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Income from equity affiliates

^[1]

$ 244,371

$ 198,198

$ 167,402

7,363

5,637

3,316

Other income

1,972

1,093

918

Total Revenues and Other Income

253,706

204,928

171,636

Costs and Other Deductions

Purchased crude oil and products

149,923

116,467

99,653

Operating expenses

21,649

19,188

17,857

Selling, general and administrative expenses

4,745

4,767

4,527

Exploration expenses

1,216

1,147

1,342

Depreciation, depletion and amortization

12,911

13,063

12,110

Taxes other than on income

^[1]

15,628

18,191

17,591

Interest and debt expense

Total Costs and Other Deductions

206,072

172,873

153,108

Income Before Income Tax Expense

47,634

32,055

18,528

Income Tax Expense

20,626

12,919

7,965

Net Income

27,008

19,136

10,563

Less: Net income attributable to noncontrolling interests

113

112

Net Income attributable to Chevron Corporation

$ 26,895

$ 19,024

$ 10,483

Per Share of Common Stock

Net Income Attributable to Chevron Corporation - Basic

$ 13.54

$ 9.53

$ 5.26

Net Income Attributable to Chevron Corporation - Diluted

$ 13.44

$ 9.48

$ 5.24

Includes excise, value-added and similar taxes:

$ 8,085

$ 8,591

$ 8,109

[1]	Includes excise, value-added and similar taxes.

Consolidated Statement of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Consolidated Statement of Comprehensive Income [Abstract]
Net Income	$ 27,008	$ 19,136	$ 10,563
Currency translation adjustment
Unrealized net change arising during period	17	6	60
Unrealized holding (loss) gain on securities
Net (loss) gain arising during period	(11)	(4)	2
Derivatives
Net derivatives gain (loss) on hedge transactions	20	25	(69)
Reclassification to net income of net realized loss (gain)	9	5	(23)
Income taxes on derivatives transactions	(10)	(10)	32
Total	19	20	(60)
Actuarial loss
Amortization to net income of net actuarial loss	773	635	575
Actuarial loss arising during period	(3,250)	(857)	(1,099)
Prior service cost
Amortization to net income of net prior service credits	(26)	(61)	(65)
Prior service cost arising during period	(27)	(12)	(34)
Defined benefit plans sponsored by equity affiliates	(81)	(12)	65
Income taxes on defined benefit plans	1,030	140	159
Total	(1,581)	(167)	(399)
Other Comprehensive Loss, Net of Tax	(1,556)	(145)	(397)
Comprehensive Income	25,452	18,991	10,166
Comprehensive income attributable to noncontrolling interests	(113)	(112)	(80)
Comprehensive Income Attributable to Chevron Corporation	$ 25,339	$ 18,879	$ 10,086

Consolidated Balance Sheet - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Assets
Cash and cash equivalents	$ 15,864	$ 14,060
Time deposits	3,958	2,855
Marketable securities	249	155
Accounts and notes receivable (less allowance: 2011 - $98; 2010 - $184)	21,793	20,759
Inventories:
Crude oil and petroleum products	3,420	3,589
Chemicals	502	395
Materials, supplies and other	1,621	1,509
Total inventories	5,543	5,493
Prepaid expenses and other current assets	5,827	5,519
Total Current Assets	53,234	48,841
Long-term receivables, net	2,233	2,077
Investments and advances	22,868	21,520
Properties, plant and equipment, at cost	233,432	207,367
Less: Accumulated depreciation, depletion and amortization	110,824	102,863
Properties, plant and equipment, net	122,608	104,504
Deferred charges and other assets	3,889	3,210
Goodwill	4,642	4,617
Total Assets	209,474	184,769
Liabilities and Equity
Total short-term debt	340	187
Accounts payable	22,147	19,259
Accrued liabilities	5,287	5,324
Federal and other taxes on income	4,584	2,776
Other taxes payable	1,242	1,466
Total Current Liabilities	33,600	29,012
Long-term debt	9,684	11,003
Capital lease obligations	128	286
Deferred credits and other noncurrent obligations	19,181	19,264
Noncurrent deferred income taxes	15,544	12,697
Reserves for employee benefit plans	9,156	6,696
Total Liabilities	87,293	78,958
Preferred stock (authorized 100,000,000 shares; $1.00 par value, none issued)
Common stock (authorized 6,000,000,000 shares; $.75 par value; 2,442,676,580 shares issued at December 31, 2011 and 2010)	1,832	1,832
Capital in excess of par value	15,156	14,796
Retained earnings	140,399	119,641
Accumulated other comprehensive loss	(6,022)	(4,466)
Deferred compensation and benefit plan trust	(298)	(311)
Treasury stock, at cost (2011 - 461,509,656 shares; 2010 - 435,195,799 shares)	(29,685)	(26,411)
Total Chevron Corporation Stockholders' Equity	121,382	105,081
Noncontrolling interests	799	730
Total Equity	122,181	105,811
Total Liabilities and Equity	$ 209,474	$ 184,769

Consolidated Balance Sheet (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Consolidated Balance Sheet [Abstract]
Allowance for Doubtful Accounts Receivable, Current	$ 98	$ 184
Preferred stock, par value	$ 1.00	$ 1.00
Preferred stock, shares authorized	100,000,000	100,000,000
Preferred stock, shares issued
Common stock, par value	$ 0.75	$ 0.75
Common stock, shares authorized	6,000,000,000	6,000,000,000
Common stock, shares issued	2,442,676,580	2,442,676,580
Treasury stock, shares	461,509,656	435,195,799

Consolidated Statement of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Operating Activities
Net Income	$ 27,008	$ 19,136	$ 10,563
Adjustments
Depreciation, depletion and amortization	12,911	13,063	12,110
Dry hole expense	377	496	552
Distributions less than income from equity affiliates	(570)	(501)	(103)
Net before-tax gains on asset retirements and sales	(1,495)	(1,004)	(1,255)
Net foreign currency effects	(103)	251	466
Deferred income tax provision	1,589	559	467
Net decrease (increase) in operating working capital	2,318	76	(2,301)
Increase in long-term receivables	(150)	(12)	(258)
Decrease in other deferred charges	341	48	201
Cash contributions to employee pension plans	(1,467)	(1,450)	(1,739)
Other	339	697	670
Net Cash Provided by Operating Activities	41,098	31,359	19,373
Investing Activities
Acquisition of Atlas Energy	(3,009)
Advance to Atlas Energy	(403)
Capital expenditures	(26,500)	(19,612)	(19,843)
Proceeds and deposits related to asset sales	3,517	1,995	2,564
Net purchases of time deposits	(1,104)	(2,855)
Net (purchases) sales of marketable securities	(74)	(49)	127
Repayment of loans by equity affiliates	339	338	336
Net (purchases) sales of other short-term investments	(255)	(732)	244
Net Cash Used for Investing Activities	(27,489)	(20,915)	(16,572)
Financing Activities
Net borrowings (payments) of short-term obligations	23	(212)	(3,192)
Proceeds from issuance of long-term debt	377	1,250	5,347
Repayments of long-term debt and other financing obligations	(2,769)	(156)	(496)
Cash dividends - common stock	(6,139)	(5,674)	(5,302)
Distributions to noncontrolling interests	(71)	(72)	(71)
Net (purchases) sales of treasury shares	(3,193)	(306)	168
Net Cash Used for Financing Activities	(11,772)	(5,170)	(3,546)
Effect of Exchange Rate Changes on Cash and Cash Equivalents	(33)	70	114
Net Change in Cash and Cash Equivalents	1,804	5,344	(631)
Cash and Cash Equivalents at January 1	14,060	8,716	9,347
Cash and Cash Equivalents at December 31	$ 15,864	$ 14,060	$ 8,716

Consolidated Statement of Equity - USD ($) shares in Thousands, $ in Millions	Total	Deferred Compensation and Benefit Plan Trust	Preferred Stock	Common Stock	Capital in Excess of Par	Treasury Stock at Cost	Retained Earnings	Accumulated Other Comprehensive Loss
Beginning Balance at Dec. 31, 2008			$ 0	$ 1,832	$ 14,448	$ (26,376)	$ 101,102
Shares, Beginning Balance at Dec. 31, 2008			0	2,442,677		438,445
Treasury Stock Transaction					183
Net Income Attributable to Chevron Corporation	$ 10,483						10,483
Cash dividends - common stock							(5,302)
Tax benefit from dividends paid on unallocated ESOP shares and other							6
Currency Translation Adjustment, Beginning Balance at Dec. 31, 2008								$ (171)
Currency translation adjustment
Unrealized net change arising during period	60							60
Currency Translation Adjustment, Ending Balance at Dec. 31, 2009								(111)
Pension and Other Postretirement Benefit Plans, Beginning Balance at Dec. 31, 2008								(3,909)
Pension and other postretirement benefit plans
Change to defined benefit plans during year								(399)
Pension and Other Postretirement Benefit Plans, Ending Balance at Dec. 31, 2009								(4,308)
Unrealized net holding gain on securities, Beginning Balance at Dec. 31, 2008								13
Unrealized net holding gain on securities
Change during year (Unrealized net holding gain on securities)	2							2
Unrealized net holding gain on securities, Ending Balance at Dec. 31, 2009								15
Net derivatives gain (loss) on hedge transactions, Beginning Balance at Dec. 31, 2008								143
Net derivatives gain (loss) on hedge transactions
Change during year (derivatives)								(60)
Net derivatives gain (loss) on hedge transactions, Ending Balance at Dec. 31, 2009								83
Deferred Compensation and Benefit Plan Trust Deferred Compensation, Beginning Balance at Dec. 31, 2008		$ (194)
Net derivatives gain (loss) on hedge transactions
Net reduction of ESOP debt and other		85
Deferred Compensation and Benefit Plan Trust Deferred Compensation, Ending Balance at Dec. 31, 2009		(109)
Net derivatives gain (loss) on hedge transactions
Benefit Plan Trust (Common Stock)		$ (240)
Benefit Plan Trust (Common Stock), shares		14,168
Treasury Stock at Cost, Purchases						$ (6)
Treasury Stock at Cost, Purchases, shares						85
Issuances - mainly employee benefit plans						$ 214
Issuances - mainly employee benefit plans, Shares						(3,575)
Ending Balance at Dec. 31, 2009	91,914	$ (349)	$ 0	$ 1,832	14,631	$ (26,168)	106,289	(4,321)
Shares, Ending Balance at Dec. 31, 2009		14,168	0	2,442,677		434,955
Net derivatives gain (loss) on hedge transactions
Noncontrolling interests	647
Total Equity	92,561
Treasury Stock Transaction					165
Net Income Attributable to Chevron Corporation	19,024						19,024
Cash dividends - common stock							(5,674)
Tax benefit from dividends paid on unallocated ESOP shares and other							2
Unrealized net change arising during period	6							6
Currency Translation Adjustment, Ending Balance at Dec. 31, 2010								(105)
Pension and other postretirement benefit plans
Change to defined benefit plans during year								(167)
Pension and Other Postretirement Benefit Plans, Ending Balance at Dec. 31, 2010								(4,475)
Unrealized net holding gain on securities
Change during year (Unrealized net holding gain on securities)	(4)							(4)
Unrealized net holding gain on securities, Ending Balance at Dec. 31, 2010								11
Net derivatives gain (loss) on hedge transactions
Change during year (derivatives)								20
Net derivatives gain (loss) on hedge transactions, Ending Balance at Dec. 31, 2010								103
Net derivatives gain (loss) on hedge transactions
Net reduction of ESOP debt and other		$ 38
Deferred Compensation and Benefit Plan Trust Deferred Compensation, Ending Balance at Dec. 31, 2010		(71)
Net derivatives gain (loss) on hedge transactions
Benefit Plan Trust (Common Stock)		$ (240)
Benefit Plan Trust (Common Stock), shares		14,168
Treasury Stock at Cost, Purchases						$ (775)
Treasury Stock at Cost, Purchases, shares						9,091
Issuances - mainly employee benefit plans						$ 532
Issuances - mainly employee benefit plans, Shares						(8,850)
Ending Balance at Dec. 31, 2010	105,081	$ (311)	$ 0	$ 1,832	14,796	$ (26,411)	119,641	(4,466)
Shares, Ending Balance at Dec. 31, 2010		14,168	0	2,442,677		435,196
Net derivatives gain (loss) on hedge transactions
Noncontrolling interests	730
Total Equity	105,811
Treasury Stock Transaction					360
Net Income Attributable to Chevron Corporation	26,895						26,895
Cash dividends - common stock							(6,139)
Tax benefit from dividends paid on unallocated ESOP shares and other							2
Unrealized net change arising during period	17							17
Currency Translation Adjustment, Ending Balance at Dec. 31, 2011								(88)
Pension and other postretirement benefit plans
Change to defined benefit plans during year								(1,581)
Pension and Other Postretirement Benefit Plans, Ending Balance at Dec. 31, 2011								(6,056)
Unrealized net holding gain on securities
Change during year (Unrealized net holding gain on securities)	(11)							(11)
Unrealized net holding gain on securities, Ending Balance at Dec. 31, 2011								0
Net derivatives gain (loss) on hedge transactions
Change during year (derivatives)								19
Net derivatives gain (loss) on hedge transactions, Ending Balance at Dec. 31, 2011								122
Net derivatives gain (loss) on hedge transactions
Net reduction of ESOP debt and other		$ 13
Deferred Compensation and Benefit Plan Trust Deferred Compensation, Ending Balance at Dec. 31, 2011		(58)
Net derivatives gain (loss) on hedge transactions
Benefit Plan Trust (Common Stock)		$ (240)
Benefit Plan Trust (Common Stock), shares		14,168
Treasury Stock at Cost, Purchases						$ (4,262)
Treasury Stock at Cost, Purchases, shares						42,424
Issuances - mainly employee benefit plans						$ 988
Issuances - mainly employee benefit plans, Shares						(16,110)
Ending Balance at Dec. 31, 2011	121,382	$ (298)	$ 0	$ 1,832	$ 15,156	$ (29,685)	$ 140,399	$ (6,022)
Shares, Ending Balance at Dec. 31, 2011		14,168	0	2,442,677		461,510
Net derivatives gain (loss) on hedge transactions
Noncontrolling interests	799
Total Equity	$ 122,181

Summary of Significant Accounting Policies	12 Months Ended
Summary of Significant Accounting Policies	Dec. 31, 2011
Summary of Significant Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 1 Summary of Significant Accounting Policies General Upstream operations consist primarily of exploring for, developing and producing crude oil and natural gas; liquefaction, transportation and regasification associated with liquefied natural gas (LNG); transporting crude oil by major international oil export pipelines; processing, transporting, storage and marketing of natural gas; and a gas-to-liquids project. Downstream operations relate primarily to refining crude oil into petroleum products; marketing of crude oil and refined products; transporting crude oil and refined products by pipeline, marine vessel, motor equipment and rail car; and manufacturing and marketing of commodity petrochemicals, plastics for industrial uses, and additives for fuels and lubricant oils. The company’s Consolidated Financial Statements are prepared in accordance with accounting principles generally accepted in the United States of America. These require the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. Although the company uses its best estimates and judgments, actual results could differ from these estimates as future confirming events occur. Subsidiary and Affiliated Companies The Consolidated Financial Statements include the accounts of controlled subsidiary companies more than 50 percent-owned and any variable-interest entities in which the company is the primary beneficiary. Undivided interests in oil and gas joint ventures and certain other assets are consolidated on a proportionate basis. Investments in and advances to affiliates in which the company has a substantial ownership interest of approximately 20 percent to 50 percent, or for which the company exercises significant influence but not control over policy decisions, are accounted for by the equity method. As part of that accounting, the company recognizes gains and losses that arise from the issuance of stock by an affiliate that results in changes in the company’s proportionate share of the dollar amount of the affiliate’s equity currently in income. Investments are assessed for possible impairment when events indicate that the fair value of the investment may be below the company’s carrying value. When such a condition is deemed to be other than temporary, the carrying value of the investment is written down to its fair value, and the amount of the write-down is included in net income. In making the determination as to whether a decline is other than temporary, the company considers such factors as the duration and extent of the decline, the investee’s financial performance, and the company’s ability and intention to retain its investment for a period that will be sufficient to allow for any anticipated recovery in the investment’s market value. The new cost basis of investments in these equity investees is not changed for subsequent recoveries in fair value. Differences between the company’s carrying value of an equity investment and its underlying equity in the net assets of the affiliate are assigned to the extent practicable to specific assets and liabilities based on the company’s analysis of the various factors giving rise to the difference. When appropriate, the company’s share of the affiliate’s reported earnings is adjusted quarterly to reflect the difference between these allocated values and the affiliate’s historical book values. Derivatives The majority of the company’s activity in derivative commodity instruments is intended to manage the financial risk posed by physical transactions. For some of this derivative activity, generally limited to large, discrete or infrequently occurring transactions, the company may elect to apply fair value or cash flow hedge accounting. For other similar derivative instruments, generally because of the short-term nature of the contracts or their limited use, the company does not apply hedge accounting, and changes in the fair value of those contracts are reflected in current income. For the company’s commodity trading activity, gains and losses from derivative instruments are reported in current income. The company may enter into interest rate swaps from time to time as part of its overall strategy to manage the interest rate risk on its debt. Interest rate swaps related to a portion of the company’s fixed-rate debt, if any, may be accounted for as fair value hedges. Interest rate swaps related to floating-rate debt, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. Where Chevron is a party to master netting arrangements, fair value receivable and payable amounts recognized for derivative instruments executed with the same counterparty are generally offset on the balance sheet. Short-Term Investments All short-term investments are classified as available for sale and are in highly liquid debt securities. Those investments that are part of the company’s cash management portfolio and have original maturities of three months or less are reported as “Cash equivalents.” Bank time deposits with maturities greater than 90 days are reported as “Time deposits.” The balance of short-term investments is reported as “Marketable securities” and is marked-to-market, with any unrealized gains or losses included in “Other comprehensive income.” Inventories Crude oil, petroleum products and chemicals inventories are generally stated at cost, using a last-in, first-out method. In the aggregate, these costs are below market. “Materials, supplies and other” inventories generally are stated at average cost. Properties, Plant and Equipment The successful efforts method is used for crude oil and natural gas exploration and production activities. All costs for development wells, related plant and equipment, proved mineral interests in crude oil and natural gas properties, and related asset retirement obligation (ARO) assets are capitalized. Costs of exploratory wells are capitalized pending determination of whether the wells found proved reserves. Costs of wells that are assigned proved reserves remain capitalized. Costs also are capitalized for exploratory wells that have found crude oil and natural gas reserves even if the reserves cannot be classified as proved when the drilling is completed, provided the exploratory well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. All other exploratory wells and costs are expensed. Refer to Note 19, beginning on page FS-47, for additional discussion of accounting for suspended exploratory well costs. Long-lived assets to be held and used, including proved crude oil and natural gas properties, are assessed for possible impairment by comparing their carrying values with their associated undiscounted, future net before-tax cash flows. Events that can trigger assessments for possible impairments include write-downs of proved reserves based on field performance, significant decreases in the market value of an asset, significant change in the extent or manner of use of or a physical change in an asset, and a more-likely-than-not expectation that a long-lived asset or asset group will be sold or otherwise disposed of significantly sooner than the end of its previously estimated useful life. Impaired assets are written down to their estimated fair values, generally their discounted future net before-tax cash flows. For proved crude oil and natural gas properties in the United States, the company generally performs the impairment review on an individual field basis. Outside the United States, reviews are performed on a country, concession, development area or field basis, as appropriate. In Downstream, impairment reviews are performed on the basis of a refinery, a plant, a marketing/lubricants area or distribution area, as appropriate. Impairment amounts are recorded as incremental “Depreciation, depletion and amortization” expense. Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the asset is considered impaired and adjusted to the lower value. Refer to Note 9, beginning on page FS-34, relating to fair value measurements. The fair value of a liability for an ARO is recorded as an asset and a liability when there is a legal obligation associated with the retirement of a long-lived asset and the amount can be reasonably estimated. Refer also to Note 25, on page FS-58, relating to AROs. Depreciation and depletion of all capitalized costs of proved crude oil and natural gas producing properties, except mineral interests, are expensed using the unit-of-production method, generally by individual field, as the proved developed reserves are produced. Depletion expenses for capitalized costs of proved mineral interests are recognized using the unit-of-production method by individual field as the related proved reserves are produced. Periodic valuation provisions for impairment of capitalized costs of unproved mineral interests are expensed. The capitalized costs of all other plant and equipment are depreciated or amortized over their estimated useful lives. In general, the declining-balance method is used to depreciate plant and equipment in the United States; the straight-line method is generally used to depreciate international plant and equipment and to amortize all capitalized leased assets. Gains or losses are not recognized for normal retirements of properties, plant and equipment subject to composite group amortization or depreciation. Gains or losses from abnormal retirements are recorded as expenses, and from sales as “Other income.” Expenditures for maintenance (including those for planned major maintenance projects), repairs and minor renewals to maintain facilities in operating condition are generally expensed as incurred. Major replacements and renewals are capitalized. Goodwill Goodwill resulting from a business combination is not subject to amortization. As required by accounting standards for goodwill (ASC 350), the company tests such goodwill at the reporting unit level for impairment on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting unit below its carrying amount. Environmental Expenditures Environmental expenditures that relate to ongoing operations or to conditions caused by past operations are expensed. Expenditures that create future benefits or contribute to future revenue generation are capitalized. Liabilities related to future remediation costs are recorded when environmental assessments or cleanups or both are probable and the costs can be reasonably estimated. For the company’s U.S. and Canadian marketing facilities, the accrual is based in part on the probability that a future remediation commitment will be required. For crude oil, natural gas and mineral-producing properties, a liability for an ARO is made in accordance with accounting standards for asset retirement and environmental obligations. Refer to Note 25, on page FS-58, for a discussion of the company’s AROs. For federal Superfund sites and analogous sites under state laws, the company records a liability for its designated share of the probable and estimable costs and probable amounts for other potentially responsible parties when mandated by the regulatory agencies because the other parties are not able to pay their respective shares. The gross amount of environmental liabilities is based on the company’s best estimate of future costs using currently available technology and applying current regulations and the company’s own internal environmental policies. Future amounts are not discounted. Recoveries or reimbursements are recorded as assets when receipt is reasonably assured. Currency Translation The U.S. dollar is the functional currency for substantially all of the company’s consolidated operations and those of its equity affiliates. For those operations, all gains and losses from currency remeasurement are included in current period income. The cumulative translation effects for those few entities, both consolidated and affiliated, using functional currencies other than the U.S. dollar are included in “Currency translation adjustment” on the Consolidated Statement of Equity. Revenue Recognition Revenues associated with sales of crude oil, natural gas, coal, petroleum and chemicals products, and all other sources are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable. Revenues from natural gas production from properties in which Chevron has an interest with other producers are generally recognized on the entitlement method. Excise, value-added and similar taxes assessed by a governmental authority on a revenue-producing transaction between a seller and a customer are presented on a gross basis. The associated amounts are shown as a footnote to the Consolidated Statement of Income, on page FS-23. Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another (including buy/sell arrangements) are combined and recorded on a net basis and reported in “Purchased crude oil and products” on the Consolidated Statement of Income. Stock Options and Other Share-Based Compensation The company issues stock options and other share-based compensation to its employees and accounts for these transactions under the accounting standards for share-based compensation (ASC 718). For equity awards, such as stock options, total compensation cost is based on the grant date fair value, and for liability awards, such as stock appreciation rights, total compensation cost is based on the settlement value. The company recognizes stock-based compensation expense for all awards over the service period required to earn the award, which is the shorter of the vesting period or the time period an employee becomes eligible to retain the award at retirement. Stock options and stock appreciation rights granted under the company’s Long-Term Incentive Plan have graded vesting provisions by which one-third of each award vests on the first, second and third anniversaries of the date of grant. The company amortizes these graded awards on a straight-line basis.

Acquisition of Atlas Energy Inc.

12 Months Ended

Dec. 31, 2011

Acquisition of Atlas Energy, Inc. [Abstract]

Acquisition of Atlas Energy, Inc.

Note 2

Acquisition of Atlas Energy, Inc.

On February 17, 2011, the company acquired Atlas Energy, Inc. (Atlas), which held one of the premier acreage positions in the Marcellus Shale, concentrated in southwestern Pennsylvania. The aggregate purchase price of Atlas was approximately $4,500, which included $3,009 cash for all the common shares of Atlas, a $403 cash advance to facilitate Atlas’ purchase of a 49 percent interest in Laurel Mountain Midstream LLC and about $1,100 of assumed debt. Subsequent to the close of the transaction, the company paid off the assumed debt and made payments of $184 in connection with Atlas equity awards. As part of the acquisition, Chevron assumed the terms of a carry arrangement whereby Reliance Marcellus, LLC, funds 75 percent of Chevron’s drilling costs, up to $1,300.

The acquisition was accounted for as a business combination (ASC 805) which, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. Provisional fair value measurements were made in first quarter 2011 for acquired assets and assumed liabilities, and the measurement process was finalized in fourth quarter 2011.

Proforma financial information is not presented as it would not be materially different from the information presented in the Consolidated Statement of Income.

The following table summarizes the measurement of the assets acquired and liabilities assumed:


Millions of Dollars	At February 17, 2011

Current assets	$	155
Investments and long-term receivables		456
Properties		6,051
Goodwill		27
Other assets		5

Total assets acquired		6,694

Current liabilities		(560	)
Long-term debt and capital leases		(761	)
Deferred income taxes		(1,915	)
Other liabilities		(25	)

Total liabilities assumed		(3,261	)

Net assets acquired	$	3,433

Properties were measured primarily using an income approach. The fair values of the acquired oil and gas properties were based on significant inputs not observable in the market and thus represent Level 3 measurements. Refer to Note 9, beginning on page FS-34 for a definition of fair value hierarchy levels. Significant inputs included estimated resource volumes, assumed future production profiles, estimated future commodity prices, a discount rate of 8 percent, and assumptions on the timing and amount of future operating and development costs. All the properties are in the United States and are included in the Upstream segment.

The acquisition date fair value of the consideration transferred was $3,400 in cash. The $27 of goodwill was assigned to the Upstream segment and represents the amount of the consideration transferred in excess of the values assigned to the individual assets acquired and liabilities assumed. Goodwill represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. None of the goodwill is deductible for tax purposes. Goodwill recorded in the acquisition is not subject to amortization, but will be tested periodically for impairment as required by the applicable accounting standard (ASC 350).

The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable).

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 88-16
-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 141
-Paragraph 51, 52
-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 141R
-Appendix F
-Paragraph F4
-Subparagraph e

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 67-73
-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 Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6911361&loc=d3e6927-128479

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6972119&loc=d3e1490-128463

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6911361&loc=d3e7008-128479

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6972119&loc=d3e1500-128463

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6910749&loc=d3e4926-128472

Reference 10: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 805
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-URI http://asc.fasb.org/extlink&oid=6910749&loc=d3e4922-128472

Reference 11: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 805
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-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6911361&loc=d3e6996-128479

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
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-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=6972119&loc=d3e1524-128463

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
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-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6972119&loc=d3e1392-128463

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
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-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6911361&loc=d3e7000-128479

Reference 15: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 805
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-URI http://asc.fasb.org/extlink&oid=6910749&loc=d3e4845-128472

Reference 16: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 805
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-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6910749&loc=d3e4934-128472

Reference 17: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
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-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=6972119&loc=d3e1497-128463

Reference 18: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
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Reference 19: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
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-URI http://asc.fasb.org/extlink&oid=6972119&loc=d3e1383-128463

Noncontrolling Interests

12 Months Ended

Dec. 31, 2011

Noncontrolling Interests [Abstract]

Noncontrolling Interests

Note 3

Noncontrolling Interests

The company adopted the accounting standard for noncontrolling interests (ASC 810) in the consolidated financial statements effective January 1, 2009, and retroactive to the earliest period presented. Ownership interests in the company’s subsidiaries held by parties other than the parent are presented separately from the parent’s equity on the Consolidated Balance Sheet. The amount of consolidated net income attributable to the parent and the noncontrolling interests are both presented on the face of the Consolidated Statement of Income. The term “earnings” is defined as “Net Income Attributable to Chevron Corporation.”

Activity for the equity attributable to noncontrolling interests for 2011, 2010 and 2009 is as follows:


	2011			2010			2009

Balance at January 1	$	730		$	647		$	469
Net income		113			112			80
Distributions to noncontrolling interests		(71	)		(72	)		(71	)
Other changes, net		27			43			169

Balance at December 31	$	799		$	730		$	647

The entire disclosure for noncontrolling interest in consolidated subsidiaries, which could include the name of the subsidiary, the ownership percentage held by the parent, the ownership percentage held by the noncontrolling owners, the amount of the noncontrolling interest, the location of this amount on the balance sheet (when not reported separately), an explanation of the increase or decrease in the amount of the noncontrolling interest, the noncontrolling interest share of the net Income or Loss of the subsidiary, the location of this amount on the income statement (when not reported separately), the nature of the noncontrolling interest such as background information and terms, the amount of the noncontrolling interest represented by preferred stock, a description of the preferred stock, and the dividend requirements of the preferred stock.

Information Relating to the Consolidated Statement of Cash Flows [Abstract]

Information Relating to the Consolidated Statement of Cash Flows

12 Months Ended

Dec. 31, 2011

Information Relating to the Consolidated Statement of Cash Flows

Note 4

Information Relating to the Consolidated Statement of Cash Flows


	Year ended December 31
	2011			2010			2009

Net decrease (increase) in operating working capital was composed of the following:
Increase in accounts and notes receivable	$	(2,156	)	$	(2,767	)	$	(1,476	)
(Increase) decrease in inventories		(404	)		15			1,213
Increase in prepaid expenses and other current assets		(853	)		(542	)		(264	)
Increase (decrease) in accounts payable and accrued liabilities		3,839			3,049			(1,121	)
Increase (decrease) in income and other taxes payable		1,892			321			(653	)

Net decrease (increase) in operating working capital	$	2,318		$	76		$	(2,301	)

Net cash provided by operating activities includes the following cash payments for interest and income taxes:
Interest paid on debt (net of capitalized interest)	$	–		$	34		$	–
Income taxes	$	17,374		$	11,749		$	7,537

Net sales of marketable securities consisted of the following gross amounts:
Marketable securities purchased	$	(112	)	$	(90	)	$	(30	)
Marketable securities sold		38			41			157

Net (purchases) sales of marketable securities	$	(74	)	$	(49	)	$	127

Net purchases of time deposits consisted of the following gross amounts:
Time deposits purchased	$	(6,439	)	$	(5,060	)	$	–
Time deposits matured		5,335			2,205			–

Net purchases of time deposits	$	(1,104	)	$	(2,855	)	$	–

In accordance with accounting standards for cash-flow classifications for stock options (ASC 718), the “Net decrease (increase) in operating working capital” includes reductions of $121, $67 and $25 for excess income tax benefits associated with stock options exercised during 2011, 2010 and 2009, respectively. These amounts are offset by an equal amount in “Net (purchases) sales of treasury shares.”

The “Acquisition of Atlas Energy” reflects the $3,009 of cash paid for all the common shares of Atlas. An “Advance to Atlas Energy” of $403 was made to facilitate the purchase of a 49 percent interest in Laurel Mountain Midstream LLC on the day of closing. The “Net decrease (increase) in operating working capital” includes $184 for payments made in connection with Atlas equity awards subsequent to the acquisition. Refer to Note 2, beginning on page FS-30 for additional discussion of the Atlas acquisition.

The “Repayments of long-term debt and other financing obligations” includes $761 for repayment of Atlas debt and $271 for payoff of the Atlas revolving credit facility.

The “Net (purchases) sales of treasury shares” represents the cost of common shares acquired less the cost of shares issued for share-based compensation plans. Purchases totaled $4,262, $775 and $6 in 2011, 2010 and 2009, respectively. In 2011 and 2010, the company purchased 42.3 million and 8.8 million common shares for $4,250 and $750 under its ongoing share repurchase program, respectively.

In 2011 and 2010, “Net sales (purchases) of other short-term investments” consist of restricted cash associated with capital-investment projects at the company’s Pascagoula and El Segundo refineries, acquisitions pending tax deferred exchanges, and Upstream abandonment activities that was invested in short-term securities and reclassified from “Cash and cash equivalents” to “Deferred charges and other assets” on the Consolidated Balance Sheet. The company issued $374, $1,250 and $350 in 2011, 2010 and 2009, respectively, of tax exempt bonds as a source of funds for U.S. refinery projects, which is included in “Proceeds from issuance of long-term debt.”

The Consolidated Statement of Cash Flows excludes changes to the Consolidated Balance Sheet that did not affect cash. In 2009, payments related to “Accrued liabilities” were excluded from “Net decrease (increase) in operating working capital” and were reported as “Capital expenditures.” The “Accrued liabilities” were related to upstream operating agreements outside the United States recorded in 2008. Refer also to Note 25, on page FS-58, for a discussion of revisions to the company’s AROs that also did not involve cash receipts or payments for the three years ending December 31, 2011.

The major components of “Capital expenditures” and the reconciliation of this amount to the reported capital and exploratory expenditures, including equity affiliates, are presented in the following table:


	Year ended December 31
	2011			2010			2009

Additions to properties, plant and equipment¹	$	25,440		$	18,474		$	16,107
Additions to investments		900			861			942
Current year dry hole expenditures		332			414			468
Payments for other liabilities and assets, net²		(172	)		(137	)		2,326

Capital expenditures		26,500			19,612			19,843
Expensed exploration expenditures		839			651			790
Assets acquired through capital lease obligations and other financing obligations		32			104			19

Capital and exploratory expenditures, excluding equity affiliates		27,371			20,367			20,652
Company’s share of expenditures by equity affiliates		1,695			1,388			1,585

Capital and exploratory expenditures, including equity affiliates	$	29,066		$	21,755		$	22,237


¹ Excludes noncash additions of $945 in 2011, $2,753 in 2010 and $985 in 2009.

² 2009 includes payments of $2,450 for accruals recorded in 2008.

Summarized Financial Data - Chevron U.S.A. Inc.

12 Months Ended

Dec. 31, 2011

Chevron U.S.A. Inc. [Member]

Summarized Financial Data - Chevron U.S.A. Inc.

Note 5

Summarized Financial Data – Chevron U.S.A. Inc.

Chevron U.S.A. Inc. (CUSA) is a major subsidiary of Chevron Corporation. CUSA and its subsidiaries manage and operate most of Chevron’s U.S. businesses. Assets include those related to the exploration and production of crude oil, natural gas and natural gas liquids and those associated with the refining, marketing, supply and distribution of products derived from petroleum, excluding most of the regulated pipeline operations of Chevron. CUSA also holds the company’s investment in the Chevron Phillips Chemical Company LLC joint venture, which is accounted for using the equity method.

The summarized financial information for CUSA and its consolidated subsidiaries is as follows:


	Year ended December 31
	2011		2010		2009

Sales and other operating revenues	$	187,917	$	145,381	$	121,553
Total costs and other deductions		178,498		139,984		120,053
Net income attributable to CUSA		6,899		4,159		1,141


	At December 31
	2011		2010

Current assets	$	34,478	$	29,211
Other assets		47,556		35,294
Current liabilities		19,082		18,098
Other liabilities		26,153		16,785

Total CUSA net equity		36,799		29,622


Memo: Total debt	$	14,763	$	8,284

Summarized Financial Data - Chevron Transport Corporation

12 Months Ended

Dec. 31, 2011

Chevron Transport Corporation [Member]

Summarized Financial Data - Chevron Transport Corporation Ltd.

Note 6

Summarized Financial Data – Chevron Transport Corporation Ltd.

Chevron Transport Corporation Ltd. (CTC), incorporated in Bermuda, is an indirect, wholly owned subsidiary of Chevron Corporation. CTC is the principal operator of Chevron’s international tanker fleet and is engaged in the marine transportation of crude oil and refined petroleum products. Most of CTC’s shipping revenue is derived from providing transportation services to other Chevron companies. Chevron Corporation has fully and unconditionally guaranteed this subsidiary’s obligations in connection with certain debt securities issued by a third party. Summarized financial information for CTC and its consolidated subsidiaries is as follows:


	Year ended December 31
	2011			2010			2009

Sales and other operating revenues	$	793		$	885		$	683
Total costs and other deductions		974			1,008			810
Net loss attributable to CTC		(177	)		(116	)		(124	)


	At December 31
	2011		2010*

Current assets	$	290	$	309
Other assets		228		201
Current liabilities		114		101
Other liabilities		346		175

Total CTC net equity		58		234


*		2010 current assets and other liabilities conformed with 2011 presentation.

There were no restrictions on CTC’s ability to pay dividends or make loans or advances at December 31, 2011.

Summarized Financial Data - Tengizchevroil LLP

12 Months Ended

Dec. 31, 2011

Summarized Financial Data of Affiliate [Abstract]

Summarized Financial Data - Tengizchevroil LLP

Note 7

Summarized Financial Data – Tengizchevroil LLP

Chevron has a 50 percent equity ownership interest in Tengizchevroil LLP (TCO). Refer to Note 12, on page FS-39, for a discussion of TCO operations.

Summarized financial information for 100 percent of TCO is presented in the following table:


	Year ended December 31
	2011		2010		2009

Sales and other operating revenues	$	25,278	$	17,812	$	12,013
Costs and other deductions		10,941		8,394		6,044
Net income attributable to TCO		10,039		6,593		4,178


	At December 31
	2011		2010

Current assets	$	3,477	$	3,376
Other assets		11,619		11,813
Current liabilities		2,995		2,402
Other liabilities		3,759		4,130

Total TCO net equity		8,342		8,657

Lease Commitments

12 Months Ended

Dec. 31, 2011

Leases [Abstract]

Lease Commitments

Note 8

Lease Commitments

Certain noncancelable leases are classified as capital leases, and the leased assets are included as part of “Properties, plant and equipment, at cost” on the Consolidated Balance Sheet. Such leasing arrangements involve crude oil production and processing equipment, service stations, bareboat charters, office buildings, and other facilities. Other leases are classified as operating leases and are not capitalized. The payments on such leases are recorded as expense. Details of the capitalized leased assets are as follows:


	At December 31
	2011		2010

Upstream	$	585	$	561
Downstream		316		316
All Other		–		169

Total		901		1,046
Less: Accumulated amortization		568		573

Net capitalized leased assets	$	333	$	473

Rental expenses incurred for operating leases during 2011, 2010 and 2009 were as follows:


	Year ended December 31
	2011		2010*		2009*

Minimum rentals	$	892	$	931	$	933
Contingent rentals		11		10		7

Total		903		941		940
Less: Sublease rental income		39		41		41

Net rental expense	$	864	$	900	$	899


*		Prior years have been adjusted to exclude cost of certain charters from rental expenses.

Contingent rentals are based on factors other than the passage of time, principally sales volumes at leased service stations. Certain leases include escalation clauses for adjusting rentals to reflect changes in price indices, renewal options ranging up to 25 years, and options to purchase the leased property during or at the end of the initial or renewal lease period for the fair market value or other specified amount at that time.

At December 31, 2011, the estimated future minimum lease payments (net of noncancelable sublease rentals) under operating and capital leases, which at inception had a noncancelable term of more than one year, were as follows:


	At December 31
	Operating		Capital
	Leases		Leases

Year: 2012		693		70
2013		632		47
2014		523		32
2015		475		21
2016		393		13
Thereafter		793		68

Total	$	3,509	$	251

Less: Amounts representing interest and executory costs				(55	)

Net present values				196
Less: Capital lease obligations included in short-term debt				(68	)

Long-term capital lease obligations			$	128

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.

Fair Value Measurements

12 Months Ended

Dec. 31, 2011

Fair Value Measurements [Abstract]

Fair Value Measurements

Note 9

Fair Value Measurements

Accounting standards for fair value measurement (ASC 820) establish a framework for measuring fair value and stipulate disclosures about fair value measurements. The standards apply to recurring and nonrecurring fair value measurements of financial and nonfinancial assets and liabilities. Among the required disclosures is the fair value hierarchy of inputs the company uses to value an asset or a liability. The three levels of the fair value hierarchy are described as follows:

Level 1: Quoted prices (unadjusted) in active markets for identical assets and liabilities. For the company, Level 1 inputs include exchange-traded futures contracts for which the parties are willing to transact at the exchange-quoted price and marketable securities that are actively traded.

Level 2: Inputs other than Level 1 that are observable, either directly or indirectly. For the company, Level 2 inputs include quoted prices for similar assets or liabilities, prices obtained through third-party broker quotes and prices that can be corroborated with other observable inputs for substantially the complete term of a contract.

Level 3: Unobservable inputs. The company does not use Level 3 inputs for any of its recurring fair value measurements. Level 3 inputs may be required for the determination of fair value associated with certain nonrecurring measurements of nonfinancial assets and liabilities.

The table below shows the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis at December 31, 2011 and December 31, 2010.

Marketable Securities The company calculates fair value for its marketable securities based on quoted market prices for identical assets and liabilities. The fair values reflect the cash that would have been received if the instruments were sold at December 31, 2011.

Derivatives The company records its derivative instruments – other than any commodity derivative contracts that are designated as normal purchase and normal sale – on the Consolidated Balance Sheet at fair value, with the offsetting amount to the Consolidated Statement of Income. For derivatives with identical or similar provisions as contracts that are publicly traded on a regular basis, the company uses the market values of the publicly traded instruments as an input for fair value calculations.

The company’s derivative instruments principally include futures, swaps, options and forward contracts for crude oil, natural gas and refined products. Derivatives classified as Level 1 include futures, swaps and options contracts traded in active markets such as the New York Mercantile Exchange.

Assets and Liabilities Measured at Fair Value on a Recurring Basis


	At December 31, 2011								At December 31, 2010
	Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3

Marketable securities		249		249		–		–		155		155		–		–
Derivatives		208		104		104		–		122		11		111		–

Total Assets at Fair Value	$	457	$	353	$	104	$	–	$	277	$	166	$	111	$	–
Derivatives		102		101		1		–		171		75		96		–

Total Liabilities at Fair Value	$	102	$	101	$	1	$	–	$	171	$	75	$	96	$	–

Derivatives classified as Level 2 include swaps, options, and forward contracts principally with financial institutions and other oil and gas companies, the fair values of which are obtained from third-party broker quotes, industry pricing services and exchanges. The company obtains multiple sources of pricing information for the Level 2 instruments. Since this pricing information is generated from observable market data, it has historically been very consistent. The company does not materially adjust this information. The company incorporates internal review, evaluation and assessment procedures, including a comparison of Level 2 fair values derived from the company’s internally developed forward curves (on a sample basis) with the pricing information to document reasonable, logical and supportable fair value determinations and proper level of classification.

Impairments of “Properties, plant and equipment” The company did not have any material long-lived assets measured at fair value on a nonrecurring basis to report in 2011 or 2010.

Impairments of “Investments and advances” The company did not have any material investments and advances measured at fair value on a nonrecurring basis to report in 2011 or 2010.

Assets and Liabilities Not Required to Be Measured at Fair Value The company holds cash equivalents and bank time deposits in U.S. and non-U.S. portfolios. The instruments classified as cash equivalents are primarily bank time deposits with maturities of 90 days or less and money market funds. “Cash and cash equivalents” had carrying/fair values of $15,864 and $14,060 at December 31, 2011, and December 31, 2010, respectively. The instruments held in “Time deposits” are bank time deposits with maturities greater than 90 days, and had carrying/fair values of $3,958 and $2,855 at December 31, 2011, and December 31, 2010, respectively. The fair values of cash, cash equivalents and bank time deposits reflect the cash that would have been received if the instruments were settled at December 31, 2011.

“Cash and cash equivalents” do not include investments with a carrying/fair value of $1,240 and $855 at December 31, 2011, and December 31, 2010, respectively. At December 31, 2011, these investments include restricted funds related to various capital-investment projects, acquisitions pending tax deferred exchanges, and Upstream abandonment activities which are reported in “Deferred charges and other assets” on the Consolidated Balance Sheet. Long-term debt of $4,101 and $5,636 at December 31, 2011, and December 31, 2010, had estimated fair values of $4,928 and $6,311, respectively.

The carrying values of short-term financial assets and liabilities on the Consolidated Balance Sheet approximate their fair values. Fair value remeasurements of other financial instruments at December 31, 2011 and 2010 were not material.

The fair value hierarchy for assets and liabilities measured at fair value on a nonrecurring basis at December 31, 2011, is as follows:

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis


	At December 31										At December 31
									Before-Tax										Before-Tax
									Loss										Loss
	Total		Level 1		Level 2		Level 3		Year 2011		Total		Level 1		Level 2		Level 3		Year 2010

Properties, plant and equipment, net (held and used)	$	67	$	–	$	–	$	67	$	81	$	57	$	–	$	–	$	57	$	85
Properties, plant and equipment, net (held for sale)		167		–		167		–		54		13		–		–		13		36
Investments and advances		–		–		–		–		108		–		–		–		–		15

Total Nonrecurring Assets at Fair Value	$	234	$	–	$	167	$	67	$	243	$	70	$	–	$	–	$	70	$	136

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.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 44A, 44B
-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 15C, 15D
-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 15A
-Subparagraph a-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 107
-Paragraph 15B
-Subparagraph a, 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 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 3, 10, 14, 15
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-Name Statement of Financial Accounting Standard (FAS)
-Number 157
-Paragraph 32, 33, 34
-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 159
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Financial and Derivative Instruments [Abstract]

Financial and Derivative Instruments

12 Months Ended

Dec. 31, 2011

Financial and Derivative Instruments

Note 10

Financial and Derivative Instruments

Derivative Commodity Instruments Chevron is exposed to market risks related to price volatility of crude oil, refined products, natural gas, natural gas liquids, liquefied natural gas and refinery feedstocks.

The company uses derivative commodity instruments to manage these exposures on a portion of its activity, including firm commitments and anticipated transactions for the purchase, sale and storage of crude oil, refined products, natural gas, natural gas liquids and feedstock for company refineries. From time to time, the company also uses derivative commodity instruments for limited trading purposes.

The company’s derivative commodity instruments principally include crude oil, natural gas and refined product futures, swaps, options, and forward contracts. None of the company’s derivative instruments is designated as a hedging instrument, although certain of the company’s affiliates make such designation. The company’s derivatives are not material to the company’s financial position, results of operations or liquidity. The company believes it has no material market or credit risks to its operations, financial position or liquidity as a result of its commodity derivative activities.

The company uses International Swaps and Derivatives Association agreements to govern derivative contracts with certain counterparties to mitigate credit risk. Depending on the nature of the derivative transactions, bilateral collateral arrangements may also be required. When the company is engaged in more than one outstanding derivative transaction with the same counterparty and also has a legally enforceable netting agreement with that counterparty, the net mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and is a reasonable measure of the company’s credit risk exposure. The company also uses other netting agreements with certain counterparties with which it conducts significant transactions to mitigate credit risk.

Derivative instruments measured at fair value at December 31, 2011, December 31, 2010, and December 31, 2009, and their classification on the Consolidated Balance Sheet and Consolidated Statement of Income are as follows:

Consolidated Balance Sheet: Fair Value of Derivatives Not Designated as Hedging Instruments


	Balance Sheet	At December 31		At December 31
Type of Contract	Classification	2011		2010

Commodity	Accounts and notes receivable, net	$	133	$	58
Commodity	Long-term receivables, net		75		64

Total Assets at Fair Value		$	208	$	122

Commodity	Accounts payable	$	36	$	131
Commodity	Deferred credits and other noncurrent obligations		66		40

Total Liabilities at Fair Value		$	102	$	171

Consolidated Statement of Income: The Effect of Derivatives Not Designated as Hedging Instruments


		Gain/(Loss)
Type of Derivative	Statement of	Year ended December 31
Contract	Income Classification	2011			2010			2009

Foreign Exchange	Other income	$	–		$	–		$	26
Commodity	Sales and other operating revenues		(255	)		(98	)		(94	)
Commodity	Purchased crude oil and products		15			(36	)		(353	)
Commodity	Other income		(2	)		(1	)		–

		$	(242	)	$	(135	)	$	(421	)

Foreign Currency The company may enter into currency derivative contracts to manage some of its foreign currency exposures. These exposures include revenue and anticipated purchase transactions, including foreign currency capital expenditures and lease commitments. The currency derivative contracts, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. There were no open currency derivative contracts at December 31, 2011 or 2010.

Interest Rates The company may enter into interest rate swaps from time to time as part of its overall strategy to manage the interest rate risk on its debt. Interest rate swaps related to a portion of the company’s fixed-rate debt, if any, may be accounted for as fair value hedges. Interest rate swaps related to floating-rate debt, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. At year-end 2011 and 2010, the company had no interest rate swaps.

Concentrations of Credit Risk The company’s financial instruments that are exposed to concentrations of credit risk consist primarily of its cash equivalents, time deposits, marketable securities, derivative financial instruments and trade receivables. The company’s short-term investments are placed with a wide array of financial institutions with high credit ratings. Company investment policies limit the company’s exposure both to credit risk and to concentrations of credit risk. Similar policies on diversification and creditworthiness are applied to the company’s counterparties in derivative instruments.

The trade receivable balances, reflecting the company’s diversified sources of revenue, are dispersed among the company’s broad customer base worldwide. As a result, the company believes concentrations of credit risk are limited. The company routinely assesses the financial strength of its customers. When the financial strength of a customer is not considered sufficient, requiring Letters of Credit is a principal method used to support sales to customers.

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.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 45
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Operating Segments and Geographic Data [Abstract]

Operating Segments and Geographic Data

12 Months Ended

Dec. 31, 2011

Operating Segments and Geographic Data

Note 11

Operating Segments and Geographic Data

Although each subsidiary of Chevron is responsible for its own affairs, Chevron Corporation manages its investments in these subsidiaries and their affiliates. The investments are grouped into two business segments, Upstream and Downstream, representing the company’s “reportable segments” and “operating segments” as defined in accounting standards for segment reporting (ASC 280). Upstream operations consist primarily of exploring for, developing and producing crude oil and natural gas; liquefaction, transportation and regasification associated with liquefied natural gas (LNG); transporting crude oil by major international oil export pipelines; processing, transporting, storage and marketing of natural gas; and a gas-to-liquids project. Downstream operations consist primarily of refining of crude oil into petroleum products; marketing of crude oil and refined products; transporting of crude oil and refined products by pipeline, marine vessel, motor equipment and rail car; and manufacturing and marketing of commodity petrochemicals, plastics for industrial uses, and fuel and lubricant additives. All Other activities of the company include mining operations, power generation businesses, worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, energy services, alternative fuels and technology.

The segments are separately managed for investment purposes under a structure that includes “segment managers” who report to the company’s “chief operating decision maker” (CODM) (terms as defined in ASC 280). The CODM is the company’s Executive Committee (EXCOM), a committee of senior officers that includes the Chief Executive Officer, and EXCOM reports to the Board of Directors of Chevron Corporation.

The operating segments represent components of the company, as described in accounting standards for segment reporting (ASC 280), that engage in activities (a) from which revenues are earned and expenses are incurred; (b) whose operating results are regularly reviewed by the CODM, which makes decisions about resources to be allocated to the segments and assesses their performance; and (c) for which discrete financial information is available.

Segment managers for the reportable segments are directly accountable to and maintain regular contact with the company’s CODM to discuss the segment’s operating activities and financial performance. The CODM approves annual capital and exploratory budgets at the reportable segment level, as well as reviews capital and exploratory funding for major projects and approves major changes to the annual capital and exploratory budgets. However, business-unit managers within the operating segments are directly responsible for decisions relating to project implementation and all other matters connected with daily operations. Company officers who are members of the EXCOM also have individual management responsibilities and participate in other committees for purposes other than acting as the CODM.

The company’s primary country of operation is the United States of America, its country of domicile. Other components of the company’s operations are reported as “International” (outside the United States).

Segment Earnings The company evaluates the performance of its operating segments on an after-tax basis, without considering the effects of debt financing interest expense or investment interest income, both of which are managed by the company on a worldwide basis. Corporate administrative costs and assets are not allocated to the operating segments. However, operating segments are billed for the direct use of corporate services. Nonbillable costs remain at the corporate level in “All Other.” Earnings by major operating area are presented in the following table:


	Year ended December 31
	2011			2010			2009

Segment Earnings
Upstream
United States	$	6,512		$	4,122		$	2,262
International		18,274			13,555			8,670

Total Upstream		24,786			17,677			10,932

Downstream
United States		1,506			1,339			(121	)
International		2,085			1,139			594

Total Downstream		3,591			2,478			473

Total Segment Earnings		28,377			20,155			11,405
All Other
Interest expense		–			(41	)		(22	)
Interest income		78			70			46
Other		(1,560	)		(1,160	)		(946	)

Net Income Attributable to Chevron Corporation	$	26,895		$	19,024		$	10,483

Segment Assets Segment assets do not include intercompany investments or intercompany receivables. Segment assets at year-end 2011 and 2010 are as follows:


	At December 31
	2011		2010

Upstream
United States	$	37,108	$	26,319
International		98,540		89,306
Goodwill		4,642		4,617

Total Upstream		140,290		120,242

Downstream
United States		22,182		21,406
International		20,517		20,559

Total Downstream		42,699		41,965

Total Segment Assets		182,989		162,207

All Other*
United States		8,824		11,125
International		17,661		11,437

Total All Other		26,485		22,562

Total Assets – United States		68,114		58,850
Total Assets – International		136,718		121,302
Goodwill		4,642		4,617

Total Assets	$	209,474	$	184,769


*		“All Other” assets consist primarily of worldwide cash, cash equivalents, time deposits and marketable securities, real estate, energy services, information systems, mining operations, power generation businesses, alternative fuels and technology companies, and assets of the corporate administrative functions.

Segment Sales and Other Operating Revenues Operating segment sales and other operating revenues, including internal transfers, for the years 2011, 2010 and 2009, are presented in the table that follows. Products are transferred between operating segments at internal product values that approximate market prices.

Revenues for the upstream segment are derived primarily from the production and sale of crude oil and natural gas, as well as the sale of third-party production of natural gas. Revenues for the downstream segment are derived from the refining and marketing of petroleum products such as gasoline, jet fuel, gas oils, lubricants, residual fuel oils and other products derived from crude oil. This segment also generates revenues from the manufacture and sale of additives for fuels and lubricant oils and the transportation and trading of refined products, crude oil and natural gas liquids. “All Other” activities include revenues from mining operations, power generation businesses, insurance operations, real estate activities, energy services, alternative fuels and technology companies.

Other than the United States, no single country accounted for 10 percent or more of the company’s total sales and other operating revenues in 2011, 2010 and 2009.


	Year ended December 31
	2011			2010			2009*

Upstream
United States	$	9,623		$	10,316		$	9,225
Intersegment		18,115			13,839			10,297

Total United States		27,738			24,155			19,522

International		20,086			17,300			13,463
Intersegment		35,012			23,834			18,477

Total International		55,098			41,134			31,940

Total Upstream		82,836			65,289			51,462

Downstream
United States		86,793			70,436			58,056
Excise and similar taxes		4,199			4,484			4,573
Intersegment		86			115			98

Total United States		91,078			75,035			62,727

International		119,254			90,922			77,845
Excise and similar taxes		3,886			4,107			3,536
Intersegment		81			93			87

Total International		123,221			95,122			81,468

Total Downstream		214,299			170,157			144,195

All Other
United States		526			610			665
Intersegment		1,072			947			964

Total United States		1,598			1,557			1,629

International		4			23			39
Intersegment		42			39			33

Total International		46			62			72

Total All Other		1,644			1,619			1,701

Segment Sales and Other Operating Revenues
United States		120,414			100,747			83,878
International		178,365			136,318			113,480

Total Segment Sales and Other Operating Revenues		298,779			237,065			197,358
Elimination of intersegment sales		(54,408	)		(38,867	)		(29,956	)

Total Sales and Other Operating Revenues	$	244,371		$	198,198		$	167,402


*	2009 conformed with 2010 and 2011 presentation.

Segment Income Taxes Segment income tax expense for the years 2011, 2010 and 2009 is as follows:


	Year ended December 31
	2011			2010			2009

Upstream
United States	$	3,701		$	2,285		$	1,251
International		16,743			10,480			7,451

Total Upstream		20,444			12,765			8,702

Downstream
United States		785			680			(83	)
International		416			462			463

Total Downstream		1,201			1,142			380

All Other		(1,019	)		(988	)		(1,117	)

Total Income Tax Expense	$	20,626		$	12,919		$	7,965

Other Segment Information Additional information for the segmentation of major equity affiliates is contained in Note 12, beginning on page FS-39. Information related to properties, plant and equipment by segment is contained in Note 13, on page FS-41.

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.

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Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8595-108599

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8933-108599

Property, Plant and Equipment [Abstract]

Investments and Advances

12 Months Ended

Dec. 31, 2011

Investments and Advances [Abstract]

Investments and Advances

Note 12

Investments and Advances

Equity in earnings, together with investments in and advances to companies accounted for using the equity method and other investments accounted for at or below cost, is shown in the following table. For certain equity affiliates, Chevron pays its share of some income taxes directly. For such affiliates, the equity in earnings does not include these taxes, which are reported on the Consolidated Statement of Income as “Income tax expense.”


	Investments and Advances				Equity in Earnings
	At December 31				Year ended December 31
	2011		2010		2011			2010			2009

Upstream
Tengizchevroil	$	5,306	$	5,789	$	5,097		$	3,398		$	2,216
Petropiar		909		973		116			262			122
Caspian Pipeline Consortium		1,094		974		122			124			105
Petroboscan		1,032		937		247			222			171
Angola LNG Limited		2,921		2,481		(42	)		(21	)		(12	)
Other		2,420		1,922		166			319			287

Total Upstream		13,682		13,076		5,706			4,304			2,889

Downstream
GS Caltex Corporation		2,572		2,496		248			158			(191	)
Chevron Phillips Chemical Company LLC		2,909		2,419		985			704			328
Star Petroleum Refining Company Ltd.		1,022		947		75			122			(4	)
Caltex Australia Ltd.		819		767		117			101			11
Colonial Pipeline Company		–		–		–			43			51
Other		630		602		183			151			149

Total Downstream		7,952		7,231		1,608			1,279			344

All Other
Other		516		509		49			54			83

Total equity method	$	22,150	$	20,816	$	7,363		$	5,637		$	3,316
Other at or below cost		718		704

Total investments and advances	$	22,868	$	21,520

Total United States	$	4,847	$	3,769	$	1,119		$	846		$	511
Total International	$	18,021	$	17,751	$	6,244		$	4,791		$	2,805

Descriptions of major affiliates, including significant differences between the company’s carrying value of its investments and its underlying equity in the net assets of the affiliates, are as follows:

Tengizchevroil Chevron has a 50 percent equity ownership interest in Tengizchevroil (TCO), a joint venture formed in 1993 to develop the Tengiz and Korolev crude oil fields in Kazakhstan over a 40-year period. At December 31, 2011, the company’s carrying value of its investment in TCO was about $180 higher than the amount of underlying equity in TCO’s net assets. This difference results from Chevron acquiring a portion of its interest in TCO at a value greater than the underlying book value for that portion of TCO’s net assets. See Note 7, on page FS-33, for summarized financial information for 100 percent of TCO.

Petropiar Chevron has a 30 percent interest in Petropiar, a joint stock company formed in 2008 to operate the Hamaca heavy-oil production and upgrading project. The project, located in Venezuela’s Orinoco Belt, has a 25-year contract term. Prior to the formation of Petropiar, Chevron had a 30 percent interest in the Hamaca project. At December 31, 2011, the company’s carrying value of its investment in Petropiar was approximately $180 less than the amount of underlying equity in Petropiar’s net assets. The difference represents the excess of Chevron’s underlying equity in Petropiar’s net assets over the net book value of the assets contributed to the venture.

Caspian Pipeline Consortium Chevron has a 15 percent interest in the Caspian Pipeline Consortium, a variable interest entity, which provides the critical export route for crude oil from both TCO and Karachaganak. The company joined the consortium in 1997 and has investments and advances totaling $1,094 which includes long-term loans of $l,111 at year-end 2011. The loans were provided to fund 30 percent of the initial pipeline construction. The company is not the primary beneficiary of the consortium because it does not direct activities of the consortium and only receives its proportionate share of the financial returns.

Petroboscan Chevron has a 39 percent interest in Petroboscan, a joint stock company formed in 2006 to operate the Boscan Field in Venezuela until 2026. Chevron previously operated the field under an operating service agreement. At December 31, 2011, the company’s carrying value of its investment in Petroboscan was approximately $220 higher than the amount of underlying equity in Petroboscan’s net assets. The difference reflects the excess of the net book value of the assets contributed by Chevron over its underlying equity in Petroboscan’s net assets.

Angola LNG Ltd. Chevron has a 36 percent interest in Angola LNG Ltd., which will process and liquefy natural gas produced in Angola for delivery to international markets.

GS Caltex Corporation Chevron owns 50 percent of GS Caltex Corporation, a joint venture with GS Holdings. The joint venture imports, refines and markets petroleum products and petrochemicals, predominantly in South Korea.

Chevron Phillips Chemical Company LLC Chevron owns 50 percent of Chevron Phillips Chemical Company LLC. The other half is owned by ConocoPhillips Corporation.

Star Petroleum Refining Company Ltd. Chevron has a 64 percent equity ownership interest in Star Petroleum Refining Company Ltd. (SPRC), which owns the Star Refinery in Thailand. PTT Public Company Limited owns the remaining 36 percent of SPRC.

Caltex Australia Ltd. Chevron has a 50 percent equity ownership interest in Caltex Australia Ltd. (CAL). The remaining 50 percent of CAL is publicly owned. At December 31, 2011, the fair value of Chevron’s share of CAL common stock was approximately $1,600.

Other Information “Sales and other operating revenues” on the Consolidated Statement of Income includes $20,164, $13,672 and $10,391 with affiliated companies for 2011, 2010 and 2009, respectively. “Purchased crude oil and products” includes $7,489, $5,559 and $4,631 with affiliated companies for 2011, 2010 and 2009, respectively.

“Accounts and notes receivable” on the Consolidated Balance Sheet includes $1,968 and $1,718 due from affiliated companies at December 31, 2011 and 2010, respectively. “Accounts payable” includes $519 and $377 due to affiliated companies at December 31, 2011 and 2010, respectively.

The following table provides summarized financial information on a 100 percent basis for all equity affiliates as well as Chevron’s total share, which includes Chevron loans to affiliates of $957, $1,543 and $2,422 at December 31, 2011, 2010 and 2009, respectively.


	Affiliates						Chevron Share
Year ended December 31	2011		2010		2009		2011		2010		2009

Total revenues	$	140,107	$	107,505	$	81,995	$	68,632	$	52,088	$	39,280
Income before income tax expense		23,054		18,468		11,083		10,555		7,966		4,511
Net income attributable to affiliates		16,663		12,831		8,261		7,413		5,683		3,285

At December 31

Current assets	$	35,573	$	30,335	$	27,111	$	14,695	$	12,845	$	11,009

Noncurrent assets		61,855		57,491		55,363		22,422		21,401		21,361
Current liabilities		24,671		20,428		17,450		11,040		9,363		7,833

Noncurrent liabilities		19,267		19,749		21,531		4,491		4,459		5,106

Total affiliates’ net equity	$	53,490	$	47,649	$	43,493	$	21,586	$	20,424	$	19,431

Properties, Plant and Equipment

12 Months Ended

Dec. 31, 2011

Properties, Plant and Equipment

Note 13

Properties, Plant and Equipment¹


	At December 31												Year ended December 31
	Gross Investment at Cost						Net Investment						Additions at Cost^2,3						Depreciation Expense⁴
	2011		2010		2009		2011		2010		2009		2011		2010		2009		2011		2010		2009

Upstream
United States	$	74,369	$	62,523	$	58,328	$	33,461	$	23,277	$	22,273	$	14,404	$	4,934	$	3,518	$	3,870	$	4,078	$	3,992
International		125,795		110,578		96,557		72,543		64,388		57,450		15,722		14,381		10,803		7,590		7,448		6,669

Total Upstream		200,164		173,101		154,885		106,004		87,665		79,723		30,126		19,315		14,231		11,460		11,526		10,661

Downstream
United States		20,699		19,820		18,962		10,723		10,379		10,032		1,226		1,199		1,874		776		741		666
International		7,422		9,697		9,852		2,995		3,948		4,154		443		361		456		332		451		454

Total Downstream		28,121		29,517		28,814		13,718		14,327		14,186		1,669		1,560		2,330		1,108		1,192		1,120

All Other⁵
United States		5,117		4,722		4,569		2,872		2,496		2,548		591		259		354		338		341		325
International		30		27		20		14		16		11		5		11		3		5		4		4

Total All Other		5,147		4,749		4,589		2,886		2,512		2,559		596		270		357		343		345		329

Total United States		100,185		87,065		81,859		47,056		36,152		34,853		16,221		6,392		5,746		4,984		5,160		4,983
Total International		133,247		120,302		106,429		75,552		68,352		61,615		16,170		14,753		11,262		7,927		7,903		7,127

Total	$	233,432	$	207,367	$	188,288	$	122,608	$	104,504	$	96,468	$	32,391	$	21,145	$	17,008	$	12,911	$	13,063	$	12,110


¹	Other than the United States, Nigeria and Australia, no other country accounted for 10 percent or more of the company’s net properties, plant and equipment (PP&E) in 2011. Nigeria had PP&E of $15,601, $13,896 and $12,463 for 2011, 2010 and 2009, respectively. Australia had $12,423 in 2011.

²	Net of dry hole expense related to prior years’ expenditures of $45, $82 and $84 in 2011, 2010 and 2009, respectively.

³	Includes properties acquired with the acquisition of Atlas Energy, Inc. in 2011.

⁴	Depreciation expense includes accretion expense of $628, $513 and $463 in 2011, 2010 and 2009, respectively.

⁵	Primarily mining operations, power generation businesses, real estate assets and management information systems.

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.

Litigation	12 Months Ended
Litigation	Dec. 31, 2011
Other Contingencies and Commitments [Abstract]
Litigation	Note 14 Litigation MTBE Chevron and many other companies in the petroleum industry have used methyl tertiary butyl ether (MTBE) as a gasoline additive. Chevron is a party to eight pending lawsuits and claims, the majority of which involve numerous other petroleum marketers and refiners. Resolution of these lawsuits and claims may ultimately require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE, including personal-injury claims, may be filed in the future. The company’s ultimate exposure related to pending lawsuits and claims is not determinable, but could be material to net income in any one period. The company no longer uses MTBE in the manufacture of gasoline in the United States. Ecuador Chevron is a defendant in a civil lawsuit before the Superior Court of Nueva Loja in Lago Agrio, Ecuador, brought in May 2003 by plaintiffs who claim to be representatives of certain residents of an area where an oil production consortium formerly had operations. The lawsuit alleges damage to the environment from the oil exploration and production operations and seeks unspecified damages to fund environmental remediation and restoration of the alleged environmental harm, plus a health monitoring program. Until 1992, Texaco Petroleum Company (Texpet), a subsidiary of Texaco Inc., was a minority member of this consortium with Petroecuador, the Ecuadorian state-owned oil company, as the majority partner; since 1990, the operations have been conducted solely by Petroecuador. At the conclusion of the consortium and following an independent third-party environmental audit of the concession area, Texpet entered into a formal agreement with the Republic of Ecuador and Petroecuador for Texpet to remediate specific sites assigned by the government in proportion to Texpet’s ownership share of the consortium. Pursuant to that agreement, Texpet conducted a three-year remediation program at a cost of $40. After certifying that the sites were properly remediated, the government granted Texpet and all related corporate entities a full release from any and all environmental liability arising from the consortium operations. Based on the history described above, Chevron believes that this lawsuit lacks legal or factual merit. As to matters of law, the company believes first, that the court lacks jurisdiction over Chevron; second, that the law under which plaintiffs bring the action, enacted in 1999, cannot be applied retroactively; third, that the claims are barred by the statute of limitations in Ecuador; and, fourth, that the lawsuit is also barred by the releases from liability previously given to Texpet by the Republic of Ecuador and Petroecuador and by the pertinent provincial and municipal governments. With regard to the facts, the company believes that the evidence confirms that Texpet’s remediation was properly conducted and that the remaining environmental damage reflects Petroecuador’s failure to timely fulfill its legal obligations and Petroecuador’s further conduct since assuming full control over the operations. In 2008, a mining engineer appointed by the court to identify and determine the cause of environmental damage, and to specify steps needed to remediate it, issued a report recommending that the court assess $18,900, which would, according to the engineer, provide financial compensation for purported damages, including wrongful death claims, and pay for, among other items, environmental remediation, health care systems and additional infrastructure for Petroecuador. The engineer’s report also asserted that an additional $8,400 could be assessed against Chevron for unjust enrichment. In 2009, following the disclosure by Chevron of evidence that the judge participated in meetings in which businesspeople and individuals holding themselves out as government officials discussed the case and its likely outcome, the judge presiding over the case was recused. In 2010, Chevron moved to strike the mining engineer’s report and to dismiss the case based on evidence obtained through discovery in the United States indicating that the report was prepared by consultants for the plaintiffs before being presented as the mining engineer’s independent and impartial work and showing further evidence of misconduct. In August 2010, the judge issued an order stating that he was not bound by the mining engineer’s report and requiring the parties to provide their positions on damages within 45 days. Chevron subsequently petitioned for recusal of the judge, claiming that he had disregarded evidence of fraud and misconduct and that he had failed to rule on a number of motions within the statutory time requirement. In September 2010, Chevron submitted its position on damages, asserting that no amount should be assessed against it. The plaintiffs’submission, which relied in part on the mining engineer’s report, took the position that damages are between approximately $16,000 and $76,000 and that unjust enrichment should be assessed in an amount between approximately $5,000 and $38,000. The next day, the judge issued an order closing the evidentiary phase of the case and notifying the parties that he had requested the case file so that he could prepare a judgment. Chevron petitioned to have that order declared a nullity in light of Chevron’s prior recusal petition, and because procedural and evidentiary matters remained unresolved. In October 2010, Chevron’s motion to recuse the judge was granted. A new judge took charge of the case and revoked the prior judge’s order closing the evidentiary phase of the case. On December 17, 2010, the judge issued an order closing the evidentiary phase of the case and notifying the parties that he had requested the case file so that he could prepare a judgment. On February 14, 2011, the provincial court in Lago Agrio rendered an adverse judgment in the case. The court rejected Chevron’s defenses to the extent the court addressed them in its opinion. The judgment assessed approximately $8,600 in damages and approximately $900 as an award for the plaintiffs’ representatives. It also assessed an additional amount of approximately $8,600 in punitive damages unless the company issued a public apology within 15 days of the judgment, which Chevron did not do. On February 17, 2011, the plaintiffs appealed the judgment, seeking increased damages, and on March 11, 2011, Chevron appealed the judgment seeking to have the judgment nullified. On January 3, 2012, an appellate panel in the provincial court affirmed the February 14, 2011 decision and ordered that Chevron pay additional attorneys’ fees in the amount of “.10% of the values that are derived from the decisional act of this judgment.” The plaintiffs filed a petition to clarify and amplify the appellate decision on January 6, 2012, and the court issued a ruling in response on January 13, 2012, purporting to clarify and amplify its January 3, 2012 ruling, which included clarification that the deadline for the company to issue a public apology to avoid the additional amount of approximately $8,600 in punitive damages was within fifteen days of the clarification ruling, or February 3, 2012. Chevron did not issue an apology because doing so might be mischaracterized as an admission of liability and would be contrary to facts and evidence submitted at trial. On January 20, 2012, Chevron appealed (called a petition for cassation) the appellate panel’s decision to Ecuador’s National Court of Justice. As part of the appeal, Chevron requested the suspension of any requirement that Chevron post a bond to prevent enforcement under Ecuadorian law of the judgment during the cassation appeal. On February 17, 2012, the appellate panel of the provincial court admitted Chevron’s cassation appeal in a procedural step necessary for the National Court of Justice to hear the appeal. The provincial court appellate panel denied Chevron’s request for a suspension of the requirement that Chevron post a bond and stated that it would not comply with the first Interim Award of the international arbitration tribunal discussed below. Chevron continues to believe the provincial court’s judgment is illegitimate and unenforceable in Ecuador, the United States and other countries. The company also believes the judgment is the product of fraud, and contrary to the legitimate scientific evidence. Chevron cannot predict the timing or ultimate outcome of the appeals process in Ecuador. Chevron will continue a vigorous defense of any imposition of liability. Chevron has no assets in Ecuador and the Lago Agrio plaintiffs’ lawyers have stated in press releases and through other media that they will seek to enforce the Ecuadorian judgement in various countries and otherwise disrupt Chevron’s operations. Chevron expects to contest and defend against any such actions. Chevron and Texpet filed an arbitration claim in September 2009 against the Republic of Ecuador before an arbitral tribunal presiding in the Permanent Court of Arbitration in The Hague under the Rules of the United Nations Commission on International Trade Law. The claim alleges violations of the Republic of Ecuador’s obligations under the United States–Ecuador Bilateral Investment Treaty (BIT) and breaches of the settlement and release agreements between the Republic of Ecuador and Texpet (described above), which are investment agreements protected by the BIT. Through the arbitration, Chevron and Texpet are seeking relief against the Republic of Ecuador, including a declaration that any judgment against Chevron in the Lago Agrio litigation constitutes a violation of Ecuador’s obligations under the BIT. On February 9, 2011, the Tribunal issued an Order for Interim Measures requiring the Republic of Ecuador to take all measures at its disposal to suspend or cause to be suspended the enforcement or recognition within and without Ecuador of any judgment against Chevron in the Lago Agrio case pending further order of the Tribunal. On January 25, 2012, the Tribunal converted the Order for Interim Measures into an Interim Award. Chevron filed a renewed application for further interim measures on January 4, 2012, and the Republic of Ecuador opposed Chevron’s application and requested that the existing Order for Interim Measures be vacated on January 9, 2012. On February 16, 2012, the Tribunal issued a second Interim Award mandating that the Republic of Ecuador take all measures necessary (whether by its judicial, legislative or executive branches) to suspend or cause to be suspended the enforcement and recognition within and without Ecuador of the judgment against Chevron and, in particular, to preclude any certification by the Republic of Ecuador that would cause the judgment to be enforceable against Chevron. Chevron expects to continue seeking permanent injunctive relief and monetary relief before the Tribunal. Through a series of recent U.S. court proceedings initiated by Chevron to obtain discovery relating to the Lago Agrio litigation and the BIT arbitration, Chevron has obtained evidence that it believes shows a pattern of fraud, collusion, corruption, and other misconduct on the part of several lawyers, consultants and others acting for the Lago Agrio plaintiffs. In February 2011, Chevron filed a civil lawsuit in the Federal District Court for the Southern District of New York against the Lago Agrio plaintiffs and several of their lawyers, consultants and supporters, alleging violations of the Racketeer Influenced and Corrupt Organizations Act and other state laws. Through the civil lawsuit, Chevron is seeking relief that includes an award of damages and a declaration that any judgment against Chevron in the Lago Agrio litigation is the result of fraud and other unlawful conduct and is therefore unenforceable. On March 7, 2011, the Federal District Court issued a preliminary injunction prohibiting the Lago Agrio plaintiffs and persons acting in concert with them from taking any action in furtherance of recognition or enforcement of any judgment against Chevron in the Lago Agrio case pending resolution of Chevron’s civil lawsuit by the Federal District Court. On May 31, 2011, the Federal District Court severed claims one through eight of Chevron’s complaint from the ninth claim for declaratory relief and imposed a discovery stay on claims one through eight pending a trial on the ninth claim for declaratory relief. On September 19, 2011, the U.S. Court of Appeals for the Second Circuit vacated the preliminary injunction, stayed the trial on Chevron’s ninth claim, a claim for declaratory relief, that had been set for November 14, 2011, and denied the defendants’ mandamus petition to recuse the judge hearing the lawsuit. The Second Circuit issued its opinion on January 26, 2012 ordering the dismissal of Chevron’s ninth claim for declaratory relief. On February 16, 2012, the Federal District Court lifted the stay on claims one through eight. The ultimate outcome of the foregoing matters, including any financial effect on Chevron, remains uncertain. Management does not believe an estimate of a reasonably possible loss (or a range of loss) can be made in this case. Due to the defects associated with the Ecuadorian judgment, the 2008 engineer’s report on alleged damages and the September 2010 plaintiffs’submission on alleged damages, management does not believe these documents have any utility in calculating a reasonably possible loss (or a range of loss). Moreover, the highly uncertain legal environment surrounding the case provides no basis for management to estimate a reasonably possible loss (or a range of loss).

Taxes

12 Months Ended

Dec. 31, 2011

Taxes [Abstract]

Taxes

Note 15

Taxes

Income Taxes


	Year ended December 31
	2011		2010		2009

Taxes on income
U.S. Federal
Current	$	1,893	$	1,501	$	128
Deferred		877		162		(147	)
State and local
Current		596		376		216
Deferred		41		20		14

Total United States		3,407		2,059		211

International
Current		16,548		10,483		7,154
Deferred		671		377		600

Total International		17,219		10,860		7,754

Total taxes on income	$	20,626	$	12,919	$	7,965

In 2011, before-tax income for U.S. operations, including related corporate and other charges, was $10,222, compared

with before-tax income of $6,528 and $1,310 in 2010 and 2009, respectively. For international operations, before-tax income was $37,412, $25,527 and $17,218 in 2011, 2010 and 2009, respectively. U.S. federal income tax expense was reduced by $191, $162 and $204 in 2011, 2010 and 2009, respectively, for business tax credits.
The reconciliation between the U.S. statutory federal income tax rate and the company’s effective income tax rate is detailed in the following table:


	Year ended December 31
	2011			2010			2009

U.S. statutory federal income tax rate		35.0	%		35.0	%		35.0	%
Effect of income taxes from inter- national operations at rates different from the U.S. statutory rate		7.5			5.2			10.4
State and local taxes on income, net of U.S. federal income tax benefit		0.9			0.8			0.9
Prior year tax adjustments		(0.1	)		(0.6	)		(0.3	)
Tax credits		(0.4	)		(0.5	)		(1.1	)
Effects of changes in tax rates		0.5			–			0.1
Other		(0.1	)		0.4			(2.0	)

Effective tax rate		43.3	%		40.3	%		43.0	%

The company’s effective tax rate increased from 40.3 percent in 2010 to 43.3 percent in 2011. This increase primarily reflected higher effective tax rates in international upstream jurisdictions. The higher international upstream effective tax rates were driven primarily by lower utilization of non-U.S. tax credits in 2011 and the effect of changes in income tax rates between periods, which were partially offset by foreign currency remeasurement impacts between periods.

The company records its deferred taxes on a tax-jurisdiction basis and classifies those net amounts as current or noncurrent based on the balance sheet classification of the related assets or liabilities. The reported deferred tax balances are composed of the following:


	At December 31
	2011			2010

Deferred tax liabilities
Properties, plant and equipment	$	23,597		$	19,855
Investments and other		2,271			2,401

Total deferred tax liabilities		25,868			22,256

Deferred tax assets
Foreign tax credits		(8,476	)		(6,669	)
Abandonment/environmental reserves		(5,387	)		(5,004	)
Employee benefits		(4,773	)		(3,627	)
Deferred credits		(1,548	)		(2,176	)
Tax loss carryforwards		(828	)		(882	)
Other accrued liabilities		(531	)		(486	)
Inventory		(360	)		(483	)
Miscellaneous		(1,595	)		(1,676	)

Total deferred tax assets		(23,498	)		(21,003	)

Deferred tax assets valuation allowance		11,096			9,185

Total deferred taxes, net	$	13,466		$	10,438

Deferred tax liabilities at the end of 2011 increased by approximately $3,600 from year-end 2010. The increase was related to increased temporary differences for property, plant and equipment.

Deferred tax assets increased by approximately $2,500 in 2011. Increases primarily related to additional foreign tax credits arising from earnings in high-tax-rate international jurisdictions (which were substantially offset by valuation allowances) and to increased temporary differences for employee benefits. These effects were partially offset by reductions in deferred credits resulting primarily from the usage of tax benefits in international tax jurisdictions.

The overall valuation allowance relates to deferred tax assets for foreign tax credit carryforwards, tax loss carryforwards and temporary differences. It reduces the deferred tax assets to amounts that are, in management’s assessment, more likely than not to be realized. At the end of 2011, tax loss carryforwards were approximately $2,160, primarily related to various international tax jurisdictions. Whereas some of these tax loss carryforwards do not have an expiration date, others expire at various times from 2012 through 2036. Foreign tax credit carryforwards of $8,476 will expire between 2012 and 2021.

At December 31, 2011 and 2010, deferred taxes were classified on the Consolidated Balance Sheet as follows:


	At December 31
	2011			2010

Prepaid expenses and other current assets	$	(1,149	)	$	(1,624	)
Deferred charges and other assets		(1,224	)		(851	)
Federal and other taxes on income		295			216
Noncurrent deferred income taxes		15,544			12,697

Total deferred income taxes, net	$	13,466		$	10,438

Income taxes are not accrued for unremitted earnings of international operations that have been or are intended to be reinvested indefinitely. Undistributed earnings of international consolidated subsidiaries and affiliates for which no deferred income tax provision has been made for possible future remittances totaled $24,376 at December 31, 2011. This amount represents earnings reinvested as part of the company’s ongoing international business. It is not practicable to estimate the amount of taxes that might be payable on the possible remittance of earnings that are intended to be reinvested indefinitely. At the end of 2011, deferred income taxes were recorded for the undistributed earnings of certain international operations where indefinite reinvestment of the earnings is not planned. The company does not anticipate incurring significant additional taxes on remittances of earnings that are not indefinitely reinvested.

Uncertain Income Tax Positions Under accounting standards for uncertainty in income taxes (ASC 740-10), a company recognizes a tax benefit in the financial statements for an uncertain tax position only if management’s assessment is that the position is “more likely than not” (i.e., a likelihood greater than 50 percent) to be allowed by the tax jurisdiction based solely on the technical merits of the position. The term “tax position” in the accounting standards for income taxes refers to a position in a previously filed tax return or a position expected to be taken in a future tax return that is reflected in measuring current or deferred income tax assets and liabilities for interim or annual periods.

The following table indicates the changes to the company’s unrecognized tax benefits for the years ended December 31, 2011, 2010 and 2009. The term “unrecognized tax benefits” in the accounting standards for income taxes refers to the differences between a tax position taken or expected to be taken in a tax return and the benefit measured and recognized in the financial statements. Interest and penalties are not included.


	2011			2010			2009

Balance at January 1	$	3,507		$	3,195		$	2,696
Foreign currency effects		(2	)		17			(1	)
Additions based on tax positions taken in current year		469			334			459
Reductions based on tax positions taken in current year		–			–			–
Additions/reductions resulting from current-year asset acquisitions/sales		(41	)		–			–
Additions for tax positions taken in prior years		236			270			533
Reductions for tax positions taken in prior years		(366	)		(165	)		(182	)
Settlements with taxing authorities in current year		(318	)		(136	)		(300	)
Reductions as a result of a lapse of the applicable statute of limitations		(4	)		(8	)		(10	)

Balance at December 31	$	3,481		$	3,507		$	3,195

Approximately 80 percent of the $3,481 of unrecognized tax benefits at December 31, 2011, would have an impact on the effective tax rate if subsequently recognized. Certain of these unrecognized tax benefits relate to tax carryforwards that may require a full valuation allowance at the time of any such recognition.

Tax positions for Chevron and its subsidiaries and affiliates are subject to income tax audits by many tax jurisdictions throughout the world. For the company’s major tax jurisdictions, examinations of tax returns for certain prior tax years had not been completed as of December 31, 2011. For these jurisdictions, the latest years for which income tax examinations had been finalized were as follows: United States – 2007, Nigeria – 2000, Angola – 2001, Saudi Arabia – 2003 and Kazakhstan – 2005.

The company engages in ongoing discussions with tax authorities regarding the resolution of tax matters in the various jurisdictions. Both the outcome of these tax matters and the timing of resolution and/or closure of the tax audits are highly uncertain. However, it is reasonably possible that developments on tax matters in certain tax jurisdictions may result in significant increases or decreases in the company’s total unrecognized tax benefits within the next 12 months. Given the number of years that still remain subject to examination and the number of matters being examined in the various tax jurisdictions, the company is unable to estimate the range of possible adjustments to the balance of unrecognized tax benefits.

On the Consolidated Statement of Income, the company reports interest and penalties related to liabilities for uncertain tax positions as “Income tax expense.” As of December 31, 2011, accruals of $118 for anticipated interest and penalty obligations were included on the Consolidated Balance Sheet, compared with accruals of $225 as of year-end 2010. Income tax expense (benefit) associated with interest and penalties was $(64), $40 and $(20) in 2011, 2010 and 2009, respectively.

Taxes Other Than on Income


	Year ended December 31
	2011		2010		2009

United States
Excise and similar taxes on products and merchandise	$	4,199	$	4,484	$	4,573
Import duties and other levies		4		–		(4	)
Property and other miscellaneous taxes		726		567		584
Payroll taxes		236		219		223
Taxes on production		308		271		135

Total United States		5,473		5,541		5,511

International
Excise and similar taxes on products and merchandise		3,886		4,107		3,536
Import duties and other levies		3,511		6,183		6,550
Property and other miscellaneous taxes		2,354		2,000		1,740
Payroll taxes		148		133		134
Taxes on production		256		227		120

Total International		10,155		12,650		12,080

Total taxes other than on income	$	15,628	$	18,191	$	17,591

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.

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
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 9
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32639-109319

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
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32537-109319

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32559-109319

Short-Term Debt

12 Months Ended

Dec. 31, 2011

Short-Term Debt

Note 16

Short-Term Debt


	At December 31
	2011			2010

Commercial paper*	$	2,498		$	2,471
Notes payable to banks and others with originating terms of one year or less		40			43
Current maturities of long-term debt		17			33
Current maturities of long-term capital leases		54			81
Redeemable long-term obligations
Long-term debt		3,317			2,943
Capital leases		14			16

Subtotal		5,940			5,587
Reclassified to long-term debt		(5,600	)		(5,400	)

Total short-term debt	$	340		$	187


*		Weighted-average interest rates at December 31, 2011 and 2010, were 0.04 percent and 0.16 percent, respectively.

Redeemable long-term obligations consist primarily of tax-exempt variable-rate put bonds that are included as current liabilities because they become redeemable at the option of the bondholders during the year following the balance sheet date. In 2011, $374 of tax-exempt bonds related to projects at the Pascagoula, Mississippi, refinery were issued.

The company may periodically enter into interest rate swaps on a portion of its short-term debt. At December 31, 2011, the company had no interest rate swaps on short-term debt.

At December 31, 2011, the company had $6,000 in committed credit facilities with various major banks, expiring in December 2016, that enable the refinancing of short-term obligations on a long-term basis. These facilities support commercial paper borrowing and can also be used for general corporate purposes. The company’s practice has been to continually replace expiring commitments with new commitments on substantially the same terms, maintaining levels management believes appropriate. Any borrowings under the facilities would be unsecured indebtedness at interest rates based on the London Interbank Offered Rate or an average of base lending rates published by specified banks and on terms reflecting the company’s strong credit rating. No borrowings were outstanding under these facilities at December 31, 2011.

At December 31, 2011 and 2010, the company classified $5,600 and $5,400, respectively, of short-term debt as long-term. Settlement of these obligations is not expected to require the use of working capital within one year, as the company has both the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis.

Long-Term Debt

12 Months Ended

Dec. 31, 2011

Long-term Debt

Note 17

Long-Term Debt

Total long-term debt, excluding capital leases, at December 31, 2011, was $9,684. The company’s long-term debt outstanding at year-end 2011 and 2010 was as follows:


	At December 31
	2011			2010

3.95% notes due 2014	$	1,998		$	1,998
3.45% notes due 2012		–			1,500
4.95% notes due 2019		1,500			1,500
8.625% debentures due 2032		147			147
8.625% debentures due 2031		107			107
7.5% debentures due 2043		83			83
8% debentures due 2032		74			74
7.327% amortizing notes due 2014¹		59			72
9.75% debentures due 2020		54			54
8.875% debentures due 2021		40			40
Medium-term notes, maturing from 2021 to 2038 (6.02%)²		38			38
Fixed interest rate notes, maturing 2011 (9.378%)²		–			19
Other long-term debt (8.07%)²		1			4

Total including debt due within one year		4,101			5,636
Debt due within one year		(17	)		(33	)
Reclassified from short-term debt		5,600			5,400

Total long-term debt	$	9,684		$	11,003


¹		Guarantee of ESOP debt.
²		Weighted-average interest rate at December 31, 2011 and 2010.

In March 2010, the company filed with the SEC an automatic registration statement that expires on February 28, 2013. This registration statement is for an unspecified amount of non-convertible debt securities issued or guaranteed by the company.

Long-term debt of $4,101 matures as follows: 2012 – $17; 2013 – $20; 2014 – $2,021; 2015 - $0; 2016 – $0; and after 2016 – $2,043.

In September 2011, $1,500 of Chevron Corp. bonds were redeemed early. In June 2010, $30 of Texaco Capital Inc. bonds matured.

See Note 9, beginning on page FS-34, for information concerning the fair value of the company’s long-term debt.

New Accounting Standards	12 Months Ended
New Accounting Standards	Dec. 31, 2011
Accounting Standards [Abstract]
New Accounting Standards	Note 18 New Accounting Standards Fair Value Measurement (Topic 820), Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS (ASU 2011-04) In May 2011, the FASB issued ASU 2011-04, which becomes effective for the company on January 1, 2012. The amendments in ASU 2011-04 result in common fair value measurement and disclosure requirements in U.S. GAAP and IFRS. As a result of these amendments, the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements were changed. The company does not anticipate changes to its existing classification and measurement of fair value when the amended standard becomes effective. However, the company’s disclosures on certain items not required to be measured at fair value are expected to be expanded when the amended standard becomes effective. Comprehensive Income (Topic 220) Presentation of Comprehensive Income (ASU 2011-05) The FASB issued ASU 2011-05 in June 2011. This standard becomes effective for the company on January 1, 2012. ASU 2011-05 changes the presentation requirements for comprehensive income. Adoption of the standard is not expected to have a significant impact on the company’s current financial statement presentation. Intangibles—Goodwill and Other (Topic 350) Testing Goodwill for Impairment (ASU 2011-08) In September 2011, the FASB issued ASU 2011-08, which becomes effective for the company on January 1, 2012. The standard simplifies how companies test goodwill for impairment. The company does not anticipate any impact to its results of operations, financial position or liquidity when the guidance becomes effective.

The entire disclosure for reporting accounting changes and error corrections. It includes the conveyance of information necessary for a user of the Company's financial information to understand all aspects and required disclosure information concerning all changes and error corrections reported in the Company's financial statements for the period.

Accounting for Suspended Exploratory Wells [Abstract]

Accounting for Suspended Exploratory Wells

12 Months Ended

Dec. 31, 2011

Accounting for Suspended Exploratory Wells

Note 19

Accounting for Suspended Exploratory Wells

Accounting standards for the costs of exploratory wells (ASC 932) provide that exploratory well costs continue to be capitalized after the completion of drilling when (a) the well has found a sufficient quantity of reserves to justify completion as a producing well and (b) the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met or if an enterprise obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well would be assumed to be impaired, and its costs, net of any salvage value, would be charged to expense. (Note that an entity is not required to complete the exploratory well as a producing well.) The accounting standards provide a number of indicators that can assist an entity in demonstrating that sufficient progress is being made in assessing the reserves and economic viability of the project. The following table indicates the changes to the company’s suspended exploratory well costs for the three years ended December 31, 2011:


	2011			2010			2009

Beginning balance at January 1	$	2,718		$	2,435		$	2,118
Additions to capitalized exploratory well costs pending the determination of proved reserves		652			482			663
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(828	)		(129	)		(174	)
Capitalized exploratory well costs charged to expense		(45	)		(70	)		(172	)
Other reductions*		(63	)		–			–

Ending balance at December 31	$	2,434		$	2,718		$	2,435


*		Represents property sales.

The following table provides an aging of capitalized well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling.


	At December 31
	2011		2010		2009

Exploratory well costs capitalized for a period of one year or less	$	557	$	419	$	564
Exploratory well costs capitalized for a period greater than one year		1,877		2,299		1,871

Balance at December 31	$	2,434	$	2,718	$	2,435

Number of projects with exploratory well costs that have been capitalized for a period greater than one year*		47		53		46


*		Certain projects have multiple wells or fields or both.

Of the $1,877 of exploratory well costs capitalized for more than one year at December 31, 2011, $939 (26 projects) is related to projects that had drilling activities under way or firmly planned for the near future. The $938 balance is related to 21 projects in areas requiring a major capital expenditure before production could begin and for which additional drilling efforts were not under way or firmly planned for the near future. Additional drilling was not deemed necessary because the presence of hydrocarbons had already been established, and other activities were in process to enable a future decision on project development.

The projects for the $938 referenced above had the following activities associated with assessing the reserves and the projects’ economic viability: (a) $322 (six projects) – development alternatives under review; (b) $283 (five projects) – development concept under review by government; (c) $208 (seven projects) – undergoing front-end engineering and design with final investment decision expected within three years; (d) $111 (one project) – project sanction approved and construction is in progress, with initial recognition of proved reserves expected upon reaching “economic producibility” per SEC guidelines; (e) $14 – miscellaneous activities for two projects with smaller amounts suspended. While progress was being made on all 47 projects, the decision on the recognition of proved reserves under SEC rules in some cases may not occur for several years because of the complexity, scale and negotiations connected with the projects. The majority of these decisions are expected to occur in the next three years.

The $1,877 of suspended well costs capitalized for a period greater than one year as of December 31, 2011, represents 161 exploratory wells in 47 projects. The tables below contain the aging of these costs on a well and project basis:


			Number
Aging based on drilling completion date of individual wells:	Amount		of wells

1997–2000	$	49		16
2001–2005		396		47
2006–2010		1,432		98

Total	$	1,877		161


Aging based on drilling completion date of last			Number
suspended well in project:	Amount		of projects

1999	$	8		1
2003–2006		345		10
2007–2011		1,524		36

Total	$	1,877		47

Stock Options and Other Share-Based Compensation

12 Months Ended

Dec. 31, 2011

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock Options and Other Share-Based Compensation

Note 20

Stock Options and Other Share-Based Compensation

Compensation expense for stock options for 2011, 2010 and 2009 was $265 ($172 after tax), $229 ($149 after tax) and $182 ($119 after tax), respectively. In addition, compensation expense for stock appreciation rights, restricted stock, performance units and restricted stock units was $214 ($139 after tax), $194 ($126 after tax) and $170 ($110 after tax) for 2011, 2010 and 2009, respectively. No significant stock-based compensation cost was capitalized at December 31, 2011 and 2010.

Cash received in payment for option exercises under all share-based payment arrangements for 2011, 2010 and 2009 was $948, $385 and $147, respectively. Actual tax benefits realized for the tax deductions from option exercises were $121, $66 and $25 for 2011, 2010 and 2009, respectively.

Cash paid to settle performance units and stock appreciation rights was $151, $140 and $89 for 2011, 2010 and 2009, respectively.

Chevron Long-Term Incentive Plan (LTIP) Awards under the LTIP may take the form of, but are not limited to, stock options, restricted stock, restricted stock units, stock appreciation rights, performance units and nonstock grants. From April 2004 through January 2014, no more than 160 million shares may be issued under the LTIP, and no more than 64 million of those shares may be in a form other than a stock option, stock appreciation right or award requiring full payment for shares by the award recipient. For the major types of awards outstanding as of December 31, 2011, the contractual terms vary between three years for the performance units and 10 years for the stock options and stock appreciation rights.

Texaco Stock Incentive Plan (Texaco SIP) On the closing of the acquisition of Texaco in October 2001, outstanding options granted under the Texaco SIP were converted to Chevron options. These options, which had 10-year contractual lives extending into 2011, retained a provision for being restored. This provision enabled a participant who exercised a stock option to receive new options equal to the number of shares exchanged or who had shares withheld to satisfy tax withholding obligations to receive new options equal to the number of shares exchanged or withheld. The restored options were fully exercisable six months after the date of grant, and the exercise price was the market value of the common stock on the day the restored option was granted. Beginning in 2007, restored options were issued under the LTIP. No further awards may be granted under the former Texaco plans.

Unocal Share-Based Plans (Unocal Plans) When Chevron acquired Unocal in August 2005, outstanding stock options and stock appreciation rights granted under various Unocal Plans were exchanged for fully vested Chevron options and appreciation rights. These awards retained the same provisions as the original Unocal Plans. Unexercised awards began expiring in early 2010 and will continue to expire through early 2015.

The fair market values of stock options and stock appreciation rights granted in 2011, 2010 and 2009 were measured on the date of grant using the Black-Scholes option-pricing model, with the following weighted-average assumptions:


	Year ended December 31
	2011			2010			2009

Stock Options
Expected term in years¹		6.2			6.1			6.0
Volatility²		31.0	%		30.8	%		30.2	%
Risk-free interest rate based on zero coupon U.S. treasury note		2.6	%		2.9	%		2.1	%
Dividend yield		3.6	%		3.9	%		3.2	%
Weighted-average fair value per option granted	$	21.24		$	16.28		$	15.36
Restored Options
Expected term in years¹		1.2			1.2			1.2
Volatility²		20.6	%		38.9	%		45.0	%
Risk-free interest rate based on zero coupon U.S. treasury note		0.7	%		0.6	%		1.1	%
Dividend yield		3.4	%		3.8	%		3.5	%
Weighted-average fair value per option granted	$	7.55		$	12.91		$	12.38


¹		Expected term is based on historical exercise and postvesting cancellation data.

²		Volatility rate is based on historical stock prices over an appropriate period, generally equal to the expected term.

A summary of option activity during 2011 is presented below:


						Weighted-
				Weighted-		Average
				Average		Remaining	Aggregate
	Shares			Exercise		Contractual	Intrinsic
	(Thousands)			Price		Term	Value

Outstanding at January 1, 2011		74,852		$	67.04
Granted		14,260		$	94.46
Exercised		(15,844	)	$	60.20
Restored		33		$	103.96
Forfeited		(953	)	$	85.79
Outstanding at December 31, 2011		72,348		$	73.71	6.4 yrs	$	2,365

Exercisable at December 31, 2011		45,494		$	67.84	5.3 yrs	$	1,755

The total intrinsic value (i.e., the difference between the exercise price and the market price) of options exercised during 2011, 2010 and 2009 was $668, $259 and $91, respectively. During this period, the company continued its practice of issuing treasury shares upon exercise of these awards.

As of December 31, 2011, there was $265 of total unrecognized before-tax compensation cost related to non-vested share-based compensation arrangements granted or restored under the plans. That cost is expected to be recognized over a weighted-average period of 1.7 years.

At January 1, 2011, the number of LTIP performance units outstanding was equivalent to 2,727,874 shares. During 2011, 1,011,200 units were granted, 810,071 units vested with cash proceeds distributed to recipients and 47,167 units were forfeited. At December 31, 2011, units outstanding were 2,881,836, and the fair value of the liability recorded for these instruments was $294. In addition, outstanding stock appreciation rights and other awards that were granted under various LTIP and former Texaco and Unocal programs totaled approximately 2.2 million equivalent shares as of December 31, 2011. A liability of $62 was recorded for these awards.

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.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 123R
-Paragraph 64, 65, A240
-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 AICPA
-Name Statement of Position (SOP)
-Number 93-6
-Paragraph 53
-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 SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 14

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 50
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6406099&loc=d3e25284-112666

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6415400&loc=d3e5047-113901

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6415400&loc=d3e5070-113901

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6415400&loc=d3e5444-113901

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 40
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6418621&loc=d3e17540-113929

Employee Benefit Plans

12 Months Ended

Dec. 31, 2011

Employee Benefits Plans [Abstract]

Employee Benefit Plans

Note 21

Employee Benefit Plans

The company has defined benefit pension plans for many employees. The company typically prefunds defined benefit plans as required by local regulations or in certain situations where prefunding provides economic advantages. In the United States, all qualified plans are subject to the Employee Retirement Income Security Act (ERISA) minimum funding standard. The company does not typically fund U.S. nonqualified pension plans that are not subject to funding requirements under laws and regulations because contributions to these pension plans may be less economic and investment returns may be less attractive than the company’s other investment alternatives.

The company also sponsors other postretirement (OPEB) plans that provide medical and dental benefits, as well as life insurance for some active and qualifying retired employees. The plans are unfunded, and the company and retirees share the costs. Medical coverage for Medicare-eligible retirees in the company’s main U.S. medical plan is secondary to Medicare (including Part D) and the increase to the company contribution for retiree medical coverage is limited to no more than 4 percent each year. Certain life insurance benefits are paid by the company.

Under accounting standards for postretirement benefits (ASC 715), the company recognizes the overfunded or underfunded status of each of its defined benefit pension and OPEB plans as an asset or liability on the Consolidated Balance Sheet.

The funded status of the company’s pension and other postretirement benefit plans for 2011 and 2010 follows:


	Pension Benefits
	2011						2010						Other Benefits
	U.S.			Int’l.			U.S.			Int’l.			2011			2010

Change in Benefit Obligation
Benefit obligation at January 1	$	10,271		$	5,070		$	9,664		$	4,715		$	3,605		$	3,065
Service cost		374			174			337			153			58			39
Interest cost		463			325			486			307			180			175
Plan participants’ contributions		–			6			–			7			148			147
Plan amendments		–			27			–			–			–			12
Actuarial loss (gain)		1,920			318			568			200			149			486
Foreign currency exchange rate changes		–			(98	)		–			(17	)		(19	)		11
Benefits paid		(863	)		(303	)		(784	)		(295	)		(346	)		(330	)
Curtailment		–			–			–			–			(10	)		–

Benefit obligation at December 31		12,165			5,519			10,271			5,070			3,765			3,605

Change in Plan Assets
Fair value of plan assets at January 1		8,579			3,503			7,304			3,235			–			–
Actual return on plan assets		(143	)		118			867			361			–			–
Foreign currency exchange rate changes		–			(66	)		–			(63	)		–			–
Employer contributions		1,147			319			1,192			258			198			183
Plan participants’ contributions		–			6			–			7			148			147
Benefits paid		(863	)		(303	)		(784	)		(295	)		(346	)		(330	)

Fair value of plan assets at December 31		8,720			3,577			8,579			3,503			–			–

Funded Status at December 31	$	(3,445	)	$	(1,942	)	$	(1,692	)	$	(1,567	)	$	(3,765	)	$	(3,605	)

Amounts recognized on the Consolidated Balance Sheet for the company’s pension and other postretirement benefit plans at December 31, 2011 and 2010, include:


	Pension Benefits
	2011						2010						Other Benefits
	U.S.			Int’l.			U.S.			Int’l.			2011			2010

Deferred charges and other assets	$	5		$	116		$	7		$	77		$	–		$	–
Accrued liabilities		(72	)		(84	)		(134	)		(71	)		(222	)		(225	)
Reserves for employee benefit plans		(3,378	)		(1,974	)		(1,565	)		(1,573	)		(3,543	)		(3,380	)

Net amount recognized at December 31	$	(3,445	)	$	(1,942	)	$	(1,692	)	$	(1,567	)	$	(3,765	)	$	(3,605	)

Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and OPEB plans were $9,279 and $6,749 at the end of 2011 and 2010, respectively. These amounts consisted of:


	Pension Benefits
	2011					2010					Other Benefits
	U.S.			Int’l.		U.S.			Int’l.		2011			2010

Net actuarial loss	$	5,982		$	2,250	$	3,919		$	1,903	$	1,002		$	935
Prior service (credit) costs		(44	)		152		(52	)		179		(63	)		(135	)

Total recognized at December 31	$	5,938		$	2,402	$	3,867		$	2,082	$	939		$	800

The accumulated benefit obligations for all U.S. and international pension plans were $11,198 and $4,518, respectively, at December 31, 2011, and $9,535 and $4,161, respectively, at December 31, 2010.

Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at December 31, 2011 and 2010, was:


	Pension Benefits
	2011				2010
	U.S.		Int’l.		U.S.		Int’l.

Projected benefit obligations	$	12,157	$	4,207	$	10,265	$	3,668
Accumulated benefit obligations		11,191		3,586		9,528		3,113
Fair value of plan assets		8,707		2,357		8,566		2,190

The components of net periodic benefit cost and amounts recognized in other comprehensive income for 2011, 2010 and 2009 are shown in the table below:


							Pension Benefits
	2011							2010						2009						Other Benefits
	U.S.			Int’l.				U.S.			Int’l.			U.S.			Int’l.			2011			2010			2009
Net Periodic Benefit Cost
Service cost	$	374		$	174			$	337		$	153		$	266		$	128		$	58		$	39		$	43
Interest cost		463			325				486			307			481			292			180			175			180
Expected return on plan assets		(613	)		(283	)			(538	)		(241	)		(395	)		(203	)		–			–			–
Amortization of prior service (credits) costs		(8	)		19				(8	)		22			(7	)		23			(72	)		(75	)		(81	)
Recognized actuarial losses		310			101				318			98			298			108			64			27			27
Settlement losses		298			–				186			6			141			1			–			–			–
Curtailment losses (gains)		–			35				–			–			–			–			(10	)		–			(5	)

Total net periodic benefit cost		824			371				781			345			784			349			220			166			164

Changes Recognized in Other Comprehensive Income
Net actuarial loss during period		2,671			448				242			118			823			194			131			497			82
Amortization of actuarial loss		(608	)		(101	)			(504	)		(104	)		(439	)		(109	)		(64	)		(27	)		(27	)
Prior service cost during period		–			27				–			–			1			13			–			12			20
Amortization of prior service credits (costs)		8			(54	)			8			(22	)		7			(23	)		72			75			81

Total changes recognized in other comprehensive income		2,071			320				(254	)		(8	)		392			75			139			557			156

Recognized in Net Periodic Benefit Cost and Other Comprehensive Income	$	2,895		$	691			$	527		$	337		$	1,176		$	424		$	359		$	723		$	320

Net actuarial losses recorded in “Accumulated other comprehensive loss” at December 31, 2011, for the company’s U.S. pension, international pension and OPEB plans are being amortized on a straight-line basis over approximately 10, 12 and eight years, respectively. These amortization periods represent the estimated average remaining service of employees expected to receive benefits under the plans. These losses are amortized to the extent they exceed 10 percent of the higher of the projected benefit obligation or market-related value of plan assets. The amount subject to amortization is determined on a plan-by-plan basis. During 2012, the company estimates actuarial losses of $476, $142 and $75 will be amortized from “Accumulated other comprehensive loss” for U.S. pension, international pension and OPEB plans, respectively. In addition, the company estimates an additional $260 will be recognized from “Accumulated other comprehensive loss” during 2012 related to lump-sum settlement costs from U.S. pension plans.

The weighted average amortization period for recognizing prior service costs (credits) recorded in “Accumulated other comprehensive loss” at December 31, 2011, was approximately six and seven years for U.S. and international pension plans, respectively, and two years for other postretirement benefit plans. During 2012, the company estimates prior service (credits) costs of $(8), $21 and $(72) will be amortized from “Accumulated other comprehensive loss” for U.S. pension, international pension and OPEB plans, respectively.

Assumptions The following weighted-average assumptions were used to determine benefit obligations and net periodic benefit costs for years ended December 31:


	Pension Benefits
				2011						2010						2009			Other Benefits
	U.S.			Int’l.			U.S.			Int’l.			U.S.			Int’l.			2011			2010			2009

Assumptions used to determine benefit obligations:
Discount rate		3.8	%		5.9	%		4.8	%		6.5	%		5.3	%		6.8	%		4.2	%		5.2	%		5.9	%
Rate of compensation increase		4.5	%		5.7	%		4.5	%		6.7	%		4.5	%		6.3	%		N/A			N/A			N/A
Assumptions used to determine net periodic benefit cost:
Discount rate		4.8	%		6.5	%		5.3	%		6.8	%		6.3	%		7.5	%		5.2	%		5.9	%		6.3	%
Expected return on plan assets		7.8	%		7.8	%		7.8	%		7.8	%		7.8	%		7.5	%		N/A			N/A			N/A
Rate of compensation increase		4.5	%		6.7	%		4.5	%		6.3	%		4.5	%		6.8	%		N/A			N/A			N/A

Expected Return on Plan Assets The company’s estimated long-term rates of return on pension assets are driven primarily by actual historical asset-class returns, an assessment of expected future performance, advice from external actuarial firms and the incorporation of specific asset-class risk factors. Asset allocations are periodically updated using pension plan asset/liability studies, and the company’s estimated long-term rates of return are consistent with these studies.

There have been no changes in the expected long-term rate of return on plan assets since 2002 for U.S. plans, which account for 70 percent of the company’s pension plan assets. At December 31, 2011, the estimated long-term rate of return on U.S. pension plan assets was 7.8 percent.

The market-related value of assets of the major U.S. pension plan used in the determination of pension expense was based on the market values in the three months preceding the year-end measurement date, as opposed to the maximum allowable period of five years under U.S. accounting rules. Management considers the three-month time period long enough to minimize the effects of distortions from day-to-day market volatility and still be contemporaneous to the end of the year. For other plans, market value of assets as of year-end is used in calculating the pension expense.

Discount Rate The discount rate assumptions used to determine U.S. and international pension and postretirement benefit plan obligations and expense reflect the prevailing rates available on high-quality, fixed-income debt instruments. At December 31, 2011, the company selected a 3.8 percent discount rate for the U.S. pension plans and 4.0 percent for the U.S. postretirement benefit plan. This rate was based on a cash flow analysis that matched estimated future benefit payments to the Citigroup Pension Discount Yield Curve as of year-end 2011. The discount rates at the end of 2010 and 2009 were 4.8 and 5.3 percent and 5.0 and 5.8 percent for the U.S. pension plans and the U.S. OPEB plan, respectively.

Other Benefit Assumptions For the measurement of accumulated postretirement benefit obligation at December 31, 2011, for the main U.S. postretirement medical plan, the assumed health care cost-trend rates start with 8 percent in 2012 and gradually decline to 5 percent for 2023 and beyond. For this measurement at December 31, 2010, the assumed health care cost-trend rates started with 8 percent in 2011 and gradually declined to 5 percent for 2018 and beyond. In both measurements, the annual increase to company contributions was capped at 4 percent.

Assumed health care cost-trend rates can have a significant effect on the amounts reported for retiree health care costs. The impact is mitigated by the 4 percent cap on the company’s medical contributions for the primary U.S. plan. A one-percentage-point change in the assumed health care cost-trend rates would have the following effects:


	1 Percent		1 Percent
	Increase		Decrease

Effect on total service and interest cost components	$	17	$	(15	)
Effect on postretirement benefit obligation	$	177	$	(150	)

Plan Assets and Investment Strategy The fair value hierarchy of inputs the company uses to value the pension assets is divided into three levels:

Level 1: Fair values of these assets are measured using unadjusted quoted prices for the assets or the prices of identical assets in active markets that the plans have the ability to access.

Level 2: Fair values of these assets are measured based on quoted prices for similar assets in active markets; quoted prices for identical or similar assets in inactive markets; inputs other than quoted prices that are observable for the asset; and inputs that are derived principally from or corroborated by observable market data through correlation or other means. If the asset has a contractual term, the Level 2 input is observable for substantially the full term of the asset. The fair values for Level 2 assets are generally obtained from third-party broker quotes, independent pricing services and exchanges.

Level 3: Inputs to the fair value measurement are unobservable for these assets. Valuation may be performed using a financial model with estimated inputs entered into the model.

The fair value measurements of the company’s pension plans for 2011 and 2010 are below:


	U.S.										Int’l.
	Total Fair Value			Level 1			Level 2		Level 3		Total Fair Value		Level 1			Level 2		Level 3

At December 31, 2011
Equities
U.S.¹	$	1,470		$	1,470		$	–	$	–	$	497	$	497		$	–	$	–
International		1,203			1,203			–		–		693		693			–		–
Collective Trusts/Mutual Funds²		2,633			14			2,619		–		596		28			568		–
Fixed Income
Government		622			146			476		–		635		25			610		–
Corporate		338			–			338		–		319		16			276		27
Mortgage-Backed Securities		107			–			107		–		2		–			–		2
Other Asset Backed		61			–			61		–		5		–			5		–
Collective Trusts/Mutual Funds²		1,046			–			1,046		–		345		61			284		–
Mixed Funds³		10			10			–		–		102		13			89		–
Real Estate⁴		843			–			–		843		155		–			–		155
Cash and Cash Equivalents		404			404			–		–		211		211			–		–
Other⁵		(17	)		(79	)		8		54		17		(2	)		17		2

Total at December 31, 2011	$	8,720		$	3,168		$	4,655	$	897	$	3,577	$	1,542		$	1,849	$	186

At December 31, 2010
Equities
U.S.¹	$	2,121		$	2,121		$	–	$	–	$	465	$	465		$	–	$	–
International		1,405			1,405			–		–		721		721			–		–
Collective Trusts/Mutual Funds²		2,068			5			2,063		–		578		80			498		–
Fixed Income
Government		659			19			640		–		568		38			530		–
Corporate		314			–			314		–		351		24			299		28
Mortgage-Backed Securities		82			–			82		–		2		–			–		2
Other Asset Backed		74			–			74		–		16		–			16		–
Collective Trusts/Mutual Funds²		1,064			–			1,064		–		332		19			313		–
Mixed Funds³		9			9			–		–		105		16			89		–
Real Estate⁴		596			–			–		596		142		–			–		142
Cash and Cash Equivalents		213			213			–		–		217		217			–		–
Other⁵		(26	)		(87	)		8		53		6		(5	)		9		2

Total at December 31, 2010	$	8,579		$	3,685		$	4,245	$	649	$	3,503	$	1,575		$	1,754	$	174


¹	U.S. equities include investments in the company’s common stock in the amount of $35 at December 31, 2011, and $38 at December 31, 2010.

²	Collective Trusts/Mutual Funds for U.S. plans are entirely index funds; for International plans, they are mostly index funds. For these index funds, the Level 2 designation is partially based on the restriction that advance notification of redemptions, typically two business days, is required.

³	Mixed funds are composed of funds that invest in both equity and fixed-income instruments in order to diversify and lower risk.

⁴	The year-end valuations of the U.S. real estate assets are based on internal appraisals by the real estate managers, which are updates of third-party appraisals that occur at least once a year for each property in the portfolio.

⁵	The “Other” asset class includes net payables for securities purchased but not yet settled (Level 1); dividends and interest- and tax-related receivables (Level 2); insurance contracts and investments in private-equity limited partnerships (Level 3).

The effects of fair value measurements using significant unobservable inputs on changes in Level 3 plan assets for the period are outlined below:


	Fixed Income
				Mortgage-Backed
	Corporate			Securities		Real Estate		Other			Total

Total at December 31, 2009		$ 18			$ 2		$ 610		$ 52			$ 682
Actual Return on Plan Assets:
Assets held at the reporting date		3			–		34		1			38
Assets sold during the period		–			–		1		–			1
Purchases, Sales and Settlements		7			–		93		2			102
Transfers in and/or out of Level 3		–			–		–		–			–

Total at December 31, 2010		$ 28			$ 2		$ 738		$ 55			$ 823

Actual Return on Plan Assets:
Assets held at the reporting date		–			–		103		4			107
Assets sold during the period		–			–		1		(2	)		(1	)
Purchases, Sales and Settlements		(1	)		–		156		(1	)		154
Transfers in and/or out of Level 3		–			–		–		–			–

Total at December 31, 2011		$ 27			$ 2		$ 998		$ 56			$1,083

The primary investment objectives of the pension plans are to achieve the highest rate of total return within prudent levels of risk and liquidity, to diversify and mitigate potential downside risk associated with the investments, and to provide adequate liquidity for benefit payments and portfolio management.

The company’s U.S. and U.K. pension plans comprise 86 percent of the total pension assets. Both the U.S. and U.K. plans have an Investment Committee that regularly meets during the year to review the asset holdings and their returns. To assess the plans’ investment performance, long-term asset allocation policy benchmarks have been established.

For the primary U.S. pension plan, the Chevron Board of Directors has established the following approved asset allocation ranges: Equities 40–70 percent, Fixed Income and Cash 20–65 percent, Real Estate 0–15 percent, and Other 0–5 percent. For the U.K. pension plan, the U.K. Board of Trustees has established the following asset allocation guidelines, which are reviewed regularly: Equities 60–80 percent and Fixed Income and Cash 20–40 percent. The other significant international pension plans also have established maximum and minimum asset allocation ranges that vary by plan. Actual asset allocation within approved ranges is based on a variety of current economic and market conditions and consideration of specific asset class risk. To mitigate concentration and other risks, assets are invested across multiple asset classes with active investment managers and passive index funds.

The company does not prefund its OPEB obligations.

Cash Contributions and Benefit Payments In 2011, the company contributed $1,147 and $319 to its U.S. and international pension plans, respectively. In 2012, the company expects contributions to be approximately $600 and $300 to its U.S. and international pension plans, respectively. Actual contribution amounts are dependent upon investment returns, changes in pension obligations, regulatory environments and other economic factors. Additional funding may ultimately be required if investment returns are insufficient to offset increases in plan obligations.

The company anticipates paying other postretirement benefits of approximately $223 in 2012, compared with $198 paid in 2011.

The following benefit payments, which include estimated future service, are expected to be paid by the company in the next 10 years:


	Pension Benefits				Other
	U.S.		Int’l.		Benefits

2012	$	1,053	$	268	$	223
2013	$	1,043	$	316	$	229
2014	$	1,046	$	320	$	234
2015	$	1,050	$	344	$	240
2016	$	1,062	$	375	$	245
2017–2021	$	5,261	$	2,153	$	1,287

Employee Savings Investment Plan Eligible employees of Chevron and certain of its subsidiaries participate in the Chevron Employee Savings Investment Plan (ESIP).

Charges to expense for the ESIP represent the company’s contributions to the plan, which are funded either through the purchase of shares of common stock on the open market or through the release of common stock held in the leveraged employee stock ownership plan (LESOP), which is described in the section that follows. Total company matching contributions to employee accounts within the ESIP were $263, $253 and $257 in 2011, 2010 and 2009, respectively. This cost was reduced by the value of shares released from the

LESOP totaling $38, $97 and $184 in 2011, 2010 and 2009, respectively. The remaining amounts, totaling $225, $156 and $73 in 2011, 2010 and 2009, respectively, represent open market purchases.

Employee Stock Ownership Plan Within the Chevron ESIP is an employee stock ownership plan (ESOP). In 1989, Chevron established a LESOP as a constituent part of the ESOP. The LESOP provides partial prefunding of the company’s future commitments to the ESIP.

As permitted by accounting standards for share-based compensation (ASC 718), the debt of the LESOP is recorded as debt, and shares pledged as collateral are reported as “Deferred compensation and benefit plan trust” on the Consolidated Balance Sheet and the Consolidated Statement of Equity.

The company reports compensation expense equal to LESOP debt principal repayments less dividends received and used by the LESOP for debt service. Interest accrued on LESOP debt is recorded as interest expense. Dividends paid on LESOP shares are reflected as a reduction of retained earnings. All LESOP shares are considered outstanding for earnings-per-share computations.

Total credits to expense for the LESOP were $1, $1 and $3 in 2011, 2010 and 2009, respectively. The net credit for the respective years was composed of credits to compensation expense of $5, $6 and $15 and charges to interest expense for LESOP debt of $4, $5 and $12.

Of the dividends paid on the LESOP shares, $18, $46 and $110 were used in 2011, 2010 and 2009, respectively, to service LESOP debt. No contributions were required in 2011, 2010 or 2009, as dividends received by the LESOP were sufficient to satisfy LESOP debt service.

Shares held in the LESOP are released and allocated to the accounts of plan participants based on debt service deemed to be paid in the year in proportion to the total of current-year and remaining debt service. LESOP shares as of December 31, 2011 and 2010, were as follows:


Thousands	2011		2010

Allocated shares		19,047		20,718
Unallocated shares		1,864		2,374

Total LESOP shares		20,911		23,092

Benefit Plan Trusts Prior to its acquisition by Chevron, Texaco established a benefit plan trust for funding obligations under some of its benefit plans. At year-end 2011, the trust contained 14.2 million shares of Chevron treasury stock. The trust will sell the shares or use the dividends from the shares to pay benefits only to the extent that the company does not pay such benefits. The company intends to continue to pay its obligations under the benefit plans. The trustee will vote the shares held in the trust as instructed by the trust’s beneficiaries. The shares held in the trust are not considered outstanding for earnings-per-share purposes until distributed or sold by the trust in payment of benefit obligations.

Prior to its acquisition by Chevron, Unocal established various grantor trusts to fund obligations under some of its benefit plans, including the deferred compensation and supplemental retirement plans. At December 31, 2011 and 2010, trust assets of $51 and $57, respectively, were invested primarily in interest-earning accounts.

Employee Incentive Plans The Chevron Incentive Plan is an annual cash bonus plan for eligible employees that links awards to corporate, unit and individual performance in the prior year. Charges to expense for cash bonuses were $1,217, $766 and $561 in 2011, 2010 and 2009, respectively. Chevron also has the LTIP for officers and other regular salaried employees of the company and its subsidiaries who hold positions of significant responsibility. Awards under the LTIP consist of stock options and other share-based compensation that are described in Note 20, beginning on page FS-48.

The entire disclosure for pension and other postretirement benefits.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Restructuring and Reorganization Costs [Abstract]

Equity	12 Months Ended
Equity	Dec. 31, 2011
Equity [Abstract]
Equity	Note 22 Equity Retained earnings at December 31, 2011 and 2010, included approximately $10,127 and $9,159, respectively, for the company’s share of undistributed earnings of equity affiliates. At December 31, 2011, about 67 million shares of Chevron’s common stock remained available for issuance from the 160 million shares that were reserved for issuance under the Chevron LTIP. In addition, approximately 258,000 shares remain available for issuance from the 800,000 shares of the company’s common stock that were reserved for awards under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan.

Restructuring and Reorganization

12 Months Ended

Dec. 31, 2011

Restructuring and Reorganization

Note 23

Restructuring and Reorganization

In the first quarter 2010, the company announced employee reduction programs related to the restructuring and reorganization of its downstream businesses and corporate staffs. Total terminations under the programs are expected to be approximately 2,700 employees. About 1,300 of the affected employees are located in the United States. About 2,500 employees have been terminated through December 31, 2011, and the programs were substantially completed by the end of 2011. Substantially all of the remaining employees designated for termination under the programs are expected to leave in 2012.

A before-tax charge of $244 was recorded in first quarter 2010 associated with these programs, of which $138 remained outstanding at December 31, 2010. During 2011, the company made payments of $74 associated with these liabilities. The majority of the payments were in Downstream. The balance at December 31, 2011, was classified as a current liability on the Consolidated Balance Sheet.


	Amounts Before Tax

Balance at January 1, 2011	$	138
Adjustments		(28	)
Payments		(74	)

Balance at December 31, 2011	$	36

The entire disclosure for restructuring and related activities. Description of restructuring activities such as exit and disposal activities, include facts and circumstances leading to the plan, the expected plan completion date, the major types of costs associated with the plan activities, total expected costs, the accrual balance at the end of the period, and the periods over which the remaining accrual will be settled.

Other Contingencies and Commitments	12 Months Ended
Other Contingencies and Commitments	Dec. 31, 2011
Other Contingencies and Commitments [Abstract]
Other Contingencies and Commitments	Note 24 Other Contingencies and Commitments Income Taxes The company calculates its income tax expense and liabilities quarterly. These liabilities generally are subject to audit and are not finalized with the individual taxing authorities until several years after the end of the annual period for which income taxes have been calculated. Refer to Note 15, beginning on page FS-43, for a discussion of the periods for which tax returns have been audited for the company’s major tax jurisdictions and a discussion for all tax jurisdictions of the differences between the amount of tax benefits recognized in the financial statements and the amount taken or expected to be taken in a tax return. The company does not expect settlement of income tax liabilities associated with uncertain tax positions to have a material effect on its results of operations, consolidated financial position or liquidity. Guarantees The company’s guarantee of approximately $600 is associated with certain payments under a terminal use agreement entered into by a company affiliate. The terminal commenced operations in third quarter 2011. Over the approximate 16-year term of the guarantee, the maximum guarantee amount will be reduced over time as certain fees are paid by the affiliate. There are numerous cross-indemnity agreements with the affiliate and the other partners to permit recovery of amounts paid under the guarantee. Chevron has recorded no liability for its obligation under this guarantee. Indemnifications The company provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell and Saudi Refining, Inc., in connection with the February 2002 sale of the company’s interests in those investments. Through the end of 2011, the company paid $48 under these indemnities and continues to be obligated up to $250 for possible additional indemnification payments in the future. The company has also provided indemnities relating to contingent environmental liabilities of assets originally contributed by Texaco to the Equilon and Motiva joint ventures and environmental conditions that existed prior to the formation of Equilon and Motiva, or that occurred during the period of Texaco’s ownership interest in the joint ventures. In general, the environmental conditions or events that are subject to these indemnities must have arisen prior to December 2001. Claims had to be asserted by February 2009 for Equilon indemnities and must be asserted no later than February 2012 for Motiva indemnities. In February 2012, Motiva Enterprises LLC delivered a letter to the company purporting to preserve unmatured claims for certain Motiva indemnities. The letter itself provides no estimate of the ultimate claim amount. Management does not believe this letter or any other information provides a basis to estimate the amount, if any, of a range of loss or potential range of loss with respect to either the Equilon or the Motiva indemnities. Under the terms of these indemnities, there is no maximum limit on the amount of potential future payments. The company posts no assets as collateral and has made no payments under the indemnities. The amounts payable for the indemnities described in the preceding paragraph are to be net of amounts recovered from insurance carriers and others and net of liabilities recorded by Equilon or Motiva prior to September 30, 2001, for any applicable incident. In the acquisition of Unocal, the company assumed certain indemnities relating to contingent environmental liabilities associated with assets that were sold in 1997. The acquirer of those assets shared in certain environmental remediation costs up to a maximum obligation of $200, which had been reached at December 31, 2009. Under the indemnification agreement, after reaching the $200 obligation, Chevron is solely responsible until April 2022, when the indemnification expires. The environmental conditions or events that are subject to these indemnities must have arisen prior to the sale of the assets in 1997. Although the company has provided for known obligations under this indemnity that are probable and reasonably estimable, the amount of additional future costs may be material to results of operations in the period in which they are recognized. The company does not expect these costs will have a material effect on its consolidated financial position or liquidity. Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements The company and its subsidiaries have certain other contingent liabilities with respect to long-term unconditional purchase obligations and commitments, including throughput and take-or-pay agreements, some of which relate to suppliers’ financing arrangements. The agreements typically provide goods and services, such as pipeline and storage capacity, drilling rigs, utilities, and petroleum products, to be used or sold in the ordinary course of the company’s business. The aggregate approximate amounts of required payments under these various commitments are: 2012 – $6,000; 2013 – $4,000; 2014 – $3,900; 2015 – $3,200; 2016 – $1,900; 2017 and after – $7,400. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were approximately $6,600 in 2011, $6,500 in 2010 and $8,100 in 2009. Environmental The company is subject to loss contingencies pursuant to laws, regulations, private claims and legal proceedings related to environmental matters that are subject to legal settlements or that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemicals or petroleum substances, including MTBE, by the company or other parties. Such contingencies may exist for various sites, including, but not limited to, federal Superfund sites and analogous sites under state laws, refineries, crude oil fields, service stations, terminals, land development areas, and mining operations, whether operating, closed or divested. These future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties. Although the company has provided for known environmental obligations that are probable and reasonably estimable, the amount of additional future costs may be material to results of operations in the period in which they are recognized. The company does not expect these costs will have a material effect on its consolidated financial position or liquidity. Also, the company does not believe its obligations to make such expenditures have had, or will have, any significant impact on the company’s competitive position relative to other U.S. or international petroleum or chemical companies. Chevron’s environmental reserve as of December 31, 2011, was $1,404. Included in this balance were remediation activities at approximately 180 sites for which the company had been identified as a potentially responsible party or otherwise involved in the remediation by the U.S. Environmental Protection Agency (EPA) or other regulatory agencies under the provisions of the federal Superfund law or analogous state laws. The company’s remediation reserve for these sites at year-end 2011 was $185. The federal Superfund law and analogous state laws provide for joint and several liability for all responsible parties. Any future actions by the EPA or other regulatory agencies to require Chevron to assume other potentially responsible parties’ costs at designated hazardous waste sites are not expected to have a material effect on the company’s results of operations, consolidated financial position or liquidity. Of the remaining year-end 2011 environmental reserves balance of $1,219, $675 related to the company’s U.S. downstream operations, including refineries and other plants, marketing locations (i.e., service stations and terminals), chemical facilities, and pipelines. The remaining $544 was associated with various sites in international downstream ($95), upstream ($368) and other businesses ($81). Liabilities at all sites, whether operating, closed or divested, were primarily associated with the company’s plans and activities to remediate soil or groundwater contamination or both. These and other activities include one or more of the following: site assessment; soil excavation; offsite disposal of contaminants; onsite containment, remediation and/or extraction of petroleum hydrocarbon liquid and vapor from soil; groundwater extraction and treatment; and monitoring of the natural attenuation of the contaminants. The company manages environmental liabilities under specific sets of regulatory requirements, which in the United States include the Resource Conservation and Recovery Act and various state and local regulations. No single remediation site at year-end 2011 had a recorded liability that was material to the company’s results of operations, consolidated financial position or liquidity. It is likely that the company will continue to incur additional liabilities, beyond those recorded, for environmental remediation relating to past operations. These future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties. Refer to Note 25 on page FS-58 for a discussion of the company’s asset retirement obligations. Other Contingencies On April 26, 2010, a California appeals court issued a ruling related to the adequacy of an Environmental Impact Report (EIR) supporting the issuance of certain permits by the city of Richmond, California, to replace and upgrade certain facilities at Chevron’s refinery in Richmond. Settlement discussions with plaintiffs in the case ended late fourth quarter 2010, and on March 3, 2011, the trial court entered a final judgment and peremptory writ ordering the City to set aside the project EIR and conditional use permits and enjoining Chevron from any further work. On May 23, 2011, the company filed an application with the City Planning Department for a conditional use permit for a revised project to complete construction of the hydrogen plant, certain sulfur removal facilities and related infrastructure. On June 10, 2011, the City published its Notice of Preparation of the revised EIR for the project. The revised and recirculated EIR is intended to comply with the appeals court decision. Management believes the outcomes associated with the project are uncertain. Due to the uncertainty of the company’s future course of action, or potential outcomes of any action or combination of actions, management does not believe an estimate of the financial effects, if any, can be made at this time. However, the company’s ultimate exposure may be significant to net income in any one future period. Chevron receives claims from and submits claims to customers; trading partners; U.S. federal, state and local regulatory bodies; governments; contractors; insurers; and suppliers. The amounts of these claims, individually and in the aggregate, may be significant and take lengthy periods to resolve. The company and its affiliates also continue to review and analyze their operations and may close, abandon, sell, exchange, acquire or restructure assets to achieve operational or strategic benefits and to improve competitiveness and profitability. These activities, individually or together, may result in gains or losses in future periods.

The entire disclosure for commitments and contingencies.

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

Asset Retirement Obligations [Abstract]

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligations

Note 25

Asset Retirement Obligations

The company records the fair value of a liability for an asset retirement obligation (ARO) as an asset and liability when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. The legal obligation to perform the asset retirement activity is unconditional, even though uncertainty may exist about the timing and/or method of settlement that may be beyond the company’s control. This uncertainty about the timing and/or method of settlement is factored into the measurement of the liability when sufficient information exists to reasonably estimate fair value. Recognition of the ARO includes: (1) the present value of a liability and offsetting asset, (2) the subsequent accretion of that liability and depreciation of the asset, and (3) the periodic review of the ARO liability estimates and discount rates.

AROs are primarily recorded for the company’s crude oil and natural gas producing assets. No significant AROs associated with any legal obligations to retire downstream long-lived assets have been recognized, as indeterminate settlement dates for the asset retirements prevent estimation of the fair value of the associated ARO. The company performs periodic reviews of its downstream long-lived assets for any changes in facts and circumstances that might require recognition of a retirement obligation.

The following table indicates the changes to the company’s before-tax asset retirement obligations in 2011, 2010 and 2009:


	2011			2010			2009

Balance at January 1	$	12,488		$	10,175		$	9,395
Liabilities incurred		62			129			144
Liabilities settled		(1,316	)		(755	)		(757	)
Accretion expense		628			513			463
Revisions in estimated cash flows		905			2,426			930

Balance at December 31	$	12,767		$	12,488		$	10,175

The long-term portion of the $12,767 balance at the end of 2011 was $11,999.

Other Financial Information

12 Months Ended

Dec. 31, 2011

Other Financial Information [Abstract]

Other Financial Information

Note 26

Other Financial Information

Earnings in 2011 included gains of approximately $1,300 relating to the sale of nonstrategic properties. Of this amount, approximately $800 and $500 related to downstream and upstream assets, respectively. Earnings in 2010 included gains of approximately $700 relating to the sale of nonstrategic properties. Of this amount, approximately $400 and $300 related to downstream and upstream assets, respectively. The revenues and earnings contributions of these assets were not material to periods presented.

Other financial information is as follows:


	Year ended December 31
	2011		2010			2009

Total financing interest and debt costs	$	288	$	317		$	301
Less: Capitalized interest		288		267			273

Interest and debt expense	$	–	$	50		$	28

Research and development expenses	$	627	$	526		$	603
Foreign currency effects*	$	121	$	(423	)	$	(744	)


^*	Includes $(27), $(71) and $(194) in 2011, 2010 and 2009, respectively, for the company’s share of equity affiliates’ foreign currency effects.

The excess of replacement cost over the carrying value of inventories for which the last-in, first-out (LIFO) method is used was $9,025 and $6,975 at December 31, 2011 and 2010, respectively. Replacement cost is generally based on average acquisition costs for the year. LIFO profits (charges) of $193, $21 and $(168) were included in earnings for the years 2011, 2010 and 2009, respectively.

The company has $4,642 in goodwill on the Consolidated Balance Sheet related to the 2005 acquisition of Unocal and to the 2011 acquisition of Atlas Energy, Inc. Under the accounting standard for goodwill (ASC 350), the company tested this goodwill for impairment during 2011 and concluded no impairment was necessary.

Earnings Per Share

12 Months Ended

Dec. 31, 2011

Earnings Per Share [Abstract]

Earnings Per Share

Note 27

Earnings Per Share

Basic earnings per share (EPS) is based upon “Net Income Attributable to Chevron Corporation” (“earnings”) and includes the effects of deferrals of salary and other compensation awards that are invested in Chevron stock units by certain officers and employees of the company. Diluted EPS includes the effects of these items as well as the dilutive effects of outstanding stock options awarded under the company’s stock option programs (refer to Note 20, “Stock Options and Other Share-Based Compensation,” beginning on page FS-48). The table below sets forth the computation of basic and diluted EPS:


	Year ended December 31
	2011		2010		2009

Basic EPS Calculation

Earnings available to common stockholders – Basic*	$	26,895	$	19,024	$	10,483

Weighted-average number of common shares outstanding		1,986		1,996		1,991
Add: Deferred awards held as stock units		–		1		1

Total weighted-average number of common shares outstanding		1,986		1,997		1,992

Earnings per share of common stock – Basic	$	13.54	$	9.53	$	5.26

Diluted EPS Calculation

Earnings available to common stockholders – Diluted*	$	26,895	$	19,024	$	10,483

Weighted-average number of common shares outstanding		1,986		1,996		1,991
Add: Deferred awards held as stock units		–		1		1
Add: Dilutive effect of employee stock-based awards		15		10		9

Total weighted-average number of common shares outstanding		2,001		2,007		2,001

Earnings per share of common stock – Diluted	$	13.44	$	9.48	$	5.24

*	There was no effect of dividend equivalents paid on stock units or dilutive impact of employee stock-based awards on earnings.

Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2011

Valuation and Qualifying Accounts [Abstract]

Valuation And Qualifying Accounts

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
Millions of Dollars


	Year Ended December 31
	2011			2010			2009

Employee Termination Benefits:
Balance at January 1	$	145		$	13		$	44
Additions (deductions) charged (credited) to expense		—			235			(12	)
Payments		(82	)		(103	)		(19	)

Balance at December 31	$	63		$	145		$	13

Allowance for Doubtful Accounts:
Balance at January 1	$	239		$	293		$	275
Additions (reductions) to expense		4			(13	)		92
Bad debt write-offs		(76	)		(41	)		(74	)

Balance at December 31	$	167		$	239		$	293

Deferred Income Tax Valuation Allowance:*
Balance at January 1	$	9,185		$	7,921		$	7,535
Additions to deferred income tax expense		2,216			1,454			2,204
Reduction of deferred income tax expense		(305	)		(190	)		(1,818	)

Balance at December 31	$	11,096		$	9,185		$	7,921


*	See also Note 15 to the Consolidated Financial Statements, beginning on page FS-43.

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2011
Summary of Significant Accounting Policies [Abstract]
General	General Upstream operations consist primarily of exploring for, developing and producing crude oil and natural gas; liquefaction, transportation and regasification associated with liquefied natural gas (LNG); transporting crude oil by major international oil export pipelines; processing, transporting, storage and marketing of natural gas; and a gas-to-liquids project. Downstream operations relate primarily to refining crude oil into petroleum products; marketing of crude oil and refined products; transporting crude oil and refined products by pipeline, marine vessel, motor equipment and rail car; and manufacturing and marketing of commodity petrochemicals, plastics for industrial uses, and additives for fuels and lubricant oils. The company’s Consolidated Financial Statements are prepared in accordance with accounting principles generally accepted in the United States of America. These require the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. Although the company uses its best estimates and judgments, actual results could differ from these estimates as future confirming events occur.
Subsidiary and Affiliated Companies	Subsidiary and Affiliated Companies The Consolidated Financial Statements include the accounts of controlled subsidiary companies more than 50 percent-owned and any variable-interest entities in which the company is the primary beneficiary. Undivided interests in oil and gas joint ventures and certain other assets are consolidated on a proportionate basis. Investments in and advances to affiliates in which the company has a substantial ownership interest of approximately 20 percent to 50 percent, or for which the company exercises significant influence but not control over policy decisions, are accounted for by the equity method. As part of that accounting, the company recognizes gains and losses that arise from the issuance of stock by an affiliate that results in changes in the company’s proportionate share of the dollar amount of the affiliate’s equity currently in income. Investments are assessed for possible impairment when events indicate that the fair value of the investment may be below the company’s carrying value. When such a condition is deemed to be other than temporary, the carrying value of the investment is written down to its fair value, and the amount of the write-down is included in net income. In making the determination as to whether a decline is other than temporary, the company considers such factors as the duration and extent of the decline, the investee’s financial performance, and the company’s ability and intention to retain its investment for a period that will be sufficient to allow for any anticipated recovery in the investment’s market value. The new cost basis of investments in these equity investees is not changed for subsequent recoveries in fair value. Differences between the company’s carrying value of an equity investment and its underlying equity in the net assets of the affiliate are assigned to the extent practicable to specific assets and liabilities based on the company’s analysis of the various factors giving rise to the difference. When appropriate, the company’s share of the affiliate’s reported earnings is adjusted quarterly to reflect the difference between these allocated values and the affiliate’s historical book values.
Derivatives	Derivatives The majority of the company’s activity in derivative commodity instruments is intended to manage the financial risk posed by physical transactions. For some of this derivative activity, generally limited to large, discrete or infrequently occurring transactions, the company may elect to apply fair value or cash flow hedge accounting. For other similar derivative instruments, generally because of the short-term nature of the contracts or their limited use, the company does not apply hedge accounting, and changes in the fair value of those contracts are reflected in current income. For the company’s commodity trading activity, gains and losses from derivative instruments are reported in current income. The company may enter into interest rate swaps from time to time as part of its overall strategy to manage the interest rate risk on its debt. Interest rate swaps related to a portion of the company’s fixed-rate debt, if any, may be accounted for as fair value hedges. Interest rate swaps related to floating-rate debt, if any, are recorded at fair value on the balance sheet with resulting gains and losses reflected in income. Where Chevron is a party to master netting arrangements, fair value receivable and payable amounts recognized for derivative instruments executed with the same counterparty are generally offset on the balance sheet.
Short-Term Investments	Short-Term Investments All short-term investments are classified as available for sale and are in highly liquid debt securities. Those investments that are part of the company’s cash management portfolio and have original maturities of three months or less are reported as “Cash equivalents.” Bank time deposits with maturities greater than 90 days are reported as “Time deposits.” The balance of short-term investments is reported as “Marketable securities” and is marked-to-market, with any unrealized gains or losses included in “Other comprehensive income.”
Inventories	Inventories Crude oil, petroleum products and chemicals inventories are generally stated at cost, using a last-in, first-out method. In the aggregate, these costs are below market. “Materials, supplies and other” inventories generally are stated at average cost.
Properties, Plant and Equipment	Properties, Plant and Equipment The successful efforts method is used for crude oil and natural gas exploration and production activities. All costs for development wells, related plant and equipment, proved mineral interests in crude oil and natural gas properties, and related asset retirement obligation (ARO) assets are capitalized. Costs of exploratory wells are capitalized pending determination of whether the wells found proved reserves. Costs of wells that are assigned proved reserves remain capitalized. Costs also are capitalized for exploratory wells that have found crude oil and natural gas reserves even if the reserves cannot be classified as proved when the drilling is completed, provided the exploratory well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. All other exploratory wells and costs are expensed. Refer to Note 19, beginning on page FS-47, for additional discussion of accounting for suspended exploratory well costs. Long-lived assets to be held and used, including proved crude oil and natural gas properties, are assessed for possible impairment by comparing their carrying values with their associated undiscounted, future net before-tax cash flows. Events that can trigger assessments for possible impairments include write-downs of proved reserves based on field performance, significant decreases in the market value of an asset, significant change in the extent or manner of use of or a physical change in an asset, and a more-likely-than-not expectation that a long-lived asset or asset group will be sold or otherwise disposed of significantly sooner than the end of its previously estimated useful life. Impaired assets are written down to their estimated fair values, generally their discounted future net before-tax cash flows. For proved crude oil and natural gas properties in the United States, the company generally performs the impairment review on an individual field basis. Outside the United States, reviews are performed on a country, concession, development area or field basis, as appropriate. In Downstream, impairment reviews are performed on the basis of a refinery, a plant, a marketing/lubricants area or distribution area, as appropriate. Impairment amounts are recorded as incremental “Depreciation, depletion and amortization” expense. Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the asset is considered impaired and adjusted to the lower value. Refer to Note 9, beginning on page FS-34, relating to fair value measurements. The fair value of a liability for an ARO is recorded as an asset and a liability when there is a legal obligation associated with the retirement of a long-lived asset and the amount can be reasonably estimated. Refer also to Note 25, on page FS-58, relating to AROs. Depreciation and depletion of all capitalized costs of proved crude oil and natural gas producing properties, except mineral interests, are expensed using the unit-of-production method, generally by individual field, as the proved developed reserves are produced. Depletion expenses for capitalized costs of proved mineral interests are recognized using the unit-of-production method by individual field as the related proved reserves are produced. Periodic valuation provisions for impairment of capitalized costs of unproved mineral interests are expensed. The capitalized costs of all other plant and equipment are depreciated or amortized over their estimated useful lives. In general, the declining-balance method is used to depreciate plant and equipment in the United States; the straight-line method is generally used to depreciate international plant and equipment and to amortize all capitalized leased assets. Gains or losses are not recognized for normal retirements of properties, plant and equipment subject to composite group amortization or depreciation. Gains or losses from abnormal retirements are recorded as expenses, and from sales as “Other income.” Expenditures for maintenance (including those for planned major maintenance projects), repairs and minor renewals to maintain facilities in operating condition are generally expensed as incurred. Major replacements and renewals are capitalized.
ASC 350 and its impact	Goodwill Goodwill resulting from a business combination is not subject to amortization. As required by accounting standards for goodwill (ASC 350), the company tests such goodwill at the reporting unit level for impairment on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting unit below its carrying amount.
Environmental Expenditures	Environmental Expenditures Environmental expenditures that relate to ongoing operations or to conditions caused by past operations are expensed. Expenditures that create future benefits or contribute to future revenue generation are capitalized. Liabilities related to future remediation costs are recorded when environmental assessments or cleanups or both are probable and the costs can be reasonably estimated. For the company’s U.S. and Canadian marketing facilities, the accrual is based in part on the probability that a future remediation commitment will be required. For crude oil, natural gas and mineral-producing properties, a liability for an ARO is made in accordance with accounting standards for asset retirement and environmental obligations. Refer to Note 25, on page FS-58, for a discussion of the company’s AROs. For federal Superfund sites and analogous sites under state laws, the company records a liability for its designated share of the probable and estimable costs and probable amounts for other potentially responsible parties when mandated by the regulatory agencies because the other parties are not able to pay their respective shares. The gross amount of environmental liabilities is based on the company’s best estimate of future costs using currently available technology and applying current regulations and the company’s own internal environmental policies. Future amounts are not discounted. Recoveries or reimbursements are recorded as assets when receipt is reasonably assured.
Currency Translation	Currency Translation The U.S. dollar is the functional currency for substantially all of the company’s consolidated operations and those of its equity affiliates. For those operations, all gains and losses from currency remeasurement are included in current period income. The cumulative translation effects for those few entities, both consolidated and affiliated, using functional currencies other than the U.S. dollar are included in “Currency translation adjustment” on the Consolidated Statement of Equity.
Revenue Recognition	Revenue Recognition Revenues associated with sales of crude oil, natural gas, coal, petroleum and chemicals products, and all other sources are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable. Revenues from natural gas production from properties in which Chevron has an interest with other producers are generally recognized on the entitlement method. Excise, value-added and similar taxes assessed by a governmental authority on a revenue-producing transaction between a seller and a customer are presented on a gross basis. The associated amounts are shown as a footnote to the Consolidated Statement of Income, on page FS-23. Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another (including buy/sell arrangements) are combined and recorded on a net basis and reported in “Purchased crude oil and products” on the Consolidated Statement of Income.
Accounting standard for share-based compensation (ASC 718)	Stock Options and Other Share-Based Compensation The company issues stock options and other share-based compensation to its employees and accounts for these transactions under the accounting standards for share-based compensation (ASC 718). For equity awards, such as stock options, total compensation cost is based on the grant date fair value, and for liability awards, such as stock appreciation rights, total compensation cost is based on the settlement value. The company recognizes stock-based compensation expense for all awards over the service period required to earn the award, which is the shorter of the vesting period or the time period an employee becomes eligible to retain the award at retirement. Stock options and stock appreciation rights granted under the company’s Long-Term Incentive Plan have graded vesting provisions by which one-third of each award vests on the first, second and third anniversaries of the date of grant. The company amortizes these graded awards on a straight-line basis.
Acquisition accounted as business combination (ASC 805)	The acquisition was accounted for as a business combination (ASC 805) which, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. Provisional fair value measurements were made in first quarter 2011 for acquired assets and assumed liabilities, and the measurement process was finalized in fourth quarter 2011.
Consolidation (ASC 810)	The company adopted the accounting standard for noncontrolling interests (ASC 810) in the consolidated financial statements effective January 1, 2009, and retroactive to the earliest period presented. Ownership interests in the company’s subsidiaries held by parties other than the parent are presented separately from the parent’s equity on the Consolidated Balance Sheet. The amount of consolidated net income attributable to the parent and the noncontrolling interests are both presented on the face of the Consolidated Statement of Income. The term “earnings” is defined as “Net Income Attributable to Chevron Corporation.”
Accounting Standards for Fair Value Measurement (ASC 820)	Accounting standards for fair value measurement (ASC 820) establish a framework for measuring fair value and stipulate disclosures about fair value measurements. The standards apply to recurring and nonrecurring fair value measurements of financial and nonfinancial assets and liabilities. Among the required disclosures is the fair value hierarchy of inputs the company uses to value an asset or a liability. The three levels of the fair value hierarchy are described as follows: Level 1: Quoted prices (unadjusted) in active markets for identical assets and liabilities. For the company, Level 1 inputs include exchange-traded futures contracts for which the parties are willing to transact at the exchange-quoted price and marketable securities that are actively traded. Level 2: Inputs other than Level 1 that are observable, either directly or indirectly. For the company, Level 2 inputs include quoted prices for similar assets or liabilities, prices obtained through third-party broker quotes and prices that can be corroborated with other observable inputs for substantially the complete term of a contract. Level 3: Unobservable inputs. The company does not use Level 3 inputs for any of its recurring fair value measurements. Level 3 inputs may be required for the determination of fair value associated with certain nonrecurring measurements of nonfinancial assets and liabilities. The table below shows the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis at December 31, 2011 and December 31, 2010.
ASC 280 and its Impact	Although each subsidiary of Chevron is responsible for its own affairs, Chevron Corporation manages its investments in these subsidiaries and their affiliates. The investments are grouped into two business segments, Upstream and Downstream, representing the company’s “reportable segments” and “operating segments” as defined in accounting standards for segment reporting (ASC 280). Upstream operations consist primarily of exploring for, developing and producing crude oil and natural gas; liquefaction, transportation and regasification associated with liquefied natural gas (LNG); transporting crude oil by major international oil export pipelines; processing, transporting, storage and marketing of natural gas; and a gas-to-liquids project. Downstream operations consist primarily of refining of crude oil into petroleum products; marketing of crude oil and refined products; transporting of crude oil and refined products by pipeline, marine vessel, motor equipment and rail car; and manufacturing and marketing of commodity petrochemicals, plastics for industrial uses, and fuel and lubricant additives. All Other activities of the company include mining operations, power generation businesses, worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, energy services, alternative fuels and technology.
ASC 740-10 and its impact	Uncertain Income Tax Positions Under accounting standards for uncertainty in income taxes (ASC 740-10), a company recognizes a tax benefit in the financial statements for an uncertain tax position only if management’s assessment is that the position is “more likely than not” (i.e., a likelihood greater than 50 percent) to be allowed by the tax jurisdiction based solely on the technical merits of the position. The term “tax position” in the accounting standards for income taxes refers to a position in a previously filed tax return or a position expected to be taken in a future tax return that is reflected in measuring current or deferred income tax assets and liabilities for interim or annual periods.
Accounting Standards for the costs of exploratory wells (ASC 932)	Accounting standards for the costs of exploratory wells (ASC 932) provide that exploratory well costs continue to be capitalized after the completion of drilling when (a) the well has found a sufficient quantity of reserves to justify completion as a producing well and (b) the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met or if an enterprise obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well would be assumed to be impaired, and its costs, net of any salvage value, would be charged to expense. (Note that an entity is not required to complete the exploratory well as a producing well.) The accounting standards provide a number of indicators that can assist an entity in demonstrating that sufficient progress is being made in assessing the reserves and economic viability of the project. The following table indicates the changes to the company’s suspended exploratory well costs for the three years ended December 31, 2011:
Comprehensive Income (Topic 220)	Comprehensive Income (Topic 220) Presentation of Comprehensive Income (ASU 2011-05) The FASB issued ASU 2011-05 in June 2011. This standard becomes effective for the company on January 1, 2012. ASU 2011-05 changes the presentation requirements for comprehensive income. Adoption of the standard is not expected to have a significant impact on the company’s current financial statement presentation.

Acquisition of Atlas Energy Inc. (Tables)

12 Months Ended

Dec. 31, 2011

Acquisition of Atlas Energy, Inc. [Abstract]

Final measurement of Atlas' assets acquired and liabilities assumed


Millions of Dollars	At February 17, 2011

Current assets	$	155
Investments and long-term receivables		456
Properties		6,051
Goodwill		27
Other assets		5

Total assets acquired		6,694

Current liabilities		(560	)
Long-term debt and capital leases		(761	)
Deferred income taxes		(1,915	)
Other liabilities		(25	)

Total liabilities assumed		(3,261	)

Net assets acquired	$	3,433

Noncontrolling Interests (Tables)

12 Months Ended

Dec. 31, 2011

Noncontrolling Interests [Abstract]

Activity for equity attributable to noncontrolling interests


	2011			2010			2009

Balance at January 1	$	730		$	647		$	469
Net income		113			112			80
Distributions to noncontrolling interests		(71	)		(72	)		(71	)
Other changes, net		27			43			169

Balance at December 31	$	799		$	730		$	647

Information Relating to the Consolidated Statement of Cash Flows (Tables)

12 Months Ended

Dec. 31, 2011

Information Relating to the Consolidated Statement of Cash Flows [Abstract]

Net decrease (increase) in operating working capital


	Year ended December 31
	2011			2010			2009

Net decrease (increase) in operating working capital was composed of the following:
Increase in accounts and notes receivable	$	(2,156	)	$	(2,767	)	$	(1,476	)
(Increase) decrease in inventories		(404	)		15			1,213
Increase in prepaid expenses and other current assets		(853	)		(542	)		(264	)
Increase (decrease) in accounts payable and accrued liabilities		3,839			3,049			(1,121	)
Increase (decrease) in income and other taxes payable		1,892			321			(653	)

Net decrease (increase) in operating working capital	$	2,318		$	76		$	(2,301	)

Net cash provided by operating activities

Net cash provided by operating activities includes the following cash payments for interest and income taxes:
Interest paid on debt (net of capitalized interest)	$	–	$	34	$	–
Income taxes	$	17,374	$	11,749	$	7,537

Net sales of marketable securities

Net sales of marketable securities consisted of the following gross amounts:
Marketable securities purchased	$	(112	)	$	(90	)	$	(30	)
Marketable securities sold		38			41			157

Net (purchases) sales of marketable securities	$	(74	)	$	(49	)	$	127

Net purchases of time deposits

Net purchases of time deposits consisted of the following gross amounts:
Time deposits purchased	$	(6,439	)	$	(5,060	)	$	–
Time deposits matured		5,335			2,205			–

Net purchases of time deposits	$	(1,104	)	$	(2,855	)	$	–

Capital expenditures


	Year ended December 31
	2011			2010			2009

Additions to properties, plant and equipment¹	$	25,440		$	18,474		$	16,107
Additions to investments		900			861			942
Current year dry hole expenditures		332			414			468
Payments for other liabilities and assets, net²		(172	)		(137	)		2,326

Capital expenditures		26,500			19,612			19,843
Expensed exploration expenditures		839			651			790
Assets acquired through capital lease obligations and other financing obligations		32			104			19

Capital and exploratory expenditures, excluding equity affiliates		27,371			20,367			20,652
Company’s share of expenditures by equity affiliates		1,695			1,388			1,585

Capital and exploratory expenditures, including equity affiliates	$	29,066		$	21,755		$	22,237


¹ Excludes noncash additions of $945 in 2011, $2,753 in 2010 and $985 in 2009.

² 2009 includes payments of $2,450 for accruals recorded in 2008.

Summarized Financial Data - Chevron U.S.A. Inc. (Tables)

12 Months Ended

Dec. 31, 2011

Summarized Financial Data of Subsidiary One [Abstract]

Summarized Financial Data - Chevron U.S.A. Inc.


	Year ended December 31
	2011		2010		2009

Sales and other operating revenues	$	187,917	$	145,381	$	121,553
Total costs and other deductions		178,498		139,984		120,053
Net income attributable to CUSA		6,899		4,159		1,141

Summarized Financial Data and its Subsidiary


	At December 31
	2011		2010

Current assets	$	34,478	$	29,211
Other assets		47,556		35,294
Current liabilities		19,082		18,098
Other liabilities		26,153		16,785

Total CUSA net equity		36,799		29,622


Memo: Total debt	$	14,763	$	8,284

Summarized Financial Data - Chevron Transport Corporation (Tables)

12 Months Ended

Dec. 31, 2011

Summarized Financial Data of Subsidiary Two [Abstract]

Summarized Financial Data - Chevron Transport Corporation


	Year ended December 31
	2011			2010			2009

Sales and other operating revenues	$	793		$	885		$	683
Total costs and other deductions		974			1,008			810
Net loss attributable to CTC		(177	)		(116	)		(124	)

Summarized Financial Data and its Subsidiary


	At December 31
	2011		2010*

Current assets	$	290	$	309
Other assets		228		201
Current liabilities		114		101
Other liabilities		346		175

Total CTC net equity		58		234


*		2010 current assets and other liabilities conformed with 2011 presentation.

Summarized Financial Data - Tengizchevroil LLP (Tables)

12 Months Ended

Dec. 31, 2011

Summarized Financial Data of Affiliate [Abstract]

Summarized Financial Data - Tengizchevroil LLP


	Year ended December 31
	2011		2010		2009

Sales and other operating revenues	$	25,278	$	17,812	$	12,013
Costs and other deductions		10,941		8,394		6,044
Net income attributable to TCO		10,039		6,593		4,178

Summarized Financial Data and its Affiliate


	At December 31
	2011		2010

Current assets	$	3,477	$	3,376
Other assets		11,619		11,813
Current liabilities		2,995		2,402
Other liabilities		3,759		4,130

Total TCO net equity		8,342		8,657

Lease Commitments (Tables)

12 Months Ended

Dec. 31, 2011

Leases [Abstract]

Schedule of capitalized leased assets


	At December 31
	2011		2010

Upstream	$	585	$	561
Downstream		316		316
All Other		–		169

Total		901		1,046
Less: Accumulated amortization		568		573

Net capitalized leased assets	$	333	$	473

Rental expenses incurred for operating leases


	Year ended December 31
	2011		2010*		2009*

Minimum rentals	$	892	$	931	$	933
Contingent rentals		11		10		7

Total		903		941		940
Less: Sublease rental income		39		41		41

Net rental expense	$	864	$	900	$	899


*		Prior years have been adjusted to exclude cost of certain charters from rental expenses.

Estimated future minimum lease payments (net of noncancelable sublease rentals) under operating and capital leases


	At December 31
	Operating		Capital
	Leases		Leases

Year: 2012		693		70
2013		632		47
2014		523		32
2015		475		21
2016		393		13
Thereafter		793		68

Total	$	3,509	$	251

Less: Amounts representing interest and executory costs				(55	)

Net present values				196
Less: Capital lease obligations included in short-term debt				(68	)

Long-term capital lease obligations			$	128

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2011

Fair Value Measurements [Abstract]

Assets and Liabilities Measured at Fair Value on a Recurring Basis


	At December 31, 2011								At December 31, 2010
	Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3

Marketable securities		249		249		–		–		155		155		–		–
Derivatives		208		104		104		–		122		11		111		–

Total Assets at Fair Value	$	457	$	353	$	104	$	–	$	277	$	166	$	111	$	–
Derivatives		102		101		1		–		171		75		96		–

Total Liabilities at Fair Value	$	102	$	101	$	1	$	–	$	171	$	75	$	96	$	–

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis


	At December 31										At December 31
									Before-Tax										Before-Tax
									Loss										Loss
	Total		Level 1		Level 2		Level 3		Year 2011		Total		Level 1		Level 2		Level 3		Year 2010

Properties, plant and equipment, net (held and used)	$	67	$	–	$	–	$	67	$	81	$	57	$	–	$	–	$	57	$	85
Properties, plant and equipment, net (held for sale)		167		–		167		–		54		13		–		–		13		36
Investments and advances		–		–		–		–		108		–		–		–		–		15

Total Nonrecurring Assets at Fair Value	$	234	$	–	$	167	$	67	$	243	$	70	$	–	$	–	$	70	$	136

Financial and Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2011

Financial and Derivative Instruments [Abstract]

Consolidated Balance Sheet: Fair Value of Derivatives not Designated as Hedging Instruments


	Balance Sheet	At December 31		At December 31
Type of Contract	Classification	2011		2010

Commodity	Accounts and notes receivable, net	$	133	$	58
Commodity	Long-term receivables, net		75		64

Total Assets at Fair Value		$	208	$	122

Commodity	Accounts payable	$	36	$	131
Commodity	Deferred credits and other noncurrent obligations		66		40

Total Liabilities at Fair Value		$	102	$	171

Consolidated Statement of Income: The Effect of Derivatives not Designated as Hedging Instruments


		Gain/(Loss)
Type of Derivative	Statement of	Year ended December 31
Contract	Income Classification	2011			2010			2009

Foreign Exchange	Other income	$	–		$	–		$	26
Commodity	Sales and other operating revenues		(255	)		(98	)		(94	)
Commodity	Purchased crude oil and products		15			(36	)		(353	)
Commodity	Other income		(2	)		(1	)		–

		$	(242	)	$	(135	)	$	(421	)

Tabular disclosure of the location and amount of gains and losses reported in the statement of financial performance, or when applicable, the statement of financial position. For example, (a) gains and losses recognized in the income statement on derivative instruments designated and qualifying as hedging instruments in fair value hedges and related hedged items designated and qualifying in fair value hedges and (b) gains and losses initially recognized in other comprehensive income on derivative instruments designated and qualifying as cash flow hedges.

Operating Segments and Geographic Data [Abstract]

Operating Segments and Geographic Data (Tables)

12 Months Ended

Dec. 31, 2011

Segment Earnings


	Year ended December 31
	2011			2010			2009

Segment Earnings
Upstream
United States	$	6,512		$	4,122		$	2,262
International		18,274			13,555			8,670

Total Upstream		24,786			17,677			10,932

Downstream
United States		1,506			1,339			(121	)
International		2,085			1,139			594

Total Downstream		3,591			2,478			473

Total Segment Earnings		28,377			20,155			11,405
All Other
Interest expense		–			(41	)		(22	)
Interest income		78			70			46
Other		(1,560	)		(1,160	)		(946	)

Net Income Attributable to Chevron Corporation	$	26,895		$	19,024		$	10,483

Segment Assets


	At December 31
	2011		2010

Upstream
United States	$	37,108	$	26,319
International		98,540		89,306
Goodwill		4,642		4,617

Total Upstream		140,290		120,242

Downstream
United States		22,182		21,406
International		20,517		20,559

Total Downstream		42,699		41,965

Total Segment Assets		182,989		162,207

All Other*
United States		8,824		11,125
International		17,661		11,437

Total All Other		26,485		22,562

Total Assets – United States		68,114		58,850
Total Assets – International		136,718		121,302
Goodwill		4,642		4,617

Total Assets	$	209,474	$	184,769


*		“All Other” assets consist primarily of worldwide cash, cash equivalents, time deposits and marketable securities, real estate, energy services, information systems, mining operations, power generation businesses, alternative fuels and technology companies, and assets of the corporate administrative functions.

Segment Sales and Other Operating Revenues


	Year ended December 31
	2011			2010			2009*

Upstream
United States	$	9,623		$	10,316		$	9,225
Intersegment		18,115			13,839			10,297

Total United States		27,738			24,155			19,522

International		20,086			17,300			13,463
Intersegment		35,012			23,834			18,477

Total International		55,098			41,134			31,940

Total Upstream		82,836			65,289			51,462

Downstream
United States		86,793			70,436			58,056
Excise and similar taxes		4,199			4,484			4,573
Intersegment		86			115			98

Total United States		91,078			75,035			62,727

International		119,254			90,922			77,845
Excise and similar taxes		3,886			4,107			3,536
Intersegment		81			93			87

Total International		123,221			95,122			81,468

Total Downstream		214,299			170,157			144,195

All Other
United States		526			610			665
Intersegment		1,072			947			964

Total United States		1,598			1,557			1,629

International		4			23			39
Intersegment		42			39			33

Total International		46			62			72

Total All Other		1,644			1,619			1,701

Segment Sales and Other Operating Revenues
United States		120,414			100,747			83,878
International		178,365			136,318			113,480

Total Segment Sales and Other Operating Revenues		298,779			237,065			197,358
Elimination of intersegment sales		(54,408	)		(38,867	)		(29,956	)

Total Sales and Other Operating Revenues	$	244,371		$	198,198		$	167,402


*	2009 conformed with 2010 and 2011 presentation.

Segment income tax expense


	Year ended December 31
	2011			2010			2009

Upstream
United States	$	3,701		$	2,285		$	1,251
International		16,743			10,480			7,451

Total Upstream		20,444			12,765			8,702

Downstream
United States		785			680			(83	)
International		416			462			463

Total Downstream		1,201			1,142			380

All Other		(1,019	)		(988	)		(1,117	)

Total Income Tax Expense	$	20,626		$	12,919		$	7,965

Investments and Advances (Tables)

12 Months Ended

Dec. 31, 2011

Investments and Advances [Abstract]

Equity in earnings, together with investments in and advances to companies accounted for using the equity method and other investments accounted for at or below cost


	Investments and Advances				Equity in Earnings
	At December 31				Year ended December 31
	2011		2010		2011			2010			2009

Upstream
Tengizchevroil	$	5,306	$	5,789	$	5,097		$	3,398		$	2,216
Petropiar		909		973		116			262			122
Caspian Pipeline Consortium		1,094		974		122			124			105
Petroboscan		1,032		937		247			222			171
Angola LNG Limited		2,921		2,481		(42	)		(21	)		(12	)
Other		2,420		1,922		166			319			287

Total Upstream		13,682		13,076		5,706			4,304			2,889

Downstream
GS Caltex Corporation		2,572		2,496		248			158			(191	)
Chevron Phillips Chemical Company LLC		2,909		2,419		985			704			328
Star Petroleum Refining Company Ltd.		1,022		947		75			122			(4	)
Caltex Australia Ltd.		819		767		117			101			11
Colonial Pipeline Company		–		–		–			43			51
Other		630		602		183			151			149

Total Downstream		7,952		7,231		1,608			1,279			344

All Other
Other		516		509		49			54			83

Total equity method	$	22,150	$	20,816	$	7,363		$	5,637		$	3,316
Other at or below cost		718		704

Total investments and advances	$	22,868	$	21,520

Total United States	$	4,847	$	3,769	$	1,119		$	846		$	511
Total International	$	18,021	$	17,751	$	6,244		$	4,791		$	2,805

Summarized financial information on a 100 percent basis for all equity affiliates as well as Chevron's total share, which includes Chevron loans to affiliates


	Affiliates						Chevron Share
Year ended December 31	2011		2010		2009		2011		2010		2009

Total revenues	$	140,107	$	107,505	$	81,995	$	68,632	$	52,088	$	39,280
Income before income tax expense		23,054		18,468		11,083		10,555		7,966		4,511
Net income attributable to affiliates		16,663		12,831		8,261		7,413		5,683		3,285

At December 31

Current assets	$	35,573	$	30,335	$	27,111	$	14,695	$	12,845	$	11,009

Noncurrent assets		61,855		57,491		55,363		22,422		21,401		21,361
Current liabilities		24,671		20,428		17,450		11,040		9,363		7,833

Noncurrent liabilities		19,267		19,749		21,531		4,491		4,459		5,106

Total affiliates’ net equity	$	53,490	$	47,649	$	43,493	$	21,586	$	20,424	$	19,431

Properties, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2011

Property, Plant and Equipment [Abstract]

Properties, Plant and Equipment


	At December 31												Year ended December 31
	Gross Investment at Cost						Net Investment						Additions at Cost^2,3						Depreciation Expense⁴
	2011		2010		2009		2011		2010		2009		2011		2010		2009		2011		2010		2009

Upstream
United States	$	74,369	$	62,523	$	58,328	$	33,461	$	23,277	$	22,273	$	14,404	$	4,934	$	3,518	$	3,870	$	4,078	$	3,992
International		125,795		110,578		96,557		72,543		64,388		57,450		15,722		14,381		10,803		7,590		7,448		6,669

Total Upstream		200,164		173,101		154,885		106,004		87,665		79,723		30,126		19,315		14,231		11,460		11,526		10,661

Downstream
United States		20,699		19,820		18,962		10,723		10,379		10,032		1,226		1,199		1,874		776		741		666
International		7,422		9,697		9,852		2,995		3,948		4,154		443		361		456		332		451		454

Total Downstream		28,121		29,517		28,814		13,718		14,327		14,186		1,669		1,560		2,330		1,108		1,192		1,120

All Other⁵
United States		5,117		4,722		4,569		2,872		2,496		2,548		591		259		354		338		341		325
International		30		27		20		14		16		11		5		11		3		5		4		4

Total All Other		5,147		4,749		4,589		2,886		2,512		2,559		596		270		357		343		345		329

Total United States		100,185		87,065		81,859		47,056		36,152		34,853		16,221		6,392		5,746		4,984		5,160		4,983
Total International		133,247		120,302		106,429		75,552		68,352		61,615		16,170		14,753		11,262		7,927		7,903		7,127

Total	$	233,432	$	207,367	$	188,288	$	122,608	$	104,504	$	96,468	$	32,391	$	21,145	$	17,008	$	12,911	$	13,063	$	12,110


¹	Other than the United States, Nigeria and Australia, no other country accounted for 10 percent or more of the company’s net properties, plant and equipment (PP&E) in 2011. Nigeria had PP&E of $15,601, $13,896 and $12,463 for 2011, 2010 and 2009, respectively. Australia had $12,423 in 2011.

²	Net of dry hole expense related to prior years’ expenditures of $45, $82 and $84 in 2011, 2010 and 2009, respectively.

³	Includes properties acquired with the acquisition of Atlas Energy, Inc. in 2011.

⁴	Depreciation expense includes accretion expense of $628, $513 and $463 in 2011, 2010 and 2009, respectively.

⁵	Primarily mining operations, power generation businesses, real estate assets and management information systems.

Taxes (Tables)

12 Months Ended

Dec. 31, 2011

Taxes [Abstract]

Income Taxes


	Year ended December 31
	2011		2010		2009

Taxes on income
U.S. Federal
Current	$	1,893	$	1,501	$	128
Deferred		877		162		(147	)
State and local
Current		596		376		216
Deferred		41		20		14

Total United States		3,407		2,059		211

International
Current		16,548		10,483		7,154
Deferred		671		377		600

Total International		17,219		10,860		7,754

Total taxes on income	$	20,626	$	12,919	$	7,965

Reconciliation between the U.S. statutory federal income tax rate and the company's effective income tax rate


	Year ended December 31
	2011			2010			2009

U.S. statutory federal income tax rate		35.0	%		35.0	%		35.0	%
Effect of income taxes from inter- national operations at rates different from the U.S. statutory rate		7.5			5.2			10.4
State and local taxes on income, net of U.S. federal income tax benefit		0.9			0.8			0.9
Prior year tax adjustments		(0.1	)		(0.6	)		(0.3	)
Tax credits		(0.4	)		(0.5	)		(1.1	)
Effects of changes in tax rates		0.5			–			0.1
Other		(0.1	)		0.4			(2.0	)

Effective tax rate		43.3	%		40.3	%		43.0	%

Composition of deferred tax balances


	At December 31
	2011			2010

Deferred tax liabilities
Properties, plant and equipment	$	23,597		$	19,855
Investments and other		2,271			2,401

Total deferred tax liabilities		25,868			22,256

Deferred tax assets
Foreign tax credits		(8,476	)		(6,669	)
Abandonment/environmental reserves		(5,387	)		(5,004	)
Employee benefits		(4,773	)		(3,627	)
Deferred credits		(1,548	)		(2,176	)
Tax loss carryforwards		(828	)		(882	)
Other accrued liabilities		(531	)		(486	)
Inventory		(360	)		(483	)
Miscellaneous		(1,595	)		(1,676	)

Total deferred tax assets		(23,498	)		(21,003	)

Deferred tax assets valuation allowance		11,096			9,185

Total deferred taxes, net	$	13,466		$	10,438

Classification of Deferred Taxes


	At December 31
	2011			2010

Prepaid expenses and other current assets	$	(1,149	)	$	(1,624	)
Deferred charges and other assets		(1,224	)		(851	)
Federal and other taxes on income		295			216
Noncurrent deferred income taxes		15,544			12,697

Total deferred income taxes, net	$	13,466		$	10,438

Changes to Company's Unrecognized Tax Benefits


	2011			2010			2009

Balance at January 1	$	3,507		$	3,195		$	2,696
Foreign currency effects		(2	)		17			(1	)
Additions based on tax positions taken in current year		469			334			459
Reductions based on tax positions taken in current year		–			–			–
Additions/reductions resulting from current-year asset acquisitions/sales		(41	)		–			–
Additions for tax positions taken in prior years		236			270			533
Reductions for tax positions taken in prior years		(366	)		(165	)		(182	)
Settlements with taxing authorities in current year		(318	)		(136	)		(300	)
Reductions as a result of a lapse of the applicable statute of limitations		(4	)		(8	)		(10	)

Balance at December 31	$	3,481		$	3,507		$	3,195

Taxes Other Than on Income


	Year ended December 31
	2011		2010		2009

United States
Excise and similar taxes on products and merchandise	$	4,199	$	4,484	$	4,573
Import duties and other levies		4		–		(4	)
Property and other miscellaneous taxes		726		567		584
Payroll taxes		236		219		223
Taxes on production		308		271		135

Total United States		5,473		5,541		5,511

International
Excise and similar taxes on products and merchandise		3,886		4,107		3,536
Import duties and other levies		3,511		6,183		6,550
Property and other miscellaneous taxes		2,354		2,000		1,740
Payroll taxes		148		133		134
Taxes on production		256		227		120

Total International		10,155		12,650		12,080

Total taxes other than on income	$	15,628	$	18,191	$	17,591

Tabular disclosure of tax positions taken in the tax returns filed or to be filed for which it is more likely than not that the tax position will not be sustained upon examination by taxing authorities (i.e., uncertain tax positions) and other types of income tax contingencies, including: (1) the policy on classification of interest and penalties; (2) a tabular reconciliation of the total amounts of unrecognized tax benefits at the beginning and end of the period; the total amount(s) of: (3) unrecognized tax benefits that, if recognized, would affect the effective tax rate, and (4) interest and penalties recognized in each of the income statement and balance sheet; (5) for positions for which it is reasonably possible that the total amounts unrecognized will significantly change within 12 months of the reporting date the: (i) nature of the uncertainty, (ii) nature of the event that could occur that would cause the change, and (iii) an estimate of the range of the reasonably possible change or a statement that an estimate of the range cannot be made; and (6) a description of tax years that remain subject to examination by major tax jurisdictions.

Short-Term Debt (Tables)

12 Months Ended

Dec. 31, 2011

Short-Term Debt


	At December 31
	2011			2010

Commercial paper*	$	2,498		$	2,471
Notes payable to banks and others with originating terms of one year or less		40			43
Current maturities of long-term debt		17			33
Current maturities of long-term capital leases		54			81
Redeemable long-term obligations
Long-term debt		3,317			2,943
Capital leases		14			16

Subtotal		5,940			5,587
Reclassified to long-term debt		(5,600	)		(5,400	)

Total short-term debt	$	340		$	187


*		Weighted-average interest rates at December 31, 2011 and 2010, were 0.04 percent and 0.16 percent, respectively.

Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2011

Long-term debt outstanding


	At December 31
	2011			2010

3.95% notes due 2014	$	1,998		$	1,998
3.45% notes due 2012		–			1,500
4.95% notes due 2019		1,500			1,500
8.625% debentures due 2032		147			147
8.625% debentures due 2031		107			107
7.5% debentures due 2043		83			83
8% debentures due 2032		74			74
7.327% amortizing notes due 2014¹		59			72
9.75% debentures due 2020		54			54
8.875% debentures due 2021		40			40
Medium-term notes, maturing from 2021 to 2038 (6.02%)²		38			38
Fixed interest rate notes, maturing 2011 (9.378%)²		–			19
Other long-term debt (8.07%)²		1			4

Total including debt due within one year		4,101			5,636
Debt due within one year		(17	)		(33	)
Reclassified from short-term debt		5,600			5,400

Total long-term debt	$	9,684		$	11,003


¹		Guarantee of ESOP debt.
²		Weighted-average interest rate at December 31, 2011 and 2010.

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 22
-Article 5

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28551-108399

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28541-108399

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21475-112644

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
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-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21506-112644

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21538-112644

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21521-112644

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6584090&loc=d3e28878-108400

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6479336&loc=d3e64711-112823

Reference 11: 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.(e),(f))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Accounting for Suspended Exploratory Wells [Abstract]

Accounting for Suspended Exploratory Wells (Tables)

12 Months Ended

Dec. 31, 2011

Changes in company's suspended exploratory well costs


	2011			2010			2009

Beginning balance at January 1	$	2,718		$	2,435		$	2,118
Additions to capitalized exploratory well costs pending the determination of proved reserves		652			482			663
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(828	)		(129	)		(174	)
Capitalized exploratory well costs charged to expense		(45	)		(70	)		(172	)
Other reductions*		(63	)		–			–

Ending balance at December 31	$	2,434		$	2,718		$	2,435


*		Represents property sales.

Aging of capitalized well costs and number of project


	At December 31
	2011		2010		2009

Exploratory well costs capitalized for a period of one year or less	$	557	$	419	$	564
Exploratory well costs capitalized for a period greater than one year		1,877		2,299		1,871

Balance at December 31	$	2,434	$	2,718	$	2,435

Number of projects with exploratory well costs that have been capitalized for a period greater than one year*		47		53		46


*		Certain projects have multiple wells or fields or both.

Aging of Costs on Well and Project Basis


			Number
Aging based on drilling completion date of individual wells:	Amount		of wells

1997–2000	$	49		16
2001–2005		396		47
2006–2010		1,432		98

Total	$	1,877		161


Aging based on drilling completion date of last			Number
suspended well in project:	Amount		of projects

1999	$	8		1
2003–2006		345		10
2007–2011		1,524		36

Total	$	1,877		47

Stock Options and Other Share-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2011

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Fair market values of stock options and stock appreciation rights granted


	Year ended December 31
	2011			2010			2009

Stock Options
Expected term in years¹		6.2			6.1			6.0
Volatility²		31.0	%		30.8	%		30.2	%
Risk-free interest rate based on zero coupon U.S. treasury note		2.6	%		2.9	%		2.1	%
Dividend yield		3.6	%		3.9	%		3.2	%
Weighted-average fair value per option granted	$	21.24		$	16.28		$	15.36
Restored Options
Expected term in years¹		1.2			1.2			1.2
Volatility²		20.6	%		38.9	%		45.0	%
Risk-free interest rate based on zero coupon U.S. treasury note		0.7	%		0.6	%		1.1	%
Dividend yield		3.4	%		3.8	%		3.5	%
Weighted-average fair value per option granted	$	7.55		$	12.91		$	12.38


¹		Expected term is based on historical exercise and postvesting cancellation data.

²		Volatility rate is based on historical stock prices over an appropriate period, generally equal to the expected term.

Summary of option activity


						Weighted-
				Weighted-		Average
				Average		Remaining	Aggregate
	Shares			Exercise		Contractual	Intrinsic
	(Thousands)			Price		Term	Value

Outstanding at January 1, 2011		74,852		$	67.04
Granted		14,260		$	94.46
Exercised		(15,844	)	$	60.20
Restored		33		$	103.96
Forfeited		(953	)	$	85.79
Outstanding at December 31, 2011		72,348		$	73.71	6.4 yrs	$	2,365

Exercisable at December 31, 2011		45,494		$	67.84	5.3 yrs	$	1,755

Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2011

Employee Benefits Plans [Abstract]

Funded status of pension and other postretirement benefit plans


	Pension Benefits
	2011						2010						Other Benefits
	U.S.			Int’l.			U.S.			Int’l.			2011			2010

Change in Benefit Obligation
Benefit obligation at January 1	$	10,271		$	5,070		$	9,664		$	4,715		$	3,605		$	3,065
Service cost		374			174			337			153			58			39
Interest cost		463			325			486			307			180			175
Plan participants’ contributions		–			6			–			7			148			147
Plan amendments		–			27			–			–			–			12
Actuarial loss (gain)		1,920			318			568			200			149			486
Foreign currency exchange rate changes		–			(98	)		–			(17	)		(19	)		11
Benefits paid		(863	)		(303	)		(784	)		(295	)		(346	)		(330	)
Curtailment		–			–			–			–			(10	)		–

Benefit obligation at December 31		12,165			5,519			10,271			5,070			3,765			3,605

Change in Plan Assets
Fair value of plan assets at January 1		8,579			3,503			7,304			3,235			–			–
Actual return on plan assets		(143	)		118			867			361			–			–
Foreign currency exchange rate changes		–			(66	)		–			(63	)		–			–
Employer contributions		1,147			319			1,192			258			198			183
Plan participants’ contributions		–			6			–			7			148			147
Benefits paid		(863	)		(303	)		(784	)		(295	)		(346	)		(330	)

Fair value of plan assets at December 31		8,720			3,577			8,579			3,503			–			–

Funded Status at December 31	$	(3,445	)	$	(1,942	)	$	(1,692	)	$	(1,567	)	$	(3,765	)	$	(3,605	)

Consolidated Balance Sheet for pension and other postretirement benefit plans


	Pension Benefits
	2011						2010						Other Benefits
	U.S.			Int’l.			U.S.			Int’l.			2011			2010

Deferred charges and other assets	$	5		$	116		$	7		$	77		$	–		$	–
Accrued liabilities		(72	)		(84	)		(134	)		(71	)		(222	)		(225	)
Reserves for employee benefit plans		(3,378	)		(1,974	)		(1,565	)		(1,573	)		(3,543	)		(3,380	)

Net amount recognized at December 31	$	(3,445	)	$	(1,942	)	$	(1,692	)	$	(1,567	)	$	(3,765	)	$	(3,605	)

Before tax basis amount in accumulated other comprehensive loss


	Pension Benefits
	2011					2010					Other Benefits
	U.S.			Int’l.		U.S.			Int’l.		2011			2010

Net actuarial loss	$	5,982		$	2,250	$	3,919		$	1,903	$	1,002		$	935
Prior service (credit) costs		(44	)		152		(52	)		179		(63	)		(135	)

Total recognized at December 31	$	5,938		$	2,402	$	3,867		$	2,082	$	939		$	800

Pension Plans With Accumulated Benefit Obligation In Excess Of Plan Assets


	Pension Benefits
	2011				2010
	U.S.		Int’l.		U.S.		Int’l.

Projected benefit obligations	$	12,157	$	4,207	$	10,265	$	3,668
Accumulated benefit obligations		11,191		3,586		9,528		3,113
Fair value of plan assets		8,707		2,357		8,566		2,190

Components of Net Periodic Benefit Cost and Amounts Recognized in Other Comprehensive Income


							Pension Benefits
	2011							2010						2009						Other Benefits
	U.S.			Int’l.				U.S.			Int’l.			U.S.			Int’l.			2011			2010			2009
Net Periodic Benefit Cost
Service cost	$	374		$	174			$	337		$	153		$	266		$	128		$	58		$	39		$	43
Interest cost		463			325				486			307			481			292			180			175			180
Expected return on plan assets		(613	)		(283	)			(538	)		(241	)		(395	)		(203	)		–			–			–
Amortization of prior service (credits) costs		(8	)		19				(8	)		22			(7	)		23			(72	)		(75	)		(81	)
Recognized actuarial losses		310			101				318			98			298			108			64			27			27
Settlement losses		298			–				186			6			141			1			–			–			–
Curtailment losses (gains)		–			35				–			–			–			–			(10	)		–			(5	)

Total net periodic benefit cost		824			371				781			345			784			349			220			166			164

Changes Recognized in Other Comprehensive Income
Net actuarial loss during period		2,671			448				242			118			823			194			131			497			82
Amortization of actuarial loss		(608	)		(101	)			(504	)		(104	)		(439	)		(109	)		(64	)		(27	)		(27	)
Prior service cost during period		–			27				–			–			1			13			–			12			20
Amortization of prior service credits (costs)		8			(54	)			8			(22	)		7			(23	)		72			75			81

Total changes recognized in other comprehensive income		2,071			320				(254	)		(8	)		392			75			139			557			156

Recognized in Net Periodic Benefit Cost and Other Comprehensive Income	$	2,895		$	691			$	527		$	337		$	1,176		$	424		$	359		$	723		$	320

Weighted-average assumptions used to determine benefit obligations and net periodic benefit costs


	Pension Benefits
				2011						2010						2009			Other Benefits
	U.S.			Int’l.			U.S.			Int’l.			U.S.			Int’l.			2011			2010			2009

Assumptions used to determine benefit obligations:
Discount rate		3.8	%		5.9	%		4.8	%		6.5	%		5.3	%		6.8	%		4.2	%		5.2	%		5.9	%
Rate of compensation increase		4.5	%		5.7	%		4.5	%		6.7	%		4.5	%		6.3	%		N/A			N/A			N/A
Assumptions used to determine net periodic benefit cost:
Discount rate		4.8	%		6.5	%		5.3	%		6.8	%		6.3	%		7.5	%		5.2	%		5.9	%		6.3	%
Expected return on plan assets		7.8	%		7.8	%		7.8	%		7.8	%		7.8	%		7.5	%		N/A			N/A			N/A
Rate of compensation increase		4.5	%		6.7	%		4.5	%		6.3	%		4.5	%		6.8	%		N/A			N/A			N/A

Effects of change in the assumed health care cost-trend rates


	1 Percent		1 Percent
	Increase		Decrease

Effect on total service and interest cost components	$	17	$	(15	)
Effect on postretirement benefit obligation	$	177	$	(150	)

Fair value measurements of the Company's pension plans


	U.S.										Int’l.
	Total Fair Value			Level 1			Level 2		Level 3		Total Fair Value		Level 1			Level 2		Level 3

At December 31, 2011
Equities
U.S.¹	$	1,470		$	1,470		$	–	$	–	$	497	$	497		$	–	$	–
International		1,203			1,203			–		–		693		693			–		–
Collective Trusts/Mutual Funds²		2,633			14			2,619		–		596		28			568		–
Fixed Income
Government		622			146			476		–		635		25			610		–
Corporate		338			–			338		–		319		16			276		27
Mortgage-Backed Securities		107			–			107		–		2		–			–		2
Other Asset Backed		61			–			61		–		5		–			5		–
Collective Trusts/Mutual Funds²		1,046			–			1,046		–		345		61			284		–
Mixed Funds³		10			10			–		–		102		13			89		–
Real Estate⁴		843			–			–		843		155		–			–		155
Cash and Cash Equivalents		404			404			–		–		211		211			–		–
Other⁵		(17	)		(79	)		8		54		17		(2	)		17		2

Total at December 31, 2011	$	8,720		$	3,168		$	4,655	$	897	$	3,577	$	1,542		$	1,849	$	186

At December 31, 2010
Equities
U.S.¹	$	2,121		$	2,121		$	–	$	–	$	465	$	465		$	–	$	–
International		1,405			1,405			–		–		721		721			–		–
Collective Trusts/Mutual Funds²		2,068			5			2,063		–		578		80			498		–
Fixed Income
Government		659			19			640		–		568		38			530		–
Corporate		314			–			314		–		351		24			299		28
Mortgage-Backed Securities		82			–			82		–		2		–			–		2
Other Asset Backed		74			–			74		–		16		–			16		–
Collective Trusts/Mutual Funds²		1,064			–			1,064		–		332		19			313		–
Mixed Funds³		9			9			–		–		105		16			89		–
Real Estate⁴		596			–			–		596		142		–			–		142
Cash and Cash Equivalents		213			213			–		–		217		217			–		–
Other⁵		(26	)		(87	)		8		53		6		(5	)		9		2

Total at December 31, 2010	$	8,579		$	3,685		$	4,245	$	649	$	3,503	$	1,575		$	1,754	$	174


¹	U.S. equities include investments in the company’s common stock in the amount of $35 at December 31, 2011, and $38 at December 31, 2010.

²	Collective Trusts/Mutual Funds for U.S. plans are entirely index funds; for International plans, they are mostly index funds. For these index funds, the Level 2 designation is partially based on the restriction that advance notification of redemptions, typically two business days, is required.

³	Mixed funds are composed of funds that invest in both equity and fixed-income instruments in order to diversify and lower risk.

⁴	The year-end valuations of the U.S. real estate assets are based on internal appraisals by the real estate managers, which are updates of third-party appraisals that occur at least once a year for each property in the portfolio.

⁵	The “Other” asset class includes net payables for securities purchased but not yet settled (Level 1); dividends and interest- and tax-related receivables (Level 2); insurance contracts and investments in private-equity limited partnerships (Level 3).

The effect of fair-value measurements using significant unobservable inputs on changes in Level 3 plan assets for the period


	Fixed Income
				Mortgage-Backed
	Corporate			Securities		Real Estate		Other			Total

Total at December 31, 2009		$ 18			$ 2		$ 610		$ 52			$ 682
Actual Return on Plan Assets:
Assets held at the reporting date		3			–		34		1			38
Assets sold during the period		–			–		1		–			1
Purchases, Sales and Settlements		7			–		93		2			102
Transfers in and/or out of Level 3		–			–		–		–			–

Total at December 31, 2010		$ 28			$ 2		$ 738		$ 55			$ 823

Actual Return on Plan Assets:
Assets held at the reporting date		–			–		103		4			107
Assets sold during the period		–			–		1		(2	)		(1	)
Purchases, Sales and Settlements		(1	)		–		156		(1	)		154
Transfers in and/or out of Level 3		–			–		–		–			–

Total at December 31, 2011		$ 27			$ 2		$ 998		$ 56			$1,083

Benefit payments, which include estimated future service that are expected to be paid by the company in the next 10 years


	Pension Benefits				Other
	U.S.		Int’l.		Benefits

2012	$	1,053	$	268	$	223
2013	$	1,043	$	316	$	229
2014	$	1,046	$	320	$	234
2015	$	1,050	$	344	$	240
2016	$	1,062	$	375	$	245
2017–2021	$	5,261	$	2,153	$	1,287

LESOP shares


Thousands	2011		2010

Allocated shares		19,047		20,718
Unallocated shares		1,864		2,374

Total LESOP shares		20,911		23,092

Restructuring and Reorganization (Tables)

12 Months Ended

Dec. 31, 2011

Restructuring and Reorganization Costs [Abstract]

Restructuring and Reorganization Costs


	Amounts Before Tax

Balance at January 1, 2011	$	138
Adjustments		(28	)
Payments		(74	)

Balance at December 31, 2011	$	36

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligations [Abstract]

Company Before Tax Asset Retirement Obligation


	2011			2010			2009

Balance at January 1	$	12,488		$	10,175		$	9,395
Liabilities incurred		62			129			144
Liabilities settled		(1,316	)		(755	)		(757	)
Accretion expense		628			513			463
Revisions in estimated cash flows		905			2,426			930

Balance at December 31	$	12,767		$	12,488		$	10,175

Other Financial Information (Tables)

12 Months Ended

Dec. 31, 2011

Other Financial Information [Abstract]

Other Financial Information


	Year ended December 31
	2011		2010			2009

Total financing interest and debt costs	$	288	$	317		$	301
Less: Capitalized interest		288		267			273

Interest and debt expense	$	–	$	50		$	28

Research and development expenses	$	627	$	526		$	603
Foreign currency effects*	$	121	$	(423	)	$	(744	)


^*	Includes $(27), $(71) and $(194) in 2011, 2010 and 2009, respectively, for the company’s share of equity affiliates’ foreign currency effects.

Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2011

Earnings Per Share [Abstract]

Computation of basic and diluted EPS


	Year ended December 31
	2011		2010		2009

Basic EPS Calculation

Earnings available to common stockholders – Basic*	$	26,895	$	19,024	$	10,483

Weighted-average number of common shares outstanding		1,986		1,996		1,991
Add: Deferred awards held as stock units		–		1		1

Total weighted-average number of common shares outstanding		1,986		1,997		1,992

Earnings per share of common stock – Basic	$	13.54	$	9.53	$	5.26

Diluted EPS Calculation

Earnings available to common stockholders – Diluted*	$	26,895	$	19,024	$	10,483

Weighted-average number of common shares outstanding		1,986		1,996		1,991
Add: Deferred awards held as stock units		–		1		1
Add: Dilutive effect of employee stock-based awards		15		10		9

Total weighted-average number of common shares outstanding		2,001		2,007		2,001

Earnings per share of common stock – Diluted	$	13.44	$	9.48	$	5.24

*	There was no effect of dividend equivalents paid on stock units or dilutive impact of employee stock-based awards on earnings.

Summary of Significant Accounting Policies (Details Textual)	12 Months Ended
	Dec. 31, 2011
Summary of Significant Accounting Policies (Textual) [Abstract]
Accounts for controlled subsidiary companies	more than 50%
Substantial ownership interest	20% to 50%
Maturity period of Bank time deposits to be reported as Time deposits	greater than 90 days

Acquisition of Atlas Energy Inc. (Details) $ in Millions	Feb. 17, 2011 USD ($)
Allocation of the Purchase price of Atlas's assets and liabilities
Current assets	$ 155
Investments and long-term receivables	456
Properties	6,051
Goodwill	27
Other assets	5
Total assets acquired	6,694
Current liabilities	(560)
Long-term debt and capital leases	(761)
Deferred income taxes	(1,915)
Other liabilities	(25)
Total liabilities assumed	(3,261)
Net assets acquired	$ 3,433

Acquisition of Atlas Energy Inc. (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Feb. 17, 2011
Acquisition of Atlas Energy Inc (Textual) [Abstract]
Purchase price of acquired entities		$ 4,500
Advance to Atlas Energy	$ 403
Assigned goodwill to the US within the upstream segment		27
Business Acquisition Assumed Preexisting Contract Description	Chevron assumed the terms of a carry arrangement whereby Reliance Marcellus, LLC funds 75 percent of Chevron’s drilling costs, up to $1.3 billion.
Discount rate	8.00%
Fair value of consideration transferred		3,400
Goodwill deductible for tax purposes	$ 0
Atlas Energy Inc [Member]
Acquisition of Atlas Energy Inc (Textual) [Abstract]
Cash purchase of equity interest	3,009	3,009
Advance to Atlas Energy	403
Assumed Debt of Atlas		$ 1,100
Payment to cash out Atlas equity awards	$ 184
Laurel Mountain Midstream LLC [Member]
Acquisition of Atlas Energy Inc (Textual) [Abstract]
Purchase of Interest in Laurel Mountain Midstream	49.00%	49.00%
Upstream Segment [Member]
Acquisition of Atlas Energy Inc (Textual) [Abstract]
Assigned goodwill to the US within the upstream segment		$ 27
Reliance Marcellus LLC [Member]
Acquisition of Atlas Energy Inc (Textual) [Abstract]
Percentage of funds carried under carry arrangement		75.00%
Drilling Costs not incurred by Chevron under carry arrangement		$ 1,300

Noncontrolling Interests (Details) - USD ($) $ in Millions	12 Months Ended
Noncontrolling Interests (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Activity for equity attributable to noncontrolling interests
Beginning Balance	$ 105,811	$ 92,561
Net Income	27,008	19,136	$ 10,563
Ending Balance	122,181	105,811	92,561
Noncontrolling Interest [Member]
Activity for equity attributable to noncontrolling interests
Beginning Balance	730	647	469
Net Income	113	112	80
Distributions to noncontrolling interests	(71)	(72)	(71)
Other changes, net	27	43	169
Ending Balance	$ 799	$ 730	$ 647

The consolidated profit or loss for the period, net of income taxes, including the portion attributable to the noncontrolling interest.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 29
-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 AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 38
-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 AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph A1, A4, A5
-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 AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-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 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 55
-Paragraph 4K
-URI http://asc.fasb.org/extlink&oid=6922042&loc=SL4591552-111686

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 45
-Paragraph 19
-URI http://asc.fasb.org/extlink&oid=6921628&loc=SL4569616-111683

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 55
-Paragraph 4J
-URI http://asc.fasb.org/extlink&oid=6922042&loc=SL4591551-111686

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 50
-Paragraph 1A
-Subparagraph (a),(c)
-URI http://asc.fasb.org/extlink&oid=6921930&loc=SL4573702-111684

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 38
-Subparagraph c(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.

Total of Stockholders' Equity (deficit) items, net of receivables from officers, directors, owners, and affiliates of the entity including portions attributable to both the parent and noncontrolling interests (previously referred to as minority interest), if any. The entity including portions attributable to the parent and noncontrolling interests is sometimes referred to as the economic entity. This excludes temporary equity and is sometimes called permanent equity.

Statement of Income - Chevron U.S.A. Inc.

Information Relating to the Consolidated Statement of Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Net decrease (increase) in operating working capital was composed of the followings:
Increase in accounts and notes receivable	$ (2,156)	$ (2,767)	$ (1,476)
(Increase) decrease in inventories	(404)	15	1,213
Increase in prepaid expenses and other current assets	(853)	(542)	(264)
Increase (decrease) in accounts payable and accrued liabilities	3,839	3,049	(1,121)
Increase (decrease) in income and other taxes payable	1,892	321	(653)
Net decrease (increase) in operating working capital	2,318	76	(2,301)
Net cash provided by operating activities includes the following cash payment for interest and income taxes:
Interest paid on debt (net of capitalized interest)		34
Income taxes	17,374	11,749	7,537
Net sales of marketable securities consisted of the following gross amounts:
Marketable securities purchased	(112)	(90)	(30)
Marketable securities sold	38	41	157
Net (purchases) sales of marketable securities	(74)	(49)	127
Net purchases of time deposits consisted of the following gross amounts:
Time deposits purchased	(6,439)	(5,060)
Time deposits matured	5,335	2,205
Net purchases of time deposits	(1,104)	(2,855)
Capital expenditures
Additions to properties, plant and equipment	25,440	18,474	16,107
Additions to investments	900	861	942
Current year dry hole expenditures	332	414	468
Payments for other liabilities and assets, net	(172)	(137)	2,326
Capital expenditures	26,500	19,612	19,843
Expensed exploration expenditures	839	651	790
Assets acquired through capital lease obligations and other financing obligations	32	104	19
Capital and exploratory expenditures, excluding equity affiliates	27,371	20,367	20,652
Company's share of expenditures by equity affiliates	1,695	1,388	1,585
Capital and exploratory expenditures, including equity affiliates	$ 29,066	$ 21,755	$ 22,237

Information Relating to the Consolidated Statement of Cash Flows (Details 1) - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Feb. 17, 2011
Additional Information Relating to the Consolidated Statement of Cash Flows (Textual) [Abstract]
Advance to Atlas Energy	$ 403
Information Relating to the Consolidated Statement of Cash Flows (Textual) [Abstract]
Reduction for income tax benefits associated with stock options exercised	$ 121	$ 67	$ 25
Stock repurchased during period, shares	42.3	8.8
Stock repurchased during period, value	$ 4,250	$ 750
Proceeds from issuance of tax exempt bonds	374	1,250	350
Noncash additions to Properties, plant and equipment	945	2,753	985
Payment for accrued liabilities			2,450
Treasury Stock at Cost
Equity, Class of Treasury Stock [Line Items]
Share repurchase value	$ 4,262	$ 775	$ 6
Laurel Mountain Midstream LLC [Member]
Additional Information Relating to the Consolidated Statement of Cash Flows (Textual) [Abstract]
Purchase of Interest in Laurel Mountain Midstream	49.00%			49.00%
Atlas Energy Inc [Member]
Additional Information Relating to the Consolidated Statement of Cash Flows (Textual) [Abstract]
Acquisition of Atlas Energy purchase price	$ 3,009			$ 3,009
Advance to Atlas Energy	403
Cash payment of equity awards included in net increase in operating working capital	184
Repayment of Atlas debt	761
Payoff of Atlas revolving credit facility	$ 271

Summarized Financial Data - Chevron U.S.A. Inc. (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

^[1]

$ 244,371

$ 198,198

$ 167,402

206,072

172,873

153,108

Chevron U.S.A. Inc. [Member]

26,895

19,024

10,483

Statement of Income - Chevron U.S.A. Inc.

187,917

145,381

121,553

178,498

139,984

120,053

$ 6,899

$ 4,159

$ 1,141

[1]	Includes excise, value-added and similar taxes.

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 87-21
-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 AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 38
-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 130
-Paragraph 10, 15
-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 95
-Paragraph 28, 29, 30
-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 SEC
-Name Regulation S-X (SX)
-Number 210
-Article 5
-Section 03
-Paragraph 19

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 04
-Paragraph 20
-Article 9

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 230
-SubTopic 10
-Section 45
-Paragraph 28
-URI http://asc.fasb.org/extlink&oid=6943989&loc=d3e3602-108585

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Net Income
-URI http://asc.fasb.org/extlink&oid=6518256

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Other Comprehensive Income
-URI http://asc.fasb.org/extlink&oid=6519514

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6371337&loc=d3e3550-109257

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 225
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03.18)
-URI http://asc.fasb.org/extlink&oid=6880815&loc=d3e20235-122688

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 944
-SubTopic 225
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04.19)
-URI http://asc.fasb.org/extlink&oid=6879464&loc=d3e573970-122913

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
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-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6920043&loc=d3e565-108580

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 944
-SubTopic 225
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04.22)
-URI http://asc.fasb.org/extlink&oid=6879464&loc=d3e573970-122913

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 38
-Subparagraph 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 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph A7
-Appendix A

Summarized Financial Data - Chevron U.S.A. Inc. (Details 1) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Balance Sheet - Chevron U.S.A. Inc.
Current assets	$ 53,234	$ 48,841
Current liabilities	33,600	29,012
Total CUSA net equity	122,181	105,811	$ 92,561
Chevron U.S.A. Inc. [Member]
Balance Sheet - Chevron U.S.A. Inc.
Current assets	34,478	29,211
Other assets	47,556	35,294
Current liabilities	19,082	18,098
Other liabilities	26,153	16,785
Total CUSA net equity	36,799	29,622
Memo: Total debt	$ 14,763	$ 8,284

Summarized Financial Data - Chevron Transport Corporation

Summarized Financial Data - Chevron Transport Corporation (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

^[1]

$ 244,371

$ 198,198

$ 167,402

206,072

172,873

153,108

Chevron Transport Corporation [Member]

26,895

19,024

10,483

Summarized Financial Data - Chevron Transport Corporation

793

885

683

974

1,008

810

$ (177)

$ (116)

$ (124)

[1]	Includes excise, value-added and similar taxes.

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

Summarized Financial Data - Chevron Transport Corporation (Details 1) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Balance Sheet - Chevron Transport Corporation
Current assets	$ 53,234	$ 48,841
Current liabilities	33,600	29,012
Total Equity	122,181	105,811	$ 92,561
Chevron Transport Corporation [Member]
Balance Sheet - Chevron Transport Corporation
Current assets	290	309
Other assets	228	201
Current liabilities	114	101
Other liabilities	346	175
Total Equity	$ 58	$ 234

Summarized Financial Data - Tengizchevroil LLP (Details) - Tengizchevroil LLP [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Summarized Financial Data - Tengizchevroil LLP
Sales and other operating revenues	$ 25,278	$ 17,812	$ 12,013
Costs and other deductions	10,941	8,394	6,044
Net income attributable to TCO	$ 10,039	$ 6,593	$ 4,178

The amount of net income (loss) reported by an equity method investment of the entity.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 18
-Subparagraph f
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 18
-Paragraph 20
-Subparagraph 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 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph bb
-Article 1

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph w
-Article 1

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Article 4
-Section 08
-Paragraph g
-Subparagraph 1, 2

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 28
-Subparagraph (f)
-URI http://asc.fasb.org/extlink&oid=6957238&loc=d3e14064-108612

Reference 7: 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.(g))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 323
-SubTopic 10
-Section 50
-Paragraph 3
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=6382943&loc=d3e33918-111571

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 323
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6382943&loc=d3e33912-111571

Summarized Financial Data - Tengizchevroil LLP (Details 1) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Summarized Financial Data (Textual) [Abstract]
Percentage of affiliate's summarized financial information presented	100.00%
Tengizchevroil LLP [Member]
Balance Sheet - Tengizchevroil LLP
Current assets	$ 3,477	$ 3,376
Other assets	11,619	11,813
Current liabilities	2,995	2,402
Other liabilities	3,759	4,130
Total net equity	$ 8,342	$ 8,657
Summarized Financial Data (Textual) [Abstract]
Equity Method Investment, Ownership Percentage	50.00%

Lease Commitments (Details) - USD ($) $ in Millions	12 Months Ended
Lease Commitments (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Schedule of capitalized leased assets
Upstream	$ 585	$ 561
Downstream	316	316
All Other		169
Total	901	1,046
Less: Accumulated amortization	568	573
Net capitalized leased assets	333	473
Rental expenses incurred for operating leases
Minimum rentals	892	931	$ 933
Contingent rentals	11	10	7
Total	903	941	940
Less: Sublease rental income	39	41	41
Net rental expense	864	900	$ 899
Estimated future minimum lease payments (net of noncancelable sublease rentals) under operating and capital leases
Future minimum operating lease payments, Current	693
Future minimum capital lease payments, Current	70
Future minimum operating lease payments, due in two years	632
Future minimum capital lease payments, due in two years	47
Future minimum operating lease payments, due in three years	523
Future minimum capital lease payments, due in three years	32
Future minimum operating lease payments, due in four years	475
Future minimum capital lease payments, due in four years	21
Future minimum operating lease payments, due in five years	393
Future minimum capital lease payments, due in five years	13
Future minimum operating lease payments, due thereafter	793
Future minimum capital lease payments, due thereafter	68
Future minimum operating leases payments, total	3,509
Future minimum capital lease payments, total	251
Less: Amounts representing interest and executory costs	(55)
Net present values	196
Less: Capital lease obligations included in short-term debt	(68)
Long-term capital lease obligations	$ 128	$ 286
Lease Commitments (Textual)
Renewal term of leasing arrangement (in years)	Up to 25
Non-cancelable term of operating and capital leases (in years)	more than 1

Fair Value Measurements (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Marketable securities	$ 249	$ 155
Derivatives	208	122
Total Assets at Fair Value	457	277
Derivatives	102	171
Total Liabilities at Fair Value	102	171
Level 1 [Member]
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Marketable securities	249	155
Derivatives	104	11
Total Assets at Fair Value	353	166
Derivatives	101	75
Total Liabilities at Fair Value	101	75
Level 2 [Member]
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Marketable securities	0	0
Derivatives	104	111
Total Assets at Fair Value	104	111
Derivatives	1	96
Total Liabilities at Fair Value	1	96
Level 3 [Member]
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Marketable securities	0	0
Derivatives	0	0
Total Assets at Fair Value	0	0
Derivatives	0	0
Total Liabilities at Fair Value	$ 0	$ 0

Fair Value Measurements (Details 1) - Fair Value, Measurements, Nonrecurring [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
Properties, plant and equipment, net (held and used)	$ 67	$ 57
Properties, plant and equipment, net (held for sale)	167	13
Investments and advances		0
Total Non-Recurring Assets at Fair Value	234	70
Properties, plant and equipment, net (held and used) before tax loss	81	85
Properties, plant and equipment, net (held for sale) before tax loss	54	36
Investments and advances before tax loss	108	15
Assets fair value before tax loss	243	136
Level 1 [Member]
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
Properties, plant and equipment, net (held and used)	0	0
Properties, plant and equipment, net (held for sale)	0	0
Investments and advances	0	0
Total Non-Recurring Assets at Fair Value	0	0
Level 2 [Member]
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
Properties, plant and equipment, net (held and used)		0
Properties, plant and equipment, net (held for sale)	167	0
Investments and advances		0
Total Non-Recurring Assets at Fair Value	167	0
Level 3 [Member]
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
Properties, plant and equipment, net (held and used)	67	57
Properties, plant and equipment, net (held for sale)		13
Investments and advances		0
Total Non-Recurring Assets at Fair Value	$ 67	$ 70

Fair Value Measurements (Details Textual) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount of long-term debt	$ 4,101	$ 5,636
Fair Value Measurements (Textual) [Abstract]
Maturity period of primarily bank time deposits, classified as cash equivalents	90 days or less
Fair Value of Cash and Cash Equivalents	$ 15,864	14,060	$ 8,716	$ 9,347
Maturity period of bank time deposits	Greater than 90 days
Carrying and fair value of time deposits	$ 3,958	2,855
Fair value of investments not included in cash and cash equivalents	1,240	855
Carrying Amount of Long-term Debt [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount of long-term debt	4,101	5,636
Fair Value of Long-term Debt [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount of long-term debt	$ 4,928	$ 6,311

Financial and Derivative Instruments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Consolidated Balance Sheet: Fair Value of Derivatives not Designated as Hedging Instruments
Total Assets at Fair Value	$ 208	$ 122
Total Liabilities at Fair Value	102	171
Consolidated Statement of Income: The Effect of Derivatives not Designated as Hedging Instruments
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(242)	(135)	$ (421)
Deferred credits and other noncurrent obligations [Member] \| Commodity [Member]
Consolidated Balance Sheet: Fair Value of Derivatives not Designated as Hedging Instruments
Total Liabilities at Fair Value	66	40
Accounts payable [Member] \| Commodity [Member]
Consolidated Balance Sheet: Fair Value of Derivatives not Designated as Hedging Instruments
Total Liabilities at Fair Value	36	131
Long term receivables, net [Member] \| Commodity [Member]
Consolidated Balance Sheet: Fair Value of Derivatives not Designated as Hedging Instruments
Total Assets at Fair Value	75	64
Accounts and notes receivable, net [Member] \| Commodity [Member]
Consolidated Balance Sheet: Fair Value of Derivatives not Designated as Hedging Instruments
Total Assets at Fair Value	133	58
Purchased crude oil and products [Member] \| Commodity [Member]
Consolidated Statement of Income: The Effect of Derivatives not Designated as Hedging Instruments
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	15	(36)	(353)
Sales and other operating revenues [Member] \| Commodity [Member]
Consolidated Statement of Income: The Effect of Derivatives not Designated as Hedging Instruments
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(255)	(98)	(94)
Other Income [Member] \| Foreign Exchange [Member]
Consolidated Statement of Income: The Effect of Derivatives not Designated as Hedging Instruments
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net			$ 26
Other Income [Member] \| Commodity [Member]
Consolidated Statement of Income: The Effect of Derivatives not Designated as Hedging Instruments
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ (2)	$ (1)

Operating Segments and Geographic Data (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Segment Earnings
Net Income attributable to Chevron Corporation	$ 26,895	$ 19,024	$ 10,483
Upstream [Member]
Segment Earnings
Net Income attributable to Chevron Corporation	24,786	17,677	10,932
Upstream [Member] \| United States [Member]
Segment Earnings
Net Income attributable to Chevron Corporation	6,512	4,122	2,262
Upstream [Member] \| International [Member]
Segment Earnings
Net Income attributable to Chevron Corporation	18,274	13,555	8,670
Downstream [Member]
Segment Earnings
Net Income attributable to Chevron Corporation	3,591	2,478	473
Downstream [Member] \| United States [Member]
Segment Earnings
Net Income attributable to Chevron Corporation	1,506	1,339	(121)
Downstream [Member] \| International [Member]
Segment Earnings
Net Income attributable to Chevron Corporation	2,085	1,139	594
Reportable Segment [Member]
Segment Earnings
Net Income attributable to Chevron Corporation	28,377	20,155	11,405
All Other Segments [Member]
Segment Earnings
Interest Expense		(41)	(22)
Interest Income	78	70	46
Other	$ (1,560)	$ (1,160)	$ (946)

Operating Segments and Geographic Data (Details 1) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Segment Assets
Goodwill	$ 4,642	$ 4,617
Total Assets	209,474	184,769
United States [Member]
Segment Assets
Total Assets	68,114	58,850
International [Member]
Segment Assets
Total Assets	136,718	121,302
Upstream [Member]
Segment Assets
Goodwill	4,642	4,617
Total Assets	140,290	120,242
Upstream [Member] \| United States [Member]
Segment Assets
Total Assets	37,108	26,319
Upstream [Member] \| International [Member]
Segment Assets
Total Assets	98,540	89,306
Downstream [Member]
Segment Assets
Total Assets	42,699	41,965
Downstream [Member] \| United States [Member]
Segment Assets
Total Assets	22,182	21,406
Downstream [Member] \| International [Member]
Segment Assets
Total Assets	20,517	20,559
Reportable Segment [Member]
Segment Assets
Total Assets	182,989	162,207
All Other Segments [Member]
Segment Assets
Total Assets	26,485	22,562
All Other Segments [Member] \| United States [Member]
Segment Assets
Total Assets	8,824	11,125
All Other Segments [Member] \| International [Member]
Segment Assets
Total Assets	$ 17,661	$ 11,437

Carrying amount as of the balance sheet date, which is the cumulative amount paid and (if applicable) the fair value of any noncontrolling interest in the acquiree, adjusted for any amortization recognized prior to the adoption of any changes in generally accepted accounting principles (as applicable) and for any impairment charges, in excess of the fair value of net assets acquired in one or more business combination transactions.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-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 142
-Paragraph 43
-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 141R
-Paragraph 68
-Subparagraph l
-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 350
-SubTopic 20
-Section 45
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6388280&loc=d3e13770-109266

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6905597&loc=d3e13816-109267

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 72
-Subparagraph 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 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-Clause 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 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 34
-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.

Operating Segments and Geographic Data (Details 2) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Operating Segments and Geographic Data (Textual) [Abstract]

^[1]

$ 244,371

$ 198,198

$ 167,402

Contribution in company's total sales and other operating revenues by a country other than United States

Less than 10%

Upstream [Member]

Upstream [Member] | Total United States [Member]

$ 82,836

65,289

51,462

Upstream [Member] | United States [Member]

27,738

24,155

19,522

Upstream [Member] | Intersegment [Member]

9,623

10,316

9,225

Upstream [Member] | International [Member]

18,115

13,839

10,297

Upstream [Member] | International [Member]

55,098

41,134

31,940

Upstream [Member] | Intersegment [Member]

20,086

17,300

13,463

35,012

23,834

18,477

Downstream [Member]

Downstream [Member] | Total United States [Member]

214,299

170,157

144,195

Downstream [Member] | United States [Member]

91,078

75,035

62,727

Downstream [Member] | Excise and Similar Taxes [Member]

86,793

70,436

58,056

Downstream [Member] | Intersegment [Member]

4,199

4,484

4,573

Downstream [Member] | International [Member]

115

Downstream [Member] | International [Member]

123,221

95,122

81,468

Downstream [Member] | Excise and Similar Taxes [Member]

119,254

90,922

77,845

Downstream [Member] | Intersegment [Member]

3,886

4,107

3,536

All Other Segments [Member]

All Other Segments [Member] | Total United States [Member]

1,644

1,619

1,701

All Other Segments [Member] | United States [Member]

1,598

1,557

1,629

All Other Segments [Member] | Intersegment [Member]

526

610

665

All Other Segments [Member] | International [Member]

1,072

947

964

All Other Segments [Member] | International [Member]

All Other Segments [Member] | Intersegment [Member]

Sales and Other Operating Revenue [Member]

Sales and Other Operating Revenue [Member] | United States [Member]

298,779

237,065

197,358

Sales and Other Operating Revenue [Member] | Intersegment [Member]

120,414

100,747

83,878

Sales and Other Operating Revenue [Member] | Elimination of Intersegment Sales [Member]

178,365

136,318

113,480

Changes to company's unrecognized tax benefits

$ (54,408)

$ (38,867)

$ (29,956)

[1]	Includes excise, value-added and similar taxes.

Operating Segments and Geographic Data (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Segment income tax expense
Income Tax Expense	$ 20,626	$ 12,919	$ 7,965
Upstream [Member]
Segment income tax expense
Income Tax Expense	20,444	12,765	8,702
Upstream [Member] \| United States [Member]
Segment income tax expense
Income Tax Expense	3,701	2,285	1,251
Upstream [Member] \| International [Member]
Segment income tax expense
Income Tax Expense	16,743	10,480	7,451
Downstream [Member]
Segment income tax expense
Income Tax Expense	1,201	1,142	380
Downstream [Member] \| United States [Member]
Segment income tax expense
Income Tax Expense	785	680	(83)
Downstream [Member] \| International [Member]
Segment income tax expense
Income Tax Expense	416	462	463
All Other Segments [Member]
Segment income tax expense
Income Tax Expense	$ (1,019)	$ (988)	$ (1,117)

Investments and Advances (Details) - USD ($) $ in Millions	12 Months Ended
Investments and Advances (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Schedule of Equity Method Investments [Line Items]
Equity in Earnings	$ 7,363	$ 5,637	$ 3,316
Investments and advances	22,150	20,816
Other at or Below Cost, Investment and Advances	718	704
Total Investment and Advances	22,868	21,520
Caspian Pipeline Consortium [Member]
Schedule of Equity Method Investments [Line Items]
Investments and advances	1,094
Upstream [Member]
Schedule of Equity Method Investments [Line Items]
Equity in Earnings	5,706	4,304	2,889
Investments and advances	13,682	13,076
Upstream [Member] \| Angola LNG Limited [Member]
Schedule of Equity Method Investments [Line Items]
Equity in Earnings	(42)	(21)	(12)
Investments and advances	2,921	2,481
Upstream [Member] \| Petroboscan [Member]
Schedule of Equity Method Investments [Line Items]
Equity in Earnings	247	222	171
Investments and advances	1,032	937
Upstream [Member] \| Tengizchevroil LLP [Member]
Schedule of Equity Method Investments [Line Items]
Equity in Earnings	5,097	3,398	2,216
Investments and advances	5,306	5,789
Upstream [Member] \| Caspian Pipeline Consortium [Member]
Schedule of Equity Method Investments [Line Items]
Equity in Earnings	122	124	105
Investments and advances	1,094	974
Upstream [Member] \| Petropiar [Member]
Schedule of Equity Method Investments [Line Items]
Equity in Earnings	116	262	122
Investments and advances	909	973
Upstream [Member] \| Other [Member]
Schedule of Equity Method Investments [Line Items]
Equity in Earnings	166	319	287
Investments and advances	2,420	1,922
Downstream [Member]
Schedule of Equity Method Investments [Line Items]
Equity in Earnings	1,608	1,279	344
Investments and advances	7,952	7,231
Downstream [Member] \| Star Petroleum Refining Company Limited [Member]
Schedule of Equity Method Investments [Line Items]
Equity in Earnings	75	122	(4)
Investments and advances	1,022	947
Downstream [Member] \| Caltex Australia Limited [Member]
Schedule of Equity Method Investments [Line Items]
Equity in Earnings	117	101	11
Investments and advances	819	767
Downstream [Member] \| Chevron Phillips Chemical Company LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity in Earnings	985	704	328
Investments and advances	2,909	2,419
Downstream [Member] \| GS Caltex Corporation [Member]
Schedule of Equity Method Investments [Line Items]
Equity in Earnings	248	158	(191)
Investments and advances	2,572	2,496
Downstream [Member] \| Colonial Pipeline Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity in Earnings		43	51
Downstream [Member] \| Other [Member]
Schedule of Equity Method Investments [Line Items]
Equity in Earnings	183	151	149
Investments and advances	630	602
All Other [Member]
Schedule of Equity Method Investments [Line Items]
Equity in Earnings	49	54	83
Investments and advances	516	509
Investments and Advances [Member] \| United States [Member]
Schedule of Equity Method Investments [Line Items]
Total Investment and Advances	4,847	3,769
Investments and Advances [Member] \| International [Member]
Schedule of Equity Method Investments [Line Items]
Total Investment and Advances	18,021	17,751
Equity in Earnings [Member] \| United States [Member]
Schedule of Equity Method Investments [Line Items]
Equity in Earnings	1,119	846	511
Equity in Earnings [Member] \| International [Member]
Schedule of Equity Method Investments [Line Items]
Equity in Earnings	$ 6,244	$ 4,791	$ 2,805

Investments and Advances (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Investment And Advances (Textual) [Abstract]
Purchased crude oil and products	$ 149,923	$ 116,467	$ 99,653
Investments and advances	$ 22,150	20,816
Investment And Advances (Additional Textual) [Abstract]
Year of formation of joint venture with Tengizchevroil	1993
Term of joint venture Tengizchevroil in years	40 years
Chevron investment carrying value over underlying equity in TCO's net assets	$ 180
Year of formation of joint venture with Petropiar	2008
Term of joint venture with Petropiar (in years)	25 years
Equity ownership portion of Chevron in Hamaca project	30.00%
Chevron investment carrying value less underlying equity in Petropiar net assets	$ 180
Percentage of Caspian Pipeline Consortium pipeline construction funded by Loans	30.00%
Long term loans of Caspian Pipeline Consortium included in investments and advances	$ 1,111
Year of formation of joint venture with Petroboscan	2006
Year of formation of joint venture with Caspian Pipeline Consortium	1997
Year of closure of the joint venture with Petroboscan	2026
Chevron investment carrying value over underlying equity in Petroboscan's net assets	$ 220
The portion of equity ownership interest held in CP Chemical by Conoco Phillips Corporation	50.00%
The portion of equity ownership interest of Star Petroleum Refining Company Ltd. held by the PTT Public Company Limited	36.00%
The portion of equity ownership interest of Caltex Australia Ltd. held by public	50.00%
Fair value of Chevron share in Caltex Australia Ltd common stock	$ 1,600
Sale and other operating revenues from affiliated companies	20,164	13,672	10,391
Accounts and notes receivable due from affiliated companies	1,968	1,718
Accounts payable due to affiliated companies	519	377
Chevron's loan to affiliates	957	1,543	2,422
Affiliated Entity [Member]
Investment And Advances (Textual) [Abstract]
Purchased crude oil and products	$ 7,489	5,559	4,631
Tengizchevroil LLP [Member]
Investment And Advances (Textual) [Abstract]
Equity Method Investment, Ownership Percentage	50.00%
Petropiar [Member]
Investment And Advances (Textual) [Abstract]
Equity Method Investment, Ownership Percentage	30.00%
Caspian Pipeline Consortium [Member]
Investment And Advances (Textual) [Abstract]
Equity Method Investment, Ownership Percentage	15.00%
Investments and advances	$ 1,094
Petroboscan [Member]
Investment And Advances (Textual) [Abstract]
Equity Method Investment, Ownership Percentage	39.00%
Angola LNG Limited [Member]
Investment And Advances (Textual) [Abstract]
Equity Method Investment, Ownership Percentage	36.00%
GS Caltex Corporation [Member]
Investment And Advances (Textual) [Abstract]
Equity Method Investment, Ownership Percentage	50.00%
Chevron Phillips Chemical Company LLC [Member]
Investment And Advances (Textual) [Abstract]
Equity Method Investment, Ownership Percentage	50.00%
Star Petroleum Refining Company Limited [Member]
Investment And Advances (Textual) [Abstract]
Equity Method Investment, Ownership Percentage	64.00%
Caltex Australia Limited [Member]
Investment And Advances (Textual) [Abstract]
Equity Method Investment, Ownership Percentage	50.00%
Chevron Share
Summarized financial information on a 100 percent basis for all equity affiliates as well as Chevron's total share, which includes Chevron loans to affiliates
Total revenues	$ 68,632	52,088	39,280
Income before income tax expense	10,555	7,966	4,511
Net income attributable to affiliates	7,413	5,683	3,285
Current assets	14,695	12,845	11,009
Noncurrent assets	22,422	21,401	21,361
Current liabilities	11,040	9,363	7,833
Noncurrent liabilities	4,491	4,459	5,106
Total net equity	21,586	20,424	19,431
Affiliates
Summarized financial information on a 100 percent basis for all equity affiliates as well as Chevron's total share, which includes Chevron loans to affiliates
Total revenues	140,107	107,505	81,995
Income before income tax expense	23,054	18,468	11,083
Net income attributable to affiliates	16,663	12,831	8,261
Current assets	35,573	30,335	27,111
Noncurrent assets	61,855	57,491	55,363
Current liabilities	24,671	20,428	17,450
Noncurrent liabilities	19,267	19,749	21,531
Total net equity	$ 53,490	$ 47,649	$ 43,493

Properties, Plant and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Properties, Plant and Equipment
Properties, plant and equipment, at cost	$ 233,432	$ 207,367	$ 188,288
Properties, plant and equipment, net	122,608	104,504	96,468
Total property plant and equipment, additions at cost	32,391	21,145	17,008
Depreciation, depletion and amortization	12,911	13,063	12,110
Total depreciation expenses	12,911	13,063	12,110
United States [Member]
Properties, Plant and Equipment
Properties, plant and equipment, at cost	100,185	87,065	81,859
Properties, plant and equipment, net	47,056	36,152	34,853
Total property plant and equipment, additions at cost	16,221	6,392	5,746
Depreciation, depletion and amortization	4,984	5,160	4,983
International [Member]
Properties, Plant and Equipment
Properties, plant and equipment, at cost	133,247	120,302	106,429
Properties, plant and equipment, net	75,552	68,352	61,615
Total property plant and equipment, additions at cost	16,170	14,753	11,262
Depreciation, depletion and amortization	7,927	7,903	7,127
Upstream [Member]
Properties, Plant and Equipment
Properties, plant and equipment, at cost	200,164	173,101	154,885
Properties, plant and equipment, net	106,004	87,665	79,723
Total property plant and equipment, additions at cost	30,126	19,315	14,231
Depreciation, depletion and amortization	11,460	11,526	10,661
Upstream [Member] \| United States [Member]
Properties, Plant and Equipment
Properties, plant and equipment, at cost	74,369	62,523	58,328
Properties, plant and equipment, net	33,461	23,277	22,273
Total property plant and equipment, additions at cost	14,404	4,934	3,518
Depreciation, depletion and amortization	3,870	4,078	3,992
Upstream [Member] \| International [Member]
Properties, Plant and Equipment
Properties, plant and equipment, at cost	125,795	110,578	96,557
Properties, plant and equipment, net	72,543	64,388	57,450
Total property plant and equipment, additions at cost	15,722	14,381	10,803
Depreciation, depletion and amortization	7,590	7,448	6,669
Downstream [Member]
Properties, Plant and Equipment
Properties, plant and equipment, at cost	28,121	29,517	28,814
Properties, plant and equipment, net	13,718	14,327	14,186
Total property plant and equipment, additions at cost	1,669	1,560	2,330
Depreciation, depletion and amortization	1,108	1,192	1,120
Downstream [Member] \| United States [Member]
Properties, Plant and Equipment
Properties, plant and equipment, at cost	20,699	19,820	18,962
Properties, plant and equipment, net	10,723	10,379	10,032
Total property plant and equipment, additions at cost	1,226	1,199	1,874
Depreciation, depletion and amortization	776	741	666
Downstream [Member] \| International [Member]
Properties, Plant and Equipment
Properties, plant and equipment, at cost	7,422	9,697	9,852
Properties, plant and equipment, net	2,995	3,948	4,154
Total property plant and equipment, additions at cost	443	361	456
Depreciation, depletion and amortization	332	451	454
All Other Segments [Member]
Properties, Plant and Equipment
Properties, plant and equipment, at cost	5,147	4,749	4,589
Properties, plant and equipment, net	2,886	2,512	2,559
Total property plant and equipment, additions at cost	596	270	357
Depreciation, depletion and amortization	343	345	329
All Other Segments [Member] \| United States [Member]
Properties, Plant and Equipment
Properties, plant and equipment, at cost	5,117	4,722	4,569
Properties, plant and equipment, net	2,872	2,496	2,548
Total property plant and equipment, additions at cost	591	259	354
Depreciation, depletion and amortization	338	341	325
All Other Segments [Member] \| International [Member]
Properties, Plant and Equipment
Properties, plant and equipment, at cost	30	27	20
Properties, plant and equipment, net	14	16	11
Total property plant and equipment, additions at cost	5	11	3
Depreciation, depletion and amortization	$ 5	$ 4	$ 4

Properties, Plant and Equipment (Details Textual) $ in Millions	12 Months Ended
	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)
Property Plant and Equipment (Textual) [Abstract]
Minimum percentage accountability of the U.S., Nigeria and Australia, of net Properties, Plant and Equipment	0.10
Net Properties, Plant and Equipment of Nigeria	$ 15,601	$ 13,896	$ 12,463
Net Properties, Plant and Equipment of Australia	12,423
Dry Hole Expense Related To Prior Year Net	45	82	84
Accretion expense	$ 628	$ 513	$ 463

Litigation (Details) $ in Millions	1 Months Ended		12 Months Ended
Litigation (Details) $ in Millions	Sep. 30, 2010 USD ($)	Aug. 31, 2010	Dec. 31, 2011 USD ($) LegalMatter	Feb. 14, 2011 USD ($)	Dec. 31, 2008 USD ($)
Litigation (Textual) [Abstract]
Conducted Remediation Program			3 years
Remediation program			$ 40
Financial compensation for purported damages on mining engineer's report					$ 18,900
Assessment for purported unjust enrichment on mining engineer's report					$ 8,400
Court order requiring the parties to provide their positions on damages within (in days)		45 days
Approximate damages on plaintiffs' submission, Maximum	$ 76,000
Approximate damages on plaintiffs' submission, Minimum	16,000
Approximate unjust enrichment on plaintiffs' submission, Maximum	38,000
Approximate unjust enrichment on plaintiffs' submission, Minimum	$ 5,000
Amount assessed in damages				$ 8,600
Amount assessed for plaintiffs representatives				900
Additional amount assessed in punitive damages				$ 8,600
Public Apology Date within Judgment				15 days
Claims associated with Chevron complaint against Lago Agrio litigation			One through eight
Chevron claim for declaratory relief related to Lago Agrio litigation			Ninth
Proposed additional payment for plaintiff attorney fees as percentage of judgement			0.10%
MTBE [Member]
Loss Contingencies [Line Items]
Pending lawsuits and claims \| LegalMatter			8

Taxes (Details) - USD ($) $ in Millions	12 Months Ended
Taxes (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
U.S. Federal
Current	$ 1,893	$ 1,501	$ 128
Deferred	877	162	(147)
State and local
Current	596	376	216
Deferred	41	20	14
Total United States	3,407	2,059	211
International
Current	16,548	10,483	7,154
Deferred	671	377	600
Total International	17,219	10,860	7,754
Total taxes on income	$ 20,626	$ 12,919	$ 7,965
Reconciliation between the U.S. statutory federal income tax rate and the company's effective income tax rate
U.S. statutory federal income tax rate	35.00%	35.00%	35.00%
Effect of income taxes from international operations at rates different from the U.S. statutory rate	7.50%	5.20%	10.40%
State and local taxes on income, net of U.S. federal income tax benefit	0.90%	0.80%	0.90%
Prior-year tax adjustments	(0.10%)	(0.60%)	(0.30%)
Tax credits	(0.40%)	(0.50%)	(1.10%)
Effects of changes in tax rates	0.50%		0.10%
Other	(0.10%)	0.40%	(2.00%)
Effective tax rate	43.30%	40.30%	43.00%

Taxes (Details 1) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Deferred tax liabilities
Properties, plant and equipment	$ 23,597	$ 19,855
Investments and other	2,271	2,401
Total deferred tax liabilities	25,868	22,256
Deferred tax assets
Foreign tax credits	(8,476)	(6,669)
Abandonment/environmental reserves	(5,387)	(5,004)
Employee benefits	(4,773)	(3,627)
Deferred credits	(1,548)	(2,176)
Tax loss carryforwards	(828)	(882)
Other accrued liabilities	(531)	(486)
Inventory	(360)	(483)
Miscellaneous	(1,595)	(1,676)
Total deferred tax assets	(23,498)	(21,003)
Deferred tax assets valuation allowance	11,096	9,185
Total deferred taxes, net	13,466	10,438
Classification of deferred taxes
Prepaid expenses and other current assets	(1,149)	(1,624)
Deferred charges and other assets	(1,224)	(851)
Federal and other taxes on income	(295)	(216)
Noncurrent deferred income taxes	15,544	12,697
Total deferred taxes, net	$ 13,466	$ 10,438

Taxes (Details 2) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Balance at January 1

$ 3,507

$ 3,195

$ 2,696

Foreign currency effects

(2)

(1)

Additions based on tax positions taken in current year

469

334

459

Reductions based on tax positions taken in current year

Additions/reductions resulting from current-year asset acquisitions/sales

(41)

Additions for tax positions taken in prior years

236

270

533

Reductions for tax positions taken in prior years

(366)

(165)

(182)

Settlements with taxing authorities in current year

(318)

(136)

(300)

Reductions as a result of a lapse of the applicable statute of limitations

(4)

(8)

(10)

Balance at December 31

3,481

3,507

3,195

Taxes other than on income

8,085

8,591

8,109

Total taxes other than on income

^[1]

15,628

18,191

17,591

United States

Taxes other than on income

4,199

4,484

4,573

Import duties and other levies

(4)

Property and other miscellaneous taxes

726

567

584

Payroll taxes

236

219

223

Taxes on production

308

271

135

Total taxes other than on income

5,473

5,541

5,511

International

Taxes other than on income

3,886

4,107

3,536

Import duties and other levies

3,511

6,183

6,550

Property and other miscellaneous taxes

2,354

2,000

1,740

Payroll taxes

148

133

134

Taxes on production

256

227

120

Total taxes other than on income

$ 10,155

$ 12,650

$ 12,080

[1]	Includes excise, value-added and similar taxes.

Taxes (Details Textual) - USD ($) $ in Millions	12 Months Ended
Taxes (Details Textual) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Income Taxes (Textual) [Abstract]
Income before income tax including related corporate and other charges for U.S. operations	$ 10,222	$ 6,528	$ 1,310
Income before Income Tax for International Operations	37,412	25,527	17,218
Income Tax Credits and Adjustments	$ 191	$ 162	$ 204
Effective Tax Rates	43.30%	40.30%	43.00%
Approximate increase in deferred tax liabilities	$ 3,600
Approximate Increase in Deferred Tax Assets	2,500
Loss Carry forwards	2,160
Carry forward amount of foreign tax credit with expiration dates	8,476	$ 6,669
Undistributed earnings of international consolidated subsidiaries and affiliates for which no deferred income tax provision has been made for future remittances	$ 24,376
Recognition of uncertain tax position under accounting standards for uncertainty in income taxes.	greater than 50 percent
Percentage of impact of unrecognized tax benefits on effective tax rate if subsequently recognized.	80.00%
Unrecognized Tax Benefits	$ 3,481	3,507	$ 3,195	$ 2,696
Income tax accruals for anticipated interest and penalty obligations	118	225
Income tax benefit expense associated with interest and penalties	$ (64)	$ 40	$ (20)
Tax Credit Carry forward Expiration Dates	2012-2021
Tax Loss Carry Forwards	2012-2036

Short-Term Debt (Details) - USD ($) $ in Millions	12 Months Ended
Short-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Short term borrowings
Commercial Paper	$ 2,498	$ 2,471
Notes payable to banks and others with originating terms of one year or less	40	43
Current maturities of long-term debt	17	33
Current maturities of long-term capital leases	54	81
Redeemable long term obligations - Long-Term Debt	3,317	2,943
Redeemable long term obligations - Capital Leases	14	16
Subtotal	5,940	5,587
Reclassified to long-term debt	(5,600)	(5,400)
Total short-term debt	$ 340	$ 187

Short-Term Debt (Details Textual) - USD ($) $ in Millions	12 Months Ended
Short-Term Debt (Details Textual) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Short-Term Debt (Textual)
Weighted-average interest rates of commercial paper	0.04%	0.16%
Tax Exempt Bond Issued Pascagoula Refinery	$ 374
Committed credit facilities	6,000
Reclassified to long-term debt	$ 5,600	$ 5,400
Committed credit facilities expiry date	Dec-2016

Long-Term Debt (Details) - USD ($) $ in Millions	12 Months Ended
Long-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Debt Instrument [Line Items]
Long-term debt instruments	$ 4,101	$ 5,636
Debt due within one year	(17)	(33)
Reclassified from Short-Term Debt	5,600	5,400
Total Long-Term Debt	9,684	11,003
Long-Term Debt (Textual) [Abstract]
Total Long-Term Debt	9,684	11,003
Long-term debt instruments	4,101	5,636
Long-term debt maturing 2012	17
Long-term debt maturing 2013	20
Long-term debt maturing 2014	2,021
Long-term debt maturing 2015	0
Long-term debt maturing 2016	0
Long-term debt maturing after 2016	2,043
Total bonds redeemed in 2011	1,500
Tax Exempt Bond Issued Pascagoula Refinery	374
Texaco Capital Inc Bonds Matured in 2010		30
3.95% notes due 2014 [Member]
Debt Instrument [Line Items]
Long-term debt instruments	1,998	1,998
Long-Term Debt (Textual) [Abstract]
Long-term debt instruments	1,998	1,998
3.45% notes due 2012 [Member]
Debt Instrument [Line Items]
Long-term debt instruments	0	1,500
Long-Term Debt (Textual) [Abstract]
Long-term debt instruments	0	1,500
4.95% notes due 2019 [Member]
Debt Instrument [Line Items]
Long-term debt instruments	1,500	1,500
Long-Term Debt (Textual) [Abstract]
Long-term debt instruments	1,500	1,500
8.625% debentures due 2032 [Member]
Debt Instrument [Line Items]
Long-term debt instruments	147	147
Long-Term Debt (Textual) [Abstract]
Long-term debt instruments	147	147
8.625 % debentures due 2031 [Member]
Debt Instrument [Line Items]
Long-term debt instruments	107	107
Long-Term Debt (Textual) [Abstract]
Long-term debt instruments	107	107
7.5 % debentures due 2043 [Member]
Debt Instrument [Line Items]
Long-term debt instruments	83	83
Long-Term Debt (Textual) [Abstract]
Long-term debt instruments	83	83
8 % debentures due 2032 [Member]
Debt Instrument [Line Items]
Long-term debt instruments	74	74
Long-Term Debt (Textual) [Abstract]
Long-term debt instruments	74	74
7.327% amortizing notes due 2014 [Member]
Debt Instrument [Line Items]
Long-term debt instruments	59	72
Long-Term Debt (Textual) [Abstract]
Long-term debt instruments	59	72
9.75 % debentures due 2020 [Member]
Debt Instrument [Line Items]
Long-term debt instruments	54	54
Long-Term Debt (Textual) [Abstract]
Long-term debt instruments	54	54
8.875 % debentures due 2021 [Member]
Debt Instrument [Line Items]
Long-term debt instruments	40	40
Long-Term Debt (Textual) [Abstract]
Long-term debt instruments	40	40
Medium-term notes, maturing from 2021 to 2038 (6.02%) [Member]
Debt Instrument [Line Items]
Long-term debt instruments	38	38
Long-Term Debt (Textual) [Abstract]
Long-term debt instruments	38	38
Fixed interest rate notes, maturing 2011(9.378%) [Member]
Debt Instrument [Line Items]
Long-term debt instruments	0	19
Long-Term Debt (Textual) [Abstract]
Long-term debt instruments	0	19
Other long-term debt (8.07%) [Member]
Debt Instrument [Line Items]
Long-term debt instruments	1	4
Long-Term Debt (Textual) [Abstract]
Long-term debt instruments	$ 1	$ 4

Accounting for Suspended Exploratory Wells (Details) $ in Millions	12 Months Ended
	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)	Dec. 31, 2011 USD ($) Project	Dec. 31, 2010 USD ($) Project	Dec. 31, 2009 USD ($) Project
Changes in company's suspended exploratory well costs
Beginning balance at January 1	$ 2,718	$ 2,435	$ 2,118
Additions to capitalized exploratory well costs pending the determination of proved reserves	652	482	663
Reclassifications to wells, facilities and equipment based on the determination of proved reserves	(828)	(129)	(174)
Capitalized exploratory well costs charged to expense	(45)	(70)	(172)
Other reductions	(63)
Ending balance at December 31	2,434	2,718	2,435
Aging of capitalized well costs and number of project
Exploratory well costs capitalized for a period of one year or less				$ 557	$ 419	$ 564
Exploratory well costs capitalized for a period greater than one year				1,877	2,299	1,871
Balance at December 31	$ 2,718	$ 2,435	$ 2,118	$ 2,434	$ 2,718	$ 2,435
Number of projects with exploratory well costs that have been capitalized for a period greater than one year \| Project				47	53	46

Accounting for Suspended Exploratory Wells (Details 1) $ in Millions	Dec. 31, 2011 USD ($) Project Well	Dec. 31, 2010 USD ($) Project	Dec. 31, 2009 USD ($) Project
Aging costs on well and project basis
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year, Total	$ 1,877	$ 2,299	$ 1,871
Total number of exploratory wells that have been capitalized for period greater Than one year \| Well	161
Projects that have Exploratory Well Costs that have been Capitalized for Period Greater than One Year, Number of Projects, Total \| Project	47	53	46
1997-2000 [Member]
Aging costs on well and project basis
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year, Total	$ 49
Aging of exploratory well costs capitalized for more than one year based on drilling completion date of individual wells 1997 to 2000 number of wells \| Well	16
2001-2005 [Member]
Aging costs on well and project basis
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year, Total	$ 396
Aging of exploratory well costs capitalized for more than one year based on drilling completion date of individual wells 2001 to 2005 number of wells \| Well	47
2006-2010 [Member]
Aging costs on well and project basis
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year, Total	$ 1,432
Aging of exploratory well costs capitalized for more than one year based on drilling completion date of individual wells 2006 to 2010 number of wells \| Well	98
1999 [Member]
Aging costs on well and project basis
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year, Total	$ 8
Projects that have Exploratory Well Costs that have been Capitalized for Period Greater than One Year, Number of Projects, Total \| Project	1
2003-2006 [Member]
Aging costs on well and project basis
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year, Total	$ 345
Projects that have Exploratory Well Costs that have been Capitalized for Period Greater than One Year, Number of Projects, Total \| Project	10
2007-2011 [Member]
Aging costs on well and project basis
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year, Total	$ 1,524
Projects that have Exploratory Well Costs that have been Capitalized for Period Greater than One Year, Number of Projects, Total \| Project	36

Accounting for Suspended Exploratory Wells (Details Textual) $ in Millions	Dec. 31, 2011 USD ($) Project yr Well	Dec. 31, 2010 USD ($) Project	Dec. 31, 2009 USD ($) Project
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year, Total \| $	$ 1,877	$ 2,299	$ 1,871
Number of projects with exploratory well costs that have been capitalized for a period greater than one year	47	53	46
Expected period for decision on the recognition of proved reserves \| yr	3
Accounting for Suspended Exploratory Wells (Textual) [Abstract]
Exploratory well costs capitalized for a period greater than one year \| $	$ 1,877	$ 2,299	$ 1,871
Capitalized Exploratory Well Costs Associated with project sanction approved and construction in progress, with initial recognition of proved reserves expected upon reaching economic producibility \| $	$ 111
Total number of exploratory wells that have been capitalized for period greater Than one year \| Well	161
Number of projects with exploratory well costs that have been capitalized for a period greater than one year	47	53	46
Project [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Number of projects with exploratory well costs that have been capitalized for a period greater than one year	1
Accounting for Suspended Exploratory Wells (Textual) [Abstract]
Number of projects with exploratory well costs that have been capitalized for a period greater than one year	1
Drilling Activity [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year, Total \| $	$ 939
Accounting for Suspended Exploratory Wells (Textual) [Abstract]
Exploratory well costs capitalized for a period greater than one year \| $	$ 939
Drilling Activity [Member] \| Project [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Number of projects with exploratory well costs that have been capitalized for a period greater than one year	26
Accounting for Suspended Exploratory Wells (Textual) [Abstract]
Number of projects with exploratory well costs that have been capitalized for a period greater than one year	26
No Drilling Activity [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year, Total \| $	$ 938
Accounting for Suspended Exploratory Wells (Textual) [Abstract]
Exploratory well costs capitalized for a period greater than one year \| $	$ 938
No Drilling Activity [Member] \| Project [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Number of projects with exploratory well costs that have been capitalized for a period greater than one year	21
Accounting for Suspended Exploratory Wells (Textual) [Abstract]
Number of projects with exploratory well costs that have been capitalized for a period greater than one year	21
Development Concept Under Review by Government [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year, Total \| $	$ 283
Accounting for Suspended Exploratory Wells (Textual) [Abstract]
Exploratory well costs capitalized for a period greater than one year \| $	$ 283
Development Concept Under Review by Government [Member] \| Project [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Number of projects with exploratory well costs that have been capitalized for a period greater than one year	5
Accounting for Suspended Exploratory Wells (Textual) [Abstract]
Number of projects with exploratory well costs that have been capitalized for a period greater than one year	5
Miscellaneous Activities [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year, Total \| $	$ 14
Accounting for Suspended Exploratory Wells (Textual) [Abstract]
Exploratory well costs capitalized for a period greater than one year \| $	$ 14
Miscellaneous Activities [Member] \| Project [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Number of projects with exploratory well costs that have been capitalized for a period greater than one year	2
Accounting for Suspended Exploratory Wells (Textual) [Abstract]
Number of projects with exploratory well costs that have been capitalized for a period greater than one year	2
Reviewing Development Alternatives [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year, Total \| $	$ 322
Accounting for Suspended Exploratory Wells (Textual) [Abstract]
Exploratory well costs capitalized for a period greater than one year \| $	$ 322
Reviewing Development Alternatives [Member] \| Project [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Number of projects with exploratory well costs that have been capitalized for a period greater than one year	6
Accounting for Suspended Exploratory Wells (Textual) [Abstract]
Number of projects with exploratory well costs that have been capitalized for a period greater than one year	6
Undergoing Front End Engineering and Design with Final Investment Decision Expected [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year, Total \| $	$ 208
Accounting for Suspended Exploratory Wells (Textual) [Abstract]
Exploratory well costs capitalized for a period greater than one year \| $	$ 208
Undergoing Front End Engineering and Design with Final Investment Decision Expected [Member] \| Project [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Number of projects with exploratory well costs that have been capitalized for a period greater than one year	7
Undergoing front-end engineering and design with final investment decision expected in three years \| yr	3
Accounting for Suspended Exploratory Wells (Textual) [Abstract]
Number of projects with exploratory well costs that have been capitalized for a period greater than one year	7

Stock Options and Other Share-Based Compensation (Details) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2011 USD ($) yr $ / shares shares	Dec. 31, 2010 yr $ / shares shares	Dec. 31, 2009 yr $ / shares
Stock Option
Expected term in years \| yr	6.2	6.1	6.0
Volatility	31.00%	30.80%	30.20%
Risk-free interest rate based on zero coupon U.S. treasury note	2.60%	2.90%	2.10%
Dividend yield	3.60%	3.90%	3.20%
Weighted-average fair value per option granted	$ 21.24	$ 16.28	$ 15.36
Restored Options
Expected term in years \| yr	1.2	1.2	1.2
Volatility	20.60%	38.90%	45.00%
Risk-free interest rate based on zero coupon U.S. treasury note	0.70%	0.60%	1.10%
Dividend yield	3.40%	3.80%	3.50%
Weighted-average fair value per option granted	$ 7.55	$ 12.91	$ 12.38
Summary of option activity
Shares Outstanding at January 1, 2011 \| shares	74,852
Weighted-Average Exercise Price of shares Outstanding at January 1, 2011	$ 67.04
Shares Granted \| shares	14,260
Weighted-Average Exercise Price Granted	$ 94.46
Shares Exercised \| shares	(15,844)
Weighted-Average Exercise Price Exercised	$ 60.20
Shares Restored \| shares	33
Weighted-Average Exercise Price Restored	$ 103.96
Shares Forfeited \| shares	(953)
Weighted-Average Exercise Price Forfeited	$ 85.79
Shares Outstanding at December 31, 2011 \| shares	72,348	74,852
Weighted-Average Exercise Price of shares Outstanding at December 31, 2011	$ 73.71	$ 67.04
Weighted-Remaining Contractual Term Outstanding at December 31, 2011 \| yr	6.4
Aggregate Intrinsic Value Outstanding at December 31, 2011 \| $	$ 2,365
Shares Exercisable at December 31, 2011 \| shares	45,494
Weighted-Average Exercise Price of shares Exercisable at December 31, 2011	$ 67.84
Weighted-Remaining Contractual Term of shares Exercisable at December 31, 2011 \| yr	5.3
Aggregate Intrinsic Value of shares Exercisable at December 31, 2011 \| $	$ 1,755

Stock Options and Other Share-Based Compensation (Details 1) $ in Millions	12 Months Ended
	Dec. 31, 2011 USD ($) yr shares	Dec. 31, 2010 USD ($) shares	Dec. 31, 2009 USD ($)
Stock Options and Other Share Based Compensation (Textual) [Abstract]
Compensation expense for stock options	$ 265	$ 229	$ 182
After tax compensation expense for stock options	172	149	119
Compensation expense for stock appreciation rights restricted stock performance units and restricted stock units	214	194	170
Compensation expense for stock appreciation rights, restricted stock, performance units and restricted stock units, After tax	139	126	110
Cash received in payment for option exercises	948	385	147
Tax benefits realized for the tax deductions from option exercises	121	66	25
Cash paid to settle performance units and stock appreciation rights	$ 151	140	89
Maximum number of share that may be issued under LTIP from April 2004 through January 2014 \| shares	160,000,000
Maximum number of shares that may be issued under the LTIP from April 2004 through January 2014 in a form other than a stock option, stock appreciation right or award requiring full payment for shares by the award recipient \| shares	64,000,000
Contractual lives for major types of awards outstanding under LTIP	vary between three years for the performance units and 10 years for the stock options and stock appreciation rights
Contractual lives of options granted under Texaco SIP (In Years) \| yr	10
Exercise period after date of grant under Texaco SIP	180 days
Total intrinsic value options exercised	$ 668	$ 259	$ 91
Total before-tax compensation cost related to nonvested share-based compensation arrangements	$ 265
Weighted-average period of recognition of unrecognized compensation cost related to nonvested share-based compensation arrangements (In Years) \| yr	1.7
Number of LTIP performance units outstanding \| shares	2,881,836	2,727,874
Number of LTIP performance units granted \| shares	1,011,200
Number of LTIP performance units vested outstanding \| shares	810,071
Number of LTIP performance units forfeited \| shares	47,167
Fair value of the liability recorded for LTIP performance units outstanding	$ 294
Equivalent shares granted under various LTIP and former Texaco and Unocal programs for outstanding stock appreciation rights and other awards \| shares	2,200,000
Liability recorded for Equivalent shares granted under various LTIP and former Texaco and Unocal programs for outstanding stock appreciation rights and other awards	$ 62

Employee Benefit Plans (Details) - USD ($) $ in Millions	12 Months Ended
Employee Benefit Plans (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
U.S. [Member]
Change in Benefit Obligation
Benefit obligation at January 1	$ 10,271	$ 9,664
Service cost	374	337	$ 266
Interest cost	463	486	481
Actuarial loss (gain)	1,920	568
Benefits paid	(863)	(784)
Benefit obligation at December 31	12,165	10,271	9,664
Change in Plan Assets
Fair value of plan assets at January	8,579	7,304
Actual return on plan assets	(143)	867
Contributions to employee pension plans	1,147	1,192
Benefits paid	(863)	(784)
Fair value of plan assets at December 31	8,720	8,579	7,304
Funded Status at December 31	(3,445)	(1,692)
International [Member]
Change in Benefit Obligation
Benefit obligation at January 1	5,070	4,715
Service cost	174	153	128
Interest cost	325	307	292
Plan participants contributions	6	7
Plan amendments	27
Actuarial loss (gain)	318	200
Foreign currency exchange rate changes	(98)	(17)
Benefits paid	(303)	(295)
Benefit obligation at December 31	5,519	5,070	4,715
Change in Plan Assets
Fair value of plan assets at January	3,503	3,235
Actual return on plan assets	118	361
Foreign currency exchange rate changes	(66)	(63)
Contributions to employee pension plans	319	258
Plan participants contributions	6	7
Benefits paid	(303)	(295)
Fair value of plan assets at December 31	3,577	3,503	3,235
Funded Status at December 31	(1,942)	(1,567)
Other Benefits [Member]
Change in Benefit Obligation
Benefit obligation at January 1	3,605	3,065
Service cost	58	39	43
Interest cost	180	175	180
Plan participants contributions	148	147
Plan amendments		12
Curtailments	(10)
Actuarial loss (gain)	149	486
Foreign currency exchange rate changes	(19)	11
Benefits paid	(346)	(330)
Benefit obligation at December 31	3,765	3,605	3,065
Change in Plan Assets
Fair value of plan assets at January	0	0
Contributions to employee pension plans	198	183
Plan participants contributions	148	147
Benefits paid	(346)	(330)
Fair value of plan assets at December 31	0	0	$ 0
Funded Status at December 31	$ (3,765)	$ (3,605)

Employee Benefit Plans (Details 1) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Consolidated Balance Sheet for pension and other postretirement benefit plans
Reserves for employee benefit plans	$ (9,156)	$ (6,696)
U.S. [Member]
Consolidated Balance Sheet for pension and other postretirement benefit plans
Deferred charges and other assets	5	7
Accrued liabilities	(72)	(134)
Reserves for employee benefit plans	(3,378)	(1,565)
Net amount recognized at December 31	(3,445)	(1,692)
International [Member]
Consolidated Balance Sheet for pension and other postretirement benefit plans
Deferred charges and other assets	116	77
Accrued liabilities	(84)	(71)
Reserves for employee benefit plans	(1,974)	(1,573)
Net amount recognized at December 31	(1,942)	(1,567)
Other Benefits [Member]
Consolidated Balance Sheet for pension and other postretirement benefit plans
Deferred charges and other assets	0	0
Accrued liabilities	(222)	(225)
Reserves for employee benefit plans	(3,543)	(3,380)
Net amount recognized at December 31	$ (3,765)	$ (3,605)

This represents the noncurrent liability for underfunded plans recognized in the balance sheet that is associated with the defined benefit pension plans and other postretirement defined benefit plans.

Employee Benefit Plans (Details 2) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Before tax basis amount in accumulated other comprehensive loss.
Total recognized at December 31	$ 9,279	$ 6,749
U.S. [Member]
Before tax basis amount in accumulated other comprehensive loss.
Net actuarial loss	5,982	3,919
Prior service (credit) costs	(44)	(52)
Total recognized at December 31	5,938	3,867
International [Member]
Before tax basis amount in accumulated other comprehensive loss.
Net actuarial loss	2,250	1,903
Prior service (credit) costs	152	179
Total recognized at December 31	2,402	2,082
Other Benefits [Member]
Before tax basis amount in accumulated other comprehensive loss.
Net actuarial loss	1,002	935
Prior service (credit) costs	(63)	(135)
Total recognized at December 31	$ 939	$ 800

Amount related to the pretax cost of benefit changes attributable to plan participants' prior service pursuant to a plan amendment or a plan initiation, which has not yet been recognized as components of net periodic benefit cost.