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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, 2011

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 001-00368

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 No.)	(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.


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 - $205,986,778,815 (As of June 30, 2011)

Number of Shares of Common Stock outstanding as of February 13, 2012 - 1,976,966,530

DOCUMENTS INCORPORATED BY REFERENCE

(To The Extent Indicated Herein)

Notice of the 2012 Annual Meeting and 2012 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company's 2012 Annual Meeting of Stockholders (in Part III)

TABLE OF CONTENTS


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		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		7
		Development Activities		7
		Exploration Activities		8
		Review of Ongoing Exploration and Production Activities in Key Areas		8
		Sales of Natural Gas and Natural Gas Liquids		23
		Downstream		24
		Refining Operations		24
		Marketing Operations		25
		Chemicals Operations		26
		Transportation		26
		Other Businesses		27
		Mining		27
		Power Generation		28
		Chevron Energy Solutions		28
		Research and Technology		28
		Environmental Protection		28
		Web Site Access to SEC Reports		29
	1A.	Risk Factors		29
	1B.	Unresolved Staff Comments		31
	2.	Properties		32
	3.	Legal Proceedings		32
	4.	Mine Safety Disclosures		33

PART II
	5.	Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		33
	6.	Selected Financial Data		33
	7.	Management's Discussion and Analysis of Financial Condition and Results of Operations		33
	7A.	Quantitative and Qualitative Disclosures About Market Risk		33
	8.	Financial Statements and Supplementary Data		34
	9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		34
	9A.	Controls and Procedures		34
		(a) Evaluation of Disclosure Controls and Procedures		34
		(b) Management's Report on Internal Control Over Financial Reporting		34
		(c) Changes in Internal Control Over Financial Reporting		34
	9B.	Other Information		34

PART III
	10.	Directors, Executive Officers and Corporate Governance		35
	11.	Executive Compensation		36
	12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		36
	13.	Certain Relationships and Related Transactions, and Director Independence		36
	14.	Principal Accounting Fees and Services		36

PART IV
	15.	Exhibits, Financial Statement Schedules		37
		Schedule II - Valuation and Qualifying Accounts		38
		Signatures		39
EX-10.9
EX-10.13
EX-10.16
EX-12.1
EX-21.1
EX-23.1
EX-24.1
EX-24.2
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-31.1
EX-31.2
EX-32.1
EX-32.2
EX-95
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 29 through 31 in this report. In addition, such results could be affected by general domestic and international economic and political conditions. Other 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. Upstream operations consist primarily of exploring for, developing and producing crude oil and natural gas; processing, liquefaction, transportation and regasification associated with liquefied natural gas; transporting crude oil by major international oil export pipelines; transporting, storage and marketing of natural gas; and a gas-to-liquids project. Downstream operations consist primarily of refining crude oil into petroleum products; marketing of crude oil and refined products; transporting crude oil and refined products by pipeline, marine vessel, motor equipment and rail car; and manufacturing and marketing of commodity petrochemicals, plastics for industrial uses and fuel and lubricant additives.

A list of the company's major subsidiaries is presented on pages E-4 and E-5. As of December 31, 2011, Chevron had approximately 61,000 employees (including about 3,800 service station employees). Approximately 30,000 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. Prices for crude oil, natural gas, petroleum products and petrochemicals are generally determined by supply and demand. 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. Laws and governmental policies, particularly in the areas of taxation, energy and the environment affect where and how companies conduct their operations and formulate their products and, in some cases, limit their profits directly.

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, transportation and chemicals 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-8 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's Strategic Direction

Chevron's primary objective is to create shareholder 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 natural gas business. In the downstream, the strategies are to improve returns and grow earnings across the value chain. The company also continues to utilize technology across all its businesses to differentiate performance, and to invest in profitable renewable energy and energy efficiency solutions.


(b)	Description of Business and Properties

The upstream and downstream activities of the company and its equity affiliates are widely dispersed geographically, with operations in North America, South America, Europe, Africa, Asia and Australia. Tabulations of segment sales and other operating revenues, earnings and income taxes for the three years ending December 31, 2011, and assets as of the end of 2011 and 2010 - for the United States and the company's international geographic areas - are in Note 11 to the Consolidated Financial Statements beginning on page FS-37. 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-39 through FS-41.

Capital and Exploratory Expenditures

Total expenditures for 2011 were $29.1 billion, including $1.7 billion for the company's share of equity-affiliate expenditures. In 2010 and 2009, expenditures were $21.8 billion and $22.2 billion, respectively, including the company's share of affiliates' expenditures of $1.4 billion in 2010 and $1.6 billion in 2009.

Of the $29.1 billion in expenditures for 2011, 89 percent, or $25.9 billion, was related to upstream activities. Approximately 87 and 80 percent was expended for upstream operations in 2010 and 2009, respectively. International upstream accounted for about 68 percent of the worldwide upstream investment in 2011, about 82 percent in 2010 and about 80 percent in 2009. These amounts exclude the acquisition of Atlas Energy, Inc. in 2011. Refer to a discussion of the acquisition of Atlas Energy, Inc., in Note 2 to the Consolidated Financial Statements on page FS-30.

In 2012, the company estimates capital and exploratory expenditures will be $32.7 billion, including $3 billion of spending by affiliates. Approximately 87 percent of the total, or $28.5 billion, is budgeted for exploration and production activities, with $22.3 billion, or about 78 percent, of this amount for projects outside the United States.

Refer also to a discussion of the company's capital and exploratory expenditures on pages FS-11 through FS-12.

Upstream

The table on the following page summarizes the net production of liquids and natural gas for 2011 and 2010 by the company and its affiliates. Worldwide oil-equivalent production was 2.673 million barrels per day, down about three percent from 2010. The decrease was mainly associated with normal field declines, maintenance-related downtime and the impact of higher prices on entitlement volumes. The start-up and ramp-up of several major capital projects - the Perdido project in the U.S. Gulf of Mexico, the expansion at the Athabasca Oil Sands Project in Canada, the Frade Field in Brazil, and the Platong II natural gas project in Thailand - as well as acquisitions in the Marcellus Shale, partially offset the decrease in net production from 2010. Refer to the "Results of Operations" section beginning on page FS-6 for a detailed discussion of the factors explaining the 2009 - 2011 changes in production for crude oil and natural gas liquids, and natural gas.

The company estimates its average worldwide oil-equivalent production in 2012 will be approximately 2.680 million barrels per day based on the average Brent price of $111 per barrel in 2011. This estimate is subject to many factors and uncertainties, including quotas that may be imposed by OPEC, price effects on entitlement volumes, changes in fiscal terms or restrictions on the scope of company operations, delays in project startups, fluctuations in demand for natural gas in various markets, weather conditions that may shut in production, civil unrest, changing geopolitics, delays in completion of maintenance turnarounds, greater-than-expected declines in production from mature fields, or other disruptions to operations. The outlook for future production levels is also 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 8, for a discussion of the company's major crude oil and natural gas development projects.

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


					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)
	2011		2010		2011		2010		2011		2010
United States		678		708		465		489		1,279		1,314
Other Americas:
Canada		70		54		69		53		4		4
Colombia		39		41		-		-		234		249
Brazil		35		24		33		23		13		7
Trinidad and Tobago		31		38		-		1		183		223
Argentina		27		32		26		31		4		5

Total Other Americas		202		189		128		108		438		488

Africa:
Nigeria		260		253		236		239		142		86
Angola		147		161		139		152		50		52
Chad		26		28		25		27		6		6
Republic of the Congo		23		25		21		23		10		10
Democratic Republic of the Congo		3		2		3		2		1		1

Total Africa		459		469		424		443		209		155

Asia:
Thailand		209		216		65		70		867		875
Indonesia		208		226		166		187		253		236
Partitioned Zone 2		91		98		88		94		20		23
Bangladesh		74		69		2		2		434		404
Kazakhstan		62		64		38		39		144		149
Azerbaijan		28		30		26		28		10		11
Philippines		25		25		4		4		126		124
China		22		20		20		18		10		13
Myanmar		14		13		-		-		86		81

Total Asia		733		761		409		442		1,950		1,916

Australia		101		111		26		34		448		458
Europe:
United Kingdom		85		97		59		64		155		194
Denmark		44		51		29		32		91		116
Netherlands		7		8		2		2		31		35
Norway		3		3		3		3		1		1

Total Europe		139		159		93		101		278		346

Total Consolidated Operations		2,312		2,397		1,545		1,617		4,602		4,677
Equity Affiliates 3		361		366		304		306		339		363

Total Including Affiliates 4		2,673		2,763		1,849		1,923		4,941		5,040



1 Includes synthetic oil: Canada, net		40		24		40		24		-		-
Venezuelan affiliate, net 32				28		32		28		-		-
2 Located between Saudi Arabia and Kuwait.
3 Volumes represent Chevron's share of production by affiliates, including Tengizchevroil in Kazakhstan and Petroboscan, Petroindependiente and Petropiar in Venezuela.
4 Volumes include natural gas consumed in operations of 582 million and 537 million cubic feet per day in 2011 and 2010, respectively. Total "as sold" natural gas volumes were 4,359 million and 4,503 million cubic feet per day for 2011 and 2010, respectively.

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Average Sales Prices and Production Costs per Unit of Production

Refer to Table IV on page FS-67 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 2011, 2010 and 2009.

Gross and Net Productive Wells

The following table summarizes gross and net productive wells at year-end 2011 for the company and its affiliates:

Productive Oil and Gas Wells at December 31, 2011


	Productive				Productive
	Oil Wells				Gas Wells
	Gross		Net		Gross		Net

United States		49,511		32,368		14,061		7,671
Other Americas		709		533		40		17
Africa		2,548		850		17		7
Asia		12,612		10,861		3,437		2,125
Australia		807		453		64		11
Europe		332		105		222		48

Total Consolidated Companies		66,519		45,170		17,841		9,879
Equity in Affiliates		1,231		434		7		2

Total Including Affiliates		67,750		45,604		17,848		9,881


Multiple completion wells included above:		887		573		378		280

Reserves

Refer to Table V beginning on page FS-67 for a tabulation of the company's proved net crude oil and natural gas reserves by geographic area, at the beginning of 2009 and each year-end from 2009 through 2011. Reserves governance, technologies used in establishing proved reserves additions, and major changes to proved reserves by geographic area for the three-year period ended December 31, 2011, are summarized in the discussion for Table V. Discussion is also provided regarding the nature of, status of and planned future activities associated with the development of proved undeveloped reserves. The company recognizes reserves for projects with various development periods, sometimes exceeding five years. The external factors that impact the duration of a project include scope and complexity, remoteness or adverse operating conditions, infrastructure constraints, and contractual limitations.

The net proved reserve balances at the end of each of the three years 2009 through 2011 are shown in the following table.

Net Proved Reserves at December 31


	2011		2010		2009

Liquids - Millions of barrels
Consolidated Companies		4,295		4,270		4,610
Affiliated Companies		2,160		2,233		2,363
Natural Gas - Billions of cubic feet
Consolidated Companies		25,229		20,755		22,153
Affiliated Companies		3,454		3,496		3,896
Total Oil-Equivalent - Millions of barrels
Consolidated Companies		8,500		7,729		8,303
Affiliated Companies		2,736		2,816		3,012

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Acreage

At December 31, 2011, the company owned or had under lease or similar agreements undeveloped and developed crude oil and natural gas properties throughout the world. The geographical distribution of the company's acreage is shown in the following table.

Acreage at December 31, 2011
(Thousands of Acres)


									Developed and
	Undeveloped*				Developed				Undeveloped
	Gross		Net		Gross		Net		Gross		Net

United States		6,290		5,171		7,752		5,051		14,042		10,222
Other Americas		26,803		15,338		1,392		395		28,195		15,733
Africa		8,068		3,921		3,324		1,370		11,392		5,291
Asia		41,125		21,613		5,426		2,760		46,551		24,373
Australia		12,801		6,064		920		240		13,721		6,304
Europe		5,093		3,608		645		137		5,738		3,745

Total Consolidated Companies		100,180		55,715		19,459		9,953		119,639		65,668

Equity in Affiliates		419		191		252		100		671		291

Total Including Affiliates		110,599		55,906		19,711		10,053		120,310		65,959


*		The gross undeveloped acres that will expire in 2012, 2013 and 2014 if production is not established by certain required dates are 4,675, 5,993 and 2,903, respectively.

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 is contractually committed to deliver to third parties 232 billion cubic feet of natural gas through 2014. The company believes it can satisfy these contracts through a combination of equity production from the company's proved developed U.S. reserves and third-party purchases. These contracts include a variety of pricing terms, including both indexed and fixed-price contracts.

Outside the United States, the company is contractually committed to deliver a total of 891 billion cubic feet of natural gas from 2012 through 2014 from operations in Australia, Colombia, Denmark and the Philippines to third parties. 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 these countries.

Development Activities

Refer to Table I on page FS-62 for details associated with the company's development expenditures and costs of proved property acquisitions for 2011, 2010 and 2009.

The table on the next page 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, 2011. 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.

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Development Well Activity


	Wells Drilling				Net Wells Completed
	at 12/31/11				2011				2010				2009
	Gross		Net		Prod.		Dry		Prod.		Dry		Prod.		Dry

United States		105		62		909		9		634		7		582		3
Other Americas		8		4		37		-		32		-		36		-
Africa		7		3		29		-		33		-		40		-
Asia		85		37		549		15		445		15		580		10
Australia		1		-		-		-		-		-		-		-
Europe		5		-		6		-		4		-		7		-

Total Consolidated Companies		211		106		1,530		24		1,148		22		1,245		13
Equity in Affiliates		1		1		25		-		8		-		6		-

Total Including Affiliates		212		107		1,555		24		1,156		22		1,251		13

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, 2011. "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
	at 12/31/11				2011				2010				2009
	Gross		Net		Prod.		Dry		Prod.		Dry		Prod.		Dry

United States		2		2		5		1		1		1		4		5
Other Americas		2		1		1		-		-		1		1		2
Africa		3		1		1		-		1		-		2		1
Asia		1		1		10		1		5		5		9		1
Australia		1		1		4		1		5		2		4		2
Europe		2		1		-		1		-		-		-		-

Total Consolidated Companies		11		7		21		4		12		9		20		11
Equity in Affiliates		-		-		1		-		-		-		-		-

Total Including Affiliates		11		7		22		4		12		9		20		11

Refer to Table I on page FS-62 for detail of the company's exploration expenditures and costs of unproved property acquisitions for 2011, 2010 and 2009.

Review of Ongoing Exploration and Production Activities in Key Areas

Chevron's 2011 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-11.

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The discussion that follows references the status of proved reserves recognition for significant long-lead-time projects not on production and for projects recently placed on production. Reserves are not discussed for exploration activities or recent discoveries that have not advanced 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.


				Chevron has exploration and production 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 exploration and production.


a)	United States

Upstream activities in the United States are concentrated in California, the Gulf of Mexico, the Appalachian Basin, Colorado, Michigan, New Mexico, Ohio, Oklahoma, Texas, Wyoming and Alaska. Average net oil-equivalent production in the United States during 2011 was 678,000 barrels per day.

In California, the company has significant production in the San Joaquin Valley. In 2011, average net oil-equivalent production was 183,000 barrels per day, composed of 165,000 barrels of crude oil, 83 million cubic feet of natural gas and 4,000 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 2011 for the company's combined interests in the Gulf of Mexico shelf and deepwater areas, and the onshore fields in the region was 244,000 barrels per day. The daily oil-equivalent production was composed of 161,000 barrels of crude oil, 401 million cubic feet of natural gas and 16,000 barrels of natural gas liquids. Chevron was engaged in various exploration and development activities in the deepwater Gulf of Mexico during 2011. The Jack and St. Malo fields are located within 25 miles of each other and are being jointly developed. Chevron has a 50 percent working interest in Jack and a 51 percent working interest in St. Malo. Both fields are company operated. All major installation contracts have been awarded and construction began for

the floating production unit hull and topsides modules during 2011. Development drilling operations commenced in fourth quarter 2011. The facility is planned to have a design capacity of 177,000 barrels of oil-equivalent per day to accommodate production from the Jack/St. Malo development, which is estimated to have maximum total daily production of 94,000 barrels of oil equivalent, plus production from a nearby third-party field. Total project costs for the initial phase of development are estimated at $7.5 billion and start-up is expected in 2014. The project has an estimated production life of 30 years. The initial recognition of proved reserves for the project occurred in 2011.

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Work continued at the 60 percent-owned and operated Big Foot discovery. The development plan includes a 15-slot drilling and production tension leg platform with water injection facilities and a design capacity of 79,000 barrels of oil equivalent per day. Fabrication of topsides, hull and other components began in first-half 2011 and initial development drilling commenced in fourth quarter 2011. First production is anticipated in 2014. The field has an estimated production life of 20 years. Initial proved reserves were recognized in 2011.

Tahiti 2 is the second development phase for the 58 percent-owned and operated Tahiti Field and is designed to increase recovery and return well capacity to 125,000 barrels of oil per day. The project includes three water injection wells, two additional production wells and the water injection facilities required to deliver water to the injection wells. Two water injection wells have been completed and drilling commenced on the first production well in early 2012. The water injection facilities have been installed and water injection began in first quarter 2012. Start-up of the first production well of the second phase is expected by 2013. Initial proved reserves for the Tahiti 2 project were recognized in 2011, and the field has an estimated production life of 30 years.

The final investment decision was made for the Tubular Bells deepwater project in fourth quarter 2011. The company has a 42.9 percent nonoperated working interest in the Tubular Bells unitized area after receiving an additional 12.9 percent equity interest relinquished by a partner in 2011. Development drilling is scheduled to begin in second quarter 2012, and plans include three producing and two injection wells, with a subsea tieback to a third-party production facility. First oil is anticipated in 2014, and maximum total daily production is expected to reach 40,000 to 45,000 barrels of oil-equivalent. At the end of 2011, proved reserves had not been recognized for this project.

The company has a 20.3 percent nonoperated working interest in the Caesar and Tonga unitized area. Development plans include a total of four wells and a subsea tieback to a nearby third-party production facility. Three of the four development wells have been drilled and completed as of year-end 2011. Drilling of the fourth well is expected to begin in mid-2012. Work on the subsea system, commissioning of the topsides and the initial well completion program continued into 2012. Installation of the production riser and first production are expected in mid-2012. Maximum total production is expected to be 46,000 barrels of oil-equivalent per day. Proved reserves have been recognized for the project.

The company has a 15.6 percent nonoperated working interest in the Mad Dog II Project. Front-end engineering and design (FEED) is expected to commence by second quarter 2012. It is anticipated that this future development would require new production facilities to support planned maximum total daily production of 120,000 to 140,000 barrels of oil equivalent. At the end of 2011, proved reserves had not been recognized for this project.

Development planning and unitization talks with owners of an adjacent field continued in 2011 for the Knotty Head project. Chevron has a 25 percent nonoperated working interest in this subsalt, Green Canyon Block 512 discovery. At the end of 2011, proved reserves had not been recognized for this project.

Deepwater exploration activities in 2011 included participation in four exploratory wells - two wildcats, one appraisal and one delineation. Following successful permitting under new, more stringent, U.S. Department of Interior guidelines, two wells resumed drilling activities after operations were halted in 2010 as a result of the deepwater drilling moratorium in the Gulf of Mexico. Drilling operations at the 43.8 percent-owned and operated Moccasin prospect resumed in first quarter 2011 and resulted in a new discovery in the Lower Tertiary Wilcox Trend. Drilling operations resumed in second quarter 2011 at the 55 percent-owned and operated Buckskin prospect, resulting in a successful appraisal well. These two discoveries, located 12 miles apart, could facilitate future co-development upon the successful completion of additional appraisal drilling planned at each prospect in 2012. Drilling was terminated at the Coronado wildcat well due to drilling conditions in the shallow section of the wellbore. The company plans to drill a replacement well at an alternate location by mid-2012.

Besides the activities connected with the development and exploration projects in the Gulf of Mexico, the company also has contracted capacity at the third-party Sabine Pass liquefied natural gas (LNG) regasification terminal in Louisiana and in a third-party pipeline system connecting the Sabine Pass LNG terminal to the natural gas pipeline grid. The pipeline provides access to two major salt dome storage fields and 10 major interstate pipeline systems, including access to Chevron's Sabine Pipeline, which connects to the Henry Hub. 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.

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				Company activities outside California and the Gulf of Mexico include operated and nonoperated interests in properties across the mid-continental United States, the Appalachian Basin, Michigan, Ohio and Alaska. During 2011, the company's U.S. production outside California and the Gulf of Mexico averaged 251,000 net oil-equivalent barrels per day, composed of 91,000 barrels of crude oil, 795 million cubic feet of natural gas and 28,000 barrels of natural gas liquids. In West Texas, the company continues to pursue development of tight carbonates, tight sands, and liquids-rich shale resources in the Midland Basin's Wolfcamp play and several plays in the Delaware Basin through use of advanced drilling and completion technologies. Additional production growth is expected from interests in these formations in

future years.

In February 2011, Chevron acquired Atlas Energy, Inc. The acquisition provided a natural gas resource position in the Marcellus Shale and Utica Shale, primarily located in southwestern Pennsylvania and Ohio. The acquisition also provided a 49 percent interest in Laurel Mountain Midstream, LLC, an affiliate that owns more than 1,000 miles of natural gas gathering lines servicing the Marcellus. In addition, the acquisition provided assets in Michigan, which include Antrim Shale producing assets and approximately 350,000 total acres in the Antrim and Collingwood/Utica Shale formations. Additional asset acquisitions in 2011 expanded the company's holdings in the Marcellus and Utica to approximately 700,000 and 600,000 total acres, respectively. In the Marcellus, 61 natural gas wells were completed in 2011.


b)	Other Americas

"Other Americas" is composed of Argentina, Brazil, Canada, Colombia, Greenland, Trinidad and Tobago, and Venezuela. Net oil-equivalent production from these countries averaged 267,000 barrels per day during 2011, including the company's share of synthetic oil production.


				Canada: Company activities in Canada include nonoperated working interests of 26.9 percent in the Hibernia Field, 26.6 percent in the Hebron Field and 23.6 percent in the unitized Hibernia South Extension, all offshore eastern Canada. In Alberta, the company holds a 20 percent nonoperated working interest in the Athabasca Oil Sands Project (AOSP). Average net oil-equivalent production during 2011 was 70,000 barrels per day, composed of 69,000 barrels of crude oil, synthetic oil and natural gas liquids and 4 million cubic feet of natural gas. Development of the Hibernia Southern Extension is expected to stem the production decline from the Hibernia Field. The project includes drilling of producing wells from the existing Hibernia platform and subsea drilling of water injection wells. All project approvals were in place by early 2011 and two producing wells were successfully drilled

from the platform to obtain early reservoir information. Further drilling is anticipated to commence in 2013 with full production start-up expected in 2014. The initial recognition of proved reserves occurred in 2011 for this project.

FEED activities continued in 2011 for the development of the heavy-oil Hebron Field and a final investment decision is expected in 2013. The project has an expected economic life of 30 years. At the end of 2011, proved reserves had not been recognized for this project.

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At AOSP, oil sands are mined from both the Muskeg River and Jackpine mines and bitumen is extracted from the oil sands and upgraded into synthetic oil. The AOSP Expansion 1 Project activities continued in 2011 with completion of the Scotford Upgrader expansion, which increased daily production design capacity to approximately 255,000 barrels per day.

During 2011, the company increased its shale exploration acreage in Alberta in the Duvernay formation. In third quarter 2011, a multiwell drilling program commenced on these 100 percent-owned and operated leases. A long-term well test is expected to begin in fourth quarter 2012, when the first well is expected to be tied into third-party processing facilities. The company also holds exploration licenses and leases in the Flemish Pass and Orphan basins offshore Atlantic Canada, the Mackenzie Delta region of the Northwest Territories and the Beaufort Sea region of Canada's Arctic, including a 35.4 percent nonoperated working interest in the offshore Amauligak discovery.

In addition, Chevron holds interests in the Aitken Creek and Alberta Hub natural gas storage facilities with an approximate total capacity of 100 billion cubic feet. These facilities are located adjacent to the Duvernay, Horn River and Montney shale gas plays.

Greenland: In 2011, the Greenland government granted a one-year extension to the initial four-year term for License 2007/26, which includes Block 4 offshore West Greenland. Interpretation of seismic data continued into early 2012. Chevron has a 29.2 percent nonoperated working interest in this exploration license.


				Argentina: Chevron holds operated interests in four concessions in the Neuquen Basin. Working interests range from 18.8 percent to 100 percent. Net oil-equivalent production in 2011 averaged 27,000 barrels per day, composed of 26,000 barrels of crude oil and natural gas liquids and 4 million cubic feet of natural gas. During 2011, the company reached an agreement to extend the El Trapial concession for an additional 10 years until 2032. The company expects to drill two exploratory wells in 2012 in the Vaca Muerta formation, targeting shale gas and tight oil resources. Brazil: Chevron holds working interests in three deepwater fields in the Campos Basin. Net oil-equivalent production in 2011 averaged 35,000 barrels per day, composed of 33,000 barrels of crude oil and 13 million cubic feet of

natural gas.

During 2011, development drilling continued at the 51.7 percent-owned and operated Frade Field, located in the Campos Basin. Eleven development wells and four injection wells had been completed as of year-end 2011. Development drilling is planned to continue through 2013, with one additional development well, one sidetrack well and several injection wells. 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 development following the end of the exploration phase of this block. During 2011, construction progressed on a floating production, storage and offloading (FPSO) vessel and tension leg well platform for the Papa-Terra project. Development drilling was initiated in fourth quarter 2011. The facility has a planned total daily capacity of 140,000 barrels of crude oil. First production is expected in 2013, and the initial recognition of proved reserves occurred during 2011. Evaluation of the field development concept for Maromba continued into early 2012. At the end of 2011, proved reserves had not been recognized for this project . These concessions expire in 2032.

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 based on prior Chuchupa capital contributions. During 2011, a gas export agreement with Venezuela was extended. An onshore, multiwell drilling program commenced in late 2011. Daily net production averaged 234 million cubic feet of natural gas in 2011.

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. Net production in 2011 averaged 183 million cubic feet of natural gas per day. Chevron also holds a

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50 percent operated interest in the Manatee Area of Block 6(d), which includes a 2005 discovery. During 2011, work progressed to mature a development concept called the Regional Cooperative Agreement.


				Venezuela: Chevron holds interests in two producing affiliates located in western Venezuela and one producing 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 net oil-equivalent production during 2011 from these operations, including synthetic oil from Hamaca, averaged

65,000 barrels per day, composed of 60,000 barrels of crude oil, synthetic oil and natural gas liquids and 27 million cubic feet of natural gas.

Chevron holds a 34 percent interest in the Petroindependencia affiliate that is working on a heavy-oil project in three blocks within the Carabobo Area of eastern Venezuela's Orinoco Belt. During 2011, work continued toward commercialization of the Carabobo 3 Project. Conceptual engineering for the potential development of the concession is in progress.

The company operates and has a working interest of 60 percent in Block 2 in the Plataforma Deltana area offshore eastern Venezuela. During 2011, work progressed to mature a development concept called the Regional Cooperative Agreement.


c)	Africa

In Africa, the company is engaged in exploration and production activities in Angola, Chad, Democratic Republic of the Congo, Liberia, Nigeria and Republic of the Congo. Net oil-equivalent production in Africa averaged 459,000 barrels per day during 2011.


				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 area. Net production from these operations in 2011 averaged 147,000 barrels of oil-equivalent per day. The company operates the 39.2 percent-owned Block 0, which averaged 108,000 barrels per day of net liquids production in 2011. The Block 0 concession extends through 2030. Work on the second development stage of the Mafumeira Field in Block 0 continued in 2011. Mafumeira Sul, a project to develop the southern portion of the field, is expected to reach a final investment decision in second quarter 2012. Maximum total production from Mafumeira Sul is expected to be 110,000 barrels of crude oil and 10,000 barrels of LPG per day. At year-end 2011, proved reserves had not been recognized for the Mafumeira Sul project. In the Greater Vanza/Longui Area of Block 0, development concept studies continued during 2011 and the project is expected to enter FEED in second-half 2012. FEED activities continued on the south extension

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of the N'Dola Field development with a final investment decision expected in late 2012. At year-end 2011, no proved reserves were recognized for these projects.

In Block 0, the Area A gas management projects at the Takula and Malongo reservoirs were designed to eliminate routine flaring of natural gas. The final project entered service in 2011, which together have reduced flaring by approximately 70 million cubic feet per day, as of year-end 2011. In Area B, the first stage of the Nemba Enhanced Secondary Recovery and Flare Reduction Project was completed in second quarter 2011. The final stage is expected to eliminate routine flaring at the North and South Nemba platforms and is scheduled to begin gas injection in 2014.

Also in Block 0, a two-well appraisal and exploration program was completed in 2011. The appraisal well completed in July 2011 in the Lifua Field was successful and development opportunities are being evaluated. The second well, completed in October 2011 in the pre-salt play, was not successful. Two additional exploratory wells are planned for second-half 2012.

In the 31 percent-owned Block 14, net production in 2011 averaged 29,000 barrels of liquids per day. Development and production rights for the various producing fields in Block 14 expire between 2023 and 2028.

For the Lucapa Field in Block 14, development alternatives continued to be evaluated during 2011. The project is expected to enter FEED in second quarter 2012. Development alternatives were evaluated during the year at the Malange Field and the preferred alternative is expected to enter FEED in mid-2012. As of the end of 2011, development of the Negage Field remained suspended until cooperative arrangements between Angola and Democratic Republic of the Congo are finalized. At the end of 2011, proved reserves had not been recognized for these projects.

In addition to the exploration and production activities in Angola, Chevron has a 36.4 percent ownership interest in the Angola LNG affiliate that began construction in 2008 of an onshore natural gas liquefaction plant at Soyo, Angola. The plant is designed to process 1.1 billion cubic feet of natural gas per day, with expected average total daily sales of 670 million cubic feet of regasified LNG and up to 63,000 barrels of natural gas liquids. Construction continued during 2011, reaching mechanical completion at year-end. The first LNG shipment from the plant is expected in second quarter 2012. The estimated total cost of the LNG plant is $10 billion, with an estimated life in excess of 20 years. The company also holds a 38.1 percent interest in a pipeline project that is expected to transport up to 250 million cubic feet of natural gas per day from Block 0 and Block 14 to the Angola LNG plant. The pipeline project entered construction in May 2011 and is expected to be completed in late 2013. Proved reserves have been recognized for the producing operations associated with the Angola LNG 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. A final investment decision for the Lianzi development project is expected in mid-2012. The project is expected to commence production in late 2014. At the end of 2011, proved reserves had not been recognized for the project.

Democratic Republic of the Congo: Chevron has a 17.7 percent nonoperated working interest in an offshore concession. Daily net production in 2011 averaged 3,000 barrels of oil-equivalent.

Republic of the Congo: Chevron has a 31.5 percent nonoperated working interest in the Nkossa, Nsoko and Moho-Bilondo permit areas and a 29.3 percent nonoperated working interest in the Kitina permit area, all of which are offshore. The development and production rights for Kitina, Nsoko, Nkossa and Moho-Bilondo expire in 2014, 2018, 2027 and 2030, respectively. Net production averaged 23,000 barrels of oil-equivalent per day in 2011.

The Moho Nord Project, located in the Moho-Bilondo Development Area, entered FEED in fourth quarter 2011. The project is expected to reach a final investment decision in 2013. At the end of 2011, proved reserves had not been recognized for this project.

Chad/Cameroon: Chevron has a 25 percent nonoperated working interest in crude oil producing operations in southern Chad and an approximate 21 percent interest in two affiliates that own an export pipeline that transports the crude oil to the coast of Cameroon. Average daily net production from the Chad fields in 2011 was 26,000 barrels of oil-equivalent. The Chad producing operations are conducted under a concession that expires in 2030.

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				Nigeria: Chevron holds a 40 percent interest in 13 concessions predominantly 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 four operated and six nonoperated deepwater blocks. In 2011, the company's net oil-equivalent production in Nigeria averaged 260,000 barrels per day, composed of 236,000 barrels of liquids and 142 million cubic feet of natural gas. Chevron operates and holds a 67.3 percent interest in the Agbami Field, located in deepwater Oil Mining Lease (OML) 127 and OML 128. During 2011, drilling continued on a 10-well, Phase 2 development program that is designed to offset field decline and maintain plateau production. The first well is expected to be

completed and placed on production in second-half 2012. The leases that contain the Agbami Field expire in 2023 and 2024.

The company holds a 30 percent nonoperated working interest in the deepwater Usan project in OML 138. During 2011, development drilling continued and the FPSO vessel was moored on location. Production start-up is expected in early 2012, with maximum total production of 180,000 barrels of crude oil per day expected within one year of start-up. The production-sharing contract (PSC) expires in 2023. Proved reserves have been recognized for this project.

Also in the deepwater area, the Aparo Field in OML 132 and OML 140 and the third-party-owned Bonga SW Field in OML 118 share a common geologic structure and are planned to be jointly developed. Initiation of FEED is expected in late 2012. At the end of 2011, no proved reserves were recognized for this project.

In the Niger Delta, ramp-up activity continued at the Escravos Gas Plant (EGP). During 2011, construction continued on Phase 3B of the EGP project, which is designed to gather 120 million cubic feet of natural gas per day from eight offshore fields and to compress and transport the natural gas to onshore facilities. The Phase 3B project is expected to be completed in 2016. Proved reserves associated with this project have been recognized.

The 40 percent-owned and operated Sonam Field Development includes facilities to produce natural gas from the Sonam natural gas field in the Escravos area. The project is designed to utilize EGP and to deliver 215 million cubic feet of natural gas per day to the domestic market, and produce an average of 30,000 barrels of liquids per day. A final investment decision was reached in late 2011, and first production is expected in 2016. Proved reserves associated with the project were recognized in 2011.

Chevron has a 75 percent-owned and operated interest in a gas-to-liquids facility at Escravos that is being developed with the Nigerian National Petroleum Corporation. The 33,000-barrel-per-day facility is designed to process 325 million cubic feet per day of natural gas supplied from the Phase 3A expansion of EGP. At the end of 2011, work on the project was more than 80 percent complete and start-up is planned for 2013. The estimated cost of the plant is $8.4 billion.

The company has a 40 percent-owned and operated interest in the Onshore Asset Gas Management project that 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. Construction activities continued through 2011, and start-up is scheduled for late 2012.

In deepwater exploration, the company has 20 percent and 27 percent nonoperated working interests in Oil Prospecting License (OPL) 214 and OPL 223, respectively. Drilling of two exploration wells commenced in fourth quarter 2011 in OPL 214, and one exploration well is planned in OPL 223 for second-half 2012. In addition, Chevron operates and holds a 95 percent interest in the deepwater Nsiko discovery in OML 140 where further exploration activities are planned.

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Shallow-water exploration activities in 2011 included reprocessing 3-D seismic data from OML 86 and OML 88. In November 2011, the company began drilling a well in OML 86. In January 2012, while drilling the well, there was a release of natural gas that led to a fire. Drilling of a relief well commenced in February 2012. A root cause investigation is under way.

Chevron is the largest shareholder, with a 37 percent interest, in the West African Gas Pipeline Company Limited affiliate, which constructed, owns and operates the 421-mile West African Gas Pipeline. The pipeline supplies Nigerian natural gas to customers in Benin, Ghana and Togo for industrial applications and power generation and has the capacity to transport 170 million cubic feet per day.

Liberia: In 2010, Chevron acquired a 70 percent interest and operatorship in three deepwater blocks off the coast of Liberia. Exploration drilling prospects were identified during 2011 based on 3-D seismic data. Two exploration wells are planned to be drilled in 2012.


d)	Asia

In Asia, the company is engaged in upstream activities in Azerbaijan, Bangladesh, Cambodia, China, Indonesia, Kazakhstan, Myanmar, the Partitioned Zone located between Saudi Arabia and Kuwait, the Philippines, Russia, Thailand, Turkey, and Vietnam. During 2011, net oil-equivalent production averaged 1,029,000 barrels per day.


				Azerbaijan: Chevron holds an 11.3 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. The company's daily net production from AIOC averaged 28,000 barrels of oil-equivalent in 2011. AIOC operations are conducted under a PSC that expires in 2024. During 2011, construction progressed on the next development phase of the ACG project, which will further develop the deepwater Gunashli Field. Production is expected to begin in 2013. Proved reserves have been recognized for this project. The total estimated cost of the project is $6 billion, with maximum total daily production of 140,000 barrels of oil-equivalent. Chevron also has an 8.9 percent interest in the Baku-Tbilisi-Ceyhan (BTC) affiliate, which owns and operates a crude oil export pipeline from Baku, Azerbaijan, through Georgia to Mediterranean deepwater port facilities at Ceyhan, Turkey. The BTC Pipeline has a capacity of 1.2 million barrels per day and transports the majority of ACG production. Another production export route for crude oil is the Western Route Export Pipeline,

wholly owned by AIOC, with capacity to transport 100,000 barrels per day from Baku, Azerbaijan, to a marine terminal at Supsa, Georgia.

Kazakhstan: Chevron participates in two major upstream developments in western Kazakhstan. The company holds a 50 percent interest in the Tengizchevroil (TCO) affiliate, which is operating and developing the Tengiz and Korolev crude oil fields under a concession that expires in 2033. Chevron's net oil-equivalent production in 2011 from these fields averaged 296,000 barrels per day, composed of 244,000 barrels of crude oil and natural gas liquids and 312 million cubic feet of natural gas. During 2011, 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 exported via rail to Black Sea ports.

Also during 2011, TCO continued to evaluate alternatives for another expansion project to increase total daily crude oil production between 250,000 and 300,000 barrels. The expansion project will rely on sour gas injection technology utilized in current operations. Approval of FEED is anticipated in 2012. As of year-end 2011, proved reserves had not been recognized for this expansion project.

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Chevron holds a 20 percent nonoperated working interest in the Karachaganak project, which is conducted under a PSC that expires in 2038. During 2011, Karachaganak net oil-equivalent production averaged 62,000 barrels per day, composed of 38,000 barrels of liquids and 144 million cubic feet of natural gas. In 2011, access to the CPC and Atyrau-Samara (Russia) pipelines enabled approximately 204,000 barrels per day (34,000 net barrels) of Karachaganak liquids to be sold at world-market prices. The remaining liquids were sold into local and Russian markets. During 2011, a fourth train entered production and increased total liquids-stabilization capacity by 56,000 barrels per day, allowing increased sales of condensate into world markets. Karachaganak project partners have reached an agreement allowing the government of Kazakhstan to become a 10 percent equity owner in the Karachaganak project. The transfer of equity to the government is anticipated to occur in June 2012 and will result in Chevron's working interest being reduced to 18 percent.

During 2011, Chevron and its partners continued to evaluate alternatives for a Phase III development of Karachaganak. The timing of the project remains uncertain until a project design is finalized. At the end of 2011, proved reserves had not been recognized for the project.

Kazakhstan/Russia: Chevron has a 15 percent interest in the CPC affiliate. During 2011, CPC transported an average of approximately 684,000 barrels of crude oil per day, including 608,000 barrels per day from Kazakhstan and 76,000 barrels per day from Russia. During 2011, the partners began construction on a project to increase pipeline capacity by 670,000 barrels per day. The total estimated cost of the project is $5.4 billion. The project is expected to be implemented in three phases, with capacity increasing progressively until reaching maximum capacity of 1.4 million barrels per day in 2016.

Turkey: In 2010, Chevron signed a Joint Operating Agreement for a 50 percent working interest in a 5.6 million acre exploration block located in the Black Sea. The initial exploration well completed in 2010 was unsuccessful. Future plans are under evaluation.

Bangladesh: Chevron holds a 98 percent interest in two operated PSCs covering Blocks 12, 13 and 14. Net oil-equivalent production from these operations in 2011 averaged 74,000 barrels per day, composed of 434 million cubic feet of natural gas and 2,000 barrels of liquids. In 2011, the Muchai compression project achieved mechanical completion and is expected to support additional production starting in second quarter 2012 from the Bibiyana, Jalalabad and Moulavi Bazar natural gas fields. Proved reserves have been recognized for this project. The Bibiyana Expansion Project entered FEED in July 2011. Project scope includes expansion of the gas plant, additional development drilling and an enhanced liquids recovery unit, with an estimated total maximum daily production of 57,000 barrels of oil equivalent. A final investment decision is expected in mid-2012. At the end of 2011, proved reserves had not been recognized for this project. Also in 2011, the company relinquished its interest in Block 7 subsequent to the completion of an unsuccessful exploratory well.


				Cambodia: Chevron owns a 30 percent interest and operates the 1.2 million-acre Block A, located in the Gulf of Thailand. In 2011, the company progressed discussions on the production permit. Government approval and a final investment decision are expected by the end of 2012. At the end of 2011, proved reserves had not been recognized for the project. 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, within Blocks M5 and M6, in the Andaman Sea. The PSC expires in 2028. The company also has a 28.3 percent nonoperated interest in a pipeline company that transports the natural gas to the Myanmar-Thailand border for delivery to power plants in Thailand. The company's average net natural gas production in 2011 was 86 million cubic feet per day.

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Thailand: Chevron has operated and nonoperated working interests in multiple offshore blocks. The company's net oil-equivalent production in 2011 averaged 209,000 barrels per day, composed of 65,000 barrels of crude oil and condensate and 867 million cubic feet of natural gas. All of the company's natural gas production is sold to PTT Public Company Limited, Thailand's national oil company, under long-term sales contracts.

Operated interests are in the Pattani Basin with ownership interests ranging from 35 percent to 80 percent. Concessions for producing areas within this basin expire between 2020 and 2035. Chevron has a 16 percent nonoperated working interest in the Arthit and North Arthit fields located in the Malay Basin. Concessions for the producing areas within this basin expire between 2036 and 2040.

Start-up of the 69.9 percent-owned and operated Platong II natural gas project occurred in October 2011, and total average daily production ramped up to 377 million cubic feet of natural gas and 11,000 barrels of condensate as of the end of 2011. Proved reserves have been recognized for this project.

During 2011, the company drilled nine exploration wells in the Pattani Basin. All of the wells were successful and development alternatives are being evaluated. The company also holds exploration interests in a number of blocks that are inactive, pending resolution of border issues between Thailand and Cambodia.

Vietnam: Chevron is the operator of two PSCs in the Malay Basin off the southwest coast of Vietnam. The company has a 42.4 percent interest in a PSC that includes Blocks B and 48/95, and a 43.4 percent interest in a PSC for Block 52/97.

In the blocks off the southwest coast, the Block B Gas Development is designed to produce natural gas from the Malay Basin for delivery to state-owned Petrovietnam. The project includes installation of wellhead and hub platforms, a floating storage and offloading vessel, a central processing platform and a pipeline to shore. FEED continued during 2011. Maximum total daily production is expected to be 490 million cubic feet of natural gas and 4,000 barrels of condensate. A final investment decision is expected to be reached in 2012. At the end of 2011, proved reserves had not been recognized for the development project.

During the year, work continued on preparations for a 2012 exploration drilling program to further evaluate the potential of the three company-operated blocks in the Malay Basin. The company also completed the evaluation of Block 122 offshore eastern Vietnam and reached a decision to exit the block.


				China: Chevron has operated and nonoperated working interests in several areas in China. The company's net oil-equivalent production in 2011 averaged 22,000 barrels per day, composed of 20,000 barrels of crude oil and condensate and 10 million cubic feet of natural gas. The company operates and holds a 49 percent interest in the Chuandongbei PSC, located in the onshore Sichuan Basin. The project includes two sour-gas processing plants with an aggregate design capacity of 740 million cubic feet per day connected by a natural gas gathering system to five fields. During 2011, the company continued construction on the first natural gas processing plant. In 2012, construction is expected to start at the second natural gas processing plant. Start-up of the initial phase of the project is expected in 2013, with planned maximum total natural gas production of 558 million cubic feet per day. Proved reserves have been recognized for this project. The PSC for Chuandongbei expires in 2037. The company holds operating interests in three deepwater exploration blocks in the South China Sea. During the exploration phase, the company has a 100 percent

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working interest in Blocks 53/30 and 64/18, and a 59.2 percent working interest in Block 42/05 under three separate PSCs. The three deepwater blocks cover approximately 4.8 million acres. During 2011, a 3-D seismic acquisition program was completed for Blocks 64/18 and 53/30 and a three-well exploration program was initiated. The first well was unsuccessful. The second and third wells are expected to be completed by mid-2012.

The company signed a joint study agreement to explore for natural gas from shale resources in the Qiannan Basin in April 2011 and commenced seismic operations in July 2011.

The company also has nonoperated working interests of 32.7 percent in Blocks 16/08 and 16/19 in the Pearl River Mouth Basin and nonoperated working interests of 24.5 percent in the QHD 32-6 Field and 16.2 percent in Block 11/19 in the Bohai Bay.


				Indonesia: Chevron holds operated and nonoperated working interests in Indonesia. The company has 100 percent-owned and operated interests in the Rokan and Siak PSCs onshore Sumatra. Chevron also operates four PSCs in the Kutei Basin, located offshore East Kalimantan. These interests range from 62 percent to 92.5 percent. Chevron also has a 51 percent operated working interests in two exploration blocks in western Papua, West Papua I and West Papua III, and a 25 percent nonoperated working interest in a joint venture in Block B in the South Natuna Sea.

The company's net oil-equivalent production in 2011 from its interests in Indonesia averaged 208,000 barrels per day, composed of 166,000 barrels of liquids and 253 million cubic feet of natural gas. The largest producing field is Duri, located in the Rokan PSC. Duri has been under steamflood since 1985 and is one of the world's largest steamflood developments. The North Duri Development is divided into multiple expansion areas. Government approval of the construction contract bid awards for North Duri Area 13 expansion project is expected in mid-2012 with start-up scheduled for 2013. The Rokan PSC expires in 2021.

During 2011, two deepwater development projects in the Kutei Basin progressed under a single plan of development. In the first of these projects, Chevron advanced FEED for the Gendalo-Gehem deepwater natural gas project. The project includes two separate hub developments, natural gas and condensate pipelines, and an onshore receiving facility. Maximum daily total production from the project is expected to be about 1.1 billion cubic feet of natural gas and 31,000 barrels of condensate. Gas from the project is expected to be used domestically and for LNG export. The company's working interest is approximately 63 percent. At the end of 2011, proved reserves had not been recognized for this project.

In the second of these projects, FEED was completed in December 2011 for the Bangka deepwater natural gas project and the contracting approval process began with the government of Indonesia. The project scope includes a subsea tie back to a floating production unit. The company's working interest is 62 percent. At year-end 2011, proved reserves had not been recognized for this project.

Exploration activities continued in the Central Sumatra Basin where six successful appraisal wells were drilled in the Bekasap, Duri and Kulin fields in 2011, and evaluation of a well drilled in the Jorang Field continued in 2012. Also in 2011, seismic data acquisition was completed for West Papua I and is under way for West Papua III. Processing of the seismic data is planned for 2012.

In West Java, Chevron operates the wholly owned Salak geothermal field with a total power-generation capacity of 377 megawatts and 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 the company's operation in Duri, Sumatra. In the Suoh-Sekincau prospect area of Sumatra, the company holds a 95 percent-owned and operated interest in a license to explore and develop a geothermal prospect.

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				Partitioned Zone (PZ): Chevron holds a concession with the Kingdom of Saudi Arabia to operate the kingdom's 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 until 2039. During 2011, the company's average net oil-equivalent production was 91,000 barrels per day, composed of 88,000 barrels of crude oil and 20 million cubic feet of natural gas. During 2011, the company continued a steam injection pilot project in the First Eocene carbonate reservoir that was initiated in 2009. A project to expand the steam injection pilot to the Second Eocene reservoir

progressed during 2011 and is expected to enter FEED in second-half 2012. At the end of 2011, proved reserves had not been recognized for these projects.

Also in 2011, the Central Gas Utilization Project entered FEED. The project is intended to increase natural gas utilization and eliminate routine flaring. A final investment decision is expected in 2013. At year-end 2011, proved reserves had not been recognized for this project.

Philippines: The company holds a 45 percent nonoperated working interest in the Malampaya natural gas field located 50 miles offshore Palawan Island. Net oil-equivalent production in 2011 averaged 25,000 barrels per day, composed of 126 million cubic feet of natural gas and 4,000 barrels of condensate. During 2011, studies were progressed to maintain capacity.

Chevron also develops and produces geothermal resources under an agreement with the Philippine government. During 2011, efforts continued to seek a new 25-year contract with the government for the continued operation of the steam fields, which supply geothermal resources to third-party, 637-megawatt power generation facilities in southern Luzon. Chevron also has a 90 percent-owned and operated interest in the Kalinga geothermal prospect area in northern Luzon and is in the early phase of geological and geophysical assessments.


e)	Australia

In Australia, the company's exploration and production efforts are concentrated off the northwest coast. During 2011, the average net oil-equivalent production from Australia was 101,000 barrels per day.


				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 2011 averaged 18,000 barrels of crude oil and condensate, 445 million cubic feet of natural gas, and 4,000 barrels of LPG. Approximately 70 percent of the natural gas was sold in the form of LNG to major utilities in Asia, primarily under long-term contracts. The remaining natural gas was sold to the Western Australia domestic market. The concession for the NWS Venture expires in 2034. The NWS Venture continues to progress two major capital projects - North Rankin 2 and NWS Oil Redevelopment. The North Rankin 2 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 maintain production capacity of NWS. The North Rankin B platform was completed and installed during 2011. Maximum total daily production is expected to be about

2 billion cubic feet of natural gas and 39,000 barrels of condensate. Total estimated projects costs are $5.4 billion and start-up is expected in 2013. Proved reserves have been recognized for the project.

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The NWS Oil Redevelopment Project recommenced production from the Cossack, Hermes, Lambert and Wanaea fields in September 2011. The project included replacement of an FPSO vessel and a portion of existing subsea infrastructure. The project is expected to extend production from these fields beyond 2020.

Chevron holds a 47.3 percent ownership interest across most of the Greater Gorgon Area and is the operator of the Gorgon Project, which combines the development of the Gorgon and nearby Io/Jansz natural gas field. 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. Maximum total daily production from the project is expected to reach about 2.6 billion cubic feet of natural gas and 20,000 barrels of condensate. Total estimated project costs for the first phase of development are $37 billion.

Work on the Gorgon Project progressed on schedule. As of year-end 2011, more than one-third of the construction activities across numerous fronts on Barrow Island and in fabrication yards in various countries had been completed. The development drilling program also commenced in July 2011.

Through year-end 2011, Chevron has signed binding LNG Sales and Purchase Agreements (SPAs) with six Asian customers for delivery of about 4.7 million metric tons of LNG per year, which brings delivery commitments to about 70 percent of Chevron's share of LNG from this project. Discussions continue with potential customers to increase long-term sales to 85 to 90 percent of Chevron's net LNG off-take. Binding SPAs were also signed in 2011 for delivery of about 55 million cubic feet per day of natural gas to two Western Australian state-owned utilities starting in 2015. Proved reserves have been recognized for the Greater Gorgon Area fields included in the project, and first production of natural gas from the fields is expected in late 2014. The project's estimated economic life exceeds 40 years from the time of start-up.

A project for development of a fourth train at the Gorgon LNG facility is expected to enter FEED in late 2012. At the end of 2011, proved reserves had not been recognized for the fields associated with this expansion.

Chevron and its joint-venture partners are proceeding with development of the Wheatstone Project. In September 2011, the company announced the final investment decision. Construction started in late 2011. Chevron holds a 72.1 percent interest in the foundation natural gas processing facilities, which include a two-train, 8.9 million-metric-ton-per-year LNG facility and a separate domestic gas plant located at Ashburton North, along the northwest coast of Australia. The company plans to supply natural gas to the foundation project from the company-operated and 90.2 percent-owned Wheatstone and Iago fields. Maximum total daily production is expected to be about 1.4 billion cubic feet of natural gas and 25,000 barrels of condensate. The LNG facilities will also be a destination for third-party natural gas. Total estimated project costs for the first phase of development are $29 billion.

Through the end of 2011, Chevron has signed binding SPAs with two Asian customers for the delivery of about 60 percent of Chevron's net LNG off-take from the Wheatstone Project. Discussions continue with potential customers to increase long-term sales to 85 to 90 percent of Chevron's net LNG off-take and to sell down equity. Start-up of the first LNG train is expected in 2016. During 2011, the company recognized proved reserves for this project.

In the Browse Basin, the Browse LNG development participants entered FEED in 2011, undertaking environmental, geophysical, geotechnical and engineering and design studies for the Brecknock, Calliance and Torosa fields. At the end of 2011, proved reserves had not been recognized for any of the Browse Basin fields.

During 2011, the company announced a natural gas discovery at the 50 percent-owned and operated Orthrus Deep prospect in Block WA-24-R. The company also announced natural gas discoveries at the 50 percent-owned and operated Vos prospect in WA-439-P and the 67 percent-owned and operated Acme West prospect in Block WA-205-P in 2011, and at the 50 percent-owned and operated Satyr-3 prospect in WA-374-P in January 2012. These discoveries are expected to support potential expansion opportunities at company-operated LNG facilities.

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f)	Europe

In Europe, the company is engaged in exploration and production activities in Bulgaria, Denmark, the Netherlands, Norway, Poland, Romania and the United Kingdom. Net oil-equivalent production in Europe averaged 139,000 barrels per day during 2011.


				Denmark: Chevron has a 15 percent working interest in the partner-operated Danish Underground Consortium (DUC), which produces crude oil and natural gas from 13 fields in the Danish North Sea. Net oil-equivalent production in 2011 from DUC averaged 44,000 barrels per day, composed of 29,000 barrels of crude oil and 91 million cubic feet of natural gas. Netherlands: Chevron operates and holds interests ranging from 34.1 percent to 80 percent in 10 blocks in the Dutch sector of the North Sea. In 2011, the company's net oil-equivalent production from the producing blocks was 7,000 barrels per day, composed of 2,000 barrels of crude oil and 31 million cubic feet of natural gas. In fourth quarter 2011, the second stage of the A/B Gas Project achieved first gas. Norway: The company holds a 7.6 percent nonoperated working interest in the Draugen Field. The company's net production averaged 3,000 barrels of oil-equivalent per day during 2011. Chevron is the operator and has a 40 percent working interest in exploration license PL 527. In 2011, Chevron was awarded a 40 percent-owned and operated interest in exploration license PL 598. Both licenses are in the deepwater portion of the Norwegian Sea. United Kingdom: The company's average net oil-equivalent production in 2011 from 10 offshore fields was 85,000 barrels per day, composed of 59,000 barrels of crude oil and natural gas liquids and 155 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.

The final investment decision was reached in fourth quarter 2011 for the Clair Ridge Project, located west of the Shetland Islands, in which the company has a 19.4 percent nonoperated working interest. Total design capacity is planned to be 120,000 barrels of crude oil per day, and total estimated projects costs are $7 billion. Production is scheduled to begin in 2016. Initial proved reserves were recognized for this phase of the project in 2011.

At the 70 percent-owned and operated Alder discovery, FEED activities progressed during 2011 and a final investment decision is planned for late 2012. In the 40 percent-owned and operated Rosebank area northwest of the Shetland Islands, seismic, geophysical, geotechnical and environmental surveys were completed during 2011, and FEED is expected to begin in the second-half 2012. At the end of 2011, proved reserves have not been recognized for these projects.

Also west of the Shetland Islands, a three-well exploration and appraisal drilling program continued through 2011 and was completed in early 2012. This program comprised exploration wells on the Lagavulin and Aberlour prospects and appraisal drilling and well testing of the Cambo discovery. The Lagavulin well was unsuccessful and the results from the other wells are under evaluation. Licenses P1196 (Lagavulin) and P1165 (Talisker) were relinquished in November 2011 at the termination of the license period.

In addition, the company entered into a master regasification agreement for access to available capacity at the South Hook LNG terminal in southwest Wales in 2011.

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				Bulgaria: In June 2011, the Bulgarian government advised that Chevron had submitted a winning tender for a permit for exploration in a 1.1 million-acre area in northeast Bulgaria. In January 2012, prior to execution of the license agreement, the Bulgarian government announced the withdrawal of the decision awarding the permit and the Bulgarian parliament imposed a ban on hydraulic fracturing, a technology commonly used for shale exploration and production. Chevron is continuing to work closely with the government of Bulgaria to provide the necessary assurances to the government and the public that hydrocarbons from shale can be developed safely and responsibly. Poland: Chevron holds four shale concessions in southeast Poland (Grabowiec, Zwierzyniec, Krasnik and Frampol). All four exploration licenses are 100 percent-owned and operated and comprise a total of 1.1 million acres. In 2011, Chevron focused on processing data from a 2-D seismic survey. The data is being used to plan a multiwell drilling program that commenced in fourth quarter 2011.

Romania: The company holds a 100 percent interest in the EV-2 Barlad shale concession. This license, located in northeast Romania, covers 1.6 million acres. In 2011, the company acquired 2-D seismic data across the EV-2 Barlad concession. A multiwell drilling program is expected to begin in late 2012. Also during 2011, the company continued negotiations on license agreements for three shale exploration blocks in southeast Romania, Blocks 17, 18 and 19, which comprise approximately 670,000 acres.

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.

During 2011, U.S. and international sales of natural gas were 5.8 billion and 4.4 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, Europe, Kazakhstan, Indonesia, Latin America, the Philippines and Thailand.

U.S. and international sales of natural gas liquids were 161 thousand and 87 thousand barrels per day, respectively, in 2011. Substantially all of the international sales of natural gas liquids are from company operations in Africa, Kazakhstan, Indonesia and the United Kingdom.

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 7 for information related to the company's delivery commitments for the sale of crude oil and natural gas.

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Downstream

Refining Operations

At the end of 2011, the company had a refining network capable of processing about 2 million barrels of crude oil per day. Operable capacity at December 31, 2011, and daily refinery inputs for 2009 through 2011 for the company and affiliate refineries were as follows:

Petroleum Refineries: Locations, Capacities and Inputs
(Crude-unit capacities and crude oil inputs in thousands of barrels per day; includes equity share in affiliates)


		December 31, 2011
				Operable		Refinery Inputs
Locations		Number		Capacity		2011		2010		2009

Pascagoula	Mississippi		1		330		327		325		345
El Segundo	California		1		269		244		250		247
Richmond	California		1		257		192		228		218
Kapolei	Hawaii		1		54		47		46		49
Salt Lake City	Utah		1		45		44		41		40
Perth Amboy 1	New Jersey		1		80		-		-		-

Total Consolidated Companies - United States			6		1,035		854		890		899

Pembroke 2	United Kingdom		-		-		122		211		205
Cape Town 3	South Africa		1		110		77		70		72
Burnaby, B.C.	Canada		1		55		43		40		49

Total Consolidated Companies - International			2		165		242		321		326
Affiliates 4	Various Locations		7		767		691		683		653

Total Including Affiliates - International			9		932		933		1,004		979

Total Including Affiliates - Worldwide			15		1,967		1,787		1,894		1,878


1		Perth Amboy has been idled since early 2008 and is operated as a terminal.
2		Pembroke was sold in August 2011.
3		Chevron holds 100 percent of the common stock issued by Chevron South Africa (Pty) Limited, which owns the Cape Town Refinery. A consortium of South African partners owns preferred shares ultimately convertible to a 25 percent equity interest in Chevron South Africa (Pty) Limited. None of the preferred shares had been converted as of February 2012.
4		Includes 1,000, 2,000 and 4,000 barrels per day of refinery inputs in 2011, 2010 and 2009, respectively, for interests in refineries that were sold during those periods.

Average crude oil distillation capacity utilization during 2011 was 89 percent, compared with 92 percent in 2010. At the U.S. fuel refineries, crude oil distillation capacity utilization averaged 89 percent in 2011, compared with 95 percent in 2010. Chevron processes both imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 85 percent and 84 percent of Chevron's U.S. refinery inputs in 2011 and 2010, respectively.

At the Pascagoula Refinery, construction progressed on a facility to produce approximately 25,000 barrels per day of premium base oil for use in manufacturing high-performance finished lubricants, such as motor oils for consumer and commercial applications. Project completion is expected by year-end 2013. In February 2012, the company signed an agreement to sell its idled 80,000-barrel-per-day refinery, which is operating as a terminal, at Perth Amboy. The sale is expected to close in second quarter 2012.

At the refinery in El Segundo, construction progressed on a new processing unit designed to further improve the facility's overall reliability, enhance high-value product yield and provide additional flexibility to process a broad range of crude slates. Project completion is expected in third quarter 2012. At the Richmond Refinery, the company filed an application for a conditional use permit for a revised project and the City of Richmond published its Notice of Preparation of the revised Environmental Impact Report in second quarter 2011. The project is designed to improve the refinery's ability to process higher sulfur crudes, without changing the refinery's capacity to process crude blends in the intermediate-light gravity range. Improved ability to process higher sulfur crudes is expected to provide increased flexibility to process lower API-gravity crudes within the refinery's existing capacity range. Refer also to a discussion of contingencies related to this project in Note 24 to the Consolidated Financial Statements on page FS-57.

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Outside the United States, GS Caltex, the company's 50 percent-owned affiliate, progressed the construction of a 53,000-barrel-per-day gas oil fluid catalytic cracking unit at the Yeosu Refinery in South Korea. The unit is scheduled for start-up in 2013. The unit is designed to increase high-value product yield and lower feedstock costs. Construction continued on modifications to the 64 percent-owned Star Petroleum Refinery in Thailand to meet regional specifications for cleaner fuels. Project completion is scheduled for 2012. During August 2011, the company completed the sale of the Pembroke Refinery in the United Kingdom. Also in 2011, Caltex Australia Ltd., the company's 50 percent-owned affiliate, initiated a review of its refining operations in Australia, which is ongoing.

Marketing Operations

The company markets petroleum products under the principal brands of "Chevron," "Texaco" and "Caltex" throughout many parts of the world. The table below identifies the company's and affiliates' refined products sales volumes, excluding intercompany sales, for the three years ended December 31, 2011.

Refined Products Sales Volumes
(Thousands of Barrels per Day)


	2011		2010		2009
United States
Gasoline		649		700		720
Jet Fuel		209		223		254
Gas Oil and Kerosene		213		232		226
Residual Fuel Oil		87		99		110
Other Petroleum Products 1		99		95		93

Total United States		1,257		1,349		1,403

International 2
Gasoline		447		521		555
Jet Fuel		269		271		264
Gas Oil and Kerosene		543		583		647
Residual Fuel Oil		233		197		209
Other Petroleum Products 1		200		192		176

Total International		1,692		1,764		1,851

Total Worldwide 2		2,949		3,113		3,254



1 Principally naphtha, lubricants, asphalt and coke.
2 Includes share of equity affiliates' sales:		556		562		516

In the United States, the company markets under the Chevron and Texaco brands. At year-end 2011, the company supplied directly or through retailers and marketers approximately 8,170 Chevron- and Texaco-branded motor vehicle service stations, primarily in the southern and western states. Approximately 490 of these outlets are company-owned or -leased stations.

Outside the United States, Chevron supplied directly or through retailers and marketers approximately 9,660 branded service stations, including affiliates. In British Columbia, Canada, the company markets under the Chevron brand. The company markets in Latin America and the Caribbean using the Texaco brand. In the Asia-Pacific region, southern Africa, Egypt and Pakistan, the company uses the Caltex brand. The company also operates through affiliates under various brand names. In South Korea, the company operates through its 50 percent-owned affiliate, GS Caltex, and in Australia through its 50 percent-owned affiliate, Caltex Australia Limited.

The company continued its ongoing effort to concentrate downstream resources and capital on strategic assets. In 2011, the company completed the sale of its fuels marketing and aviation businesses in 16 countries in the Caribbean and Latin America and certain marketing businesses in five countries in Africa. In August 2011, the company also completed the sale of its marketing businesses in Ireland and the United Kingdom. In 2012, the company expects to complete the sale of its fuels marketing, finished lubricants and aviation fuels businesses in Spain as well as certain fuels marketing and aviation businesses in the central Caribbean, following receipt of required local regulatory and government approvals. In addition, the company converted more than 240 company-operated service stations into retailer-owned sites in various countries outside the United States.

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Chevron markets commercial aviation fuel at approximately 170 airports worldwide. The company also markets an extensive line of lubricant and coolant products under the brand names Havoline, Delo, Ursa, Meropa and Taro.

Chemicals Operations

Chevron owns a 50 percent interest in its Chevron Phillips Chemical Company LLC (CPChem) affiliate. At the end of 2011, CPChem owned or had joint-venture interests in 38 manufacturing facilities and four research and technical centers around the world.

CPChem's 35 percent-owned Saudi Polymers Company expects to commence commercial operations on a new petrochemical project in Al Jubail, Saudi Arabia, in 2012. The joint-venture project includes olefins, polyethylene, polypropylene, 1-hexene and polystyrene units.

In the United States, CPChem continued with plans to construct a 1-hexene plant at the company's Cedar Bayou complex in Baytown, Texas, capable of producing in excess of 200,000 tons per year. Start-up is expected in 2014. The plant is expected to be the largest 1-hexene unit in the world and will utilize CPChem's proprietary 1-hexene technology. CPChem is also conducting a feasibility study to evaluate a potential U.S. Gulf Coast ethylene cracker and derivatives complex to capitalize on advantaged feedstock sourced from emerging shale gas development in North America.

Chevron's Oronite brand lubricant and fuel additives business is a leading developer, manufacturer and marketer of performance additives for lubricating oils and fuels. The company owns and operates facilities in Brazil, France, Japan, the Netherlands, Singapore and the United States and has equity interests in facilities in India and Mexico. Oronite lubricant additives are blended into refined base oil to produce finished lubricant packages used primarily in engine applications such as passenger car, heavy-duty diesel, marine, locomotive and motorcycle engines, and additives for fuels that are blended to improve engine performance and extend engine life. In February 2012, the company reached a final investment decision to significantly increase the capacity of the existing additives plant in Singapore.

Transportation

Pipelines: Chevron owns and operates an extensive network of crude oil, refined product, chemical, natural gas liquid and natural gas pipelines and other infrastructure assets in the United States. The company also has direct and indirect interests in other U.S. and international pipelines. The company's ownership interests in pipelines are summarized in the following table.

Pipeline Mileage at December 31, 2011


	Net Mileage 1,2
United States:
Crude Oil		2,115
Natural Gas		2,282
Petroleum Products		6,125

Total United States		10,522
International:
Crude Oil		700
Natural Gas		699
Petroleum Products		311

Total International		1,710

Worldwide		12,232


1	Includes company's share of pipeline mileage owned by equity affiliates.

2	Excludes gathering pipelines relating to the crude oil and natural gas production function.

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Work was completed in first quarter 2012 to return the Cal-Ky Pipeline to crude oil service as a supply line for the Pascagoula Refinery. This crude oil pipeline is also expected to provide additional outlets for the company's equity production. The company is leading the construction of a 136 mile, 24-inch pipeline from the Jack/St. Malo facility to Green Canyon 19 in the U.S. Gulf of Mexico, where there is an interconnect to pipelines delivering crude oil into Texas and Louisiana.

Refer to pages 14, 16 and 17 in the Upstream section for information on the Chad/Cameroon pipeline, the West Africa Gas Pipeline, the Baku-Tbilisi-Ceyhan Pipeline, the Western Route Export Pipeline and the Caspian Pipeline Consortium.

Tankers: All tankers in Chevron's controlled seagoing fleet were utilized during 2011. During 2011, the company had 48 deep-sea vessels chartered on a voyage basis, or for a period of less than one year. The table below summarizes the capacity of the company's controlled fleet.

Controlled Tankers at December 31, 2011 1


	U.S. Flag				Foreign Flag
			Cargo Capacity				Cargo Capacity
	Number		(Millions of Barrels)		Number		(Millions of Barrels)

Owned		-		-		1		1.1
Bareboat-Chartered		4		1.4		17		25.0
Time-Chartered 2		-		-		13		10.5

Total		4		1.4		31		36.6


1	Consolidated companies only. Excludes tankers chartered on a voyage basis, those with dead-weight tonnage less than 25,000 and those used exclusively for storage.

2	Tankers chartered for more than one year.

Chevron Corp (CVX) SEC Annual Report (10-K) for 2011

Form 10-K

Chevron Corporation