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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2009

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-368-2

Chevron Corporation

(Exact name of registrant as specified in its charter)


Delaware	94-0890210	6001 Bollinger Canyon Road, San Ramon, California 94583-2324

(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)	(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code (925) 842-1000

Securities registered pursuant to Section 12(b) of the Act:


Title of Each Class		Name of Each Exchange on Which Registered
Common stock, par value $.75 per share		New York Stock Exchange, Inc.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes ☑ No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes o No ☑

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes ☑ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☑ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer ☑		Accelerated filer o		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No ☑

Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter - $132,865,210,015 (As of June 30, 2009)

Number of Shares of Common Stock outstanding as of February 19, 2010 - 2,008,352,638

DOCUMENTS INCORPORATED BY REFERENCE

(To The Extent Indicated Herein)

Notice of the 2010 Annual Meeting and 2010 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company's 2010 Annual Meeting of Stockholders (in Part III)

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Item			Page No.

PART I
	1.	Business		3
		(a) General Development of Business		3
		(b) Description of Business and Properties		4
		Capital and Exploratory Expenditures		4
		Upstream - Exploration and Production		4
		Net Production of Crude Oil and Natural Gas Liquids and Natural Gas		5
		Average Sales Prices and Production Costs per Unit of Production		6
		Gross and Net Productive Wells		6
		Reserves		6
		Acreage		7
		Delivery Commitments		8
		Development Activities		8
		Exploration Activities		9
		Review of Ongoing Exploration and Production Activities in Key Areas		9
		Sales of Natural Gas and Natural Gas Liquids		23
		Downstream - Refining, Marketing and Transportation		24
		Refining Operations		24
		Gas-to-Liquids		25
		Marketing Operations		25
		Transportation Operations		26
		Chemicals		28
		Other Businesses		28
		Mining		28
		Power Generation		29
		Chevron Energy Solutions		29
		Research and Technology		29
		Environmental Protection		29
		Web Site Access to SEC Reports		30
	1A.	Risk Factors		30
	1B.	Unresolved Staff Comments		32
	2.	Properties		32
	3.	Legal Proceedings		32
	4.	Submission of Matters to a Vote of Security Holders		33

PART II
	5.	Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		34
	6.	Selected Financial Data		34
	7.	Management's Discussion and Analysis of Financial Condition and Results of Operations		34
	7A.	Quantitative and Qualitative Disclosures About Market Risk		34
	8.	Financial Statements and Supplementary Data		34
	9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		35
	9A.	Controls and Procedures		35
		(a) Evaluation of Disclosure Controls and Procedures		35
		(b) Management's Report on Internal Control Over Financial Reporting		35
		(c) Changes in Internal Control Over Financial Reporting		35
	9B.	Other Information		35

PART III
	10.	Directors, Executive Officers and Corporate Governance		36
	11.	Executive Compensation		37
	12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		37
	13.	Certain Relationships and Related Transactions, and Director Independence		37
	14.	Principal Accounting Fees and Services		37

PART IV
	15.	Exhibits, Financial Statement Schedules		38
		Schedule II - Valuation and Qualifying Accounts		38
		Signatures		39
EX-10.15
EX-10.16
EX-10.17
EX-10.19
EX-10.20
EX-12.1
EX-21.1
EX-23.1
EX-24.1
EX-24.1
EX-24.3
EX-24.4
EX-24.5
EX-24.6
EX-24.7
EX-24.8
EX-24.9
EX-24.10
EX-24.11
EX-24.12
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-99.1
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

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CAUTIONARY STATEMENT RELEVANT TO FORWARD-LOOKING INFORMATION
FOR THE PURPOSE OF "SAFE HARBOR" PROVISIONS OF THE
PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This Annual Report on Form 10-K of Chevron Corporation contains forward-looking statements relating to Chevron's operations that are based on management's current expectations, estimates and projections about the petroleum, chemicals and other energy-related industries. Words such as "anticipates," "expects," "intends," "plans," "targets," "projects," "believes," "seeks," "schedules," "estimates," "budgets" and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond the company's control and are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, Chevron undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.

Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are: changing crude-oil and natural-gas prices; changing refining, marketing and chemical margins; actions of competitors or regulators; timing of exploration expenses; timing of crude-oil liftings; the competitiveness of alternate-energy sources or product substitutes; technological developments; the results of operations and financial condition of equity affiliates; the inability or failure of the company's joint-venture partners to fund their share of operations and development activities; the potential failure to achieve expected net production from existing and future crude-oil and natural-gas development projects; potential delays in the development, construction or start-up of planned projects; the potential disruption or interruption of the company's net production or manufacturing facilities or delivery/transportation networks due to war, accidents, political events, civil unrest, severe weather or crude-oil production quotas that might be imposed by the Organization of Petroleum Exporting Countries; the potential liability for remedial actions or assessments under existing or future environmental regulations and litigation; significant investment or product changes under existing or future environmental statutes, regulations and litigation; the potential liability resulting from other pending or future litigation; the company's future acquisition or disposition of assets and gains and losses from asset dispositions or impairments; government-mandated sales, divestitures, recapitalizations, industry-specific taxes, changes in fiscal terms or restrictions on scope of company operations; foreign-currency movements compared with the U.S. dollar; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; and the factors set forth under the heading "Risk Factors" on pages 30 through 32 in this report. In addition, such statements could be affected by general domestic and international economic and political conditions. Unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements.

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PART I


Item 1.	Business


(a)	General Development of Business

Summary Description of Chevron

Chevron Corporation,* a Delaware corporation, manages its investments in subsidiaries and affiliates and provides administrative, financial, management and technology support to U.S. and international subsidiaries that engage in fully integrated petroleum operations, chemicals operations, mining operations, power generation and energy services. Exploration and production (upstream) operations consist of exploring for, developing and producing crude oil and natural gas and also marketing natural gas. Refining, marketing and transportation (downstream) operations relate to refining crude oil and converting natural gas 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. Chemicals operations include the manufacture and marketing of commodity petrochemicals, plastics for industrial uses, and fuel and lubricant oil additives.

A list of the company's major subsidiaries is presented on pages E-23 and E-24. As of December 31, 2009, Chevron had approximately 64,000 employees (including about 4,000 service station employees). Approximately 31,500 employees (including about 3,500 service station employees), or 49 percent, were employed in U.S. operations.

Overview of Petroleum Industry

Petroleum industry operations and profitability are influenced by many factors, and individual petroleum companies have little control over some of them. Governmental policies, particularly in the areas of taxation, energy and the environment, have a significant impact on petroleum activities, regulating how companies are structured and where and how companies conduct their operations and formulate their products and, in some cases, limiting their profits directly. Prices for crude oil, natural gas, petroleum products and petrochemicals are generally determined by supply and demand for these commodities. However, some governments impose price controls on refined products such as gasoline or diesel fuel. The members of the Organization of Petroleum Exporting Countries (OPEC) are typically the world's swing producers of crude oil, and their production levels are a major factor in determining worldwide supply. Demand for crude oil and its products and for natural gas is largely driven by the conditions of local, national and global economies, although weather patterns and taxation relative to other energy sources also play a significant part. Seasonality is not a primary driver of changes in the company's quarterly earnings during the year.

Strong competition exists in all sectors of the petroleum and petrochemical industries in supplying the energy, fuel and chemical needs of industry and individual consumers. Chevron competes with fully integrated major global petroleum companies, as well as independent and national petroleum companies, for the acquisition of crude-oil and natural-gas leases and other properties and for the equipment and labor required to develop and operate those properties. In its downstream business, Chevron also competes with fully integrated major petroleum companies and other independent refining, marketing and transportation entities and national petroleum companies in the sale or acquisition of various goods or services in many national and international markets.

Operating Environment

Refer to pages FS-2 through FS-9 of this Form 10-K in Management's Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the company's current business environment and outlook.

* Incorporated in Delaware in 1926 as Standard Oil Company of California, the company adopted the name Chevron Corporation in 1984 and ChevronTexaco Corporation in 2001. In 2005, ChevronTexaco Corporation changed its name to Chevron Corporation. As used in this report, the term "Chevron" and such terms as "the company," "the corporation," "our," "we" and "us" may refer to Chevron Corporation, one or more of its consolidated subsidiaries, or all of them taken as a whole, but unless stated otherwise, it does not include "affiliates" of Chevron - i.e., those companies accounted for by the equity method (generally owned 50 percent or less) or investments accounted for by the cost method. All of these terms are used for convenience only and are not intended as a precise description of any of the separate companies, each of which manages its own affairs.

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Chevron Strategic Direction

Chevron's primary objective is to create stockholder value and achieve sustained financial returns from its operations that will enable it to outperform its competitors. In the upstream, the company's strategies are to grow profitably in core areas, build new legacy positions and commercialize the company's equity natural-gas resource base while growing a high-impact global gas business. In the downstream, the strategies are to improve returns and selectively grow, with a focus on integrated value creation. The company also continues to invest in renewable-energy technologies, with an objective of capturing profitable positions.


(b)	Description of Business and Properties

The upstream, downstream and chemicals activities of the company and its equity affiliates are widely dispersed geographically, with operations in North America, South America, Europe, Africa, the Middle East, Asia and Australia. Tabulations of segment sales and other operating revenues, earnings and income taxes for the three years ending December 31, 2009, and assets as of the end of 2009 and 2008 - for the United States and the company's international geographic areas - are in Note 11 to the Consolidated Financial Statements beginning on page FS-40. Similar comparative data for the company's investments in and income from equity affiliates and property, plant and equipment are in Notes 12 and 13 on pages FS-43 through FS-45.

Capital and Exploratory Expenditures

Total expenditures for 2009 were $22.2 billion, including $1.6 billion for the company's share of equity-affiliate expenditures. In 2008 and 2007, expenditures were $22.8 billion and $20 billion, respectively, including the company's share of affiliates' expenditures of $2.3 billion in both periods.

Of the $22.2 billion in expenditures for 2009, about three-fourths, or $17.1 billion, was related to upstream activities. Approximately the same percentage was also expended for upstream operations in 2008 and 2007. International upstream accounted for about 80 percent of the worldwide upstream investment in 2009 and about 70 percent in 2008 and 2007, reflecting the company's continuing focus on opportunities available outside the United States.

In 2010, the company estimates capital and exploratory expenditures will be $21.6 billion, including $1.6 billion of spending by affiliates. About 80 percent of the total, or $17.3 billion, is budgeted for exploration and production activities, with $13.2 billion of that amount for projects outside the United States.

Refer also to a discussion of the company's capital and exploratory expenditures on page FS-12.

Upstream - Exploration and Production

The table on the following page summarizes the net production of liquids and natural gas for 2009 and 2008 by the company and its affiliates.

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Net Production of Crude Oil and Natural Gas Liquids and Natural Gas 1,2


					Components of Oil-Equivalent
					Crude Oil & Natural Gas
	Oil-Equivalent (Thousands				Liquids (Thousands of				Natural Gas (Millions of
	of Barrels per Day)				Barrels per Day)				Cubic Feet per Day)
	2009		2008		2009		2008		2009		2008
United States		717		671		484		421		1,399		1,501
Africa:
Nigeria		232		154		225		142		48		72
Angola		150		154		141		145		49		52
Chad		27		29		26		28		5		5
Republic of the Congo		21		13		19		11		13		12
Democratic Republic of the Congo		3		2		3		2		1		1

Total Africa		433		352		414		328		116		142

Asia:
Indonesia		243		235		199		182		268		319
Thailand		198		217		65		67		794		894
Partitioned Zone (PZ) 3		105		106		101		103		21		20
Kazakhstan		69		66		42		41		161		153
Bangladesh		66		71		2		2		387		414
Azerbaijan		30		29		28		28		10		7
Philippines		27		26		4		5		137		128
China		19		22		17		19		16		22
Myanmar		13		15		-		-		76		89

Total Asia		770		787		458		447		1,870		2,046

Other:
United Kingdom		110		106		73		71		222		208
Australia		108		96		35		34		434		376
Denmark		55		61		35		37		119		142
Colombia		41		35		-		-		245		209
Argentina		38		44		33		37		27		45
Trinidad and Tobago		34		32		1		-		199		189
Canada		28		37		27		36		4		4
Netherlands		9		9		2		2		41		40
Norway		5		6		5		6		1		1
Brazil		2		-		2		-		-		-

Total Other		430		426		213		223		1,292		1,214

Total Consolidated Operations		2,350		2,236		1,569		1,419		4,677		4,903
Equity Affiliates 4		328		267		277		230		312		222

Total Including Affiliates 5		2,678		2,503		1,846		1,649		4,989		5,125


1 2008 conformed to 2009 geographic presentation.
2 Excludes Athabasca oil sands production, net:		26		27		26		27		-		-
3 Located between Saudi Arabia and Kuwait.
4 Volumes represent Chevron's share of production by affiliates, including Tengizchevroil (TCO) in Kazakhstan and Petroboscan, Petroindependiente and Petropiar in Venezuela.
5 Volumes include natural gas consumed in operations of 521 million and 520 million cubic feet per day in 2009 and 2008, respectively.

Worldwide oil-equivalent production, including volumes from oil sands (refer to footnote 2 above), was 2.7 million barrels per day, up about 7 percent from 2008. The increase was mostly associated with the start-up of the Blind Faith and Tahiti fields in the U.S. Gulf of Mexico in late 2008 and the second quarter 2009, respectively, the commencement of operations in the third quarter 2008 at the Agbami Field in Nigeria, and the expansion at Tengiz in Kazakhstan. Refer to the "Results of Operations" section beginning on page FS-6 for a detailed discussion of the factors explaining the 2007-2009 changes in production for crude oil and natural gas liquids, and natural gas.

The company estimates that its average worldwide oil-equivalent production in 2010 will be approximately 2.73 million barrels per day. This estimate is subject to many uncertainties, including quotas that may be imposed by OPEC, the price effect on production volumes calculated under cost-recovery and variable-royalty provisions of certain contracts, changes in fiscal terms or restrictions on the scope of company operations, delays in project start-ups, fluctuations in demand for natural gas in various markets, and production that may have to be shut in due to weather conditions, civil unrest,

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changing geopolitics or other disruptions to operations. Future production levels also are affected by the size and number of economic investment opportunities and, for new large-scale projects, the time lag between initial exploration and the beginning of production. Refer to the "Review of Ongoing Exploration and Production Activities in Key Areas," beginning on page 9, for a discussion of the company's major crude-oil and natural-gas development projects.

Average Sales Prices and Production Costs per Unit of Production

Refer to Table IV on page FS-69 for the company's average sales price per barrel of crude oil, condensate and natural gas liquids and per thousand cubic feet of natural gas produced and the average production cost per oil-equivalent barrel for 2009, 2008 and 2007.

Gross and Net Productive Wells

The following table summarizes gross and net productive wells at year-end 2009 for the company and its affiliates:

Productive Oil and Gas Wells 1 at December 31, 2009


	Productive 2,3				Productive 2
	Oil Wells				Gas Wells
	Gross		Net		Gross		Net

United States		49,761		32,720		11,567		5,671
Africa		2,292		766		17		7
Asia		10,580		9,106		2,336		1,510
Other		1,605		963		275		74

Total Consolidated Companies		64,238		43,555		14,195		7,262
Equity in Affiliates		1,133		403		7		2

Total Including Affiliates		65,371		43,958		14,202		7,264

Multiple completion wells included above:		929		596		390		313


1		Includes wells producing or capable of producing and injection wells temporarily functioning as producing wells. Wells that produce both oil and gas are classified as oil wells.
2		Gross wells include the total number of wells in which the company has an interest. Net wells include wholly owned wells and the sum of the company's fractional interests in gross wells.
3		Canadian synthetic oil is not produced through wells and therefore is not presented in the table above.

Reserves

Refer to Table V beginning on page FS-69 for a tabulation of the company's proved net crude-oil and natural-gas reserves by geographic area, at the beginning of 2007 and each year-end from 2007 through 2009, and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period ending December 31, 2009. During 2009, the company provided crude-oil and natural-gas reserves estimates for 2008 to the Department of Energy, Energy Information Administration (EIA) that agree with the 2008 reserve volumes in Table V. This reporting fulfilled the requirement that such estimates be consistent with, and not differ more than 5 percent from, the information furnished to the Securities and Exchange Commission (SEC) in the company's 2008 Annual Report on Form 10-K. During 2010, the company will file estimates of crude-oil and natural-gas reserves with the Department of Energy, EIA, consistent with the 2009 reserve data reported in Table V.

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The net proved-reserve balances at the end of each of the three years 2007 through 2009 are shown in the table below:

Net Proved Reserves at December 31


	2009		2008		2007

Liquids* - Millions of barrels
Consolidated Companies		4,610		4,735		4,665
Affiliated Companies		2,363		2,615		2,422
Natural Gas - Billions of cubic feet
Consolidated Companies		22,153		19,022		19,137
Affiliated Companies		3,896		4,053		3,003
Total Oil-Equivalent - Millions of barrels
Consolidated Companies		8,303		7,905		7,855
Affiliated Companies		3,012		3,291		2,922


*		Crude oil, condensate and natural gas liquids. 2009 liquids amount for consolidated companies includes 460 million barrels of synthetic oil produced from oil sands mining operations in Canada in accordance with the adoption of the new SEC definition of oil and gas producing activity.

Acreage

At December 31, 2009, the company owned or had under lease or similar agreements undeveloped and developed crude-oil and natural-gas properties located throughout the world. The geographical distribution of the company's acreage is shown in the following table.

Acreage 1,2 at December 31, 2009
(Thousands of Acres)


									Developed and
	Undeveloped 3				Developed 3				Undeveloped
	Gross		Net		Gross		Net		Gross		Net

United States		4,679		3,708		6,139		3,769		10,818		7,477
Africa		9,663		5,705		2,499		917		12,162		6,622
Asia		38,370		18,491		5,313		2,742		43,683		21,233
Other		53,181		26,407		3,243		792		56,424		27,199

Total Consolidated Companies		105,893		54,311		17,194		8,220		123,087		62,531
Equity in Affiliates		640		300		259		104		899		404

Total Including Affiliates		106,533		54,611		17,453		8,324		123,986		62,935


1		Gross acreage includes the total number of acres in all tracts in which the company has an interest. Net acreage includes wholly owned interests and the sum of the company's fractional interests in gross acreage.
2		Table does not include mining acreage associated with the synthetic oil production in Canada. At year-end 2009, undeveloped gross and net acreage totaled 235 and 31, respectively. Developed gross and net acreage totaled 35 and 7, respectively. Developed acreage is acreage associated with productive mines. Undeveloped acreage is acreage on which mines have not been established and that may contain undeveloped proved reserves.
3		Developed acreage is spaced or assignable to productive wells. Undeveloped acreage is acreage on which wells have not been drilled or completed to permit commercial production and that may contain undeveloped proved reserves. The gross undeveloped acres that will expire in 2010, 2011 and 2012 if production is not established by certain required dates are 13,526, 9,784 and 3,662, respectively.

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Delivery Commitments

The company sells crude oil and natural gas from its producing operations under a variety of contractual obligations. Most contracts generally commit the company to sell quantities based on production from specified properties, but some natural-gas sales contracts specify delivery of fixed and determinable quantities, as discussed below.

In the United States, the company has no fixed and determinable delivery commitments to third-parties or affiliates.

Outside the United States, the company is contractually committed to deliver to third parties a total of 821 billion cubic feet of natural gas from 2010 through 2012 from Australia, Colombia, Denmark and the Philippines. The sales contracts contain variable pricing formulas that are generally referenced to the prevailing market price for crude oil, natural gas or other petroleum products at the time of delivery. The company believes it can satisfy these contracts from quantities available from production of the company's proved developed reserves in Australia, Colombia, Denmark and the Philippines.

Development Activities

Refer to Table I on page FS-64 for details associated with the company's development expenditures and costs of proved property acquisitions for 2009, 2008 and 2007.

The table below summarizes the company's net interest in productive and dry development wells completed in each of the past three years and the status of the company's development wells drilling at December 31, 2009. A "development well" is a well drilled within the proved area of a crude-oil or natural-gas reservoir to the depth of a stratigraphic horizon known to be productive.

Development Well Activity


	Wells Drilling				Net Wells Completed 1,2
	at 12/31/09 3				2009				2008				2007
	Gross		Net		Prod.		Dry		Prod.		Dry		Prod.		Dry

United States		47		22		582		3		846		4		875		5
Africa		6		2		40		-		33		-		43		-
Asia		38		22		580		-		665		1		597		-
Other		11		4		43		-		41		-		52		-

Total Consolidated Companies		102		50		1,245		3		1,585		5		1,567		5
Equity in Affiliates		1		-		6		-		16		-		3		-

Total Including Affiliates		103		50		1,251		3		1,601		5		1,570		5


1		2008 and 2007 conformed to 2009 geographic presentation.
2		Indicates the fractional number of wells completed during the year, regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for the production of crude oil or natural gas or, in the case of a dry well, the reporting of abandonment to the appropriate agency.
3		Represents wells in the process of drilling, including wells for which drilling was not completed and which were temporarily suspended at the end of 2009. Gross wells include the total number of wells in which the company has an interest. Net wells include wholly owned wells and the sum of the company's fractional interests in gross wells.

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Exploration Activities

The following table summarizes the company's net interests in productive and dry exploratory wells completed in each of the last three years and the number of exploratory wells drilling at December 31, 2009. "Exploratory wells" are wells drilled to find and produce crude oil or natural gas in unproved areas and include delineation wells, which are wells drilled to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir or to extend a known reservoir beyond the proved area.

Exploratory Well Activity


	Wells Drilling				Net Wells Completed 1,2
	at 12/31/09 3				2009				2008				2007
	Gross		Net		Prod.		Dry		Prod.		Dry		Prod.		Dry

United States		3		1		4		5		8		2		4		8
Africa		6		2		2		1		2		1		6		2
Asia		1		-		9		1		9		2		13		9
Other		4		3		5		4		44		2		43		6

Total Consolidated Companies		14		6		20		11		63		7		66		25
Equity in Affiliates		-		-		-		-		-		-		-		-

Total Including Affiliates		14		6		20		11		63		7		66		25


1		2008 and 2007 conformed to 2009 geographic presentation.
2		Indicates the fractional number of wells completed during the year, regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for the production of crude oil or natural gas or, in the case of a dry well, the reporting of abandonment to the appropriate agency. Some exploratory wells are not drilled with the intention of producing from the well bore. In such cases, "completion" refers to the completion of drilling. Further categorization of productive or dry is based on the determination as to whether hydrocarbons in a sufficient quantity were found to justify completion as a producing well, whether or not the well is actually going to be completed as a producer.
3		Represents wells that are in the process of drilling but have been neither abandoned nor completed as of the last day of the year, including wells for which drilling was not completed and which were temporarily suspended at the end of 2009. Gross wells include the total number of wells in which the company has an interest. Net wells include wholly owned wells and the sum of the company's fractional interests in gross wells.

Refer to Table I on page FS-64 for detail of the company's exploration expenditures and costs of unproved property acquisitions for 2009, 2008 and 2007.

Review of Ongoing Exploration and Production Activities in Key Areas

Chevron's 2009 key upstream activities, some of which are also discussed in Management's Discussion and Analysis of Financial Condition and Results of Operations beginning on page FS-2, are presented below. The comments include references to "total production" and "net production," which are defined under "Production" in Exhibit 99.1 on page E-42.

The discussion that follows references the status of proved reserves recognition for significant long-lead-time projects not yet on production and for projects recently placed on production. Reserves are not discussed for recent discoveries that have yet to advance to a project stage or for mature areas of production that do not have individual projects requiring significant levels of capital or exploratory investment. Amounts indicated for project costs represent total project costs, not the company's share of costs for projects that are less than wholly owned.

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				Chevron has production and exploration activities in most of the world's major hydrocarbon basins. The company's upstream strategy is to grow profitably in core areas, build new legacy positions and commercialize the company's equity natural-gas resource base while growing a high-impact global gas business. The map at left indicates Chevron's primary areas of production and exploration.


a)	United States

Upstream activities in the United States are concentrated in California, the Gulf of Mexico, Louisiana, Texas, New Mexico, the Rocky Mountains and Alaska. Average net oil-equivalent production in the United States during 2009 was 717,000 barrels per day.

In California, the company has significant production in the San Joaquin Valley. In 2009, average net oil-equivalent production was 211,000 barrels per day, composed of 191,000 barrels of crude oil, 91 million cubic feet of natural gas and 5,000 barrels of natural gas liquids. Approximately 84 percent of the crude-oil production is considered heavy oil (typically with API gravity lower than 22 degrees).

Average net oil-equivalent production during 2009 for the company's combined interests in the Gulf of Mexico shelf and deepwater areas, and the onshore fields in the region was 243,000 barrels per day. The daily oil-equivalent production comprised 149,000 barrels of crude oil, 484 million cubic feet of natural gas and 14,000 barrels of natural gas liquids.



				During 2009, Chevron was engaged in various development and exploration activities in the deepwater Gulf of Mexico. The 75 percent-owned and operated Blind Faith development, which achieved first oil in the fourth quarter 2008, reached maximum total production of 70,000 barrels per day of oil-equivalent in 2009. Blind Faith has an estimated production life of 20 years. At the 58 percent-owned and operated Tahiti Field, first oil was achieved in the second quarter 2009. Maximum total production of 135,000 barrels per day of oil-equivalent was achieved in the third quarter 2009. A second development phase is under evaluation, including additional development drilling and a probable waterflood, with a final investment decision planned formid-2010. The waterflood includes water injection topsides

equipment, subsea equipment and water injection wells. Tahiti has an estimated production life of 30 years. As of the end of 2009, proved reserves had been recognized for the first development phase of the Tahiti Field.

The company is participating in the ultra-deepwater Perdido Regional Development. The project encompasses the installation of a producing host facility to service multiple fields, including Chevron's 33.3 percent-owned Great White, 60 percent-owned Silvertip and 57.5 percent-owned Tobago. Chevron has a 37.5 percent interest in the Perdido Regional Host. All of these fields and the production facility are partner-operated. Activities during 2009 included installation of the topsides on the spar, installation of umbilicals, hook-up and commissioning of the facility systems, and ongoing development drilling. First oil is expected in the first half of 2010, with the facility designed to handle 130,000 barrels of oil-equivalent per day. The project has an expected life of approximately 25 years. Proved reserves have been recognized for the project.

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The company has a 60 percent-owned and operated interest in Big Foot. Two successful appraisal wells have been drilled, the most recent in the first quarter 2009. The company also acquired the rights to an adjacent block during 2009. The project entered front-end engineering and design (FEED) in October 2009 and a final investment decision is expected in late 2010. Total maximum production from the project is expected to be 63,000 barrels of oil-equivalent per day. At the end of 2009, proved reserves had not been recognized.

The Caesar and Tonga partnerships for properties located in a number of blocks in the Green Canyon area have formed a unit agreement for the area, with Chevron having a 20.3 percent nonoperated working interest. A final investment decision on the joint Caesar-Tonga project was made in the first quarter 2009. Development plans include four wells and a subsea tie-back to a nearby third-party production facility. Two development sidetracks were completed during the year. Proved reserves have been recognized for the project and first oil is expected in 2011.

The Jack and St. Malo fields are located within 25 miles of each other and are being considered for joint development. Chevron has a 50 percent-owned interest in Jack and a 51 percent-owned interest in St. Malo, following the anticipated acquisition of an additional 9.8 percent equity interest in St. Malo in March 2010. Both fields are company operated. The project entered FEED in May 2009 and a final investment decision is expected in late 2010. The facility is planned to have an initial design capacity of 150,000 barrels of oil-equivalent per day and start-up is expected in 2014. At the end of 2009, proved reserves had not been recognized.

Deepwater exploration activities in 2009 and early 2010 included participation in 10 exploratory wells - five wildcat, three appraisal and two delineation. Exploratory work included the following:


	•	Buckskin - 55 percent-owned and operated. A successful wildcat discovery was announced in February 2009. The first appraisal well is scheduled to begin drilling in the second quarter 2010.

	•	Knotty Head - 25 percent nonoperated working interest. The first appraisal well began drilling in October 2009 at this 2005 discovery.

	•	Puma - 21.8 percent nonoperated working interest. An appraisal well completed drilling in early 2009. Leases were relinquished in mid-2009.

	•	Tubular Bells - 30 percent nonoperated working interest. Studies to screen and evaluate future development alternatives were continuing at the end of 2009.

At the end of 2009, the company had not recognized proved reserves for any of the exploration projects discussed above.

Besides the activities connected with the development and exploration projects in the Gulf of Mexico, the company also has contracted capacity of 1 billion cubic feet per day at the third-party Sabine Pass liquefied natural gas (LNG) regasification terminal in Louisiana. The 20-year capacity reservation agreement became effective in July 2009 and enables import of natural gas for the North America market. In September 2009, Chevron began to utilize a portion of the reserved capacity under this agreement.

Chevron has also contracted 1.6 billion cubic feet per day of capacity in a third-party pipeline system connecting the Sabine Pass LNG terminal to the natural-gas pipeline grid. The new pipeline, which was placed in service in July 2009, provides access to two major salt dome storage fields and 10 major interstate pipeline systems, including an interconnect with Chevron's Sabine Pipeline, which connects to the Henry Hub. An interconnect to Chevron's Bridgeline Pipeline is scheduled to be completed in the third quarter 2010. The Henry Hub interconnects to nine interstate and four intrastate pipelines and is the pricing point for natural gas futures contracts traded on the New York Mercantile Exchange.

Outside California and the Gulf of Mexico, the company manages operations across the mid-continental United States and Alaska. During 2009, the company's U.S. production outside California and the Gulf of Mexico averaged 263,000 net oil-equivalent barrels per day, composed of 94,000 barrels of crude oil, 824 million cubic feet of natural gas and 31,000 barrels of natural gas liquids.

In the Piceance Basin in northwestern Colorado, additional production came on line in September 2009 from the company's 100 percent-owned and operated natural-gas development. Development drilling, which began in 2007, surpassed 190 wells in 2009, with 81 completed wells available to supply natural gas to the central processing facility. Construction of compression and dehydration facilities to produce 65 million cubic feet per day of natural gas was completed in the third quarter 2009. Future work is expected to be completed in multiple stages. The full development plan includes drilling more than 2,000 wells from multi-well pads over the next 30 to 40 years. Proved reserves for subsequent stages of the project had not been recognized at year-end 2009.

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b)	Africa

In Africa, the company is engaged in exploration and production activities in Angola, Chad, Democratic Republic of the Congo, Nigeria and Republic of the Congo. Net oil-equivalent production in Africa averaged 433,000 barrels per day during 2009.


				Angola: Chevron holds company-operated working interests in offshore Blocks 0 and 14 and nonoperated working interests in offshore Block 2 and the onshore Fina Sonangol Texaco (FST) area. Net production from these operations in 2009 averaged 150,000 barrels of oil-equivalent per day. The company operates the 39.2 percent-owned Block 0, which averaged 105,000 barrels per day of net liquids production in 2009. The Block 0 concession extends through 2030. Initial production from the northern portion of the Mafumeira Field in Block 0 occurred in July 2009, and total maximum crude-oil production of 42,000 barrels per day was achieved in first quarter 2010. Front-end engineering and design (FEED) started in January 2010 on Mafumeira Sul, a project to develop the southern portion of the Mafumeira Field. A final investment decision is expected in 2011. Maximum production from Mafumeira Sul is expected to be 95,000 barrels of crude oil per day. At year-end 2009, no proved reserves had been recognized for this project.

In the Greater Vanza/Longui Area of Block 0, development concept selection was under way and continued into 2010. FEED is planned for 2011. FEED activities continued on the south extension of the N'Dola Field development. At year-end 2009, no proved reserves had been recognized for these projects.

Four gas management projects in Block 0 are expected to eliminate routine flaring of natural gas by injecting excess natural gas into various reservoirs. The Takula Flare and Relief Modification Project and the Cabinda Gas Plant Project entered service in June 2009 and December 2009, respectively. These projects are expected to reduce flaring by up to 60 million cubic feet per day. Work continued on the Nemba Enhanced Secondary Recovery and Flare Reduction Project and the Malongo Flare and Relief Modification Project, which are scheduled for start-up in the fourth quarter 2010 and in 2011, respectively.

Also in Block 0, a successful two-well exploration and appraisal program was completed. The exploration well was completed in March 2009, and the appraisal well was completed in May 2009. Drilling began on another exploration well in November 2009 and was completed in the first quarter 2010. The results are under evaluation.

In the 31 percent-owned Block 14, net production in 2009 averaged 33,000 barrels of liquids per day from the Benguela Belize - Lobito Tomboco development and the Kuito, Tombua and Landana fields. Development and production rights for the various fields in Block 14 expire between 2027 and 2029.

Development of the Tombua and Landana fields continued in 2009. First production occurred in August 2009 from new production facilities that were installed in late 2008. Proved developed reserves were recognized at start of production. Development drilling is expected to continue, with maximum total daily production of 100,000 barrels of crude oil anticipated in 2011.

During 2009, studies to evaluate development alternatives for the Lucapa Field continued. The project is expected to enter FEED in the fourth quarter 2010. A successful appraisal well was completed in the fourth quarter 2009 in the Malange area. As of the end of 2009, development of the Negage Field was suspended until cooperative arrangements between Angola and Democratic Republic of the Congo could be finalized. At the end of 2009, proved reserves had not been recognized for these projects.

The 39.2 percent-owned and operated Malongo Terminal Oil Export project was completed in November 2009. The new export system more than doubled export capacity from the area, which includes Blocks 0 and 14. In the 20 percent-owned Block 2 and the 16.3 percent-owned FST areas, combined production during 2009 averaged 3,000 barrels of net liquids per day.

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Equity Affiliate Operations: In addition to the exploration and producing activities in Angola, Chevron has a 36.4 percent ownership interest in the Angola LNG affiliate that began construction in early 2008 of an onshore natural gas liquefaction plant located in Soyo, Angola. The plant is designed to process more than 1 billion cubic feet of natural gas per day. Construction continued on schedule during 2009 with plant start-up scheduled for 2012. The life of the LNG plant is estimated to be in excess of 20 years. Proved reserves have been recognized for the producing operations associated with this project.

Angola - Republic of the Congo Joint Development Area: Chevron operates and holds a 31.3 percent interest in the Lianzi Development Area located between Angola and Republic of the Congo. In late 2008, the development project entered FEED, which continued through 2009. No proved reserves have been recognized for Lianzi.

Republic of the Congo: Chevron has a 31.5 percent nonoperated working interest in the Nkossa, Nsoko and Moho-Bilondo exploitation permits and a 29.3 percent nonoperated working interest in the Kitina exploitation permit, all of which are offshore. The development and production rights for Nkossa, Nsoko and Kitina expire in 2027, 2018 and 2019, respectively. Net production from the Republic of the Congo fields averaged 21,000 barrels of oil-equivalent per day in 2009.

In May 2009, a successful exploration well was drilled in the Moho-Bilondo exploitation permit area. Development alternatives were being evaluated during 2009. The Moho-Bilondo subsea development project, which started production in 2008, is expected to achieve maximum total production of 90,000 barrels of crude oil per day in the third quarter 2010. Chevron's development and production rights for Moho-Bilondo expire in 2030.

Democratic Republic of the Congo: Chevron has a 17.7 percent nonoperated working interest in an offshore concession. Daily net production in 2009 averaged 3,000 barrels of oil-equivalent.

Chad/Cameroon: Chevron participates in a project to develop crude-oil fields in southern Chad and transport the produced volumes by pipeline to the coast of Cameroon for export. Chevron has a 25 percent nonoperated working interest in the producing operations and an approximate 21 percent interest in two affiliates that own the pipeline. Average daily net production from the Chad fields in 2009 was 27,000 barrels of oil-equivalent. In September 2009, first production was achieved at the Timbre Field in the Doba area. The Chad producing operations are conducted under a concession that expires in 2030.

Libya: After an unsuccessful exploration well was completed, the company elected to relinquish its 100 percent interest in the onshore Block 177 exploration license in the fourth quarter 2009.


				Nigeria: Chevron holds a 40 percent interest in 13 concessions in the onshore and near-offshore region of the Niger Delta. The company operates under a joint-venture arrangement in this region with the Nigerian National Petroleum Corporation, which owns a 60 percent interest. The company also owns varying interests in deepwater offshore blocks. In 2009, the company's net oil-equivalent production in Nigeria averaged 232,000 barrels per day, composed of 225,000 barrels of liquids and 48 million cubic feet of natural gas. In deepwater Oil Mining Lease (OML) 127 and OML 128, the 68.2 percent-owned and operated Agbami Field reached maximum total liquids production of 250,000 barrels per day in August 2009, following completion of development drilling. In December 2009, a subsequent 10-well development program was initiated and is expected to offset field decline. The leases that contain the Agbami Field expire in 2023 and 2024. Also in the deepwater area, the Aparo Field in OML 132 and OML 140 and the Bonga SW Field in offshore OML 118 share a common geologic structure and are planned to be jointly developed under a proposed unitization agreement. Work continued in 2009 on a final unitization agreement between Chevron and

partners in OML 118. At the end of 2009, no proved reserves were recognized for this project.

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Chevron operates and holds a 95 percent interest in the deepwater Nsiko discovery on OML 140. Development activities continued in 2009, with FEED expected to start after commercial terms are resolved. At the end of 2009, the company had not recognized proved reserves for this project.

The company also holds a 30 percent nonoperated working interest in the deepwater Usan project in OML 138. The development plans involve subsea wells producing to a floating production, storage and offloading vessel. Development drilling started in June 2009. Production start-up is scheduled for 2012, and maximum total production of 180,000 barrels of crude oil per day is expected to be achieved within one year of start-up. Total costs for the project are estimated at $8.4 billion. Usan has an estimated production life of 20 years. Proved reserves have been recognized for this project.

Chevron participated in one successful deepwater exploration well during 2009 in Oil Prospecting License (OPL) 223. The company has a 30 percent nonoperated working interest in the license. At the end of 2009, proved reserves had not been recognized for the exploration project.

In the Niger Delta, construction on the Phase 3A expansion of the Escravos Gas Plant (EGP) was completed in late 2009 and start of production is expected in March 2010. EGP Phase 3A scope includes offshore natural-gas gathering and compression infrastructure and the addition of a second natural-gas processing facility. The modifications are designed to increase processing capacity from 285 million to 680 million cubic feet of natural gas per day and increase LPG and condensate export capacity from 15,000 to 58,000 barrels per day. EGP Phase 3A is designed to process natural gas from the Meji, Delta South, Okan and Mefa fields. The anticipated life of EGP Phase 3A is 25 years. Phase 3B of the EGP project is designed to gather natural gas from eight offshore fields and to compress and transport natural gas to onshore facilities beginning in 2012. The engineering, procurement, construction, and installation contract for the pipelines was awarded and work commenced in late 2009. Proved reserves have been recognized for these projects.

The 40 percent-owned and operated Onshore Asset Gas Management project is designed to restore approximately 125 million cubic feet per day of natural-gas production from certain onshore fields that have been shut in since 2003 due to civil unrest. Natural gas from these fields is sold in the Nigerian domestic gas market. The main on-site construction contracts are expected to be awarded in the second quarter 2010.

Refer to page 25 for a discussion of the planned gas-to-liquids facility at Escravos.

Equity Affiliate Operations: Chevron holds a 19.5 percent interest in the OKLNG Free Zone Enterprise (OKLNG) affiliate, which will operate the Olokola LNG project. OKLNG plans to build a multi-train natural-gas liquefaction facility and marine terminal located northwest of Escravos. At the end of 2009, timing of the final investment decision remains uncertain. The company has not recognized proved reserves associated with this project.

Refer to "Pipelines" under "Transportation Operations" beginning on page 26 for a discussion of the West African Gas Pipeline operations.

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c) Asia

Major producing countries in Asia include Azerbaijan, Bangladesh, Indonesia, Kazakhstan, the Partitioned Zone located between Saudi Arabia and Kuwait, and Thailand. During 2009, net oil-equivalent production averaged 1,044,000 barrels per day in Asia.


				Azerbaijan: Chevron holds a 10.3 percent nonoperated working interest in the Azerbaijan International Operating Company (AIOC), which produces crude oil in the Caspian Sea from the Azeri-Chirag-Gunashli (ACG) project. Chevron also has an 8.9 percent interest in the Baku-Tbilisi-Ceyhan (BTC) affiliate, which transports AIOC production by pipeline from Baku, Azerbaijan, through Georgia to Mediterranean deepwater port facilities in Ceyhan, Turkey. (Refer to "Pipelines" under "Transportation Operations" beginning on page 26 for a discussion of BTC operations.) In 2009, the company's daily net production from AIOC averaged 30,000 barrels of oil-equivalent. The final investment decision on the next development phase is expected in the first half 2010. AIOC operations are conducted under a 30-year production-sharing contract (PSC) that expires in 2024. Kazakhstan: Chevron holds a 20 percent nonoperated working interest in the Karachaganak project, which is being developed in phases. During 2009, Karachaganak net oil-equivalent production averaged 69,000 barrels per day, composed of 42,000 barrels of liquids and 161 million cubic feet of natural gas. In 2009, access to the Caspian Pipeline Consortium (CPC) and Atyrau-Samara (Russia) pipelines enabled approximately 184,000 barrels per day (33,000 net barrels) of Karachaganak liquids to be sold at world-market

prices. The remaining liquids were sold into Russian markets. During 2009, work continued on a fourth train that is designed to increase total export of processed liquids by 56,000 barrels per day. The fourth train is expected to start-up in 2011.

During 2009, Chevron and its partners continued to evaluate alternatives for a Phase III development of Karachaganak. Timing for the recognition of Phase III proved reserves is uncertain and depends on finalizing a project design and achieving project milestones. Karachaganak operations are conducted under a 40-year PSC that expires in 2038.

Equity Affiliate Operations: The company holds a 50 percent interest in Tengizchevroil (TCO), which is operating and developing the Tengiz and Korolev crude-oil fields, located in western Kazakhstan, under a 40-year concession that expires in 2033. Chevron's net oil-equivalent production in 2009 from these fields averaged 274,000 barrels per day, composed of 226,000 barrels of crude oil and natural gas liquids and 289 million cubic feet of natural gas.

In 2009, TCO continued ramp-up of the Sour Gas Injection (SGI) and Second Generation Plant (SGP) facilities. The SGI facility injects approximately one-third of the sour gas separated from the crude oil back into the reservoir. The injected gas maintains higher reservoir pressure and displaces oil towards producing wells. TCO is evaluating options for another expansion project based on SGI/SGP technologies.

During 2009, the majority of TCO's crude-oil production was exported through the Caspian Pipeline Consortium (CPC) pipeline that runs from Tengiz in Kazakhstan to tanker-loading facilities at Novorossiysk on the Russian coast of the Black Sea. The balance was shipped via other export routes, which included shipment via tanker to Baku for transport by the BTC pipeline to Ceyhan or by rail to Black Sea ports. (Refer to "Pipelines" under "Transportation Operations" beginning on page 26 for a discussion of CPC operations.)

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Turkey: Chevron holds a 25 percent nonoperated working interest in the Silopi licenses in southeast Turkey, which is on trend with production in Iraq's northern Zagros Fold Belt. An exploration well in the Lale prospect completed drilling in the first quarter 2010, and is under evaluation.

Bangladesh: Chevron holds interests in three operated PSCs covering onshore Blocks 12, 13 and 14 and offshore Block 7. The company has a 98 percent interest in Blocks 12, 13 and 14. Government approval of a 2009 farm-out in Block 7 was received in February 2010, reducing the company's interest from 88 percent to 43 percent. The farm-out was to GS Caltex, a 50 percent-owned affiliate of the company. Net oil-equivalent production from these operations in 2009 averaged 66,000 barrels per day, composed of 387 million cubic feet of natural gas and 2,000 barrels of liquids. In 2009, a final investment decision was achieved after the government approved the development of a compression project that is expected to support additional production starting in 2012 from the Bibiyana, Jalalabad and Moulavi Bazar natural-gas fields. Proved reserves have been recognized for this project. The government also approved an amendment to the PSC for Blocks 13 and 14 that allows the company to acquire additional 3-D seismic over the Jalalabad Field. Also in 2009, the company acquired seismic data on Block 7. Evaluation and data processing is under way, and an exploration well is planned to be completed by 2011.

Cambodia: Chevron operates the 1.2 million-acre (4,709 sq-km) Block A, located offshore in the Gulf of Thailand, and expects to reduce its ownership to 30 percent pending government approval of the farm-out that is anticipated in the second quarter 2010. In 2009, commercial evaluation of the prospects continued. The company was granted an extension for the Block A exploration period to the third quarter 2010 in exchange for the obligation to drill three exploration wells. Information gained from the drilling program is expected to provide improved definition of the resource in the block. Proved reserves had not been recognized as of the end of 2009.

Myanmar: Chevron has a 28.3 percent nonoperated working interest in a PSC for the production of natural gas from the Yadana and Sein fields offshore in the Andaman Sea. The company also has a 28.3 percent interest in a pipeline company that transports the natural gas from Yadana to the Myanmar-Thailand border for delivery to power plants in Thailand. Most of the natural gas is purchased by Thailand's PTT Public Company Limited (PTT). The company's average net natural gas production in 2009 was 76 million cubic feet per day. During 2009, the platform for a compression project was completed. Project start-up is expected in 2011.


				Thailand: Chevron has operated and nonoperated working interests in several different offshore blocks. The company's net oil-equivalent production in 2009 averaged 198,000 barrels per day, composed of 65,000 barrels of crude oil and condensate and 794 million cubic feet of natural gas. All of the company's natural-gas production is sold to PTT under long-term sales contracts. Operated interests are in Pattani and other fields with ownership interests ranging from 35 percent to 80 percent in Blocks 10 through 13, B12/27, B8/32, 9A, G4/43 and G4/48. Blocks B8/32 and 9A produce crude oil and natural gas from eight operating areas, and Blocks 10 through 13 and B12/27 produce crude oil, condensate and natural gas from 16 operating areas.

Chevron has a 16 percent nonoperated working interest in Blocks 14A, 15A, 16A, G9/48 and G8/50, known collectively as the Arthit Field.

During 2009, construction at the 69.8 percent-owned and operated Platong Gas II project continued. The project is designed to add 420 million cubic feet per day of processing capacity in 2012. Proved reserves have been recognized for this project. Concessions for Blocks 10 through 13 expire in 2022.

During 2009, 14 exploration wells were drilled in the Gulf of Thailand, 13 were successful and one nonoperated well in the Arthit Field was unsuccessful. Two 3-D seismic surveys and geological studies for Block G4/50 were also completed in 2009. At the end of 2009, proved reserves had not been recognized for these activities. Three exploratory wells in Block G4/50 are planned for the second quarter 2010. For Blocks G6/50 and G7/50, one exploration well is scheduled in each block for completion by the third quarter 2010. In addition, Chevron holds exploration interests in a number of blocks that are currently inactive, pending resolution of border issues between Thailand and Cambodia.

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Vietnam: The company operates off the southwest coast and has a 42.4 percent interest in a PSC that includes Blocks B and 48/95, and a 43.4 percent interest in another PSC for Block 52/97. In August 2009, Chevron reduced its ownership interest in a third operated PSC to 20 percent in Block B122 offshore eastern Vietnam. No production occurred in these areas during 2009.

In the blocks off the southwest coast, the Vietnam Gas Project is aimed at developing an area in the Malay Basin to supply natural gas to state-owned Petrovietnam. The project includes installation of wellhead and hub platforms, a floating storage and offloading vessel, field pipelines and a central processing platform. The project is expected to enter front-end engineering and design (FEED) in the first quarter 2010, and a final investment decision is expected in 2011. Maximum total production is planned to be about 500 million cubic feet of natural gas per day. At the end of 2009, proved reserves had not been recognized for this project.

In conjunction with the Vietnam Gas Project, a Petrovietnam-operated pipeline will be required to support the offshore development. Chevron will have a 28.7 percent interest in the pipeline, which is planned to transport natural gas from the offshore development to customers in southern Vietnam.

During the year, the company continued to analyze well results and seismic processing from Block B and Block 52/97. In Block 122, 2-D seismic data processing and geologic studies were completed. An exploration well is planned for 2011. Proved reserves had not been recognized as of the end of 2009. Future activity in Block 122 may be affected by an ongoing territorial dispute between Vietnam and China.


				China: Chevron has one operated and three nonoperated working interests in several areas. Net oil-equivalent production from the nonoperated areas in 2009 averaged 19,000 barrels per day, composed of 17,000 barrels of crude oil and condensate and 16 million cubic feet of natural gas. The company holds a 49 percent-owned and operated interest in the Chuandongbei area in the onshore Sichuan Basin, where the company entered into a 30-year PSC effective February 2008 to develop natural-gas resources. Project plans included two sour-gas purification plants with an aggregate design capacity of 740 million cubic feet per day. During 2009, general infrastructure for the plant site and well pads progressed. Development drilling and the construction and installation of additional processing facilities and gathering systems are expected to start in 2010. Proved reserves have been recognized for this project. The PSC for Chuandongbei expires in 2038. In the South China Sea, the company has nonoperated working interests of 32.7 percent in Blocks 16/08 and 16/19 located in the Pearl River Delta Mouth Basin, 24.5 percent in the QHD-32-6 Field in Bohai Bay, and 16.2 percent in the unitized and producing BZ 25-1 and BZ 19-4 crude-oil fields in Bohai Bay Block 11/19. In

November 2009, a storm damaged the floating production, storage and offloading (FPSO) vessel utilized by the company's nonoperated assets in Block 11/19. Temporary and permanent recovery options are under development and production is expected to fully resume in 2012.

The joint development of the HZ25-3 and HZ25-1 crude-oil fields in Block 16/19 continued through the end of 2009. First production was delayed from the third quarter 2009 and is expected to be fully restored in the fourth quarter 2010 following damage to the FPSO vessel caused by a typhoon that struck the area in September 2009.

In 2009, Chevron relinquished its nonoperated working interest in four exploration blocks in the Ordos Basin. Government approval is expected in mid-2010.

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				Indonesia: Chevron's operated interests in Indonesia are managed by several wholly owned subsidiaries, including PT Chevron Pacific Indonesia (CPI). CPI holds operated interests of 100 percent in the Rokan and Siak PSCs and 90 percent in the MFK (Mountain Front Kuantan) PSC. Other subsidiaries operate four PSCs in the Kutei Basin, located offshore East Kalimantan, and one PSC in the East Ambalat Block, located offshore northeast Kalimantan. These interests range from 80 percent to 100 percent. Chevron also has nonoperated working interests in a joint venture in Block B in the South Natuna Sea and in the NE Madura III Block inthe East Java Sea Basin. Chevron's interests in these PSCs range from 25 percent to 40 percent.

The company's net oil-equivalent production in 2009 from all of its interests in Indonesia averaged 243,000 barrels per day. The daily oil-equivalent rate comprised 199,000 barrels of liquids and 268 million cubic feet of natural gas. The largest producing field is Duri, located in the Rokan PSC. Duri has been under steamflood operation since 1985 and is one of the world's largest steamflood developments. The North Duri Development is divided into multiple expansion areas. The first expansion in Area 12 started steam injection in June 2009. Maximum total daily production from Area 12 is estimated at 34,000 barrels of crude oil in 2012. A final investment decision regarding North Duri Area 13 is expected by year-end 2010. The Rokan PSC expires in 2021.

Chevron advanced its development plans for the Gendalo and Gehem deepwater natural-gas fields located in the Kutei Basin. FEED started in December 2009, with completion dependent upon achieving project milestones and receipt of government approvals. The Bangka deepwater natural-gas project was progressed during the year under a revised, lower-cost development plan. The project is expected to enter FEED in the second quarter 2010. Under the terms of the PSCs for both projects, the company's 80 percent-owned and operated interest is expected to be reduced to 72 percent in 2010 with the farm-in of an Indonesian company. At the end of 2009, the company had not recognized proved reserves for either of these projects.

Also in the Kutei Basin, first production at the Seturian Field occurred in September 2009, which is providing natural gas to a state-owned refinery. During 2009, evaluation of the 50 percent-owned and operated Sadewa project in the Kutei Basin was suspended.

A drilling campaign continued through 2009 in South Natuna Sea Block B to provide additional supply for long-term natural-gas sales contracts with additional development drilling planned for 2010. The North Belut development project achieved first production in November 2009. The South Belut development project was under review during the year.

A two-well exploration program was conducted in the Central Sumatra Basin in 2009. One commercial discovery was made in the Rokan Block, and a second well in the Siak Block resulted in a dry hole. Chevron's working interests in two exploration blocks in western Papua, West Papua I and West Papua III, are expected to be reduced to 51 percent interests in 2010. Completion of geological studies for those blocks was ongoing at year-end 2009, and 2-D seismic acquisition is planned for the second half 2010.

In West Java, Chevron operates the wholly owned Salak geothermal field with a total power-generation capacity of 377 megawatts. Also in West Java, Chevron holds a 95 percent interest in a power generation company that operates the Darajat geothermal contract area with a total capacity of 259 megawatts. Chevron also operates a 95 percent-owned 300-megawatt cogeneration facility in support of CPI's operation in North Duri, Sumatra.

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				Partitioned Zone (PZ): Chevron holds a 30-year agreement with the Kingdom of Saudi Arabia to operate on behalf of the Saudi government its 50 percent interest in the petroleum resources of the onshore area of the PZ between Saudi Arabia and Kuwait. Under the agreement, the company has rights to this 50 percent interest in the hydrocarbon resource and pays royalty and taxes on the associated volumes produced until 2039. During 2009, the company's average net oil-equivalent production was 105,000 barrels per day, composed of 101,000 barrels of crude oil and 21 million cubic feet of natural gas. In June 2009, steam injection was initiated in the second phase of a steamflood pilot project.

The pilot is an application of steam injection into a carbonate reservoir and, if successful, could significantly increase heavy oil recovery. The Central Gas Utilization Project was initiated in 2009 to assess alternatives to increase natural-gas utilization and eliminate routine flaring. A final investment decision is expected in 2011. No reserves have been recognized for these projects.

Philippines: The company holds a 45 percent nonoperated working interest in the Malampaya natural-gas field located 50 miles (80 km) offshore Palawan Island. Net oil-equivalent production in 2009 averaged 27,000 barrels per day, composed of 137 million cubic feet of natural gas and 4,000 barrels of condensate. Chevron also develops and produces geothermal resources under an agreement with the Philippine government. Chevron expects to sign a new 25-year contract with the government by the end of 2010 to operate the steam fields, which supply geothermal resources to the 637 megawatt geothermal facilities.

d) Other

"Other" is composed of Australia, Argentina, Brazil, Colombia, Trinidad and Tobago, Venezuela, Canada, Greenland, Denmark, Faroe Islands, the Netherlands, Norway, Poland and the United Kingdom. Net oil-equivalent production from countries included in this section averaged 484,000 barrels per day during 2009. In addition, the company's share of production from oil sands (for upgrading into synthetic oil) from the Athabasca Oil Sands Project in Canada was 26,000 barrels per day.


				Australia: During 2009, the average net oil-equivalent production from Chevron's interests in Australia was 108,000 barrels per day, composed of 35,000 barrels of liquids and 434 million cubic feet of natural gas. Chevron has a 16.7 percent nonoperated working interest in the North West Shelf (NWS) Venture offshore Western Australia. Daily net production from the project during 2009 averaged 26,000 barrels of crude oil and condensate, 433 million cubic feet of natural gas, and 5,000 barrels of LPG. Approximately 70 percent of the natural gas was sold in the form of LNG to major utilities in Japan, South Korea and China, primarily under long-term contracts. The remaining natural gas was sold to the Western Australia domestic market. The NWS Venture continues to progress two major capital projects that achieved final investment decision in 2008. Fabrication of platform topsides for the North Rankin 2 project commenced in June 2009. The project is designed to recover remaining low-pressure natural gas from the North Rankin and Perseus natural-gas fields to meet gas supply needs and includes necessary tie-ins to, and refurbishment of, the North Rankin A platform. Upon completion, both platforms are

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designed to be operated as a single integrated facility. The project is scheduled to start production in 2013. Proved reserves have been recognized for the project.

The NWS Venture is also advancing plans to extend the period of crude-oil production. The NWS Oil Redevelopment Project is designed to replace the present floating production, storage and offloading vessel and a portion of existing subsea infrastructure that services production from the Cossack, Hermes, Lambert and Wanaea offshore fields. In 2009, work commenced on conversion of the replacement vessel. The project is expected to start-up in early 2011 and extend production past 2020. The concession for the NWS Venture expires in 2034.

On Barrow and Thevenard islands off the northwest coast of Australia, Chevron operates crude-oil producing facilities that had combined net production of 4,000 barrels per day in 2009. Chevron's interests in these operations are 57.1 percent for Barrow and 51.4 percent for Thevenard.

Also off the northwest coast of Australia, Chevron holds significant equity interests in the large natural-gas resource of the Greater Gorgon Area. The company initially held a 50 percent ownership interest across most of the area and is the operator of the Gorgon Project. Chevron and its joint-venture partners are proceeding with the combined development of Gorgon and nearby natural-gas fields as one large-scale project. Environmental approval from the Australian Commonwealth Government was issued in August 2009. In September 2009, the company announced the final investment decision and total estimated project costs for the first phase of development of $37 billion (AU$ 43 billion). The project's scope includes a three-train, 15 million-metric-ton-per-year LNG facility; a carbon sequestration project; and a domestic natural-gas plant. Natural gas for the project is expected to be supplied from the Gorgon and Io/Jansz fields.

In 2009, long-term, binding agreements were finalized with four Asian customers for the delivery of about 4.4 million metric tons per year of LNG from the Gorgon Project. Equity sales agreements with three of the customers reduced Chevron's interest in the project to 47.3 percent at the end of 2009. Nonbinding Heads of Agreements (HOA) for delivery of an additional 2.1 million metric tons per year of LNG were also signed with three additional Asian customers in 2009 and early 2010. Negotiations continue to finalize binding sales agreements, which would bring LNG delivery commitments to a combined total of about 90 percent of Chevron's share of LNG from the project. During 2009, the company recognized proved reserves for the Greater Gorgon Area fields included in the project. First production of natural gas from these fields is expected in 2014. The project's estimated economic life exceeds 40 years from the time of start-up.

Development of the company's majority-owned and operated Wheatstone and Iago fields, located offshore Western Australia, continued with the project entering front-end engineering and design (FEED) in July 2009. Chevron operates the project and plans to supply natural gas to its 75 percent-owned and operated LNG facilities from two 100 percent-owned licenses comprising the majority of the Wheatstone Field and part of the nearby Iago Field. In October 2009, agreements were signed with two companies to join the Wheatstone Project as combined 25 percent LNG facility owners and suppliers of natural gas for the project's first two LNG trains. In December 2009 and January 2010, nonbinding HOAs were signed with two Asian customers to take delivery of 4.9 million tons of LNG per year from the project, representing about 60 percent of the total LNG available from the foundation project. In addition, under these same HOAs the parties would acquire a combined 16.8 percent nonoperated working interest in the Wheatstone Field licenses and a 12.6 percent interest in the foundation natural-gas processing facilities at the final investment decision. At the end of 2009, the company had not recognized proved reserves for this project.

In the Browse Basin, the company continued engineering and survey work on two potential development concepts for the Brecknock, Calliance and Torosa fields. At the end of 2009, proved reserves had not been recognized.

In May 2009, the company announced the successful completion of a well at the Clio prospect to further explore and appraise the 66.7 percent-owned Block WA-205-P. In 2009 and early 2010, the company also announced natural-gas discoveries at the Kentish Knock prospect in the 50 percent-owned Block WA-365-P, the Achilles and Satyr prospects in the 50 percent-owned Block WA-374-P and the Yellowglen prospect in the 50 percent-owned WA-268-P Block. All prospects are Chevron-operated. At the end of 2009, proved reserves had not been recognized.

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				Argentina: Chevron holds operated interests in eight concessions in the Neuquen Basin. Working interests range from 18.8 percent to 100 percent. Net oil-equivalent production in 2009 averaged 38,000 barrels per day, composed of 33,000 barrels of crude oil and natural gas liquids and 27 million cubic feet of natural gas. The company also holds a 14 percent interest in the Oleoductos del Valle S.A. pipeline. In 2009, Chevron sold its oil and gas concession in the Austral Basin and its interest in the Confluencia Field in the Neuquen Basin. Brazil: Chevron holds working interests in three deepwater blocks in the Campos Basin. Chevron also holds a nonoperated working interest in one block in the Santos Basin. Net oil-equivalent production in 2009 averaged 2,000 barrels per day. The Frade Field, located in the Campos Basin, achieved first oil in June 2009. Chevron is the operator and has a 51.7 percent interest in the field. Additional development drilling is under way, with an estimated maximum total production of 72,000 oil-equivalent barrels per day. The concession that includes the Frade project expires in 2025. In the partner-operated Campos Basin Block BC-20, two areas - 37.5 percent-owned Papa-Terra and 30 percent-owned Maromba - were retained for developmentfollowing the end of the exploration phase of this block. The Papa-Terra project progressed through FEED, and a

final investment decision was made in January 2010. The project operator estimates total costs of $5.2 billion and expects first production in 2013. The facility is expected to be capable of producing up to 140,000 barrels of crude oil per day. Evaluation of design options for Maromba continued into 2010. At the end of 2009, proved reserves had not been recognized for these projects.

In the Santos Basin, evaluation of investment options continued into 2010 for the 20 percent-owned and partner-operated Atlanta and Oliva fields. At the end of 2009, proved reserves had not been recognized for these fields.

Colombia: The company operates the offshore Chuchupa and the onshore Ballena and Riohacha natural-gas fields as part of the Guajira Association contract. In exchange, Chevron receives 43 percent of the production for the remaining life of each field and a variable production volume from a fixed-fee Build-Operate-Maintain-Transfer agreement based on prior Chuchupa capital contributions. Daily net production averaged 245 million cubic feet of natural gas in 2009.

Trinidad and Tobago: Company interests include 50 percent ownership in three partner-operated blocks in the East Coast Marine Area offshore Trinidad, which includes the Dolphin and Dolphin Deep producing natural-gas fields and the Starfish discovery. Chevron also holds a 50 percent operated interest in the Manatee area of Block 6(d). Net production in 2009 averaged 199 million cubic feet of natural gas per day. Incremental production associated with a new domestic sales agreement commenced at Dolphin in the third quarter 2009.

Venezuela: The company operates in two exploratory blocks offshore Plataforma Deltana, with working interests of 60 percent in Block 2 and 100 percent in Block 3. Chevron also holds a 100 percent operated interest in the Cardon III exploratory block, located north of Lake Maracaibo in the Gulf of Venezuela. Petróleos de Venezuela, S.A. (PDVSA), Venezuela's national crude-oil and natural-gas company, has the option to increase its ownership in each of the three company-operated blocks up to 35 percent upon declaration of commerciality. In February 2010, a Chevron-led consortium was selected to participate in a heavy-oil project composed of three blocks in the Orinoco Oil Belt of eastern Venezuela. The consortium is expected to acquire a 40 percent interest in the project, with PDVSA holding the remaining interest.

The Loran Field in Block 2 is projected to provide the initial supply of natural gas for Delta Caribe LNG (DCLNG) Train 1, Venezuela's first LNG train. A DCLNG framework agreement was signed in 2008, which provides Chevron with

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a 10 percent nonoperated interest in the first train and the associated offshore pipeline. An interim operating agreement governing activities prior to a final investment decision was signed by Chevron and its Train 1 partners in March 2009. In May 2009, the company relinquished part of Block 3 and retained the portion containing the 2005 Macuira natural-gas discovery. An unsuccessful exploration well was drilled in the Cardon III block in 2009. The company plans to continue to evaluate exploration potential in the Cardon III block in 2010. At the end of 2009, proved reserves had not been recognized in these exploratory blocks.

Equity Affiliate Operations: Chevron also holds interests in two affiliates located in western Venezuela and in one affiliate in the Orinoco Belt. Chevron has a 30 percent interest in the Petropiar affiliate that operates the Hamaca heavy-oil production and upgrading project located in Venezuela's Orinoco Belt, a 39.2 percent interest in the Petroboscan affiliate that operates the Boscan Field in the western part of the country, and a 25.2 percent interest in the Petroindependiente affiliate that operates the LL-652 Field in Lake Maracaibo. The company's share of average net oil-equivalent production during 2009 from these operations was 54,000 barrels per day, composed of 51,000 barrels of crude oil and natural gas liquids and 23 million cubic feet of natural gas.


				Canada: Company activities in Canada include nonoperated working interests of 26.9 percent in the Hibernia Field and 26.6 percent in the Hebron Field, both offshore eastern Canada, and 20 percent in the Athabasca Oil Sands Project (AOSP) and operated interests of 60 percent in the Ells River Oil Sands Project. Excluding volumes mined at AOSP, average net oil-equivalent production during 2009 was 28,000 barrels per day, composed of 27,000 barrels of crude oil and natural gas liquids and 4 million cubic feet of natural gas. Substantially all of this production was from the Hibernia Field, where the working interest owners are also pursuing development of the Hibernia Southern Extension (HSE). Development of the HSE nonunitized area was approved by the provincial regulator in 2009, and the first producing well for the project was completed at year-end.

In February 2010, binding agreements were signed with the Government of Newfoundland and Labrador on the development of the HSE unitized area, providing Chevron with a 23.6 percent nonoperated working interest in the unitized area.

For Hebron, agreements were reached during 2008 with the Government of Newfoundland and Labrador that allow development activities to begin. At the end of 2009, proved reserves had not been recognized for this project.

At AOSP, the company's production from oil sands (for upgrading into synthetic oil) averaged 26,000 barrels per day during 2009. The first phase of an expansion project is under way and is expected to increase total production from oil sands by 100,000 barrels per day. The expansion would increase total AOSP design capacity to more than 255,000 barrels per day in late 2010. The projected cost of this expansion is $14.3 billion.

The Ells River project consists of heavy-oil leases of more than 85,000 acres (344 sq km). The area contains significant volumes with potential for recovery by using Steam Assisted Gravity Drainage, an industry-proven technology that employs steam and horizontal drilling to extract the production from oil sands through wells rather than through mining operations. Additional field appraisal activity is not planned in the near-term. At the end of 2009, proved reserves had not been recognized.

The company also holds exploration leases in the Mackenzie Delta and Beaufort Sea region, including a 34 percent nonoperated working interest in the offshore Amauligak discovery. Three exploration wells were drilled on company leases in the Mackenzie Delta region in 2009, and assessment of development concept alternatives for Amauligak continues. The company holds additional exploration acreage in eastern Labrador and the Orphan Basin. In 2009, the company was also successful in acquiring a western Canada lease position to explore for shale gas. At the end of 2009, proved reserves had not been recognized for any of these areas.

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Greenland: Processing of the 2-D seismic survey acquired over License 2007/26 in Block 4 offshore West Greenland in 2008 continued in 2009, and evaluation will commence in the first-half 2010. Chevron has a 29.2 percent nonoperated working interest in this exploration license.


				Denmark: Chevron has a 15 percent working interest in the partner-operated Danish Underground Consortium (DUC), which produces crude oil and natural gas from 15 fields in the Danish North Sea. Net oil-equivalent production in 2009 from DUC averaged 55,000 barrels per day, composed of 35,000 barrels of crude oil and 119 million cubic feet of natural gas. DUC development activity in the region includes the ongoing Halfdan Phase IV project, which achieved first production in July 2009. Faroe Islands: Chevron withdrew from License 008 in 2009, but continues to assess exploration opportunities in the area. Netherlands: Chevron operates and holds interests ranging from 34.1 percent to 80 percent in eight blocks in the Dutch sector of the North Sea. In 2009, the company's net oil-equivalent production from the five producing blocks was 9,000 barrels per day, composed of 2,000 barrels of crude oil and 41 million cubic feet of natural gas. In 2009 Chevron divested its 48 percent interest in the L11/b license.

Norway: The company holds a 7.6 percent interest in the partner-operated Draugen Field. The company's net production averaged 5,000 barrels of oil-equivalent per day during 2009. In 2009, Chevron was awarded a 40 percent working interest as operator of the exploration license PL 527 in the deepwater portion of the Norwegian Sea. Data acquisition was completed on a 2-D seismic survey, and evaluation is under way.

Poland: In December 2009, Chevron was awarded three five-year exploration licenses in the Zwierzyniec, Kransnik and Frampol concessions, and in February 2010, Chevron acquired the exploration rights to the Grabowiec concession. Chevron has a 100 percent-owned and operated interest in these four concessions to explore for shale gas.

United Kingdom: The company's average net oil-equivalent production in 2009 from 10 offshore fields was 110,000 barrels per day, composed of 73,000 barrels of crude oil and natural gas liquids and 222 million cubic feet of natural gas. Most of the production was from the 85 percent-owned and operated Captain Field, the 23.4 percent-owned and operated Alba Field and the 32.4 percent-owned and jointly operated Britannia Field.

Evaluation of development alternatives continued during 2009 for the 19.4 percent-owned and partner-operated Clair Phase 2 project west of the Shetland Islands. In the 40 percent-owned and operated Rosebank/Lochnagar area northwest of the Shetland Islands, an exploration well in Rosebank North was completed in the second quarter 2009 and an appraisal well in Rosebank/Lochnagar was completed in the third quarter 2009. Also northwest of the Shetland Islands, a three-well exploration and appraisal drilling program was completed in 2009 at the Cambo prospect. Technical studies have commenced to select a preferred development alternative. Additional exploration drilling in the region is expected to occur in the second-half 2010. As of the end of 2009, proved reserves had not been recognized for any of these prospects.

In February 2010, the company sold its 10 percent nonoperated interest in the Laggan/Tormore discovery.

Sales of Natural Gas and Natural Gas Liquids

The company sells natural gas and natural gas liquids from its producing operations under a variety of contractual arrangements. In addition, the company also makes third-party purchases and sales of natural gas and natural gas liquids in connection with its trading activities.

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During 2009, U.S. and international sales of natural gas were 5.9 billion and 4.1 billion cubic feet per day, respectively, which includes the company's share of equity affiliates' sales. Outside the United States, substantially all of the natural-gas sales from the company's producing interests are from operations in Australia, Bangladesh, Kazakhstan, Indonesia, Latin America, the Philippines, Thailand and the United Kingdom.

U.S. and international sales of natural gas liquids were 161 thousand and 111 thousand barrels per day, respectively, in 2009. Substantially all of the international sales of natural gas liquids are from company operations in Africa, Australia and Indonesia.

Refer to "Selected Operating Data," on page FS-10 in Management's Discussion and Analysis of Financial Condition and Results of Operations, for further information on the company's sales volumes of natural gas and natural gas liquids. Refer also to "Delivery Commitments" on page 8 for information related to the company's delivery commitments for the sale of crude oil and natural gas.

Downstream - Refining, Marketing and Transportation

Refining Operations

Chevron Corp (CVX) SEC Annual Report (10-K) for 2009

Form 10-K

Chevron Corporation