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Document and Company Information - USD ($)	12 Months Ended
Document and Company Information - USD ($)	Dec. 31, 2009	Feb. 19, 2010	Jun. 30, 2009
Document and Company Information [Abstract]
Entity Registrant Name	CHEVRON CORP
Entity Central Index Key	0000093410
Document Type	10-K
Document Period End Date	Dec. 31, 2009
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 132,865,210,015
Entity Common Stock, Shares Outstanding		2,008,352,638

Consolidated Statement of Income - USD ($) $ in Millions	12 Months Ended
Consolidated Statement of Income - USD ($) $ in Millions	Dec. 31, 2009	Dec. 31, 2008	Dec. 31, 2007
Revenues and Other Income
Sales and other operating revenues*	$ 167,402	$ 264,958	$ 214,091
Income from equity affiliates	3,316	5,366	4,144
Other income	918	2,681	2,669
Total Revenues and Other Income	171,636	273,005	220,904
Costs and Other Deductions
Purchased crude oil and products	99,653	171,397	133,309
Operating expenses	17,857	20,795	16,932
Selling, general and administrative expenses	4,527	5,756	5,926
Exploration expenses	1,342	1,169	1,323
Depreciation, depletion and amortization	12,110	9,528	8,708
Taxes other than on income*	17,591	21,303	22,266
Interest and debt expense	28	0	166
Total Costs and Other Deductions	153,108	229,948	188,630
Income Before Income Tax Expense	18,528	43,057	32,274
Income Tax Expense	7,965	19,026	13,479
Net Income	10,563	24,031	18,795
Less: Net income attributable to noncontrolling interests	80	100	107
Net Income Attributable to Chevron Corporation	$ 10,483	$ 23,931	$ 18,688
Per-Share of Common Stock
Net Income Attributable to Chevron Corporation - Basic	$ 5.26	$ 11.74	$ 8.83
Net Income Attributable to Chevron Corporation - Diluted	$ 5.24	$ 11.67	$ 8.77
*Includes excise, value-added and similar taxes.	$ 8,109	$ 9,846	$ 10,121

Consolidated Statement of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2009	Dec. 31, 2008	Dec. 31, 2007
Statement of Comprehensive Income [Abstract]
Net Income	$ 10,563	$ 24,031	$ 18,795
Currency translation adjustment
Unrealized net change arising during period	60	(112)	31
Unrealized holding gain (loss) on securities
Net gain (loss) arising during period	2	(6)	17
Reclassification to net income of net realized loss	0	0	2
Total	2	(6)	19
Derivatives
Net derivatives (loss) gain on hedge transactions	(69)	139	(10)
Reclassification to net income of net realized (gain) loss	(23)	32	7
Income taxes on derivatives transactions	32	(61)	(3)
Total	(60)	110	(6)
Defined benefit plans - Actuarial loss
Amortization to net income of net actuarial loss	575	483	356
Actuarial (loss) gain arising during period	(1,099)	(3,228)	530
Defined benefit plans - Prior service cost
Amortization to net income of net prior service credits	(65)	(64)	(15)
Prior service (cost) credit arising during period	(34)	(32)	204
Defined benefit plans sponsored by equity affiliates	65	(97)	19
Income taxes on defined benefit plans	159	1,037	(409)
Total	(399)	(1,901)	685
Other Comprehensive (Loss) Gain, Net of Tax	(397)	(1,909)	729
Comprehensive Income	10,166	22,122	19,524
Comprehensive income attributable to noncontrolling interests	(80)	(100)	(107)
Comprehensive Income Attributable to Chevron Corporation	$ 10,086	$ 22,022	$ 19,417

Consolidated Balance Sheet - USD ($) $ in Millions	Dec. 31, 2009	Dec. 31, 2008
Assets
Cash and cash equivalents	$ 8,716	$ 9,347
Marketable securities	106	213
Accounts and notes receivable (less allowance: 2009 - $228; 2008 - $246)	17,703	15,856
Inventories:
Crude oil and petroleum products	3,680	5,175
Chemicals	383	459
Materials, supplies and other	1,466	1,220
Total inventories	5,529	6,854
Prepaid expenses and other current assets	5,162	4,200
Total Current Assets	37,216	36,470
Long-term receivables, net	2,282	2,413
Investments and advances	21,158	20,920
Properties, plant and equipment, at cost	188,288	173,299
Less: Accumulated depreciation, depletion and amortization	91,820	81,519
Properties, plant and equipment, net	96,468	91,780
Deferred charges and other assets	2,879	4,711
Goodwill	4,618	4,619
Assets held for sale	0	252
Total Assets	164,621	161,165
Liabilities and Equity
Short-term debt	384	2,818
Accounts payable	16,437	16,580
Accrued liabilities	5,375	8,077
Federal and other taxes on income	2,624	3,079
Other taxes payable	1,391	1,469
Total Current Liabilities	26,211	32,023
Long-term debt	9,829	5,742
Capital lease obligations	301	341
Deferred credits and other noncurrent obligations	17,390	17,678
Noncurrent deferred income taxes	11,521	11,539
Reserves for employee benefit plans	6,808	6,725
Total Liabilities	72,060	74,048
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, 2009 and 2008)	1,832	1,832
Capital in excess of par value	14,631	14,448
Retained earnings	106,289	101,102
Accumulated other comprehensive loss	(4,321)	(3,924)
Deferred compensation and benefit plan trust	(349)	(434)
Treasury stock, at cost (2009 - 434,954,774 shares; 2008 - 438,444,795 shares)	(26,168)	(26,376)
Total Chevron Corporation Stockholders' Equity	91,914	86,648
Noncontrolling interests	647	469
Total Equity	92,561	87,117
Total Liabilities and Equity	$ 164,621	$ 161,165

Consolidated Statement of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2009	Dec. 31, 2008	Dec. 31, 2007
Operating Activities
Net Income	$ 10,563	$ 24,031	$ 18,795
Adjustments
Depreciation, depletion and amortization	12,110	9,528	8,708
Dry hole expense	552	375	507
Distributions less than income from equity affiliates	(103)	(440)	(1,439)
Net before-tax gains on asset retirements and sales	(1,255)	(1,358)	(2,315)
Net foreign currency effects	466	(355)	378
Deferred income tax provision	467	598	261
Net (increase) decrease in operating working capital	(2,301)	(1,673)	685
Increase in long-term receivables	(258)	(161)	(82)
Decrease (increase) in other deferred charges	201	(84)	(530)
Cash contributions to employee pension plans	(1,739)	(839)	(317)
Other	670	10	326
Net Cash Provided by Operating Activities	19,373	29,632	24,977
Investing Activities
Capital expenditures	(19,843)	(19,666)	(16,678)
Proceeds and deposits related to asset sales	2,564	1,491	3,338
Net sales of marketable securities	127	483	185
Repayment of loans by equity affiliates	336	179	21
Net sales (purchases) of other short-term investments	244	432	(799)
Net Cash Used for Investing Activities	(16,572)	(17,081)	(13,933)
Financing Activities
Net (payments) borrowings of short-term obligations	(3,192)	2,647	(345)
Proceeds from issuance of long-term debt	5,347	0	650
Repayments of long-term debt and other financing obligations	(496)	(965)	(3,343)
Cash dividends - common stock	(5,302)	(5,162)	(4,791)
Distributions to noncontrolling interests	(71)	(99)	(77)
Net sales (purchases) of treasury shares	168	(6,821)	(6,389)
Net Cash Used for Financing Activities	(3,546)	(10,400)	(14,295)
Effect of Exchange Rate Changes on Cash and Cash Equivalents	114	(166)	120
Net Change in Cash and Cash Equivalents	(631)	1,985	(3,131)
Cash and Cash Equivalents at January 1	9,347	7,362	10,493
Cash and Cash Equivalents at December 31	$ 8,716	$ 9,347	$ 7,362

Consolidated Statement of Equity - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2009	Dec. 31, 2008	Dec. 31, 2007
Statement [Line Items]
Beginning Balance	$ 86,648	$ 77,088
Net Income Attributable to Chevron Corporation	10,483	23,931	$ 18,688
Notes Receivable - Key Employees	0	0	(1)
Currency translation adjustment
Unrealized net change arising during period	60	(112)	31
Unrealized Net Holding Gain On Securities
Change during year (Unrealized net holding gain on securities)	2	(6)	19
Net derivatives gain (loss) on hedge transactions
Ending Balance	91,914	86,648	77,088
Noncontrolling interests	647	469	204
Total Equity	92,561	87,117	77,292
Deferred Compensation Benefit Plan Trust
Statement [Line Items]
Beginning Balance	$ (434)	$ (454)
Shares, Beginning Balance	14,168	14,168
Net derivatives gain (loss) on hedge transactions
Deferred Compensation and Benefit Plan Trust Deferred Compensation, Beginning Balance	$ (194)	$ (214)	(214)
Net reduction of ESOP debt and other	85	20	0
Deferred Compensation and Benefit Plan Trust Deferred Compensation, Ending Balance	(109)	(194)	(214)
Benefit Plan Trust (Common Stock)	$ (240)	$ (240)	$ (240)
Benefit Plan Trust (Common Stock), shares	14,168	14,168	14,168
Ending Balance	$ (349)	$ (434)	$ (454)
Shares, Ending Balance	14,168	14,168	14,168
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	$ 1,832	$ 1,832	$ 1,832
Shares, Ending Balance	2,442,677	2,442,677	2,442,677
Capital in Excess of Par
Statement [Line Items]
Beginning Balance	$ 14,448	$ 14,289	$ 14,126
Treasury stock transactions	183	159	163
Net derivatives gain (loss) on hedge transactions
Ending Balance	14,631	14,448	14,289
Treasury Stock at Cost
Statement [Line Items]
Beginning Balance	$ (26,376)	$ (18,892)	$ (12,395)
Shares, Beginning Balance	438,445	352,243	278,118
Net derivatives gain (loss) on hedge transactions
Treasury Stock at cost, Purchases	$ (6)	$ (8,011)	$ (7,036)
Treasury Stock at cost, Purchases, shares	85	95,631	85,429
Issuances- mainly employee benefit plans	$ 214	$ 527	$ 539
Issuances - mainly employee benefit plans, shares	(3,575)	(9,429)	(11,304)
Ending Balance	$ (26,168)	$ (26,376)	$ (18,892)
Shares, Ending Balance	434,955	438,445	352,243
Retained Earnings
Statement [Line Items]
Beginning Balance	$ 101,102	$ 82,329	$ 68,464
Net Income Attributable to Chevron Corporation	10,483	23,931	18,688
Cash dividends on common stock	(5,302)	(5,162)	(4,791)
Adoption of new accounting standard for uncertain income tax positions	0	0	(35)
Tax benefit from dividends paid on unallocated ESOP shares and other	6	4	3
Net derivatives gain (loss) on hedge transactions
Ending Balance	106,289	101,102	82,329
Accumulated Other Comprehensive Loss
Statement [Line Items]
Beginning Balance	(3,924)	(2,015)
Currency translation adjustment
Currency Translation Adjustment, Beginning Balance	(171)	(59)	(90)
Unrealized net change arising during period	60	(112)	31
Currency Translation Adjustment, Ending Balance	(111)	(171)	(59)
Pension And Other Postretirement Benefit Plans
Pension and other postretirement benefit plans, Beginning Balance	(3,909)	(2,008)	(2,585)
Change to defined benefit plans during year	(399)	(1,901)	685
Adoption of new accounting standard for defined benefit pension and other retirement plans	0	0	(108)
Pension and other postretirement benefit plans, Ending Balance	(4,308)	(3,909)	(2,008)
Unrealized Net Holding Gain On Securities
Unrealized net holding gain on securities, Beginning Balance	13	19	0
Change during year (Unrealized net holding gain on securities)	2	(6)	19
Unrealized net holding gain on securities, Ending Balance	15	13	19
Net derivatives gain (loss) on hedge transactions
Net derivatives gain (loss) on hedge transactions, Beginning Balance	143	33	39
Change during year (derivatives)	(60)	110	(6)
Net derivatives gain (loss) on hedge transactions, Ending Balance	83	143	33
Ending Balance	$ (4,321)	$ (3,924)	$ (2,015)

Summary of Significant Accounting Policies	12 Months Ended
Summary of Significant Accounting Policies	Dec. 31, 2009
Summary of Significant Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 1 Summary of Significant Accounting Policies General Exploration and production (upstream) operations consist of exploring for, developing and producing crude oil and natural gas and marketing natural gas. Refining, marketing and transportation (downstream) operations relate to refining crude oil into finished petroleum products; marketing crude oil and the many products derived from petroleum; and transporting crude oil, natural gas and petroleum products by pipeline, marine vessel, motor equipment and rail car. Chemical operations include the manufacture and marketing of commodity petrochemicals, plastics for industrial uses, and fuel and lubricant oil additives. 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 and foreign currency exposures, gains and losses from derivative instruments are reported in current income. Interest rate swaps – hedging a portion of the company’s fixed-rate debt – are accounted for as fair value hedges, whereas interest rate swaps relating to a portion of the company’s floating-rate debt are recorded at fair value on the Consolidated 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 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.” The balance of the 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 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 the refining, marketing, transportation and chemicals areas, 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. As required under accounting standards for asset retirement and environmental 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 23, on page FS-60, 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 23, on page FS-60, 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 translations are currently included in 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.

Information Relating to the Consolidated Statement of Cash Flows

12 Months Ended

Dec. 31, 2009

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 Statements of Cash Flows


	Year ended December 31
	2009			2008			2007

Net (increase) decrease in operating working capital was composed of the following:
(Increase) decrease in accounts and notes receivable	$	(1,476	)	$	6,030		$	(3,867	)
Decrease (increase) in inventories		1,213			(1,545	)		(749	)
Increase in prepaid expenses and other current assets		(264	)		(621	)		(370	)
(Decrease) increase in accounts payable and accrued liabilities		(1,121	)		(4,628	)		4,930
(Decrease) increase in income and other taxes payable		(653	)		(909	)		741

Net (increase) decrease in operating working capital	$	(2,301	)	$	(1,673	)	$	685

Net cash provided by operating activities includes the following cash payments for interest and income taxes:
Interest paid on debt (net of capitalized interest)	$	–		$	–		$	203

Income taxes	$	7,537		$	19,130		$	12,340

Net sales of marketable securities consisted of the following gross amounts:
Marketable securities sold	$	157		$	3,719		$	2,160
Marketable securities purchased		(30	)		(3,236	)		(1,975	)

Net sales of marketable securities	$	127		$	483		$	185

In accordance with accounting standards for cash-flow classifications for stock options (ASC 718), the “Net (increase) decrease in operating working capital” includes reductions of $25, $106 and $96 for excess income tax benefits associated with stock options exercised during 2009, 2008 and 2007, respectively. These amounts are offset by an equal amount in “Net sales (purchases) of treasury shares.”

The “Net sales (purchases) of treasury shares” represents the cost of common shares purchased less the cost of shares issued for share-based compensation plans. Purchases totaled $6, $8,011 and $7,036 in 2009, 2008 and 2007, respectively. Purchases in 2008 and 2007 included shares purchased under the company’s common stock repurchase programs.

In 2009, “Net sales (purchases) of other short-term investments” consisted of $123 in restricted cash associated with capital-investment projects at the company’s Pascagoula, Mississippi refinery 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 $350 and $650, in 2009 and 2007 respectively, of tax exempt Mississippi Gulf Opportunity Zone Bonds as a source of funds for Pascagoula Refinery projects.

The Consolidated Statement of Cash Flows for 2009 excludes changes to the Consolidated Balance Sheet that did not affect cash. In 2008, “Net sales (purchases) 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 non-cash transactions and excluded from “Net (increase) decrease in operating working capital” and “Capital expenditures.” In 2009, the payments related to these “Accrued liabilities” were excluded from “Net (increase) decrease 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 23, on page FS-60, 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, 2009.

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
	2009		2008			2007

Additions to properties, plant and equipment¹	$	16,107	$	18,495		$	16,127
Additions to investments		942		1,051			881
Current-year dry-hole expenditures		468		320			418
Payments for other liabilities and assets, net²		2,326		(200	)		(748	)

Capital expenditures		19,843		19,666			16,678
Expensed exploration expenditures		790		794			816
Assets acquired through capital lease obligations and other financing obligations		19		9			196

Capital and exploratory expenditures, excluding equity affiliates		20,652		20,469			17,690
Company’s share of expenditures by equity affiliates		1,585		2,306			2,336

Capital and exploratory expenditures, including equity affiliates	$	22,237	$	22,775		$	20,026


¹ Excludes noncash additions of $985 in 2009, $5,153 in 2008 and $3,560 in 2007.

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

Fair Value Measurements

12 Months Ended

Dec. 31, 2009

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. ASC 820 became effective for Chevron on January 1, 2008, for all financial assets and liabilities and recurring nonfinancial assets and liabilities. On January 1, 2009, the standard became effective for nonrecurring nonfinancial assets and liabilities. Among the required disclosures is the fair-value hierarchy of inputs the company uses to value an asset or a liability. The three levels of the fair-value hierarchy are described as follows:

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

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

Level 3: Unobservable inputs. The company does not use Level 3 inputs for any of its recurring fair-value measurements. Level 3 inputs may be required for the determination of fair value associated with certain nonrecurring measurements of nonfinancial assets and liabilities. In 2009, 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, 2009, and December 31, 2008, 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
	2009		(Level 1)		(Level 2)		(Level 3)		2008		(Level 1)		(Level 2)		(Level 3)

Marketable Securities	$	106	$	106	$	–	$	–	$	213	$	213	$	–	$	–
Derivatives		127		14		113		–		805		529		276		–

Total Recurring Assets
at Fair Value	$	233	$	120	$	113	$	–	$	1,018	$	742	$	276	$	–

Derivatives	$	101	$	20	$	81	$	–	$	516	$	98	$	418	$	–

Total Recurring Liabilities
at Fair Value	$	101	$	20	$	81	$	–	$	516	$	98	$	418	$	–

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, 2009. Marketable securities had average maturities of less than one year.

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 to the Consolidated Statement of Income. For derivatives with identical or similar provisions as contracts that are publicly traded on a regular basis, the company uses the market values of the publicly traded instruments as an input for fair-value calculations.

The company’s derivative instruments principally include 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 forward curves (on a sample basis) with the pricing information to document reasonable, logical and supportable fair-value determinations and proper level of classification.

Impairments of “Properties, plant and equipment” During 2009 and in accordance with the accounting standard for the impairment or disposal of long-lived assets (ASC 360), long-lived assets “held and used” with a carrying amount of $949 were written down to a fair value of $490, resulting in a before-tax loss of $459. 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 a carrying amount of $160 were written down to a fair value of $68, resulting in a before-tax loss of $92. The fair values were determined based on bids received from prospective buyers.

The fair-value hierarchy for nonrecurring assets and liabilities measured at fair value during 2009 is presented in the following table.

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


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

Properties, plant and equipment, net (held and used)	$	490	$	–	$	–	$	490	$	459
Properties, plant and equipment, net (held for sale)		68		–		68		–		92

Total Nonrecurring Assets at Fair Value	$	558	$	–	$	68	$	490	$	551

Assets and Liabilities Not Required to Be Measured at Fair Value The company holds cash equivalents in U.S. and non-U.S. portfolios. The instruments held are primarily time deposits and money market funds. The fair values reflect the cash that would have been received or paid if the instruments were settled at year-end. Cash equivalents had carrying/fair values of $6,396 and $7,058 at December 31, 2009 and 2008, respectively, and average maturities under 90 days. The balance at December 31, 2009, includes $123 of investments for restricted funds related to an international upstream development project and Pascagoula Refinery projects, which are included in “Deferred charges and other assets” on the Consolidated Balance Sheet. Long-term debt of $5,705 and $1,221 had estimated fair values of $6,229 and $1,414 at December 31, 2009 and 2008, respectively.

Fair values of other financial instruments at the end of 2009 and 2008 were not material.

Financial and Derivative Instruments

12 Months Ended

Dec. 31, 2009

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 commodities and other derivatives 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, 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	2009		2008		Classification	2009		2008

Foreign Exchange	Accounts and notes receivable, net	$	–	$	11	Accrued liabilities	$	–	$	89
Commodity	Accounts and notes receivable, net		99		764	Accounts payable		73		344
Commodity	Long-term receivables, net		28		30	Deferred credits and other noncurrent obligations		28		83

		$	127	$	805		$	101	$	516

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	2009			2008


Foreign Exchange	Other income	$	26		$	(314	)
Commodity	Sales and other
	operating revenues		(94	)		706
Commodity	Purchased crude oil
	and products		(353	)		424
Commodity	Other income		–			(3	)

		$	(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, 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. Historically, under the terms of the swaps, net cash settlements were based on the difference between fixed-rate and floating-rate interest amounts calculated by reference to agreed notional principal amounts. 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 2009, the company had no interest rate swaps. The company’s only interest rate swaps on fixed-rate debt matured in January 2009.

Concentrations of Credit Risk The company’s financial instruments that are exposed to concentrations of credit risk consist primarily of its cash equivalents, 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. This diversified investment policy limits the company’s exposure both to credit risk and to concentrations of credit risk. Similar standards of diversity 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, 2009

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. For this purpose, the investments are grouped as follows: upstream – exploration and production; downstream – refining, marketing and transportation; chemicals; and all other. The first three of these groupings represent the company’s “reportable segments” and “operating segments” as defined in accounting standards for segment reporting (ASC 280).

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, a committee of senior officers that includes the Chief Executive Officer and that, in turn, 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 to assess 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 Executive Committee also have individual management responsibilities and participate in other committees for purposes other than acting as the CODM.

“All Other” activities include mining operations, power generation businesses, worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, alternative fuels and technology companies, and the company’s interest in Dynegy (through May 2007, when Chevron sold its interest).

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
	2009			2008			2007

Segment Earnings
Upstream
United States	$	2,216		$	7,126		$	4,532
International		8,215			14,584			10,284

Total Upstream		10,431			21,710			14,816

Downstream
United States		(273	)		1,369			966
International		838			2,060			2,536

Total Downstream		565			3,429			3,502

Chemicals
United States		198			22			253
International		211			160			143

Total Chemicals		409			182			396

Total Segment Earnings		11,405			25,321			18,714
All Other
Interest expense		(22	)		–			(107	)
Interest income		46			192			385
Other		(946	)		(1,582	)		(304	)

Net Income Attributable to Chevron Corporation	$	10,483		$	23,931		$	18,688

Segment Assets Segment assets do not include intercompany investments or intercompany receivables. Segment assets at year-end 2009 and 2008 are as follows:


	At December 31
	2009		2008

Upstream
United States	$	24,918	$	26,071
International		74,937		72,530
Goodwill		4,618		4,619

Total Upstream		104,473		103,220

Downstream
United States		18,067		15,869
International		24,824		23,572

Total Downstream		42,891		39,441

Chemicals
United States		2,810		2,535
International		1,066		1,086

Total Chemicals		3,876		3,621

Total Segment Assets		151,240		146,282

All Other*
United States		7,125		8,984
International		6,256		5,899

Total All Other		13,381		14,883

Total Assets – United States		52,920		53,459
Total Assets – International		107,083		103,087
Goodwill		4,618		4,619

Total Assets	$	164,621	$	161,165


*“All Other” assets consist primarily of worldwide cash, cash equivalents and marketable securities, real estate, 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 2009, 2008 and 2007, are presented in the table on the following page. 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 transportation and trading of refined products, crude oil and natural gas liquids. Revenues for the chemicals segment are derived primarily from the manufacture and sale of additives for lubricants and fuels.
“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 2009, 2008 and 2007.


	Year ended December 31
	2009			2008			2007

Upstream
United States	$	9,164		$	23,503		$	18,736
Intersegment		10,278			15,142			11,625

Total United States		19,442			38,645			30,361

International		13,409			19,469			15,213
Intersegment		18,477			24,204			19,647

Total International		31,886			43,673			34,860

Total Upstream		51,328			82,318			65,221

Downstream
United States		57,846			87,515			70,535
Excise and similar taxes		4,573			4,746			4,990
Intersegment		190			447			491

Total United States		62,609			92,708			76,016

International		76,668			122,064			97,178
Excise and similar taxes		3,471			5,044			5,042
Intersegment		106			122			38

Total International		80,245			127,230			102,258

Total Downstream		142,854			219,938			178,274

Chemicals
United States		271			305			351
Excise and similar taxes		-			2			2
Intersegment		194			266			235

Total United States		465			573			588

International		1,231			1,388			1,143
Excise and similar taxes		65			55			86
Intersegment		132			154			142

Total International		1,428			1,597			1,371

Total Chemicals		1,893			2,170			1,959

All Other
United States		665			815			757
Intersegment		964			917			760

Total United States		1,629			1,732			1,517

International		39			52			58
Intersegment		33			33			31

Total International		72			85			89

Total All Other		1,701			1,817			1,606

Segment Sales and Other
Operating Revenues
United States		84,145			133,658			108,482
International		113,631			172,585			138,578

Total Segment Sales and Other Operating Revenues		197,776			306,243			247,060
Elimination of intersegment sales		(30,374	)		(41,285	)		(32,969	)

Total Sales and Other Operating Revenues	$	167,402		$	264,958		$	214,091

Segment Income Taxes Segment income tax expense for the years 2009, 2008 and 2007 is as follows:


	Year ended December 31
	2009			2008			2007

Upstream
United States	$	1,225		$	3,693		$	2,541
International		7,686			15,132			11,307

Total Upstream		8,911			18,825			13,848

Downstream
United States		(111	)		815			520
International		182			813			400

Total Downstream		71			1,628			920

Chemicals
United States		54			(22	)		6
International		46			47			36

Total Chemicals		100			25			42

All Other		(1,117	)		(1,452	)		(1,331	)

Total Income Tax Expense	$	7,965		$	19,026		$	13,479

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, 2009

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 table below. 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
	2009		2008		2009			2008			2007

Upstream
Tengizchevroil	$	5,938	$	6,290	$	2,216		$	3,220		$	2,135
Petropiar/Hamaca		1,139		1,130		122			317			327
Petroboscan		832		816		171			244			185
Angola LNG Limited		1,853		1,191		(12	)		(8	)		21
Other		686		725		118			206			204

Total Upstream		10,448		10,152		2,615			3,979			2,872

Downstream
GS Caltex Corporation		2,406		2,601		(191	)		444			217
Caspian Pipeline Consortium		852		749		105			103			102
Star Petroleum Refining
Company Ltd.		873		877		(4	)		22			157
Caltex Australia Ltd.		740		723		11			250			129
Colonial Pipeline Company		514		536		51			32			39
Other		1,773		1,664		311			354			318

Total Downstream		7,158		7,150		283			1,205			962

Chemicals
Chevron Phillips Chemical
Company LLC		2,327		2,037		328			158			380
Other		28		25		7			4			6

Total Chemicals		2,355		2,062		335			162			386

All Other
Other		507		567		83			20			(76	)

Total equity method	$	20,468	$	19,931	$	3,316		$	5,366		$	4,144
Other at or below cost		690		989

Total investments and advances	$	21,158	$	20,920

Total United States	$	4,195	$	4,002	$	511		$	307		$	478
Total International	$	16,963	$	16,918	$	2,805		$	5,059		$	3,666

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, 2009, the company’s carrying value of its investment in TCO was about $200 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, 2009, the company’s carrying value of its investment in Petropiar was approximately $195 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.

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, 2009, the company’s carrying value of its investment in Petroboscan was approximately $275 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.

Caspian Pipeline Consortium Chevron has a 15 percent interest in the Caspian Pipeline Consortium, which provides the critical export route for crude oil from both TCO and Karachaganak.

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. The Petroleum Authority of Thailand 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, 2009, the fair value of Chevron’s share of CAL common stock was approximately $1,120.

Colonial Pipeline Company Chevron owns an approximate 23 percent equity interest in the Colonial Pipeline Company. The Colonial Pipeline system runs from Texas to New Jersey and transports petroleum products in a 13-state market. At December 31, 2009, the company’s carrying value of its investment in Colonial Pipeline was approximately $550 higher than the amount of underlying equity in Colonial Pipeline net assets. This difference primarily relates to purchase price adjustments from the acquisition of Unocal Corporation.

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

Other Information “Sales and other operating revenues” on the Consolidated Statement of Income includes $10,391, $15,390 and $11,555 with affiliated companies for 2009, 2008 and 2007, respectively. “Purchased crude oil and products” includes
$4,631, $6,850 and $5,464 with affiliated companies for 2009, 2008 and 2007, respectively.

“Accounts and notes receivable” on the Consolidated Balance Sheet includes $1,125 and $701 due from affiliated companies at December 31, 2009 and 2008, respectively. “Accounts payable” includes $345 and $289 due to affiliated companies at December 31, 2009 and 2008, 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 $2,422 at December 31, 2009.


	Affiliates						Chevron Share
Year ended December 31	2009		2008		2007		2009		2008		2007

Total revenues	$	81,995	$	112,707	$	94,864	$	39,280	$	54,055	$	46,579
Income before income tax expense		11,083		17,500		12,510		4,511		7,532		5,836
Net income attributable to affiliates		8,261		12,705		9,743		3,285		5,524		4,550

At December 31

Current assets	$	27,111	$	25,194	$	26,360	$	11,009	$	10,804	$	11,914
Noncurrent assets		55,363		51,878		48,440		21,361		20,129		19,045
Current liabilities		17,450		17,727		19,033		7,833		7,474		9,009
Noncurrent liabilities		21,531		21,049		22,757		5,106		4,533		3,745

Total affiliates’ net equity	$	43,493	$	38,296	$	33,010	$	19,431	$	18,926	$	18,205

Litigation	12 Months Ended
Litigation	Dec. 31, 2009
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 50 pending lawsuits and claims, the majority of which involve numerous other petroleum marketers and refiners. Resolution of these lawsuits and claims may ultimately require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE, including personal-injury claims, may be filed in the future. The company’s ultimate exposure related to pending lawsuits and claims is not determinable, but could be material to net income in any one period. The company no longer uses MTBE in the manufacture of gasoline in the United States. Ecuador Chevron is a defendant in a civil lawsuit before the Superior Court of Nueva Loja in Lago Agrio, Ecuador, brought in May 2003 by plaintiffs who claim to be representatives of certain residents of an area where an oil production consortium formerly had operations. The lawsuit alleges damage to the environment from the oil exploration and production operations and seeks unspecified damages to fund environmental remediation and restoration of the alleged environmental harm, plus a health monitoring program. Until 1992, Texaco Petroleum Company (Texpet), a subsidiary of Texaco Inc., was a minority member of this consortium with Petroecuador, the Ecuadorian state-owned oil company, as the majority partner; since 1990, the operations have been conducted solely by Petroecuador. At the conclusion of the consortium and following an independent third-party environmental audit of the concession area, Texpet entered into a formal agreement with the Republic of Ecuador and Petroecuador for Texpet to remediate specific sites assigned by the government in proportion to Texpet’s ownership share of the consortium. Pursuant to that agreement, Texpet conducted a three-year remediation program at a cost of $40. After certifying that the sites were properly remediated, the government granted Texpet and all related corporate entities a full release from any and all environmental liability arising from the consortium operations. Based on the history described above, Chevron believes that this lawsuit lacks legal or factual merit. As to matters of law, the company believes first, that the court lacks jurisdiction over Chevron; second, that the law under which plaintiffs bring the action, enacted in 1999, cannot be applied retroactively; third, that the claims are barred by the statute of limitations in Ecuador; and, fourth, that the lawsuit is also barred by the releases from liability previously given to Texpet by the Republic of Ecuador and Petroecuador. 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 April 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 $8,000, 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 $8,300 could be assessed against Chevron for unjust enrichment. The engineer’s report is not binding on the court. Chevron also believes that the engineer’s work was performed and his report prepared in a manner contrary to law and in violation of the court’s orders. Chevron submitted a rebuttal to the report in which it asked the court to strike the report in its entirety. In November 2008, the engineer revised the report and, without additional evidence, recommended an increase in the financial compensation for purported damages to a total of $18,900 and an increase in the assessment for purported unjust enrichment to a total of $8,400. Chevron submitted a rebuttal to the revised report, which the court dismissed. In September 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 petitioned to be recused. In late September 2009, the judge was recused, and in October 2009, the full chamber of the provincial court affirmed the recusal, resulting in the appointment of a new judge. Chevron filed motions to annul all of the rulings made by the prior judge, but the new judge denied these motions. The court has completed most of the procedural aspects of the case and could render a judgment at any time. Chevron will continue a vigorous defense of any attempted imposition of liability. In the event of an adverse judgment, Chevron would expect to pursue its appeals and vigorously defend against enforcement of any such judgment; therefore, the ultimate outcome – and 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 engineer’s report, management does not believe the report has 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, 2009

Taxes [Abstract]

Taxes

Note 15

Taxes

Income Taxes


	Year ended December 31
	2009			2008		2007

Taxes on income
U.S. Federal
Current	$	128		$	2,879	$	1,446
Deferred		(147	)		274		225
State and local
Current		216			528		356
Deferred		14			141		(18	)

Total United States		211			3,822		2,009

International
Current		7,154			15,021		11,416
Deferred		600			183		54

Total International		7,754			15,204		11,470

Total taxes on income	$	7,965		$	19,026	$	13,479

In 2009, before-tax income for U.S. operations, including related corporate and other charges, was $1,310, compared with before-tax income of $10,765 and $7,886 in 2008 and 2007, respectively. For international operations, before-tax income was $17,218, $32,292 and $24,388 in 2009, 2008 and 2007, respectively. U.S. federal income tax expense was reduced by $204, $198 and $132 in 2009, 2008 and 2007, 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
	2009			2008			2007

U.S. statutory federal income tax rate		35.0	%		35.0	%		35.0	%
Effect of income taxes from international operations at rates different from the U.S. statutory rate		10.4			10.1			8.2
State and local taxes on income, net of U.S. federal income tax benefit		0.9			1.0			0.8
Prior-year tax adjustments		(0.3	)		(0.1	)		0.3
Tax credits		(1.1	)		(0.5	)		(0.4	)
Effects of enacted changes in tax laws		0.1			(0.6	)		(0.3	)
Other		(2.0	)		(0.7	)		(1.8	)

Effective tax rate		43.0	%		44.2	%		41.8	%

The company’s effective tax rate decreased from 44.2 percent in 2008 to 43.0 percent in 2009. The rate was lower in 2009 mainly due to the effect of deferred tax benefits and relatively low tax rates on asset sales, both related to an international upstream project. In addition, a greater proportion of before-tax income was earned in 2009 by equity affiliates than in 2008. (Equity-affiliate income is reported as a single amount on an after-tax basis on the Consolidated Statement of Income.) Partially offsetting these items was the effect of a greater proportion of income earned in 2009 in tax jurisdictions with higher tax rates.

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
	2009			2008

Deferred tax liabilities
Properties, plant and equipment	$	18,545		$	18,271
Investments and other		2,350			2,225

Total deferred tax liabilities		20,895			20,496

Deferred tax assets
Foreign tax credits		(5,387	)		(4,784	)
Abandonment/environmental reserves		(4,424	)		(4,338	)
Employee benefits		(3,499	)		(3,488	)
Deferred credits		(3,469	)		(3,933	)
Tax loss carryforwards		(819	)		(1,139	)
Other accrued liabilities		(553	)		(445	)
Inventory		(431	)		(260	)
Miscellaneous		(1,681	)		(1,732	)

Total deferred tax assets		(20,263	)		(20,119	)

Deferred tax assets valuation allowance		7,921			7,535

Total deferred taxes, net	$	8,553		$	7,912

Deferred tax liabilities at the end of 2009 increased by approximately $400 from year-end 2008. The increase was primarily related to increased temporary differences for properties, plant and equipment.

Deferred tax assets were essentially unchanged in 2009. Increases related to additional foreign tax credits arising from earnings in high-tax-rate international jurisdictions (which were substantially offset by valuation allowances) and to inventory-related temporary differences. These effects were offset by reductions in deferred credits and tax loss carryforwards primarily resulting 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 2010 through 2036. Foreign tax credit carryforwards of $5,387 will expire between 2010 and 2019.

At December 31, 2009 and 2008, deferred taxes were classified on the Consolidated Balance Sheet as follows:


	At December 31
	2009			2008

Prepaid expenses and other current assets	$	(1,825	)	$	(1,130	)
Deferred charges and other assets		(1,268	)		(2,686	)
Federal and other taxes on income		125			189
Noncurrent deferred income taxes		11,521			11,539

Total deferred income taxes, net	$	8,553		$	7,912

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 $20,458 at December 31, 2009. 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 2009, 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 year ended December 31, 2009. 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.


	2009			2008			2007

Balance at January 1	$	2,696		$	2,199		$	2,296
Foreign currency effects		(1	)		(1	)		19
Additions based on tax positions taken in current year		459			522			418
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		533			337			120
Reductions for tax positions taken in prior years		(182	)		(246	)		(225	)
Settlements with taxing authorities in current year		(300	)		(215	)		(255	)
Reductions as a result of a lapse of the applicable statute of limitations		(10	)		(58	)		–
Reductions due to tax positions previously expected to be taken but subsequently not taken on prior-year tax returns		–			–			(174	)

Balance at December 31	$	3,195		$	2,696		$	2,199

Although unrecognized tax benefits for individual tax positions may increase or decrease during 2010, the company believes that no change will be individually significant during 2010. Approximately 90 percent of the $3,195 of unrecognized tax benefits at December 31, 2009, would have an impact on the effective tax rate if subsequently recognized.

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, 2009. 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.

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, 2009, accruals of $232 for anticipated interest and penalty obligations were included on the Consolidated Balance Sheet, compared with accruals of $276 as of year-end 2008. Income tax (benefit) expense associated with interest and penalties was $(20), $79 and $70 in 2009, 2008 and 2007, respectively.

Taxes Other Than on Income


	Year ended December 31
	2009			2008		2007

United States
Excise and similar taxes on products and merchandise	$	4,573		$	4,748	$	4,992
Import duties and other levies		(4	)		1		12
Property and other miscellaneous taxes		584			588		491
Payroll taxes		223			204		185
Taxes on production		135			431		288

Total United States		5,511			5,972		5,968

International
Excise and similar taxes on products and merchandise		3,536			5,098		5,129
Import duties and other levies		6,550			8,368		10,404
Property and other miscellaneous taxes		1,740			1,557		528
Payroll taxes		134			106		89
Taxes on production		120			202		148

Total International		12,080			15,331		16,298

Total taxes other than on income	$	17,591		$	21,303	$	22,266

Accounting for Suspended Exploratory Wells

12 Months Ended

Dec. 31, 2009

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 enterprise 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. 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, 2009:


	2009			2008			2007

Beginning balance at January 1	$	2,118		$	1,660		$	1,239
Additions to capitalized exploratory well costs pending the determination of proved reserves		663			643			486
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(174	)		(49	)		(23	)
Capitalized exploratory well costs
charged to expense		(172	)		(136	)		(42	)

Ending balance at December 31	$	2,435		$	2,118		$	1,660

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
	2009		2008		2007

Exploratory well costs capitalized for a period of one year or less	$	564	$	559	$	449
Exploratory well costs capitalized for a period greater than one year		1,871		1,559		1,211

Balance at December 31	$	2,435	$	2,118	$	1,660

Number of projects with exploratory well costs that have been capitalized for a period greater than one year*		46		50		54


*		Certain projects have multiple wells or fields or both.

Of the $1,871 of exploratory well costs capitalized for more than one year at December 31, 2009, $1,143 (28 projects) is related to projects that had drilling activities under way or firmly planned for the near future. The $728 balance is related to 18 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 $728 referenced above had the following activities associated with assessing the reserves and the projects’ economic viability: (a) $330 (one project) – negotiation of crude-oil and natural-gas transportation contracts and construction agreements; (b) $107 (two projects) – discussion with possible natural-gas purchasers ongoing; (c) $73 (two projects) – continued unitization efforts on adjacent discoveries that span international boundaries while planning on an LNG facility has commenced; (d) $49 (one project) – progression of development concept selection; (e) $47 (one project) – subsurface and facilities engineering studies concluding with front-end engineering and design expected to begin in early 2010; (f) $34 (one project) – reviewing development alternatives; $88 – miscellaneous activities for 10 projects with smaller amounts suspended. While progress was being made on all 46 projects, the decision on the recognition of proved reserves under SEC rules in some cases may not occur for several years because of the complexity, scale and negotiations connected with the projects. The majority of these decisions are expected to occur in the next three years.

The $1,871 of suspended well costs capitalized for a period greater than one year as of December 31, 2009, represents 149 exploratory wells in 46 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
1997–1998		15		3
1999–2003		271		42
2004–2008		1,577		101

Total	$	1,871		149


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

1992	$	8		1
1999		8		1
2003–2004		242		5
2005–2009		1,613		39

Total	$	1,871		46

Stock Options and Other Share-Based Compensation

12 Months Ended

Dec. 31, 2009

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 2009, 2008 and 2007 was $182 ($119 after tax), $168 ($109 after tax) and $146 ($95 after tax), respectively. In addition, compensation expense for stock appreciation rights, restricted stock, performance units and restricted stock units was $170 ($110 after tax), $132 ($86 after tax) and $205 ($133 after tax) for 2009, 2008 and 2007, respectively. No significant stock-based compensation cost was capitalized at December 31, 2009 and 2008.

Cash received in payment for option exercises under all share-based payment arrangements for 2009, 2008 and 2007 was $147, $404 and $445, respectively. Actual tax benefits realized for the tax deductions from option exercises were $25, $103 and $94 for 2009, 2008 and 2007, respectively.

Cash paid to settle performance units and stock appreciation rights was $89, $136 and $88 for 2009, 2008 and 2007, 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.

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. If not exercised, these awards will expire between early 2010 and early 2015.

The fair market values of stock options and stock appreciation rights granted in 2009, 2008 and 2007 were measured on the date of grant using the Black-Scholes option-pricing model, with the following weighted-average assumptions:


	Year ended December 31
	2009			2008			2007

Stock Options
Expected term in years¹		6.0			6.1			6.3
Volatility²		30.2	%		22.0	%		22.0	%
Risk-free interest rate based on zero coupon U.S. treasury note		2.1	%		3.0	%		4.5	%
Dividend yield		3.2	%		2.7	%		3.2	%
Weighted-average fair value per option granted	$	15.36		$	15.97		$	15.27

Restored Options
Expected term in years¹		1.2			1.2			1.6
Volatility²		45.0	%		23.1	%		21.2	%
Risk-free interest rate based on zero coupon U.S. treasury note		1.1	%		1.9	%		4.5	%
Dividend yield		3.5	%		2.7	%		3.2	%
Weighted-average fair value per option granted	$	12.38		$	10.01		$	8.61


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 2009 is presented below:


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

Outstanding at January 1, 2009		59,013		$	61.36
Granted		14,709		$	69.69
Exercised		(3,418	)	$	45.75
Restored		1		$	70.40
Forfeited		(842	)	$	76.02
Outstanding at December 31, 2009		69,463		$	63.70	6.4 yrs	$	1,019

Exercisable at December 31, 2009		44,120		$	57.34	5.1 yrs	$	904

The total intrinsic value (i.e., the difference between the exercise price and the market price) of options exercised during 2009, 2008 and 2007 was $91, $433 and $423, respectively. During this period, the company continued its practice of issuing treasury shares upon exercise of these awards.

As of December 31, 2009, there was $233 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 1.8 years.

At January 1, 2009, the number of LTIP performance units outstanding was equivalent to 2,400,555 shares. During 2009, 992,800 units were granted, 668,953 units vested with cash proceeds distributed to recipients and 45,294 units were forfeited. At December 31, 2009, units outstanding were 2,679,108, and the fair value of the liability recorded for these instruments was $233. In addition, outstanding stock appreciation rights and other awards that were granted under various LTIP and former Texaco and Unocal programs totaled approximately 1.5 million equivalent shares as of December 31, 2009. A liability of $45 was recorded for these awards.

In March 2009, Chevron granted all eligible LTIP employees restricted stock units in lieu of annual cash bonus. The expense associated with these special restricted stock units was recognized at the time of the grants. A total of 453,965 units were granted at $69.70 per unit at the time of the grant. Total fair value of the special restricted stock units was $32 as of December 31, 2009. All of the special restricted stock units will be payable in November 2010.

Employee Benefit Plans

12 Months Ended

Dec. 31, 2009

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 per 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 as an asset or liability on the Consolidated Balance Sheet.

The funded status of the company’s pension and other postretirement benefit plans for 2009 and 2008 is on the following page:


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

Change in Benefit Obligation
Benefit obligation at January 1	$	8,127		$	3,891		$	8,395		$	4,633		$	2,931		$	2,939
Service cost		266			128			250			132			43			44
Interest cost		481			292			499			292			180			178
Plan participants’ contributions		–			7			–			9			145			152
Plan amendments		1			10			–			32			20			–
Curtailments		–			–			–			–			(5	)		–
Actuarial loss (gain)		1,391			299			(62	)		(104	)		56			(14	)
Foreign currency exchange rate changes		–			333			–			(858	)		27			(28	)
Benefits paid		(602	)		(245	)		(955	)		(246	)		(332	)		(340	)
Special termination benefits		–			–			–			1			–			–

Benefit obligation at December 31		9,664			4,715			8,127			3,891			3,065			2,931

Change in Plan Assets
Fair value of plan assets at January 1		5,448			2,600			7,918			3,892			–			–
Actual return on plan assets		964			402			(2,092	)		(655	)		–			–
Foreign currency exchange rate changes		–			226			–			(662	)		–			–
Employer contributions		1,494			245			577			262			187			188
Plan participants’ contributions		–			7			–			9			145			152
Benefits paid		(602	)		(245	)		(955	)		(246	)		(332	)		(340	)

Fair value of plan assets at December 31		7,304			3,235			5,448			2,600			–			–

Funded Status at December 31	$	(2,360	)	$	(1,480	)	$	(2,679	)	$	(1,291	)	$	(3,065	)	$	(2,931	)

Amounts recognized on the Consolidated Balance Sheet for the company’s pension and other postretirement benefit plans at December 31, 2009 and 2008, include:


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

Deferred charges and other assets	$	6		$	37		$	6		$	31		$	–		$	–
Accrued liabilities		(66	)		(67	)		(72	)		(61	)		(208	)		(209	)
Reserves for employee benefit plans		(2,300	)		(1,450	)		(2,613	)		(1,261	)		(2,857	)		(2,722	)

Net amount recognized at December 31	$	(2,360	)	$	(1,480	)	$	(2,679	)	$	(1,291	)	$	(3,065	)	$	(2,931	)

Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and OPEB plans were $6,454 and $5,831 at the end of 2009 and 2008, respectively. These amounts consisted of:


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

Net actuarial loss	$	4,181		$	1,889	$	3,797		$	1,804	$	465		$	410
Prior-service (credit) costs		(60	)		201		(68	)		211		(222	)		(323	)

Total recognized at December 31	$	4,121		$	2,090	$	3,729		$	2,015	$	243		$	87

The accumulated benefit obligations for all U.S. and international pension plans were $8,707 and $4,029, respectively, at December 31, 2009, and $7,376 and $3,273, respectively, at December 31, 2008.

Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at December 31, 2009 and 2008, was:


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

Projected benefit obligations	$	9,658	$	3,550	$	8,121	$	2,906
Accumulated benefit obligations		8,702		3,102		7,371		2,539
Fair value of plan assets		7,292		2,116		5,436		1,698

The components of net periodic benefit cost and amounts recognized in other comprehensive income for 2009, 2008 and 2007 are shown in the table below:


	Pension Benefits
	2009						2008						2007						Other Benefits
	U.S.			Int’l.			U.S.			Int’l.			U.S.			Int’l.			2009			2008			2007

Net Periodic Benefit Cost
Service cost	$	266		$	128		$	250		$	132		$	260		$	125		$	43		$	44		$	49
Interest cost		481			292			499			292			483			255			180			178			184
Expected return on plan assets		(395	)		(203	)		(593	)		(273	)		(578	)		(266	)		–			–			–
Amortization of prior-service
(credits) costs		(7	)		23			(7	)		24			46			17			(81	)		(81	)		(81	)
Recognized actuarial losses		298			108			60			77			128			82			27			38			81
Settlement losses		141			1			306			2			65			–			–			–			–
Curtailment losses		–			–			–			–			–			3			(5	)		–			–
Special termination benefit recognition		–			–			–			1			–			–			–			–			–

Total net periodic benefit cost		784			349			515			255			404			216			164			179			233

Changes Recognized in Other
Comprehensive Income
Net actuarial loss (gain) during period		823			194			2,624			646			(160	)		31			82			(42	)		(401	)
Amortization of actuarial loss		(439	)		(109	)		(366	)		(79	)		(193	)		(82	)		(27	)		(38	)		(81	)
Prior service cost (credit) during period		1			13			–			32			(301	)		97			20			–			–
Amortization of prior-service
credits (costs)		7			(23	)		7			(24	)		(46	)		(20	)		81			81			81

Total changes recognized in
other comprehensive income		392			75			2,265			575			(700	)		26			156			1			(401	)

Recognized in Net Periodic
Benefit Cost and Other
Comprehensive Income	$	1,176		$	424		$	2,780		$	830		$	(296	)	$	242		$	320		$	180		$	(168	)

Net actuarial losses recorded in “Accumulated other comprehensive loss” at December 31, 2009, for the company’s U.S. pension, international pension and OPEB plans are being amortized on a straight-line basis over approximately 11, 13 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 2010, the company estimates actuarial losses of $318, $102 and $26 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 $220 will be recognized from “Accumulated other comprehensive loss” during 2010 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, 2009, was approximately eight and 12 years for U.S. and international pension plans, respectively, and eight years for other postretirement benefit plans. During 2010, the company estimates prior service (credits) costs of $(7), $27 and $(74) 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
	2009						2008						2007						Other Benefits
	U.S.			Int’l.			U.S.			Int’l.			U.S.			Int’l.			2009			2008			2007

Assumptions used to determine benefit obligations
Discount rate		5.3	%		6.8	%		6.3	%		7.5	%		6.3	%		6.7	%		5.9	%		6.3	%		6.3	%
Rate of compensation increase		4.5	%		6.3	%		4.5	%		6.8	%		4.5	%		6.4	%		N/A			4.0	%		4.5	%
Assumptions used to determine net periodic benefit cost
Discount rate		6.3	%		7.5	%		6.3	%		6.7	%		5.8	%		6.0	%		6.3	%		6.3	%		5.8	%
Expected return on plan assets		7.8	%		7.5	%		7.8	%		7.4	%		7.8	%		7.5	%		N/A			N/A			N/A
Rate of compensation increase		4.5	%		6.8	%		4.5	%		6.4	%		4.5	%		6.1	%		N/A			4.5	%		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 69 percent of the company’s pension plan assets. At December 31, 2009, the estimated long-term rate of return on U.S. pension plan assets was 7.8 percent.

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

Discount Rate The discount rate assumptions used to determine U.S. and international pension and postretirement benefit plan obligations and expense reflect the prevailing rates available on high-quality, fixed-income debt instruments. At December 31, 2009, the company selected a 5.3 percent discount rate for the U.S. pension plan and 5.8 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 2009. The discount rates at the end of 2008 and 2007 were 6.3 percent for the U.S. pension plan and the OPEB plan.

Other Benefit Assumptions For the measurement of accumulated postretirement benefit obligation at December 31, 2009, for the main U.S. postretirement medical plan, the assumed health care cost-trend rates start with 7 percent in 2010 and gradually decline to 5 percent for 2018 and beyond. For this measurement at December 31, 2008, the assumed health care cost-trend rates started with 7 percent in 2009 and gradually declined to 5 percent for 2017 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	$	10	$	(9	)
Effect on postretirement benefit obligation	$	102	$	(87	)

Plan Assets and Investment Strategy Effective December 31, 2009, the company implemented the expanded disclosure requirements for the plan assets of defined benefit pension and OPEB plans (ASC 715) to provide users of financial statements with an understanding of: how investment allocation decisions are made; the major categories 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 2009 are below:


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

Equities
U.S.¹	$	2,115	$	2,115		$	–	$	–	$	370	$	370		$	–	$	–
International		977		977			–		–		492		492			–		–
Collective Trusts/Mutual Funds²		1,264		3			1,261		–		789		94			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 Funds³		8		8			–		–		102		14			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 $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 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 category includes net payables for securities purchased but not yet settled (Level 1); dividends, interest- and tax-related receivables (Level 2); insurance contracts and investments in private-equity limited partnerships (Level 3).

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

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 84 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 plan’s 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 20-60 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 category risk. There are no significant concentrations of risk in plan assets due to the diversification of investment categories.

The company does not prefund its OPEB obligations.

Cash Contributions and Benefit Payments In 2009, the company contributed $1,494 and $245 to its U.S. and international pension plans, respectively. In 2010, the company expects contributions to be approximately $600 and $300 to its U.S. and international pension plans, respectively. Actual contribution amounts are dependent upon plan-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 $208 in 2010, as compared with $187 paid in 2009.

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

2010	$	855	$	242	$	208
2011	$	851	$	271	$	213
2012	$	861	$	284	$	217
2013	$	884	$	296	$	222
2014	$	913	$	317	$	229
2015–2019	$	4,707	$	1,969	$	1,197

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 $257, $231 and $206 in 2009, 2008 and 2007, respectively. This cost was reduced by the value of shares released from the LESOP totaling $184, $40 and $33 in 2009, 2008 and 2007, respectively. The remaining amounts, totaling $73, $191 and $173 in 2009, 2008 and 2007, 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 $3, $1 and $1 in 2009, 2008 and 2007, respectively. The net credit for the respective years was composed of credits to compensation expense of $15, $15 and $17 and charges to interest expense for LESOP debt of $12, $14 and $16.

Of the dividends paid on the LESOP shares, $110, $35 and $8 were used in 2009, 2008 and 2007, respectively, to service LESOP debt. No contributions were required in 2009, 2008 or 2007 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, 2009 and 2008, were as follows:


Thousands	2009		2008

Allocated shares		21,211		19,651
Unallocated shares		3,636		6,366

Total LESOP shares		24,847		26,017

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 2009, 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, 2009 and 2008, trust assets of $57 and $60, respectively, were invested primarily in interest-earning accounts.

Employee Incentive Plans Effective January 2008, the company established the Chevron Incentive Plan (CIP), a single annual cash bonus plan for eligible employees that links awards to corporate, unit and individual performance in the prior year. This plan replaced other cash bonus programs, which primarily included the Management Incentive Plan (MIP) and the Chevron Success Sharing program. In 2009 and 2008, charges to expense for cash bonuses were $561 and $757, respectively. In 2007, charges to expense for MIP were $184 and charges for other cash bonus programs were $431. 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.

Other Contingencies and Commitments	12 Months Ended
Other Contingencies and Commitments	Dec. 31, 2009
Other Contingencies and Commitments [Abstract]
Other Contingencies and Commitments	Note 22 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-46 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 2009, 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. In February 2009, Shell delivered a letter to the company purporting to preserve unmatured claims for certain Equilon indemnities. The letter itself provides no estimate of the ultimate claim amount. Management does not believe this letter or any other information provides a basis to estimate the amount, if any, of a range of loss or potential range of loss with respect to either the Equilon or the Motiva indemnities. 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 relating 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: 2010 – $7,500; 2011 – $4,300; 2012 – $1,400; 2013 – $1,400; 2014 – $1,000; 2015 and after – $4,100. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were approximately $8,100 in 2009, $5,100 in 2008 and $3,700 in 2007. 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, 2009, was $1,700. Included in this balance were remediation activities at approximately 250 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 2009 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 2009 environmental reserves balance of $1,515, $820 related to the company’s U.S. downstream operations, including refineries and other plants, marketing locations (i.e., service stations and terminals), and pipelines. The remaining $695 was associated with various sites in international downstream ($107), upstream ($369), chemicals ($149) and other businesses ($70). 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 2009 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 23 for a discussion of the company’s asset retirement obligations. Equity Redetermination For oil and 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 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.

Equity	12 Months Ended
Equity	Dec. 31, 2009
Equity [Abstract]
Equity	Note 3 Equity Retained earnings at December 31, 2009 and 2008, included approximately $8,122 and $7,951, respectively, for the company’s share of undistributed earnings of equity affiliates. At December 31, 2009, about 94 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 342,000 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 (Non-Employee Directors’ Plan).

New Accounting Standards	12 Months Ended
New Accounting Standards	Dec. 31, 2009
New Accounting Standards [Abstract]
New Accounting Standards	Note 18 New Accounting Standards The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162 (FAS 168) In June 2009, the FASB issued FAS 168, which became effective for the company in the quarter ending September 30, 2009. This standard established the FASB Accounting Standards Codification (ASC) system as the single authoritative source of U.S. generally accepted accounting principles (GAAP) and superseded existing literature of the FASB, Emerging Issues Task Force, American Institute of CPAs and other sources. The ASC did not change GAAP, but organized the literature into about 90 accounting Topics. Adoption of the ASC did not affect the company’s accounting. Employer’s Disclosures About Postretirement Benefit Plan Assets (FSP FAS 132(R)-1) In December 2008, the FASB issued FSP FAS 132(R)-1, which was subsequently codified into ASC 715, Compensation – Retirement Benefits, and became effective with the company’s reporting at December 31, 2009. This standard amended and expanded the disclosure requirements for the plan assets of defined benefit pension and other postretirement plans. Refer to information beginning on page FS-52 in Note 21, Employee Benefits, for these disclosures. 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 is not expected to have an impact 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 is not expected to have a material impact on the company’s results of operations, financial position or liquidity. Extractive Industries – Oil and Gas (ASC 932), Oil and Gas Reserve Estimation and Disclosures (ASU 2010-03) In January 2010, the FASB issued ASU 2010-03, which became effective for the company on December 31, 2009. The standard amends certain sections of ASC 932, Extractive Industries – Oil and Gas, to align them with the requirements in the Securities and Exchange Commission’s final rule, Modernization of the Oil and Gas Reporting Requirements (the final rule). The final rule was issued on December 31, 2008. Refer to Table V – Reserve Quantity Information, beginning on page FS-69, for additional information on the final rule and the impact of adoption.

Assets Held for Sale	12 Months Ended
Assets Held for Sale	Dec. 31, 2009
Assets Held for Sale [Abstract]
Assets Held for Sale	Note 25 Assets Held for Sale At December 31, 2009, the company reported no assets as “Assets held for sale” (AHS) on the Consolidated Balance Sheet. At December 31, 2008, $252 of net properties, plant and equipment were reported as AHS. Assets in this category are related to groups of service stations, aviation facilities, lubricants blending plants, and commercial and industrial fuels business. These assets were sold in 2009.

Consolidated Balance Sheet (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2009	Dec. 31, 2008
Assets
Allowance for Doubtful Accounts Receivable, Current	$ 228	$ 246
Liabilities and Equity
Preferred stock, shares authorized	100,000,000	100,000,000
Preferred stock, par value	$ 1	$ 1
Preferred stock, shares issued	0	0
Common stock, shares authorized	6,000,000,000	6,000,000,000
Common stock, par value	$ 0.75	$ 0.75
Common stock, shares issued	2,442,676,580	2,442,676,580
Treasury stock, shares	434,954,774	438,444,795