		(1)
Transfers to Level 2		-		(30)		-
Purchases		-		2		5
Sales		-		-		(23)
Issuances		-		-		(44)
Settlements		-		(10)		30
Spin-off of downstream business		2		-		-
Ending balance	$	-	$	(2)	$	9

Net income for 2010 and 2009 included unrealized losses of $1 million, and $7 million related to the derivatives in Level 3. See Note 16 for income statement impacts of our derivative instruments.

Fair Values – Nonrecurring

The following table shows the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition for continuing operations.

		2011				2010				2009
(In millions)		Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	226	$	282	$	147	$	447	$	5	$	15
Long-lived assets held for sale		0		0		85		64		311		154
Intangible assets		0		25		0		0		0		0
Equity method investments		0		0		0		25		0		0

In May 2011, significant water production and reservoir pressure declines occurred at our E&P segment's Droshky development in the Gulf of Mexico. Plans for a waterflood were cancelled and the field will be produced to abandonment pressures, which are expected in the first half of 2012. Consequently, 3.4 million barrels of oil equivalent of proved reserves were written off and a $273 million impairment of this long-lived asset to fair value was recorded in the second quarter of 2011. The $226 million fair value of the Droshky development was determined using an income approach based upon internal estimates of future production levels, prices and discount rate, all Level 3 inputs.

In the second quarter of 2011, our outlook for U.S. natural gas prices made it unlikely that sufficient U.S. demand for LNG would materialize by 2021, which is when the rights lapse under our arrangements at the Elba Island, Georgia regasification facility. Using an income approach based upon internal estimates of gas prices and future deliveries, which are Level 3 inputs, we determined that the contract had no remaining fair value and recorded a full impairment of this intangible asset held in our Integrated Gas segment.

In the fourth quarter of 2010, due to the pending sale of our E&P segment's outside-operated interest in the Gudrun field development, located offshore Norway, we recorded a loss for this asset held for sale. The fair value of $85 million was based upon the pending transaction, which is a Level 3 market input.

In the third quarter of 2010, we fully impaired our Integrated Gas segment's equity method investment in an entity engaged in gas-to-fuels related technology. This investment was determined to have sustained an other than temporary loss in value. Based upon recent financial information, the fair value was measured with an income approach using internally developed estimates of future cash flows. These cash flows are Level 3 inputs.

In March 2010, we completed a reservoir study which resulted in a portion of our Powder River Basin field being removed from plans for future development in our E&P segment. The field's fair value was measured at $144 million, using an income approach based upon internal estimates of future production levels, prices and discount rate which are Level 3 inputs. This resulted in an impairment of $423 million.

The impairment charge recorded on assets held for sale in 2009 related to the sale of the Corrib natural gas development offshore Ireland and was based on the fair value of anticipated sale proceeds (see Note 6). Fair value of anticipated sale proceeds included cash received at closing, a minimum amount due at the earlier of first gas or December 31, 2012, and a range of contingent proceeds subject to the timing of first commercial gas. The fair value of the total proceeds was measured using an income method that incorporated a probability-weighted approach with respect to timing of first commercial gas and an associated sliding scale on the amount of corresponding consideration specified in the sales agreement: the longer it takes to achieve first gas, the lower the amount of the consideration. Because a portion of the proceeds is variable in timing and amount depending upon timing of first commercial gas, the inputs to the fair value calculation were classified as Level 3 inputs.

Impairments of several other long-lived assets held for use in our E&P segment that were evaluated in 2011, 2010 and 2009 were a result of reduced drilling expectations, reduction of estimated reserves or declining natural gas prices, and are also reported above. The fair values of those assets were measured using an income approach based upon internal estimates of future production levels, commodity prices and discount rate, which are Level 3 inputs. Natural gas prices began declining in September 2011 and have continued to decline in 2012. Should natural gas prices remain depressed, an impairment charge related to our natural gas assets may be necessary.

Fair Values – Financial Instruments

The following table summarizes financial instruments, excluding the derivative financial instruments reported above, by individual balance sheet line item at December 31, 2011 and 2010.

	December 31,
	2011^{a}				2010
		Fair		Carrying		Fair		Carrying
(In millions)		Value		Amount		Value		Amount
Financial assets
Other current assets	$	146	$	148	$	226	$	220
Other noncurrent assets		68		68		396		231

Total financial assets		214		216		622		451

Financial liabilities
Long-term debt, including current portion^{b}		5,479		4,753		8,364		7,527
Deferred credits and other liabilities		36		38		66		67

Total financial liabilities	$	5,515	$	4,791	$	8,430	$	7,594

Financial assets and liabilities have decreased from 2010 due to the spin-off of our downsteam business, early retirement of long-term debt and United States Steel's redemption of the bonds for which they retained responsibilty.
Excludes capital leases.

Our current assets and liabilities include financial instruments, the most significant of which are trade accounts receivables and payables. We believe the carrying values of these current assets and liabilities approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments, (2) our investment-grade credit rating, and (3) our historical incurrence of and expected future insignificance of bad debt expense, which includes an evaluation of counterparty credit risk. The current portion of our long-term debt, which is reported with long-term debt above and discussed below, is an exception to this assessment.

Fair values of our remaining financial assets included in other noncurrent assets and of our financial liabilities included in deferred credits and other liabilities are measured using an income approach and most inputs are internally generated, which results in a Level 3 classification. Estimated future cash flows are discounted using a rate deemed appropriate to obtain the fair value.

Over 90 percent of our long-term debt instruments are publicly-traded. A market approach, based upon quotes from major financial institutions is used to measure the fair value of such debt. Because such quotes cannot be independently verified to the market they are considered Level 3 inputs. The fair value of our debt that is not publicly-traded is measured using an income approach. The future debt service payments are discounted using the rate at which we currently expect to borrow. All inputs to this calculation are Level 3.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References

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-Name Statement of Financial Accounting Standard (FAS)
-Number 133
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Derivatives

12 Months Ended

Dec. 31, 2011

Derivatives Disclosure [Abstract]

Derivatives

16. Derivatives

For further information regarding the fair value measurement of derivative instruments see Note 15. See Note 1 for discussion of the types of derivatives we use and the reasons for them. As of December 30, 2011, our only derivatives outstanding are interest rate swaps that are fair value hedges, which have an asset value of $5 million and are located on the consolidated balance sheet in Other noncurrent assets.

The following table presents the gross fair values of derivative instruments, excluding cash collateral, and where they appear on the consolidated balance sheet as of December 31, 2010. The majority of our 2010 commodity derivatives were related to our downstream business.

	December 31, 2010
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	32	$	-	$	32	Other noncurrent assets
Total Designated Hedges		32		-		32

Not Designated as Hedges
Commodity		58		102		(44)	Other current assets
Total Not Designated as Hedges		58		102		(44)

Total	$	90	$	102	$	(12)

	December 31, 2010
(In millions)	Asset		Liability		Net Liability		Balance Sheet Location
Not Designated as Hedges
Commodity	$	1	$	3	$	2	Other current liabilities
Total Not Designated as Hedges		1		3		2

Total	$	1	$	3	$	2

Derivatives Designated as Cash Flow Hedges

We had no derivatives designated as cash flow hedges at December 31, 2011 and 2010.

The following table summarizes the pretax effect of derivative instruments designated as cash flow hedges in other comprehensive income:

	Gain (Loss) in OCI
(In millions)	2011			2010		2009
Foreign currency	$	-	$	4	$	39
Interest rate	$	-	$	-	$	(15)

Derivatives Designated as Fair Value Hedges

As of December 31, 2011, we had multiple interest rate swap agreements with a total notional amount of $600 million at a weighted-average, LIBOR-based, floating rate of 4.76 percent. As of December 31, 2010, we had multiple interest rate swap agreements with a total notional amount of $1,450 million at a weighted-average, LIBOR-based, floating rate of 4.43 percent. The interest rate swaps have no hedge ineffectiveness.

In connection with the debt retired in February and March 2011 discussed in Note 17, we settled interest rate swaps with a notional amount of $1,450 million. We recorded a $29 million gain, which reduced the loss on early extinguishment of debt.

The following table summarizes the pretax effect related to continuing operations of derivative instruments designated as hedges of fair value in our consolidated statements of income.

		Gain (Loss)
(In millions)	Income Statement Location	2011		2010		2009
Derivative
Commodity	Sales and other operating revenues	$	-	$	(1)	$	(16)
Interest rate	Net interest and other		28		26		-
			28		25		(16)
Hedged Item
Commodity	Sales and other operating revenues		-		1		16
Long-term debt	Net interest and other		(28)		(26)		-
		$	(28)	$	(25)	$	16

Derivatives Not Designated as Hedges

The following table summarizes the effect related to continuing operations of all derivative instruments not designated as hedges in our consolidated statements of income.

		Gain (Loss)
(In millions)	Income Statement Location	2011		2010		2009
Commodity	Sales and other operating revenues	$	5	$	121	$	90
Foreign currency	Net interest and other		0		0		3
		$	5	$	121	$	93

- Definition

The entire disclosure for the entity's entire derivative instruments and hedging activities. Describes an entity's risk management strategies, derivatives in hedging activities and non-hedging derivative instruments, the assets, obligations, liabilities, revenues and expenses arising therefrom, and the amounts of and methodologies and assumptions used in determining the amounts of such items.

+ References

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-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 45
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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+ Details

Debt

12 Months Ended

Dec. 31, 2011

Debt Disclosure [Abstract]

Debt

17. Debt

As of December 31, 2011, we had no borrowings against our $3 billion revolving credit facility and no commercial paper outstanding under our U.S. commercial paper program that is backed by the revolving credit facility.

		December 31,
(In millions)		2011		2010
Marathon Oil Corporation:
	Revolving credit facility	$	0	$	0
	6.125% notes due 2012		0		450
	6.000% notes due 2012		0		400
	5.900% notes due 2018^{a}		854		894
	6.800% notes due 2032^{a}		550		550
	9.375% debentures due 2012		53		53
	9.125% debentures due 2013		114		114
	6.500% debentures due 2014		0		700
	7.500% debentures due 2019^{a}		228		688
	6.000% debentures due 2017^{a}		682		682
	9.375% debentures due 2022		32		32
	8.500% debentures due 2023		70		70
	8.125% debentures due 2023		131		131
	6.600% debentures due 2037		750		750
	4.550% promissory note, semi-annual payments due 2012 - 2015		272		340
	Series A medium term notes due 2022		3		3
	4.750% - 6.875% obligations relating to industrial development and
	environmental improvement bonds and notes due 2013 - 2033		0		198
	5.375% obligation relating to revenue bonds due 2013		23		23
	5.125% obligation relating to revenue bonds due 2037		1,000		1,000
	Sale-leaseback financing due 2012		11		20
	Capital lease obligation due 2012		9		17
Consolidated subsidiaries
	8.375% secured notes due 2012^{a}		0		448
	Capital lease obligations due 2012 - 2034
	Downstream business		0		279
	Other		11		12
Total^{b}			4,793		7,854
	Unamortized fair value differential for debt assumed in acquisitions		0		16
	Unamortized discount		(10)		(16)
	Fair value adjustments ^{c}		32		42
	Amounts due within one year		(141)		(295)
Total long-term debt due after one year		$	4,674	$	7,601

(a) These notes contain a make-whole provision allowing us the right to repay the debt at a premium to market price.

(b) In the event of a change in control, as defined in the related agreements, debt obligations totaling $431 million at December 31, 2011, may be declared immediately due and payable.

The termination date on $2,625 million of our revolving credit facility is May 2013. The remaining $375 million has a termination date of May 2012. The facility requires a representation at an initial borrowing that there has been no change in our consolidated financial position or operations, considered as a whole which would materially and adversely affect our ability to perform our obligations under the revolving credit facility. Interest on the facility is based on defined short-term market rates. During the term of the agreement, we are obligated to pay a variable facility fee on the total commitment, which at December 31, 2011 was 0.10 percent.

Our long-term debt agreements do not contain restrictive financial covenants.

On December 31, 2010, we were obligated (primarily or contingently) for $221 million of debt for which United States Steel assumed responsibility for repayment. During the fourth quarter of 2011, United States Steel called all industrial development and environmental improvement bonds and notes for which they had assumed responsibility.

The following table shows five years of debt payments:

(In millions)
2012	$	141
2013		205
2014		68
2015		68
2016		0

In February and March 2011, we retired the following debt at a weighted average price equal to 112 percent of face value. A $279 million loss on early extinguishment of debt was recognized in the first quarter of 2011. The loss includes related deferred financing and premium costs partially offset by the gain on settled interest rate swaps.

(In millions)
6.000% notes due 2012	$	400
6.125% notes due 2012		450
8.375% secured notes due 2012^{a}		448
6.500% debentures due 2014		700
5.900% notes due 2018		40
7.500% debentures due 2019		460
Total debt purchases	$	2,498

(a) These notes were senior secured notes of Marathon Oil Canada Corporation.

In April 2010, we retired $500 million in aggregate principal of our debt under two tender offers at a weighted average price equal to 117 percent of face value. As a result, we recorded a loss on early extinguishment of debt of $92 million, including the transaction premium as well as the expensing of related deferred financing costs on the debt in the second quarter of 2010.

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligations Disclosure [Abstract]

Asset Retirement Obligations

18. Asset Retirement Obligations

The following summarizes the changes in asset retirement obligations:

(In millions)		2011		2010
Beginning balance		$	1,355	$	1,102
	Incurred, including acquisitions		37		49
	Settled		(39)		(28)
	Accretion expense (included in depreciation, depletion and amortization)		81		70
	Revisions to previous estimates		126		162
	Spin-off downstream business		(50)		-

Ending balance^{a}		$	1,510	$	1,355

Includes asset retirement obligation of $1 million classified as short-term at December 31, 2010.

Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2011

Supplemental Cash Flow Information Disclosure [Abstract]

Supplemental Cash Flow Information

19. Supplemental Cash Flow Information

(In millions)	2011		2010		2009
Net cash provided from operating activities included:
Interest paid (net of amounts capitalized)	$	268	$	107	$	19
Income taxes paid to taxing authorities		2,893		2,155		1,663
Commercial paper and revolving credit arrangements, net:
Commercial paper - issuances	$	421	$	-	$	897
- repayments		(421)		-		(897)
Total	$	-	$	-	$	-
Noncash investing and financing activities related to continuing operations:
Additions to property, plant and equipment
Asset retirement costs capitalized, excluding acquisitions	$	151	$	207	$	135
Change in capital expenditure accrual		104		(140)		(28)
Debt payments made by United States Steel		214		105		144
Capital lease and sale-leaseback financing obligations increase		-		-		9

Defined Benefit Postretirement Plans

12 Months Ended

Dec. 31, 2011

Defined Benefit Postretirement Plans Disclosure [Abstract]

Defined Benefit Postretirement Plans

20. Defined Benefit Postretirement Plans

We have noncontributory defined benefit pension plans covering substantially all domestic employees as well as international employees located in Norway and the United Kingdom. Benefits under these plans are based on plan provisions specific to each plan.

We also have defined benefit plans for other postretirement benefits covering most employees. Health care benefits are provided through comprehensive hospital, surgical and major medical benefit provisions subject to various cost-sharing features. Life insurance benefits are provided to certain retiree beneficiaries. Other postretirement benefits are not funded in advance.

Obligations and funded status – The accumulated benefit obligation for all defined benefit pension plans was $1,231 million and $2,737 million as of December 31, 2011 and 2010.

Summary information for our defined benefit pension plans follows. In 2011, both our U.S. and international plans have accumulated benefit obligations in excess of plan assets, while in 2010 only our U.S. plans had accumulated benefit obligations in excess of plan assets.

	December 31,
	2011				2010
(In millions)		U.S.		Int'l		U.S.
Projected benefit obligation	$	(986)	$	(465)	$	(3,221)
Accumulated benefit obligation		(813)		(418)		(2,365)
Fair value of plan assets		516		412		1,798

The following summarizes the obligations and funded status for our defined benefit pension and other postretirement plans.

			Pension Benefits									Other Benefits
			2011					2010				2011		2010
(In millions)				U.S.			Int'l		U.S.		Int'l
Change in benefit obligations:
	Benefit obligations at January 1		$	3,221	$		415	$	2,989	$	395	$	779	$	685
		Spin-off downstream business		(2,308)			0		0		0		(483)		0
		Service cost		28			19		92		19		4		18
		Interest cost		44			22		153		22		16		39
		Plan amendment		0			11		0		0		0		0
		Actuarial loss		84			13		287		6		1		69
		Foreign currency exchange rate changes		0			(2)		0		(18)		0		0
		Other		0			0		0		6		0		0
		Benefits paid		(83)			(13)		(300)		(15)		(16)		(32)
	Benefit obligations at December 31		$	986		$	465	$	3,221	$	415	$	301	$	779
Change in plan assets:
	Fair value of plan assets at January 1		$	1,798		$	389	$	1,623	$	348	$	0	$	0
		Spin-off downstream business		(1,268)			0		0		0		0		0
		Actual return on plan assets		30			15		214		47		0		0
		Employer contributions		39			23		267		20		0		0
		Foreign currency exchange rate changes		0			(2)		0		(14)		0		0
		Other		0			0		(6)		3		0		0
		Benefits paid		(83)			(13)		(300)		(15)		0		0
	Fair value of plan assets at December 31		$	516		$	412	$	1,798	$	389	$	0	$	0
Funded status of plans at December 31			$	(470)		$	(53)	$	(1,423)	$	(26)	$	(301)	$	(779)
	Amounts recognized in the consolidated
		balance sheet:
		Current liabilities		(17)			0		(21)		0		(18)		(36)
		Noncurrent liabilities		(453)			(53)		(1,402)		(26)		(283)		(743)
	Accrued benefit cost		$	(470)		$	(53)	$	(1,423)	$	(26)	$	(301)	$	(779)
Pretax amounts in accumulated other
	comprehensive income:
	Net loss		$	432		$	63	$	1,382	$	41	$	16	$	18
	Prior service cost (credit)			27			11		81		0		(18)		(24)

Components of net periodic benefit cost and other comprehensive income –The following summarizes the net periodic benefit costs and the amounts recognized as other comprehensive income for our defined benefit pension and other postretirement plans.

		Pension Benefits
		2011				2010				2009				Other Benefits
(In millions)		U.S.	Int'l			U.S.	Int'l			U.S.	Int'l			2011	2010		2009
Components of net periodic benefit cost related to continuing operations:
Service cost	$	28	$	19	$	30	$	19	$	36	$	14	$	4	$	3	$	3
Interest cost		44		22		47		22		46		22		16		16		18
Expected return on plan assets		(43)		(23)		(44)		(22)		(47)		(21)		-		-		-
- prior service cost (credit)		6		-		6		-		6		1		(7)		(7)		(6)
- actuarial loss		47		2		48		5		20		2		-		-		-
Other		-		-		-		2		-		-		-		-		-
Net settlement/curtailment loss^{a}		30		-		56		-		4		18		-		-		-
Net periodic benefit cost^{b}	$	112	$	20	$	143	$	26	$	65	$	36	$	13	$	12	$	15

Other changes in plan assets and benefit
obligations recognized in other
comprehensive income (pretax):
Actuarial loss (gain)	$	97	$	24	$	211	$	(25)	$	587	$	52	$	1	$	69	$	(34)
Amortization of actuarial (loss) gain		(77)		(2)		(167)		(5)		(33)		(7)		-		2		5
Prior service cost		-		(11)		-		-		-		-		-		-		-
Amortization of prior service credit (cost)		(6)		-		(13)		-		(13)		(1)		7		6		5
Spin off downstream business		(24)		-		-		-		-		-		-		-		-
Total recognized in other comprehensive income	$	(10)	$	11	$	31	$	(30)	$	541	$	44	$	8	$	77	$	(24)
Total recognized in net periodic benefit cost and
other comprehensive income	$	102	$	31	$	174	$	(4)	$	606	$	80	$	21	$	89	$	(9)

(a) Settlement losses are recorded when lump sum payments from a plan in a period exceed the plan's total service and interest costs for the period. Such settlements occurred in one or more of our U.S. plans in 2011 and 2010. Additionally, in 2009 a curtailment and settlement was recorded related to our discontinued operations in Ireland as discussed in Note 6.

(b) Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.

The estimated net loss and prior service cost for our defined benefit pension plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost in 2012 are $46 million and $7 million. The estimated prior service credit for our other defined benefit postretirement plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost in 2012 is $7 million.

Plan assumptions – The following summarizes the assumptions used to determine the benefit obligations at December 31, and net periodic benefit cost for the defined benefit pension and other postretirement plans for 2011, 2010 and 2009.

		Pension Benefits
		2011		2010		2009		Other Benefits
(In millions)		U.S.	Int'l	U.S.	Int'l	U.S.	Int'l	2011	2010	2009
Weighted average assumptions used to
	determine benefit obligation:
	Discount rate	4.45%	4.70%	5.05%	5.40%	5.50%	5.70%	4.90%	5.55%	5.95%
	Rate of compensation increase	5.00%	4.30%	5.00%	5.10%	4.50%	5.55%	5.00%	5.00%	4.50%
Weighted average assumptions used to
	determine net periodic benefit cost:
	Discount rate	5.05%	5.40%	5.23%	5.70%	6.90%	6.70%	5.55%	6.85%	6.85%
	Expected long-term return on plan assets^{a}	8.50%	5.86%	8.50%	6.40%	8.50%	6.10%	-	-	-
	Rate of compensation increase	5.00%	5.10%	4.50%	5.55%	4.50%	4.75%	5.00%	4.50%	4.50%

Due to the revised targeted asset allocation as discussed under the plan investment policies and strategies, effective January 1, 2012, the expected long term rate of return on plan assets was changed from 8.50 percent to 7.75 percent.

Expected long-term return on plan assets

U.S. plan – The overall expected long-term return on plan assets assumption for our U.S. plan is determined based on an asset rate-of-return modeling tool developed by a third-party investment group. The tool utilizes underlying assumptions based on actual returns by asset category and inflation and takes into account our U.S. pension plan's asset allocation to derive an expected long-term rate of return on those assets. Capital market assumptions reflect the long-term capital market outlook. The assumptions for equity and fixed income investments are developed using a building-block approach, reflecting observable inflation information and interest rate information available in the fixed income markets. Long-term assumptions for other asset categories are based on historical results, current market characteristics and the professional judgment of our internal and external investment teams.

International plans – To determine the overall expected long-term return on plan assets assumption for our international plans, we consider the current level of expected returns on risk-free investments (primarily government bonds), the historical levels of the risk premiums associated with the other applicable asset categories and the expectations for future returns of each asset class. The expected return for each asset category is then weighted based on the actual asset allocation in our international pension plans to develop the overall expected long-term return on plan assets assumption.

Assumed health care cost trend rates

		2011	2010	2009
Health care cost trend rate assumed for the following year:
	Medical
	Pre-65	7.50%	7.50%	7.00%
	Post-65	7.00%	7.00%	6.75%
	Prescription drugs	7.50%	7.50%	7.50%
Rate to which the cost trend rate is assumed to decline (the ultimate
	trend rate):
	Medical
	Pre-65	5.00%	5.00%	5.00%
	Post-65	5.00%	5.00%	5.00%
	Prescription drugs	5.00%	5.00%	5.00%
Year that the rate reaches the ultimate trend rate:
	Medical
	Pre-65	2018	2018	2014
	Post-65	2017	2017	2015
	Prescription drugs	2018	2018	2015

Assumed health care cost trend rates have a significant effect on the amounts reported for defined benefit retiree health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

		1-Percentage-		1-Percentage-
(In millions)		Point Increase		Point Decrease
Effect on total of service and interest cost components	$	2	$	2
Effect on other postretirement benefit obligations		33		27

Plan investment policies and strategies

The investment policies for our U.S. and international pension plan assets reflect the funded status of the plans and expectations regarding our future ability to make further contributions. Long-term investment goals are to: (1) manage the assets in accordance with the legal requirements of all applicable laws; (2) produce investment returns which meet or exceed the rates of return achievable in the capital markets while maintaining the risk parameters set by the plans' investment committees and protecting the assets from any erosion of purchasing power; and (3) position the portfolios with a long-term risk/return orientation.

U.S. plan – Historical performance and future expectations suggest that common stocks will provide higher total investment returns than fixed income securities over a long-term investment horizon. Short-term investments are utilized for pension payments, expenses, and other liquidity needs. As such, for 2011 and prior, the plan's targeted asset allocation was comprised of 75 percent equity securities and 25 percent fixed income securities. Effective January 1, 2012, the U.S. plan's targeted asset allocation is comprised of 65 percent equity securities and 35 percent fixed income securities but may be adjusted accordingly to better match the plan's liabilities over time as the funded ratio (as defined by the investment policy) changes.

The plan's assets are managed by a third-party investment manager. The investment manager is limited to pursuing the investment strategies regarding asset mix and purchases and sales of securities within the parameters defined in the investment policy guidelines and investment management agreement. Investment performance and risk is measured and monitored on an ongoing basis through quarterly investment meetings and periodic asset and liability studies.

International plans – Our international plans' target asset allocation is comprised of 70 percent equity securities and 30 percent fixed income securities. The plan assets are invested in six separate portfolios, mainly pooled fund vehicles, managed by several professional investment managers. Investments are diversified by industry and type, limited by grade and maturity. The use of derivatives by the investment managers is permitted, subject to strict guidelines. The investment managers' performance is measured independently by a third-party asset servicing consulting firm. Overall, investment performance and risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews and periodic asset and liability studies.

Fair value measurements

Plan assets are measured at fair value. The following provides a description of the valuation techniques employed for each major plan asset class at December 31, 2011 and 2010.

Cash and cash equivalents – Cash and cash equivalents include cash on deposit and an investment in a money market mutual fund that invests mainly in short-term instruments and cash, both of which are valued using a market approach and are considered Level 1 in the fair value hierarchy. The money market mutual fund is valued at the net asset value (“NAV”) of shares held.

Equity securities – Investments in public investment trusts and S&P 500 exchange-traded funds are valued using a market approach at the closing price reported in an active market and are therefore considered Level 1. During the fourth quarter 2011, Level 1 investment trust holdings were liquidated and the proceeds were re-invested in an exchange traded fund. Non-public investment trusts are valued using a market approach based on the underlying investments in the trust, which are publicly-traded securities, and are considered Level 2. Private equity investments include interests in limited partnerships which are valued based on the sum of the estimated fair values of the investments held by each partnership, determined using a combination of market, income and cost approaches, plus working capital, adjusted for liabilities, currency translation and estimated performance incentives. These private equity investments are considered Level 3.

Mutual funds – Investments in mutual funds are valued using a market approach. The shares or units held are traded on the public exchanges and such prices are Level 1 inputs.

Pooled funds – Investments in pooled funds are valued using a market approach at the NAV of units held, but investment opportunities in such funds are limited to institutional investors on the behalf of defined benefit plans. The various funds consist of either an equity or fixed income investment portfolio with underlying investments held in U.S. and non-U.S. securities. Nearly all of the underlying investments are publicly-traded. During the fourth quarter 2011, the U.S. plan's ownership interest held in the fixed income pooled fund was liquidated and the proceeds were re-invested in U.S. treasuries. Further, the U.S. plan's ownership interest held in the equity based pooled fund was liquidated and the proceeds were re-invested in an exchange traded fund. The majority of the pooled funds held by our international pension plans are benchmarked against a relative public index. These are considered Level 2.

U.S. treasuries – U.S. treasury notes are valued at the closing price reported in an active market. These notes are considered Level 1 investments.

Real estate – Real estate investments are valued based on discounted cash flows, comparable sales, outside appraisals, price per square foot or some combination thereof and therefore are considered Level 3.

Other – Other investments are composed of an investment in an unallocated annuity contract, an investment contract with an international insurance carrier, and investments in two limited liability companies (“LLCs”) with no public market. The LLCs were formed to acquire timberland in the northwest and other properties. The investment in an unallocated annuity contract is valued using a market approach based on the experience of the assets held in an insurer's general account and is considered Level 2. The majority of the general account is invested in a well-diversified portfolio of high-quality fixed income securities, primarily consisting of investment-grade bonds. Investment income is allocated among pension plans participating in the general account based on the investment year method. Under this method, a record of the book value of assets held is maintained in subdivisions according to the calendar year in which the funds are invested. The earnings rate for each of these calendar year subdivisions varies from year to year, reflecting the actual earnings on the assets attributed to that year. The insurance carrier contract is funded by premiums paid annually by the participating plans and the funds are invested by the insurance carrier in portfolios with different risk profiles (low, medium, high) that can be elected by investors. The contract is valued using a market approach based on the underlying investments within the portfolio and is considered Level 2. The majority of the underlying investments consists of a well-diversified mix of non-U.S. publicly traded equity and fixed income securities. The values of the LLCs are determined using an income approach based on discounted cash flows and are considered Level 3.

The following table presents the fair values of our defined benefit pension plans' assets, by level within the fair value hierarchy, as of December 31, 2011 and 2010.

		December 31, 2011
(In millions)		Level 1				Level 2				Level 3				Total
		U.S.		Int'l		U.S.		Int'l		U.S.		Int'l		U.S.		Int'l
Cash and cash equivalents	$	12	$	2	$	-	$	-	$	-	$	-	$	12	$	2
Equity securities:
Investment trusts		-		-		7		-		-		-		7		-
Exchange traded funds		324		-		-		-		-		-		324		-
Private equity		-		-		-		-		23		-		23		-
Investment funds
Mutual funds - equity^{a}		-		159		-		-		-		-		-		159
Pooled funds - equity^{b}		-		-		-		96		-		-		-		96
Pooled funds - fixed income^{c}		-		-		-		149		-		-		-		149
U.S. treasuries		92		-		-		-		-		-		92		-
Real estate^{d}		-		-		-		-		21		-		21		-
Other		-		-		30^{e}		6		7		-		37		6
Total investments, at fair value	$	428	$	161	$	37	$	251	$	51	$	-	$	516^{f}	$	412

		December 31, 2010
(In millions)		Level 1				Level 2				Level 3				Total
		U.S.		Int'l		U.S.		Int'l		U.S.		Int'l		U.S.		Int'l
Cash and cash equivalents	$	8	$	1	$	-	$	-	$	-	$	-	$	8	$	1
Equity securities:
Investment trusts		25		0		137		-		-		-		162		-
Exchange traded funds		56		0		-		-		-		-		56		-
Private equity		-		-		-		-		67		-		67		-
Investment funds
Mutual funds - equity^{a}		-		161		-		-		-		-		0		161
Pooled funds - equity^{b}		-		-		1,072		97		-		-		1,072		97
Pooled funds - fixed income^{c}		-		-		350		126		-		-		350	0	126
Real estate^{d}		-		-		-		0		54		-		54		-
Other		-		-		5		4		24		-		29		4
Total investments, at fair value	$	89	$	162	$	1,564	$	227	$	145	$	0	$	1,798	$	389

(a) Includes approximately 70 percent of investments held in U.S. and non-U.S. common stocks in the financial services, consumer staples, health care, energy and basic material sectors and 30 percent of investments held among various other sectors. The funds objective is to outperform their respective benchmark indexes FTSE All Share, MSCI World Free, and MSCI Europe (excluding the U.K.) as defined by the investment policy.

(b) U.S. – At December 31, 2010, includes approximately 70 percent of investments held in U.S. and non-U.S. publicly traded common stocks in the consumer staples, consumer discretionary, technology, health and energy sectors and 30 percent of investments held among various other sectors. Int'l – Includes approximately 70 percent of investments held in non-U.S. common stocks (specifically Asia Pacific, except Japan, and the U.K.) in the financials, energy, consumer staples, industrials, and telecommunication services sectors and the 30 percent of investments held amongst various other sectors. The funds objective is to outperform their respective benchmark indexes, MSCI AC Asia and FTSE All-Share, as defined by the investment policy.

(c) U.S. – At December 31, 2010, includes approximately 80 percent of investments held in U.S. and non-U.S. publicly traded investment grade government and corporate bonds which include treasuries, mortgage-backed securities and industrials and 20 percent of investments held among various other sectors. Int'l – Includes approximately 80 percent of investments held in U.S. and non-U.S. publicly traded investment grade government and corporate bonds which include gilts, treasuries, financials, sovereigns and collateralized asset backed securities and 20 percent of investments held among various other sectors. The funds objective is to outperform their respective benchmark indexes, as defined by the investment policy.

(d) Includes investments diversified by property type and location. The largest property sector holdings, which represent approximately 70 percent of investments held, are office, hotel, residential and land with the greatest percentage of investments made in the U.S. and Asia, which includes the emerging markets of China and India.

(e) Includes an $18 million receivable for the sale of an investment that closed as of December 31, 2011 but did not cash settle until the next business day.

The following is a reconciliation of the beginning and ending balances recorded for plan assets classified as Level 3 in the fair value hierarchy.

	2011
(In millions)		Private Equity		Real Estate		Other		Total
Beginning balance	$	67	$	54	$	24	$	145
Spin-off downstream business		(46)		(37)		(17)		(100)
Actual return on plan assets		3		2		-		5
Purchases		3		4		-		7
Sales		(4)		(2)		-		(6)
Ending balance	$	23	$	21	$	7	$	51

	2010
(In millions)		Private Equity		Real Estate		Other		Total
Beginning balance	$	42	$	36	$	23	$	101
Actual return on plan assets		13		4		1		18
Purchases		15		17		-		32
Sales		(3)		(3)		-		(6)
Ending balance	$	67	$	54	$	24	$	145

Cash flows

Contributions to defined benefit plans – We expect to make contributions to the funded pension plans of up to $113 million in 2012. Cash contributions to be paid from our general assets for the unfunded pension and postretirement plans are expected to be approximately $18 million and $21 million in 2012.

Estimated future benefit payments – The following gross benefit payments, which reflect expected future services, as appropriate, are expected to be paid in the years indicated.

	Pension Benefits					Other
(In millions)		U.S.		Int'l		Benefits^{a}
2012	$	104	$	12	$	21
2013		100		13		22
2014		102		15		22
2015		101		16		23
2016		104		18		24
2017 through 2021		482		105		121

a) Expected Medicare reimbursements for 2012 through 2013 total $5 million. Effective 2013, as a result of the PPACA, future Medicare reimbursements will no longer be tax deductible and must be used to reduce the costs of providing Medicare Part D equivalent prescription drug benefits to retirees. The total of these future reimbursements from 2014 through 2021 is $22 million.

Contributions to defined contribution plans – We contribute to several defined contribution plans for eligible employees. Contributions to these plans related to continuing operations totaled $50 million in 2011, $75 million in 2010 and $59 million in 2009.

- Definition

The entire disclosure for pension and other postretirement benefits.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph h
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph q
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 8
-Subparagraph m
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 106
-Paragraph 518
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 87
-Paragraph 264
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 03-2
-Paragraph 8
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
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Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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+ Details

Incentive Based Compensation

12 Months Ended

Dec. 31, 2011

Stock Based Compensation Plans Disclosure [Abstract]

Stock-Based Compensation Plans

21. Incentive Based Compensation

Description of Stock Based Compensation Plans

The Marathon Oil Corporation 2007 Incentive Compensation Plan (the “2007 Plan”) was approved by our stockholders in April 2007 and authorizes the Compensation Committee of the Board of Directors to grant stock options, stock appreciation rights, stock awards (including restricted stock and restricted stock unit awards) and performance awards to employees. The 2007 Plan also allows us to provide equity compensation to our non-employee directors. No more than 34 million shares of our common stock may be issued under the 2007 Plan and no more than 12 million of those shares may be used for awards other than stock options or stock appreciation rights.

Shares subject to awards under the 2007 Plan that are forfeited, are terminated or expire unexercised become available for future grants. If a stock appreciation right is settled upon exercise by delivery of shares of common stock, the full number of shares with respect to which the stock appreciation right was exercised will count against the number of shares of our common stock reserved for issuance under the 2007 Plan and will not again become available under the 2007 Plan. In addition, the number of shares of our common stock reserved for issuance under the 2007 Plan will not be increased by shares tendered to satisfy the purchase price of an award, exchanged for other awards or withheld to satisfy tax withholding obligations. Shares issued as a result of awards granted under the 2007 Plan are generally funded out of common stock held in treasury, except to the extent there are insufficient treasury shares, in which case new common shares are issued.

After approval of the 2007 Plan, no new grants were or will be made from the 2003 Incentive Compensation Plan (the “2003 Plan”). The 2003 Plan replaced the 1990 Stock Plan, the Non-Officer Restricted Stock Plan, the Non-Employee Director Stock Plan, the deferred stock benefit provision of the Deferred Compensation Plan for Non-Employee Directors, the Senior Executive Officer Annual Incentive Compensation Plan and the Annual Incentive Compensation Plan (the “Prior Plans”). No new grants will be made from the Prior Plans. Any awards previously granted under the 2003 Plan or the Prior Plans shall continue to be exercisable in accordance with their original terms and conditions.

Stock based awards under the Plan

Stock options – We grant stock options under the 2007 Plan. Our stock options represent the right to purchase shares of our common stock at its fair market value on the date of grant. Through 2004, certain stock options were granted under the 2003 Plan with a tandem stock appreciation right, which allows the recipient to instead elect to receive cash or our common stock equal to the excess of the fair market value of shares of common stock, as determined in accordance with the 2003 Plan, over the option price of the shares. In general, stock options granted under the 2007 Plan and the 2003 Plan vest ratably over a three-year period and have a maximum term of ten years from the date they are granted.

Stock appreciation rights – Prior to 2005, we granted SARs under the 2003 Plan. No stock appreciation rights have been granted under the 2007 Plan. Similar to stock options, stock appreciation rights represent the right to receive a payment equal to the excess of the fair market value of shares of common stock on the date the right is exercised over the grant price. Under the 2003 Plan, certain SARs were granted as stock-settled SARs and others were granted in tandem with stock options. In general, SARs granted under the 2003 Plan vest ratably over a three-year period and have a maximum term of ten years from the date they are granted.

Restricted stock – We grant restricted stock and restricted stock units under the 2007 Plan and previously granted such awards under the 2003 Plan. In 2005, the Compensation Committee began granting time-based restricted stock to certain of our U.S.-based officers as part of their annual long-term incentive package. The restricted stock awards to officers vest three years from the date of grant, contingent on the recipient's continued employment. We also grant restricted stock to certain non-officer employees and restricted stock units to certain international employees (“restricted stock awards”), based on their performance within certain guidelines and for retention purposes. The restricted stock awards to non-officers generally vest in one-third increments over a three-year period, contingent on the recipient's continued employment, however, certain restricted stock awards will vest over a four-year period, contingent on the recipient's continued employment. Prior to vesting, all restricted stock recipients have the right to vote such stock and receive dividends thereon. The non-vested shares are not transferable and are held by our transfer agent.

Common stock units – We maintain an equity compensation program for our non-employee directors under the 2007 Plan and previously maintained such a program under the 2003 Plan. All non-employee directors receive annual grants of common stock units, and they are required to hold units granted prior to 2012 until they leave the Board of Directors. When dividends are paid on our common stock, directors receive dividend equivalents in the form of additional common stock units.

Total stock based compensation expense

Total employee stock based compensation expense related to continuing operations was $65 million, $51 million and $59 million in 2011, 2010 and 2009, while the total related income tax benefits were $23 million, $19 million and $22 million in the same years. In 2011, 2010 and 2009 cash received upon exercise of stock option awards related was $77 million, $12 million and $4 million. Tax benefits realized for deductions for stock awards exercised during 2011, 2010 and 2009 totalled $32 million, $11 million and $10 million.

Stock option awards

During 2011, 2010 and 2009, we granted stock option awards to both officer and non-officer employees. The weighted average grant date fair value of these awards was based on the following Black-Scholes assumptions:

	2011			2010			2009
Weighted average exercise price per share	$	32.30		$	30.00		$	27.62
Expected annual dividend yield		2.1	%		3.2	%		3.5	%
Expected life in years		5.3			5.1			4.9
Expected volatility		40	%		43	%		41	%
Risk-free interest rate		1.7	%		2.2	%		2.3	%

Weighted average grant date fair value of stock option awards granted	$	10.44		$	8.70		$	7.67

The following is a summary of stock option award activity in 2011.

				Weighted Average Exercise price
		Number
		of Shares
Outstanding at beginning of year		24,912,261	$	24.85
	Granted	7,676,544		32.30
	Exercised	(3,576,373)		15.12
	Cancelled	(652,607)		25.88
	Spin-off downstream business	(6,989,110)		30.94
Outstanding at end of year		21,370,715	$	24.41

The intrinsic value of stock option awards exercised during 2011, 2010 and 2009 was $59 million, $8 million and $3 million.

The following table presents information related to stock option awards at December 31, 2011.

		Outstanding				Exercisable
			Weighted Average Remaining Contractual Life
	Range of	Number			Weighted	Number		Weighted
	Exercise	of Shares			Average	of Shares		Average
	Prices	Under Option			Exercise Price	Under Option		Exercise Price
$	7.99-12.75	1,272,745	2	$	10.23	1,272,745	$	10.23
	12.76-16.81	2,850,590	5		15.21	2,354,373		15.28
	16.82-23.20	6,642,268	8		18.60	2,810,120		18.52
	23.21-29.24	2,021,400	4		23.92	1,955,767		23.82
	29.25-30.36	22,388	7		29.56	22,388		29.56
	30.37-47.91	8,561,324	7		34.20	4,690,067		35.75
	Total	21,370,715	6		24.41	13,105,460		24.11

As of December 31, 2011, the aggregate intrinsic value of stock option awards outstanding was $146 million. The aggregate intrinsic value and weighted average remaining contractual life of stock option awards currently exercisable were $98 million and 5 years.

As of December 31, 2011, the number of fully-vested stock option awards and stock option awards expected to vest was 21,142,660. The weighted average exercise price and weighted average remaining contractual life of these stock option awards were $24.38 and 6 years and the aggregate intrinsic value was $145 million. As of December 31, 2011, unrecognized compensation cost related to stock option awards was $36 million, which is expected to be recognized over a weighted average period of 2 years.

Restricted stock awards

The following is a summary of restricted stock award activity

					Weighted Average
					Grant Date
		Awards			Fair Value
Unvested at beginning of year		2,084,680		$	23.03
	Granted	3,066,978	^{a}		27.74
	Vested	(993,949)			27.34
	Forfeited	(163,806)			23.88
	Spin-off downstream business	(289,925)			21.30
Unvested at end of year		3,703,978			25.88

(a) Beginning in August, 2011, most employees on the U.S., U.K., Canadian and Norwegian payrolls are eligible for a restricted stock grant, based on performance.

The vesting date fair value of restricted stock awards which vested during 2011, 2010 and 2009 was $30 million, $21 million and $24 million. The weighted average grant date fair value of restricted stock awards was $25.88, $23.03, and $44.89 for awards unvested at December 31, 2011, 2010 and 2009.

As of December 31, 2011, there was $78 million of unrecognized compensation cost related to restricted stock awards which is expected to be recognized over a weighted average period of 2.5 years.

Performance unit awards

Performance units provide for named executive officers to receive a cash payment upon the achievement of certain performance goals at the end of a defined measurement period. The performance goals are tied to our total shareholder return (“TSR”) as compared to TSR for a group of peer companies determined by the Compensation Committee of the Board of Directors. The target value of each performance unit is $1, with the actual payout varying from $0 to $2 per unit (capped at a maximum payout of $2 per unit). Because performance units are to be settled in cash at the end of the performance period, they are accounted for as liability awards. Compensation expense related to continuing operations associated with performance units was $32 million and $2 million in 2011 and 2009, but was not significant in 2010. Expense for 2011 included $14 million paid on three groups of performance unit grants outstanding June 30, 2011, that were accelerated with the total payout determined based on performance through the effective date of the spin-off of our downstream business.

During the third quarter of 2011, we granted 15 million performance units to named executive officers. A portion of these units have an 18-month performance period and a portion have a 30-month performance period to reflect the remaining periods of the original 2011 and 2010 performance unit grants outstanding prior to the spinoff.

- Definition

The entire disclosure for compensation-related costs for equity-based compensation, which may include disclosure of policies, compensation plan details, allocation of equity compensation, incentive distributions, equity-based arrangements to obtain goods and services, deferred compensation arrangements, employee stock ownership plan details and employee stock purchase plan details.

+ References

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-Name Statement of Financial Accounting Standard (FAS)
-Number 123R
-Paragraph 64, 65, A240
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-Name Statement of Position (SOP)
-Number 93-6
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-Name Staff Accounting Bulletin (SAB)
-Number Topic 14

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+ Details

Stockholders' Equity

12 Months Ended

Dec. 31, 2011

Stockholders Equity Disclosure [Abstract]

Stockholders' Equity

22. Stockholders' Equity

Securities exchangeable into Marathon common stock – In conjunction with our acquisition of Western Oil Sands Inc. (“Western”) on October 18, 2007, Canadian residents were able to receive, at their election, cash, Marathon common stock or securities exchangeable into Marathon common stock (the “Exchangeable Shares”). The Exchangeable Shares were shares of an indirect Canadian subsidiary of Marathon and were exchanged into Marathon stock based upon an exchange ratio that began at one-for-one and adjusted quarterly to reflect cash dividends. The Exchangeable Shares were exchangeable at the option of the holder at any time and were automatically redeemable on October 18, 2011. They could also be redeemed prior to their automatic redemption if certain conditions were met. Those conditions were met and we filed notice of the proposed redemption in Canada on March 3, 2010. On April 7, 2010, the remaining exchangeable shares were redeemed.

Preferred shares – Also in connection with our acquisition of Western, the Board of Directors authorized a class of voting preferred stock. Upon completion of the acquisition, we issued shares of this voting preferred stock to a trustee, who held the shares for the benefit of the holders of the Exchangeable Shares discussed above. Each share of voting preferred stock was entitled to one vote on all matters submitted to the holders of Marathon common stock. Each holder of Exchangeable Shares could direct the trustee to vote the number of shares of voting preferred stock equal to the number of shares of Marathon common stock issuable upon the exchange of the Exchangeable Shares held by that holder. In no event would the aggregate number of votes entitled to be cast by the trustee with respect to the outstanding shares of voting preferred stock exceed the number of votes entitled to be cast with respect to the outstanding Exchangeable Shares. Except as otherwise provided in our restated certificate of incorporation or by applicable law, the common stock and the voting preferred stock voted together as a single class in the election of directors of Marathon and on all other matters submitted to a vote of stockholders of Marathon generally. The voting preferred stock had no other voting rights except as required by law. Other than dividends payable solely in shares of voting preferred stock, no dividend or other distribution, was paid or payable to the holder of the voting preferred stock. In the event of any liquidation, dissolution or winding up of Marathon, the holder of shares of the voting preferred stock would not be entitled to receive any assets of Marathon available for distribution to its stockholders. The voting preferred stock was not convertible into any other class or series of the capital stock of Marathon or into cash, property or other rights, and could not be redeemed. In connection with the redemption of the Exchangeable Shares, these preferred shares were eliminated in June 2010.

Share repurchase plan – The Board of Directors has authorized the repurchase of up to $5 billion of our common stock. Purchases under the program may be in either open market transactions, including block purchases, or in privately negotiated transactions using cash on hand, cash generated from operations, proceeds from potential asset sales or cash from available borrowings to acquire shares. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion. The repurchase program does not include specific price targets or timetables. As of December 31, 2011, we had acquired 78 million common shares at a cost of $3,222 million under this authorized share repurchase program, including 12 million common shares acquired during 2011 at a cost of $300 million.

- Definition

The entire disclosure for shareholders' equity, comprised of portions attributable to the parent entity and noncontrolling interest, if any, including other comprehensive income (as applicable). Including, but not limited to: (1) balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings; (2) accumulated balance for each classification of other comprehensive income and total amount of comprehensive income; (3) amount and nature of changes in separate accounts, including the number of shares authorized and outstanding, number of shares issued upon exercise and conversion, and for other comprehensive income, the adjustments for reclassifications to net income; (4) rights and privileges of each class of stock authorized; (5) basis of treasury stock, if other than cost, and amounts paid and accounting treatment for treasury stock purchased significantly in excess of market; (6) dividends paid or payable per share and in the aggregate for each class of stock for each period presented; (7) dividend restrictions and accumulated preferred dividends in arrears (in aggregate and per share amount); (8) retained earnings appropriations or restrictions, such as dividend restrictions; (9) impact of change in accounting principle, initial adoption of new accounting principle and correction of an error in previously issued financial statements; (10) shares held in trust for Employee Stock Ownership Plan (ESOP); (11) deferred compensation related to issuance of capital stock; (12) note received for issuance of stock; (13) unamortized discount on shares; (14) description, terms, and number of warrants or rights outstanding; (15) shares under subscription and subscription receivables, effective date of new retained earnings after quasi-reorganization and deficit eliminated by quasi-reorganization and, for a period of at least ten years after the effective date, the point in time from which the new retained dates; and (16) retroactive effective of subsequent change in capital structure.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 12
-Paragraph 10
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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-Number 43
-Chapter 1
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-Paragraph 7, 11A
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+ Details

Leases

12 Months Ended

Dec. 31, 2011

Leases Of Lessee Disclosure [Abstract]

Leases of Lessee Disclosure [Text Block]

23. Leases

We lease a wide variety of facilities and equipment under operating leases, including land, building space, equipment and vehicles. Most long-term leases include renewal options and, in certain leases, purchase options. Future minimum commitments for capital lease obligations (including sale-leasebacks accounted for as financings) and for operating lease obligations having initial or remaining noncancelable lease terms in excess of one year are as follows:

(In millions)		Capital Lease Obligations		Operating Lease Obligations
2012		$	22	$	42
2013			1		38
2014			1		29
2015			1		26
2016			1		25
Later years			25		66
Sublease rentals			0		(2)
	Total minimum lease payments	$	51	$	224
Less imputed interest costs			(20)
	Present value of net minimum lease payments	$	31

Operating lease rental expense related to continuing operations was $74 million, $77 million and $105 million in 2011, 2010 and 2009, which excludes $16 million and $3 million paid by United States Steel on assumed leases in 2010 and 2009.

- Definition

The entire disclosure for lessee entity's leasing arrangements including, but not limited to, all of the following: (a.) The basis on which contingent rental payments are determined, (b.) The existence and terms of renewal or purchase options and escalation clauses, (c.) Restrictions imposed by lease agreements, such as those concerning dividends, additional debt, and further leasing.

+ References + Details

Commitments and Contingencies

12 Months Ended

Dec. 31, 2011

Commitments And Contingencies [Abstract]

Commitments and Contingencies

24. Commitments and Contingencies

We are a defendant in a number of lawsuits arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims and environmental claims. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe that the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. Certain of these matters are discussed below.

Litigation - In March 2011, Noble Drilling (U.S.) LLC (“Noble”) filed a lawsuit against us in the District Court of Harris County, Texas alleging, among other things, breach of contract, breach of the duty of good faith and fair dealing, and negligent misrepresentation, relating to a multi-year drilling contract for a newly constructed drilling rig to be deployed in the U.S. Gulf of Mexico. We filed an answer in April 2011, contending, among other things, failure to perform, failure to comply with material obligations, failure to mitigate alleged damages and that Noble failed to provide the rig according to the operating, performance and safety requirements specified in the drilling contract. Noble is seeking an unspecified amount of damages. We are vigorously defending this litigation. The ultimate outcome of this lawsuit, including any financial effect on us, remains uncertain. We do not believe an estimate of a reasonably probable loss (or range of loss) can be made for this lawsuit at this time.

Environmental matters – We are subject to federal, state, local and foreign laws and regulations relating to the environment. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance.

At December 31, 2011 and 2010, accrued liabilities for remediation totaled $1 million and $119 million. It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties that may be imposed.

Guarantees – We have provided certain guarantees, direct and indirect, of the indebtedness of other companies. Under the terms of most of these guarantee arrangements, we would be required to perform should the guaranteed party fail to fulfill its obligations under the specified arrangements. In addition to these financial guarantees, we also have various performance guarantees related to specific agreements.

United States Steel was the sole general partner of Clairton 1314B Partnership, L.P., which owned certain facilities formerly owned by United States Steel. We have agreed, under certain circumstances, to indemnify the limited partners if the partnership's product sales fail to qualify for the credit under Section 29 of the Internal Revenue Code. The Clairton 1314B Partnership was terminated on October 31, 2008, but we were not released from our obligations. United States Steel has estimated the maximum potential amount of this indemnity obligation, including interest and tax gross-up, was approximately $110 million as of December 31, 2011, all of which is related to our continuing operations.

We have entered into other guarantees related to our continuing operations with maximum potential undiscounted payments totaling $139 million as of December 31, 2011, which consist primarily of leases of corporate assets containing general lease indemnities and guaranteed residual values, a performance guarantee and a long-term transportation services agreement.

In October 2010, upon acquiring a position in four exploration blocks in the Iraqi Kurdistan Region, we indemnified the KRG against any negative tax effects related to certain payments we are obligated to make to the KRG. As of December 31, 2011, some of those payments had been made, no related taxes have been assessed, and neither is there any history of such payments being taxed. Given the lack of history of tax assessment against such payments, and because certain of our future payments to the KRG are not quantifiable, a maximum potential undiscounted payments cannot be calculated.

Over the years, we have sold various assets in the normal course of our business. Certain of the related agreements contain performance and general guarantees, including guarantees regarding inaccuracies in representations, warranties, covenants and agreements, and environmental and general indemnifications that require us to perform upon the occurrence of a triggering event or condition. These guarantees and indemnifications are part of the normal course of selling assets. We are typically not able to calculate the maximum potential amount of future payments that could be made under such contractual provisions because of the variability inherent in the guarantees and indemnities. Most often, the nature of the guarantees and indemnities is such that there is no appropriate method for quantifying the exposure because the underlying triggering event has little or no past experience upon which a reasonable prediction of the outcome can be based.

Contract commitments – At December 31, 2011 and 2010, contractual commitments of our continuing operations to acquire property, plant and equipment totaled $2,683 million and $1,881 million.

Other contingencies - During the second quarter of 2011, the AOSP operator determined the need and developed preliminary plans to address water flow into a previously mined and contained section of the Muskeg River mine. Our share of the estimated costs in the amount of $64 million was recorded to cost of revenues. At December 31, 2011, the remaining liability is $49 million.

- Definition

The entire disclosure for commitments and contingencies.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 14
-Paragraph 3
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 9, 10, 11, 12
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.25)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 450
-SubTopic 20
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6952336&loc=d3e14435-108349

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 460
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6398077&loc=d3e12565-110249

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 440
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6394976&loc=d3e25287-109308

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6449706&loc=d3e16207-108621

+ Details

Summary of Principal Accounting Policies (Policies)	12 Months Ended
Summary of Principal Accounting Policies (Policies)	Dec. 31, 2011
Accounting Policies [Abstract]
Nature Of Operations	We are engaged in worldwide exploration, production and marketing of liquid hydrocarbons and natural gas; oil sands mining and bitumen transportation and upgrading in Canada; and production and marketing of products manufactured from natural gas, such as LNG and methanol in EG.
Consolidation Policy [Text Block]	Principles applied in consolidation - These consolidated financial statements include the accounts of our majority-owned, controlled subsidiaries and variable interest entities for which we are the primary beneficiary. Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting. This includes entities in which we hold majority ownership but the minority shareholders have substantive participating rights in the investee. Income from equity method investments represents our proportionate share of net income generated by the equity method investees. Equity method investments are carried at our share of net assets plus loans and advances. Such investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other than temporary. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in net income. Differences in the basis of the investments and the separate net asset value of the investees, if any, are amortized into net income over the remaining useful lives of the underlying assets, except for the excess related to goodwill. Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis. As a result of the spin-off of our downstream business (see Note 3), the results of operations and cash flows for the downstream business have been classified as discontinued operations for all periods presented. The disclosures in this report related to results of operations and cash flows are presented on the basis of continuing operations unless otherwise stated.
Use of Estimates, Policy [Policy Text Block]	Use of estimates - The preparation of financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods.
Foreign Currency Transactions And Translations Policy [Text Block]	Foreign currency transactions - The U.S. dollar is the functional currency of our foreign operating subsidiaries. Foreign currency transaction gains and losses are included in net income.
Revenue Recognition Policy [Text Block]	Revenue recognition - Revenues are recognized when products are shipped or services are provided to customers, title is transferred, the sales price is fixed or determinable and collectability is reasonably assured. Costs associated with revenues are recorded in cost of revenues. In the lower 48 states of the U.S., production volumes of liquid hydrocarbons and natural gas are sold immediately and transported to market. In Alaska and international locations, liquid hydrocarbon and natural gas production volumes may be stored as inventory and sold at a later time. In Canada, mined bitumen is first processed through an upgrader and then sold as synthetic crude oil. Both bitumen and synthetic crude oil may be stored as inventory.
Gas Balancing, Policy [Policy Text Block]	We follow the sales method of accounting for crude oil and natural gas production imbalances and would recognize a liability if our existing proved reserves were not adequate to cover an imbalance. Imbalances have not been significant in the periods presented.
Cash And Cash Equivalents Policy [Text Block]	Cash and cash equivalents - Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with original maturities of three months or less.
Receivables, Policy [Policy Text Block]	Accounts receivable - The majority of our receivables are from joint interest owners in properties we operate, or purchasers of liquid hydrocarbons, are recorded at invoiced amounts and do not bear interest. We determine the allowance for doubtful accounts based on historical write-off experience. Past-due balances over 180 days are reviewed individually for collectability..
Inventory Policy [Text Block]	Inventories - Inventories are carried at the lower of cost or market value. The majority of our inventories are recorded at average cost. The last-in, first-out (“LIFO”) method is used for domestic natural gas inventory.
Matching Buy Sell Policy [Text Block]	We may enter into a contract to sell a particular quantity and quality of crude oil at a specified location and date to a particular counterparty, and simultaneously agree to buy a particular quantity and quality of the same commodity at a specified location on the same or another specified date from the same counterparty. We account for such matching buy/sell arrangements as exchanges of inventory.
Derivatives Policy [Text Block]	Derivative instruments - We may use derivatives to manage a portion of our exposure to commodity price risk, interest rate risk and foreign currency exchange rate risk. All derivative instruments are recorded at fair value. Commodity derivatives are reflected on our consolidated balance sheet on a net basis by brokerage firm, as they are governed by master netting agreements. Cash flows related to derivatives used to manage commodity price risk, interest rate risk and foreign currency exchange rate risk related to operating expenditures are classified in operating activities with the underlying transactions. Cash flows related to derivatives used to manage exchange rate risk related to capital expenditures denominated in foreign currencies are classified in investing activities with the underlying transactions. Our derivative instruments contain no significant contingent credit features. Concentrations of credit risk - All of our financial instruments, including derivatives, involve elements of credit and market risk. The most significant portion of our credit risk relates to nonperformance by counterparties. The counterparties to our financial instruments consist primarily of major financial institutions and companies within the energy industry. To manage counterparty risk associated with financial instruments, we select and monitor counterparties based on our assessment of their financial strength and on credit ratings, if available. Additionally, we limit the level of exposure with any single counterparty.
Derivatives, Methods of Accounting, Hedging Derivatives [Policy Text Block]	Cash flow hedges - We may use foreign currency forwards and options to manage foreign currency risk associated with anticipated transactions, primarily expenditures for capital projects denominated in certain foreign currencies, and designate them as cash flow hedges. The effective portion of changes in fair value is recognized in other comprehensive income (“OCI”) and is reclassified to net income when the underlying forecasted transaction is recognized in net income. Any ineffective portion is recognized in net interest and other as it occurs. For a discontinued cash flow hedge, prospective changes in the fair value of the derivative are recognized in net income. The accumulated gain or loss recognized in OCI at the time a hedge is discontinued continues to be deferred until the original forecasted transaction occurs. However, if it is determined that the likelihood of the original forecasted transaction occurring is no longer probable, the entire accumulated gain or loss recognized in OCI is immediately reclassified into net income. We may use interest rate derivative instruments to manage the risk of interest rate changes during the period prior to anticipated borrowings and designate them as cash flow hedges. No such derivatives were outstanding at December 31, 2011 and 2010. Fair value hedges - We may use interest rate swaps to manage our exposure to interest rate risk associated with fixed interest rate debt in our portfolio and we may use commodity derivative instruments to manage the price risk on natural gas that we purchase to be marketed with our natural gas production. Changes in the fair values of both the hedged item and the related derivative are recognized immediately in net income with an offsetting effect included in the basis of the hedged item. The net effect is to report in net income the extent to which the hedge is not effective in achieving offsetting changes in fair value.
Derivatives, Methods of Accounting, Derivatives Not Designated or Qualifying as Hedges [Policy Text Block]	Derivatives not designated as hedges - Derivatives that are not designated as hedges may include commodity derivatives used primarily to manage price risk on the forecasted sale of crude oil, natural gas and synthetic crude oil that we produce. Changes in the fair value of derivatives not designated as hedges are recognized immediately in net income.
Full Cost or Successful Efforts, Policy [Policy Text Block]	Property, plant and equipment - We use the successful efforts method of accounting for oil and gas producing activities, which include our bitumen mining and upgrading.
Costs Incurred, Policy [Policy Text Block]	Property acquisition costs - Costs to acquire mineral interests in traditional oil and natural gas properties or in oil sands mines, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells and to construct or expand oil sand mines and upgrading facilities are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves but cannot yet be classified as proved are capitalized if (1) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (2) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. The status of suspended well costs is monitored continuously and reviewed at least quarterly.
Property Plant And Equipment Policy [Text Block]	Depreciation, depletion and amortization - Capitalized costs to acquire oil and natural gas properties, which include our bitumen mining and upgrading facilities, are depreciated and depleted on a units-of-production basis based on estimated proved reserves. Capitalized costs of exploratory wells and development costs are depreciated and depleted on a units-of-production basis based on estimated proved developed reserves. Support equipment and other property, plant and equipment related to oil and gas producing activities are depreciated on a straight-line basis over their estimated useful lives which range from 3 to 43 years. Property, plant and equipment unrelated to oil and gas producing activities is recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets, which range from 3 to 40 years.
Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block]	Impairments - We evaluate our oil and gas producing properties, including capitalized costs of exploratory wells, development costs and our bitumen mining and upgrading facilities, for impairment of value whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. Oil and gas producing properties are reviewed for impairment on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure. Impairment of proved properties is required when the carrying value exceeds the related undiscounted future net cash flows based on proved and probable reserves. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows or, if available, comparable market value. We evaluate our unproved property investment and record impairment based on time or geologic factors in addition to the use of an undiscounted future net cash flow approach. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage are also considered. Unproved property investments deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows. Impairment expense for unproved oil and natural gas properties is reported in exploration expenses.
Property Plant And Equipment Dispositions Policy [Text Block]	Dispositions - When property, plant and equipment depreciated on an individual basis are sold or otherwise disposed of, any gains or losses are reported in net income. Gains on the disposal of property, plant and equipment are recognized when earned, which is generally at the time of closing. If a loss on disposal is expected, such losses are recognized when the assets are classified as held for sale. Proceeds from the disposal of property, plant and equipment depreciated on a group basis are credited to accumulated depreciation, depletion and amortization with no immediate effect on net income until net book value is reduced to zero.
Goodwill and Intangible Assets, Policy [Policy Text Block]	Goodwill - Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Such goodwill is not amortized, but rather is tested for impairment annually and when events or changes in circumstances indicate that the fair value of a reporting unit with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then the recorded goodwill is impaired to its implied fair value with a charge to operating expense.
Property, Plant and Equipment, Planned Major Maintenance Activities, Policy [Policy Text Block]	Major maintenance activities - Costs for planned major maintenance are expensed in the period incurred. These types of costs include contractor repair services, materials and supplies, equipment rentals and our labor costs.
Environmental Costs, Policy [Policy Text Block]	Environmental costs - Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. We provide for remediation costs and penalties when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. The timing of remediation accruals coincides with completion of a feasibility study or the commitment to a formal plan of action. Remediation liabilities are accrued based on estimates of known environmental exposure and are discounted when the estimated amounts are reasonably fixed and determinable.
Asset Retirement Obligations, Policy [Policy Text Block]	Asset retirement obligations - The fair value of asset retirement obligations is recognized in the period in which the obligations are incurred if a reasonable estimate of fair value can be made. Our asset retirement obligations primarily relate to the abandonment of oil and gas producing facilities, which include our bitumen mining facilities. Asset retirement obligations for such facilities include costs to dismantle and relocate or dispose of production platforms, mine assets, gathering systems, wells and related structures and restoration costs of land and seabed, including those leased. Estimates of these costs are developed for each property based on the type of production structure, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering professionals. Asset retirement obligations have not been recognized for certain of our international oil and gas producing facilities as we currently do not have a legal obligation associated with the retirement of those facilities. Asset retirement obligations have not been recognized for the removal of materials and equipment from or the closure of certain bitumen upgrading assets because the fair value cannot be reasonably estimated since the settlement dates of the obligations are indeterminate. Current inflation rates and credit-adjusted-risk-free interest rates are used to estimate the fair value of asset retirement obligations. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is generally determined on a units-of-production basis for oil and gas production facilities, which include our bitumen mining facilities, while accretion escalates over the lives of the assets.
Income Tax Policy [Text Block]	Deferred income taxes - Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax bases as reported in our filings with the respective taxing authorities. Deferred tax assets are recorded when it is more likely than not that they will be realized. The realization of deferred tax assets is assessed periodically based on several interrelated factors. These factors include our expectation to generate sufficient future taxable income including future foreign source income, tax credits, operating loss carryforwards and management's intent regarding the permanent reinvestment of the income from certain foreign subsidiaries.
Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block]	Stock based compensation arrangements - The fair value of stock options, stock options with tandem stock appreciation rights (“SARs”) and stock-settled SARs (“stock option awards”) is estimated on the date of grant using the Black-Scholes option pricing model. The model employs various assumptions, based on management's best estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the life of the stock option award. Of the required assumptions, the expected life of the stock option award and the expected volatility of our stock price have the most significant impact on the fair value calculation. We have utilized historical data and analyzed current information which reasonably support these assumptions. The fair value of our restricted stock awards and common stock units is determined based on the fair market value of our common stock on the date of grant. Our stock-based compensation expense is recognized based on management's best estimate of the awards that are expected to vest, using the straight-line attribution method for all service-based awards with a graded vesting feature. If actual forfeiture results are different than expected, adjustments to recognized compensation expense may be required in future periods. Unearned stock-based compensation is charged to stockholders' equity when restricted stock awards are granted. Compensation expense is recognized over the vesting period and is adjusted if conditions of the restricted stock award are not met. Options with tandem SARs are classified as a liability and are remeasured at fair value each reporting period until settlement.

Spin-Off (Tables)

12 Months Ended

Dec. 31, 2011

Spin Off Note Tables [Abstract]

Schedule Of Disposal Groups Including Discontinued Operations Balance Sheet Disclosures [Text Block]

(In millions)
Current assets:
	Cash and cash equivalents		$	1,622
	Receivables			5,041
	Inventories			3,679
	Other current assets			170
		Total current assets of discontinued operations		10,512
Equity method investments				323
Property, plant and equipment				11,935
Goodwill				847
Other noncurrent assets				351
		Total assets of discontinued operations	$	23,968

Current liabilities:
	Accounts payable		$	7,329
	Payroll and benefits payable			222
	Accrued and deferred taxes			443
	Other current liabilities			461
	Long-term debt due within one year			12
		Total current liabilities of discontinued operations		8,467
Long-term debt				3,262
Deferred income taxes				1,568
Defined benefit postretirement plan obligations				1,489
Deferred credits and other liabilities				276
		Total liabilities of discontinued operations	$	15,062

Spin Off Discontinued Operations Disclosure [Text Block]

(In millions)	2011		2010		2009
Revenues applicable to discontinued operations	$	38,602	$	62,488	$	45,529
Pretax income from discontinued operations	$	2,012	$	1,065	$	894

Acquisitions (Tables)

12 Months Ended

Dec. 31, 2011

Business Acquisition, Purchase Price Allocation [Abstract]

Schedule of Purchase Price Allocation [Table Text Block]

(In millions)
Current assets:
	Receivables			$	40
	Inventories				4
	Other current assets				30
		Total current assets acquired			74
Property, plant and equipment					4,501
Other noncurrent assets					21
		Total assets acquired		$	4,596
Current liabilities:
	Accounts payable			$	101
	Other current liabilities				20
		Total current liabilities assumed			121
Asset retirement obligations					5
		Total liabilities assumed			126
			Net assets acquired	$	4,470

Dispositions (Tables)

12 Months Ended

Dec. 31, 2011

Dispositions Note Tables [Abstract]

Discontinued Operations Table

(In millions)	2009
Revenues applicable to discontinued operations	$	188
Pretax income from discontinued operations	$	80

Income per Common Share (Tables)

12 Months Ended

Dec. 31, 2011

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

	2011				2010				2009
(In millions, except per share data)		Basic		Diluted		Basic		Diluted		Basic		Diluted
Income from continuing operations	$	1,707	$	1,707	$	1,882	$	1,882	$	716	$	716
Discontinued operations		1,239		1,239		686		686		747		747

Net income	$	2,946	$	2,946	$	2,568	$	2,568	$	1,463	$	1,463
Weighted average common
shares outstanding		710		710		710		710		709		709
Effect of dilutive securities		-		4		-		2		-		2

Weighted average common shares,
including dilutive effect		710		714		710		712		709		711
Per share:
Income from continuing operations	$	2.40	$	2.39	$	2.65	$	2.65	$	1.01	$	1.01

Discontinued operations	$	1.75	$	1.74	$	0.97	$	0.96	$	1.05	$	1.05

Net income	$	4.15	$	4.13	$	3.62	$	3.61	$	2.06	$	2.06

Segment Information (Tables)

12 Months Ended

Dec. 31, 2011

Segment Information Note Tables [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

(In millions)	E&P		OSM		IG		Total
2011
Revenues:
Customer	$	12,922	$	1,588	$	93	$	14,603
Intersegment		47		0		0		47
Related parties		60		0		0		60
Segment revenues		13,029		1,588		93		14,710
Elimination of intersegment revenues		(47)		0		0		(47)
Total revenues	$	12,982	$	1,588	$	93	$	14,663

Segment income	$	2,157	$	256	$	178	$	2,591
Income from equity method investments		249		0		213		462
Depreciation, depletion and amortization		2,028		196		3		2,227
Income tax provision		2,808		82		74		2,964
Capital expenditures		3,038		308		2		3,348

(In millions)	E&P		OSM		IG		Total
2010
Revenues:
Customer	$	10,651	$	833	$	150	$	11,634
Intersegment		75		0		0		75
Related parties		56		0		0		56
Segment revenues		10,782		833		150		11,765
Elimination of intersegment revenues		(75)		0		0		(75)
Total revenues	$	10,707	$	833	$	150	$	11,690

Segment income (loss)	$	1,941	$	(50)	$	142	$	2,033
Income from equity method investments		188		0		181		369
Depreciation, depletion and amortization		1,911		105		2		2,018
Income tax provision (benefit)		2,266		(12)		73		2,327
Capital expenditures		2,474		874		2		3,350

(In millions)	E&P		OSM		IG		Total
2009
Revenues:
Customer	$	7,651	$	692	$	50	$	8,393
Intersegment		28		0		0		28
Related parties		59		0		0		59
Segment revenues		7,738		692		50		8,480
Elimination of intersegment revenues		(28)		0		0		(28)
Gain on U.K. natural gas contracts^{a}		72		0		0		72^{a}
Total revenues	$	7,782	$	692	$	50	$	8,524

Segment income	$	1,218	$	44	$	90	$	1,352
Income from equity method investments		125		0		143		268
Depreciation, depletion and amortization		1,776		124		3		1,903
Income tax provision		1,560		6		39		1,605
Capital expenditures		2,162		1,115		2		3,279

The U.K. natural gas contracts expired in September 2009.

Reconciliation of segment income to net income

(In millions)	2011		2010		2009
Segment income	$	2,591	$	2,033	$	1,352
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items		(326)		(202)		(431)
Foreign currency remeasurement of taxes		9		32		(319)
Impairments^{a}		(195)		(286)		(45)
Loss on early extinguishment of debt		(176)		(57)		0
Tax effect of subsidiary restructuring		(122)		0		0
Deferred income taxes		(61)		(45)		0
Water abatement - Oil Sands		(48)		0		0
Eagle Ford transaction costs		(10)		0		0
Gain on dispositions^{b}		45		407		122
Gain on U.K. natural gas contracts		0		0		37
Income from continuing operations		1,707		1,882		716
Discontinued operations		1,239		686		747
Net income	$	2,946	$	2,568	$	1,463

(a) Significant impairments are further discussed, on a pretax basis, in Note 15.

(b) Significant dispositions are further discussed, on a pretax basis, in Note 6.

Reconciliation of Revenue from Segments to Consolidated [Table Text Block]

(In millions)	2011		2010		2009
Total revenues	$	14,663	$	11,690	$	8,524
Less: Sales to related parties		60		56		59
Sales and other operating revenues	$	14,603	$	11,634	$	8,465

Revenues from customers by geographic area

(In millions)	2011		2010		2009
United States	$	6,971	$	5,363	$	3,326
United Kingdom		1,546		1,063		1,143
Libya^{a}		216		1,473		1,139
Norway		3,386		2,243		1,617
Canada		1,588		833		692
Other international		956		715		607
Total revenues	$	14,663	$	11,690	$	8,524

Long-lived assets by geographic area

(In millions)	2011		2010
United States	$	10,928	$	18,415
Canada		9,711		9,564
Equatorial Guinea		2,214		2,389
Norway		1,133		1,353
Other international		2,721		2,399
Total long-lived assets	$	26,707	$	34,120

Revenues by product line

(In millions)	2011		2010		2009
Liquid hydrocarbons	$	13,298	$	10,312	$	7,343
Natural gas		1,291		1,295		1,126
Transportation & other		74		83		55
Total revenues	$	14,663	$	11,690	$	8,524

- Definition

Tabular disclosure of the profit or loss and total assets for each reportable segment. An entity discloses certain information on each reportable segment if the amounts (a) are included in the measure of segment profit or loss reviewed by the chief operating decision maker or (b) are otherwise regularly provided to the chief operating decision maker, even if not included in that measure of segment profit or loss.

+ References + Details

Other Items (Tables)

12 Months Ended

Dec. 31, 2011

Other Income and Expenses [Abstract]

Schedule Of Net Interest And Other Financing Table [Text Block]

(In millions)	2011		2010		2009
Interest:
Interest income	$	12	$	11	$	8
Interest expense^{a}		(281)		(375)		(262)
Income on interest rate swaps		10		26		17
Interest capitalized		151		297		214
Total interest		(108)		(41)		(23)

Other:
Net foreign currency gains (losses)		24		(21)		(28)
Write-off of contingent proceeds^{b}		(7)		(15)		(70)
Other		(16)		2		(1)
Total other		1		(34)		(99)
Net interest and other	$	(107)	$	(75)	$	(122)

(a) Excludes $10 million, $16 million and $27 million paid by United States Steel in 2011, 2010 and 2009 on assumed debt

Schedule Of Foreign Currency Transactions Table [Text Block]

(In millions)	2011		2010		2009
Net interest and other	$	24	$	(21)	$	(28)
Provision for income taxes		(57)		(1)		(319)

Aggregate foreign currency losses	$	(33)	$	(22)	$	(347)

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2011

Income Taxes Note Tables [Abstract]

Income Tax Provisions (Benefits)

		2011						2010						2009
(In millions)		Current		Deferred		Total		Current		Deferred		Total		Current		Deferred		Total
Federal		$	(210)	$	(206)	$	(416)	$	(279)	$	(267)	$	(546)	$	40	$	(329)	$	(289)
State and local			24		82		106		2		(10)		(8)		(19)		5		(14)
Foreign			3,088		(58)		3,030		2,941		(212)		2,729		1,480		870		2,350
	Total	$	2,902	$	(182)	$	2,720	$	2,664	$	(489)	$	2,175	$	1,501	$	546	$	2,047

Reconciliation of Federal Statutory Income Tax Rate to Provision for Income Taxes

	2011		2010			2009
Statutory rate applied to income from continuing operations before income taxes	35	%		35	%		35	%
Effects of foreign operations, including foreign tax credits	6			20			16
Change in permanent reinvestment assertion	5			-			-
Foreign currency remeasurement	-			-			11
Adjustments to valuation allowances	14			(2)			10
Tax law changes	1			1			-
Other	-			-			2
Effective income tax rate on continuing operations	61	%		54	%		74	%

Deferred Tax Assets and Liabilities

	December 31,
(In millions)	2011		2010
Deferred tax assets:
Employee benefits	$	413	$	1,079
Operating loss carryforwards^{a}		376		285
Foreign tax credits		3,005		2,045
Other		88		141
Valuation allowances
Federal		(791)		(206)
State		(61)		(48)
Foreign^{a}		(194)		(142)
Total deferred tax assets		2,836		3,154
Deferred tax liabilities
Property, plant and equipment^{a}		3,283		5,292
Inventories		0		597
Investments in subsidiaries and affiliates		1,286		1,116
Other		43		42
Total deferred tax liabilities		4,612		7,047
Net deferred tax liabilities	$	1,776	$	3,893

(a) Certain 2010 amounts were reclassified to conform to the current period's presentation.

Net Deferred Tax Assets Liabilities

			December 31,
(In millions)			2011		2010
Assets:
	Current deferred tax assets		$	99	$	-
	Other noncurrent assets			674		-
Liabilities:
	Current deferred tax liabilities			5		324
	Noncurrent deferred tax liabilities			2,544		3,569
		Net deferred tax liabilities	$	1,776	$	3,893

Income Tax Returns Remaining Subject to Examination

United States^{a}	2004 - 2010
Canada	2006 - 2010
Equatorial Guinea	2006 - 2010
Libya	2006 - 2009
Norway	2008 - 2010
United Kingdom	2008 - 2010

(a) Includes federal and state jurisdictions

Summary of Activity in Unrecognized Tax Benefits

(In millions)	2011		2010		2009
Beginning balance	$	103	$	75	$	39
Additions for tax positions related to the current year		4		28		30
Reductions for tax positions related to the current year		0		(1)		(2)
Additions for tax positions of prior years		87		25		30
Reductions for tax positions of prior years		(29)		(12)		(15)
Settlements		(8)		(12)		(7)
Ending balance	$	157	$	103	$	75

Inventories (Tables)

12 Months Ended

Dec. 31, 2011

Inventories Note Tables [Abstract]

Schedule of Inventory, Current [Table Text Block]

	December 31,
(In millions)	2011		2010
Liquid hydrocarbons, natural gas and bitumen	$	147	$	1,275
Refined products and merchandise		0		1,774
Supplies and sundry items		214		404
Inventories at cost	$	361	$	3,453

EMI and Related Party (Tables)

12 Months Ended

Dec. 31, 2011

Equity Method Investments Note Tables [Abstract]

Equity Method Investments Table [Text Block]

	Ownership as of		December 31,
(In millions)	December 31, 2011		2011		2010
EGHoldings	60	%	$	875	$	927
Alba Plant LLC	52	%		272		303
AMPCO	45	%		191		210
Downstream business investments				0		311
Other investments				45		51
Total			$	1,383	$	1,802

Income And Balance Sheet Information of Equity Investees Table [Text Block]

(In millions)	2011^{a}		2010		2009
Income data – year:
Revenues and other income	$	1,544	$	2,243	$	1,916
Income from operations		942		999		677
Net income		820		841		576
Balance sheet data – December 31:
Current assets	$	688	$	898
Noncurrent assets		2,079		3,371
Current liabilities		504		513
Noncurrent liabilities		115		832

Values in 2011 are lower than in previous years due to the spin-off of our downstream business on June 30, 2011.

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2011

Property Plant And Equipment Note Tables [Abstract]

Schedule of Aging of Capitalized Exploratory Well Costs [Table Text Block]

	December 31,
(In millions)	2011		2010		2009
Amounts capitalized less than one year after completion of drilling	$	482	$	334	$	679
Amounts capitalized greater than one year after completion of drilling		222		323		150
Total deferred exploratory well costs	$	704	$	657	$	829
Number of projects with costs capitalized greater than one year
after completion of drilling		5		7		3

Capitalized Exploratory Well Costs, Roll Forward [Table Text Block]

(In millions)		2011		2010		2009
Beginning balance		$	657	$	829	$	917
	Additions		670		329		155
	Dry well expense		(268)		(83)		(32)
	Transfers to development		(279)		(54)		(211)
	Dispositions		(76)		(364)		-
Ending balance		$	704	$	657	$	829

Schedule of Projects with Exploratory Well Costs Capitalized for More than One Year [Table Text Block]

(In millions)
Gulf of Mexico	$	73
Angola		124
Other International		25
Total	$	222

Schedule Of Property Plant And Equipment [Table Text Block]

	December 31,
(In millions)	2011		2010
E&P
United States	$	19,679	$	13,532
International		12,579		11,736
Total E&P		32,258		25,268
OSM		9,936		9,631
IG		37		47
Downstream business		-		16,624
Corporate		341		457
Total property, plant and equipment	$	42,572	$	52,027
Less accumulated depreciation, depletion and amortization		(17,248)		(19,805)
Net property, plant and equipment	$	25,324	$	32,222

Goodwill (Tables)

12 Months Ended

Dec. 31, 2011

Goodwill Rollforward Table [Abstract]

Schedule of Goodwill [Table Text Block]

(In millions)		E&P		OSM		Downstream business		Total
2010
Beginning balance, gross		$	537	$	1,412	$	885	$	2,834
	Less: accumulated impairment		-		(1,412)		-		(1,412)
Beginning balance, net			537		-		885		1,422
	Contingent consideration adjustment		-		-		(1)		(1)
	Purchase price adjustment		-		-		(7)		(7)
	Dispositions		-		-		(34)		(34)
Ending balance, net			537		-		843		1,380
2011
Beginning balance, gross			537		1,412		843		2,792
	Less: accumulated impairments		-		(1,412)		-		(1,412)
Beginning balance, net			537		-		843		1,380
	Dispositions		(1)		-		(2)		(3)
	Contingent consideration adjustment		-		-		(3)		(3)
	Purchase price adjustment		-		-		9		9
	Spin-off downstream business		-		-		(847)		(847)
Ending balance, net		$	536	$	-	$	-	$	536

- Definition

Tabular disclosure of goodwill by reportable segment and in total. Disclosure details may include, but are not limited to, the carrying amount of goodwill, goodwill acquired during the year, goodwill impairment losses recognized, goodwill written-off due to the sale of a business unit, goodwill not yet allocated, and any other changes to goodwill.

+ References + Details

Fair Value (Tables)

12 Months Ended

Dec. 31, 2011

Fair Value Measurements Note Tables [Abstract]

Derivative Fair Value Assets And Liabilities Table [Text Block]

	December 31, 2010
(In millions)		Level 1		Level 2		Level 3		Collateral		Total
Derivative instruments, assets
Commodity	$	58	$	-	$	1	$	81	$	140
Interest rate		-		32		-		-		32
Derivative instruments, assets		58		32		1		81		172
Derivative instruments, liabilities
Commodity	$	(102)	$	-	$	(3)	$	-	$	(105)
Derivative instruments, liabilities		(102)		-		(3)		-		(105)

Nonrecurring fair value table

		2011				2010				2009
(In millions)		Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	226	$	282	$	147	$	447	$	5	$	15
Long-lived assets held for sale		0		0		85		64		311		154
Intangible assets		0		25		0		0		0		0
Equity method investments		0		0		0		25		0		0

Financial instruments fair value table

	December 31,
	2011^{a}				2010
		Fair		Carrying		Fair		Carrying
(In millions)		Value		Amount		Value		Amount
Financial assets
Other current assets	$	146	$	148	$	226	$	220
Other noncurrent assets		68		68		396		231

Total financial assets		214		216		622		451

Financial liabilities
Long-term debt, including current portion^{b}		5,479		4,753		8,364		7,527
Deferred credits and other liabilities		36		38		66		67

Total financial liabilities	$	5,515	$	4,791	$	8,430	$	7,594

Financial assets and liabilities have decreased from 2010 due to the spin-off of our downsteam business, early retirement of long-term debt and United States Steel's redemption of the bonds for which they retained responsibilty.
Excludes capital leases.

Fair value recurring derivative level 3 rollforward [Table Text Block]

(In millions)	2011		2010		2009
Beginning balance	$	(2)	$	9	$	(26)
Total realized and unrealized gains (losses):
Included in net income		-		23		68
Included in other comprehensive income		-		4		(1)
Transfers to Level 2		-		(30)		-
Purchases		-		2		5
Sales		-		-		(23)
Issuances		-		-		(44)
Settlements		-		(10)		30
Spin-off of downstream business		2		-		-
Ending balance	$	-	$	(2)	$	9

- Definition

Tabular disclosure of the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments, assets, and liabilities. Such certain disclosures about the financial instruments, assets, and liabilities include: (1) the fair value of the required items together with their carrying amounts (as appropriate) and (2) the methodology and assumptions used in developing such estimates of fair value.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 10
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 14
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15
-Subparagraph b-d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 157
-Paragraph 32
-Subparagraph a, c(1), c(2), c(3), d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 18
-Subparagraph c(2), d, e, f
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 19
-Subparagraph a, b, c(1), d(1)
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 10
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6947722&loc=d3e13433-108611

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=6947722&loc=d3e13467-108611

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=6947722&loc=d3e13476-108611

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 30
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6957238&loc=d3e14172-108612

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 820
-SubTopic 10
-Section 50
-Paragraph 2
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6925170&loc=d3e19207-110258

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6447952&loc=d3e13220-108610

+ Details

Derivatives (Tables)

12 Months Ended

Dec. 31, 2011

Derivatives Note Tables [Abstract]

Derivatives as they appear on the Balance Sheet

	December 31, 2010
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	32	$	-	$	32	Other noncurrent assets
Total Designated Hedges		32		-		32

Not Designated as Hedges
Commodity		58		102		(44)	Other current assets
Total Not Designated as Hedges		58		102		(44)

Total	$	90	$	102	$	(12)

	December 31, 2010
(In millions)	Asset		Liability		Net Liability		Balance Sheet Location
Not Designated as Hedges
Commodity	$	1	$	3	$	2	Other current liabilities
Total Not Designated as Hedges		1		3		2

Total	$	1	$	3	$	2

Effects of derivatives designated as cash flow hedges

	Gain (Loss) in OCI
(In millions)	2011			2010		2009
Foreign currency	$	-	$	4	$	39
Interest rate	$	-	$	-	$	(15)

Effects of derivatives designated as fair value hedges

		Gain (Loss)
(In millions)	Income Statement Location	2011		2010		2009
Derivative
Commodity	Sales and other operating revenues	$	-	$	(1)	$	(16)
Interest rate	Net interest and other		28		26		-
			28		25		(16)
Hedged Item
Commodity	Sales and other operating revenues		-		1		16
Long-term debt	Net interest and other		(28)		(26)		-
		$	(28)	$	(25)	$	16

Effects of derivatives not designated as hedges

		Gain (Loss)
(In millions)	Income Statement Location	2011		2010		2009
Commodity	Sales and other operating revenues	$	5	$	121	$	90
Foreign currency	Net interest and other		0		0		3
		$	5	$	121	$	93

Debt (Tables)

12 Months Ended

Dec. 31, 2011

Debt Note Tables [Abstract]

Schedule of Extinguishment of Debt [Text Block]

(In millions)
6.000% notes due 2012	$	400
6.125% notes due 2012		450
8.375% secured notes due 2012^{a}		448
6.500% debentures due 2014		700
5.900% notes due 2018		40
7.500% debentures due 2019		460
Total debt purchases	$	2,498

a) These notes were senior secured notes of Marathon Oil Canada Corporation.

Schedule of long term debt table [Text Block]

		December 31,
(In millions)		2011		2010
Marathon Oil Corporation:
	Revolving credit facility	$	0	$	0
	6.125% notes due 2012		0		450
	6.000% notes due 2012		0		400
	5.900% notes due 2018^{a}		854		894
	6.800% notes due 2032^{a}		550		550
	9.375% debentures due 2012		53		53
	9.125% debentures due 2013		114		114
	6.500% debentures due 2014		0		700
	7.500% debentures due 2019^{a}		228		688
	6.000% debentures due 2017^{a}		682		682
	9.375% debentures due 2022		32		32
	8.500% debentures due 2023		70		70
	8.125% debentures due 2023		131		131
	6.600% debentures due 2037		750		750
	4.550% promissory note, semi-annual payments due 2012 - 2015		272		340
	Series A medium term notes due 2022		3		3
	4.750% - 6.875% obligations relating to industrial development and
	environmental improvement bonds and notes due 2013 - 2033		0		198
	5.375% obligation relating to revenue bonds due 2013		23		23
	5.125% obligation relating to revenue bonds due 2037		1,000		1,000
	Sale-leaseback financing due 2012		11		20
	Capital lease obligation due 2012		9		17
Consolidated subsidiaries
	8.375% secured notes due 2012^{a}		0		448
	Capital lease obligations due 2012 - 2034
	Downstream business		0		279
	Other		11		12
Total^{b}			4,793		7,854
	Unamortized fair value differential for debt assumed in acquisitions		0		16
	Unamortized discount		(10)		(16)
	Fair value adjustments ^{c}		32		42
	Amounts due within one year		(141)		(295)
Total long-term debt due after one year		$	4,674	$	7,601

(a) These notes contain a make-whole provision allowing us the right to repay the debt at a premium to market price.

(b) In the event of a change in control, as defined in the related agreements, debt obligations totaling $431 million at December 31, 2011, may be declared immediately due and payable.

Five Year Schedule Of Debt Payments Table [Text Block]

(In millions)
2012	$	141
2013		205
2014		68
2015		68
2016		0

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation [Table Text Block]

(In millions)		2011		2010
Beginning balance		$	1,355	$	1,102
	Incurred, including acquisitions		37		49
	Settled		(39)		(28)
	Accretion expense (included in depreciation, depletion and amortization)		81		70
	Revisions to previous estimates		126		162
	Spin-off downstream business		(50)		-

Ending balance^{a}		$	1,510	$	1,355

Includes asset retirement obligation of $1 million classified as short-term at December 31, 2010.

Includes asset retirement obligation of $1 million classified as short-term at December 31, 2010.

Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2011

Supplemental Cash Flow Information Note Details [Abstract]

Schedule of interest paid, income taxes paid, and significant noncash items

(In millions)	2011		2010		2009
Net cash provided from operating activities included:
Interest paid (net of amounts capitalized)	$	268	$	107	$	19
Income taxes paid to taxing authorities		2,893		2,155		1,663
Commercial paper and revolving credit arrangements, net:
Commercial paper - issuances	$	421	$	-	$	897
- repayments		(421)		-		(897)
Total	$	-	$	-	$	-
Noncash investing and financing activities related to continuing operations:
Additions to property, plant and equipment
Asset retirement costs capitalized, excluding acquisitions	$	151	$	207	$	135
Change in capital expenditure accrual		104		(140)		(28)
Debt payments made by United States Steel		214		105		144
Capital lease and sale-leaseback financing obligations increase		-		-		9

Defined Benefit Postretirement Plans (Tables)

12 Months Ended

Dec. 31, 2011

Defined Benefit Postretirement Plans Note Tables [Abstract]

Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets [Table Text Block]

	December 31,
	2011				2010
(In millions)		U.S.		Int'l		U.S.
Projected benefit obligation	$	(986)	$	(465)	$	(3,221)
Accumulated benefit obligation		(813)		(418)		(2,365)
Fair value of plan assets		516		412		1,798

Summary Of Defined Benefit Pension Plans With Accumulated Benefit Obligations In Excess Of Plan Assets [Table Text Block]

			Pension Benefits									Other Benefits
			2011					2010				2011		2010
(In millions)				U.S.			Int'l		U.S.		Int'l
Change in benefit obligations:
	Benefit obligations at January 1		$	3,221	$		415	$	2,989	$	395	$	779	$	685
		Spin-off downstream business		(2,308)			0		0		0		(483)		0
		Service cost		28			19		92		19		4		18
		Interest cost		44			22		153		22		16		39
		Plan amendment		0			11		0		0		0		0
		Actuarial loss		84			13		287		6		1		69
		Foreign currency exchange rate changes		0			(2)		0		(18)		0		0
		Other		0			0		0		6		0		0
		Benefits paid		(83)			(13)		(300)		(15)		(16)		(32)
	Benefit obligations at December 31		$	986		$	465	$	3,221	$	415	$	301	$	779
Change in plan assets:
	Fair value of plan assets at January 1		$	1,798		$	389	$	1,623	$	348	$	0	$	0
		Spin-off downstream business		(1,268)			0		0		0		0		0
		Actual return on plan assets		30			15		214		47		0		0
		Employer contributions		39			23		267		20		0		0
		Foreign currency exchange rate changes		0			(2)		0		(14)		0		0
		Other		0			0		(6)		3		0		0
		Benefits paid		(83)			(13)		(300)		(15)		0		0
	Fair value of plan assets at December 31		$	516		$	412	$	1,798	$	389	$	0	$	0
Funded status of plans at December 31			$	(470)		$	(53)	$	(1,423)	$	(26)	$	(301)	$	(779)
	Amounts recognized in the consolidated
		balance sheet:
		Current liabilities		(17)			0		(21)		0		(18)		(36)
		Noncurrent liabilities		(453)			(53)		(1,402)		(26)		(283)		(743)
	Accrued benefit cost		$	(470)		$	(53)	$	(1,423)	$	(26)	$	(301)	$	(779)
Pretax amounts in accumulated other
	comprehensive income:
	Net loss		$	432		$	63	$	1,382	$	41	$	16	$	18
	Prior service cost (credit)			27			11		81		0		(18)		(24)

Schedule Of Net Periodic Benefit Cost And Other Comprehensive Income [Table Text Block]

		Pension Benefits
		2011				2010				2009				Other Benefits
(In millions)		U.S.	Int'l			U.S.	Int'l			U.S.	Int'l			2011	2010		2009
Components of net periodic benefit cost related to continuing operations:
Service cost	$	28	$	19	$	30	$	19	$	36	$	14	$	4	$	3	$	3
Interest cost		44		22		47		22		46		22		16		16		18
Expected return on plan assets		(43)		(23)		(44)		(22)		(47)		(21)		-		-		-
- prior service cost (credit)		6		-		6		-		6		1		(7)		(7)		(6)
- actuarial loss		47		2		48		5		20		2		-		-		-
Other		-		-		-		2		-		-		-		-		-
Net settlement/curtailment loss^{a}		30		-		56		-		4		18		-		-		-
Net periodic benefit cost^{b}	$	112	$	20	$	143	$	26	$	65	$	36	$	13	$	12	$	15

Other changes in plan assets and benefit
obligations recognized in other
comprehensive income (pretax):
Actuarial loss (gain)	$	97	$	24	$	211	$	(25)	$	587	$	52	$	1	$	69	$	(34)
Amortization of actuarial (loss) gain		(77)		(2)		(167)		(5)		(33)		(7)		-		2		5
Prior service cost		-		(11)		-		-		-		-		-		-		-
Amortization of prior service credit (cost)		(6)		-		(13)		-		(13)		(1)		7		6		5
Spin off downstream business		(24)		-		-		-		-		-		-		-		-
Total recognized in other comprehensive income	$	(10)	$	11	$	31	$	(30)	$	541	$	44	$	8	$	77	$	(24)
Total recognized in net periodic benefit cost and
other comprehensive income	$	102	$	31	$	174	$	(4)	$	606	$	80	$	21	$	89	$	(9)

(b) Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.

Schedule of Assumptions Used [Table Text Block]

		Pension Benefits
		2011		2010		2009		Other Benefits
(In millions)		U.S.	Int'l	U.S.	Int'l	U.S.	Int'l	2011	2010	2009
Weighted average assumptions used to
	determine benefit obligation:
	Discount rate	4.45%	4.70%	5.05%	5.40%	5.50%	5.70%	4.90%	5.55%	5.95%
	Rate of compensation increase	5.00%	4.30%	5.00%	5.10%	4.50%	5.55%	5.00%	5.00%	4.50%
Weighted average assumptions used to
	determine net periodic benefit cost:
	Discount rate	5.05%	5.40%	5.23%	5.70%	6.90%	6.70%	5.55%	6.85%	6.85%
	Expected long-term return on plan assets^{a}	8.50%	5.86%	8.50%	6.40%	8.50%	6.10%	-	-	-
	Rate of compensation increase	5.00%	5.10%	4.50%	5.55%	4.50%	4.75%	5.00%	4.50%	4.50%

Due to the revised targeted asset allocation as discussed under the plan investment policies and strategies, effective January 1, 2012, the expected long term rate of return on plan assets was changed from 8.50 percent to 7.75 percent.

Schedule of Health Care Cost Trend Rates [Table Text Block]

		2011	2010	2009
Health care cost trend rate assumed for the following year:
	Medical
	Pre-65	7.50%	7.50%	7.00%
	Post-65	7.00%	7.00%	6.75%
	Prescription drugs	7.50%	7.50%	7.50%
Rate to which the cost trend rate is assumed to decline (the ultimate
	trend rate):
	Medical
	Pre-65	5.00%	5.00%	5.00%
	Post-65	5.00%	5.00%	5.00%
	Prescription drugs	5.00%	5.00%	5.00%
Year that the rate reaches the ultimate trend rate:
	Medical
	Pre-65	2018	2018	2014
	Post-65	2017	2017	2015
	Prescription drugs	2018	2018	2015

Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block]

		1-Percentage-		1-Percentage-
(In millions)		Point Increase		Point Decrease
Effect on total of service and interest cost components	$	2	$	2
Effect on other postretirement benefit obligations		33		27

Fair Value of Defined Benefit Pension Plans Assets [Table Text Block]

		December 31, 2011
(In millions)		Level 1				Level 2				Level 3				Total
		U.S.		Int'l		U.S.		Int'l		U.S.		Int'l		U.S.		Int'l
Cash and cash equivalents	$	12	$	2	$	-	$	-	$	-	$	-	$	12	$	2
Equity securities:
Investment trusts		-		-		7		-		-		-		7		-
Exchange traded funds		324		-		-		-		-		-		324		-
Private equity		-		-		-		-		23		-		23		-
Investment funds
Mutual funds - equity^{a}		-		159		-		-		-		-		-		159
Pooled funds - equity^{b}		-		-		-		96		-		-		-		96
Pooled funds - fixed income^{c}		-		-		-		149		-		-		-		149
U.S. treasuries		92		-		-		-		-		-		92		-
Real estate^{d}		-		-		-		-		21		-		21		-
Other		-		-		30^{e}		6		7		-		37		6
Total investments, at fair value	$	428	$	161	$	37	$	251	$	51	$	-	$	516^{f}	$	412

		December 31, 2010
(In millions)		Level 1				Level 2				Level 3				Total
		U.S.		Int'l		U.S.		Int'l		U.S.		Int'l		U.S.		Int'l
Cash and cash equivalents	$	8	$	1	$	-	$	-	$	-	$	-	$	8	$	1
Equity securities:
Investment trusts		25		0		137		-		-		-		162		-
Exchange traded funds		56		0		-		-		-		-		56		-
Private equity		-		-		-		-		67		-		67		-
Investment funds
Mutual funds - equity^{a}		-		161		-		-		-		-		0		161
Pooled funds - equity^{b}		-		-		1,072		97		-		-		1,072		97
Pooled funds - fixed income^{c}		-		-		350		126		-		-		350	0	126
Real estate^{d}		-		-		-		0		54		-		54		-
Other		-		-		5		4		24		-		29		4
Total investments, at fair value	$	89	$	162	$	1,564	$	227	$	145	$	0	$	1,798	$	389

(e) Includes an $18 million receivable for the sale of an investment that closed as of December 31, 2011 but did not cash settle until the next business day.

Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets [Table Text Block]

	2011
(In millions)		Private Equity		Real Estate		Other		Total
Beginning balance	$	67	$	54	$	24	$	145
Spin-off downstream business		(46)		(37)		(17)		(100)
Actual return on plan assets		3		2		-		5
Purchases		3		4		-		7
Sales		(4)		(2)		-		(6)
Ending balance	$	23	$	21	$	7	$	51

	2010
(In millions)		Private Equity		Real Estate		Other		Total
Beginning balance	$	42	$	36	$	23	$	101
Actual return on plan assets		13		4		1		18
Purchases		15		17		-		32
Sales		(3)		(3)		-		(6)
Ending balance	$	67	$	54	$	24	$	145

Schedule of Expected Benefit Payments [Table Text Block]

	Pension Benefits					Other
(In millions)		U.S.		Int'l		Benefits^{a}
2012	$	104	$	12	$	21
2013		100		13		22
2014		102		15		22
2015		101		16		23
2016		104		18		24
2017 through 2021		482		105		121

(a) Expected Medicare reimbursements for 2012 through 2013 total $5 million. Effective 2013, as a result of the PPACA, future Medicare reimbursements will no longer be tax deductible and must be used to reduce the costs of providing Medicare Part D equivalent prescription drug benefits to retirees. The total of these future reimbursements from 2014 through 2021 is $22 million.

Stock-Based Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2011

Stock Based Compensation Plans Note Tables [Abstract]

Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value [Table Text Block]

	2011			2010			2009
Weighted average exercise price per share	$	32.30		$	30.00		$	27.62
Expected annual dividend yield		2.1	%		3.2	%		3.5	%
Expected life in years		5.3			5.1			4.9
Expected volatility		40	%		43	%		41	%
Risk-free interest rate		1.7	%		2.2	%		2.3	%

Weighted average grant date fair value of stock option awards granted	$	10.44		$	8.70		$	7.67

Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block]

				Weighted Average Exercise price
		Number
		of Shares
Outstanding at beginning of year		24,912,261	$	24.85
	Granted	7,676,544		32.30
	Exercised	(3,576,373)		15.12
	Cancelled	(652,607)		25.88
	Spin-off downstream business	(6,989,110)		30.94
Outstanding at end of year		21,370,715	$	24.41

Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, by Exercise Price Range [Table Text Block]

		Outstanding				Exercisable
			Weighted Average Remaining Contractual Life
	Range of	Number			Weighted	Number		Weighted
	Exercise	of Shares			Average	of Shares		Average
	Prices	Under Option			Exercise Price	Under Option		Exercise Price
$	7.99-12.75	1,272,745	2	$	10.23	1,272,745	$	10.23
	12.76-16.81	2,850,590	5		15.21	2,354,373		15.28
	16.82-23.20	6,642,268	8		18.60	2,810,120		18.52
	23.21-29.24	2,021,400	4		23.92	1,955,767		23.82
	29.25-30.36	22,388	7		29.56	22,388		29.56
	30.37-47.91	8,561,324	7		34.20	4,690,067		35.75
	Total	21,370,715	6		24.41	13,105,460		24.11

Schedule of Nonvested Restricted Stock Units Activity [Table Text Block]

					Weighted Average
					Grant Date
		Awards			Fair Value
Unvested at beginning of year		2,084,680		$	23.03
	Granted	3,066,978	^{a}		27.74
	Vested	(993,949)			27.34
	Forfeited	(163,806)			23.88
	Spin-off downstream business	(289,925)			21.30
Unvested at end of year		3,703,978			25.88

Leases (Tables)

12 Months Ended

Dec. 31, 2011

Leases Note Tables [Abstract]

Future minimum commitments for capital lease obligations and operating lease obligations

(In millions)		Capital Lease Obligations		Operating Lease Obligations
2012		$	22	$	42
2013			1		38
2014			1		29
2015			1		26
2016			1		25
Later years			25		66
Sublease rentals			0		(2)
	Total minimum lease payments	$	51	$	224
Less imputed interest costs			(20)
	Present value of net minimum lease payments	$	31

Spin-Off (Details) - USD ($) $ in Millions	12 Months Ended
Spin-Off (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Jun. 30, 2011
Current assets of discontinued operations:
Cash and cash equivalents of discontinued operations				$ 1,622
Receivables of discontinued operations				5,041
Inventories of discontinued opeartions				3,679
Other current assets of discontinued operations				170
Total current assets of discontinued operations				10,512
Noncurrent assets of discontinued operations [Abstract]
Equity method investments of discontinued operations				323
Property, plant, and equipment of discontinued operations				11,935
Goodwill of discontinued operations				847
Other noncurrent assets of discontinued operations				351
Total assets of discontinued operations				23,968
Current liabilities of discontinued operations:
Accounts payable of discontinued operations				7,329
Payroll and benefits payable of discontinued operations				222
Accrued and deferred taxes of discontinued operations				443
Other current liabilities of discontinued operations				461
Long term debt of discontinued operations, due within one year				12
Total current liabilities of discontinued operations				8,467
Long term debt of discontinued operations				3,262
Deferred income taxes of discontinued operations				1,568
Defined benefit postretirement plan obligations of discontinued operations				1,489
Deferred credits and other noncurrent liabilities of discontinued operations				276
Total liabilities of discontinued operations				$ 15,062
Discontinued Operations Disclosure [Abstract]
Revenues applicable to discontinued operations	$ 38,602	$ 62,488	$ 45,529
Pretax income from discontinued operations	$ 2,012	$ 1,065	$ 894

Variable Interest Entities (Details) - Variable Interest Entity, Not Primary Beneficiary [Member] $ in Millions	Dec. 31, 2011 USD ($)
Variable Interest Entity [Line Items]
Recorded liability related to unconsolidated VIE	$ 3
Maximum exposure to loss related to unconsolidated VIE	$ 715

Acquisitions (Details) - Eagle Ford Acquistion [Member] $ in Millions	12 Months Ended
	Dec. 31, 2011 USD ($) acres
Asset acquisition [Line Items]
Acquisition Costs, Period Cost \| $	$ 4,500
Gas and oil acreages undeveloped and developed net \| acres	167,000

Acquisitions (Details -Business Comb) $ in Millions	12 Months Ended
Acquisitions (Details -Business Comb) $ in Millions	Dec. 31, 2011 USD ($) acres
Business Acquisition, Purchase Price Allocation [Abstract]
Business Acquisition, Purchase Price Allocation, Current Assets, Receivables	$ 40
Business Acquisition, Purchase Price Allocation, Current Assets, Inventory	4
Business Acquisition, Purchase Price Allocation, Current Assets, Prepaid Expense and Other Assets	30
Business Acquisition, Purchase Price Allocation, Current Assets, Total	74
Business Acquisition, Purchase Price Allocation, Property, Plant and Equipment	4,501
Business Acquisition, Purchase Price Allocation, Noncurrent Assets	21
Business Acquisition, Purchase Price Allocation, Assets Acquired	4,596
Business Acquisition, Purchase Price Allocation, Current Liabilities, Accounts Payable	101
Business Acquisition, Purchase Price Allocation, Current Liabilities, Other Liabilities	20
Business Acquisition, Purchase Price Allocation, Current Liabilities, Total	121
Business Acquisition, Purchase Price Allocation, Other Noncurrent Liabilities	5
Business Acquisition, Purchase Price Allocation, Liabilities Assumed	126
Business Acquisition, Purchase Price Allocation, Assets Acquired (Liabilities Assumed), Net, Total	$ 4,470
Eagle Ford [Member]
Business Acquisition [Line Items]
Gas and oil acreages undeveloped and developed net \| acres	108,000
Business Acquisition, Cost of Acquired Entity, Cash Paid	$ 265
Business acquisition discount factor	11.00%

Dispositions (Details) $ in Millions	12 Months Ended
Dispositions (Details) $ in Millions	Dec. 31, 2012 USD ($)	Dec. 31, 2011 USD ($) acres	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)
Dispositions Detail [Line Items]
Equity method investments		$ 1,383	$ 1,802
Proceeds from Sale of Oil and Gas Property and Equipment		518	1,368	$ 812
Impairment of long-lived assets held for sale			64	154
Pretax income and revenue discontinued operation [Line Items]
Revenues applicable to discontinued operations		38,602	62,488	45,529
Pretax income from discontinued operations		2,012	1,065	894
Ireland and Gabon [Member]
Pretax income and revenue discontinued operation [Line Items]
Revenues applicable to discontinued operations				188
Pretax income from discontinued operations				80
GOM Pipelines [Member]
Dispositions Detail [Line Items]
Equity method investments	$ 38
Proceeds from Sale of Oil and Gas Property and Equipment	$ 205
Burnspoint [Member]
Dispositions Detail [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment		36
Pretax gain/loss on sale		$ 34
Burnspoint [Member] \| Disposed [Member]
Dispositions Detail [Line Items]
Interest Percentage		50.00%
Alaska Lng [Member]
Dispositions Detail [Line Items]
Pretax gain/loss on sale		$ 8
DJ Basin [Member]
Dispositions Detail [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment		270
Pretax gain/loss on sale		$ 37
Gas and oil acreages, net \| acres		180,000
DJ Basin [Member] \| Disposed [Member]
Dispositions Detail [Line Items]
Interest Percentage		30.00%
Angola [Member]
Dispositions Detail [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment			1,300
Pretax gain/loss on sale			$ 811
Angola [Member] \| Disposed [Member]
Dispositions Detail [Line Items]
Interest Percentage			20.00%
Angola [Member] \| Held [Member]
Dispositions Detail [Line Items]
Interest Percentage			10.00%
Gudrun [Member]
Dispositions Detail [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment			$ 85
Pretax gain/loss on sale			$ (64)
Gabon [Member]
Dispositions Detail [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment				269
Pretax gain/loss on sale				232
Permian Basin [Member]
Dispositions Detail [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment				293
Pretax gain/loss on sale				196
Ireland (Operated Properties) [Member]
Dispositions Detail [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment				84
Pretax gain/loss on sale				158
Charge for pension plan termination				18
Ireland (Corrib) [Member]
Dispositions Detail [Line Items]
Impairment of long-lived assets held for sale				154
Initial proceeds payment dispositon of asset		$ 100
Fixed proceeds on disposition of asset				$ 135
Ireland (Corrib) [Member] \| Disposed [Member]
Dispositions Detail [Line Items]
Interest Percentage				19.00%

Income per Common Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Earnings Per Share [Abstract]
Income from continuing operations	$ 1,707	$ 1,882	$ 716
Discontinued operations	1,239	686	747
Net income	$ 2,946	$ 2,568	$ 1,463
Weighted average common shares outstanding, basic	710	710	709
Effect of dilutive securities	4	2	2
Weighted average common shares outstanding, diluted	714	712	711
Basic:
Income from continuing operations, per basic share	$ 2.40	$ 2.65	$ 1.01
Discontinued operations, per basic share	1.75	0.97	1.05
Net income, per basic share	4.15	3.62	2.06
Diluted:
Income from continuing operations, per diluted share	2.39	2.65	1.01
Discontinued operations, per diluted share	1.74	0.96	1.05
Net income, per diluted share	$ 4.13	$ 3.61	$ 2.06
Antidilutive securities excluded from computation of earnings per share	7	13	10

Segment Information (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
Segment Information (Details) - USD ($) $ in Millions	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Revenues:
Customer		$ 14,603	$ 11,634	$ 8,465
Related parties		60	56	59
Total revenue		14,663	11,690	8,524
Segment income		2,591	2,033	1,352
Income (loss) from equity method investments,segment		462	344	268
Depreciation, depletion and amortization, segment		2,266	2,056	1,934
Income tax provision (benefit), segment		2,720	2,175	2,047
Crude oil intersegment sales reclass	$ 1,400		1,800	534
Exploration and Production Segment [Member]
Revenues:
Customer		12,922	10,651	7,651
Intersegment revenues		47	75	28
Related parties		60	56	59
Segment revenues, total		13,029	10,782	7,738
Elimination of intersegment revenues		(47)	(75)	(28)
Gain on U.K. natural gas contracts				72
Total revenue		12,982	10,707	7,782
Segment income		2,157	1,941	1,218
Income (loss) from equity method investments,segment		249	188	125
Depreciation, depletion and amortization, segment		2,028	1,911	1,776
Income tax provision (benefit), segment		2,808	2,266	1,560
Capital expenditures, segment		3,038	2,474	2,162
Oil Sands Mining Segment [Member]
Revenues:
Customer		1,588	833	692
Segment revenues, total		1,588	833	692
Total revenue		1,588	833	692
Segment income		256	(50)	44
Income (loss) from equity method investments,segment			0
Depreciation, depletion and amortization, segment		196	105	124
Income tax provision (benefit), segment		82	(12)	6
Capital expenditures, segment		308	874	1,115
Integrated Gas Segment [Member]
Revenues:
Customer		93	150	50
Segment revenues, total		93	150	50
Total revenue		93	150	50
Segment income		178	142	90
Income (loss) from equity method investments,segment		213	181	143
Depreciation, depletion and amortization, segment		3	2	3
Income tax provision (benefit), segment		74	73	39
Capital expenditures, segment		2	2	2
Total All Segments [Member]
Revenues:
Customer		14,603	11,634	8,393
Intersegment revenues		47	75	28
Related parties		60	56	59
Segment revenues, total		14,710	11,765	8,480
Elimination of intersegment revenues		(47)	(75)	(28)
Gain on U.K. natural gas contracts				72
Income (loss) from equity method investments,segment		462	369	268
Depreciation, depletion and amortization, segment		2,227	2,018	1,903
Income tax provision (benefit), segment		2,964	2,327	1,605
Capital expenditures, segment		$ 3,348	$ 3,350	$ 3,279
MPC [Member]
Entity-Wide Revenue, Major Customer, Percent [Line Items]
Entity-Wide Revenue, Major Customer, Percent		18.00%	16.00%	12.00%
Libyan National Oil Company [Member]
Entity-Wide Revenue, Major Customer, Percent [Line Items]
Entity-Wide Revenue, Major Customer, Percent			13.00%	13.00%

Segment Information (Details 2) - USD ($) $ in Millions	12 Months Ended
Segment Information (Details 2) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Reconciliation of segment income to net income:
Segment income	$ 2,591	$ 2,033	$ 1,352
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items	(326)	(202)	(431)
Foreign currency remeasurement of taxes	9	32	(319)
Gain(loss) on dispositions, not allocated to segments	45	407	122
Impairments, not allocated to segements	(195)	(286)	(45)
Loss on early extinguishment of debt, after-tax	(176)	(57)
Water abatement costs	(48)
Deferred income tax items	(61)	(45)
Gain on U.K. natural gas contracts, after-tax			37
Tax effect of subsidiary restructure	(122)
Eagle Ford transaction costs	(10)
Income from continuing operations	1,707	1,882	716
Discontinued operations	1,239	686	747
Net income	2,946	2,568	1,463
Reconciliation of total revenues to sales and other operating revenues (including consumer excise taxes) as reported in the consolidated statements of income:
Total revenue	14,663	11,690	8,524
Less: Sales to related parties	60	56	59
Sales and other operating revenues	$ 14,603	$ 11,634	$ 8,465

Segment Information (Details 3) - USD ($) $ in Millions	12 Months Ended
Segment Information (Details 3) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
United States [Member]
Revenues From External Customers And Long-Lived Assets [Line Items]
Total revenues	$ 6,971	$ 5,363	$ 3,326
Long-Lived Assets	10,928	18,415
Canada [Member]
Revenues From External Customers And Long-Lived Assets [Line Items]
Total revenues	1,588	833	692
Long-Lived Assets	9,711	9,564
Equatorial Guinea [Member]
Revenues From External Customers And Long-Lived Assets [Line Items]
Long-Lived Assets	2,214	2,389
Norway [Member]
Revenues From External Customers And Long-Lived Assets [Line Items]
Total revenues	3,386	2,243	1,617
Long-Lived Assets	1,133	1,353
Other International [Member]
Revenues From External Customers And Long-Lived Assets [Line Items]
Total revenues	956	715	607
Long-Lived Assets	2,721	2,399
UK [Member]
Revenues From External Customers And Long-Lived Assets [Line Items]
Total revenues	1,546	1,063	1,143
Libya 1 [Member]
Revenues From External Customers And Long-Lived Assets [Line Items]
Total revenues	$ 216	$ 1,473	$ 1,139

Segment Information (Details 4) - USD ($) $ in Millions	12 Months Ended
Segment Information (Details 4) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Revenue from External Customer [Line Items]
Revenuse by product line	$ 14,663	$ 11,690	$ 8,524
Liquid hydrocarbons [Member]
Revenue from External Customer [Line Items]
Revenuse by product line	13,298	10,312	7,343
Natural Gas [Member]
Revenue from External Customer [Line Items]
Revenuse by product line	1,291	1,295	1,126
Transportation and other [Member]
Revenue from External Customer [Line Items]
Revenuse by product line	$ 74	$ 83	$ 55

Other Items (Details) - USD ($) $ in Millions	12 Months Ended
Other Items (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Net Interest and Other Financing [Abstract]
Interest income	$ 12	$ 11	$ 8
Interest expense	(281)	(375)	(262)
Income(loss) on interest rate swaps	10	26	17
Interest capitalized	151	297	214
Net interest	(108)	(41)	(23)
Net foreign currency gains or losses	24	(21)	(28)
Write off contigent proceeds	(7)	(15)	(70)
Other	(16)	2	(1)
Total other	1	(34)	(99)
Net interest and other financing costs	(107)	(75)	(122)
Interest payments made on our behalf	10	16	27
Aggregate foreign currency gains losses [Abstract]
Net foreign currency gains or losses	24	(21)	(28)
Provision for income taxes foreign currency transaction gain loss	(57)	(1)	(319)
Aggregate foreign currency gains (losses)	$ (33)	$ (22)	$ (347)

Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
Income Taxes (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Federal Income Tax Expense Benefit Continuing Operations [Abstract]
Current Federal Tax Expense Benefit	$ (210)	$ (279)	$ 40
Deferred Federal Income Tax Expense Benefit	(206)	(267)	(329)
Federal Income Tax Expense Benefit Continuing Operations	(416)	(546)	(289)
State And Local Income Tax Expense Benefit Continuing Operations [Abstract]
Current State And Local Tax Expense Benefit	24	2	(19)
Deferred State And Local Income Tax Expense Benefit	82	(10)	5
State And Local Income Tax Expense Benefit Continuing Operations	106	(8)	(14)
Foreign Income Tax Expense Benefit Continuing Operations [Abstract]
Current Foreign Tax Expense Benefit	3,088	2,941	1,480
Deferred Foreign Income Tax Expense Benefit	(58)	(212)	870
Foreign Income Tax Expense Benefit Continuing Operations	3,030	2,729	2,350
Current Income Tax Expense Benefit	2,902	2,664	1,501
Deferred income taxes	(182)	(489)	546
Provision for income taxes	$ 2,720	$ 2,175	$ 2,047
Effective Tax Rate Reconciliation [Abstract]
Statutory rate applied to income from continuing operations before income taxes	35.00%	35.00%	35.00%
Effects of foreign operations, including foreign tax credits	6.00%	20.00%	16.00%
Changes in permanent reinvestment assertion	5.00%
Foreign currency remeasurement (gain) loss			11.00%
Adjustments to valuation allowances	14.00%	(2.00%)	10.00%
Tax law changes	1.00%	1.00%
Other adjustments to effective tax rate			2.00%
Effective income tax rate on continuing operations	61.00%	54.00%	74.00%
Statutory Income Tax rate in Libya	in excess of 90 percent
U.S. deferred tax on foreign undistributed earnings	$ 716
Undistributed Earnings of Foreign Operations	2,046
United states foreign tax credits	$ 488
Previous UK supplemental tax rate	20.00%
UK supplemental tax rate effective March 2011	32.00%
Deferred tax expense due to foreign tax law change	$ 10
Deferred tax asset write-off due to health care reform acts		$ 45
Deferred tax asset write-off due to state tax law change	32
Deferred Tax Assets Gross [Abstract]
Deferred Tax Assets Employee Benefits	413	1,079
Operating Loss Carryforwards	376	285
Deferred Tax Assets Tax Credit Carryforwards Foreign	3,005	2,045
Deferred Tax Assets Other	88	141
Deferred Tax Assets Valuation Allowance Federal	(791)	(206)
Deferred Tax Assets Valuation Allowance State	(61)	(48)
Deferred Tax Assets Valuation Allowance Foreign	(194)	(142)
Deferred Tax Assets	2,836	3,154
Deferred Tax Liabilities [Abstract]
Deferred Tax Liabilities Property Plant And Equipment	3,283	5,292
Deferred Tax Liabilities Inventories		597
Deferred Tax Liabilities Consolidated Subsidiaries	1,286	1,116
Deferred Tax Liabilities Other	43	42
Deferred Tax Liabilities	4,612	7,047
Net Deferred Tax Liabilities	$ 1,776	$ 3,893

Income Taxes (Details 2) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
Income Taxes (Details 2) - USD ($) $ in Millions	Jun. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Valuation Allowance [Abstract]
Change in federal valuation allowances		$ 585	$ (74)	$ 280
Change in foreign valuation allowances	$ (228)	52	40	$ (79)
Deferred Tax Assets Liabilities Net [Abstract]
Deferred Tax Assets Gross Current		99
Deferred Tax Assets Gross Noncurrent		674
Deferred Tax Liabilities Current		5	324
Deferred Tax Liabilities Noncurrent		2,544	3,569
Net Deferred Tax Liabilities		1,776	$ 3,893
Foreign Country Canada [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets Operating Loss Carryforwards		811
Foreign Country Indonesia [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets Operating Loss Carryforwards		245
State And Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets Operating Loss Carryforwards		$ 915

Income Taxes (Details 3) - USD ($) $ in Millions	12 Months Ended
Income Taxes (Details 3) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Foreign Source Income [Abstract]
Foreign Source Income	$ 4,869	$ 4,563	$ 2,947
Undistributed Income of Certain Consolidated Foreign Subsidiaries [Abstract]
Undistributed Income Of Certain Consolidated Foreign Subsidiaries	235
Income Tax Expense If Not Permanently Reinvested	82
Unrecognized Tax Benefit Rollforward [Abstract]
Unrecognized Tax Benefits, Beginning Balance	103	75	39
Unrecognized Tax Benefits Increases Resulting From Current Period Tax Positions	4	28	30
Unrecognized Tax Benefits Decreases Resulting From Current Period Tax Positions		(1)	(2)
Unrecognized Tax Benefits Increases Resulting From Prior Period Tax Positions	87	25	30
Unrecognized Tax Benefits Decreases Resulting From Prior Period Tax Positions	(29)	(12)	(15)
Unrecognized Tax Benefits Decreases Resulting From Settlements With Taxing Authorities	(8)	(12)	(7)
Unrecognized Tax Benefits, Ending Balance	157	103	75
Unrecognized Tax Benefits That Would Impact Effective Tax Rate	103
Significant Change In Unrecognized Tax Benefits Is Reasonably Possible Amount Of Unrecorded Benefit	19
Unrecognized Tax Benefits Income Tax Penalties And Interest Accrued Abstract
Unrecognized Tax Benefits Income Tax Penalties And Interest Accrued	27	15
Unrecognized Tax Benefits Income Tax Penalties And Interest Expense Abstract
Unrecognized Tax Benefits Income Tax Penalties And Interest Expense	$ 13	$ 5	$ 0
United States [Member]
Income Tax Uncertainties [Line Items]
Open Tax Years By Major Tax Jurisdiction	2004 - 2010
Canada [Member]
Income Tax Uncertainties [Line Items]
Open Tax Years By Major Tax Jurisdiction	2006 - 2010
Equatorial Guinea [Member]
Income Tax Uncertainties [Line Items]
Open Tax Years By Major Tax Jurisdiction	2006 - 2010
Libya [Member]
Income Tax Uncertainties [Line Items]
Open Tax Years By Major Tax Jurisdiction	2006 - 2009
Norway [Member]
Income Tax Uncertainties [Line Items]
Open Tax Years By Major Tax Jurisdiction	2008 - 2010
United Kingdom [Member]
Income Tax Uncertainties [Line Items]
Open Tax Years By Major Tax Jurisdiction	2008 - 2010

Inventories (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Inventories Note Tables [Abstract]
Liquid hydrocarbons natural gas and bitumen	$ 147	$ 1,275
Refined products and merchandise	0	1,774
Supplies and sundry items	214	404
Inventories	$ 361	$ 3,453
Percentage of total inventory at LIFO	16.00%	85.00%
Current acquisition costs in excess of LIFO	$ 74	$ 4,166

EMI and Related Party (Details) - USD ($) $ in Millions	12 Months Ended
EMI and Related Party (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Schedule Of Equity Method Investments [Line Items]
Carrying value of equity method investments	$ 1,383	$ 1,802
Income Data- Year
Equity method investment revenues and other income	1,544	2,243	$ 1,916
Equity method investment income from operations	942	999	677
Net Income	820	841	576
Balance sheet data
Current Assets	688	898
Noncurrent Assets	2,079	3,371
Current Liabilities	504	513
Noncurrent Liabilities	115	832
Equity Method Investment Difference Between Carrying Amount And Underlying Equity	155
Dividends and partnership distributions received from equity method investments	509	400	$ 302
EG Holdings [Member]
Schedule Of Equity Method Investments [Line Items]
Carrying value of equity method investments	$ 875	927
Ownership percentage	60.00%
Alba Plant LLC [Member]
Schedule Of Equity Method Investments [Line Items]
Carrying value of equity method investments	$ 272	303
Ownership percentage	52.00%
AMPCO [Member]
Schedule Of Equity Method Investments [Line Items]
Carrying value of equity method investments	$ 191	210
Ownership percentage	45.00%
Other Equity Method Investees [Member]
Schedule Of Equity Method Investments [Line Items]
Carrying value of equity method investments	$ 45	51
Downstream business investments [Member]
Schedule Of Equity Method Investments [Line Items]
Carrying value of equity method investments		$ 311

Property, Plant and Equipment (Details) $ in Millions	Dec. 31, 2011 USD ($) Boe	Dec. 31, 2010 USD ($)
Segment Reporting Information [Line Items]
Less accumulated depreciation, depletion and amortization	$ (17,248)	$ (19,805)
Property, plant and equipment, net	25,324	32,222
PPE gross assets capital leases	13	272
Accumulated DDA capital leases	1	48
United States Exploration and Production [Member]
Segment Reporting Information [Line Items]
Total property, plant and equipment	19,679	13,532
International Exploration and Production [Member]
Segment Reporting Information [Line Items]
Total property, plant and equipment	12,579	11,736
Exploration and Production Segment [Member]
Segment Reporting Information [Line Items]
Total property, plant and equipment	32,258	25,268
Integrated Gas Segment [Member]
Segment Reporting Information [Line Items]
Total property, plant and equipment	37	47
Oil Sands Mining Segment [Member]
Segment Reporting Information [Line Items]
Total property, plant and equipment	9,936	9,631
Refining, Marketing and Transportation Segment [Member]
Segment Reporting Information [Line Items]
Total property, plant and equipment	0	16,624
Corporate [Member]
Segment Reporting Information [Line Items]
Total property, plant and equipment	341	457
Libya [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, net	$ 756
Proved Developed and Undeveloped Reserves, Net \| Boe	239
Total All Segments [Member]
Segment Reporting Information [Line Items]
Total property, plant and equipment	$ 42,572	52,027
Property, plant and equipment, net		$ 32,222

Property, Plant and Equipment (Details 2) $ in Millions	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)	Dec. 31, 2008 USD ($)
Total Deferred Exploratory Well Costs [Abstract]
Amounts capitalized greater than one year after completion of drilling	$ 222	$ 323	$ 150
Amounts capitalized less than one year after completion of drilling	482	334	679
Capitalized Exploratory Well Costs, Total	$ 704	$ 657	$ 829	$ 917
Projects that have Exploratory Well Costs that have been Capitalized for Period Greater than One Year, Number of Projects	5	7	3
GOM Capitalized Greater One Year [Member]
Total Deferred Exploratory Well Costs [Abstract]
Amounts capitalized greater than one year after completion of drilling	$ 73
Angola Capitalized Greater One Year [Member]
Total Deferred Exploratory Well Costs [Abstract]
Amounts capitalized greater than one year after completion of drilling	124
Other International Capitalized Greater One Year [Member]
Total Deferred Exploratory Well Costs [Abstract]
Amounts capitalized greater than one year after completion of drilling	$ 25

Property, Plant and Equipment (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Deferred exploratory well costs, beginning balance	$ 657	$ 829	$ 917
Capitalized Exploratory Well Cost, Additions Pending Determination of Proved Reserves	670	329	155
Capitalized Exploratory Well Cost, Charged to Expense	(268)	(83)	(32)
Reclassification To Well Facilities And Equipment Based On Determination Of Proved Reserves	(279)	(54)	(211)
Capitalized exploratory well cost period increase decrease for sold assets	(76)	(364)	0
Capitalized Exploratory Well Costs, Ending Balance	$ 704	$ 657	$ 829

Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
Goodwill (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Goodwill [Line Items]
Goodwill Gross		$ 2,792	$ 2,834
Goodwill, Impaired, Accumulated Impairment Loss		(1,412)	(1,412)
Goodwill Roll Forward
Beginning Balance	$ 1,380	1,422
Contingent consideration adjustment	(3)	(1)
Goodwill Spinoff Transaction	(847)
Goodwill Translation And Purchase Accounting Adjustments	9	(7)
Goodwill Written Off Related To Sale Of Business Unit	(3)	(34)
Ending Balance	536	1,380
Exploration and Production Segment [Member]
Goodwill [Line Items]
Goodwill Gross		537	537
Goodwill Roll Forward
Beginning Balance	537	537
Goodwill Written Off Related To Sale Of Business Unit	(1)
Ending Balance	536	537
Oil Sands Mining Segment [Member]
Goodwill [Line Items]
Goodwill Gross		1,412	1,412
Goodwill, Impaired, Accumulated Impairment Loss		(1,412)	(1,412)
Goodwill Roll Forward
Beginning Balance	0
Ending Balance	0	0
Refining, Marketing and Transportation Segment [Member]
Goodwill [Line Items]
Goodwill Gross		843	$ 885
Goodwill Roll Forward
Beginning Balance	843	885
Contingent consideration adjustment	(3)	(1)
Goodwill Spinoff Transaction	(847)
Goodwill Translation And Purchase Accounting Adjustments	9	(7)
Goodwill Written Off Related To Sale Of Business Unit	(2)	(34)
Ending Balance	$ 0	$ 843

Fair Value Measurements (Details-Recurring) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Fair value of assets on a recurring basis
Derivative Assets	$ 5	$ 172
Derivative Liabilities		(105)
Reconciliation of net beginning and ending balances recorded for derivative instruments classified as Level 3 in the fair value hierarchy
Beginning balance, net Level 3 fair value asset (liability)	(2)	9	$ (26)
Total realized and unrealized gains (losses):
Included in net income		23	68
Included in other comprehensive income		4	(1)
Transfers to Level 2		(30)
Purchases		2	5
Sales			(23)
Issuances			(44)
Settlements		(10)	30
Spin-off downstream businesses	2
Ending balance, net Level 3 fair value asset (liability)	0	(2)	9
Unrealized gains(losses) included in net income related to Level 3 derivative instruments		(1)	$ (7)
Commodity [Member]
Fair value of assets on a recurring basis
Derivative Assets		140
Derivative Liabilities		(105)
Interest rate [Member]
Fair value of assets on a recurring basis
Derivative Assets	5	32
Fair Value, Inputs, Level 1 [Member]
Fair value of assets on a recurring basis
Derivative Assets		58
Derivative Liabilities		(102)
Fair Value, Inputs, Level 1 [Member] \| Commodity [Member]
Fair value of assets on a recurring basis
Derivative Assets		58
Derivative Liabilities		(102)
Fair Value Inputs Level 2 [Member]
Fair value of assets on a recurring basis
Derivative Assets	5	32
Fair Value Inputs Level 2 [Member] \| Interest rate [Member]
Fair value of assets on a recurring basis
Derivative Assets	$ 5	32
Fair Value, Inputs, Level 3 [Member]
Fair value of assets on a recurring basis
Derivative Assets		1
Derivative Liabilities		(3)
Fair Value, Inputs, Level 3 [Member] \| Commodity [Member]
Fair value of assets on a recurring basis
Derivative Assets		1
Derivative Liabilities		(3)
Fair Value (no inputs) Collateral [Member]
Fair value of assets on a recurring basis
Derivative Assets		$ 81

Fair Value Measurements (Details 2-Nonrecurring) $ in Millions	3 Months Ended	12 Months Ended
	Jun. 30, 2011 USD ($) Boe	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Fair value of long-lived assets held for use, year-to-date		$ 226	$ 147	$ 5
Impairment of long-lived assets held for use		282	447	15
Fair value of long-lived assets held for sale			85	311
Impairment of long-lived assets held for sale			64	$ 154
Impairment of equity method investment			25
Impairment of Intangible Assets, Finite-lived		$ 25
Assets Held for Sale Gudrun [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Fair value of long-lived assets held for use, year-to-date			85
Assets Held and Used Powder River Basin [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Fair value of long-lived assets held for use, year-to-date			144
Impairment of long-lived assets held for use			$ 423
Assets Held and Used Droshky [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Fair value of long-lived assets held for use, year-to-date	$ 226
Impairment of long-lived assets held for use	$ 273
Proved reserves write off \| Boe	3.4

Fair Value Measurements (Details 3-Reported) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Fair Value [Member]
Financial Instruments, Financial Assets, Balance Sheet Groupings [Abstract]
Other current financial assets	$ 146	$ 226
Other noncurrent financial assets	68	396
Total financial assets	214	622
Financial liabilities
Long-term Debt, Fair Value	5,479	8,364
Deferred credits and other financial liabilities	36	66
Total financial liabilities	5,515	8,430
Carrying Amount [Member]
Financial Instruments, Financial Assets, Balance Sheet Groupings [Abstract]
Other current financial assets	148	220
Other noncurrent financial assets	68	231
Total financial assets	216	451
Financial liabilities
Long-term Debt, Fair Value	4,753	7,527
Deferred credits and other financial liabilities	38	67
Total financial liabilities	$ 4,791	$ 7,594

Derivatives (Details-BS) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Derivatives Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 5	$ 90
Derivative Asset, Fair Value, Gross Liability		102
Derivative Asset, Fair Value, Net	5	(12)
Derivative Liability, Fair Value, Gross Asset		1
Derivative Liability, Fair Value, Gross Liability		3
Derivative Liability, Fair Value, Net		2
Designated as Hedging Instrument [Member]
Derivatives Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	5	32
Derivative Asset, Fair Value, Net	5	32
Not Designated as Hedges [Member]
Derivatives Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		58
Derivative Asset, Fair Value, Gross Liability		102
Derivative Asset, Fair Value, Net		(44)
Derivative Liability, Fair Value, Gross Asset		1
Derivative Liability, Fair Value, Gross Liability		3
Derivative Liability, Fair Value, Net		2
Commodity [Member] \| Other Current Assets [Member] \| Not Designated as Hedges [Member]
Derivatives Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		58
Derivative Asset, Fair Value, Gross Liability		102
Derivative Asset, Fair Value, Net		(44)
Commodity [Member] \| Other Current Liabilities [Member] \| Not Designated as Hedges [Member]
Derivatives Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset		1
Derivative Liability, Fair Value, Gross Liability		3
Derivative Liability, Fair Value, Net		2
Interest rate [Member] \| Other Noncurrent Assets [Member] \| Designated as Hedging Instrument [Member]
Derivatives Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	5	32
Derivative Asset, Fair Value, Net	$ 5	$ 32

Derivatives (Details 2-IS & OCI) - USD ($) $ in Millions	12 Months Ended
Derivatives (Details 2-IS & OCI) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Gain (Loss) on Derivative Instruments [Line Items]
Gain (loss) on derivative instruments recognized in income	$ 5	$ 121	$ 93
Foreign currency [Member]
Gain (Loss) on Derivative Instruments [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net		4	39
Interest rate [Member]
Gain (Loss) on Derivative Instruments [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net			(15)
Fair Value Hedges [Member]
Gain (Loss) on Derivative Instruments [Line Items]
Gain (loss) on derivative instruments recognized in income	28	25	(16)
Change in unrealized gain (loss) on hedged item in fair value hedge	(28)	(25)	16
Sales [Member] \| Commodity [Member]
Gain (Loss) on Derivative Instruments [Line Items]
Gain (loss) on derivative instruments recognized in income	5	121	90
Sales [Member] \| Fair Value Hedges [Member] \| Commodity [Member]
Gain (Loss) on Derivative Instruments [Line Items]
Gain (loss) on derivative instruments recognized in income		(1)	(16)
Change in unrealized gain (loss) on hedged item in fair value hedge		1	16
Net Interest and other Financing Costs [Member] \| Foreign currency [Member]
Gain (Loss) on Derivative Instruments [Line Items]
Gain (loss) on derivative instruments recognized in income			$ 3
Net Interest and other Financing Costs [Member] \| Fair Value Hedges [Member]
Gain (Loss) on Derivative Instruments [Line Items]
Change in unrealized gain (loss) on hedged item in fair value hedge	(28)	(26)
Net Interest and other Financing Costs [Member] \| Fair Value Hedges [Member] \| Interest rate [Member]
Gain (Loss) on Derivative Instruments [Line Items]
Gain (loss) on derivative instruments recognized in income	$ 28	$ 26

Derivatives (Details 3) - USD ($) $ in Millions	12 Months Ended
Derivatives (Details 3) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Interest Rate Fair Value Hedges [Abstract]
Notional Amount of Interest Rate Fair Value Hedge Derivatives	$ 600	$ 1,450
Weighted-average, LIBOR-based, floating rate	4.76%	4.43%
Interest Rate Swaps	$ 29

Debt (Details) - USD ($) $ in Millions	12 Months Ended
Debt (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Debt Instrument [Line Items]
Loss on early extinguishment of debt	$ (279)	$ (92)	$ 0
Debt Extinguished Percent Of Face Value	112.00%	117.00%
Unamortized fair value differential for debt assumed in acquisitions	$ 0	$ 16
Unamortized discount	10	16
Fair value adjustments	32	42
Long-term debt due within one year	141	295
Debt Immediately Due If Change In Control	431
Long Term Debt By Maturity Abstract
Debt due year 1	141
Debt due year 2	205
Debt due year 3	68
Debt due year 4	68
Debt due year 5	0
Outstanding Short Term Debt [Abstract]
Commercial paper outstanding	0
Borrowings against revolving credit facility outstanding	0
Revolving credit facility borrowing capacity	3,000
Portion of revolving credit facility terminating in May 2013	2,625
Portion of revolving credit facility terminating in May 2012	$ 375
Variable facility fee on commitment	0.10%
United States Steel Industrial Revenue Bond Balance Current Maturity		221
Notes Due 2012 [A] [Member]
Debt Instrument [Line Items]
Long-term debt	$ 0	450
Year of debt maturity	2012
Stated interest rate on long-term debt	6.125%
Notes Due 2012 [B] [Member]
Debt Instrument [Line Items]
Long-term debt	$ 0	400
Year of debt maturity	2012
Stated interest rate on long-term debt	6.00%
Notes Due 2018 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 854	894
Year of debt maturity	2018
Stated interest rate on long-term debt	5.90%
Notes Due 2032 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 550	550
Year of debt maturity	2032
Stated interest rate on long-term debt	6.80%
Debentures Due 2012 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 53	53
Year of debt maturity	2012
Stated interest rate on long-term debt	9.375%
Debentures Due 2013 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 114	114
Year of debt maturity	2013
Stated interest rate on long-term debt	9.125%
Debentures Due 2014 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 0	700
Year of debt maturity	2014
Stated interest rate on long-term debt	6.50%
Debentures Due 2019 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 228	688
Year of debt maturity	2019
Stated interest rate on long-term debt	7.50%
Debentures Due 2017 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 682	682
Year of debt maturity	2017
Stated interest rate on long-term debt	6.00%
Debentures Due 2022 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 32	32
Year of debt maturity	2022
Stated interest rate on long-term debt	9.375%
Debentures Due 2023 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 70	70
Year of debt maturity	2023
Stated interest rate on long-term debt	8.50%
Debentures Due 2023 [B] [Member]
Debt Instrument [Line Items]
Long-term debt	$ 131	131
Year of debt maturity	2023
Stated interest rate on long-term debt	8.125%
Debentures Due 2037 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 750	750
Year of debt maturity	2037
Stated interest rate on long-term debt	6.60%
Promissory Note [Member]
Debt Instrument [Line Items]
Long-term debt	$ 272	340
Year of debt maturity	2012 - 2015
Stated interest rate on long-term debt	4.55%
Series Medium Term Notes Due 2022 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 3	3
Year of debt maturity	2022
Industrial Development And Environmental Improvement Bond [Member]
Debt Instrument [Line Items]
Long-term debt	$ 0	198
Year of debt maturity	2013 - 2033
Stated interest rate on long-term debt	4.75%
Obligation Relating To Revenue Bonds Due 2013 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 23	23
Year of debt maturity	2013
Stated interest rate on long-term debt	5.375%
Obligation Relating To Revenue Bonds Due 2037 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 1,000	1,000
Year of debt maturity	2037
Stated interest rate on long-term debt	5.125%
Sale Leaseback Financing Due [Member]
Debt Instrument [Line Items]
Long-term debt	$ 11	20
Year of debt maturity	2012
Capital Lease Obligation Due 2012 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 9	17
Year of debt maturity	2012
Consolidated Subsidiaries Secured Notes Due 2012 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 0	448
Year of debt maturity	2012
Stated interest rate on long-term debt	8.375%
Downstream Business Capital Lease Obligations Due 2034 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 0	279
Year of debt maturity	2012 - 2034
Other capital lease obligations due 2012 - 2034
Debt Instrument [Line Items]
Long-term debt	$ 11	$ 12
Year of debt maturity	2012 - 2034

Debt (Details 1) - USD ($) $ in Millions	12 Months Ended
Debt (Details 1) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Extinguishment of Debt [Line Items]
Extinguishment of debt amount	$ 2,498	$ 500
Notes Due 2012 [A] [Member]
Extinguishment of Debt [Line Items]
Extinguishment of debt amount	$ 400
Maturity date of long-term debt	Jul. 01, 2012
Stated interest rate for debt repurchases	6.00%
Notes Due 2012 [B] [Member]
Extinguishment of Debt [Line Items]
Extinguishment of debt amount	$ 450
Maturity date of long-term debt	Mar. 15, 2012
Stated interest rate for debt repurchases	6.13%
Consolidated Subsidiaries Secured Notes Due 2012 [Member]
Extinguishment of Debt [Line Items]
Extinguishment of debt amount	$ 448
Maturity date of long-term debt	May 12, 2012
Stated interest rate for debt repurchases	8.38%
Debentures Due 2014 [Member]
Extinguishment of Debt [Line Items]
Extinguishment of debt amount	$ 700
Maturity date of long-term debt	Feb. 15, 2014
Stated interest rate for debt repurchases	6.50%
Notes Due 2018 [Member]
Extinguishment of Debt [Line Items]
Extinguishment of debt amount	$ 40
Maturity date of long-term debt	Mar. 15, 2018
Stated interest rate for debt repurchases	5.90%
Debentures Due 2019 [Member]
Extinguishment of Debt [Line Items]
Extinguishment of debt amount	$ 460
Maturity date of long-term debt	Feb. 15, 2019
Stated interest rate for debt repurchases	7.50%

Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Asset retirement obligation roll forward analysis roll forward
Asset retirement obligation beginning balance	$ 1,355	$ 1,102
Incurred, including acquisitions	37	49
Settled	(39)	(28)
Accretion expense (including depreciation, depletion, and amortization)	81	70
Revisions to previous estimates	126	162
Spin-off downstream business	(50)
Asset retirement obligation ending balance	$ 1,510	1,355
Asset retirement obligation classified as short-term		$ 1

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Net cash provided by continuing operatons:
Interest paid (net of amounts capitalized)	$ 268	$ 107	$ 19
Income taxes paid to taxing authorities	2,893	2,155	1,663
Commercial paper and revolving credit arrangements, net:
Commercial paper - issuances	421	0	897
Commercial paper - repayments	421	0	897
Noncash investing and financing activities
Asset retirement costs capitalized, excluding acquisitions	151	207	135
Change In Capital Accruals	104	(140)	(28)
Debt payments made on our behalf	$ 214	$ 105	144
Capital lease obligations increase			$ 9

Defined Benefit Postretirement Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Change in benefit obligations:
Spin-off downstream business	$ (483)
Benefits paid	(83)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Benefits paid	(83)
Fair value of plan assets at December 31	6
United States Pension Plans Of US Entity Defined Benefit [Member]
Change in benefit obligations:
Benefit obligations at January 1	3,221	$ 2,989
Spin-off downstream business	(2,308)
Service Cost	28	92
Interest Cost	44	153
Actuarial loss (gain)	84	287
Benefits paid	(83)	(300)
Benefit obligations at December 31	986	3,221
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at January 1	1,798	1,623
Spin-off downstream business	(1,268)
Actual return on plan assets	30	214
Employer contributions	39	267
Other		(6)
Benefits paid	(83)	(300)
Fair value of plan assets at December 31	516	1,798
Funded status of plans
Funded status of plans at December 31	(470)	(1,423)
Amounts recognized in the consolidated balance sheet
Pension current liabilities	(17)	(21)
Pension noncurrent liabilities	(453)	(1,402)
Accrued benefit cost	(470)	(1,423)
Pretax amounts in accumulated other comprehensive income:
Net loss	432	1,382
Prior service cost (credit)	27	81
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets [Abstract]
Projected benefit obligation	(986)	(3,221)
Accumulated benefit obligation	(813)	(2,365)
Fair value of plan assets	516	1,798
Foreign Pension Plans Defined Benefit [Member]
Change in benefit obligations:
Benefit obligations at January 1	415	395
Service Cost	19	19
Interest Cost	22	22
Plan Amendments	11
Actuarial loss (gain)	13	6
Foreign currency exchange rate changes on plan obligations	2	18
Other		6
Benefits paid	(13)	(15)
Benefit obligations at December 31	465	415
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at January 1	389	348
Actual return on plan assets	15	47
Employer contributions	23	20
Foreign currency exchange rate changes	2	14
Other		3
Benefits paid	(13)	(15)
Fair value of plan assets at December 31	412	389
Funded status of plans
Funded status of plans at December 31	(53)	(26)
Amounts recognized in the consolidated balance sheet
Pension noncurrent liabilities	(53)	(26)
Accrued benefit cost	(53)	(26)
Pretax amounts in accumulated other comprehensive income:
Net loss	63	41
Prior service cost (credit)	11
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets [Abstract]
Projected benefit obligation	(465)
Accumulated benefit obligation	(418)
Fair value of plan assets	412
Other Postretirement Benefit Plans Defined Benefit [Member]
Change in benefit obligations:
Benefit obligations at January 1	779	685
Service Cost	4	18
Interest Cost	16	39
Actuarial loss (gain)	1	69
Benefits paid	(16)	(32)
Benefit obligations at December 31	301	779
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Benefits paid	(16)	(32)
Funded status of plans
Funded status of plans at December 31	(301)	(779)
Amounts recognized in the consolidated balance sheet
Pension current liabilities	(18)	(36)
Pension noncurrent liabilities	(283)	(743)
Accrued benefit cost	(301)	(779)
Pretax amounts in accumulated other comprehensive income:
Net loss	16	18
Prior service cost (credit)	$ (18)	$ (24)

Defined Benefit Postretirement Plans (Details 2) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Other Postretirement Benefit Plans Defined Benefit [Member]
Defined Benefit Plan Net Periodic Benefit Cost [Line Items]
Service cost for continuing operation		$ 4	$ 3	$ 3
Interest cost for continuing operation		16	16	18
Amortization:
- prior service cost (credit)		(7)	(7)	(6)
Net periodic benefit cost		13	12	15
Other changes in plan assets and benefit obligations recognized in other comprehensive income (pretax):
Actuarial loss (gain)		1	69	(34)
Amortization of actuarial loss		0	2	5
Amortization of prior service credit (cost)		7	6	5
Total recognized in other comprehensive income		8	77	(24)
Total recognized in net periodic benefit cost and other comprehensive income		21	89	(9)
Defined Benefit Plan Amounts That Will Be Amortized From Accumulated Other Comprehensive Income Loss In Next Fiscal Year Abstract
Prior service cost to be amortized next year	$ 7
United States Pension Plans Of US Entity Defined Benefit [Member]
Defined Benefit Plan Net Periodic Benefit Cost [Line Items]
Service cost for continuing operation		28	30	36
Interest cost for continuing operation		44	47	46
Expected return on plan assets		(43)	(44)	(47)
Amortization:
- prior service cost (credit)		6	6	6
-actuarial loss (gain)		47	48	20
- net settlement/curtailment loss		30	56	4
Net periodic benefit cost		112	143	65
Other changes in plan assets and benefit obligations recognized in other comprehensive income (pretax):
Actuarial loss (gain)		97	211	587
Amortization of actuarial loss		(77)	(167)	(33)
Amortization of prior service credit (cost)		(6)	(13)	(13)
Spin-off downstream business		(24)
Total recognized in other comprehensive income		(10)	31	541
Total recognized in net periodic benefit cost and other comprehensive income		102	174	606
Foreign Pension Plans Defined Benefit [Member]
Defined Benefit Plan Net Periodic Benefit Cost [Line Items]
Service cost for continuing operation		19	19	14
Interest cost for continuing operation		22	22	22
Expected return on plan assets		(23)	(22)	(21)
Amortization:
- prior service cost (credit)				1
-actuarial loss (gain)		2	5	2
Other			2
- net settlement/curtailment loss				18
Net periodic benefit cost		20	26	36
Other changes in plan assets and benefit obligations recognized in other comprehensive income (pretax):
Actuarial loss (gain)		24	(25)	52
Amortization of actuarial loss		(2)	(5)	(7)
Prior service cost		(11)
Amortization of prior service credit (cost)				(1)
Total recognized in other comprehensive income		11	(30)	44
Total recognized in net periodic benefit cost and other comprehensive income		$ 31	$ (4)	$ 80
United States and Foreign Pension Plans Defined Benefit [Member]
Defined Benefit Plan Amounts That Will Be Amortized From Accumulated Other Comprehensive Income Loss In Next Fiscal Year Abstract
Prior service cost to be amortized next year	7
Net loss to be amortized next year	$ 46

Defined Benefit Postretirement Plans (Details 3)	12 Months Ended
Defined Benefit Postretirement Plans (Details 3)	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Other Postretirement Benefit Plans Defined Benefit [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate		4.90%	5.55%	5.95%
Rate of compensation increase		5.00%	5.00%	4.50%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate (net periodic benefit cost)		5.55%	6.85%	6.85%
Rate of compensation increase		5.00%	4.50%	4.50%
United States Pension Plans Of US Entity Defined Benefit [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate		4.45%	5.05%	5.50%
Rate of compensation increase		5.00%	5.00%	4.50%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate (net periodic benefit cost)		5.05%	5.23%	6.90%
Expected long-term return on plan assets	7.75%	8.50%	8.50%	8.50%
Rate of compensation increase		5.00%	4.50%	4.50%
Foreign Pension Plans Defined Benefit [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate		4.70%	5.40%	5.70%
Rate of compensation increase		4.30%	5.10%	5.55%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate (net periodic benefit cost)		5.40%	5.70%	6.70%
Expected long-term return on plan assets		5.86%	6.40%	6.10%
Rate of compensation increase		5.10%	5.55%	4.75%

Defined Benefit Postretirement Plans (Details 4) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
One percent point change in assumed health care cost trend rates
Effect on total of service and interest cost components 1- Percentage increase	$ 2
Effect on total of service and interest cost components 1- Percentage decrease	2
Effect on other postretirement benefit obligations 1- Percentage increase	33
Effect on other postretirement benefit obligations 1- Percentage decrease	$ 27
Medical Pre-65 [Member]
Defined Benefit Plan Assumed Health Care Cost Trend Rates [Line Items]
Health care cost trend rate assumed for the following year:	7.50%	7.50%	7.00%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate):	5.00%	5.00%	5.00%
Year that the rate reaches the ultimate trend rate:	2018	2018	2014
Medical Post-65 [Member]
Defined Benefit Plan Assumed Health Care Cost Trend Rates [Line Items]
Health care cost trend rate assumed for the following year:	7.00%	7.00%	6.75%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate):	5.00%	5.00%	5.00%
Year that the rate reaches the ultimate trend rate:	2017	2017	2015
Assumed Health Care Cost Prescription Drugs [Member]
Defined Benefit Plan Assumed Health Care Cost Trend Rates [Line Items]
Health care cost trend rate assumed for the following year:	7.50%	7.50%	7.50%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate):	5.00%	5.00%	5.00%
Year that the rate reaches the ultimate trend rate:	2018	2018	2015

Defined Benefit Postretirement Plans (Details 5) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Percent of interest [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	$ 6
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Spin-off downstream businesses	2
Purchases		$ 2	$ 5
Sales			(23)
Settlements		(10)	30
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Ending Balance	23
Sale of investment that did not cash settle	18
United States Pension Plans Of US Entity Defined Benefit [Member]
Percent of interest [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	516	1,798	1,623
Foreign Pension Plans Defined Benefit [Member]
Percent of interest [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	412	389	348
Fair Value, Inputs, Level 1 [Member] \| United States Pension Plans Of US Entity Defined Benefit [Member] \| Cash And Cash Equivalents [Member]
Percent of interest [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	12	8
Fair Value, Inputs, Level 1 [Member] \| United States Pension Plans Of US Entity Defined Benefit [Member] \| Equity Securities Investment Objective [Member]
Percent of interest [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets		25
Fair Value, Inputs, Level 1 [Member] \| United States Pension Plans Of US Entity Defined Benefit [Member] \| Exchange Traded Funds [Member]
Percent of interest [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets		56
Fair Value, Inputs, Level 1 [Member] \| United States Pension Plans Of US Entity Defined Benefit [Member] \| US Treasury [Member]
Percent of interest [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	92
Fair Value, Inputs, Level 1 [Member] \| Foreign Pension Plans Defined Benefit [Member] \| Cash And Cash Equivalents [Member]
Percent of interest [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	2	1
Fair Value, Inputs, Level 1 [Member] \| Foreign Pension Plans Defined Benefit [Member] \| Investment Funds Mutual Funds Equity [Member]
Percent of interest [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	159	161
Fair Value Inputs Level 2 [Member] \| United States Pension Plans Of US Entity Defined Benefit [Member] \| Equity Securities Investment Objective [Member]
Percent of interest [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	7	137
Fair Value Inputs Level 2 [Member] \| United States Pension Plans Of US Entity Defined Benefit [Member] \| Equity Funds [Member]
Percent of interest [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets		1,072
Fair Value Inputs Level 2 [Member] \| United States Pension Plans Of US Entity Defined Benefit [Member] \| Fixed Income Funds [Member]
Percent of interest [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets		350
Fair Value Inputs Level 2 [Member] \| United States Pension Plans Of US Entity Defined Benefit [Member] \| Other Investments [Member]
Percent of interest [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	30	5
Fair Value Inputs Level 2 [Member] \| Foreign Pension Plans Defined Benefit [Member] \| Equity Funds [Member]
Percent of interest [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	96	97
Fair Value Inputs Level 2 [Member] \| Foreign Pension Plans Defined Benefit [Member] \| Fixed Income Funds [Member]
Percent of interest [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	149	126
Fair Value Inputs Level 2 [Member] \| Foreign Pension Plans Defined Benefit [Member] \| Other Investments [Member]
Percent of interest [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets		4
Fair Value, Inputs, Level 3 [Member] \| Private Equity Funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Beginning Balance	67	42
Spin-off downstream businesses	(46)
Actual Return on plan assets	3	13
Purchases	3	15
Sales	(4)	(3)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Ending Balance		67	42
Fair Value, Inputs, Level 3 [Member] \| Real Estate [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Beginning Balance	54	36
Spin-off downstream businesses	(37)
Actual Return on plan assets	2	4
Purchases	4	17
Sales	(2)	(3)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Ending Balance	21	54	36
Fair Value, Inputs, Level 3 [Member] \| Other Investments [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Beginning Balance	24	23
Spin-off downstream businesses	(17)
Actual Return on plan assets		1
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Ending Balance	7	24	$ 23
Fair Value, Inputs, Level 3 [Member] \| United States Pension Plans Of US Entity Defined Benefit [Member] \| Exchange Traded Funds [Member]
Percent of interest [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	324
Fair Value, Inputs, Level 3 [Member] \| United States Pension Plans Of US Entity Defined Benefit [Member] \| Private Equity Funds [Member]
Percent of interest [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	23	67
Fair Value, Inputs, Level 3 [Member] \| United States Pension Plans Of US Entity Defined Benefit [Member] \| Real Estate [Member]
Percent of interest [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	21	54
Fair Value, Inputs, Level 3 [Member] \| United States Pension Plans Of US Entity Defined Benefit [Member] \| Other Investments [Member]
Percent of interest [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	$ 7	$ 24

Defined Benefit Postretirement Plans (Details 6) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Defined Benefit Plan Information About Plan Assets [Abstract]
Contributions to defined benefit plan	$ 113
Cash Contributions Expected To Be Paid From General Assets Postretirement Plan		$ 21
Cash Contributions Expected To Be Paid From General Assets Unfunded Plan		18
Medicare reimbursement		5
Prescription drug subsidy no longer tax deductible		22
Defined contribution plan contributions		$ 50	$ 75	$ 59
Defined Benefit Plan Target Allocation Percentage Of Assets Debt Securities	35.00%	25.00%
Defined Benefit Plan Target Allocation Percentage Of Assets Equity Securities	65.00%	75.00%
Defined Benefit International Plan, Target Allocation Percentage of Assets, Debt Securities		30.00%
Defined Benefit International Plan, Target Allocation Percentage of Assets, Equity Securities		70.00%
Other Postretirement Benefit Plans Defined Benefit [Member]
Defined Benefit Plan Estimated Future Benefit Payments [Line Items]
Expected Future Benefit Payments In Year One		$ 21
Expected Future Benefit Payments In Year Two		22
Expected Future Benefit Payments In Year Three		22
Expected Future Benefit Payments In Year Four		23
Expected Future Benefit Payments In Year Five		24
Expected Future Benefit Payments Five Years Thereafter		121
United States Pension Plans Of US Entity Defined Benefit [Member]
Defined Benefit Plan Estimated Future Benefit Payments [Line Items]
Expected Future Benefit Payments In Year One		104
Expected Future Benefit Payments In Year Two		100
Expected Future Benefit Payments In Year Three		102
Expected Future Benefit Payments In Year Four		101
Expected Future Benefit Payments In Year Five		104
Expected Future Benefit Payments Five Years Thereafter		482
Foreign Pension Plans Defined Benefit [Member]
Defined Benefit Plan Estimated Future Benefit Payments [Line Items]
Expected Future Benefit Payments In Year One		12
Expected Future Benefit Payments In Year Two		13
Expected Future Benefit Payments In Year Three		15
Expected Future Benefit Payments In Year Four		16
Expected Future Benefit Payments In Year Five		18
Expected Future Benefit Payments Five Years Thereafter		$ 105

Stock-Based Compensation Plans (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2011 USD ($) $ / shares shares	Dec. 31, 2010 USD ($) $ / shares	Dec. 31, 2009 USD ($) $ / shares
Stock Option Disclosure [Abstract]
Common Stock that may be issued under the 2007 Plan \| shares	34
Portion of shares under 2007 plan that may be used for awards other than stock options or stock appreciation rights \| shares	12
Employee stock based compensation expense	$ 65	$ 51	$ 59
Tax benefits related to stock-based compensation expense	23	19	22
Cash received upon exercise of stock option awards	77	12	4
Tax benefits realized for deductions for stock awards exercised	$ 32	$ 11	$ 10
Schedule of Weighted Average Grant Date Fair Value of Stock Option Awards [Abstract]
Weighted average exercise price per share \| $ / shares	$ 32.30	$ 30.00	$ 27.62
Expected annual dividends per share	2.10%	3.20%	3.50%
Expected life in years	5.3	5.1	4.9
Expected volatility	40.00%	43.00%	41.00%
Risk-free interest rate	1.70%	2.20%	2.30%
Weighted average grant date fair value of stock option awards granted \| $ / shares	$ 10.44	$ 8.70	$ 7.67

Stock-Based Compensation Plans (Details 2) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Stock Options
Beginning year stock option awards	24,912,261
Granted stock option awards	7,676,544
Exercised stock option awards	(3,576,373)
Canceled stock option awards	(652,607)
Downstream spin-off stock option award change	(6,989,110)
End of year stock option awards	21,370,715	24,912,261
Beginning year weighted average exercise price	$ 24.85
Granted weighted average exercise price	32.30	$ 30.00	$ 27.62
Exercises weighted average exercise price	15.12
Canceled weighted average exercise price	25.88
Downstream spin-off weighted average exercise price	30.94
End of year weighted average exercise price	$ 24.41	$ 24.85
Intrinsic value of stock option awards exercised	$ 59	$ 8	$ 3

Stock-Based Compensation Plans (Details 3-Stock Options) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2011 USD ($) $ / shares shares
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range End Of Period [Line Items]
Number of Shares Under Option Outstanding \| shares	21,370,715
Weighted Average Remaining Contractual Life Outstanding	6
Weighted Average Exercise Price Outstanding \| $ / shares	$ 24.41
Number of Shares Under Option Exercisable \| shares	13,105,460
Weighted Average Exercise Price Exercisable \| $ / shares	$ 24.11
Aggregate intrinsic value of stock option awards outstanding \| $	$ 146
Aggregate intrinsic value of stock option awards currently exercisable \| $	$ 98
Weighted average remaining contractual life of stock option awards currently exercisable	5
Number of fully-vested stock option awards and stock option awards expected to vest \| shares	21,142,660
Weighted average exercise price of fully-vested stock option awards and stock option awards expected to vest \| $ / shares	$ 24.38
Remaining contractual life of fully-vested stock option awards and stock option awards expected to vest	6
Aggregate intrinsic value of fully-vested stock option awards and stock option awards expected to vest \| $	$ 145
Unrecognized compensation cost related to stock option awards \| $	$ 36
Weighted average period over which unrecognized compensation costs are expected to be recognized	2
Range of Exercise Prices First [Member]
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range End Of Period [Line Items]
Number of Shares Under Option Outstanding \| shares	1,272,745
Weighted Average Remaining Contractual Life Outstanding	2
Weighted Average Exercise Price Outstanding \| $ / shares	$ 10.23
Number of Shares Under Option Exercisable \| shares	1,272,745
Weighted Average Exercise Price Exercisable \| $ / shares	$ 10.23
Range of Exercise Prices Second [Member]
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range End Of Period [Line Items]
Number of Shares Under Option Outstanding \| shares	2,850,590
Weighted Average Remaining Contractual Life Outstanding	5
Weighted Average Exercise Price Outstanding \| $ / shares	$ 15.21
Number of Shares Under Option Exercisable \| shares	2,354,373
Weighted Average Exercise Price Exercisable \| $ / shares	$ 15.28
Range of Exercise Prices Third [Member]
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range End Of Period [Line Items]
Number of Shares Under Option Outstanding \| shares	6,642,268
Weighted Average Remaining Contractual Life Outstanding	8
Weighted Average Exercise Price Outstanding \| $ / shares	$ 18.60
Number of Shares Under Option Exercisable \| shares	2,810,120
Weighted Average Exercise Price Exercisable \| $ / shares	$ 18.52
Range of Exercise Prices Fourth [Member]
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range End Of Period [Line Items]
Number of Shares Under Option Outstanding \| shares	2,021,400
Weighted Average Remaining Contractual Life Outstanding	4
Weighted Average Exercise Price Outstanding \| $ / shares	$ 23.92
Number of Shares Under Option Exercisable \| shares	1,955,767
Weighted Average Exercise Price Exercisable \| $ / shares	$ 23.82
Range of Exercise Prices Fifth [Member]
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range End Of Period [Line Items]
Number of Shares Under Option Outstanding \| shares	22,388
Weighted Average Remaining Contractual Life Outstanding	7
Weighted Average Exercise Price Outstanding \| $ / shares	$ 29.56
Number of Shares Under Option Exercisable \| shares	22,388
Weighted Average Exercise Price Exercisable \| $ / shares	$ 29.56
Range of Exercise Prices Sixth [Member]
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range End Of Period [Line Items]
Number of Shares Under Option Outstanding \| shares	8,561,324
Weighted Average Remaining Contractual Life Outstanding	7
Weighted Average Exercise Price Outstanding \| $ / shares	$ 34.20
Number of Shares Under Option Exercisable \| shares	4,690,067
Weighted Average Exercise Price Exercisable \| $ / shares	$ 35.75

Stock-Based Compensation Plans (Details 4-Restricted) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2011 USD ($) $ / shares shares	Dec. 31, 2010 USD ($) $ / shares shares	Dec. 31, 2009 USD ($) $ / shares	Dec. 31, 2011 USD ($) $ / shares
Restricted Stock
Beginning year unvested restricted stock \| shares	2,084,680
Granted restricted stock \| shares	3,066,978
Vested restricted stock \| shares	(993,949)
Forfeited restricted stock \| shares	(163,806)
Share based compensation arrangement by share based payment award equity instruments other than options spin off in period \| shares	(289,925)
End of year unvested restricted stock \| shares	3,703,978	2,084,680
Beginning year weighted average grant date fair value unvested restricted stock	$ 23.03	$ 44.89
Granted restricted stock weighted average grant date fair value restricted stock	27.74
Vested restricted stock weighted average grant date fair value restricted stock	27.34
Forfeited restricted stock weighted average grant date fair value restricted stock				$ 23.88
Downstream spin-off weighted average grant date fair value restricted stock				21.30
End of year weighted average grant date fair value unvested restricted stock	$ 25.88	$ 23.03	$ 44.89
Restricted Stock vesting date fair value \| $	$ 30	$ 21	$ 24
Restricted stock unrecognized compensation cost \| $				$ 78
Restricted stock weighted average grant date fair value	$ 23.03	$ 23.03	$ 44.89	$ 25.88
Restricted stock unrecognized compensation cost weighted average period recognized	2.5

Stock-Based Compensation Plans (Details 5-Performance Unit) $ in Millions	12 Months Ended
	Dec. 31, 2011 USD ($) $ / shares shares	Dec. 31, 2009 USD ($)
Performance Unit Disclosures [Abstract]
Performance Unit Target Value Per Unit	1
Award instruments other than options performance unit minimum value	0
Performance Unit Maximum Value Per Unit	2
Award instruments other than options performance unit compensation expense \| $	$ 32	$ 2
Performance Unit Compensation Expense Accelerated \| $	$ 14
Performance Unit Granted \| shares	15

Stockholders' Equity (Details) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2011 USD ($) shares
Stockholders Equity Details [Abstract]
Treasury Stock Amount Of Repurchase Authorization	$ 5,000
Shares repurchased	$ 300
Shares repurchased, shares \| shares	12
Authorized Stock Repurchase Program Repurchased Number Of Shares \| shares	78
Authorized Stock Repurchase Program Repurchase Amount	$ 3,222

Leases (Details) - USD ($) $ in Millions	12 Months Ended
Leases (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Operating Leases Future Minimum Payments Due Abstract
Year 1	$ 42
Year 2	38
Year 3	29
Year 4	26
Year 5	25
Later years, Operating Leases	66
Sublease Rentals, Operating Leases	2
Total minimum operating lease payments	224
Capital Leases Future Minimum Payments Due Abstract
Year 1	22
Year 2	1
Year 3	1
Year 4	1
Year 5	1
Later years, Capital Leases	25
Total minimum capital lease payments	51
Less inputed interest costs	(20)
Present value of net minimum capital lease payments	31
Operating Leases Rent Expense Abstract
Lease Payments Made On Our Behalf		$ 16	$ 3
Operating Leases, Rent Expense	$ 74	$ 77	$ 105

Commitments and Contingencies (Details) - USD ($) $ in Millions	Dec. 31, 2011	Jun. 30, 2011	Dec. 31, 2010
Environmental matters
Accrued Liabilities for remediation	$ 1		$ 119
Guarantee Obligations [Line Items]
Commitments to acquire property, plant and equipment	2,683		$ 1,881
Water abatement Oil Sands [Member]
Site Contingency [Line Items]
Site Contingency, Accrual, Undiscounted Amount	49	$ 64
Other Guarantee [Member]
Guarantee Obligations [Line Items]
Maximum potential undiscounted payments under guarantees	139
Clairton [Member]
Guarantee Obligations [Line Items]
Maximum potential undiscounted payments under guarantees	$ 110