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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

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

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2006

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

SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 1-368-2

Chevron Corporation

(Exact name of registrant as specified in its charter)


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

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

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

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


Title of Each Class		Name of Each Exchange on Which Registered

Common stock, par value $.75 per share		New York Stock Exchange, Inc.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ 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 þ

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 þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Act. (Check one):

Large accelerated filer þ Accelerated filer o Non-accelerated filer o

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

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 — $136,407,118,275 (As of June 30, 2006)

Number of Shares of Common Stock outstanding as of February 23, 2007 — 2,157,780,998

DOCUMENTS INCORPORATED BY REFERENCE

(To The Extent Indicated Herein)

Notice of the 2007 Annual Meeting and 2007 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company’s 2007 Annual Meeting of Stockholders (in Part III)

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 our 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 crude oil and natural gas prices; refining margins and marketing margins; chemicals prices and competitive conditions affecting supply and demand for aromatics, olefins and additives products; actions of competitors; 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 or severe weather; the potential liability for remedial actions 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 pending or future litigation; the company’s acquisition or disposition of assets; government-mandated sales, divestitures, recapitalizations, changes in fiscal terms or restrictions on scope of company operations; 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” in this report. In addition, such statements could be affected by general domestic and international economic and political conditions. Unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements.

PART I


Item 1.	Business


(a)	General Development of Business

Summary Description of Chevron

Chevron Corporation,¹ a Delaware corporation, manages its investments in subsidiaries and affiliates and provides administrative, financial, management and technology support to U.S. and foreign subsidiaries that engage in fully integrated petroleum operations, chemicals operations, mining operations of coal and other minerals, power generation and energy services. The company conducts business activities in the United States and approximately 180 other countries. Exploration and production (upstream) operations consist of exploring for, developing and producing crude oil and natural gas and also marketing natural gas. Refining, marketing and transportation (downstream) operations relate to refining crude oil into finished petroleum products; marketing crude oil and the many products derived from petroleum; and transporting crude oil, natural gas and petroleum products by pipeline, marine vessel, motor equipment and rail car. Chemical operations include the manufacture and marketing of commodity petrochemicals, plastics for industrial uses, and fuel and lubricant oil additives.

A list of the company’s major subsidiaries is presented on pages E-4 and E-5 of this Annual Report on Form 10-K. As of December 31, 2006, Chevron had nearly 62,500 employees (including about 6,600 service station employees). Approximately 28,800, or 46 percent, of the company’s employees were employed in U.S. operations.

Acquisition of Unocal Corporation

On August 10, 2005, the company acquired Unocal Corporation (Unocal), an independent oil and gas exploration and production company. This acquisition was accounted for under the rules of Financial Accounting Standards Board Statement No. 141, Business Combinations. Unocal’s principal upstream operations were in North America and Asia, including the Caspian region. Other activities included ownership interests in proprietary and common carrier pipelines, natural gas storage facilities and mining operations. Further discussion of the Unocal acquisition is contained in Note 2 beginning on page FS-34 of this Annual Report on Form 10-K.

Overview of Petroleum Industry

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

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

¹ 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.

Operating Environment

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

Chevron Strategic Direction

Chevron’s primary objective is to create value and achieve sustained financial returns from its operations that will enable it to outperform its competitors. As a foundation for achieving this objective, the company had established the following strategies, which continue into 2007:

Strategies for Major Businesses


	•	*Upstream* — grow profitably in core areas, build new legacy positions and commercialize the company’s natural gas equity resource base while growing a high-impact global gas business

	•	*Downstream* — improve base-business returns and selectively grow, with a focus on integrated value creation

The company will also continue to invest in renewable-energy technologies, with an objective of capturing profitable positions in important renewable sources of energy.

Enabling Strategies Companywide


	•	*Invest in people* to achieve the company’s strategies

	•	*Leverage technology* to deliver superior performance and growth

	•	*Build organizational capability* to deliver world-class performance in operational excellence, cost reduction, capital stewardship and profitable growth


(b)	Description of Business and Properties

The upstream, downstream and chemicals activities of the company and its equity affiliates are widely dispersed geographically, with operations in North America, South America, Europe, Africa, the Middle East, Asia, and Australasia. Tabulations of segment sales and other operating revenues, earnings and income taxes for the three years ending December 31, 2006, and assets as of the end of 2006 and 2005 — for the United States and the company’s international geographic areas — are in Note 8 to the consolidated financial statements beginning on page FS-38 of this Annual Report on Form 10-K. In addition, 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-41 to FS-43.

Capital and Exploratory Expenditures

Total reported expenditures for 2006 were $16.6 billion, including $1.9 billion for Chevron’s share of expenditures by affiliated companies, which did not require cash outlays by the company. In 2005 and 2004, expenditures were $11.1 billion and $8.3 billion, respectively, including the company’s share of affiliates’ expenditures of $1.7 billion and $1.6 billion in the corresponding periods. The 2005 amount excludes the $17.3 billion acquisition of Unocal.

Of the $16.6 billion in expenditures for 2006, 77 percent, or $12.8 billion, related to upstream activities. Approximately the same percentage was also expended for upstream operations in 2005 and 2004. International upstream accounted for about 70 percent of the worldwide upstream investment in each of the three years, reflecting the company’s continuing focus on opportunities that are available outside the United States.

In 2007, the company estimates capital and exploratory expenditures will be 18 percent higher at $19.6 billion, including $2.4 billion of spending by affiliates. About three-fourths, or $14.6 billion, is budgeted for exploration and production activities, with $10.6 billion of that amount outside the United States.

Refer also to a discussion of the company’s capital and exploratory expenditures on page FS-13 of this Annual Report on Form 10-K.

Upstream — Exploration and Production

The table on the following page summarizes the net production of liquids and natural gas for 2006 and 2005 by the company and its affiliates.

Net Production¹ of Crude Oil and Natural Gas Liquids and Natural Gas


	Crude Oil & Natural Gas								Memo: Oil-Equivalent
	Liquids (Thousands of				Natural Gas (Millions of				(Thousands of
	Barrels per Day)				Cubic Feet per Day)				Barrels per Day)²
	2006		2005		2006		2005		2006		2005
United States:
California		207		217		101		106		224		235
Gulf of Mexico³		114		112		661		579		224		208
Texas³		79		61		425		380		150		124
Wyoming		8		9		153		161		33		36
Other States³		54		56		470		408		132		124

Total United States³		462		455		1,810		1,634		763		727

Africa:
Angola		156		139		47		36		164		145
Nigeria		139		125		29		68		144		136
Chad		34		38		4		3		35		39
Republic of the Congo		11		11		8		8		12		12
Democratic Republic of the Congo³		3		1		2		—		3		1
Asia-Pacific:
Partitioned Neutral Zone (PNZ)⁴		111		112		19		22		114		116
Thailand³		73		43		856		409		216		111
Azerbaijan³		46		13		4		1		47		13
Australia		39		42		360		362		99		102
Kazakhstan		38		37		143		142		62		61
China		23		26		18		—		26		26
Philippines		6		8		108		163		24		35
Bangladesh³		—		—		126		59		21		10
Myanmar³		—		—		89		32		15		5
Indonesia³		198		202		302		211		248		237
Other International:
United Kingdom		75		83		242		300		115		133
Canada³		46		54		6		19		47		57
Denmark		44		47		146		146		68		71
Argentina		38		43		54		55		47		52
Norway		6		8		1		2		6		9
Venezuela⁵		3		4		21		35		7		10
Netherlands³		3		2		7		4		4		3
Colombia		—		—		174		185		29		31
Trinidad and Tobago		—		—		174		115		29		19

Total International³		1,092		1,038		2,940		2,377		1,582		1,434

Total Consolidated Operations³		1,554		1,493		4,750		4,011		2,345		2,161
Equity Affiliates⁶		178		176		206		222		213		213

Total Including Affiliates^3,7,8		1,732		1,669		4,956		4,233		2,558		2,374


1		Net production excludes royalty interests owned by others.
2		Barrels of oil-equivalent is crude oil and natural gas liquids plus natural gas converted to oil-equivalent gas (OEG) barrels at 6,000 cubic feet = 1 OEG barrel.
3		Includes net production beginning August 2005 for properties associated with acquisition of Unocal.
4		Located between the Kingdom of Saudi Arabia and the State of Kuwait.
5		Through September 30, 2006, LL-652 was reported as part of Venezuela consolidated operations. As of October 1, 2006, LL-652 is reported under Equity Affiliates. See footnote 6 below.
6		Represents Chevron’s share of production by affiliates, including Tengizchevroil (TCO) in Kazakhstan, Hamaca in Venezuela and for the last three months of 2006 Chevron’s share of LL-652 and Boscan in Venezuela. Effective October 1, 2006, the company converted its interests in Boscan and LL-652 operating service agreements in Venezuela to Empresas Mixtas (i.e., joint stock contractual structures), and these interests are accounted for as equity affiliates. LL-652 was previously reported as part of Venezuela consolidated operations, and Boscan was included only as part of footnote 8 below, “Other produced volumes.”
7		Includes natural gas consumed in operations of 475 and 404 million cubic feet per day in 2006 and 2005, respectively.
8		Does not include other produced volumes:


Athabasca Oil Sands — net	27	32	—	—	27	32
Boscan Operating Service Agreement	82	111	—	—	82	111
(through September 30, 2006 — see footnote 6 above)

In 2006, Chevron conducted exploration and production operations in the United States and approximately 35 other countries. Worldwide oil-equivalent production of 2.67 million barrels per day in 2006, including volumes produced from oil sands in Canada and production under the Boscan operating service agreement in Venezuela, increased approximately 6 percent from 2005. The increase between periods was mostly attributable to the Unocal acquisition. Refer to the “Results of Operations” section beginning on page FS-6 for a detailed discussion of the factors explaining the 2004–2006 changes in production for crude oil and natural gas liquids and natural gas.

The company estimates that its average worldwide oil-equivalent production in 2007 will be approximately 2.6 million barrels per day. This estimate is subject to many uncertainties, including quotas that may be imposed by OPEC, the price effect on production volumes calculated under cost-recovery and variable-royalty provisions of certain contracts, changes in fiscal terms or restrictions on scope of company operations, and production that may have to be shut in due to weather conditions, civil unrest, changing geopolitics or other disruptions to daily operations. Future production levels also are affected by the size and number of economic investment opportunities and, for new large-scale projects, the time lag between initial exploration and the beginning of production. Expected additions to production capacity in 2008 through 2010 may permit worldwide oil-equivalent production levels to increase from 2007 levels. Refer to the “Review of Ongoing Exploration and Production Activities in Key Areas,” beginning on page 9, for a discussion of the company’s major oil and gas development projects.

Average Sales Prices and Production Costs per Unit of Production

Refer to Table IV on page FS-68 of this Annual Report on Form 10-K for data about the company’s average sales price per unit of crude oil and natural gas produced as well as the average production cost per unit for 2006, 2005 and 2004.

Gross and Net Productive Wells

The following table summarizes gross and net productive wells at year-end 2006 for the company and its affiliates:

Productive Oil and Gas Wells¹ at December 31, 2006


	Productive²				Productive²
	Oil Wells				Gas Wells
	Gross		Net		Gross		Net

United States:
California		24,484		22,754		185		58
Gulf of Mexico		2,429		1,788		1,454		1,080
Other U.S.		23,602		8,525		10,793		5,074

Total United States		50,515		33,067		12,432		6,212

Africa		2,083		702		7		3
Asia-Pacific		2,394		1,146		1,989		1,251
Indonesia		7,580		7,434		203		162
Other International		989		621		239		97

Total International		13,046		9,903		2,438		1,513

Total Consolidated Companies		63,561		42,970		14,870		7,725
Equity in Affiliates		1,067		375		—		—

Total Including Affiliates		64,628		43,345		14,870		7,725


Multiple completion wells included above:		890		542		390		281


1		Includes wells producing or capable of producing and injection wells temporarily functioning as producing wells. Wells that produce both oil and gas are classified as oil wells.
2		Gross wells include the total number of wells in which the company has an interest. Net wells include wholly owned and the sum of the company’s fractional interests in gross wells.

Reserves

Table V, beginning on page FS-68, provides a tabulation of the company’s proved net oil and gas reserves, by geographic area, as of each year-end 2004 through 2006 and an accompanying discussion of major changes to proved

reserves by geographic area for the three-year period. During 2006, the company provided oil and gas reserves estimates for 2005 to the Department of Energy, Energy Information Agency. Such estimates are consistent with, and do not differ more than 5 percent from, the information furnished to the Securities and Exchange Commission on the company’s Annual Report on Form 10-K. During 2007, the company will file estimates of oil and gas reserves with the Department of Energy, Energy Information Agency, consistent with the reserve data reported in Table V.

Acreage

At December 31, 2006, the company owned or had under lease or similar agreements undeveloped and developed oil and gas properties located throughout the world. The geographical distribution of the company’s acreage is shown in the following table.

Acreage¹ at December 31, 2006
(Thousands of Acres)


									Developed
									and
	Undeveloped²				Developed²				Undeveloped
	Gross		Net		Gross		Net		Gross		Net

United States:
California		139		121		206		178		345		299
Gulf of Mexico		3,713		2,690		1,759		1,300		5,472		3,990
Other U.S.		4,651		3,353		5,444		2,626		10,095		5,979

Total United States		8,503		6,164		7,409		4,104		15,912		10,268

Africa		18,448		8,024		2,522		925		20,970		8,949
Asia-Pacific		50,216		22,680		5,773		2,605		55,989		25,285
Indonesia		10,310		6,545		380		340		10,690		6,885
Other International		33,529		19,368		2,267		622		35,796		19,990

Total International		112,503		56,617		10,942		4,492		123,445		61,109

Total Consolidated Companies		121,006		62,781		18,351		8,596		139,357		71,377
Equity in Affiliates		924		431		252		102		1,176		533

Total Including Affiliates		121,930		63,212		18,603		8,698		140,533		71,910


1		Gross acreage includes the total number of acres in all tracts in which the company has an interest. Net acreage is the sum of the company’s fractional interests in gross acreage.
2		Developed acreage is spaced or assignable to productive wells. Undeveloped acreage is acreage where wells have not been drilled or completed to permit commercial production and that may contain undeveloped proved reserves. The gross undeveloped acres that will expire in 2007, 2008 and 2009 if production is not established by certain required dates are 12,459, 7,731 and 10,207, respectively.

Contract Obligations

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 certain natural gas sales contracts specify delivery of fixed and determinable quantities.

In the United States, the company is contractually committed to deliver to third parties and affiliates approximately 281 billion cubic feet of natural gas through 2009 from U.S. reserves. The company believes it can satisfy these contracts from quantities available from production of the company’s proved developed U.S. reserves. These contracts include variable-pricing terms.

Outside the United States, the company is contractually committed to deliver to third parties a total of approximately 560 billion cubic feet of natural gas from 2007 through 2009 from Argentina, Australia, Canada, Colombia and the Philippines. The sales contracts contain variable pricing formulas that are generally referenced to the prevailing market price for crude oil, natural gas or other petroleum products at the time of delivery and in some cases consider inflation or other factors. The company believes it can satisfy these contracts from quantities available from

production of the company’s proved developed reserves in Argentina, Australia, Colombia and the Philippines. The company plans to meet its Canadian contractual delivery commitments of 27 billion cubic feet through third-party purchases.

Development Activities

Details of the company’s development expenditures and costs of proved property acquisitions for 2006, 2005 and 2004 are presented in Table I on page FS-63 of this Annual Report on Form 10-K.

The table below summarizes the company’s net interest in productive and dry development wells completed in each of the past three years and the status of the company’s development wells drilling at December 31, 2006. A “development well” is a well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Development Well Activity


	Wells
	Drilling at				Net Wells Completed^1,2
	12/31/06³				2006				2005				2004
	Gross		Net		Prod.		Dry		Prod.		Dry		Prod.		Dry

United States:
California		12		3		600		—		661		—		636		1
Gulf of Mexico		14		8		34		5		29		3		43		3
Other U.S.		8		8		317		6		256		4		221		3

Total United States		34		19		951		11		946		7		900		7

Africa		10		3		45		2		38		—		36		—
Asia-Pacific⁴		88		48		235		1		150		—		84		—
Indonesia		6		6		258		—		107		—		163		—
Other International⁴		7		2		43		—		79		—		84		—

Total International		111		59		581		3		374		—		367		—

Total Consolidated Companies		145		78		1,532		14		1,320		7		1,267		7
Equity in Affiliates		—		—		13		—		23		—		20		—

Total Including Affiliates		145		78		1,545		14		1,343		7		1,287		7


1		Indicates the fractional number of wells completed during the year, regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for the production of crude oil or natural gas or, in the case of a dry well, the reporting of abandonment to the appropriate agency.
2		Includes completion of wells beginning August 2005 related to the former Unocal operations.
3		Represents wells in process of drilling, including wells for which drilling was not completed and were temporarily suspended at the end of 2006. Gross wells include the total number of wells in which the company has an interest. Net wells include wholly owned and the sum of the company’s fractional interests in gross wells.
4		2005 conformed to 2006 presentation.

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, 2006. “Exploratory wells” are wells drilled to find and produce crude oil or natural gas in unproved areas and include delineation wells, which are wells drilled to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir or to extend a known reservoir beyond the proved area.

Exploratory Well Activity


	Wells
	Drilling				Net Wells Completed^1,2
	at 12/31/06³				2006				2005				2004
	Gross		Net		Prod.		Dry		Prod.		Dry		Prod.		Dry

United States:
California		—		—		—		—		—		—		—		—
Gulf of Mexico		6		3		9		8		14		8		13		8
Other U.S.		1		1		7		—		5		6		3		1

Total United States		7		4		16		8		19		14		16		9

Africa		4		1		1		—		4		1		3		1
Asia-Pacific		15		9		18		7		10		—		16		—
Indonesia		—		—		2		—		5		—		2		—
Other International⁴		5		1		6		3		7		4		3		7

Total International		24		11		27		10		26		5		24		8

Total Consolidated Companies		31		15		43		18		45		19		40		17
Equity in Affiliates⁴		—		—		1		—		8		—		—		—

Total Including Affiliates		31		15		44		18		53		19		40		17


1		Indicates the fractional number of wells completed during the year, regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for the production of crude oil or natural gas or, in the case of a dry well, the reporting of abandonment to the appropriate agency. Some exploratory wells are not drilled with the intention of producing from the well bore. In such cases, “completion” refers to the completion of drilling. Further categorization of productive or dry is based on the determination as to whether hydrocarbons in a sufficient quantity were found to justify completion as a producing well, whether or not the well is actually going to be completed as a producer.
2		Includes completion of wells beginning August 2005 related to the former Unocal operations.
3		Represents wells that are in the process of drilling but have been neither abandoned nor completed as of the last day of the year, including wells for which drilling was not completed and were temporarily suspended at the end of 2006. Does not include wells for which drilling was completed at year-end 2006 and were reported as suspended wells in Note 20 on page FS-47. Gross wells include the total number of wells in which the company has an interest. Net wells include wholly owned and the sum of the company’s fractional interests in gross wells.
4		2005 conformed to 2006 presentation.

Details of the company’s exploration expenditures and costs of unproved property acquisitions for 2006, 2005 and 2004 are presented in Table I on page FS-63 of this Annual Report on Form 10-K.

Review of Ongoing Exploration and Production Activities in Key Areas

Chevron’s 2006 key upstream activities, 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 below include references to “total production” and “net production,” which are defined under “Production” in Exhibit 99.1 on page E-11 of this Annual Report on Form 10-K. In addition to the activities discussed, Chevron was active in other geographic areas, but those activities are considered less significant.

The discussion below also references the status of proved reserves recognition for significant long-lead-time projects not yet on production and for projects recently placed on production. Reserves are not discussed for recent discoveries that have yet to advance to a project stage and for production in mature areas.

Consolidated Operations


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

a) United States

Upstream activities in the United States are concentrated in the Gulf of Mexico, Louisiana, Texas, New Mexico, the Rocky Mountains and California. Average daily net production during 2006 was 462,000 barrels of crude oil and natural gas liquids and 1.8 billion cubic feet of natural gas, or 763,000 barrels per day on an oil-equivalent basis. Refer to Table V beginning on page FS-68 for a discussion of the net proved reserves and different hydrocarbon characteristics for the company’s major U.S. producing areas.


		California: The company has significant production in the San Joaquin Valley. In 2006, average daily net production was 202,000 barrels of crude oil, 101 million cubic feet of natural gas and 5,000 barrels of natural gas liquids, or 224,000 barrels of oil-equivalent. Approximately 80 percent of the crude oil production is considered heavy oil (typically with API gravity lower than 22 degrees).


		Gulf of Mexico: Average daily net production rates during 2006 for the company’s combined interests in the Gulf of Mexico shelf and deepwater areas and the fields onshore Louisiana were 102,000 barrels of crude oil, 661 million cubic feet of natural gas and 12,000 barrels of natural gas liquids, or 224,000 barrels of oil-equivalent. Net production at the end of 2006 was approximately the same rate, which reflects restoration of most of the volumes that were economic to restore following the production outages caused by hurricanes in 2005.

In the Gulf of Mexico deepwater areas, the company’s producing fields during 2006 included:


	•	Genesis — 57 percent-owned and operated. Daily net production in 2006 averaged 7,000 barrels of crude oil and 10 million cubic feet of natural gas, or 9,000 barrels of oil-equivalent.

	•	Petronius — 50 percent-owned and operated and includes the Perseus discovery, which started production from the Petronius platform in 2005. Daily net production in 2006 was 20,000 barrels of crude oil and 22 million cubic feet of natural gas, or 25,000 barrels of oil-equivalent.

	•	Mad Dog — 16 percent-owned and nonoperated and started production in 2005. Net production in 2006 averaged 5,000 barrels of oil-equivalent per day. Ongoing development work is expected to increase the maximum total daily production in 2008 to the design capacity of 80,000 barrels of crude oil and 40 million cubic feet of natural gas.

The company’s interests in the deepwater Typhoon and Boris fields were sold during 2006. The production platform at Typhoon capsized during Hurricane Rita in 2005 and was safely converted into an artificial reef prior to the sale.

During 2006, Chevron was engaged in other development and exploration activities in the deepwater Gulf of Mexico. Development work continued at the 58 percent-owned and operated Tahiti Field, where production start-up is expected in 2008. Development drilling commenced in February 2006, and well completion work is expected to be finalized during 2007. Initial booking of proved undeveloped reserves occurred in 2003, and the transfer of these reserves into the proved developed category is anticipated near the time of production start-up. With an estimated production life of 30 years, Tahiti is designed to have a maximum total daily production of 125,000 barrels of crude oil and 70 million cubic feet of natural gas.

At the 63 percent-owned and operated Blind Faith discovery, a subsea development plan utilizing a semi-submersible production system was approved by Chevron and its partner in late 2005, at which time the company made its initial booking of proved undeveloped reserves. Development drilling at Blind Faith commenced in early 2007. Reclassification of the reserves to the proved developed category is anticipated near the time of production start-up in 2008. Initial total daily production rates for the field are estimated at 30,000 barrels of crude oil and 30 million cubic feet of natural gas, thereafter rising to maximum rates of 40,000 barrels of crude oil and 35 million cubic feet of natural gas. The expected production life of the field is approximately 20 years.

In the fourth quarter 2006, the company announced its decision to participate in the ultra-deep Perdido Regional Development in the U.S. Gulf of Mexico. The development encompasses the installation of a producing host facility designed to service multiple fields, including Chevron’s 33 percent-owned Great White, 60 percent-owned Silvertip and 58 percent-owned Tobago. Chevron has a 38 percent interest in the Perdido Regional Host. All of these fields and the production facility are partner-operated. First oil is expected to occur by 2010, with the facility capable of handling 130,000 barrels of oil-equivalent per day. The company’s initial booking of proved undeveloped reserves occurred in 2006, and the phased reclassification of these reserves to the proved developed category is anticipated near the time of production start-up. The project has an expected life of approximately 25 years.

Exploration activities in 2006 included the announcement of a discovery early in the year at the 60 percent-owned and operated Big Foot prospect located in Walker Ridge Block 29. A sidetrack well at Big Foot was completed mid-year and encountered the same pay intervals as the discovery well. Additional appraisal drilling is planned for the first half of 2007.

At the 50 percent-owned and operated Jack discovery in Walker Ridge Block 758, a successful extended production flow test on the Jack #2 well was completed in mid-2006. Additional appraisal drilling is scheduled for the 2007–2008 time frame. Data evaluation continued in early 2007 at the nearby 41 percent-owned and operated Saint Malo prospect. Saint Malo was discovered in 2003, and an appraisal well was completed in 2004. Future appraisal drilling is being planned based on ongoing technical studies that are incorporating additional regional data. At the 25 percent-owned and nonoperated 2005 Knotty Head discovery, a successful sidetrack well was drilled during 2006. Additional appraisal drilling and possible development alternatives were being evaluated in early 2007. At the 30 percent-owned and nonoperated Tubular Bells prospect, an appraisal well in 2006 successfully tested the eastern portion of the reservoir structure. Additional appraisal work is being planned to further delineate the reservoir and to evaluate potential deeper targets. Plans were in progress in early 2007 at the 22 percent-owned and nonoperated Puma discovery to complete an in-progress appraisal well and to schedule additional appraisal drilling for 2007.

At the end of 2006, the company had not yet recognized proved reserves for any of the exploration projects discussed above.

Besides the activities connected with the development and exploration projects in the Gulf of Mexico area, Chevron also moved forward with the federal, state and local permitting process for construction of a natural gas import terminal at Casotte Landing in Jackson County, Mississippi. In February 2007, the company received approval from the Federal Energy Regulatory Commission to construct the facility. The terminal would be located adjacent to the company’s Pascagoula Refinery and be designed to process imported liquefied natural gas (LNG) for distribution to industrial, commercial and residential customers in Mississippi, Florida and the Northeast. The terminal would have an initial natural-gas processing capacity of 1.3 billion cubic feet per day. A decision to construct the facility will be timed to align with the company’s LNG supply projects.

The company also has contractual rights to 1 billion cubic feet per day of regasification capacity at the third party-owned Sabine Pass LNG terminal beginning in 2009. Also in the Sabine Pass area, the company has up to 1 billion cubic feet per day of pipeline capacity in a new pipeline that will be connected to the Sabine Pass LNG terminal. The new pipeline system will provide access to Chevron’s Sabine and Bridgeline pipelines, which connect to the Henry Hub. Interconnect capacity of 600 million cubic feet per day has also been secured to an existing pipeline. The Henry Hub is the pricing point for natural gas futures contracts traded on the New York Mercantile Exchange (NYMEX) and is located on the natural gas pipeline system in Louisiana. Henry Hub interconnects to nine interstate and four intrastate pipelines.

Other U.S. Areas: Outside California and the Gulf of Mexico, the company manages operations in areas of the midcontinent United States that extend from the Rockies to southern Texas. In the Piceance Basin of northwestern Colorado, the company drilled 14 tight-gas delineation wells during 2006 on the Skinner Ridge properties. Development drilling is scheduled to begin in the second quarter 2007 with the delivery of two custom-built drilling rigs. Chevron also operates 10 offshore platforms and five producing natural gas fields in Alaska’s Cook Inlet and owns nonoperated production on the North Slope. During 2006, the company’s operations outside California and the Gulf of Mexico averaged daily net production of 141,000 barrels of crude oil and natural gas liquids and about 1 billion cubic feet of natural gas (315,000 barrels of oil-equivalent).

b) Africa


		Angola: Chevron has working interests in four concessions in Angola — Blocks 0 and 14, which are company-operated, and Block 2 and the FST area, which are nonoperated. The 39 percent-owned Block 0 and 31 percent-owned Block 14 are off the coast, north of the Congo River. In Block 0, the company operates in two areas — A and B — composed of 20 fields that produced 127,000 barrels per day of net liquids in 2006. The Block 0 concession extends through 2030. Area A of Block 0 comprises 14 producing fields and averaged daily net production of approximately 67,000 barrels of crude oil and 1,000 barrels of liquefied petroleum gas (LPG) in 2006. The first phase of development of the Mafumeira Field in Area A was approved in 2006 and will target the northern portion of the field. Initial booking of proved undeveloped reserves for this development occurred in 2003, and reclassification of proved undeveloped reserves into the proved developed category is anticipated near the time of first production, which is expected in 2008. Maximum total daily production is expected to be approximately 30,000 barrels of crude oil in 2011.

In Area B of Block 0, average daily net production from six producing fields was 52,000 barrels of crude oil and condensate and 7,000 barrels of LPG in 2006. Included in this production were 28,000 barrels of liquids per day from the Sanha condensate natural gas utilization and Bomboco crude oil project. Initial reclassification of reserves from proved undeveloped to proved developed for this project occurred in 2004 and is expected to continue during the drilling program that is scheduled for completion in 2007. Maximum total daily production from the Sanha and Bomboco fields reached 100,000 barrels of liquids in 2006.

In Block 14, net production from the Kuito, Belize, Lobito and Landana fields averaged 25,000 barrels of crude oil per day in 2006. Belize and Lobito are part of the Benguela Belize-Lobito Tomboco (BBLT) development project. Phase 1 of the BBLT project involved the installation of an integrated drilling and production platform and the

development of the Benguela and Belize fields. First oil was produced at the Belize Field in January 2006. Phase 2 of the project involved the installation of subsea production systems, pipelines and wells for the development of Lobito and Tomboco fields. First oil was produced from the Lobito Field in June 2006. Maximum total production for both phases of BBLT is estimated at 200,000 barrels of crude oil per day and is scheduled to occur in 2008. Proved undeveloped reserves for Benguela and Belize were initially recognized in 1998 and for Lobito and Tomboco in 2000. Certain proved developed reserves for Belize and Lobito were recognized in 2006, and additional BBLT reserves are expected to be reclassified to proved developed as project milestones are met. The concession period for these fields expires in 2027.

Another major project in Block 14 is the development of the Tombua and Landana fields. Construction on the project started in 2006. The maximum total daily production of 100,000 barrels of crude oil is expected to occur by 2010. First oil was produced from the Landana North reservoir in June 2006, using the BBLT infrastructure. Proved undeveloped reserves were recognized for Tombua and Landana in 2001 and 2002, respectively. Initial reclassification from proved undeveloped to proved developed for Landana occurred in 2006. Further reclassification is expected from 2009, when the Tombua-Landana facilities are completed, through 2012, when the drilling program is scheduled for completion. The concession for these fields expires in 2028. The total cost of the Tombua-Landana project is estimated at $3.8 billion.

Four exploration wells were drilled in Block 14 in 2006. One well resulted in a crude oil discovery at the deepwater Lucapa prospect. A second well appraised a prior-year discovery at Gabela, where development options are being studied. The remaining two wells are expected to be completed in the first-half 2007.

In Chevron’s other two concessions, the nonoperated working interests are 20 percent in Block 2, which is adjacent to the northwestern part of Angola’s coast, south of the Congo River, and 16 percent in the onshore FST area. Combined net production from these properties in 2006 was 4,000 barrels of crude oil per day.

In addition to the producing activities in Angola, Chevron has a 36 percent interest in the planned Angola LNG project, which will be integrated with natural gas production in the area. As of early 2007, participants in the Angola LNG project were finalizing the engineering, procurement, construction and commissioning contract for the 5-million-metric-ton-per-year onshore LNG plant to be located in the northern part of the country. Chevron and Sonangol, Angola’s national oil company, are co-leaders of the project. Construction is expected to begin in late 2007. At the end of 2006, the company had not yet recognized proved reserves for the natural gas associated with this project.

Democratic Republic of the Congo: Chevron has an 18 percent nonoperated working interest in a production-sharing contract (PSC) off the coast of Democratic Republic of the Congo. Daily net production from seven fields averaged 3,000 barrels of crude oil in 2006.

Republic of the Congo: Chevron has a 32 percent nonoperated working interest in the Nkossa, Nsoko and Moho-Bilondo exploitation permits and a 29 percent nonoperated working interest in the Kitina and Sounda exploitation permits, all of which are offshore Republic of the Congo. Net production from the Republic of the Congo fields averaged 11,000 barrels of crude oil per day in 2006. The Moho-Bilondo development continued in 2006, with first production expected in 2008. The development plan calls for crude oil produced by subsea well clusters to flow into a floating processing unit. Maximum total daily production of 80,000 barrels of crude oil is expected by 2010. Proved undeveloped reserves were initially recognized in 2001. Transfer to the proved developed category is expected near the time of first production. The Moho-Bilondo concession expires in 2030.

Angola-Republic of the Congo Joint Development Area: Chevron is operator and holds a 31 percent interest in the 14K/A-IMI Unit, located in a joint development area shared equally between Angola and Republic of the Congo. In 2006, Chevron submitted a conceptual field development plan to a committee of representatives from the two countries.

Chad/Cameroon: Chevron is a nonoperating partner in a project to develop crude oil fields in southern Chad and transport the crude oil by pipeline to the coast of Cameroon for export. Chevron has a 25 percent working interest in the producing operations and a 21 percent interest in the pipeline. Average daily net production from five fields in 2006 was 34,000 barrels of crude oil. The first of the satellite-field development projects was completed in the first quarter of 2006, and first oil was achieved in 2005 from the Nya Field and in March 2006 from the Moundouli Field. The second satellite-field development project, Maikeri, was approved for funding in the second half of 2006, with first oil anticipated for fourth quarter 2007. The Chad producing operations are conducted under a concession agreement that expires in 2030.

Libya: In 2005, the company was awarded Block 177 in Libya’s first exploration license round under the Exploration and Production Sharing Agreement IV. Chevron is the operator and holds a 100 percent interest in the block.

Acquisition and evaluation of seismic data is scheduled for completion in late 2007. A drilling program is scheduled for 2008.


		Equatorial Guinea: Until October 2006, Chevron was a 22 percent partner and operator of Block L, offshore Equatorial Guinea. Following the drilling of two noncommercial wells and expiration of the exploration period, the company relinquished its equity in the block. Nigeria: Chevron’s principal subsidiary in Nigeria, Chevron Nigeria Limited (CNL), operates and holds a 40 percent interest in 14 concessions, predominantly in the onshore and near-offshore regions of the Niger Delta. CNL operates under a joint-venture arrangement with the Nigerian National Petroleum Corporation (NNPC), which owns a 60 percent interest. In 2006, daily net production from 30 fields averaged 137,000 barrels of crude oil, 29 million cubic feet of natural gas and 2,000 barrels of LPG. During 2006, the company continued development activities for the deepwater Agbami project, in which Chevron has a 68 percent operated interest. The total capital investment for this project is estimated at $5.2 billion. The Agbami Field is located approximately 70 miles off the coast in the central Niger Delta. Discovered in 1998, Agbami is at a water depth of approximately 4,800 feet. The geologic structure spans 45,000 acres across Oil Mining License (OML) 127

and OML 128. Agbami is designed as an all-subsea development, with the wells tied back to a floating production, storage and offloading (FPSO) vessel. The subsea wells will be connected to the FPSO by a system of flexible flowlines, manifolds and control umbilicals. All wells are to be drilled by a mobile drilling unit. Development drilling and completion operations were conducted throughout 2006.

During 2006, the Agbami development achieved the following major milestones: the FPSO hull was floated out of drydock in South Korea; topside modules fabricated in South Korea were installed on the FPSO and modules fabricated in Nigeria were received at the shipyard in South Korea. All other major equipment items were shipped to South Korea for installation, and manufacturing began on the equipment for the subsea wells. Completion of the FPSO and subsequent transport to Nigeria are expected in the fourth quarter 2007.

Agbami’s maximum total daily production of 250,000 barrels of crude oil and natural gas liquids is expected to be reached within the first year after start-up in the second half 2008. The company initially recognized proved undeveloped reserves for Agbami in 2002. A portion of the proved undeveloped reserves will be reclassified to proved developed in advance of production start-up. The expected field life is approximately 20 years.

For Chevron’s Aparo discovery in 2003 on OML 132 (formerly Oil Prospecting License [OPL] 213), the company entered into a joint-study agreement in 2004 with the partner group of the Bonga SW Field in OML 118 (formerly OPL 212) for the unitization and joint development of Aparo, which straddles OML 132 and OPL 249. Negotiation of final terms for a unitization agreement for this development was ongoing as of early 2007. Front-end engineering and design (FEED) continued through 2006, and discussions were under way in early 2007 with potential contractors. Development will likely involve an FPSO and subsea wells. Partners are expected to make the investment decision during 2007, with production start-up estimated to occur in 2011. Maximum total production of 150,000 barrels of crude oil per day is expected to be reached within one year of production start-up. The company recognized initial proved undeveloped reserves in 2006 for its approximate 20 percent nonoperated working interest in the unitized project.

The company holds a 30 percent nonoperated working interest in the Usan project, located offshore in OPL 222. FEED for the Usan Field continued through 2006 on a selected FPSO concept. Technical tendering for the major contracts were under way as of early 2007. Project partners expect to make the investment decision during 2007. The company recognized proved undeveloped reserves for the project in 2004. Production start-up is estimated for late 2011, before which time certain proved undeveloped reserves are expected to be reclassified to the proved developed category. Maximum total production of 180,000 barrels of crude oil per day is expected to be achieved within one year of start-up. The end date of the concession period will be determined after final regulatory approvals are obtained.

Chevron operates and holds a 95 percent interest in the 2003 Nsiko discovery, also on OPL 249. Two successful appraisal wells were drilled in 2004, with subsurface evaluations and field development planning ongoing in early 2007. The company expects FEED to begin in late 2007. Maximum total production of 100,000 barrels of oil per day is anticipated within one year of initial start-up, targeted for 2012. At the end of 2006, no proved reserves had been recognized for this project.

The Nnwa Field in OML 129 (formerly OPL 218) was discovered in 1999 and extends into two adjacent non-Chevron leased blocks. Chevron’s nonoperated working interest in OML 129 is 46 percent. A later discovery in OML 129 was made in the Bilah Field. Commerciality of these fields is dependent upon resolution of the Nigerian Deepwater Gas fiscal regime and collaboration agreements with adjacent blocks. The Bilah Field discovery was under evaluation in early 2007 for further appraisal and the viability of a stand-alone condensate liquid recovery scheme.

Chevron is a participant in the South Offshore Water Injection Project, an enhanced crude-oil recovery project in the south offshore area of OML 90. The company operates and holds a 40 percent interest as part of the joint venture with NNPC. The objective of the project is to increase production by providing water injection, natural-gas lift and production debottlenecking in the South Offshore Asset Area (Okan and Delta fields). The 25-year-life project is in its development phase and by the end of 2006 was contributing incremental production of approximately 7,000 net barrels of crude oil per day. Maximum total production from this project is expected to be 35,000 barrels of crude oil per day in 2010. The major project milestones expected in 2007 include commencement of water injection from the new Delta South Water Inject Platform facility, drilling of 10 additional wells and the installation of pipelines. Initial recognition of proved developed and proved undeveloped reserves was made in 2005. Reclassification of proved reserves to the proved developed category is expected to occur after the evaluation of the water injection performance.

In May 2006, the company announced the discovery of crude oil at the Uge-1 well in the 20 percent-owned and nonoperated offshore OPL 214. Future drilling is contingent primarily on completing technical studies.

Chevron is involved in projects in Nigeria that support the company’s strategic initiative to commercialize its significant natural gas resource base outside the United States. Construction began in early 2006 on the Phase 3A expansion of the Escravos Gas Plant (EGP). Engineering, procurement and construction are expected to continue through 2007, with start-up targeted for early 2009. The scope of EGP Phase 3A includes offshore natural gas gathering and compression infrastructure and a second plant, which potentially would increase processing capacity from 285 million to 680 million cubic feet of natural gas per day and increase LPG and condensate export capacity from 4,000 to 43,000 barrels per day. Proved undeveloped reserves associated with EGP Phase 3A were recognized in 2002. These reserves are expected to be reclassified to proved developed as various project milestones are reached and related projects are completed. The anticipated life of the project is 25 years. Chevron holds a 40 percent operated interest in this project.

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

Chevron holds a 38 percent interest in the West African Gas Pipeline, which is expected to start up in the first-half 2007 and supply Nigerian natural gas to customers in Ghana, Benin and Togo for industrial applications and power generation. A 350-mile offshore segment of the West African Gas Pipeline connects to an existing onshore pipeline in Nigeria. Chevron is the managing sponsor in West African Pipeline Company Limited, which constructed, owns and will operate the pipeline.

In February 2006, Chevron signed a Project Development Agreement for a 19 percent nonoperated working interest in the Olokola LNG Project, which involves construction of a four-train, 22-million-metric-ton-per-year natural gas liquefaction facility and marine terminal located in a free trade zone between Lagos and Escravos. Chevron is expected to supply approximately 1.8 billion cubic feet per day of natural gas to the LNG plant. The project entered FEED in the first quarter 2006. The partners’ investment decision is scheduled for 2007, and initial production is targeted for 2012. The company had not recognized proved reserves for this project at the end of 2006.

Nigeria-São Tomé e Príncipe Joint Development Zone (JDZ): Chevron is the operator of JDZ Block 1 and holds a 46 percent interest following the sale of a 5 percent interest in 2006. In March 2006, the first exploration well was completed and encountered hydrocarbons. In early 2007, commercial options were being examined to determine the possible need for additional drilling.

c) Asia-Pacific


		Australia: During 2006, the net daily production from Chevron’s interests in Australia was 34,000 barrels of crude oil and condensate, 5,000 barrels of LPG, and 360 million cubic feet of natural gas. Chevron has a 17 percent nonoperated working interest in the North West Shelf (NWS) Venture offshore Western Australia. Daily net production from the project during 2006 averaged 29,000 barrels of crude oil and condensate, 358 million cubic feet of natural gas, and 5,000 barrels of LPG. Approximately 75 percent of the natural gas was sold in the form of LNG to major utilities in Japan and South Korea, primarily under long-term contracts. The remaining natural gas was sold to the Western Australia domestic market. A fifth LNG train, which is intended to increase export capacity by more than 4 million metric tons per year to more than 16 million, is expected to be commissioned in 2008. The Angel natural gas field, being developed at an estimated total cost of $1.2 billion, will supply the fifth LNG train. NWS reserves are recorded according to existing sales agreements. Start-up of the fifth train is projected to accelerate production of proved reserves and additional reclassification of proved undeveloped reserves to proved developed. The end of the concession period for the NWS Venture is 2034.

On Barrow and Thevenard islands off the northwest coast of Australia, Chevron operates crude oil producing facilities that had combined net production of 5,000 barrels per day in 2006. Chevron’s interest in this operation is 57 percent for Barrow Island and 51 percent for Thevenard Island.

Also off the northwest coast of Australia, Chevron is the operator of the Gorgon-area fields and has a 50 percent ownership interest across most of the Greater Gorgon Area. Chevron and its two joint-venture participants signed a Framework Agreement in 2005 that will enable the combined development of Gorgon and the nearby natural gas fields as one world-scale project. In early 2007, progress continued toward securing environmental regulatory approvals necessary for the development of the Greater Gorgon LNG project on Barrow Island. A two-train, 10-million-metric-ton-per-year LNG development is planned for the island, with natural gas supplied from the Gorgon and Jansz natural gas fields.

Elsewhere in the Greater Gorgon Area during 2006, concept studies were undertaken on the Wheatstone-1 natural gas discovery located northeast of the Gorgon Field. Appraisal drilling is scheduled for 2007. The company also announced in 2006 two significant natural gas discoveries at the 67 percent-owned Clio-1 and 50 percent-owned Chandon-1 exploration wells located offshore northwestern coast in the Greater Gorgon development area. Additional work on these two company-operated prospects includes a 3-D seismic survey program that started in late 2006 to better determine the potential of the natural gas find and subsequent development options.

Chevron was also awarded exploration rights to Blocks WA-374-P (Greater Gorgon Area) and WA-383-P (Exmouth West) in the Carnarvon Basin offshore Western Australia. Chevron holds a 50 percent operated interest in the blocks. Operations commenced in WA-374-P with the acquisition of 3-D seismic data. On WA-383-P, a three-year work program includes geotechnical studies and 2-D seismic work. In early 2007, the company was also named operator and awarded a 50 percent interest in exploration acreage in Block W06-12 in the Greater Gorgon Area. A three-year work program includes geotechnical studies, seismic surveys and drilling of an exploration well.

At the end of 2006, the company had not recognized proved reserves for any of the Greater Gorgon Area fields. Recognition is contingent on securing sufficient LNG sales agreements and achieving other key project milestones. The company has signed separate nonbinding Heads of Agreements totaling 4.2 million metric tons per year with three companies in Japan to supply LNG from the Gorgon project. As of early 2007, negotiations were continuing to finalize binding sales agreements. Purchases by each of these customers are expected to range from 1.2 million metric tons per year to 1.5 million metric tons per year of LNG over 25 years beginning after 2010.


		Azerbaijan: Chevron holds a 10 percent nonoperated working interest in the Azerbaijan International Operating Company (AIOC), which holds offshore crude oil reserves in the Caspian Sea from the Azeri-Chirag-Gunashli (ACG) project. Chevron also has a 9 percent equity interest in the Baku-Tbilisi-Ceyhan (BTC) pipeline, which transports AIOC production from Baku, Azerbaijan, through Georgia to deepwater port facilities in Ceyhan, Turkey. (Refer to “Pipelines” under “Transportation Operations” on page 27 for a discussion of the BTC operations.) In 2006, the company’s daily net crude oil production from AIOC averaged 46,000 barrels. Phase II of the ACG development project began producing from the West Azeri Field in late 2005 and was completed with the production of first oil from the East Azeri Field in October 2006. Phase III was in the final phase of development in early 2007, with production start-up targeted for 2008. Total crude oil production from the project is expected to increase to about 700,000 barrels per day in 2007 and to more than 1 million barrels per day by 2009. Proved undeveloped reserves for ACG are expected to be reclassified to proved developed reserves as new wells are drilled and completed. The AIOC operations are conducted under a 30-year PSC that expires at the end of 2024.

Kazakhstan: Chevron holds a 20 percent nonoperated working interest in the Karachaganak project that is being developed in phases. During 2006, Karachaganak daily net production averaged 38,000 barrels of liquids and 143 million cubic feet of natural gas.

The Karachaganak operations are conducted under a 40-year concession agreement that expires in 2038. In 2006, access to the Caspian Pipeline Consortium (CPC) and Atyrau-Samara pipelines allowed Karachaganak sales of approximately 143,000 barrels per day (27,000 net barrels) of processed liquids at prices available in world markets. A fourth train was approved in December 2006 that is designed to increase this export of processed liquids by 56,000 barrels per day (11,000 net barrels). The fourth train is expected to start up in 2009.

Phase III of Karachagnak field development is contingent upon the Republic of Kazakhstan’s identifying and enabling a commercially attractive outlet for the increased natural gas volumes. Timing for the recognition of Phase III proved reserves and an increase in production are uncertain, and both depend on achieving a natural gas sales agreement and finalizing a viable Phase III project design.

Refer also to page 23 for a discussion of Tengizchevroil, a 50 percent-owned affiliate with operations in Kazakhstan.

Russia: In 2005, OAO Gazprom, Russia’s largest natural gas producer, included Chevron on a list of companies that could continue discussions concerning the development and related commercial activities of the Shtokmanovskoye Field, a very large natural gas field offshore Russia in the Barents Sea. In October 2006, OAO Gazprom issued a public statement indicating its plan to develop Shtokmanovskoye without foreign partners. Refer also to page 24 for a discussion of the company’s interest in a Russian joint venture.

Bangladesh: Chevron is the operator of four onshore blocks, with a 98 percent interest in Blocks 12, 13 and 14 and a 43 percent interest in Block 7. In 2006, the properties averaged daily net production of 126 million cubic feet of natural gas. Following a two-year development program, production from the Bibiyana Field in Block 12 is scheduled to start in the first-half 2007, reaching maximum total production of 500 million cubic feet per day by late 2010. The development program includes a gas processing plant with capacity of 600 million cubic feet per day and a natural gas pipeline. Initial proved reserves were recognized in 2005. In 2006, additional proved reserves were recognized based on additional development wells drilled during the year, and certain proved undeveloped reserves were reclassified to the proved developed category in recognition of imminent completion of the gas plant and pipeline infrastructure required for production start-up. The Bibiyana PSC expires in 2034.


		Cambodia: Chevron operates and holds a 55 percent interest in the 1.6 million-acre Block A, located offshore in the Gulf of Thailand. A third drilling campaign commenced in third quarter 2006 and is expected to be completed by first quarter 2007. Myanmar: Chevron has a 28 percent nonoperated working interest in a PSC for the production of natural gas from the Yadana and Sein fields, located offshore Myanmar in the Andaman Sea. The company also has a 28 percent interest in a pipeline company that transports the natural gas from the Yadana Field to the Myanmar-Thailand border for final delivery to power plants in Thailand. The company’s average net natural gas production in Myanmar was 89 million cubic feet per day in 2006.

Thailand: Chevron has both operated and nonoperated working interests in several different offshore blocks in Thailand. The company’s daily net production averaged 73,000 barrels of crude oil and condensate and 856 million cubic feet of natural gas in 2006.

Operated interests include concessions with ownership interests ranging from 35 percent to 80 percent in Blocks 10 through 13 and B12/27, 52 percent-owned Blocks B8/32 and 9A, 60 percent-owned G4/43 and 71 percent-owned G4/48.

In the concession containing Blocks 10 through 13 and B12/27, debottlenecking of all central processing platforms was completed, which is expected to add more than 160 million cubic feet per day of natural gas processing capability. The company anticipates this additional capacity will be used when PTT Public Company Limited completes the third natural gas pipeline to shore in 2007. In late 2007, the company expects to complete the evaluation of a possible second natural gas central processing facility in Platong to support a Heads of Agreement signed in 2003 for additional natural gas sales to meet future natural gas demands in Thailand. This Platong Gas II Project, in which the company has a 70 percent interest, would add 330 million cubic feet per day of processing capacity in the Platong area, which spans Blocks 10, 10A, 11 and 11A in the Gulf of Thailand. The new facilities would include a central processing platform, pipelines and five initial wellhead platforms. First gas sales would occur in 2010. Proved reserves would be recognized throughout the 12-year project life as the required wellhead platforms are developed.

In Blocks B8/32 and 9A, crude oil is produced from six operating areas within the Pattani Field. First production from Lanta area in Block G4/43 is anticipated in the first-half 2007.

Chevron has a 16 percent nonoperated working interest in Blocks 14A, 15A, 16A and G9/48, known collectively as the Arthit Field. Development of Arthit is progressing with six wellhead platforms installed and 41 wells drilled in 2006. First production is planned for 2008.

In 2006, the company signed two exploration concessions, Blocks G4/48 and G9/48. Two delineation wells are scheduled to be drilled in Block G4/48 in 2007. One exploration well in Block G9/48 is required to be drilled by the first quarter 2009. As of early 2007, processing and interpretation of seismic data were under way in Block G9/48. Chevron also holds exploration interests in a number of blocks that are currently inactive, pending resolution of border issues between Thailand and Cambodia.

Vietnam: The company is operator in two PSCs offshore southwest Vietnam in the northern part of the Malay Basin. Chevron has a 42 percent interest in Blocks B and 48/95 and a 43 percent interest in Block 52/97. In April 2006, the company signed a 30-year PSC for Block 122 located offshore eastern Vietnam. The company has a 50 percent operated interest in this block and has undertaken a three-year work program for seismic acquisition and drilling of an exploratory well.

In July 2006, the company submitted a revised summary development plan to state-owned PetroVietnam for Blocks B, 48/95 and 52/97 for the Vietnam Gas Project. The final detailed development plan is expected to be submitted in the third quarter 2007, with FEED projected to begin by the end of 2007. First natural gas production is targeted for 2011 but is dependent on the progress of commercial negotiations. Maximum total production of approximately 500 million cubic feet of natural gas per day is projected within four years of the production start-up. Recognition of initial proved reserves is expected to follow execution of the gas sales agreements and anticipated project sanction in 2008. Total development cost for the project is approximately $3.5 billion.

China: Chevron has a 33 percent nonoperated working interest in Blocks 16/08 and 16/19 located in the Pearl River Delta Mouth Basin, a 25 percent nonoperated working interest in QHD-32-6 in Bohai Bay, and a 16 percent nonoperated working interest in the unitized and producing Bozhong 25-1 Field in Bohai Bay Block 11/19. Daily net production from the company’s interests in China averaged 23,000 barrels of crude oil and condensate and 18 million cubic feet of natural gas in 2006. Production during 2006 included first natural gas in January from the HZ21-1 natural gas development project, located in Block 16/08. Chevron also has interests ranging from 36 percent to 50 percent in four prospective onshore natural gas blocks in the Ordos Basin totaling about 1.5 million acres.

Partitioned Neutral Zone (PNZ): Saudi Arabian Chevron Inc., a Chevron subsidiary, holds a 60-year concession that expires in 2009 to produce crude oil from onshore properties in the PNZ, which is located between the Kingdom of Saudi Arabia and the State of Kuwait. In September 2006, Chevron submitted to the Kingdom of Saudi Arabia a proposal to extend the concession agreement. Under the current concession, Chevron has the right to Saudi Arabia’s 50 percent undivided interest in the hydrocarbon resource and pays a royalty and other taxes on volumes produced. During 2006, average daily net production was 111,000 barrels of crude oil and 19 million cubic feet of natural gas. Facilities for the first phase of a steamflood project were completed in December 2005, and steam injection began in February 2006. The success of the first phase has led to the approval of funding for a second phase steamflood pilot project that is expected to be completed by late 2008. This pilot is a unique application of steam injection into a carbonate reservoir.

Philippines: The company holds a 45 percent nonoperated working interest in the Malampaya natural gas field located about 50 miles offshore Palawan Island. Daily net production in 2006 was 108 million cubic feet of natural gas and 6,000 barrels of condensate. Chevron also develops and produces steam resources under an agreement with the National Power Corporation, a Philippine government-owned company. The combined generating capacity is 634 megawatts.

d) Indonesia


		Chevron’s operated interests in Indonesia are managed by several wholly owned subsidiaries, including PT. Chevron Pacific Indonesia (CPI), Chevron Indonesia Company, Chevron Makassar Ltd, Chevron Geothermal Indonesia (CGI) and Chevron Geothermal Salak Ltd (CGS), and a subsidiary P.T. Mandau CiptaTenaga Nusantara (MCTN). CPI operates four PSCs, with interests ranging from 50 percent to 100 percent. In addition Chevron operates five PSCs in the Kutei Basin, East Kalimantan and one PSC in the Tarakan Basin, Northeast Kalimantan. These interests range from 35 percent to 100 percent. Chevron also has a 25 percent working interest in a nonoperated joint venture in South Natuna Sea Block B and a 40 percent working interest in the nonoperated NE Madura III Block in the East Java Sea Basin. CGI is a power generation company that operates the Darajat geothermal contract area in West Java, with a total capacity of 145 megawatts. MCTN operates a cogeneration facility in support of CPI’s operation in North Duri. CGS operates the Salak geothermal field, located in West Java, with a total capacity of 377 megawatts.

In North Duri, located in the Rokan PSC, development is progressing on steamflood activity for the sequential development of three possible expansion areas. The first expansion involves the development of Area 12, in which the company has a 100 percent interest, and is planned to come onstream in 2008, with maximum total daily production estimated at 34,000 barrels of crude oil in 2012. Proved undeveloped reserves for North Duri were recognized in previous years, and reclassification from proved undeveloped to proved developed will occur during various stages of sequential project completion.

A drilling campaign is scheduled to continue through 2007 in South Natuna Sea Block B, with first oil from Kerisi Field expected in late 2007. In 2006, the company executed a farm-out agreement relinquishing five Indonesian PSCs in exchange for a 40 percent nonoperated working interest in the NE Madura III Block.

In early 2007, the company submitted preliminary plans of development to the government of Indonesia for the Bangka, Gendalo Hub and Gehem Hub deepwater natural gas projects, located in the Kutei Basin. These projects will

likely be developed in parallel, with first production for all projects targeted for 2013. The actual timing is partially dependent on government approvals, market conditions and the achievement of key project milestones.

The development concept for the 50 percent-owned and operated Sadewa project, located in the Kutei Basin is under evaluation and is expected to be completed in late 2007. Assuming the evaluation is positive, initial proved reserves recognition would be expected to occur in 2008, with first production expected in 2010.

Daily net production from all producing areas in Indonesia averaged 198,000 barrels of crude oil and 302 million cubic feet of natural gas in 2006.

e) Other International Areas


		Argentina: Chevron operates in Argentina through its subsidiary, Chevron Argentina S.R.L. The company and its partners hold 17 operated production concessions and four exploration blocks (two operated and two nonoperated) in the Neuquen and Austral basins. Working interests range from approximately 19 percent to 100 percent in operated license areas. Daily net production in 2006 averaged 38,000 barrels of crude oil and 54 million cubic feet of natural gas. Chevron also holds a 14 percent interest in Oleoductos del Valle S.A. pipeline and a 28 percent interest in the Oleoducto Transandino pipeline. Brazil: Chevron holds working interests ranging from 20 percent to 52 percent in four deepwater blocks. In Block BC-4, located in the Campos Basin, the company is the operator and has a 52 percent interest in the Frade Field. In 2006, the Frade project completed FEED and started construction with all major contracts in place. The total project cost is estimated at $2.8 billion. Proved undeveloped reserves were recorded for the first time in 2005. Reclassification of proved undeveloped reserves to the proved developed category is anticipated upon production start-up in early 2009 and is expected to continue until 2011. Estimated maximum total production of 90,000 oil-equivalent barrels per day is anticipated in 2011. The Frade concession expires in 2025.

The company concentrates its exploration efforts in the Campos and Santos basins. In the nonoperated Campos Basin Block BC-20, two areas — 38 percent-owned Papa-Terra (formerly RJS610) and 30 percent-owned RJS609 — have been retained for development following the end of the exploration phase of this block. In the Papa-Terra area, the appraisal phase has been completed confirming hydrocarbons in three separate reservoirs. In June 2006, a field development plan was submitted to the government. FEED for the Papa-Terra Field is expected to commence in late 2007 after completing an appraisal program planned for mid-2007. In the RJS609 area, all appraisal drilling was completed to fulfill requirements for a Declaration of Commerciality that was filed in December 2006 for a new field, designated Maromba. Elsewhere in Campos, the company holds a 30 percent nonoperated working interest in the BM-C-4 Block, in which drilling of the final obligatory exploration well began in October 2006. As of early 2007, drilling of the Guarana prospect was ongoing, with completion and evaluation expected to occur later in 2007. In the 20 percent-owned and nonoperated Santos Basin BS-4 Block, the evaluation of an exploration campaign was completed in 2006, with the Declaration of Commerciality filed in December 2006 designating two new fields, Atlanta and Oliva.

Colombia: The company operates three natural gas fields in Colombia — the offshore Chuchupa and the onshore Ballena and Riohacha. The fields are part of the Guajira Association contract, a joint venture agreement that was extended in 2003. At that time, additional proved reserves were recognized. The company continues to operate the fields and receives 43 percent of the production for the remaining life of each field as well as a variable production volume from a fixed-fee Build-Operate-Maintain-Transfer (BOMT) agreement based on prior Chuchupa capital contributions. The BOMT agreement expires in 2016. Net production averaged 174 million cubic feet of natural gas per day in 2006. New production capacity was commissioned in 2006 and will help meet the demand of the growing Colombian natural gas market.

Trinidad and Tobago: The company has a 50 percent nonoperated working interest in four blocks in offshore Trinidad, which include the Dolphin and Dolphin Deep producing natural gas fields and the Starfish discovery. Net natural gas production from Dolphin and Dolphin Deep in 2006 averaged 174 million cubic feet per day.

Natural gas supply to the Atlantic LNG Train 3 from the Dolphin Field began in 2005. In July 2006, Chevron delivered the first natural gas from the Dolphin Deep development to the Atlantic LNG Train 3 and Train 4. The initial phase of the development became fully operational during 2006 and supplied an average of 38 million net cubic feet of natural gas per day to Train 3 and 31 million net cubic feet of natural gas per day to Train 4. Proved reserves associated with the Train 4 gas sales agreement were recognized in 2004. Reserves associated with Trains 3 and 4 were transferred to the proved developed category in 2005. The contract period for Train 3 ends in 2023 and for Train 4 in 2026.

Chevron also holds a 50 percent operated interest in the Manatee area of Block 6d. After successful exploration drilling results in 2005, the company assessed alternative development strategies for the Loran Field in Venezuela and Manatee area in 2006. As of early 2007, negotiations were in progress between Trinidad and Tobago and Venezuela to unitize the Loran and Manatee discoveries.

Venezuela: As of October 2006, the company’s operations at the Boscan and LL-652 fields were converted to two joint stock companies. From that date, these activities were treated as affiliate operations and accounted for under the equity method. Refer to page 23 for a further discussion of these operations.

The company also has ongoing exploration activity in two blocks offshore Plataforma Deltana, in which the company is operator and holds a 60 percent interest. In Block 2, which includes the Loran Field, evaluation and project development work continued during 2006. In the 100 percent-owned and operated Block 3, Chevron discovered natural gas in 2005. The discovery is in close proximity to the Loran natural gas field and provides significant resources that will be included in the detailed evaluation as a potential gas supply source for Venezuela’s first LNG train. Seismic work elsewhere in Block 3 started in 2006. Chevron also has 100 percent interest in the Cardon III exploration block, located offshore western Venezuela north of the Maracaibo producing region. Seismic work in this block, which has natural gas potential, is planned for 2007.

Refer also to page 23 for a discussion of the Hamaca heavy oil production and upgrading project in Venezuela.

Canada: The company’s assets in Canada include a 27 percent nonoperated working interest in the Hibernia Field offshore eastern Canada, a 20 percent nonoperated working interest in the Athabasca Oil Sands Project (AOSP) and exploration acreage in the Mackenzie Delta and Orphan Basin. Excluding volumes mined at the AOSP, daily net production in 2006 from the company’s Canadian operations was 46,000 barrels of crude oil and natural gas liquids and 6 million cubic feet of natural gas. The company also owns a 28 percent operated interest in the Hebron project offshore eastern Canada. Negotiations with the government of Newfoundland and Labrador on commercial terms for the development of the field were suspended in April 2006, and the project team was demobilized. The timing for a possible resumption of negotiations was uncertain as of early 2007.

At the AOSP, which began operations in 2003, bitumen is mined from oil sands and upgraded into synthetic crude oil using hydroprocessing technology. Chevron’s share of bitumen production in 2006 averaged 27,000 barrels per day.

In 2006, the company elected to participate in the first phase of expansion of the AOSP. The expansion is being designed to produce approximately 100,000 barrels of bitumen per day (20,000 net barrels) and upgrade it into synthetic crude oil at an estimated total cost of $10 billion. The expansion will increase total AOSP design capacity to approximately 255,000 barrels of bitumen per day by 2010. This phase of expansion includes the construction of mining and extraction facilities at the Jackpine Mine, for which net proved undeveloped oil sands reserves were recorded in 2006.

Net proved oil sands reserves at the end of 2006 were 443 million barrels, increasing from 2005 primarily due to the addition of reserves for the Jackpine Mine and proved developed oil sands reserves for the Muskeg River Mine. Securities and Exchange Commission regulations define these reserves as mining-related and not a part of conventional oil and gas reserves.

Chevron also holds a 60 percent operated interest in the Ells River “In Situ” Oil Sands Project in the Athabasca region. This project consists of heavy oil leases of more than 75,000 acres that were acquired in 2005 and 2006. The area contains significant volumes with the potential for recovery using Steam Assisted Gravity Drainage, a proven technology that employs steam and horizontal drilling to extract the bitumen through wells rather than through mining operations. Initial drilling began in January 2007.


		Denmark: Chevron holds a 15 percent nonoperated working interest in the Danish Underground Consortium (DUC), which produces crude oil and natural gas from 15 fields in the Danish North Sea and involves 12 percent to 27 percent interests in five exploration licenses. Daily net production in 2006 from the DUC was 44,000 barrels of crude oil and 146 million cubic feet of natural gas. Faroe Islands: During 2006, the company focused on the interpretation of the seismic program over License 008, located near the Rosebank/Lochnagar discovery in the United Kingdom. The company has a 40 percent interest in five offshore blocks and is the operator. Netherlands: Chevron is the operator and holds interests ranging from 34 percent to 80 percent in nine blocks in the Netherlands sector of the North Sea. The company’s daily net production from seven producing fields averaged 3,000 barrels of crude oil and 7 million cubic feet of natural gas in 2006. Production start-up at the first stage of the A/B Gas Project is scheduled for early 2008.

Norway: At the 8 percent-owned and nonoperated Draugen Field, the company’s share of production during 2006 was 6,000 barrels of crude oil per day. In the 30 percent-owned and nonoperated PL 324 Field, the first exploration well is planned for the first-half 2007. In the 40 percent-owned and operated PL 325, seismic data was acquired in 2006. Pending the results of the ongoing seismic processing, a first exploration well is planned for 2008. At PL 283, in which Chevron holds a 25 percent nonoperated working interest, an exploration well that tested natural gas in the Stetind prospect in 2006 will be followed by another exploration well in mid-2007.

Through an Area of Mutual Interest with a partner in the Barents Sea, Chevron was awarded a 40 percent nonoperated working interest in PL 397 in April 2006, encompassing six blocks located in the Nordkapp East Basin. A 3-D seismic survey was acquired and is planned to be processed in 2007.

United Kingdom: Offshore United Kingdom, the company’s daily net production in 2006 from nine fields was 75,000 barrels of crude oil and 242 million cubic feet of natural gas. Of this volume, daily net production from the 85 percent-owned and operated Captain Field was 37,000 barrels of crude oil and from the co-operated and 32 percent-owned Britannia Field was 5,000 barrels of crude oil and 138 million cubic feet of natural gas. In December 2006, Chevron exchanged interests in the nonproducing North Sea Blocks 16/22 and 16/23 for an additional 2 percent interest in the Chevron-operated Alba Field, raising the company’s total interest to 23 percent. Daily net production from this field averaged 11,000 barrels of crude oil in 2006.

As of early 2007, development activities were continuing at the Britannia satellite fields Callanish and Brodgar, in which Chevron holds 17 percent and 25 percent nonoperated working interests, respectively. A new platform and all subsea equipment and pipelines were installed in 2006. Production start-up from these two satellite fields is expected to occur in 2008. Together, these fields are expected to achieve maximum total daily production of 25,000 barrels of crude oil and 133 million cubic feet of natural gas several months after both fields start up. Proved undeveloped reserves were initially recognized in 2000. In 2006, proved undeveloped reserves were reclassified to the proved developed category. This project has an expected production life of approximately 15 years.

Production start-up occurred in June 2006 at the Area C project in the eastern portion of the Captain Field. The project included the installation of subsea infrastructure and the drilling of two new subsea wells. Maximum total production of 14,000 barrels of crude oil per day was achieved in September 2006. Initial proved undeveloped reserves were booked in 2004 and were reclassified as proved developed in 2006 following completion of development drilling. Further additions to proved reserves are expected to occur as the field matures.

The Alder discovery, west of the Britannia Field, is being evaluated and likely to be developed as a tieback to existing infrastructure. The company has a 70 percent operated interest in the project, which is expected to start up and reach maximum total daily production rates of 9,000 barrels of crude oil and 80 million cubic feet of natural gas in 2011. No proved reserves had been recognized as of year-end 2006.

In late 2006, the first well in a three-well program began drilling to evaluate the commercial potential of the Rosebank/Lochnagar discovery and adjacent acreage.

In early 2007, Chevron was awarded eight operated exploration blocks and two nonoperated blocks west of Shetland Islands in the 24th United Kingdom Offshore Licensing Round.

f) Affiliate Operations

Kazakhstan: The company holds a 50 percent interest in Tengizchevroil (TCO), which is developing the Tengiz and Korolev crude oil fields located in western Kazakhstan under a 40-year concession that expires in 2033. Chevron’s share of daily net production in 2006 averaged 135,000 barrels of crude oil and natural gas liquids and 193 million cubic feet of natural gas.

TCO is undergoing a significant expansion composed of two integrated projects referred to as the Second Generation Plant (SGP) and Sour Gas Injection (SGI). At a total combined cost of approximately $6 billion, these projects are designed to increase TCO’s crude oil production capacity from 300,000 barrels per day to between 460,000 and 550,000 barrels per day in 2008. The actual production level within the estimated range is dependent partially on the effects of the SGI, which are discussed below. The start-up of the SGP/SGI project is expected in 2007.

SGP involves the construction of a large processing train for treating crude oil and the associated sour gas (i.e., high in sulfur content). The SGP design is based on the same conventional technology employed in the existing processing trains. Proved undeveloped reserves associated with SGP were recognized in 2001. During 2006, 55 wells were drilled, deepened and/or completed in the Tengiz and Korolev reservoirs to generate volumes required for the new SGP train, and reserves associated with the project were reclassified to the proved developed category. Over the next decade, ongoing field development is expected to result in the reclassification of additional proved undeveloped reserves to proved developed.

SGI involves taking a portion of the sour gas separated from the crude oil production at the SGP processing train and reinjecting it into the Tengiz reservoir. Chevron expects that SGI will have two key effects. First, SGI will reduce the sour gas processing capacity required at SGP, thereby increasing liquid production capacity and lowering the quantities of sulfur and gas that would otherwise be generated. Second, it is expected that over time SGI will increase production efficiency and recoverable volumes as the injected gas maintains higher reservoir pressure and displaces oil toward producing wells. Between 2007 and 2008, the company anticipates recognizing additional proved reserves associated with the SGI expansion. The primary SGI risks include uncertainties about compressor performance associated with injecting high-pressure sour gas and subsurface responses to injection.

Essentially all of TCO’s production is 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. CPC is seeking stockholder approval for an expansion to accommodate increased TCO volumes beginning in 2009. During 2006, TCO continued the construction of expanded rail car loading and rail export facilities, which is expected to be completed by third quarter 2007. As of early 2007, other alternatives were also being explored to increase export capacity prior to expansion of the CPC pipeline.

Venezuela: Chevron has a 30 percent interest in the Hamaca heavy oil production and upgrading project located in Venezuela’s Orinoco Belt. The crude oil upgrading began in late 2004. In 2005, the facility reached total design capacity of processing and upgrading 190,000 barrels per day of heavy crude oil (8.5 degrees API gravity) into 180,000 barrels of lighter, higher-value crude oil (26 degrees API gravity). In 2006, daily net production averaged 36,000 barrels of liquids and 8 million cubic feet of natural gas. In late February 2007, the President of Venezuela issued a decree announcing the government’s intention for the state-owned oil company, Petróleos de Venezuela S.A., to increase its ownership later this year in all Orinoco Heavy Oil Associations, including Chevron’s 30 percent-owned Hamaca project, to a minimum of 60 percent. The impact on Chevron from such an action is uncertain but is not expected to have a material effect on the company’s results of operations, consolidated financial position or liquidity.

The company operated the onshore Boscan Field for 10 years under an operating service agreement with Petróleos de Venezuela S.A. In October 2006, the contract was converted into a joint stock company, Petroboscan, in which Chevron is a 39 percent owner. At the same time, operatorship was transferred from Chevron to Petroboscan. No proved reserves had been recognized under the operating service agreement, but proved reserves associated with this new 20-year production contract were recorded in 2006. Under the operating service agreement, Boscan had average net production of 109,000 oil-equivalent barrels per day for the first nine months of 2006. Net production for the final three months of 2006 under the joint stock company was 30,000 oil-equivalent barrels per day.

The company operated the LL-652 Field for eight years under a risked-service agreement with a 63 percent interest until the contract was converted in October 2006 to a 25 percent-owned joint stock company, Petroindependiente. Under the new contract, Petroindependiente is the operator during the 20-year contract period. Located in Lake Maracaibo, LL-652’s net production averaged 3,000 barrels of liquids per day and 25 million cubic feet of natural gas per day during 2006. Chevron had previously booked reserves for LL-652 under the risked-service agreement.

Russia: In October 2006, Chevron signed a framework agreement with OAO Gazpromneft, establishing a Russian joint venture for exploration and development activities focused in the Yamal-Nenets region of Western Siberia. Chevron will maintain a 49 percent joint-operated interest in the venture. Refer to page 17 for a discussion of the company’s other activities in Russia.

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. Outside the United States, the majority of the company’s natural gas sales occur in Australia, Indonesia, Latin America, Thailand and the United Kingdom and in the company’s affiliate operations in Kazakhstan. International natural gas liquids sales take place in Africa, Australia and Europe. Refer to “Selected Operating Data,” on page FS-11 in Management’s Discussion and Analysis of Financial Condition and Results of Operations, for further information on the company’s natural gas and natural gas liquids sales volumes. Refer also to “Contract Obligations” on page 7 for information related to the company’s contractual commitments for the sale of crude oil and natural gas.

Downstream — Refining, Marketing and Transportation

Refining Operations

At the end of 2006, the company’s refining system consisted of 20 fuel refineries and an asphalt plant. The company operated nine of these facilities, and 12 were operated by affiliated companies.

The daily refinery inputs for 2004 through 2006 for the company and affiliate refineries are as follows:

Petroleum Refineries: Locations, Capacities and Inputs
(Inputs and Capacities in Thousands of Barrels per Day)


		December 31, 2006
				Operable		Refinery Inputs
Locations		Number		Capacity		2006		2005		2004

Pascagoula	Mississippi		1		330		337		263		312
El Segundo	California		1		260		258		230		234
Richmond	California		1		243		224		233		233
Kapolei	Hawaii		1		54		50		50		51
Salt Lake City	Utah		1		45		39		41		42
Other¹			1		80		31		28		42

Total Consolidated Companies — United States			6		1,012		939		845		914

Pembroke	United Kingdom		1		210		165		186		209
Cape Town²	South Africa		1		110		71		61		62
Burnaby, B.C.	Canada		1		55		49		45		49

Total Consolidated Companies — International			3		375		285		292		320
Affiliates³	Various Locations		12		834		765		746		724

Total Including Affiliates — International			15		1,209		1,050		1,038		1,044

Total Including Affiliates — Worldwide			21		2,221		1,989		1,883		1,958


1		Asphalt plants in Perth Amboy, New Jersey, and Portland, Oregon. The Portland plant was sold in February 2005.
2		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 2007.
3		Chevron acquired an 8 percent ownership interest in the SONARA refinery located in Limbe, Cameroon, in July 2006. This increased the company’s share of operable capacity by about 3,000 barrels per day.

Average crude oil distillation capacity utilization during 2006 was 90 percent, compared with 86 percent in 2005. In general, this increase resulted from less planned and unplanned downtime in 2006, due partly to downtime in 2005 that was attributable to hurricanes in the U.S. Gulf of Mexico. No downtime was caused by hurricanes in 2006. At the U.S. fuel refineries, crude oil distillation capacity utilization averaged 99 percent in 2006, compared with 90 percent in 2005, and cracking and coking capacity utilization averaged 86 percent and 76 percent in 2006 and 2005, respectively. Cracking and coking units, including fluid catalytic cracking units, are the primary facilities used in fuel refineries to convert heavier products into gasoline and other light products.

The company’s U.S. West Coast, Gulf Coast and Salt Lake refineries produce low-sulfur fuels that meet 2006 federal government specifications. Investments required to produce low-sulfur fuels in Europe, Canada, South Africa and Australia were completed in 2006. The company is evaluating alternatives for clean-fuel projects in its Southeast Asia refineries.

In 2006, the company completed an expansion of the Pascagoula, Mississippi, refinery’s Fluid Catalytic Cracking Unit to increase the production of gasoline and other light products. In addition, construction projects began at the El Segundo, California, refinery to increase heavy, sour crude oil processing capability and at the Pembroke, United Kingdom, refinery to increase the capability to process Caspian-blend crude oils. Completion of these projects is expected in 2007. Additional projects to upgrade the company’s refineries in Mississippi and California were being evaluated in early 2007.

Also in 2006, GS Caltex, the company’s 50 percent-owned affiliate, began construction of an upgrade project at the 650,000-barrel-per-day Yeosu refining complex in South Korea. At a total estimated cost of $1.5 billion, this project is designed to increase the yield of high-value refined products and reduce feedstock costs through the processing of heavy crude oil. Completion of the Yeosu project is expected in late 2007.

In April 2006, Chevron purchased a 5 percent interest in Reliance Petroleum Limited, a company formed by Reliance Industries Limited to own and operate a new export refinery being constructed in Jamnagar, India. The 580,000-barrel-per-day-crude-oil-capacity refinery is expected to begin operation in December 2008. Chevron has future rights to increase its equity ownership to 29 percent. The new refinery would be the world’s sixth largest on a single site.

Refer to page FS-2 for a discussion of the pending disposition of the company’s 31 percent interest in the Nerefco Refinery in the Netherlands.

Chevron processes imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 87 percent and 83 percent of Chevron’s U.S. refinery inputs in 2006 and 2005, respectively.

Gas-to-Liquids

The Sasol Chevron Global 50-50 Joint Venture was established in 2000 to develop a worldwide gas-to-liquids (GTL) business. Through this venture, the company is pursuing GTL opportunities in Qatar and other countries.

In Nigeria, Chevron Nigeria Limited and the Nigerian National Petroleum Corporation are developing a 34,000-barrel-per-day GTL facility at Escravos that will process natural gas supplied from the Phase 3A expansion of the Escravos Gas Plant (EGP). Plant construction began in 2005, and the first process modules are expected to be delivered to the site by the second half of 2007. The GTL plant is expected to be operational by the end of the decade. Refer also to page 15 for a discussion on the EGP Phase 3A expansion.

Marketing Operations

The company markets petroleum products throughout much of the world. The principal brands for identifying these products are “Chevron,” “Texaco” and “Caltex.”

The table on the following page shows the company’s and affiliates’ refined products sales volumes, excluding intercompany sales, for the three years ending December 31, 2006.

Refined Products Sales Volumes¹(Thousands of Barrels per Day)


	2006		2005		2004

United States
Gasolines		712		709		701
Jet Fuel		280		291		302
Gas Oils and Kerosene		252		231		218
Residual Fuel Oil		128		122		148
Other Petroleum Products²		122		120		137

Total United States		1,494		1,473		1,506

International⁴
Gasolines		595		662		715
Jet Fuel		266		258		250
Gas Oils and Kerosene		776		781		804
Residual Fuel Oil		324		404		458
Other Petroleum Products²		166		147		141

Total International³		2,127		2,252		2,368

Total Worldwide⁴		3,621		3,725		3,874


1 Includes buy/sell arrangements. Refer to Note 14 on page FS-43.	50	217	180
2 Principally naphtha, lubricants, asphalt and coke.
3 2005 and 2004 conformed to 2006 presentation.
4 Includes share of equity affiliates’ sales:	492	498	502

In the United States, the company markets under the Chevron and Texaco brands. The company supplies directly or through retailers and marketers almost 9,600 branded motor vehicle retail outlets, concentrated in the mid-Atlantic, southern and western states. Approximately 600 of the outlets are company-owned or -leased stations. By the end of 2006, the company was supplying more than 2,100 Texaco retail sites, primarily in the Southeast and West. All rights to the Texaco brand in the United States reverted to Chevron in July 2006.

Outside the United States, Chevron supplies directly or through retailers and marketers approximately 16,200 branded service stations, including affiliates, in about 75 countries. In British Columbia, Canada, the company markets under the Chevron brand. In Europe, the company has marketing operations under the Texaco brand primarily in the United Kingdom, Ireland, the Netherlands, Belgium and Luxembourg. In West Africa, the company operates or leases to retailers in Benin, Cameroon, Côte d’Ivoire, Nigeria, Republic of the Congo and Togo. In these countries, the company uses the Texaco brand. The company also operates across the Caribbean, Central America and South America, with a significant presence in Brazil, using the Texaco brand. In the Asia-Pacific region, southern, Central and East 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, using the GS Caltex brand. The company’s 50 percent-owned affiliate in Australia operates using the Caltex, Caltex Woolworths and Ampol brands. In Scandinavia, the company sold its 50 percent interest in the HydroTexaco joint venture in 2006.

The company continued the marketing and sale of service station sites, focusing on selected areas outside the United States. In 2006, the company sold its interest in more than 450 service stations, primarily in the United Kingdom and Latin America. Since the beginning of 2003, the company has sold its interests in nearly 2,800 service station sites. The vast majority of these sites will continue to market company-branded gasoline through new supply agreements.

The company also manages other marketing businesses globally. Chevron markets aviation fuel in approximately 75 countries, representing a worldwide market share of about 12 percent, and is the leading marketer of jet fuels in the United States. The company also markets an extensive line of lubricant and coolant products in about 175 countries under brand names that include Havoline, Delo, Ursa and Revtex.

Refer to page FS-2 for a discussion of the possible disposition of the company’s fuels marketing operations in the Netherlands, Belgium and Luxembourg regions.

Transportation Operations

Pipelines: Chevron owns and operates an extensive system of crude oil, refined products, chemicals, natural gas liquids and natural gas pipelines in the United States. The company also has direct or 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, 2006


	Net Mileage¹

United States:
Crude Oil²		2,884
Natural Gas		2,275
Petroleum Products³		6,932

Total United States		12,091
International:
Crude Oil²		714
Natural Gas		475
Petroleum Products³		421

Total International		1,610

Worldwide		13,701


1		Partially owned pipelines are included at the company’s equity percentage.
2		Includes gathering lines related to the transportation function. Excludes gathering lines related to the U.S. and international production activities.
3		Includes refined products, chemicals and natural gas liquids.

In the United States during 2006, the company completed the sale of three refined-product pipeline systems in Texas and New Mexico as well as its interest in the Windy Hill natural gas storage project in northeastern Colorado. By year-end 2006, work to restore the company’s Empire Terminal in Louisiana, which was damaged in the 2005 hurricanes, was substantially complete. During 2006, the company began a project to expand capacity at its Keystone natural gas storage facility by about 3 billion cubic feet to meet increased demand in the Permian Basin production region near the Waha Hub. The Waha Hub is a pricing point for natural-gas-basis swap-futures contracts traded on the New York Mercantile Exchange (NYMEX) and is located in West Texas south of the natural gas deposits in the San Juan and Permian Basins.

Chevron also has a 15 percent ownership interest in the Caspian Pipeline Consortium (CPC). CPC operates a crude oil export pipeline from the Tengiz Field in Kazakhstan to the Russian Black Sea port of Novorossiysk. At the end of 2006, CPC had transported an average of 664,000 barrels of crude oil per day, including 519,000 barrels per day from the Caspian region and 145,000 barrels per day from Russia.

In addition, the company has a 9 percent equity interest in the Baku-Tbilisi-Ceyhan (BTC) pipeline, which transports Azerbaijan International Operating Company (AIOC) production from Baku, Azerbaijan, through Georgia to deepwater port facilities in Ceyhan, Turkey. Chevron holds a 10 percent nonoperated working interest in AIOC. The first tanker loading at the Ceyhan marine terminal on the Mediterranean Sea occurred in June 2006. The pipeline has a crude oil capacity of 1 million barrels per day and is expected to accommodate the majority of the AIOC production. Another crude oil production export route is the 515-mile Baku-Supsa pipeline, wholly owned by AIOC, with crude oil capacity to transport 145,000 barrels per day from Baku, Azerbaijan, to the terminal at Supsa, Georgia.

For information on projects under way related to the Chad/Cameroon pipeline, the West African Gas Pipeline and the expansion of the CPC pipeline, refer to pages 13, 15 and 23, respectively.

Tankers: At any given time during 2006, the company had approximately 70 vessels chartered on a voyage basis or for a period of less than one year. Additionally, all tankers in Chevron’s controlled seagoing fleet were utilized during 2006. The following table summarizes cargo transported on the company’s controlled fleet.

Controlled Tankers at December 31, 2006


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

Owned		3		0.8		1		1.1
Bareboat Chartered		—		—		18		27.4
Time Chartered*		—		—		22		11.5

Total		3		0.8		41		40.0


*	One year or more.

Federal law requires that cargo transported between U.S. ports be carried in ships built and registered in the United States, owned and operated by U.S. entities, and manned by U.S. crews. At year-end 2006, the company’s U.S. flag fleet was engaged primarily in transporting refined products between the Gulf Coast and the East Coast and from California refineries to terminals on the West Coast and in Alaska and Hawaii. During the year, the company contracted for the building of four U.S. flagged product tankers, each capable of carrying 300,000 barrels of cargo. These tankers are scheduled for delivery from 2007 through 2010 and are intended to replace the existing three U.S. flag ships.

The international flag vessels were engaged primarily in transporting crude oil from the Middle East, Asia, Black Sea, Mexico and West Africa to ports in the United States, Europe, Australia and Asia. Refined products were also transported by tanker worldwide. During 2006, the company took delivery of two new double-hulled tankers with a total capacity of 2.5 million barrels and terminated the lease on its last single-hulled vessel.

In addition to the vessels described above, the company owns a one-sixth interest in each of seven liquefied natural gas (LNG) tankers transporting cargoes for the North West Shelf (NWS) project in Australia. Additionally, the NWS project has two LNG tankers under long-term time charter. In 2005, Chevron placed orders for two additional LNG tankers to support expected growth in the company’s LNG business. These carriers are planned to be delivered in 2009.

The Federal Oil Pollution Act of 1990 requires the scheduled phase-out by year-end 2010 of all single-hull tankers trading to U.S. ports or transferring cargo in waters within the U.S. Exclusive Economic Zone. This has raised the demand for double-hull tankers. At the end of 2006, 100 percent of the company’s owned and bareboat-chartered fleet was double-hulled. The company is a member of many oil-spill-response cooperatives in areas around the world in which it operates.

Chemicals

Chevron Phillips Chemical Company LLC (CPChem) is equally owned with ConocoPhillips Corporation. At the end of 2006, CPChem owned or had joint venture interests in 30 manufacturing facilities and six research and technical centers in the United States, Puerto Rico, Belgium, China, Saudi Arabia, Singapore, South Korea and Qatar.

In 2006, construction progressed on CPChem’s integrated, world-scale styrene facility in Al Jubail, Saudi Arabia. Jointly owned with the Saudi Industrial Investment Group (SIIG), the project’s operational start-up is anticipated in late 2007. The styrene facility is located adjacent to CPChem and SIIG’s existing aromatics complex in Al Jubail. Also during the year, CPChem continued development of plans for a third petrochemical project in Al Jubail. Preliminary studies are focused on the construction of a world-scale olefins unit, as well as related downstream units, to produce polyethylene, polypropylene, 1-hexene and polystyrene.

In addition, construction continued on the Q-Chem II project in 2006. The Q-Chem II project includes a 350,000-metric-ton-per-year polyethylene plant and a 345,000-metric-ton-per-year normal alpha olefins plant — each utilizing CPChem proprietary technology — and is located adjacent to the existing Q-Chem I complex in Mesaieed, Qatar. The Q-Chem II project also includes a separate joint venture to develop a 1.3-million-metric-ton-per-year ethylene cracker at Qatar’s Ras Laffan Industrial City, in which Q-Chem II owns 54 percent of the capacity rights. CPChem and its partners expect to start up the plants in early 2009. CPChem owns a 49 percent interest in Q-Chem II.

Chevron’s Oronite brand fuel and lubricant additives business is a leading developer, manufacturer and marketer of performance additives for fuels and lubricating oils. The company owns and operates facilities in the United States, Brazil, France, Japan, the Netherlands and Singapore and has equity interests in facilities in India and Mexico.

Oronite provides additives for lubricating oil in most engine applications, such as passenger car, heavy-duty diesel, marine, locomotive and motorcycle engines, and additives for fuels to improve engine performance and extend engine life.

Other Businesses

Mining

Chevron’s mining companies in the United States produce and market coal, molybdenum, rare earth minerals and calcined petroleum coke. Sales occur in both U.S. and international markets.

The company’s coal mining and marketing subsidiary, The Pittsburg & Midway Coal Mining Co. (P&M), owns and operates two surface mines, McKinley, in New Mexico, and Kemmerer, in Wyoming, and one underground mine, North River, in Alabama. Sales of coal from P&M’s wholly owned mines were 12.6 million tons, down 1.0 million tons from 2005. Final reclamation activities continued in 2006 at the Farco surface mine in Texas.

At year-end 2006, P&M controlled approximately 225 million tons of proven and probable coal reserves in the United States, including reserves of environmentally desirable low-sulfur coal. The company is contractually committed to deliver between 11 million and 12 million tons of coal per year through the end of 2009 and believes it will satisfy these contracts from existing coal reserves.

Molycorp Inc. is the company’s mining and marketing subsidiary for molybdenum and rare earth minerals. Molycorp owns and operates the Questa molybdenum mine in New Mexico and the Mountain Pass lanthanides mine in California. In addition, the company owns a 33 percent interest in Sumikin Molycorp, a manufacturer of neodymium compounds, located in Japan. During 2006, Molycorp performed environmental remediation activities at Questa and Mountain Pass, and at its closed rare-earth processing facility in Pennsylvania. The company’s 35 percent interest in Companhia Brasileira de Metalurgia e Mineracao, a producer of niobium in Brazil, was sold in 2006.

At year-end 2006, Molycorp controlled approximately 60 million pounds of proven molybdenum reserves at Questa and 240 million pounds of proven and probable lanthanide reserves at Mountain Pass.

The company also owns the Chicago Carbon Company, a producer and marketer of calcined petroleum coke, which operates a 250,000-ton-per-year petroleum coke calciner facility in Lemont, Illinois.

Global Power Generation

Chevron’s Global Power Generation (GPG) business has more than 20 years experience in developing and operating commercial power projects and owns 15 power assets located in the United States and Asia. GPG manages the production of more than 2,334 megawatts of electricity at 11 facilities it owns through joint ventures. The company operates gas-fired cogeneration facilities that use waste heat recovery to produce additional electricity or to support industrial thermal hosts. A number of the facilities produce steam for use in upstream operations to facilitate production of heavy oil.

The company has major geothermal operations in Indonesia and the Philippines and is investigating several advanced solar technologies for use in oil field operations as part of its renewable energy strategy. For additional information on the company’s geothermal operations and renewable energy projects, refer to pages 19 and 30, respectively.

In September 2006, the company sold its interest in the 8-megawatt Amada Rayong power generation facility in Thailand.

Chevron Energy Solutions

Chevron Energy Solutions (CES) is a wholly owned subsidiary that provides public institutions and businesses with projects designed to increase energy efficiency and reliability, reduce energy costs and utilize renewable and alternative power technologies. CES has energy-saving projects installed in more than a thousand buildings nationwide. Major

projects completed by CES in 2006 include energy efficiency and renewable power installations for U.S. Postal Service facilities, the first megawatt-class hydrogen fuel cell cogeneration plant in California, and cogeneration and biomass facilities for a municipal water pollution control plant.

Research and Technology

The company’s Energy Technology Company supports Chevron’s upstream and downstream businesses with technologies that span the hydrocarbon value chain from exploration to refining and marketing.

The Technology Ventures Company identifies, grows and commercializes emerging technologies with the potential to transform energy production and use. The business development portfolio includes biofuels, hydrogen infrastructure, advanced batteries, nano-materials and renewable energy applications.

In the second quarter 2006, the company completed the acquisition of a 22 percent interest in Galveston Bay Biodiesel L.P., which is building one of the first large-scale biofuel plants in the United States. During 2006, the company also entered into research alliances with the University of California, Davis and the Georgia Institute of Technology. Both are focused on converting cellulosic biomass into viable transportation fuels.

Chevron’s research and development expenses were $468 million, $316 million and $242 million for the years 2006, 2005 and 2004, respectively.

Some of the investments the company makes in the areas described above are in new or unproven technologies and business processes, and ultimate successes are not certain. Although not all initiatives may prove to be economically viable, the company’s overall investment in this area is not significant to the company’s consolidated financial position.

Environmental Protection

Virtually all aspects of the company’s businesses are subject to various U.S. federal, state and local environmental, health and safety laws and regulations, and similar laws and regulations in other countries. These regulatory requirements continue to change and increase in both number and complexity and to govern not only the manner in which the company conducts its operations, but also the products it sells. Chevron expects more environmental-related regulations in the countries where it has operations. Most of the costs of complying with the many laws and regulations pertaining to its operations are embedded in the normal costs of conducting business.

In 2006, the company’s U.S. capitalized environmental expenditures were $385 million, representing approximately 7 percent of the company’s total consolidated U.S. capital and exploratory expenditures. These environmental expenditures include capital outlays to retrofit existing facilities as well as those associated with new facilities. The expenditures are predominantly in the upstream and downstream segments and relate mostly to air- and water-quality projects and activities at the company’s refineries, oil and gas producing facilities, and marketing facilities. For 2007, the company estimates U.S. capital expenditures for environmental control facilities will be approximately $350 million. The future annual capital costs of fulfilling this commitment are uncertain and will be governed by several factors, including future changes to regulatory requirements.

Further information on environmental matters and their impact on Chevron and on the company’s 2006 environmental expenditures, remediation provisions and year-end environmental reserves are contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages FS-17 through FS-19 of this Annual Report on Form 10-K.

Web Site Access to SEC Reports

The company’s Internet Web site can be found at http://www.chevron.com/. Information contained on the company’s Internet Web site is not part of this Annual Report on Form 10-K.

The company’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available on the company’s Web site soon after such reports are filed with or furnished to the Securities and Exchange Commission (SEC). Alternatively, you may access these reports at the SEC’s Internet Web site: http://www.sec.gov/.

Item 1A. Risk Factors

Chevron is a major fully integrated petroleum company with a diversified business portfolio, strong balance sheet, and a history of generating sufficient cash to fund capital and exploratory expenditures and to pay dividends. Nevertheless, some inherent risks could materially impact the company’s financial results of operations or financial condition.

Chevron is exposed to the effects of changing commodity prices.

Chevron is primarily in a commodities business with a history of price volatility. The single largest variable that affects the company’s results of operations is crude oil prices. Except in the ordinary course of running an integrated petroleum business, Chevron does not seek to hedge its exposure to price changes. A significant, persistent decline in crude oil prices may have a material adverse effect on its results of operations and its capital and exploratory expenditure plans.

The scope of Chevron’s business will decline if the company does not successfully develop resources.

The company is in an extractive business; therefore, if Chevron is not successful in replacing the crude oil and natural gas it produces with good prospects for future production, the company’s business will decline. Creating and maintaining an inventory of projects depends on many factors, including obtaining rights to explore, develop and produce hydrocarbons in promising areas; drilling success; ability to bring long-lead-time, capital-intensive projects to completion on budget and schedule; and efficient and profitable operation of mature properties.

The company’s operations could be disrupted by natural or human factors.

Chevron operates in both urban areas and remote and sometimes inhospitable regions. The company’s operations and facilities are therefore subject to disruption from either natural or human causes, including hurricanes, floods and other forms of severe weather, war, civil unrest and other political events, fires, earthquakes, and explosions, any of which could result in suspension of operations or harm to people or the natural environment.

Chevron’s business subjects the company to liability risks.

The company produces, transports, refines and markets materials with potential toxicity, and it purchases, handles and disposes of other potentially toxic materials in the course of the company’s business. Chevron operations also produce by-products, which may be considered pollutants. Any of these activities could result in liability, either as a result of an accidental, unlawful discharge or as a result of new conclusions on the effects of the company’s operations on human health or the environment.

Political instability could harm Chevron’s business.

The company’s operations, particularly exploration and production, can be affected by changing economic, regulatory and political environments in the various countries in which it operates. As has occurred in the past, actions could be taken by governments to increase public ownership of the company’s partially or wholly owned businesses and/or to impose additional taxes or royalties.

In certain locations, governments have imposed restrictions, controls and taxes, and in others, political conditions have existed that may threaten the safety of employees and the company’s continued presence in those countries. Internal unrest, acts of violence or strained relations between a government and the company or other governments may affect the company’s operations. Those developments have, at times, significantly affected the company’s related operations and results and are carefully considered by management when evaluating the level of current and future activity in such countries. At December 31, 2006, 24 percent of the company’s proved reserves were located in Kazakhstan. The company also has significant interests in Organization of Petroleum Exporting Countries (OPEC)-member countries including Indonesia, Nigeria and Venezuela. Approximately 25 percent of the company’s net proved reserves, including affiliates, were located in OPEC countries at December 31, 2006. In December 2006, OPEC admitted Angola as a new member effective January 1, 2007. Oil-equivalent reserves at the end of 2006 in Angola represented 5 percent of the company’s total.

Regulation of greenhouse gas emissions could increase Chevron’s operational costs and reduce demand for Chevron’s products.

Management believes it is reasonably likely that the scientific and political attention to issues concerning the existence and extent of climate change, and the role of human activity in it, will continue, with the potential for further regulation that affects the company’s operations. Although uncertain, these developments could increase costs or reduce

the demand for the products the company sells. The company’s production and processing operations (e.g., the production of crude oil at offshore platforms and the processing of natural gas at liquefied natural gas facilities) typically result in emissions of greenhouse gases. Likewise, emissions arise from midstream and downstream operations, including crude oil transportation and refining. Finally, although beyond the control of the company, the use of passenger vehicle fuels and related products by consumers also results in these emissions.

International agreements, domestic legislation and regulatory measures to limit greenhouse gas emissions are currently in various phases of discussion or implementation. These include the Kyoto Protocol, proposed federal legislation and current state-level actions. Some of the countries in which Chevron operates have ratified the Kyoto Protocol, and the company is currently complying with greenhouse gas emissions limits within the European Union. Although resolutions supporting “cap and trade” systems have been introduced in the U.S. Congress, no bill restricting greenhouse gas emissions has been passed to date.

In California, the Global Warming Solutions Act became effective on January 1, 2007. This law caps California’s greenhouse gas emissions at 1990 levels by 2020; directs the Air Resources Board, the responsible state agency, to determine greenhouse gas emissions in and outside California to adopt mandatory reporting rules for significant sources of greenhouse gases; delegates to the agency the authority to adopt compliance mechanisms (including market-based approaches); and permits a one-year extension of the targets under extraordinary circumstances. Related regulatory activity is under way within the California Public Utilities Commission. The company extracts crude oil and natural gas, operates refineries, and markets and sells gasoline in California. It is not known at this time whether or to what extent the state agencies’ regulations will affect the company’s California operations.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

The location and character of the company’s crude oil, natural gas and mining properties and its refining, marketing, transportation and chemicals facilities are described above under Item 1. Business. Information required by the Securities Exchange Act Industry Guide No. 2 (“Disclosure of Oil and Gas Operations”) is also contained in Item 1 and in Tables I through VII on pages FS-63 to FS-76 of this Annual Report on Form 10-K. Note 13, “Properties, Plant and Equipment,” to the company’s financial statements is on page FS-43 of this Annual Report on Form 10-K.

Item 3. Legal Proceedings

Chevron’s U.S. refineries are implementing a consent decree with the federal Environmental Protection Agency (EPA) and four state air agencies to resolve claims about Chevron’s past application of “New Source Review” permitting programs under the Clean Air Act. The consent decree provides that Chevron will pay stipulated penalties for certain violations of the consent decree, if demand is made by the EPA. In July 2006, Chevron’s refinery in Pascagoula, Mississippi exceeded its emission limit under the consent decree for particulate matter. The exceedance was reported at the time and the possibility of a penalty was discussed. In January 2007, the Mississippi Department of Environmental Quality (MDEQ) and the EPA issued a notice of violation and a request for payment of $210,000 in stipulated penalties for the July 2006 particulate matter exceedance. The company, the EPA and the MDEQ are in negotiation with regard to the nature and amount of the penalty demand.

Item 4. Submission of Matters to a Vote of Security Holders

None.

Executive Officers of the Registrant at February 28, 2007


Name and Age		Executive Office Held	Major Area of Responsibility

D.J. O’Reilly	60	Chairman of the Board since 2000 Director since 1998 Vice Chairman from 1998 to 2000 President of Chevron Products Company from 1994 to 1998 Executive Committee Member since 1994	Chief Executive Officer
P.J. Robertson	60	Vice Chairman of the Board since 2002 Vice President from 1994 to 2001 President of Chevron Overseas Petroleum Inc. from 2000 to 2002 Executive Committee Member since 1997	Strategic Planning; Policy, Government and Public Affairs; Human Resources
J.E. Bethancourt	55	Executive Vice President since 2003 Executive Committee Member since 2003	Technology; Chemicals; Coal; Health, Environment and Safety
G.L. Kirkland	56	Executive Vice President since 2005 President of Chevron Overseas Petroleum Inc. from 2002 to 2004 Vice President from 2000 to 2004 President of Chevron U.S.A. Production Company from 2000 to 2002 Executive Committee Member from 2000 to 2001 and since 2005	Worldwide Exploration and Production Activities and Global Gas Activities, including Natural Gas Trading
M.K. Wirth	46	Executive Vice President, effective March 1, 2006 President of Global Supply and Trading from 2004 to 2006 Executive Committee Member since 2006	Global Refining, Marketing, Lubricants, and Supply and Trading, excluding Natural Gas Trading
S.J. Crowe	59	Vice President and Chief Financial Officer since 2005 Vice President and Comptroller from 2000 through 2004 Comptroller from 1996 to 2000 Executive Committee Member since 2005	Finance
C.A. James	52	Vice President and General Counsel since 2002 Executive Committee Member since 2002	Law
J.S. Watson	50	Vice President and President of Chevron International Exploration and Production Company since 2005 Vice President and Chief Financial Officer from 2000 through 2004 Executive Committee Member from 2000 to 2004	International Exploration and Production
G.P. Luquette	51	Vice President and President, Chevron North America Exploration and Production Company since 2006	North American Exploration and Production

The Executive Officers of the Corporation consist of the Chairman of the Board, the Vice Chairman of the Board, and such other officers of the Corporation who are either Directors or members of the Executive Committee or who are chief executive officers of principal business units. Except as noted below, all of the Corporation’s Executive Officers have held one or more of such positions for more than five years.



J.E. Bethancourt	-	Vice President, Texaco Inc., President of Production Operations, Worldwide Exploration and Production, Texaco Inc. — 2000
	-	Vice President, Human Resources, Chevron Corporation — 2001
	-	Executive Vice President, Chevron Corporation — 2003

C.A. James	-	Partner, Jones Day (a major U.S. law firm) — 1992
	-	Assistant Attorney General, Antitrust Division, U.S. Department of Justice — 2001
	-	Vice President and General Counsel — 2002

G.P. Luquette	-	Vice President, San Joaquin Valley Business Unit, Chevron North America Exploration and Production — 2001
	-	President and Managing Director, Chevron Upstream Europe — 2003
	-	Vice President and President, Chevron North America Exploration and Production — 2006

M.K. Wirth	-	General Manager, U.S. Retail Marketing, Chevron Products Company — 1999
	-	President, Marketing, Caltex Corporation — 2000
	-	President, Marketing, Asia, Middle East and Africa Marketing Business Unit, Chevron Corporation — 2001
	-	President, Global Supply and Trading — 2004
	-	Executive Vice President, Chevron Corporation — 2006

PART II

Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

The information on Chevron’s common stock market prices, dividends, principal exchanges on which the stock is traded and number of stockholders of record is contained in the Quarterly Results and Stock Market Data tabulations, on page FS-24 of this Annual Report on Form 10-K.

CHEVRON CORPORATION

ISSUER PURCHASES OF EQUITY SECURITIES

Maximum

Total Number of

Number of Shares

Total Number

Average

Shares Purchased as

that May Yet Be

of Shares

Price Paid

Part of Publicly

Purchased Under

Period

Purchased ⁽¹⁾⁽²⁾

per Share

Announced Program

the Program

Oct. 1 – Oct. 31, 2006

6,888,498

64.33

6,647,000

—

Nov. 1 – Nov. 30, 2006

11,568,904

69.53

11,115,500

—

Dec. 1 – Dec. 31, 2006

1,512,735

74.68

1,336,000

—

Total Oct. 1 – Dec. 31, 2006

19,970,137

68.13

19,098,500

)


(1)	Includes 116,630 common shares repurchased during the three-month period ended December 31, 2006, from company employees for required personal income tax withholdings on the exercise of the stock options issued to management and employees under the company’s broad-based employee stock options, long-term incentive plans and former Texaco Inc. stock option plans. Also includes 755,007 shares delivered or attested to in satisfaction of the exercise price by holders of certain former Texaco Inc. employee stock options exercised during the three-month period ended December 31, 2006.

(2)	In December 2005, the company announced a $5 billion common stock repurchase program. The program was completed on November 30, 2006, at which time 80,260,800 shares had been repurchased for a total of $5 billion.

In December 2006, the company authorized stock repurchases of up to $5 billion that may be made from time to time at prevailing prices as permitted by securities laws and other requirements and subject to market conditions and other factors. The program will occur over a period of up to three years and may be discontinued at any time. As of December 31, 2006, 1,336,000 shares had been acquired under this program for $100 million.

Item 6. Selected Financial Data

The selected financial data for years 2002 through 2006 are presented on page FS-62 of this Annual Report on Form 10-K.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The index to Management’s Discussion and Analysis, Consolidated Financial Statements and Supplementary Data is presented on page FS-1 of this Annual Report on Form 10-K.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The company’s discussion of interest rate, foreign currency and commodity price market risk is contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations — “Financial and Derivative Instruments,” beginning on page FS-15 and in Note 7 to the Consolidated Financial Statements, “Financial and Derivative Instruments,” beginning on page FS-37.

Item 8. Financial Statements and Supplementary Data

The index to Management’s Discussion and Analysis, Consolidated Financial Statements and Supplementary Data is presented on page FS-1 of this Annual Report on Form 10-K.

Item 9. Changes in and Disagreements With Auditors on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures

Chevron Corporation’s Chief Executive Officer and Chief Financial Officer, after evaluating the effectiveness of the company’s “disclosure controls and procedures” (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)), as of December 31, 2006, have concluded that as of December 31, 2006, the company’s disclosure controls and procedures were effective and designed to provide reasonable assurance that material information relating to the company and its consolidated subsidiaries required to be included in the company’s periodic filings under the Exchange Act would be made known to them by others within those entities.

(b) Management’s Report on Internal Control Over Financial Reporting

The company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). The company’s management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of its internal control over financial reporting based on the Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the results of this evaluation, the company’s management concluded that its internal control over financial reporting was effective as of December 31, 2006.

The company management’s assessment of the effectiveness of its internal control over financial reporting as of December 31, 2006, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report that is included on page FS-26 of this Annual Report on Form 10-K.

During the quarter ended December 31, 2006, there were no changes in the company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the company’s internal control over financial reporting.

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information on Directors appearing under the heading “Election of Directors — Nominees For Directors” in the Notice of the 2007 Annual Meeting of Stockholders and 2007 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), in connection with the company’s 2007 Annual Meeting of Stockholders (the “2007 Proxy Statement”), is incorporated by reference in this Annual Report on Form 10-K. See Executive Officers of the Registrant on pages 33 and 34 of this Annual Report on Form 10-K for information about Executive Officers of the company.

The information contained under the heading “Stock Ownership Information — Section 16(a) Beneficial Ownership Reporting Compliance” in the 2007 Proxy Statement is incorporated by reference in this Annual Report on Form 10-K.

The information contained under the heading “Board Operations — Business Conduct and Ethics Code” in the 2007 Proxy Statement is incorporated by reference in this Annual Report on Form 10-K.

The company has a separately designated standing Audit Committee established in accordance with Section 3(a)(58)(A) of the Exchange Act. The members of the Audit Committee are Charles R. Shoemate (Chairperson), Linnet F. Deily, Robert E. Denham and Franklyn G. Jenifer, all of whom are independent under the New York Stock Exchange Corporate Governance Rules. Of these Audit Committee members, Charles R. Shoemate, Linnet F. Deily and Robert E. Denham are audit committee financial experts as determined by the Board within the applicable definition of the SEC.

There were no changes to the process by which stockholders may recommend nominees to the Board of Directors during the last fiscal year.

Item 11. Executive Compensation

The information appearing under the headings “Executive Compensation” and “Directors’ Compensation” in the 2007 Proxy Statement is incorporated herein by reference in this Annual Report on Form 10-K.

“The members of the Compensation Committee of the Board of Directors during the last fiscal year were Carla A. Hills (until her retirement on April 26, 2006), Robert J. Eaton, Samuel H. Armacost, Ronald D. Sugar and Carl Ware, none of whom is a present or former officer or employee of the company. In addition, during 2006, no officers had an “interlock” relationship, as that term is defined by the SEC, to report.”

The information appearing under the heading “Management Compensation Committee Report” in the 2007 Proxy Statement is incorporated herein by reference in this Annual Report on Form 10-K. Pursuant to the rules and regulations of the SEC under the Exchange Act, the information under such caption incorporated by reference from the 2007 Proxy Statement shall not be deemed “filed” for purposes of Section 18 of the Exchange Act nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information appearing under the heading “Stock Ownership Information — Security Ownership of Certain Beneficial Owners and Management” in the 2007 Proxy Statement is incorporated by reference in this Annual Report on Form 10-K.

The information contained under the heading “Equity Compensation Plan Information” in the 2007 Proxy Statement is incorporated by reference in this Annual Report on Form 10-K.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information appearing under the heading “Board Operations” in the 2007 Proxy Statement is incorporated by reference in this Annual Report on Form 10-K.

Item 14. Principal Accounting Fees and Services

The information appearing under the headings “Ratification of Independent Registered Public Accounting Firm — Principal Accountant Fees and Services” and “Ratification of Independent Registered Public Accounting Firm — Audit Committee Pre-Approval Policies and Procedures” in the 2007 Proxy Statement is incorporated by reference in this Annual Report on Form 10-K.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 28th day of February, 2007.

Chevron Corporation


	By	/s/ David J. O’Reilly

David J. O’Reilly, Chairman of the Board

and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on the 28th day of February, 2007.


Principal Executive Officers
(and Directors)		Directors

/s/David J. O’Reilly David J. O’Reilly, Chairman of the Board and Chief Executive Officer		Samuel H. Armacost* Samuel H. Armacost

/s/Peter J. Robertson Peter J. Robertson, Vice Chairman of the Board		Linnet F. Deily* Linnet F. Deily

		Robert E. Denham* Robert E. Denham

		Robert J. Eaton* Robert J. Eaton

Principal Financial Officer		Sam Ginn* Sam Ginn

/s/Stephen J. Crowe Stephen J. Crowe, Vice President and Chief Financial Officer		Franklyn G. Jenifer* Franklyn G. Jenifer

Principal Accounting Officer

/s/Mark A. Humphrey Mark A. Humphrey, Vice President and Comptroller		Sam Nunn* Sam Nunn

		Donald B. Rice* Donald B. Rice

*By: /s/Lydia I. Beebe Lydia I. Beebe, Attorney-in-Fact		Charles R. Shoemate* Charles R. Shoemate

		Ronald D. Sugar* Ronald D. Sugar

		Carl Ware* Carl Ware

INDEX TO MANAGEMENT’S DISCUSSION AND ANALYSIS,
CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

KEY FINANCIAL RESULTS


Millions of dollars, except per-share amounts	2006			2005			2004

Net Income	$	17,138		$	14,099		$	13,328
Per Share Amounts:
Net Income – Basic	$	7.84		$	6.58		$	6.30
– Diluted	$	7.80		$	6.54		$	6.28
Dividends	$	2.01		$	1.75		$	1.53
Sales and Other Operating Revenues	$	204,892		$	193,641		$	150,865
Return on:
Average Capital Employed		22.6	%		21.9	%		25.8	%
Average Stockholders’ Equity		26.0	%		26.1	%		32.7	%

INCOME FROM CONTINUING OPERATIONS BY MAJOR
OPERATING AREA


Millions of dollars	2006			2005			2004

Income From Continuing Operations
Upstream – Exploration and Production
United States	$	4,270		$	4,168		$	3,868
International		8,872			7,556			5,622

Total Upstream		13,142			11,724			9,490

Downstream – Refining, Marketing and Transportation
United States		1,938			980			1,261
International		2,035			1,786			1,989

Total Downstream		3,973			2,766			3,250

Chemicals		539			298			314
All Other		(516	)		(689	)		(20	)

Income From Continuing Operations	$	17,138		$	14,099		$	13,034
Income From Discontinued Operations – Upstream		–			–			294

Net Income*	$	17,138		$	14,099		$	13,328

^*Includes Foreign Currency Effects:		$(219)			$(61)			$(81)

Refer to the “Results of Operations” section beginning on page FS-6 for a detailed discussion of financial results by major operating area for the three years ending December 31, 2006.

BUSINESS ENVIRONMENT AND OUTLOOK

Chevron’s current and future earnings depend largely on the profitability of its upstream (exploration and production) and downstream (refining, marketing and transportation) business segments. The single biggest factor that affects the results of operations for both segments is movement in the price of crude oil. In the downstream business, crude oil is the largest cost component of refined products. The overall trend in earnings is typically less affected by results from the company’s chemicals business and other activities and investments. Earnings for the company in any period may also be influenced by events or transactions that are infrequent and/ or unusual in nature. Chevron and the oil and gas industry at large are currently experiencing an increase in certain costs that exceeds the general trend of inflation in many areas of the world. This increase in costs is affecting the company’s

operating expenses for all business segments and capital expenditures, particularly for the upstream business.

To sustain its long-term competitive position in the upstream business, the company must develop and replenish an inventory of projects that offer adequate financial returns for the investment required. Identifying promising areas for exploration, acquiring the necessary rights to explore for and to produce crude oil and natural gas, drilling successfully, and handling the many technical and operational details in a safe and cost-effective manner are all important factors in this effort. Projects often require long lead times and large capital commitments. Changes in economic, legal or political circumstances can have significant effects on the profitability of a project over its expected life. In the current environment of higher commodity prices, certain governments have sought to renegotiate contracts or impose additional costs on the company. Other governments may attempt to do so in the future. The company will continue to monitor these developments, take them into account in evaluating future investment opportunities, and otherwise seek to mitigate any risks to the company’s current operations or future prospects. In late February 2007, the President of Venezuela issued a decree announcing the government’s intention for the state-owned oil company, Petróleos de Venezuela S.A., to increase its ownership later this year in all Orinoco Heavy Oil Associations, including Chevron’s 30 percent-owned Hamaca project, to a minimum of 60 percent. The impact on Chevron from such an action is uncertain but is not expected to have a material effect on the company’s results of operations, consolidated financial position or liquidity.

The company also continually evaluates opportunities to dispose of assets that are not key to providing sufficient long-term value, or to acquire assets or operations complementary to its asset base to help augment the company’s growth. During the first quarter 2007, the company authorized the sale of its 31 percent ownership interest in the Nerefco Refinery and the associated TEAM Terminal in the Netherlands. The transaction is subject to signing of the sales agreement and obtaining necessary regulatory approvals. The company expects to record a gain upon close of the sale. In early 2007, the company was also in discussions regarding the possible sale of its fuels marketing operations in the Netherlands, Belgium and Luxembourg. Neither the refining nor marketing assets were classified as held-for-sale as of December 31, 2006, in accordance with the held-for-sale criteria of Financial Accounting Standards Board (FASB) Statement No. 144, Impairment or Disposal of Long-Lived Assets. Other asset dispositions and restructurings may occur in future periods and could result in significant gains or losses.

Comments related to earnings trends for the company’s major business areas are as follows:

Upstream Earnings for the upstream segment are closely aligned with industry price levels for crude oil and natural gas. Crude oil and natural gas prices are subject to external factors over which the company has no control, including product demand connected with global economic conditions, industry inventory levels, production quotas imposed by the Organization of Petroleum Exporting Countries (OPEC), weather-related damage and disruptions, competing fuel prices, and regional supply interruptions that may be caused by military conflicts, civil unrest or political uncertainty.

Moreover, any of these factors could also inhibit the company’s production capacity in an affected region. The company monitors developments closely in the countries in which it operates and holds investments, and attempts to manage risks in operating its facilities and business.

Price levels for capital and exploratory costs and operating expenses associated with the efficient production of crude oil and natural gas can also be subject to external factors beyond the company’s control. External factors include not

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only the general level of inflation, but also prices charged by the industry’s product- and service-providers, which can be affected by the volatility of the industry’s own supply and demand conditions for such products and services. The oil and gas industry worldwide experienced significant price increases for these items during 2005 and 2006, and an upward trend in prices may continue into 2007. Capital and exploratory expenditures and operating expenses also can be affected by uninsured damages to production facilities caused by severe weather or civil unrest.

Industry price levels for crude oil generally increased in the first half of 2006 and declined in the second half. Prices at the end of 2006 were slightly lower than at the beginning of the year. The spot price for West Texas Intermediate (WTI) crude oil, a benchmark crude oil, averaged $66 per barrel in 2006, an increase of approximately $9 per barrel from the 2005 average price. The rise in crude oil prices between years reflected, among other things, increasing demand in growing economies, the heightened level of geopolitical uncertainty in some areas of the world and supply concerns in other key producing regions. For early 2007 into late February, the WTI spot price averaged about $56 per barrel.

As was the case in 2005, a wide differential in prices existed in 2006 between high-quality, light-sweet crude oils (such as the U.S. benchmark WTI) and heavier types of crude. The price for the heavier crudes has been dampened because of ample supply and lower relative demand due to the limited number of refineries that are able to process this lower-quality feedstock into light products (i.e., motor gasoline, jet fuel, aviation gasoline and diesel fuel). The price

for higher-quality, light-sweet crude oil has remained high, as the demand for light products, which can be more easily manufactured by refineries from light-sweet crude oil, has been strong worldwide. Chevron produces heavy crude oil in California, Chad, Indonesia, the Partitioned Neutral Zone between Saudi Arabia and Kuwait, Venezuela and in certain fields in Angola, China and the United Kingdom North Sea. (Refer to page FS-11 for the company’s average U.S. and international crude oil prices.)

In contrast to price movements in the global market for crude oil, price changes for natural gas are more closely aligned with regional supply and demand conditions. In the United States during 2006, benchmark prices at Henry Hub averaged about $6.50 per thousand cubic feet (MCF), compared with about $8 in 2005. For early 2007 into late February, prices averaged about $7 per MCF. Fluctuations in the price for natural gas in the United States are closely associated with the volumes produced in North America and the inventory in underground storage relative to customer demand. Natural gas prices in the United States are also typically higher during the winter period when demand for heating is greatest.

In contrast to the United States, certain other regions of the world in which the company operates have different supply, demand and regulatory circumstances, typically resulting in significantly lower average sales prices for the company’s production of natural gas. (Refer to page FS-11 for the company’s average natural gas prices for the United States and international regions.) Additionally, excess supply conditions that exist in certain parts of the world cannot easily serve to mitigate the relatively high-price conditions in the United States and other markets because of the lack of infrastructure to transport and receive liquefied natural gas.

To help address this regional imbalance between supply and demand for natural gas, Chevron is planning increased

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investments in long-term projects in areas of excess supply to install infrastructure to produce and liquefy natural gas for transport by tanker, along with investments and commitments to regasify the product in markets where demand is strong and supplies are not as plentiful. Due to the significance of the overall investment in these long-term projects, the natural gas sales prices in the areas of excess supply (before the natural gas is transferred to a company-owned or third-party processing facility) are expected to remain well below sales prices for natural gas that is produced much nearer to areas of high demand and can be transported in existing natural gas pipeline networks (as in the United States).

Besides the impact of the fluctuation in price for crude oil and natural gas, the longer-term trend in earnings for the upstream segment is also a function of other factors, including the company’s ability to find or acquire and efficiently produce crude oil and natural gas, changes in fiscal terms, and the cost of goods and services.

Chevron’s worldwide net oil-equivalent production in 2006, including volumes produced from oil sands and production under an operating service agreement, averaged 2.67 million barrels per day, or 6 percent higher than production in 2005. The increase between periods was largely due to volumes associated with the acquisition of Unocal in August 2005. The company estimates that oil-equivalent production in 2007 will average approximately 2.6 million barrels per day. This estimate is subject to many uncertainties, including quotas that may be imposed by OPEC, the price effect on production volumes calculated under cost-recovery and variable-royalty provisions of certain contracts, changes in fiscal terms or restrictions on the scope of company operations, and production disruptions that could be caused by severe weather, local civil unrest and changing geopolitics. Future production levels also are affected by the size and number of economic investment opportunities and, for new large-scale projects, the time lag between initial exploration and the beginning of production. Most of Chevron’s upstream investment is currently being made outside the United States. Investments in upstream projects generally are made well in advance of the start of the associated crude oil and natural gas production.

Approximately 24 percent of the company’s net oil-equivalent production in 2006 occurred in the OPEC-member countries of Indonesia, Nigeria and Venezuela and in the Partitioned Neutral Zone between Saudi Arabia and Kuwait. In December 2006, OPEC admitted Angola as a new member effective January 1, 2007. Oil-equivalent production for 2006 in Angola represented 6 percent of the company’s total. In October 2006, OPEC announced its decision to reduce OPEC-member production quotas by 1.2 million barrels of crude oil per day, or 4.4 percent, from a production level of 27.5 million barrels, effective

November 1, 2006. In December 2006, OPEC announced an additional quota reduction of 500,000 barrels of crude oil per day, effective February 1, 2007. OPEC quotas did not significantly affect Chevron’s production level in 2006. The impact of quotas on the company’s production in 2007 is uncertain.

In October 2006, Chevron’s Boscan and LL-652 operating service agreements in Venezuela were converted to Empresas Mixtas (i.e. joint stock contractual structures), with Petróleos de Venezuela S.A., as majority shareholder. Beginning in October, Chevron reported its equity share of the Boscan and LL-652 production, which was approximately 90,000 barrels per day less than what the company previously reported under the operating service agreements. The change to the Empresa Mixta structure did not have a material effect on the company’s results of operations, consolidated financial position or liquidity.

At the end of 2005 in certain onshore areas of Nigeria, approximately 30,000 barrels per day of the company’s net production capacity remained shut-in following civil unrest and damage to production facilities that occurred in 2003. By the end of 2006, the company had resumed operations in portions of all the affected fields, and more than 20,000 barrels per day of production had been restored. In early 2007, additional production restoration activities continued in the area; however, intermittent civil unrest could adversely impact company operations in the future.

Refer to pages FS-6 through FS-7 for additional discussion of the company’s upstream operations.

Downstream Earnings for the downstream segment are closely tied to global and regional supply and demand for refined products and the associated effects on industry refining and marketing margins. Other factors include the reliability and efficiency of the company’s refining and marketing network, the effectiveness of the crude-oil and product-supply functions, and the economic returns on invested capital. Profitability can also be affected by the volatility of charter expenses for the company’s shipping operations, which are driven by the industry’s demand for crude oil and product tankers. Other factors that are beyond the company’s control include the general level of inflation and energy costs to operate the company’s refinery and distribution network.

The company’s core marketing areas are the West Coast of North America, the U.S. Gulf Coast, Latin America, Asia and sub-Saharan Africa. The company operates or has ownership interests in refineries in each of these areas, except Latin America. In 2006, earnings for the segment improved substantially, mainly as the result of higher average margins for refined products and improved operations at the company’s refineries.

Industry margins in the future may be volatile and are influenced by changes in the price of crude oil used for refinery feedstock and by changes in the supply and demand for crude oil and refined products. The industry supply and demand balance can be affected by disruptions at refineries resulting from maintenance programs and unplanned outages, including weather-related disruptions; refined-product inventory levels; and geopolitical events.

Refer to pages FS-8 through FS-9 for additional discussion of the company’s downstream operations.

Chemicals Earnings in the petrochemicals business are closely tied to global chemical demand, industry inventory levels and plant capacity utilization. Feedstock and fuel costs, which tend to follow crude oil and natural gas price movements, also influence earnings in this segment.

Refer to page FS-9 for additional discussion of chemicals earnings.

OPERATING DEVELOPMENTS

Key operating developments and other events during 2006 and early 2007 included:

Upstream

United States In the Gulf of Mexico, the company announced in September 2006 the completion of a successful production test on the 50 percent-owned and operated Jack #2 well. The test was a follow-up to the 2004 Jack discovery and was the deepest well-test ever accomplished in the Gulf of Mexico.

Also in the Gulf of Mexico, the company announced in October its decision to develop the Great White, Tobago and Silvertip fields via a common producing hub, the Perdido Regional Host,

which will have a processing capacity of 130,000 barrels of oil-equivalent per day. First production from the 38 percent-owned Perdido Regional Host is anticipated by 2010. The company’s ownership interests in the fields are Great White – 33 percent, Tobago – 58 percent and Silvertip – 60 percent.

Angola In June 2006, the company produced the first crude oil from the offshore Lobito field, located in Block 14. Lobito is part of the 31 percent-owned and operated Benguela Belize–Lobito Tomboco (BBLT) development project. As fields and wells are added over the next two years, BBLT’s maximum production is expected to reach approximately 200,000 barrels of oil per day. Also in Block 14, the company produced first crude oil in June 2006

from the Landana North reservoir in the 31 percent-owned and operated Tombua-Landana development area. This initial production is tied back to the nearby BBLT production facilities. Tombua-Landana is the company’s third deepwater development offshore Angola. Maximum production from the completed Tombua-Landana development is estimated at 100,000 barrels per day by 2010.

In early 2007, the company announced a discovery of crude oil at the 31 percent-owned and operated Lucapa-1 well in deepwater Block 14. The company plans to conduct appraisal drilling and additional geologic and engineering studies to assess the potential resource.

Australia In July 2006, the company discovered natural gas at the Chandon-1 exploration well offshore the northwestern coast in the Greater Gorgon development area. The company’s interest in the property is 50 percent.

Also offshore the northwestern coast, the company announced in November 2006 a significant natural gas discovery at its Clio-1 exploration well. The company holds a 67 percent interest in the block where Clio-1 is located. Chevron will be undertaking further work, including a 3-D seismic survey program that started in late 2006, to better determine the potential of the gas find and subsequent development options.

In early 2007, the company was also named operator and awarded a 50 percent interest in exploration acreage in the Greater Gorgon Area. A three-year work program includes geotechnical studies, seismic surveys and drilling of an exploration well.

Azerbaijan The first tanker lifting of crude oil transported through the 9 percent-owned Baku-Tbilisi-Ceyhan (BTC) pipeline occurred in June 2006. The crude is being supplied by the Azerbaijan International Oil Company, in which the company has a 10 percent nonoperated working interest.

Brazil In June 2006, the company announced the decision to develop the 52 percent-owned and operated offshore Frade Field. Initial production is targeted by early 2009, with a maximum annual rate estimated at 90,000 oil-equivalent barrels per day in 2011.

Canada The company acquired heavy oil leases in the Athabasca region of northern Alberta, Canada in 2005 and 2006. The leases comprise more than 75,000 acres and contain significant volumes that have potential for recovery using Steam Assisted Gravity Drainage technology.

Also in Alberta, the company announced its decision in October 2006 to participate in the expansion of the Athabasca Oil Sands Project (AOSP). The expansion is expected to add 100,000 barrels per day of mining and upgrading capacity at an estimated total project cost of $10 billion. Completion of the expansion is planned for 2010, increasing total capacity of the project to approximately 255,000 barrels per day. The company holds a 20 percent nonoperated working interest in AOSP.

Nigeria In May 2006, the company announced the discovery of crude oil at the nonoperated Uge-1 exploration well in the 20 percent-owned offshore Oil Prospecting License 214. Future drilling is contingent primarily on the outcome of ongoing technical studies.

Norway In April 2006, the company was awarded the rights to six blocks in the 19th Norwegian Licensing Round. The 40 percent-owned blocks are located in the Nordkapp East Basin in the Norwegian Barents Sea. A 3-D seismic survey was acquired and is planned to be processed in 2007.

Thailand In early 2006, the company signed two petroleum exploration concessions in the Gulf of Thailand. Chevron has a 71 percent operated interest in one concession, which is in the proximity of the company’s Tantawan and Plamuk fields. Initial drilling in the concession is scheduled during 2007. Drilling is projected by 2009 for the other concession, in which Chevron has a 16 percent nonoperated working interest.

United Kingdom In June 2006, the company produced the first crude oil from the 85 percent-owned and operated Area C in the Captain Field. The project reached maximum production of 14,000 barrels of crude oil per day in September 2006.

In early 2007, the company was awarded eight operated exploration blocks and two nonoperated blocks west of Shetland Islands in the 24th United Kingdom Offshore Licensing Round.

Vietnam In April 2006, the company signed a 30-year production-sharing contract with Vietnam Oil and Gas Corporation for Block 122 offshore eastern Vietnam. The company has a 50 percent interest in this block and has undertaken a three-year work program for seismic acquisition and drilling of an exploratory well.

Downstream

United States In December 2006, the company completed the expansion of the Fluid Catalytic Cracking Unit at the company’s refinery in Pascagoula, Mississippi, increasing the refinery’s gasoline manufacturing capacity by about 10 percent. The company also submitted an environmental permit application for construction of facilities to increase gasoline output by another 15 percent.

India In April 2006, the company acquired a 5 percent interest in Reliance Petroleum Limited, a company formed by Reliance Industries Limited to construct, own and operate a refinery in Jamnagar, India. The new refinery would be the world’s sixth largest, designed for a crude oil processing capacity of 580,000 barrels per day. Chevron and Reliance Industries also signed two memoranda of understanding to jointly pursue other downstream and upstream business opportunities. If discussions pursuant to the memoranda of understanding lead to definitive agreements, Chevron may increase its equity stake in Reliance Petroleum to 29 percent.

Other

Biofuels In May 2006, the company announced that it had completed the acquisition of a 22 percent interest in Galveston Bay Biodiesel L.P., which is building one of the first large-scale biodiesel plants in the United States. The following month, the company entered into a research alliance with the Georgia Institute of Technology to pursue advanced technology aimed at making cellulosic biofuels and hydrogen into transportation fuels. In September, the company announced a research collaboration with the University of California, Davis aimed at converting cellulosic biomass into transportation fuels.

Common Stock Dividends and Stock Repurchase Program In April 2006, the company increased its quarterly common stock dividend by 15.5 percent to $0.52 per share. In November, the company completed its second $5 billion common stock buyback program since 2004 and in December authorized the acquisition of up to $5 billion of additional shares over a period of up to three years.

RESULTS OF OPERATIONS

Major Operating Areas The following section presents the results of operations for the company’s business segments – upstream, downstream and chemicals – as well as for “all other,” which includes mining, power generation businesses, and the various companies and departments that are managed at the corporate level. Income is also presented for the U.S. and international geographic areas of the upstream and downstream business segments. (Refer to Note 8, beginning on page FS-38, for a discussion of the company’s “reportable segments,” as defined in FASB No. 131, Disclosures About Segments of an Enterprise and Related Information.) This section should also be read in conjunction with the discussion in “Business Environment and Outlook” on pages FS-2 through FS-5.

U.S. Upstream – Exploration and Production


Millions of dollars	2006		2005		2004

Income From Continuing Operations	$	4,270	$	4,168	$	3,868
Income From Discontinued Operations		–		–		70

Total Income	$	4,270	$	4,168	$	3,938

U.S. upstream income of $4.3 billion in 2006 increased approximately $100 million from 2005. Earnings in 2006 benefited about $850 million from higher average prices on oil-equivalent production and the effect of seven additional months of production from the Unocal properties that were acquired in August 2005. Substantially offsetting these benefits were increases in operating expense and expenses for depreciation and exploration. Included in the operating expense increases were costs associated with the carryover effects of hurricanes in the Gulf of Mexico in 2005.

Income of $4.2 billion in 2005 was $230 million higher than 2004. The 2004 amount included gains of approxi-

mately $400 million from asset sales. Higher prices for crude oil and natural gas in 2005 and five months of earnings from the former Unocal operations contributed approximately $2 billion to the increase between periods. Approximately 90 percent of this amount related to the effects of higher prices on heritage-Chevron production. These benefits were substantially offset by the adverse effects of lower production, higher operating expenses and higher depreciation expense associated with the heritage Chevron properties.

The company’s average realization for crude oil and natural gas liquids in 2006 was $56.66 per barrel, compared with $46.97 in 2005 and $34.12 in 2004. The average natural gas realization was $6.29 per thousand cubic feet in 2006, compared with $7.43 and $5.51 in 2005 and 2004, respectively.

Net oil-equivalent production in 2006 averaged 763,000 barrels per day, up 5 percent from 2005 and down 7 percent from 2004. The increase between 2005 and 2006 was due to the full-year benefit of production from the former Unocal

(BAR CHARTS)

properties. The decrease from 2004 was associated mainly with the effects of hurricanes, property sales and normal field declines, partially offset by additional volumes from the former Unocal properties.

The net liquids component of oil-equivalent production for 2006 averaged 462,000 barrels per day, an increase of approximately 2 percent from 2005 and a decrease of 9 percent from 2004. Net natural gas production averaged 1.8 billion cubic feet per day in 2006, up 11 percent from 2005 and down 3 percent from 2004.

Refer to the “Selected Operating Data” table, on page FS-11, for the three-year comparative production volumes in the United States.

International Upstream – Exploration and Production


Millions of dollars	2006		2005		2004

Income From Continuing Operations*	$	8,872	$	7,556	$	5,622
Income From Discontinued Operations		–		–		224

Total Income*	$	8,872	$	7,556	$	5,846

*Includes Foreign Currency Effects:		$ (371)		$ 14		$ (129)

International upstream income of approximately $8.9 billion in 2006 increased $1.3 billion from 2005. Earnings in 2006 benefited approximately $3.0 billion from higher prices for crude oil and natural gas and an additional seven months of production from the former Unocal properties. About 70 percent of this benefit was associated with the impact of higher prices. Substantially offsetting these benefits were increases in depreciation expense, operating expense and exploration expense. Also adversely affecting 2006 income were higher taxes related to an increase in tax rates in the U.K. and Venezuela and settlement of tax claims and other tax items in Venezuela, Angola and Chad. Foreign currency effects reduced earnings by $371 million in 2006, but increased income $14 million in 2005.

Income in 2005 was approximately $7.5 billion, compared with $5.8 billion in 2004, which included gains of approximately $850 million from property sales. Higher prices for crude oil and natural gas in 2005 and five months of earnings from the former Unocal operations increased income approximately $2.9 billion between periods. About 80 percent of this benefit arose from the effects of higher prices on heritage-Chevron production. Partially offsetting these benefits were higher expenses between periods for certain income tax items, including the absence of a $200 million benefit in 2004 relating to changes in income tax laws. Foreign currency effects increased income $14 million in 2005 but reduced income $129 million in 2004.

The company’s average realization for crude oil and natural gas liquids in 2006 was $57.65 per barrel, compared with $47.59 in 2005 and $34.17 in 2004. The average natural gas realization was $3.73 per thousand cubic feet in 2006, compared with $3.19 and $2.68 in 2005 and 2004, respectively.

Net oil-equivalent production of 1.9 million barrels per day in 2006, including about 100,000 net barrels per day from oil sands in Canada and production under an operating service agreement in Venezuela prior to its conversion to a joint stock company, increased about 6 percent from 2005 and 13 percent from 2004. This trend was largely the result of the effects of the Unocal acquisition in August 2005, partially offset by the effect of normal field declines and property sales in 2004.

The net liquids component of oil-equivalent production was 1.4 million barrels per day in 2006, an increase of approximately 2 percent from 2005 and 2004. Net natural gas production of 3.1 billion cubic feet per day in 2006 was up 21 percent and 51 percent from 2005 and 2004, respectively.

Refer to the “Selected Operating Data” table, on page FS-11, for the three-year comparative of international production volumes.

U.S. Downstream – Refining, Marketing and Transportation


Millions of dollars	2006		2005		2004

Income	$	1,938	$	980	$	1,261

U.S. downstream earnings of $1.9 billion in 2006 increased about $1 billion from 2005 and approximately $700 million from 2004. Average refined-product margins in 2006 were higher than in 2005, which in turn were also higher than in 2004. Refinery crude inputs were higher in 2006 than in the other comparative periods and also benefited earnings. However, earnings declined in 2005 from

(BAR CHARTS)

a year earlier due mainly to increased downtime at the company’s refineries, including the shutdown of operations at Pascagoula, Mississippi, for more than a month due to hurricanes in the Gulf of Mexico. The company’s marketing and pipeline operations along the Gulf Coast were also disrupted for an extended period due to the hurricanes. Fuel costs were also higher in 2005 than in 2004.

Sales volumes of refined products in 2006 were approximately 1.5 million barrels per day, an increase of 1 percent from 2005 and relatively unchanged from 2004. The reported sales volume for 2006 was on a different basis than in 2005 and 2004 due to a change in accounting rules that became effective April 1, 2006, for certain purchase and sale

(buy/sell) contracts with the same counterparty. Excluding the impact of the accounting change, refined product sales in 2006 increased by approximately 6 percent and 3 percent from 2005 and 2004, respectively. Branded gasoline sales volumes of approximately 614,000 barrels per day in 2006 increased about 4 percent from 2005, largely due to the growth of the Texaco brand. In 2005, refined-product sales volumes decreased about 2 percent from 2004, primarily due to disruption related to the hurricanes.

Refer to the “Selected Operating Data” table, on page FS-11, for the three-year comparative refined-product sales volumes in the United States. Refer also to Note 14, Accounting for Buy/Sell Contracts, on page FS-43 for a discussion of the accounting for purchase and sale contracts with the same counterparty.

International Downstream – Refining, Marketing and Transportation


Millions of dollars	2006		2005		2004

Income*	$	2,035	$	1,786	$	1,989

*Includes Foreign Currency Effects:		$ 98		$ (24)		$ 7

International downstream income of $2 billion in 2006 increased about $250 million from 2005 and about $50 million from 2004. The increase in 2006 from 2005 was associated mainly with the

benefit of higher-refined product margins in Asia-Pacific and Canada and improved results from crude-oil and refined-product trading activities. The decrease in earnings in 2005 from 2004 was due mainly to lower sales volumes; higher costs for fuel and transportation; expenses associated with a fire at a 40 percent-owned, nonoperated terminal in the United Kingdom; and tax adjustments in various countries. These items more than offset an improvement in average refined-product margins between periods. Foreign currency effects improved income by $98 million and $7 million in 2006 and 2004, respectively, but reduced income by $24 million in 2005.

Refined-product sales volumes were 2.1 million barrels per day in 2006, about 6 percent lower than 2005. Excluding the accounting change for buy/sell contracts, sales were down 1 percent between 2005 and 2006. Refined-product sales volume of 2.3 million barrels per day in 2005 were about 4 percent lower than in 2004, primarily the result of lower gasoline trading activity and lower fuel oil sales. Refer to the “Selected Operating Data” table, on page FS-11, for the three-year comparative refined-product sales volumes in the international areas.

Chemicals


Millions of dollars	2006		2005		2004

Income*	$	539	$	298	$	314

*Includes Foreign Currency Effects:		$(8)		$–		$(3)

The chemicals segment includes the company’s Oronite subsidiary and the 50 percent-owned Chevron Phillips Chemical Company LLC (CPChem). In 2006, earnings of $539 million increased about $200 million from both 2005 and 2004. Margins in 2006 for commodity chemicals at CPChem and for fuel and lubricant additives at Oronite were higher than in 2005 and 2004. The earnings decline from 2004 to 2005 was mainly attributable to plant outages and expenses in the Gulf of Mexico region due to hurricanes, which affected both Oronite and CPChem.

All Other


Millions of dollars	2006			2005			2004

Net Charges*	$	(516	)	$	(689	)	$	(20	)

*Includes Foreign Currency Effects:		$62			$(51)			$44

All Other consists of the company’s interest in Dynegy Inc., mining operations, power generation businesses, worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, and technology companies.

Net charges of $516 million in 2006 decreased $173 million from $689 million in 2005. Excluding the effects of foreign currency, net charges declined $60 million between periods. Interest income was higher in 2006, and interest expense was lower.

Between 2004 and 2005, net charges increased $669 million. Excluding the effects of foreign exchange, net charges increased $574 million. Approximately $400 million of the increase was related to larger benefits in 2004 from

corporate-level tax adjustments. Higher charges in 2005 also were associated with environmental remediation of properties that had been sold or idled and Unocal corporate-level activities. Interest expense was higher in 2005 due to an increase in interest rates and the debt assumed with the Unocal acquisition.

CONSOLIDATED STATEMENT OF INCOME

Comparative amounts for certain income statement categories are shown below:


Millions of dollars	2006		2005		2004

Sales and other operating revenues	$	204,892	$	193,641	$	150,865

Sales and other operating revenues in 2006 increased over 2005 due primarily to higher prices for refined products. The increase in 2005 from 2004 was a result of the same factor plus the effect of higher average prices for crude oil and natural gas. The higher revenues in 2006 were net of an impact from the change in the accounting for buy/sell contracts, as described in Note 14 on page FS-43.


Millions of dollars	2006		2005		2004

Income from equity affiliates	$	4,255	$	3,731	$	2,582

Increased income from equity affiliates in 2006 was mainly due to improved results for Tengizchevroil (TCO) and CPChem. The improvement in 2005 from 2004 was primarily due to improved results for TCO and Hamaca (Venezuela). Refer to Note 12, beginning on page FS-41, for a discussion of Chevron’s investment in affiliated companies.


Millions of dollars	2006		2005		2004

Other income	$	971	$	828	$	1,853

Other income of nearly $1.9 billion in 2004 included approximately $1.3 billion of gains from upstream property sales. Interest income contributed $600 million, $400 million and $200 million in 2006, 2005 and 2004, respectively. Average interest rates and balances of cash and marketable securities increased each year. Foreign currency losses were $260 million in 2006 and $60 million in both 2005 and 2004.


Millions of dollars	2006		2005		2004

Purchased crude oil and products	$	128,151	$	127,968	$	94,419

Crude oil and product purchases in 2006 increased from 2005 on higher prices for crude oil and refined products and the inclusion of Unocal-related amounts for a full year in 2006. The increase was mitigated by the effect of the accounting change in April 2006 for buy/sell contracts. Purchase costs increased 35 percent in 2005 from the prior year as a result of higher prices for crude oil, natural gas and refined products, as well as to the inclusion of Unocal-related amounts for five months.


Millions of dollars	2006		2005		2004

Operating, selling, general and administrative expenses	$	19,717	$	17,019	$	14,389

Operating, selling, general and administrative expenses in 2006 increased 16 percent from a year earlier. Expenses associated with the former Unocal operations are included for the full year in 2006, vs. five months in 2005. Besides this effect, expenses were higher in 2006 for labor, transportation, uninsured costs associated with the hurricanes in 2005 and a number of corporate items that individually were not significant. Total expenses increased in 2005 from 2004 due mainly to the inclusion of former-Unocal expenses for five months, higher costs for labor and transportation, uninsured costs associated with storms in the Gulf of Mexico, and asset write-offs.


Millions of dollars	2006		2005		2004

Exploration expense	$	1,364	$	743	$	697

Exploration expenses in 2006 increased from 2005 mainly due to higher amounts for well write-offs and geological and geophysical costs for operations outside the United States, as well as the inclusion of expenses for the former Unocal operations for a full year in 2006. Expenses increased in 2005 from 2004 due mainly to the inclusion of Unocal-related amounts for five months.


Millions of dollars	2006		2005		2004

Depreciation, depletion and amortization	$	7,506	$	5,913	$	4,935

Depreciation, depletion and amortization expenses increased from 2004 through 2006 mainly as a result of depreciation and depletion expense for the former Unocal assets and higher depreciation rates for certain heritage-Chevron crude oil and natural gas producing fields worldwide.


Millions of dollars	2006		2005		2004

Interest and debt expense	$	451	$	482	$	406

Interest and debt expense in 2006 decreased from 2005 primarily due to lower average debt balances and an increase in the amount of interest capitalized, partially offset by higher average interest rates on commercial paper and other variable-rate debt. The increase in 2005 over 2004 was mainly due to the inclusion of debt assumed with the Unocal acquisition and higher average interest rates for commercial paper borrowings.


Millions of dollars	2006		2005		2004

Taxes other than on income	$	20,883	$	20,782	$	19,818

Taxes other than on income were essentially unchanged in 2006 from 2005, with the effect of higher U.S. refined product sales being offset by lower sales volumes subject to duties in the company’s European downstream operations.

SELECTED OPERATING DATA^1,2


	2006		2005		2004

U.S. Upstream³
Net Crude Oil and Natural Gas
Liquids Production (MBPD)		462		455		505
Net Natural Gas Production (MMCFPD)⁴		1,810		1,634		1,873
Net Oil-Equivalent Production (MBOEPD)		763		727		817
Sales of Natural Gas (MMCFPD)		7,051		5,449		4,518
Sales of Natural Gas Liquids (MBPD)		124		151		177
Revenues From Net Production Liquids ($/Bbl)	$	56.66	$	46.97	$	34.12
Natural Gas ($/MCF)	$	6.29	$	7.43	$	5.51

International Upstream³
Net Crude Oil and Natural Gas Liquids Production (MBPD)		1,270		1,214		1,205
Net Natural Gas Production (MMCFPD)⁴		3,146		2,599		2,085
Net Oil-Equivalent Production (MBOEPD)⁵		1,904		1,790		1,692
Sales Natural Gas (MMCFPD)		3,478		2,450		2,039
Sales Natural Gas Liquids (MBPD)		102		120		118
Revenues From Liftings Liquids ($/Bbl)	$	57.65	$	47.59	$	34.17
Natural Gas ($/MCF)	$	3.73	$	3.19	$	2.68

U.S. and International Upstream³
Net Oil-Equivalent Production Including Other Produced Volumes (MBOEPD)^4,5
United States		763		727		817
International		1,904		1,790		1,692

Total		2,667		2,517		2,509

U.S. Downstream
Gasoline Sales (MBPD)⁶		712		709		701
Other Refined Products Sales (MBPD)		782		764		805

Total (MBPD)⁷		1,494		1,473		1,506
Refinery Input (MBPD)		939		845		914

International Downstream
Gasoline Sales (MBPD)⁶		595		662		715
Other Refined Products Sales (MBPD)		1,532		1,590		1,653

Total (MBPD)^7,8		2,127		2,252		2,368
Refinery Input (MBPD)		1,050		1,038		1,044


¹ Includes equity in affiliates.
² MBPD = Thousands of barrels per day; MMCFPD = Millions of cubic feet per day; MBOEPD = Thousands of barrels of oil equivalents per day; Bbl = Barrel; MCF = Thousands of cubic feet. Oil-equivalent gas (OEG) conversion ratio is 6,000 cubic feet of gas = 1 barrel of oil.
³ Includes net production beginning August 2005, for properties associated with acquisition of Unocal.
⁴ Includes natural gas consumed in operations (MMCFPD):
United States	56	48	50
International	419	356	293
⁵ Includes other produced volumes (MBPD):
Athabasca Oil Sands – Net	27	32	27
Boscan Operating Service Agreement	82	111	113

	109	143	140
⁶ Includes branded and unbranded gasoline.
⁷ Includes volumes for buy/sell contracts (MBPD):
United States	26	88	84
International	24	129	96
⁸ Includes sales of affiliates (MBPD):	492	498	502

INFORMATION RELATED TO INVESTMENT IN
DYNEGY INC.

At year-end 2006, Chevron owned a 19 percent equity interest in the common stock of Dynegy Inc., a provider of electricity to markets and customers throughout the United States.

Investment in Dynegy Common Stock At December 31, 2006, the carrying value of the company’s investment in Dynegy common stock was approximately $250 million. This amount was about $180 million below the company’s proportionate interest in Dynegy’s underlying net assets. This difference is primarily the result of write-downs of the investment in 2002 for declines in the market value of the common shares below the company’s carrying value that were deemed to be other than temporary. The difference had been assigned to the extent practicable to specific Dynegy assets and liabilities, based upon the company’s analysis of the various factors associated with the decline in value of the Dynegy shares. The company’s equity share of Dynegy’s reported earnings is adjusted quarterly when appropriate to recognize a portion of the difference between these allocated values and Dynegy’s historical book values. The market value of the company’s investment in Dynegy’s common stock at December 31, 2006, was approximately $700 million.

Investments in Dynegy Preferred Stock In May 2006, the company’s investment in Dynegy Series C preferred stock was redeemed at its face value of $400 million. Upon redemption of the preferred stock, the company recorded a before-tax gain of $130 million ($87 million after tax).

Dynegy Proposed Business Combination with LS Power Group Dynegy and LS Power Group, a privately held power plant investor, developer and manager, announced in September 2006 that the companies had executed a definitive agreement to combine Dynegy’s assets and operations with LS Power Group’s power-generation portfolio and for Dynegy to acquire a 50 percent ownership interest in a development joint venture with LS Power. Upon close of the transaction, Chevron will receive the same number of shares of the new company’s Class A common stock that it currently holds in Dynegy. Chevron’s ownership interest in the combined company will be approximately 11 percent. The transaction is subject to specified conditions, including the affirmative vote of two-thirds of Dynegy’s common shareholders and the receipt of regulatory approvals.

LIQUIDITY AND CAPITAL RESOURCES

Cash, cash equivalents and marketable securities Total balances were $11.4 billion and $11.1 billion at December 31, 2006 and 2005, respectively. Cash provided by operating activities in 2006 was $24.3 billion, compared with $20.1 billion in 2005 and $14.7 billion in 2004.

The 2006 increase in cash provided by operating activities mainly reflected higher earnings in the upstream and downstream segments, including a full year of earnings from the former Unocal operations that were acquired in August 2005. Cash provided by operating activities was net of contributions to employee pension plans of $0.4 billion, $1.0 billion and $1.6 billion in 2006, 2005 and 2004, respectively. Cash provided by investing activities included proceeds from asset sales of $1.0 billion in 2006, $2.7 billion in 2005 and $3.7 billion in 2004.

Cash provided by operating activities and asset sales during 2006 was sufficient to fund the company’s $13.8 billion capital and exploratory program, pay $4.4 billion of dividends to stockholders, repay approximately $2.9 billion in debt and repurchase $5 billion of common stock.

Dividends The company paid dividends of approximately $4.4 billion in 2006, $3.8 billion in 2005 and $3.2 billion in 2004. In April 2006, the company increased its quarterly common stock dividend by 15.5 percent to 52 cents per share.

Debt, capital lease and minority interest obligations Total debt and capital lease balances were $9.8 billion at

December 31, 2006, down from $12.9 billion at year-end 2005. The company also had minority interest obligations of $209 million, up from $200 million at December 31, 2005.

The $3.1 billion reduction in total debt and capital lease obligations during 2006 included the early redemption and maturity of several individual debt issues. In the first quarter, $185 million of Union Oil Company bonds matured. In the second quarter, the company redeemed approximately $1.7 billion of Unocal debt prior to maturity. In the fourth quarter, a $129 million Texaco Capital Inc. bond matured, and Union Oil Company bonds of $196 million were redeemed prior to maturity. Commercial paper balances at the end of 2006 were reduced $626 million from year-end 2005. In February 2007, a $144 million Texaco Capital Inc. bond matured.

The company’s debt and capital lease obligations due within one year, consisting primarily of commercial paper and the current portion of long-term debt, totaled $6.6 billion at December 31, 2006, up from $5.6 billion at year-end 2005. Of these amounts, $4.5 billion and $4.9 billion were reclassified to long-term at the end of each period, respectively. At year-end 2006, settlement of the reclassified amount was not expected to require the use of working capital in 2007, as the company had the intent and the ability, as evidenced by committed credit facilities, to refinance the amounts on a long-term basis. The company’s practice has been to maintain commercial paper levels it believes appropriate and economic.

At year-end 2006, the company had $5 billion in committed credit facilities with various major banks, which permitted the refinancing of short-term obligations on a long-term basis. These facilities support commercial paper borrowings and can be used for general corporate purposes. The company’s practice has been to continually replace expiring commitments with new commitments on substantially the same terms, maintaining levels management believes appropriate. Any borrowings under the facilities would be unsecured indebtedness at interest rates based on the London Interbank Offered Rate or an average of base lending rates published by specified banks and on terms reflecting the company’s strong credit rating. No borrowings were outstanding under these facilities at December 31, 2006. In addition, the company has three existing effective “shelf” registration statements on file with the Securities and Exchange Commission that together would permit additional registered debt offerings up to an aggregate $3.8 billion of debt securities.

In 2004, Chevron entered into $1 billion of interest rate swap transactions, in which the company receives a fixed interest rate and pays a floating rate, based on the notional principal amounts. Under the terms of the swap agreements, of which $250 million and $750 million will terminate in September 2007 and February 2008, respectively, the net cash settlement will be based on the difference between fixed interest rates and floating interest rates.

The company has outstanding public bonds issued by Chevron Corporation Profit Sharing/Savings Plan Trust Fund, Chevron Canada Funding Company (formerly Chevron Texaco Capital Company), Texaco Capital Inc. and Union Oil Company of California. All of these securities are guaranteed by Chevron Corporation and are rated AA by Standard and Poor’s Corporation and Aa2 by Moody’s Investors Service. The company’s U.S. commercial paper is rated A-1+ by Standard and Poor’s and P-1 by Moody’s, and the company’s Canadian commercial paper is rated R-1 (middle) by Dominion Bond Rating Service. All of these ratings denote high-quality, investment-grade securities.

The company’s future debt level is dependent primarily on results of operations, the capital-spending program and cash that may be generated from asset dispositions. The company believes that it has substantial borrowing capacity to meet unanticipated cash requirements and that during periods of low prices for crude oil and natural gas and narrow margins for refined products and commodity chemicals, it has the flexibility to increase borrowings and/or modify capital-spending plans to continue paying the common stock dividend and maintain the company’s high-quality debt ratings.

Common stock repurchase program A $5 billion stock repurchase program initiated in December 2005 was completed in November 2006. During 2006, about 78.5 million common shares were repurchased under this program at a total cost of $4.9 billion.

In December 2006, the company authorized the acquisition of up to an additional $5 billion of its common shares from time to time at prevailing prices, as permitted by securities laws and other legal requirements and subject to market conditions and other factors. The program is for a period of up to three years and may be discontinued at any time. Under this program, the company acquired approximately 1.3 million shares in the open market for $100 million during December 2006 and through mid-February 2007 increased the total shares acquired to 8.2 million at a cost of $592 million.

Capital and exploratory expenditures Total reported expenditures for 2006 were $16.6 billion, including $1.9 billion for the company’s share of affiliates’ expenditures, which did not require cash outlays by the company. In 2005 and 2004, expenditures were $11.1 billion and $8.3 billion, respectively, including the company’s share of affiliates’ expenditures of $1.7 billion and $1.6 billion in the cor-

responding periods. The 2005 amount excludes the $17.3 billion acquisition of Unocal Corporation.

Of the $16.6 billion in expenditures for 2006, about three-fourths, or $12.8 billion, related to upstream activities. Approximately the same percentage was also expended for upstream operations in 2005 and 2004. International upstream accounted for about 70 percent of the worldwide upstream investment in each of the three years, reflecting the company’s continuing focus on opportunities that are available outside the United States.

exploration and production activities, with $10.6 billion of this amount outside the United States. Spending in 2007 is primarily targeted for exploratory prospects in the deepwater Gulf of Mexico and western Africa and major development projects in Angola, Australia, Brazil, Kazakhstan, Nigeria, the deepwater Gulf of Mexico and an oil sands project in Canada.

Worldwide downstream spending in 2007 is estimated at $3.8 billion, with about $1.6 billion for projects in the United States. Capital projects include upgrades to refineries in the United States and South Korea and construction of liquefied natural gas tankers and gas-to-liquids facilities in support of associated upstream projects.

Investments in chemicals, technology and other corporate businesses in 2007 are budgeted at $1.2 billion. Technology investments include projects related to molecular transformation, unconventional hydrocarbons, oil and gas reservoir management and development of second-generation biofuel production.

Pension Obligations In 2006, the company’s pension plan contributions totaled approximately $450 million. Approximately $225 million of the total was contributed to U.S. plans. In 2007, the company estimates total contributions will be $500 million. Actual amounts are dependent upon plan-investment results, changes in pension obligations, regulatory requirements and other economic factors. Additional funding may be required if investment returns are insufficient to offset increases in plan obligations. Refer also to the discussion of pension accounting in “Critical Accounting Estimates and Assumptions,” beginning on page FS-20.

FINANCIAL RATIOS

Financial Ratios


	At December 31
	2006			2005			2004

Current Ratio		1.3			1.4			1.5
Interest Coverage Ratio		53.5			47.5			47.6
Total Debt/Total Debt-Plus-Equity		12.5	%		17.0	%		19.9	%

Current Ratio – current assets divided by current liabilities. The current ratio in all periods was adversely affected by the fact that Chevron’s inventories are valued on a Last-In-First-Out basis. At year-end 2006, the book value of inventory was lower than replacement costs, based on average acquisition costs during the year, by approximately $6 billion.

Interest Coverage Ratio – income before income tax expense, plus interest and debt expense and amortization of capitalized interest, divided by before-tax interest costs. The interest coverage ratio was higher in 2006 compared with 2005, primarily due to higher before-tax income and lower average debt balances. The company’s interest coverage ratio was essentially unchanged between 2005 and 2004.

(BAR CHART)

Debt Ratio – total debt as a percentage of total debt plus equity. The decrease between 2005 and 2006 was due to lower average debt levels and an increase in stockholders’ equity. Although total debt was slightly higher at the end of 2005 than a year earlier due to the assumption of debt associated with the Unocal acquisition, the debt ratio declined as a result of higher stockholders’ equity

balances for retained earnings and the capital stock that was issued in connection with the Unocal acquisition.

GUARANTEES, OFF-BALANCE-SHEET
ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS,
AND OTHER CONTINGENCIES

Direct or Indirect Guarantees*


Millions of dollars	Commitment Expiration by Period

					2008-				After
	Total		2007		2010		2011		2011

Guarantees of non-consolidated affiliates or joint-venture obligations	$	296	$	21	$	253	$	9	$	13
Guarantees of obligations of third parties		131		4		113		3		11
Guarantees of Equilon debt and leases		119		14		38		11		56

* The amounts exclude indemnifications of contingencies associated with the sale of the company’s interest in Equilon and Motiva in 2002, as discussed in the “Indemnifications” section on page FS-15.

At December 31, 2006, the company and its subsidiaries provided guarantees, either directly or indirectly, of $296 million for notes and other contractual obligations of affiliated companies and $131 million for third parties, as described by major category below. There are no amounts being carried as liabilities for the company’s obligations under these guarantees.

The $296 million in guarantees provided to affiliates related to borrowings for capital projects. These guarantees were undertaken to achieve lower interest rates and generally cover the construction periods of the capital projects. Included in these amounts are the company’s guarantees of $214 million associated with a construction completion guarantee for the debt financing of the company’s equity interest in the BTC crude oil pipeline project. Substantially all of the $296 million guaranteed will expire between 2007 and 2011, with the remaining expiring by the end of 2015. Under the terms of the guarantees, the company would be required to fulfill the guarantee should an affiliate be in default of its loan terms, generally for the full amounts disclosed.

The $131 million in guarantees provided on behalf of third parties relate to construction loans to governments of certain of the company’s international upstream operations. Substantially all of the $131 million in guarantees expire by 2011, with the remainder expiring by 2015. The company would be required to perform under the terms of the guarantees should an entity be in default of its loan or contract terms, generally for the full amounts disclosed.

At December 31, 2006, Chevron also had outstanding guarantees for about $120 million of Equilon debt and leases. Following the February 2002 disposition of its interest in Equilon, the company received an indemnification from Shell for any claims arising from the guarantees. The company has

not recorded a liability for these guarantees. Approximately 50 percent of the amounts guaranteed will expire within the 2007 through 2011 period, with the guarantees of the remaining amounts expiring by 2019.

Indemnifications The company provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell and Saudi Refining, Inc., in connection with the February 2002 sale of the company’s interests in those investments. The company would be required to perform if the indemnified liabilities become actual losses. Were that to occur, the company could be required to make future payments up to $300 million. Through the end of 2006, the company paid approximately $48 million under these indemnities and continues to be obligated for possible additional indemnification payments in the future.

The company has also provided indemnities relating to contingent environmental liabilities related to assets originally contributed by Texaco to the Equilon and Motiva joint ventures and environmental conditions that existed prior to the formation of Equilon and Motiva or that occurred during the period of Texaco’s ownership interest in the joint ventures. In general, the environmental conditions or events that are subject to these indemnities must have arisen prior to December 2001. Claims relating to Equilon indemnities must be asserted either as early as February 2007 or no later than February 2009, and claims relating to Motiva indemnities must be asserted either as early as February 2007 or no later than February 2012. Under the terms of these indemnities, there is no maximum limit on the amount of potential future payments. The company has not recorded any liabilities for possible claims under these indemnities. The company posts no assets as collateral and has made no payments under the indemnities.

The amounts payable for the indemnities described above are to be net of amounts recovered from insurance carriers and others and net of liabilities recorded by Equilon or Motiva prior to September 30, 2001, for any applicable incident.

In the acquisition of Unocal, the company assumed certain indemnities relating to contingent environmental liabilities associated with assets that were sold in 1997. Under the indemnification agreement, the company’s liability is unlimited until April 2022, when the liability expires. The acquirer shares in certain environmental remediation costs up to a maximum obligation of $200 million, which had not been reached as of December 31, 2006.

Securitization The company securitizes certain retail and trade accounts receivable in its downstream business through the use of qualifying Special Purpose Entities (SPEs). At December 31, 2006, approximately $1.2 billion, representing about 7 percent of Chevron’s total current accounts and notes receivable balance, were securitized. Chevron’s total estimated financial exposure under these securitizations at December 31, 2006, was approximately $80 million. These arrangements have the effect of accelerating Chevron’s collection of the securitized amounts. In the event that the SPEs experience major defaults in the collection of receivables, Chevron believes that it would have no loss exposure connected with third-party investments in these securitizations.

Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements The company and its subsidiaries have certain other contingent liabilities relating to long-term unconditional purchase obligations and commitments, including throughput and take-or-pay agreements, some of which relate to suppliers’ financing arrangements. The agreements typically provide goods and services, such as pipeline and storage capacity, drilling rigs, utilities, and petroleum products, to be used or sold in the ordinary course of the company’s business. The aggregate approximate amounts of required payments under these various commitments are: 2007 – $3.2 billion; 2008 – $1.7 billion; 2009 – $2.1 billion; 2010 – $1.9 billion; 2011 – $0.9 billion; 2012 and after – $4.1 billion. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were approximately $3.0 billion in 2006, $2.1 billion in 2005 and $1.6 billion in 2004.

Minority Interests The company has commitments of $209 million related to minority interests in subsidiary companies.

The following table summarizes the company’s significant contractual obligations:

Contractual Obligations


Millions of dollars	Payments Due by Period

					2008–				After
	Total		2007		2010		2011		2011

On Balance Sheet:
Short-Term Debt¹	$	2,159	$	2,159	$	–	$	–	$	–
Long-Term Debt^1,2		7,405		–		5,868		50		1,487
Noncancelable Capital Lease Obligations		274		–		138		40		96
Interest		5,269		491		1,173		366		3,239
Off-Balance-Sheet:
Noncancelable Operating Lease Obligations		3,058		509		1,374		311		864
Throughput and Take-or-Pay Agreements		9,796		2,765		3,027		475		3,529
Other Unconditional Purchase Obligations		4,072		383		2,696		427		566

¹		$4.5 billion of short-term debt that the company expects to refinance is included in long-term debt. The repayment schedule above reflects the projected repayment of the entire amounts in the 2008–2010 period.
²		Includes guarantees of $213 of ESOP (employee stock ownership plan) debt due after 2007. The 2007 amount of $20, which was scheduled for payment on the first business day of January 2007, was paid in late December 2006.

FINANCIAL AND DERIVATIVE INSTRUMENTS

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

The company uses derivative commodity instruments to manage these exposures on a portion of its activity, including: firm commitments and anticipated transactions for the purchase, sale and storage of crude oil, refined products, natural gas, natural gas liquids and feedstock for company refineries. The company also uses derivative commodity instruments for limited trading purposes. The results of this activity were not material to the company’s financial position, net income or cash flows in 2006.

The company’s market exposure positions are monitored and managed on a daily basis by an internal Risk

Control group to ensure compliance with the company’s risk management policies that have been approved by the Audit Committee of the company’s Board of Directors.

The derivative instruments used in the company’s risk management and trading activities consist mainly of futures, options, and swap contracts traded on the NYMEX (New York Mercantile Exchange) and on electronic platforms of ICE (Inter-Continental Exchange) and GLOBEX (Chicago Mercantile Exchange). In addition, crude oil, natural gas and refined product swap contracts and option contracts are entered into principally with major financial institutions and other oil and gas companies in the “over-the-counter” markets.

Virtually all derivatives beyond those designated as normal purchase and normal sale contracts are recorded at fair value on the Consolidated Balance Sheet with resulting gains and losses reflected in income. Fair values are derived principally from published market quotes and other independent third-party quotes.

Each hypothetical 10 percent increase in the price of natural gas, crude oil and refined products would increase the fair value of the natural gas purchase derivative contracts by approximately $10 million, increase the fair value of the crude oil purchase derivative contracts by about $4 million and reduce the fair value of the refined product sale derivative contracts by about $30 million, respectively. The same hypothetical decrease in the prices of these commodities would result in approximately the same opposite effects on the fair values of the contracts.

The hypothetical effect on these contracts was estimated by calculating the fair value of the contracts as the difference between the hypothetical and current market prices multiplied by the contract amounts.

Foreign Currency The company enters into forward exchange contracts, generally with terms of 180 days or less, to manage some of its foreign currency exposures. These exposures include revenue and anticipated purchase transactions, including foreign currency capital expenditures and lease commitments, forecasted to occur within 180 days. The forward exchange contracts are recorded at fair value on the balance sheet with resulting gains and losses reflected in income.

The aggregate effect of a hypothetical 10 percent increase in the value of the U.S. dollar at year-end 2006 would be a reduction in the fair value of the foreign exchange contracts of approximately $40 million. The effect would be the opposite for a hypothetical 10 percent decrease in the year-end value of the U.S. dollar.

Interest Rates The company enters into interest rate swaps as part of its overall strategy to manage the interest rate risk on its debt. Under the terms of the swaps, net cash settlements are based on the difference between fixed-rate and floating-rate interest amounts calculated by reference to agreed notional principal amounts. Interest rate swaps related

to a portion of the company’s fixed-rate debt are accounted for as fair value hedges, whereas interest rate swaps related to a portion of the company’s floating-rate debt are recorded at fair value on the balance sheet with resulting gains and losses reflected in income.

At year-end 2006, the weighted average maturity of “receive fixed” interest rate swaps was approximately one year. There were no “receive floating” swaps outstanding at year end. A hypothetical increase of 10 basis points in fixed interest rates would reduce the fair value of the “receive fixed” swaps by approximately $2 million.

For the financial and derivative instruments discussed above, there was not a material change in market risk between 2006 and 2005.

The hypothetical variances used in this section were selected for illustrative purposes only and do not represent the company’s estimation of market changes. The actual impact of future market changes could differ materially due to factors discussed elsewhere in this report, including those set forth under the heading “Risk Factors” in Part I, Item 1A, of the company’s 2006 Annual Report on Form 10-K.

TRANSACTIONS WITH RELATED PARTIES

Chevron enters into a number of business arrangements with related parties, principally its equity affiliates. These arrangements include long-term supply or offtake agreements. Long-term purchase agreements are in place with the company’s refining affiliate in Thailand. Refer to page FS-15 for further discussion. Management believes the foregoing agreements and others have been negotiated on terms consistent with those that would have been negotiated with an unrelated party.

LITIGATION AND OTHER CONTINGENCIES

MTBE Chevron and many other companies in the petroleum industry have used methyl tertiary butyl ether (MTBE) as a gasoline additive. Chevron is a party to approximately 75 lawsuits and claims, the majority of which involve numerous other petroleum marketers and refiners, related to the use of MTBE in certain oxygenated gasolines and the alleged seepage of MTBE into groundwater. Resolution of these actions may ultimately require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE, including personal-injury claims, may be filed in the future.

The company’s ultimate exposure related to these lawsuits and claims is not currently determinable, but could be material to net income in any one period. The company currently does not use MTBE in the manufacture of gasoline in the United States.

RFG Patent Fourteen purported class actions were brought by consumers of reformulated gasoline (RFG)

alleging that Unocal misled the California Air Resources Board into adopting standards for composition of RFG that overlapped with Unocal’s undisclosed and pending patents. Eleven lawsuits are now consolidated in U.S. District Court for the Central District of California and three are consolidated in California State Court. Unocal is alleged to have monopolized, conspired and engaged in unfair methods of competition, resulting in injury to consumers of RFG. Plaintiffs in both consolidated actions seek unspecified actual and punitive damages, attorneys’ fees, and interest on behalf of an alleged class of consumers who purchased “summertime” RFG in California from January 1995 through August 2005. Unocal believes it has valid defenses and intends to vigorously defend against these lawsuits. The company’s potential exposure related to these lawsuits cannot currently be estimated.

Environmental The company is subject to loss contingencies pursuant to environmental laws and regulations that in the future may require the company to take action to correct or ameliorate the effects on the environment of prior release of chemicals or petroleum substances, including MTBE, by the company or other parties. Such contingencies may exist for various sites, including, but not limited to, federal Superfund sites and analogous sites under state laws, refineries, crude oil fields, service stations, terminals,

(BAR CHART)

land development areas, and mining operations, whether operating, closed or divested. These future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.

Although the company has provided for known environmental obligations that are probable and reasonably estimable, the amount of additional future costs may be material to results of operations in the period in which they are recognized. The company does not expect these costs will have a material effect on its consolidated financial position or liquidity. Also, the company does not believe its obligations to make such expenditures have had, or will have, any significant impact on the company’s competitive position relative to other U.S. or international petroleum or chemical companies.

The following table displays the annual changes to the company’s before-tax environmental remediation reserves, including those for federal Superfund sites and analogous sites under state laws.


Millions of dollars	2006			2005			2004

Balance at January 1	$	1,469		$	1,047		$	1,149
Net Additions		366			731			155
Expenditures		(394	)		(309	)		(257	)

Balance at December 31	$	1,441		$	1,469		$	1,047

Chevron’s environmental reserve as of December 31, 2006, was $1,441 million. Included in this balance were remediation activities of 242 sites for which the company had been identified as a potentially responsible party or otherwise involved in the remediation by the U.S. Environmental Protection Agency (EPA) or other regulatory agencies under the provisions of the federal Superfund law or analogous state laws. The company’s remediation reserve for these sites at year-end 2006 was $122 million. The federal Superfund law and analogous state laws provide for joint and several liability for all responsible parties. Any future actions by the EPA or other regulatory agencies to require Chevron to assume other potentially responsible parties’ costs at designated hazardous waste sites are not expected to have a material effect on the company’s consolidated financial position or liquidity.

Of the remaining year-end 2006 environmental reserves balance of $1,319 million, $834 million related to approximately 2,250 sites for the company’s U.S. downstream operations, including refineries and other plants, marketing locations (i.e., service stations and terminals), and pipelines. The remaining $485 million was associated with various sites in the international downstream ($117 million), upstream ($252 million), chemicals ($61 million) and other ($55 million). Liabilities at all sites, whether operating, closed or divested, were primarily associated with the company’s plans and activities to remediate soil or groundwater contamination or both. These and other activities include one or more of the following: site assessment; soil excavation; offsite disposal of contaminants; onsite containment, remediation and/or extraction of petroleum hydrocarbon liquid and vapor from soil; groundwater extraction and treatment; and monitoring of the natural attenuation of the contaminants.

The company manages environmental liabilities under specific sets of regulatory requirements, which in the United States include the Resource Conservation and Recovery Act and various state or local regulations. No single remediation site at year-end 2006 had a recorded liability that was material to the company’s financial position, results of operations or liquidity.

It is likely that the company will continue to incur additional liabilities, beyond those recorded, for environmental remediation relating to past operations. These future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.

Effective January 1, 2003, the company implemented FASB Statement No. 143, Accounting for Asset Retirement Obligations (FAS 143). Under FAS 143, the fair value of a liability for an asset retirement obligation is recorded when there is a legal obligation associated with the retirement of

long-lived assets and the liability can be reasonably estimated. The liability balance of approximately $5.8 billion for asset retirement obligations at year-end 2006 related primarily to upstream and mining properties. Refer to Note 24 on page FS-58 for a discussion of the company’s asset retirement obligations.

For the company’s other ongoing operating assets, such as refineries and chemicals facilities, no provisions are made for exit or cleanup costs that may be required when such assets reach the end of their useful lives unless a decision to sell or otherwise abandon the facility has been made, as the indeterminate settlement dates for the asset retirements prevent estimation of the fair value of the asset retirement obligation.

Refer also to Note 24, on page FS-58, related to FAS 143 and the company’s adoption in 2005 of FASB Interpretation No. (FIN) 47, Accounting for Conditional Asset Retirement Obligations – An Interpretation of FASB Statement No. 143 (FIN 47), and the discussion of “Environmental Matters” on page FS-19.

Income Taxes The company calculates its income tax expense and liabilities quarterly. These liabilities generally are not finalized with the individual taxing authorities until several years after the end of the annual period for which income taxes have been calculated. The U.S. federal income tax liabilities have been settled through 1996 for Chevron Corporation, 1997 for Unocal Corporation (Unocal) and 2001 for Texaco Corporation (Texaco). California franchise tax liabilities have been settled through 1991 for Chevron, 1998 for Unocal and 1987 for Texaco. Settlement of open tax years, as well as tax issues in other countries where the company conducts its businesses, is not expected to have a material effect on the consolidated financial position or liquidity of the company and, in the opinion of management, adequate provision has been made for income and franchise taxes for all years under examination or subject to future examination.

Global Operations Chevron and its affiliates conduct business activities in approximately 180 countries. Besides the United States, the company and its affiliates have significant operations in the following countries: Angola, Argentina, Australia, Azerbaijan, Bangladesh, Brazil, Cambodia, Canada, Chad, China, Colombia, Democratic Republic of the Congo, Denmark, France, India, Indonesia, Kazakhstan, Myanmar, the Netherlands, Nigeria, Norway, the Partitioned Neutral Zone between Kuwait and Saudi Arabia, the Philippines, Republic of the Congo, Singapore, South Africa, South Korea, Thailand, Trinidad and Tobago, the United Kingdom, Venezuela, and Vietnam.

The company’s operations, particularly exploration and production, can be affected by changing economic, regulatory and political environments in the various countries

in which it operates, including the United States. As has occurred in the past, actions could be taken by governments to increase public ownership of the company’s partially or wholly owned businesses or assets or to impose additional taxes or royalties on the company’s operations or both.

Suspended Wells The company suspends the costs of exploratory wells pending a final determination of the commercial potential of the related crude oil and natural gas fields. The ultimate disposition of these well costs is dependent on the results of future drilling activity or development decisions or both. At December 31, 2006, the company had approximately $1.2 billion of suspended exploratory wells included in properties, plant and equipment, an increase of $130 million from 2005 and an increase of $568 million from 2004. More than $300 million of suspended wells were added at the time of the Unocal acquisition in August 2005.

The future trend of the company’s exploration expenses can be affected by amounts associated with well write-offs, including wells that had been previously suspended pending determination as to whether the well had found reserves that could be classified as proved. The effect on exploration expenses in future periods of the $1.2 billion of suspended wells at year-end 2006 is uncertain pending future activities, including normal project evaluation and additional drilling.

Refer to Note 20, beginning on page FS-47, for additional discussion of suspended wells.

Equity Redetermination For oil and gas producing operations, ownership agreements may provide for periodic reassessments of equity interests in estimated crude oil and natural gas reserves. These activities, individually or together, may result in gains or losses that could be material to earnings in any given period. One such equity redetermination process has been under way since 1996 for Chevron’s interests in four producing zones at the Naval Petroleum Reserve at Elk Hills, California, for the time when the remaining interests in these zones were owned by the U.S. Department of Energy. A wide range remains for a possible net settlement amount for the four zones. For this range of settlement, Chevron estimates its maximum possible net before-tax liability at approximately $200 million, and the possible maximum net amount that could be owed to Chevron is

estimated at about $150 million. The timing of the settlement and the exact amount within this range of estimates are uncertain.

Other Contingencies Chevron receives claims from and submits claims to customers, trading partners, U.S. federal, state and local regulatory bodies, governments, contractors, insurers, and suppliers. The amounts of these claims, individually and in the aggregate, may be significant and take lengthy periods to resolve.

The company and its affiliates also continue to review and analyze their operations and may close, abandon, sell, exchange, acquire or restructure assets to achieve operational or strategic benefits and to improve competitiveness and profitability. These activities, individually or together, may result in gains or losses in future periods.

ENVIRONMENTAL MATTERS

Virtually all aspects of the businesses in which the company engages are subject to various federal, state and local environmental, health and safety laws and regulations. These regulatory requirements continue to increase in both number and complexity over time and govern not only the manner in which the company conducts its operations, but also the products it sells. Most of the costs of complying with laws and regulations pertaining to company operations and products are embedded in the normal costs of doing business.

Accidental leaks and spills requiring cleanup may occur in the ordinary course of business. In addition to the costs for environmental protection associated with its ongoing operations and products, the company may incur expenses for corrective actions at various owned and previously owned facilities and at third-party-owned waste-disposal sites used by the company. An obligation may arise when operations are closed or sold or at non-Chevron sites where company products have been handled or disposed of. Most of the expenditures to fulfill these obligations relate to facilities and sites where past operations followed practices and procedures that were considered acceptable at the time but now require investigative or remedial work or both to meet current standards.

Using definitions and guidelines established by the American Petroleum Institute, Chevron estimated its worldwide environmental spending in 2006 at approximately $2.2 billion for its consolidated companies. Included in these expenditures were approximately $870 million of environmental capital expenditures and $1.3 billion of costs associated with the prevention, control, abatement or elimination of hazardous substances and pollutants from operating, closed or divested sites, and the abandonment and restoration of sites.

For 2007, total worldwide environmental capital expenditures are estimated at $1.2 billion. These capital costs are in addition to the ongoing costs of complying with environmental regulations and the costs to remediate previously contaminated sites.

It is not possible to predict with certainty the amount of additional investments in new or existing facilities or amounts of incremental operating costs to be incurred in the future to: prevent, control, reduce or eliminate releases of hazardous materials into the environment; comply with exist-

ing and new environmental laws or regulations; or remediate and restore areas damaged by prior releases of hazardous materials. Although these costs may be significant to the results of operations in any single period, the company does not expect them to have a material effect on the company’s liquidity or financial position.

CRITICAL ACCOUNTING ESTIMATES AND ASSUMPTIONS

Management makes many estimates and assumptions in the application of generally accepted accounting principles (GAAP) that may have a material impact on the company’s consolidated financial statements and related disclosures and on the comparability of such information over different reporting periods. All such estimates and assumptions affect reported amounts of assets, liabilities, revenues and expenses, as well as disclosures of contingent assets and liabilities. Estimates and assumptions are based on management’s experience and other information available prior to the issuance of the financial statements. Materially different results can occur as circumstances change and additional information becomes known.

The discussion in this section of “critical” accounting estimates or assumptions is according to the disclosure guidelines of the Securities and Exchange Commission (SEC), wherein:

	1.		the nature of the estimates or assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change; and
	2.		the impact of the estimates and assumptions on the company’s financial condition or operating performance is material.

Besides those meeting these “critical” criteria, the company makes many other accounting estimates and assumptions in preparing its financial statements and related disclosures. Although not associated with “highly uncertain matters,” these estimates and assumptions are also subject to revision as circumstances warrant, and materially different results may sometimes occur.

For example, the recording of deferred tax assets requires an assessment under the accounting rules that the future realization of the associated tax benefits be “more likely than not.” Another example is the estimation of crude oil and natural gas reserves under SEC rules that require “... geological and engineering data (that) demonstrate with reasonable certainty (reserves) to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made.” Refer to Table V, “Reserve Quantity Information,” beginning on page FS-68, for the changes in these estimates for the three years ending December 31, 2006, and to Table VII, “Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves” on page FS-76 for estimates of proved-reserve values for each of the three years ending December 31, 2004 through 2006, which were based on year-end prices at the time. Note 1 to the Consolidated Financial Statements, beginning on page FS-32, includes a description of the “successful efforts” method of accounting for oil and gas exploration and production activities. The estimates of crude oil and

natural gas reserves are important to the timing of expense recognition for costs incurred.

The discussion of the critical accounting policy for “Impairment of Properties, Plant and Equipment and Investments in Affiliates,” on page FS-21, includes reference to conditions under which downward revisions of proved-reserve quantities could result in impairments of oil and gas properties. This commentary should be read in conjunction with disclosures elsewhere in this discussion and in the Notes to the Consolidated Financial Statements related to estimates, uncertainties, contingencies and new accounting standards. Significant accounting policies are discussed in Note 1 to the Consolidated Financial Statements, beginning on page FS-32. The development and selection of accounting estimates and assumptions, including those deemed “critical,” and the associated disclosures in this discussion have been discussed by management with the Audit Committee of the Board of Directors.

The areas of accounting and the associated “critical” estimates and assumptions made by the company are as follows:

Pension and Other Postretirement Benefit Plans The determination of pension plan obligations and expense is based on a number of actuarial assumptions. Two critical assumptions are the expected long-term rate of return on plan assets and the discount rate applied to pension plan obligations. For other postretirement employee benefit (OPEB) plans, which provide for certain health care and life insurance benefits for qualifying retired employees and which are not funded, critical assumptions in determining OPEB obligations and expense are the discount rate and the assumed health care cost-trend rates.

Note 21, beginning on page FS-48, includes information on the funded status of the company’s pension and OPEB plans at the end of 2006 and 2005, the components of pension and OPEB expense for the three years ending December 31, 2006, and the underlying assumptions for those periods. The note also presents the incremental impact of recording the funded status of each of the company’s pension and OPEB plans at year-end 2006 under the provisions of FASB Statement No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132R (FAS 158).

Pension and OPEB expense is recorded on the Consolidated Statement of Income in “Operating expenses” or “Selling, general and administrative expenses” and applies to all business segments. With the adoption of FAS 158, the year-end 2006 funded status, measured as the difference between plan assets and obligations, of each of the company’s pension and OPEB plans is recognized on the Consolidated Balance Sheet. The funded status of overfunded pension plans is recorded as a long-term asset in “Deferred charges and other assets.” The funded status of underfunded or unfunded

pension and OPEB plans is recorded in “Accrued liabilities” or “Reserves for employee benefit plans.” Amounts yet to be recognized as components of pension or OPEB expense are recorded in “Accumulated other comprehensive income.”

To estimate the long-term rate of return on pension assets, the company uses a process that incorporates actual historical asset-class returns and an assessment of expected future performance and takes into consideration external actuarial advice and asset-class factors. Asset allocations are periodically updated using pension plan asset/liability studies, and the determination of the company’s estimates of long-term rates of return are consistent with these studies. The expected long-term rate of return on U.S. pension plan assets, which account for 70 percent of the company’s pension plan assets, has remained at 7.8 percent since 2002. For the 10 years ending December 31, 2006, actual asset returns averaged 9.7 percent for this plan.

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

The discount rate assumptions used to determine U.S. and international pension and postretirement benefit plan obligations and expense reflect the prevailing rates available on high-quality fixed-income debt instruments. At December 31, 2006, the company selected a 5.8 percent discount rate for the major U.S. pension and postretirement plans. This rate was selected based on Moody’s Aa Corporate Bond Index and a cash flow analysis that matched estimated future benefit payments to the Citigroup Pension Discount Yield Curve as of year-end 2006. The discount rates at the end of 2005 and 2004 were 5.5 percent and 5.8 percent, respectively.

An increase in the expected long-term return on plan assets or the discount rate would reduce pension plan expense, and vice versa. Total pension expense for 2006 was approximately $585 million. As an indication of the sensitivity of pension expense to the long-term rate of return assumption, a 1 percent increase in the expected rate of return on assets of the company’s primary U.S. pension plan would have reduced total pension plan expense for 2006 by approximately $60 million. A 1 percent increase in the discount rate for this same plan, which accounted for about 60 percent of the companywide pension obligation, would have reduced total pension plan expense for 2006 by approximately $160 million.

An increase in the discount rate would decrease pension obligation, thus changing the funded status of a plan recorded on the Consolidated Balance Sheet. The total pension liability on the Consolidated Balance Sheet at December 31, 2006, for underfunded plans was approximately $1.7 billion. As an indication of the sensitivity of pension liabilities to the discount rate assumption, a 0.25 percent increase in the discount rate applied to the company’s primary U.S. pension plan would have reduced the plan obligation by approximately $275 million, which would have changed the plan’s funded status from underfunded to overfunded, resulting in a pension asset of about $250 million. Other plans would be less underfunded as discount rates increase. The actual rates of return on plan assets and discount rates may vary significantly from estimates because of unanticipated changes in the world’s financial markets.

In 2006, the company’s pension plan contributions were approximately $450 million (approximately $225 million to the U.S. plans). In 2007, the company estimates contributions will be approximately $500 million. Actual contribution amounts are dependent upon plan-investment results, changes in pension obligations, regulatory requirements and other economic factors. Additional funding may be required if investment returns are insufficient to offset increases in plan obligations.

For the company’s OPEB plans, expense for 2006 was about $230 million and the total liability, which reflected the underfunded status of the plans at the end of 2006, was $3.3 billion.

As an indication of discount rate sensitivity to the determination of OPEB expense in 2006, a 1 percent increase in the discount rate for the company’s primary U.S. OPEB plan, which accounted for about 75 percent of the company-wide OPEB expense, would have decreased OPEB expense by approximately $25 million. A 0.25 percent increase in the discount rate for the same plan, which accounted for about 90 percent of the companywide OPEB liabilities, would have decreased total OPEB liabilities at the end of 2006 by approximately $70 million.

For the main U.S. postretirement medical plan, the annual increase to company contributions is limited to 4 percent per year. The cap becomes effective in the year of retirement for pre–Medicare-eligible employees retiring on or after January 1, 2005. The cap was effective as of January 1, 2005, for pre–Medicare-eligible employees retiring before that date and all Medicare-eligible retirees. For active employees and retirees under age 65 whose claims experiences are combined for rating purposes, the assumed health care cost-trend rates start with 9 percent in 2007 and gradually drop to 5 percent for 2011 and beyond. As an indication of the health care cost-trend rate sensitivity to the determination of OPEB expense in 2006, a 1 percent increase in the rates for the main U.S. postretirement medical plan, which accounted for about 90 percent of the companywide OPEB obligations, would have increased OPEB expense $8 million.

Differences between the various assumptions used to determine expense and the funded status of each plan and actual experience are not included in benefit plan costs in

the year the difference occurs. Instead, the differences are included in actuarial gain/loss and unamortized amounts have been reflected in “Accumulated other comprehensive loss” on the Consolidated Balance Sheet. Refer to Note 21, beginning on page FS-48, for information on the $2.6 billion of actuarial losses recorded by the company as of December 31, 2006; a description of the method used to amortize those costs; and an estimate of the costs to be recognized in expense during 2007.

Impairment of Properties, Plant and Equipment and Investments in Affiliates The company assesses its properties, plant and equipment (PP&E) for possible impairment whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable. Such indicators include changes in the company’s business plans, changes in commodity prices and, for crude oil and natural gas properties, significant downward revisions of estimated proved-reserve quantities. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, an impairment charge is recorded for the excess of carrying value of the asset over its fair value.

Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles, and the outlook for global or regional market supply and demand conditions for crude oil, natural gas, commodity chemicals and refined products. However, the impairment reviews and calculations are based on assumptions that are consistent with the company’s business plans and long-term investment decisions.

No major impairments of PP&E were recorded for the three years ending December 31, 2006. An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in impairment reviews and impairment calculations is not practicable, given the broad range of the company’s PP&E and the number of assumptions involved in the estimates. That is, favorable changes to some assumptions might have avoided the need to impair any assets in these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired.

Investments in common stock of affiliates that are accounted for under the equity method, as well as investments in other securities of these equity investees, are reviewed for impairment when the fair value of the investment falls below the company’s carrying value. When such a decline is deemed to be other than temporary, an impairment charge is recorded to the income statement for the difference between the investment’s carrying value and its estimated fair value at the time. In making the determination as to whether a decline is other than temporary, the company considers such factors as the duration and extent of the decline, the investee’s financial performance, and the company’s ability and intention to retain its investment for a period that will be sufficient to allow for any anticipated recovery in the investment’s market value. Differing assumptions could affect whether an investment is impaired in any period or

the amount of the impairment and are not subject to sensitivity analysis.

From time to time, the company performs impairment reviews and determines that no write-down in the carrying value of an asset or asset group is required. For example, when significant downward revisions to crude oil and natural gas reserves are made for any single field or concession, an impairment review is performed to determine if the carrying value of the asset remains recoverable. Also, if the expectation of sale of a particular asset or asset group in any period has been deemed more likely than not, an impairment review is performed, and if the estimated net proceeds exceed the carrying value of the asset or asset group, no impairment charge is required. Such calculations are reviewed each period until the asset or asset group is disposed of. Assets that are not impaired on a held-and-used basis could possibly become impaired if a decision is made to sell such assets. That is, the assets would be impaired if they are classified as held-for-sale and the estimated proceeds from the sale, less costs to sell, are less than the assets’ associated carrying values.

Business Combinations – Purchase-Price Allocation Accounting for business combinations requires the allocation of the company’s purchase price to the various assets and liabilities of the acquired business at their respective fair values. The company uses all available information to make these fair value determinations, and for major acquisitions, may hire an independent appraisal firm to assist in making fair-value estimates. In some instances, assumptions with respect to the timing and amount of future revenues and expenses associated with an asset might have to be used in determining its fair value. Actual timing and amount of net cash flows from revenues and expenses related to that asset over time may differ materially from those initial estimates, and if the timing is delayed significantly or if the net cash flows decline significantly, the asset could become impaired.

Goodwill Goodwill acquired in a business combination is not subject to amortization. As required by FASB Statement No. 142, Goodwill and Other Intangible Assets, the company tests such goodwill at the reporting unit level for impairment on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. The goodwill arising from the Unocal acquisition is described in more detail in Note 2, beginning on page FS-34.

Contingent Losses Management also makes judgments and estimates in recording liabilities for claims, litigation, tax matters and environmental remediation. Actual costs can frequently vary from estimates for a variety of reasons. For example, the costs from settlement of claims and litigation can vary from estimates based on differing interpretations of laws, opinions on culpability and assessments on the

amount of damages. Similarly, liabilities for environmental remediation are subject to change because of changes in laws, regulations and their interpretation, the determination of additional information on the extent and nature of site contamination, and improvements in technology.

Under the accounting rules, a liability is recorded for these types of contingencies if management determines the loss to be both probable and estimable. The company generally records these losses as “Operating expenses” or “Selling, general and administrative expenses” on the Consolidated Statement of Income. Refer to the business segment discussions elsewhere in this section for the effect on earnings from losses associated with certain litigation and environmental remediation and tax matters for the three years ended December 31, 2006.

An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in recording these liabilities is not practicable because of the number of contingencies that must be assessed, the number of underlying assumptions and the wide range of reasonably possible outcomes, both in terms of the probability of loss and the estimates of such loss.

NEW ACCOUNTING STANDARDS

EITF Issue No. 04-6, Accounting for Stripping Costs Incurred During Production in the Mining Industry (Issue 04-6) In March 2005, the FASB ratified the earlier Emerging Issues Task Force (EITF) consensus on Issue 04-6, which was adopted by the company on January 1, 2006. Stripping costs are costs of removing overburden and other waste materials to access mineral deposits. The consensus calls for stripping costs incurred once a mine goes into production to be treated as variable production costs that should be considered a component of mineral inventory cost subject to Accounting Research Bulletin (ARB) No. 43, Restatement and Revision of Accounting Research Bulletins. Adoption of this accounting for the company’s coal, oil sands and other mining operations resulted in a $19 million reduction of retained earnings as of January 1, 2006.

FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109 (FIN 48) In July 2006, the FASB issued FIN 48, which became effective for the company on January 1, 2007. This interpretation clarifies the accounting for income tax benefits that are uncertain in nature. Under FIN 48, a company will recognize a tax benefit in the financial statements for an uncertain tax position only if management’s assessment is that its position is “more likely than not” (i.e., a greater than 50 percent likelihood) to be upheld on audit based only on the technical merits of the tax position. This accounting interpretation also provides guidance on measurement methodology, derecognition thresholds, financial statement classification and disclosures, interest and penalties recogni-

tion, and accounting for the cumulative-effect adjustment. The new interpretation is intended to provide better financial statement comparability among companies.

Required annual disclosures include a tabular reconciliation of unrecognized tax benefits at the beginning and end of the period; the amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate; the amounts of interest and penalties recognized in the financial statements; any expected significant impacts from unrecognized tax benefits on the financial statements over the subsequent 12-month reporting period; and a description of the tax years remaining to be examined in major tax jurisdictions.

As a result of the implementation of FIN 48, the company expects to recognize an increase in the liability for unrecognized tax benefits and associated interest and penalties as of January 1, 2007. In connection with this increase in liability, the company estimates retained earnings at the beginning of 2007 will be reduced by $250 million or less. The amount of the liability and impact on retained earnings will depend in part on clarification expected to be issued by the FASB related to the criteria for determining the date of ultimate settlement with a tax authority.

FASB Statement No. 157, Fair Value Measurements (FAS 157) In September 2006, the FASB issued FAS 157, which will become effective for the company on January 1, 2008. This standard defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. FAS 157 does not require any new fair value measurements but would apply to assets and liabilities that are required to be recorded at fair value under other accounting standards. The impact, if any, to the company from the adoption of FAS 157 in 2008 will depend on the company’s assets and liabilities at that time that are required to be measured at fair value.

FASB Statement No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106 and 132(R) (FAS 158) In September 2006, the FASB issued FAS 158, which was adopted by the company on December 31, 2006. Refer to Note 21, beginning on page FS-48, for additional information.


	2006								2005
Millions of dollars, except per-share amounts	4TH Q		3RD Q		2ND Q		1ST Q		4TH Q		3RD Q		2ND Q		1ST Q

REVENUES AND OTHER INCOME
Sales and other operating revenues^1,2	$	46,238	$	52,977	$	52,153	$	53,524	$	52,457	$	53,429	$	47,265	$	40,490
Income from equity affiliates		1,079		1,080		1,113		983		1,110		871		861		889
Other income		429		155		270		117		227		156		217		228

TOTAL REVENUES AND OTHER INCOME		47,746		54,212		53,536		54,624		53,794		54,456		48,343		41,607

COSTS AND OTHER DEDUCTIONS
Purchased crude oil and products²		27,658		32,076		32,747		35,670		34,246		36,101		31,130		26,491
Operating expenses		4,092		3,650		3,835		3,047		3,819		3,190		2,713		2,469
Selling, general and administrative expenses		1,203		1,428		1,207		1,255		1,340		1,337		1,152		999
Exploration expenses		547		284		265		268		274		177		139		153
Depreciation, depletion and amortization		1,988		1,923		1,807		1,788		1,725		1,534		1,320		1,334
Taxes other than on income¹		5,533		5,403		5,153		4,794		5,063		5,282		5,311		5,126
Interest and debt expense		92		104		121		134		135		136		104		107
Minority interests		2		20		22		26		33		24		18		21

TOTAL COSTS AND OTHER DEDUCTIONS		41,115		44,888		45,157		46,982		46,635		47,781		41,887		36,700

INCOME BEFORE INCOME TAX EXPENSE		6,631		9,324		8,379		7,642		7,159		6,675		6,456		4,907
INCOME TAX EXPENSE		2,859		4,307		4,026		3,646		3,015		3,081		2,772		2,230

NET INCOME	$	3,772	$	5,017	$	4,353	$	3,996	$	4,144	$	3,594	$	3,684	$	2,677

PER-SHARE OF COMMON STOCK
INCOME FROM CONTINUING OPERATIONS
– BASIC	$	1.75	$	2.30	$	1.98	$	1.81	$	1.88	$	1.65	$	1.77	$	1.28
– DILUTED	$	1.74	$	2.29	$	1.97	$	1.80	$	1.86	$	1.64	$	1.76	$	1.28

NET INCOME
– BASIC	$	1.75	$	2.30	$	1.98	$	1.81	$	1.88	$	1.65	$	1.77	$	1.28
– DILUTED	$	1.74	$	2.29	$	1.97	$	1.80	$	1.86	$	1.64	$	1.76	$	1.28

DIVIDENDS	$	0.52	$	0.52	$	0.52	$	0.45	$	0.45	$	0.45	$	0.45	$	0.40
COMMON STOCK PRICE RANGE – HIGH	$	75.97	$	67.85	$	62.88	$	62.21	$	64.45	$	65.77	$	59.34	$	62.08
– LOW	$	62.94	$	60.88	$	56.78	$	54.08	$	55.75	$	56.36	$	50.51	$	50.55

¹ Includes excise, value-added and other similar taxes:		$ 2,498		$ 2,522		$ 2,416		$ 2,115		$ 2,173		$ 2,268		$ 2,162		$ 2,116
² Includes amounts for buy/sell contracts:		$ –		$ –		$ –		$ 6,725		$ 5,897		$ 6,588		$ 5,962		$ 5,375

The company’s common stock is listed on the New York Stock Exchange (trading symbol: CVX). As of February 23, 2007,
stockholders of record numbered approximately 223,000. There are no restrictions on the company’s ability to pay dividends.

FS-24

To the Stockholders of Chevron Corporation

Management of Chevron is responsible for preparing the accompanying Consolidated Financial Statements and the related information appearing in this report. The statements were prepared in accordance with accounting principles generally accepted in the United States of America and fairly represent the transactions and financial position of the company. The financial statements include amounts that are based on management’s best estimates and judgment.

As stated in its report included herein, the independent registered public accounting firm of PricewaterhouseCoopers LLP has audited the company’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).

The Board of Directors of Chevron has an Audit Committee composed of directors who are not officers or employees of the company. The Audit Committee meets regularly with members of management, the internal auditors and the independent registered public accounting firm to review accounting, internal control, auditing and financial reporting matters. Both the internal auditors and the independent registered public accounting firm have free and direct access to the Audit Committee without the presence of management.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a–15(f). The company’s management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of its internal control over financial reporting based on the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the results of this evaluation, the company’s management concluded that its internal control over financial reporting was effective as of December 31, 2006.



DAVID J. O’REILLY	STEPHEN J. CROWE	MARK A. HUMPHREY
Chairman of the Board	Vice President	Vice President
and Chief Executive Officer	and Chief Financial Officer	and Comptroller
February 28, 2007

FS-25

To the Stockholders and the Board of Directors of Chevron Corporation:

We have completed integrated audits of Chevron Corporation’s consolidated financial statements and of its internal control over financial reporting as of December 31, 2006, in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

CONSOLIDATED FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) of the Annual Report on Form 10-K present fairly, in all material respects, the financial position of Chevron Corporation and its subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 14 to the Consolidated Financial Statements, the Company changed its method of accounting for buy/sell contracts on April 1, 2006.

As discussed in Note 21 to the Consolidated Financial Statements, the Company changed its method of accounting for defined benefit pension and other postretirement plans on December 31, 2006.

INTERNAL CONTROL OVER FINANCIAL REPORTING

Also, in our opinion, management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that the Company maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is

fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control – Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/PricewaterhouseCoopers LLP

San Francisco, California
February 28, 2007

FS-26


	Year ended December 31
	2006		2005		2004

REVENUES AND OTHER INCOME
Sales and other operating revenues^1,2	$	204,892	$	193,641	$	150,865
Income from equity affiliates		4,255		3,731		2,582
Other income		971		828		1,853

TOTAL REVENUES AND OTHER INCOME		210,118		198,200		155,300

COSTS AND OTHER DEDUCTIONS
Purchased crude oil and products²		128,151		127,968		94,419
Operating expenses		14,624		12,191		9,832
Selling, general and administrative expenses		5,093		4,828		4,557
Exploration expenses		1,364		743		697
Depreciation, depletion and amortization		7,506		5,913		4,935
Taxes other than on income¹		20,883		20,782		19,818
Interest and debt expense		451		482		406
Minority interests		70		96		85

TOTAL COSTS AND OTHER DEDUCTIONS		178,142		173,003		134,749

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE		31,976		25,197		20,551
INCOME TAX EXPENSE		14,838		11,098		7,517

INCOME FROM CONTINUING OPERATIONS		17,138		14,099		13,034
INCOME FROM DISCONTINUED OPERATIONS		–		–		294

NET INCOME	$	17,138	$	14,099	$	$13,328

PER-SHARE OF COMMON STOCK³
INCOME FROM CONTINUING OPERATIONS
– BASIC	$	7.84	$	6.58	$	6.16
– DILUTED	$	7.80	$	6.54	$	6.14
INCOME FROM DISCONTINUED OPERATIONS
– BASIC	$	–	$	–	$	0.14
– DILUTED	$	–	$	–	$	0.14
NET INCOME
– BASIC	$	7.84	$	6.58	$	6.30
– DILUTED	$	7.80	$	6.54	$	6.28

¹ Includes excise, value-added and other similar taxes:		$ 9,551		$ 8,719		$ 7,968
² Includes amounts in revenues for buy/sell contracts; associated costs are in “Purchased crude oil and products.”
Refer also to Note 14, on page FS-43.		$ 6,725		$ 23,822		$ 18,650
³ All periods reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.

See accompanying Notes to the Consolidated Financial Statements.

FS-27


	At December 31
	2006			2005

ASSETS
Cash and cash equivalents	$	10,493		$	10,043
Marketable securities		953			1,101
Accounts and notes receivable (less allowance: 2006 – $175; 2005 – $156)		17,628			17,184
Inventories:
Crude oil and petroleum products		3,586			3,182
Chemicals		258			245
Materials, supplies and other		812			694

Total inventories		4,656			4,121
Prepaid expenses and other current assets		2,574			1,887

TOTAL CURRENT ASSETS		36,304			34,336
Long-term receivables, net		2,203			1,686
Investments and advances		18,552			17,057
Properties, plant and equipment, at cost		137,747			127,446
Less: Accumulated depreciation, depletion and amortization		68,889			63,756

Properties, plant and equipment, net		68,858			63,690
Deferred charges and other assets		2,088			4,428
Goodwill		4,623			4,636

TOTAL ASSETS	$	132,628		$	125,833

LIABILITIES AND STOCKHOLDERS’ EQUITY
Short-term debt	$	2,159		$	739
Accounts payable		16,675			16,074
Accrued liabilities		4,546			3,690
Federal and other taxes on income		3,626			3,127
Other taxes payable		1,403			1,381

TOTAL CURRENT LIABILITIES		28,409			25,011
Long-term debt		7,405			11,807
Capital lease obligations		274			324
Deferred credits and other noncurrent obligations		11,000			10,507
Noncurrent deferred income taxes		11,647			11,262
Reserves for employee benefit plans		4,749			4,046
Minority interests		209			200

TOTAL LIABILITIES		63,693			63,157

Preferred stock (authorized 100,000,000 shares, $1.00 par value; none issued)		–			–
Common stock (authorized 4,000,000,000 shares, $0.75 par value; 2,442,676,580 shares issued at December 31, 2006 and 2005)		1,832			1,832
Capital in excess of par value		14,126			13,894
Retained earnings		68,464			55,738
Notes receivable – key employees		(2	)		(3	)
Accumulated other comprehensive loss		(2,636	)		(429	)
Deferred compensation and benefit plan trust		(454	)		(486	)
Treasury stock, at cost (2006 – 278,118,341 shares; 2005 – 209,989,910 shares)		(12,395	)		(7,870	)

TOTAL STOCKHOLDERS’ EQUITY		68,935			62,676

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	132,628		$	125,833

See accompanying Notes to the Consolidated Financial Statements.

FS-29


		Page(s)

Report of Independent Registered Public Accounting Firm — PricewaterhouseCoopers LLP		FS-26
Consolidated Statement of Income for the three years ended December 31, 2006		FS-27
Consolidated Statement of Comprehensive Income for the three years ended December 31, 2006		FS-28
Consolidated Balance Sheet at December 31, 2006 and 2005		FS-29
Consolidated Statement of Cash Flows for the three years ended December 31, 2006		FS-30
Consolidated Statement of Stockholders’ Equity for the three years ended December 31, 2006		FS-31
Notes to the Consolidated Financial Statements		FS-32 to FS-60


		Page No.
Key Financial Results		FS-2
Income From Continuing Operations by Major Operating Area		FS-2
Business Environment and Outlook		FS-2 to FS-5
Operating Developments		FS-5 to FS-6
Results of Operations		FS-6 to FS-9
Consolidated Statement of Income		FS-9 to FS-10
Selected Operating Data		FS-11
Information Related to Investment in Dynegy Inc.		FS-11
Liquidity and Capital Resources		FS-12 to FS-14
Financial Ratios		FS-14
Guarantees, Off-Balance-Sheet Arrangements and Contractual Obligations, and Other Contingencies		FS-14 to FS-15
Financial and Derivative Instruments		FS-15 to FS-16
Transactions With Related Parties		FS-16
Litigation and Other Contingencies		FS-16 to FS-19
Environmental Matters		FS-19
Critical Accounting Estimates and Assumptions		FS-19 to FS-22
New Accounting Standards		FS-22 to FS-23
Quarterly Results and Stock Market Data		FS-24
Report of Management		FS-25
Report of Independent Registered Public Accounting Firm		FS-26

Consolidated Financial Statements
Consolidated Statement of Income		FS-27
Consolidated Statement of Comprehensive Income		FS-28
Consolidated Balance Sheet		FS-29
Consolidated Statement of Cash Flows		FS-30
Consolidated Statement of Stockholders’ Equity		FS-31

Notes to Consolidated Financial Statements:
Note 1. Summary of Significant Accounting Policies		FS-32 to FS-34
Note 2. Acquisition of Unocal Corporation		FS-34 to FS-35
Note 3. Information Relating to the Consolidated Statement of Cash Flows		FS-35 to FS-36
Note 4. Summarized Financial Data – Chevron U.S.A. Inc.		FS-36
Note 5. Summarized Financial Data – Chevron Transport Corporation Ltd.		FS-36
Note 6. Stockholders’ Equity		FS-36 to FS-37
Note 7. Financial and Derivative Instruments		FS-37 to FS-38
Note 8. Operating Segments and Geographic Data		FS-38 to FS-40
Note 9. Lease Commitments		FS-40
Note 10. Restructuring and Reorganization Costs		FS-40 to FS-41
Note 11. Assets Held for Sale and Discontinued Operations		FS-41
Note 12. Investments and Advances		FS-41 to FS-43
Note 13. Properties, Plant and Equipment		FS-43
Note 14. Accounting for Buy/Sell Contracts		FS-43
Note 15. Litigation		FS-44
Note 16. Taxes		FS-44 to FS-45
Note 17. Short-term Debt		FS-45 to FS-46
Note 18. Long-term Debt		FS-46
Note 19. New Accounting Standards		FS-46 to FS-47
Note 20. Accounting for Suspended Exploratory Wells		FS-47 to FS-48
Note 21. Employee Benefit Plans		FS-48 to FS-53
Note 22. Stock Options and Other Share-Based Compensation		FS-53 to FS-55
Note 23. Other Contingencies and Commitments		FS-55 to FS-58
Note 24. Asset Retirement Obligations		FS-58
Note 25. Common Stock Split		FS-58
Note 26. Other Financial Information		FS-59
Note 27. Earnings Per Share		FS-59 to FS-60
Five-Year Financial Summary		FS-62
Supplemental Information on Oil and Gas Producing Activities		FS-63 to FS-76


	2006						2005						2004
Millions of dollars	U.S.		Int'l.		Total		U.S.		Int'l.		Total		U.S.		Int'l.		Total

Upstream – Exploration and Production	$	4,123	$	8,696	$	12,819	$	2,450	$	5,939	$	8,389	$	1,820	$	4,501	$	6,321
Downstream – Refining, Marketing and Transportation		1,176		1,999		3,175		818		1,332		2,150		497		832		1,329
Chemicals		146		54		200		108		43		151		123		27		150
All Other		403		14		417		329		44		373		512		3		515

Total	$	5,848	$	10,763	$	16,611	$	3,705	$	7,358	$	11,063	$	2,952	$	5,363	$	8,315

Total, Excluding Equity in Affiliates	$	5,642	$	9,050	$	14,692	$	3,522	$	5,860	$	9,382	$	2,729	$	4,024	$	6,753


Item			Page No.

PART I
	1.	Business		3
		(a) General Development of Business		3
		(b) Description of Business and Properties		4
		Capital and Exploratory Expenditures		4
		Upstream — Exploration and Production		4
		Net Production of Crude Oil and Natural Gas Liquids and Natural Gas		5
		Average Sales Prices and Production Costs per Unit of Production		6
		Gross and Net Productive Wells		6
		Reserves		6
		Acreage		7
		Contract Obligations		7
		Development Activities		8
		Exploration Activities		9
		Review of Ongoing Exploration and Production Activities in Key Areas		9
		Sales of Natural Gas and Natural Gas Liquids		24
		Downstream — Refining, Marketing and Transportation		24
		Refining Operations		24
		Gas-to-Liquids		25
		Marketing Operations		25
		Transportation Operations		27
		Chemicals		28
		Other Businesses		29
		Mining		29
		Global Power Generation		29
		Chevron Energy Solutions		29
		Research and Technology		30
		Environmental Protection		30
		Web Site Access to SEC Reports		30
	1A.	Risk Factors		31
	1B.	Unresolved Staff Comments		32
	2.	Properties		32
	3.	Legal Proceedings		32
	4.	Submission of Matters to a Vote of Security Holders		32
		Executive Officers of the Registrant at February 28, 2007		33

PART II
	5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		35
	6.	Selected Financial Data		35
	7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		35
	7A.	Quantitative and Qualitative Disclosures About Market Risk		35
	8.	Financial Statements and Supplementary Data		35
	9.	Changes in and Disagreements With Auditors on Accounting and Financial Disclosure		36
	9A.	Controls and Procedures		36
		(a) Evaluation of Disclosure Controls and Procedures		36
		(b) Management’s Report on Internal Control Over Financial Reporting		36
		(c) Changes in Internal Control Over Financial Reporting		36
	9B.	Other Information		36

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

PART IV
	15.	Exhibits, Financial Statement Schedules		38
		Schedule II — Valuation and Qualifying Accounts		39
		Signatures		40
EXHIBIT 12.1
EXHIBIT 21.1
EXHIBIT 23.1
EXHIBIT 24.1
EXHIBIT 24.2
EXHIBIT 24.3
EXHIBIT 24.4
EXHIBIT 24.5
EXHIBIT 24.6
EXHIBIT 24.7
EXHIBIT 24.8
EXHIBIT 24.9
EXHIBIT 24.10
EXHIBIT 24.11
EXHIBIT 31.1
EXHIBIT 31.2
EXHIBIT 32.1
EXHIBIT 32.2
EXHIBIT 99.1


		We have included, on page 39 of this Annual Report on Form 10-K, Schedule II — Valuation and Qualifying Accounts.


		The Exhibit Index on pages E-1 and E-2 of this Annual Report on Form 10-K lists the exhibits that are filed as part of this report.


	Year Ended December 31
	2006			2005			2004

Employee Termination Benefits:
Balance at January 1	$	91		$	137		$	341
(Deductions) additions (credited) charged to expense		(21	)		(21	)		29
Additions related to Unocal acquisition		—			106			—
Payments		(42	)		(131	)		(233	)

Balance at December 31	$	28		$	91		$	137

Allowance for Doubtful Accounts:
Balance at January 1	$	198		$	219		$	229
Additions charged to expense		61			3			36
Additions related to Unocal acquisition		—			6			—
Bad debt write-offs		(42	)		(30	)		(46	)

Balance at December 31	$	217		$	198		$	219

Deferred Income Tax Valuation Allowance:*
Balance at January 1	$	3,249		$	1,661		$	1,553
Additions charged to deferred income tax expense		1,700			1,593			714
Additions related to Unocal acquisition		—			400			—
Deductions credited to goodwill		(77	)		(60	)		—
Deductions credited to deferred income tax expense		(481	)		(345	)		(606	)

Balance at December 31	$	4,391		$	3,249		$	1,661


*	See also Note 16 to the Consolidated Financial Statements beginning on page FS-44.