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Income from equity affiliates

^[1]

$ 198,198

$ 167,402

$ 264,958

5,637

3,316

5,366

Other income

1,093

918

2,681

Total Revenues and Other Income

204,928

171,636

273,005

Costs and Other Deductions

Purchased crude oil and products

116,467

99,653

171,397

Operating expenses

19,188

17,857

20,795

Selling, general and administrative expenses

4,767

4,527

5,756

Exploration expenses

1,147

1,342

1,169

Depreciation, depletion and amortization

13,063

12,110

9,528

Taxes other than on income

^[1]

18,191

17,591

21,303

Interest and debt expense

Total Costs and Other Deductions

172,873

153,108

229,948

Income Before Income Tax Expense

32,055

18,528

43,057

Income Tax Expense

12,919

7,965

19,026

Net Income

19,136

10,563

24,031

Less: Net income attributable to noncontrolling interests

112

100

Net Income Attributable to Chevron Corporation

$ 19,024

$ 10,483

$ 23,931

Per Share of Common Stock

Net Income Attributable to Chevron Corporation - Basic

$ 9.53

$ 5.26

$ 11.74

Net Income Attributable to Chevron Corporation - Diluted

$ 9.48

$ 5.24

$ 11.67

Includes excise, value-added and similar taxes

$ 8,591

$ 8,109

$ 9,846

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

Consolidated Statement of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Consolidated Statement of Comprehensive Income [Abstract]
Net Income	$ 19,136	$ 10,563	$ 24,031
Currency translation adjustment
Unrealized net change arising during period	6	60	(112)
Unrealized holding (loss) gain on securities
Net (loss) gain arising during period	(4)	2	(6)
Derivatives
Net derivatives gain (loss) on hedge transactions	25	(69)	139
Reclassification to net income of net realized loss (gain)	5	(23)	32
Income taxes on derivatives transactions	(10)	32	(61)
Total	20	(60)	110
Actuarial loss
Amortization to net income of net actuarial loss	635	575	483
Actuarial loss arising during period	(857)	(1,099)	(3,228)
Prior service cost
Amortization to net income of net prior service credits	(61)	(65)	(64)
Prior service cost arising during period	(12)	(34)	(32)
Defined benefit plans sponsored by equity affiliates	(12)	65	(97)
Income taxes on defined benefit plans	140	159	1,037
Total	(167)	(399)	(1,901)
Other Comprehensive Loss, Net of Tax	(145)	(397)	(1,909)
Comprehensive Income	18,991	10,166	22,122
Comprehensive income attributable to noncontrolling interests	(112)	(80)	(100)
Comprehensive Income Attributable to Chevron Corporation	$ 18,879	$ 10,086	$ 22,022

Consolidated Balance Sheet - USD ($) $ in Millions	Dec. 31, 2010	Dec. 31, 2009
Assets
Cash and cash equivalents	$ 14,060	$ 8,716
Time deposits	2,855	0
Marketable securities	155	106
Accounts and notes receivable (less allowance: 2010 - $184; 2009 - $228)	20,759	17,703
Inventories:
Crude oil and petroleum products	3,589	3,680
Chemicals	395	383
Materials, supplies and other	1,509	1,466
Total inventories	5,493	5,529
Prepaid expenses and other current assets	5,519	5,162
Total Current Assets	48,841	37,216
Long-term receivables, net	2,077	2,282
Investments and advances	21,520	21,158
Properties, plant and equipment, at cost	207,367	188,288
Less: Accumulated depreciation, depletion and amortization	102,863	91,820
Properties, plant and equipment, net	104,504	96,468
Deferred charges and other assets	3,210	2,879
Goodwill	4,617	4,618
Total Assets	184,769	164,621
Liabilities and Equity
Short-term debt	187	384
Accounts payable	19,259	16,437
Accrued liabilities	5,324	5,375
Federal and other taxes on income	2,776	2,624
Other taxes payable	1,466	1,391
Total Current Liabilities	29,012	26,211
Long-term debt	11,003	9,829
Capital lease obligations	286	301
Deferred credits and other noncurrent obligations	19,264	17,390
Noncurrent deferred income taxes	12,697	11,521
Reserves for employee benefit plans	6,696	6,808
Total Liabilities	78,958	72,060
Preferred stock (authorized 100,000,000 shares, $1.00 par value; none issued)	0	0
Common stock (authorized 6,000,000,000 shares; $.75 par value; 2,442,676,580 shares issued at December 31, 2010 and 2009)	1,832	1,832
Capital in excess of par value	14,796	14,631
Retained earnings	119,641	106,289
Accumulated other comprehensive loss	(4,466)	(4,321)
Deferred compensation and benefit plan trust	(311)	(349)
Treasury stock, at cost (2010 435,195,799 shares; 2009 434,954,774 shares)	(26,411)	(26,168)
Total Chevron Corporation Stockholders' Equity	105,081	91,914
Noncontrolling interests	730	647
Total Equity	105,811	92,561
Total Liabilities and Equity	$ 184,769	$ 164,621

Consolidated Balance Sheet (Parenthetical) - USD ($)	Dec. 31, 2010	Dec. 31, 2009
Assets
Allowance for accounts and notes receivables	$ 184,000,000	$ 228,000,000
Liabilities and Equity
Preferred stock, par value	$ 1	$ 1
Preferred stock, shares authorized	100,000,000	100,000,000
Preferred stock, shares issued	0	0
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	435,195,799	434,954,774

Consolidated Statement of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Operating Activities
Net Income	$ 19,136	$ 10,563	$ 24,031
Adjustments
Depreciation, depletion and amortization	13,063	12,110	9,528
Dry hole expense	496	552	375
Distributions less than income from equity affiliates	(501)	(103)	(440)
Net before-tax gains on asset retirements and sales	(1,004)	(1,255)	(1,358)
Net foreign currency effects	251	466	(355)
Deferred income tax provision	559	467	598
Net decrease (increase) in operating working capital	76	(2,301)	(1,673)
Increase in long-term receivables	(12)	(258)	(161)
Decrease (increase) in other deferred charges	48	201	(84)
Cash contributions to employee pension plans	(1,450)	(1,739)	(839)
Other	697	670	10
Net Cash Provided by Operating Activities	31,359	19,373	29,632
Investing Activities
Capital expenditures	(19,612)	(19,843)	(19,666)
Proceeds and deposits related to asset sales	1,995	2,564	1,491
Net purchases of time deposits	(2,855)
Net (purchases) sales of marketable securities	(49)	127	483
Repayment of loans by equity affiliates	338	336	179
Net (purchases) sales of other short-term investments	(732)	244	432
Net Cash Used for Investing Activities	(20,915)	(16,572)	(17,081)
Financing Activities
Net (payments) borrowings of short-term obligations	(212)	(3,192)	2,647
Proceeds from issuances of long-term debt	1,250	5,347
Repayments of long-term debt and other financing obligations	(156)	(496)	(965)
Cash dividends - common stock	(5,674)	(5,302)	(5,162)
Distributions to noncontrolling interests	(72)	(71)	(99)
Net (purchases) sales of treasury shares	(306)	168	(6,821)
Net Cash Used for Financing Activities	(5,170)	(3,546)	(10,400)
Effect of Exchange Rate Changes on Cash and Cash Equivalents	70	114	(166)
Net Change in Cash and Cash Equivalents	5,344	(631)	1,985
Cash and Cash Equivalents at January 1	8,716	9,347	7,362
Cash and Cash Equivalents at December 31	$ 14,060	$ 8,716	$ 9,347

Consolidated Statement of Equity - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Statement [Line Items]
Beginning Balance	$ 91,914	$ 86,648
Net Income Attributable to Chevron Corporation	19,024	10,483	$ 23,931
Currency translation adjustment
Unrealized net change arising during period	6	60	(112)
Net derivatives gain (loss) on hedge transactions
Ending Balance	105,081	91,914	86,648
Noncontrolling interests	730	647	469
Total Equity	105,811	92,561	87,117
Deferred Compensation and Benefit Plan Trust
Statement [Line Items]
Beginning Balance	$ (349)	$ (434)
Shares, Beginning Balance	14,168	14,168
Net derivatives gain (loss) on hedge transactions
Deferred Compensation and Benefit Plan Trust Deffered Compensation, Beginning Balance	$ (109)	$ (194)	(214)
Net reduction of ESOP debt and other	38	85	20
Deferred Compensation and Benefit Plan Trust Deffered Compensation, Ending Balance	(71)	(109)	(194)
Benefit Plan Trust (Common Stock)	$ (240)	$ (240)	$ (240)
Benefit Plan Trust (Common Stock), shares	14,168	14,168	14,168
Ending Balance	$ (311)	$ (349)	$ (434)
Shares, Ending Balance	14,168	14,168	14,168
Preferred Stock
Statement [Line Items]
Beginning Balance	$ 0
Shares, Beginning Balance	0
Net derivatives gain (loss) on hedge transactions
Ending Balance	$ 0	$ 0
Shares, Ending Balance	0	0
Common Stock
Statement [Line Items]
Beginning Balance	$ 1,832	$ 1,832	$ 1,832
Shares, Beginning Balance	2,442,677	2,442,677	2,442,677
Net derivatives gain (loss) on hedge transactions
Ending Balance	$ 0	$ 1,832	$ 1,832
Shares, Ending Balance	0	2,442,677	2,442,677
Capital in Excess of Par
Statement [Line Items]
Beginning Balance	$ 14,631	$ 14,448	$ 14,289
Treasury stock transactions	165	183	159
Net derivatives gain (loss) on hedge transactions
Ending Balance	14,796	14,631	14,448
Treasury Stock at Cost
Statement [Line Items]
Beginning Balance	$ (26,168)	$ (26,376)	$ (18,892)
Shares, Beginning Balance	434,955	438,445	352,243
Net derivatives gain (loss) on hedge transactions
Treasury Stock at cost, Purchases	$ (775)	$ (6)	$ (8,011)
Treasury Stock at cost, Purchases, shares	9,091	85	95,631
Issuances - mainly employee benefit plans	$ 532	$ 214	$ 527
Issuances - mainly employee benefit plans, shares	(8,850)	(3,575)	(9,429)
Ending Balance	$ (26,411)	$ (26,168)	$ (26,376)
Shares, Ending Balance	435,196	434,955	438,445
Retained Earnings
Statement [Line Items]
Beginning Balance	$ 106,289	$ 101,102	$ 82,329
Net Income Attributable to Chevron Corporation	19,024	10,483	23,931
Cash dividends on common stock	(5,674)	(5,302)	(5,162)
Tax benefit from dividends paid on unallocated ESOP shares and other	2	6	4
Net derivatives gain (loss) on hedge transactions
Ending Balance	119,641	106,289	101,102
Accumulated Other Comprehensive Loss
Statement [Line Items]
Beginning Balance	(4,321)	(3,924)
Currency translation adjustment
Currency Translation Adjustment, Beginning Balance	(111)	(171)	(59)
Unrealized net change arising during period	6	60	(112)
Currency Translation Adjustment, Ending Balance	(105)	(111)	(171)
Pension and Other Postretirement Benefit Plans
Pension and Other Postretirement Benefit Plans, Beginning Balance	(4,308)	(3,909)	(2,008)
Change to defined benefit plans during year	(167)	(399)	(1,901)
Pension and Other Postretirement Benefit Plans, Ending Balance	(4,475)	(4,308)	(3,909)
Unrealized Net Holding Gain On Securities
Unrealized net holding gain on securities, Beginning Balance	15	13	19
Change during year (Unrealized net holding gain on securities)	(4)	2	(6)
Unrealized net holding gain on securities, Ending Balance	11	15	13
Net derivatives gain (loss) on hedge transactions
Net derivatives gain (loss) on hedge transactions, Beginning Balance	83	143	33
Change during year (derivatives)	20	(60)	110
Net derivatives gain (loss) on hedge transactions, Ending Balance	103	83	143
Ending Balance	$ (4,466)	$ (4,321)	$ (3,924)

Summary of Significant Accounting Policies	12 Months Ended
Summary of Significant Accounting Policies	Dec. 31, 2010
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. The nature of the company’s operations and the many countries in which it operates subject the company to changing economic, regulatory and political conditions. The company does not believe it is vulnerable to the risk of near-term severe impact as a result of any concentration of its activities. Subsidiary and Affiliated Companies The Consolidated Financial Statements include the accounts of controlled subsidiary companies more than 50 percent-owned and 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 (LIFO) 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-50, 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 generally done on the basis of a refinery, a plant, a marketing area or marketing assets by country. 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-37, relating to fair value measurements. As required under accounting standards for asset retirement obligations (Accounting Standards Codification (ASC) 410), 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-62, 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. Depreciation and depletion expenses for mining assets are determined using the unit-of-production method as the proved reserves are produced. 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 generally is 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 a 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, following accounting standards for asset retirement and environmental obligations. Refer to Note 25, on page FS-62, 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-27. 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.

Agreement to Acquire Atlas Energy, Inc.	12 Months Ended
Agreement to Acquire Atlas Energy, Inc.	Dec. 31, 2010
Agreement to Acquire Atlas Energy, Inc. [Abstract]
Agreement to Acquire Atlas Energy, Inc.	Note 2 Agreement to Acquire Atlas Energy, Inc. In November 2010, Chevron announced plans to acquire Atlas Energy, Inc. The acquisition was completed in February 2011 for $4,470, including assumed debt. The acquisition will be accounted for as a business combination (ASC 805). Atlas holds one of the premier acreage positions in the Marcellus Shale, concentrated in southwestern Pennsylvania.

Noncontrolling Interests

12 Months Ended

Dec. 31, 2010

Noncontrolling Interests [Abstract]

Noncontrolling Interests

Note 3

Noncontrolling Interests

The company adopted accounting standards 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 2010, 2009 and 2008 is as follows:


	2010			2009			2008

Balance at January 1	$	647		$	469		$	204
Net income		112			80			100
Distributions to noncontrolling interests		(72	)		(71	)		(99	)
Other changes, net		43			169			264

Balance at December 31	$	730		$	647		$	469

Information Relating to the Consolidated Statement of Cash Flows

12 Months Ended

Dec. 31, 2010

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

Information Relating to the Consolidated Statement of Cash Flows

Note 4

Information Relating to the Consolidated Statement of Cash Flows


	Year ended December 31
	2010			2009			2008

Net decrease (increase) in operating working capital was composed of the following:
(Increase) decrease in accounts and notes receivable	$	(2,767	)	$	(1,476	)	$	6,030
Decrease (increase) in inventories		15			1,213			(1,545	)
Increase in prepaid expenses and other current assets		(542	)		(264	)		(621	)
Increase (decrease) in accounts payable and accrued liabilities		3,049			(1,121	)		(4,628	)
Increase (decrease) in income and other taxes payable		321			(653	)		(909	)

Net decrease (increase) in operating working capital	$	76		$	(2,301	)	$	(1,673	)

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	$	11,749		$	7,537		$	19,130

Net sales of marketable securities consisted of the following gross amounts:
Marketable securities sold	$	41		$	157		$	3,719
Marketable securities purchased		(90	)		(30	)		(3,236	)

Net (purchases) sales of marketable securities	$	(49	)	$	127		$	483

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

Net purchases of time deposits	$	(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 $67, $25 and $106 for excess income tax benefits associated with stock options exercised during 2010, 2009 and 2008, respectively. These amounts are offset by an equal amount in “Net (purchases) sales of treasury shares.”

The “Net (purchases) sales of treasury shares” represents the cost of common shares purchased less the cost of shares issued for share-based compensation plans. Purchases totaled $775, $6 and $8,011 in 2010, 2009 and 2008, respectively. Purchases in 2010 and 2008 included shares purchased under the company’s common stock repurchase programs.

In 2010, “Net (purchases) sales of other short-term investments” consist of restricted cash associated with capital-investment projects at the company’s Pascagoula and El Segundo refineries and the Angola liquefied natural gas project 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 $1,250 and $350, in 2010 and 2009, respectively, of tax exempt bonds as a source of funds for U.S. refinery projects.

The Consolidated Statement of Cash Flows excludes changes to the Consolidated Balance Sheet that did not affect cash. In 2008, “Net (purchases) sales of treasury shares” excludes $680 of treasury shares acquired in exchange for a U.S. upstream property and $280 in cash. The carrying value of this property in “Properties, plant and equipment” on the Consolidated Balance Sheet was not significant. In 2008, a $2,450 increase in “Accrued liabilities” and a corresponding increase to “Properties, plant and equipment, at cost” were considered noncash transactions and excluded from “Net decrease (increase) in operating working capital” and “Capital expenditures.” In 2009, the payments related to these “Accrued liabilities” were excluded from “Net decrease (increase) in operating working capital” and were reported as “Capital expenditures.” The amount is related to upstream operating agreements outside the United States. “Capital expenditures” in 2008 excludes a $1,400 increase in “Properties, plant and equipment” related to the acquisition of an additional interest in an equity affiliate that required a change to the consolidated method of accounting for the investment during 2008. This addition was offset primarily by reductions in “Investments and advances” and working capital and an increase in “Non-current deferred income tax” liabilities. Refer also to Note 25, on page FS-62, 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, 2010.

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
	2010			2009		2008

Additions to properties, plant and equipment¹	$	18,474		$	16,107	$	18,495
Additions to investments		861			942		1,051
Current year dry hole expenditures		414			468		320
Payments for other liabilities and assets, net²		(137	)		2,326		(200	)

Capital expenditures		19,612			19,843		19,666
Expensed exploration expenditures		651			790		794
Assets acquired through capital lease obligations and other financing obligations		104			19		9

Capital and exploratory expenditures, excluding equity affiliates		20,367			20,652		20,469
Company’s share of expenditures by equity affiliates		1,388			1,585		2,306

Capital and exploratory expenditures, including equity affiliates	$	21,755		$	22,237	$	22,775


¹ Excludes noncash additions of $2,753 in 2010, $985 in 2009 and $5,153 in 2008.

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, 2010

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

Statement [Line Items]

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.

During 2008, Chevron implemented legal reorganizations in which certain Chevron subsidiaries transferred assets to or under CUSA. The summarized financial information for CUSA and its consolidated subsidiaries presented in the table below gives retroactive effect to the reorganizations as if they had occurred on January 1, 2008. However, the financial information in the following table may not reflect the financial position and operating results in the future or the historical results in the periods presented if the reorganization actually had occurred on that date. The summarized financial information for CUSA and its consolidated subsidiaries is as follows:


	Year ended December 31
	2010		2009		2008

Sales and other operating revenues	$	145,381	$	121,553	$	195,593
Total costs and other deductions		139,984		120,053		185,788
Net income attributable to CUSA		4,159		1,141		7,318


	At December 31
	2010		2009

Current assets	$	29,211	$	23,286
Other assets		35,294		32,827
Current liabilities		18,098		16,098
Other liabilities		16,785		14,625

Total CUSA net equity		29,622		25,390


Memo: Total debt		$ 8,284		$ 6,999

The “Net income attributable to CUSA” for the year ended December 31, 2008, has been adjusted by an immaterial amount associated with the allocation of income-tax liabilities among Chevron Corporation subsidiaries.

Summarized Financial Data - Chevron Transport Corporation Ltd.

12 Months Ended

Dec. 31, 2010

Chevron Transport Corporation [Member]

Statement [Line Items]

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
	2010			2009			2008

Sales and other operating revenues	$	885		$	683		$	1,022
Total costs and other deductions		1,008			810			947
Net (loss) income attributable to CTC		(116	)		(124	)		120


	At December 31
	2010		2009

Current assets	$	209	$	377
Other assets		201		173
Current liabilities		101		115
Other liabilities		75		90

Total CTC net equity		234		345

There were no restrictions on CTC’s ability to pay dividends or make loans or advances at December 31, 2010.

Summarized Financial Data - Tengizchevroil LLP

12 Months Ended

Dec. 31, 2010

Tengizchevroil LLP [Member]

Statement [Line Items]

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-43, for a discussion of TCO operations.

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


	Year ended December 31
	2010		2009		2008

Sales and other operating revenues	$	17,812	$	12,013	$	14,329
Costs and other deductions		8,394		6,044		5,621
Net income attributable to TCO		6,593		4,178		6,134


	At December 31
	2010		2009

Current assets	$	3,376	$	3,190
Other assets		11,813		12,022
Current liabilities		2,402		2,426
Other liabilities		4,130		4,484

Total TCO net equity		8,657		8,302

Lease Commitments

12 Months Ended

Dec. 31, 2010

Lease Commitments [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 tanker charters, crude oil production and processing equipment, service stations, 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
	2010		2009

Upstream	$	561	$	510
Downstream		316		334
All Other		169		169

Total		1,046		1,013
Less: Accumulated amortization		573		585

Net capitalized leased assets	$	473	$	428

Rental expenses incurred for operating leases during 2010, 2009 and 2008 were as follows:


	Year ended December 31
	2010		2009		2008

Minimum rentals	$	2,373	$	2,179	$	2,984
Contingent rentals		10		7		6

Total		2,383		2,186		2,990
Less: Sublease rental income		41		41		41

Net rental expense	$	2,342	$	2,145	$	2,949

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, 2010, 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: 2011		650		99
2012		530		93
2013		370		68
2014		288		51
2015		273		40
Thereafter		725		137

Total	$	2,836	$	488

Less: Amounts representing interest and executory costs				(105	)

Net present values				383
Less: Capital lease obligations included in short-term debt				(97	)

Long-term capital lease obligations			$	286

Fair Value Measurements

12 Months Ended

Dec. 31, 2010

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 financial and nonfinancial assets and liabilities that require or permit fair value measurements. 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. In 2010, the company used Level 3 inputs to determine the fair value of certain nonrecurring nonfinancial assets.

The fair value hierarchy for recurring assets and liabilities measured at fair value at December 31, 2010, and December 31, 2009, is as follows:

Assets and Liabilities Measured at Fair Value on a Recurring Basis


			Prices in Active								Prices in Active
			Markets for		Other						Markets for		Other
			Identical		Observable		Unobservable				Identical		Observable		Unobservable
	At December 31		Assets/Liabilities		Inputs		Inputs		At December 31		Assets/Liabilities		Inputs		Inputs
	2010		(Level 1)		(Level 2)		(Level 3)		2009		(Level 1)		(Level 2)		(Level 3)

Marketable securities	$	155	$	155	$	–	$	–	$	106	$	106	$	–	$	–
Derivatives		122		11		111		–		127		14		113		–

Total Recurring Assets
at Fair Value	$	277	$	166	$	111	$	–	$	233	$	120	$	113	$	–

Derivatives	$	171	$	75	$	96	$	–	$	101	$	20	$	81	$	–

Total Recurring Liabilities
at Fair Value	$	171	$	75	$	96	$	–	$	101	$	20	$	81	$	–

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, 2010.

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 virtually all the offsetting amount on 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 crude oil, natural gas and refined product futures, swaps, options and forward contracts. Derivatives classified as Level 1 include futures, swaps and options contracts traded in active markets such as the New York Mercantile Exchange.

Derivatives classified as Level 2 include swaps, options, and forward contracts principally with financial institutions and other oil and gas companies, the fair values for 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 for- ward 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” In accordance with the accounting standard for the impairment or disposal of long-lived assets (ASC 360), during 2010 and 2009 long-lived assets “held and used” with carrying amounts of $142 and $949 were written down to fair values of $57 and $490 resulting in before-tax losses of $85 and $459, respectively. The fair values were determined from internal cash flow models, using discount rates consistent with those used by the company to evaluate cash flows of other assets of a similar nature.

Long-lived assets “held for sale” with carrying amounts of $49 and $160 were written down to a fair value of $13 and $68, resulting in a before-tax loss of $36 and $92 in 2010 and 2009, respectively. The fair values were determined based on bids received from prospective buyers and from internal cash-flow models consistent with those used by the company to evaluate cash flows of other assets of a similar nature.

Impairments of “Investments and advances” In accordance with the accounting standards under the equity method of accounting (ASC 323) and the cost method of accounting (ASC 325), during 2010 and 2009 investments with carrying amounts of $15 and $81 were written down to fair values of $0 and $39 resulting in before-tax losses of $15 and $42, respectively. The fair values were determined using discount rates consistent with those used by the company to evaluate cash flows of other investments of a similar nature.

The fair value hierarchy for nonrecurring assets and liabilities measured at fair value during 2010 is presented in the following table:

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis


			Prices in Active		Other				Loss (Before Tax)				Prices in Active		Other				Loss (Before Tax)
	Year ended		Markets for		Observable		Unobservable		Year ended		Year ended		Markets for		Observable		Unobservable		Year ended
	December 31		Identical Assets		Inputs		Inputs		December 31		December 31		Identical Assets		Inputs		Inputs		December 31
	2010		(Level 1)		(Level 2)		(Level 3)		2010		2009		(Level 1)		(Level 2)		(Level 3)		2009

Properties, plant and equipment, net (held and used)	$	57	$	–	$	–	$	57	$	85	$	490	$	–	$	–	$	490	$	459
Properties, plant and equipment, net (held for sale)		13		–		–		13		36		68		–		68		–		92
Investments and advances		–		–		–		–		15		39		–		–		39		42

Total Nonrecurring Assets at Fair Value	$	70	$	–	$	–	$	70	$	136	$	597	$	–	$	68	$	529	$	593

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 $14,060 and $8,716 at December 31, 2010 and December 31, 2009, respectively. The instruments held in “Time deposits” are bank time deposits with maturities greater than 90 days and had carrying/fair values of $2,855 at December 31, 2010. The fair values of cash, cash equivalents and bank time deposits reflect the cash that would have been received or paid if the instruments were settled at year-end.

“Cash and cash equivalents” do not include investments with a carrying/fair value of $855 and $123 at December 31, 2010 and December 31, 2009, respectively. These investments are restricted funds related to an international upstream development project and U.S. refinery projects, which are reported in “Deferred charges and other assets” on the Consolidated Balance Sheet. Long-term debt of $5,636 and $5,705 had estimated fair values of $6,311 and $6,229 at December 31, 2010 and December 31, 2009, respectively.

The carrying values of short-term financial assets and liabilities on the balance sheet approximate their fair values. Fair values of other financial instruments at the end of 2010 and 2009 were not material.

Financial and Derivative Instruments

12 Months Ended

Dec. 31, 2010

Financial and Derivative Instruments [Abstract]

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, 2010, December 31, 2009 and December 31, 2008, 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


		Asset Derivatives – Fair Value				Liability Derivatives – Fair Value
Type of	Balance Sheet	At December 31		At December 31		Balance Sheet	At December 31		At December 31
Derivative Contract	Classification	2010		2009		Classification	2010		2009

Commodity	Accounts and notes receivable, net	$	58	$	99	Accrued payable	$	131	$	73
Commodity	Long-term receivable, net		64		28	Deferred credits and other noncurrent obligations		40		28

		$	122	$	127		$	171	$	101

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	2010			2009			2008


Foreign Exchange	Other income	$	–		$	26		$	(314	)

Commodity	Sales and other
	operating revenues		(98	)		(94	)		706

Commodity	Purchased crude oil
	and products		(36	)		(353	)		424

Commodity	Other income		(1	)		–			(3	)

		$	(135	)	$	(421	)	$	813

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, 2010 or 2009.

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 2010 and 2009, 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. These 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.

Operating Segments and Geographic Data

12 Months Ended

Dec. 31, 2010

Operating Segments and Geographic Data [Abstract]

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, and 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 activities reported in Chevron’s upstream and downstream operating segments have changed effective January 1, 2010. Chemicals businesses are now reported as part of the downstream segment. In addition, the company’s significant upstream-enabling operations, primarily a gas-to-liquids project and major international export pipelines, have been reclassified from the downstream segment to the upstream segment. Prior period information in this report has been revised to conform to the 2010 presentation.

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
	2010			2009			2008

Segment Earnings
Upstream
United States	$	4,122		$	2,262		$	7,147
International		13,555			8,670			15,022

Total Upstream		17,677			10,932			22,169

Downstream
United States		1,339			(121	)		1,369
International		1,139			594			1,783

Total Downstream		2,478			473			3,152

Total Segment Earnings		20,155			11,405			25,321
All Other
Interest expense		(41	)		(22	)		–
Interest income		70			46			192
Other		(1,160	)		(946	)		(1,582	)

Net Income Attributable
to Chevron Corporation	$	19,024		$	10,483		$	23,931

Segment Assets Segment assets do not include intercompany investments or intercompany receivables. Segment assets at year-end 2010 and 2009 are as follows:


	At December 31
	2010		2009

Upstream
United States	$	26,319	$	25,478
International		89,306		81,209
Goodwill		4,617		4,618

Total Upstream		120,242		111,305

Downstream
United States		21,406		20,317
International		20,559		19,618

Total Downstream		41,965		39,935

Total Segment Assets		162,207		151,240

All Other*
United States		11,125		7,125
International		11,437		6,256

Total All Other		22,562		13,381

Total Assets – United States		58,850		52,920
Total Assets – International		121,302		107,083
Goodwill		4,617		4,618

Total Assets	$	184,769	$	164,621


*“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 2010, 2009 and 2008, are presented in the table at the right. 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 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 2010, 2009 and 2008.


	Year ended December 31
	2010			2009			2008

Upstream
United States	$	10,316		$	9,225		$	23,566
Intersegment		13,839			10,297			15,162

Total United States		24,155			19,522			38,728

International		17,300			13,463			19,531
Intersegment		23,834			18,477			24,205

Total International		41,134			31,940			43,736

Total Upstream		65,289			51,462			82,464

Downstream
United States		70,436			58,056			87,759
Excise and similar taxes		4,484			4,573			4,748
Intersegment		115			98			242

Total United States		75,035			62,727			92,749

International		90,922			77,845			123,389
Excise and similar taxes		4,107			3,536			5,098
Intersegment		93			87			80

Total International		95,122			81,468			128,567

Total Downstream		170,157			144,195			221,316

All Other
United States		610			665			815
Intersegment		947			964			917

Total United States		1,557			1,629			1,732

International		23			39			52
Intersegment		39			33			33

Total International		62			72			85

Total All Other		1,619			1,701			1,817

Segment Sales and Other
Operating Revenues
United States		100,747			83,878			133,209
International		136,318			113,480			172,388

Total Segment Sales and Other
Operating Revenues		237,065			197,358			305,597
Elimination of intersegment sales		(38,867	)		(29,956	)		(40,639	)

Total Sales and Other
Operating Revenues	$	198,198		$	167,402		$	264,958


Segment Income Taxes Segment income tax expense for the years 2010, 2009 and 2008 is as follows:
	Year ended December 31
	2010			2009			2008

Upstream
United States	$	2,285		$	1,251		$	3,705
International		10,480			7,451			15,122

Total Upstream		12,765			8,702			18,827

Downstream
United States		680			(83	)		780
International		462			463			871

Total Downstream		1,142			380			1,651

All Other		(988	)		(1,117	)		(1,452	)

Total Income Tax Expense	$	12,919		$	7,965		$	19,026

Other Segment Information Additional information for the segmentation of major equity affiliates is contained in Note 12, beginning on page FS-43. Information related to properties, plant and equipment by segment is contained in Note 13, on page FS-45.

Investments and Advances

12 Months Ended

Dec. 31, 2010

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
	2010		2009		2010			2009			2008

Upstream
Tengizchevroil	$	5,789	$	5,938	$	3,398		$	2,216		$	3,220
Petropiar/Hamaca		973		1,139		262			122			317
Caspian Pipeline Consortium		974		852		124			105			103
Petroboscan		937		832		222			171			244
Angola LNG Limited		2,481		1,853		(21	)		(12	)		(8	)
Other		1,922		1,947		319			287			424

Total Upstream		13,076		12,561		4,304			2,889			4,300

Downstream
GS Caltex Corporation		2,496		2,406		158			(191	)		444
Chevron Phillips Chemical
Company LLC		2,419		2,327		704			328			158
Star Petroleum Refining
Company Ltd.		947		873		122			(4	)		22
Caltex Australia Ltd.		767		740		101			11			250
Colonial Pipeline Company		–		514		43			51			32
Other		602		540		151			149			140

Total Downstream		7,231		7,400		1,279			344			1,046

All Other
Other		509		507		54			83			20

Total equity method	$	20,816	$	20,468	$	5,637		$	3,316		$	5,366
Other at or below cost		704		690

Total investments and
advances	$	21,520	$	21,158

Total United States	$	3,769	$	4,195	$	846		$	511		$	307
Total International	$	17,751	$	16,963	$	4,791		$	2,805		$	5,059

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, 2010, the company’s carrying value of its investment in TCO was about $190 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-36, 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, 2010, the company’s carrying value of its investment in Petropiar was approximately $190 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 $974 which includes long term loans of $1,046 at year-end 2010. The loans were provided to fund 30 percent of the 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, 2010, the company’s carrying value of its investment in Petroboscan was approximately $250 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, 2010, the fair value of Chevron’s share of CAL common stock was approximately $1,970.

Colonial Pipeline Company In October 2010, the company sold its 23.4 percent equity interest in the Colonial Pipeline Company.

Other Information “Sales and other operating revenues” on the Consolidated Statement of Income includes $13,672, $10,391 and $15,390 with affiliated companies for 2010, 2009 and 2008, respectively. “Purchased crude oil and products” includes $5,559, $4,631 and $6,850 with affiliated companies for 2010, 2009 and 2008, respectively.

“Accounts and notes receivable” on the Consolidated Balance Sheet includes $1,718 and $1,125 due from affiliated companies at December 31, 2010 and 2009, respectively. “Accounts payable” includes $377 and $345 due to affiliated companies at December 31, 2010 and 2009, 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 $1,543, $2,422 and $2,820 at December 31, 2010, 2009 and 2008, respectively.


	Affiliates						Chevron Share
Year ended December 31	2010		2009		2008		2010		2009		2008

Total revenues	$	107,505	$	81,995	$	112,707	$	52,088	$	39,280	$	54,055
Income before income tax expense		18,468		11,083		17,500		7,966		4,511		7,532
Net income attributable to affiliates		12,831		8,261		12,705		5,683		3,285		5,524

At December 31

Current assets	$	30,335	$	27,111	$	25,194	$	12,845	$	11,009	$	10,804
Noncurrent assets		57,491		55,363		51,878		21,401		21,361		20,129
Current liabilities		20,428		17,450		17,727		9,363		7,833		7,474
Noncurrent liabilities		19,749		21,531		21,049		4,459		5,106		4,533

Total affiliates’ net equity	$	47,649	$	43,493	$	38,296	$	20,424	$	19,431	$	18,926

Properties, Plant and Equipment

12 Months Ended

Dec. 31, 2010

Property, Plant and Equipment [Abstract]

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 Cost²						Depreciation Expense³
	2010		2009		2008		2010		2009		2008		2010		2009		2008		2010		2009		2008

Upstream
United States	$	62,523	$	58,328	$	54,878	$	23,277	$	22,273	$	22,701	$	4,934	$	3,518	$	5,395	$	4,078	$	3,992	$	2,704
International		110,578		96,557		86,676		64,388		57,450		53,371		14,381		10,803		14,997		7,448		6,669		5,461

Total Upstream		173,101		154,885		141,554		87,665		79,723		76,072		19,315		14,321		20,392		11,526		10,661		8,165

Downstream
United States		19,820		18,962		17,397		10,379		10,032		8,908		1,199		1,874		2,061		741		666		627
International		9,697		9,852		10,021		3,948		4,154		4,266		361		456		537		451		454		482

Total Downstream		29,517		28,814		27,418		14,327		14,186		13,174		1,560		2,330		2,598		1,192		1,120		1,109

All Other⁴
United States		4,722		4,569		4,310		2,496		2,548		2,523		259		354		598		341		325		250
International		27		20		17		16		11		11		11		3		5		4		4		4

Total All Other		4,749		4,589		4,327		2,512		2,559		2,534		270		357		603		345		329		254

Total United States		87,065		81,859		76,585		36,152		34,853		34,132		6,392		5,746		8,054		5,160		4,983		3,581
Total International		120,302		106,429		96,714		68,352		61,615		57,648		14,753		11,262		15,539		7,903		7,127		5,947

Total	$	207,367	$	188,288	$	173,299	$	104,504	$	96,468	$	91,780	$	21,145	$	17,008	$	23,593	$	13,063	$	12,110	$	9,528


¹	Other than the United States and Nigeria, no other country accounted for 10 percent or more of the company’s net properties, plant and equipment (PP&E) in 2010, 2009 and 2008. Nigeria had net PP&E of $13,896, $12,463 and $10,730 for 2010, 2009 and 2008, respectively.

²	Net of dry hole expense related to prior years’ expenditures of $82, $84 and $55 in 2010, 2009 and 2008, respectively.

³	Depreciation expense includes accretion expense of $513, $463 and $430 in 2010, 2009 and 2008, respectively.

⁴	Primarily mining operations, power generation businesses, real estate assets and management information systems.

Litigation	12 Months Ended
Litigation	Dec. 31, 2010
Litigation [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 19 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 con- ducted 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 remain 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. Chevron and Texpet filed an arbitration claim in September 2009 against the Republic of Ecuador before 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 Permanent Court of Arbitration 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. 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 February 8, 2011, the Court issued a temporary restraining order 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 until March 8, 2011. Chevron’s motion for a preliminary injunction is presently before the Court. On February 14, 2011, the Provincial Court in Lago Agrio rendered an adverse judgment in the case. The Provincial Court rejected Chevron’s defenses to the extent the Court addressed them in its opinion. The judgment assesses approximately $8,600 in damages and about $900 for the plaintiffs’ representatives. It also assesses an additional amount of approximately $8,600 in punitive damages unless the company provides a public apology. Chevron continues to believe the 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 will appeal this decision in Ecuador. 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. Because Chevron has no substantial assets in Ecuador, Chevron would expect enforcement actions as a result of this judgment to be brought in other jurisdictions. Chevron expects to contest any such actions. 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 judgment, the 2008 engineer’s report and the September 2010 plaintiffs’ submission, 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, 2010

Taxes [Abstract]

Taxes

Note 15

Taxes

Income Taxes


	Year ended December 31
	2010		2009			2008

Taxes on income
U.S. Federal
Current	$	1,501	$	128		$	2,879
Deferred		162		(147	)		274
State and local
Current		376		216			528
Deferred		20		14			141

Total United States		2,059		211			3,822

International
Current		10,483		7,154			15,021
Deferred		377		600			183

Total International		10,860		7,754			15,204

Total taxes on income	$	12,919	$	7,965		$	19,026

In 2010, before-tax income for U.S. operations, including related corporate and other charges, was $6,528, compared with before-tax income of $1,310 and $10,765 in 2009 and 2008, respectively. For international operations, before-tax income was $25,527, $17,218 and $32,292 in 2010, 2009 and 2008, respectively. U.S. federal income tax expense was reduced by $162, $204 and $198 in 2010, 2009 and 2008, 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 explained in the following table:


	Year ended December 31
	2010			2009			2008

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		5.2			10.4			10.1
State and local taxes on income, net
of U.S. federal income tax benefit		0.8			0.9			1.0
Prior year tax adjustments		(0.6	)		(0.3	)		(0.1	)
Tax credits		(0.5	)		(1.1	)		(0.5	)
Effects of enacted changes in tax laws		0.0			0.1			(0.6	)
Other		0.4			(2.0	)		(0.7	)

Effective tax rate		40.3	%		43.0	%		44.2	%

The company’s effective tax rate decreased from 43.0 percent in 2009 to 40.3 percent in 2010. The rate was lower in 2010 than in 2009 primarily due to international upstream impacts. A lower effective tax rate in international upstream in 2010 was primarily driven by an increased utilization of tax credits, which had a greater impact on the rate than one-time deferred tax benefits and relatively low tax rates on asset sales in 2009. Also, a smaller portion of company income was earned in higher tax rate international upstream jurisdictions in 2010 than in 2009. Finally, foreign currency remeasurement impacts caused a reduction in the effective tax rate 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
	2010			2009

Deferred tax liabilities
Properties, plant and equipment	$	19,855		$	18,545
Investments and other		2,401			2,350

Total deferred tax liabilities		22,256			20,895

Deferred tax assets
Foreign tax credits		(6,669	)		(5,387	)
Abandonment/environmental reserves		(5,004	)		(4,424	)
Employee benefits		(3,627	)		(3,499	)
Deferred credits		(2,176	)		(3,469	)
Tax loss carryforwards		(882	)		(819	)
Other accrued liabilities		(486	)		(553	)
Inventory		(483	)		(431	)
Miscellaneous		(1,676	)		(1,681	)

Total deferred tax assets		(21,003	)		(20,263	)

Deferred tax assets valuation allowance		9,185			7,921

Total deferred taxes, net	$	10,438		$	8,553

Deferred tax liabilities at the end of 2010 increased by almost $1,400 from year-end 2009. The increase was primarily related to increased temporary differences for property, plant and equipment.

Deferred tax assets increased by approximately $700 in 2010. 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 asset retirement obligations, environmental reserves and 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. Tax loss carryforwards exist in many international jurisdictions. Whereas some of these tax loss carryforwards do not have an expiration date, others expire at various times from 2011 through 2036. Foreign tax credit carryforwards of $6,669 will expire between 2011 and 2020.

At December 31, 2010 and 2009, deferred taxes were classified on the Consolidated Balance Sheet as follows:


	At December 31
	2010			2009

Prepaid expenses and other current assets	$	(1,624	)	$	(1,825	)
Deferred charges and other assets		(851	)		(1,268	)
Federal and other taxes on income		216			125
Noncurrent deferred income taxes		12,697			11,521

Total deferred income taxes, net	$	10,438		$	8,553

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 $21,347 at December 31, 2010. 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 eventual remittance of earnings that are intended to be reinvested indefinitely. At the end of 2010, deferred income taxes were recorded for the undistributed earnings of certain international operations for which the company no longer intends to indefinitely reinvest the earnings. 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 (ASC 740-10-20) 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, 2010, 2009 and 2008. The term “unrecognized tax benefits” in the accounting standards for income taxes (ASC 740-10-20) 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.


	2010			2009			2008

Balance at January 1	$	3,195		$	2,696		$	2,199
Foreign currency effects		17			(1	)		(1	)
Additions based on tax positions taken in current year		334			459			522
Reductions based on tax positions taken in current year		–			–			(17	)
Additions/reductions resulting from current-year asset acquisitions/sales		–			–			175
Additions for tax positions taken in prior years		270			533			337
Reductions for tax positions taken in prior years		(165	)		(182	)		(246	)
Settlements with taxing authorities in current year		(136	)		(300	)		(215	)
Reductions as a result of a lapse of the applicable statute of limitations		(8	)		(10	)		(58	)

Balance at December 31	$	3,507		$	3,195		$	2,696

Approximately 80 percent of the $3,507 of unrecognized tax benefits at December 31, 2010, 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, 2010. For these jurisdictions, the latest years for which income tax examinations had been finalized were as follows: United States – 2005, Nigeria – 1994, Angola – 2001 and Saudi Arabia – 2003.

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, we are 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, 2010, accruals of $225 for anticipated interest and penalty obligations were included on the Consolidated Balance Sheet, compared with accruals of $232 as of year-end 2009. Income tax expense (benefit) associated with interest and penalties was $40, $(20) and $79 in 2010, 2009 and 2008, respectively.

Taxes Other Than on Income


	Year ended December 31
	2010		2009			2008

United States
Excise and similar taxes on products and merchandise	$	4,484	$	4,573		$	4,748
Import duties and other levies		–		(4	)		1
Property and other miscellaneous taxes		567		584			588
Payroll taxes		219		223			204
Taxes on production		271		135			431

Total United States		5,541		5,511			5,972

International
Excise and similar taxes on products and merchandise		4,107		3,536			5,098
Import duties and other levies		6,183		6,550			8,368
Property and other miscellaneous taxes		2,000		1,740			1,557
Payroll taxes		133		134			106
Taxes on production		227		120			202

Total International		12,650		12,080			15,331

Total taxes other than on income	$	18,191	$	17,591		$	21,303

Short-Term Debt

12 Months Ended

Dec. 31, 2010

Short-Term Debt [Abstract]

Short-Term Debt

Note 16

Short-Term Debt


	At December 31
	2010			2009

Commercial paper*	$	2,471		$	2,499
Notes payable to banks and others with originating terms of one year or less		43			213
Current maturities of long-term debt		33			66
Current maturities of long-term capital leases		81			76
Redeemable long-term obligations Long-term debt		2,943			1,702
Capital leases		16			18

Subtotal		5,587			4,574
Reclassified to long-term debt		(5,400	)		(4,190	)

Total short-term debt	$	187		$	384


*		Weighted-average interest rates at December 31, 2010 and 2009, were 0.16 percent and 0.08 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 within one year following the balance sheet date.

In 2010, $1,250 of tax-exempt bonds related to projects at the Pascagoula and El Segundo refineries were issued.

The company periodically enters into interest rate swaps on a portion of its short-term debt. At December 31, 2010, the company had no interest rate swaps on short-term debt.

At December 31, 2010, the company had $6,000 in committed credit facilities with various major banks, expiring in May 2013, 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, 2010.

At December 31, 2010 and 2009, the company classified $5,400 and $4,190, 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, 2010

Long-Term Debt [Abstract]

Long-Term Debt

Note 17

Long-Term Debt

Total long-term debt, excluding capital leases, at December 31, 2010, was $11,003. The company’s long-term debt outstanding at year-end 2010 and 2009 was as follows:


	At December 31
	2010			2009

3.95% notes due 2014	$	1,998		$	1,997
3.45% notes due 2012		1,500			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		72			109
9.75% debentures due 2020		54			56
8.875% debentures due 2021		40			40
8.625% debentures due 2010		–			30
Medium-term notes, maturing from
2021 to 2038 (5.97%)²		38			38
Fixed interest rate notes, maturing 2011 (9.378%)²		19			19
Other foreign currency obligations		–			–
Other long-term debt (5.66%)²		4			5

Total including debt due within one year		5,636			5,705
Debt due within one year		(33	)		(66	)
Reclassified from short-term debt		5,400			4,190

Total long-term debt	$	11,003		$	9,829


¹		Guarantee of ESOP debt.

²		Weighted-average interest rate at December 31, 2010.

Long-term debt of $5,636 matures as follows: 2011 – $33; 2012 – $1,520; 2013 – $20; 2014 – $2,020; 2015 – $0; and after 2015 – $2,043.

In 2010, $30 of bonds matured. In 2009, $5,000 of public bonds was issued, and $400 of Texaco Capital Inc. bonds matured.

See Note 9, beginning on page FS-37, for information concerning the fair value of the company’s long-term debt.

New Accounting Standards	12 Months Ended
New Accounting Standards	Dec. 31, 2010
New Accounting Standards [Abstract]
New Accounting Standards	Note 18 New Accounting Standards Transfers and Servicing (ASC 860), Accounting for Transfers of Financial Assets (ASU 2009-16) The FASB issued ASU 2009-16 in December 2009. This standard became effective for the company on January 1, 2010. ASU 2009-16 changes how companies account for transfers of financial assets and eliminates the concept of qualifying special-purpose entities. Adoption of the guidance did not have an effect on the company’s results of operations, financial position or liquidity. Consolidation (ASC 810), Improvements to Financial Reporting by Enterprises Involved With Variable Interest Entities (ASU 2009-17) The FASB issued ASU 2009-17 in December 2009. This standard became effective for the company January 1, 2010. ASU 2009-17 requires the enterprise to qualitatively assess if it is the primary beneficiary of a variable-interest entity (VIE), and if so, the VIE must be consolidated. Adoption of the standard did not have an impact on the company’s results of operations, financial position or liquidity. Receivables (ASC 310), Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses (ASU 2010-20) In July 2010, the FASB issued ASU 2010-20, which became effective with the company’s reporting at December 31, 2010. This standard amends and expands disclosure requirements about the credit quality of financing receivables and the related allowance for credit losses. As a result of these amendments, companies are required to disaggregate, by portfolio segment or class of financing receivable, certain existing disclosures and provide certain new disclosures about financing receivables and related allowance for credit losses. Adoption of the standard did not change the company’s existing disclosures.

Accounting for Suspended Exploratory Wells

12 Months Ended

Dec. 31, 2010

Accounting for Suspended Exploratory Wells [Abstract]

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 or exploratory-type stratigraphic 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, 2010:


	2010			2009			2008

Beginning balance at January 1	$	2,435		$	2,118		$	1,660
Additions to capitalized exploratory well costs pending the determination of proved reserves		482			663			643
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(129	)		(174	)		(49	)
Capitalized exploratory well costs charged to expense		(70	)		(172	)		(136	)

Ending balance at December 31	$	2,718		$	2,435		$	2,118

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
	2010		2009		2008

Exploratory well costs capitalized for a period of one year or less	$	419	$	564	$	559
Exploratory well costs capitalized for a period greater than one year		2,299		1,871		1,559

Balance at December 31	$	2,718	$	2,435	$	2,118

Number of projects with exploratory well costs that have been capitalized for a period greater than one year*		53		46		50


*		Certain projects have multiple wells or fields or both.

Of the $2,299 of exploratory well costs capitalized for more than one year at December 31, 2010, $982 (26 projects) is related to projects that had drilling activities under way or firmly planned for the near future. The $1,317 balance is related to 27 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 $1,317 referenced above had the following activities associated with assessing the reserves and the projects’ economic viability: (a) $501 (three projects) – project sanction approved and construction is in progress, with initial recognition of proved reserves expected upon reaching “economic producibility” per SEC guidelines; (b) $263 (six projects) – development alternatives under review; (c) $178 (three projects) – in process of entering contracts for front-end engineering and design; (d) $154 (three projects) – progression of development concept selection and unitization agreement; (e) $109 (five projects) – undergoing front-end engineering and design with final investment decision expected in 2011; (f) $73 (two projects) – development concept under review by government; $39 – miscellaneous activities for five projects with smaller amounts suspended. While progress was being made on all 53 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 $2,299 of suspended well costs capitalized for a period greater than one year as of December 31, 2010, represents 176 exploratory wells in 53 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

1992	$	8		3
1997–1999		27		6
2000–2004		442		54
2005–2009		1,822		113

Total	$	2,299		176


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

1992	$	8		1
1999		8		1
2003–2005		340		9
2006–2010		1,943		42

Total	$	2,299		53

Stock Options and Other Share-Based Compensation

12 Months Ended

Dec. 31, 2010

Stock Options and Other Share-Based Compensation [Abstract]

Stock Options and Other Share-Based Compensation

Note 20

Stock Options and Other Share-Based Compensation

Compensation expense for stock options for 2010, 2009 and 2008 was $229 ($149 after tax), $182 ($119 after tax) and $168 ($109 after tax), respectively. In addition, compensation expense for stock appreciation rights, restricted stock, performance units and restricted stock units was $194 ($126 after tax), $170 ($110 after tax) and $132 ($86 after tax) for 2010, 2009 and 2008, respectively. No significant stock-based compensation cost was capitalized at December 31, 2010 and 2009.

Cash received in payment for option exercises under all share-based payment arrangements for 2010, 2009 and 2008 was $385, $147 and $404, respectively. Actual tax benefits realized for the tax deductions from option exercises were $66, $25 and $103 for 2010, 2009 and 2008, respectively.

Cash paid to settle performance units and stock appreciation rights was $140, $89 and $136 for 2010, 2009 and 2008, 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, 2010, 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 have 10-year contractual lives extending into 2011, retained a provision for being restored. This provision enables a participant who exercises a stock option to receive new options equal to the number of shares exchanged or who has shares withheld to satisfy tax withholding obligations to receive new options equal to the number of shares exchanged or withheld. The restored options are fully exercisable six months after the date of grant, and the exercise price is the market value of the common stock on the day the restored option is 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 2010, 2009 and 2008 were measured on the date of grant using the Black-Scholes option-pricing model, with the following weighted-average assumptions:


	Year ended December 31
	2010			2009			2008

Stock Options
Expected term in years¹		6.1			6.0			6.1
Volatility²		30.8	%		30.2	%		22.0	%
Risk-free interest rate based on zero coupon U.S. treasury note		2.9	%		2.1	%		3.0	%
Dividend yield		3.9	%		3.2	%		2.7	%
Weighted-average fair value per option granted	$	16.28		$	15.36		$	15.97

Restored Options
Expected term in years¹		1.2			1.2			1.2
Volatility²		38.9	%		45.0	%		23.1	%
Risk-free interest rate based on zero coupon U.S. treasury note		0.6	%		1.1	%		1.9	%
Dividend yield		3.8	%		3.5	%		2.7	%
Weighted-average fair value per option granted	$	12.91		$	12.38		$	10.01


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 2010 is presented below:


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

Outstanding at January 1, 2010		69,463		$	63.70
Granted		15,454		$	73.70
Exercised		(8,133	)	$	49.82
Restored		27		$	78.41
Forfeited		(1,959	)	$	73.34
Outstanding at December 31, 2010		74,852		$	67.04	6.4 yrs	$	1,813

Exercisable at December 31, 2010		48,174		$	63.29	5.2 yrs	$	1,348

The total intrinsic value (i.e., the difference between the exercise price and the market price) of options exercised during 2010, 2009 and 2008 was $259, $91 and $433, respectively. During this period, the company continued its practice of issuing treasury shares upon exercise of these awards.

As of December 31, 2010, there was $242 of total unrecognized before-tax compensation cost related to nonvested 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, 2010, the number of LTIP performance units outstanding was equivalent to 2,679,108 shares. During 2010, 1,104,000 units were granted, 881,759 units vested with cash proceeds distributed to recipients and 173,475 units were forfeited. At December 31, 2010, units outstanding were 2,727,874, and the fair value of the liability recorded for these instruments was $266. In addition, outstanding stock appreciation rights and other awards that were granted under various LTIP and former Texaco and Unocal programs totaled approximately 1.6 million equivalent shares as of December 31, 2010. A liability of $40 was recorded for these awards.

In March 2009, Chevron granted all eligible LTIP employees restricted stock units in lieu of an annual cash bonus. A total of 453,965 units were granted at $69.70 per unit at the time of the grant. The expense associated with these special restricted stock units was recognized in 2009. All of the special restricted stock units were distributed in November 2010.

Employee Benefit Plans

12 Months Ended

Dec. 31, 2010

Employee Benefit 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 2010 and 2009 is on the following page:


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

Change in Benefit Obligation
Benefit obligation at January 1	$	9,664		$	4,715		$	8,127		$	3,891		$	3,065		$	2,931
Service cost		337			153			266			128			39			43
Interest cost		486			307			481			292			175			180
Plan participants’ contributions		–			7			–			7			147			145
Plan amendments		–			–			1			10			12			20
Curtailments		–			–			–			–			–			(5	)
Actuarial loss (gain)		568			200			1,391			299			486			56
Foreign currency exchange rate changes		–			(17	)		–			333			11			27
Benefits paid		(784	)		(295	)		(602	)		(245	)		(330	)		(332	)

Benefit obligation at December 31		10,271			5,070			9,664			4,715			3,605			3,065

Change in Plan Assets
Fair value of plan assets at January 1		7,304			3,235			5,448			2,600			–			–
Actual return on plan assets		867			361			964			402			–			–
Foreign currency exchange rate changes		–			(63	)		–			226			–			–
Employer contributions		1,192			258			1,494			245			183			187
Plan participants’ contributions		–			7			–			7			147			145
Benefits paid		(784	)		(295	)		(602	)		(245	)		(330	)		(332	)

Fair value of plan assets at December 31		8,579			3,503			7,304			3,235			–			–

Funded Status at December 31	$	(1,692	)	$	(1,567	)	$	(2,360	)	$	(1,480	)	$	(3,605	)	$	(3,065	)

Amounts recognized on the Consolidated Balance Sheet for the company’s pension and other postretirement benefit plans at December 31, 2010 and 2009, include:


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

Deferred charges and other assets	$	7		$	77		$	6		$	37		$	–		$	–
Accrued liabilities		(134	)		(71	)		(66	)		(67	)		(225	)		(208	)
Reserves for employee benefit plans		(1,565	)		(1,573	)		(2,300	)		(1,450	)		(3,380	)		(2,857	)

Net amount recognized at December 31	$	(1,692	)	$	(1,567	)	$	(2,360	)	$	(1,480	)	$	(3,605	)	$	(3,065	)

Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and OPEB plans were $6,749 and $6,454 at the end of 2010 and 2009, respectively. These amounts consisted of:


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

Net actuarial loss	$	3,919		$	1,903	$	4,181		$	1,889	$	935		$	465
Prior service (credit) costs		(52	)		179		(60	)		201		(135	)		(222	)

Total recognized at December 31	$	3,867		$	2,082	$	4,121		$	2,090	$	800		$	243

The accumulated benefit obligations for all U.S. and international pension plans were $9,535 and $4,161, respectively, at December 31, 2010, and $8,707 and $4,029, respectively, at December 31, 2009.

Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at December 31, 2010 and 2009, was:


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

Projected benefit obligations	$	10,265	$	3,668	$	9,658	$	3,550
Accumulated benefit obligations		9,528		3,113		8,702		3,102
Fair value of plan assets		8,566		2,190		7,292		2,116

The components of net periodic benefit cost and amounts recognized in other comprehensive income for 2010, 2009 and 2008 are shown in the table below:


	Pension Benefits
	2010						2009						2008						Other Benefits
	U.S.			Int’l.			U.S.			Int’l.			U.S.			Int’l.			2010			2009			2008

Net Periodic Benefit Cost
Service cost	$	337		$	153		$	266		$	128		$	250		$	132		$	39		$	43		$	44
Interest cost		486			307			481			292			499			292			175			180			178
Expected return on plan assets		(538	)		(241	)		(395	)		(203	)		(593	)		(273	)		–			–			–
Amortization of prior service (credits) costs		(8	)		22			(7	)		23			(7	)		24			(75	)		(81	)		(81	)
Recognized actuarial losses		318			98			298			108			60			77			27			27			38
Settlement losses		186			6			141			1			306			2			–			–			–
Curtailment losses		–			–			–			–			–			–			–			(5	)		–
Special termination benefit recognition		–			–			–			–			–			1			–			–			–

Total net periodic benefit cost		781			345			784			349			515			255			166			164			179

Changes Recognized in Other Comprehensive Income
Net actuarial loss (gain) during period		242			118			823			194			2,624			646			497			82			(42	)
Amortization of actuarial loss		(504	)		(104	)		(439	)		(109	)		(366	)		(79	)		(27	)		(27	)		(38	)
Prior service cost during period		–			–			1			13			–			32			12			20			–
Amortization of prior service credits (costs)		8			(22	)		7			(23	)		7			(24	)		75			81			81

Total changes recognized in other comprehensive income		(254	)		(8	)		392			75			2,265			575			557			156			1

Recognized in Net Periodic Benefit Cost and Other Comprehensive Income	$	527		$	337		$	1,176		$	424		$	2,780		$	830		$	723		$	320		$	180

Net actuarial losses recorded in “Accumulated other comprehensive loss” at December 31, 2010, 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 10 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 2011, the company estimates actuarial losses of $314, $114 and $64 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 $250 will be recognized from “Accumulated other comprehensive loss” during 2011 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, 2010, was approximately seven and 11 years for U.S. and international pension plans, respectively, and 12 years for other postretirement benefit plans. During 2011, the company estimates prior service (credits) costs of $(8), $27 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
	2010						2009						2008						Other Benefits
	U.S.			Int’l.			U.S.			Int’l.			U.S.			Int’l.			2010			2009			2008

Assumptions used to determine
benefit obligations:
Discount rate		4.8	%		6.5	%		5.3	%		6.8	%		6.3	%		7.5	%		5.2	%		5.9	%		6.3	%
Rate of compensation increase		4.5	%		6.7	%		4.5	%		6.3	%		4.5	%		6.8	%		N/A			N/A			4.0	%
Assumptions used to determine
net periodic benefit cost:
Discount rate		5.3	%		6.8	%		6.3	%		7.5	%		6.3	%		6.7	%		5.9	%		6.3	%		6.3	%
Expected return on plan assets		7.8	%		7.8	%		7.8	%		7.5	%		7.8	%		7.4	%		N/A			N/A			N/A
Rate of compensation increase		4.5	%		6.3	%		4.5	%		6.8	%		4.5	%		6.4	%		N/A			N/A			4.5	%

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, 2010, 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-today 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, 2010, the company selected a 4.8 percent discount rate for the U.S. pension plan and 5.0 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 2010. The discount rates at the end of 2009 were 5.3 percent and 5.8 percent for the U.S. pension plan and the U.S. OPEB plan, respectively. The discount rate at the end of 2008 was 6.3 percent for both the U.S. pension plan and the U.S. OPEB plan.

Other Benefit Assumptions For the measurement of accumulated postretirement benefit obligation at December 31, 2010, for the main U.S. postretirement medical plan, the assumed health care cost-trend rates start with 8 percent in 2011 and gradually decline to 5 percent for 2018 and beyond. For this measurement at December 31, 2009, the assumed health care cost-trend rates started with 7 percent in 2010 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	$	11	$	(9	)
Effect on postretirement benefit obligation	$	146	$	(125	)

Plan Assets and Investment Strategy The accounting standards for defined benefit pension and OPEB plans (ASC 715) provide users of financial statements with an understanding of: how investment allocation decisions are made; the major classes of plan assets; the inputs and valuation techniques used to measure the fair value of plan assets; the effect of fair value measurements using unobservable inputs on changes in plan assets for the period; and significant concentrations of risk within plan assets.

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 by 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 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, 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

At December 31, 2009
Equities
U.S.¹	$	2,115		$	2,115		$	–	$	–	$	370	$	370		$	–	$	–
International		977			977			–		–		492		492			–		–
Collective Trusts/Mutual Funds^2,6		1,264			3			1,261		–		786		91			695		–
Fixed Income
Government		713			149			564		–		506		54			452		–
Corporate		430			–			430		–		371		17			336		18
Mortgage-Backed Securities		149			–			149		–		2		–			–		2
Other Asset Backed		90			–			90		–		19		–			19		–
Collective Trusts/Mutual Funds²		326			–			326		–		230		14			216		–
Mixed Funds^3,6		8			8			–		–		105		17			88		–
Real Estate⁴		479			–			–		479		131		–			–		131
Cash and Cash Equivalents		743			743			–		–		207		207			–		–
Other⁵		10			(57	)		16		51		16		(3	)		18		1

Total at December 31, 2009	$	7,304		$	3,938		$	2,836	$	530	$	3,235	$	1,259		$	1,824	$	152


¹	U.S. equities include investments in the company’s common stock in the amount of $38 at December 31, 2010 and $29 at December 31, 2009.

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).

⁶	Certain amounts have been reclassified to conform to their 2010 presentation.

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
	U.S. Equities			Corporate			Securities		Real Estate			Other		Total

Total at December 31, 2008	$	1		$	23		$	2	$	763		$	52	$	841
Actual Return on Plan Assets:
Assets held at the reporting date		(1	)		2			–		(178	)		–		(177	)
Assets sold during the period		–			5			–		8			–		13
Purchases, Sales and Settlements		–			(12	)		–		17			–		5
Transfers in and/or out of Level 3		–			–			–		–			–		–

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

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. There are no significant concentrations of risk in plan assets due to the diversification of investment classes.

The company does not prefund its OPEB obligations.

Cash Contributions and Benefit Payments In 2010, the company contributed $1,192 and $258 to its U.S. and international pension plans, respectively. In 2011, the company expects contributions to be approximately $650 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 $225 in 2011, as compared with $183 paid in 2010.

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

2011	$	994	$	247	$	225
2012	$	926	$	298	$	230
2013	$	924	$	300	$	238
2014	$	934	$	320	$	246
2015	$	937	$	346	$	253
2016–2020	$	4,687	$	2,095	$	1,345

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 $253, $257, and $231 in 2010, 2009 and 2008, respectively. This cost was reduced by the value of shares released from the LESOP totaling $97, $184 and $40 in 2010, 2009 and 2008, respectively. The remaining amounts, totaling $156, $73 and $191 in 2010, 2009 and 2008, 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, $3 and $1 in 2010, 2009 and 2008, respectively. The net credit for the respective years was composed of credits to compensation expense of $6, $15 and $15 and charges to interest expense for LESOP debt of $5, $12 and $14.

Of the dividends paid on the LESOP shares, $46, $110 and $35 were used in 2010, 2009 and 2008, respectively, to service LESOP debt. No contributions were required in 2010, 2009 or 2008, 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, 2010 and 2009, were as follows:


Thousands	2010		2009

Allocated shares		20,718		21,211
Unallocated shares		2,374		3,636

Total LESOP shares		23,092		24,847

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 2010, 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, 2010 and 2009, trust assets of $57 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 $766, $561 and $757 in 2010, 2009 and 2008, 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, on page FS-51.

Equity	12 Months Ended
Equity	Dec. 31, 2010
Equity [Abstract]
Equity	Note 22 Equity Retained earnings at December 31, 2010 and 2009, included approximately $9,159 and $8,122, respectively, for the company’s share of undistributed earnings of equity affiliates. At December 31, 2010, about 81 million shares of Chevron’s common stock remained available for issuance from the 160 million shares that were reserved for issuance under the Chevron Corporation Long-Term Incentive Plan (LTIP). In addition, approximately 280,000 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, 2010

Restructuring and Reorganization [Abstract]

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. The initial estimate included approximately 3,200 employees in Downstream and 600 employees from corporate staffs that were expected to be terminated under the programs. Due to redeployment efforts within the company, total employee terminations under the programs are expected to be reduced from approximately 3,800 employees to approximately 3,200 employees. About 1,500 of the affected employees are located in the United States. About 1,500 employees have been terminated to date, and the programs are expected to be completed by the end of 2011.

A before-tax charge of $244 ($175 after tax) was recorded in first quarter 2010, with $191 reported as “Operating expenses” and $53 as “Selling, general and administrative expenses” on the Consolidated Statement of Income. Due to the reduction in terminations resulting from reassignments within the company, an adjustment to total charges was made in fourth quarter 2010, which effectively reduced the total before-tax charge from $244 to $234 ($167 after tax). The accrued liability is classified as current on the Consolidated Balance Sheet. Approximately $71 ($45 after tax) is associated with terminations in U.S. Downstream, $119 ($92 after tax) in International Downstream and $44 ($30 after tax) in All Other.

During the last nine months of 2010, the company made payments of $96 associated with these liabilities. The majority of the payments were in Downstream.


	Amounts Before Tax

Balance at January 1, 2010		$	–
Accruals			244
Adjustments			(10	)
Payments			(96	)

Balance at December 31, 2010		$	138

Other Contingencies and Commitments	12 Months Ended
Other Contingencies and Commitments	Dec. 31, 2010
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-47, 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 will 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 is expected to be operational by 2012. 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 any 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. The company would be required to perform if the indemnified liabilities become actual losses. Were that to occur, the company could be required to make future payments up to $300. Through the end of 2010, the company paid $48 under these indemnities and continues to be obligated for possible additional indemnification payments in the future. The company has also provided indemnities relating to contingent environmental liabilities related to 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. 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: 2011 – $17,200; 2012 – $4,100; 2013 – $3,500; 2014 – $3,100; 2015 – $3,000; 2016 and after – $7,700. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were approximately $6,500 in 2010, $8,100 in 2009 and $5,100 in 2008. 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, 2010, was $1,507. Included in this balance were remediation activities at approximately 182 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 2010 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 2010 environmental reserves balance of $1,322, $814 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 $508 was associated with various sites in international downstream ($100), upstream ($329) and other businesses ($79). 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 or local regulations. No single remediation site at year-end 2010 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 for a discussion of the company’s asset retirement obligations. Equity Redetermination For crude oil and natural gas producing operations, ownership agreements may provide for periodic reassessments of equity interests in estimated crude oil and natural gas reserves. These activities, individually or together, may result in gains or losses that could be material to earnings in any given period. One such equity redetermination process has been under way since 1996 for Chevron’s interests in four producing zones at the Naval Petroleum Reserve at Elk Hills, California, for the time when the remaining interests in these zones were owned by the U.S. Department of Energy. A wide range remains for a possible net settlement amount for the four zones. For this range of settlement, Chevron estimates its maximum possible net before-tax liability at approximately $200, and the possible maximum net amount that could be owed to Chevron is estimated at about $150. The timing of the settlement and the exact amount within this range of estimates are uncertain. 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 the company continues to evaluate its options going forward, which may include requesting the city to revise the EIR to address the issues identified by the Court of Appeal or other actions. Management believes the outcomes associated with the potential options for 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, of the ruling 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.

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2010

Asset Retirement Obligations [Tables] [Abstract]

Asset Retirement Obligations

Note 25

Asset Retirement Obligations

In accordance with accounting standards for asset retirement obligations (ASC 410), the company records the fair value of a liability for an asset retirement obligation (ARO) 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.

Accounting standards for asset retirement obligations primarily affect the company’s accounting for 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 2010, 2009 and 2008:


	2010			2009			2008

Balance at January 1	$	10,175		$	9,395		$	8,253
Liabilities incurred		129			144			308
Liabilities settled		(755	)		(757	)		(973	)
Accretion expense		513			463			430
Revisions in estimated cash flows		2,426			930			1,377

Balance at December 31	$	12,488		$	10,175		$	9,395

In the table above, the amounts associated with “Revisions in estimated cash flows” reflect increasing costs to abandon wells, equipment and facilities. The long-term portion of the $12,488 balance at the end of 2010 was $11,788.

Other Financial Information

12 Months Ended

Dec. 31, 2010

Other Financial Information [Abstract]

Other Financial Information

Note 26

Other Financial Information

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. Earnings in 2009 included gains of approximately $1,000 relating to the sale of nonstrategic properties. Of this amount, approximately $600 and $400 related to downstream and upstream assets, respectively. Earnings in 2008 included gains of approximately $1,200 relating to the sale of nonstrategic properties. Of this amount, approximately $1,000 related to upstream assets.

Other financial information is as follows:


	Year ended December 31
	2010			2009			2008

Total financing interest and debt costs	$	317		$	301		$	256
Less: Capitalized interest		267			273			256

Interest and debt expense	$	50		$	28		$	–

Research and development expenses	$	526		$	603		$	702

Foreign currency effects*	$	(423	)	$	(744	)	$	862


*	Includes $(71), $(194) and $420 in 2010, 2009 and 2008, 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 $6,975 and $5,491 at December 31, 2010 and 2009, respectively. Replacement cost is generally based on average acquisition costs for the year. LIFO profits (charges) of $21, $(168) and $210 were included in earnings for the years 2010, 2009 and 2008, respectively.

The company has $4,617 in goodwill on the Consolidated Balance Sheet related to the 2005 acquisition of Unocal. Under the accounting standard for goodwill (ASC 350), the company tested this goodwill for impairment during 2010 and concluded no impairment was necessary.

Earnings Per Share

12 Months Ended

Dec. 31, 2010

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 and the company’s share of stock transactions of affiliates, which, under the applicable accounting rules, may be recorded directly to the company’s retained earnings instead of net income. 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-51). The table below sets forth the computation of basic and diluted EPS:


	Year ended December 31
	2010		2009		2008

Basic EPS Calculation

Earnings available to common stockholders – Basic¹	$	19,024	$	10,483	$	23,931

Weighted-average number of common shares outstanding		1,996		1,991		2,037
Add: Deferred awards held as stock units		1		1		1

Total weighted-average number of common shares outstanding		1,997		1,992		2,038

Earnings per share of common stock – Basic	$	9.53	$	5.26	$	11.74

Diluted EPS Calculation

Earnings available to common stockholders – Diluted¹	$	19,024	$	10,483	$	23,931

Weighted-average number of common shares outstanding		1,996		1,991		2,037
Add: Deferred awards held as stock units		1		1		1
Add: Dilutive effect of employee stock-based awards		10		9		12

Total weighted-average number of common shares outstanding		2,007		2,001		2,050

Earnings per share of common stock – Diluted	$	9.48	$	5.24	$	11.67


¹	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, 2010

Valuation and Qualifying Accounts [Abstract]

Schedule II - Valuation and Qualifying Accounts

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
Millions of Dollars


	Year Ended December 31
	2010			2009			2008

Employee Termination Benefits:
Balance at January 1	$	13		$	44		$	117
Additions (deductions) charged (credited) to expense		235			(12	)		(13	)
Payments		(103	)		(19	)		(60	)

Balance at December 31	$	145		$	13		$	44

Allowance for Doubtful Accounts:
Balance at January 1	$	293		$	275		$	200
(Reductions) additions to expense		(13	)		92			105
Bad debt write-offs		(41	)		(74	)		(30	)

Balance at December 31	$	239		$	293		$	275

Deferred Income Tax Valuation Allowance:*
Balance at January 1	$	7,921		$	7,535		$	5,949
Additions to deferred income tax expense		1,454			2,204			2,599
Reduction of deferred income tax expense		(190	)		(1,818	)		(1,013	)

Balance at December 31	$	9,185		$	7,921		$	7,535


*	See also Note 15 to the Consolidated Financial Statements, beginning on page FS-47.

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2010
Summary of Significant Accounting Policies (Policies) [Abstract]
Adoption of ASC 410 and its impact	As required under accounting standards for asset retirement obligations (Accounting Standards Codification (ASC) 410), 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-62, relating to AROs.
Adoption of 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 a reporting unit below its carrying amount.
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.
Adoption of 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, and 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.
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 or exploratory-type stratigraphic 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.
Accounting Standards for Fair Value Measurement (ASC 820)	Impairments of “Investments and advances” In accordance with the accounting standards under the equity method of accounting (ASC 323) and the cost method of accounting (ASC 325), during 2010 and 2009 investments with carrying amounts of $15 and $81 were written down to fair values of $0 and $39 resulting in before-tax losses of $15 and $42, respectively. The fair values were determined using discount rates consistent with those used by the company to evaluate cash flows of other investments of a similar nature.
Adoption of ASC 860 and its impact	Transfers and Servicing (ASC 860), Accounting for Transfers of Financial Assets (ASU 2009-16) The FASB issued ASU 2009-16 in December 2009. This standard became effective for the company on January 1, 2010. ASU 2009-16 changes how companies account for transfers of financial assets and eliminates the concept of qualifying special-purpose entities. Adoption of the guidance did not have an effect on the company’s results of operations, financial position or liquidity.
Acquisition accounted as business combination (ASC 805)	In November 2010, Chevron announced plans to acquire Atlas Energy, Inc. The acquisition was completed in February 2011 for $4,470, including assumed debt. The acquisition will be accounted for as a business combination (ASC 805). Atlas holds one of the premier acreage positions in the Marcellus Shale, concentrated in southwestern Pennsylvania.
Consolidation (ASC 810)	The company adopted accounting standards 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.” Consolidation (ASC 810), Improvements to Financial Reporting by Enterprises Involved With Variable Interest Entities (ASU 2009-17) The FASB issued ASU 2009-17 in December 2009. This standard became effective for the company January 1, 2010. ASU 2009-17 requires the enterprise to qualitatively assess if it is the primary beneficiary of a variable-interest entity (VIE), and if so, the VIE must be consolidated. Adoption of the standard did not have an impact on the company’s results of operations, financial position or liquidity.
Receivables ASC 310 and its impact	Receivables (ASC 310), Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses (ASU 2010-20) In July 2010, the FASB issued ASU 2010-20, which became effective with the company’s reporting at December 31, 2010. This standard amends and expands disclosure requirements about the credit quality of financing receivables and the related allowance for credit losses. As a result of these amendments, companies are required to disaggregate, by portfolio segment or class of financing receivable, certain existing disclosures and provide certain new disclosures about financing receivables and related allowance for credit losses. Adoption of the standard did not change the company’s existing disclosures.
Adoption of accounting standards for income taxes and uncertainty in income taxes 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 (ASC 740-10-20) 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, 2010, 2009 and 2008. The term “unrecognized tax benefits” in the accounting standards for income taxes (ASC 740-10-20) 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.
Adoption of Accounting standard for the impairment or disposal of long-lived assets (ASC 360)	Impairments of “Properties, plant and equipment” In accordance with the accounting standard for the impairment or disposal of long-lived assets (ASC 360), during 2010 and 2009 long-lived assets “held and used” with carrying amounts of $142 and $949 were written down to fair values of $57 and $490 resulting in before-tax losses of $85 and $459, respectively. The fair values were determined from internal cash flow models, using discount rates consistent with those used by the company to evaluate cash flows of other assets of a similar nature. Long-lived assets “held for sale” with carrying amounts of $49 and $160 were written down to a fair value of $13 and $68, resulting in a before-tax loss of $36 and $92 in 2010 and 2009, respectively. The fair values were determined based on bids received from prospective buyers and from internal cash-flow models consistent with those used by the company to evaluate cash flows of other assets of a similar nature.

Noncontrolling Interests (Tables)

12 Months Ended

Dec. 31, 2010

Noncontrolling Interests (Tables) [Abstract]

Activity for equity attributable to noncontrolling interests


	2010			2009			2008

Balance at January 1	$	647		$	469		$	204
Net income		112			80			100
Distributions to noncontrolling interests		(72	)		(71	)		(99	)
Other changes, net		43			169			264

Balance at December 31	$	730		$	647		$	469

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

12 Months Ended

Dec. 31, 2010

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

Net increase in operating working capital


	Year ended December 31
	2010			2009			2008

Net decrease (increase) in operating working capital was composed of the following:
(Increase) decrease in accounts and notes receivable	$	(2,767	)	$	(1,476	)	$	6,030
Decrease (increase) in inventories		15			1,213			(1,545	)
Increase in prepaid expenses and other current assets		(542	)		(264	)		(621	)
Increase (decrease) in accounts payable and accrued liabilities		3,049			(1,121	)		(4,628	)
Increase (decrease) in income and other taxes payable		321			(653	)		(909	)

Net decrease (increase) in operating working capital	$	76		$	(2,301	)	$	(1,673	)

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	$	11,749		$	7,537		$	19,130

Net sales of marketable securities consisted of the following gross amounts:
Marketable securities sold	$	41		$	157		$	3,719
Marketable securities purchased		(90	)		(30	)		(3,236	)

Net (purchases) sales of marketable securities	$	(49	)	$	127		$	483

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

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

Net Cash Provided by Operating Activities


	Year ended December 31
	2010			2009			2008

Net decrease (increase) in operating working capital was composed of the following:
(Increase) decrease in accounts and notes receivable	$	(2,767	)	$	(1,476	)	$	6,030
Decrease (increase) in inventories		15			1,213			(1,545	)
Increase in prepaid expenses and other current assets		(542	)		(264	)		(621	)
Increase (decrease) in accounts payable and accrued liabilities		3,049			(1,121	)		(4,628	)
Increase (decrease) in income and other taxes payable		321			(653	)		(909	)

Net decrease (increase) in operating working capital	$	76		$	(2,301	)	$	(1,673	)

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	$	11,749		$	7,537		$	19,130

Net sales of marketable securities consisted of the following gross amounts:
Marketable securities sold	$	41		$	157		$	3,719
Marketable securities purchased		(90	)		(30	)		(3,236	)

Net (purchases) sales of marketable securities	$	(49	)	$	127		$	483

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

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

Net sales of marketable securities


	Year ended December 31
	2010			2009			2008

Net decrease (increase) in operating working capital was composed of the following:
(Increase) decrease in accounts and notes receivable	$	(2,767	)	$	(1,476	)	$	6,030
Decrease (increase) in inventories		15			1,213			(1,545	)
Increase in prepaid expenses and other current assets		(542	)		(264	)		(621	)
Increase (decrease) in accounts payable and accrued liabilities		3,049			(1,121	)		(4,628	)
Increase (decrease) in income and other taxes payable		321			(653	)		(909	)

Net decrease (increase) in operating working capital	$	76		$	(2,301	)	$	(1,673	)

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	$	11,749		$	7,537		$	19,130

Net sales of marketable securities consisted of the following gross amounts:
Marketable securities sold	$	41		$	157		$	3,719
Marketable securities purchased		(90	)		(30	)		(3,236	)

Net (purchases) sales of marketable securities	$	(49	)	$	127		$	483

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

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

Net purchases of time deposits


	Year ended December 31
	2010			2009			2008

Net decrease (increase) in operating working capital was composed of the following:
(Increase) decrease in accounts and notes receivable	$	(2,767	)	$	(1,476	)	$	6,030
Decrease (increase) in inventories		15			1,213			(1,545	)
Increase in prepaid expenses and other current assets		(542	)		(264	)		(621	)
Increase (decrease) in accounts payable and accrued liabilities		3,049			(1,121	)		(4,628	)
Increase (decrease) in income and other taxes payable		321			(653	)		(909	)

Net decrease (increase) in operating working capital	$	76		$	(2,301	)	$	(1,673	)

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	$	11,749		$	7,537		$	19,130

Net sales of marketable securities consisted of the following gross amounts:
Marketable securities sold	$	41		$	157		$	3,719
Marketable securities purchased		(90	)		(30	)		(3,236	)

Net (purchases) sales of marketable securities	$	(49	)	$	127		$	483

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

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

Capital expenditures


	Year ended December 31
	2010			2009		2008

Additions to properties, plant and equipment¹	$	18,474		$	16,107	$	18,495
Additions to investments		861			942		1,051
Current year dry hole expenditures		414			468		320
Payments for other liabilities and assets, net²		(137	)		2,326		(200	)

Capital expenditures		19,612			19,843		19,666
Expensed exploration expenditures		651			790		794
Assets acquired through capital lease obligations and other financing obligations		104			19		9

Capital and exploratory expenditures, excluding equity affiliates		20,367			20,652		20,469
Company’s share of expenditures by equity affiliates		1,388			1,585		2,306

Capital and exploratory expenditures, including equity affiliates	$	21,755		$	22,237	$	22,775


¹ Excludes noncash additions of $2,753 in 2010, $985 in 2009 and $5,153 in 2008.

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, 2010

Summarized Financial Data Subsidiary (Tables) [Abstract]

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


	Year ended December 31
	2010		2009		2008

Sales and other operating revenues	$	145,381	$	121,553	$	195,593
Total costs and other deductions		139,984		120,053		185,788
Net income attributable to CUSA		4,159		1,141		7,318


	At December 31
	2010		2009

Current assets	$	29,211	$	23,286
Other assets		35,294		32,827
Current liabilities		18,098		16,098
Other liabilities		16,785		14,625

Total CUSA net equity		29,622		25,390


Memo: Total debt		$ 8,284		$ 6,999

Summarized Financial Data - Chevron Transport Corporation Ltd. (Tables)

12 Months Ended

Dec. 31, 2010

Summarized Financial Data Subsidiary One Tables Abstract

Summarized Financial Data - Chevron Transport Corporation


	Year ended December 31
	2010			2009			2008

Sales and other operating revenues	$	885		$	683		$	1,022
Total costs and other deductions		1,008			810			947
Net (loss) income attributable to CTC		(116	)		(124	)		120

Summarized Financial Data and its Subsidiary


	At December 31
	2010		2009

Current assets	$	209	$	377
Other assets		201		173
Current liabilities		101		115
Other liabilities		75		90

Total CTC net equity		234		345

Summarized Financial Data - Tengizchevroil LLP (Tables)

12 Months Ended

Dec. 31, 2010

Summarized Financial Data Of Subsidiary Three Tables Abstract

Summarized Financial Data - Tengizchevroil LLP


	Year ended December 31
	2010		2009		2008

Sales and other operating revenues	$	17,812	$	12,013	$	14,329
Costs and other deductions		8,394		6,044		5,621
Net income attributable to TCO		6,593		4,178		6,134


	At December 31
	2010		2009

Current assets	$	3,376	$	3,190
Other assets		11,813		12,022
Current liabilities		2,402		2,426
Other liabilities		4,130		4,484

Total TCO net equity		8,657		8,302

Lease Commitments (Tables)

12 Months Ended

Dec. 31, 2010

Lease Commitments (Tables) [Abstract]

Schedule of capitalized leased assets


	At December 31
	2010		2009

Upstream	$	561	$	510
Downstream		316		334
All Other		169		169

Total		1,046		1,013
Less: Accumulated amortization		573		585

Net capitalized leased assets	$	473	$	428

Rental expenses incurred for operating leases


	Year ended December 31
	2010		2009		2008

Minimum rentals	$	2,373	$	2,179	$	2,984
Contingent rentals		10		7		6

Total		2,383		2,186		2,990
Less: Sublease rental income		41		41		41

Net rental expense	$	2,342	$	2,145	$	2,949

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


	At December 31
	Operating		Capital
	Leases		Leases

Year: 2011		650		99
2012		530		93
2013		370		68
2014		288		51
2015		273		40
Thereafter		725		137

Total	$	2,836	$	488

Less: Amounts representing interest and executory costs				(105	)

Net present values				383
Less: Capital lease obligations included in short-term debt				(97	)

Long-term capital lease obligations			$	286

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2010

Fair Value Measurements (Tables) [Abstract]

Assets and Liabilities Measured at Fair Value on a Recurring Basis


			Prices in Active								Prices in Active
			Markets for		Other						Markets for		Other
			Identical		Observable		Unobservable				Identical		Observable		Unobservable
	At December 31		Assets/Liabilities		Inputs		Inputs		At December 31		Assets/Liabilities		Inputs		Inputs
	2010		(Level 1)		(Level 2)		(Level 3)		2009		(Level 1)		(Level 2)		(Level 3)

Marketable securities	$	155	$	155	$	–	$	–	$	106	$	106	$	–	$	–
Derivatives		122		11		111		–		127		14		113		–

Total Recurring Assets
at Fair Value	$	277	$	166	$	111	$	–	$	233	$	120	$	113	$	–

Derivatives	$	171	$	75	$	96	$	–	$	101	$	20	$	81	$	–

Total Recurring Liabilities
at Fair Value	$	171	$	75	$	96	$	–	$	101	$	20	$	81	$	–

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


			Prices in Active		Other				Loss (Before Tax)				Prices in Active		Other				Loss (Before Tax)
	Year ended		Markets for		Observable		Unobservable		Year ended		Year ended		Markets for		Observable		Unobservable		Year ended
	December 31		Identical Assets		Inputs		Inputs		December 31		December 31		Identical Assets		Inputs		Inputs		December 31
	2010		(Level 1)		(Level 2)		(Level 3)		2010		2009		(Level 1)		(Level 2)		(Level 3)		2009

Properties, plant and equipment, net (held and used)	$	57	$	–	$	–	$	57	$	85	$	490	$	–	$	–	$	490	$	459
Properties, plant and equipment, net (held for sale)		13		–		–		13		36		68		–		68		–		92
Investments and advances		–		–		–		–		15		39		–		–		39		42

Total Nonrecurring Assets at Fair Value	$	70	$	–	$	–	$	70	$	136	$	597	$	–	$	68	$	529	$	593

Financial and Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2010

Financial and Derivative Instruments (Tables) [Abstract]

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


		Asset Derivatives – Fair Value				Liability Derivatives – Fair Value
Type of	Balance Sheet	At December 31		At December 31		Balance Sheet	At December 31		At December 31
Derivative Contract	Classification	2010		2009		Classification	2010		2009

Commodity	Accounts and notes receivable, net	$	58	$	99	Accrued payable	$	131	$	73
Commodity	Long-term receivable, net		64		28	Deferred credits and other noncurrent obligations		40		28

		$	122	$	127		$	171	$	101

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	2010			2009			2008


Foreign Exchange	Other income	$	–		$	26		$	(314	)

Commodity	Sales and other
	operating revenues		(98	)		(94	)		706

Commodity	Purchased crude oil
	and products		(36	)		(353	)		424

Commodity	Other income		(1	)		–			(3	)

		$	(135	)	$	(421	)	$	813

Operating Segments and Geographic Data (Tables)

12 Months Ended

Dec. 31, 2010

Operating Segments and Geographic Data (Tables) [Abstract]

Segment Earnings


	Year ended December 31
	2010			2009			2008

Segment Earnings
Upstream
United States	$	4,122		$	2,262		$	7,147
International		13,555			8,670			15,022

Total Upstream		17,677			10,932			22,169

Downstream
United States		1,339			(121	)		1,369
International		1,139			594			1,783

Total Downstream		2,478			473			3,152

Total Segment Earnings		20,155			11,405			25,321
All Other
Interest expense		(41	)		(22	)		–
Interest income		70			46			192
Other		(1,160	)		(946	)		(1,582	)

Net Income Attributable
to Chevron Corporation	$	19,024		$	10,483		$	23,931

Segment Assets


	At December 31
	2010		2009

Upstream
United States	$	26,319	$	25,478
International		89,306		81,209
Goodwill		4,617		4,618

Total Upstream		120,242		111,305

Downstream
United States		21,406		20,317
International		20,559		19,618

Total Downstream		41,965		39,935

Total Segment Assets		162,207		151,240

All Other*
United States		11,125		7,125
International		11,437		6,256

Total All Other		22,562		13,381

Total Assets – United States		58,850		52,920
Total Assets – International		121,302		107,083
Goodwill		4,617		4,618

Total Assets	$	184,769	$	164,621


*“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.

Sales and Other Operating Revenues


	Year ended December 31
	2010			2009			2008

Upstream
United States	$	10,316		$	9,225		$	23,566
Intersegment		13,839			10,297			15,162

Total United States		24,155			19,522			38,728

International		17,300			13,463			19,531
Intersegment		23,834			18,477			24,205

Total International		41,134			31,940			43,736

Total Upstream		65,289			51,462			82,464

Downstream
United States		70,436			58,056			87,759
Excise and similar taxes		4,484			4,573			4,748
Intersegment		115			98			242

Total United States		75,035			62,727			92,749

International		90,922			77,845			123,389
Excise and similar taxes		4,107			3,536			5,098
Intersegment		93			87			80

Total International		95,122			81,468			128,567

Total Downstream		170,157			144,195			221,316

All Other
United States		610			665			815
Intersegment		947			964			917

Total United States		1,557			1,629			1,732

International		23			39			52
Intersegment		39			33			33

Total International		62			72			85

Total All Other		1,619			1,701			1,817

Segment Sales and Other
Operating Revenues
United States		100,747			83,878			133,209
International		136,318			113,480			172,388

Total Segment Sales and Other
Operating Revenues		237,065			197,358			305,597
Elimination of intersegment sales		(38,867	)		(29,956	)		(40,639	)

Total Sales and Other
Operating Revenues	$	198,198		$	167,402		$	264,958


Segment Income Taxes Segment income tax expense for the years 2010, 2009 and 2008 is as follows:
	Year ended December 31
	2010			2009			2008

Upstream
United States	$	2,285		$	1,251		$	3,705
International		10,480			7,451			15,122

Total Upstream		12,765			8,702			18,827

Downstream
United States		680			(83	)		780
International		462			463			871

Total Downstream		1,142			380			1,651

All Other		(988	)		(1,117	)		(1,452	)

Total Income Tax Expense	$	12,919		$	7,965		$	19,026

Investments and Advances (Tables)

12 Months Ended

Dec. 31, 2010

Investments and Advances (Tables) [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
	2010		2009		2010			2009			2008

Upstream
Tengizchevroil	$	5,789	$	5,938	$	3,398		$	2,216		$	3,220
Petropiar/Hamaca		973		1,139		262			122			317
Caspian Pipeline Consortium		974		852		124			105			103
Petroboscan		937		832		222			171			244
Angola LNG Limited		2,481		1,853		(21	)		(12	)		(8	)
Other		1,922		1,947		319			287			424

Total Upstream		13,076		12,561		4,304			2,889			4,300

Downstream
GS Caltex Corporation		2,496		2,406		158			(191	)		444
Chevron Phillips Chemical
Company LLC		2,419		2,327		704			328			158
Star Petroleum Refining
Company Ltd.		947		873		122			(4	)		22
Caltex Australia Ltd.		767		740		101			11			250
Colonial Pipeline Company		–		514		43			51			32
Other		602		540		151			149			140

Total Downstream		7,231		7,400		1,279			344			1,046

All Other
Other		509		507		54			83			20

Total equity method	$	20,816	$	20,468	$	5,637		$	3,316		$	5,366
Other at or below cost		704		690

Total investments and
advances	$	21,520	$	21,158

Total United States	$	3,769	$	4,195	$	846		$	511		$	307
Total International	$	17,751	$	16,963	$	4,791		$	2,805		$	5,059

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	2010		2009		2008		2010		2009		2008

Total revenues	$	107,505	$	81,995	$	112,707	$	52,088	$	39,280	$	54,055
Income before income tax expense		18,468		11,083		17,500		7,966		4,511		7,532
Net income attributable to affiliates		12,831		8,261		12,705		5,683		3,285		5,524

At December 31

Current assets	$	30,335	$	27,111	$	25,194	$	12,845	$	11,009	$	10,804
Noncurrent assets		57,491		55,363		51,878		21,401		21,361		20,129
Current liabilities		20,428		17,450		17,727		9,363		7,833		7,474
Noncurrent liabilities		19,749		21,531		21,049		4,459		5,106		4,533

Total affiliates’ net equity	$	47,649	$	43,493	$	38,296	$	20,424	$	19,431	$	18,926

Properties, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2010

Properties, Plant and Equipment (Tables) [Abstract]

Properties, Plant and Equipment


	At December 31												Year ended December 31
	Gross Investment at Cost						Net Investment						Additions at Cost²						Depreciation Expense³
	2010		2009		2008		2010		2009		2008		2010		2009		2008		2010		2009		2008

Upstream
United States	$	62,523	$	58,328	$	54,878	$	23,277	$	22,273	$	22,701	$	4,934	$	3,518	$	5,395	$	4,078	$	3,992	$	2,704
International		110,578		96,557		86,676		64,388		57,450		53,371		14,381		10,803		14,997		7,448		6,669		5,461

Total Upstream		173,101		154,885		141,554		87,665		79,723		76,072		19,315		14,321		20,392		11,526		10,661		8,165

Downstream
United States		19,820		18,962		17,397		10,379		10,032		8,908		1,199		1,874		2,061		741		666		627
International		9,697		9,852		10,021		3,948		4,154		4,266		361		456		537		451		454		482

Total Downstream		29,517		28,814		27,418		14,327		14,186		13,174		1,560		2,330		2,598		1,192		1,120		1,109

All Other⁴
United States		4,722		4,569		4,310		2,496		2,548		2,523		259		354		598		341		325		250
International		27		20		17		16		11		11		11		3		5		4		4		4

Total All Other		4,749		4,589		4,327		2,512		2,559		2,534		270		357		603		345		329		254

Total United States		87,065		81,859		76,585		36,152		34,853		34,132		6,392		5,746		8,054		5,160		4,983		3,581
Total International		120,302		106,429		96,714		68,352		61,615		57,648		14,753		11,262		15,539		7,903		7,127		5,947

Total	$	207,367	$	188,288	$	173,299	$	104,504	$	96,468	$	91,780	$	21,145	$	17,008	$	23,593	$	13,063	$	12,110	$	9,528


¹	Other than the United States and Nigeria, no other country accounted for 10 percent or more of the company’s net properties, plant and equipment (PP&E) in 2010, 2009 and 2008. Nigeria had net PP&E of $13,896, $12,463 and $10,730 for 2010, 2009 and 2008, respectively.

²	Net of dry hole expense related to prior years’ expenditures of $82, $84 and $55 in 2010, 2009 and 2008, respectively.

³	Depreciation expense includes accretion expense of $513, $463 and $430 in 2010, 2009 and 2008, respectively.

⁴	Primarily mining operations, power generation businesses, real estate assets and management information systems.

Taxes (Tables)

12 Months Ended

Dec. 31, 2010

Income Taxes Tables Abstract

Income Taxes


	Year ended December 31
	2010		2009			2008

Taxes on income
U.S. Federal
Current	$	1,501	$	128		$	2,879
Deferred		162		(147	)		274
State and local
Current		376		216			528
Deferred		20		14			141

Total United States		2,059		211			3,822

International
Current		10,483		7,154			15,021
Deferred		377		600			183

Total International		10,860		7,754			15,204

Total taxes on income	$	12,919	$	7,965		$	19,026

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

<div align="left" style="font-size: 10pt; font-family: Helvetica,Arial,sans-serif"> <div align="center"> <table style="font-size: 8pt; text-align: left" cellspacing="0" border="0" cellpadding="0" width="100%">  <tr valign="bottom"> <td width="65%"> </td> <td width="5%"> </td> <td width="1%"> </td> <td width="5%"> </td> <td width="1%"> </td> <td width="2%"> </td> <td width="2%"> </td> <td width="1%"> </td> <td width="5%"> </td> <td width="1%"> </td> <td width="5%"> </td> <td width="1%"> </td> <td width="5%"> </td> <td width="1%"> </td> </tr> <tr style="font-size: 7pt" valign="bottom"> <td> </td> <td> </td> <td nowrap="nowrap" align="right" colspan="11" style="border-bottom: 1px solid #0077c0">Year ended December 31</td> <td> </td> </tr> <tr style="font-size: 7pt" valign="bottom"> <td> </td> <td> </td> <td nowrap="nowrap" align="right" colspan="2"><b>2010</b></td> <td> </td> <td> </td> <td> </td> <td nowrap="nowrap" align="right" colspan="2">2009</td> <td> </td> <td> </td> <td nowrap="nowrap" align="right" colspan="2">2008</td> <td> </td> </tr>   <tr style="font-size: 1px"> <td colspan="5" align="left" style="border-top: 1px solid #0077c0"> </td> <td align="left" style="border-right: 1px solid #0077c0; border-top: 1px solid #0077c0"> </td> <td align="left" style="border-top: 1px solid #0077c0"> </td> <td colspan="6" align="left" style="border-top: 1px solid #0077c0"> </td> </tr> <tr valign="bottom" style="background: #ffffff"> <td> <div style="margin-left:15px; text-indent:-15px">U.S. statutory federal income tax rate </div></td> <td> </td> <td nowrap="nowrap" align="left"> </td> <td align="right"><b>35.0</b></td> <td nowrap="nowrap"><b>%</b></td> <td style="border-right: 1px solid #0077c0"> </td> <td> </td> <td nowrap="nowrap" align="left"> </td> <td align="right">35.0</td> <td nowrap="nowrap">%</td> <td> </td> <td nowrap="nowrap" align="left"> </td> <td align="right">35.0</td> <td nowrap="nowrap">%</td> </tr> <tr valign="bottom"> <td> <div style="margin-left:15px; text-indent:-15px">Effect of income taxes from inter-<br /> national operations at rates different<br /> from the U.S. statutory rate </div></td> <td> </td> <td> </td> <td align="right"><b>5.2</b></td> <td> </td> <td style="border-right: 1px solid #0077c0"> </td> <td> </td> <td> </td> <td align="right">10.4</td> <td> </td> <td> </td> <td> </td> <td align="right">10.1</td> <td> </td> </tr> <tr valign="bottom" style="background: #ffffff"> <td> <div style="margin-left:15px; text-indent:-15px">State and local taxes on income, net </div></td> <td> </td> <td> </td> <td> </td> <td> </td> <td style="border-right: 1px solid #0077c0"> </td> <td> </td> <td> </td> <td> </td> <td> </td> <td> </td> <td> </td> <td> </td> <td> </td> </tr> <tr valign="bottom"> <td> <div style="margin-left:30px; text-indent:-15px">of U.S. federal income tax benefit </div></td> <td> </td> <td> </td> <td align="right"><b>0.8</b></td> <td> </td> <td style="border-right: 1px solid #0077c0"> </td> <td> </td> <td> </td> <td align="right">0.9</td> <td> </td> <td> </td> <td> </td> <td align="right">1.0</td> <td> </td> </tr> <tr valign="bottom" style="background: #ffffff"> <td> <div style="margin-left:15px; text-indent:-15px">Prior year tax adjustments </div></td> <td> </td> <td nowrap="nowrap" align="left"> </td> <td align="right"><b>(0.6</b></td> <td nowrap="nowrap"><b>)</b></td> <td style="border-right: 1px solid #0077c0"> </td> <td> </td> <td nowrap="nowrap" align="left"> </td> <td align="right">(0.3</td> <td nowrap="nowrap">)</td> <td> </td> <td nowrap="nowrap" align="left"> </td> <td align="right">(0.1</td> <td nowrap="nowrap">)</td> </tr> <tr valign="bottom"> <td> <div style="margin-left:15px; text-indent:-15px">Tax credits </div></td> <td> </td> <td nowrap="nowrap" align="left"> </td> <td align="right"><b>(0.5</b></td> <td nowrap="nowrap"><b>)</b></td> <td style="border-right: 1px solid #0077c0"> </td> <td> </td> <td nowrap="nowrap" align="left"> </td> <td align="right">(1.1</td> <td nowrap="nowrap">)</td> <td> </td> <td nowrap="nowrap" align="left"> </td> <td align="right">(0.5</td> <td nowrap="nowrap">)</td> </tr> <tr valign="bottom" style="background: #ffffff"> <td> <div style="margin-left:15px; text-indent:-15px">Effects of enacted changes in tax laws </div></td> <td> </td> <td> </td> <td align="right"><b>0.0</b></td> <td> </td> <td style="border-right: 1px solid #0077c0"> </td> <td> </td> <td> </td> <td align="right">0.1</td> <td> </td> <td> </td> <td nowrap="nowrap" align="left"> </td> <td align="right">(0.6</td> <td nowrap="nowrap">)</td> </tr> <tr valign="bottom"> <td> <div style="margin-left:15px; text-indent:-15px">Other </div></td> <td> </td> <td> </td> <td align="right"><b>0.4</b></td> <td> </td> <td style="border-right: 1px solid #0077c0"> </td> <td> </td> <td nowrap="nowrap" align="left"> </td> <td align="right">(2.0</td> <td nowrap="nowrap">)</td> <td> </td> <td nowrap="nowrap" align="left"> </td> <td align="right">(0.7</td> <td nowrap="nowrap">)</td> </tr> <tr style="font-size: 1px"> <td colspan="5" align="left" style="border-top: 1px solid #0077c0"> </td> <td align="left" style="border-right: 1px solid #0077c0; border-top: 1px solid #0077c0"> </td> <td align="left" style="border-top: 1px solid #0077c0"> </td> <td colspan="6" align="left" style="border-top: 1px solid #0077c0"> </td> </tr> <tr valign="bottom" style="background: #ffffff"> <td> <div style="margin-left:15px; text-indent:-15px">Effective tax rate </div></td> <td> </td> <td nowrap="nowrap" align="left"> </td> <td align="right"><b>40.3</b></td> <td nowrap="nowrap"><b>%</b></td> <td style="border-right: 1px solid #0077c0"> </td> <td> </td> <td nowrap="nowrap" align="left"> </td> <td align="right">43.0</td> <td nowrap="nowrap">%</td> <td> </td> <td nowrap="nowrap" align="left"> </td> <td align="right">44.2</td> <td nowrap="nowrap">%</td> </tr> <tr style="font-size: 1px"> <td colspan="5" align="left" style="border-top: 3px solid #0077c0"> </td> <td align="left" style="border-right: 0px solid #0077c0; border-top: 3px solid #0077c0"> </td> <td align="left" style="border-top: 3px solid #0077c0"> </td> <td colspan="6" align="left" style="border-top: 3px solid #0077c0"> </td> </tr>  </table> </div> </div>

Composition of deferred tax balances


	At December 31
	2010			2009

Deferred tax liabilities
Properties, plant and equipment	$	19,855		$	18,545
Investments and other		2,401			2,350

Total deferred tax liabilities		22,256			20,895

Deferred tax assets
Foreign tax credits		(6,669	)		(5,387	)
Abandonment/environmental reserves		(5,004	)		(4,424	)
Employee benefits		(3,627	)		(3,499	)
Deferred credits		(2,176	)		(3,469	)
Tax loss carryforwards		(882	)		(819	)
Other accrued liabilities		(486	)		(553	)
Inventory		(483	)		(431	)
Miscellaneous		(1,676	)		(1,681	)

Total deferred tax assets		(21,003	)		(20,263	)

Deferred tax assets valuation allowance		9,185			7,921

Total deferred taxes, net	$	10,438		$	8,553

Classification of deferred taxes


	At December 31
	2010			2009

Prepaid expenses and other current assets	$	(1,624	)	$	(1,825	)
Deferred charges and other assets		(851	)		(1,268	)
Federal and other taxes on income		216			125
Noncurrent deferred income taxes		12,697			11,521

Total deferred income taxes, net	$	10,438		$	8,553

Changes to company's unrecognized tax benefits


	2010			2009			2008

Balance at January 1	$	3,195		$	2,696		$	2,199
Foreign currency effects		17			(1	)		(1	)
Additions based on tax positions taken in current year		334			459			522
Reductions based on tax positions taken in current year		–			–			(17	)
Additions/reductions resulting from current-year asset acquisitions/sales		–			–			175
Additions for tax positions taken in prior years		270			533			337
Reductions for tax positions taken in prior years		(165	)		(182	)		(246	)
Settlements with taxing authorities in current year		(136	)		(300	)		(215	)
Reductions as a result of a lapse of the applicable statute of limitations		(8	)		(10	)		(58	)

Balance at December 31	$	3,507		$	3,195		$	2,696

Taxes Other Than on Income


	Year ended December 31
	2010		2009			2008

United States
Excise and similar taxes on products and merchandise	$	4,484	$	4,573		$	4,748
Import duties and other levies		–		(4	)		1
Property and other miscellaneous taxes		567		584			588
Payroll taxes		219		223			204
Taxes on production		271		135			431

Total United States		5,541		5,511			5,972

International
Excise and similar taxes on products and merchandise		4,107		3,536			5,098
Import duties and other levies		6,183		6,550			8,368
Property and other miscellaneous taxes		2,000		1,740			1,557
Payroll taxes		133		134			106
Taxes on production		227		120			202

Total International		12,650		12,080			15,331

Total taxes other than on income	$	18,191	$	17,591		$	21,303

Short-Term Debt (Tables)

12 Months Ended

Dec. 31, 2010

Short-Term Debt (Tables) [Abstract]

Total short-term debt


	At December 31
	2010			2009

Commercial paper*	$	2,471		$	2,499
Notes payable to banks and others with originating terms of one year or less		43			213
Current maturities of long-term debt		33			66
Current maturities of long-term capital leases		81			76
Redeemable long-term obligations Long-term debt		2,943			1,702
Capital leases		16			18

Subtotal		5,587			4,574
Reclassified to long-term debt		(5,400	)		(4,190	)

Total short-term debt	$	187		$	384


*		Weighted-average interest rates at December 31, 2010 and 2009, were 0.16 percent and 0.08 percent, respectively.

Long Term Debt (Tables)

12 Months Ended

Dec. 31, 2010

Long Term Debt (Tables) [Abstract]

Total long-term debt


	At December 31
	2010			2009

3.95% notes due 2014	$	1,998		$	1,997
3.45% notes due 2012		1,500			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		72			109
9.75% debentures due 2020		54			56
8.875% debentures due 2021		40			40
8.625% debentures due 2010		–			30
Medium-term notes, maturing from
2021 to 2038 (5.97%)²		38			38
Fixed interest rate notes, maturing 2011 (9.378%)²		19			19
Other foreign currency obligations		–			–
Other long-term debt (5.66%)²		4			5

Total including debt due within one year		5,636			5,705
Debt due within one year		(33	)		(66	)
Reclassified from short-term debt		5,400			4,190

Total long-term debt	$	11,003		$	9,829


¹		Guarantee of ESOP debt.

²		Weighted-average interest rate at December 31, 2010.

Accounting for Suspended Exploratory Wells (Tables)

12 Months Ended

Dec. 31, 2010

Accounting For Suspended Exploratory Wells (Tables) [Abstract]

Changes in company's suspended exploratory well costs


	2010			2009			2008

Beginning balance at January 1	$	2,435		$	2,118		$	1,660
Additions to capitalized exploratory well costs pending the determination of proved reserves		482			663			643
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(129	)		(174	)		(49	)
Capitalized exploratory well costs charged to expense		(70	)		(172	)		(136	)

Ending balance at December 31	$	2,718		$	2,435		$	2,118

Aging of capitalized well costs and number of project


			At December 31
	2010		2009		2008

Exploratory well costs capitalized for a period of one year or less	$	419	$	564	$	559
Exploratory well costs capitalized for a period greater than one year		2,299		1,871		1,559

Balance at December 31	$	2,718	$	2,435	$	2,118

Number of projects with exploratory well costs that have been capitalized for a period greater than one year*		53		46		50


*		Certain projects have multiple wells or fields or both.

Aging costs on well and project basis


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

1992	$	8		3
1997–1999		27		6
2000–2004		442		54
2005–2009		1,822		113

Total	$	2,299		176


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

1992	$	8		1
1999		8		1
2003–2005		340		9
2006–2010		1,943		42

Total	$	2,299		53

Stock Options and Other Share-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2010

Stock Options and Other Share Based Compensation (Tables) [Abstract]

Fair market values of stock options and stock appreciation rights granted


	Year ended December 31
	2010			2009			2008

Stock Options
Expected term in years¹		6.1			6.0			6.1
Volatility²		30.8	%		30.2	%		22.0	%
Risk-free interest rate based on zero coupon U.S. treasury note		2.9	%		2.1	%		3.0	%
Dividend yield		3.9	%		3.2	%		2.7	%
Weighted-average fair value per option granted	$	16.28		$	15.36		$	15.97

Restored Options
Expected term in years¹		1.2			1.2			1.2
Volatility²		38.9	%		45.0	%		23.1	%
Risk-free interest rate based on zero coupon U.S. treasury note		0.6	%		1.1	%		1.9	%
Dividend yield		3.8	%		3.5	%		2.7	%
Weighted-average fair value per option granted	$	12.91		$	12.38		$	10.01


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, 2010		69,463		$	63.70
Granted		15,454		$	73.70
Exercised		(8,133	)	$	49.82
Restored		27		$	78.41
Forfeited		(1,959	)	$	73.34
Outstanding at December 31, 2010		74,852		$	67.04	6.4 yrs	$	1,813

Exercisable at December 31, 2010		48,174		$	63.29	5.2 yrs	$	1,348

Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2010

Employee Benefits Tables Abstract

Funded status of pension and other postretirement benefit plans


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

Change in Benefit Obligation
Benefit obligation at January 1	$	9,664		$	4,715		$	8,127		$	3,891		$	3,065		$	2,931
Service cost		337			153			266			128			39			43
Interest cost		486			307			481			292			175			180
Plan participants’ contributions		–			7			–			7			147			145
Plan amendments		–			–			1			10			12			20
Curtailments		–			–			–			–			–			(5	)
Actuarial loss (gain)		568			200			1,391			299			486			56
Foreign currency exchange rate changes		–			(17	)		–			333			11			27
Benefits paid		(784	)		(295	)		(602	)		(245	)		(330	)		(332	)

Benefit obligation at December 31		10,271			5,070			9,664			4,715			3,605			3,065

Change in Plan Assets
Fair value of plan assets at January 1		7,304			3,235			5,448			2,600			–			–
Actual return on plan assets		867			361			964			402			–			–
Foreign currency exchange rate changes		–			(63	)		–			226			–			–
Employer contributions		1,192			258			1,494			245			183			187
Plan participants’ contributions		–			7			–			7			147			145
Benefits paid		(784	)		(295	)		(602	)		(245	)		(330	)		(332	)

Fair value of plan assets at December 31		8,579			3,503			7,304			3,235			–			–

Funded Status at December 31	$	(1,692	)	$	(1,567	)	$	(2,360	)	$	(1,480	)	$	(3,605	)	$	(3,065	)

Consolidated Balance Sheet for pension and other postretirement benefit plans


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

Deferred charges and other assets	$	7		$	77		$	6		$	37		$	–		$	–
Accrued liabilities		(134	)		(71	)		(66	)		(67	)		(225	)		(208	)
Reserves for employee benefit plans		(1,565	)		(1,573	)		(2,300	)		(1,450	)		(3,380	)		(2,857	)

Net amount recognized at December 31	$	(1,692	)	$	(1,567	)	$	(2,360	)	$	(1,480	)	$	(3,605	)	$	(3,065	)

Before tax basis amount in Accumulated other comprehensive loss


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

Net actuarial loss	$	3,919		$	1,903	$	4,181		$	1,889	$	935		$	465
Prior service (credit) costs		(52	)		179		(60	)		201		(135	)		(222	)

Total recognized at December 31	$	3,867		$	2,082	$	4,121		$	2,090	$	800		$	243

Pension plans with an accumulated benefit obligation in excess of plan assets


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

Projected benefit obligations	$	10,265	$	3,668	$	9,658	$	3,550
Accumulated benefit obligations		9,528		3,113		8,702		3,102
Fair value of plan assets		8,566		2,190		7,292		2,116

Components of net periodic benefit cost and amounts recognized in other comprehensive income


	Pension Benefits
	2010						2009						2008						Other Benefits
	U.S.			Int’l.			U.S.			Int’l.			U.S.			Int’l.			2010			2009			2008

Net Periodic Benefit Cost
Service cost	$	337		$	153		$	266		$	128		$	250		$	132		$	39		$	43		$	44
Interest cost		486			307			481			292			499			292			175			180			178
Expected return on plan assets		(538	)		(241	)		(395	)		(203	)		(593	)		(273	)		–			–			–
Amortization of prior service (credits) costs		(8	)		22			(7	)		23			(7	)		24			(75	)		(81	)		(81	)
Recognized actuarial losses		318			98			298			108			60			77			27			27			38
Settlement losses		186			6			141			1			306			2			–			–			–
Curtailment losses		–			–			–			–			–			–			–			(5	)		–
Special termination benefit recognition		–			–			–			–			–			1			–			–			–

Total net periodic benefit cost		781			345			784			349			515			255			166			164			179

Changes Recognized in Other Comprehensive Income
Net actuarial loss (gain) during period		242			118			823			194			2,624			646			497			82			(42	)
Amortization of actuarial loss		(504	)		(104	)		(439	)		(109	)		(366	)		(79	)		(27	)		(27	)		(38	)
Prior service cost during period		–			–			1			13			–			32			12			20			–
Amortization of prior service credits (costs)		8			(22	)		7			(23	)		7			(24	)		75			81			81

Total changes recognized in other comprehensive income		(254	)		(8	)		392			75			2,265			575			557			156			1

Recognized in Net Periodic Benefit Cost and Other Comprehensive Income	$	527		$	337		$	1,176		$	424		$	2,780		$	830		$	723		$	320		$	180

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


	Pension Benefits
	2010						2009						2008						Other Benefits
	U.S.			Int’l.			U.S.			Int’l.			U.S.			Int’l.			2010			2009			2008

Assumptions used to determine
benefit obligations:
Discount rate		4.8	%		6.5	%		5.3	%		6.8	%		6.3	%		7.5	%		5.2	%		5.9	%		6.3	%
Rate of compensation increase		4.5	%		6.7	%		4.5	%		6.3	%		4.5	%		6.8	%		N/A			N/A			4.0	%
Assumptions used to determine
net periodic benefit cost:
Discount rate		5.3	%		6.8	%		6.3	%		7.5	%		6.3	%		6.7	%		5.9	%		6.3	%		6.3	%
Expected return on plan assets		7.8	%		7.8	%		7.8	%		7.5	%		7.8	%		7.4	%		N/A			N/A			N/A
Rate of compensation increase		4.5	%		6.3	%		4.5	%		6.8	%		4.5	%		6.4	%		N/A			N/A			4.5	%

Effects of change in assumed health care cost-trend rates


	1 Percent		1 Percent
	Increase		Decrease

Effect on total service and interest cost components	$	11	$	(9	)
Effect on postretirement benefit obligation	$	146	$	(125	)

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, 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

At December 31, 2009
Equities
U.S.¹	$	2,115		$	2,115		$	–	$	–	$	370	$	370		$	–	$	–
International		977			977			–		–		492		492			–		–
Collective Trusts/Mutual Funds^2,6		1,264			3			1,261		–		786		91			695		–
Fixed Income
Government		713			149			564		–		506		54			452		–
Corporate		430			–			430		–		371		17			336		18
Mortgage-Backed Securities		149			–			149		–		2		–			–		2
Other Asset Backed		90			–			90		–		19		–			19		–
Collective Trusts/Mutual Funds²		326			–			326		–		230		14			216		–
Mixed Funds^3,6		8			8			–		–		105		17			88		–
Real Estate⁴		479			–			–		479		131		–			–		131
Cash and Cash Equivalents		743			743			–		–		207		207			–		–
Other⁵		10			(57	)		16		51		16		(3	)		18		1

Total at December 31, 2009	$	7,304		$	3,938		$	2,836	$	530	$	3,235	$	1,259		$	1,824	$	152


¹	U.S. equities include investments in the company’s common stock in the amount of $38 at December 31, 2010 and $29 at December 31, 2009.

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).

⁶	Certain amounts have been reclassified to conform to their 2010 presentation.

Effect of fair-value measurements using significant unobservable inputs on changes in Level 3 plan assets


				Fixed Income
							Mortgage-
							Backed
	U.S. Equities			Corporate			Securities		Real Estate			Other		Total

Total at December 31, 2008	$	1		$	23		$	2	$	763		$	52	$	841
Actual Return on Plan Assets:
Assets held at the reporting date		(1	)		2			–		(178	)		–		(177	)
Assets sold during the period		–			5			–		8			–		13
Purchases, Sales and Settlements		–			(12	)		–		17			–		5
Transfers in and/or out of Level 3		–			–			–		–			–		–

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

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


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

2011	$	994	$	247	$	225
2012	$	926	$	298	$	230
2013	$	924	$	300	$	238
2014	$	934	$	320	$	246
2015	$	937	$	346	$	253
2016–2020	$	4,687	$	2,095	$	1,345

LESOP shares


Thousands	2010		2009

Allocated shares		20,718		21,211
Unallocated shares		2,374		3,636

Total LESOP shares		23,092		24,847

Restructuring And Reorganization (Tables)

12 Months Ended

Dec. 31, 2010

Restructuring And Reorganization (Tables) [Abstract]

Restructuring and Reorganization Costs


	Amounts Before Tax

Balance at January 1, 2010		$	–
Accruals			244
Adjustments			(10	)
Payments			(96	)

Balance at December 31, 2010		$	138

Asset Retirement Obligations [Tables]

12 Months Ended

Dec. 31, 2010

Asset Retirement Obligations [Tables] [Abstract]

Company Before Tax Obligation


	2010			2009			2008

Balance at January 1	$	10,175		$	9,395		$	8,253
Liabilities incurred		129			144			308
Liabilities settled		(755	)		(757	)		(973	)
Accretion expense		513			463			430
Revisions in estimated cash flows		2,426			930			1,377

Balance at December 31	$	12,488		$	10,175		$	9,395

Other Financial Information (Tables)

12 Months Ended

Dec. 31, 2010

Other Financial Information (Tables) [Abstract]

Other Finacial Information


	Year ended December 31
	2010			2009			2008

Total financing interest and debt costs	$	317		$	301		$	256
Less: Capitalized interest		267			273			256

Interest and debt expense	$	50		$	28		$	–

Research and development expenses	$	526		$	603		$	702

Foreign currency effects*	$	(423	)	$	(744	)	$	862


*	Includes $(71), $(194) and $420 in 2010, 2009 and 2008, respectively, for the company’s share of equity affiliates’ foreign currency effects.

Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2010

Earnings Per Share (Tables) [Abstract]

Computation of basic and diluted EPS


	Year ended December 31
	2010		2009		2008

Basic EPS Calculation

Earnings available to common stockholders – Basic¹	$	19,024	$	10,483	$	23,931

Weighted-average number of common shares outstanding		1,996		1,991		2,037
Add: Deferred awards held as stock units		1		1		1

Total weighted-average number of common shares outstanding		1,997		1,992		2,038

Earnings per share of common stock – Basic	$	9.53	$	5.26	$	11.74

Diluted EPS Calculation

Earnings available to common stockholders – Diluted¹	$	19,024	$	10,483	$	23,931

Weighted-average number of common shares outstanding		1,996		1,991		2,037
Add: Deferred awards held as stock units		1		1		1
Add: Dilutive effect of employee stock-based awards		10		9		12

Total weighted-average number of common shares outstanding		2,007		2,001		2,050

Earnings per share of common stock – Diluted	$	9.48	$	5.24	$	11.67


¹	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)	12 Months Ended
Summary of Significant Accounting Policies (Details)	Dec. 31, 2010
Summary of Significant Accounting Policies (Textuals) [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

Agreement to Acquire Atlas Energy, Inc. (Details) $ in Millions	Feb. 28, 2011 USD ($)
Agreement to Acquire Atlas Energy, Inc. (Textuals)
Cost of acquisition of Atlas Energy including assumed debt	$ 4,470

Noncontrolling Interests (Details) - USD ($) $ in Millions	12 Months Ended
Noncontrolling Interests (Details) - USD ($) $ in Millions	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Activity for equity attributable to noncontrolling interests
Beginning Balance	$ 647	$ 469
Net income	112	80	$ 100
Ending Balance	730	647	469
Noncontrolling Interest [Member]
Activity for equity attributable to noncontrolling interests
Beginning Balance	647	469	204
Net income	112	80	100
Distributions to noncontrolling interests	(72)	(71)	(99)
Other changes, net	43	169	264
Ending Balance	$ 730	$ 647	$ 469

Information Relating to the Consolidated Statement of Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Net decrease (increase) in operating working capital
(Increase) decrease in accounts and notes receivable	$ (2,767)	$ (1,476)	$ 6,030
Decrease (Increase) in inventories	15	1,213	(1,545)
Increase in prepaid expenses and other current assets	(542)	(264)	(621)
Increase (Decrease) in accounts payable and accrued liabilities	3,049	(1,121)	(4,628)
Increase (decrease) in income and other taxes payable	321	(653)	(909)
Net decrease (increase) in operating working capital	76	(2,301)	(1,673)
Net Cash Provided by Operating Activities
Interest paid on debt (net of capitalized interest)	34
Income taxes	11,749	7,537	19,130
Net sales of marketable securities
Marketable securities sold	41	157	3,719
Marketable securities purchased	(90)	(30)	(3,236)
Net (purchases) sales of marketable securities	(49)	127	483
Net purchases of time deposits
Time deposits purchased	(5,060)
Time deposits matured	2,205
Net purchases of time deposits	(2,855)
Capital expenditures
Additions to properties, plant and equipment	18,474	16,107	18,495
Additions to investments	861	942	1,051
Current year dry hole expenditures	414	468	320
Payments for other liabilities and assets, net	(137)	2,326	(200)
Capital expenditures	19,612	19,843	19,666
Expensed exploration expenditures	651	790	794
Assets acquired through capital lease obligations and other financing obligations	104	19	9
Capital and exploratory expenditures, excluding equity affiliates	20,367	20,652	20,469
Company's share of expenditures by equity affiliates	1,388	1,585	2,306
Capital and exploratory expenditures, including equity affiliates	21,755	22,237	22,775
Information Relating to the Consolidated Statement of Cash Flows (Textuals) [Abstract]
Tax Benefit from Stock Options Exercised	67	25	106
Net sales (purchases) of treasury shares	(775)	(6)	(8,011)
Tax-exempt bonds issued to fund U.S. refinery projects	1,250	350
Treasury shares acquired in exchange for U.S. upstream property			680
Treasury shares acquired in cash			280
Increase in accrued liabilities			2,450
Increase in property, plant and equipments related to acquisition of additional interest in equity affiliate			1,400
Noncash Additions to property, plant and equipment	$ 2,753	985	$ 5,153
Payments for Accrued liabilities		$ 2,450

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

12 Months Ended

Dec. 31, 2010

Dec. 31, 2009

Dec. 31, 2008

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

^[1]

$ 198,198

$ 167,402

$ 264,958

Net Income Attributable to Chevron Corporation

172,873

153,108

229,948

19,024

10,483

23,931

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

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

145,381

121,553

195,593

Net Income Attributable to Chevron Corporation

139,984

120,053

185,788

$ 4,159

$ 1,141

$ 7,318

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

Summarized Financial Data - Chevron U.S.A. Inc. (Details 1) - USD ($) $ in Millions	Dec. 31, 2010	Dec. 31, 2009
Balance Sheet - Chevron U.S.A. Inc.
Current assets	$ 48,841	$ 37,216
Other assets	11,813	12,022
Current liabilities	29,012	26,211
Other liabilities	4,130	4,484
Chevron U.S.A. Inc. [Member]
Balance Sheet - Chevron U.S.A. Inc.
Current assets	29,211	23,286
Other assets	35,294	32,827
Current liabilities	18,098	16,098
Other liabilities	16,785	14,625
Total CUSA net equity	29,622	25,390
Memo: Total debt	$ 8,284	$ 6,999

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

12 Months Ended

Dec. 31, 2010

Dec. 31, 2009

Dec. 31, 2008

Summarized Financial Data - Chevron Transport Corporation

^[1]

$ 198,198

$ 167,402

$ 264,958

Net (loss) income attributable to CTC

172,873

153,108

229,948

19,024

10,483

23,931

Chevron Transport Corporation [Member]

Summarized Financial Data - Chevron Transport Corporation

885

683

1,022

Net (loss) income attributable to CTC

1,008

810

947

$ (116)

$ (124)

$ 120

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

Summarized Financial Data - Chevron Transport Corporation Ltd. (Details 1) - USD ($) $ in Millions	Dec. 31, 2010	Dec. 31, 2009
Balance Sheet - Chevron Transport Corporation
Current assets	$ 48,841	$ 37,216
Other assets	11,813	12,022
Current liabilities	29,012	26,211
Other liabilities	4,130	4,484
Chevron Transport Corporation [Member]
Balance Sheet - Chevron Transport Corporation
Current assets	209	377
Other assets	201	173
Current liabilities	101	115
Other liabilities	75	90
Total CTC net equity	$ 234	$ 345

Summarized Financial Data - Tengizchevroil LLP (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Summarized Financial Data - Tengizchevroil LLP
Sales and other operating revenues	$ 17,812	$ 12,013	$ 14,329
Costs and other deductions	8,394	6,044	5,621
Net income attributable to TCO	6,593	4,178	$ 6,134
Current assets	3,376	3,190
Other assets	11,813	12,022
Current liabilities	2,402	2,426
Other liabilities	4,130	4,484
Total TCO net equity	$ 8,657	$ 8,302
Summarized Financial Data (Textuals) [Abstract]
Equity ownership interest by Chevron in TCO (percentage)	50.00%

Lease Commitments (Details) - USD ($) $ in Millions	12 Months Ended
Lease Commitments (Details) - USD ($) $ in Millions	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Schedule of capitalized leased assets
Upstream capital leases	$ 561	$ 510
Downstream capital leases	316	334
All other capital leases	169	169
Gross capitalized lease assets	1,046	1,013
Less: Accumulated amortization of capital leases	573	585
Net capitalized leased assets	473	428
Rental expenses incurred for operating leases
Minimum rentals operating lease expense	2,373	2,179	$ 2,984
Contingent rentals operating lease expense	10	7	6
Gross rental operating lease expense	2,383	2,186	2,990
Less: Sublease rental income on operating lease	41	41	41
Net Rental Expense On Operating Leases	2,342	2,145	$ 2,949
Estimated future minimum lease payments (net of noncancellable sublease rentals) under operating and capital leases
Future minimum operating lease payments, current	650
Future minimum capital lease payments, current	99
Future minimum operating lease payments, due in two years	530
Future minimum capital lease payments, due in two years	93
Future minimum operating lease payments, due in three years	370
Future minimum capital lease payments, due in three years	68
Future minimum operating lease payments, due in four years	288
Future minimum capital lease payments, due in four years	51
Future minimum operating lease payments, due in five years	273
Future minimum capital lease payments, due in five years	40
Future minimum operating lease payments, due thereafter	725
Future minimum capital lease payments, due thereafter	137
Future minimum operating lease payments, total	2,836
Future minimum capital lease payments, total	488
Less: Amounts representing interest and executory costs in future capital lease payments	(105)
Future minimum capital lease payments, net present value	383
Current maturities of long-term capital leases	(97)
Long Term capital lease obligations	$ 286	$ 301
Lease Commitments (Textuals) [Abstract]
Renewal term of leasing arrangement (in years)	Up to 25
Non-cancellable term of operating and capital leases (in years)	more than 1

Fair Value Measurements (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
Fair Value Measurements (Details) - USD ($) $ in Millions	Sep. 30, 2010	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008	Dec. 31, 2007
Fair Value, Assets Measured on Recurring Basis, Financial Statement Captions [Line Items]
Marketable securities		$ 155	$ 106
Derivatives		122	127
Total Recurring Assets at Fair Value		277	233
Fair Value, Liabilities Measured on Recurring Basis, Financial Statement Captions [Line Items]
Derivatives		171	101
Total Recurring Liabilities at Fair Value		171	101
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying amount of long-term debt		$ 5,636	5,705
Fair Value Measurements (Textuals) [Abstract]
Maturity period of primarily bank time deposits, classified as cash equivalents		90 Days or less
Fair value of cash equivalents		$ 14,060	8,716	$ 9,347	$ 7,362
Maturity period of bank time deposits	Greater than 90 days
Time deposits		2,855	0
Fair value of investments not included in cash and cash equivalents		855	123
Carrying amount of long-lived assets "held and used"		142	949
Carrying amount of long-lived assets "held for sale"		49	160
Carrying amount of Investments and advances		15	81
Carrying Amount of Long-term Debt [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying amount of long-term debt		5,636	5,705
Fair Value of Long-term Debt [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying amount of long-term debt		6,311	6,229
Prices in Active Markets for Identical Assets (Level 1) [Member]
Fair Value, Liabilities Measured on Recurring Basis, Financial Statement Captions [Line Items]
Derivatives		75	20
Total Recurring Liabilities at Fair Value		75	20
Other Observable Inputs (Level 2) [Member]
Fair Value, Liabilities Measured on Recurring Basis, Financial Statement Captions [Line Items]
Derivatives		96	81
Total Recurring Liabilities at Fair Value		96	81
Unobservable Inputs (Level 3) [Member]
Fair Value, Liabilities Measured on Recurring Basis, Financial Statement Captions [Line Items]
Derivatives		0	0
Total Recurring Liabilities at Fair Value		0	0
Prices in Active Markets for Identical Assets (Level 1) [Member]
Fair Value, Assets Measured on Recurring Basis, Financial Statement Captions [Line Items]
Marketable securities		155	106
Derivatives		11	14
Total Recurring Assets at Fair Value		166	120
Other Observable Inputs (Level 2) [Member]
Fair Value, Assets Measured on Recurring Basis, Financial Statement Captions [Line Items]
Marketable securities		0	0
Derivatives		111	113
Total Recurring Assets at Fair Value		111	113
Unobservable Inputs (Level 3) [Member]
Fair Value, Assets Measured on Recurring Basis, Financial Statement Captions [Line Items]
Marketable securities		0	0
Derivatives		0	0
Total Recurring Assets at Fair Value		$ 0	$ 0

Fair Value Measurements (Details 1) - USD ($) $ in Millions	12 Months Ended
Fair Value Measurements (Details 1) - USD ($) $ in Millions	Dec. 31, 2010	Dec. 31, 2009
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Properties, plant and equipment, net (held and used)	$ 57	$ 490
Properties, plant and equipment, net (held for sale)	13	68
Investments and advances	0	39
Total Nonrecurring Assets at Fair Value	70	597
Assets and Liabilities Measured at Fair Value on Nonrecurring Basis (Textuals) [Abstract]
Fair Value of Investments after write down	0	39
Impairment of Investments	15	42
Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets and Liabilities Measured at Fair Value on a Nonrecurring 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 Nonrecurring Assets at Fair Value	0	0
Other Observable Inputs (Level 2) [Member]
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Properties, plant and equipment, net (held and used)	0	0
Properties, plant and equipment, net (held for sale)	0	68
Investments and advances	0	0
Total Nonrecurring Assets at Fair Value	0	68
Unobservable Inputs (Level 3) [Member]
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Properties, plant and equipment, net (held and used)	57	490
Properties, plant and equipment, net (held for sale)	13	0
Investments and advances	0	39
Total Nonrecurring Assets at Fair Value	70	529
Loss (Before Tax) [Member]
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Properties, plant and equipment, net (held and used)	85	459
Properties, plant and equipment, net (held for sale)	36	92
Investments and advances	15	42
Total Nonrecurring Assets at Fair Value	$ 136	$ 593

Financial and Derivative Instruments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Consolidated Statement of Income: The Effect of Derivatives not Designated as Hedging Instruments
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ (135)	$ (421)	$ 813
Consolidated Balance Sheet: Fair Value of Derivatives not Designated as Hedging Instruments
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value	122	127
Derivative Instruments Not Designated as Hedging Instruments, Liability, at Fair Value	171	101
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	(314)
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	(1)		(3)
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	(36)	(353)	424
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	$ (98)	$ (94)	$ 706

Operating Segments and Geographic Data (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Segment Earnings
Total Segment Earnings	$ 20,155	$ 11,405	$ 25,321
Net Income Attributable to Chevron Corporation	19,024	10,483	23,931
Upstream [Member]
Segment Earnings
United States	4,122	2,262	7,147
International	13,555	8,670	15,022
Total Segment Earnings	17,677	10,932	22,169
Downstream [Member]
Segment Earnings
United States	1,339	(121)	1,369
International	1,139	594	1,783
Total Segment Earnings	2,478	473	3,152
All Other [Member]
Segment Earnings
Interest Expense	(41)	(22)
Interest Income	70	46	192
Other	$ (1,160)	$ (946)	$ (1,582)

Operating Segments and Geographic Data (Details 1) - USD ($) $ in Millions	Dec. 31, 2010	Dec. 31, 2009
Segment Assets
Goodwill	$ 4,617	$ 4,618
Segment Assets	162,207	151,240
Total Assets - United States	58,850	52,920
Total Assets - International	121,302	107,083
Total Assets	184,769	164,621
Upstream [Member]
Segment Assets
United States	26,319	25,478
International	89,306	81,209
Goodwill	4,617	4,618
Segment Assets	120,242	111,305
Downstream [Member]
Segment Assets
United States	21,406	20,317
International	20,559	19,618
Segment Assets	41,965	39,935
All Other [Member]
Segment Assets
United States	11,125	7,125
International	11,437	6,256
Total All Other	$ 22,562	$ 13,381

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

12 Months Ended

Dec. 31, 2010

Dec. 31, 2009

Dec. 31, 2008

Elimination of intersegment sales

$ (38,867)

$ (29,956)

$ (40,639)

Total Sales and Other Operating Revenues

^[1]

$ 198,198

167,402

264,958

Operating Segments and Geographic Data (Textual) [Abstract]

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

Less than 10 %

Upstream [Member]

Intersegment - United States

$ 10,316

9,225

23,566

13,839

10,297

15,162

Total United States

24,155

19,522

38,728

Intersegment - International

17,300

13,463

19,531

23,834

18,477

24,205

Total International

41,134

31,940

43,736

65,289

51,462

82,464

Downstream [Member]

Domestic excise and similar taxes

70,436

58,056

87,759

4,484

4,573

4,748

Intersegment - United States

115

242

Total United States

75,035

62,727

92,749

International Excise and Similar Taxes

90,922

77,845

123,389

4,107

3,536

5,098

Intersegment - International

Total International

95,122

81,468

128,567

170,157

144,195

221,316

All Other [Member]

Intersegment - United States

610

665

815

947

964

917

Total United States

1,557

1,629

1,732

Intersegment - International

Total International

Sales and Other Operating Revenue [Member]

1,619

1,701

1,817

100,747

83,878

133,209

136,318

113,480

172,388