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 endedDecember 31, ~~2006~~2007

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

SECURITIES EXCHANGE ACT OF 1934

For the transition period fromto

Commission ~~file number~~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 ofRegulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of thisForm 10-K or any amendment to thisForm 10-K. þ

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

Large accelerated filerþ Accelerated filero Non-accelerated filero Smaller reporting companyo

(Do not check if a smaller

reporting company)

Indicate by check mark whether the registrant is a shell company (as defined inRule 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~~$179,575,224,370 (As of June 30, ~~2006)~~2007)

Number of Shares of Common Stock outstanding as of February ~~23, 2007~~22, 2008 — ~~2,157,780,998~~2,076,680,120

DOCUMENTS INCORPORATED BY REFERENCE

(To The Extent Indicated Herein)

Notice of the ~~2007~~2008 Annual Meeting and ~~2007~~2008 Proxy Statement, to be filed pursuant toRule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company’s ~~2007~~2008 Annual Meeting of Stockholders (in Part III)

TABLE OF CONTENTS


Item	Item		Page No.		Item		Page No.

PART I	PART I				PART I
	1.	Business		3
		(a) General Development of Business		3	1.	Business		3
		(b) Description of Business and Properties		4		(a) General Development of Business		3
		Capital and Exploratory Expenditures		4		(b) Description of Business and Properties		4
		Upstream — Exploration and Production		4		Capital and Exploratory Expenditures		4
		Net Production of Crude Oil and Natural Gas Liquids and Natural Gas		5		Upstream — Exploration and Production		4
		Average Sales Prices and Production Costs per Unit of Production		6		Net Production of Crude Oil and Natural Gas Liquids and Natural Gas		5
		Gross and Net Productive Wells		6		Average Sales Prices and Production Costs per Unit of Production		6
		Reserves		6		Gross and Net Productive Wells		6
		Acreage		7		Reserves		6
		Contract Obligations		7		Acreage		7
		Development Activities		8		Contract Obligations		8
		Exploration Activities		9		Development Activities		8
		Review of Ongoing Exploration and Production Activities in Key Areas		9		Exploration Activities		9
		Sales of Natural Gas and Natural Gas Liquids		24		Review of Ongoing Exploration and Production Activities in Key Areas		9
		Downstream — Refining, Marketing and Transportation		24		Sales of Natural Gas and Natural Gas Liquids		24
		Refining Operations		24		Downstream — Refining, Marketing and Transportation		25
		Gas-to-Liquids		25		Refining Operations		25
		Marketing Operations		25		Gas-to-Liquids		26
		Transportation Operations		27		Marketing Operations		27
		Chemicals		28		Transportation Operations		28
		Other Businesses		29		Chemicals		29
		Mining		29		Other Businesses		30
		Global Power Generation		29		Mining		30
		Chevron Energy Solutions		29		Power Generation		30
		Research and Technology		30		Chevron Energy Solutions		30
		Environmental Protection		30		Research and Technology		31
		Web Site Access to SEC Reports		30		Environmental Protection		31
	1A.	Risk Factors		31		Web Site Access to SEC Reports		31
	1B.	Unresolved Staff Comments		32	1A.	Risk Factors		32
	2.	Properties		32	1B.	Unresolved Staff Comments		33
	3.	Legal Proceedings		32	2.	Properties		33
	4.	Submission of Matters to a Vote of Security Holders		32	3.	Legal Proceedings		33
		Executive Officers of the Registrant at February 28, 2007		33	4.	Submission of Matters to a Vote of Security Holders		33

PART II	PART II				PART II
	5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		35	5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		34
	6.	Selected Financial Data		35	6.	Selected Financial Data		34
	7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		35	7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation		34
	7A.	Quantitative and Qualitative Disclosures About Market Risk		35	7A.	Quantitative and Qualitative Disclosures About Market Risk		34
	8.	Financial Statements and Supplementary Data		35	8.	Financial Statements and Supplementary Data		34
	9.	Changes in and Disagreements With Auditors on Accounting and Financial Disclosure		36	9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		35
	9A.	Controls and Procedures		36	9A.	Controls and Procedures		35
		(a) Evaluation of Disclosure Controls and Procedures		36		(a) Evaluation of Disclosure Controls and Procedures		35
		(b) Management’s Report on Internal Control Over Financial Reporting		36		(b) Management’s Report on Internal Control Over Financial Reporting		35
		(c) Changes in Internal Control Over Financial Reporting		36		(c) Changes in Internal Control Over Financial Reporting		35
	9B.	Other Information		36	9B.	Other Information		35

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

PART IV	PART IV				PART IV
	15.	Exhibits, Financial Statement Schedules		38	15.	Exhibits, Financial Statement Schedules		38
		Schedule II — Valuation and Qualifying Accounts		39		Schedule II — Valuation and Qualifying Accounts		39
		Signatures		40		Signatures		40
EXHIBIT 12.1	EXHIBIT 12.1				EXHIBIT 12.1
EXHIBIT 21.1	EXHIBIT 21.1				EXHIBIT 21.1
EXHIBIT 23.1	EXHIBIT 23.1				EXHIBIT 23.1
EXHIBIT 24.1	EXHIBIT 24.1				EXHIBIT 24.1
EXHIBIT 24.2	EXHIBIT 24.2				EXHIBIT 24.2
EXHIBIT 24.3	EXHIBIT 24.3				EXHIBIT 24.3
EXHIBIT 24.4	EXHIBIT 24.4				EXHIBIT 24.4
EXHIBIT 24.5	EXHIBIT 24.5				EXHIBIT 24.5
EXHIBIT 24.6	EXHIBIT 24.6				EXHIBIT 24.6
EXHIBIT 24.7	EXHIBIT 24.7				EXHIBIT 24.7
EXHIBIT 24.8	EXHIBIT 24.8				EXHIBIT 24.8
EXHIBIT 24.9	EXHIBIT 24.9				EXHIBIT 24.9
EXHIBIT 24.10	EXHIBIT 24.10				EXHIBIT 24.10
EXHIBIT 24.11	EXHIBIT 24.11				EXHIBIT 24.11
EXHIBIT 24.12					EXHIBIT 24.12
EXHIBIT 31.1	EXHIBIT 31.1				EXHIBIT 31.1
EXHIBIT 31.2	EXHIBIT 31.2				EXHIBIT 31.2
EXHIBIT 32.1	EXHIBIT 32.1				EXHIBIT 32.1
EXHIBIT 32.2	EXHIBIT 32.2				EXHIBIT 32.2
EXHIBIT 99.1	EXHIBIT 99.1				EXHIBIT 99.1

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 onForm 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;~~margins; actions of competitors; timing of exploration expenses; 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 orstart-up of planned projects; the potential disruption or interruption of the company’s net production or manufacturing facilities or delivery/transportation networks due to war, accidents, political events, civil unrest, severe weather or ~~severe weather;~~crude-oil production quotas that might be imposed by OPEC (Organization of Petroleum Exporting Countries); 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; gains and losses from asset dispositions or impairments; government-mandated sales, divestitures, recapitalizations, changes in fiscal terms or restrictions on scope of company operations; foreign currency movements compared with the U.S. dollar; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; and the factors set forth under the heading “Risk Factors” on pages 32 and 33 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~~international 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 pagesE-4~~ ~~andE-5~~ ~~of this Annual Report onForm 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 discussionDiscussion of the Unocal acquisition is ~~contained~~ in Note 2 ~~beginning~~ onpage ~~FS-34~~ ~~of this Annual Report onForm 10-K.~~FS-34.

A list of the company’s major subsidiaries is presented on pagesE-4 andE-5. As of December 31, 2007, Chevron had approximately 65,000 employees (including about 6,000 service station employees). Approximately 31,000, or 48 percent, of the company’s employees were employed in U.S. operations.

Overview of Petroleum Industry

Petroleum industry operations and profitability are influenced by many factors, and individual petroleum companies have little control over some of them. Governmental policies, particularly in the areas of taxation, energy and the environment have a significant impact on petroleum activities, regulating how companies are structured and where and how companies conduct their operations and formulate their products and, in some cases, limiting their profits directly. Prices for crude oil and natural gas, petroleum products and petrochemicals are generally determined by supply and demand for these commodities. However, some governments impose price controls on refined products such as gasoline or diesel fuel. The members of the Organization of Petroleum Exporting Countries (OPEC) are typically the world’s swing producers of crude oil, and their production levels are a major factor in determining worldwide supply. Demand for crude oil and its products and for natural gas is largely driven by the conditions of local, national and global economies, although weather patterns and taxation relative to other energy sources also play a significant part. Seasonality is not a primary driver 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 global petroleum companies, as well as independent and national petroleum companies, for the acquisition of crude oil and natural gas leases and other properties and for the equipment and labor required to develop and operate those properties. In its downstream business, Chevron also competes with fully integrated major petroleum companies and other independent refining, marketing and transportation entities 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~~FS-8 of thisForm 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion onof 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~~has established the following ~~strategies, which continue into 2007:~~strategies:

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~~continues 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,~~2007, and assets as of the end of ~~2006~~2007 and ~~2005~~2006 — for the United States and the company’s international geographic areas — are in Note 8 to the ~~consolidated financial statements~~Consolidated Financial Statements beginning onpage ~~FS-38~~ ~~of this Annual Report onForm 10-K.~~FS-37. In addition, similar comparative data for the company’s investments in and income from equity affiliates and property, plant and equipment are in Notes 1211 and 1312 on pages ~~FS-41~~FS-40 to ~~FS-43.~~FS-42.

Capital and Exploratory Expenditures

Total reported expenditures for ~~2006~~2007 were ~~$16.6~~$20 billion, including ~~$1.9~~$2.3 billion for Chevron’s share of expenditures by affiliated companies, which did not require cash outlays by the company. In ~~2005~~2006 and ~~2004,~~2005, expenditures were ~~$11.1~~$16.6 billion and ~~$8.3~~$11.1 billion, respectively, including the company’s share of affiliates’ expenditures of ~~$1.7~~$1.9 billion and ~~$1.6~~$1.7 billion in the corresponding periods. The 2005 amount excludes ~~the~~ $17.3 billion for the acquisition of Unocal.

Of the ~~$16.6~~$20 billion in expenditures for ~~2006, 77~~2007, 78 percent, or ~~$12.8~~$15.5 billion, related to upstream activities. Approximately the same percentage was also expended for upstream operations in ~~2005~~2006 and ~~2004.~~2005. 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,~~2008, the company estimates capital and exploratory expenditures will be 1815 percent higher at ~~$19.6~~$22.9 billion, including ~~$2.4~~$2.6 billion of spending by affiliates. About three-fourths of the total, or ~~$14.6~~$17.5 billion, is budgeted for exploration and production activities, with ~~$10.6~~$12.7 billion of that amount outside the United States.

Refer also to a discussion of the company’s capital and exploratory expenditures onpage ~~FS-13~~ ~~of this Annual Report onForm 10-K.~~FS-12.

Upstream — Exploration and Production

The table on the following page summarizes the net production of liquids and natural gas for ~~2006~~2007 and ~~2005~~2006 by the company and its affiliates.

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


																	Components of Oil-Equivalent
																	Crude Oil & Natural Gas
	Crude Oil & Natural Gas								Memo: Oil-Equivalent				Oil-Equivalent (Thousands				Liquids (Thousands of				Natural Gas (Millions of
	Liquids (Thousands of				Natural Gas (Millions of				(Thousands of				of Barrels per Day)				Barrels per Day)				Cubic Feet per Day)
	Barrels per Day)				Cubic Feet per Day)				Barrels per Day)²				2007		2006		2007		2006		2007		2006
	2006		2005		2006		2005		2006		2005
United States:
California		207		217		101		106		224		235		221		224		205		207		97		101
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
Gulf of Mexico														214		224		118		114		576		661
Texas (Onshore)														153		150		77		79		457		425
Other States														155		165		60		62		569		623

Total United States³		462		455		1,810		1,634		763		727
Total United States														743		763		460		462		1,699		1,810

Africa:
Angola		156		139		47		36		164		145		179		164		171		156		48		47
Nigeria		139		125		29		68		144		136		129		144		126		139		15		29
Chad		34		38		4		3		35		39		32		35		31		34		4		4
Republic of the Congo		11		11		8		8		12		12		8		12		7		11		7		8
Democratic Republic of the Congo³		3		1		2		—		3		1
Democratic Republic of the Congo														3		3		3		3		2		2

Total Africa														351		358		338		343		76		90

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
Thailand														224		216		71		73		916		856
Partitioned Neutral Zone (PNZ)¹														112		114		109		111		17		19
Australia		39		42		360		362		99		102		100		99		39		39		372		360
Kazakhstan		38		37		143		142		62		61		66		62		41		38		149		143
Azerbaijan														61		47		60		46		5		4
Bangladesh														47		21		2		—		275		126
China		23		26		18		—		26		26		26		26		22		23		22		18
Philippines		6		8		108		163		24		35		26		24		5		6		126		108
Bangladesh³		—		—		126		59		21		10
Myanmar³		—		—		89		32		15		5
Indonesia³		198		202		302		211		248		237
Myanmar														17		15		—		—		100		89

Total Asia-Pacific														679		624		349		336		1,982		1,723

Indonesia														241		248		195		198		277		302
Other International:
United Kingdom		75		83		242		300		115		133		115		115		78		75		220		242
Canada³		46		54		6		19		47		57
Denmark		44		47		146		146		68		71		63		68		41		44		132		146
Argentina		38		43		54		55		47		52		47		47		39		38		50		54
Norway		6		8		1		2		6		9
Venezuela⁵		3		4		21		35		7		10
Netherlands³		3		2		7		4		4		3
Canada														36		47		35		46		5		6
Colombia		—		—		174		185		29		31		30		29		—		—		178		174
Trinidad and Tobago		—		—		174		115		29		19		29		29		—		—		174		174
Norway														6		6		6		6		1		1
Netherlands														4		4		3		3		5		7
Venezuela²														—		7		—		3		—		21

Total International³		1,092		1,038		2,940		2,377		1,582		1,434
Total Other International														330		352		202		215		765		825

Total Consolidated Operations³		1,554		1,493		4,750		4,011		2,345		2,161
Equity Affiliates⁶		178		176		206		222		213		213
Total International														1,601		1,582		1,084		1,092		3,100		2,940

Total Including Affiliates^3,7,8		1,732		1,669		4,956		4,233		2,558		2,374
Total Consolidated Operations														2,344		2,345		1,544		1,554		4,799		4,750
Equity Affiliates³														248		213		212		178		220		206

Total Including Affiliates^4,5														2,592		2,558		1,756		1,732		5,019		4,956


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.
5²		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 63 below.
6³		~~Represents~~Equity Affiliates represent 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~~Hamaca 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~~in “other produced volumes.” See footnote 5 below.
7⁴		Includes natural gas consumed in operations of ~~475~~498 million and ~~404~~475 million cubic feet per day in ~~2006~~2007 and ~~2005,~~2006, respectively.
8⁵		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)


Athabasca Oil Sands — net	27	27	27	27	—	—
Boscan Operating Service Agreement³	—	82	—	82	—	—

~~In 2006, Chevron conducted exploration and production operations~~As shown in the ~~United States and approximately 35 other countries. Worldwide~~table on page 5, worldwide oil-equivalent production of ~~2.67~~2.59 million barrels per day in ~~2006,~~2007 was up 34,000 barrels per day from the prior year. Worldwide oil-equivalent production including ~~volumes~~“other produced volumes” (refer to footnote 5 to the table on page 5) was 2.62 million barrels per day, down about 2 percent from ~~oil sands~~2006. The decline was mostly attributable to the change 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.~~a joint-stock company in October 2006. Refer to the “Results of Operations” section beginning onpage FS-6 for a detailed discussion of the factors explaining the ~~2004–2006~~2005–2007 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~~2008 will be approximately ~~2.6~~2.65 million barrels per day. This estimate is subject to many uncertainties, including quotas that may be imposed by OPEC, the price effect on production volumes calculated under cost-recovery and variable-royalty provisions of certain contracts, changes in fiscal terms or restrictions on the scope of company operations, delays in projectstart-ups, 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 onpage ~~FS-68~~ ~~of this Annual Report onForm 10-K~~FS-66 for data about the company’s average sales price per ~~unit~~barrel of crude oil and natural gas liquids and per thousand cubic feet of natural gas produced ~~as well as~~and the average production cost per ~~unit~~oil-equivalent barrel for 2007, 2006 ~~2005~~ and ~~2004.~~2005.

Gross and Net Productive Wells

The following table summarizes gross and net productive wells at year-end ~~2006~~2007 for the company and its affiliates:

Productive Oil and Gas Wells¹ at December 31, ~~2006~~2007


	Productive²				Productive²				Productive²				Productive²
	Oil Wells				Gas Wells				Oil Wells				Gas Wells
	Gross		Net		Gross		Net		Gross		Net		Gross		Net

United States:
California		24,484		22,754		185		58		25,029		23,305		176		44
Gulf of Mexico		2,429		1,788		1,454		1,080		1,600		1,375		1,104		893
Other U.S.		23,602		8,525		10,793		5,074		23,628		8,537		10,929		5,106

Total United States		50,515		33,067		12,432		6,212		50,257		33,217		12,209		6,043

Africa		2,083		702		7		3		2,190		748		8		3
Asia-Pacific		2,394		1,146		1,989		1,251		2,405		1,139		2,308		1,451
Indonesia		7,580		7,434		203		162		8,150		7,991		211		170
Other International		989		621		239		97		1,042		660		256		106

Total International		13,046		9,903		2,438		1,513		13,787		10,538		2,783		1,730

Total Consolidated Companies		63,561		42,970		14,870		7,725		64,044		43,755		14,992		7,773
Equity in Affiliates		1,067		375		—		—		1,072		375		—		—

Total Including Affiliates		64,628		43,345		14,870		7,725		65,116		44,130		14,992		7,773


Multiple completion wells included above:		890		542		390		281		967		587		456		340


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

Reserves

Table V, beginning onpage ~~FS-68,~~FS-66, provides a tabulation of the company’s proved net oil and gas reserves, by geographic area, as of each year-end 2004 through ~~2006~~2007, and an accompanying discussion of major changes to proved

reserves by geographic area for the three-year period. During ~~2006,~~2007, the company provided oil and gas reserves estimates

for ~~2005~~2006 to the Department of Energy, Energy Information ~~Agency. Such~~Administration (EIA), that agree with the 2006 reserve volumes in Table V. This reporting fulfilled the requirement that such estimates are to be consistent with, and do not differ more than 5 percent from, the information furnished to the Securities and Exchange Commission onin the company’s 2006 Annual Report onForm 10-K. During ~~2007,~~2008, the company will file estimates of oil and gas reserves with the Department of Energy, ~~Energy Information Agency,~~EIA, consistent with the 2007 reserve data reported in Table V.

The net proved-reserve balances at the end of each of the three years 2005 through 2007 are shown in the table below:

Net Proved Reserves at December 31


	2007		2006		2005

Liquids* — Millions of barrels
Consolidated Companies		4,665		5,294		5,626
Affiliated Companies		2,422		2,512		2,374
Natural Gas — Billions of cubic feet
Consolidated Companies		19,137		19,910		20,466
Affiliated Companies		3,003		2,974		2,968
Total Oil-Equivalent — Millions of barrels
Consolidated Companies		7,855		8,612		9,037
Affiliated Companies		2,922		3,008		2,869


*		Crude oil, condensate and natural gas liquids

Acreage

At December 31, ~~2006,~~2007, 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~~2007
(Thousands of Acres)


									Developed
									and													Developed and
	Undeveloped²				Developed²				Undeveloped					Undeveloped²				Developed²				Undeveloped
	Gross		Net		Gross		Net		Gross		Net			Gross		Net		Gross		Net		Gross		Net

United States:
California		139		121		206		178		345		299			139		122		185		178		324		300
Gulf of Mexico		3,713		2,690		1,759		1,300		5,472		3,990			2,482		1,828		1,621		1,178		4,103		3,006
Other U.S.		4,651		3,353		5,444		2,626		10,095		5,979			3,800		3,012		5,884		2,588		9,684		5,600

Total United States		8,503		6,164		7,409		4,104		15,912		10,268			6,421		4,962		7,690		3,944		14,111		8,906

Africa		18,448		8,024		2,522		925		20,970		8,949			17,391		7,619		2,520		922		19,911		8,541
Asia-Pacific		50,216		22,680		5,773		2,605		55,989		25,285			52,006		23,660		5,847		2,630		57,853		26,290
Indonesia		10,310		6,545		380		340		10,690		6,885			9,109		5,894		382		340		9,491		6,234
Other International		33,529		19,368		2,267		622		35,796		19,990			35,688		20,022		2,397		664		38,085		20,686

Total International		112,503		56,617		10,942		4,492		123,445		61,109			114,194		57,195		11,146		4,556		125,340		61,751
													��
Total Consolidated Companies		121,006		62,781		18,351		8,596		139,357		71,377			120,615		62,157		18,836		8,500		139,451		70,657
Equity in Affiliates		924		431		252		102		1,176		533			647		302		252		103		899		405

Total Including Affiliates		121,930		63,212		18,603		8,698		140,533		71,910			121,262		62,459		19,088		8,603		140,350		71,062


¹		Gross acreage includes the total number of acres in all tracts in which the company has an interest. Net acreage isincludes wholly owned interests and 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~~on which wells have not been drilled or completed to permit commercial production and that may contain undeveloped proved reserves. The gross undeveloped acres that will expire in ~~2007,~~ 2008, 2009 and ~~2009~~2010 if production is not established by certain required dates are ~~12,459, 7,731~~7,770, 10,860 and ~~10,207,~~4,288, 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~~some 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~~456 billion cubic feet of natural gas through ~~2009 from U.S. reserves.~~2010. 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~~631 billion cubic feet of natural gas from ~~2007~~2008 through ~~2009~~2010 from Argentina, Australia, Canada, Colombia, Denmark and the Philippines. The sales contracts contain variable pricing formulas that are generally referenced to the prevailing market price for crude oil, natural gas or other petroleum products at the time of delivery 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, Denmark and the Philippines. The company plans to meet its Canadian contractual delivery commitments of 2730 billion cubic feet through third-party purchases.

Development Activities

Details of the company’s development expenditures and costs of proved property acquisitions for 2007, 2006 ~~2005~~ and ~~2004~~2005 are presented in Table I onpage ~~FS-63~~ ~~of this Annual Report onForm 10-K.~~FS-61.

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.~~2007. 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												Wells Drilling				Net Wells Completed^1,2
	12/31/06³				2006				2005				2004				at 12/31/07³				2007				2006				2005
	Gross		Net		Prod.		Dry		Prod.		Dry		Prod.		Dry		Gross		Net		Prod.		Dry		Prod.		Dry		Prod.		Dry

United States:
California		12		3		600		—		661		—		636		1		5		1		620		—		600		—		661		—
Gulf of Mexico		14		8		34		5		29		3		43		3		39		18		30		1		34		5		29		3
Other U.S.		8		8		317		6		256		4		221		3		11		10		225		4		317		6		256		4

Total United States		34		19		951		11		946		7		900		7		55		29		875		5		951		11		946		7

Africa		10		3		45		2		38		—		36		—		8		3		43		—		45		2		38		—
Asia-Pacific⁴		88		48		235		1		150		—		84		—
Asia-Pacific																		13		4		223		—		235		1		150		—
Indonesia		6		6		258		—		107		—		163		—		—		—		374		—		258		—		107		—
Other International⁴		7		2		43		—		79		—		84		—
Other International																		4		—		52		—		43		—		79		—

Total International		111		59		581		3		374		—		367		—		25		7		692		—		581		3		374		—

Total Consolidated Companies		145		78		1,532		14		1,320		7		1,267		7		80		36		1,567		5		1,532		14		1,320		7
Equity in Affiliates		—		—		13		—		23		—		20		—		—		—		3		—		13		—		23		—

Total Including Affiliates		145		78		1,545		14		1,343		7		1,287		7		80		36		1,570		5		1,545		14		1,343		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 the process of drilling, including wells for which drilling was not completed and which were temporarily suspended at the end of ~~2006.~~2007. Gross wells include the total number of wells in which the company has an interest. Net wells include wholly owned wells and the sum of the company’s fractional interests in gross wells.
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.~~2007. “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																Wells
	Drilling				Net Wells Completed^1,2												Drilling				Net Wells Completed^1,2
	at 12/31/06³				2006				2005				2004				at 12/31/07³				2007				2006				2005
	Gross		Net		Prod.		Dry		Prod.		Dry		Prod.		Dry		Gross		Net		Prod.		Dry		Prod.		Dry		Prod.		Dry

United States:
California		—		—		—		—		—		—		—		—		—		—		—		—		—		—		—		—
Gulf of Mexico		6		3		9		8		14		8		13		8		12		5		4		7		9		8		14		8
Other U.S.		1		1		7		—		5		6		3		1		—		—		—		1		7		—		5		6

Total United States		7		4		16		8		19		14		16		9		12		5		4		8		16		8		19		14

Africa		4		1		1		—		4		1		3		1		35		15		6		2		1		—		4		1
Asia-Pacific		15		9		18		7		10		—		16		—		1		1		14		10		18		7		10		—
Indonesia		—		—		2		—		5		—		2		—		—		—		1		—		2		—		5		—
Other International⁴		5		1		6		3		7		4		3		7
Other International																		3		1		5		2		6		3		7		4

Total International		24		11		27		10		26		5		24		8		39		17		26		14		27		10		26		5

Total Consolidated Companies		31		15		43		18		45		19		40		17		51		22		30		22		43		18		45		19
Equity in Affiliates⁴		—		—		1		—		8		—		—		—
Equity in Affiliates																		—		—		41		—		1		—		8		—

Total Including Affiliates		31		15		44		18		53		19		40		17		51		22		71		22		44		18		53		19


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 which were temporarily suspended at the end of ~~2006.~~2007. Does not include wells for which drilling was completed at year-end ~~2006~~2007 and that were reported as suspended wells in Note 2019 beginning onpage FS-47. Gross wells include the total number of wells in which the company has an interest. Net wells include wholly owned wells and the sum of the company’s fractional interests in gross wells.
4		~~2005 conformed to 2006 presentation.~~

Details of the company’s exploration expenditures and costs of unproved property acquisitions for 2007, 2006 ~~2005~~ and ~~2004~~2005 are presented in Table I onpage ~~FS-63~~ ~~of this Annual Report onForm 10-K.~~FS-61.

Review of Ongoing Exploration and Production Activities in Key Areas

Chevron’s ~~2006~~2007 key upstream activities, some of which are also discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations beginning onpage 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 onpage ~~E-11~~E-23. ~~of this Annual Report onForm 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~~that follows references the status of proved reserves recognition for significant long-lead-time projects not yet on production and for projects recently placed on production. Reserves are not discussed for recent discoveries that have yet to advance to a project stage ~~and~~or for mature areas of production that do not have individual projects requiring significant levels of capital or exploratory investment. Amounts indicated for project costs represent total project costs, not the company’s share of costs for projects that are less than wholly owned. In addition to the activities discussed, Chevron was active in ~~mature areas.~~other geographic areas, but those activities are considered less significant.

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 aton the left indicates Chevron’s primary areas of production and exploration as well as the potential target markets for the company’s natural gas resources.

~~a) United States~~


a)	United States

Upstream activities in the United States are concentrated in California, the Gulf of Mexico, Louisiana, Texas, New Mexico, the Rocky Mountains and ~~California.~~Alaska. Average ~~daily~~ net oil-equivalent production during ~~2006~~2007 was ~~462,000~~743,000 barrels per day, composed of 460,000 barrels of crude oil and natural gas liquids and ~~1.8~~1.7 billion cubic feet of natural ~~gas, or 763,000 barrels per day on an oil-equivalent basis.~~gas. Refer to Table V beginning onpage ~~FS-68~~FS-66 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,~~2007, average ~~daily~~ netoil-equivalent production was ~~202,000~~221,000 barrels per day, composed of 200,000 barrels of crude oil, ~~101~~97 million cubic feet of natural gas and 5,000 barrels of natural gas ~~liquids, or 224,000 barrels of oil-equivalent.~~liquids. Approximately 80 percent of the ~~crude oil~~crude-oil production is considered heavy oil (typically with API gravity lower than 22 degrees).


		Gulf of Mexico:Average ~~daily~~ net oil-equivalent production ~~rates~~ during ~~2006~~2007 for the company’s combined interests in the Gulf of Mexico shelf and deepwater areas, and the onshore fields ~~onshore Louisiana were 102,000~~in the region was 214,000 barrels per day. The daily oil-equivalent production comprised 105,000 barrels of crude oil, ~~661~~576 million cubic feet of natural gas and ~~12,000~~13,000 barrels of natural gas ~~liquids, or 224,000 barrels~~liquids. During 2007, Chevron was engaged in various development and exploration activities in the deepwater Gulf of ~~oil-equivalent. Net production~~Mexico. Development work continued at the ~~end~~58 percent-owned and operated Tahiti Field, where productionstart-up is expected in the third quarter 2009. Construction of ~~2006~~
the spar hull and topsides was ~~approximately the same rate, which reflects restoration of most~~completed in 2007; however, installation of the ~~volumes that~~spar hull was delayed for about one year when testing revealed a metallurgical problem with the mooring shackles. Six development wells were ~~economic~~drilled in 2007, and flow-back tests for five of the six were completed during the year. 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 productionstart-up. With an estimated production life of 30 years, Tahiti is designed to ~~restore following the~~have a maximum total daily 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~~of 125,000 barrels of crude oil and 1070 million cubic feet of natural ~~gas, or 9,000 barrels of oil-equivalent.~~

	•	~~Petronius — 50 percent-owned and operated~~gas. The total cost for this project is estimated at $4.7 billion and includes ~~the Perseus discovery, which started production from the Petronius platform in 2005. Daily net production in 2006 was 20,000 barrels~~a planned second phase of ~~crude oil~~field development afterstart-up that involves additional wells 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.facility upgrades.

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~~Also under development ~~and exploration activities in~~is the ~~deepwater Gulf of Mexico. Development work continued at the 58 percent-owned and operated Tahiti Field, where productionstart-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~~75 percent-owned and operated Blind Faith discovery, in which the company increased its ownership from 63 percent in July 2007. Three development wells were drilled, and construction of the topsides and hull was completed in 2007. The project includes a subsea development plan, ~~utilizing~~with tieback to a ~~semi-submersible~~semisubmersible floating production ~~system was approved by Chevron~~facility that had an original daily-production design capacity of 45,000 barrels of crude oil and ~~its partner~~45 million cubic feet of natural gas based on the initial three-well development program. A fourth development well and associated facility upgrades are planned to commence in ~~late 2005,~~the first half of 2008. The facility upgrades are planned to increase the daily capacity to 60,000 barrels of crude oil and 60 million cubic feet of natural gas. Initial daily total production, including the fourth well, is estimated at ~~which time~~45,000 to 60,000 barrels of crude oil and 45 million to 60 million cubic feet of natural gas. Proved undeveloped reserves for the ~~company made its initial booking of proved undeveloped reserves. Development drilling at Blind Faith commenced~~project were recognized in ~~early 2007.~~2005. Reclassification of the reserves to the proved developed category is anticipated near the time of productionstart-up in the second quarter 2008. ~~Initial total daily production rates for the field are~~The 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~~The company ~~announced its decision to participate~~is also participating in the ultra-deep Perdido Regional ~~Development in the U.S. Gulf of Mexico.~~Development. The ~~development~~project 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. Activities during 2007 included facility construction and development drilling. First oil is expected ~~to occur by~~in 2010, with the facility capable of handling 130,000 barrels of oil-equivalent per day. ~~The company’s initial booking of proved~~Proved undeveloped reserves ~~occurred~~related to the project were first recorded in 2006, and the phased reclassification of these reserves to the proved developed category is anticipated near the time of productionstart-up. The project has an expected life of approximately 25 years.

~~Exploration~~Deepwater exploration activities in ~~2006~~2007 included participation in 12 exploratory wells — six wildcat and six appraisal. Exploratory work 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.following:


	•	Big Foot — 60 percent-owned and operated. A successful appraisal well was completed in January 2008.

	•	Jack — 50 percent-owned and operated. A second appraisal well is scheduled for completion in the second quarter 2008.

	•	Saint Malo — 41 percent-owned and operated. Located near the Jack discovery, a second appraisal well drilled in 2007 is scheduled for completion by the end of the first quarter 2008.

	•	Tubular Bells — 30 percent-owned and nonoperated working interest. The second appraisal well began drilling in 2007 and is scheduled for completion in the first quarter 2008.

	•	Knotty Head — 25 percent-owned and nonoperated working interest. Discovered in 2005, subsurface studies were in progress in early 2008.

	•	Puma — 22 percent-owned and nonoperated working interest. Two appraisal wells were drilled in 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.


	•	West Tonga — 21 percent-owned and nonoperated working interest. A successful discovery well was drilled in 2007.

At the end of ~~2006,~~2007, 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~~continued the federal, state and local permitting process during 2007 and early 2008 for ~~construction of~~ a proposed 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~~for the ~~facility.~~proposed terminal. 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~~natural gas processing capacity of 1.3 billion cubic feet per day. AThe decision to construct ~~the~~a 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 beginning in 2009 at the third party-owned Sabine Pass LNG terminal ~~beginning~~that is expected to be commissioned in ~~2009.~~the second quarter 2008. Also in the Sabine Pass area in Louisiana, the company has upa binding agreement to be one of the anchor shippers in a 3.2 billion-cubic-foot-per-day third party-owned natural gas pipeline. Chevron will have 1.6 billion cubic feet per day of capacity in the pipeline, of which 1 billion cubic feet per day ~~of pipeline capacity~~is in a new pipeline ~~that will be connected~~and 600 million cubic feet per day is interconnecting capacity to ~~the Sabine Pass LNG terminal.~~an existing pipeline. 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~~across the ~~midcontinent~~mid-continental United States ~~that extend from the Rockies to southern Texas. In~~and Alaska. During 2007 in the Piceance Basin of northwestern Colorado, the company ~~drilled 14 tight-gas delineation wells during 2006 on the Skinner Ridge properties. Development~~commenced development drilling ~~is scheduled to begin~~ in the ~~second quarter~~basin’s tight-gas formation. Facilities to produce 50 million cubic feet of natural gas per day are expected to start up in 2009. The Piceance project, in which the company holds a 100 percent operated working interest, is scalable, and the work is planned to be completed in multiple phases over the 15- to20-year project life. The plans include expanding facilities to a production capacity of 450 million cubic feet per day. The total cost for this project is estimated at $7.3 billion. Also during 2007, ~~with~~Chevron initiated redevelopment programs in three offshore fields in Alaska’s Cook Inlet, where the ~~delivery of two custom-built drilling rigs. Chevron also~~company operates 10 offshore platforms and five producing natural gas ~~fields in Alaska’s Cook Inlet and~~fields. The company also owns nonoperated working interest production and exploratory acreage at the White Hills prospect on the North ~~Slope.~~Slope of Alaska. During ~~2006,~~2007, the company’s ~~operations~~production outside California and the Gulf of Mexico averaged ~~daily~~308,000 net ~~production~~oil-equivalent barrels per day, composed of ~~141,000~~104,000 barrels of crude oil, ~~and natural gas liquids and about~~ 1 billion cubic feet of natural gas ~~(315,000~~and 33,000 barrels of ~~oil-equivalent).~~natural gas liquids.

~~b) Africa~~


b)	Africa


		Angola:Chevron ~~has~~holds company-operated working interests in ~~four concessions in Angola —~~ Blocks 0 and 14 ~~which are company-operated,~~ and nonoperated working interests in Block 2 and the ~~FST area, which are nonoperated.~~Fina Sonangol Texaco (FST) area. In 2007, daily net production was 179,000 barrels of oil-equivalent. The 39 percent-owned Block 0 and 31 percent-owned Block 14 are off the west coast, north of the Congo River. In Block 0, the company operates in two areas — A and B — composed of 2021 fields that produced ~~127,000~~120,000 barrels per day of net liquids in ~~2006.~~2007. The Block 0 concession extends through 2030. Area A of Block 0 comprises 1415 producing fields and averaged daily net production of approximately ~~67,000~~65,000 barrels of crude oil and 1,000 barrels of liquefied petroleum gas (LPG) in ~~2006.~~2007. This production includes volumes from the Banzala Field that produced first oil in June 2007. The ~~first phase of~~ development of the Mafumeira Field in Area A ~~was approved~~continued in ~~2006~~2007 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.~~2009. Maximum total daily production is expected to be approximately 30,000 barrels of crude oil in 2011.

Also in Area A, construction continued during 2007 on the Takula Gas Processing Platform and on projects for the Cabinda Gas Plant and the Flare and Relief Modification. These three projects, called the Area A Gas Management projects, are scheduled to start up in 2009 and are expected to eliminate the routine flaring of natural gas by reinjecting excess natural gas into various reservoirs.

In Area B of Block 0, average daily net production in 2007 from six producing fields was ~~52,000~~47,000 barrels of crude oil and condensate and 7,000 barrels of ~~LPG in 2006.~~LPG. Included in this production were ~~28,000 barrels of liquids per day~~volumes from the Sanha condensate natural gas utilization and Bomboco crude oil ~~project. Initial reclassification~~project that was completed in mid-2007. During 2007, a portion of ~~reserves from~~the proved undeveloped ~~to proved developed~~reserves for this project ~~occurred in 2004 and is expected~~was reclassified 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.~~proved developed category.

In Block 14, net production in 2007 from the ~~Kuito,~~Benguela, Belize, Lobito, Tomboco, Kuito and Landana fields averaged ~~25,000~~48,000 barrels of ~~crude oil~~liquids per ~~day in 2006. Belize and Lobito are part~~day. During 2007, development of the Benguela Belize-Lobito Tomboco (BBLT) ~~development project. Phase 1~~project continued, with production of ~~the BBLT project involved the installation of an integrated drilling and production platform and the~~

~~development of~~first oil at 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.~~Further development drilling is expected to continue at all BBLT fields. 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.~~late 2008 or early 2009. Proved undeveloped reserves for Benguela and Belize were initially recognized in 1998 and for Lobito and Tomboco in 2000. ~~Certain proved~~Proved developed reserves for Belize and Lobito were recognized in 2006 and ~~additional~~for Benguela and Tomboco in 2007. Additional BBLT reserves are expected to be reclassified to proved developed as project milestones are met. ~~The concession period~~Development and production rights for these fields ~~expires~~expire in 2027.

Another major project in Block 14 is the development of the Tombua and Landana fields. Construction onof facilities continued in 2007. Production from the ~~project started in 2006.~~Landana North reservoir is utilizing the BBLT infrastructure. The maximum total daily production from Tombua and Landana 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.~~2011. 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.~~2006 and continued in 2007. Further reclassification is expected ~~from~~between 2009 when theTombua-Landana facilities are completed ~~through~~and 2012 when the drilling program is scheduled for completion. ~~The concession~~Development and production rights for these fields ~~expires~~expire in 2028. ~~The total cost of theTombua-Landana~~ ~~project is estimated at $3.8 billion.~~

~~Four~~As of early 2008, the Negage project in Block 14 was under evaluation. Front-end engineering and design (FEED) for this project was expected to begin in late 2008, with the date of productionstart-up yet to be determined.

Three exploration wells were drilled in Block 14 in ~~2006. One~~2007, one of which successfully appraised the 2006 Lucapa discovery. In the Malange Pinda prospect, one well resulted in a ~~crude oil~~crude-oil discovery, atand as of early 2008, evaluation was ongoing for the ~~deepwater Lucapa prospect. A second~~third 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~~first quarter 2007. Appraisal drilling of the discoveries is expected to continue in 2008.

~~In Chevron’s other two concessions, the nonoperated working interests are~~Chevron also has a 20 percent interest in a production-sharing contract (PSC) that covers Block 2, which is adjacent to the northwestern part of Angola’s coast south of the Congo River, and a 16 percent interest in the onshore FST area. Combined net production from these properties in ~~2006~~2007 was ~~4,000~~3,000 barrels of ~~crude oil~~liquids per day.

~~In addition~~Refer also to ~~the producing activities~~page 23 for a discussion of affiliate operations 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.Angola.

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.~~concession for offshore properties. Daily net production from seven fields averaged 3,000 barrels of ~~crude oil~~oil-equivalent in ~~2006.~~2007.

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.~~offshore. Net production from the Republic of the Congo fields averaged ~~11,000~~8,000 barrels of ~~crude oil~~oil-equivalent per day in ~~2006.~~2007. The Moho-Bilondo development continued in ~~2006,~~2007, with first production expected in the second half 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~~90,000 barrels of crude oil is expected byin 2010. Proved undeveloped reserves were initially recognized in 2001. Transfer to the proved developed category is expected near the time of first production. ~~The~~Chevron’s development and production rights for Moho-Bilondo ~~concession expires~~expire in 2030.

Two exploration wells were drilled in the Moho-Bilondo permit area during 2007 and were determined to have oil accumulations. As of early 2008, results continued under evaluation.

Angola-Republic of the Congo Joint Development Area: Chevron is the operator and holds a 31 percent interest in the Lianzi Development Area (formerly referenced as the 14K/A-IMI ~~Unit,~~Unitization Zone), located in a joint development area shared equally between Angola and Republic of the Congo. In 2006, ~~Chevron submitted a conceptual field~~the development ~~plan to a~~of the Lianzi area was approved by the committee of representatives from the two ~~countries.~~countries, and a conceptual field development plan was also submitted to this committee. In early 2007, one additional exploration well was drilled in the Lianzi area, but the results were considered subcommercial. As of early 2008, development studies and planning continued for this area.

Chad/Cameroon: Chevron is a nonoperating partner in a project to develop ~~crude oil~~crude-oil fields in southern Chad and transport the ~~crude oil~~produced volumes by pipeline to the coast of Cameroon for export. Chevron has a 25 percent nonoperated working interest in the producing operations and a 21 percent interest in two affiliates that own the pipeline. Average daily net production from ~~five~~six fields in ~~2006~~2007 was ~~34,000~~32,000 barrels of ~~crude oil. The first of the satellite-field~~oil-equivalent, including volumes from a satellite field development ~~projects was completed~~project in the ~~first quarter of 2006, and~~Maikeri Field that produced first oil in July 2007. In late 2007, a development application 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~~submitted for ~~funding~~another satellite field, Timbre, in the ~~second half of 2006, with first oil anticipated for fourth quarter 2007.~~Doba area. 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~~onshore Block 177 exploration license. Evaluation of seismic data ~~is scheduled for completion~~was completed in late ~~2007. A~~2007, and an exploratory drilling program is scheduled for 2008.


		~~Equatorial Guinea:~~Nigeria: ~~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 1413 concessions predominantly in the onshore and near-offshore regions of the Niger ~~Delta. CNL~~Delta and varying interests in deepwater offshore blocks. In the Niger Delta, the company operates under a joint-venture arrangement with the Nigerian National Petroleum Corporation (NNPC), which owns a 60 percent interest. In ~~2006, daily~~2007, net oil- equivalent production from 3032 fields averaged ~~137,000~~129,000 barrels per day. The daily oil-equivalent rate comprised 126,000 barrels of ~~crude oil, 29~~liquids and 15 million cubic feet of natural ~~gas and 2,000 barrels of LPG.~~gas. ~~During 2006,~~In the ~~company continued development activities for the deepwater Agbami project, in which~~Niger Delta, Chevron has a 6840 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~~interest in the ~~central Niger Delta. Discovered~~South Offshore Water Injection Project (SOWIP), an enhancedcrude-oil recovery project 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~~90 aimed at increasing production through water injection, natural-gas lift and production debottlenecking in the Okan and Delta fields. The upgraded Delta South Water Injection Platform (DSWIP), which is part of SOWIP, began water injection in March 2007 at a total daily rate of 100,000 barrels. The total maximum daily water injection rate
is expected to increase to 240,000 barrels in 2009 upon the laying of water injection pipelines. Crude-oil production at year-end 2007 was approximately 5,000 barrels per day, and maximum total production is expected to be 35,000 barrels per day in 2010. Initial recognition of proved reserves was made in 2005. Reclassification of additional proved undeveloped reserves to the developed category is expected to occur after the evaluation of the water injection performance. The estimated life of the project is 25 years.

During 2007, the company continued development activities of deepwater offshore projects. The 68 percent-owned and operated deepwater Agbami project in OML 127 and OML ~~128. Agbami~~128 is ~~designed as an all-subsea~~a 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.~~vessel, which was delivered from South Korea in December 2007. Development drilling and completion operations ~~were conducted throughout 2006.~~

~~During~~started in 2006, ~~the Agbami development achieved the following major milestones: the FPSO hull was floated out~~and subsea installation of ~~drydock~~production equipment began 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~~ Maximum total daily production of 250,000 barrels of crude oil and natural gas liquids is ~~expected to be reached~~anticipated within ~~the first~~one year afterstart-up, inwhich is expected by the ~~second half~~third quarter 2008. The company initially recognized proved undeveloped reserves for Agbami in 2002. A portion of the proved undeveloped reserves ~~will~~is scheduled to be reclassified to proved developed in ~~advance of~~2008 near productionstart-up. The expected field life is approximately 20 years. The total cost for this project is estimated at $5.4 billion.

~~For Chevron’s~~The Aparo ~~discovery~~Field 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~~and OML 140 and the Bonga SW Field in OML 118 ~~(formerly OPL 212) for~~share a common geologic structure and are planned to be jointly developed. The geologic structure lies 70 miles offshore in 4,300 feet of water. Apre-unit agreement was executed between Chevron and the ~~unitization and joint development of Aparo, which straddles~~ OML ~~132 and OPL 249. Negotiation of final~~118 partner group in 2006. Final terms for a unitization agreement ~~for this development was ongoing as~~are expected to be completed in mid-2008. In 2007, FEED and tendering of ~~early 2007. Front-end engineering and design (FEED) continued through 2006, and discussions were under way in early 2007 with potential contractors.~~major contracts continued. Development will likely involve an FPSO vessel and subsea wells. Partners are expected to make the final investment decision ~~during 2007,~~in the second half 2008, with productionstart-up ~~estimated to occur in 2011.~~projected for 2012. Maximum total production of 150,000 barrels of crude oil per day is expected to be reached within one year of productionstart-up. The company recognized initial proved undeveloped reserves in 2006 for its approximate 20 percent nonoperated working interest in the unitized ~~project.~~area. The expected production life of this project is 20 years.

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~~OML 138 and designed to utilize an 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.~~vessel. The company recognized proved undeveloped reserves ~~for the project~~ in 2004. Productionstart-up is estimated for late 2011, before which time ~~certain~~a portion of proved undeveloped reserves ~~are~~is 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 ofstart-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~~OML 140. As of early 2008, subsurface evaluations and field development planning ~~ongoing~~were ongoing. An investment decision is contingent on negotiations concerning the level of Nigerian content 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 initialstart-up,~~ ~~targeted for 2012. At~~ the ~~end of 2006, no proved reserves had been recognized for this project.~~project’s contracts.

The company has a 46 percent nonoperated interest in the Nnwa Field in OML 129, ~~(formerly OPL 218) was discovered in 1999 and~~which contains a discovery that 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.~~blocks not owned by Chevron. Commerciality ~~of these fields~~ is dependent upon resolution of the Nigerian Deepwater Gas fiscal regime and collaboration agreements with the adjacent blocks. A joint study was initiated in 2007 with owners in adjoining block OML 135 to progress technical and commercial evaluations.

Chevron participated in two deepwater exploration wells during 2007. The ~~Bilah Field~~Uge 2 well, drilled as an appraisal well to the Uge 1 discovery in Oil Prospecting License (OPL) 214, confirmed hydrocarbons. The company has a 20 percent nonoperated working interest in OPL 214. The second well was ~~under evaluation~~deemed noncommercial. Two additional deepwater exploration wells are planned in ~~early 2007 for further appraisal and the viability of a stand-alone condensate liquid recovery scheme.~~2008.

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 theUge-1~~ ~~well in the 20 percent-owned and nonoperated offshore OPL 214. Future drilling is contingent primarily on completing technical studies.~~

~~Chevron~~also is involved in projects in ~~Nigeria~~the Niger Delta region that support the company’s strategic initiative to commercialize its significant natural gas resource base outside the United States. Construction ~~began in early 2006~~is under way on the Phase 3A expansion of the Escravos Gas Plant (EGP)~~. Engineering, procurement and construction are~~, which is expected to ~~continue through 2007, withstart-up~~ ~~targeted for early~~start up in 2009. ~~The scope of EGP~~ Phase 3A scope includes offshore natural gas gathering and compression infrastructure and a second ~~plant,~~gas processing facility, 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~~12,000 to ~~43,000~~47,000 barrels per day. EGP Phase 3A is designed to process natural gas from the Meji, Delta South, Okan and Mefa producing fields. 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 2526 for a discussion onof the plannedgas-to-liquids facility at Escravos.

Chevron holds a 3837 percent interest in the West African Gas Pipeline, which is ~~expected~~designed 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~~First gas is anticipated to be shipped by mid-2008, and facility completion, with a capacity of 170 million cubic feet of natural gas per day, is expected in the ~~West African Gas Pipeline connects to an existing onshore pipeline in Nigeria.~~second-half 2008. Chevron is the managing sponsor in the West African Pipeline Company Limited affiliate, which constructed, owns and ~~will operate~~operates the412-mile pipeline.

In ~~February 2006,~~March 2007, Chevron signed a ~~Project Development Agreement~~shareholders’ agreement for a 19 percent ~~nonoperated working~~ interest in the OKLNG Free Zone Enterprise (OKLNG) affiliate, which will operate the Olokola LNG ~~Project, which involves construction of~~project. OKLNG plans to build a ~~four-train,22-million-metric-ton-per-year~~multitrain, 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.~~zone. The project entered FEED in 2006 and is expected to be implemented in phases, commencing with two trains having at least 11 million-metric-ton-per-year total capacity. Approximately 50 percent of the ~~first quarter 2006. The partners’ investment decision~~gas supplied to the plant is ~~scheduled for 2007, and initial production is targeted for 2012. The company had not recognized proved reserves for~~expected to be provided from the producing areas associated with Chevron’s joint-venture arrangement with NNPC (discussed earlier in this ~~project at the end of 2006.~~section).

~~Nigeria-Sã~~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~~operated interest in ~~2006.~~JDZ Block 1. In ~~March~~ 2006, the first exploration well ~~was completed and~~ encountered hydrocarbons. In ~~early 2007, commercial options were being examined~~2008, technical studies are planned to determine the ~~possible~~ need for additional ~~drilling.~~drilling and evaluate development alternatives.

~~c) Asia-Pacific~~


c)	Asia-Pacific


		Australia:During ~~2006,~~2007, the average net ~~daily~~oil-equivalent production from Chevron’s interests in Australia was ~~34,000~~100,000 barrels per day, composed of 39,000 barrels of ~~crude oil~~liquids and ~~condensate, 5,000 barrels of LPG, and 360~~372 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~~2007 averaged 29,000 barrels of crude oil and condensate, ~~358~~369 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 and China, 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 late 2008. The Angel natural gas field, ~~being developed at an estimated total cost of $1.2 billion,~~where development is under way, and the North Rankin Redevelopment project 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~~from the NWS fields. An investment decision by the company and ~~additional reclassification of proved undeveloped reserves to proved developed.~~its partners on the North Rankin Redevelopment project is expected in late 2008. The end of the NWS Venture 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.~~2007. Chevron’s ~~interest~~interests in ~~this operation is~~these operations are 57 percent for Barrow ~~Island~~ and 51 percent for ~~Thevenard Island.~~Thevenard.

Also off the northwest coast of Australia, Chevron is the operator of the ~~Gorgon-area fields~~Gorgon development 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~~the company received environmental regulatory approvals necessary for the development of the Greater Gorgon LNG project on Barrow ~~Island. A~~Island using a two-train,~~10-million-metric-ton-per-year~~ 10 million-metric-ton-per-year LNG development ~~is planned~~plan. As of early 2008, the detailed environmental conditions were incorporated into the project’s updated optimization and engineering efforts for a three-train, 15 million-metric-ton-per-year LNG configuration, and activities to secure the necessary government approvals were under way. Natural gas for the ~~island, with natural gas~~project will be supplied from the Gorgon and Jansz ~~natural gas~~ fields. The Gorgon project has an expected economic life of at least 40 years.

Elsewhere in the Greater Gorgon Area during ~~2006, concept studies were undertaken on~~2007, Chevron participated in four successful appraisal wells — two in the~~Wheatstone-1~~ ~~natural gas discovery located northeast of~~ Browse Basin and two in the ~~Gorgon Field. Appraisal drilling is scheduled for 2007. The company~~Carnarvon Basin. Chevron also ~~announced~~participated 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 a3-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~~with Lady Nora resulting in a natural gas discovery and Snarf-1 expecting to be completed in 2008. As of early 2008, plans were also being developed to appraise the 67 percent-owned Clio and the 50 ~~percent operated interest~~percent-owned Chandon natural gas discoveries. Concept studies continued in 2007 on the Wheatstone natural gas discovery, and a successful appraisal well was drilled late in the ~~blocks. Operations commenced in WA-374-P with the acquisition of3-D~~ ~~seismic data. On WA-383-P, a three-year work program includes geotechnical studies and2-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~~year. Further appraisal wells are planned to be drilled in the ~~Greater Gorgon Area. A three-year work program includes geotechnical studies, seismic surveys and drilling of an exploration well.~~area in 2008.

At the end of ~~2006,~~2007, 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~~In 2007, the company ~~has~~ signed ~~separate~~a nonbinding Heads of ~~Agreements totaling 4.2~~Agreement (HOA) with GS Caltex, a Chevron affiliated company, to supply 250,000 metric tons of LNG annually from the Gorgon project. Combined with the nonbinding HOAs signed previously with three utility customers in Japan, volumes under the four HOAs totaled 4.5 million metric tons per ~~year with three companies in Japan to supply LNG from the Gorgon project.~~year. As of early ~~2007,~~2008, negotiations were continuing to finalize binding sales ~~agreements.~~agreements on these HOAs. Purchases by each of these customers are expected to range from ~~1.2 million~~300,000 metric tons per year to 1.5 million metric tons per year ~~of LNG~~ over 25 ~~years beginning after 2010.~~years.


		Azerbaijan:Chevron holds a 10 percent nonoperated working interest in the Azerbaijan International Operating Company (AIOC), which ~~holds offshore~~produces 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,~~affiliate, which transports AIOC production by pipeline from Baku, Azerbaijan, through Georgia to Mediterranean deepwater port facilities in Ceyhan, Turkey. (Refer to “Pipelines” under “Transportation Operations” on page 2728 for a discussion of the BTC operations.) In ~~2006,~~2007, the company’s daily net ~~crude oil~~ production from AIOC averaged ~~46,000 barrels.~~61,000 barrels of oil-equivalent. First production from Phase IIIII of ~~the~~ ACG development ~~project began producing~~is targeted for the second quarter 2008. Total crude-oil production 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~~ACG project is expected to increase to about ~~700,000~~940,000 barrels per day ~~in 2007~~by the end of 2008 and to more than 1 million barrels per day byin 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 a30-year PSC that expires ~~at the end of~~in 2024.

Kazakhstan: Chevron holds a 20 percent nonoperated working interest in the Karachaganak project that is being developed in phases. During ~~2006,~~2007, Karachaganak ~~daily~~ net oil-equivalent production averaged ~~38,000~~66,000 barrels per day, composed of 41,000 barrels of liquids and ~~143~~149 million cubic feet of natural gas.

~~The Karachaganak operations are conducted under a40-year~~ ~~concession agreement that expires in 2038.~~ In ~~2006,~~2007, access to the Caspian Pipeline Consortium (CPC) and Atyrau-Samara (Russia) pipelines allowed Karachaganak sales of approximately ~~143,000~~166,000 barrels per day ~~(27,000~~(31,000 net barrels) of processed liquids at prices available in world markets. AThe remaining liquids were sold into Russian markets. During 2007, work continued on 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.

In 2007, the Karachaganak operator signed a15-year natural gas sales agreement to deliver up to 1.6 billion cubic feet per day of sour gas to a Russian-Kazakh joint venture. Deliveries under the agreement commenced in September 2007. As of early 2008, Phase III development of ~~Karachagnak field development is contingent upon the Republic~~Karachaganak continued under evaluation. The project could increase maximum total production to 335,000 barrels of ~~Kazakhstan’s identifying~~liquids per day and ~~enabling a commercially attractive outlet for the increased~~1.7 billion cubic feet of natural gas ~~volumes.~~per day. Timing for the recognition of Phase III proved reserves ~~and an increase in production are~~is uncertain and ~~both depend~~depends on ~~achieving a natural gas sales agreement and~~ finalizing a viable Phase III project design.

Projectstart-up is anticipated in 2012 or after, depending on achievement of project milestones. Karachaganak operations are conducted under a40-year PSC that expires in 2038.

Refer also to ~~page~~pages 23 and 24 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~~three onshore blocks, with a 98 percent interest in Blocks 12, 13 and 14 and operator of Block 7, in which the company holds a 43 percent ~~interest~~interest. Net oil-equivalent production in ~~Block 7. In 2006, the properties~~2007 averaged ~~daily net production~~47,000 barrels per day, composed of ~~126~~275 million cubic feet of natural ~~gas. Following a two-year development program, production~~gas and 2,000 barrels of liquids. Production from the Bibiyana Field in Block 12 started in March 2007. The project is ~~scheduled~~expected to ~~start in the first-half 2007, reaching~~reach maximum total production of 500 million cubic feet per day by late 2010. The development program ~~includes~~included 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,~~2007, additional proved reserves were recognized based on ~~additional~~ development wells drilled during the year, and ~~certain~~a portion of proved undeveloped reserves were reclassified to the proved developed ~~category in recognition of imminent completion of the gas plant and pipeline infrastructure required for productionstart-up.~~ ~~The~~category. Bibiyana operations are conducted under a PSC that expires in 2034.


		Cambodia:Chevron operates and holds a 55 percent interest in the~~1.6~~1.2 million-acre Block A, located offshore in the Gulf of Thailand. A ~~third~~four-well exploration and appraisal program was completed in 2007. As of early 2008, the results and prospects for further drilling ~~campaign commenced in third quarter 2006 and is expected to be completed by first quarter 2007.~~were being evaluated. 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. Most of the natural gas is purchased by
Thailand’s PTT Public Company Limited (PTT). The company’s average net natural gas production in ~~Myanmar~~2007 was 89100 million cubic feet per day, ~~in 2006.~~or 17,000 barrels of oil-equivalent.

Thailand: Chevron has ~~both~~ operated and nonoperated working interests in several different offshore ~~blocks in Thailand.~~blocks. The company’s ~~daily~~ net oil-equivalent production in 2007 averaged ~~73,000~~224,000 barrels per day, composed of 71,000 barrels of crude oil and condensate and ~~856~~916 million cubic feet of natural gas. All of the company’s natural gas ~~in 2006.~~production is sold to PTT under long-term sales contracts.

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

~~In the concession containing~~natural gas from six operating areas, and Blocks 10 through 13 and B12/27 ~~debottlenecking~~produce crude oil, condensate and natural gas from 16 operating areas.

The company’s production of ~~all central processing platforms was completed, which~~natural gas increased beginning in March 2007 with PTT’s commissioning of a third natural gas pipeline. In October 2007, the leases for Blocks 10 through 13 were extended from 2012 to 2022. In December 2007, the company signed a natural gas sales agreement that will increase daily contract quantity of natural gas from these blocks by 500 million cubic feet, to 1.2 billion, by 2012. In addition, this agreement is expected to ~~add more than 160 million cubic feet per day~~enable the construction of a second central 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 the Platong ~~to support a Heads of Agreement signed in 2003 for additional natural gas sales to meet future natural gas demands in Thailand. This~~area. The 70 percent-owned Platong Gas II ~~Project, in which the company has a 70 percent interest, would~~project is designed to add ~~330~~420 million cubic feet per day of processing capacity in the ~~Platong area, which spans Blocks 10, 10A, 11 and 11A in~~first quarter 2011. The company expects to recognize proved reserves throughout 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 theproject’s12-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.~~installed.

Chevron has a 16 percent nonoperated working interest in Blocks 14A, 15A, 16A, G9/48 and ~~G9/48,~~G8/50, known collectively as the Arthit Field. ~~Development of Arthit is progressing with six wellhead platforms installed and 41 wells drilled in 2006.~~ First production from Arthit is planned for the second quarter 2008 and is expected to reach an estimated maximum total production of 330 million cubic feet of natural gas per day by the end of 2008. Proved undeveloped reserves were recorded for the first time in 2006. Reclassification of proved undeveloped reserves to the proved developed category is anticipated in 2008, near productionstart-up. The concessions that cover Arthit operations expire in 2040.

In ~~2006, the company signed two~~G9/48, one 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.

In late 2007, the company was granted the concession rights to four prospective offshore petroleum blocks in Thailand, which includes Block G8/50 (discussed earlier in this section). Chevron’s interest in the other three operated blocks, G4/50, G6/50 and G7/50, ranges from 35 percent to 75 percent.

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 one PSC that includes Blocks B and 48/95 and a 43 percent interest in the other PSC that has Block 52/97. ~~In April 2006, the company signed a30-year~~ ~~PSC for Block 122 located offshore eastern Vietnam. The company~~Chevron also 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.~~Block B122 offshore eastern Vietnam. No production occurred in these PSCs during 2007.

~~In July 2006,~~The Vietnam Gas Project is aimed at developing an area in the ~~company submitted a revised summary development plan~~two Malay Basin PSCs to supply natural gas 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~~PetroVietnam. In the third quarter 2007, ~~with FEED projected to begin by~~PetroVietnam approved the ~~end~~revised development plan, joint development area and unitization agreement for the project. The project includes installation of ~~2007. First~~wellhead and hub platforms, an FPSO vessel, infield pipelines and a central processing platform. The timing of first natural gas production is ~~targeted for 2011 but is~~ dependent onupon the ~~progress~~outcome of commercial negotiations. Maximum total production of approximately 500 million cubic feet of natural gas per day is projected within ~~four~~five years of ~~the production~~start-up. Recognition of initial proved undeveloped reserves ~~is expected to~~would follow execution of the gas sales agreements and ~~anticipated~~ project ~~sanction~~approval. The PSC for Blocks B and 48/95 and the PSC for Block 52/97 will expire in ~~2008. Total development cost for the project is approximately $3.5 billion.~~2022 and 2029, respectively.

In Block 122, a planned seismic program was postponed in 2007 due to issues of territorial claim between Vietnam and China.

China: Chevron has anonoperated working interests of 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 the QHD-32-6 Field in Bohai Bay and a 16 percent ~~nonoperated working interest~~ in the unitized and producing ~~Bozhong~~BZ25-1 Field in Bohai Bay Block 11/19. ~~Daily~~The company’s net oil-equivalent production ~~from the company’s interests~~ in China during 2007 averaged ~~23,000~~26,000 barrels per day, composed of 22,000 barrels of crude oil and condensate and 1822 million cubic feet of natural ~~gas in 2006. Production during 2006 included first natural gas in January from~~gas.

Joint development of the ~~HZ21-1 natural gas development project, located~~HZ25-3 and HZ25-1 crude-oil fields in Block 16/~~08.~~19 commenced in the first quarter 2007. First production is expected in early 2009, reaching a maximum total daily production of approximately 14,000 barrels of crude oil late in the year. 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. In December 2007, the company signed a30-year PSC that became effective in February 2008 for the development of the Chuandongbei natural gas area in the onshore Sichuan Basin. The aggregate design input capacity of the proposed gas plants is expected to be 740 million cubic feet of natural gas per day. The company holds a 49 percent interest in the area.

Partitioned Neutral Zone (PNZ): ~~Saudi Arabian~~ Chevron ~~Inc., a Chevron subsidiary,~~ holds a60-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~~Negotiations to extend the concession ~~agreement.~~ period were ongoing in early 2008. Net production in PNZ for 2007 represented 4 percent of Chevron’s net barrels of oil-equivalent total.

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,~~2007, average ~~daily~~ net oil-equivalent production was ~~111,000~~112,000 barrels per day, composed of 109,000 barrels of crude oil and 1917 million cubic feet of natural gas. ~~Facilities for the first~~The second 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.~~in early 2009. This pilot is a unique application of steam injection into a carbonate ~~reservoir.~~reservoir and, if successful, could significantly increase recoverability of the heavy oil in place.

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~~Net oil-equivalent production in ~~2006 was 108~~2007 averaged 26,000 barrels per day, composed of 126 million cubic feet of natural gas and ~~6,000~~5,000 barrels of condensate. Chevron also develops and produces steam resources under an agreement with the National Power Corporation, a Philippine ~~government-owned~~government — owned company. The combined generating capacity is ~~634~~637 megawatts.

~~d) Indonesia~~


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~~holds operated interests of 100 percent in the Rokan and Siak PSCs and 90 percent in the Mountain Front Kuantan PSC. Other subsidiaries operate 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 3580 percent to 100 percent. Chevron also has ~~a 25 percent~~nonoperated working ~~interest~~interests in a ~~nonoperated~~ joint venture in South Natuna Sea Block B and ~~a 40 percent working interest~~ in the ~~nonoperated~~ NE Madura III ~~Block~~block in the East Java Sea Basin. ~~CGI is~~Chevron’s interests in these PSCs range from 25 percent to 40 percent. In January 2008, Chevron relinquished its 35 percent nonoperated working interest
in the Donggala PSC in the Kutei Basin. In West Java, Chevron wholly owns a power generation company that operates the Darajat geothermal contract area in Garut, West Java, with a total capacity of ~~145~~259 megawatts. ~~MCTN~~This includes the Darajat III 110-megawatt unit that was placed online in July 2007. Chevron also operates a 95 percent-owned300-megawatt cogeneration facility in support of CPI’s operation in North ~~Duri. CGS operates~~Duri and the wholly owned Salak geothermal field, located in West Java, with a total capacity of 377 megawatts.

~~In North~~The company’s net oil-equivalent production in 2007 from all of its interests in Indonesia averaged 241,000 barrels per day. The daily oil-equivalent rate comprised 195,000 barrels of crude oil and 277 million cubic feet of natural gas. The largest producing field is Duri, located in the Rokan ~~PSC, development~~PSC. Duri has been under steamflood operation since 1985 and is ~~progressing on~~one of the world’s largest steamflood ~~activity for the sequential development of three possible~~developments. An expansion ~~areas. The first expansion involves the development of~~area, Area 12, is targeted forstart-upin ~~which the company has a 100 percent interest, and is planned to come onstream in 2008, with maximum~~late 2008. Maximum total daily production is estimated at 34,000 barrels of crude oil in 2012. Two other areas have been identified for possible sequential expansions. Proved undeveloped reserves for North Duri were recognized in previous years, and reclassification from proved undeveloped to proved developed ~~will~~is scheduled to occur during various stages of sequential ~~project~~ completion. The Rokan PSC expires in 2021.

A drilling campaign ~~is scheduled to continue~~continued through 2007 in South Natuna Sea Block B, with first oil produced from the Kerisi Field in December 2007. First production of LPG from the Belanak Field was achieved in April 2007. Additional development drilling in the North Belut Field is scheduled to begin in mid-2008, with first production 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.~~2009.

In ~~early~~January 2007, Chevron combined the development of the Gendalo and Gehem deepwater natural gas fields located in the Kutei Basin into a single project with one development concept. In August 2007, the company submitted ~~preliminary~~final development plans ~~of development~~ to the government of ~~Indonesia for~~Indonesia. Approvals are expected during the first-half 2008. The Bangka ~~Gendalo Hub and Gehem Hub deepwater~~ natural gas ~~projects, located~~project was under evaluation in ~~the Kutei Basin. These projects~~2007 and will

likely be developed in parallel with ~~first production for all projects targeted for 2013.~~Gendalo and Gehem. The ~~actual~~development timing is partially dependent on government approvals, market conditions and the achievement of key project milestones. The company holds an 80 percent operated interest in these projects.

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

~~Daily net production from all producing areas in Indonesia averaged 198,000 barrels of crude oil and 302 million cubic feet of~~late 2008. The project is designed to supply natural gas ~~in 2006.~~to a state-owned refinery.

~~e) Other International Areas~~


e)	Other International Areas


		Argentina:Chevron ~~operates~~holds an operated interest 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)~~one exploratory block in the Neuquen and Austral basins. Working interests range from ~~approximately~~ 19 percent to 100 ~~percent in operated license areas. Daily net~~percent. Net oil-equivalent production in ~~2006~~2007 averaged ~~38,000~~47,000 barrels per day, composed of 39,000 barrels of crude oil and 5450 million cubic feet of natural gas. Chevron also holds a 14 percent interest in the Oleoductos del Valle S.A. ~~pipeline and a 28 percent interest~~pipeline. In 2007, three exploratory wells were drilled in the ~~Oleoducto Transandino pipeline.~~Austral Basin, and two were successful. Brazil:Chevron holds working interests ranging from 20 percent to 52 percent in ~~four~~three deepwater blocks. None of the blocks had production in 2007. 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,~~2007, major construction activities included work to convert a crude-oil tanker to an FPSO vessel and the ~~Frade project completed FEED~~manufacture of subsea systems and ~~started construction with all major contracts~~flowlines for the project. Subsea installation activities began in ~~place. The total project cost is estimated at $2.8 billion.~~early 2008. Proved undeveloped reserves were recorded for
the first time in 2005. ~~Reclassification~~Partial reclassification of proved undeveloped reserves to the proved developed category is anticipated upon productionstart-up in early ~~2009 and is expected to continue until 2011.~~2009. Estimated maximum total production of 90,000oil-equivalent barrels per day is anticipated in 2011. The concession that involves the Frade ~~concession~~project expires in 2025.

The company concentrates its exploration efforts in the Campos and Santos basins. In the ~~nonoperated~~partner-operated Campos Basin Block BC-20, two areas — 38 percent-owned Papa-Terra ~~(formerly RJS610)~~ and 30 percent-owned ~~RJS609~~Maromba — 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 Papa-Terra field development plan was submitted to the ~~government. FEED~~government, and as of early 2008 this plan was still under evaluation. In Maromba as of early 2008, a pilot production system was under consideration, with first oil projected 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.2013. Elsewhere in Campos, the company ~~holds a~~relinquished its 30 percent nonoperated working interest in ~~theBM-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.BM-C-4. In the 20 percent-owned and ~~nonoperated~~partner-operated Santos Basin Block BS-4, ~~Block,~~development options for 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.~~Oliva fields were under evaluation.

Colombia: The company operates ~~three natural gas fields in Colombia —~~ the offshore Chuchupa and the onshore Ballena and ~~Riohacha. The~~Riohacha natural gas fields ~~are~~as 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~~contract. In exchange, Chevron receives 43 percent of the production for the remaining life of each field ~~as well as~~and 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~~Daily net production averaged ~~174~~178 million cubic feet of natural gas, ~~per day~~or 30,000 barrels of oil-equivalent, in ~~2006. New production capacity was commissioned in 2006 and will help meet~~2007. During the ~~demand of the growing Colombian~~year, new dehydration facilities were constructed that enabled natural gas ~~market.~~exports to Venezuela beginning in January 2008.

Trinidad and Tobago: The company has a 50 percent nonoperated working interest in four blocks in the East Coast Marine Area 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~~2007 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, or 29,000 barrels of oil-equivalent.

In May 2007, a domestic natural gas sales agreement was signed for the Trinidad Incremental Gas project. The agreement includes the delivery of 220 million cubic feet per day for 11 years with an option for a four-year extension. Drilling operations started in late 2007 at the Dolphin platform. First gas for the project is expected in 2009, ramping up to ~~Train 3 and 31~~maximum total production of 220 million ~~net~~ cubic feet of natural gas per day ~~to Train 4. Proved~~in early 2010. Reserves were initially booked in 2006. In 2007, additional proved reserves ~~associated with the Train 4 gas sales agreement~~ were ~~recognized in 2004. Reserves associated with Trains 3~~recorded, and 4some proved undeveloped reserves were ~~transferred~~reclassified to the proved developed ~~category~~category. Further reclassifications are expected in ~~2005. The contract period for Train 3 ends in 2023 and for Train 4 in 2026.~~2008, following the drilling of additional development wells.

Chevron also holds a 50 percent operated interest in the Manatee area of Block 6d. ~~After successful exploration drilling results in 2005,~~In early 2007, an agreement was signed by the ~~company assessed alternative development strategies for~~governments of Venezuela and Trinidad and Tobago to unitize the Loran Field in Venezuela and the Manatee ~~area~~area. Negotiations are expected to continue in ~~2006. As of early 2007, negotiations were in progress between Trinidad and Tobago and Venezuela~~2008 to ~~unitize the Loran and Manatee discoveries.~~achieve a field-specific unitization treaty.

Venezuela: ~~As of October 2006,~~Chevron holds interest in two affiliates located in western Venezuela and one affiliate in 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.

Orinoco Belt. The company also ~~has ongoing exploration activity~~operates in two exploratory blocks offshore Plataforma Deltana, ~~in which the company is operator and holds a~~with working interests of 60 percent ~~interest.~~in Block 2 and 100 percent in Block 3. In Block 2, which includes the Loran ~~Field, evaluation and project~~natural gas field, a conceptual offshore development ~~work continued during 2006.~~plan was completed in 2007. In ~~the 100 percent-owned and operated~~ Block 3, Chevron discovered natural gas in ~~2005. The discovery~~2005 that is in close proximity to ~~the~~Loran. Both Block 3 and Loran ~~natural gas field and provides significant resources that~~ will ~~be included in the detailed evaluation as~~provide a ~~potential gas~~possible supply source for Venezuela’s first LNG train. Seismic work elsewhere in Block 3 ~~started~~was completed in ~~2006.~~2007. Chevron also has a 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, was acquired in 2007 and is planned ~~for 2007.~~to be processed in 2008. Petróleos de Venezuela, S.A. (PDVSA) has the option to increase its ownership in all three company-operated blocks up to 35 percent upon declaration of commerciality.

Refer also to page 2324 for a discussion of ~~the Hamaca heavy oil production and upgrading project~~affiliate operations in Venezuela.

Canada: The ~~company’s assets in Canada include a~~company has nonoperated working interests of 27 percent ~~nonoperated working interest~~ in the Hibernia Field offshore eastern Canada aand 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, a 28 percent operated interest in the ~~Athabasca region. This~~Hebron project and exploration acreage in the Mackenzie Delta, Beaufort Sea and the Orphan Basin. Excluding volumes mined at the AOSP, average net oil-equivalent production during 2007 was 36,000 barrels per day, composed of 35,000 barrels of crude oil and natural gas liquids and 5 million cubic feet of natural gas. Substantially all of the production was from the Hibernia Field. At AOSP, bitumen mined and upgraded to synthetic crude oil averaged 27,000 net barrels per day.

At AOSP, the first phase of an expansion project, with an estimated total project cost of $10.2 billion, is being designed to upgrade an additional 100,000 barrels of bitumen into synthetic crude oil per day. The expansion would increase total AOSP design capacity to more than 255,000 barrels of bitumen per day in 2010. Preliminary work is under way to determine the feasibility of additional expansion projects.

The Ells River project consists of heavy oil leases of more than ~~75,000 acres that were acquired in 2005 and 2006.~~85,000 acres. 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~~During 2007, a successful appraisal drilling ~~began~~program involving 66 wells was completed.Follow-up appraisal activities are planned in ~~January 2007.~~2008, with a similar number of wells and a small2-D and3-D seismic program.

The potential development at Hebron stalled in 2006 after unsuccessful negotiations with the provincial government of Newfoundland and Labrador. In mid-2007, the Hebron partners executed a nonbinding memorandum of understanding with the government that outlined fiscal, equity and local-benefit terms associated with the Hebron project. Execution of formal agreements is expected during 2008.

Exploratory activities are expected to continue during 2008 in the Mackenzie Delta and the Orphan Basin.


		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~~has a 12 percent ~~to 27 percent interests~~interest in ~~five~~each of four exploration licenses. ~~Daily net~~Net oil-equivalent production in ~~2006~~2007 from ~~the~~ DUC ~~was 44,000~~averaged 63,000 barrels per day, composed of 41,000 barrels of crude oil and ~~146~~132 million cubic feet of natural gas. Faroe Islands:Chevron has a 40 percent interest in five offshore blocks and is the operator. During ~~2006,~~2007, the company ~~focused on the interpretation of the~~acquired a2-D seismic ~~program~~survey over License 008, located near the Rosebank/Lochnagar discovery in the United Kingdom. ~~The company has~~ Greenland: In October 2007, Chevron was awarded a 4029 percent nonoperated working interest in ~~five~~an exploration license in Block 4 offshore ~~blocks and is the operator.~~ ~~Netherlands:~~ ~~Chevron is the operator and holds interests ranging from 34 percent to 80 percent in nine blocks~~West Greenland in the ~~Netherlands sector of the North Sea.~~Baffin Basin. The ~~company’s daily net production from seven producing fields averaged 3,000 barrels of crude oil~~planned four-year work program includes seismic acquisition, and ~~7 million cubic feet of natural gas in 2006. Productionstart-up~~ ~~at the first stage of the A/B Gas Project is scheduled for early 2008.~~geologic, engineering and environmental studies.

Netherlands: Chevron is the operator and holds interests ranging from 34 percent to 80 percent in nine blocks in the Dutch sector of the North Sea. The company’s daily net production from eight producing fields averaged 3,000 barrels of crude oil and 5 million cubic feet of natural gas. Productionstart-up at the first stage of the A/B Gas Project from Block A12 occurred in December 2007 at an initial daily total rate of 60 million cubic feet of natural gas. As of early 2008, the second stage of the project was under evaluation.

Norway: At the 8 percent-owned and ~~nonoperated~~partner-operated Draugen Field, the company’s ~~share of~~net production during ~~2006~~2007 was 6,000 barrels of ~~crude oil~~oil-equivalent 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,~~partner-operated PL397, seismic survey data was ~~acquired~~processed in ~~2006. Pending the results~~2007. Acquisition of ~~the ongoing~~additional seismic ~~processing, a first exploration well~~data is planned for 2008. ~~At PL 283,~~Exploration activities are expected to continue in ~~which Chevron holds a 25 percent nonoperated working interest, an exploration well that tested natural gas~~2008 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.~~various license areas.

United Kingdom: ~~Offshore United Kingdom, the~~The company’s ~~daily~~average net oil-equivalent production in ~~2006~~2007 from nine offshore fields was ~~75,000~~115,000 barrels per day, composed of 78,000 barrels of crude oil and ~~242~~220 million cubic feet of natural gas. ~~Of this volume, daily net~~ Most of the

production was 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 and jointly-operated 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.Field.

As of early ~~2007,~~2008, 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.~~ Productionstart-up from these two ~~satellite~~ fields is expected to occur in late 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.~~2000. In 2006, proved undeveloped reserves were reclassified to the proved developed category. This project has an expected production life of approximately 15 years.

~~Productionstart-up~~ ~~occurred in June 2006 at~~In exploration activities, 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 iswas being evaluated in early 2008 and is 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~~2012. The timing of ~~year-end 2006.~~the initial proved-reserves recognition was also under evaluation in early 2008. This project has an expected production life of approximately nine years.

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

~~In early 2007, Chevron was awarded eight operated exploration blocks and two nonoperated blocks~~ west of the Shetland Islands, an appraisal program consisting of three wells and a sidetrack was completed in 2007. All four wellbores encountered hydrocarbons, and an evaluation for commerciality was under way in early 2008. Evaluation continued of a successful natural gas production test at the Tormore well that is also in the ~~24th United Kingdom Offshore Licensing Round.~~West of Shetlands gas trend. During 2007, another successful appraisal well was drilled in the Clair Phase 2 area.

f)Equity Affiliate Operations

Angola: In addition to the exploration and producing activities in Angola, Chevron participates in the Angola LNG project, for which the company and partners made a final investment decision at the end of 2007. The LNG plant will be designed with a capacity to process 1 billion cubic feet of natural gas per day and will provide a commercial option for Angola’s natural gas resources. Chevron has a 36 percent interest in the Angola LNG affiliate. Construction began in early 2008 on the 5.2 million-metric-ton-per-year onshore LNG plant that is located in the northern part of the country. Plantstart-up is expected in 2012. At the end of 2007, the company made an initial booking of proved natural gas reserves for the producing operations associated with this LNG project. The life of the LNG plant is estimated to be in excess of 20 years.

Kazakhstan: The company holds a 50 percent interest in Tengizchevroil (TCO), which is developing the Tengiz and Korolev ~~crude oil~~crude-oil fields located in western Kazakhstan under a40-year concession that expires in 2033. Chevron’s ~~share of daily~~ net oil-equivalent production in ~~2006~~2007 from these fields averaged ~~135,000~~176,000 barrels per day, composed of 144,000 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$7.2 billion, these projects are designed to increase TCO’s ~~crude oil~~crude-oil production capacity ~~from 300,000~~to 540,000 barrels per day ~~to between 460,000 and 550,000 barrels per day in~~during the second half of 2008. ~~The actual production level within the estimated range is dependent partially on the effects of the SGI, which are discussed below. Thestart-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~~Wells were drilled, deepenedand/or completed since 2002 in the Tengiz and Korolev reservoirs to ~~generate~~produce volumes required for the new SGP ~~train, and reserves~~train. 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~~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, itSGI is expected ~~that~~ over time ~~SGI will~~to 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~~The company anticipates recognizing additional proved reserves associated with the SGI ~~expansion.~~expansion in late 2008. The primary SGI risks include uncertainties about compressor performance associated with injecting high-pressure sour gas and subsurface responses to injection.

Initial production from the first phase of the SGI/SGP expansion projects occurred in late 2007. This first phase increased production capacity by 90,000 barrels per day, to approximately 400,000, in January 2008.

~~Essentially~~As of early 2008, essentially all of TCO’s production iswas being 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. Also in early 2008, CPC iswas seeking stockholder approval for an expansion to accommodate increased TCO volumes beginning in 2009. ~~During 2006, TCO continued the construction of expanded rail car~~Expanded rail-car loading and ~~rail export~~rail-export facilities, ~~which is expected~~designed to ~~be completed by third quarter~~transport most of the incremental SGI/SGP production prior to the CPC expansion, started operation during 2007. As of early ~~2007,~~2008, other alternatives were also being explored to increase export ~~capacity prior to expansion of the CPC pipeline.~~capacity.

Venezuela: Chevron has a 30 percent interest in the Hamaca heavy oil production and upgrading project located in Venezuela’s Orinoco ~~Belt.~~Belt, a 39 percent interest in the Petroboscan affiliate that operates the Boscan Field, and a 25 percent interest in the Petroindependiente affiliate that operates the LL-652 Field. The company’s average net oil-equivalent production during 2007 from these affiliates was 72,000 barrels per day, composed of 68,000 barrels of crude oil ~~upgrading began in late 2004. In 2005, the facility reached~~and 27 million cubic feet of natural gas.

The Hamaca project has a total design capacity offor 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~~president of Venezuela issued a decree announcing the government’s intention for ~~the state-owned oil company, Petróleos de Venezuela S.A.,~~PDVSA to increase its ownership ~~later this year~~ in all Orinoco Heavy Oil Associations effective May 1, 2007, including Chevron’s 30 percent-owned Hamaca project, to a minimum of 60 percent. In December 2007, Chevron executed a conversion agreement and signed a charter and by-laws with a PDVSA subsidiary that provided for Chevron to retain its 30 percent interest in the Hamaca project. 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.~~new entity, Petropiar, commenced activities in January 2008.

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~~is located onshore western Venezuela. A 3-D seismic program was acquired in 2007 that is expected to guide future development activities in South Boscan. The water-injection pressure-maintenance project was expanded to include four wells converted ~~into a joint stock company, Petroboscan,~~to injectors in ~~which Chevron is a 39 percent owner. At the same time, operatorship was transferred from Chevron~~2007, and four new injectors are planned to ~~Petroboscan. No proved reserves had been recognized under the operating service agreement, but proved reserves associated with this new20-year~~ ~~production contract were recorded~~be drilled 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.

2008 and 2009. 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 the20-year~~ ~~contract period. Located~~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.Maracaibo.

Russia: ~~In October 2006,~~As of early 2008, Chevron ~~signed a framework agreement with OAO Gazpromneft, establishing a Russian joint venture~~and JSC Gazprom Neft continued to negotiate the final agreements for exploration and development activities ~~focused~~in two licensed areas in the Yamal-Nenets region of ~~Western~~western Siberia. Once the agreement is finalized, Chevron ~~will maintain~~is expected to hold a 49 percent ~~joint-operated~~ interest in the ~~venture. Refer to page 17~~Northern Taiga Neftegaz LLC affiliate, which will operate in the licensed areas. Exploration and delineation activities are planned for ~~a discussion of the company’s other activities in Russia.~~2008 on both licenses.

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, substantially all of the ~~majority~~natural gas sales are from the company’s producing interests in Australia, Bangladesh, Kazakhstan, Indonesia, Latin America, the Philippines, Thailand and the United Kingdom. Substantially all 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~~are from company operations in Africa, Australia and ~~Europe.~~Indonesia. Refer to “Selected Operating Data,” onpage ~~FS-11~~FS-10 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 78 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,~~2007, the company’s refining system consisted of 2019 fuel refineries and an asphalt plant. The company operated nine of these facilities, and 1211 were operated by affiliated companies.

The daily refinery inputs for ~~2004~~2005 through ~~2006~~2007 for the company and affiliate refineries are as follows:

Petroleum Refineries: Locations, Capacities and Inputs
(~~Inputs~~Capacities and ~~Capacities~~inputs in ~~Thousands~~thousands of ~~Barrels~~barrels per ~~Day)~~day; includes equity share in affiliates)


			December 31, 2006												December 31, 2007
					Operable		Refinery Inputs										Operable		Refinery Inputs
Locations	Locations		Number		Capacity		2006		2005		2004		Locations		Number		Capacity		2007		2006		2005

Pascagoula		Mississippi		1		330		337		263		312		Mississippi		1		330		285		337		263
El Segundo		California		1		260		258		230		234		California		1		260		222		258		230
Richmond		California		1		243		224		233		233		California		1		243		192		224		233
Kapolei		Hawaii		1		54		50		50		51		Hawaii		1		54		51		50		50
Salt Lake City		Utah		1		45		39		41		42		Utah		1		45		42		39		41
Other¹				1		80		31		28		42				1		80		20		31		28

Total Consolidated Companies —United States	Total Consolidated Companies —United States			6		1,012		939		845		914	Total Consolidated Companies —United States			6		1,012		812		939		845

Pembroke		United Kingdom		1		210		165		186		209		United Kingdom		1		210		212		165		186
Cape Town²		South Africa		1		110		71		61		62		South Africa		1		110		72		71		61
Burnaby, B.C.		Canada		1		55		49		45		49		Canada		1		55		49		49		45

Total Consolidated Companies —International	Total Consolidated Companies —International			3		375		285		292		320	Total Consolidated Companies —International			3		375		333		285		292
Affiliates³		Various Locations		12		834		765		746		724		Various Locations		11		728		688		765		746

Total Including Affiliates —International	Total Including Affiliates —International			15		1,209		1,050		1,038		1,044	Total Including Affiliates —International			14		1,103		1,021		1,050		1,038

Total Including Affiliates —Worldwide	Total Including Affiliates —Worldwide			21		2,221		1,989		1,883		1,958	Total Including Affiliates —Worldwide			20		2,115		1,833		1,989		1,883


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.~~2008.
³		Chevron ~~acquired an 8~~sold its 31 percent ~~ownership~~ interest in the ~~SONARA refinery located~~Nerefco Refinery in ~~Limbe, Cameroon,~~the Netherlands in ~~July 2006.~~March 2007. This ~~increased~~decreased the company’s share of operable capacity by about ~~3,000~~124,000 barrels per day.

In the first quarter 2008, the company sold its 4 percent ownership interest in an affiliate that owned a refinery in Abidjan, Côte d’Ivoire, decreasing the company’s share of operable capacity by about 2,000 barrels per day.

Average crude oil distillation capacity utilization during ~~2006~~2007 was 9086 percent, compared with 8690 percent in ~~2005. In general, this increase~~2006. This decrease generally resulted from ~~less planned~~unplanned downtime to repair damage resulting from fires in the crude units at the Richmond and Pascagoula refineries during 2007. This impact was partially offset by an improvement in capacity utilization at the Pembroke, U.K., refinery, which had unplanned downtime in ~~2006, due partly~~2006. The crude unit at the Pascagoula Refinery was back in service in February 2008. Despite the outage at Pascagoula, the company was able to ~~downtime~~maintain uninterrupted product supplies to customers through the use of other feedstocks in ~~2005 that was attributable to hurricanes in~~its gasoline-producing facilities at the ~~U.S. Gulf of Mexico. No downtime was caused by hurricanes in 2006.~~refinery. At the U.S. fuel refineries, crude oil distillation capacity utilization averaged 85 percent in 2007, compared with 99 percent in 2006, ~~compared with 90 percent in 2005,~~ and cracking and coking capacity utilization averaged 78 percent and 86 percent in 2007 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~~fuel refineries ~~produce low-sulfur fuels that meet 2006 federal government specifications. Investments required to produce low-sulfur fuels~~ in the United States, Europe, Canada, South Africa and Australia ~~were completed~~produce low-sulfur fuels. In 2007, Singapore Refining Company, the company’s 50 percent-owned affiliate, began an upgrade project at its 290,000-barrel-per-day refinery in ~~2006. The company is evaluating alternatives for clean-fuel projects in its Southeast Asia refineries.~~Singapore to produce diesel fuels that meet Euro IV specifications.

In ~~2006,~~2007, the company completed ~~an expansion~~modifications at its refineries in El Segundo, California, to enable the processing of ~~the Pascagoula, Mississippi, refinery’s Fluid Catalytic Cracking Unit to increase the production of~~heavier crude oils into gasoline, diesel and other light ~~products. In addition, construction projects began at~~products, and in 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~~In October 2007, the company approved plans to construct a $500 million Continuous Catalyst Regeneration unit at the Pascagoula, Mississippi, refinery, which is expected to increase gasoline production by 10 percent, or 600,000 gallons per day, by mid-2010. Design and engineering for a project to increase the

flexibility to process lower API-gravity crude oils at the company’s Richmond, California, refinery continued in 2007. ~~Additional~~Other upgrade projects ~~to upgrade~~at the ~~company’s refineries in Mississippi and California~~El Segundo Refinery were being evaluated in early ~~2007.~~2008.

~~Also in 2006,~~In late 2007, GS Caltex, the company’s 50 percent-owned affiliate, ~~began construction~~completed commissioning of annew facilities associated with a $1.5 billion upgrade project at the~~650,000-barrel-per-day~~ 680,000-barrel-per-day Yeosu refining complex in South Korea. ~~At a total estimated cost of $1.5 billion, this~~This project is ~~designed~~expected to increase the yield of high-value refined products by 33,000 barrels per day, add 15,000 barrels of new lubricant base oil production and reduce feedstock costs through an increase in the ~~processing of~~refinery’s ability to process heavy ~~crude~~ oil. ~~Completion of the Yeosu project is expected in late 2007.~~

~~In April 2006,~~ Chevron ~~purchased~~owns 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.~~by year-end 2008, with a crude-oil capacity of 580,000 barrels per day. 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 topage 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~~2007 and ~~2005,~~2006, respectively.

Gas-to-Liquids

~~The~~Through the Sasol Chevron Global50-50 Joint Venture, ~~was established in 2000 to develop a worldwidegas-to-liquids~~ ~~(GTL) business. Through this venture,~~ the company is pursuing ~~GTL~~gas-to-liquids (GTL) opportunities in ~~Qatar and other~~several countries.

In Nigeria, Chevron ~~Nigeria Limited~~ and the Nigerian National Petroleum Corporation are developing a34,000-barrel-per-day GTL facility at Escravos ~~that will~~designed to process natural gas supplied from the Phase 3A expansion of the Escravos Gas Plant (EGP). ~~Plant construction began~~As of early 2008, approximately 90 percent of engineering and procurement activities had been completed. Chevron has a 75 percent interest in ~~2005, and~~ the ~~first process modules are expected to be delivered to the site by the second half of 2007. The GTL~~ plant, which is expected to be operational by the end of the decade. Refer also to page 1516 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~~below identifies the company’s and affiliates’ refined products sales volumes, excluding intercompany sales, for the three years ending December 31, ~~2006.~~2007.

Refined Products Sales Volumes¹(Thousands of Barrels per Day)


	2006		2005		2004		2007		2006		2005

United States
Gasolines		712		709		701		728		712		709
Jet Fuel		280		291		302		271		280		291
Gas Oils and Kerosene		252		231		218		221		252		231
Residual Fuel Oil		128		122		148		138		128		122
Other Petroleum Products²		122		120		137		99		122		120

Total United States		1,494		1,473		1,506		1,457		1,494		1,473

International⁴
International³
Gasolines		595		662		715		581		595		662
Jet Fuel		266		258		250		274		266		258
Gas Oils and Kerosene		776		781		804		730		776		781
Residual Fuel Oil		324		404		458		271		324		404
Other Petroleum Products²		166		147		141		171		166		147

Total International³		2,127		2,252		2,368
Total International								2,027		2,127		2,252

Total Worldwide⁴		3,621		3,725		3,874
Total Worldwide³								3,484		3,621		3,725

1 Includes buy/sell arrangements. Refer to Note 14 onpage 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


¹	Includes buy/sell arrangements. Refer to Note 13 onpage FS-42.	—	50	217
²	Principally naphtha, lubricants, asphalt and coke.
³	Includes share of equity affiliates’ sales:	492	492	498

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~~approximately 9,700 Chevron- and Texaco-branded motor vehicle retail outlets, concentrated in the mid-Atlantic, southern and western states. Approximately ~~600~~550 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~~15,400 branded service stations, including ~~affiliates, in about 75 countries.~~affiliates. In British Columbia, Canada, the company markets under the Chevron brand. In Europe, the company ~~has marketing operations under the Texaco brand~~markets primarily in the United Kingdom and Ireland under the ~~Netherlands, Belgium and Luxembourg.~~Texaco brand. 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~~central and ~~East~~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 retail fuels networks and individual service station sites, focusing on selected areas outside the United States. In ~~2006,~~2007, the company sold its fuels marketing businesses in Belgium, the Netherlands and Luxembourg and its retail fuels business in Uruguay. The company also sold its interest in ~~more than 450~~about 500 individual service ~~stations,~~station sites, primarily in the United Kingdom and Latin America. Since the beginning of 2003, the company has sold its interests in ~~nearly 2,800~~about 3,300 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,~~at more than 1,000 airports, representing a worldwide market share of about 1211 percent, and is ~~the~~a 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, Meropa and ~~Revtex.~~

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

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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~~2007


	Net Mileage¹

United States:
Crude Oil²		~~2,884~~2,853
Natural Gas		2,275
Petroleum Products³		~~6,932~~7,053

Total United States		~~12,091~~12,181
International:
Crude Oil²		~~714~~700
Natural Gas		~~475~~768
Petroleum Products³		~~421~~426

Total International		~~1,610~~1,894

Worldwide		~~13,701~~14,075


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,~~

During 2007, the company ~~completed~~led the ~~sale~~development of ~~three refined-product~~a natural gas gathering pipeline ~~systems~~serving the Piceance Basin in ~~Texas and New Mexico as well as its interest~~northwest Colorado; participated in the ~~Windy Hill~~successful installation of the55-mile Amberjack-Tahiti lateral pipeline on the seafloor of the U.S. Gulf of Mexico; and completed a pipeline running from the U.S. Gulf of Mexico subsea to the Fourchon Terminal in southern Louisiana. The company is also leading the expansion of the West Texas liquefied natural gas ~~storage project~~pipeline system that is expected to be operational 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,~~late 2008. In addition, the company ~~began a~~continued with its project to expand capacity by about 2 billion cubic feet at its Keystone natural gas storage facility, ~~by about 3 billion cubic feet~~which is expected to ~~meet increased demand~~be completed 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.2009.

Chevron ~~also~~ has a 15 percent ~~ownership~~ interest in the Caspian Pipeline Consortium (CPC). affiliate. 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,~~During 2007, CPC ~~had~~ transported an average of ~~664,000~~approximately 700,000 barrels of crude oil per day, including ~~519,000~~545,000 barrels per day from ~~the Caspian region~~Kazakhstan and ~~145,000~~155,000 barrels per day from Russia. For information related to the possible expansion of the CPC pipeline, refer to page 24.

~~In addition, the~~The company has a 9 percent ~~equity~~ interest in the Baku-Tbilisi-Ceyhan (BTC) affiliate, whose pipeline ~~which~~ transports Azerbaijan International Operating Company (AIOC) (owned 10 percent by Chevron) 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~~BTC pipeline has a ~~crude oil~~crude-oil capacity of 1 million barrels per day and ~~is expected to accommodate~~transports the majority of the AIOC production. Another crude oil production export route is the~~515-mile~~ ~~Baku-Supsa pipeline,~~ Western Route Export Pipeline, wholly owned by AIOC, with ~~crude oil~~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.~~page 16.

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Tankers: At any given time during ~~2006,~~2007, the company had approximately 7080 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.~~2007. The following table summarizes cargo transported on the company’s controlled fleet.

Controlled Tankers at December 31, ~~2006~~2007


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

Owned		3		0.8		1		1.1		3		0.8		1		1.1
Bareboat Chartered		—		—		18		27.4		1		0.3		19		28.1
Time Chartered*		—		—		22		11.5		—		—		24		14.3

Total		3		0.8		41		40.0		4		1.1		44		43.5


*	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,~~In 2007, 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~~ThreeU.S.-flagged product tankers, each capable of carrying 300,000 barrels of ~~cargo. These tankers~~cargo, are scheduled for delivery from ~~2007~~2008 through ~~2010 and are intended to replace the existing three U.S. flag ships.~~2010.

The ~~international flag~~foreign-flagged vessels were engaged primarily in transporting crude oil from the Middle East, Asia, the 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,~~2007, the company took delivery of ~~two~~one new double-hulled ~~tankers~~tanker, with a total capacity of ~~2.5 million~~500,000 barrels, and ~~terminated~~oneU.S.-flagged product tanker capable of carrying 300,000 barrels of cargo. The company also returned a1 million-barrel-capacity crude tanker at the ~~lease on~~end of its ~~last single-hulled vessel.~~lease.

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~~Venture in Australia. ~~Additionally, the~~The NWS project also has two LNG tankers under long-term time charter. In 2005, Chevron placed orders for two ~~additional~~company-owned LNG ~~tankers to support expected growth in the company’s LNG business. These carriers are planned to be delivered in 2009.~~tankers.

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,~~2007, 100 percent of the company’s owned and bareboat-chartered fleet wasdouble-hulled. The company is a member of many oil-spill-response cooperatives in areas ~~around the world~~ in which it ~~operates.~~operates around the world.

Chemicals

Chevron Phillips Chemical Company LLC (CPChem) is equally owned with ConocoPhillips Corporation. At the end of ~~2006,~~2007, CPChem owned or had joint venture interests in 30 manufacturing facilities and six research and technical centers in ~~the United States,~~Belgium, China, Puerto Rico, ~~Belgium, China,~~Qatar, Saudi Arabia, Singapore, South Korea and ~~Qatar~~.the United States.

In ~~2006,~~2007, CPChem completed construction ~~progressed~~ on ~~CPChem’s~~the integrated, world-scale styrene facility in Al Jubail, Saudi Arabia. Jointly owned with the Saudi Industrial Investment Group (SIIG), ~~the project’s operationalstart-up~~commercial production is ~~anticipated~~expected to commence in ~~late 2007.~~mid-2008. The styrene facility is located adjacent to CPChem and SIIG’s existing aromatics complex in Al Jubail. Also during ~~the year,~~2007, CPChem ~~continued development of plans~~secured final approval for a third petrochemical project in Al Jubail. Construction began in early 2008, with expected completion in 2011. 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 the first half of 2008, commercial operations are expected to begin for the Americas Styrenics joint venture between CPChem and Dow Chemical Company that combines CPChem’s styrene and polystyrene operations with Dow’s polystyrene operations.

~~In addition,~~CPChem continued construction ~~continued~~during 2007 on the 49 percent-owned Q-Chem II project in ~~2006.~~Mesaieed, Qatar. 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~~complex. Q-Chem II ~~project~~ also includes a separate joint venture to develop a~~1.3-million-metric-ton-per-year~~ 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~~the first half of 2009. ~~CPChem owns a 49 percent interest~~Construction also began during 2007 of the Ryton^® polyphenylene sulfide manufacturing facility in ~~Q-Chem II.~~Texas, with completion scheduled for 2009.

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

Oronite has completed construction of the new carboxylate detergent unit in France. This facility will produce new sulfur-free detergent components for marine engine applications and low-sulfur components for automotive engine oil applications. Full commercial production from this facility is expected to commence early in the second quarter 2008.

Other Businesses

Mining

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

~~The~~In 2007, the company’s coal mining and marketing subsidiary, The Pittsburg & Midway Coal Mining Co. (P&M), changed its name to Chevron Mining Inc. (CMI) and merged with Molycorp Inc., another Chevron mining subsidiary, to form a single Chevron mining entity. The company owns and operates two surface coal mines, McKinley, in New Mexico, and Kemmerer, in Wyoming, and one underground coal mine, North River, in Alabama. Sales of coal from ~~P&M’s~~CMI’s wholly owned mines were ~~12.6~~12 million tons, down ~~1.0~~about 1 million tons from ~~2005. Final reclamation activities continued in 2006 at the Farco surface mine in Texas.~~2006.

At year-end ~~2006, P&M~~2007, CMI controlled approximately ~~225~~214 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~~In addition to the ~~company’s mining and marketing subsidiary for molybdenum and rare earth minerals. Molycorp~~coal operations, Chevron owns and operates the Questa molybdenum mine in New Mexico and the Mountain Pass ~~lanthanides~~rare earth mine in California. ~~In addition, the company~~At year-end 2007, CMI controlled approximately 57 million pounds of proven molybdenum reserves at Questa and 241 million pounds of proven and probable rare earth reserves at Mountain Pass.

Chevron also 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~~Japan, and ~~Mountain Pass, and at its closed rare-earth processing facility in Pennsylvania. The company’s 35~~a 50 percent interest in ~~Companhia Brasileira de Metalurgia e Mineracao,~~Youngs Creek Mining Company LLC, a ~~producer of niobium~~joint venture to develop a coal mine 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.~~

northern Wyoming. 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)~~power generation business ~~has more than 20 years experience in developing~~develops and ~~operating~~operates commercial power projects and owns 15 power assets located in the United States and Asia. ~~GPG~~The company 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,~~20, and the Research and Technology section below, 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

2930

projects completed by CES in ~~2006~~2007 include energy efficiency ~~and renewable power~~ installations for ~~U.S. Postal Service~~the state of Colorado government facilities ~~the first megawatt-class hydrogen fuel cell cogeneration plant in California,~~ and ~~cogeneration and biomass facilities for~~ a ~~municipal water pollution control plant.~~1.1 megawatt solar system at California’s Fresno State University.

Research and Technology

The company’s Energy Technology Company (ETC) supports Chevron’s upstream and downstream ~~businesses with technologies that span the hydrocarbon value chain from exploration to refining~~businesses. ETC provides technology and ~~marketing.~~competency support in earth sciences; reservoir and production engineering; drilling and completions; facilities engineering; health, environment and safety; refining; technical computing; strategic planning; and organizational capability.

~~The~~ Technology Ventures Company ~~identifies, grows~~manages investments and ~~commercializes~~projects in emerging energy technologies and their integration into Chevron’s core businesses. Its activities are managed through four business units: Venture Capital, Biofuels, Hydrogen and Emerging Energy.

Information Technology Company integrates computing, telecommunications, data management, security and network technology to provide a standardized digital infrastructure for Chevron’s global operations.

During 2007, the company entered into research alliances with Texas A&M University, with focus on the ~~potential to transform energy~~ production and ~~use.~~conversion of crops for biofuels from cellulose, and the Colorado Center for Biorefining and Biofuel, with focus on conversion technologies. 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~~has research alliances with the University of California, Davis and the Georgia Institute of ~~Technology. Both~~Technology that are focused on converting cellulosic biomass into ~~viable~~ transportation fuels.

Chevron’s research and development expenses were $562 million, $468 million ~~$316 million~~ and ~~$242~~$316 million for the years 2007, 2006 ~~2005~~ and ~~2004,~~2005, 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 to 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~~environment-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,~~2007, the company’s U.S. capitalized environmental expenditures were ~~$385~~approximately $350 million, representing approximately 75 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,~~2008, the company estimates U.S. capital expenditures for environmental control facilities will be approximately ~~$350~~$580 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~~2007 environmental expenditures, remediation provisions and year-end environmental reserves are contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations onpages~~FS-17~~ FS-16 ~~through~~and~~FS-19~~ ~~of this Annual Report onForm 10-K.~~FS-17.

Web Site Access to SEC Reports

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

The company’s Annual Reports onForm 10-K, Quarterly Reports onForm 10-Q, Current Reports onForm 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~~The reports are also available at the SEC’s ~~Internet~~ Web ~~site:~~site,~~http://www.sec.gov/~~www.sec.gov.

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Item 1A. Risk Factors

Chevron is a major fully integrated petroleum company with a diversified business portfolio, a 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~~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~~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 and renewing rights to explore, develop and produce ~~hydrocarbons in promising areas;~~hydrocarbons; 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,~~byproducts, 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 businessesand/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~~2007, 26 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~~ — member countries including Angola, Indonesia, Nigeria and Venezuela. ~~Approximately 25~~Twenty-eight 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.~~greenhouse gas emissions that may be regulated.

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 certain 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 Air Resources Board and the California Energy Commission are also in the process of developing a “Low Carbon Fuel Standard” for transportation fuels used in California, as directed by Governor Arnold Schwarzenegger. The company extracts crude oil and natural gas, operates refineries, and markets and sells gasoline, diesel and jet fuel in California. ~~It is not known at this time whether or~~The extent to ~~what extent~~which the state and local agencies’ regulations will affect the company’s California ~~operations.~~operations was not known as of early 2008.

~~Item 1B. Unresolved Staff Comments~~


Item 1B.	Unresolved Staff Comments

None.

~~Item 2. Properties~~


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~~on page 3 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~~FS-61 to ~~FS-76 of this Annual Report onForm 10-K.~~FS-74. Note ~~13,~~12, “Properties, Plant and Equipment,” to the company’s financial statements is onpage ~~FS-43~~ ~~of this Annual Report onForm 10-K.~~FS-42.


Item 3.	Legal Proceedings

~~Item 3. Legal Proceedings~~In January 2008, Chevron agreed to pay the state of New York a $162,500 civil penalty in connection with a February 2006 oil spill at the company’s facility in Perth Amboy, New Jersey.

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~~


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, onpage ~~FS-24~~ ~~of this Annual Report onForm 10-K.~~FS-24.

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 (2 )


							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, 2007		4,225,293		92.09		4,038,000		—
Nov. 1 – Nov. 30, 2007		10,455,696		86.46		10,200,000		—
Dec. 1 – Dec. 31, 2007		8,375,829		90.82		8,221,763		—

Total Oct. 1 – Dec. 31, 2007		23,056,818		89.08		22,459,763		(2	)


(1)	Includes ~~116,630~~42,494 common shares repurchased during the three-month period ended December 31, ~~2006,~~2007, 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~~554,561 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.~~2007.

(2)	In ~~December 2005,~~September 2007, the company ~~announced a $5~~authorized stock repurchases of up to $15 billion ~~common stock repurchase program.~~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 ~~was completed on November 30, 2006,~~will occur over a period of up to three years and may be discontinued at ~~which time 80,260,800~~any time. As of December 31, 2007, 23,530,209 shares had been ~~repurchased~~acquired under this program for ~~a total of $5~~$2.1 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~~2003 through ~~2006~~2007 are presented onpage ~~FS-62~~ ~~of this Annual Report onForm 10-K.~~FS-60.

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

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

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 onpage ~~FS-15~~FS-14 and in Note 7 to the Consolidated Financial Statements, “Financial and Derivative Instruments,” beginning onpage ~~FS-37.~~FS-36.

Item 8. Financial Statements and Supplementary Data

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

3534

Item 9. Changes in and Disagreements With ~~Auditors~~Accountants 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 inRules 13a-15(e) and15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)), as of December 31, ~~2006,~~2007, have concluded that as of December 31, ~~2006,~~2007, 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 ActRules 13a-15(f). The company’s management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of ~~its~~the company’s internal control over financial reporting based on theInternal Control — Integrated Frameworkissued 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.~~2007.

The ~~company management’s assessment~~effectiveness of the ~~effectiveness of its~~company’s internal control over financial reporting as of December 31, ~~2006,~~2007, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report ~~that is~~ included onpage ~~FS-26 of this Annual Report onForm 10-K.~~FS-26.

During the quarter ended December 31, ~~2006,~~2007, 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.

3635

PART III


Item 10.	Directors, Executive Officers and Corporate Governance

Executive Officers of the Registrant at February 28, 2008

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 members of the Executive Committee.


Name and Age		Current and Prior Positions (up to five years)	Current Areas of Responsibility

D.J. O’Reilly	61	Chairman of the Board and Chief Executive Officer (since 2000)	Chief Executive Officer
P.J. Robertson	61	Vice Chairman of the Board (since 2002) President of Chevron Overseas Petroleum Inc. (2000 to 2002)	Policy, Government and Public Affairs; Human Resources
J.E. Bethancourt	56	Executive Vice President (since 2003) Vice President of Human Resources (2001 to 2003)	Technology; Chemicals; Mining; Health, Environment and Safety
G.L. Kirkland	57	Executive Vice President (since 2005) President of Chevron Overseas Petroleum Inc. (2002 to 2004) President of Chevron U.S.A. Production Company (2000 to 2002)	Worldwide Exploration and Production Activities and Global Gas Activities, including Natural Gas Trading
J.S. Watson	51	Executive Vice President (since 2008) Vice President and President of Chevron International Exploration and Production Company (2005 through 2007) Vice President and Chief Financial Officer (2000 through 2004)	Business Development; Mergers and Acquisitions; Strategic Planning; Project Resources Company
M.K. Wirth	47	Executive Vice President (since 2006) President of Global Supply and Trading (2004 to 2006) President of Marketing, Asia, Middle East and Africa Marketing Business Unit (2001 to 2004)	Global Refining, Marketing, Lubricants, and Supply and Trading, excluding Natural Gas Trading
S.J. Crowe	60	Vice President and Chief Financial Officer (since 2005) Vice President and Comptroller (from 2000 through 2004)	Finance
C.A. James	53	Vice President and General Counsel (since 2002)	Law

The information on Directors appearing under the heading “Election of Directors — Nominees ~~For~~for Directors” in the Notice of the ~~2007~~2008 Annual Meeting of Stockholders and ~~2007~~2008 Proxy Statement, to be filed pursuant toRule 14a-6(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), in connection with the company’s ~~2007~~2008 Annual Meeting of Stockholders (the ~~“2007~~“2008 Proxy Statement”), is incorporated by reference in this Annual Report onForm 10-K. ~~See Executive Officers of the Registrant on pages 33 and 34 of this Annual Report onForm 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~~2008 Proxy Statement is incorporated by reference in this Annual Report onForm 10-K.

The information contained under the heading “Board Operations — Business Conduct and Ethics Code” in the ~~2007~~2008 Proxy Statement is incorporated by reference in this Annual Report onForm 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 independentinformation contained under the ~~New York Stock Exchange Corporate Governance Rules. Of these Audit~~heading “Board Operations — Board Committee ~~members, Charles R. Shoemate, Linnet F. Deily~~Membership and ~~Robert E. Denham are audit committee financial experts as determined~~Functions” in the 2008 Proxy Statement is incorporated by ~~the Board within the applicable definition of the SEC.~~reference in this Annual Report onForm 10-K.

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~~2008 Proxy Statement is incorporated herein by reference in this Annual Report onForm 10-K.

“The ~~members of~~information contained under the ~~Compensation~~heading “Board Operations — Board Committee ofMembership and Functions” in the ~~Board of Directors during the last fiscal year were Carla A. Hills (until her retirement~~2008 Proxy Statement is incorporated by reference in this Annual Report 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.”Form 10-K.

The information appearing under the heading “Management Compensation Committee Report” in the ~~2007~~2008 Proxy Statement is incorporated herein by reference in this Annual Report onForm 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~~2008 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~~2008 Proxy Statement is incorporated by reference in this Annual Report onForm 10-K.

The information contained under the heading “Equity Compensation Plan Information” in the ~~2007~~2008 Proxy Statement is incorporated by reference in this Annual Report onForm 10-K.

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

The information appearing under the heading “Board ~~Operations”~~Operations — Transactions With Related Persons” in the ~~2007~~2008 Proxy Statement is incorporated by reference in this Annual Report onForm 10-K.

Item 14. Principal Accounting Fees and Services

The information appearing under the ~~headings~~heading “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”~~Firm” in the ~~2007~~2008 Proxy Statement is incorporated by reference in this Annual Report onForm 10-K.

PART IV

~~Item 15. Exhibits, Financial Statement Schedules~~


Item 15.	Exhibits, Financial Statement Schedules

(a) The following documents are filed as part of this report:

(1) Financial Statements:


		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~~2007		FS-27
Consolidated Statement of Comprehensive Income for the three years ended December 31, ~~2006~~2007		FS-28
Consolidated Balance Sheet at December 31, ~~2006~~2007 and ~~2005~~2006		FS-29
Consolidated Statement of Cash Flows for the three years ended December 31, ~~2006~~2007		FS-30
Consolidated Statement of Stockholders’ Equity for the three years ended December 31, ~~2006~~2007		FS-31
Notes to the Consolidated Financial Statements		FS-32 to ~~FS-60~~FS-58

(2) Financial Statement Schedules:


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

(3) Exhibits:


		The Exhibit Index on pagesE-1 andE-2 ~~of this Annual Report on Form10-K~~lists the exhibits that are filed as part of this report.

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
Millions of Dollars


	Year Ended December 31									Year Ended December 31
	2006			2005			2004			2007			2006			2005

Employee Termination Benefits:
Balance at January 1	$	91		$	137		$	341		$	28		$	91		$	137
(Deductions) additions (credited) charged to expense		(21	)		(21	)		29
Additions (deductions) charged (credited) to expense											106			(21	)		(21	)
Additions related to Unocal acquisition		—			106			—			—			—			106
Payments		(42	)		(131	)		(233	)		(17	)		(42	)		(131	)

Balance at December 31	$	28		$	91		$	137		$	117		$	28		$	91

Allowance for Doubtful Accounts:
Balance at January 1	$	198		$	219		$	229		$	217		$	198		$	219
Additions charged to expense		61			3			36			29			61			3
Additions related to Unocal acquisition		—			6			—			—			—			6
Bad debt write-offs		(42	)		(30	)		(46	)		(46	)		(42	)		(30	)

Balance at December 31	$	217		$	198		$	219		$	200		$	217		$	198

Deferred Income Tax Valuation Allowance:*
Balance at January 1	$	3,249		$	1,661		$	1,553		$	4,391		$	3,249		$	1,661
Additions charged to deferred income tax expense		1,700			1,593			714			1,894			1,700			1,593
Additions related to Unocal acquisition		—			400			—			—			—			400
Deductions credited to goodwill		(77	)		(60	)		—			—			(77	)		(60	)
Deductions credited to deferred income tax expense		(481	)		(345	)		(606	)		(336	)		(481	)		(345	)

Balance at December 31	$	4,391		$	3,249		$	1,661		$	5,949		$	4,391		$	3,249


*	See also Note 1615 to the Consolidated Financial Statements beginning onpage ~~FS-44.~~FS-43.

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.~~2008.

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.~~2008.


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		Kevin W. Sharer* Kevin W. Sharer
		Charles R. Shoemate* Charles R. Shoemate

		Ronald D. Sugar* Ronald D. Sugar

		Carl Ware* Carl Ware

(This Page Intentionally Left Blank)

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


FS-2
	~~Page No.~~
Management’s Discussion and Analysis of Financial Condition and Results of Operations
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-l0
Liquidity and Capital Resources		FS-11
~~Information Related to Investment in Dynegy Inc.~~Financial Ratios		~~FS-11~~FS-13
~~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~~FS-13
Financial and Derivative Instruments		~~FS-15 to FS-16~~FS-14
Transactions With Related Parties		FS-15
Litigation and Other Contingencies		FS-16
~~Litigation and Other Contingencies~~Environmental Matters		~~FS-16 to FS-19~~FS-18
~~Environmental Matters~~		~~FS-19~~
Critical Accounting Estimates and Assumptions	~~FS-19 to FS-22~~FS-18
New Accounting Standards		~~FS-22 to FS-23~~FS-21
~~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~~

~~FS-1~~


~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL~~ ~~CONDITION AND RESULTS OF OPERATIONS~~

FS-24

Consolidated Financial Statements
Quarterly Results and Stock Market Data		FS-24
Report of Management		FS-25
Report of Independent Registered Public Accounting Firm		FS-26
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


FS-32

Notes to the Consolidated Financial Statements
Note 1	Summary of Significant Accounting Policies	FS-32
Note 2	Acquisition of Unocal Corporation	FS-34
Note 3	Information Relating to the Consolidated Statement of Cash Flows	FS-35
Note 4	Summarized Financial Data – Chevron U.S.A. Inc.	FS-35
Note 5	Summarized Financial Data – Chevron Transport Corporation Ltd.	FS-36
Note 6	Stockholders’ Equity	FS-36
Note 7	Financial and Derivative Instruments	FS-36
Note 8	Operating Segments and Geographic Data	FS-37
Note 9	Lease Commitments	FS-39
Note 10	Restructuring and Reorganization Costs	FS-40
Note 11	Investments and Advances	FS-40
Note 12	Properties, Plant and Equipment	FS-42
Note 13	Accounting for Buy/Sell Contracts	FS-42
Note 14	Litigation	FS-43
Note 15	Taxes	FS-43
Note 16	Short-Term Debt	FS-45
Note 17	Long-Term Debt	FS-46
Note 18	New Accounting Standards	FS-46
Note 19	Accounting for Suspended Exploratory Wells	FS-47
Note 20	Employee Benefit Plans	FS-48
Note 21	Stock Options and Other Share-Based Compensation	FS-53
Note 22	Other Contingencies and Commitments	FS-55
Note 23	Asset Retirement Obligations	FS-57
Note 24	Other Financial Information	FS-58
Note 25	Earnings Per Share	FS-58
Five-Year Financial Summary		FS-60
Supplemental Information on Oil and Gas Producing Activities		FS-61

FS-1

Management’s Discussion and Analysis of
Financial Condition and Results of Operations

~~KEY FINANCIAL RESULTS~~Key Financial Results


Millions of dollars, except per-share amounts	2006			2005			2004			2007			2006			2005

Net Income	$	17,138		$	14,099		$	13,328		$	18,688		$	17,138		$	14,099
Per Share Amounts:
Net Income – Basic	$	7.84		$	6.58		$	6.30		$	8.83		$	7.84		$	6.58
– Diluted	$	7.80		$	6.54		$	6.28		$	8.77		$	7.80		$	6.54
Dividends	$	2.01		$	1.75		$	1.53		$	2.26		$	2.01		$	1.75
Sales and Other Operating Revenues	$	204,892		$	193,641		$	150,865		$	214,091		$	204,892		$	193,641
Return on:
Average Capital Employed		22.6	%		21.9	%		25.8	%		23.1	%		22.6	%		21.9	%
Average Stockholders’ Equity		26.0	%		26.1	%		32.7	%		25.6	%		26.0	%		26.1	%

~~INCOME FROM CONTINUING OPERATIONS BY MAJOR~~
~~OPERATING AREA~~Income by Major Operating Area


Millions of dollars	2006			2005			2004			2007			2006			2005

Income From Continuing Operations
Upstream – Exploration and Production
United States	$	4,270		$	4,168		$	3,868		$	4,532		$	4,270		$	4,168
International		8,872			7,556			5,622			10,284			8,872			7,556

Total Upstream		13,142			11,724			9,490			14,816			13,142			11,724

Downstream – Refining, Marketing and Transportation
United States		1,938			980			1,261			966			1,938			980
International		2,035			1,786			1,989			2,536			2,035			1,786

Total Downstream		3,973			2,766			3,250			3,502			3,973			2,766

Chemicals		539			298			314			396			539			298
All Other		(516	)		(689	)		(20	)		(26	)		(516	)		(689	)

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

Net Income*	$	17,138		$	14,099		$	13,328		$	18,688		$	17,138		$	14,099

^*Includes Foreign Currency Effects:		$(219)			$(61)			$(81)
*Includes Foreign Currency Effects:											$ (352)			$ (219)			$ (61)

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.~~

2007.

~~BUSINESS ENVIRONMENT AND OUTLOOK~~Business Environment and Outlook

~~Chevron’s current~~Chevron is a global energy company with significant business activities 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 Saudi Arabia and Kuwait, the Philippines, Qatar, Republic of the Congo, Singapore, South Africa, South Korea, Thailand, Trinidad and Tobago, the United Kingdom, the United States, Venezuela and Vietnam.

Current and future earnings of the company 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~~continue to experience 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. The company’s operations, especially upstream, can also be affected by changing economic, regulatory and political environments in the various countries in which it operates, including the United States. Civil unrest, acts of violence or strained relations between a government and the company or other governments may impact the company’s operations or investments. Those developments have at times significantly affected the company’s operations and results and are carefully considered by management when evaluating the level of current and future activity in such countries.

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~~expected to ~~providing~~provide sufficient long-term value, or to acquire assets or operations complementary to its asset base to help augment the company’s growth. ~~During~~Asset sales during 2007 included the ~~first quarter 2007, the company authorized the sale of its~~company’s 31 percent ownership interest in a refinery and related assets in the ~~Nerefco Refinery~~Netherlands; fuels marketing businesses in Belgium, Luxembourg, the Netherlands and Uruguay; and the ~~associated TEAM Terminal~~investment in ~~the Netherlands. The transaction is subject to signing~~common stock 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~~.Dynegy Inc. 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:

FS-2

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 or fears thereof that

may be caused by military conflicts, civil unrest or political uncertainty.

~~FS-2~~

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

only the general level of inflation but also prices charged by the industry’s ~~product-~~material- and service-providers, which can be affected by the volatility of the industry’s own supply and demand conditions for such ~~products~~materials and services. The oil and gas industry worldwide has experienced significant price increases for these items ~~during~~since 2005, and ~~2006, and an upward trend in prices~~future price increases may continue ~~into 2007.~~to exceed the general level of inflation. 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.~~during 2007. The spot price for West Texas Intermediate (WTI) crude oil, a benchmark crude oil, averaged ~~$66~~$72 per barrel in ~~2006, an increase of~~2007, up approximately $9$6 per barrel from the ~~2005~~2006 average price. The rise in crude oil prices ~~between years reflected, among other things,~~was attributed primarily to 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,~~As of mid-February 2008, the WTI ~~spot~~ price ~~averaged~~was about ~~$56~~$93 per barrel.

As ~~was the case~~ in ~~2005,~~2006, a wide differential in prices existed in ~~2006~~2007 between high-quality ~~light-sweet~~(i.e., high-gravity, low sulfur) crude oils ~~(such as the U.S. benchmark WTI)~~

and those of lower quality (i.e., low-gravity, heavier types of ~~crude.~~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~~high-quality crude oil, has been strong worldwide. Chevron produces or shares in the production of 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~~FS-l0 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 in many regional markets are more closely aligned with ~~regional~~ supply and demand ~~conditions.~~conditions in those markets. In the United States during ~~2006,~~2007, benchmark prices at Henry Hub averaged about ~~$6.50~~$7 per thousand cubic feet (MCF), compared with about $8$6.50 in ~~2005. For early 2007 into late February, prices averaged~~2006. As of mid-February 2008, the Henry Hub price was about $7$8 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~~U.S. 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~~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~~FS-l0 for the company’s average natural gas prices for the ~~United States~~U.S. and international regions.) Additionally, ~~excess supply~~excess-supply conditions that exist in certain parts of the world cannot easily serve to mitigate the relatively ~~high-price~~high-

FS-3

Management’s Discussion and Analysis of
Financial Condition and Results of Operations

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

~~FS-3~~


~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL~~ ~~CONDITION AND RESULTS OF OPERATIONS~~

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 of contracts, changes in tax rates on income, and the cost of goods and services.

Chevron’s worldwide net oil-equivalent production in ~~2006,~~2007, including volumes produced from oil sands, ~~and production under an operating service agreement,~~ averaged ~~2.67~~2.62 million barrels per day, ~~or 6 percent higher than~~a decline of about 48,000 barrels per day from 2006, due mainly to the effect of a conversion of operating service agreements in Venezuela to joint-stock companies. (Refer to the table “Selected Operating Data” on page FS-l0 for a listing of production ~~in 2005. The increase between periods was largely due to~~ volumes ~~associated with~~for each of the ~~acquisition of Unocal in August 2005.~~three years ending December 31, 2007.) The company estimates that oil-equivalent production in ~~2007~~2008 will average approximately ~~2.6~~2.65 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~~delays in project start-ups, weather conditions that may shut in production, ~~disruptions that could be caused by severe weather, local~~ civil unrest, ~~and~~ changing ~~geopolitics.~~geopolitics or other disruptions to operations. Future production levels also are affected by the size and number of economic investment opportunities and, for new large-scale projects, the time lag between initial exploration and the beginning of production. 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 2428 percent of the company’s net oil-equivalent production in ~~2006~~2007 occurred in the OPEC-member countries of Angola, 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.~~ 2007.

The impact of OPEC quotas on the company’s production in ~~2007~~2008 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)~~, joint-stock companies), with Petróleos de Venezuela, S.A., (PDVSA) as majority shareholder. ~~Beginning in October,~~From that time, Chevron reported its equity share of the Boscan and LL-652 production, which was approximately ~~90,000~~85,000 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.

AtIn February 2007, the ~~end~~president of ~~2005~~Venezuela issued a decree announcing the government’s intention for PDVSA to take over operational control of all Orinoco Heavy Oil Associations effective May 1, 2007, and to increase its ownership in ~~certain onshore areas~~all such Associations to a minimum of ~~Nigeria, approximately 30,000 barrels per day~~60 percent. The decree included Chevron’s 30 percent-owned Hamaca project. In April 2007, Chevron signed a memorandum of understanding (MOU) with PDVSA that summarized the ~~company’s net production capacity remained shut-in following civil unrest and damage~~ongoing discussions to ~~production facilities that occurred in 2003. By the end~~transfer control of ~~2006, the company had resumed~~Hamaca operations in ~~portions of all~~accordance with the ~~affected fields, and more than 20,000 barrels per day of production had been restored. In early 2007, additional production restoration activities continued~~February decree. As provided in the ~~area; however, intermittent civil unrest could adversely impact company~~MOU, a PDVSA-controlled transitory operational committee, on which Chevron had representation, assumed responsibility for daily operations on May 1, 2007. The MOU stipulated that terms of existing contracts were to remain in place during the transition period. In December 2007, Chevron executed a conversion agreement and signed a charter and by-laws with a PDVSA subsidiary that provided for Chevron to retain its 30 percent interest in the ~~future.~~Hamaca project. The new entity, Petropiar, commenced activities in January 2008. The conversion agreement did not have a material effect on Chevron’s results of operations, consolidated financial position or liquidity.

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 margins on the refining and marketing of products that include gasoline, diesel, jet fuel, lubricants, fuel oil and feedstocks for chemical manufacturing. Industry margins are sometimes volatile and can be affected by the global and regional ~~supply and demand~~supply-and-demand balance for refined products and by changes in the ~~associated effects on industry refining~~price of crude oil used for refinery feedstock. Industry margins can also be influenced by refined-product inventory levels, geopolitical events, refinery maintenance programs and ~~marketing margins.~~disruptions at refineries resulting from unplanned outages that may be due to severe weather, fires or other operational events.

Other factors affecting profitability for downstream operations include the reliability and efficiency of the company’s refining and marketing network, the effectiveness of the crude-oil and

FS-4

product-supply functions and the economic returns on invested capital. Profitability can also be affected by the volatility of tanker charter ~~expenses~~rates 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~~most significant marketing areas are the West Coast of North America, the U.S. Gulf Coast, Latin America, Asia, sub-Saharan Africa and ~~sub-Saharan Africa. The company~~the United Kingdom. Chevron operates or has ownership interests in refineries in each of these areas except Latin America. ~~In 2006, earnings for~~For the ~~segment improved substantially, mainly as~~industry, refined-product margins were generally higher in 2007 than in 2006. For the ~~result of higher average~~company, U.S. refined-product margins ~~for refined products~~during 2007 were negatively affected by planned and ~~improved operations~~unplanned downtime at ~~the company’s~~its three largest U.S. refineries.

~~FS-4~~

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~~page FS-7 through 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~~FS-8 for additional discussion of chemicals earnings.

~~OPERATING DEVELOPMENTS~~Operating Developments

Key operating developments and other events during ~~2006~~2007 and early ~~2007 included:~~2008 included the following:

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~~Discovered crude oil at the 31 percent-owned and operated ~~Lucapa-1~~Malange-1 well in ~~deepwater~~offshore Block 14. ~~The company plans to conduct appraisal~~Additional drilling and ~~additional~~ geologic and engineering studies are planned to ~~assess~~appraise the ~~potential resource.~~discovery. The company and partners also made the final investment decision to construct a liquefied natural gas (LNG) plant that will be owned 36 percent by Chevron. The plant will be designed

with a capacity to process 1 billion cubic feet of natural gas per day and produce 5.2 million metric tons a year of LNG and related gas liquids products.

Australia ~~In July 2006,~~Received federal and state environmental approvals for development of the ~~company discovered~~50 percent-owned and operated Gorgon LNG project located off the northwest coast. The approvals represented a significant milestone towards the development of the company’s natural gas resources offshore Australia.

Bangladesh Began production 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~~98 percent-owned Bibiyana natural gas ~~discovery at its Clio-1 exploration well.~~field. The ~~company holds~~field’s total production is expected to increase to a 67maximum of 500 million cubic feet per day by 2010.

China Signed a 30-year production-sharing contract with China National Petroleum Corporation to assume operatorship and hold a 49 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~~development of the Chuandongbei natural gas ~~find and subsequent development options.~~

~~In early 2007,~~area in central China. Design input capacity of 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 drillingproposed gas plants is expected to be 740 million cubic feet of ~~an exploration well.~~natural gas per day.

~~Azerbaijan~~Indonesia Began commercial operation of the 1l0-megawatt Darajat III geothermal power plant in Garut, West Java. The plant increased Darajat’s total capacity to 259 megawatts.

Kazakhstan Initiated production from the first ~~tanker lifting~~phase of the Sour Gas Injection and Second Generation Plant expansion projects at the 50 percent-owned Tengiz Field. This phase increased production capacity by 90,000 barrels of crude oil ~~transported through~~per day to approximately 400,000. Full facility expansion is expected to occur during the ~~9 percent-owned Baku-Tbilisi-Ceyhan (BTC) pipeline occurred~~second-half 2008, increasing production capacity to 540,000 barrels per day.

Republic of the Congo Confirmed two crude oil discoveries in ~~June 2006. The crude is being supplied by~~ the ~~Azerbaijan International Oil Company,~~offshore Moho-Bilondo permit. Evaluation and development studies were undertaken to appraise the discoveries, in which ~~the company has~~Chevron holds a 1032 percent nonoperated working interest.

~~Brazil~~Thailand ~~In June 2006,~~Signed an agreement to increase sales of natural gas from company-operated Blocks 10, 11, 12 and 13 in the Gulf of Thailand to PTT Public Company Limited. Chevron has ownership interests ranging from 60 percent to 80 percent in the blocks, which received 10-year production-period extensions to 2022. The company ~~announced~~was also granted the ~~decision~~concession rights for a six-year period to ~~develop the 52 percent-owned and operated~~four prospective 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.~~petroleum blocks, three of which it will operate.

~~Canada~~Trinidad and Tobago Signed an agreement to sell natural gas to the National Gas Company of Trinidad and Tobago for 11 years with an option for a four-year extension. 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~~gas is expected to ~~add 100,000 barrels per day~~be sourced from Chevron’s 50 percent-owned East Coast Marine Area.

United States Announced that first production from the Tahiti project in the deepwater Gulf of ~~mining and upgrading capacity at an estimated total project cost of $10 billion. Completion of~~Mexico is expected by the ~~expansion~~third quarter 2009. The start-up is approximately one year later than originally planned due to metallurgical problems with the mooring shackles for ~~2010, increasing total capacity of~~ the ~~project to approximately 255,000 barrels per day. The company holds a 20~~floating production facility.

Downstream

Benelux Countries Sold the company’s 31 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~~Nerefco Refinery and related assets in the ~~20 percent-owned offshore Oil Prospecting License 214. Future drilling is contingent primarily on~~Netherlands, and the ~~outcome of ongoing technical studies.~~company’s fuels marketing businesses in Belgium, Luxembourg and the Netherlands, resulting in gains totaling $960 million.

FS-5


Management’s Discussion and Analysis of Financial Condition and Results of Operations ~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL~~ ~~CONDITION AND RESULTS OF OPERATIONS~~

~~Norway~~South Korea ~~In April 2006,~~Completed construction and commissioned new facilities associated with a $1.5 billion upgrade at the ~~company was awarded~~50 percent-owned GS Caltex Yeosu Refinery, enabling the ~~rights~~refinery to ~~six blocks in~~process heavier and higher-sulfur crude oils and increase 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.~~gasoline, diesel and other light products.

~~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~~Approved plans at the company’s refinery in Pascagoula, Mississippi, ~~increasing~~for the ~~refinery’s gasoline manufacturing capacity by about 10 percent. The company also submitted an environmental permit application for~~ construction of ~~facilities~~a Continuous Catalyst Regeneration unit, which is expected to increase gasoline ~~output~~production by ~~another 15 percent.~~

~~India~~ ~~In April 2006,~~10 percent, or 600,000 gallons per day, by mid-2010. At 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~~El Segundo, California, modifications were completed to enable the ~~world’s sixth largest, designed for a~~processing of heavier crude ~~oil processing capacity of 580,000 barrels per day. Chevron~~oils into light transportation fuels 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.refined products.

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,~~Increased the ~~company increased its~~company’s quarterly common stock dividend by ~~15.5~~11.5 percent in April to ~~$0.52~~$0.58 per ~~share. In November,~~share, marking the 20th consecutive year the company ~~completed~~has increased its ~~second $5 billion common stock buyback~~annual dividend payment.

Common Stock Repurchase Program Approved a program ~~since 2004 and~~ in ~~December authorized the acquisition of~~September to acquire up to $5$15 billion of ~~additional shares~~the company’s common stock over a period of up to three ~~years.~~years, which followed three stock repurchase programs of $5 billion each that were completed in 2005, 2006 and September 2007.

Dynegy Sold the company’s common stock investment in Dynegy Inc., resulting in a gain of $680 million.

~~RESULTS OF OPERATIONS~~Results of Operations

Major Operating AreasThe 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.~~level, and the company’s investment in Dynegy prior to its sale in May 2007. 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,~~FS-37, for a discussion of the company’s “reportable segments,” as defined in FASB No. 131,Disclosures About Segments of an Enterprise and Related ~~Information~~.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


Millions of dollars	2007		2006		2005

Income	$	4,532	$	4,270	$	4,168

U.S. upstream income of $4.5 billion in 2007 increased approximately $260 million from 2006. Results in 2007 benefited approximately $700 million from higher prices for crude oil and natural gas liquids. This benefit to income was partially offset by the

effects of a decline in oil-equivalent production and an increase in depreciation, operating and exploration expenses.

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~~exploration and ~~expenses for~~ depreciation ~~and exploration.~~expenses. 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-~~

~~FS-6~~

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~~2007 was ~~$56.66~~$63.16 per barrel, compared with $56.66 in 2006 and $46.97 in ~~2005 and $34.12 in 2004.~~2005. The average natural gas realization was ~~$6.29~~$6.12 per thousand cubic feet in ~~2006,~~2007, compared with $6.29 and $7.43 in 2006 and ~~$5.51 in~~ 2005, ~~and 2004,~~ respectively.

Net oil-equivalent production in ~~2006~~2007 averaged ~~763,000~~743,000 barrels per day, down 2.6 percent from 2006 and up 52 percent from 2005, ~~and down 7 percent from 2004. The increase between 2005 and 2006 was due to the full-year benefit~~which included only five months of production from the ~~former~~ Unocal

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

that year. The net liquids component of oil-equivalent production for 2007 averaged 460,000 barrels a day, which was essentially flat compared with 2006, ~~averaged 462,000 barrels per day,~~and an increase of ~~approximately 2~~1 percent from ~~2005 and a decrease of 9 percent from 2004.~~2005. Net natural gas production averaged ~~1.8~~1.7 billion cubic feet per day in ~~2006, up 11~~2007, down 6 percent from ~~2005~~2006 and ~~down 3~~up 4 percent from ~~2004.~~2005.

FS-6

Refer to the “Selected Operating Data” table, on page ~~FS-11,~~FS-10, for the three-year comparative production volumes in the United States.

International Upstream – -Exploration and Production


Millions of dollars	2007		2006		2005

Income*	$	10,284	$	8,872	$	7,556

*Includes Foreign Currency Effects:		$ (417)		$ (371)		$ 14

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 $10.3 billion in 2007 increased $1.4 billion from 2006. Earnings in 2007 benefited approximately $1.6 billion from higher prices, primarily for crude oil, and $300 million from increased liftings. Non-recurring income tax items also benefited earnings between periods. These benefits to income were partially offset by the impact of higher operating and depreciation expenses.

Income in 2006 of approximately $8.9 billion ~~in 2006~~ increased $1.3 billion from 2005. Earnings in 2006 benefited approximately ~~$3.0~~$3 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~~2007 was ~~$57.65~~$65.01 per barrel, compared with $57.65 in 2006 and $47.59 in ~~2005 and $34.17 in 2004.~~2005. The average natural gas realization was ~~$3.73~~$3.90 per thousand cubic feet in ~~2006,~~2007, compared with $3.73 and $3.19 in 2006 and ~~$2.68 in~~ 2005, ~~and 2004,~~ respectively.

Net oil-equivalent production of ~~1.9~~1.88 million barrels per day in 2007 declined about 2 percent from 2006 ~~including about 100,000 net barrels per day~~and increased 5 percent from 2005. The volumes for each year included production from oil sands in Canada and ~~production under~~ an operating service agreement in Venezuela ~~prior to~~until its conversion to a ~~joint stock~~joint-stock company in October 2006. The decline between 2006 and 2007 was associated with the impact of this contract conversion in Venezuela and the price effects on production volumes calculated under production-sharing agreements. Partially offsetting the decline was increased ~~about 6 percent~~production in Bangladesh, Angola and Azerbaijan. The increase from 2005 ~~and 13 percent~~was due to that year having included only five months of production from ~~2004. This trend was largely~~ the ~~result of the effects of the~~former Unocal ~~acquisition in August 2005, partially offset by the effect of normal field declines and property sales in 2004.~~properties.

The net liquids component of oil-equivalent production was ~~1.4~~1.3 million barrels per day in ~~2006, an increase~~2007, a decrease of approximately 24 percent from ~~2005~~2006 and ~~2004.~~3 percent from 2005. Net natural gas production of ~~3.1~~3.3 billion cubic feet per day in ~~2006~~2007 was up 215.5 percent and 5128 percent from ~~2005~~2006 and ~~2004,~~2005, respectively.

Refer to the “Selected Operating Data” table, on page ~~FS-11,~~FS-10, for the three-year comparative of international production volumes.

~~FS-7~~


~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL~~ ~~CONDITION AND RESULTS OF OPERATIONS~~

~~U.S.~~US. Downstream – -Refining, Marketing and Transportation


Millions of dollars	2007		2006		2005

Income	$	966	$	1,938	$	980

Millions of dollars 2006 2005 2004

Income
$ 1,938 $ 980 $ 1,261

U.S. downstream earnings of ~~$1.9 billion~~$966 million in ~~2006 increased about~~2007 declined nearly $1 billion from 2006 and were essentially the same as 2005. The decline in 2007 from 2006 was associated mainly with weaker refined-product margins due to the effects of higher crude oil prices and the negative impacts of higher planned and unplanned downtime on refinery production volumes at the company’s three major refineries. Operating expenses were also higher in 2007. The improvement in 2006 earnings from 2005 ~~and approximately $700 million from 2004. Average~~was primarily associated with higher average refined-product margins in 2006 ~~were higher than~~and the adverse effect of downtime in 2005 ~~which in turn were also higher than in 2004. Refinery crude inputs were higher in 2006 than in the other comparative periods~~at refining, marketing and ~~also benefited earnings. However, earnings declined in 2005 from~~

~~a year earlier due mainly to increased downtime at the company’s refineries, including the shutdown of~~pipeline operations ~~at Pascagoula, Mississippi, for more than a month due to~~that was caused by 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~~1.46 million barrels per day ~~an increase~~in 2007, a decrease of 3 percent and 1 percent from 2006 and 2005, ~~and relatively unchanged from 2004.~~respectively. The reported sales volume for ~~2006~~2007 was on a different basis than in2006 and 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~~this accounting ~~change, refined product~~standard, refined-product sales in ~~2006 increased by approximately 6 percent and 3~~2007 decreased 1 percent from ~~2005~~2006 and ~~2004, respectively.~~increased about 5 percent from 2005. Branded gasoline sales volumes of ~~approximately 614,000~~629,000 barrels per day in ~~2006~~2007 increased about 42 percent from 2006 and 6 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,~~FS-l0 for ~~the~~a three-year comparative ~~refined-product~~of sales volumes ~~in the United States.~~of gasoline and other refined products and refinery-input volumes. Refer also to Note ~~14,~~~~Accounting~~13, “Accounting for Buy/Sell Contracts,,” on page ~~FS-43~~FS-42 for a discussion of the accounting for purchase and sale contracts with the same counterparty.

FS-7

Management’s Discussion and Analysis of
Financial Condition and Results of Operations

International Downstream–Refining, Marketing and Transportation


Millions of dollars	2006		2005		2004		2007		2006		2005

Income*	$	2,035	$	1,786	$	1,989	$	2,536	$	2,035	$	1,786

*Includes Foreign Currency Effects:		$ 98		$ (24)		$ 7		$ 62		$ 98		$(24	)

International downstream income of $2$2.5 billion in ~~2006~~2007 increased about ~~$250~~$500 million from ~~2005~~2006 and ~~about $50~~$750 million from ~~2004.~~2005. Results for 2007 included gains of approximately $1 billion on the sale of assets, including an interest in a refinery and marketing assets in the Benelux region of Europe. Margins on the sale of refined products in 2007 were up slightly from the prior year. Operating expenses were higher, and earnings from the company’s shipping operations were lower. The increase in earnings in 2006 ~~from~~compared with 2005 was associated mainly with the

benefit of ~~higher-refined product~~higher refined-product sales margins in the Asia-Pacific area 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.

~~FS-8~~

Refined-product sales volumes were ~~2.1~~2.03 million barrels per day in ~~2006,~~2007, about 65 percent and 10 percent lower than ~~2005.~~2006 and 2005, respectively, due largely to the impact of asset sales and the accounting-standard change for buy/sell contracts. 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~~decreased about 4 percent ~~lower than in 2004, primarily the result of lower gasoline trading activity~~ and ~~lower fuel oil sales.~~5 percent from 2006 and 2005, respectively.

Refer to the “Selected Operating Data” table on page ~~FS-11,~~FS-10 for ~~the~~a three-year comparative ~~refined-product~~of sales volumes inof gasoline and other refined products and refinery-input volumes. Refer also to Note 13, “Accounting for Buy/Sell Contracts,” on page FS-42 for a discussion of the ~~international areas.~~accounting for purchase and sale contracts with the same counterparty.

Chemicals

Millions of dollars 2006 2005 2004

Income*
$ 539 $ 298 $ 314

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


Millions of dollars	2007		2006		2005

Income*	$	396	$	539	$	298

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

The chemicals segment includes the company’s Oronite subsidiary and the 50 percent-owned Chevron Phillips Chemical Company LLC (CPChem). In 2007, earnings were $396 million, compared with $539 million and $298 million in 2006 and 2005, respectively. Between 2006 and 2007, the benefit of improved margins on sales of lubricants and fuel additives by Oronite was more than offset by the effect of lower margins on the sale of commodity chemicals by CPChem. In 2006, earnings of $539 million increased about ~~$200~~$240 million from ~~both~~ 2005 ~~and 2004. Margins in 2006~~due to higher margins 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.

Oronite.

All Other


Millions of dollars	2006			2005			2004			2007			2006			2005

Net Charges*	$	(516	)	$	(689	)	$	(20	)	$	(26	)	$	(516	)	$	(689	)

*Includes Foreign Currency Effects:		$62			$(51)			$44			$ 6			$ 62			(51	)

All Other ~~consists of the company’s interest in Dynegy Inc.,~~includes mining operations, power generation businesses, worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, alternative fuels and technology ~~companies.~~companies, and the company’s interest in Dynegy prior to its sale in May 2007.

Net charges of $26 million in 2007 decreased $490 million from 2006. Results in 2007 included a $680 million gain on the sale of the company’s investment in Dynegy common stock and a loss of approximately $175 million associated with the early redemption of Texaco Capital Inc. bonds. Excluding these items and the effects of foreign currency, net charges decreased about $40 million between periods.

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~~periods, primarily due to higher interest income ~~was higher in 2006,~~ and lower 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~~2006.

FS-8

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~~Consolidated Statement of Income

Comparative amounts for certain income statement categories are shown below:


Millions of dollars	2006		2005		2004		2007		2006		2005

Sales and other operating revenues	$	204,892	$	193,641	$	150,865	$	214,091	$	204,892	$	193,641

Sales and other operating revenues in ~~2006~~2007 increased over ~~2005~~2006 due primarily to higher prices for crude oil, natural gas, natural gas liquids and refined ~~products.~~products, partially offset by lower sales volumes. The increase in 2006 from 2005 ~~from 2004~~ was ~~a result of the same factor plus the effect of~~primarily due to higher ~~average~~ prices for ~~crude oil and natural gas.~~refined products. The higher revenues in 2006 were net of an impact from ~~the~~a change in the accounting for buy/sell contracts, as described in Note 1413 on page ~~FS-43.~~FS-42.


Millions of dollars	2007		2006		2005

Income from equity affiliates	$	4,144	$	4,255	$	3,731

Millions of dollars 2006 2005 2004

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

~~Increased~~

Lower income from equity affiliates in ~~2006~~2007 was mainly due to a decline in earnings from CPChem, Dynegy (sold in May 2007) and downstream affiliates in the Asia-Pacific area. Partially offsetting these declines were improved results for Tengizchevroil (TCO) and ~~CPChem.~~income for a full year from Petroboscan, which was converted from an operating service agreement to a joint-stock company in October 2006. The ~~improvement in~~increase between 2005 ~~from 2004~~and 2006 was primarily due to improved results for TCO and ~~Hamaca (Venezuela).~~CPChem. Refer to Note ~~12,~~11, beginning on page ~~FS-41,~~FS-40, for a discussion of Chevron’s investment in affiliated companies.


Millions of dollars	2007		2006		2005

Other income	$	2,669	$	971	$	828

Millions of dollars 2006 2005 2004

Other income
$ 971 $ 828 $ 1,853

Other income of nearly ~~$1.9~~$2.7 billion in ~~2004~~2007 included ~~approximately $1.3 billion~~the net of gains totaling $1.7 billion from ~~upstream property sales.~~the sale of downstream assets in the Benelux countries and the company’s investment in Dynegy and a loss of approximately $245 million on the early redemption of Texaco debt. Interest income ~~contributed~~was approximately $600 million, $600 million and $400 million in 2007, 2006 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 $352 million, $260 million ~~in 2006~~ and $60 million in ~~both 2005~~the corresponding years.


Millions of dollars	2007		2006		2005

Purchased crude oil and products	$	133,309	$	128,151	$	127,968

Crude oil and ~~2004.~~

Millions of dollars 2006 2005 2004

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

product purchases in 2007 increased from 2006 due to higher prices for crude oil, natural gas, natural gas liquids and refined products. 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 athe full year 2006 vs. five months in ~~2006.~~2005. 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		2007		2006		2005

Operating, selling, general and administrative expenses	$	19,717	$	17,019	$	14,389	$	22,858	$	19,717	$	17,019

~~FS-9~~


~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL~~ ~~CONDITION AND RESULTS OF OPERATIONS~~

Operating, selling, general and administrative expenses in ~~2006~~2007 increased 16 percent from a year earlier. Expenses ~~associated~~were higher in a number of categories, with the ~~former Unocal operations are included~~largest increases recorded for the cost of employee payroll and contract labor. Total expenses increased in 2006 from 2005 due mainly to the inclusion of former-Unocal expenses for the full year ~~in 2006, vs. five months in 2005.~~2006. Besides this effect, expenses were higher in 2006 for labor, transportation, and 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.2005.


Millions of dollars	2007		2006		2005

Exploration expense	$	1,323	$	1,364	$	743

Millions of dollars 2006 2005 2004

Exploration expense
$ 1,364 $ 743 $ 697

Exploration expenses in 2007 declined from 2006 mainly due to lower amounts for well write-offs and geological and geophysical costs for operations outside the United States. Expenses increased in 2006 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.~~the full year 2006.


Millions of dollars	2007		2006		2005

Depreciation, depletion and amortization	$	8,708	$	7,506	$	5,913

Millions of dollars 2006 2005 2004

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

Depreciation, depletion and amortization expenses increased from ~~2004~~2005 through ~~2006 mainly as a result of depreciation and depletion expense for the former Unocal assets~~2007, reflecting an increase in charges related to asset write-downs 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~~worldwide 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~~Unocal-related amounts beginning in August 2005.


Millions of dollars	2007		2006		2005

Taxes other than on income	$	22,266	$	20,883	$	20,782

Taxes other than on income increased in 2007 from a year earlier due to higher duties in 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

company’s U.K. downstream operations. 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.


Millions of dollars	2007		2006		2005

Interest and debt expense	$	166	$	451	$	482

Interest and debt expense in 2007 decreased from 2006 primarily due to lower average debt balances and higher amounts of interest capitalized. The decrease in 2006 vs. 2005 was mainly due to lower average debt balances and an increase in ~~2005 from 2004 was~~ the ~~result~~amount of interest capitalized, partially offset by higher ~~international taxes assessed~~average interest rates on ~~product values, higher duty rates in the areas of the company’s European downstream operations~~commercial paper and ~~higher U.S. federal excise taxes on jet fuel resulting from a change in tax law that became effective in 2005.~~other variable-rate debt.

FS-9

Millions of dollars 2006 2005 2004

Income tax expense
$ 14,838 $ 11,098 $ 7,517

Management’s Discussion and Analysis of
Financial Condition and Results of Operations


Millions of dollars	2007		2006		2005

Income tax expense	$	13,479	$	14,838	$	11,098

Effective income tax rates were 42 percent in 2007, 46 percent in 2006 and 44 percent in ~~2005~~2005. Rates were lower in 2007 compared with the prior year due mainly to the impact of nonrecurring items, including asset sales in 2007 and ~~37 percent in 2004. The higher tax rate in~~the absence of 2006 ~~included the effect of one-time~~ charges ~~totaling $400 million, including an increase in~~related to a tax-law change that increased tax rates on upstream operations in the U.K. North Sea and the settlement of a tax claim in Venezuela. ~~Rates were~~The higher tax rate in ~~2005~~2006 compared with ~~the prior year due to an increase~~2005 also reflected these nonrecurring charges in ~~earnings in countries with higher tax rates and the absence of benefits in 2004 from changes in the income tax laws for certain international operations.~~2006. Refer also to the discussion of income taxes in Note 1615 beginning on page ~~FS-44.~~FS-43.

Selected Operating Data^1,2


	2007			2006		2005

U.S. Upstream³
Net Crude Oil and Natural Gas Liquids Production (MBPD)		460			462		455
Net Natural Gas Production (MMCFPD)⁴		1,699			1,810		1,634
Net Oil-Equivalent Production (MBOEPD)		743			763		727
Sales of Natural Gas (MMCFPD)		7,624			7,051		5,449
Sales of Natural Gas Liquids (MBPD)		160			124		151
Revenues From Net Production
Liquids ($/Bbl)	$	63.16		$	56.66	$	46.97
Natural Gas ($/MCF)	$	6.12		$	6.29	$	7.43

International Upstream³
Net Crude Oil and Natural Gas Liquids Production (MBPD)		1,296			1,270		1,214
Net Natural Gas Production (MMCFPD)⁴		3,320			3,146		2,599
Net Oil-Equivalent Production (MBOEPD)⁵		1,876			1,904		1,790
Sales Natural Gas (MMCFPD)		3,792			3,478		2,450
Sales Natural Gas Liquids (MBPD)		118			102		120
Revenues From Liftings
Liquids ($/Bbl)	$	65.01		$	57.65	$	47.59
Natural Gas ($/MCF)	$	3.90		$	3.73	$	3.19

U.S. and International Upstream³
Net Oil-Equivalent Production Including Other Produced Volumes (MBOEPD)^4,5
United States		743			763		727
International		1,876			1,904		1,790

Total		2,619			2,667		2,517

U.S. Downstream			��
Gasoline Sales (MBPD)⁶		728			712		709
Other Refined Product Sales (MBPD)		729			782		764

Total (MBPD)⁷		1,457			1,494		1,473
Refinery Input (MBPD)		812			939		845

International Downstream
Gasoline Sales (MBPD)⁶		581			595		662
Other Refined Product Sales (MBPD)		1,446			1,532		1,590

Total (MBPD)^7,8		2,027			2,127		2,252
Refinery Input (MBPD)		1,021			1,050		1,038


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	65	56	48
International	433	419	356
⁵ Includes other produced volumes (MBPD):
Athabasca Oil Sands – Net	27	27	32
Boscan Operating Service Agreement	–	82	111

	27	109	143
⁶ Includes branded and unbranded gasoline.
⁷ Includes volumes for buy/sell contracts (MBPD):
United States	–	26	88
International	–	24	129

⁸ Includes sales of affiliates (MBPD):	492	492	498

FS-10

~~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.~~Liquidity and Capital Resources

~~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.

~~FS-11~~


~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL~~ ~~CONDITION AND RESULTS OF OPERATIONS~~

~~LIQUIDITY AND CAPITAL RESOURCES~~

Cash, cash equivalents and marketable securities Total balances were ~~$11.4~~$8.1 billion and ~~$11.1~~$11.4 billion at December 31, ~~2006~~2007 and ~~2005,~~2006, respectively. Cash provided by operating activities in ~~2006~~2007 was ~~$24.3~~$25.0 billion, compared with $24.3 billion in 2006 and $20.1 billion in ~~2005 and $14.7 billion in 2004.~~2005.

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,~~$300 million, $400 million and $1.0 billion in 2007, 2006 and ~~$1.6 billion in 2006,~~ 2005, ~~and 2004,~~ respectively. Cash provided by investing activities included proceeds from asset sales of $3.3 billion in 2007, $1.0 billion in 2006 and $2.7 billion in ~~2005 and $3.7 billion in 2004.~~2005.

Cash provided by operating activities and asset sales during ~~2006~~2007 was sufficient to fund the company’s ~~$13.8~~$17.7 billion capital and exploratory program, pay ~~$4.4~~$4.8 billion of dividends to stockholders and repay approximately ~~$2.9 billion in debt and repurchase $5~~$3.7 billion of ~~common stock.~~debt.

Restricted cash of $799 million associated with capital-investment projects at the company’s Pascagoula, Mississippi, refinery and Angola liquefied natural gas project was invested in short-term marketable securities and reclassified from cash equivalents to a long-term asset on the Consolidated Balance Sheet.

Dividends The company paid dividends of approximately $4.8 billion in 2007, $4.4 billion in 2006 and $3.8 billion in ~~2005 and $3.2 billion in 2004.~~2005. In April ~~2006,~~2007, the company increased its quarterly common stock dividend by ~~15.5~~11.5 percent to 5258 cents per share.

Debt, capital lease and minority interest obligations Total debt and capital lease balances were ~~$9.8~~$7.2 billion at

December 31, ~~2006,~~2007, down from ~~$12.9~~$9.8 billion at year-end ~~2005.~~2006. The company also had minority interest obligations of ~~$209~~$204 million, updown from ~~$200~~$209 million at December 31, ~~2005.~~2006.

The ~~$3.1~~$2.6 billion reduction in total debt and capital lease obligations during ~~2006~~2007 included the early redemption and maturity of ~~several~~ individual debt issues. In ~~the first quarter, $185~~February, $144 million of ~~Union Oil Company~~Texaco Capital Inc. bonds matured. In the second ~~quarter,~~and fourth quarters, the company redeemed approximately ~~$1.7~~$809 million and $65 million, respectively of Texaco Capital Inc.

debt and recognized an after-tax loss of approximately $175 million. In August, $2 billion of ~~Unocal debt prior to maturity. In the fourth quarter, a $129 million Texaco Capital Inc. bond matured, and Union Oil~~Chevron Canada Funding Company bonds ~~of $196~~matured. In December, the company issued a $650 million ~~were redeemed prior~~tax exempt Mississippi Gulf Opportunity Zone bond to ~~maturity.~~fund an upgrade project at the company’s refinery in Pascagoula, Mississippi. Commercial paper balances at the end of ~~2006 were reduced $626~~2007 declined approximately $450 million from $3.5 billion at year-end ~~2005.~~2006. In February ~~2007, a $144~~2008, $750 million ~~Texaco Capital Inc. bond~~of Chevron Canada Funding Company bonds 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~~$5.5 billion at December 31, ~~2006, up~~2007, down from ~~$5.6~~$6.6 billion at year-end ~~2005.~~2006. Of these amounts, ~~$4.5~~$4.4 billion and ~~$4.9~~$4.5 billion were reclassified to long-term at the end of each period, respectively. At year-end ~~2006,~~2007, settlement of ~~the reclassified amount~~these obligations was not expected to require the use of working capital ~~in 2007,~~within one year, as the company had the intent and the ability, as evidenced by committed credit facilities, to refinance ~~the amounts~~them 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,~~2007, the company had $5 billion in committed credit facilities with various major banks, which ~~permitted~~permit the refinancing of short-term obligations on a long-term basis. These facilities support commercial paper ~~borrowings~~borrowing and also 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.~~2007.

In ~~addition,~~March 2007, the company ~~has~~filed with the Securities and Exchange Commission (SEC) an automatic registration statement that expires in March 2010. This registration statement is for an unspecified amount of non-convertible debt securities issued or guaranteed by the company. At the same time, the company withdrew three ~~existing effective “shelf”~~shelf registration statements on file with the ~~Securities and Exchange Commission~~SEC that ~~together would permit additional registered debt offerings~~permitted the issuance of up to ~~an aggregate~~ $3.8 billion of debt securities.

~~In 2004, Chevron entered into $1 billion of interest rate swap transactions, in which~~At December 31, 2007, 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.

~~FS-12~~

~~The company has~~had outstanding public bonds issued by Chevron Corporation Profit Sharing/Savings Plan Trust Fund, Chevron Canada Funding Company (formerly ~~Chevron Texaco~~ChevronTexaco 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~~Aal by Moody’s Investors Service. The rating by Moody’s reflects an upgrade in December from Aa2. The company’s U.S. commercial paper is rated ~~A-1+~~A-l+ 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.~~Moody’s. 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

FS-11

Management’s Discussion and Analysis of
Financial Condition and Results of Operations

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~~2006 was completed in ~~November 2006.~~September 2007. During ~~2006,~~2007, about ~~78.5~~61.5 million common shares were ~~repurchased~~acquired under this program at a total cost of $4.9 billion.

~~In December 2006,~~ Upon completion of this program, the company authorized the acquisition of up to ~~an additional $5~~$15 billion of ~~its~~additional 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~~As of December 31, 2007, 23.5 million shares inhad been acquired under the ~~open market~~new program for ~~$100 million during December 2006 and~~$2.1 billion. Purchases through mid-February ~~2007~~2008 increased the total shares acquired to ~~8.2~~34.2 million at a cost of ~~$592 million.~~approximately $3.0 billion.

Capital and exploratory expenditures Total reported expenditures for ~~2006~~2007 were ~~$16.6~~$20 billion, including ~~$1.9~~$2.3 billion for the company’s share of affiliates’ expenditures, which did not require cash outlays by the company. In ~~2005~~2006 and ~~2004,~~2005, expenditures were ~~$11.1~~$16.6 billion and ~~$8.3~~$11.1 billion, respectively, including the company’s share of affiliates’ expenditures of ~~$1.7~~$1.9 billion and ~~$1.6~~$1.7 billion in the ~~cor-~~

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

Of the ~~$16.6~~$20 billion in expenditures for ~~2006,~~2007, about three-fourths, or ~~$12.8~~$15.5 billion, related to upstream activities. Approximately the same percentage was also expended for upstream operations in ~~2005~~2006 and ~~2004.~~2005. 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~~$12.7 billion of this amount outside the United States. Spending in ~~2007~~2008 is primarily targeted for exploratory prospects in the deepwater Gulf of Mexico and western Africa and major development projects in Angola, Australia, Brazil, Indonesia, Kazakhstan, Nigeria, Thailand, the deepwater Gulf of Mexico, the Piceance Basin in Colorado and an oil sands project in Canada.

Worldwide downstream spending in ~~2007~~2008 is estimated at ~~$3.8~~$4.1 billion, with about ~~$1.6~~$2.3 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~~2008 are budgeted at ~~$1.2~~$1.3 billion. Technology investments include projects related to ~~molecular transformation,~~ unconventional hydrocarbons technologies, oil and gas reservoir management and ~~development of second-generation biofuel production.~~gas-fired and renewable power generation.

Capital and Exploratory Expenditures


	2006						2005						2004						2007						2006						2005
Millions of dollars	U.S.		Int'l.		Total		U.S.		Int'l.		Total		U.S.		Int'l.		Total		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	$	4,558	$	10,980	$	15,538	$	4,123	$	8,696	$	12,819	$	2,450	$	5,939	$	8,389
Downstream – Refining, Marketing and Transportation		1,176		1,999		3,175		818		1,332		2,150		497		832		1,329		1,576		1,867		3,443		1,176		1,999		3,175		818		1,332		2,150
Chemicals		146		54		200		108		43		151		123		27		150		218		53		271		146		54		200		108		43		151
All Other		403		14		417		329		44		373		512		3		515		768		6		774		403		14		417		329		44		373

Total	$	5,848	$	10,763	$	16,611	$	3,705	$	7,358	$	11,063	$	2,952	$	5,363	$	8,315	$	7,120	$	12,906	$	20,026	$	5,848	$	10,763	$	16,611	$	3,705	$	7,358	$	11,063

Total, Excluding Equity in Affiliates	$	5,642	$	9,050	$	14,692	$	3,522	$	5,860	$	9,382	$	2,729	$	4,024	$	6,753	$	6,900	$	10,790	$	17,690	$	5,642	$	9,050	$	14,692	$	3,522	$	5,860	$	9,382

~~FS-13~~FS-12


~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL~~ ~~CONDITION AND RESULTS OF OPERATIONS~~

Pension Obligations In ~~2006,~~2007, the company’s pension plan contributions ~~totaled approximately $450 million. Approximately $225~~were $317 million of(approximately $78 million to the ~~total was contributed to~~ U.S. ~~plans. In 2007, the~~plans). The company estimates ~~total~~ contributions in 2008 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. Refer also to the discussion of pension accounting in “Critical Accounting Estimates and Assumptions,” beginning on page ~~FS-20.~~FS-18.

~~FINANCIAL RATIOS~~Financial Ratios

Financial Ratios


	At December 31									At December 31
	2006			2005			2004			2007			2006			2005

Current Ratio		1.3			1.4			1.5			1.2			1.3			1.4
Interest Coverage Ratio		53.5			47.5			47.6			69.2			53.5			47.5
Total Debt/Total Debt-Plus-Equity		12.5	%		17.0	%		19.9	%		8.6	%		12.5	%		17.0	%

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,~~2007, the book value of inventory was lower than replacement costs, based on average acquisition costs during the year, by approximately $6$7 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 company’s interest coverage ratio was higher inbetween 2007 and 2006 ~~compared with~~and between 2006 and 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.~~

balances in each of the subsequent years.

Debt Ratio – total debt as a percentage of total debt plus equity. The progressive decrease between 2005 and ~~2006~~2007, was due to lower average debt levels and ~~an increase in~~higher stockholders’ ~~equity. Although total debt was slightly higher at the end~~equity balances.

Guarantees, Off-Balance-Sheet Arrangements and Contractual Obligations, and Other Contingencies

Direct Guarantee


Millions of dollars	Commitment Expiration by Period
	Total		2008		2009- 2011		2012		After 2012

Guarantee of non-consolidated affiliate or joint-venture obligation	$	613	$	–	$	–	$	38	$	575

The company’s guarantee of ~~2005 than a year earlier due to the assumption of debt~~approximately $600 million is associated with certain payments under a terminal use agreement entered into by a company affiliate. The terminal is expected to be operational by 2012. Over the ~~Unocal acquisition,~~approximate 16-year term of the ~~debt ratio declined~~guarantee, the maximum guarantee amount will reduce over time as ~~a result of higher stockholders’ equity~~

~~balances for retained earnings~~certain fees are paid by the affiliate. There are numerous cross-indemnity agreements with the affiliate 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

* Theother partners to permit recovery of any 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 performpaid 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,~~guarantee. 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

~~FS-14~~

~~not recorded a~~carries no 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.~~its obligation under this guarantee.

Indemnifications The company provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell and Saudi Refining, Inc., in connection with the February 2002 sale of the company’s interests in those investments. The company would be required to perform if the indemnified liabilities become actual losses. Were that to occur, the company could be required to make future payments up to $300 million. Through the end of ~~2006,~~2007, the company had 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~~for Equilon indemnities ~~must be asserted either as early as February 2007 or~~and no later than February ~~2012.~~2012 for Motiva indemnities. 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~~indemnification expires. The acquirer shares in certain environmental remediation costs up to a maximum

FS-13

Management’s Discussion and Analysis of
Financial Condition and Results of Operations

obligation of $200 million, which had not been reached as of December 31, ~~2006.~~2007.

Securitization ~~The~~During 2007, the company ~~securitizes certain~~completed the sale of its U.S. proprietary consumer credit card business and related receivables. This transaction included terminating the qualifying Special Purpose Entity (SPE) that was used to securitize associated retail ~~and~~accounts receivable.

Through the use of another qualifying SPE, the company had $675 million of securitized trade accounts receivable inrelated to its downstream business ~~through the use~~as 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 have2007. This arrangement has the effect of accelerating Chevron’s collection of the securitized amounts. Chevron’s total estimated financial exposure under this securitization at December 31, 2007, was $65 million. In the event that the ~~SPEs experience~~SPE experiences major defaults in the collection of receivables, Chevron believes that it would have no additional loss exposure connected with third-party investments in ~~these securitizations.~~

this securitization.

Minority Interests The company has commitments of $204 million related to minority interests in subsidiary companies.

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~~$4.7 billion; 2009 – ~~$2.1~~$3.3 billion; 2010 – ~~$1.9~~$3.3 billion; 2011 – ~~$0.9~~$1.9 billion; 2012 – $1.3 billion; 2013 and after – ~~$4.1~~$4.9 billion. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were approximately $3.7 billion in 2007, $3.0 billion in 2006 and $2.1 billion in ~~2005 and $1.6 billion in 2004.~~2005.

~~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										Payments Due by Period
															2009-				After
					2008–				After		Total		2008		2011		2012		2012
	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
On Balance Sheet:¹
Short-Term Debt²											$	1,162	$	1,162	$	–	$	–	$	–
Long-Term Debt²												5,664		–		4,926		33		705
Noncancelable Capital Lease Obligations		274		–		138		40		96		406		–		193		61		152
Interest		5,269		491		1,173		366		3,239		3,950		360		899		292		2,399
Off-Balance-Sheet:
Noncancelable Operating Lease Obligations		3,058		509		1,374		311		864		3,167		513		1,255		293		1,106
Throughput and Take-or-Pay Agreements		9,796		2,765		3,027		475		3,529		13,118		3,699		4,783		618		4,018
Other Unconditional Purchase Obligations		4,072		383		2,696		427		566
Other Unconditional Purchase Obligations³												6,300		988		3,779		653		880

¹		Does not include amounts related to the company’s income tax liabilities associated with uncertain tax positions. The company is unable to make reasonable estimates for the periods in which these liabilities may become due. The company does not expect settlement of such liabilities will have a material effect on its results of operations, consolidated financial position or liquidity in any single period.

²		$~~4.5~~4.4. 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~~2009-2011 period.

²³		~~Includes guarantees~~Does not include obligations to purchase the company’s share of ~~$213~~natural gas liquids and regasified natural gas associated with operations of ~~ESOP (employee stock ownership plan) debt due after 2007.~~the 36.4 percent-owned Angola LNG affiliate. The ~~2007 amount~~LNG plant is expected to commence operations in 2012 and is designed to produce 5.2 million metric tons of ~~$20, which was scheduled for payment on the first business day of January 2007, was paid in late December 2006.~~liquefied natural gas and related natural gas liquids per year. Volumes and prices associated with these purchase obligations are neither fixed nor determinable.

~~FINANCIAL AND DERIVATIVE INSTRUMENTS~~Financial and Derivative Instruments

No material change in market risk occurred between 2006 and 2007 for the financial and derivative instruments discussed below. 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 1, Item 1A, of the company’s 2007 Annual Report on Form 10-K.

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:~~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.~~2007.

FS-14

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

~~FS-15~~


~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL~~ ~~CONDITION AND RESULTS OF OPERATIONS~~

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~~Effective with 2007 year-end reporting, the company changed the model used to quantify information about market risk for its commodity derivatives from a “sensitivity analysis” approach to Value-at-Risk (VaR). The major reason for the change is that VaR allows estimation of a portfolio’s aggregate market risk exposure and takes into account correlations between trading assets. Therefore, it reflects risk reduction due to diversification or hedging activities. Most of the company’s market positions are time and commodity spreads, and the company believes that VaR is a more accurate tool to measure this type of exposure than the sensitivity analysis model. The company fully developed and tested its VaR model during 2007.

VaR is the maximum loss not to be exceeded within a given probability or confidence level over a given period of time. The company’s VaR model uses the Monte Carlo simulation method that involves generating hypothetical scenarios from the specified probability distribution and constructing a full distribution of a potential portfolio’s values.

The VaR model utilizes an exponentially-weighted moving average for computing historical volatilities and correlations, a 95 percent confidence level, and one-day holding period. That is, the company’s 95 percent, one-day VaR corresponds to the unrealized loss in portfolio value that would not be exceeded on average more than one in every 20 trading days, if the portfolio were held constant for one day.

The one-day holding period is based on the assumption that market-risk positions can be liquidated or hedged within one day. For hedging and risk management, the company uses conventional exchange-traded instruments such as futures and options, as well as non-exchange-traded swaps, most of which can be liquidated or hedged effectively within one day. The table below presents 95 percent/one-day VaR for each of the company’s primary risk exposures in the area of commodity derivative instruments at December 31, 2007:


Millions of dollars	2007

Crude Oil	$	29
Natural Gas		3
Refined Products		23

Sensitivity analysis for the company’s open commodity derivative instruments at December 31, 2007, and December 31, 2006, based on a hypothetical 10 percent increase in commodity prices, is provided in the ~~price~~following table:

Incremental Increase (Decrease) in Fair Value of ~~natural gas, crude oil and refined products would increase the fair value~~Open Commodity
Derivative Contracts Assuming a Hypothetical Increase in
Year-End Commodity Prices 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.10 Percent


Millions of dollars	2007			2006

Crude Oil	$	(113	)	$	4
Natural Gas		14			10
Refined Products		(96	)		(30	)

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.

The change in the amounts between years in the table above for crude oil and refined products is associated with an increase in commodity prices, volumes hedged and the use of longer-term contracts.

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~~2007 would be a reduction in the fair value of the foreign exchange contracts of approximately ~~$40~~$75 million. The effect would be the opposite for a hypothetical 10 percent decrease in the ~~year-end~~ value of the U.S. ~~dollar.~~dollar at year-end 2007.

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~~hedges. 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,~~2007, the company had no interest-rate swaps on floating-rate debt. At year-end 2007, the weighted average maturity of “receive fixed” interest rate swaps was ~~approximately~~less than one year. ~~There were no “receive floating” swaps outstanding at year end.~~ A hypothetical increase or decrease of 10 basis points in fixed interest rates would ~~reduce~~have ade minimisimpact on 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.swaps.

~~TRANSACTIONS WITH RELATED PARTIES~~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

FS-15

Management’s Discussion and Analysis of
Financial Condition and Results of Operations

in Thailand. Refer to page ~~FS-15~~FS-5 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~~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~~The company is a party to ~~approximately 75~~88 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~~seepages of MTBE into groundwater. Chevron has agreed in principle to a tentative settlement of 60 pending lawsuits and claims. The terms of this agreement, which must be approved by a number of parties, including the court, are confidential and not material to the company’s results of operations, liquidity or financial position.

Resolution of ~~these actions~~remaining lawsuits and claims may ultimately require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE, including personal-injury claims, may be filed in the future.

The tentative settlement of the referenced 60 lawsuits did not set any precedents related to standards of liability to be used to judge the merits of the claims, corrective measures required or monetary damages to be assessed for the remaining lawsuits and claims or future lawsuits and claims. As a result, the company’s ultimate exposure related to ~~these~~pending lawsuits and claims is not currently determinable, but could be material to net income in any one period. The company ~~currently does not use~~no longer uses MTBE in the manufacture of gasoline in the United States.

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

~~FS-16~~
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~~were consolidated in U.S. District Court for the Central District of California, where a class action has been certified, and three ~~are~~were consolidated in ~~California State Court.~~a state court action. 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~~The parties have reached a tentative agreement to resolve all of the above matters in an amount that is not material to the company’s results of operations, liquidity or financial position. The terms of this agreement are confidential, and ~~intends~~subject to ~~vigorously defend against these lawsuits. The company’s potential exposure related to these lawsuits cannot currently be estimated.~~further negotiation and approval, including by the courts.

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,

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.

FS-16
     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 2007 2006 2005

Balance at January 1 $ 1,469 $ 1,047 $ 1,149 $ 1,441 $ 1,469 $ 1,047
Net Additions 366 731 155 562 366 731
Expenditures (394 ) (309 ) (257 ) (464 ) (394 ) (309 )

Balance at December 31
$ 1,441 $ 1,469 $ 1,047 $ 1,539 $ 1,441 $ 1,469

     ~~Chevron’s environmental reserve as of December 31, 2006, was $1,441 million.~~     Included in ~~this~~the $1,539 million year-end 2007 reserve balance were remediation activities of ~~242~~240 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~~2007 was ~~$122~~$123 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~~2007 environmental reserves balance of ~~$1,319~~$1,416 million, ~~$834~~$864 million related to approximately ~~2,250~~2,000 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~~$552 million was associated with various sites in ~~the~~ international downstream ($~~117~~146 million), upstream ($~~252~~267 million), chemicals ($61105 million) and other ($5534 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~~2007 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~~The company ~~implemented FASB~~accounts for asset retirement obligations in accordance with Financial Accounting Standards Board Statement (FASB) 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

~~FS-17~~
~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL~~
~~CONDITION AND RESULTS OF OPERATIONS~~

long-lived assets and the liability can be reasonably estimated. The liability balance of approximately ~~$5.8~~$8.3 billion for asset retirement obligations at year-end ~~2006~~2007 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,~~23, beginning on page ~~FS-58,~~FS-57, 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~~ (FIN 47), and the discussion of “Environmental Matters” on page ~~FS-19.~~FS-18.
     Income Taxes  The company calculates its income tax expense and liabilities quarterly. These liabilities generally are subject to audit and are not finalized with the individual taxing authorities until several years after the end of the annual period for which income taxes have been calculated. Refer to Note 15 beginning on page FS-43 for a discussion of the periods for which tax returns have been audited for the company’s major tax jurisdictions and a discussion for all tax jurisdictions of the differences between the amount of tax benefits recognized in the financial statements and the amount taken or expected to be taken in a tax return. The ~~U.S. federal~~company does not expect settlement of income tax liabilities ~~have been settled through 1996 for Chevron Corporation, 1997 for Unocal Corporation (Unocal) and 2001 for Texaco Corporation (Texaco). California franchise~~associated with uncertain 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 topositions will have a material effect on ~~the~~its results of operations, 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.~~liquidity.
     ~~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,~~2007, the company had approximately ~~$1.2~~$1.7 billion of suspended exploratory wells included in properties, plant and equipment, an increase of ~~$130~~$421 million from ~~2005~~2006 and an increase of ~~$568~~$551 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~~$1.7 billion of suspended wells at year-end ~~2006~~2007 is uncertain pending future activities, including normal project evaluation and additional drilling.

Refer to Note ~~20,~~19, beginning on page FS-47, for additional discussion of suspended wells.

FS-17
Management’s Discussion and Analysis of
Financial Condition and Results of Operations

     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

~~FS-18~~
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,~~customers; trading ~~partners,~~partners; U.S. federal, state and local regulatory ~~bodies, governments, contractors, insurers,~~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~~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~~2007 at approximately ~~$2.2~~$2.7 billion for its consolidated companies. Included in these expenditures were approximately ~~$870~~$900 million of environmental capital expenditures and ~~$1.3~~$1.8 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,~~2008, total worldwide environmental capital expenditures are estimated at ~~$1.2~~$1.9 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~~existing 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~~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.

FS-18
     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,~~FS-66, for the changes in these estimates for the three years ending December 31, ~~2006,~~2007, and to Table VII, “Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves” on page ~~FS-76~~FS-74 for estimates of proved-reserve values for each of the three years ending December 31, ~~2004 through 2006,~~2007, 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

~~FS-19~~

~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL~~
~~CONDITION AND RESULTS OF OPERATIONS~~
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,” beginning on page ~~FS-21,~~FS-20, 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,~~20, beginning on page FS-48, includes information on the funded status of the company’s pension and OPEB
plans at the end of ~~2006~~2007 and ~~2005,~~2006, the components of pension and OPEB expense for the three years ending December 31, ~~2006,~~2007, 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~~The year-end 2007 and 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 7067 percent of the company’s pension plan assets, has remained at 7.8 percent since 2002. For the 10 years ending December 31, ~~2006,~~2007, actual asset returns averaged ~~9.7~~8.7 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,~~2007, the company selected a ~~5.8~~6.3 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.~~2007. The discount rates at the end of 2006 and 2005 ~~and 2004~~ were ~~5.5~~5.8 percent and ~~5.8~~5.5 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~~2007 was ~~approximately $585~~$620 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~~2007 by approximately ~~$60~~ $70

FS-19
Management’s Discussion and Analysis of
Financial Condition and Results of Operations

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~~2007 by approximately ~~$160~~$155 million.

~~FS-20~~
     An increase in the discount rate would decrease the 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,~~2007, 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~~$250 million, which would have ~~changed~~increased the plan’s ~~funded~~over-funded status from ~~underfunded~~approximately $160 million to ~~overfunded, resulting in a pension asset of about $250~~$410 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,~~2007, the company’s pension plan contributions were ~~approximately $450~~$317 million ~~(approximately $225~~(including $78 million to the U.S. plans). In ~~2007,~~2008, 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~~2007 was ~~about $230~~$233 million and the total liability, which reflected the underfunded status of the plans at the end of ~~2006,~~2007, was ~~$3.3~~$2.9 billion.
     As an indication of discount rate sensitivity to the determination of OPEB expense in ~~2006,~~2007, 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~~companywide OPEB expense, would have decreased OPEB expense by approximately ~~$25~~$20 million. A 0.25 percent increase in the discount rate for the same plan, which accounted for about 9087 percent of the companywide OPEB liabilities, would have decreased total OPEB liabilities at the end of ~~2006~~2007 by approximately ~~$70~~$60 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~~pre-Medicare-eligible employees retiring on or after January 1, 2005. The cap was effective as of January 1, 2005, for ~~pre–Medicare-eligible~~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 98 percent in ~~2007~~2008 and gradually drop to 5 percent for ~~2011~~2014 and beyond. As an indication of the health care cost-trend rate sensitivity to the determination of
OPEB expense in ~~2006,~~2007, a 1 percent increase in the rates for the main U.S. ~~postretirement medical~~OPEB plan, which accounted for about 9087 percent of the companywide OPEB ~~obligations,~~liabilities, 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,~~20, beginning on page FS-48, for information on the ~~$2.6~~$3.3 billion of before-tax actuarial losses recorded by the company as of December 31, ~~2006;~~2007; a description of the method used to amortize those costs; and an estimate of the costs to be recognized in expense during ~~2007.~~2008.
     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 estimated 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 individual impairments of PP&E were recorded for the three years ending December 31, ~~2006.~~2007. 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

FS-20
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

~~FS-21~~
~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL~~
~~CONDITION AND RESULTS OF OPERATIONS~~

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~~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~~resulting from 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 generally 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. An exception to this handling is for income tax matters, for which benefits are recognized only if management determines the tax position is “more likely than not” (i.e. likelihood greater than 50 percent) to be allowed by the tax jurisdiction. For additional discussion of income tax uncertainties, refer to Note 15 beginning on page FS-43. Refer also 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.~~2007.
     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~~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-

~~FS-22~~
~~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~~became 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~~applies 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~~implementation of FAS 157 ~~in 2008 will depend~~did not have a material effect on the company’s results of operations or consolidated financial position.
FASB Staff Position FAS No. 157-1, Application of FASB Statement No. 157 to FASB Statement No. 13 and Its Related Interpretive Accounting Pronouncements That Address Leasing Transactions (FSP 157-1)  In February 2008, the FASB issued FSP 157-1, which became effective for the company on January 1, 2008. This FSP excludes FASB Statement No. 13, Accounting for Leases, and its related interpretive accounting pronouncements from the provisions of FAS 157. Implementation of this standard did not have a material effect on the company’s results of operations or consolidated financial position.
FASB Staff Position FAS No. 157-2, Effective Date of FASB Statement No. 157 (FSP 157-2)  In February 2008, the FASB issued FSP 157-2, which delays the company’s January 1, 2008, effective date of FAS 157 for all nonfinancial assets and nonfinancial

FS-21
Management’s Discussion and Analysis of
Financial Condition and Results of Operations

liabilities, except those recognized or disclosed at ~~that time that are required~~fair value in the financial statements on a recurring basis (at least annually), until January 1, 2009. Implementation of this standard did not have a material effect on the company’s results of operations or consolidated financial position.
FASB Statement No. 159, The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115 (FAS 159)  In February 2007, the FASB issued FAS 159, which became effective for the company on January 1, 2008. This standard permits companies to choose to measure many financial instruments and certain other items at fair value and report unrealized gains and losses in earnings. Such accounting is optional and is generally to be applied instrument by instrument. The implementation of FAS 159 did not have a material effect on the company’s results of operations or consolidated financial position.
FASB Statement No. 141 (revised 2007), Business Combinations (FAS 141-R)  In December 2007, the FASB issued FAS 141-R, which will become effective for business combination transactions having an acquisition date on or after January 1, 2009. This standard requires the acquiring entity in a business combination to recognize the assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at the acquisition date to be measured at their respective fair ~~value.~~values. The Statement requires acquisition-related costs, as well as restructuring costs the acquirer expects to incur for
which it is not obligated at acquisition date, to be recorded against income rather than included in purchase-price determination. It also requires recognition of contingent arrangements at their acquisition-date fair values, with subsequent changes in fair value generally reflected in income.
     FASB Statement No. ~~158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans –~~160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ~~FASB Statements~~ARB No. ~~87, 88, 106 and 132(R)~~51 (FAS ~~158)~~160)~~In September 2006, the~~  The FASB issued FAS ~~158,~~160 in December 2007, which ~~was adopted by~~will become effective for the company January 1, 2009, with retroactive adoption of the Statement’s presentation and disclosure requirements for existing minority interests. This standard will require ownership interests in subsidiaries held by parties other than the parent to be presented within the equity section of the consolidated statement of financial position but separate from the parent’s equity. It will also require the amount of consolidated net income attributable to the parent and the noncontrolling interest to be clearly identified and presented on ~~December 31, 2006. Refer~~the face of the consolidated income statement. Certain changes in a parent’s ownership interest are to ~~Note 21, beginning on page FS-48,~~be accounted for ~~additional information.~~
as equity transactions and when a subsidiary is deconsolidated, any noncontrolling equity investment in the former subsidiary is to be initially measured at fair value. The company does not anticipate the implementation of FAS 160 will significantly change the presentation of its consolidated income statement or consolidated balance sheet.

FS-22
THIS PAGE INTENTIONALLY LEFT BLANK
FS-23
~~QUARTERLY RESULTS AND STOCK MARKET DATA~~
Quarterly Results and Stock Market Data
Unaudited

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

2007 2006
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
$ 59,900 $ 53,545 $ 54,344 $ 46,302 $ 46,238 $ 52,977 $ 52,153 $ 53,524
Income from equity affiliates 1,153 1,160 894 937 1,079 1,080 1,113 983
Other income 357 468 856 988 429 155 270 117

Total Revenues and Other Income
61,410 55,173 56,094 48,227 47,746 54,212 53,536 54,624

Costs and Other Deductions

Purchased crude oil and products²
38,056 33,988 33,138 28,127 27,658 32,076 32,747 35,670
Operating expenses 4,798 4,397 4,124 3,613 4,092 3,650 3,835 3,047
Selling, general and administrative expenses 1,833 1,446 1,516 1,131 1,203 1,428 1,207 1,255
Exploration expenses 449 295 273 306 547 284 265 268
Depreciation, depletion and amortization 2,094 2,495 2,156 1,963 1,988 1,923 1,807 1,788
Taxes other than on income¹
5,560 5,538 5,743 5,425 5,533 5,403 5,153 4,794
Interest and debt expense 7 22 63 74 92 104 121 134
Minority interests 35 25 19 28 2 20 22 26

Total Costs and Other Deductions
52,832 48,206 47,032 40,667 41,115 44,888 45,157 46,982

Income Before Income Tax Expense
8,578 6,967 9,062 7,560 6,631 9,324 8,379 7,642
Income Tax Expense
3,703 3,249 3,682 2,845 2,859 4,307 4,026 3,646

Net Income
$ 4,875 $ 3,718 $ 5,380 $ 4,715 $ 3,772 $ 5,017 $ 4,353 $ 3,996

Per-Share of Common Stock

Net Income

– Basic
$ 2.34 $ 1.77 $ 2.52 $ 2.20 $ 1.75 $ 2.30 $ 1.98 $ 1.81
– Diluted
$ 2.32 $ 1.75 $ 2.52 $ 2.18 $ 1.74 $ 2.29 $ 1.97 $ 1.80

Dividends
$ 0.58 $ 0.58 $ 0.58 $ 0.52 $ 0.52 $ 0.52 $ 0.52 $ 0.45
Common Stock Price Range – High³
$ 94.86 $ 94.84 $ 84.24 $ 74.95 $ 75.97 $ 67.85 $ 62.88 $ 62.21
– Low³
$ 83.79 $ 80.76 $ 74.83 $ 66.43 $ 62.94 $ 60.88 $ 56.78 $ 54.08

¹ Includes excise, value-added and similar taxes:
$2,548 $2,550 $2,609 $2,414 $2,498 $2,522 $2,416 $2,115
² Includes amounts for buy/sell contracts:
$       – $       – $       – $       – $       – $       – $       – $6,725
³ End of day price.

The company’s common stock is listed on the New York Stock Exchange (trading symbol: CVX). As of February ~~23, 2007,~~
22, 2008, stockholders of record numbered approximately ~~223,000.~~214,000. There are no restrictions on the company’s ability to pay dividends.
FS-24
~~MANAGEMENT’S RESPONSIBILITY FOR FINANCIAL STATEMENTS~~
Management’s Responsibility for Financial Statements
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~~
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~~the company’s internal control over financial reporting based on theInternal Control – Integrated Frameworkissued 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.~~2007.
     The ~~company management’s assessment~~effectiveness of the ~~effectiveness of its~~company’s internal control over financial reporting as of December 31, ~~2006,~~2007, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included herein.

~~DAVID~~David J. ~~O’REILLY~~O’Reilly ~~STEPHEN~~Stephen J. ~~CROWE~~Crowe ~~MARK~~Mark A. ~~HUMPHREY~~Humphrey
Chairman of the Board Vice President Vice President
and Chief Executive Officer and Chief Financial Officer and Comptroller
February 28, ~~2007~~2008
FS-25
~~REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM~~Report of Independent Registered Public Accounting Firm
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 accompanying consolidated ~~financial~~balance sheets and the related consolidated statements ~~listed in the index appearing under Item 15(a)(1)~~ of ~~the Annual Report on Form 10-K~~income, comprehensive income, shareholders’ equity and cash flows present fairly, in all material respects, the financial position of Chevron Corporation and its subsidiaries at December 31, ~~2006~~2007, and ~~2005,~~December 31, 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, ~~2006,~~2007, 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~~Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial ~~statements and financial statement schedule are~~reporting as of December 31, 2007, based on criteria established inInternal Control – Integrated Frameworkissued by the ~~responsibility~~Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s ~~management. Our responsibility~~management is ~~to express an opinion on~~responsible for these financial statements and financial statement schedule; for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Controls Over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated 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~~audits to obtain reasonable assurance about whether the financial statements are free of material ~~misstatement. An audit~~misstatements and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements ~~includes~~included 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control, based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in
the circumstances. We believe that our audits provide a reasonable basis for our ~~opinion.~~
opinions.
     As discussed in Note 1413 to the Consolidated Financial Statements, the Company changed its method of accounting for buy/sell contracts on April 1, 2006.
     As discussed in Note 2115 to the Consolidated Financial Statements, the Company changed its method of accounting for uncertain income tax positions on January 1, 2007.
     As discussed in Note 20 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 Frameworkissued 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~~2008

FS-26
~~CONSOLIDATED STATEMENT OF INCOME~~
Consolidated Statement of Income
Millions of dollars, except per-share amounts

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.

Year ended December 31
2007 2006 2005

Revenues and Other Income

Sales and other operating revenues^1,2
$ 214,091 $ 204,892 $ 193,641
Income from equity affiliates 4,144 4,255 3,731
Other income 2,669 971 828

Total Revenues and Other Income
220,904 210,118 198,200

Costs and Other Deductions

Purchased crude oil and products²
133,309 128,151 127,968
Operating expenses 16,932 14,624 12,191
Selling, general and administrative expenses 5,926 5,093 4,828
Exploration expenses 1,323 1,364 743
Depreciation, depletion and amortization 8,708 7,506 5,913
Taxes other than on income¹
22,266 20,883 20,782
Interest and debt expense 166 451 482
Minority interests 107 70 96

Total Costs and Other Deductions
188,737 178,142 173,003

Income Before Income Tax Expense
32,167 31,976 25,197
Income Tax Expense
13,479 14,838 11,098

Net Income
$ 18,688 $ 17,138 $ 14,099

Per-Share of Common Stock

Net Income

– Basic
$ 8.83 $ 7.84 $ 6.58
– Diluted
$ 8.77 $ 7.80 $ 6.54

¹ Includes excise, value-added and similar taxes.
$ 10,121 $ 9,551 $ 8,719
² Includes amounts in revenues for buy/sell contracts; associated costs are in “Purchased crude oil and products.”

Refer also to Note 13, on page FS-42. $ – $ 6,725 $ 23,822
See accompanying Notes to the Consolidated Financial Statements.
FS-27
~~CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME~~
Consolidated Statement of Comprehensive Income
Millions of dollars

Year ended December 31
2006 2005 2004

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

Currency translation adjustment
Unrealized net change arising during period 55 (5 ) 36

Unrealized holding (loss) gain on securities
Net (loss) gain arising during period (88 ) (32 ) 35
Reclassification to net income of net realized (gain) – – (44 )

Total (88 ) (32 ) (9 )

Net derivatives gain (loss) on hedge transactions
Net gain (loss) arising during period
Before income taxes 2 (242 ) (8 )
Income taxes 6 89 (1 )
Reclassification to net income of net realized gain (loss)
Before income taxes 95 34 –
Income taxes (36 ) (12 ) –

Total 67 (131 ) (9 )

Minimum pension liability adjustment
Before income taxes (88 ) 89 719
Income taxes 50 (31 ) (247 )

Total (38 ) 58 472

OTHER COMPREHENSIVE (LOSS) GAIN, NET OF TAX
(4 ) (110 ) 490

COMPREHENSIVE INCOME
$ 17,134 $ 13,989 $ 13,818

Year ended December 31
2007 2006 2005

Net Income
$ 18,688 $ 17,138 $ 14,099

Currency translation adjustment
Unrealized net change arising during period 31 55 (5 )

Unrealized holding gain (loss) on securities
Net gain (loss) arising during period 17 (88 ) (32 )
Reclassification to net income of net realized loss 2 – –

Total 19 (88 ) (32 )

Derivatives
Net derivatives (loss) gain on hedge transactions (10 ) 2 (242 )
Reclassification to net income of net realized loss 7 95 34
Income taxes on derivatives transactions (3 ) (30 ) 77

Total (6 ) 67 (131 )

Defined benefit plans
Minimum pension liability adjustment – (88 ) 89
Actuarial loss
Amortization to net income of net actuarial loss 356 – –
Actuarial gain arising during period 530 – –
Prior service cost
Amortization to net income of net prior service credits (15 ) – –
Prior service cost arising during period 204 – –
Non-sponsored defined benefit plans 19 – –
Income taxes on defined benefit plans (409 ) 50 (31 )

Total 685 (38 ) 58

Other Comprehensive Gain (Loss), Net of Tax
729 (4 ) (110 )

Comprehensive Income
$ 19,417 $ 17,134 $ 13,989

See accompanying Notes to the Consolidated Financial Statements.
FS-28
~~CONSOLIDATED BALANCE SHEET~~
Consolidated Balance Sheet
Millions of dollars, except per-share amounts

At December 31 At December 31
2006 2005 2007 2006

ASSETS

Assets

Cash and cash equivalents $ 10,493 $ 10,043 $ 7,362 $ 10,493
Marketable securities 953 1,101 732 953
Accounts and notes receivable (less allowance: 2006 – $175; 2005 – $156) 17,628 17,184
Accounts and notes receivable (less allowance: 2007 – $165; 2006 – $175) 22,446 17,628
Inventories:
Crude oil and petroleum products 3,586 3,182 4,003 3,586
Chemicals 258 245 290 258
Materials, supplies and other 812 694 1,017 812

Total inventories 4,656 4,121 5,310 4,656
Prepaid expenses and other current assets 2,574 1,887 3,527 2,574

TOTAL CURRENT ASSETS
36,304 34,336
Total Current Assets
39,377 36,304
Long-term receivables, net 2,203 1,686 2,194 2,203
Investments and advances 18,552 17,057 20,477 18,552
Properties, plant and equipment, at cost 137,747 127,446 154,084 137,747
Less: Accumulated depreciation, depletion and amortization 68,889 63,756 75,474 68,889

Properties, plant and equipment, net 68,858 63,690 78,610 68,858
Deferred charges and other assets 2,088 4,428 3,491 2,088
Goodwill 4,623 4,636 4,637 4,623

TOTAL ASSETS
$ 132,628 $ 125,833
Total Assets
$ 148,786 $ 132,628

LIABILITIES AND STOCKHOLDERS’ EQUITY

Liabilities and Stockholders’ Equity

Short-term debt $ 2,159 $ 739 $ 1,162 $ 2,159
Accounts payable 16,675 16,074 21,756 16,675
Accrued liabilities 4,546 3,690 5,275 4,546
Federal and other taxes on income 3,626 3,127 3,972 3,626
Other taxes payable 1,403 1,381 1,633 1,403

TOTAL CURRENT LIABILITIES
28,409 25,011
Total Current Liabilities
33,798 28,409
Long-term debt 7,405 11,807 5,664 7,405
Capital lease obligations 274 324 406 274
Deferred credits and other noncurrent obligations 11,000 10,507 15,007 11,000
Noncurrent deferred income taxes 11,647 11,262 12,170 11,647
Reserves for employee benefit plans 4,749 4,046 4,449 4,749
Minority interests 209 200 204 209

TOTAL LIABILITIES
63,693 63,157
Total Liabilities
71,698 63,693

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
Common stock (authorized 4,000,000,000 shares, $0.75 par value; 2,442,676,580 shares issued at December 31, 2007 and 2006) 1,832 1,832
Capital in excess of par value 14,126 13,894 14,289 14,126
Retained earnings 68,464 55,738 82,329 68,464
Notes receivable – key employees (2 ) (3 ) (1 ) (2 )
Accumulated other comprehensive loss (2,636 ) (429 ) (2,015 ) (2,636 )
Deferred compensation and benefit plan trust (454 ) (486 ) (454 ) (454 )
Treasury stock, at cost (2006 – 278,118,341 shares; 2005 – 209,989,910 shares) (12,395 ) (7,870 )
Treasury stock, at cost (2007 – 352,242,618 shares; 2006 – 278,118,341 shares) (18,892 ) (12,395 )

TOTAL STOCKHOLDERS’ EQUITY
68,935 62,676
Total Stockholders’ Equity
77,088 68,935

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$ 132,628 $ 125,833
Total Liabilities and Stockholders’ Equity
$ 148,786 $ 132,628

See accompanying Notes to the Consolidated Financial Statements.
FS-29
~~CONSOLIDATED STATEMENT OF CASH FLOWS~~
Consolidated Statement of Cash Flows
Millions of dollars

Year ended December 31 Year ended December 31
2006 2005 2004 2007 2006 2005

OPERATING ACTIVITIES

Operating Activities

Net income $ 17,138 $ 14,099 $ 13,328 $ 18,688 $ 17,138 $ 14,099
Adjustments
Depreciation, depletion and amortization 7,506 5,913 4,935
Adjustments
Depreciation, depletion and amortization 8,708 7,506 5,913
Dry hole expense 520 226 286 507 520 226
Distributions less than income from equity affiliates (979 ) (1,304 ) (1,422 ) (1,439 ) (979 ) (1,304 )
Net before-tax gains on asset retirements and sales (229 ) (134 ) (1,882 ) (2,315 ) (229 ) (134 )
Net foreign currency effects 259 62 60 378 259 62
Deferred income tax provision 614 1,393 (224 ) 261 614 1,393
Net decrease (increase) in operating working capital 1,044 (54 ) 430 685 1,044 (54 )
Minority interest in net income 70 96 85 107 70 96
Increase in long-term receivables (900 ) (191 ) (60 )
Decrease (increase) in other deferred charges 232 668 (69 )
(Increase) in long-term receivables (82 ) (900 ) (191 )
(Increase) decrease in other deferred charges (530 ) 232 668
Cash contributions to employee pension plans (449 ) (1,022 ) (1,643 ) (317 ) (449 ) (1,022 )
Other (503 ) 353 866 326 (503 ) 353

NET CASH PROVIDED BY OPERATING ACTIVITIES
24,323 20,105 14,690
Net Cash Provided by Operating Activities
24,977 24,323 20,105

INVESTING ACTIVITIES

Investing Activities

Cash portion of Unocal acquisition, net of Unocal cash received – (5,934 ) – – – (5,934 )
Capital expenditures (13,813 ) (8,701 ) (6,310 ) (16,678 ) (13,813 ) (8,701 )
Repayment of loans by equity affiliates 463 57 1,790 21 463 57
Proceeds from asset sales 989 2,681 3,671 3,338 989 2,681
Net sales (purchases) of marketable securities 142 336 (450 )
Advances to equity affiliate – – (2,200 )
Net sales of marketable securities 185 142 336
Net purchases of other short-term investments (799 ) – –

NET CASH USED FOR INVESTING ACTIVITIES
(12,219 ) (11,561 ) (3,499 )
Net Cash Used for Investing Activities
(13,933 ) (12,219 ) (11,561 )

FINANCING ACTIVITIES

Net (payments) borrowings of short-term obligations (677 ) (109 ) 114
Financing Activities

Net payments of short-term obligations (345 ) (677 ) (109 )
Repayments of long-term debt and other financing obligations (2,224 ) (966 ) (1,398 ) (3,343 ) (2,224 ) (966 )
Proceeds from issuances of long-term debt 650 – 20
Cash dividends – common stock (4,396 ) (3,778 ) (3,236 ) (4,791 ) (4,396 ) (3,778 )
Dividends paid to minority interests (60 ) (98 ) (41 ) (77 ) (60 ) (98 )
Net purchases of treasury shares (4,491 ) (2,597 ) (1,645 ) (6,389 ) (4,491 ) (2,597 )
Redemption of preferred stock of subsidiaries – (140 ) (18 ) – – (140 )
Proceeds from issuances of long-term debt – 20 –

NET CASH USED FOR FINANCING ACTIVITIES
(11,848 ) (7,668 ) (6,224 )
Net Cash Used for Financing Activities
(14,295 ) (11,848 ) (7,668 )

EFFECT OF EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS
194 (124 ) 58
Effect of Exchange Rate Changes
On Cash and Cash Equivalents
120 194 (124 )

NET CHANGE IN CASH AND CASH EQUIVALENTS
450 752 5,025
CASH AND CASH EQUIVALENTS AT JANUARY 1
10,043 9,291 4,266
Net Change in Cash and Cash Equivalents
(3,131 ) 450 752
Cash and Cash Equivalents at January 1
10,493 10,043 9,291

CASH AND CASH EQUIVALENTS AT DECEMBER 31
$ 10,493 $ 10,043 $ 9,291
Cash and Cash Equivalents at December 31
$ 7,362 $ 10,493 $ 10,043

See accompanying Notes to the Consolidated Financial Statements.
FS-30
~~CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY~~
Consolidated Statement of Stockholders’ Equity
Shares in thousands; amounts in millions of dollars

2006 2005 2004 2007 2006 2005
Shares Amount Shares Amount Shares Amount Shares Amount Shares Amount Shares Amount

PREFERRED STOCK
– $ – – $ – – $ –
Preferred Stock
– $ – – $ – – $ –

COMMON STOCK

Common Stock

Balance at January 1 2,442,677 $ 1,832 2,274,032 $ 1,706 2,274,042 $ 1,706 2,442,677 $ 1,832 2,442,677 $ 1,832 2,274,032 $ 1,706
Shares issued for Unocal acquisition – – 168,645 126 – – – – – 168,645 126
Conversion of Texaco Inc. acquisition – – – – (10 ) –

BALANCE AT DECEMBER 31
2,442,677 $ 1,832 2,442,677 $ 1,832 2,274,032 $ 1,706
Balance at December 31
2,442,677 $ 1,832 2,442,677 $ 1,832 2,442,677 $ 1,832

CAPITAL IN EXCESS OF PAR

Capital in Excess of Par

Balance at January 1 $ 13,894 $ 4,160 $ 4,002 $ 14,126 $ 13,894 $ 4,160
Shares issued for Unocal acquisition – 9,585 – – – 9,585
Treasury stock transactions 232 149 158 163 232 149

BALANCE AT DECEMBER 31
$ 14,126 $ 13,894 $ 4,160
Balance at December 31
$ 14,289 $ 14,126 $ 13,894

RETAINED EARNINGS

Retained Earnings

Balance at January 1 $ 55,738 $ 45,414 $ 35,315 $ 68,464 $ 55,738 $ 45,414
Net income 17,138 14,099 13,328 18,688 17,138 14,099
Cash dividends on common stock (4,396 ) (3,778 ) (3,236 ) (4,791 ) (4,396 ) (3,778 )
Adoption of EITF 04-6, “Accounting for Stripping Costs Incurred during Production in the Mining Industry” (19 ) – –
Adoption of EITF 04–6, “Accounting for Stripping Costs Incurred during Production in the Mining Industry” – (19 ) –
Adoption of FIN 48, “Accounting for Uncertainty in Income Taxes” (35 ) – –
Tax benefit from dividends paid on unallocated ESOP shares and other 3 3 7 3 3 3

BALANCE AT DECEMBER 31
$ 68,464 $ 55,738 $ 45,414
Balance at December 31
$ 82,329 $ 68,464 $ 55,738

NOTES RECEIVABLE – KEY EMPLOYEES
$ (2 ) $ (3 ) $ –
Notes Receivable – Key Employees
$ (1 ) $ (2 ) $ (3 )

ACCUMULATED OTHER COMPREHENSIVE LOSS

Accumulated Other Comprehensive Loss

Currency translation adjustment
Balance at January 1 $ (145 ) $ (140 ) $ (176 ) $ (90 ) $ (145 ) $ (140 )
Change during year 55 (5 ) 36 31 55 (5 )

Balance at December 31 $ (90 ) $ (145 ) $ (140 ) $ (59 ) $ (90 ) $ (145 )
Pension and other postretirement benefit plans
Balance at January 1 $ (344 ) $ (402 ) $ (874 ) $ (2,585 ) $ (344 ) $ (402 )
Change to minimum pension liability during year (38 ) 58 472
Adoption of FAS 158, “Employers’ Accounting for Defined Pension and Other Postretirement Plans” (2,203 ) – –
Change to defined benefit plans during year 685 (38 ) 58
Adoption of FAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (108 ) (2,203 ) –

Balance at December 31 $ (2,585 ) $ (344 ) $ (402 ) $ (2,008 ) $ (2,585 ) $ (344 )
Unrealized net holding gain on securities
Balance at January 1 $ 88 $ 120 $ 129 $ – $ 88 $ 120
Change during year (88 ) (32 ) (9 ) 19 (88 ) (32 )

Balance at December 31 $ – $ 88 $ 120 $ 19 $ – $ 88
Net derivatives gain (loss) on hedge transactions
Balance at January 1 $ (28 ) $ 103 $ 112 $ 39 $ (28 ) $ 103
Change during year 67 (131 ) (9 ) (6 ) 67 (131 )

Balance at December 31 $ 39 $ (28 ) $ 103 $ 33 $ 39 $ (28 )

BALANCE AT DECEMBER 31
$ (2,636 ) $ (429 ) $ (319 )
Balance at December 31
$ (2,015 ) $ (2,636 ) $ (429 )

DEFERRED COMPENSATION AND BENEFIT PLAN TRUST

DEFERRED COMPENSATION

Deferred Compensation and Benefit Plan Trust Deferred Compensation

Balance at January 1 $ (246 ) $ (367 ) $ (362 ) $ (214 ) $ (246 ) $ (367 )
Net reduction of ESOP debt and other 32 121 (5 ) – 32 121

BALANCE AT DECEMBER 31
(214 ) (246 ) (367 )
BENEFIT PLAN TRUST (COMMON STOCK)
14,168 (240 ) 14,168 (240 ) 14,168 (240 )
Balance at December 31
(214 ) (214 ) (246 )
Benefit Plan Trust (Common Stock)
14,168 (240 ) 14,168 (240 ) 14,168 (240 )

BALANCE AT DECEMBER 31
14,168 $ (454 ) 14,168 $ (486 ) 14,168 $ (607 )
Balance at December 31
14,168 $ (454 ) 14,168 $ (454 ) 14,168 $ (486 )

TREASURY STOCK AT COST

Treasury Stock at Cost

Balance at January 1 209,990 $ (7,870 ) 166,912 $ (5,124 ) 135,747 $ (3,317 ) 278,118 $ (12,395 ) 209,990 $ (7,870 ) 166,912 $ (5,124 )
Purchases 80,369 (5,033 ) 52,013 (3,029 ) 42,607 (2,122 ) 85,429 (7,036 ) 80,369 (5,033 ) 52,013 (3,029 )
Issuances – mainly employee benefit plans (12,241 ) 508 (8,935 ) 283 (11,442 ) 315 (11,304 ) 539 (12,241 ) 508 (8,935 ) 283

BALANCE AT DECEMBER 31
278,118 $ (12,395 ) 209,990 $ (7,870 ) 166,912 $ (5,124 )
Balance at December 31
352,243 $ (18,892 ) 278,118 $ (12,395 ) 209,990 $ (7,870 )

TOTAL STOCKHOLDERS’ EQUITY AT DECEMBER 31
$ 68,935 $ 62,676 $ 45,230
Total Stockholders’ Equity at December 31
$ 77,088 $ 68,935 $ 62,676

See accompanying Notes to the Consolidated Financial Statements.
FS-31

~~NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS~~Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts

~~NOTE 1.~~Note 1
~~SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES~~Summary of Significant Accounting Policies
General  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.
     The company’s Consolidated Financial Statements are prepared in accordance with accounting principles generally accepted in the United States of America. These require the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. Although the company uses its best estimates and judgments, actual results could differ from these estimates as future confirming events occur.
     The nature of the company’s operations and the many countries in which it operates subject the company to changing economic, regulatory and political conditions. The company does not believe it is vulnerable to the risk of near-term severe impact as a result of any concentration of its activities.
Subsidiary and Affiliated Companies   The Consolidated Financial Statements include the accounts of controlled subsidiary companies more than 50 percent-owned and variable-interest entities in which the company is the primary beneficiary. Undivided interests in oil and gas joint ventures and certain other assets are consolidated on a proportionate basis. Investments in and advances to affiliates in which the company has a substantial ownership interest of approximately 20 percent to 50 percent or for which the company exercises significant influence but not control over policy decisions are accounted for by the equity method. As part of that accounting, the company recognizes gains and losses that arise from the issuance of stock by an affiliate that results in changes in the company’s proportionate share of the dollar amount of the affiliate’s equity currently in income. ~~Deferred income taxes are provided for these gains and losses.~~
     Investments are assessed for possible impairment when events indicate that the fair value of the investment may be below the company’s carrying value. When such a condition is deemed to be other than temporary, the carrying value of the investment is written down to its fair value, and the amount of the write-down is included in net income. In making the determination as to whether a decline is other than temporary, the company considers such factors as the
duration and extent of the decline, the investee’s financial
performance, and the company’s ability and intention to retain its investment for a period that will be sufficient to allow for any anticipated recovery in the investment’s market value. The new cost basis of investments in these equity investees is not changed for subsequent recoveries in fair value. Subsequent recoveries in the carrying value of other investments are reported in “Other comprehensive income.”
     Differences between the company’s carrying value of an equity investment and its underlying equity in the net assets of the affiliate are assigned to the extent practicable to specific assets and liabilities based on the company’s analysis of the various factors giving rise to the difference. The company’s share of the affiliate’s reported earnings is adjusted quarterly when appropriate to reflect the difference between these allocated values and the affiliate’s historical book values.
Derivatives  The majority of the company’s activity in commodity derivative instruments is intended to manage the financial risk posed by physical transactions. For some of this derivative activity, generally limited to large, discrete or infrequently occurring transactions, the company may elect to apply fair value or cash flow hedge accounting. For other similar derivative instruments, generally because of the short-term nature of the contracts or their limited use, the company does not apply hedge accounting, and changes in the fair value of those contracts are reflected in current income. For the company’s commodity trading activity, gains and losses from the derivative instruments are reported in current income. For derivative instruments relating to foreign currency exposures, gains and losses are reported in current income. Interest rate swaps – hedging a portion of the company’s fixed-rate debt – are accounted for as fair value hedges, whereas interest rate swaps relating to a portion of the company’s floating-rate debt are recorded at fair value on the Consolidated Balance Sheet, with resulting gains and losses reflected in income.
Where Chevron is a party to master netting arrangements, fair value receivable and payable amounts recognized for derivative instruments executed with the same counterparty are offset on the balance sheet.
Short-Term Investments  All short-term investments are classified as available for sale and are in highly liquid debt securities. Those investments that are part of the company’s cash management portfolio and have original maturities of three months or less are reported as “Cash equivalents.” The balance of the short-term investments is reported as “Marketable securities” and are marked-to-market, with any unrealized gains or losses included in “Other comprehensive income.”
Inventories  Crude oil, petroleum products and chemicals are generally stated at cost, using a Last-In, First-Out (LIFO) method. In the aggregate, these costs are below market. “Materials, supplies and other” inventories generally are stated at average cost.

FS-32

~~NOTE 1.~~Note 1 ~~SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES~~Summary of Significant Accounting Policies – Continued

Properties, Plant and Equipment  The successful efforts method is used for crude oil and natural gas exploration and production activities. All costs for development wells, related plant and equipment, proved mineral interests in crude oil and natural gas properties, and related asset retirement obligation (ARO) assets are capitalized. Costs of exploratory wells are capitalized pending determination of whether the wells found proved reserves. Costs of wells that are assigned proved reserves remain capitalized. Costs are also capitalized for exploratory wells that have found crude oil and natural gas reserves even if the reserves cannot be classified as proved when the drilling is completed, provided the exploratory well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. All other exploratory wells and costs are expensed. Refer to Note ~~20,~~19, beginning on page FS-47, for additional discussion of accounting for suspended exploratory well costs.
     Long-lived assets to be held and used, including proved crude oil and natural gas properties, are assessed for possible impairment by comparing their carrying values with their associated undiscounted future net before-tax cash flows. Events that can trigger assessments for possible impairments include write-downs of proved reserves based on field performance, significant decreases in the market value of an asset, significant change in the extent or manner of use of or a physical change in an asset, and a more-likely-than-not expectation that a long-lived asset or asset group will be sold or otherwise disposed of significantly sooner than the end of its previously estimated useful life. Impaired assets are written down to their estimated fair values, generally their discounted future net before-tax cash flows. For proved crude oil and natural gas properties in the United States, the company generally performs the impairment review on an individual field basis. Outside the United States, reviews are performed on a country, concession, development area or field basis, as appropriate. In the refining, marketing, transportation and chemical areas, impairment reviews are generally done on the basis of a refinery, a plant, a marketing area or marketing assets by country. Impairment amounts are recorded as incremental “Depreciation, depletion and amortization” expense.
     Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the asset is considered impaired and adjusted to the lower value.
     As required under Financial Accounting Standards Board (FASB) Statement No. 143,Accounting for Asset Retirement Obligations(FAS 143), the fair value of a liability for an ARO is recorded as an asset and a liability when there is a legal
obligation associated with the retirement of a long-lived
asset and the amount can be reasonably estimated. Refer also to Note ~~24,~~23, beginning on page ~~FS-58,~~FS-57, relating to AROs.
     Depreciation and depletion of all capitalized costs of proved crude oil and natural gas producing properties, except mineral interests, are expensed using the unit-of-production method by individual field as the proved developed reserves are produced. Depletion expenses for capitalized costs of proved mineral interests are recognized using the unit-of-production method by individual field as the related proved reserves are produced. Periodic valuation provisions for impairment of capitalized costs of unproved mineral interests are expensed.
     Depreciation and depletion expenses for mining assets are determined using the unit-of-production method as the proven reserves are produced. The capitalized costs of all other plant and equipment are depreciated or amortized over their estimated useful lives. In general, the declining-balance method is used to depreciate plant and equipment in the United States; the straight-line method generally is used to depreciate international plant and equipment and to amortize all capitalized leased assets.
     Gains or losses are not recognized for normal retirements of properties, plant and equipment subject to composite group amortization or depreciation. Gains or losses from abnormal retirements are recorded as expenses and from sales as “Other income.”
     Expenditures for maintenance (including those for planned major maintenance projects), repairs and minor renewals to maintain facilities in operating condition are generally expensed as incurred. Major replacements and renewals are capitalized.
Goodwill  Goodwill ~~acquired in~~resulting from 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.~~
Environmental Expenditures  Environmental expenditures that relate to ongoing operations or to conditions caused by past operations are expensed. Expenditures that create future benefits or contribute to future revenue generation are capitalized.
     Liabilities related to future remediation costs are recorded when environmental assessments or cleanups or both are probable and the costs can be reasonably estimated. For the company’s U.S. and Canadian marketing facilities, the accrual is based in part on the probability that a future remediation commitment will be required. For crude oil, natural gas and mineral producing properties, ~~a liability for an asset retire-~~

FS-33

Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts

~~NOTE 1.~~Note 1 ~~SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES~~Summary of Significant Accounting Policies – Continued

~~ment~~
a liability for an asset retirement obligation is made, following FAS 143. Refer to Note ~~24,~~23, beginning on page ~~FS-58,~~FS-57, for a discussion of FAS 143.
     For federal Superfund sites and analogous sites under state laws, the company records a liability for its designated share of the probable and estimable costs and probable amounts for other potentially responsible parties when mandated by the regulatory agencies because the other parties are not able to pay their respective shares.
     The gross amount of environmental liabilities is based on the company’s best estimate of future costs using currently available technology and applying current regulations and the company’s own internal environmental policies. Future amounts are not discounted. Recoveries or reimbursements are recorded as assets when receipt is reasonably assured.
Currency Translation  The U.S. dollar is the functional currency for substantially all of the company’s consolidated operations and those of its equity affiliates. For those operations, all gains and losses from currency translations are currently included in income. The cumulative translation effects for those few entities, both consolidated and affiliated, using functional currencies other than the U.S. dollar are included in the currency translation adjustment in “Stockholders’ Equity.”
Revenue Recognition  Revenues associated with sales of crude oil, natural gas, coal, petroleum and chemicals products, and all other sources are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable. Revenues from natural gas production from properties in which Chevron has an interest with other producers are generally recognized on the basis of the company’s net working interest (entitlement method). Excise, value-added and ~~other~~ similar taxes assessed by a governmental authority on a revenue-producing transaction between a seller and a customer are presented on a gross basis. The associated amounts are shown as a footnote to the Consolidated Statement of Income on page FS-27. Refer to Note ~~14,~~13, on page ~~FS-43,~~FS-42, for a discussion of the accounting for buy/sell arrangements.
Stock Options and Other Share-Based Compensation  Effective July 1, 2005, the company adopted the provisions of FASB Statement No. 123R,Share-Based Payment(FAS 123R), for its share-based compensation plans. The company previously accounted for these plans under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25,Accounting for Stock Issued to Employees(APB 25), and related interpretations and disclosure requirements established by FASB Statement No. 123,Accounting for Stock-Based Compensation(FAS 123).
     Refer to Note ~~22,~~21, beginning on page FS-53, for a description of the company’s share-based compensation plans,
information related to awards granted under those plans and additional information on the company’s adoption of FAS 123R.
     The following table illustrates the effect on net income and earnings per share as if the company had applied the fair-value recognition provisions of FAS ~~123~~123R to stock options, stock appreciation rights, performance units and restricted stock units for ~~periods prior to adoption of FAS 123R and~~ the ~~actual effect on 2005 net income and earnings per share for periods after adoption of FAS 123R.~~full year 2005.

Year ended December 31 Year ended December 31
2005 2004 2005

Net income, as reported
$ 14,099 $ 13,328 $ 14,099
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects 81 42 81
Deduct: Total stock-based employee compensation expense determined Under fair-valued-based method for awards, net of related tax effects¹
(108 ) (84 )
Deduct: Total stock-based employee compensation expense determined under fair-valued-based method for awards, net of related tax effects* (108 )

Pro forma net income
$ 14,072 $ 13,286 $ 14,072

Net income per share:²

Net income per share:

Basic – as reported $ 6.58 $ 6.30 $ 6.58
Basic – pro forma $ 6.56 $ 6.28 $ 6.56
Diluted – as reported $ 6.54 $ 6.28 $ 6.54
Diluted – pro forma $ 6.53 $ 6.26 $ 6.53

¹ ~~Fair value determined using the Black-Scholes option-pricing model.~~
² ~~Per-share amounts in all periods reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.~~
*Fair value determined using the Black-Scholes option-pricing model.
~~NOTE 2.~~Note 2
~~ACQUISITION OF UNOCAL CORPORATION~~Acquisition of Unocal Corporation
In August 2005, the company acquired Unocal Corporation (Unocal), an independent oil and gas exploration and production company. Unocal’s principal upstream operations were in North America and Asia, including the Caspian region. Also located in Asia were Unocal’s geothermal energy and electrical power businesses. Other activities included ownership interests in proprietary and common carrier pipelines, natural gas storage facilities and mining operations.
The aggregate purchase price of Unocal was ~~approximately~~ $17,288. ~~A third-party appraisal firm was engaged to assist the company in the process of determining the fair values of Unocal’s tangible and intangible assets.~~ The final purchase-price allocation to the assets and liabilities acquired was completed as of June 30, 2006.
     The following unaudited pro forma summary presents the results of operations as if the acquisition of Unocal had occurred at the beginning of 2005:

Year ended December 31
2005

Sales and other operating revenues $ 198,762
Net income 14,967
Net income per share of common stock
Basic $ 6.68
Diluted $ 6.64

     The pro forma summary used estimates and assumptions based on information available at the time. Management believes the estimates and assumptions to be reasonable; however, actual results may have differed significantly from this pro forma financial information.

FS-34

~~NOTE 2.~~ ~~ACQUISITION OF UNOCAL CORPORATION – Continued~~

     ~~The acquisition was accounted for under the rules of FASB Statement No. 141,~~~~Business Combinations~~~~. The following table summarizes the final purchase-price allocation:~~
Note 3

Current assets $ 3,573
Investments and long-term receivables 1,695
Properties 17,285
Goodwill 4,820
Other assets 2,174

Total assets acquired 29,547

Current liabilities (2,364 )
Long-term debt and capital leases (2,392 )
Deferred income taxes (4,009 )
Other liabilities (3,494 )

Total liabilities assumed (12,259 )

Net assets acquired $ 17,288

     ~~The $4,820 of goodwill, which represents benefits of the acquisition that are additional~~Information Relating to the ~~fair values~~Consolidated Statement of the other net assets acquired, was assigned to the upstream segment. The goodwill is not deductible for tax purposes. The goodwill balance was reviewed for possible impairment as of June 30, 2006, according to the requirements of FASB Statement No. 142,~~Goodwill and Other Intangible Assets~~, to test goodwill for impairment on an annual basis. Goodwill was determined not to be impaired at that time, and no events have occurred subsequently that would necessitate an additional impairment review.Cash Flows
     ~~The following unaudited pro forma summary presents the results of operations as if the acquisition of Unocal had occurred at the beginning of each period:~~

Year ended December 31
2005 2004

Sales and other operating revenues $ 198,762 $ 158,471
Net income 14,967 14,164
Net income per share of common stock
Basic $ 6.68 $ 6.22
Diluted $ 6.64 $ 6.19

     The pro forma summary uses estimates and assumptions based on information available at the time. Management believes the estimates and assumptions to be reasonable; however, actual results may differ significantly from this pro forma financial information. The pro forma information does not reflect any synergistic savings that might be achieved from combining the operations and is not intended to reflect the actual results that would have occurred had the companies actually been combined during the periods presented.
~~NOTE 3.~~
~~INFORMATION RELATING TO THE CONSOLIDATED STATEMENT OF CASH FLOWS~~

Year ended December 31
Year ended December 31
2006 2005 2004 2007 2006 2005

Net decrease (increase) in operating working capital was composed of the following:
Decrease (increase) in accounts and notes receivable $ 17 $ (3,164 ) $ (2,515 )
(Increase) decrease in accounts and notes receivable $ (3,867 ) $ 17 $ (3,164 )
Increase in inventories (536 ) (968 ) (298 ) (749 ) (536 ) (968 )
Increase in prepaid expenses and other current assets (31 ) (54 ) (76 ) (370 ) (31 ) (54 )
Increase in accounts payable and accrued liabilities 1,246 3,851 2,175 4,930 1,246 3,851
Increase in income and other taxes payable 348 281 1,144 741 348 281

Net decrease (increase) in operating working capital $ 1,044 $ (54 ) $ 430 $ 685 $ 1,044 $ (54 )

Net cash provided by operating activities includes the following cash payments for interest and income taxes:
Interest paid on debt (net of capitalized interest) $ 470 $ 455 $ 422 $ 203 $ 470 $ 455
Income taxes $ 13,806 $ 8,875 $ 6,679 $ 12,340 $ 13,806 $ 8,875

Net (purchases) sales of marketable securities consisted of the following gross amounts:
Marketable securities purchased $ (1,271 ) $ (918 ) $ (1,951 ) $ (1,975 ) $ (1,271 ) $ (918 )
Marketable securities sold 1,413 1,254 1,501 2,160 1,413 1,254

Net sales (purchases) of marketable securities $ 142 $ 336 $ (450 ) $ 185 $ 142 $ 336


     The Consolidated Statement of Cash Flows ~~excludes the effects of~~does not include noncash transactions. In October 2006, operating service agreements in Venezuela were converted to joint stock companies. Upon conversion, the company reclassified $441 of long-term receivables, $132 of accounts receivablefinancing and ~~$45 of properties, plant and equipment to investments in equity affiliates.~~investing activities. Refer ~~also~~ to Note 2123, starting on page ~~FS-48~~FS-57, for a discussion of revisions to the ~~non-cash effects associated with the implementation of FASB Statement No. 158,~~~~Employers’ Accounting for Defined Pension and Other Postretirement Plans~~.company’s asset retirement obligations that did not involve cash receipts or payments in 2007.
     In accordance with the cash-flow classification requirements of FAS 123R,Share-Based Payment, the “Net decrease (increase) in operating working capital” includes reductions of ~~$94~~$96 and ~~$20~~$94 for excess income tax benefits associated with stock options exercised during ~~2006~~2007 and ~~2005,~~2006, respectively. These amounts are offset by “Net purchases of treasury shares.”
     The 2007 “Net purchases of other short-term investments” consist of $799 in restricted cash associated with capital-investment projects at the company’s Pascagoula, Mississippi refinery and Angola liquefied natural gas project that was invested in short-term marketable securities and reclassified from cash equivalents to a long-term deferred asset on the Consolidated Balance Sheet. In December 2007, the company issued a $650 tax exempt Mississippi Gulf Opportunity Zone Bond as a source of funds for the Pascagoula Refinery project.
     The “Net purchases of treasury shares” represents the cost of common shares acquired in the open market less the cost of shares issued for share-based compensation plans. Open-market purchases totaled $7,036, $5,033 and $3,029 in 2007, 2006 and ~~$2,122 in 2006,~~ 2005, ~~and 2004,~~ respectively.

~~FS-35~~
~~Notes to the Consolidated Financial Statements~~
~~Millions of dollars, except per-share amounts~~

~~NOTE 3.~~~~INFORMATION RELATING TO THE CONSOLIDATED~~
~~STATEMENT OF CASH FLOWS – Continued~~
     In May 2006, the company’s investment in Dynegy Series C preferred stock was redeemed at its face value of $400. Upon redemption of the preferred stock, the company recorded a before-tax gain of $130 ($87 after tax). The $130 gain is included in the Consolidated Statement of Income as “Income from equity affiliates.”
     The 2005 “cash portion of Unocal acquisition, net of Unocal cash received” represents the purchase price, net of $1,600 of cash received. The aggregate purchase price of Unocal was approximately $17,288. Refer to Note 2, starting on page FS-34, for additional discussion of the Unocal acquisition.
     The major components of “Capital expenditures” and the reconciliation of this amount to the reported capital and exploratory expenditures, including equity affiliates, presented in Management’s Discussion and Analysis, beginning on page FS-2, are presented in the following table:

Year ended December 31
Year ended December 31
2006 2005 2004 2007 2006 2005

Additions to properties, plant and equipment* $ 12,800 $ 8,154 $ 5,798 $ 16,127 $ 12,800 $ 8,154
Additions to investments 880 459 303 881 880 459
Current-year dry hole expenditures 400 198 228 418 400 198
Payments for other liabilities and assets, net (267 ) (110 ) (19 ) (748 ) (267 ) (110 )

Capital expenditures 13,813 8,701 6,310 16,678 13,813 8,701
Expensed exploration expenditures 844 517 412 816 844 517
Assets acquired through capital lease obligations and other financing obligations 35 164 31 196 35 164

Capital and exploratory expenditures, excluding equity affiliates 14,692 9,382 6,753 17,690 14,692 9,382
Equity in affiliates’ expenditures 1,919 1,681 1,562 2,336 1,919 1,681

Capital and exploratory expenditures, including equity affiliates $ 16,611 $ 11,063 $ 8,315 $ 20,026 $ 16,611 $ 11,063

*Net of noncash additions of $3,560 in 2007, $440 in 2006 and $435 in ~~2005 and $212 in 2004.~~2005.
~~NOTE 4.~~Note 4
~~SUMMARIZED FINANCIAL DATA~~Summarized Financial Data – ~~CHEVRON~~Chevron U.S.A. ~~INC.~~Inc.
Chevron U.S.A. Inc. (CUSA) is a major subsidiary of Chevron Corporation. CUSA and its subsidiaries manage and operate most of Chevron’s U.S. businesses. Assets include those related to the exploration and production of crude oil, natural gas and natural gas liquids and those associated with the refining, marketing, supply and distribution of products derived from petroleum, other than natural gas liquids, excluding most of the regulated pipeline operations of Chevron. CUSA also holds Chevron’s ~~investments~~investment in the Chevron Phillips Chemical Company LLC (CPChem) joint venture ~~and Dynegy Inc. (Dynegy),~~ which ~~are~~is accounted for using the equity method.
     During 2007, Chevron implemented legal reorganizations in which certain Chevron subsidiaries transferred assets to or under CUSA. The summarized financial information for CUSA and its consolidated subsidiaries presented in the table on the following page gives retroactive effect to the reorganizations as if they had occurred on January 1, 2005. However, the financial information on the following page may not reflect the financial position and operating results in the periods presented if the reorganization actually had occurred on that date.

FS-35
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts

Note 4Summarized Financial Data Chevron U.S.A. Inc. – Continued

Year ended December 31
Year ended December 31
2006 2005 2004 2007 2006 2005

Sales and other operating revenues $ 146,447 $ 138,296 $ 108,351 $ 153,574 $ 145,774 $ 137,866
Total costs and other deductions 138,494 132,180 102,180 147,510 137,765 131,809
Net income 5,399 4,693 4,773 5,203 5,668 4,775

At December 31
At December 31
2006 2005 2007 2006

Current assets $ 26,356 $ 27,878 $ 32,803 $ 26,066
Other assets 23,200 20,611 27,401 23,538
Current liabilities 17,250 20,286 20,050 16,917
Other liabilities 11,501 12,897 11,447 9,037
Net equity 20,805 15,306 28,707 23,650

Memo: Total debt $ 6,020 $ 8,353 $ 4,433 $ 3,465
~~NOTE 5.~~Note 5
~~SUMMARIZED FINANCIAL DATA~~Summarized Financial Data – ~~CHEVRON TRANSPORT CORPORATION LTD.~~Chevron Transport Corporation Ltd.
Chevron Transport Corporation Ltd. (CTC), incorporated in Bermuda, is an indirect, wholly owned subsidiary of Chevron Corporation. CTC is the principal operator of Chevron’s international tanker fleet and is engaged in the marine transportation of crude oil and refined petroleum products. Most of CTC’s shipping revenue is derived from providing transportation services to other Chevron companies. Chevron Corporation has fully and unconditionally guaranteed this subsidiary’s obligations in connection with certain debt securities issued by a third party. Summarized financial information for CTC and its consolidated subsidiaries is presented in the following table:

Year ended December 31 Year ended December 31
2006 2005 2004 2007 2006 2005

Sales and other operating revenues $ 692 $ 640 $ 660 $ 667 $ 692 $ 640
Total costs and other deductions 602 509 495 713 602 509
Net income 119 113 160 (39 ) 119 113

At December 31 At December 31
2006 2005 2007 2006

Current assets $ 413 $ 358 $ 335 $ 413
Other assets 345 283 337 345
Current liabilities 92 119 107 92
Other liabilities 250 243 188 250
Net equity 416 279 377 416


     There were no restrictions on CTC’s ability to pay dividends or make loans or advances at December 31, ~~2006.~~2007.
~~NOTE 6.~~Note 6
~~STOCKHOLDERS’ EQUITY~~Stockholders’ Equity
Retained earnings at December 31, ~~2006~~2007 and ~~2005,~~2006, included approximately ~~$5,580~~$7,284 and ~~$5,000,~~$5,580, respectively, for the company’s share of undistributed earnings of equity affiliates.
     At December 31, ~~2006,~~2007, about ~~134~~120 million shares of Chevron’s common stock remained available for issuance from

~~FS-36~~

~~NOTE 6.~~ ~~STOCKHOLDER’S EQUITY – Continued~~
the 160 million shares that were reserved for issuance under the Chevron Corporation Long-Term Incentive Plan (LTIP)~~, as amended and restated, which was approved by the stockholders in 2004.~~. In addition,
approximately ~~503,000~~454,000 shares remain available for issuance from the 800,000 shares of the company’s common stock that were reserved for awards under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan (Non-Employee Directors’ Plan)~~, which was approved by stockholders in 2003. Refer to Note 25, on page FS-58, for a discussion of the company’s common stock split in 2004.~~.
~~NOTE 7.~~Note 7
~~FINANCIAL AND DERIVATIVE INSTRUMENTS~~Financial and Derivative Instruments
For the financial and derivative instruments discussed below, no material change in market risk occurred relative to the information presented in 2006.
Commodity Derivative InstrumentsChevron is exposed to market risks related to price volatility of crude oil, refined products, natural gas, natural gas liquids, liquefied natural gas and refinery feedstocks.
     The company uses derivative commodity instruments to manage these exposures on a portion of its activity, ~~including:~~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 company uses International Swaps ~~Dealers~~and Derivatives Association agreements to govern derivative contracts with certain counterparties to mitigate credit risk. Depending on the nature of the derivative transactions, bilateral collateral arrangements may also be required. When the company is engaged in more than one outstanding derivative transaction with the same counterparty and also has a legally enforceable netting agreement with that counterparty, the net marked-to-market exposure represents the netting of the positive and negative exposures with that counterparty and is a reasonable measure of the company’s credit risk exposure. The company also uses other netting agreements with certain counterparties with which it conducts significant transactions to mitigate credit risk.
     The fair values of the outstanding contracts are reported on the Consolidated Balance Sheet as “Accounts and notes receivable,” “Accounts payable,” “Long-term receivables – net” and “Deferred credits and other noncurrent obligations.” Gains and losses on the company’s risk management activities are reported as either “Sales and other operating revenues” or “Purchased crude oil and products,” whereas trading gains and losses are reported as “Other income.”
Foreign CurrencyThe 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.

FS-36

Note 7Financial and Derivative Instruments – Continued
     The fair values of the outstanding contracts are reported on the Consolidated Balance Sheet as “Accounts and notes receivable” or “Accounts payable,” with gains and losses reported as “Other income.”
Interest RatesThe 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.~~hedges.
     Fair values of the interest rate swaps are reported on the Consolidated Balance Sheet as “Accounts and notes receivable” or “Accounts ~~payable,” with gains and losses reported directly in income as part of “Interest and debt expense.~~payable.”
Fair ValueFair values are derived ~~either~~ from quoted market prices, other independent third-party quotes or, if not available, the present value of the expected cash flows. The fair values reflect the cash that would have been received or paid if the instruments were settled at year-end.
     Long-term debt of ~~$5,131~~$2,132 and ~~$7,424~~$5,131 had estimated fair values of ~~$5,621~~$2,325 and ~~$7,945~~$5,621 at December 31, ~~2006~~2007 and ~~2005,~~2006, respectively.
     The company holds cash equivalents and marketable securities in U.S. and non-U.S. portfolios. Eurodollar bonds, floating-rate notes, time deposits and commercial paper are the primary instruments held. Cash equivalents and marketable securities had carrying/fair values of ~~$9,200~~$5,427 and ~~$8,995~~$9,200 at December 31, ~~2006~~2007 and ~~2005,~~2006, respectively. Of these balances, ~~$8,247~~$4,695 and ~~$7,894~~$8,247 at the respective year-ends were classified as cash equivalents that had average maturities under 90 days. The remainder, classified as marketable securities, had average maturities of approximately ~~1.4 years.~~
     ~~For~~one year. At December 31, 2007, restricted cash with a carrying/fair value of $799 that is related to capital-investment projects at the ~~financial~~company’s Pascagoula, Mississippi refinery and ~~derivative instruments discussed above, there~~Angola liquefied natural gas project was ~~not~~reclassified from cash equivalents to a ~~material change~~long-term deferred asset on the Consolidated Balance Sheet. This restricted cash was invested in ~~market risk from that presented in 2005.~~short-term marketable securities.
     Fair values of other financial and derivative instruments at the end of ~~2006~~2007 and ~~2005~~2006 were not material.
Concentrations of Credit RiskThe company’s financial instruments that are exposed to concentrations of credit risk consist primarily of its cash equivalents, marketable securities, derivative financial instruments and trade receivables. The company’s short-term investments are placed with a wide array of ~~finan-~~

~~FS-37~~
~~Notes to the Consolidated Financial Statements~~
~~Millions of dollars, except per-share amounts~~

~~NOTE 7.~~~~FINANCIAL AND DERIVATIVE INSTRUMENTS – Continued~~
~~cial~~financial institutions with high credit ratings. This diversified investment policy limits the company’s exposure both to credit risk and to concentrations of credit risk. Similar standards of diversity and creditworthiness are applied to the company’s counterparties in derivative instruments.
     The trade receivable balances, reflecting the company’s diversified sources of revenue, are dispersed among the
company’s broad customer base worldwide. As a consequence, the company believes concentrations of credit risk are limited. The company routinely assesses the financial strength of its customers. When the financial strength of a customer is not considered sufficient, requiring Letters of Credit is a principal method used to support sales to customers.
~~NOTE 8.~~Note 8
~~OPERATING SEGMENTS AND GEOGRAPHIC DATA~~Operating Segments and Geographic Data
Although each subsidiary of Chevron is responsible for its own affairs, Chevron Corporation manages its investments in these subsidiaries and their affiliates. For this purpose, the investments are grouped as follows: upstream – exploration and production; downstream – refining, marketing and transportation; chemicals; and all other. The first three of these groupings represent the company’s “reportable segments” and “operating segments” as defined in Financial Accounting Standards Board (FASB) Statement No. 131,Disclosures About Segments of an Enterprise and Related Information(FAS 131).
     The segments are separately managed for investment purposes under a structure that includes “segment managers” who report to the company’s “chief operating decision maker” (CODM) (terms as defined in FAS 131). The CODM is the company’s Executive Committee, a committee of senior officers that includes the Chief Executive Officer and that, in turn, reports to the Board of Directors of Chevron Corporation.
     The operating segments represent components of the company as described in FAS 131 terms that engage in activities (a) from which revenues are earned and expenses are incurred; (b) whose operating results are regularly reviewed by the CODM, which makes decisions about resources to be allocated to the segments and to assess their performance; and (c) for which discrete financial information is available.
     Segment managers for the reportable segments are accountable directly to and maintain regular contact with the company’s CODM to discuss the segment’s operating activities and financial performance. The CODM approves annual capital and exploratory budgets at the reportable segment level, as well as reviews capital and exploratory funding for major projects and approves major changes to the annual capital and exploratory budgets. However, business-unit managers within the operating segments are directly responsible for decisions relating to project implementation and all other matters connected with daily operations. Company officers who are members of the Executive Committee also have individual
management responsibilities and participate in other committees for purposes other than acting as the CODM.
     “All Other” activities include the company’s interest in Dynegy (through May 2007, when Chevron sold its interest), mining operations, power generation businesses, worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, alternative fuels, and technology companies.

FS-37
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts

Note 8Operating Segments and Geographic Data – Continued
     The company’s primary country of operation is the United States of America, its country of domicile. Other components of the company’s operations are reported as “International” (outside the United States).
Segment EarningsThe company evaluates the performance of its operating segments on an after-tax basis, without considering the effects of debt financing interest expense or investment interest income, both of which are managed by the company on a worldwide basis. Corporate administrative costs and assets are not allocated to the operating segments. However, operating segments are billed for the direct use of corporate services. Nonbillable costs remain at the corporate level in “All Other.” After-tax segment income ~~from continuing operations~~by major operating area is presented in the following table:

Year ended December 31 Year ended December 31
2006 2005 2004 2007 2006 2005

Income From Continuing Operations

Income by Major Operating Area

Upstream

United States $ 4,270 $ 4,168 $ 3,868 $ 4,532 $ 4,270 $ 4,168
International 8,872 7,556 5,622 10,284 8,872 7,556

Total Upstream
13,142 11,724 9,490 14,816 13,142 11,724

Downstream

United States 1,938 980 1,261 966 1,938 980
International 2,035 1,786 1,989 2,536 2,035 1,786

Total Downstream
3,973 2,766 3,250 3,502 3,973 2,766

Chemicals

United States 430 240 251 253 430 240
International 109 58 63 143 109 58

Total Chemicals
539 298 314 396 539 298

Total Segment Income
17,654 14,788 13,054 18,714 17,654 14,788
All Other

Interest expense (312 ) (337 ) (257 ) (107 ) (312 ) (337 )
Interest income 380 266 129 385 380 266
Other (584 ) (618 ) 108 (304 ) (584 ) (618 )

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

Net Income
$ 17,138 $ 14,099 $ 13,328 $ 18,688 $ 17,138 $ 14,099

~~FS-38~~

~~NOTE 8.~~~~OPERATING SEGMENTS AND GEOGRAPHIC DATA – Continued~~
Segment AssetsSegment assets do not include intercompany investments or intercompany receivables. Segment assets at year-end ~~2006~~2007 and ~~2005~~2006 are as follows:

At December 31 At December 31
2006 2005 2007 2006

Upstream

United States $ 20,727 $ 19,006 $ 23,535 $ 20,727
International 51,844 46,501 61,049 51,844
Goodwill 4,623 4,636 4,637 4,623

Total Upstream
77,194 70,143 89,221 77,194

Downstream

United States 13,482 12,273 16,790 13,482
International 22,892 22,294 26,075 22,892

Total Downstream
36,374 34,567 42,865 36,374

Chemicals

United States 2,568 2,452 2,484 2,568
International 832 727 870 832

Total Chemicals
3,400 3,179 3,354 3,400

Total Segment Assets
116,968 107,889 135,440 116,968

All Other*

United States 8,481 9,234 6,847 8,481
International 7,179 8,710 6,499 7,179

Total All Other
15,660 17,944 13,346 15,660

Total Assets – United States
45,258 42,965 49,656 45,258
Total Assets – International
82,747 78,232 94,493 82,747
Goodwill
4,623 4,636 4,637 4,623

Total Assets
$ 132,628 $ 125,833 $ 148,786 $ 132,628

*“All Other” assets consist primarily of worldwide cash, cash equivalents and marketable securities, real estate, information systems, the company’s investment in Dynegy prior to its disposition in 2007, mining operations, power generation businesses, technology companies, and assets of the corporate administrative functions.
Segment Sales and Other Operating RevenuesOperating segment sales and other operating revenues, including internal transfers, for the years 2007, 2006 ~~2005~~ and ~~2004~~2005 are presented in the following table. Products are transferred between operating segments at internal product values that approximate market prices.
     Revenues for the upstream segment are derived primarily from the production and sale of crude oil and natural gas, as well as the sale of third-party production of natural gas. Revenues for the downstream segment are derived from the refining and marketing of petroleum products, such as gasoline, jet fuel, gas oils, kerosene, lubricants, residual fuel oils and other products derived from crude oil. This segment also generates revenues from the transportation and trading of crude oil and refined products. Revenues for the chemicals segment are derived primarily from the manufacture and sale of additives for lubricants and fuel. “All Other” activities include revenues from mining operations of coal and other minerals, power generation businesses, insurance operations, real estate activities, and technology companies.
     Other than the United States, no single country accounted for 10 percent or more of the company’s total sales and other operating revenues in ~~2006.~~2007.

Year ended December 31
2006 2005 2004

Upstream

United States $ 18,061 $ 16,044 $ 8,242
Intersegment 10,069 8,651 8,121

Total United States 28,130 24,695 16,363

International 14,560 10,190 7,246
Intersegment 17,139 13,652 10,184

Total International 31,699 23,842 17,430

Total Upstream
59,829 48,537 33,793

Downstream

United States 69,367 73,721 57,723
Excise and other similar taxes 4,829 4,521 4,147
Intersegment 533 535 179

Total United States 74,729 78,777 62,049

International 91,325 83,223 67,944
Excise and other similar taxes 4,657 4,184 3,810
Intersegment 37 14 87

Total International 96,019 87,421 71,841

Total Downstream
170,748 166,198 133,890

Chemicals

United States 372 343 347
Excise and other similar taxes 2 – –
Intersegment 243 241 188

Total United States 617 584 535

International 959 760 747
Excise and other similar taxes 63 14 11
Intersegment 160 131 107

Total International 1,182 905 865

Total Chemicals
1,799 1,489 1,400

All Other

United States 653 597 551
Intersegment 584 514 431

Total United States 1,237 1,111 982

International 44 44 97
Intersegment 23 26 16

Total International 67 70 113

Total All Other
1,304 1,181 1,095

Segment Sales and Other Operating Revenues

United States 104,713 105,167 79,929
International 128,967 112,238 90,249

Total Segment Sales and Other Operating Revenues
233,680 217,405 170,178
Elimination of intersegment sales (28,788 ) (23,764 ) (19,313 )

Total Sales and Other Operating Revenues*
$ 204,892 $ 193,641 $ 150,865

*Includes buy/sell contracts of $6,725 in 2006, $23,822 in 2005 and $18,650 in 2004. Substantially all of the amounts in each period relates to the downstream segment. Refer to Note 14, on page FS-43 for a discussion of the company’s accounting for buy/sell contracts.

~~FS-39~~FS-38

~~Notes to the Consolidated Financial Statements~~
~~Millions of dollars, except per-share amounts~~

~~NOTE 8.~~Note 8~~OPERATING SEGMENTS AND GEOGRAPHIC DATA~~Operating Segments and Geographic Data – Continued

Year ended December 31
2007 2006 2005

Upstream

United States $ 18,736 $ 18,061 $ 16,044
Intersegment 11,625 10,069 8,651

Total United States 30,361 28,130 24,695

International 15,213 14,560 10,190
Intersegment 19,647 17,139 13,652

Total International 34,860 31,699 23,842

Total Upstream
65,221 59,829 48,537

Downstream

United States 70,535 69,367 73,721
Excise and similar taxes 4,990 4,829 4,521
Intersegment 491 533 535

Total United States 76,016 74,729 78,777

International 97,178 91,325 83,223
Excise and similar taxes 5,042 4,657 4,184
Intersegment 38 37 14

Total International 102,258 96,019 87,421

Total Downstream
178,274 170,748 166,198

Chemicals

United States 351 372 343
Excise and similar taxes 2 2 –
Intersegment 235 243 241

Total United States 588 617 584

International 1,143 959 760
Excise and similar taxes 86 63 14
Intersegment 142 160 131

Total International 1,371 1,182 905

Total Chemicals
1,959 1,799 1,489

All Other

United States 757 653 597
Intersegment 760 584 514

Total United States 1,517 1,237 1,111

International 58 44 44
Intersegment 31 23 26

Total International 89 67 70

Total All Other
1,606 1,304 1,181

Segment Sales and Other Operating Revenues

United States 108,482 104,713 105,167
International 138,578 128,967 112,238
��
Total Segment Sales and Other Operating Revenues
247,060 233,680 217,405
Elimination of intersegment sales (32,969 ) (28,788 ) (23,764 )

Total Sales and Other Operating Revenues*
$ 214,091 $ 204,892 $ 193,641

*Includes buy/sell contracts of $6,725 in 2006 and $23,822 in 2005. Substantially all of the amounts in each period relate to the downstream segment. Refer to Note 13, on page FS-42, for a discussion of the company’s accounting for buy/sell contracts.
Segment Income TaxesSegment income tax ~~expenses~~expense for the years 2007, 2006 ~~2005~~ and ~~2004~~2005 are as follows:

Year ended December 31
2007 2006 2005

Upstream

United States $ 2,541 $ 2,668 $ 2,330
International 11,307 10,987 8,440

Total Upstream
13,848 13,655 10,770

Downstream

United States 520 1,162 575
International 400 586 576

Total Downstream
920 1,748 1,151

Chemicals

United States 6 213 99
International 36 30 25

Total Chemicals
42 243 124

All Other
(1,331 ) (808 ) (947 )

Total Income Tax Expense
$ 13,479 $ 14,838 $ 11,098

Year ended December 31
2006 2005 2004

Upstream

United States $ 2,668 $ 2,330 $ 2,308
International 10,987 8,440 5,041

Total Upstream
13,655 10,770 7,349

Downstream

United States 1,162 575 739
International 586 576 442

Total Downstream
1,748 1,151 1,181
��
Chemicals

United States 213 99 47
International 30 25 17

Total Chemicals
243 124 64

All Other
(808 ) (947 ) (1,077 )

Income Tax Expense From Continuing Operations*
$ 14,838 $ 11,098 $ 7,517

*Income tax expense of $100 related to discontinued operations for 2004 is not included.
Other Segment Information   Additional information for the segmentation of major equity affiliates is contained in Note ~~12,~~11, beginning on page ~~FS-41.~~FS-40. Information related to properties, plant and equipment by segment is contained in Note ~~13,~~12, on page ~~FS-43.~~FS-42.
~~NOTE 9.~~Note 9
~~LEASE COMMITMENTS~~Lease Commitments
Certain noncancelable leases are classified as capital leases, and the leased assets are included as part of “Properties, plant and equipment, at cost.” Such leasing arrangements involve tanker charters, crude oil production and processing equipment, service stations, office buildings and other facilities. Other leases are classified as operating leases and are not capitalized. The payments on such leases are recorded as expense. Details of the capitalized leased assets are as follows:

At December 31
2006 2005

Upstream $ 461 $ 442
Downstream 896 837

Total 1,357 1,279
Less: Accumulated amortization 813 745

Net capitalized leased assets $ 544 $ 534

At December 31
2007 2006*

Upstream $ 482 $ 461
Downstream $ 551 $ 550
Chemical and all other 171 2

Total 1,204 1,013
Less: Accumulated amortization 628 548

Net capitalized leased assets $ 576 $ 465

*2006 conformed to 2007 presentation.
     Rental expenses incurred for operating leases during 2007, 2006 ~~2005~~ and ~~2004~~2005 were as follows:

Year ended December 31 Year ended December 31
2006 2005 2004 2007 2006 2005

Minimum rentals $ 2,326 $ 2,102 $ 2,093 $ 2,419 $ 2,326 $ 2,102
Contingent rentals 6 6 7 6 6 6

Total 2,332 2,108 2,100 2,425 2,332 2,108
Less: Sublease rental income 33 43 40 30 33 43

Net rental expense $ 2,299 $ 2,065 $ 2,060 $ 2,395 $ 2,299 $ 2,065

FS-39
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts

Note 9Lease Commitments – Continued
     Contingent rentals are based on factors other than the passage of time, principally sales volumes at leased service stations. Certain leases include escalation clauses for adjusting rentals to reflect changes in price indices, renewal options ranging up to 25 years, and options to purchase the leased property during or at the end of the initial or renewal lease period for the fair market value or other specified amount at that time.
     At December 31, ~~2006,~~2007, the estimated future minimum lease payments (net of noncancelable sublease rentals) under operating and capital leases, which at inception had a non-cancelable term of more than one year, were as follows:

At December 31 At December 31
Operating Capital
Leases Leases Operating Capital
Leases Leases
Year: 2007 $ 509 $ 91
2008 507 80

Year: 2008 $ 513 $ 103
2009 477 81 478 106
2010 390 59 430 83
2011 311 57 347 85
2012 293 91
Thereafter 864 520 1,106 347

Total $ 3,058 $ 888 $ 3,167 $ 815

Less: Amounts representing interest and executory costs (262 ) (315 )

Net present values 626 500
Less: Capital lease obligations included in short-term debt (352 ) (94 )

Long-term capital lease obligations $ 274 $ 406

~~NOTE 10.~~Note 10
~~RESTRUCTURING AND REORGANIZATION COSTS~~Restructuring and Reorganization Costs
In ~~connection with the Unocal acquisition,~~2007, the company implemented a restructuring and reorganization program ~~as part of the effort to capture the synergies of the combined companies by eliminating redundant operations, consolidating offices and facilities, and sharing common services and functions.~~
     ~~As part of the restructuring and reorganization, approximately 600~~in its downstream operations. Approximately 1,000 employees were eligible for severance payments. Most of the associated positions are inlocated outside the United ~~States~~States. The majority of the terminations are expected to occur in 2008 and ~~relate primarily to corporate and upstream executive and administrative functions. By year-end 2006,~~ the program ~~was substantially complete.~~

~~FS-40~~

~~NOTE 10.~~ ~~RESTRUCTURING AND REORGANIZATION COSTS – Continued~~

     ~~An accrual~~is expected to be complete by the end of $106 was established as part of the purchase-price allocation for Unocal. The $11 balance at year-end 2006 was classified as a current liability on the Consolidated Balance Sheet. Activity for this accrual is shown in the table below.

Amounts before tax 2006 2005

Balance at January 1 $ 44 $ –
Additions/Adjustments (14 ) 106
Payments (19 ) (62 )

Balance at December 31 $ 11 $ 44

2009.
     Shown in the table below is the activity for the company’s liability related to ~~various other reorganizations and restructurings across several businesses and corporate departments. The $17 balance at year-end 2006 was also classified as a current liability on~~ the ~~Consolidated Balance Sheet.~~downstream reorganization. The associated charges ~~or credits during the periods~~against income were categorized as “Operating expenses” or “Selling, general and administrative expenses” on the Consolidated Statement of Income.
     ~~Activity for the company’s liability related to other various reorganizations and restructurings is summarized in the following table:~~

Amounts before tax 2007

Balance at January 1 $ –
Additions 85
Payments –

Balance at December 31 $ 85

Amounts before tax 2006 2005

Balance at January 1 $ 47 $ 119
Additions/adjustments (7 ) (10 )
Payments (23 ) (62 )

Balance at December 31 $ 17 $ 47

~~NOTE 11.~~Note 11
~~ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS~~
~~At December 31, 2004, the company classified $162 of net properties, plant~~Investments and ~~equipment as “Assets held for sale” on the Consolidated Balance Sheet. Assets in this category related to a group of service stations outside the United States.~~
     ~~Summarized income statement information relating to discontinued operations is as follows:~~

Year ended December 31
2006 2005 2004

Revenues and other income $ – $ – $ 635
Income from discontinued operations before income tax expense – – 394
Income from discontinued operations, net of tax – – 294

     Not all assets sold or to be disposed of are classified as discontinued operations, mainly because the cash flows from the assets were not, or will not be, eliminated from the ongoing operations of the company.
     Subsequent to December 31, 2006, approximately $300 of the company’s refining assets in the Netherlands met the criteria for classifying the assets as held for sale. The company expects to record a gain upon close of sale, which is subject to
~~signing of the sales agreement and obtaining necessary regulatory approvals.~~
~~NOTE 12.~~
~~INVESTMENTS AND ADVANCES~~Advances
Equity in earnings, together with investments in and advances to companies accounted for using the equity method and other investments accounted for at or below cost, ~~are~~is shown in the table below. For certain equity affiliates, Chevron pays its share of some income taxes directly. For such affiliates, the equity in earnings dodoes not include these taxes, which are reported on the Consolidated Statement of Income as “Income tax expense.”

Investments and Advances Equity in Earnings
Investments and Advances Equity in Earnings At December 31 Year ended December 31
At December 31 Year ended December 31
2006 2005 2006 2005 2004 2007 2006 2007 2006 2005

Upstream

Tengizchevroil $ 5,507 $ 5,007 $ 1,817 $ 1,514 $ 950 $ 6,321 $ 5,507 $ 2,135 $ 1,817 $ 1,514
Hamaca 928 1,189 319 390 98 1,168 928 327 319 390
Petroboscan 712 – 31 – – 762 712 185 31 –
Angola LNG Limited 574 – 21 – –
Other 682 679 123 139 148 765 682 204 123 139

Total Upstream 7,829 6,875 2,290 2,043 1,196 9,590 7,829 2,872 2,290 2,043

Downstream

GS Caltex Corporation 2,176 1,984 316 320 296 2,276 2,176 217 316 320
Caspian Pipeline Consortium 990 1,014 117 101 140 951 990 102 117 101
Star Petroleum Refining Company Ltd. 787 709 116 81 207 944 787 157 116 81
Escravos Gas-to-Liquids 628 432 103 146 95
Caltex Australia Ltd. 559 435 186 214 173 580 559 129 186 214
Colonial Pipeline Company 555 565 34 13 – 546 555 39 34 13
Other 1,839 1,562 358 273 143 1,501 1,407 215 212 178

Total Downstream 6,906 6,269 1,127 1,002 959 7,426 6,906 962 1,127 1,002

Chemicals

Chevron Phillips Chemical Company LLC 2,044 1,908 697 449 334 2,024 2,044 380 697 449
Other 22 20 5 3 2 24 22 6 5 3

Total Chemicals 2,066 1,928 702 452 336 2,048 2,066 386 702 452

All Other

Dynegy Inc. 254 682 68 189 86 – 254 8 68 189
Other 586 740 68 45 5 449 586 (84 ) 68 45

Total equity method $ 17,641 $ 16,494 $ 4,255 $ 3,731 $ 2,582 $ 19,513 $ 17,641 $ 4,144 $ 4,255 $ 3,731
Other at or below cost 911 563 964 911

Total investments and advances $ 18,552 $ 17,057 $ 20,477 $ 18,552

Total United States $ 4,191 $ 4,624 $ 955 $ 833 $ 588 $ 3,889 $ 4,191 $ 478 $ 955 $ 833
Total International $ 14,361 $ 12,433 $ 3,300 $ 2,898 $ 1,994 $ 16,588 $ 14,361 $ 3,666 $ 3,300 $ 2,898


     Descriptions of major affiliates are as follows:
Tengizchevroil  Chevron has a 50 percent equity ownership interest in Tengizchevroil (TCO), a joint venture formed in 1993 to develop the Tengiz and Korolev crude oil fields in Kazakhstan over a 40-year period. At December 31, 2007, the company’s carrying value of its investment in TCO was about $210 higher than the amount of underlying equity in TCO net assets.
Hamaca  ~~Chevron has a~~Chevron’s 30 percent interest in the Hamaca heavy oil production and upgrading project located in Venezuela’s Orinoco ~~Belt.~~Belt was converted to a 30 percent share-holding in a joint stock company in January 2008, with a 25-year contract term.

~~FS-41~~FS-40

~~Notes to the Consolidated Financial Statements~~
~~Millions of dollars, except per-share amounts~~

~~NOTE 12.~~Note 11 ~~INVESTMENTS AND ADVANCES~~Investments and Advances – Continued

Petroboscan  Chevron has a 39 percent interest in Petroboscan, a joint stock company formed in 2006 to operate the Boscan Field in ~~Venezuela.~~Venezuela until 2026. Chevron previously operated the field under an operating service agreement. At December 31, ~~2006,~~2007, the company’s carrying value of its investment in Petroboscan was approximately ~~$300~~$310 higher than the amount of underlying equity in ~~Petroboscan’s~~Petroboscan net assets.
Angola LNG Ltd.Chevron has a 36 percent interest in Angola LNG, which will process and liquefy natural gas produced in Angola for delivery to international markets.
GS Caltex Corporation  Chevron owns 50 percent of GS Caltex, a joint venture with GS Holdings. The joint venture, originally formed in 1967 between the LG Group and Caltex, imports, refines and markets petroleum products and petrochemicals predominantly in South Korea.
Caspian Pipeline Consortium  Chevron has a 15 percent interest in the Caspian Pipeline Consortium (CPC), which provides the critical export route for crude oil from both TCO and Karachaganak. At December 31, ~~2006,~~2007, the company’s carrying value of its investment in CPC was about $50 higher than the amount of underlying equity in ~~CPC’s~~CPC net assets.
Star Petroleum Refining Company Ltd.  Chevron has a 64 percent equity ownership interest in Star Petroleum Refining Company Limited (SPRC), which owns the Star Refinery in Thailand. The Petroleum Authority of Thailand owns the remaining 36 percent of SPRC.
Escravos Gas-to-LiquidsChevron Nigeria Limited (CNL) has a 75 percent interest in Escravos Gas-to-Liquids (EGTL) with the other 25 percent of the joint venture owned by Nigeria National Petroleum Company. Sasol Ltd provides 50 percent of the venture capital required by CNL as risk-based financing (returns are based on project performance). This venture was formed to convert natural gas produced from Chevron’s Nigerian operations into liquid products for sale in international markets. At December 31, 2007, the company’s carrying value of its investment in EGTL was about $25 lower than the amount of underlying equity in EGTL net assets.
Caltex Australia Ltd.  Chevron has a 50 percent equity ownership interest in Caltex Australia Limited (CAL). The remaining 50 percent of CAL is publicly owned. At December 31, ~~2006,~~2007, the fair value of Chevron’s share of CAL common stock was approximately ~~$2,400.~~$2,294. The aggregate carrying value of the company’s investment in CAL was approximately ~~$60~~$50 lower than the amount of underlying equity in CAL net assets.
Colonial Pipeline Company  Chevron owns an approximate 23 percent equity interest in the Colonial Pipeline Company. The Colonial Pipeline system runs from Texas to New Jersey and transports petroleum products in a 13-state market. At December 31, ~~2006,~~2007, the company’s carrying value of its investment in Colonial Pipeline was approximately ~~$590~~$580 higher than the amount of underlying equity in Colonial ~~Pipeline’s~~Pipeline net assets.
Chevron Phillips Chemical Company LLC  Chevron owns 50 percent of Chevron Phillips Chemical Company LLC (CPChem), with the other half owned by ConocoPhillips Corporation. At December 31, ~~2006,~~2007, the company’s carrying value of its investment in CPChem was approximately ~~$80~~$60 lower than the amount of underlying equity in ~~CPChem’s~~CPChem net assets.
Dynegy Inc.  In May 2007, Chevron ~~owns a~~sold its 19 percent ~~equity interest in the~~ common stock ofinvestment in Dynegy Inc., a provider of electricity to markets and customers throughout the United ~~States.~~
~~Investment~~States, for approximately $940, resulting in ~~Dynegy Common Stock~~   At December 31, 2006, the carrying value of the company’s investment in Dynegy common stock was approximately $250. This amount was about $180 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. This difference has been assigned to the extent practicable to specific Dynegy assets and liabilities, based upon the company’s analysis of the various factors contributing to the decline in value of the Dynegy shares. The company’s equity share of Dynegy’s reported earnings is adjusted quarterly when appropriate to reflect 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.
~~Investment 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. Upon redemption of the preferred stock, the company recorded~~ a ~~before-tax~~ gain of ~~$130 ($87 after tax).~~
$680.
~~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.
Other Information  ~~“Sales~~“Sales and other operating revenues” on the Consolidated Statement of Income includes $11,555, $9,582 ~~$8,824~~ and ~~$7,933~~$8,824 with affiliated companies for 2007, 2006 ~~2005~~ and ~~2004,~~2005, respectively. “Purchased crude oil and products” includes $5,464, $4,222 ~~$3,219~~ and ~~$2,548~~$3,219 with affiliated companies for 2007, 2006 ~~2005~~ and ~~2004,~~2005, respectively.
     “Accounts and notes receivable” on the Consolidated Balance Sheet includes ~~$1,297~~$1,722 and ~~$1,729~~$1,297 due from affiliated companies at December 31, ~~2006~~2007 and ~~2005,~~2006, respectively. “Accounts payable” includes ~~$262~~$374 and ~~$249~~$262 due to affiliated companies at December 31, ~~2006~~2007 and ~~2005,~~2006, respectively.

~~FS-42~~FS-41

Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts

~~NOTE 12.~~Note 11 ~~INVESTMENTS AND ADVANCES~~Investments and Advances – Continued


     The following table provides summarized financial information on a 100 percent basis for all equity affiliates as well as Chevron’s total share, which includes Chevron loans to affiliates of ~~$3,915~~$4,124 at December 31, ~~2006.~~2007.

Affiliates Chevron Share
Affiliates Chevron Share
Year ended December 31 2006 2005 2004 2006 2005 2004 2007 2006 2005 2007 2006 2005

Total revenues $ 73,746 $ 64,642 $ 55,152 $ 35,695 $ 31,252 $ 25,916 $ 94,864 $ 73,746 $ 64,642 $ 46,579 $ 35,695 $ 31,252
Income before income tax expense 10,973 7,883 5,309 5,295 4,165 3,015 12,510 10,973 7,883 5,836 5,295 4,165
Net income 7,905 6,645 4,441 4,072 3,534 2,582 9,743 7,905 6,645 4,550 4,072 3,534

At December 31

Current assets $ 19,769 $ 19,903 $ 16,506 $ 8,944 $ 8,537 $ 7,540 $ 26,360 $ 19,769 $ 19,903 $ 11,914 $ 8,944 $ 8,537
Noncurrent assets 49,896 46,925 38,104 18,575 17,747 15,567 48,440 49,896 46,925 19,045 18,575 17,747
Current liabilities 15,254 13,427 10,949 6,818 6,034 4,962 19,033 15,254 13,427 9,009 6,818 6,034
Noncurrent liabilities 24,059 26,579 22,261 3,902 4,906 4,520 22,757 24,059 26,579 3,745 3,902 4,906

Net equity
$ 30,352 $ 26,822 $ 21,400 $ 16,799 $ 15,344 $ 13,625 $ 33,010 $ 30,352 $ 26,822 $ 18,205 $ 16,799 $ 15,344

~~NOTE 13.~~Note 12
~~PROPERTIES, PLANT AND EQUIPMENT~~¹Properties, Plant and Equipment

At December 31 Year ended December 31 At December 31 Year ended December 31
Gross Investment at Cost Net Investment Additions at Cost² Depreciation Expense^3,4 Gross Investment at Cost Net Investment Additions at Cost¹ Depreciation Expense²
2006 2005 2004 2006 2005 2004 2006 2005 2004 2006 2005 2004 2007 2006 2005 2007 2006 2005 2007 2006 2005 2007 2006 2005

Upstream

United States $ 46,191 $ 43,390 $ 37,329 $ 16,706 $ 15,327 $ 10,047 $ 3,739 $ 2,160 $ 1,584 $ 2,374 $ 1,869 $ 1,508 $ 50,991 $ 46,191 $ 43,390 $ 19,850 $ 16,706 $ 15,327 $ 5,725 $ 3,739 $ 2,160 $ 2,700 $ 2,374 $ 1,869
International 61,281 54,497 38,721 37,730 34,311 21,192 7,290 4,897 3,090 3,888 2,804 2,180 71,408 61,281 54,497 43,431 37,730 34,311 10,512 7,290 4,897 4,605 3,888 2,804

Total Upstream 107,472 97,887 76,050 54,436 49,638 31,239 11,029 7,057 4,674 6,262 4,673 3,688 122,399 107,472 97,887 63,281 54,436 49,638 16,237 11,029 7,057 7,305 6,262 4,673

Downstream

United States 14,553 13,832 12,826 6,741 6,169 5,611 1,109 793 482 474 461 490 15,807 14,553 13,832 7,685 6,741 6,169 1,514 1,109 793 509 474 461
International 11,036 11,235 10,843 5,233 5,529 5,443 532 453 441 551 550 572 10,471 11,036 11,235 4,690 5,233 5,529 519 532 453 633 551 550

Total Downstream 25,589 25,067 23,669 11,974 11,698 11,054 1,641 1,246 923 1,025 1,011 1,062 26,278 25,589 25,067 12,375 11,974 11,698 2,033 1,641 1,246 1,142 1,025 1,011

Chemicals

United States 645 624 615 289 282 292 25 12 12 19 19 20 678 645 624 308 289 282 40 25 12 19 19 19
International 771 721 725 431 402 392 54 43 27 24 23 26 815 771 721 453 431 402 53 54 43 26 24 23

Total Chemicals 1,416 1,345 1,340 720 684 684 79 55 39 43 42 46 1,493 1,416 1,345 761 720 684 93 79 55 45 43 42

All Other⁵

All Other³

United States 3,243 3,127 2,877 1,709 1,655 1,466 270 199 314 171 186 158 3,873 3,243 3,127 2,179 1,709 1,655 680 270 199 215 171 186
International 27 20 18 19 15 15 8 4 2 5 1 3 41 27 20 14 19 15 5 8 4 1 5 1

Total All Other 3,270 3,147 2,895 1,728 1,670 1,481 278 203 316 176 187 161 3,914 3,270 3,147 2,193 1,728 1,670 685 278 203 216 176 187

Total United States 64,632 60,973 53,647 25,445 23,433 17,416 5,143 3,164 2,392 3,038 2,535 2,176 71,349 64,632 60,973 30,022 25,445 23,433 7,959 5,143 3,164 3,443 3,038 2,535
Total International 73,115 66,473 50,307 43,413 40,257 27,042 7,884 5,397 3,560 4,468 3,378 2,781 82,735 73,115 66,473 48,588 43,413 40,257 11,089 7,884 5,397 5,265 4,468 3,378

Total $ 137,747 $ 127,446 $ 103,954 $ 68,858 $ 63,690 $ 44,458 $ 13,027 $ 8,561 $ 5,952 $ 7,506 $ 5,913 $ 4,957 $ 154,084 $ 137,747 $ 127,446 $ 78,610 $ 68,858 $ 63,690 $ 19,048 $ 13,027 $ 8,561 $ 8,708 $ 7,506 $ 5,913

¹ ~~Includes assets acquired in connection with the acquisition of Unocal Corporation in August 2005. Refer to Note 2, beginning on page FS-34, for additional information.~~
² Net of dry hole expense related to prior years’ expenditures of $89, $120 and $28 in 2007, 2006 and ~~$58~~2005, respectively.
² Depreciation expense includes accretion expense of $399, $275 and $187 in 2007, 2006 ~~2005~~ and ~~2004,~~2005, respectively.

³ ~~Depreciation expense includes accretion expense of $275, $187 and $93 in 2006, 2005 and 2004, respectively.~~
⁴ ~~Depreciation expense includes discontinued operations of $22 in 2004.~~
⁵ Primarily mining operations, power generation businesses, real estate assets and management information systems.
~~NOTE 14.~~Note 13
~~ACCOUNTING FOR BUY/SELL CONTRACTS~~Accounting for Buy/Sell Contracts
The company adopted the accounting prescribed by ~~EITF~~Emerging Issues Task Force (EITF) Issue No. 04-13,Accounting for Purchases and Sales of Inventory with the Same Counterparty(Issue 04-13) on a prospective basis from April 1, 2006. Issue 04-13 requires that two or more legally separate exchange transactions with the same counterparty, including buy/sell transactions, be combined and considered as a single arrangement for purposes of applying the provisions of Accounting Principles Board Opinion No. 29,Accounting for Nonmonetary Transactions,when the transactions are entered into “in contemplation” of one another. In prior
~~another. In prior~~ periods, the company accounted for buy/sell transactions in the Consolidated Statement of Income as a monetary transaction – purchases were reported as “Purchased crude oil and products”; sales were reported as “Sales and other operating revenues.”
     With the company’s adoption of Issue 04-13, buy/sell transactions beginning in the second quarter 2006 are netted against each other on the Consolidated Statement of Income, with no effect on net income. Amounts associated with buy/sell transactions in periods prior to the second quarter 2006 are shown as a footnote to the Consolidated Statement of Income on page FS-27.

~~FS-43~~FS-42

~~Notes to the Consolidated Financial Statements~~
~~Millions of dollars, except per-share amounts~~

~~NOTE 15.~~Note 14
~~LITIGATION~~Litigation
MTBE  Chevron and many other companies in the petroleum industry have used methyl tertiary butyl ether (MTBE) as a gasoline additive. ~~Chevron~~The company is a party to ~~approximately 75~~88 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~~seepages of MTBE into groundwater. Chevron has agreed in principle to a tentative settlement of 60 pending lawsuits and claims. The terms of this agreement, which must be approved by a number of parties, including the court, are confidential and not material to the company’s results of operations, liquidity or financial position.
Resolution of ~~these actions~~remaining lawsuits and claims may ultimately require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE, including personal-injury claims, may be filed in the future.
The tentative settlement of the referenced 60 lawsuits did not set any precedents related to standards of liability to be used to judge the merits of the claims, corrective measures required or monetary damages to be assessed for the remaining lawsuits and claims or future lawsuits and claims. As a result, the company’s ultimate exposure related to ~~these~~pending lawsuits and claims is not currently determinable, but could be material to net income in any one period. The company ~~currently does not use~~no longer uses 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~~were consolidated in U.S. District Court for the Central District of California, where a class action has been certified, and three ~~are~~were consolidated in ~~California State Court.~~a state court action. 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~~The parties have reached a tentative agreement to resolve all of the above matters in an amount that is not material to the company’s results of operations, liquidity or
financial position. The terms of this agreement are confidential, and ~~intends~~subject to ~~vigorously defend against these lawsuits. The company’s potential exposure related to these lawsuits cannot currently be estimated.~~further negotiation and approval, including by the courts.
Note 15
Taxes
Income Taxes

Year ended December 31
2007 2006 2005

Taxes on income
U.S. Federal
Current $ 1,446 $ 2,828 $ 1,459
Deferred 225 200 567
State and local 338 581 409

Total United States 2,009 3,609 2,435

International
Current 11,416 11,030 7,837
Deferred 54 199 826

Total International 11,470 11,229 8,663

Total taxes on income $ 13,479 $ 14,838 $ 11,098

~~NOTE 16.~~
~~TAXES~~

Year ended December 31
2006 2005 2004

Taxes on income*
U.S. federal
Current $ 2,828 $ 1,459 $ 2,246
Deferred 200 567 (290 )
State and local 581 409 345

Total United States 3,609 2,435 2,301

International
Current 11,030 7,837 5,150
Deferred 199 826 66

Total International 11,229 8,663 5,216

Total taxes on income $ 14,838 $ 11,098 $ 7,517

* ~~Excludes income tax expense of $100 related to discontinued operations for 2004.~~
     In ~~2006, the~~2007, before-tax income for U.S. operations, including related corporate and other charges, was ~~$9,131,~~$7,794, compared with a before-tax income of $9,131 and $6,733 in 2006 and ~~$7,776 in~~ 2005, ~~and 2004,~~ respectively. For international operations, before-tax income was $24,373, $22,845 and $18,464 in 2007, 2006 and ~~$12,775 in 2006,~~ 2005, ~~and 2004,~~ respectively. U.S. federal income tax expense was reduced by $132, $116 and $289 in 2007, 2006 and ~~$176 in 2006,~~ 2005, ~~and 2004,~~ respectively, for business tax credits.
     The reconciliation between the U.S. statutory federal income tax rate and the company’s effective income tax rate is explained in the table below:

Year ended December 31 Year ended December 31
2006 2005 2004 2007 2006 2005

U.S. statutory federal income tax rate 35.0 % 35.0 % 35.0 % 35.0 % 35.0 % 35.0 %
Effect of income taxes from international operations at rates different from the U.S. statutory rate 10.3 9.2 5.3 8.3 10.3 9.2
State and local taxes on income, net of U.S. federal income tax benefit 1.0 1.0 0.9 0.8 1.0 1.0
Prior-year tax adjustments 0.9 0.1 (1.0 ) 0.3 0.9 0.1
Tax credits (0.4 ) (1.1 ) (0.9 ) (0.4 ) (0.4 ) (1.1 )
Effects of enacted changes in tax laws 0.3 – (0.6 ) (0.3 ) 0.3 –
Capital loss tax benefit – (0.1 ) (2.1 )
Other (0.7 ) – – (1.8 ) (0.7 ) (0.1 )

Effective tax rate 46.4 % 44.1 % 36.6 % 41.9 % 46.4 % 44.1 %


     The ~~company records its deferred taxes on a~~
~~tax-jurisdiction basis and classifies those net amounts as current or noncurrent based on the balance sheet classification of the related assets or liabilities.~~
     ~~The reported deferred~~company’s effective tax ~~balances are composed of the following:~~

At December 31
2006 2005

Deferred tax liabilities
Properties, plant and equipment $ 16,054 $ 14,220
Investments and other 2,137 1,469

Total deferred tax liabilities 18,191 15,689

Deferred tax assets
Abandonment/environmental reserves (2,925 ) (2,083 )
Employee benefits (2,707 ) (1,250 )
Tax loss carryforwards (1,509 ) (1,113 )
Capital losses (246 ) (246 )
Deferred credits (1,670 ) (1,618 )
Foreign tax credits (1,916 ) (1,145 )
Inventory (378 ) (182 )
Other accrued liabilities (375 ) (240 )
Miscellaneous (1,144 ) (1,237 )

Total deferred tax assets (12,870 ) (9,114 )

Deferred tax assets valuation allowance 4,391 3,249

Total deferred taxes, net $ 9,712 $ 9,824

     ~~In 2006, deferred tax liabilities increased~~rate decreased by ~~approximately $2,500~~4.5 percent in 2007 from the ~~amount reported in 2005.~~prior year. The 2 percent decrease pertaining to the “Effect of income taxes from international

~~FS-44~~FS-43

Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts

~~NOTE 16.~~Note 15 ~~TAXES~~ Taxes – Continued

operations ...” was primarily due to the impact of asset sales and to lower effective tax rates in certain non-U.S. operations. The 1 percent decrease in “Other” primarily relates to the effects of asset sales in 2007.
     The company records its deferred taxes on a tax-jurisdiction basis and classifies those net amounts as current or noncurrent based on the balance sheet classification of the related assets or liabilities. The reported deferred tax balances are composed of the following:

At December 31
2007 2006

Deferred tax liabilities
Properties, plant and equipment $ 17,310 $ 16,054
Investments and other 1,837 2,137

Total deferred tax liabilities 19,147 18,191

Deferred tax assets
Abandonment/environmental reserves (3,587 ) (2,925 )
Employee benefits (2,148 ) (2,707 )
Tax loss carryforwards (1,603 ) (1,509 )
Capital losses – (246 )
Deferred credits (1,689 ) (1,670 )
Foreign tax credits (3,138 ) (1,916 )
Inventory (608 ) (378 )
Other accrued liabilities (477 ) (375 )
Miscellaneous (1,528 ) (1,144 )

Total deferred tax assets (14,778 ) (12,870 )

Deferred tax assets valuation allowance 5,949 4,391

Total deferred taxes, net $ 10,318 $ 9,712

     In 2007, deferred tax liabilities increased by approximately $1,000 from the amount reported in 2006. The increase was primarily related to increased temporary differences for properties, plant and equipment.
     Deferred tax assets increased by approximately ~~$3,800~~$1,900 in ~~2006.~~2007. The increase related primarily to ~~higher pension and other benefit obligations resulting from the implementation of FAS 158, increased~~additional foreign tax credits ~~resulting~~arising from ~~higher crude oil prices~~earnings in ~~tax jurisdictions with high income tax rates, and increased asset retirement obligations.~~high-tax-rate international jurisdictions. This increase was substantially offset by valuation allowances.
     The overall valuation allowance relates to foreign tax credit carryforwards, tax loss carryforwards and temporary differences for which no benefit is expected to be realized. Tax loss carryforwards exist in many international jurisdictions. Whereas some of these tax loss carryforwards do not have an expiration date, others expire at various times from ~~2007~~2008 through 2029. Foreign tax credit carryforwards of ~~$1,916~~$3,138 will expire between ~~2009~~2008 and ~~2016.~~2017.
     At December 31, ~~2006~~2007 and ~~2005,~~2006, deferred taxes were classified in the Consolidated Balance Sheet as follows:

At December 31 At December 31
2006 2005 2007 2006

Prepaid expenses and other current assets $ (1,167 ) $ (892 ) $ (1,234 ) $ (1,167 )
Deferred charges and other assets (844 ) (547 ) (812 ) (844 )
Federal and other taxes on income 76 1 194 76
Noncurrent deferred income taxes 11,647 11,262 12,170 11,647

Total deferred income taxes, net $ 9,712 $ 9,824 $ 10,318 $ 9,712


     Income taxes are not accrued for unremitted earnings of international operations that have been or are intended to be reinvested indefinitely. Undistributed earnings of international consolidated subsidiaries and affiliates for which no deferred income tax provision has been made for possible future remittances totaled ~~$21,035~~$20,557 at December 31, ~~2006. A significant majority of this~~2007. This amount represents earnings reinvested as part of the company’s ongoing international business. It is not practicable to estimate the amount of taxes that might be payable on the eventual remittance of ~~such~~earnings that are intended to be reinvested indefinitely. At the end of 2007, deferred income taxes were recorded for the undistributed earnings of certain international operations for which the company no longer intends to indefinitely reinvest the earnings. The company does not anticipate incurring significant additional taxes on remittances of earnings that are not indefinitely reinvested.
Uncertain Income Tax PositionsEffective January 1, 2007, the company implemented Financial Accounting Standards Board (FASB) Interpretation No. 48,~~American Jobs Creation Act~~Accounting for Uncertainty in Income Taxes – An Interpretation of ~~2004~~FASB Statement No. 109   ~~In October 2004,~~ (FIN 48), which clarifies the ~~American Jobs Creation Act of 2004 was passed into law. The Act provides a deduction~~accounting for income ~~from qualified domestic refining and upstream production activities, which~~tax benefits that are uncertain in nature. This interpretation was intended by the standard-setters to address the diversity in practice that existed in this area of accounting for income taxes.
     Under FIN 48, a company recognizes a tax benefit in the financial statements for an uncertain tax position only if management’s assessment is that the position is “more likely than not” (i.e., a likelihood greater than 50 percent) to be ~~phased in from 2005 through 2010. The company expects~~allowed by the ~~net effect of this provision~~tax jurisdiction based solely on the technical merits of the ~~Act~~position. The term “tax position” in FIN 48 refers to ~~result~~a position in a ~~decrease~~previously filed tax return or a position expected to be taken in a future tax return that is reflected in measuring current or deferred income tax assets and liabilities for interim or annual periods. The accounting interpretation also provides guidance on measurement methodology, derecognition thresholds, financial statement classification and disclosures, recognition of interest and penalties, and accounting for the cumulative-effect adjustment at the date of adoption. Upon adoption of FIN 48 on January 1, 2007, the company recorded a cumulative-effect adjustment that reduced retained earnings by $35.

FS-44

Note 15 Taxes – Continued
     The following table indicates the changes to the company’s unrecognized tax benefits for the year ended December 31, 2007. The term “unrecognized tax benefits” in FIN 48 refers to the differences between a tax position taken or expected to be taken in a tax return and the benefit measured and recognized in the ~~federal effective~~financial statements in accordance with the guidelines of FIN 48. Interest and penalties are not included.

Balance at January 1, 2007 (date of FIN 48 adoption) $ 2,296
Foreign currency effects 19
Additions based on tax positions taken in 2007 418
Additions for tax positions taken in prior years 120
Reductions for tax positions taken in prior years (225 )
Settlements with taxing authorities in 2007 (255 )
Reductions due to tax positions previously expected to be taken but subsequently not taken on 2006 tax returns (174 )

Balance at December 31, 2007 $ 2,199

     The only individually significant change for 2007 was a reduction in an unrecognized tax benefit for a position previously expected to be taken but subsequently not taken on a 2006 tax return. Although unrecognized tax benefits for individual tax positions may increase or decrease during 2008, the company believes that no change will be individually significant during 2008. Approximately 80 percent of the $2,199 of unrecognized tax benefits at December 31, 2007, would have an impact on the overall tax rate if subsequently recognized.
      Tax positions for ~~2007~~Chevron and its subsidiaries and affiliates are subject to ~~approximately 33 percent, based on current earnings levels.~~income tax audits by many tax jurisdictions throughout the world. For the company’s major tax jurisdictions, examinations of tax returns for certain prior tax years had not been completed as of December 31, 2007. In ~~the long term,~~this regard, the company ~~expects that~~received a final U.S. federal income tax audit report for years 2002 and 2003 in March 2007. In early 2008, the ~~new deduction will result in a decrease of~~company’s 2004 and 2005 tax returns were under examination by the ~~annual effective~~Internal Revenue Service. For other major tax ~~rate to about 32 percent~~jurisdictions, the latest years for ~~that category of~~which income ~~based on current earnings levels.~~
     ~~Taxes other than on income~~tax examinations had been finalized were as follows: Nigeria – 1994, Angola – 2001 and Saudi Arabia – 2003.

Year ended December 31
2006 2005 2004

United States
Excise and other similar taxes on products and merchandise $ 4,831 $ 4,521 $ 4,147
Import duties and other levies 32 8 5
Property and other miscellaneous taxes 475 392 359
Payroll taxes 155 149 137
Taxes on production 360 323 257

Total United States 5,853 5,393 4,905

International
Excise and other similar taxes on products and merchandise 4,720 4,198 3,821
Import duties and other levies 9,618 10,466 10,542
Property and other miscellaneous taxes 491 535 415
Payroll taxes 75 52 52
Taxes on production 126 138 86

Total International 15,030 15,389 14,916

Total taxes other than on income* $ 20,883 $ 20,782 $ 19,821

     On the Consolidated Statement of Income, the company reports interest and penalties related to liabilities for uncertain tax positions as “Income tax expense.” As of December 31, 2007, accruals of $198 for anticipated interest and penalty obligations were included on the Consolidated Balance Sheet. For the year 2007, income tax expense associated with interest and penalties was not material.
* ~~Includes taxes on discontinued operations of $3 in 2004.~~
Taxes Other Than on Income

Year ended December 31
2007 2006 2005

United States
Excise and similar taxes on products and merchandise $ 4,992 $ 4,831 $ 4,521
Import duties and other levies 12 32 8
Property and other miscellaneous taxes 491 475 392
Payroll taxes 185 155 149
Taxes on production 288 360 323

Total United States 5,968 5,853 5,393

International
Excise and similar taxes on products and merchandise 5,129 4,720 4,198
Import duties and other levies 10,404 9,618 10,466
Property and other miscellaneous taxes 528 491 535
Payroll taxes 89 75 52
Taxes on production 148 126 138

Total International 16,298 15,030 15,389

Total taxes other than on income $ 22,266 $ 20,883 $ 20,782

~~NOTE 17.~~Note 16
~~SHORT-TERM DEBT~~Short-Term Debt

At December 31 At December 31
2006 2005 2007 2006

Commercial paper* $ 3,472 $ 4,098 $ 3,030 $ 3,472
Notes payable to banks and others with originating terms of one year or less 122 170 219 122
Current maturities of long-term debt 2,176 467 850 2,176
Current maturities of long-term capital leases 57 70 73 57
Redeemable long-term obligations Long-term debt 487 487
Redeemable long-term obligations
Long-term debt 1,351 487
Capital leases 295 297 21 295

Subtotal 6,609 5,589 5,544 6,609
Reclassified to long-term debt (4,450 ) (4,850 ) (4,382 ) (4,450 )

Total short-term debt $ 2,159 $ 739 $ 1,162 $ 2,159

* ~~Weighted-average interest rates at December 31, 2006 and 2005, were 5.25 percent and 4.18 percent, respectively.~~
*Weighted-average interest rates at December 31, 2007 and 2006, were 4.35 percent and 5.25 percent, respectively.

     Redeemable long-term obligations consist primarily of tax-exempt variable-rate put bonds that are included as current liabilities because they become redeemable at the option of the bondholders during the year following the balance sheet date.
     The company periodically enters into interest rate swaps on a portion of its short-term debt. See Note 7, beginning on page ~~FS-37,~~FS-36, for information concerning the company’s debt-related derivative activities.
     At December 31, ~~2006,~~2007, the company had $4,950 of committed credit facilities with banks worldwide, which permit the company to refinance short-term obligations on a long-term basis. The facilities support the company’s commercial paper borrowings. Interest on borrowings under the terms of specific agreements may be based

FS-45

Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts

~~NOTE 17.~~Note 16 ~~SHORT-TERM DEBT~~Short-Term Debt – Continued

~~paper borrowings. Interest on borrowings under the terms of specific agreements may be based~~ on the London Interbank Offered Rate or bank prime rate. No amounts were outstanding under these credit agreements during ~~2006~~2007 or at year-end.
     At December 31, ~~2006~~2007 and ~~2005,~~2006, the company classified ~~$4,450~~$4,382 and ~~$4,850,~~$4,450, respectively, of short-term debt as long-term. Settlement of these obligations is not expected to require the use of working capital in ~~2007,~~2008, as the company has both the intent and the ability to refinance this debt on a long-term basis.
~~NOTE 18.~~Note 17
~~LONG-TERM DEBT~~Long-Term Debt
~~Chevron has three “shelf” registration statements on file with the SEC that together would permit the issuance of $3,800 of debt securities pursuant to Rule��415 of the Securities Act of 1933.~~ Total long-term debt, excluding capital leases, at December 31, ~~2006,~~2007, was ~~$7,405.~~$5,664. The company’s long-term debt outstanding at year-end ~~2006~~2007 and ~~2005~~2006 was as follows:

At December 31 At December 31
2006 2005 2007 2006

3.5% notes due 2007 $ 1,996 $ 1,992
3.375% notes due 2008 738 736 $ 749 $ 738
5.5% notes due 2009 401 406 405 401
7.327% amortizing notes due 2014¹
213 213
8.625% debentures due 2032 161 199
8.625% debentures due 2031 108 199
7.5% debentures due 2043 85 198
8% debentures due 2032 81 148
9.75% debentures due 2020 250 250 57 250
7.327% amortizing notes due 2014¹
213 247
8.625% debentures due 2031 199 199
8.625% debentures due 2032 199 199
7.5% debentures due 2043 198 198
8.875% debentures due 2021 46 150
8.625% debentures due 2010 150 150 30 150
8.875% debentures due 2021 150 150
8% debentures due 2032 148 148
3.85% notes due 2008 30 –
3.5% notes due 2007 – 1,996
7.09% notes due 2007 144 144 – 144
7.5% debentures due 2029 – 475
5.05% debentures due 2012 – 412
7.35% debentures due 2009 – 347
7% debentures due 2028 – 259
Fixed and floating interest rate loans due 2007 to 2009 – 194
9.125% debentures due 2006 – 167
8.25% debentures due 2006 – 129
Medium-term notes, maturing from 2017 to 2043 (7.7%)²
210 210
Fixed interest rate notes, maturing from 2007 to 2011 (7.4%)²
46 241
Other foreign currency obligations (2.2%)²
23 30
Other long-term debt (7.6%)²
66 141
Medium-term notes, maturing from 2021 to 2038 (6.2%)²
64 210
Fixed interest rate notes, maturing from 2008 to 2011 (8.2%)²
27 46
Other foreign currency obligations (0.5%)²
17 23
Other long-term debt (7.4%)²
59 66

Total including debt due within one year 5,131 7,424 2,132 5,131
Debt due within one year (2,176 ) (467 ) (850 ) (2,176 )
Reclassified from short-term debt 4,450 4,850 4,382 4,450

Total long-term debt $ 7,405 $ 11,807 $ 5,664 $ 7,405

¹ Guarantee of ESOP debt.

² ~~Less than $100 individually; weighted-average~~Weighted-average interest rate at December 31, ~~2006.~~2007.

     Long-term debt of ~~$5,131~~$2,132 matures as follows: ~~2007 – $2,176;~~ 2008 – ~~$805;~~$850; 2009 – ~~$428;~~$431; 2010 – ~~$185;~~$65; 2011 – ~~$50;~~$48; 2012 – $33; and after ~~2011~~2012 – ~~$1,487.~~$705.
     In ~~the first quarter~~2007, $2,000 of Chevron Canada Funding Company bonds matured. The company also redeemed early $874 of Texaco Capital Inc. bonds, at an after-tax loss of approximately $175. In 2006, ~~$185 of Union Oil Company~~$510 in bonds were retired at ~~maturity. In the second quarter, the company redeemed approximately~~maturity and $1,700 of Unocal debt ~~and recognized~~was redeemed early at a $92 before-tax gain. ~~In October 2006, a $129 Texaco Capital Inc. bond matured. In November 2006, the company retired Union Oil Company bonds of $196.~~
~~NOTE 19.~~Note 18
~~NEW ACCOUNTING STANDARDS~~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 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 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)~~157, Fair Value Measurements (FAS 157)  In ~~July~~September 2006, the FASB issued ~~FIN 48,~~FAS 157, which became effective for the company on January 1, ~~2007.~~2008. This ~~interpretation clarifies the accounting~~standard defines fair value, establishes a framework for ~~income tax benefits~~measuring fair value and expands disclosures about fair value measurements. FAS 157 does not require any new fair value measurements but applies to assets and liabilities that are ~~uncertain in nature. Under FIN 48,~~required to be recorded at fair value under other accounting standards. The implementation of FAS 157 did not have a material effect on the company’s results of operations or consolidated financial position.
FASB Staff Position FAS No. 157-1, Application of FASB Statement No. 157 to FASB Statement No. 13 and Its Related Interpretive Accounting Pronouncements That Address Leasing Transactions (FSP 157-1)In February 2008, the FASB issued FSP 157-1, which became effective for the company ~~will recognize~~on January 1, 2008. This FSP excludes FASB Statement No. 13, Accounting for Leases, and its related interpretive accounting pronouncements from the provisions of FAS 157. Implementation of this standard did not have a ~~tax benefit~~material effect on the company’s results of operations or consolidated financial position.
FASB Staff Position FAS No. 157-2, Effective Date of FASB Statement No. 157 (FSP 157-2)In February 2008, the FASB issued FSP 157-2, which delays the company’s January 1, 2008 effective date of FAS 157 for all nonfinancial assets and nonfinancial liabilities, except those recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until January 1, 2009. Implementation of this standard did not have a material effect on the company’s results of operations or consolidated financial position.
FASB Statement No. 159, The Fair Value Option for Financial Assets and Financial Liabilities - Including an ~~uncertain tax position only if management’s assessment~~amendment of FASB Statement No. 115 (FAS 159)In February 2007, the FASB issued FAS 159, which became effective for the company on January 1, 2008. This standard permits companies to choose to measure many financial instruments and certain other items at fair value and report unrealized gains and losses in earnings. Such accounting is ~~that its position~~optional and is ~~“more likely than not” (i.e., a greater than 50 percent likelihood)~~generally to be ~~upheld on audit based only~~applied instrument by instrument. The implementation of FAS 159 did not have a material effect on the ~~technical merits~~company’s results of operations or consolidated financial position.
FASB Statement No. 141 (revised 2007), Business Combinations (FAS 141-R)In December 2007, the ~~tax position.~~FASB issued FAS 141-R, which will become effective for business combination transactions having an acquisition date on or after January 1, 2009. This accounting interpretation also provides guidance on measurement methodology, derecognition thresholds, financial statement classification and disclosures, interest and penalties recognition, and accounting forstandard requires the ~~cumulative-effect adjustment. The new interpretation is intended~~acquiring entity in a business combination 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 unrecog-~~

FS-46

~~NOTE 19.~~Note 18 ~~NEW ACCOUNTING STANDARDS~~New Accounting Standards – Continued

~~nized tax benefits~~recognize the assets acquired, the liabilities assumed, and ~~associated~~any noncontrolling interest ~~and penalties as of January 1, 2007. In connection with this increase~~ in ~~liability,~~ the ~~company estimates retained earnings~~acquiree at the ~~beginning of 2007 will be reduced by $250 or less. The amount of the liability and impact on retained earnings will depend in part on clarification expected~~acquisition date to be ~~issued by~~measured at their respective fair values. The Statement requires acquisition-related costs, as well as restructuring costs the ~~FASB related~~acquirer expects to ~~the criteria~~incur for ~~determining the~~which it is not obligated at acquisition date, to be recorded against income rather than included in purchase-price determination. It also requires recognition of ~~ultimate settlement~~contingent arrangements at their acquisition-date fair values, with ~~a tax authority.~~subsequent changes in fair value generally reflected in income.
FASB Statement No. ~~157, Fair Value Measurements~~160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51 (FAS ~~157)~~160)  ~~In September 2006, the~~The FASB issued FAS ~~157,~~160 in December 2007, which will become effective for the company on January 1, ~~2008.~~2009, with retroactive adoption of the Statement’s presentation and disclosure requirements for existing minority interests. This standard ~~defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. The Statement does not~~will require ~~any new fair value measurements but would apply to assets and liabilities that are required~~ownership interests in subsidiaries held by parties other than the parent to be ~~recorded at fair value under other accounting standards. The impact, if any,~~presented within the equity section of the consolidated statement of financial position but separate from the parent’s equity. It will also require the amount of consolidated net income attributable to the ~~company from~~parent and the ~~adoption of FAS 157 in 2008 will depend~~noncontrolling interest to be clearly identified and presented on the ~~company��s assets~~face of the consolidated income statement. Certain changes in a parent’s ownership interest are to be accounted for as equity transactions and ~~liabilities at that time that are required~~when a subsidiary is deconsolidated, any noncontrolling equity investment in the former subsidiary is to be initially measured at fair value.
~~FASB Statement No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an Amendment~~ The company does not anticipate the implementation of ~~FASB Statements No. 87, 88, 106 and 132(R) (FAS 158)~~   ~~In September 2006,~~FAS 160 will significantly change 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.~~presentation of its consolidated income statement or consolidated balance sheet.
~~NOTE 20.~~Note 19
~~ACCOUNTING FOR SUSPENDED EXPLORATORY WELLS~~Accounting for Suspended Exploratory Wells
The company accounts for the cost of exploratory wells in accordance with FASB Statement No. 19,Financial and Reporting by Oil and Gas Producing Companies(FAS 19),as amended by FASB Staff Position (FSP) FAS 19-1,Accounting for Suspended Well Costs, which provides that exploratory well costs continue to be capitalized after the completion of drilling when (a) the well has found a sufficient quantity of reserves to justify completion as a producing well and (b) the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met or if an enterprise obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well would be assumed to be impaired, and its costs, net of any salvage value, would be charged to expense. FAS 19 provides a number of indicators that can assist an entity to demonstrate sufficient progress is being made in assessing the reserves and economic viability of the project.
     The following table indicates the changes to the company’s suspended exploratory well costs for the three years ended December 31, ~~2006.~~2007. No capitalized exploratory well costs were charged to expense upon the 2005 adoption of FSP FAS 19-1.

2007 2006 2005

Beginning balance at January 1 $ 1,239 $ 1,109 $ 671
Additions associated with the acquisition of Unocal – – 317
Additions to capitalized exploratory well costs pending the determination of proved reserves 486 446 290
Reclassifications to wells, facilities and equipment based on the determination of proved reserves (23 ) (171 ) (140 )
Capitalized exploratory well costs charged to expense (42 ) (121 ) (6 )
Other reductions* – (24 ) (23 )

Ending balance at December 31 $ 1,660 $ 1,239 $ 1,109

Year ended December 31
2006 2005 2004

Beginning balance at January 1 $ 1,109 $ 671 $ 549
Additions associated with the acquisition of Unocal – 317 –
Additions to capitalized exploratory well costs pending the determination of proved reserves 446 290 252
Reclassifications to wells, facilities and equipment based on the determination of proved reserves (171 ) (140 ) (64 )
Capitalized exploratory well costs charged to expense (121 ) (6 ) (66 )
Other reductions* (24 ) (23 ) –

Ending balance at December 31 $ 1,239 $ 1,109 $ 671

*Represent property sales and exchanges.
* ~~Represent property sales and exchanges.~~

     The following table provides an aging of capitalized well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling. The aging of the former Unocal wells is based on the date the drilling was completed, rather than the date of Chevron’s acquisition of Unocal in 2005.

Year ended December 31 At December 31
2006 2005 2004 2007 2006 2005

Exploratory well costs capitalized for a period of one year or less $ 332 $ 259 $ 222 $ 449 $ 332 $ 259
Exploratory well costs capitalized for a period greater than one year 907 850 449 1,211 907 850

Balance at December 31 $ 1,239 $ 1,109 $ 671 $ 1,660 $ 1,239 $ 1,109

Number of projects with exploratory well costs that have been capitalized for a period greater than one year* 44 40 22 54 44 40

* ~~Certain projects have multiple wells or fields or both.~~
*Certain projects have multiple wells or fields or both.

     Of the ~~$907~~$1,211 of exploratory well costs capitalized for ~~a period greater~~more than one year at December 31, ~~2006, $447 (23~~2007, $750 (32 projects) is related to projects that had drilling activities under way or firmly planned for the near future. An additional ~~$63 (one project)~~$8 (three projects) is related to projects that had drilling activity during ~~2006.~~2007. The ~~$397~~$453 balance related to 2019 projects in areas requiring a major capital expenditure before production could begin and for which additional drilling efforts were not under way or firmly planned for the near future. Additional drilling was not deemed necessary because the presence of hydrocarbons had already been established, and other activities were in process to enable a future decision on project development.
     The projects for the ~~$397~~$453 referenced above had the following activities associated with assessing the reserves and the projects’ economic viability: (a) $99 million (two projects) – development plans submitted to a government in early 2007; (b) $80 million (one project) – pre-FEED (front-end engineering and design) studies are ongoing with FEED expected to commence in 2007; (c) $75 million (three projects) – continued to pursue unitization opportunities on

FS-47

Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts

~~NOTE 20.~~Note 19 ~~ACCOUNTING FOR SUSPENDED~~
~~EXPLORATORY WELLS~~  Accounting For Suspended Exploratory Wells – Continued

projects’ economic viability: (a) $99 (one project) – combined two projects into a single development project and submitted plans to government in 2007; (b) $74 (three projects) – continued unitization efforts on adjacent discoveries that span international boundaries; ~~(d) $42 million~~(c) $74 (one project) – finalizing field development evaluation; (d) $74 (one project) – field rework continues to accommodate larger design capacity and finalize ~~analysis of new seismic study to determine the~~sales agreements; (e) $42 (one project) – finalizing development ~~facility~~ concept; ~~(e) $101~~(f) $90 – miscellaneous activities for 1312 projects with smaller amounts suspended. While progress was being made on all ~~the~~54 projects, ~~in this category,~~ the decision on the recognition of proved reserves under SEC rules in some cases may not occur for several years because of the complexity, scale and negotiations connected with the projects. The majority of these decisions are expected to occur in the next three years.
     The ~~$907~~$1,211 of suspended well costs capitalized for a period greater than one year as of December 31, ~~2006,~~2007, represents ~~110~~127 exploratory wells in 4454 projects. The tables below contain the aging of these costs on a well and project basis:

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

1994-1996 $ 27 3
1997-2001 128 33
2002-2005 752 74

Total $ 907 110

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

1994–1996 $ 27 3
1997–2001 128 32
2002–2006 1,056 92

Total $ 1,211 127

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

1999–2001 $ 9 2
2002–2006 898 42

Total $ 907 44

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

1999 $ 8 1
2003–2007 1,203 53

Total $ 1,211 54

~~NOTE 21.~~Note 20
~~EMPLOYEE BENEFIT PLANS~~Employee Benefit Plans
The company has defined-benefit pension plans for many employees. The company typically prefunds defined-benefit plans as required by local regulations or in certain situations where prefunding provides economic advantages. In the United States, all qualified plans are subject to the Employee Retirement Income Security Act ~~(ERISA)~~ minimum funding standard. The company does not typically fund U.S. nonqualified pension plans that are not subject to funding requirements under laws and regulations because contributions to these pension plans may be less economic and investment returns may be less attractive than the company’s other investment alternatives.
     The provisions of the Pension Protection Act of 2006 (PPA) became effective for the company in 2008. These provisions change, among other things, the methodology for determining the interest rate to be used in calculating lump-sum benefits. This change in methodology increased the lump-sum interest rate and lowered the company’s pension benefit obligations by about $300 at December 31, 2007. The effect of the interest rate change on pension plan contributions during 2008 is expected to bede minimis, as the company’s funded pension plans are considered “well-funded” under PPA provisions.
     The company also sponsors other postretirement plans that provide medical and dental benefits, as well as life insurance for some active and qualifying retired employees. The plans are unfunded, and the company and ~~the~~ retirees share the costs. Medical coverage for Medicare-eligible retirees in the company’s main U.S. medical plan is secondary to Medicare (including Part D) and the increase to the company contribution for retiree medical coverage is limited to no more than 4 percent per year. This contribution 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 retirees retiring
~~before that date and all Medicare-eligible retirees.~~ Certain life insurance benefits are paid by the ~~company, and annual contributions are based on actual plan experience.~~
     In June 2006, the company announced changes to several of its U.S. pension and other postretirement benefit plans, primarily merging benefits under several Unocal plans into related Chevron plans. Under the plan combinations, former-Unocal employees retiring on or after July 1, 2006, received recognition for Unocal pay and service history toward benefits to be paid under the Chevron pension and postretirement benefit plans. Unocal employees who retired before July 1, 2006, and were participating in the Unocal postretirement medical plan were merged into the Chevron primary U.S. plan effective January 1, 2007. In addition, the company’s contributions for Medicare-eligible retirees under the Chevron plan were increased in 2007 in conjunction with the merger of former-Unocal participants into the Chevron plan.company.
     Effective December 31, 2006, the company implemented the recognition and measurement provisions of Financial Accounting Standards Board ~~(FASB)~~ Statement No. 158,Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and132(R)(FAS 158), which requires the recognition of the overfunded or underfunded status of each of its defined benefit pension and other postretirement benefit plans as an asset or liability, with the offset to “Accumulated other comprehensive loss.” In addition, Chevron recognized its share of amounts recorded by affiliated companies in “Accumulated other comprehensive loss” to reflect their adoption of FAS 158 at December 31, 2006. The following table illustrates the incremental effect of the adoption of FAS 158 on individual lines in the company’s December 2006 “Consolidated Balance Sheet” after applying the additional minimum liability adjustment required by FASB Statement No. 87,~~Employers’ Accounting for Pensions~~.

Before After
Application FAS 158 Application
of FAS 158 * Adjustments of FAS 158

Noncurrent assets –
Investments and advances $ 18,542 $ 10 $ 18,552
Noncurrent assets –
Deferred charges and other assets $ 4,794 $ (2,706 ) $ 2,088
Total assets $ 135,324 $ (2,696 ) $ 132,628
Noncurrent liabilities – Noncurrent deferred income taxes $ 12,924 $ (1,277 ) $ 11,647
Noncurrent liabilities – Reserves for employee benefits $ 3,965 $ 784 $ 4,749
Total liabilities $ 64,186 $ (493 ) $ 63,693
Accumulated other comprehensive (loss) $ (433 ) $ (2,203 ) $ (2,636 )
Total stockholders’ equity $ 71,138 $ (2,203 ) $ 68,935

* Accounts include minimum pension liabilities of $636 ($40 for affiliates) recognized prior to application of FAS 158 at December 31, 2006. Deferred income taxes of $234 ($13 for affiliates) were recognized on the amounts reflected in “Accumulated other comprehensive loss”.

FS-48

~~NOTE 21.~~Note 20 ~~EMPLOYEE BENEFIT PLANS~~ Employee Benefit Plans – Continued

The company uses a measurement date of December 31 to value its benefit plan assets and obligations. The funded status of the company’s pension and other postretirement benefit plans for ~~2006~~2007 and ~~2005~~2006 is as follows:

Pension Benefits Pension Benefits
2006 2005 Other Benefits 2007 2006 Other Benefits
U.S. Int’l. U.S. Int’l. 2006 2005 U.S. Int’l. U.S. Int’l. 2007 2006

CHANGE IN BENEFIT OBLIGATION

Change in Benefit Obligation

Benefit obligation at January 1 $ 8,594 $ 3,611 $ 6,587 $ 3,144 $ 3,252 $ 2,820 $ 8,792 $ 4,207 $ 8,594 $ 3,611 $ 3,257 $ 3,252
Assumption of Unocal benefit obligations – – 1,437 169 – 277
Service cost 234 98 208 84 35 30 260 125 234 98 49 35
Interest cost 468 214 395 199 181 164 483 255 468 214 184 181
Plan participants’ contributions – 7 1 6 134 129 – 7 – 7 122 134
Plan amendments 14 37 42 7 107 – (301 ) 97 14 37 – 107
Actuarial loss 297 97 593 476 (102 ) 189
Curtailments – (12 ) – – – –
Actuarial (gain) loss (131 ) (40 ) 297 97 (413 ) (102 )
Foreign currency exchange rate changes – 355 – (293 ) (5 ) (2 ) – 219 – 355 12 (5 )
Benefits paid (815 ) (212 ) (669 ) (181 ) (345 ) (355 ) (708 ) (225 ) (815 ) (212 ) (272 ) (345 )

Benefit obligation at December 31 8,792 4,207 8,594 3,611 3,257 3,252 8,395 4,633 8,792 4,207 2,939 3,257

CHANGE IN PLAN ASSETS

Change in Plan Assets

Fair value of plan assets at January 1 7,463 2,890 5,776 2,634 – – 7,941 3,456 7,463 2,890 – –
Acquisition of Unocal plan assets – – 1,034 65 – –
Actual return on plan assets 1,069 225 527 441 – – 607 232 1,069 225 – –
Foreign currency exchange rate changes – 321 – (303 ) – – – 183 – 321 – –
Employer contributions 224 225 794 228 211 226 78 239 224 225 150 211
Plan participants’ contributions – 7 1 6 134 129 – 7 – 7 122 134
Benefits paid (815 ) (212 ) (669 ) (181 ) (345 ) (355 ) (708 ) (225 ) (815 ) (212 ) (272 ) (345 )

Fair value of plan assets at December 31 7,941 3,456 7,463 2,890 – – 7,918 3,892 7,941 3,456 – –

FUNDED STATUS AT DECEMBER 31
(851 ) (751 ) (1,131 ) (721 ) (3,257 ) (3,252 )
Unrecognized net actuarial loss – – 2,332 1,108 – 1,167
Unrecognized prior-service cost – – 305 89 – (679 )
Unrecognized net transitional assets – – – 5 – –
Funded Status at December 31
$ (477 ) $ (741 ) $ (851 ) $ (751 ) $ (2,939 ) $ (3,257 )

Total recognized at December 31 $ (851 ) $ (751 ) $ 1,506 $ 481 $ (3,257 ) $ (2,764 )

     Amounts recognized inon the Consolidated Balance Sheet for the company’s pension and other postretirement benefit plans at December 31, ~~2005, reflected the net of cumulative employer contributions~~2007 and ~~net periodic benefit costs~~2006, include:

Pension Benefits
2007 2006 Other Benefits
U.S. Int’l. U.S. Int’l. 2007 2006

Deferred charges and other assets $ 181 $ 279 $ 18 $ 96 $ – $ –
Accrued liabilities (68 ) (55 ) (53 ) (47 ) (207 ) (223 )
Reserves for employee benefit plans (590 ) (965 ) (816 ) (800 ) (2,732 ) (3,034 )

Net amount recognized at December 31 $ (477 ) $ (741 ) $ (851 ) $ (751 ) $ (2,939 ) $ (3,257 )

     Amounts recognized ~~in earnings. The 2005 amounts for noncurrent pension liabilities also included minimum pension liability adjustments, which were offset~~on a before-tax basis in “Accumulated other comprehensive loss” ~~and “Deferred charges and other assets.” Amounts recognized at December 31, 2006, reflected~~for the ~~net funded status of each of the~~ company’s ~~defined-benefit~~ pension and other postretirement plans ~~presented as either a net asset (overfunded) or a liability (underfunded).~~were $2,990 and $4,065 at the end of 2007 and 2006. These amounts consisted of:

Pension Benefits
2006 2005 Other Benefits
U.S. Int’l. U.S. Int’l. 2006 2005

Noncurrent assets – Prepaid benefit cost¹
$ 18 $ 96 $ 1,961 $ 960 $ – $ –
Noncurrent assets – Intangible asset¹
– – 12 2 – –
Current liabilities – Accrued liabilities (53 ) (47 ) (57 ) (17 ) (223 ) (186 )
Noncurrent liabilities – Reserves for employee benefit plans²
(816 ) (800 ) (833 ) (528 ) (3,034 ) (2,578 )
Accumulated other comprehensive income³ – Minimum pension liability
– – 423 64 – –

Net amount recognized $ (851 ) $ (751 ) $ 1,506 $ 481 $ (3,257 ) $ (2,764 )

Pension Benefits
2007 2006 Other Benefits
U.S. Int’l. U.S. Int’l. 2007 2006

Net actuarial loss $ 1,539 $ 1,237 $ 1,892 $ 1,288 $ 490 $ 972
Prior-service costs (credit) (75 ) 203 272 126 (404 ) (485 )

Total recognized at December 31 $ 1,464 $ 1,440 $ 2,164 $ 1,414 $ 86 $ 487

¹ ~~Noncurrent assets are recorded in “Deferred charges and other assets” on the Consolidated Balance Sheet.~~
² ~~The company recorded additional minimum liabilities of $435 and $66 in 2005 for U.S. and international pension plans, respectively.~~
³ “Accumulated other comprehensive loss” in 2005 includes deferred income taxes of $148 and $22 for U.S. and international plans, respectively. This amount is presented net of those taxes in the Consolidated Statement of Stockholders’ Equity.
     The accumulated benefit obligations for all U.S. and international pension plans were $7,712 and $4,000, respectively, at December 31, 2007, and $7,987 and $3,669, respectively, at December 31, 2006.
     Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at December 31, 2007 and 2006, was:

Pension Benefits
2007 2006
U.S. Int’l. U.S. Int’l.

Projected benefit obligations $ 678 $ 1,089 $ 848 $ 849
Accumulated benefit obligations 638 926 806 741
Fair value of plan assets 20 271 12 172

FS-49

Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts

~~NOTE 21.~~Note 20 ~~EMPLOYEE BENEFIT PLANS~~ Employee Benefit Plans – Continued

     Amounts recognized on a before-tax basis in “Accumulated other comprehensive loss” for the company’s pension and other postretirement plans (excludes affiliates) at the end of 2006 after adoption of FAS 158 consisted of:

Pension Benefits Other
2006 Benefits
U.S. Int'l. 2006

Net actuarial loss $ 1,892 $ 1,288 $ 972
Prior-service cost (credit) 272 126 (485 )

Total recognized at December 31 $ 2,164 $ 1,414 $ 487

     ~~The accumulated benefit obligations for all U.S. and international pension plans were $7,987 and $3,669 respectively, at December 31, 2006, and $7,931 and $3,080, respectively, at December 31, 2005.~~
     ~~Information for U.S. and international pension plans with an accumulated benefit obligation in excess of plan assets at December 31, 2006 and 2005, was:~~

Pension Benefits
2006 2005
U.S. Int'l. U.S. Int'l.

Projected benefit obligations $ 848 $ 849 $ 2,132 $ 818
Accumulated benefit obligations 806 741 1,993 632
Fair value of plan assets 12 172 1,206 153

     The components of net periodic benefit cost for 2007, 2006 and 2005 and ~~2004 were:~~amounts recognized in other comprehensive income for 2007 are shown in the table below. For 2007, changes in pension plan assets and benefit obligations were recognized as changes in other comprehensive income.

Pension Benefits Pension Benefits
2006 2005 2004 Other Benefits 2007 2006 2005 Other Benefits
U.S. Int'l. U.S. Int'l. U.S. Int'l. 2006 2005 2004 U.S. Int’l. U.S. Int’l. U.S. Int’l. 2007 2006 2005

Net Periodic Benefit Cost

Service cost $ 234 $ 98 $ 208 $ 84 $ 170 $ 70 $ 35 $ 30 $ 26 $ 260 $ 125 $ 234 $ 98 $ 208 $ 84 $ 49 $ 35 $ 30
Interest cost 468 214 395 199 326 180 181 164 164 483 255 468 214 395 199 184 181 164
Expected return on plan assets (550 ) (227 ) (449 ) (208 ) (358 ) (169 ) – – – (578 ) (266 ) (550 ) (227 ) (449 ) (208 ) – – –
Amortization of transitional assets – 1 – 2 – 1 – – – – – – 1 – 2 – – –
Amortization of prior-service costs 46 14 45 16 42 16 (86 ) (91 ) (47 )
Amortization of prior-service costs (credits) 46 17 46 14 45 16 (81 ) (86 ) (91 )
Recognized actuarial losses 149 69 177 51 114 69 97 93 54 128 82 149 69 177 51 81 97 93
Settlement losses 70 – 86 – 96 4 – – – 65 – 70 – 86 – – – –
Curtailment losses – – – – – 2 – – – – 3 – – – – – – –
Special termination benefits recognition – – – – – 1 – – –

Net periodic benefit cost $ 417 $ 169 $ 462 $ 144 $ 390 $ 174 $ 227 $ 196 $ 197 404 216 417 169 462 144 233 227 196

Changes Recognized in Other Comprehensive Income

Net actuarial (gain) loss during period (160 ) 31 – – – – (401 ) – –
Amortization of actuarial (loss) (193 ) (82 ) – – – – (81 ) – –
Prior service (credit) cost during period (301 ) 97 – – – – – – –
Amortization of prior-service (costs) credits (46 ) (20 ) – – – – 81 – –

Total changes recognized in other comprehensive income (700 ) 26 – – – – (401 ) – –

Recognized in Net Periodic Benefit Cost and Other Comprehensive Income
$ (296 ) $ 242 $ 417 $ 169 $ 462 $ 144 $ (168 ) $ 227 $ 196

     Net actuarial losses recorded in “Accumulated other comprehensive ~~income”~~loss” at December 31, ~~2006, related to~~2007, for the company’s U.S. pension, international pension and other postretirement benefit plans are being amortized on a straight-line basis over approximately ~~nine,~~10, 13 and 10 years, respectively. These amortization periods represent the estimated average remaining service of employees expected to receive benefits under the plans. These losses are amortized to the extent they exceed 10 percent of the higher of the projected benefit obligation or market-related value of plan assets. The amount subject to amortization is determined on a plan-by-plan basis. During ~~2007,~~2008, the company estimates actuarial losses of ~~$139~~$59, $80 and ~~$81~~$39 will be amortized from
~~accumulated~~ “Accumulated other comprehensive ~~income~~loss” for U.S. ~~and~~pension, international pension ~~plans,~~ and ~~actuarial losses of $81 will be amortized from accumulated other comprehensive income for~~ other postretirement benefit plans, respectively. In addition, the company
estimates an additional $78 will be recognized from “Accumulated other comprehensive loss” during 2008 related to lump-sum settlement costs from U.S. pension plans.
     The weighted average amortization period for recognizing prior service costs (credits) recorded in “Accumulated other comprehensive loss” at December 31, ~~2006,~~2007, was approximately ~~six~~nine and 1311 years for U.S. and international pension plans, respectively, and ~~seven~~six years for other postretirement benefit plans. During ~~2007,~~2008, the company estimates prior service (credits) costs of ~~$46~~$(7), $25 and ~~$17~~$(81) will be amortized from ~~accumulated~~“Accumulated other comprehensive ~~income~~loss” for U.S. ~~and~~pension, international pension ~~plans,~~ and ~~prior service credits of $81 will be amortized from accumulated other comprehensive income for~~ other postretirement benefit ~~plans.~~plans, respectively.

FS-50

~~NOTE 21.~~Note 20 ~~EMPLOYEE BENEFIT PLANS~~Employee Benefit Plans – Continued

Assumptions   The following weighted-average assumptions were used to determine benefit obligations and net periodic benefit costs for years ended December 31:

Pension Benefits
2006 2005 2004 Other Benefits
U.S. Int’l. U.S. Int’l. U.S. Int’l. 2006 2005 2004

Assumptions used to determine benefit obligations
Discount rate
5.8 % 6.0 % 5.5 % 5.9 % 5.8 % 6.4 % 5.8 % 5.6 % 5.8 %
Rate of compensation increase 4.5 % 6.1 % 4.0 % 5.1 % 4.0 % 4.9 % 4.5 % 4.0 % 4.1 %
Assumptions used to determine net periodic benefit cost
Discount rate^1,2,3
5.8 % 5.9 % 5.5 % 6.4 % 5.9 % 6.8 % 5.9 % 5.8 % 6.1 %
Expected return on plan assets^1,2
7.8 % 7.4 % 7.8 % 7.9 % 7.8 % 8.3 % N/A N/A N/A
Rate of compensation increase²
4.2 % 5.1 % 4.0 % 5.0 % 4.0 % 4.9 % 4.2 % 4.0 % 4.1 %

Pension Benefits

2007 2006 2005 Other Benefits

U.S. Int’l. U.S. Int’l. U.S. Int’l. 2007 2006 2005

Assumptions used to determine benefit obligations
Discount rate 6.3 % 6.7 % 5.8 % 6.0 % 5.5 % 5.9 % 6.3 % 5.8 % 5.6 %
Rate of compensation increase 4.5 % 6.4 % 4.5 % 6.1 % 4.0 % 5.1 % 4.5 % 4.5 % 4.0 %
Assumptions used to determine net periodic benefit cost
Discount rate^1,2
5.8 % 6.0 % 5.8 % 5.9 % 5.5 % 6.4 % 5.8 % 5.9 % 5.8 %
Expected return on plan assets¹
7.8 % 7.5 % 7.8 % 7.4 % 7.8 % 7.9 % N/A N/A N/A
Rate of compensation increase¹
4.5 % 6.1 % 4.2 % 5.1 % 4.0 % 5.0 % 4.5 % 4.2 % 4.0 %

¹ ~~Discount rate and expected rate of return on plan assets were reviewed and updated as needed on a quarterly basis for the main U.S. pension plan.~~
² The 2005 discount rate, expected return on plan assets and rate of compensation increase reflect the remeasurement of the acquired Unocal benefit plans at July 31, ~~2005, due to the acquisition of Unocal.~~2005.

³² The 2006 U.S. discount rate reflects remeasurement on July 1, 2006, due to plan combinations and changes, primarily ~~merging benefits under~~ several Unocal plans into related Chevron plans.
Expected Return on Plan Assets  The company’s ~~estimates of the~~estimated long-term rate of return on pension assets is driven primarily by actual historical asset-class returns, an assessment of expected future performance, advice from external actuarial firms and the incorporation of specific asset-class risk factors. Asset allocations are periodically updated using pension plan asset/liability studies, and the ~~determination of the~~ company’s ~~estimates of~~estimated long-term rates of return are consistent with these studies.
     There have been no changes in the expected long-term rate of return on plan assets since 2002 for U.S. plans, which account for 7067 percent of the company’s pension plan assets. At December 31, ~~2006,~~2007, the estimated long-term rate of return on U.S. pension plan assets was 7.8 percent.
     The market-related value of assets of the major U.S. pension plan used in the determination of pension expense was based on the market values in the three months preceding the year-end measurement date, as opposed to the maximum allowable period of five years under U.S. accounting rules. Management considers the three-month time period long enough to minimize the effects of distortions from day-to-day market volatility and still be contemporaneous to the end of the year. For other plans, market value of assets as of the measurement date is used in calculating the pension expense.
Discount Rate  The discount rate assumptions used to determine U.S. and international pension and postretirement benefit plan obligations and expense reflect the prevailing rates available on high-quality, fixed-income debt instruments. At December 31, ~~2006,~~2007, the company selected a ~~5.8~~6.3 percent discount rate for the major U.S. pension and postretirement plans. This rate was 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.~~Curve as of year-end 2007. The discount rates at the end of 2006 and 2005 ~~and 2004~~ were ~~5.5~~5.8 percent and ~~5.8~~5.5 percent, respectively.
Other Benefit Assumptions  For the measurement of accumulated postretirement benefit obligation at December 31, ~~2006,~~2007, for the main U.S. postretirement medical plan, the assumed health care cost-trend rates start with 98 percent in ~~2007~~2008 and gradually decline to 5 percent for ~~2011~~2014 and beyond. For this measurement at December 31, ~~2005,~~2006, the assumed health care cost-trend rates started with 109 percent in ~~2006~~2007 and gradually ~~decline~~declined to 5 percent for 2011 and beyond. In both measurements, the annual increase to company contributions was capped at 4 percent.
     Assumed health care cost-trend rates can have a significant effect on the amounts reported for retiree health care costs. The impact is mitigated by the 4 percent cap on the company’s medical contributions for the primary U.S. plan. A one-percentage-point change in the assumed health care cost-trend rates would have the following effects:

1 Percent 1 Percent 1 Percent 1 Percent
Increase Decrease Increase Decrease

Effect on total service and interest cost components $ 8 $ (8 ) $ 9 $ (8 )
Effect on postretirement benefit obligation $ 89 $ (85 ) $ 86 $ (75 )

Plan Assets and Investment Strategy  The company’s pension plan weighted-average asset allocations at December 31 by asset category are as follows:

U.S. International
U.S. International
Asset Category 2006 2005 2006 2005 2007 2006 2007 2006

Equities 68 % 69 % 62 % 60 % 64 % 68 % 56 % 62 %
Fixed Income 21 % 21 % 37 % 39 % 23 % 21 % 43 % 37 %
Real Estate 10 % 9 % 1 % 1 % 12 % 10 % 1 % 1 %
Other 1 % 1 % – – 1 % 1 % – –

Total 100 % 100 % 100 % 100 % 100 % 100 % 100 % 100 %

     The pension plans invest primarily in asset categories with sufficient size, liquidity and cost efficiency to permit investments of reasonable size. The pension plans invest in asset categories that provide diversification benefits and are easily measured. To assess

FS-51

Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts

~~NOTE 21.~~Note 20 ~~EMPLOYEE BENEFIT PLANS~~Employee Benefit Plans – Continued

~~measured. To assess~~ the plans’ investment performance, long-term asset allocation policy benchmarks have been established.
     For the primary U.S. pension plan, the Chevron Board of Directors has ~~established~~approved the following ~~approved asset allocation~~percentage asset-allocation ranges: Equities 40–70, ~~percent,~~ Fixed ~~Income~~Income/Cash 20–60, ~~percent,~~ Real Estate 0–15 ~~percent~~ and Other 0–~~5 percent.~~5. The significant international pension plans also have established maximum and minimum asset allocation ranges that vary by each plan. Actual asset allocation within approved ranges is based on a variety of current economic and market conditions and consideration of specific asset category risk.
     Equities include investments in the company’s common stock in the amount of ~~$17~~$36 and ~~$13~~$17 at December 31, ~~2006~~2007 and ~~2005,~~2006, respectively. The “Other” asset category includes minimal investments in private-equity limited partnerships.
Cash Contributions and Benefit Payments  In ~~2006,~~2007, the company contributed ~~$224~~$78 and ~~$225~~$239 to its U.S. and international pension plans, respectively. In ~~2007,~~2008, the company expects contributions to be approximately $300 and $200 to its U.S. and international pension plans, respectively. Actual contribution amounts are dependent upon plan-investment returns, changes in pension obligations, regulatory environments and other economic factors. Additional funding may ultimately be required if investment returns are insufficient to offset increases in plan obligations.
     The company anticipates paying other postretirement benefits of approximately ~~$223~~$207 in ~~2007,~~2008, as compared with ~~$211~~$150 paid in ~~2006.~~2007.
     The following benefit payments, which include estimated future service, are expected to be paid in the next 10 years:

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

2007 $ 775 $ 206 $ 223
2008 $ 755 $ 228 $ 226 $ 832 $ 238 $ 207
2009 $ 786 $ 237 $ 228 $ 841 $ 272 $ 213
2010 $ 821 $ 253 $ 233 $ 849 $ 282 $ 219
2011 $ 865 $ 249 $ 239 $ 856 $ 279 $ 225
2012–2016 $ 4,522 $ 1,475 $ 1,252
2012 $ 863 $ 296 $ 228
2013–2017 $ 4,338 $ 1,819 $ 1,195

Employee Savings Investment Plan  Eligible employees of Chevron and certain of its subsidiaries participate in the Chevron Employee Savings Investment Plan (ESIP).
     Charges to expense for the ESIP represent the company’s contributions to the plan, which are funded either through the purchase of shares of common stock on the open market or through the release of common stock held in the leveraged employee stock ownership plan (LESOP), which ~~is discussed below.~~follows. Total company matching contributions to employee accounts within the ESIP were $206, $169 and $145 in 2007, 2006 and ~~$139 in 2006,~~ 2005, ~~and 2004,~~ respectively. This cost was reduced by the value of shares released from the LESOP totaling
$33, $6 and $4 in 2007, 2006 and ~~$138 in 2006,~~ 2005, ~~and 2004,~~ respectively. The remaining amounts,
totaling $173, $163 and $141 in 2007, 2006 and ~~$1 in 2006,~~ 2005, ~~and 2004,~~ respectively, represent open market purchases.
Employee Stock Ownership Plan  Within the Chevron ESIP is an employee stock ownership plan (ESOP). In 1989, Chevron established a LESOP as a constituent part of the ESOP. The LESOP provides partial prefunding of the company’s future commitments to the ESIP.
     As permitted by American Institute of Certified Public Accountants (AICPA) Statement of Position 93-6,Employers’ Accounting for Employee Stock Ownership Plans, the company has elected to continue its practices, which are based on AICPA Statement of Position 76-3,Accounting Practices for Certain Employee Stock Ownership Plans, and subsequent consensus of the EITF of the FASB. The debt of the LESOP is recorded as debt, and shares pledged as collateral are reported as “Deferred compensation and benefit plan trust” on the Consolidated Balance Sheet and the Consolidated Statement of Stockholders’ Equity.
     The company reports compensation expense equal to LESOP debt principal repayments less dividends received and used by the LESOP for debt service. Interest accrued on LESOP debt is recorded as interest expense. Dividends paid on LESOP shares are reflected as a reduction of retained earnings. All LESOP shares are considered outstanding for earnings-per-share computations.
     Total (credits) expenses recorded for the LESOP were $(1), $(1) and $94 in 2007, 2006 and ~~$(29) in 2006,~~ 2005, ~~and 2004,~~ respectively, including $16, $17 ~~$18~~ and ~~$23~~$18 of interest expense related to LESOP debt and a (credit) charge to compensation expense of ~~$(18)~~$(17), ~~$76~~$(18) and ~~$(52).~~$76.
     Of the dividends paid on the LESOP shares, $8, $59 ~~$55~~ and ~~$52~~$55 were used in 2007, 2006 ~~2005~~ and ~~2004,~~2005, respectively, to service LESOP debt. The amount in 2006 included $28 of LESOP debt service that was scheduled for payment on the first business day of January 2007 and was paid in late December 2006. ~~Included in the 2004 amount was a repayment of debt entered into in 1999 to pay interest on the ESOP debt. Interest expense on this debt was recognized and reported as LESOP interest expense in 1999.~~ In addition, the company made contributions in 2005 of $98 to satisfy LESOP debt service in excess of dividends received by the LESOP. No contributions were required in ~~2006~~2007 or ~~2004~~2006 as dividends received by the LESOP were sufficient to satisfy LESOP debt service.
     Shares held in the LESOP are released and allocated to the accounts of plan participants based on debt service deemed to be paid in the year in proportion to the total of current year and remaining debt service. LESOP shares as of December 31, ~~2006~~2007 and ~~2005,~~2006, were as follows:

Thousands 2007 2006

Allocated shares 20,506 21,827
Unallocated shares 7,365 8,316

Total LESOP shares 27,871 30,143

FS-52

~~NOTE 21.~~Note 20 ~~EMPLOYEE BENEFIT PLANS~~Employee Benefit Plans – Continued

Thousands 2006 2005

Allocated shares 21,827 23,928
Unallocated shares 8,316 9,163

Total LESOP shares 30,143 33,091

Benefit Plan Trusts  Texaco established a benefit plan trust for funding obligations under some of its benefit plans. At year-end ~~2006,~~2007, the trust contained 14.2 million shares of Chevron treasury stock. The company intends to continue to pay its obligations under the benefit plans. The trust will sell the shares or use the dividends from the shares to pay benefits only to the extent that the company does not pay such benefits. The trustee will vote the shares held in the trust as instructed by the trust’s beneficiaries. The shares held in the trust are not considered outstanding for earnings-per-share purposes until distributed or sold by the trust in payment of benefit obligations.
     Unocal established various grantor trusts to fund obligations under some of its benefit plans, including the deferred compensation and supplemental retirement plans. At December 31, ~~2006~~2007 and ~~2005,~~2006, trust assets of ~~$98~~$69 and ~~$130,~~$98, respectively, were invested primarily in interest-earning accounts.
~~Management~~Employee Incentive Plans  Chevron has two incentive plans, the Management Incentive Plan (MIP) and the Long-Term Incentive Plan (LTIP), for officers and other regular salaried employees of the company and its subsidiaries who hold positions of significant responsibility. ~~The~~ MIP is an annual cash incentive plan that links awards to performance results of the prior year. The cash awards may be deferred by the recipients by conversion to stock units or other investment fund ~~alternatives~~.alternatives. Aggregate charges to expense for MIP were $184, $180 and $155 in 2007, 2006 and ~~$147 in 2006,~~ 2005, ~~and 2004,~~ respectively. Awards under ~~the~~ LTIP consist of stock options and other share-based compensation that are described in Note 2221 below.
~~Other Incentive Plans~~   ~~The~~
     Through 2007 the company ~~has~~had a program that ~~provides~~provided eligible employees, other than those covered by MIP and LTIP, with an annual cash bonus if the company achieves certain financial and safety goals. Charges for the ~~programs~~program were $431, $329 and $324 in 2007, 2006 and ~~$339~~2005, respectively. Effective in ~~2006, 2005~~2008, this program was modified to mirror the design of MIP and ~~2004, respectively.~~both were combined into a single plan named the Chevron Incentive Plan (CIP).
~~NOTE 22.~~Note 21
~~STOCK OPTIONS AND OTHER SHARE-BASED COMPENSATION~~Stock Options and Other Share-Based Compensation
Effective July 1, 2005, the company adopted the provisions of Financial Accounting Standards Board ~~(FASB)~~ Statement No. 123R,Share-Based Payment(FAS 123R),for its share-based compensation plans. The company previously accounted for these plans under the recognition and measurement principles of Accounting Principles Board Opinion No. 25,Accounting for Stock Issued to Employees, and related interpretations and ~~dis-~~
~~closure~~disclosure requirements established by FASB Statement No. 123,Accounting for Stock-Based Compensation~~(FAS 123)~~.
     The company adopted FAS 123R using the modified prospective method and, accordingly, results for prior periods were
not restated. Refer to Note 1, beginning on page FS-32, for the pro forma effect on net income and earnings per share as if the company had applied the fair-value recognition provisions of FAS ~~123~~123R for ~~periods prior to adoption of FAS 123R.~~the full year 2005.
     For 2007, 2006 and 2005, compensation expense ~~charged against income~~ for stock options was $146 ($95 after tax), $125 ($81 after tax) and $65 ($42 after tax), respectively. In addition, compensation expense ~~charged against income~~ for stock appreciation rights, performance units and restricted stock units was $205 ($133 after tax), $113 ($73 after tax), and $59 ($39 after tax) for 2007, 2006 and ~~$65 ($42 after tax) for 2006,~~ 2005, ~~and 2004,~~ respectively. There were no significant stock-based compensation costs that were capitalized at December 31, ~~2006~~2007 and ~~2005, that were capitalized.~~2006.
     Cash received ~~from~~in payment for option exercises under all share-based payment arrangements for 2007, 2006 and 2005 was $445, $444 and ~~2004 was $444,~~ $297, ~~and $385,~~ respectively. Actual tax benefits realized for the tax deductions from option exercises were $94, $91 and $71 for 2007, 2006 and ~~$49 for 2006,~~ 2005, ~~and 2004,~~ respectively.
     Cash paid to settle performance units and stock appreciation rights was $88, $68 and $110 for 2007, 2006 and ~~$23 for 2006,~~ 2005, ~~and 2004,~~ respectively. Cash paid in 2005 included $73 ~~million~~ for Unocal awards paid under change-in-control plan provisions.
     The company presents the tax benefits of deductions from the exercise of stock options as financing cash inflows in the Consolidated Statement of Cash Flows. In ~~the second quarter~~ 2006, the company implemented the transition method of FASB Staff Position FAS 123R-3,Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards, for calculating the beginning balance of the pool of excess tax benefits related to employee compensation and determining the subsequent impact on the pool of employee awards that were fully vested and outstanding upon the adoption of FAS 123R. The company’s reported tax expense for the period subsequent to the implementation of FAS 123R was not affected by this election. Refer to Note 3, ~~beginning~~ on page FS-35, for information on excess tax benefits reported on the company’s Statement of Cash Flows.
     ~~In the discussion below, the references to share price and number of shares have been adjusted for the two-for-one stock split in September 2004.~~
Chevron Long-Term Incentive Plan (LTIP)  Awards under the LTIP may take the form of, but are not limited to, stock options, restricted stock, restricted stock units, stock appreciation rights, performance units and ~~non-stock~~nonstock grants. From April 2004 through January 2014, no more than 160 million shares may be issued under the LTIP, and no more than 64 million of those shares may be in a form other than a stock

~~FS-53~~
~~Notes to the Consolidated Financial Statements~~
~~Millions of dollars, except per-share amounts~~

~~NOTE 22.~~ ~~STOCK OPTIONS AND OTHER SHARE-BASED~~
~~COMPENSATION – Continued~~
option, stock appreciation right or award requiring full payment for shares by the award recipient.
     Stock options and stock appreciation rights granted under the LTIP extend for 10 years from grant date. Effective with options granted in June 2002, one-third of each award vests on the first, second and third anniversaries of the date of grant. Prior to this change, options ~~granted by Chevron~~ vested one year after the date of grant.

FS-53
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts

Note 21Stock Options and Other Share-Based Compensation – Continued
Performance units granted under the LTIP settle in cash at the end of a three-year performance period. Settlement amounts are based on achievement of performance targets relative to major competitors over the period, and payments are indexed to the company’s stock price.
Texaco Stock Incentive Plan (Texaco SIP)  On the closing of the acquisition of Texaco in October 2001, outstanding options granted under the Texaco SIP were converted to Chevron options. These options, which have 10-year contractual lives extending into 2011, retained a provision for being ~~restored, which~~restored. This provision enables a participant who exercises a stock option to receive new options equal to the number of shares exchanged or who has shares withheld to satisfy tax withholding obligations to receive new options equal to the number of shares exchanged or withheld. The restored options are fully exercisable six months after the date of grant, and the exercise price is the market value of the common stock on the day the restored option is granted. ~~Apart from the~~Beginning in 2007, restored options nowere granted under the LTIP. No further awards may be granted under the former Texaco plans.
Unocal Share-Based Plans (Unocal Plans)  ~~On the closing of the acquisition of~~When Chevron acquired Unocal in August 2005, outstanding stock options and stock appreciation rights granted under various Unocal Plans were exchanged for fully vested Chevron options and appreciation ~~rights at a conversion ratio of 1.07 Chevron shares for each Unocal share.~~rights. These awards retained the same provisions as the original Unocal Plans. Awards issued prior to 2004 generally may be exercised for up to three years after termination of employment (depending upon the terms of the individual award agreements) or the original expiration date, whichever is earlier. Awards issued since 2004 generally ~~remain~~remained exercisable until the end of the normal option term if termination of employment ~~occurs~~occurred prior to August 10, 2007. Other awards issued under the Unocal Plans, including restricted stock, stock units, restricted stock units and performance shares, became vested at the acquisition date, and shares or cash were issued to recipients in accordance with change-in-control provisions of the plans.

The fair market values of stock options and stock appreciation rights granted in 2007, 2006 ~~2005~~ and ~~2004~~2005 were measured on the date of grant using the Black-Scholes option-pricing model, with the following weighted-average assumptions:

Year ended December 31 Year ended December 31
2006 2005 2004 2007 2006 2005

Chevron LTIP

Stock Options

Expected term in years¹
6.4 6.4 7.0 6.3 6.4 6.4
Volatility²
23.7 % 24.5 % 16.5 % 22.0 % 23.7 % 24.5 %
Risk-free interest rate based on zero coupon U.S. treasury note 4.7 % 3.8 % 4.4 % 4.5 % 4.7 % 3.8 %
Dividend yield 3.1 % 3.4 % 3.7 % 3.2 % 3.1 % 3.4 %
Weighted-average fair value per option granted $ 12.74 $ 11.66 $ 7.14 $ 15.27 $ 12.74 $ 11.66
Texaco SIP

Restored Options

Expected term in years¹
2.2 2.1 2.0 1.6 2.2 2.1
Volatility²
19.6 % 18.6 % 17.8 % 21.2 % 19.6 % 18.6 %
Risk-free interest rate based on zero coupon U.S. treasury note 4.8 % 3.8 % 2.5 % 4.5 % 4.8 % 3.8 %
Dividend yield 3.3 % 3.4 % 3.8 % 3.2 % 3.3 % 3.4 %
Weighted-average fair value per option granted $ 7.72 $ 6.09 $ 4.00 $ 8.61 $ 7.72 $ 6.09

Unocal Plans³

Expected term in years¹
– 4.2 – – – 4.2
Volatility²
– 21.6 % – – – 21.6 %
Risk-free interest rate based on zero coupon U.S. treasury note – 3.9 % – – – 3.9 %
Dividend yield – 3.4 % – – – 3.4 %
Weighted-average fair value per option granted – $ 21.48 – – – $ 21.48

¹ Expected term is based on historical exercise and post-vesting cancellation data.

² Volatility rate is based on historical stock prices over an appropriate period, generally equal to the expected term.

³ ~~Represents~~Represent options converted at the acquisition date.
     A summary of option activity during ~~2006~~2007 is presented below:

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

Outstanding at January 1, 2006
59,524 $ 45.32
Outstanding at January 1, 2007
55,945 $ 47.91
Granted 9,248 $ 56.64 12,848 $ 74.08
Exercised (14,921 ) $ 46.11 (14,340 ) $ 51.92
Restored 4,002 $ 64.13 3,458 $ 80.45
Forfeited (1,908 ) $ 57.09 (554 ) $ 72.36
Outstanding at December 31, 2006
55,945 $ 47.91 6.0 yrs. $ 1,433
Outstanding at December 31, 2007
57,357 $ 54.50 6.3 yrs. $ 2,227

Exercisable at December 31, 2006
37,063 $ 43.56 5.1yrs. $ 1,111
Exercisable at December 31, 2007
35,540 $ 45.93 5.1 yrs. $ 1,685

     The total intrinsic value (i.e., the difference between the exercise price and the market price) of options exercised during 2007, 2006 and 2005 was $423, $281 and ~~2004 was $281,~~ $258, ~~and $129,~~ respectively.
     AtUpon adoption of FAS 123R, the company elected to amortize newly issued graded awards on a straight-line basis over the requisite service period. In accordance with FAS 123R implementation guidance issued by the staff of the Securities and Exchange Commission, the company accelerates the ~~vest-~~vesting

FS-54

~~NOTE 22.~~Note 21 ~~STOCK OPTIONS AND OTHER SHARE-BASED~~
~~COMPENSATION~~Stock Options and Other Share-Based Compensation – Continued

~~ing~~
period for retirement-eligible employees in accordance with vesting provisions of the company’s share-based compensation programs for awards issued after adoption of FAS 123R. As of December 31, ~~2006,~~2007, there was ~~$99~~$160 of total unrecognized before-tax compensation cost related to nonvested share-based compensation arrangements granted or restored under the plans. That cost is expected to be recognized over a weighted-average period of ~~2.0~~two years.
     At January 1, ~~2006,~~2007, the number of LTIP performance units outstanding was equivalent to ~~2,346,016~~2,110,196 shares. During ~~2006, 709,200~~2007, 931,200 units were granted, ~~827,450~~784,364 units vested with cash proceeds distributed to recipients and ~~117,570~~32,017 units were forfeited. At December 31, ~~2006,~~2007, units outstanding were ~~2,110,196,~~2,225,015, and the fair value of the liability recorded for these instruments was ~~$113.~~$205. In addition, outstanding stock appreciation rights and other awards that were ~~awarded~~granted under various LTIP and former Texaco and Unocal programs totaled approximately ~~700,000~~1 million equivalent shares as of December 31, ~~2006.~~2007. A liability of ~~$16~~$38 was recorded for these awards.
Broad-Based Employee Stock Options   In addition to the plans described above, Chevron granted all eligible employees stock options or equivalents in 1998. The options vested ~~after two years,~~ in February 2000 and ~~expire after 10 years,~~expired in February 2008. A total of 9,641,600 options were awarded with an exercise price of $38.16 per share.
     The fair value of each option on the date of grant was estimated at $9.54 using the Black-Scholes model for the preceding 10 years. The assumptions used in the model, based on a 10-year average, were: a risk-free interest rate of 7 percent, a dividend yield of 4.2 percent, an expected life of seven years and a volatility of 24.7 percent.
     At January 1, ~~2006,~~2007, the number of broad-based employee stock options outstanding was ~~1,682,904.~~1,306,059. During ~~2006,~~2007, exercises of ~~354,845~~637,044 shares and forfeitures of ~~22,000~~16,300 shares reduced outstanding options to ~~1,306,059.~~652,715. As of December 31, ~~2006,~~2007, these instruments had an aggregate intrinsic value of ~~$46~~$36 and the remaining contractual term of these options was ~~1.1 years.~~0.1 year. The total intrinsic value of these options exercised during 2007, 2006 and 2005 was $30, $10 and ~~2004 was $10,~~ $9, ~~and $16,~~ respectively.
~~NOTE 23.~~Note 22
~~OTHER CONTINGENCIES AND COMMITMENTS~~Other Contingencies and Commitments
Income Taxes   The company calculates its income tax expense and liabilities quarterly. These liabilities generally are subject to audit and are not finalized with the individual taxing authorities until several years after the end of the annual period for which income taxes have been calculated. Refer to Note 15 beginning on page FS-43 for a discussion of the periods for which tax returns have been audited for the company’s major tax jurisdictions and a discussion for all tax jurisdictions of the differences between the amount of tax benefits recognized in the financial statements and the amount taken or expected to be taken in a tax return. The ~~U.S. federal~~company does not expect
settlement of income tax liabilities ~~have been settled through 1996 for Chevron Corporation, 1997 for Unocal Corporation (Unocal) and 2001 for Texaco Corporation (Texaco). California franchise~~associated with uncertain 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 topositions will have a material effect on ~~the~~its results of operations, consolidated financial position or ~~liquidity~~liquidity.
Guarantees   The company’s guarantee of approximately $600 is associated with certain payments under a terminal use agreement entered into by a company affiliate. The terminal is expected to be operational by 2012. Over the approximate 16-year term of the ~~company and, in~~guarantee, the ~~opinion of management, adequate provision has been made for income and franchise taxes for all years under examination or subject to future examination.~~
~~Guarantees~~   ~~At December 31, 2006,~~maximum guarantee amount will reduce over time as certain fees are paid by the company and its subsidiaries provided guarantees, either directly or indirectly, of $296 for notes and other contractual obligations of affiliated companies and $131 for third parties, as described by major category below.affiliate. There are ~~no amounts being carried as liabilities for the company’s obligations under these guarantees.~~
     The $296 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 associated with a construction completion guarantee for the debt financing of the company’s equity interest in the Baku-Tbilisi-Ceyhan (BTC) crude oil pipeline project. Substantially all of the $296 guaranteed will expire between 2007 and 2011,numerous cross-indemnity agreements with the ~~remaining expiring by~~affiliate and the ~~end~~other partners to permit recovery 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~~any amounts ~~disclosed.~~
     The $131 in guarantees provided on behalf of third parties related to construction loans to governments of certain of the company’s international upstream operations. Substantially all of the $131 in guarantees expire by 2011, with the remainder expiring by 2015. The company would be required to performpaid 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,~~guarantee. Chevron also had outstanding guarantees for about $120 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 acarries no 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.~~
its obligation under this guarantee.
Indemnifications   The company provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell and Saudi Refining, Inc., in connection with the February 2002 sale of the company’s interests in those investments. The company would be required to perform if the indemnified liabilities become actual losses. Were that to occur, the company could be required to make future payments up to $300.

~~FS-55~~
~~Notes to the Consolidated Financial Statements~~
~~Millions of dollars, except per-share amounts~~

~~NOTE 23.~~ ~~OTHER CONTINGENCIES AND COMMITMENTS – Continued~~
Through the end of ~~2006,~~2007, the company paid ~~approximately~~ $48 under these indemnities and continues to be obligated for possible additional indemnification payments in the future.
     The company has also provided indemnities relating to contingent environmental liabilities related to assets originally contributed by Texaco to the Equilon and Motiva joint ventures and environmental conditions that existed prior to the formation of Equilon and Motiva or that occurred during the period of Texaco’s ownership interest in the joint ventures. In general, the environmental conditions or events that are subject to these indemnities must have arisen prior to December 2001. Claims ~~relating to Equilon indemnities~~ must be asserted ~~either as early as February 2007, or~~ no later than February 2009 ~~and claims relating to Motiva~~for Equilon indemnities ~~must be asserted either as early as February 2007, or~~and no later than February ~~2012.~~2012 for Motiva indemnities. 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~~indemnification expires. The acquirer shares in certain environmental remediation costs up to a maximum obligation of $200, which had not been reached as of December 31, ~~2006.~~2007.

FS-55
Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts

Note 22Other Contingencies and Commitments – Continued
Securitization   ~~The~~   During 2007, the company ~~securitizes certain~~completed the sale of its U.S. proprietary consumer credit card business and related receivables. This transaction included terminating the qualifying Special Purpose Entity (SPE) that was used to securitize associated retail ~~and~~accounts receivable.
     Through the use of another qualifying SPE, the company had $675 of securitized trade accounts receivable inrelated to its downstream business ~~through the use~~as of ~~qualifying Special Purpose Entities (SPEs). At~~ December 31, 2006, approximately $1,200, representing about 7 percent of Chevron’s total current accounts and notes receivables balance, were securitized. Chevron’s total estimated financial exposure under these securitizations at December 31, 2006, was approximately $80. These arrangements have2007. This arrangement has the effect of accelerating Chevron’s collection of the securitized amounts. Chevron’s total estimated financial exposure under this securitization at December 31, 2007, was $65. In the event that the ~~SPEs experience~~SPE experiences major defaults in the collection of receivables, Chevron believes that it would have no additional loss exposure connected with third-party investments in ~~these securitizations.~~
this securitization.
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 – $3,200;~~ 2008 – ~~$1,700;~~$4,700; 2009 – ~~$2,100;~~$3,300; 2010 – ~~$1,900;~~$3,300; 2011 – ~~$900;~~$1,900; 2012 – $1,300; 2013 and after – ~~$4,100.~~$4,900. A portion of these commitments may ultimately be shared with project partners. Total payments under the agreements were approximately $3,700 in 2007, $3,000 in 2006 and $2,100 in ~~2005 and $1,600 in 2004.~~2005.
Minority Interests  The company has commitments of ~~$209~~$204 related to minority interests in subsidiary companies.
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, land development areas, and mining operations, whether operating, closed or divested. These future costs are not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions that may be required, the determination of the company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.
     Although the company has provided for known environmental obligations that are probable and reasonably estimable, the amount of additional future costs may be material to results of operations in the period in which they are recognized. The company does not expect these costs will have a material effect on its consolidated financial position or liquidity. Also, the company does not believe its obligations to make such expenditures have had, or will have, any significant impact on the company’s competitive position relative to other U.S. or international petroleum or chemical companies.
     Chevron’s environmental reserve as of December 31, ~~2006,~~2007, was ~~$1,441.~~$1,539. Included in this balance were remediation activities of ~~242~~240 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

~~FS-56~~

~~NOTE 23.~~ ~~OTHER CONTINGENCIES AND COMMITMENTS – Continued~~
reserve for these sites at year-end ~~2006~~2007 was ~~$122.~~$123. The federal Superfund law and analogous state laws provide for joint and several liability for all responsible parties. Any future actions by the EPA or other regulatory agencies to require Chevron to assume other potentially responsible parties’ costs at designated hazardous waste sites are not expected to have a material effect on the company’s results of operations, consolidated financial position or liquidity.
     Of the remaining year-end ~~2006~~2007 environmental reserves balance of ~~$1,319, $834~~$1,416, $864 related to approximately ~~2,250~~2,000 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~~$552 was associated with various sites in the international downstream ($~~117)~~146), upstream ($~~252)~~267), chemicals ($~~61)~~105) and other ($~~55)~~34). 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~~2007 had a recorded liability that was material to the company’s ~~financial position,~~ results of operations, consolidated financial position or liquidity.
     It is likely that the company will continue to incur additional liabilities, beyond those recorded, for environmental remediation relating to past operations. These future costs are not fully determinable due to such factors as the unknown magnitude

FS-56

Note 22Other Contingencies and Commitments – Continued
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 $5,800 for asset retirement obligations at year-end 2006 related primarily to upstream and mining properties. Refer to Note ~~24 on page FS-58~~23 below 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.
~~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.
     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.
Equity RedeterminationFor 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,

~~FS-57~~
~~Notes to the Consolidated Financial Statements~~
~~Millions of dollars, except per-share amounts~~

~~NOTE 23.~~ ~~OTHER CONTINGENCIES AND COMMITMENTS – Continued~~
Chevron estimates its maximum possible net before-tax liability at approximately $200, and the possible maximum net amount that could be owed to Chevron is estimated at about $150. The timing of the settlement and the exact amount within this range of estimates are uncertain.
Other ContingenciesChevron receives claims from and submits claims to ~~customers,~~customers; trading ~~partners,~~partners; U.S. federal, state and local regulatory ~~bodies, governments, contractors, insurers,~~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.
~~NOTE 24.~~Note 23
~~ASSET RETIREMENT OBLIGATIONS~~Asset Retirement Obligations
The company accounts for asset retirement obligations (ARO) in accordance with Financial Accounting Standards Board Statement (FASB) No. 143,Accounting for Asset Retirement Obligations~~, (FAS~~(FAS 143). This accounting standard applies to the fair value of a liability for an ~~asset retirement obligation (ARO)~~ARO that is recorded when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. Obligations associated with the retirement of these assets require recognition in certain circumstances: (1) the present value of a liability and offsetting asset for an ARO, (2) the subsequent accretion of that liability
and depreciation of the asset, and (3) the periodic review of the ARO liability estimates and discount rates. In 2005, the FASB issued FASB Interpretation No. 47,Accounting for Conditional Asset Retirement Obligations – An Interpretation of FASB Statement No. 143~~, (FIN~~(FIN 47), which was effective for the company on December 31, 2005. FIN 47 clarifies that the phrase “conditional asset retirement obligation,” as used in FAS 143, refers to a legal obligation to perform asset retirement activity for which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the company. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Uncertainty about the timing and/or method of settlement of a conditional ARO should be factored into the measurement of the liability when sufficient information exists. FAS 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an ARO. FIN 47 also clarifies when an entity would have sufficient information to reasonably
estimate the fair value of an ARO. In adopting FIN 47, the company did not recognize any additional liabilities for conditional AROs due to an inability to reasonably estimate the fair value of those obligations because of their indeterminate settlement dates.
     FAS 143 and FIN 47 primarily affect the company’s accounting for crude oil and natural gas producing assets. No significant AROs associated with any legal obligations to retire refining, marketing and transportation (downstream) and chemical long-lived assets have been recognized, as indeterminate settlement dates for the asset retirements ~~prevented~~prevent estimation of the fair value of the associated ARO. The company performs periodic reviews of its downstream and chemical long-lived assets for any changes in facts and circumstances that might require recognition of a retirement obligation.
     The following table indicates the changes to the company’s before-tax asset retirement obligations in 2007, 2006 ~~2005~~ and ~~2004:~~2005:

2006 2005 2004

Balance at January 1 $ 4,304 $ 2,878 $ 2,856
Liabilities assumed in the Unocal acquisition – 1,216 –
Liabilities incurred 153 90 37
Liabilities settled (387 ) (172 ) (426 )
Accretion expense 275 187 93
Revisions in estimated cash flows 1,428 * 105 318

Balance at December 31 $ 5,773 $ 4,304 $ 2,878

* ~~Includes $1,128 associated with estimated costs to dismantle and abandon wells and facilities damaged by the 2005 hurricanes in the Gulf of Mexico.~~
~~NOTE 25.~~
~~COMMON STOCK SPLIT~~

2007 2006 2005

Balance at January 1 $ 5,773 $ 4,304 $ 2,878
Liabilities assumed in the Unocal acquisition – – 1,216
Liabilities incurred 178 153 90
Liabilities settled (818 ) (387 ) (172 )
Accretion expense 399 * 275 187
Revisions in estimated cash flows 2,721 1,428 105

Balance at December 31 $ 8,253 $ 5,773 $ 4,304

*Includes $175 for revision to the ARO liability retained on properties that had been sold.
In ~~September 2004,~~ the ~~company effected a two-for-one stock split~~table above, the amounts for 2007 and 2006 associated with “Revisions in ~~the form of a stock dividend. The total number of authorized common stock shares~~estimated cash flows” reflect increasing costs to abandon onshore and associated par value were unchanged by this action. All per-share amounts in the financial statements reflect the stock split for all periods presented. The effect of the common stock split is reflected on the Consolidated Balance Sheet in “Common stock”offshore wells, equipment and ~~“Capital in excess of par value.”~~facilities,

~~FS-58~~FS-57

Notes to the Consolidated Financial Statements
Millions of dollars, except per-share amounts

Note 23Asset Retirement Obligations – Continued

including $1,128 in 2006 for the estimated costs to dismantle and abandon wells and facilities damaged by 2005 hurricanes in the Gulf of Mexico. The long-term portion of the $8,253 balance at the end of 2007 was $7,555.
~~NOTE 26.~~Note 24
~~OTHER FINANCIAL INFORMATION~~Other Financial Information
Net income in ~~2004~~2007 included gains of approximately ~~$1,200~~$2,000 relating to the sale of nonstrategic ~~upstream~~ properties. Of this amount, ~~$257~~approximately $1,100 related to downstream assets ~~classified as discontinued operations.~~and $680 related to the sale of the company’s investment in Dynegy Inc.
     Other financial information is as follows:

Year ended December 31 Year ended December 31
2006 2005 2004 2007 2006 2005

Total financing interest and debt costs $ 608 $ 542 $ 450 $ 468 $ 608 $ 542
Less: Capitalized interest 157 60 44 302 157 60

Interest and debt expense $ 451 $ 482 $ 406 $ 166 $ 451 $ 482

Research and development expenses $ 468 $ 316 $ 242 $ 562 $ 468 $ 316
Foreign currency effects* $ (219 ) $ (61 ) $ (81 ) $ (352 ) $ (219 ) $ (61 )

*Includes $18, $15 and $(2) in 2007, 2006 and ~~$(13) in 2006,~~ 2005, ~~and 2004,~~ respectively, for the company’s share of equity affiliates’ foreign currency effects.
     The excess of ~~market value~~replacement cost over the carrying value of inventories for which the Last-In, First-Out (LIFO) method is used was ~~$6,010, $4,846~~$6,958 and ~~$3,036~~$6,010 at December 31, 2007 and 2006, ~~2005 and 2004,~~ respectively. ~~Market value~~Replacement cost is generally based on average acquisition costs for the year. LIFO profits of $113, $82 ~~$34~~ and ~~$36~~$34 were included in net income for the years 2007, 2006 ~~2005~~ and ~~2004,~~2005, respectively.
~~NOTE 27.~~Note 25
~~EARNINGS PER SHARE~~Earnings Per Share
Basic earnings per share (EPS) is based upon net income less preferred stock dividend requirements and includes the effects of deferrals of salary and other compensation awards that are invested in Chevron stock units by certain officers and employees of the company and the company’s share of stock transactions of affiliates, which, under the applicable accounting rules, may be recorded directly to the company’s retained earnings instead of net income. Diluted EPS includes the effects of these items as well as the dilutive effects of outstanding stock options awarded under the company’s stock option programs (refer to Note ~~22,~~21, “Stock Options and Other Share-Based Compensation” beginning on page FS-53). The table ~~on the following page~~below sets forth the computation of basic and diluted EPS:

Year ended December 31
2007 2006 2005

Basic EPS Calculation

Income from operations $ 18,688 $ 17,138 $ 14,099
Add: Dividend equivalents paid on stock units – 1 2

Net income available to common stockholders – Basic $ 18,688 $ 17,139 $ 14,101

Weighted-average number of common shares outstanding 2,117 2,185 2,143
Add: Deferred awards held as stock units 1 1 1

Total weighted-average number of common shares outstanding 2,118 2,186 2,144

Per share of common stock
Net income – Basic $ 8.83 $ 7.84 $ 6.58

Diluted EPS Calculation

Income from operations $ 18,688 $ 17,138 $ 14,099
Add: Dividend equivalents paid on stock units – 1 2
Add: Dilutive effects of employee stock-based awards – – 2

Net income available to common stockholders – Diluted $ 18,688 $ 17,139 $ 14,103

Weighted-average number of common shares outstanding 2,117 2,185 2,143
Add: Deferred awards held as stock units 1 1 1
Add: Dilutive effect of employee stock-based awards 14 11 11

Total weighted-average number of common shares outstanding 2,132 2,197 2,155

Per share of common stock
Net income – Diluted $ 8.77 $ 7.80 $ 6.54

~~FS-59~~
~~Notes to the Consolidated Financial Statements~~
~~Millions of dollars, except per-share amounts~~

~~NOTE 27.~~~~EARNINGS PER SHARE – Continued~~

Year ended December 31
2006 2005 2004

BASIC EPS CALCULATION

Income from continuing operations $ 17,138 $ 14,099 $ 13,034
Add: Dividend equivalents paid on stock units 1 2 3

Income from continuing operations available to common stockholders $ 17,139 $ 14,101 $ 13,037
Income from discontinued operations – – 294

Net income available to common stockholders – Basic $ 17,139 $ 14,101 $ 13,331

Weighted-average number of common shares outstanding* 2,185 2,143 2,114
Add: Deferred awards held as stock units 1 1 2

Total weighted-average number of common shares outstanding 2,186 2,144 2,116

Per share of common stock
Income from continuing operations available to common stockholders $ 7.84 $ 6.58 $ 6.16
Income from discontinued operations – – 0.14

Net income – Basic $ 7.84 $ 6.58 $ 6.30

DILUTED EPS CALCULATION

Income from continuing operations $ 17,138 $ 14,099 $ 13,034
Add: Dividend equivalents paid on stock units 1 2 3
Add: Dilutive effects of employee stock-based awards – 2 1

Income from continuing operations available to common stockholders $ 17,139 $ 14,103 $ 13,038
Income from discontinued operations – – 294

Net income available to common stockholders – Diluted $ 17,139 $ 14,103 $ 13,332

Weighted-average number of common shares outstanding* 2,185 2,143 2,114
Add: Deferred awards held as stock units 1 1 2
Add: Dilutive effect of employee stock-based awards 11 11 6

Total weighted-average number of common shares outstanding 2,197 2,155 2,122

Per share of common stock
Income from continuing operations available to common stockholders $ 7.80 $ 6.54 $ 6.14
Income from discontinued operations – – 0.14

Net income – Diluted $ 7.80 $ 6.54 $ 6.28

* ~~Share amounts in all periods reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.~~
~~FS-60~~FS-58
~~This page intentionally left blank.~~THIS PAGE INTENTIONALLY LEFT BLANK
~~FS-61~~FS-59
~~FIVE-YEAR FINANCIAL SUMMARY~~Five-Year Financial Summary
Unaudited

Millions of dollars, except per-share amounts 2006 2005 2004 2003 2002

COMBINED STATEMENT OF INCOME DATA

REVENUES AND OTHER INCOME

Total sales and other operating revenues $ 204,892 $ 193,641 $ 150,865 $ 119,575 $ 98,340
Income from equity affiliates and other income 5,226 4,559 4,435 1,702 197

TOTAL REVENUES AND OTHER INCOME
210,118 198,200 155,300 121,277 98,537
TOTAL COSTS AND OTHER DEDUCTIONS
178,142 173,003 134,749 108,601 94,437

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
31,976 25,197 20,551 12,676 4,100
INCOME TAX EXPENSE
14,838 11,098 7,517 5,294 2,998

INCOME FROM CONTINUING OPERATIONS
17,138 14,099 13,034 7,382 1,102
INCOME FROM DISCONTINUED OPERATIONS
– – 294 44 30

INCOME BEFORE EXTRAORDINARY ITEM AND

CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES
17,138 14,099 13,328 7,426 1,132
Cumulative effect of changes in accounting principles – – – (196 ) –

NET INCOME
$ 17,138 $ 14,099 $ 13,328 $ 7,230 $ 1,132

PER SHARE OF COMMON STOCK¹

INCOME FROM CONTINUING OPERATIONS²

– Basic $ 7.84 $ 6.58 $ 6.16 $ 3.55 $ 0.52
– Diluted $ 7.80 $ 6.54 $ 6.14 $ 3.55 $ 0.52
INCOME FROM DISCONTINUED OPERATIONS

– Basic $ – $ – $ 0.14 $ 0.02 $ 0.01
– Diluted $ – $ – $ 0.14 $ 0.02 $ 0.01
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES

– Basic $ – $ – $ – $ (0.09 ) $ –
– Diluted $ – $ – $ – $ (0.09 ) $ –
NET INCOME²

– Basic $ 7.84 $ 6.58 $ 6.30 $ 3.48 $ 0.53
– Diluted $ 7.80 $ 6.54 $ 6.28 $ 3.48 $ 0.53

CASH DIVIDENDS PER SHARE
$ 2.01 $ 1.75 $ 1.53 $ 1.43 $ 1.40

COMBINED BALANCE SHEET DATA (AT DECEMBER 31)

Current assets $ 36,304 $ 34,336 $ 28,503 $ 19,426 $ 17,776
Noncurrent assets 96,324 91,497 64,705 62,044 59,583

TOTAL ASSETS
132,628 125,833 93,208 81,470 77,359

Short-term debt 2,159 739 816 1,703 5,358
Other current liabilities 26,250 24,272 17,979 14,408 14,518
Long-term debt and capital lease obligations 7,679 12,131 10,456 10,894 10,911
Other noncurrent liabilities 27,605 26,015 18,727 18,170 14,968

TOTAL LIABILITIES
63,693 63,157 47,978 45,175 45,755

STOCKHOLDERS’ EQUITY
$ 68,935 $ 62,676 $ 45,230 $ 36,295 $ 31,604

Millions of dollars, except per-share amounts 2007 2006 2005 2004 2003

Statement of Income Data

Revenues and Other Income

Total sales and other operating revenues^1,2
$ 214,091 $ 204,892 $ 193,641 $ 150,865 $ 119,575
Income from equity affiliates and other income 6,813 5,226 4,559 4,435 1,702

Total Revenues and Other Income
220,904 210,118 198,200 155,300 121,277
Total Costs and Other Deductions
188,737 178,142 173,003 134,749 108,601

Income From Continuing Operations Before Income Taxes
32,167 31,976 25,197 20,551 12,676
Income Tax Expense
13,479 14,838 11,098 7,517 5,294

Income From Continuing Operations
18,688 17,138 14,099 13,034 7,382
Income From Discontinued Operations
– – – 294 44

Income Before

Cumulative Effect of Changes in Accounting Principles
18,688 17,138 14,099 13,328 7,426
Cumulative effect of changes in accounting principles – – – – (196 )

Net Income
$ 18,688 $ 17,138 $ 14,099 $ 13,328 $ 7,230

Per Share of Common Stock³

Income From Continuing Operations⁴

– Basic $ 8.83 $ 7.84 $ 6.58 $ 6.16 $ 3.55
– Diluted $ 8.77 $ 7.80 $ 6.54 $ 6.14 $ 3.55
Income From Discontinued Operations

– Basic $ – $ – $ – $ 0.14 $ 0.02
– Diluted $ – $ – $ – $ 0.14 $ 0.02
Cumulative Effect of Changes in Accounting Principles

– Basic $ – $ – $ – $ – $ (0.09 )
– Diluted $ – $ – $ – $ – $ (0.09 )
Net Income²

– Basic $ 8.83 $ 7.84 $ 6.58 $ 6.30 $ 3.48
– Diluted $ 8.77 $ 7.80 $ 6.54 $ 6.28 $ 3.48

Cash Dividends Per Share
$ 2.26 $ 2.01 $ 1.75 $ 1.53 $ 1.43

Balance Sheet Data (at December 31)

Current assets $ 39,377 $ 36,304 $ 34,336 $ 28,503 $ 19,426
Noncurrent assets 109,409 96,324 91,497 64,705 62,044

Total Assets
148,786 132,628 125,833 93,208 81,470

Short-term debt 1,162 2,159 739 816 1,703
Other current liabilities 32,636 26,250 24,272 17,979 14,408
Long-term debt and capital lease obligations 6,070 7,679 12,131 10,456 10,894
Other noncurrent liabilities 31,830 27,605 26,015 18,727 18,170

Total Liabilities
71,698 63,693 63,157 47,978 45,175

Stockholders’ Equity
$ 77,088 $ 68,935 $ 62,676 $ 45,230 $ 36,295

¹ Includes excise, value-added and similar taxes:
$ 10,121 $ 9,551 $ 8,719 $ 7,968 $ 7,095
² Includes amounts in revenues for buy/sell contracts; associated costs are in “Total Costs and Other Deductions.” Refer also to Note 13, on page FS-42.
$ – $ 6,725 $ 23,822 $ 18,650 $ 14,246
³ Per-share amounts in all periods reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.
⁴ The amount in 2003 includes a benefit of $0.08 for the company’s share of a capital stock transaction of its Dynegy affiliate, which, under the applicable accounting rules, was recorded directly to retained earnings and not included in net income for the period.
¹ ~~Per-share amounts in all periods reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.~~
² The amount in 2003 includes a benefit of $0.08 for the company’s share of a capital stock transaction of its Dynegy affiliate, which, under the applicable accounting rules, was recorded directly to retained earnings and not included in net income for the period.
~~FS-62~~FS-60

~~SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES~~Supplemental Information on Oil and Gas Producing Activities
Unaudited

In accordance with Statement of FAS 69,Disclosures About Oil and Gas Producing Activities,, this section provides supplemental information on oil and gas exploration and producing activities of the company in seven separate tables. Tables I through IV provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations.
Tables V through VII present information on the company’s estimated net proved reserve ~~quantities;~~quantities, standardized measure of estimated discounted future net cash flows related to proved ~~reserves;~~reserves, and changes in estimated discounted future net cash flows. The Africa geographic area includes activities principally in Nigeria, Angola, Chad, Republic of the Congo and Democratic Republic of the Congo. The Asia-Pacific

~~TABLE~~Table I – ~~COSTS INCURRED IN EXPLORATION, PROPERTY ACQUISITIONS AND DEVELOPMENT~~Costs Incurred in Exploration, Property Acquisitions and Development¹

Consolidated Companies Consolidated Companies
United States International United States International
Gulf of Total Asia- Total Affiliated Companies Gulf of Total Asia- Total Affiliated Companies
Millions of dollars Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int’l. Total TCO Other Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int’l Total TCO Other

YEAR ENDED DEC. 31, 2006

Year Ended Dec. 31, 2007

Exploration
Wells $ – $ 493 $ 22 $ 515 $ 151 $ 121 $ 20 $ 246 $ 538 $ 1,053 $ 25 $ – $ 4 $ 430 $ 18 $ 452 $ 202 $ 156 $ 3 $ 195 $ 556 $ 1,008 $ – $ 7
Geological and geophysical – 96 8 104 180 53 12 92 337 441 – – – 59 14 73 136 48 11 98 293 366 – –
Rentals and other – 116 16 132 48 140 58 50 296 428 – – – 128 5 133 70 120 50 79 319 452 – –

Total exploration – 705 46 751 379 314 90 388 1,171 1,922 25 – 4 617 37 658 408 324 64 372 1,168 1,826 – 7

Property acquisitions
Proved²
6 152 – 158 1 10 – 15 26 184 – 581
Property acquisitions²

Proved 10 220 13 243 5 92 – (2 ) 95 338 – –
Unproved 1 47 10 58 – 1 – 135 136 194 – – 35 75 3 113 8 35 – 24 67 180 – –

Total property acquisitions 7 199 10 216 1 11 – 150 162 378 – 581 45 295 16 356 13 127 – 22 162 518 – –

Development³
686 1,632 868 3,186 2,890 1,788 460 1,019 6,157 9,343 671 25 1,198 2,237 1,775 5,210 4,176 1,897 620 1,504 8,197 13,407 832 64

TOTAL COSTS INCURRED
$ 693 $ 2,536 $ 924 $ 4,153 $ 3,270 $ 2,113 $ 550 $ 1,557 $ 7,490 $ 11,643 $ 696 $ 606
Total Costs Incurred
$ 1,247 $ 3,149 $ 1,828 $ 6,224 $ 4,597 $ 2,348 $ 684 $ 1,898 $ 9,527 $ 15,751 $ 832 $ 71

YEAR ENDED DEC. 31, 2005⁴

Year Ended Dec. 31, 2006

Exploration
Wells $ – $ 452 $ 24 $ 476 $ 105 $ 38 $ 9 $ 201 $ 353 $ 829 $ – $ – $ – $ 493 $ 22 $ 515 $ 151 $ 121 $ 20 $ 246 $ 538 $ 1,053 $ 25 $ –
Geological and geophysical – 67 – 67 96 28 10 68 202 269 – – – 96 8 104 180 53 12 92 337 441 – –
Rentals and other – 93 8 101 24 58 12 72 166 267 – – – 116 16 132 48 140 58 50 296 428 – –

Total exploration – 612 32 644 225 124 31 341 721 1,365 – – – 705 46 751 379 314 90 388 1,171 1,922 25 –

Property acquisitions
Proved – Unocal²
– 1,608 2,388 3,996 30 6,609 637 1,790 9,066 13,062 – –
Proved – Other²
– 6 10 16 2 2 – 12 16 32 – –
Property acquisitions²

Proved 6 152 – 158 1 10 – 15 26 184 – 581
Unproved 1 47 10 58 – 1 – 135 136 194 – –

Total property acquisitions 7 199 10 216 1 11 – 150 162 378 – 581

Development³
686 1,632 868 3,186 2,890 1,788 460 1,019 6,157 9,343 671 25

Total Costs Incurred
$ 693 $ 2,536 $ 924 $ 4,153 $ 3,270 $ 2,113 $ 550 $ 1,557 $ 7,490 $ 11,643 $ 696 $ 606

Year Ended Dec. 31, 2005

Exploration
Wells $ – $ 452 $ 24 $ 476 $ 105 $ 38 $ 9 $ 201 $ 353 $ 829 $ – $ –
Geological and geophysical – 67 – 67 96 28 10 68 202 269 – –
Rentals and other – 93 8 �� 101 24 58 12 72 166 267 – –

Total exploration – 612 32 644 225 124 31 341 721 1,365 – –

Property acquisitions²

Proved – Unocal – 1,608 2,388 3,996 30 6,609 637 1,790 9,066 13,062 – –
Proved – Other – 6 10 16 2 2 – 12 16 32 – –
Unproved – Unocal – 819 295 1,114 11 2,209 821 38 3,079 4,193 – – – 819 295 1,114 11 2,209 821 38 3,079 4,193 – –
Unproved – Other – 17 6 23 67 – – 28 95 118 – – – 17 6 23 67 – – 28 95 118 – –

Total property acquisitions – 2,450 2,699 5,149 110 8,820 1,458 1,868 12,256 17,405 – – – 2,450 2,699 5,149 110 8,820 1,458 1,868 12,256 17,405 – –

Development³
507 680 601 1,788 1,892 1,088 382 726 4,088 5,876 767 43 507 680 601 1,788 1,892 1,088 382 726 4,088 5,876 767 43

TOTAL COSTS INCURRED
$ 507 $ 3,742 $ 3,332 $ 7,581 $ 2,227 $ 10,032 $ 1,871 $ 2,935 $ 17,065 $ 24,646 $ 767 $ 43
Total Costs Incurred
$ 507 $ 3,742 $ 3,332 $ 7,581 $ 2,227 $ 10,032 $ 1,871 $ 2,935 $ 17,065 $ 24,646 $ 767 $ 43

YEAR ENDED DEC. 31, 2004⁴

Exploration
Wells $ – $ 388 $ – $ 388 $ 116 $ 25 $ 2 $ 127 $ 270 $ 658 $ – $ –
Geological and geophysical – 47 2 49 103 10 12 46 171 220 – –
Rentals and other – 43 3 46 52 47 1 53 153 199 – –

Total exploration – 478 5 483 271 82 15 226 594 1,077 – –

Property acquisitions
Proved²
– 6 1 7 111 16 – 4 131 138 – –
Unproved – 29 – 29 82 – – 5 87 116 – –

Total property acquisitions – 35 1 36 193 16 – 9 218 254 – –

Development³
413 466 375 1,254 1,057 620 403 627 2,707 3,961 896 208

TOTAL COSTS INCURRED
$ 413 $ 979 $ 381 $ 1,773 $ 1,521 $ 718 $ 418 $ 862 $ 3,519 $ 5,292 $ 896 $ 208

¹ Includes costs incurred whether capitalized or expensed. Excludes general support equipment expenditures. Includes capitalized amounts related to asset retirement obligations. See Note ~~24,~~23, “Asset Retirement Obligations,” beginning on page ~~FS-58.~~FS-57.

² Includes wells, equipment and facilities associated with proved reserves. Does not include properties acquired ~~through property exchanges.~~in nonmonetary transactions.

³ Includes ~~$160,~~$99, $160 and ~~$63~~$160 costs incurred prior to assignment of proved reserves in 2007, 2006 and 2005, ~~and 2004,~~ respectively.
⁴ ~~2005 and 2004 presentation conformed to 2006.~~
~~FS-63~~FS-61

Supplemental Information on Oil and Gas Producing Activities – Continued

geographic area includes activities principally in Australia, Azerbaijan, Bangladesh, China, Kazakhstan, Myanmar, the Partitioned Neutral Zone between Kuwait and Saudi Arabia, the Philippines, and Thailand. The international “Other” geographic category includes activities in Argentina, Brazil, Canada, Colombia, Denmark, the Netherlands, Norway, Trinidad and Tobago, Venezuela, the United Kingdom, and
other countries. Amounts for TCO represent Chevron’s 50 percent equity share of Tengizchevroil, an exploration and
production partnership in the Republic of Kazakhstan. The affiliated companies “Other” amounts are composed of the company’s equity interests in Venezuela, Angola and Russia. Refer to Note 11 beginning on page FS-40 for a ~~30 percent~~discussion of the company’s major equity ~~share~~affiliates.

Table II – Capitalized Costs Related to Oil and Gas Producing Activities

Consolidated Companies
United States International
Gulf of Total Asia- Total Affiliated Companies
Millions of dollars Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int’l. Total TCO Other

At Dec. 31, 2007

Unproved properties $ 805 $ 892 $ 353 $ 2,050 $ 314 $ 2,639 $ 630 $ 1,015 $ 4,598 $ 6,648 $ 112 $ –
Proved properties and related producing assets 11,260 19,110 13,718 44,088 11,894 17,321 7,705 11,360 48,280 92,368 4,247 858
Support equipment 201 206 230 637 850 284 1,123 439 2,696 3,333 758 –
Deferred exploratory wells – 406 7 413 368 293 148 438 1,247 1,660 – –
Other uncompleted projects 308 3,128 573 4,009 6,430 2,049 593 1,421 10,493 14,502 1,633 55

Gross Cap. Costs
12,574 23,742 14,881 51,197 19,856 22,586 10,199 14,673 67,314 118,511 6,750 913

Unproved properties valuation 741 57 35 833 201 221 39 427 888 1,721 23 –
Proved producing properties –
Depreciation and depletion 7,383 15,074 7,640 30,097 5,427 6,912 5,592 7,062 24,993 55,090 644 167
Support equipment depreciation 133 92 124 349 464 144 571 261 1,440 1,789 267 –

Accumulated provisions 8,257 15,223 7,799 31,279 6,092 7,277 6,202 7,750 27,321 58,600 934 167

Net Capitalized Costs
$ 4,317 $ 8,519 $ 7,082 $ 19,918 $ 13,764 $ 15,309 $ 3,997 $ 6,923 $ 39,993 $ 59,911 $ 5,816 $ 746

At Dec. 31, 2006

Unproved properties $ 770 $ 1,007 $ 370 $ 2,147 $ 342 $ 2,373 $ 707 $ 1,082 $ 4,504 $ 6,651 $ 112 $ –
Proved properties and related producing assets 9,960 18,464 12,284 40,708 9,943 15,486 7,110 10,461 43,000 83,708 2,701 1,096
Support equipment 189 212 226 627 745 240 1,093 364 2,442 3,069 611 –
Deferred exploratory wells – 343 7 350 231 217 149 292 889 1,239 – –
Other uncompleted projects 370 2,188 – 2,558 4,299 1,546 493 917 7,255 9,813 2,493 40

Gross Cap. Costs
11,289 22,214 12,887 46,390 15,560 19,862 9,552 13,116 58,090 104,480 5,917 1,136

Unproved properties valuation 738 52 29 819 189 74 14 337 614 1,433 22 –
Proved producing properties –
Depreciation and depletion 7,082 14,468 6,880 28,430 4,794 5,273 4,971 �� 6,087 21,125 49,555 541 109
Support equipment depreciation 125 111 130 366 400 102 522 238 1,262 1,628 242 –

Accumulated provisions 7,945 14,631 7,039 29,615 5,383 5,449 5,507 6,662 23,001 52,616 805 109

Net Capitalized Costs
$ 3,344 $ 7,583 $ 5,848 $ 16,775 $ 10,177 $ 14,413 $ 4,045 $ 6,454 $ 35,089 $ 51,864 $ 5,112 $ 1,027

FS-62

Table II Capitalized Costs Related to Oil and Gas Producing Activities – Continued

Consolidated Companies
United States International
Gulf of Total Asia- Total Affiliated Companies
Millions of dollars Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int’l. Total TCO Other

At Dec. 31, 2005

Unproved properties $ 769 $ 1,077 $ 397 $ 2,243 $ 407 $ 2,287 $ 645 $ 983 $ 4,322 $ 6,565 $ 108 $ –
Proved properties and related producing assets 9,546 18,283 11,467 39,296 8,404 14,928 6,613 9,627 39,572 78,868 2,264 1,213
Support equipment 204 193 230 627 715 426 1,217 356 2,714 3,341 549 –
Deferred exploratory wells – 284 5 289 245 154 173 248 820 1,109 – –
Other uncompleted projects 149 782 209 1,140 2,878 790 427 946 5,041 6,181 2,332 –

Gross Cap. Costs
10,668 20,619 12,308 43,595 12,649 18,585 9,075 12,160 52,469 96,064 5,253 1,213

Unproved properties valuation 736 90 22 848 162 69 – 318 549 1,397 17 –
Proved producing properties –
Depreciation and depletion 6,818 14,067 6,049 26,934 4,266 4,016 4,105 5,720 18,107 45,041 460 90
Support equipment depreciation 140 119 149 408 317 88 680 222 1,307 1,715 213 –

Accumulated provisions 7,694 14,276 6,220 28,190 4,745 4,173 4,785 6,260 19,963 48,153 690 90

Net Capitalized Costs
$ 2,974 $ 6,343 $ 6,088 $ 15,405 $ 7,904 $ 14,412 $ 4,290 $ 5,900 $ 32,506 $ 47,911 $ 4,563 $ 1,123

FS-63
Supplemental Information on Oil and Gas Producing Activities –Continued

Table III Results of Operations for Oil and Gas Producing Activities¹
     The company’s results of ~~Hamaca, an~~operations from oil and gas producing activities for the years 2007, 2006 and 2005 are shown in the following table. Net income from exploration and production ~~partnership~~activities as reported on page FS-38 reflects income taxes computed on an effective rate basis.
In accordance with FAS 69, income taxes in ~~Venezuela~~Table III are based on statutory tax rates, reflecting allowable deductions and ~~effective October 2006, Chevron’s 39 percent interest~~tax credits. Interest income and ~~25 percent interest~~expense are excluded from the results reported in ~~Petroboscan~~Table III and ~~Petroindependiente, respectively. These joint stock companies are involved in~~from the ~~development of the Boscan and LL-652 fields in Venezuela, respectively.~~net income amounts on page FS-38.

~~TABLE II – CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES~~

Consolidated Companies
United States International
Gulf of Total Asia- Total Affiliated Companies
Millions of dollars Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int’l. Total TCO Other

AT DEC. 31, 2006

Unproved properties $ 770 $ 1,007 $ 370 $ 2,147 $ 342 $ 2,373 $ 707 $ 1,082 $ 4,504 $ 6,651 $ 112 $ –
Proved properties and related producing assets 9,960 18,464 12,284 40,708 9,943 15,486 7,110 10,461 43,000 83,708 2,701 1,096
Support equipment 189 212 226 627 745 240 1,093 364 2,442 3,069 611 –
Deferred exploratory wells – 343 7 350 231 217 149 292 889 1,239 – –
Other uncompleted projects 370 2,188 – 2,558 4,299 1,546 493 917 7,255 9,813 2,493 40

GROSS CAP. COSTS
11,289 22,214 12,887 46,390 15,560 19,862 9,552 13,116 58,090 104,480 5,917 1,136

Unproved properties valuation 738 52 29 819 189 74 14 337 614 1,433 22 –
Proved producing properties – Depreciation and depletion 7,082 14,468 6,880 28,430 4,794 5,273 4,971 6,087 21,125 49,555 541 109
Support equipment depreciation 125 111 130 366 400 102 522 238 1,262 1,628 242 –

Accumulated provisions 7,945 14,631 7,039 29,615 5,383 5,449 5,507 6,662 23,001 52,616 805 109

NET CAPITALIZED COSTS
$ 3,344 $ 7,583 $ 5,848 $ 16,775 $ 10,177 $ 14,413 $ 4,045 $ 6,454 $ 35,089 $ 51,864 $ 5,112 $ 1,027

AT DEC. 31, 2005^*

Unproved properties $ 769 $ 1,077 $ 397 $ 2,243 $ 407 $ 2,287 $ 645 $ 983 $ 4,322 $ 6,565 $ 108 $ –
Proved properties and related producing assets 9,546 18,283 11,467 39,296 8,404 14,928 6,613 9,627 39,572 78,868 2,264 1,213
Support equipment 204 193 230 627 715 426 1,217 356 2,714 3,341 549 –
Deferred exploratory wells – 284 5 289 245 154 173 248 820 1,109 – –
Other uncompleted projects 149 782 209 1,140 2,878 790 427 946 5,041 6,181 2,332 –

GROSS CAP. COSTS
10,668 20,619 12,308 43,595 12,649 18,585 9,075 12,160 52,469 96,064 5,253 1,213

Unproved properties valuation 736 90 22 848 162 69 – 318 549 1,397 17 –
Proved producing properties – Depreciation and depletion 6,818 14,067 6,049 26,934 4,266 4,016 4,105 5,720 18,107 45,041 460 90
Support equipment depreciation 140 119 149 408 317 88 680 222 1,307 1,715 213 –

Accumulated provisions 7,694 14,276 6,220 28,190 4,745 4,173 4,785 6,260 19,963 48,153 690 90

NET CAPITALIZED COSTS
$ 2,974 $ 6,343 $ 6,088 $ 15,405 $ 7,904 $ 14,412 $ 4,290 $ 5,900 $ 32,506 $ 47,911 $ 4,563 $ 1,123

Consolidated Companies
United States International
Gulf of Total Asia- Total Affiliated Companies
Millions of dollars Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int’l. Total TCO Other

Year Ended Dec. 31, 2007

Revenues from net production
Sales $ 202 $ 1,555 $ 2,476 $ 4,233 $ 1,810 $ 6,192 $ 1,045 $ 3,012 $ 12,059 $ 16,292 $ 3,327 $ 1,290
Transfers 4,671 2,630 2,707 10,008 6,778 4,440 2,590 2,744 16,552 26,560 – –

Total 4,873 4,185 5,183 14,241 8,588 10,632 3,635 5,756 28,611 42,852 3,327 1,290
Production expenses excluding taxes²
(1,063 ) (936 ) (1,400 ) (3,399 ) (892 ) (953 ) (892 ) (828 ) (3,565 ) (6,964 ) (248 ) (92 )
Taxes other than on income (91 ) (53 ) (378 ) (522 ) (49 ) (292 ) (2 ) (58 ) (401 ) (923 ) (31 ) (163 )
Proved producing properties: Depreciation and depletion (300 ) (1,143 ) (833 ) (2,276 ) (646 ) (1,668 ) (623 ) (980 ) (3,917 ) (6,193 ) (127 ) (94 )
Accretion expense³
(92 ) 1 (167 ) (258 ) (33 ) (36 ) (21 ) (27 ) (117 ) (375 ) (1 ) (2 )
Exploration expenses – (486 ) (25 ) (511 ) (267 ) (225 ) (61 ) (259 ) (812 ) (1,323 ) – –
Unproved properties valuation (3 ) (102 ) (27 ) (132 ) (12 ) (150 ) (30 ) (120 ) (312 ) (444 ) – –
Other income (expense)⁴
3 2 31 36 (447 ) (302 ) (197 ) (722 ) (1,668 ) (1,632 ) 18 (7 )

Results before income taxes 3,327 1,468 2,384 7,179 6,242 7,006 1,809 2,762 17,819 24,998 2,938 946
Income tax expense (1,204 ) (531 ) (864 ) (2,599 ) (4,907 ) (3,456 ) (841 ) (1,624 ) (10,828 ) (13,427 ) (887 ) (462 )

Results of Producing Operations
$ 2,123 $ 937 $ 1,520 $ 4,580 $ 1,335 $ 3,550 $ 968 $ 1,138 $ 6,991 $ 11,571 $ 2,051 $ 484

Year Ended Dec. 31, 2006

Revenues from net production
Sales $ 308 $ 1,845 $ 2,976 $ 5,129 $ 2,377 $ 4,938 $ 1,001 $ 2,814 $ 11,130 $ 16,259 $ 2,861 $ 598
Transfers 4,072 2,317 2,046 8,435 5,264 4,084 2,211 2,848 14,407 22,842 – –

Total 4,380 4,162 5,022 13,564 7,641 9,022 3,212 5,662 25,537 39,101 2,861 598
Production expenses excluding taxes (889 ) (765 ) (1,057 ) (2,711 ) (640 ) (740 ) (728 ) (664 ) (2,772 ) (5,483 ) (202 ) (42 )
Taxes other than on income (84 ) (57 ) (442 ) (583 ) (57 ) (231 ) (1 ) (60 ) (349 ) (932 ) (28 ) (6 )
Proved producing properties: Depreciation and depletion (275 ) (1,096 ) (763 ) (2,134 ) (579 ) (1,475 ) (666 ) (703 ) (3,423 ) (5,557 ) (114 ) (33 )
Accretion expense³
(11 ) (80 ) (39 ) (130 ) (26 ) (30 ) (23 ) (49 ) (128 ) (258 ) (1 ) –
Exploration expenses – (407 ) (24 ) (431 ) (296 ) (209 ) (110 ) (318 ) (933 ) (1,364 ) (25 ) –
Unproved properties valuation (3 ) (73 ) (8 ) (84 ) (28 ) (15 ) (14 ) (27 ) (84 ) (168 ) – –
Other income (expense)⁴
1 (732 ) 254 (477 ) (435 ) (475 ) 50 385 (475 ) (952 ) 8 (50 )

Results before income taxes 3,119 952 2,943 7,014 5,580 5,847 1,720 4,226 17,373 24,387 2,499 467
Income tax expense (1,169 ) (357 ) (1,103 ) (2,629 ) (4,740 ) (3,224 ) (793 ) (2,151 ) (10,908 ) (13,537 ) (750 ) (174 )

Results of Producing Operations
$ 1,950 $ 595 $ 1,840 $ 4,385 $ 840 $ 2,623 $ 927 $ 2,075 $ 6,465 $ 10,850 $ 1,749 $ 293

¹ The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.

^*2 ~~Conformed~~Includes $10 costs incurred prior to ~~2006 presentation.~~assignment of proved reserves in 2007.
³ Represents accretion of ARO liability. Refer to Note 23, “Asset Retirement Obligations,” beginning on page FS-57.
⁴ Includes foreign currency gains and losses, gains and losses on property dispositions, and income from operating and technical service agreements.
FS-64

~~TABLE II~~Table III Results of Operations for Oil and Gas Producing Activities¹– ~~CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES–~~Continued

Consolidated Companies
United States International
Gulf of Total Asia- Total Affiliated Companies
Millions of dollars Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int’l. Total TCO Other

AT DEC. 31, 2004^1,2

Unproved properties $ 769 $ 380 $ 109 $ 1,258 $ 322 $ 211 $ – $ 970 $ 1,503 $ 2,761 $ 108 $ –
Proved properties and related producing assets 9,198 16,814 8,730 34,742 7,394 7,598 5,731 9,253 29,976 64,718 2,183 963
Support equipment 211 175 208 594 513 127 1,123 361 2,124 2,718 496 –
Deferred exploratory wells – 225 – 225 213 81 – 152 446 671 – –
Other uncompleted projects 91 400 169 660 2,050 605 351 391 3,397 4,057 1,749 149

GROSS CAP. COSTS
10,269 17,994 9,216 37,479 10,492 8,622 7,205 11,127 37,446 74,925 4,536 1,112

Unproved properties valuation 734 111 27 872 118 67 – 294 479 1,351 15 –
Proved producing properties – Depreciation and depletion 6,718 13,736 5,681 26,135 3,881 3,171 3,576 5,081 15,709 41,844 428 43
Support equipment depreciation 148 107 139 394 268 60 658 206 1,192 1,586 190 –

Accumulated provisions 7,600 13,954 5,847 27,401 4,267 3,298 4,234 5,581 17,380 44,781 633 43

NET CAPITALIZED COSTS
$ 2,669 $ 4,040 $ 3,369 $ 10,078 $ 6,225 $ 5,324 $ 2,971 $ 5,546 $ 20,066 $ 30,144 $ 3,903 $ 1,069

Consolidated Companies
United States International
Gulf of Total Asia- Total Affiliated Companies
Millions of dollars Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int’l. Total TCO Other

Year Ended Dec. 31, 2005

Revenues from net production
Sales $ 337 $ 1,576 $ 3,174 $ 5,087 $ 2,142 $ 2,941 $ 539 $ 2,668 $ 8,290 $ 13,377 $ 2,307 $ 666
Transfers 3,497 2,127 1,395 7,019 3,615 3,179 1,986 2,607 11,387 18,406 – –

Total 3,834 3,703 4,569 12,106 5,757 6,120 2,525 5,275 19,677 31,783 2,307 666
Production expenses excluding taxes (916 ) (638 ) (777 ) (2,331 ) (558 ) (570 ) (660 ) (596 ) (2,384 ) (4,715 ) (152 ) (82 )
Taxes other than on income (65 ) (41 ) (384 ) (490 ) (48 ) (189 ) (1 ) (195 ) (433 ) (923 ) (27 ) –
Proved producing properties:
Depreciation and depletion (253 ) (936 ) (520 ) (1,709 ) (414 ) (852 ) (550 ) (672 ) (2,488 ) (4,197 ) (83 ) (46 )
Accretion expense²
(13 ) (35 ) (46 ) (94 ) (22 ) (20 ) (15 ) (25 ) (82 ) (176 ) (1 ) –
Exploration expenses – (307 ) (13 ) (320 ) (117 ) (90 ) (26 ) (190 ) (423 ) (743 ) – –
Unproved properties valuation (3 ) (32 ) (4 ) (39 ) (50 ) (8 ) – (24 ) (82 ) (121 ) – –
Other income (expense)³
2 (354 ) (140 ) (492 ) (243 ) (182 ) 182 280 37 (455 ) (9 ) 8

Results before income taxes 2,586 1,360 2,685 6,631 4,305 4,209 1,455 3,853 13,822 20,453 2,035 546
Income tax expense (913 ) (482 ) (953 ) (2,348 ) (3,430 ) (2,264 ) (644 ) (1,938 ) (8,276 ) (10,624 ) (611 ) (186 )

Results of Producing Operations
$ 1,673 $ 878 $ 1,732 $ 4,283 $ 875 $ 1,945 $ 811 $ 1,915 $ 5,546 $ 9,829 $ 1,424 $ 360

¹ ~~Includes assets held for sale.~~ The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.

² ~~Conformed~~ Represents accretion of ARO liability. Refer to ~~2006 presentation.~~Note 23, “Asset Retirement Obligations,” beginning on page FS-57.
³ Includes foreign currency gains and losses, gains and losses on property dispositions, and income from operating and technical service agreements.
FS-65

Supplemental Information on Oil and Gas Producing Activities –Continued

~~TABLE III~~Table IV Results of Operations for Oil and Gas Producing Activities – ~~RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES~~Unit Prices and Costs^11,2

     The company’s results of operations from oil and gas producing activities for the years 2006, 2005 and 2004 are shown in the following table. Net income from exploration and production activities as reported on page FS-38 reflects income taxes computed on an effective rate basis.
In accordance with FAS 69, income taxes in Table III are based on statutory tax rates, reflecting allowable deductions and tax credits. Interest income and expense are excluded from the results reported in Table III and from the net income amounts on page FS-38.

Consolidated Companies
United States International
Gulf of Total Asia- Total Affiliated Companies
Millions of dollars Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int’l. Total TCO Other

YEAR ENDED DEC. 31, 2006

Revenues from net production
Sales $ 308 $ 1,845 $ 2,976 $ 5,129 $ 2,377 $ 4,938 $ 1,001 $ 2,814 $ 11,130 $ 16,259 $ 2,861 $ 598
Transfers 4,072 2,317 2,046 8,435 5,264 4,084 2,211 2,848 14,407 22,842 – –

Total 4,380 4,162 5,022 13,564 7,641 9,022 3,212 5,662 25,537 39,101 2,861 598
Production expenses excluding taxes (889 ) (765 ) (1,057 ) (2,711 ) (640 ) (740 ) (728 ) (664 ) (2,772 ) (5,483 ) (202 ) (42 )
Taxes other than on income (84 ) (57 ) (442 ) (583 ) (57 ) (231 ) (1 ) (60 ) (349 ) (932 ) (28 ) (6 )
Proved producing properties: Depreciation and depletion (275 ) (1,096 ) (763 ) (2,134 ) (579 ) (1,475 ) (666 ) (703 ) (3,423 ) (5,557 ) (114 ) (33 )
Accretion expense²
(11 ) (80 ) (39 ) (130 ) (26 ) (30 ) (23 ) (49 ) (128 ) (258 ) (1 ) –
Exploration expenses – (407 ) (24 ) (431 ) (296 ) (209 ) (110 ) (318 ) (933 ) (1,364 ) (25 ) –
Unproved properties valuation (3 ) (73 ) (8 ) (84 ) (28 ) (15 ) (14 ) (27 ) (84 ) (168 ) – –
Other income (expense)³
1 (732 ) 254 (477 ) (435 ) (475 ) 50 385 (475 ) (952 ) 8 (50 )

Results before income taxes 3,119 952 2,943 7,014 5,580 5,847 1,720 4,226 17,373 24,387 2,499 467
Income tax expense (1,169 ) (357 ) (1,103 ) (2,629 ) (4,740 ) (3,224 ) (793 ) (2,151 ) (10,908 ) (13,537 ) (750 ) (174 )

RESULTS OF PRODUCING OPERATIONS
$ 1,950 $ 595 $ 1,840 $ 4,385 $ 840 $ 2,623 $ 927 $ 2,075 $ 6,465 $ 10,850 $ 1,749 $ 293

YEAR ENDED DEC. 31, 2005

Revenues from net production
Sales $ 337 $ 1,576 $ 3,174 $ 5,087 $ 2,142 $ 2,941 $ 539 $ 2,668 $ 8,290 $ 13,377 $ 2,307 $ 666
Transfers 3,497 2,127 1,395 7,019 3,615 3,179 1,986 2,607 11,387 18,406 – –

Total 3,834 3,703 4,569 12,106 5,757 6,120 2,525 5,275 19,677 31,783 2,307 666
Production expenses excluding taxes (916 ) (638 ) (777 ) (2,331 ) (558 ) (570 ) (660 ) (596 ) (2,384 ) (4,715 ) (152 ) (82 )
Taxes other than on income (65 ) (41 ) (384 ) (490 ) (48 ) (189 ) (1 ) (195 ) (433 ) (923 ) (27 ) –
Proved producing properties: Depreciation and depletion (253 ) (936 ) (520 ) (1,709 ) (414 ) (852 ) (550 ) (672 ) (2,488 ) (4,197 ) (83 ) (46 )
Accretion expense²
(13 ) (35 ) (46 ) (94 ) (22 ) (20 ) (15 ) (25 ) (82 ) (176 ) (1 ) –
Exploration expenses – (307 ) (13 ) (320 ) (117 ) (90 ) (26 ) (190 ) (423 ) (743 ) – –
Unproved properties valuation (3 ) (32 ) (4 ) (39 ) (50 ) (8 ) – (24 ) (82 ) (121 ) – –
Other income (expense)³
2 (354 ) (140 ) (492 ) (243 ) (182 ) 182 280 37 (455 ) (9 ) 8

Results before income taxes 2,586 1,360 2,685 6,631 4,305 4,209 1,455 3,853 13,822 20,453 2,035 546
Income tax expense (913 ) (482 ) (953 ) (2,348 ) (3,430 ) (2,264 ) (644 ) (1,938 ) (8,276 ) (10,624 ) (611 ) (186 )

RESULTS OF PRODUCING OPERATIONS
$ 1,673 $ 878 $ 1,732 $ 4,283 $ 875 $ 1,945 $ 811 $ 1,915 $ 5,546 $ 9,829 $ 1,424 $ 360

Consolidated Companies
United States International
Gulf of Total Asia- Total Affiliated Companies
Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int’l. Total TCO Other

Year Ended Dec. 31, 2007

Average sales prices
Liquids, per barrel $ 62.61 $ 65.07 $ 62.35 $ 63.16 $ 69.90 $ 64.20 $ 61.05 $ 62.97 $ 65.40 $ 64.71 $ 62.47 $ 51.98
Natural gas, per thousand cubic feet 5.77 7.01 5.65 6.12 – 3.60 7.61 4.13 4.02 4.79 0.89 0.44
Average production costs, per barrel 13.23 12.32 12.62 12.72 7.26 3.96 14.28 6.96 6.54 8.58 3.98 3.56

Year Ended Dec. 31, 2006

Average sales prices
Liquids, per barrel $ 55.20 $ 60.35 $ 55.80 $ 56.66 $ 61.53 $ 57.05 $ 52.23 $ 57.31 $ 57.92 $ 57.53 $ 56.80 $ 37.26
Natural gas, per thousand cubic feet 6.08 7.20 5.73 6.29 0.06 3.44 7.12 4.03 3.88 4.85 0.77 0.36
Average production costs, per barrel 10.94 9.59 9.26 9.85 5.13 3.36 11.44 5.23 5.17 6.76 3.31 2.51

Year Ended Dec. 31, 2005

Average sales prices
Liquids, per barrel $ 45.24 $ 48.80 $ 48.29 $ 46.97 $ 50.54 $ 45.88 $ 44.40 $ 48.61 $ 47.83 $ 47.56 $ 45.59 $ 45.89
Natural gas, per thousand cubic feet 6.94 8.43 6.90 7.43 0.04 3.59 5.74 3.31 3.48 5.18 0.61 0.26
Average production costs, per barrel 10.74 8.55 7.57 8.88 4.72 3.38 11.28 4.32 4.93 6.32 2.45 5.53

¹ The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.
² ~~Represents accretion of ARO liability. Refer to Note 24, “Asset Retirement Obligations,” on page FS-58.~~
³ ~~Includes foreign currency gains and losses, gains and losses on property dispositions, and income from operating and technical service agreements.~~
~~FS-66~~

~~TABLE III~~ ~~– RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES~~¹ ~~– Continued~~

Consolidated Companies
United States International
Gulf of Total Asia- Total Affiliated Companies
Millions of dollars Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int'l. Total TCO Other

YEAR ENDED DEC. 31, 2004

Revenues from net
production
Sales $ 251 $ 1,925 $ 2,163 $ 4,339 $ 1,321 $ 1,191 $ 256 $ 2,481 $ 5,249 $ 9,588 $ 1,619 $ 205
Transfers 2,651 1,768 1,224 5,643 2,645 2,265 1,613 1,903 8,426 14,069 – –

Total 2,902 3,693 3,387 9,982 3,966 3,456 1,869 4,384 13,675 23,657 1,619 205
Production expenses excluding taxes (710 ) (547 ) (697 ) (1,954 ) (574 ) (431 ) (591 ) (544 ) (2,140 ) (4,094 ) (143 ) (53 )
Taxes other than on income (57 ) (45 ) (321 ) (423 ) (24 ) (138 ) (1 ) (134 ) (297 ) (720 ) (26 ) –
Proved producing properties:
Depreciation and depletion (232 ) (774 ) (384 ) (1,390 ) (367 ) (401 ) (393 ) (798 ) (1,959 ) (3,349 ) (104 ) (4 )
Accretion expense²
(12 ) (25 ) (19 ) (56 ) (22 ) (8 ) (13 ) 11 (32 ) (88 ) (2 ) –
Exploration expenses – (227 ) (6 ) (233 ) (235 ) (69 ) (17 ) (144 ) (465 ) (698 ) – –
Unproved properties valuation (3 ) (29 ) (4 ) (36 ) (23 ) (8 ) – (25 ) (56 ) (92 ) – –
Other income (expense)³
14 24 474 512 49 10 12 1,028 1,099 1,611 (7 ) (58 )

Results before income taxes 1,902 2,070 2,430 6,402 2,770 2,411 866 3,778 9,825 16,227 1,337 90
Income tax expense (703 ) (765 ) (898 ) (2,366 ) (2,036 ) (1,395 ) (371 ) (1,759 ) (5,561 ) (7,927 ) (401 ) –

RESULTS OF PRODUCING OPERATIONS
$ 1,199 $ 1,305 $ 1,532 $ 4,036 $ 734 $ 1,016 $ 495 $ 2,019 $ 4,264 $ 8,300 $ 936 $ 90

¹ The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.
² ~~Represents accretion of ARO liability. Refer to Note 24, “Asset Retirement Obligations,” on page FS-58.~~
³ ~~Includes foreign currency gains and losses, gains and losses on property dispositions, and income from operating and technical service agreements.~~
~~FS-67~~
~~Supplemental Information on Oil and Gas Producing Activities –Continued~~
~~TABLE IV – RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES –~~
~~UNIT PRICES AND COSTS~~^1,2

Consolidated Companies
United States International
Gulf of Total Asia- Total Affiliated Companies
Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int'l. Total TCO Other

YEAR ENDED DEC. 31, 2006

Average sales prices Liquids, per barrel $ 55.20 $ 60.35 $ 55.80 $ 56.66 $ 61.53 $ 57.05 $ 52.23 $ 57.31 $ 57.92 $ 57.53 $ 56.80 $ 37.26
Natural gas, per thousand cubic feet 6.08 7.20 5.73 6.29 0.06 3.44 7.12 4.03 3.88 4.85 0.77 0.36
Average production costs, per barrel 10.94 9.59 9.26 9.85 5.13 3.36 11.44 5.23 5.17 6.76 3.31 2.51

YEAR ENDED DEC. 31, 2005

Average sales prices Liquids, per barrel $ 45.24 $ 48.80 $ 48.29 $ 46.97 $ 50.54 $ 45.88 $ 44.40 $ 48.61 $ 47.83 $ 47.56 $ 45.59 $ 45.89
Natural gas, per thousand cubic feet 6.94 8.43 6.90 7.43 0.04 3.59 5.74 3.31 3.48 5.18 0.61 0.26
Average production costs, per barrel 10.74 8.55 7.57 8.88 4.72 3.38 11.28 4.32 4.93 6.32 2.45 5.53

YEAR ENDED DEC. 31, 2004

Average sales prices Liquids, per barrel $ 33.43 $ 34.69 $ 34.61 $ 34.12 $ 34.85 $ 31.34 $ 31.12 $ 34.58 $ 33.33 $ 33.60 $ 30.23 $ 23.32
Natural gas, per thousand cubic feet 5.18 6.08 5.07 5.51 0.04 3.41 3.88 2.68 2.90 4.27 0.65 0.27
Average production costs, per barrel 8.14 5.26 6.65 6.60 4.89 3.50 9.69 3.47 4.67 5.43 2.31 6.10

¹ The value of owned production consumed in operations as fuel has been eliminated from revenues and production expenses, and the related volumes have been deducted from net production in calculating the unit average sales price and production cost. This has no effect on the results of producing operations.
² Natural gas converted to oil-equivalent gas (OEG) barrels at a rate of 6 MCF = 1 OEG barrel.
~~TABLE~~Table V – ~~RESERVE QUANTITY INFORMATION~~Reserve Quantity Information
Reserves Governance   The company has adopted a comprehensive reserves and resource classification system modeled after a system developed and approved by the Society of Petroleum Engineers, the World Petroleum Congress and the American Association of Petroleum Geologists. The system classifies recoverable hydrocarbons into six categories based on their status at the time of reporting – three deemed commercial and three noncommercial. Within the commercial classification are proved reserves and two categories of ~~unproved,~~unproved: probable and possible. The noncommercial categories are also referred to as contingent resources. For reserves estimates to be classified as proved, they must meet all SEC and company standards.
     Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Net proved reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at the time of the estimate.
     Proved reserves are classified as either developed or undeveloped. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods.
     Due to the inherent uncertainties and the limited nature of reservoir data, estimates of ~~underground~~ reserves are subject to change as additional information becomes available.
     Proved reserves are estimated by company asset teams composed of earth scientists and engineers. As part of the internal control process related to reserves estimation, the company maintains a Reserves Advisory Committee (RAC) that is chaired by the corporate reserves manager, who is a member of a corporate department that reports directly to the executive vice president responsible for the company’s worldwide exploration and production activities. All of the RAC members are knowledgeable in SEC guidelines for proved reserves classification. The RAC coordinates its activities through two operating company-level reserves managers. These two reserves managers are not members of the RAC so as to preserve the corporate-level independence.
     The RAC has the following primary responsibilities: provide independent reviews of the business units’ recommended reserve changes; confirm that proved reserves are recognized in accordance with SEC guidelines; determine that reserve volumes are calculated using consistent and appropriate standards, procedures and technology; and maintain theCorporate Reserves Manual,which provides standardized procedures used corporatewide for classifying and reporting hydrocarbon reserves.

~~FS-68~~FS-66

~~TABLE~~Table V ~~– RESERVE QUANTITY INFORMATION~~Reserve Quantity Information – Continued

     During the year, the RAC is represented in meetings with each of the company’s upstream business units to review and discuss reserve changes recommended by the various asset teams. Major changes are also reviewed with the company’s Strategy and Planning Committee and the Executive Committee, whose members include the Chief Executive Officer and the Chief Financial Officer. The company’s annual reserve activity is also reviewed with the Board of Directors. If major changes to reserves were to occur between the annual reviews, those matters would also be discussed with the Board.
     RAC subteams also conduct in-depth reviews during the year of many of the fields that have the largest proved reserves quantities. These reviews include an examination of the proved-reserve records and documentation of their alignment with theCorporate Reserves Manual.
     Reserve Quantities   At December 31, ~~2006,~~2007, oil-equivalent reserves for the company’s consolidated operations were ~~8.6~~7.9 billion barrels. (Refer to the term “Reserves” on page ~~E-11~~E-24 for the definition of oil-equivalent reserves.) Approximately 28 percent of the total reserves were in the United States. For the company’s interests in equity affiliates, oil-equivalent reserves were 32.9 billion barrels, 8084 percent of which were associated with the company’s 50 percent ownership in TCO. During the year, the company’s Boscan and LL-652 contracts in Venezuela were converted to Empresas Mixtas (i.e., joint stock contractual structures). The company had not previously recorded any reserves for its Boscan operations, but did so this year as a result of the conversion. The conversion of LL-652 reserves was treated as the sale of consolidated company reserves and the acquisition of equity affiliate reserves.
     Aside from the TCO operations, no single property accounted for more than 5 percent of the company’s total oil-equivalent proved reserves. Fewer than 20 other individual properties in the company’s portfolio of assets each contained between 1 percent and 5 percent of the company’s oil-equivalent proved reserves, which in the aggregate accounted for about 3637 percent of the company’s proved reserves total. These properties were geographically dispersed, located in the United States, South America, West Africa ~~the Middle East~~ and the Asia-Pacific region.
     In the United States, total oil-equivalent reserves at year-end ~~2006~~2007 were ~~2.4~~2.2 billion barrels. Of this amount, 4041 percent, 21 percent and 3938 percent were located in California, the Gulf of Mexico and other U.S. areas, respectively.
     In California, liquids reserves represented 9594 percent of the total, with most classified as heavy oil. Because of heavy oil’s high viscosity and the need to employ enhanced recovery methods, the producing operations are capital intensive in nature. Most of the company’s heavy-oil fields in California employ a continuous steamflooding process.
     In the Gulf of Mexico region, liquids represented approximately 6466 percent of total oil-equivalent reserves. Production operations are mostly offshore and, as a result, are also capital intensive. Costs include investments in wells, production platforms and other facilities, such as gathering lines and storage facilities.
     In other U.S. areas, the reserves were split about equally between liquids and natural gas. For production of crude oil, some fields utilize enhanced recovery methods, including ~~water-flood~~waterflood and CO₂ injection.
     The pattern of net reserve changes shown in the following tables, for the three years ending December 31, ~~2006,~~2007, is not necessarily indicative of future trends. Apart from acquisitions, the company’s ability to add proved reserves is affected by, among other things, events and circumstances that are outside the company’s control, such as delays in government permitting, partner approvals of development plans, ~~declines~~changes in oil and gas prices, OPEC constraints, geopolitical uncertainties, and civil unrest.
     The company’s estimated net proved ~~underground~~ oil and natural gas reserves and changes thereto for the years ~~2004,~~ 2005, 2006 and ~~2006~~2007 are shown in the tables on pages ~~FS-70~~FS-68 and ~~FS-72.~~FS-70.

~~FS-69~~FS-67

Supplemental Information on Oil and Gas Producing Activities –Continued

~~TABLE~~Table V ~~– RESERVE QUANTITY INFORMATION~~Reserve Quantity Information – Continued

~~NET PROVED RESERVES OF CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS~~Net Proved Reserves of Crude Oil, Condensate and Natural Gas Liquids

Consolidated Companies Consolidated Companies
United States International United States International
Gulf of Total Asia- Total Affiliated Companies Gulf of Total Asia- Total Affiliated Companies
Millions of barrels Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int’l. Total TCO Other Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int'l. Total TCO Other

RESERVES AT JAN. 1, 2004
1,051 435 572 2,058 1,923 796 807 696 4,222 6,280 1,840 479
Reserves at Jan. 1, 2005
1,011 294 432 1,737 1,833 676 698 567 3,774 5,511 1,994 468
Changes attributable to:
Revisions 13 (68 ) (2 ) (57 ) (70 ) (43 ) (36 ) (12 ) (161 ) (218 ) 206 (2 ) (23 ) (6 ) (11 ) (40 ) (29 ) (56 ) (108 ) (6 ) (199 ) (239 ) (5 ) (19 )
Improved recovery 28 – 6 34 34 – 6 – 40 74 – – 57 – 4 61 67 4 42 29 142 203 – –
Extensions and discoveries – 8 6 14 77 9 – 17 103 117 – – – 37 7 44 53 21 1 65 140 184 – –
Purchases¹
– 2 – 2 – – – – – 2 – – – 49 147 196 4 287 20 65 376 572 – –
Sales²
– (27 ) (103 ) (130 ) (16 ) – – (33 ) (49 ) (179 ) – – (1 ) – (1 ) (2 ) – – – (58 ) (58 ) (60 ) – –
Production (81 ) (56 ) (47 ) (184 ) (115 ) (86 ) (79 ) (101 ) (381 ) (565 ) (52 ) (9 ) (79 ) (41 ) (45 ) (165 ) (114 ) (103 ) (74 ) (89 ) (380 ) (545 ) (50 ) (14 )

RESERVES AT DEC. 31, 2004³
1,011 294 432 1,737 1,833 676 698 567 3,774 5,511 1,994 468
Reserves at Dec. 31, 2005³
965 333 533 1,831 1,814 829 579 573 3,795 5,626 1,939 435
Changes attributable to:
Revisions (23 ) (6 ) (11 ) (40 ) (29 ) (56 ) (108 ) (6 ) (199 ) (239 ) (5 ) (19 ) (14 ) 7 7 – (49 ) 72 61 (45 ) 39 39 60 24
Improved recovery 57 – 4 61 67 4 42 29 142 203 – – 49 – 3 52 13 1 6 11 31 83 – –
Extensions and discoveries – 37 7 44 53 21 1 65 140 184 – – – 25 8 33 30 6 2 36 74 107 – –
Purchases¹
– 49 147 196 4 287 20 65 376 572 – – 2 2 – 4 15 – – 2 17 21 – 119
Sales²
(1 ) – (1 ) (2 ) – – – (58 ) (58 ) (60 ) – – – – – – – – – (15 ) (15 ) (15 ) – –
Production (79 ) (41 ) (45 ) (165 ) (114 ) (103 ) (74 ) (89 ) (380 ) (545 ) (50 ) (14 ) (76 ) (42 ) (51 ) (169 ) (125 ) (123 ) (72 ) (78 ) (398 ) (567 ) (49 ) (16 )

RESERVES AT DEC. 31, 2005³
965 333 533 1,831 1,814 829 579 573 3,795 5,626 1,939 435
Reserves at Dec. 31, 2006³
926 325 500 1,751 1,698 785 576 484 3,543 5,294 1,950 562
Changes attributable to:
Revisions (14 ) 7 7 – (49 ) 72 61 (45 ) 39 39 60 24 1 (1 ) (5 ) (5 ) (89 ) 7 (66 ) 7 (141 ) (146 ) 92 11
Improved recovery 49 – 3 52 13 1 6 11 31 83 – – 6 – 3 9 7 3 1 – 11 20 – –
Extensions and discoveries – 25 8 33 30 6 2 36 74 107 – – 1 25 10 36 6 1 – 17 24 60 – –
Purchases¹
2 2 – 4 15 – – 2 17 21 – 119 1 9 – 10 – – – – – 10 – 316
Sales²
– – – – – – – (15 ) (15 ) (15 ) – – – (8 ) (1 ) (9 ) – – – – – (9 ) – (432 )
Production (76 ) (42 ) (51 ) (169 ) (125 ) (123 ) (72 ) (78 ) (398 ) (567 ) (49 ) (16 ) (75 ) (43 ) (50 ) (168 ) (122 ) (128 ) (72 ) (74 ) (396 ) (564 ) (53 ) (24 )

RESERVES AT DEC. 31, 2006^3,4
926 325 500 1,751 1,698 785 576 484 3,543 5,294 1,950 562
Reserves at Dec. 31, 2007^3,4
860 307 457 1,624 1,500 668 439 434 3,041 4,665 1,989 433

DEVELOPED RESERVES⁵

Developed Reserves⁵

At Jan. 1, 2004 832 304 515 1,651 1,059 641 588 522 2,810 4,461 1,304 140
At Dec. 31, 2004 832 192 386 1,410 990 543 490 469 2,492 3,902 1,510 188
At Jan. 1, 2005 832 192 386 1,410 990 543 490 469 2,492 3,902 1,510 188
At Dec. 31, 2005 809 177 474 1,460 945 534 439 416 2,334 3,794 1,611 196 809 177 474 1,460 945 534 439 416 2,334 3,794 1,611 196
At Dec. 31, 2006
749 163 443 1,355 893 530 426 349 2,198 3,553 1,003 311 749 163 443 1,355 893 530 426 349 2,198 3,553 1,003 311
At Dec. 31, 2007
701 136 401 1,238 758 422 363 305 1,848 3,086 1,273 263

¹ Includes reserves acquired through ~~property exchanges.~~nonmonetary transactions.
² Includes reserves disposed of through ~~property exchanges.~~nonmonetary transactions.
³ Included are year-end reserve quantities related to production-sharing contracts (PSC) (refer to page ~~E-11~~E-23 for the definition of a PSC). PSC-related reserve quantities are 26 percent, 30 percent ~~29 percent~~ and 2829 percent for consolidated companies for 2007, 2006 and 2005, ~~and 2004, respectively, and 100 percent for TCO for each year.~~respectively.
⁴ Net reserve changes (excluding production) in ~~2006~~2007 consist of ~~326~~97 million barrels of developed reserves and ~~(91)~~(162) million barrels of undeveloped reserves for consolidated companies and ~~(428)~~299 million barrels of developed reserves and ~~631~~(312) million barrels of undeveloped reserves for affiliated companies.
⁵ During ~~2006,~~2007, the percentages of undeveloped reserves at December 31, ~~2005,~~2006, transferred to developed reserves were 118 percent and 224 percent for consolidated companies and affiliated companies, respectively.
~~INFORMATION ON CANADIAN OIL SANDS NET PROVED RESERVES NOT INCLUDED ABOVE:~~Information on Canadian Oil Sands Net Proved Reserves Not Included Above:
In addition to conventional liquids and natural gas proved reserves, Chevron has significant interests in proved oil sands reserves in Canada associated with the Athabasca project. For internal management purposes, Chevron views these reserves and their development as an integral part of total upstream operations. However, SEC regulations define these reserves as mining-related and not a part of conventional oil and gas reserves. Net proved oil sands reserves were ~~443~~436 million barrels as of December 31, ~~2006.~~2007. The oil sands reserves are not considered in the standardized measure of discounted future net cash flows for conventional oil and gas reserves, which is found on page ~~FS-75.~~FS-73.
     Noteworthy amounts in the categories of liquids proved-reserve changes for ~~2004~~2005 through ~~2006 in the table above~~2007 are discussed below:
     Revisions   In 2004, net revisions decreased reserves 218 million barrels for consolidated companies and increased reserves for affiliates by 204 million barrels. For consolidated companies, the decrease was composed of 161 million barrels for international areas and 57 million barrels for the United States. The largest downward revision internationally was 70 million barrels in Africa. One field in Angola accounted
for the majority of the net decline as changes were made to oil-in-place estimates based on reservoir performance data. One field in the Asia-Pacific area essentially accounted for the 43 million-barrel downward revision for that region. The revision was associated with reduced well performance. Part of the 36 million-barrel net downward revision for Indonesia was associated with the effect of higher year-end prices on the calculation of reserves for cost-oil recovery under a production-sharing contract. In the United States, the 68 million-barrel net downward revision in the Gulf of

~~FS-70~~

~~TABLE V~~ ~~– RESERVE QUANTITY INFORMATION – Continued~~
Mexico area was across several fields and based mainly on reservoir analyses and assessments of well performance. For affiliated companies, the 206 million-barrel increase for TCO was based on an updated assessment of reservoir performance for the Tengiz Field. Partially offsetting this increase was a downward effect of higher year-end prices on the variable royalty-rate calculation. Downward revisions also occurred in other geographic areas because of the effect of higher year-end prices on various production-sharing terms and variable royalty calculations.
In 2005, net revisions reduced reserves by 239 million and 24 million barrels for worldwide consolidated companies and equity affiliates, respectively. For consolidated companies, the net decrease was 199 million barrels in the international areas and 40 million barrels in the United States. The largest downward net revisions internationally were 108 million barrels in Indonesia and
53 million barrels in Kazakhstan, due primarily to the effect of higher year-end prices on the calculation of reserves associated with production-sharing and variable-royalty contracts. In the United States, the 40 million-barrel reduction was across many fields in each of the geographic sections. Most of the downward revision for affiliated companies was a 19 million-barrel reduction in Hamaca, attributable to revised government royalty provisions. For TCO, the downward effect of higher year-end prices was partially offset by increased reservoir performance.

FS-68

Table V Reserve Quantity Information – Continued
     In 2006, net revisions increased reserves by 39 million and 84 million barrels for worldwide consolidated companies and equity affiliates, respectively. International consolidated companies accounted for the net increase of 39 million barrels. The largest upward net revisions were 61 million barrels in Indonesia and 27 million barrels in Thailand. In Indonesia, the increase was the result of infill drilling and improved steamflood performance. The upward revision in Thailand reflected additional drilling and development activity during the year. These upward revisions were partially offset by reductions in reservoir performance in Nigeria and the United Kingdom, which decreased reserves by 43 million barrels and by 32 million barrels, respectively. Most of the upward revision for affiliated companies was related to a 60 ~~million barrel~~million-barrel increase in TCO as a result of improved reservoir performance.
     In 2007, net revisions decreased reserves by 146 million barrels for worldwide consolidated companies and increased reserves by 103 million barrels for equity affiliates. For consolidated companies, the largest downward net revisions were 89 million barrels in Africa and 66 million barrels in Indonesia. In Africa, the decrease was mainly based on field performance data for fields in Nigeria and the effect of higher year-end prices in Angola and the Republic of the Congo. In Indonesia, the decline also reflected the impact of higher year-end prices. Higher prices also resulted in downward revisions in Karachaganak and Azerbaijan. For equity affiliates, most of the upward revision was related to a 92 million-barrel increase for the Tengiz Field in TCO and an 11 million-barrel increase for Petroboscan in Venezuela, both as a result of improved reservoir performance. At TCO, the upward revision was tempered by the negative impact of higher year-end prices.
Improved Recovery In 2005, improved recovery increased liquids volumes worldwide by 203 million barrels for consolidated companies. International areas accounted for 142 million barrels of the increase. Indonesia added 42 million barrels due to improved performance. Reserve additions of 67 million barrels in Africa occurred primarily in Angola and resulted from infill drilling, wells workovers and secondary recovery from gas injection. Additions of 29 million barrels in the “Other” international area were mainly attributable to improved waterflood performance offshore eastern Canada. An increase of 61 million barrels occurred in the United States, primarily in California due to improved performance on a large heavy oil field under thermal recovery.
     In 2006, improved recovery increased liquids volumes worldwide by 83 million barrels for consolidated companies. Reserves in the United States increased 52 million barrels, with California representing 49 million barrels of the total increase due to steamflood expansion and revised modeling activities. Internationally, improved recovery increased reserves by 31 million barrels, with no single country accounting for an increase of more than 10 million barrels.
     In 2007, improved recovery increased liquids volumes by 20 million barrels worldwide. No addition was individually significant.
     Extensions and Discoveries In 2005, extensions and discoveries increased liquids volumes worldwide by 184 million barrels for consolidated companies. The largest increase was 49 million barrels in Nigeria, reflecting new development drilling, including in the Agbami Field, among others. New field developments in Brazil contributed another 41 million barrels of discoveries. In the United States, the 44 million-barrel addition was associated mainly with the initial booking of reserves for the Blind Faith Field in the deepwater Gulf of Mexico.
     In 2006, extensions and discoveries increased liquids volumes worldwide by 107 million barrels for consolidated companies. Reserves in Nigeria
increased by 27 million barrels due in part to the initial booking of reserves for the Aparo ~~field.~~Field. Additional drilling activities contributed 19 million barrels in the United Kingdom and 14 million barrels in Argentina. In the United States, the Gulf of Mexico added 25 million barrels, mainly the result of the initial booking of the Great White Field in the deepwater Perdido Fold Belt area.
     In 2007, extensions and discoveries increased liquids volumes by 60 million barrels worldwide. The largest additions were 25 million barrels in the U.S. Gulf of Mexico, mainly for the deepwater Tahiti and Mad Dog fields.
     Purchases In 2005, the acquisition of 572 million barrels of liquids related solely to the acquisition of Unocal in August. About three-fourths of the 376 million barrels acquired in the international areas were represented by volumes in Azerbaijan and Thailand. Most volumes acquired in the United States were in Texas and Alaska.
     In 2006, acquisitions increased liquids volumes worldwide by 21 million barrels for consolidated companies and 119 million barrels for equity affiliates. For consolidated companies, the amount was mainly the result of new agreements in Nigeria, which added 13 million barrels of reserves. The other-equity-affiliates quantity reflects the result of the conversion of Boscan and LL-652 operations to joint stock companies in Venezuela.
     In 2007, acquisitions of 316 million barrels for equity affiliates related to the formation of a new Hamaca equity affiliate in Venezuela.
Sales   In 2004, sales of liquids volumes reduced reserves of consolidated companies by 179 million barrels. Sales totaled 130 million barrels in the United States and 33 million barrels in the “Other” international region. Sales in the “Other” region of the United States totaled 103 million barrels, with two fields accounting for approximately one-half of the volume. The 27 million barrels sold in the Gulf of Mexico reflect the sale of a number of Shelf properties. The “Other” international sales include the disposal of western Canada properties and several fields in the United Kingdom. All the sales were associated with the company’s program to dispose of assets deemed nonstrategic to the portfolio of producing properties.
In 2005, sales of 58 million barrels in the “Other” international area related to the disposition of the former Unocal operations onshore in Canada.
     In 2006, sales decreased reserves by 15 million barrels due to the conversion of the LL-652 risked service agreement to a joint stock company in Venezuela.
     In 2007, affiliated company sales of 432 million barrels related to the dissolution of a Hamaca equity affiliate in Venezuela.

~~FS-71~~FS-69

Supplemental Information on Oil and Gas Producing Activities –Continued

~~TABLE~~Table V ~~– RESERVE QUANTITY INFORMATION~~Reserve Quantity Information – Continued

~~NET PROVED RESERVES OF NATURAL GAS~~Net Proved Reserves of Natural Gas

Consolidated Companies Consolidated Companies
United States International United States International
Gulf of Total Asia- Total Affiliated Companies Gulf of Total Asia- Total Affiliated Companies
Billions of cubic feet Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int’l. Total TCO Other Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int'l. Total TCO Other

RESERVES AT JAN. 1, 2004³
323 1,841 3,189 5,353 2,642 5,373 520 3,665 12,200 17,553 2,526 112
Reserves at Jan. 1, 2005
314 1,064 2,326 3,704 2,979 5,405 502 3,538 12,424 16,128 3,413 134
Changes attributable to:
Revisions 27 (391 ) (316 ) (680 ) 346 236 21 325 928 248 963 23 21 (15 ) (15 ) (9 ) 211 (428 ) (31 ) 243 (5 ) (14 ) (547 ) 49
Improved recovery 2 – 1 3 7 – 13 – 20 23 – – 8 – – 8 13 – – 31 44 52 – –
Extensions and discoveries 1 54 89 144 16 39 2 13 70 214 – – – 68 99 167 25 118 5 55 203 370 – –
Purchases¹
– 5 – 5 – 4 – – 4 9 – – – 269 899 1,168 5 3,962 247 274 4,488 5,656 – –
Sales²
– (147 ) (289 ) (436 ) – – – (111 ) (111 ) (547 ) – – – – (6 ) (6 ) – – – (248 ) (248 ) (254 ) – –
Production (39 ) (298 ) (348 ) (685 ) (32 ) (247 ) (54 ) (354 ) (687 ) (1,372 ) (76 ) (1 ) (39 ) (215 ) (350 ) (604 ) (42 ) (434 ) (77 ) (315 ) (868 ) (1,472 ) (79 ) (2 )

RESERVES AT DEC. 31, 2004³
314 1,064 2,326 3,704 2,979 5,405 502 3,538 12,424 16,128 3,413 134
Reserves at Dec. 31, 2005³
304 1,171 2,953 4,428 3,191 8,623 646 3,578 16,038 20,466 2,787 181
Changes attributable to:
Revisions 21 (15 ) (15 ) (9 ) 211 (428 ) (31 ) 243 (5 ) (14 ) (547 ) 49 32 40 (102 ) (30 ) 34 400 38 39 511 481 26 –
Improved recovery 8 – – 8 13 – – 31 44 52 – – 5 – – 5 3 – – 5 8 13 – –
Extensions and discoveries – 68 99 167 25 118 5 55 203 370 – – – 111 157 268 11 510 – 10 531 799 – –
Purchases¹
– 269 899 1,168 5 3,962 247 274 4,488 5,656 – – 6 13 – 19 – 16 – – 16 35 – 54
Sales²
– – (6 ) (6 ) – – – (248 ) (248 ) (254 ) – – – – (1 ) (1 ) – – – (148 ) (148 ) (149 ) – –
Production (39 ) (215 ) (350 ) (604 ) (42 ) (434 ) (77 ) (315 ) (868 ) (1,472 ) (79 ) (2 ) (37 ) (241 ) (383 ) (661 ) (33 ) (629 ) (110 ) (302 ) (1,074 ) (1,735 ) (70 ) (4 )

RESERVES AT DEC. 31, 2005³
304 1,171 2,953 4,428 3,191 8,623 646 3,578 16,038 20,466 2,787 181
Reserves at Dec. 31, 2006³
310 1,094 2,624 4,028 3,206 8,920 574 3,182 15,882 19,910 2,743 231
Changes attributable to:
Revisions 32 40 (102 ) (30 ) 34 400 38 39 511 481 26 – 40 39 130 209 (141 ) 149 12 166 186 395 75 (2 )
Improved recovery 5 – – 5 3 – – 5 8 13 – – – – – – – – – 1 1 1 – –
Extensions and discoveries – 111 157 268 11 510 – 10 531 799 – – – 40 46 86 11 392 – 29 432 518 – –
Purchases¹
6 13 – 19 – 16 – – 16 35 – 54 2 19 29 50 – 91 – – 91 141 – 211
Sales²
– – (1 ) (1 ) – – – (148 ) (148 ) (149 ) – – – (39 ) (37 ) (76 ) – – – – – (76 ) – (175 )
Production (37 ) (241 ) (383 ) (661 ) (33 ) (629 ) (110 ) (302 ) (1,074 ) (1,735 ) (70 ) (4 ) (35 ) (210 ) (375 ) (620 ) (27 ) (725 ) (101 ) (279 ) (1,132 ) (1,752 ) (70 ) (10 )

RESERVES AT DEC. 31, 2006^3,4
310 1,094 2,624 4,028 3,206 8,920 574 3,182 15,882 19,910 2,743 231
Reserves at Dec. 31, 2007^3,4
317 943 2,417 3,677 3,049 8,827 485 3,099 15,460 19,137 2,748 255

DEVELOPED RESERVES⁵

At Jan. 1, 2004 265 1,572 2,964 4,801 954 3,627 223 3,043 7,847 12,648 1,789 52
At Dec. 31, 2004 252 937 2,191 3,380 1,108 3,701 271 2,273 7,353 10,733 2,584 63
Developed Reserves⁵

At Jan. 1, 2005 252 937 2,191 3,380 1,108 3,701 271 2,273 7,353 10,733 2,584 63
At Dec. 31, 2005 251 977 2,794 4,022 1,346 4,819 449 2,453 9,067 13,089 2,314 85 251 977 2,794 4,022 1,346 4,819 449 2,453 9,067 13,089 2,314 85
At Dec. 31, 2006
250 873 2,434 3,557 1,306 4,751 377 1,912 8,346 11,903 1,412 144 250 873 2,434 3,557 1,306 4,751 377 1,912 8,346 11,903 1,412 144
At Dec. 31, 2007
261 727 2,238 3,226 1,151 5,081 326 1,915 8,473 11,699 1,762 117

¹ Includes reserves acquired through ~~property exchanges.~~nonmonetary transactions.

² Includes reserves disposed of through ~~property exchanges.~~nonmonetary transactions.

³ ~~Included are~~Includes year-end reserve quantities related to production-sharing contracts (PSC) (refer to page ~~E-11~~E-23 for the definition of a PSC). PSC-related reserve quantities are 37 percent, 47 percent ~~44 percent~~ and 3344 percent for consolidated companies for 2007, 2006 and 2005, ~~and 2004, respectively, and 100 percent for TCO for each year.~~respectively.

⁴ Net reserve changes (excluding production) in ~~2006~~2007 consist of ~~549~~1,548 billion cubic feet of developed reserves and ~~630~~(569) billion cubic feet of undeveloped reserves for consolidated companies and ~~(769)~~403 billion cubic feet of developed reserves and ~~849~~(294) billion cubic feet of undeveloped reserves for affiliated companies.

⁵ During ~~2005,~~2007, the percentages of undeveloped reserves at December 31, ~~2004,~~2006, transferred to developed reserves were 510 percent and 227 percent for consolidated companies and affiliated companies, respectively.
     Noteworthy amounts in the categories of natural gas proved-reserve changes for ~~2004~~2005 through ~~2006 in the table above~~2007 are discussed below:
     Revisions In 2004, revisions increased reserves for consolidated companies by a net 248 billion cubic feet (BCF), composed of increases of 928 BCF internationally and decreases of 680 BCF in the United States. Internationally, about half of the 346 BCF increase in Africa related to properties in Nigeria, for which changes were associated with well performance reviews, development drilling and lease fuel calculations. The 236 BCF addition in the Asia-Pacific region was related primarily to reservoir analysis for a single field. Most of the 325 BCF in the “Other” international area
was related to a new gas sales contract in Trinidad and Tobago. In the United States, the net 391 BCF downward revision in the Gulf of Mexico was related to well-performance reviews and technical analyses in several fields. Most of the net 316 BCF negative revision in the “Other” U.S. area related to two coal bed methane fields in the Mid-Continent region and their associated wells’ performance. The 963 BCF increase for TCO was connected with updated analyses of reservoir performance and processing plant yields.
     In 2005, reserves were revised downward by 14 ~~BCF~~billion cubic feet (BCF) for consolidated companies and 498 BCF for equity affiliates. For consolidated companies, negative revisions were 428 BCF in the Asia-Pacific region. Most of the decrease was ~~attribut-~~

~~FS-72~~

~~TABLE V~~ ~~– RESERVE QUANTITY INFORMATION – Continued~~
~~able~~attributable to one field in Kazakhstan, due mainly to the effects of higher year-end prices on variable-royalty provisions of the production-sharing contract. Reserves additions for consolidated companies totaled 211 BCF and 243 BCF in Africa and “Other,”
respectively. The majority of the African region changes were in Angola, due to a revised forecast of fuel gas usage, and in Nigeria, from improved reservoir performance. The availability of third-party compression in Colombia accounted for most of the increase in the “Other” region. Revisions in the United States decreased reserves by 9 BCF, as nominal increases in the San Joaquin Valley were more than offset by decreases in the Gulf of Mexico and “Other” region. For the TCO affiliate in Kazakhstan, a reduction of 547 BCF reflects the updated forecast of future royalties payable and year-end price effects, partially offset by volumes added as a result of an updated assessment of reservoir performance.

FS-70

Table V Reserve Quantity Information – Continued
     In 2006, revisions accounted for a net increase of 481 BCF for consolidated companies and 26 BCF for affiliates. For consolidated companies, net increases of 511 BCF internationally were partially offset by a 30 BCF downward revision in the United States. Drilling and development activities added 337 BCF of reserves in Thailand, while Kazakhstan added 200 BCF, largely due to development activity. Trinidad and Tobago increased 185 BCF, attributable to improved reservoir performance and a new contract for sales of natural gas. These additions were partially offset by downward revisions of 224 BCF in the United Kingdom and 130 BCF in Australia due to drilling results and reservoir performance. U.S. “Other” had a downward revision of 102 BCF due to reservoir performance, which was partially offset by upward revisions of 72 BCF in the Gulf of Mexico and California related to reservoir performance and development drilling. TCO had an upward revision of 26 BCF associated with additional development activity and updated reservoir performance.
     In 2007, revisions increased reserves for consolidated companies by a net 395 BCF and increased reserves for affiliated companies by a net 73 BCF. For consolidated companies, net increases were 209 BCF in the United States and 186 BCF internationally. Improved reservoir performance for many fields in the United States contributed 130 BCF in the “Other” region, 40 BCF in California and 39 BCF in the Gulf of Mexico. Drilling activities added 360 BCF in Thailand and improved reservoir performance added 188 BCF in Trinidad and Tobago. These additions were partially offset by downward revisions of 185 BCF in Australia due to drilling results and 136 BCF in Nigeria due to field performance. Negative revisions due to the impact of higher prices were recorded in Azerbaijan and Kazakhstan. TCO had an upward revision of 75 BCF associated with improved reservoir performance and development activities. This upward revision was net of a negative impact due to higher year-end prices.
Extensions and Discoveries   In 2004, extensions and discoveries accounted for an increase of 214 BCF, reflecting an increase in the United States of 144 BCF, with 89 BCF added in the “Other” region and 54 BCF added in the Gulf of Mexico through drilling activities in a large number of fields.
In 2005, consolidated companies increased reserves by 370 BCF, including 167 BCF in the United States and 118 BCF in the Asia-Pacific region. In the United States, 99 BCF was added in the “Other” region and 68 BCF in the Gulf of Mexico, primarily due to drilling activities. The addition in Asia-Pacific resulted primarily from increased drilling in Kazakhstan.
     In 2006, extensions and discoveries accounted for an increase of 799 BCF for consolidated companies, reflecting a 531 BCF increase outside the United States and a U.S. increase of 268 BCF. Bangladesh added 451 BCF, the result of development activity and field extensions, and Thailand added 59 BCF, the result of drilling activities. U.S. “Other” contributed
157 BCF, approximately half of which was related to ~~the~~ South Texas and the Piceance Basin, and the Gulf of Mexico added 111 BCF, partly due to the initial booking of reserves at the Great White ~~field~~Field in the deepwater Perdido Fold Belt area.
     In 2007, extensions and discoveries accounted for an increase of 518 BCF worldwide. The largest addition was 330 BCF in Bangladesh, the result of drilling activities. Other additions were not individually significant.
     Purchases In 2005, all except 7 BCF of the 5,656 BCF total purchases were associated with the Unocal acquisition. International reserve acquisitions were 4,488 BCF, with Thailand accounting for about half the volumes. Other significant volumes were added in Bangladesh and Myanmar.
     In 2006, ~~acquisition~~purchases of natural gas reserves were 35 BCF for consolidated companies, about evenly divided between the company’s United States and international operations. Affiliated companies added 54 BCF of reserves, the result of conversion of an operating service agreement to a joint stock company in Venezuela.
     ~~Sales~~In ~~2004, sales~~2007, purchases of natural gas reserves were 141 BCF for consolidated companies, ~~totaled 547 BCF. Of this total, 436 BCF was~~which included the acquisition of an additional interest in the ~~United States and 111~~Bibiyana Field in Bangladesh. Affiliated company purchases of 211 BCF inrelated to the ~~“Other” international region. In the United States, “Other” region sales accounted for 289 BCF, reflecting the disposal~~formation of a ~~large number of smaller properties, including a coal bed methane field. Gulf of Mexico sales of 147 BCF reflected~~new Hamaca equity affiliate in Venezuela and an initial booking related to the sale of Shelf properties, with four fields accounting for more than one-third of the total sales. Sales in the “Other” international region reflected the disposition of the properties in western Canada and the United Kingdom.Angola LNG project.
Sales In 2005, sales of 248 BCF in the “Other” international region related to the disposition of former-Unocal’s onshore properties in Canada.
     In 2006, sales for consolidated companies totaled 149 BCF, mostly associated with the conversion of a risked service agreement to a joint stock company in Venezuela.
     In 2007, sales were 76 BCF and 175 BCF for consolidated companies and equity affiliates, respectively. The affiliated company sales related to the dissolution of a Hamaca equity affiliate in Venezuela.

~~FS-73~~FS-71

Supplemental Information on Oil and Gas Producing Activities –Continued

~~TABLE~~
Table VI ~~– STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS~~
~~RELATED TO PROVED OIL AND GAS RESERVES~~ Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves

     The standardized measure of discounted future net cash flows, related to the preceding proved oil and gas reserves, is calculated in accordance with the requirements of FAS 69. Estimated future cash inflows from production are computed by applying year-end prices for oil and gas to year-end quantities of estimated net proved reserves. Future price changes are limited to those provided by contractual arrangements in existence at the end of each reporting year. Future development and production costs are those estimated future expenditures necessary to develop and produce year-end estimated proved reserves based on year-end cost indices, assuming continuation of year-end economic conditions, and include estimated costs for asset retirement obligations. Estimated future income taxes are calculated by applying appropriate year-end statutory tax rates. These rates reflect allowable deductions and tax credits and are applied to estimated future pretax net cash flows, less the tax basis of related assets. Discounted future net cash flows are calculated
using 10 percent midperiod discount factors. Discounting requires a year-by-year estimate of when future expenditures will be incurred and when reserves will be produced.
     The information provided does not represent management’s estimate of the company’s expected future cash flows or value of proved oil and gas reserves. Estimates of proved-reserve quantities are imprecise and change over time as new information becomes available. Moreover, probable and possible reserves, which may become proved in the future, are excluded from the calculations. The arbitrary valuation prescribed under FAS 69 requires assumptions as to the timing and amount of future development and production costs. The calculations are made as of December 31 each year and should not be relied upon as an indication of the company’s future cash flows or value of its oil and gas reserves. In the following table, “Standardized Measure Net Cash Flows” refers to the standardized measure of discounted future net cash flows.

~~FS-74~~FS-72

~~TABLE~~Table VI ~~– STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS~~
~~RELATED TO PROVED OIL AND GAS RESERVES~~Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves – Continued

Consolidated Companies Consolidated Companies
United States International United States International
Gulf of Total Asia- Total Affiliated Companies Gulf of Total Asia- Total Affiliated Companies
Millions of dollars Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int’l. Total TCO Other Calif. Mexico Other U.S. Africa Pacific Indonesia Other Int'l. Total TCO Other

AT DECEMBER 31, 2006

At December 31, 2007

Future cash inflows from production $ 48,828 $ 23,768 $ 38,727 $ 111,323 $ 97,571 $ 70,288 $ 30,538 $ 36,272 $ 234,669 $ 345,992 $ 104,069 $ 20,644 $ 75,201 $ 34,162 $ 52,775 $ 162,138 $ 132,450 $ 93,046 $ 35,020 $ 45,566 $ 306,082 $ 468,220 159,078 $ 29,845
Future production costs (14,791 ) (6,750 ) (12,845 ) (34,386 ) (12,523 ) (13,398 ) (16,281 ) (10,777 ) (52,979 ) (87,365 ) (7,796 ) (2,348 ) (17,888 ) (7,193 ) (16,780 ) (41,861 ) (15,707 ) (16,022 ) (18,270 ) (11,990 ) (61,989 ) (103,850 ) (10,408 ) (1,529 )
Future devel. costs (3,999 ) (2,947 ) (1,399 ) (8,345 ) (9,648 ) (6,963 ) (2,284 ) (3,082 ) (21,977 ) (30,322 ) (7,026 ) (1,732 ) (3,491 ) (3,011 ) (1,578 ) (8,080 ) (11,516 ) (8,263 ) (4,012 ) (3,468 ) (27,259 ) (35,339 ) (8,580 ) (1,175 )
Future income taxes (10,171 ) (4,764 ) (8,290 ) (23,225 ) (53,214 ) (20,633 ) (5,448 ) (11,164 ) (90,459 ) (113,684 ) (25,212 ) (8,282 ) (19,112 ) (8,507 ) (12,221 ) (39,840 ) (74,172 ) (26,838 ) (5,796 ) (15,524 ) (122,330 ) (162,170 ) (39,575 ) (13,600 )

Undiscounted future net cash flows 19,867 9,307 16,193 45,367 22,186 29,294 6,525 11,249 69,254 114,621 64,035 8,282 34,710 15,451 22,196 72,357 31,055 41,923 6,942 14,584 94,504 166,861 100,515 13,541
10 percent midyear annual discount for timing of estimated cash flows (9,779 ) (3,256 ) (7,210 ) (20,245 ) (10,065 ) (12,457 ) (2,426 ) (3,608 ) (28,556 ) (48,801 ) (40,597 ) (5,185 ) (17,204 ) (4,438 ) (9,491 ) (31,133 ) (14,171 ) (17,117 ) (2,702 ) (4,689 ) (38,679 ) (69,812 ) (64,519 ) (7,779 )

STANDARDIZED MEASURE NET CASH FLOWS
$ 10,088 $ 6,051 $ 8,983 $ 25,122 $ 12,121 $ 16,837 $ 4,099 $ 7,641 $ 40,698 $ 65,820 $ 23,438 $ 3,097
Standardized Measure Net Cash Flows
$ 17,506 $ 11,013 $ 12,705 $ 41,224 $ 16,884 $ 24,806 $ 4,240 $ 9,895 $ 55,825 $ 97,049 $ 35,996 $ 5,762

AT DECEMBER 31, 2005

At December 31, 2006

Future cash inflows from production $ 50,771 $ 29,422 $ 50,039 $ 130,232 $ 101,912 $ 73,612 $ 32,538 $ 44,680 $ 252,742 $ 382,974 $ 97,707 $ 20,616 $ 48,828 $ 23,768 $ 38,727 $ 111,323 $ 97,571 $ 70,288 $ 30,538 $ 36,272 $ 234,669 $ 345,992 $ 104,069 $ 20,644
Future production costs (15,719 ) (5,758 ) (12,767 ) (34,244 ) (11,366 ) (12,459 ) (18,260 ) (11,908 ) (53,993 ) (88,237 ) (7,399 ) (2,101 ) (14,791 ) (6,750 ) (12,845 ) (34,386 ) (12,523 ) (13,398 ) (16,281 ) (10,777 ) (52,979 ) (87,365 ) (7,796 ) (2,348 )
Future devel. costs (2,274 ) (2,467 ) (873 ) (5,614 ) (8,197 ) (5,840 ) (1,730 ) (2,439 ) (18,206 ) (23,820 ) (5,996 ) (762 ) (3,999 ) (2,947 ) (1,399 ) (8,345 ) (9,648 ) (6,963 ) (2,284 ) (3,082 ) (21,977 ) (30,322 ) (7,026 ) (1,732 )
Future income taxes (11,092 ) (7,173 ) (12,317 ) (30,582 ) (50,894 ) (21,509 ) (5,709 ) (13,917 ) (92,029 ) (122,611 ) (23,818 ) (6,036 ) (10,171 ) (4,764 ) (8,290 ) (23,225 ) (53,214 ) (20,633 ) (5,448 ) (11,164 ) (90,459 ) (113,684 ) (25,212 ) (8,282 )

Undiscounted future net cash flows 21,686 14,024 24,082 59,792 31,455 33,804 6,839 16,416 88,514 148,306 60,494 11,717 19,867 9,307 16,193 45,367 22,186 29,294 6,525 11,249 69,254 114,621 64,035 8,282
10 percent midyear annual discount for timing of estimated cash flows (10,947 ) (4,520 ) (10,838 ) (26,305 ) (14,881 ) (14,929 ) (2,269 ) (5,635 ) (37,714 ) (64,019 ) (37,674 ) (7,768 ) (9,779 ) (3,256 ) (7,210 ) (20,245 ) (10,065 ) (12,457 ) (2,426 ) (3,608 ) (28,556 ) (48,801 ) (40,597 ) (5,185 )

STANDARDIZED MEASURE NET CASH FLOWS
$ 10,739 $ 9,504 $ 13,244 $ 33,487 $ 16,574 $ 18,875 $ 4,570 $ 10,781 $ 50,800 $ 84,287 $ 22,820 $ 3,949
Standardized Measure Net Cash Flows
$ 10,088 $ 6,051 $ 8,983 $ 25,122 $ 12,121 $ 16,837 $ 4,099 $ 7,641 $ 40,698 $ 65,820 $ 23,438 $ 3,097

AT DECEMBER 31, 2004

At December 31, 2005

Future cash inflows from production $ 32,793 $ 19,043 $ 28,676 $ 80,512 $ 64,628 $ 35,960 $ 25,313 $ 30,061 $ 155,962 $ 236,474 $ 61,875 $ 12,769 $ 50,771 $ 29,422 $ 50,039 $ 130,232 $ 101,912 $ 73,612 $ 32,538 $ 44,680 $ 252,742 $ 382,974 $ 97,707 $ 20,616
Future production costs (11,245 ) (3,840 ) (7,343 ) (22,428 ) (10,662 ) (8,604 ) (12,830 ) (7,884 ) (39,980 ) (62,408 ) (7,322 ) (3,734 ) (15,719 ) (5,758 ) (12,767 ) (34,244 ) (11,366 ) (12,459 ) (18,260 ) (11,908 ) (53,993 ) (88,237 ) (7,399 ) (2,101 )
Future devel. costs (1,731 ) (2,389 ) (667 ) (4,787 ) (6,355 ) (2,531 ) (717 ) �� (1,593 ) (11,196 ) (15,983 ) (5,366 ) (407 ) (2,274 ) (2,467 ) (873 ) (5,614 ) (8,197 ) (5,840 ) (1,730 ) (2,439 ) (18,206 ) (23,820 ) (5,996 ) (762 )
Future income taxes (6,706 ) (4,336 ) (6,991 ) (18,033 ) (29,519 ) (9,731 ) (5,354 ) (9,914 ) (54,518 ) (72,551 ) (13,895 ) (2,934 ) (11,092 ) (7,173 ) (12,317 ) (30,582 ) (50,894 ) (21,509 ) (5,709 ) (13,917 ) (92,029 ) (122,611 ) (23,818 ) (6,036 )

Undiscounted future net cash flows 13,111 8,478 13,675 35,264 18,092 15,094 6,412 10,670 50,268 85,532 35,292 5,694 21,686 14,024 24,082 59,792 31,455 33,804 6,839 16,416 88,514 148,306 60,494 11,717
10 percent midyear annual discount for timing of estimated cash flows (6,656 ) (2,715 ) (6,110 ) (15,481 ) (9,035 ) (6,966 ) (2,465 ) (3,451 ) (21,917 ) (37,398 ) (22,249 ) (3,817 ) (10,947 ) (4,520 ) (10,838 ) (26,305 ) (14,881 ) (14,929 ) (2,269 ) (5,635 ) (37,714 ) (64,019 ) (37,674 ) (7,768 )

STANDARDIZED MEASURE NET CASH FLOWS
$ 6,455 $ 5,763 $ 7,565 $ 19,783 $ 9,057 $ 8,128 $ 3,947 $ 7,219 $ 28,351 $ 48,134 $ 13,043 $ 1,877
Standardized Measure Net Cash Flows
$ 10,739 $ 9,504 $ 13,244 $ 33,487 $ 16,574 $ 18,875 $ 4,570 $ 10,781 $ 50,800 $ 84,287 $ 22,820 $ 3,949

~~FS-75~~FS-73

Supplemental Information on Oil and Gas Producing Activities –Continued

~~TABLE~~
Table VII ~~– CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET~~
~~CASH FLOWS FROM PROVED RESERVES~~ Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves

     The changes in present values between years, which can be significant, reflect changes in estimated ~~proved reserve~~proved-reserve quantities and prices and assumptions used in forecasting
production volumes and costs. Changes in the timing of production are included with “Revisions of previous quantity estimates.”

Consolidated Companies Affiliated Companies Consolidated Companies Affiliated Companies
Millions of dollars 2006 2005 2004 2006 2005 2004 2007 2006 2005 2007 2006 2005

PRESENT VALUE AT JANUARY 1
$ 84,287 $ 48,134 $ 50,805 $ 26,769 $ 14,920 $ 13,118
Present Value at January 1 $ 65,820 $ 84,287 $ 48,134 $ 26,535 $ 26,769 $ 14,920

Sales and transfers of oil and gas produced net of production costs (32,690 ) (26,145 ) (18,843 ) (3,180 ) (2,712 ) (1,602 ) (34,957 ) (32,690 ) (26,145 ) (4,084 ) (3,180 ) (2,712 )
Development costs incurred 8,875 5,504 3,579 721 810 1,104 10,468 8,875 5,504 889 721 810
Purchases of reserves 580 25,307 58 1,767 – – 780 580 25,307 7,711 1,767 –
Sales of reserves (306 ) (2,006 ) (3,734 ) – – – (425 ) (306 ) (2,006 ) (7,767 ) – –
Extensions, discoveries and improved recovery less related costs 4,067 7,446 2,678 – – – 3,664 4,067 7,446 – – –
Revisions of previous quantity estimates 7,277 (13,564 ) 1,611 (967 ) (2,598 ) 970 (7,801 ) 7,277 (13,564 ) (1,333 ) (967 ) (2,598 )
Net changes in prices, development and production costs (24,725 ) 61,370 6,173 (837 ) 19,205 266 74,900 (24,725 ) 61,370 23,616 (837 ) 19,205
Accretion of discount 14,218 8,160 8,139 3,673 2,055 1,818 12,196 14,218 8,160 3,745 3,673 2,055
Net change in income tax 4,237 (29,919 ) (2,332 ) (1,412 ) (4,911 ) (754 ) (27,596 ) 4,237 (29,919 ) (7,554 ) (1,411 ) (4,911 )

Net change for the year (18,467 ) 36,153 (2,671 ) (235 ) 11,849 1,802 31,229 (18,467 ) 36,153 15,223 (234 ) 11,849

PRESENT VALUE AT DECEMBER 31
$ 65,820 $ 84,287 $ 48,134 $ 26,534 $ 26,769 $ 14,920
Present Value at December 31 $ 97,049 $ 65,820 $ 84,287 $ 41,758 $ 26,535 $ 26,769

~~FS-76~~FS-74

EXHIBIT INDEX

Exhibit No.
Description

3 .1 Restated Certificate of Incorporation of Chevron Corporation, dated May 9, 2005, filed as Exhibit 99.1 to Chevron Corporation’s Current Report onForm 8-K dated May 10, 2005, and incorporated herein by reference.

3 .2 By-Laws of Chevron Corporation, as amended January 31, 2007, filed as Exhibit 3.1 to Chevron Corporation’s Current Report onForm 8-K dated January 31, 2007, and incorporated herein by reference.

4 Pursuant to the Instructions to Exhibits, certain instruments defining the rights of holders of long-term debt securities of the corporation and its consolidated subsidiaries are not filed because the total amount of securities authorized under any such instrument does not exceed 10 percent of the total assets of the corporation and its subsidiaries on a consolidated basis. A copy of such instrument will be furnished to the Commission upon request.

10 .1 Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan filed as Exhibit 10.6 to Chevron Corporation’s Current Report onForm 8-K dated December 6, 2006, and incorporated herein by reference.

10 .2 Management Incentive Plan of Chevron Corporation filed as Exhibit 10.3 to Chevron Corporation’s Current Report onForm 8-K dated December 6, 2006, and incorporated herein by reference.

10 .4 Chevron Corporation Long-Term Incentive Plan filed as Exhibit 10.4 to Chevron Corporation’s Current Report onForm 8-K dated December 6, 2006, and incorporated herein by reference.

10 .6 Chevron Corporation Deferred Compensation Plan for Management Employees, as amended and restated on December 7, 2005, filed as Exhibit 10.5 to Chevron Corporation’s Current Report onForm 8-K dated December 7, 2005, and incorporated herein by reference.

10 .7 Chevron Corporation Deferred Compensation Plan for Management Employees II filed as Exhibit 10.5 to Chevron Corporation’s Current Report onForm 8-K dated December 6, 2006, and incorporated herein by reference.

10 .8 Texaco Inc. Stock Incentive Plan, adopted May 9, 1989, as amended May 13, 1993, and May 13, 1997, filed as Exhibit 10.13 to Chevron Corporation’s Annual Report onForm 10-K for the year ended December 31, 2001, and incorporated herein by reference.

10 .9 Supplemental Pension Plan of Texaco Inc., dated June 26, 1975, filed as Exhibit 10.14 to Chevron Corporation’s Annual Report onForm 10-K for the year ended December 31, 2001, and incorporated herein by reference.

10 .10 Supplemental Bonus Retirement Plan of Texaco Inc., dated May 1, 1981, filed as Exhibit 10.15 to Chevron Corporation’s Annual Report onForm 10-K for the year ended December 31, 2001, and incorporated herein by reference.

10 .11 Texaco Inc. Director and Employee Deferral Plan approved March 28, 1997, filed as Exhibit 10.16 to Chevron Corporation’s Annual Report onForm 10-K for the year ended December 31, 2001, and incorporated herein by reference.

10 .12 Chevron Corporation 1998 Stock Option Program for U.S. Dollar Payroll Employees, filed as Exhibit 10.12 to Chevron Corporation’s Annual Report onForm 10-K for the year ended December 31, 2002, and incorporated herein by reference.

10 .13 Summary of Chevron’s Management and Incentive Plan Awards and Criteria, filed as Exhibit 10.13 to Chevron Corporation’s Quarterly Report onForm 10-Q for the quarterly period ended March 31, 2005, and incorporated herein by reference.

10 .14 Chevron Corporation Change in Control Surplus Employee Severance Program for Salary Grades 41 through 43 filed as Exhibit 10.1 to Chevron Corporation’s Current Report onForm 8-K dated December 6, 2006, and incorporated herein by reference.

Exhibit No.
Description

3 .1 Restated Certificate of Incorporation of Chevron Corporation, dated May 1, 2007, filed as Exhibit 3.1 to Chevron Corporation’s Quarterly Report onForm 10-Q for the quarterly period ended March 31, 2007, and incorporated herein by reference.

3 .2 By-Laws of Chevron Corporation, as amended January 30, 2008, filed as Exhibit 3.1 to Chevron Corporation’s Current Report onForm 8-K dated February 1, 2008, and incorporated herein by reference.

4 Pursuant to the Instructions to Exhibits, certain instruments defining the rights of holders of long-term debt securities of the company and its consolidated subsidiaries are not filed because the total amount of securities authorized under any such instrument does not exceed 10 percent of the total assets of the corporation and its subsidiaries on a consolidated basis. A copy of such instrument will be furnished to the Commission upon request.

10 .1 Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan filed as Exhibit 10.1 to Chevron Corporation’s Quarterly Report onForm 10-Q for the quarterly period ended March 31, 2007, and incorporated herein by reference.

10 .2 Management Incentive Plan of Chevron Corporation filed as Exhibit 10.3 to Chevron Corporation’s Current Report onForm 8-K dated December 6, 2006, and incorporated herein by reference.

10 .4 Chevron Corporation Long-Term Incentive Plan filed as Exhibit 10.4 to Chevron Corporation’s Current Report onForm 8-K dated December 6, 2006, and incorporated herein by reference.

10 .6 Chevron Corporation Deferred Compensation Plan for Management Employees, as amended and restated on December 7, 2005, filed as Exhibit 10.5 to Chevron Corporation’s Current Report onForm 8-K dated December 7, 2005, and incorporated herein by reference.

10 .7 Chevron Corporation Deferred Compensation Plan for Management Employees II filed as Exhibit 10.5 to Chevron Corporation’s Current Report onForm 8-K dated December 6, 2006, and incorporated herein by reference.

10 .8 Texaco Inc. Stock Incentive Plan, adopted May 9, 1989, as amended May 13, 1993, and May 13, 1997, filed as Exhibit 10.13 to Chevron Corporation’s Annual Report onForm 10-K for the year ended December 31, 2001, and incorporated herein by reference.

10 .9 Supplemental Pension Plan of Texaco Inc., dated June 26, 1975, filed as Exhibit 10.14 to Chevron Corporation’s Annual Report onForm 10-K for the year ended December 31, 2001, and incorporated herein by reference.

10 .10 Supplemental Bonus Retirement Plan of Texaco Inc., dated May 1, 1981, filed as Exhibit 10.15 to Chevron Corporation’s Annual Report onForm 10-K for the year ended December 31, 2001, and incorporated herein by reference.

10 .11 Texaco Inc. Director and Employee Deferral Plan approved March 28, 1997, filed as Exhibit 10.16 to Chevron Corporation’s Annual Report onForm 10-K for the year ended December 31, 2001, and incorporated herein by reference.

10 .12 Chevron Corporation 1998 Stock Option Program for U.S. Dollar Payroll Employees, filed as Exhibit 10.12 to Chevron Corporation’s Annual Report onForm 10-K for the year ended December 31, 2002, and incorporated herein by reference.

10 .13 Summary of Chevron’s Management and Incentive Plan Awards and Criteria, filed as Exhibit 10.13 to Chevron Corporation’s Quarterly Report onForm 10-Q for the quarterly period ended March 31, 2005, and incorporated herein by reference.

10 .14 Chevron Corporation Change in Control Surplus Employee Severance Program for Salary Grades 41 through 43 filed as Exhibit 10.1 to Chevron Corporation’s Current Report onForm 8-K dated December 6, 2006, and incorporated herein by reference.

E-1

Exhibit No.
Description

10 .15 Chevron Corporation Benefit Protection Program filed as Exhibit 10.2 to Chevron Corporation’s Current Report onForm 8-K dated December 6, 2006, and incorporated herein by reference.

10 .16 Form of Notice of Grant under the Chevron Corporation Long-Term Incentive Plan, filed as Exhibit 10.1 to Chevron’s Current Report onForm 8-K dated June 29, 2005, and incorporated herein by reference.

10 .17 Form of Retainer Stock Option Agreement under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.2 to Chevron’s Current Report onForm 8-K dated June 29, 2005, and incorporated herein by reference.

10 .18 Chevron Corporation Retirement Restoration Plan filed as Exhibit 10.18 to Chevron Corporation’s Quarterly Report onForm 10-Q for the quarterly period ended June 30, 2006, and incorporated herein by reference.

10 .19 Chevron Corporation ESIP Restoration Plan filed as Exhibit 10.19 to Chevron Corporation’s Quarterly Report onForm 10-Q for the quarterly period ended June 30, 2006, and incorporated herein by reference.

10 .20 Form of Restricted Stock Unit Grant Agreement under the Chevron Corporation Long-Term Incentive Plan filed as Exhibit 10.20 to Chevron Corporation’s Quarterly Report onForm 10-Q for the quarterly period ended June 30, 2006, and incorporated herein by reference.

12 .1* Computation of Ratio of Earnings to Fixed Charges(page E-3).

21 .1* Subsidiaries of Chevron Corporation(page E-4 toE-5).

23 .1* Consent of PricewaterhouseCoopers LLP(page E-6).

24 .1to 24.11* Powers of Attorney for directors and certain officers of Chevron Corporation, authorizing the signing of the Annual Report onForm 10-K on their behalf.

31 .1* Rule 13a-14(a)/15d-14(a) Certification of the company’s Chief Executive Officer(page E-18).

31 .2* Rule 13a-14(a)/15d-14(a) Certification of the company’s Chief Financial Officer(page E-19).

32 .1* Section 1350 Certification of the company’s Chief Executive Officer(page E-20).

32 .2* Section 1350 Certification of the company’s Chief Financial Officer(page E-21).

99 .1* Definitions of Selected Energy and Financial Terms(page E-22 toE-23).

Exhibit No.
Description

10 .15 Chevron Corporation Benefit Protection Program, filed as Exhibit 10.2 to Chevron Corporation’s Current Report onForm 8-K dated December 6, 2006, and incorporated herein by reference.

10 .16 Form of Notice of Grant under the Chevron Corporation Long-Term Incentive Plan, filed as Exhibit 10.1 to Chevron’s Current Report onForm 8-K dated June 29, 2005, and incorporated herein by reference.

10 .17 Form of Retainer Stock Option Agreement under the Chevron Corporation Non-Employee Directors’ Equity Compensation and Deferral Plan, filed as Exhibit 10.2 to Chevron’s Current Report onForm 8-K dated June 29, 2005, and incorporated herein by reference.

10 .18 Chevron Corporation Retirement Restoration Plan, filed as Exhibit 10.18 to Chevron Corporation’s Quarterly Report onForm 10-Q for the quarterly period ended June 30, 2006, and incorporated herein by reference.

10 .19 Chevron Corporation ESIP Restoration Plan, filed as Exhibit 10.19 to Chevron Corporation’s Quarterly Report onForm 10-Q for the quarterly period ended June 30, 2006, and incorporated herein by reference.

10 .20 Form of Restricted Stock Unit Grant Agreement under the Chevron Corporation Long-Term Incentive Plan, filed as Exhibit 10.20 to Chevron Corporation’s Quarterly Report onForm 10-Q for the quarterly period ended June 30, 2006, and incorporated herein by reference.

12 .1* Computation of Ratio of Earnings to Fixed Charges(page E-3).

21 .1* Subsidiaries of Chevron Corporation (pagesE-4 toE-5).

23 .1* Consent of PricewaterhouseCoopers LLP(page E-6).

24 .1
to 24.12* Powers of Attorney for directors and certain officers of Chevron Corporation, authorizing the signing of the Annual Report onForm 10-K on their behalf.

31 .1* Rule 13a-14(a)/15d-14(a) Certification of the company’s Chief Executive Officer(page E-19).

31 .2* Rule 13a-14(a)/15d-14(a) Certification of the company’s Chief Financial Officer(page E-20).

32 .1* Section 1350 Certification of the company’s Chief Executive Officer(page E-21).

32 .2* Section 1350 Certification of the company’s Chief Financial Officer(page E-22).

99 .1* Definitions of Selected Energy and Financial Terms (pagesE-23 toE-25).

* Filed herewith.

Copies of above exhibits not contained herein are available, to any security holder upon written request to the Corporate Governance Department, Chevron Corporation, 6001 Bollinger Canyon Road, San Ramon, California94583-2324.

E-2


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


1 Includes buy/sell arrangements. Refer to Note 14 onpage 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


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

	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.



~~DAVID~~David J. ~~O’REILLY~~O’Reilly	~~STEPHEN~~Stephen J. ~~CROWE~~Crowe	~~MARK~~Mark A. ~~HUMPHREY~~Humphrey
Chairman of the Board	Vice President	Vice President
and Chief Executive Officer	and Chief Financial Officer	and Comptroller

February 28, ~~2007~~2008


~~NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS~~Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts



~~NOTE 1.~~Note 1 ~~SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES~~Summary of Significant Accounting Policies – Continued

¹		~~Fair value determined using the Black-Scholes option-pricing model.~~

²		~~Per-share amounts in all periods reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2004.~~



~~NOTE 2.~~ ~~ACQUISITION OF UNOCAL CORPORATION – Continued~~



Current assets	$	3,573
Investments and long-term receivables		1,695
Properties		17,285
Goodwill		4,820
Other assets		2,174

Total assets acquired		29,547

Current liabilities		(2,364	)
Long-term debt and capital leases		(2,392	)
Deferred income taxes		(4,009	)
Other liabilities		(3,494	)

Total liabilities assumed		(12,259	)

Net assets acquired	$	17,288


~~Notes to the Consolidated Financial Statements~~ ~~Millions of dollars, except per-share amounts~~
~~NOTE 3.~~~~INFORMATION RELATING TO THE CONSOLIDATED~~ ~~STATEMENT OF CASH FLOWS – Continued~~


Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts
Note 4Summarized Financial Data Chevron U.S.A. Inc. – Continued



Note 7Financial and Derivative Instruments – Continued


~~Notes to the Consolidated Financial Statements~~ ~~Millions of dollars, except per-share amounts~~
~~NOTE 7.~~~~FINANCIAL AND DERIVATIVE INSTRUMENTS – Continued~~


Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts
Note 8Operating Segments and Geographic Data – Continued



~~NOTE 8.~~~~OPERATING SEGMENTS AND GEOGRAPHIC DATA – Continued~~


~~Notes to the Consolidated Financial Statements~~ ~~Millions of dollars, except per-share amounts~~
~~NOTE 8.~~Note 8~~OPERATING SEGMENTS AND GEOGRAPHIC DATA~~Operating Segments and Geographic Data – Continued


	At December 31
	2007		2006*

Upstream	$	482	$	461
Downstream	$	551	$	550
Chemical and all other		171		2

Total		1,204		1,013
Less: Accumulated amortization		628		548

Net capitalized leased assets	$	576	$	465


Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts
Note 9Lease Commitments – Continued


	At December 31					At December 31
	Operating		Capital
	Leases		Leases			Operating		Capital
						Leases		Leases
Year: 2007	$	509	$	91
2008		507		80

Year: 2008						$	513	$	103
2009		477		81			478		106
2010		390		59			430		83
2011		311		57			347		85
2012							293		91
Thereafter		864		520			1,106		347

Total	$	3,058	$	888		$	3,167	$	815

Less: Amounts representing interest and executory costs				(262	)				(315	)

Net present values				626					500
Less: Capital lease obligations included in short-term debt				(352	)				(94	)

Long-term capital lease obligations			$	274				$	406



~~NOTE 10.~~ ~~RESTRUCTURING AND REORGANIZATION COSTS – Continued~~


Amounts before tax	2006			2005

Balance at January 1	$	44		$	–
Additions/Adjustments		(14	)		106
Payments		(19	)		(62	)

Balance at December 31	$	11		$	44


											Investments and Advances				Equity in Earnings
	Investments and Advances				Equity in Earnings						At December 31				Year ended December 31
	At December 31				Year ended December 31
	2006		2005		2006		2005		2004		2007		2006		2007			2006		2005

Upstream
Tengizchevroil	$	5,507	$	5,007	$	1,817	$	1,514	$	950	$	6,321	$	5,507	$	2,135		$	1,817	$	1,514
Hamaca		928		1,189		319		390		98		1,168		928		327			319		390
Petroboscan		712		–		31		–		–		762		712		185			31		–
Angola LNG Limited												574		–		21			–		–
Other		682		679		123		139		148		765		682		204			123		139

Total Upstream		7,829		6,875		2,290		2,043		1,196		9,590		7,829		2,872			2,290		2,043

Downstream
GS Caltex Corporation		2,176		1,984		316		320		296		2,276		2,176		217			316		320
Caspian Pipeline Consortium		990		1,014		117		101		140		951		990		102			117		101
Star Petroleum Refining Company Ltd.		787		709		116		81		207		944		787		157			116		81
Escravos Gas-to-Liquids												628		432		103			146		95
Caltex Australia Ltd.		559		435		186		214		173		580		559		129			186		214
Colonial Pipeline Company		555		565		34		13		–		546		555		39			34		13
Other		1,839		1,562		358		273		143		1,501		1,407		215			212		178

Total Downstream		6,906		6,269		1,127		1,002		959		7,426		6,906		962			1,127		1,002

Chemicals
Chevron Phillips Chemical Company LLC		2,044		1,908		697		449		334		2,024		2,044		380			697		449
Other		22		20		5		3		2		24		22		6			5		3

Total Chemicals		2,066		1,928		702		452		336		2,048		2,066		386			702		452

All Other
Dynegy Inc.		254		682		68		189		86		–		254		8			68		189
Other		586		740		68		45		5		449		586		(84	)		68		45

Total equity method	$	17,641	$	16,494	$	4,255	$	3,731	$	2,582	$	19,513	$	17,641	$	4,144		$	4,255	$	3,731
Other at or below cost		911		563								964		911

Total investments and advances	$	18,552	$	17,057							$	20,477	$	18,552

Total United States	$	4,191	$	4,624	$	955	$	833	$	588	$	3,889	$	4,191	$	478		$	955	$	833
Total International	$	14,361	$	12,433	$	3,300	$	2,898	$	1,994	$	16,588	$	14,361	$	3,666		$	3,300	$	2,898


~~Notes to the Consolidated Financial Statements~~ ~~Millions of dollars, except per-share amounts~~
~~NOTE 12.~~Note 11 ~~INVESTMENTS AND ADVANCES~~Investments and Advances – Continued


													Affiliates						Chevron Share
	Affiliates						Chevron Share
Year ended December 31	2006		2005		2004		2006		2005		2004		2007		2006		2005		2007		2006		2005

Total revenues	$	73,746	$	64,642	$	55,152	$	35,695	$	31,252	$	25,916	$	94,864	$	73,746	$	64,642	$	46,579	$	35,695	$	31,252
Income before income tax expense		10,973		7,883		5,309		5,295		4,165		3,015		12,510		10,973		7,883		5,836		5,295		4,165
Net income		7,905		6,645		4,441		4,072		3,534		2,582		9,743		7,905		6,645		4,550		4,072		3,534

At December 31

Current assets	$	19,769	$	19,903	$	16,506	$	8,944	$	8,537	$	7,540	$	26,360	$	19,769	$	19,903	$	11,914	$	8,944	$	8,537
Noncurrent assets		49,896		46,925		38,104		18,575		17,747		15,567		48,440		49,896		46,925		19,045		18,575		17,747
Current liabilities		15,254		13,427		10,949		6,818		6,034		4,962		19,033		15,254		13,427		9,009		6,818		6,034
Noncurrent liabilities		24,059		26,579		22,261		3,902		4,906		4,520		22,757		24,059		26,579		3,745		3,902		4,906

Net equity	$	30,352	$	26,822	$	21,400	$	16,799	$	15,344	$	13,625	$	33,010	$	30,352	$	26,822	$	18,205	$	16,799	$	15,344

¹	~~Includes assets acquired in connection with the acquisition of Unocal Corporation in August 2005. Refer to Note 2, beginning on page FS-34, for additional information.~~

²	Net of dry hole expense related to prior years’ expenditures of $89, $120 and $28 in 2007, 2006 and ~~$58~~2005, respectively.

²		Depreciation expense includes accretion expense of $399, $275 and $187 in 2007, 2006 ~~2005~~ and ~~2004,~~2005, respectively.

³	~~Depreciation expense includes accretion expense of $275, $187 and $93 in 2006, 2005 and 2004, respectively.~~

⁴	~~Depreciation expense includes discontinued operations of $22 in 2004.~~

⁵	Primarily mining operations, power generation businesses, real estate assets and management information systems.


Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts
~~NOTE 16.~~Note 15 ~~TAXES~~ Taxes – Continued



Balance at January 1, 2007 (date of FIN 48 adoption)	$	2,296
Foreign currency effects		19
Additions based on tax positions taken in 2007		418
Additions for tax positions taken in prior years		120
Reductions for tax positions taken in prior years		(225	)
Settlements with taxing authorities in 2007		(255	)
Reductions due to tax positions previously expected to be taken but subsequently not taken on 2006 tax returns		(174	)

Balance at December 31, 2007	$	2,199


Notes to the Consolidated Financial Statements Millions of dollars, except per-share amounts
~~NOTE 17.~~Note 16 ~~SHORT-TERM DEBT~~Short-Term Debt – Continued

¹		Guarantee of ESOP debt.

²		~~Less than $100 individually; weighted-average~~Weighted-average interest rate at December 31, ~~2006.~~2007.