CHEVRONTEXACO CORP - 10-K Annual Report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K


þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2002

or

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 1-368-2

ChevronTexaco Corporation

(Exact name of registrant as specified in its charter)


Delaware		94-0890210
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

6001 Bollinger Canyon Road,

San Ramon, California 94583

(Address of principal executive offices) (Zip Code)

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

575 Market Street, San Francisco, California 94105

(Former name or former address, if changed since last report.)

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.
Preferred stock purchase rights		Pacific Exchange

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

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). 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 — $93,724,828,928 (As of June 30, 2002)

Number of Shares of Common Stock outstanding as of February 28, 2003 — 1,068,317,395

DOCUMENTS INCORPORATED BY REFERENCE

(To The Extent Indicated Herein)

Notice of the 2003 Annual Meeting and 2003 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company’s 2003 Annual Meeting of Stockholders (in Part III)

TABLE OF CONTENTS


Item		Page No.

	PART I
1.	Business		3
	(a) General Development of Business		3
	(b) Description of Business and Properties		5
	Capital and Exploratory Expenditures		6
	Petroleum — Exploration and Production		7
	Liquids and Natural Gas Production		7
	Acreage		9
	Reserves and Contract Obligations		10
	Development Activities		11
	Exploration Activities		11
	Review of Ongoing Exploration and Production Activities in Key Areas		12
	Petroleum — Natural Gas and Natural Gas Liquids		17
	Petroleum — Refining		17
	Petroleum — Refined Products Marketing		19
	Petroleum — Transportation		20
	Chemicals		21
	Coal		22
	Other Activities — Synthetic Crude Oil		22
	Power and Gasification		22
	Research and Technology		22
	Environmental Protection		23
	Website Access to SEC Reports		23
	Compliance with Certification Requirements		23
2.	Properties		24
3.	Legal Proceedings		24
4.	Submission of Matters to a Vote of Security Holders		24
	Executive Officers of the Registrant at March 1, 2003		25
	PART II
5.	Market for the Registrant’s Common Equity and Related Stockholder Matters		26
6.	Selected Financial Data		26
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		26
7A.	Quantitative and Qualitative Disclosures About Market Risk		26
8.	Financial Statement and Supplementary Data		26
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		27
	PART III
10.	Directors and Executive Officers of the Registrant		27
11.	Executive Compensation		27
12.	Security Ownership of Certain Beneficial Owners and Management		27
13.	Certain Relationships and Related Transactions		27
14.	Controls and Procedures		27


Item		Page No.

	PART IV
15.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K		29
	Schedule II — Valuation and Qualifying Accounts		30
	Signatures		31
	Certifications		32

CAUTIONARY STATEMENTS RELEVANT TO FORWARD-LOOKING INFORMATION

FOR THE PURPOSE OF “SAFE HARBOR” PROVISIONS OF THE

PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This Annual Report on Form 10-K of ChevronTexaco Corporation contains forward-looking statements relating to ChevronTexaco’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,” “estimates” 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. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, ChevronTexaco undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.

Among the factors that could cause actual results to differ materially are crude oil and natural gas prices; refining margins and marketing margins; chemicals prices and competitive conditions affecting supply and demand for aromatics, olefins and additives products; actions of competitors; the competitiveness of alternate energy sources or product substitutes; technological developments; the results of operations and financial condition of equity affiliates; the ability of the company’s Dynegy equity affiliate to successfully execute its recapitalization and restructuring plans and the results of Dynegy’s re-audit of its 1999-2001 financial statements; inability or failure of the company’s joint-venture partners to fund their share of operations and development activities; potential failure to achieve expected production from existing and future oil and gas development projects; potential delays in the development, construction or start-up of planned projects; potential disruption or interruption of the company’s production or manufacturing facilities due to accidents, political events, severe weather or war; potential liability for remedial actions under existing or future environmental regulations and litigation; significant investment or product changes under existing or future environmental regulations (including, particularly, regulations and litigation dealing with gasoline composition and characteristics); potential liability resulting from pending or future litigation; and the possibility of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies. In addition, such statements could be affected by general domestic and international economic and political conditions. Unpredictable or unknown factors not discussed herein also could have material adverse effects on forward-looking statements.

PART I

Item 1. Business

(a) General Development of Business

Summary Description of ChevronTexaco

ChevronTexaco Corporation¹, a Delaware corporation, manages its investments in subsidiaries and affiliates, and provides administrative, financial and management support to U.S. and foreign subsidiaries that engage in fully integrated petroleum operations, chemicals operations, coal mining, power and energy services. The company operates in the United States and approximately 180 other countries. Petroleum operations consist of exploring for, developing and producing crude oil and natural gas; refining crude oil into finished petroleum products; marketing crude oil, natural gas and the many products derived from petroleum; and transporting crude oil, natural gas and petroleum products by pipelines, marine vessels, motor equipment and rail car. Chemicals operations include the manufacture and marketing, by an affiliate, of commodity petrochemicals and plastics for industrial uses, and the manufacture and marketing, by a consolidated subsidiary, of fuel and lubricating oil additives.

In this report, exploration and production of crude oil, natural gas liquids and natural gas may be referred to as “E&P” or “upstream” activities. Refining, marketing and transportation may be referred to as “RM&T” or “downstream” activities. A list of the company’s major subsidiaries is presented on pages E-4 to E-6 of this Annual Report on Form 10-K. As of December 31, 2002, ChevronTexaco had 53,014 employees (excluding 13,024 service station employees), down about 2,700 from year-end 2001. Approximately 29,000, or 44 percent, of the company’s employees, including service station employees, were employed in U.S. operations, of which approximately 3,700 were unionized.

Overview of Petroleum Industry

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

Strong competition exists in all sectors of the petroleum and petrochemical industries. There is competition within the industries and also with other industries in supplying the energy, fuel and chemical needs of industry and individual consumers. ChevronTexaco competes with fully integrated major

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. As used in this report, the term “ChevronTexaco” and such terms as “the company,” “the corporation,” “our,” “we,” and “us” may refer to ChevronTexaco Corporation, one or more of its consolidated subsidiaries, or to all of them taken as a whole, but unless it is stated otherwise, does not include “affiliates” of ChevronTexaco — 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.

petroleum companies, as well as independent and national petroleum companies for the acquisition of oil and gas leases and other properties, and for the equipment and labor required to develop and operate those properties. In its downstream business, ChevronTexaco also competes with fully integrated major petroleum companies and other independent refining and marketing entities in the sale or purchase of various goods or services in many national and international markets.

Operating Environment

Refer to pages FS-2 and FS-3 of this Annual Report on Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion on the company’s current business environment and outlook.

Texaco Merger Transaction

On October 9, 2001, Texaco Inc. (Texaco) became a wholly owned subsidiary of Chevron Corporation (Chevron) pursuant to a merger transaction, and Chevron changed its name to ChevronTexaco Corporation. The combination was accounted for as a pooling of interests, and each share of Texaco common stock was converted on a tax-free basis into the right to receive 0.77 shares of ChevronTexaco common stock. In the merger, ChevronTexaco issued approximately 425 million shares of common stock, representing about 40 percent of the outstanding ChevronTexaco common stock after the merger. Further discussion of the

Texaco merger transaction, including merger-related expenses, is contained on pages FS-3 and FS-27 of this Annual Report on Form 10-K.

ChevronTexaco Strategic Direction

ChevronTexaco’s primary objective is to achieve sustained financial returns that will enable it to outperform its competitors. The company has set as a goal to generate the highest total stockholder return among a designated peer group for the five-year period 2000-2004. British Petroleum, ExxonMobil and Royal Dutch Shell — among the world’s largest integrated petroleum companies — comprise the company’s designated competitor peer group for this purpose. The company had the second highest total stockholder return in this peer group for the 2000-2002 period.

As a foundation for attaining this goal, the company has established four key priorities:

• Operational excellence through safe, reliable, efficient and environmentally sound operations;

• Cost reduction by lowering unit costs through innovation and technology;

• Capital stewardship by investing in the best project opportunities and executing them successfully (safer, faster, and at lower cost); and

• Profitable growth through leadership in developing new business opportunities in both existing and new markets.

Supporting these four priorities is a focus on:

• Organizational Capability: Having the right people, processes and culture to achieve and sustain industry-leading performance in the four priorities described above.

The Corporate Strategic Plan builds on this framework with strategies focused on appropriately balancing financial returns and growth. The company is currently conducting a rigorous evaluation of its entire portfolio of assets and expects to finalize this review later this year. As a result of this evaluation, the company anticipates exploring potential asset transactions to increase the efficiency and profitability of continuing operations and enhancing the economic value of its asset base. The company expects that its worldwide exploration and production business will continue to be its most important business, with development of its large proved and unproved natural gas reserves constituting perhaps the largest opportunity over time to expand the company’s base of production and to capture economic value from emerging natural gas market opportunities. The company is also seeking to deliver improved and competitive returns from its worldwide downstream businesses.

(b) Description of Business and Properties

The company’s largest business segments are exploration and production, and refining, marketing and transportation. Chemicals is also a significant segment, conducted mainly by the company’s affiliate — Chevron Phillips Chemical Company LLC (CPChem). The petroleum activities of the company are widely dispersed geographically. The company has petroleum operations in North America, South America, Europe, Africa, Middle East, Central and Far East Asia, and Australia.

CPChem has operations in the United States, Puerto Rico, Belgium, China, South Korea, Singapore, Saudi Arabia, Qatar and Mexico. ChevronTexaco’s wholly owned Oronite fuel and lube oil additives business has operations in the United States, Mexico, France, the Netherlands, Singapore, India, Japan and Brazil.

An equity affiliate, Dynegy Inc. (Dynegy), owns operating divisions engaged in power generation, natural gas liquids and regulated energy delivery. ChevronTexaco owns approximately 26 percent of Dynegy’s common stock and also holds $1.5 billion aggregate principal amount of Dynegy’s preferred stock. Until recently, Dynegy also conducted a large electricity and natural gas trading and marketing business, as well as broadband trading. ChevronTexaco sold essentially all of its U.S. natural gas production to Dynegy, which then sold it into the market. Following the collapse of the merchant energy sector in 2002, Dynegy experienced a marked reduction in liquidity. Its debt ratings were downgraded and a sharp decline in its stock price

occurred. In 2002, Dynegy announced its intent to exit the energy trading business. As a result of those changes, ChevronTexaco is re-establishing a natural gas marketing business to market the company’s U.S. natural gas production and to purchase supply for its requirements. Refer to page FS-8 for further information relating to the company’s investment in Dynegy.

Tabulations of segment sales and other operating revenues, earnings, income taxes and assets, by United States and International geographic areas, for the years 2000 to 2002, may be found in Note 10 to the consolidated financial statements beginning on page FS-31 of this Annual Report on Form 10-K. In addition, similar comparative data for the company’s investments in and income from equity affiliates and property, plant and equipment are contained in Notes 13 and 14 on pages FS-34 to FS-36.

The company’s worldwide operations can be affected significantly by changing economic, tax, regulatory and political environments in the various countries in which it operates, including the United States. Environmental regulations and government policies concerning economic development, energy and taxation may have a significant effect on the company’s operations. Management evaluates the economic and political risk of initiating, maintaining or expanding operations in any geographical area. The company monitors political events worldwide and the possible threat these may pose to its activities — particularly the company’s oil and gas exploration and production operations — and the safety of the company’s employees. The company is carefully monitoring the potential for disruption of its operations in the event of hostilities in Iraq. Approximately five percent of the company’s worldwide net oil-equivalent production for 2002 came from the Partitioned Neutral Zone (PNZ), which is located between the Kingdom of Saudi Arabia and the State of Kuwait.

Capital and Exploratory Expenditures

A discussion of the company’s capital and exploratory expenditures is contained on page FS-9 to FS-10 of this Annual Report on Form 10-K.

Petroleum — Exploration and Production

Liquids and Natural Gas Production

The following table summarizes the company’s and its affiliates’ net production of crude oil and natural gas liquids, and natural gas, and oil-equivalent production for 2002 and 2001.

Net Production⁽¹⁾ Of Crude Oil And Natural Gas Liquids And Natural Gas



		Crude Oil &								Memo:
		Natural Gas				Natural Gas				Oil-Equivalent
		Liquids				(Millions of				(BOE)
		(Thousands of				Cubic Feet per				(Thousands of
		Barrels per Day)				Day)				Barrels per Day)⁽²⁾

		2002		2001		2002		2001		2002		2001

United States:
	California		243		249		125		116		264		268
	Gulf of Mexico		182		187		801		1,023		316		357
	Texas		91		87		566		598		185		187
	Wyoming		12		11		199		220		45		48
	Other States		74		80		714		749		193		205

Total United States			602		614		2,405		2,706		1,003		1,065

Africa:
Angola			164		168		—		1		164		168
Nigeria			127		158		74		43		139		165
Republic of Congo			16		20		—		—		16		20
Democratic Republic of Congo			8		9		—		—		8		9
Asia-Pacific:
Indonesia			263		304		147		134		288		326
Partitioned Neutral Zone (PNZ)⁽³⁾			140		144		15		10		142		146
Australia			52		45		264		235		96		84
China			27		24		—		—		27		24
Kazakhstan			22		17		85		67		36		28
Thailand			18		16		87		75		33		28
Philippines			7		1		105		9		25		3
Papua New Guinea			6		7		—		—		6		7
Other International:
United Kingdom (North Sea)			113		115		361		350		173		173
Canada			70		64		140		167		93		92
Argentina			55		57		71		56		67		66
Denmark			42		39		102		100		59		56
Norway			15		17		3		4		16		18
Venezuela			4		4		7		4		4		5
Colombia			—		—		222		203		37		34
Trinidad			—		—		107		100		18		17
Netherlands			—		—		—		1		—		—

Total International			1,149		1,209		1,790		1,559		1,447		1,469

Total Consolidated Operations			1,751		1,823		4,195		4,265		2,450		2,534
Equity in Affiliates⁽⁴⁾			146		136		181		152		176		161

Total Including Affiliates			1,897		1,959		4,376		4,417		2,626		2,695

Memo: Other produced volumes⁽⁵⁾			97		105		—		—		97		105

⁽¹⁾ Net production excludes royalty interests owned by others.

⁽²⁾ Natural gas converted to oil-equivalent gas (OEG) barrels at 6 MCF = 1 OEG barrel.

⁽³⁾ Located between the Kingdom of Saudi Arabia and the State of Kuwait.

⁽⁴⁾ Affiliates include TCO in Kazakhstan and Hamaca in Venezuela.

⁽⁵⁾ Represents total field production under the Boscan operating service agreement in Venezuela.

In 2002, ChevronTexaco conducted its exploration and production operations in the United States and approximately 25 other countries. Worldwide net crude oil and natural gas liquids production, including that of affiliates but excluding volumes produced under operating service agreements, decreased by about 3 percent from the 2001 levels. Net worldwide production of natural gas, including affiliates, decreased about 1 percent in 2002.

Net liquids and natural gas production in the United States was down about 2 percent and 11 percent, respectively. The decline in U.S. natural gas production in 2002 reflected decreases in the Gulf of Mexico, primarily attributable to declines in mature fields. Early in 2001, production from a number of fields was accelerated via increased drilling at a time of high natural gas prices. In addition to normal field declines, production disruptions caused by tropical storms in the Gulf of Mexico reduced net crude oil and natural gas liquids production by 10,000 barrels per day and 60 million cubic feet of natural gas per day on an annualized basis.

International net liquids production, including affiliates, decreased about 4 percent, while net natural gas production rose 15 percent from 2001. In Nigeria, the decline in net liquids production between years was primarily attributable to OPEC production constraints. In Indonesia, about 25,000 barrels per day of the year to year decline was attributable to changes in certain production-sharing contract terms and 10,000 barrels per day was related to the expiration of a production sharing agreement. The increase in international natural gas volumes occurred primarily in the Philippines, due to a full year of new production from the Malampaya Field.

For the past five years, the company’s worldwide oil-equivalent production has followed a downward trend with 2002 production at 91 percent of 1998 levels, equivalent to an average annual decline rate between 1 and 2 percent. During this time period, increases in international oil-equivalent production have been more than offset by decreases in the United States.

For 2003, the company currently anticipates lower oil-equivalent production rates in the United States as a result of lower capital expenditures in recent years and natural field declines. The company expects this to be more than offset by capacity increases in international areas resulting in worldwide oil-equivalent production capacity in 2003 slightly higher than actual production levels achieved in 2002. The ultimate level of production in 2003 remains uncertain due to unanticipated production interruptions, OPEC constraints and other economic factors.

Acreage

At December 31, 2002, 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 next table.

Acreage⁽¹⁾ At December 31, 2002

(Thousands of Acres)



									Developed and
	Undeveloped⁽²⁾				Developed⁽²⁾				Undeveloped

	Gross		Net		Gross		Net		Gross		Net

United States		9,172		6,604		8,529		4,002		17,701		10,606

Africa		23,373		7,783		482		142		23,855		7,925
Asia-Pacific		48,697		21,450		1,846		664		50,543		22,114
Other International		36,104		18,788		2,830		1,197		38,934		19,985

Total International		108,174		48,021		5,158		2,003		113,332		50,024

Total Consolidated Companies		117,346		54,625		13,687		6,005		131,033		60,630
Equity in Affiliates		1,063		503		84		38		1,147		541

Total Including Affiliates		118,409		55,128		13,771		6,043		132,180		61,171

⁽¹⁾ Gross acreage includes the total number of acres in all tracts in which the company has an interest. Net acreage is the sum of the company’s fractional interests in gross acreage.

⁽²⁾ Undeveloped acreage is acreage where wells have not been drilled or completed to permit commercial production, and may contain undeveloped proved reserves. Developed acreage is spaced or assignable to productive wells.

Refer to Table IV on page FS-51 of this Annual Report on Form 10-K for data about the company’s average sales price per unit of oil and gas produced, as well as the average production cost per unit for 2002, 2001 and 2000. The following table summarizes gross and net productive wells at year-end 2002 for the company and its affiliates.

Productive Oil And Gas Wells At December 31, 2002



	Productive⁽¹⁾				Productive⁽¹⁾
	Oil Wells				Gas Wells

	Gross⁽²⁾		Net⁽²⁾		Gross⁽²⁾		Net⁽²⁾

United States		57,432		33,364		14,199		6,906

Africa		1,650		593		18		8
Asia-Pacific		8,571		7,633		241		127
Other International		2,420		1,520		415		169

Total International		12,641		9,746		674		304

Total Consolidated Companies		70,073		43,110		14,873		7,210
Equity in Affiliates		164		61		—		—

Total Including Affiliates		70,237		43,171		14,873		7,210

Multiple completion wells included above:		1,154		782		794		573

⁽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 are the sum of the company’s fractional interests in gross wells.

Reserves and Contract Obligations

Table V on pages FS-51 and FS-52 of this Annual Report on Form 10-K sets forth the company’s net proved oil and gas reserves, by geographic area, as of December 31, 2002, 2001 and 2000. During 2003, the company will file estimates of oil and gas reserves with the Department of Energy, Energy Information Agency. Those estimates are consistent with the reserve data reported on page FS-52 of this Annual Report on Form 10-K.

In 2002, ChevronTexaco’s worldwide oil and equivalent-gas (OEG) barrels of net proved reserves additions exceeded production, with a replacement rate of 114 percent of net production, including sales and acquisitions. Excluding sales and acquisitions, the replacement rate was 112 percent of net production. In Africa, the reserves replacement rate increased to 521 percent, compared with 268 percent in 2001, due primarily to reserves additions in West Africa. In the United States, the addition of reserve quantities for the Kern River Field in California’s San Joaquin Valley, due to improved recovery from reservoir management, was more than offset by downward revisions in gas fields in the Mid-Continent, CO₂ projects in the Permian Basin, and a number of fields in the Gulf of Mexico. The following table summarizes the company’s net additions to net proved reserves of crude oil and natural gas liquids, and natural gas, compared with net production during 2002.

Reserves Replacement — 2002



	Net													Memo:
	Additions to						Net							BOE
	Reserves						Production							Replacement %
														Excluding
	Liquids			Gas			Liquids		Gas		BOE			Sales and
	(mmbbls)⁽¹⁾			(bcf)⁽²⁾			(mmbbls)⁽¹⁾		(bcf)⁽²⁾		Replacement %⁽⁴⁾			Acquisitions⁽⁴⁾

United States		36			(92	)		220		878		6	%		0	%
Africa		547			453			115		27		521	%		521	%
Asia-Pacific		(7	)		662			195		257		43	%		43	%
Other International ⁽³⁾		260			499			162		435		146	%		146	%

Total Worldwide		836			1,522			692		1,597		114	%		112	%

⁽¹⁾ mmbbls = millions of barrels

⁽²⁾ bcf = billions of cubic feet

⁽³⁾ Includes equity in affiliates

⁽⁴⁾ Natural gas converted to oil-equivalent gas (OEG) barrels at 6 MCF = 1 OEG barrel.

The company sells crude oil and natural gas from its producing operations under a variety of contractual arrangements. Most contracts generally commit the company to sell quantities based on production from specified properties, but certain gas sales contracts specify delivery of fixed and determinable quantities. During 2002, Dynegy purchased substantially all natural gas and natural gas liquids produced by the company in the United States, excluding Alaska, and supplied natural gas and natural gas liquids feedstocks to the company’s U.S. refineries and chemical plants. The company reached an agreement with Dynegy to terminate existing natural gas purchase and sale contracts and other related contracts at the end of January 2003. See page FS-8 for further information on Dynegy. Outside the United States, the company is contractually committed to deliver approximately 400 billion cubic feet of natural gas through 2005 from Australian, Colombian and Philippine reserves, and approximately 1,300 billion cubic feet of natural gas from 2006 through 2020 from Australian and Philippine reserves. The company believes it can satisfy these contracts from quantities available from production of the company’s proved developed Australian, Colombian and Philippine reserves. The contracts discussed above include variable-pricing terms.

Development Activities

Details of the company’s development expenditures and costs of proved property acquisitions for 2002, 2001 and 2000 are presented in Table I on page FS-48 of this Annual Report on Form 10-K.

The table below summarizes the company’s net interest in productive and dry development wells completed in each of the past three years and the status of the company’s development wells drilling at December 31, 2002. A “development well” is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. “Wells drilling” include wells temporarily suspended.

Development Well Activity



					Net Wells Completed⁽¹⁾
	Wells
	Drilling
	At 12/31/02				2002				2001				2000

	Gross⁽²⁾		Net⁽²⁾		Prod		Dry		Prod		Dry		Prod		Dry

United States		60		32		638		16		866		21		919		14

Africa		6		2		27		—		22		—		39		—
Asia-Pacific		3		2		470		—		555		—		501		1
Other International		39		23		140		—		109		2		113		—

Total International		48		27		637		—		686		2		653		1

Total Consolidated Companies		108		59		1,275		16		1,552		23		1,572		15
Equity in Affiliates		4		2		20		—		17		—		33		—

Total Including Affiliates		112		61		1,295		16		1,569		23		1,605		15

⁽¹⁾ Indicates the 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 oil or gas or, in the case of a dry well, the reporting of abandonment to the appropriate agency.

⁽²⁾ Gross wells include the total number of wells in which the company has an interest. Net wells are the sum of the company’s fractional interests in gross wells.

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, 2002. “Exploratory wells” are wells drilled to find and produce oil or 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 oil or gas in another reservoir or to extend a known reservoir beyond the proved area. “Wells drilling” include wells temporarily suspended. The company had $450 million of suspended exploratory wells included in properties, plant and equipment at year-end 2002, a decrease of $238 million from 2001. Decreases in Nigeria, Angola and China were partially offset by increases in the United States. The wells are suspended pending a final determination of the commercial potential of the related oil and gas deposits. The ultimate disposition of these well costs is dependent on: (1) decisions on additional major capital expenditures, (2) the results of additional exploratory drilling that is underway or firmly planned, and in some cases, (3) securing final regulatory approvals for development.

Exploratory Well Activity



					Net Wells Completed⁽¹⁾
	Wells
	Drilling
	At 12/31/02				2002				2001				2000

	Gross⁽²⁾		Net⁽²⁾		Prod.		Dry		Prod		Dry		Prod		Dry

United States		24		14		57		22		101		32		69		30

Africa		1		—		6		1		8		2		2		4
Asia-Pacific		2		1		4		1		31		8		15		11
Other International		2		1		7		9		6		10		7		7

Total International		5		2		17		11		45		20		24		22

Total Consolidated Companies		29		16		74		33		146		52		93		52
Equity in Affiliates		—		—		4		—		14		—		—		—

Total Including Affiliates		29		16		78		33		160		52		93		52

Details of the company’s exploration expenditures and costs of unproved property acquisitions for 2002, 2001 and 2000 are presented in Table I on page FS-48 of this Annual Report on Form 10-K.

Review of Ongoing Exploration and Production Activities in Key Areas

ChevronTexaco’s 2002 key upstream activities not discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations beginning on page FS-2 of this Annual Report on Form 10-K are presented below. The comments include reference to “net production,” which excludes partner shares and royalty interests. “Total production” includes these components. In addition to the activities discussed, ChevronTexaco was active in other geographic areas, but these activities were less significant.

Consolidated Operations

A) United States

United States exploration and production activities are concentrated in approximately 700 fields located mainly in the Gulf of Mexico, Texas, New Mexico, the Rocky Mountains, California and Alaska.

Gulf of Mexico: In the Gulf of Mexico Shelf, average daily net production rates were 124,000 barrels of crude oil, one billion cubic feet of natural gas, and 15,300 barrels of natural gas liquids.

In the deepwater, the company has interests in three significant developments: (1) 57 percent-owned and operated Genesis, which averaged 31,000 barrels of net oil equivalent per day; (2) 50 percent-owned and operated Typhoon, which averaged 17,700 barrels of net oil equivalent per day; and (3) 50 percent-owned and operated Petronius, which averaged 26,500 barrels of net oil equivalent per day. Exploration programs resulted in two significant discoveries, for which evaluation continued into 2003: (1) 58 percent-owned and operated Tahiti; and (2) 33 percent-owned Great White. Appraisal work is ongoing at the 2001 Trident and 2000 Blind Faith discoveries, and production began at Boris, a 2001 discovery, in February 2003.

In December, ChevronTexaco submitted an application to the U.S. Department of Transportation to construct and operate a Liquefied Natural Gas (LNG) receiving and regasification terminal located approximately 50 miles offshore in the Gulf of Mexico. The Port Pelican development, 100 percent owned

by ChevronTexaco, includes plans to construct in phases. Phase 1 is expected to initially process approximately 800 million cubic feet of natural gas per day and connect to existing infrastructure to deliver natural gas to the Gulf Coast. Phase 2 would expand the terminal to accommodate a total of 1.6 billion cubic feet of natural gas per day. Phase 1 is expected to be operational in 2006.

Mid-Continent: Onshore operations in the mid-continent United States are concentrated in Texas, Wyoming, Oklahoma, Colorado, Utah and New Mexico. Net natural gas production averaged 830 million cubic feet per day, while net production of crude oil and natural gas liquids averaged 30,000 barrels per day. Capital spending was focused on natural gas development in Wyoming, east and south Texas and coalbed methane activity, located mainly in Utah.

Permian: Permian operations are located primarily in southeast New Mexico and west Texas. In 2002, net daily production averaged 118,000 barrels of crude oil and natural gas liquids and 270 million cubic feet of natural gas.

California: During 2002, average net daily production from the company’s San Joaquin Valley fields was about 244,000 barrels of crude oil and natural gas liquids and 129 million cubic feet of natural gas. Approximately 208,000 barrels per day of the crude oil production was heavy oil (defined as roughly 15 API gravity or lower).

Alaska: ChevronTexaco has a 25 percent interest in the Point Thomson Field where development has progressed into the preliminary engineering phase. The field is a large high-pressure gas condensate reservoir located on the eastern North Slope that has been delineated with 15 wells. In the Greater Prudhoe Bay area, the company and its partners completed an alignment of the interest in 2002.

Offshore Florida: In July, ChevronTexaco settled a breach of contract case with the federal government and relinquished all interest in the Destin Dome 56 Unit leases, offshore Florida. ChevronTexaco received $46 million from the federal government for its share of the settlement.

B) Africa

Nigeria: ChevronTexaco’s principal subsidiary in Nigeria, Chevron Nigeria Limited (CNL), operates and holds a 40 percent interest in 11 concessions, predominantly in the swamp and near-offshore regions of the Niger Delta. CNL operates under a joint venture arrangement with the Nigerian National Petroleum Corporation (NNPC), which owns the remaining 60 percent interest. ChevronTexaco’s subsidiaries Chevron Oil Company Nigeria Limited (COCNL) and Texaco Overseas Nigeria Petroleum Company Unlimited (TOPCON) each hold a 20 percent interest in six additional concessions. TOPCON operates these concessions under a joint venture agreement with NNPC, which owns the remaining 60 percent interest.

In 2002, net daily production from the 33 CNL-operated fields averaged 115,100 barrels of oil and 3,100 barrels of liquefied petroleum gas (LPG). TOPCON shut in one of its fields in 2002. Net production from the five remaining fields operated by TOPCON during the year averaged approximately 8,700 barrels of oil per day.

In the third quarter 2001, preliminary design started for Phase 3 of the Escravos gas project, which includes adding a second gas plant and expanding processing capacity to 680 million cubic feet per day, and is targeted for completion in 2005. ChevronTexaco holds a 40 percent working interest in the Escravos gas project, which processed 236 million cubic feet of natural gas per day during 2002.

Front-end engineering and design have been completed for a proposed gas-to-liquids (GTL) facility and site preparation in Escravos is at an advanced stage. The proposed 33,000 barrels-per-day GTL project is the company’s first to use the Sasol Chevron Global Joint Venture’s technology and operational expertise. Project start-up is expected to be in 2006. ChevronTexaco holds a 38 percent interest.

The company also continued activities in the deepwater Agbami development. Unitization efforts between Block 216 and Block 217 participants progressed during 2002 and unit agreements are expected in 2003. Initial production is expected in 2007.

Angola: ChevronTexaco is the largest producer in Angola and the first to produce in the deepwater. Cabinda Gulf Oil Company Limited (CABGOC), a wholly owned subsidiary of ChevronTexaco, is operator of two concessions, Blocks 0 and 14, off the coast of Angola’s Cabinda enclave. Block 0, in which CABGOC has a 39 percent interest, is a 2,155-square-mile concession adjacent to the Cabinda coastline. Block 14, in which CABGOC has a 31 percent interest, is a 1,580-square-mile deepwater concession located west of Block 0.

In Block 0, the company operates in three areas — A, B and C — comprised of 21 fields producing 136,000 barrels of net crude oil per day during 2002. Area A, containing 16 fields currently producing, averaged net daily production of approximately 85,000 barrels of crude oil and 1,000 barrels of liquefied petroleum gas in 2002. Area B, with three fields producing, averaged net production of 42,000 barrels of crude oil per day. Area C averaged net production of 9,000 barrels of crude oil per day from two producing fields.

In Block 14, net production in 2002 from the Kuito Field, Angola’s first deepwater producing area, averaged approximately 20,500 barrels of crude oil per day. The Benguela Belize-Lobito Tomboco development plans were approved by partners in early 2003. The project includes the phased development of the Benguela, Belize, Lobito and Tomboco fields. In 2002, Block 14 exploration activities included two successful discoveries, Gabela-1 and Negage-1. Development studies for the Gabela and Negage fields have commenced and appraisal drilling decisions are to be made during 2003.

ChevronTexaco has two other concessions in Angola. The company is the operator of Block 2 with a 20 percent interest and 6,500 barrels per day of crude oil production in 2002. It is also a non-operator in Block FST, with a 17 percent interest and 1,900 barrels per day of crude oil production.

Republic of Congo: ChevronTexaco has interests in two license areas, Haute Mer and Marine VII Kitina/ Sounda, in offshore Congo and adjacent to the company’s concessions in Cabinda. The company has a 30 percent interest in the Haute Mer exploration permit and a 29 percent interest in the Marine VII and Sounda exploration permits. Net production from ChevronTexaco’s concessions in the Republic of Congo averaged 15,800 barrels of oil per day in 2002. Appraisal drilling of the deepwater Moho and Bilondo development was completed in 2002. A development decision for Moho and Bilondo, where the company has a 30 percent interest, is anticipated in mid-2003.

Chad-Cameroon: ChevronTexaco is a 25 percent partner in a project to develop landlocked oil fields in southern Chad and transport crude oil by pipeline to the coast of Cameroon for export to world markets. At the end of 2002, the overall development project was about 70 percent complete. Pipeline completion and first production are expected in mid-2003.

Equatorial Guinea: ChevronTexaco is a 65 percent partner and operator of the L Block offshore the Republic of Equatorial Guinea. Processing and interpretation of the seismic studies have been completed and a location has been selected for the first exploration well, Ballena-1, which is scheduled to begin drilling in March 2003.

C) Asia-Pacific

China: ChevronTexaco has a 33 percent interest in Block 16/08, located in the Pearl River Mouth Basin. Six fields in Block 16/08 had a total production average of 72,100 barrels of oil per day in 2002. The company has a 25 percent interest in QHD-32-6 in Bohai Bay, which achieved first oil in 2001. All six platforms were on production by October 2002, with a total production average of 35,100 barrels of oil per day. Also in October, ChevronTexaco entered into a unitization agreement with China National Offshore Oil Corp. to jointly develop the BZ25-1/25-1S (Bozhong) oil field, in which the company holds a 16 percent interest.

Indonesia: ChevronTexaco’s interests in Indonesia are managed by two wholly owned subsidiaries, P.T. Caltex Pacific Indonesia (CPI) and Amoseas Indonesia (AI). CPI accounts for approximately 40 percent of Indonesia’s total crude oil output and holds an interest in five production-sharing contracts. One production-sharing contract expired in 2002 and reduced 2002 net production by approximately 10,000

barrels of crude oil per day. AI is a power generation company that operates the Darajat geothermal contract area in West Java and a cogeneration facility in support of CPI’s operation in North Duri. In addition to the above interest, ChevronTexaco has a 25 percent non-operated interest in South Natuna Sea Block B.

ChevronTexaco’s net share of production during 2002 was 288,000 barrels of oil equivalent per day. CPI continues to implement enhanced oil recovery projects to extract more oil from its existing reservoirs. The Duri Field in the Rokan Block, under steamflood since 1985, is the largest steamflood project in the world, with total production averaging 228,000 barrels of oil per day in 2002. ChevronTexaco’s net production from South Natuna Sea Block B in 2002 was about 13,000 barrels of oil equivalent per day.

Thailand: The company operates Block B8/32 in the Gulf of Thailand with a 52 percent interest. The company holds a 33 percent interest in adjacent exploration Blocks 7, 8 and 9, which are currently inactive pending resolution of border issues between Thailand and Cambodia. Government representatives from both nations are in active negotiations to resolve border issues. Block B8/32 produces oil and natural gas from three fields: Tantawan, Maliwan and Benchamas. Net daily production during 2002 from the company’s interests in Thailand was 87 million cubic feet of natural gas and 18,200 barrels of crude oil. A partial upgrade of Benchamas processing capacity was completed during 2002, increasing total capacity to approximately 57,000 barrels of oil per day. Five of the six exploration wells drilled in 2002 were successful, extending the productive areas in Block B8/32 significantly. During 2003, an exploration program is planned to continue to evaluate the remaining portions of the concession.

Cambodia: In early 2002, the company was awarded a 70 percent interest and operatorship in Block A, which covers one million acres and is located offshore Cambodia in the Gulf of Thailand. The company plans to drill two exploration wells in 2003.

Australia: ChevronTexaco has a one-sixth interest in the North West Shelf (NWS) Project in offshore Western Australia. Net daily production from the project during 2002 averaged 18,800 barrels of condensate, 264 million cubic feet of natural gas, 20,000 barrels of crude oil and 3,900 barrels of liquefied petroleum gas. Approximately 60 percent of the natural gas was sold, primarily under long-term contracts, in the form of liquefied natural gas (LNG) to major utilities in Japan and South Korea. The remaining natural gas was sold to the Western Australia domestic market. The Train 4 LNG expansion project is currently under construction, which is planned to increase LNG capacity by about 50 percent in mid-2004. The NWS Venture was selected by China to be the sole supplier of LNG for the proposed Guangdong LNG Terminal Project, and a conditional 25-year LNG Sale and Purchase Agreement (SPA) for approximately 3.9 trillion cubic feet of natural gas, equivalent to about 400 million cubic feet per day, was signed in October 2002. A 30-year LNG SPA conditional contract was signed in 2002 with a Japanese customer for approximately 1.5 trillion cubic feet of natural gas.

The company is operator and has a 57 percent interest in the undeveloped Gorgon area gas field offshore northwest Australia. ChevronTexaco is actively pursuing long-term gas sales from Gorgon to Australian industrial customers and in international LNG markets including China, South Korea, and the west coast of North America.

In 2002, ChevronTexaco drilled a successful appraisal well in the Jansz gas field, offshore Western Australia, where the company holds a 50 percent interest.

Philippines: The company holds a 45 percent interest in the Malampaya gas field located about 50 miles offshore of the Palawan Island. The Malampaya gas-to-power project represents the first offshore production of natural gas in the Philippines. Net daily production was 105 million cubic feet of natural gas and 7,400 barrels of crude oil and condensate. The Malampaya gas project, which represents a significant investment for ChevronTexaco, makes available indigenous fuel for power generation.

Middle East: Saudi Arabia Texaco, a ChevronTexaco subsidiary, holds a concession to produce onshore crude oil from the Partitioned Neutral Zone (PNZ), located between the Kingdom of Saudi Arabia and the State of Kuwait. The Kingdom of Saudi Arabia and the State of Kuwait each own an undivided 50 percent of the PNZ’s hydrocarbon resources. The company, by virtue of its concession, has

the rights to the Kingdom’s undivided 50 percent interest in the hydrocarbon resources located in the onshore PNZ, on which it pays a royalty and other taxes on hydrocarbons produced. During 2002, average net production was 139,800 barrels of crude oil per day. The company also has exploration agreements in Bahrain and Qatar. The company is carefully monitoring the potential for disruption of its operations in the event of hostilities in Iraq. Approximately five percent of the company’s worldwide net oil-equivalent production for 2002 came from the PNZ.

Caspian Region: The company holds a 20 percent equity interest in the Karachaganak Field located in northwest Kazakhstan. The Karachaganak Field’s net daily production for 2002 was 18,400 barrels of condensate and 85 million cubic feet of natural gas from the existing production facilities. The current phase of the Karachaganak development includes the building of processing and liquid export facilities and is scheduled to be completed in early 2004.


	D) Other International Areas

Europe: The company holds producing interests in 25 fields in Denmark, Norway and the United Kingdom with combined net daily production of 170,700 barrels of oil and 467 million cubic feet of natural gas during 2002. This includes the Alba Field in the United Kingdom North Sea, where ChevronTexaco is operator and holds a 21 percent equity interest, which had total daily production of 61,200 barrels of crude oil and 11 million cubic feet of natural gas. The Alba Extreme South project achieved first oil production in October 2002, contributing an average total of about 44,100 barrels of oil-equivalent per day to the Alba Field from its start-up. In February 2002, production commenced from the Jade development, in which ChevronTexaco holds a 20 percent interest. This field achieved a total daily average (ten-month) production of 14,000 barrels of oil and 145 million cubic feet of natural gas. ChevronTexaco holds a 32 percent interest in the Britannia Field, which it operates jointly with ConocoPhillips. Total daily production averaged 28,000 barrels of crude oil and 598 million cubic feet of natural gas. The Captain Field total production averaged 57,300 barrels of crude oil per day during 2002. ChevronTexaco is operator and holds an 85 percent interest.

Canada: Total production from the Hibernia Field offshore Newfoundland, in which ChevronTexaco holds an interest of about 27 percent, averaged approximately 181,000 barrels of crude oil per day. Average net daily production from the company’s onshore Canadian operations was approximately 43,400 barrels of oil equivalent during 2002.

Venezuela: The company operates the onshore Boscan Field under an Operating Services Agreement and receives operating expense reimbursement and capital recovery, plus interest and an incentive fee. Development drilling continued in 2002. Total Boscan crude oil production, subject to Venezuela’s OPEC production restrictions, averaged 97,300 barrels per day during 2002, compared with a capacity of 115,000 barrels per day. The company is also the operator and has a 27 percent interest in the LL-652 Field in Lake Maracaibo. Net production from LL-652 during 2002 averaged 4,300 barrels of oil equivalent per day. The Venezuelan general strike, which began in December 2002, did not have a significant impact on either Boscan or LL-652 production for the year. In January 2003, production from Boscan was reduced by about 50,000 barrels per day as a result of the general strike. Production had returned to pre-strike levels in February. Also in February 2003, ChevronTexaco was awarded the license for offshore Block 2 in the northeastern Plataforma Deltana. Block 2 contains the undeveloped Loran gas field. The company plans to begin exploration and delineation program of Block 2 to determine commerciality.

Argentina: ChevronTexaco operates in Argentina as Chevron San Jorge S.R.L. Chevron San Jorge holds more than 6.1 million exploration and production acres in the Neuquén and Austral basins of Argentina, with working interest shares ranging from 19 to 100 percent in operated license areas. In addition, the company holds a 14 percent interest in Oleoductos del Valle S.A., a major oil pipeline from the Neuquén producing area to the Atlantic coast. Net production during 2002 in the Neuquén and Austral areas averaged over 66,600 barrels of oil equivalent per day.

Brazil: ChevronTexaco holds working interests ranging from 20 to 68 percent in seven deepwater blocks offshore Brazil totaling approximately 4.3 million acres. Deepwater exploration is concentrated in the Campos and Santos basins. During 2002, the company participated in drilling two exploratory wells, without commercial success. In 2003, ChevronTexaco plans to participate in up to three exploration wells.

Colombia: ChevronTexaco’s Colombian subsidiary, ChevronTexaco Petroleum Company, and Ecopetrol, the Colombian national oil company, signed an agreement in February 2003 for incremental natural gas production from the Guajira region. Natural gas production currently averages 510 million cubic feet per day. The new agreement, effective through 2016, will enable both companies to develop and produce additional reserves.

Affiliate operations

Caspian Region: The Tengizchevroil (TCO) partnership includes the Tengiz and Korolev oil fields located in western Kazakhstan where ChevronTexaco holds a 50 percent interest. In 2002, total crude oil production from TCO increased for the ninth consecutive year, averaging 285,000 barrels of oil per day. By late 2002, TCO had begun exporting all of its crude oil from Tengiz to the Russian port city of Novorossiysk via the Caspian Pipeline Consortium (CPC) pipeline. In January 2003, TCO partners agreed to proceed with the Second Generation Program and Sour Gas Injection Project; completion is targeted for mid-2006. These two projects are expected to increase TCO’s crude oil production capacity from the current rate of about 285,000 barrels per day to between 430,000 and 500,000 barrels per day.

Venezuela: ChevronTexaco has a 30 percent interest in the Hamaca integrated oil production and upgrading project located in Venezuela’s Orinoco Belt. Development drilling and major facility construction at Hamaca continued throughout 2002. At the completion of the crude oil upgrading facilities in mid-2004, peak heavy oil production will be upgraded to 180,000 barrels of lighter, higher-value crude per day. The general strike in Venezuela did not materially impact project construction, although oil production was halted in December 2002 and January 2003. Production has since resumed and is ramping back up to pre-strike levels.


	Petroleum — 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. During 2002, the company’s equity affiliate Dynegy purchased substantially all natural gas and natural gas liquids produced by the company in the United States, excluding Alaska, and supplied natural gas and natural gas liquids feedstocks to the company’s U.S. refineries and chemical plants. Following Dynegy’s decision to exit the gas marketing and trading business, the company reached an agreement with Dynegy to terminate the existing natural gas purchase and sale contracts at the end of January 2003. ChevronTexaco formed a new unit, ChevronTexaco Natural Gas, with Dynegy providing transitional support until ChevronTexaco Natural Gas becomes fully operational, currently planned for April 2003 business. The company’s existing natural gas processing and liquids arrangements with Dynegy were not affected by the early termination of natural gas purchase and sales contracts, and will continue as an ongoing commercial relationship. Refer to page FS-8 of this Annual Report on Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations for further comments on Dynegy.

Outside the United States, the majority of the company’s natural gas sales occur in the United Kingdom, Australia, Canada, Latin America, and in the company’s affiliate operations in Kazakhstan. International natural gas liquids sales take place in the company’s Canadian upstream operations, with lower sales levels in Africa, Australia and Europe.

Refer to “Selected Operating Data” on page FS-6 of this Annual Report on Form 10-K 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.

Petroleum — Refining

Distillation operating capacity utilization in 2002, adjusted for sales and closures, averaged 94 percent in the United States (including asphalt plants) and 91 percent worldwide (including affiliates), compared with 88 percent in the United States and 87 percent worldwide in the prior year. ChevronTexaco’s capacity utilization at its U.S. fuels refineries averaged 98 percent in 2002, compared with 90 percent in 2001. ChevronTexaco’s capacity utilization of its wholly owned U.S. cracking and coking facilities, which are the primary facilities used to convert heavier products to gasoline and other light products, averaged 85 percent in 2002, compared with 84 percent in the year earlier. The company processed imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for 70 percent of ChevronTexaco’s U.S. refinery inputs in 2002.

Prior to October 2001, the company also had interests in eight U.S. refineries with a combined capacity of about 1.3 million barrels per day through its investments in the Equilon and Motiva affiliates. These investments were sold, as required by the U.S. Federal Trade Commission, in February 2002.

The daily refinery inputs over the last three years for the company and affiliate refineries are shown in the following table:

Petroleum Refineries: Locations, Capacities And Inputs

(Inputs and Capacities are in Thousands of Barrels Per Day)



		December 31, 2002				Refinery Inputs

				Operable
Locations		Number		Capacity		2002	2001	2000

Pascagoula	Mississippi		1		295	329	332	313
El Segundo	California		1		260	251	213	219
Richmond	California		1		225	187	229	203
El Paso⁽¹⁾	Texas		1		65	61	61	60
Honolulu	Hawaii		1		54	53	54	51
Salt Lake City	Utah		1		45	43	44	44
Other⁽²⁾			2		96	55	50	53

Total Consolidated Companies — United States			8		1,040	979	983	943

Equity in Affiliates⁽³⁾	Various Locations		—		—	—	353	447

Total Including Affiliates — United States			8		1,040	979	1,336	1,390

Pembroke	United Kingdom		1		210	204	202	215
Cape Town	South Africa		1		112	74	71	65
Batangas	Philippines		1		76	59	65	65
Colón⁽⁴⁾	Panama		—		—	27	54	44
Burnaby, B.C.,	Canada		1		52	51	52	51
Escuintla⁽⁴⁾	Guatemala		—		—	11	16	16

Total Consolidated Companies — International			4		450	426	460	456
Equity in Affiliates	Various Locations		11		785	674	676	694

Total Including Affiliates — International			15		1,235	1,100	1,136	1,150

Total Including Affiliates — Worldwide			23		2,275	2,079	2,472	2,540

⁽¹⁾ Capacity and input amounts for El Paso represent ChevronTexaco’s share.

⁽²⁾ Refineries in Perth Amboy, New Jersey and Portland, Oregon, which are primarily asphalt plants.

⁽³⁾ Represents ChevronTexaco interests in Equilon and Motiva refineries, which were placed in trust on October 9, 2001, as required by the U.S. Federal Trade Commission, and disposed of in February 2002.

⁽⁴⁾ ChevronTexaco ceased refining operations at the Panama and Guatemala refineries on July 21, 2002 and September 12, 2002, respectively. The Guatemala facility was converted to terminal operations in 2002 while the Panama facility is expected to be converted to a terminaling facility in 2003.


	Petroleum — Refined Products Marketing

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

The following table shows the company’s and its affiliates’ refined product sales volumes, excluding intercompany sales, over the past three years:

Refined Products Sales Volumes^(1,2)

(Thousands of Barrels Per Day)


		2002		2001		2000

United States
	Gasolines		733		709		717
	Jet Fuel		389		424		402
	Gas Oils and Kerosene		262		245		237
	Residual Fuel Oil		94		183		167
	Other Petroleum Products⁽³⁾		132		122		128

	Total United States		1,610		1,683		1,651

International
	Gasolines		519		533		455
	Jet Fuel		164		185		156
	Gas Oils and Kerosene		619		702		629
	Residual Fuel Oil		413		503		573
	Other Petroleum Products⁽³⁾		543		531		708

	Total International		2,258		2,454		2,521

Total Worldwide			3,868		4,137		4,172

⁽¹⁾ Includes equity in affiliates

⁽²⁾ Excludes Equilon and Motiva pre-merger

⁽³⁾ Principally naphtha, lubricants, asphalt and coke

In the United States, the company supplies, directly or through dealers and jobbers, more than 7,900 Chevron-branded motor vehicle retail outlets, of which about 1,200 are company-owned or -leased stations. The company’s gasoline market area is concentrated in the southern, southwestern and western states. According to the Lundberg Share of Market Report, ChevronTexaco ranks among the top three gasoline marketers in 14 states.

In Canada — primarily British Columbia — the company’s Chevron-branded products are sold in 166 stations (mainly owned or leased).

ChevronTexaco operates a network of over 8,100 service stations in more than 30 countries that cover the Asia-Pacific region, Southern and East Africa, and the Middle East. ChevronTexaco uses the Caltex brand name in these areas.

In Europe, the company has marketing operations in the United Kingdom, Ireland, the Netherlands, Belgium and Luxembourg. The company operates in Denmark and Norway through its 50 percent-owned affiliate, HydroTexaco, using the HydroTexaco brand. In West Africa, the company operates in Cameroon, the Canary Islands, Cote d’Ivoire, Nigeria, Republic of Congo, Togo and Benin. In these regions, the company mainly uses the Texaco brand name.

ChevronTexaco operates in approximately 40 countries across the Caribbean, Central America, and South America, with a significant presence in Brazil. In this region, the company uses the Texaco brand name.

In addition to the above activities, the company manages other marketing businesses globally. In global aviation fuel marketing, the company markets 450,000 barrels per day of aviation fuel in 80 countries, representing a worldwide market share of about 12 percent. The company is the leading marketer of jet fuels in North America and is tied for third in the Asia-Pacific region, Latin America, and the Caribbean. ChevronTexaco markets residual fuel oils and marine lubricants in over 100 countries, and motor lubricants in more than 180 countries.


	Petroleum — Transportation

Pipelines: ChevronTexaco 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, 2002


		Net
		Mileage⁽¹⁾

United States:
	Crude oil⁽²⁾		2,334
	Natural gas		2,016
	Petroleum products		4,322

	Total United States		8,672

International:
	Crude oil⁽²⁾		288
	Natural gas		56
	Petroleum products		329

	Total International		673

Worldwide			9,345

⁽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.

The Caspian Pipeline Consortium (CPC) was formed to build a crude oil export pipeline from the Tengiz Field in Kazakhstan to the Russian Black Sea port of Novorossiysk. In the second half of 2002, TCO fully transitioned to exporting its crude oil through the CPC. The company has a 15 percent

ownership interest in CPC. The system capacity is 600,000 barrels of oil per day. In the second half of 2003, CPC plans to begin transporting condensate from the Karachaganak Field in Kazakhstan.

Tankers: ChevronTexaco’s controlled seagoing fleet at December 31, 2002, is summarized in the following table. All controlled tankers were utilized in 2002. In addition, at any given time, the company has 30 to 40 vessels under a voyage basis or as time charters of less than one year.

Controlled Tankers At December 31, 2002



		U.S. Flag				Foreign Flag

				Cargo Capacity				Cargo Capacity
		Number		(Millions of Barrels)		Number		(Millions of Barrels)

Owned			3		0.8		6		10.6
Bareboat Charter			—		—		14		20.8
Time-Charter*			—		—		8		6.1

	Total		3		0.8		28		37.5

* Greater than one year.

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 2002, the company’s U.S. flag fleet was engaged primarily in transporting refined products between the Gulf Coast and East Coast, and refined products from California refineries to terminals on the West Coast, Alaska and Hawaii.

The foreign flag vessels were engaged primarily in transporting crude oil from the Middle East, Indonesia, Mexico and West Africa to ports in the United States, Europe and Asia. Refined products also were transported by tanker worldwide.

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 resulted in the utilization of double-hull tankers. During 2002, ChevronTexaco operated a total of 19 double-hull tankers and expects to take delivery of three additional double-hull tankers in 2003, also to be operated under long-term bareboat charters. The company is a member of many oil-spill response cooperatives in areas in which it operates around the world.


	Chemicals

Chevron Phillips Chemical Company (CPChem) is a 50-50 joint venture with ConocoPhillips Corporation. CPChem owns or has joint venture interests in 32 manufacturing facilities and six research and technical centers in the United States, Puerto Rico, Belgium, China, Mexico, Saudi Arabia, Singapore, South Korea and Qatar.

An olefins and polyolefins complex in Qatar was completed and is currently undergoing commissioning. The complex is owned and operated by Qatar Chemical Company, Ltd., a joint venture between CPChem, with a 49 percent interest, and Qatar General Petroleum, which owns the remaining 51 percent.

A 50-50 joint venture with BP Solvay to build a new high-density polyethylene (HDPE) facility at a CPChem site in the Houston area is on track for start-up in 2003. The jointly owned 700-million-pounds-per-year HDPE facility will be the largest of its kind in the world and will use CPChem proprietary manufacturing technology.

ChevronTexaco’s “Oronite” fuel and lubricant additives business is a leading developer, manufacturer and marketer of performance additives for fuels and lubricating oils. The company owns and operates

facilities in the United States, France, the Netherlands, Singapore, Japan and Brazil and has equity interests in facilities in India and Mexico.


	Coal

The company’s coal mining and marketing subsidiary, The Pittsburg & Midway Coal Mining Co. (P&M), owned and operated two surface mines and one underground mine at year-end 2002. In addition, final reclamation activities were underway at two mines prior to their planned closure. P&M also owns an approximate 30 percent interest in Inter-American Coal Holding N.V., which has interests in coal mining operations in Venezuela. Sales of coal from P&M’s wholly owned mines and from its affiliates were 14.9 million tons, a decrease of 8 percent from 2001 primarily the result of reduced demand. At year-end 2002, P&M controlled approximately 186 million tons of developed and undeveloped coal reserves, including significant reserves of environmentally desirable low-sulfur fuel. The company is contractually committed to deliver approximately 13 million tons of coal per year through the end of 2005. The company believes it can satisfy these contracts from existing coal reserves.


	Other Activities — Synthetic Crude Oil

In Canada, ChevronTexaco has a 20 percent interest in the Athabasca Oil Sands Project where bitumen production began in December 2002. Production was temporarily suspended in early 2003 and is expected to resume in late March. The bitumen will be upgraded into synthetic crude oil using hydroprocessing technology at a synthetic crude unit, expected to begin operations in the second quarter 2003. Bitumen production is expected to reach an average rate of 155,000 barrels of per day in 2005.


	Power and Gasification

ChevronTexaco participates in its power and gasification business through ownership, equity investments with others and licensing of proprietary technology. The company’s electrical power business includes conventional power generation projects, as well as cogeneration facilities. Cogeneration produces thermal energy, such as steam, and electric power. ChevronTexaco has used steam produced in cogeneration in its upstream operations onshore California and in Indonesia. The company uses its proprietary gasification technology to convert a wide variety of hydrocarbon feedstocks into a clean synthesis gas. The synthetic gas can be used as a feedstock for basic chemicals or to generate electricity in low-emission power plants. ChevronTexaco licenses this technology, operates owned gasification facilities and invests in projects using the technology. The company has licensed its gasification technology to more than 70 plants worldwide.


	Research and Technology

The company’s core hydrocarbon technology efforts support the upstream, downstream and power and gasification businesses. These activities include heavy oil recovery and upgrading, deepwater exploration and production, shallow water production operations, gas-to-liquids processing, hydrocarbon gasification to power, and new and improved refinery processes.

Additionally, ChevronTexaco’s Technology Ventures Company focuses upon the identification, growth, and commercialization of emerging technologies that have the potential to change or transform the way that energy is produced or consumed. The range of business spans early-stage venture capital investing in emerging technologies to developing joint venture companies in new energy systems such as advanced batteries for distributed power and transportation systems and hydrogen fuel storage.

The company has largely completed the implementation of a new information technology infrastructure encompassing computing, data management, security, and connectivity of partners, suppliers, and employees. The architecture, known as “Net Ready,” provides the foundation for the company to cost effectively and rapidly integrate advances in computing and network-based technology.

ChevronTexaco’s research and development expenses were $221 million, $209 million and $211 million for the years 2002, 2001 and 2000, respectively.

Because some of the investments the company makes in the areas described above are in new or unproven technologies and business processes, ultimate success is 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 federal, state and local environmental, health and safety laws and regulations. These regulatory requirements continue to change and increase in both number and complexity, and govern not only the manner in which the company conducts its operations, but also the products it sells. ChevronTexaco expects more environmental-related regulations in the countries where it has operations. Most of the costs of complying with the many laws and regulations pertaining to its operations are embedded in the normal costs of conducting its business.

In 2002, the company’s U.S. capitalized environmental expenditures were $271 million, representing approximately 8 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 petroleum segment 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 2003, the company estimates U.S. capital expenditures for environmental control facilities will be $287 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 ChevronTexaco, and the company’s 2002 environmental expenditures, remediation provisions and year-end environmental reserves are contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages FS-13 and FS-14 of this Annual Report on Form 10-K.


	Web Site Access to SEC Reports

The company’s Internet web site can be found at http://www.chevrontexaco.com/. Information contained on the company’s Internet web site is not part of this report.

The company’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available on the company’s web site, free of charge, as soon as reasonably practicable after such reports are filed with or furnished to the SEC.

Alternatively, you may access these reports at the SEC’s Internet web site: http://www.sec.gov/.


	Compliance with Certification Requirements

The certifications by the company’s Chief Executive Officer and Chief Financial Officer of this Annual Report on Form 10-K, as required by Section 302 of the Sarbanes-Oxley Act of 2002 and the SEC regulations under it, are contained on pages 32 and 33 of this report. The certifications by such officers of this Annual Report on Form 10-K, as required by Section 906 of the Sarbanes-Oxley Act of 2002, have been submitted to the SEC as additional correspondence accompanying this report.

Item 2. Properties

The location and character of the company’s oil, natural gas and coal properties and its refining, marketing, transportation and chemicals facilities are described above under Item 1. Business. Information required by the Securities Exchange Act Industry Guide No. 2 (“Disclosure of Oil and Gas Operations”) is also contained in Item 1 and in Tables I through VII on pages FS-48 to FS-54 of this Annual Report on Form 10-K. Note 14, “Properties, Plant and Equipment,” to the company’s financial statements is on page FS-36 of this Annual Report on Form 10-K.

Item 3. Legal Proceedings

A. Richmond Refinery — Notices of Violation, Bay Area Air Quality Management District

Chevron Products Company’s (a division of Chevron U.S.A. Inc.) Richmond, California, refinery has been issued approximately 40 Notices of Violation during the calendar years 2001 and 2002, which allege non-compliance with the regulations of the Bay Area Air Quality Management District. The Notices of Violation address a variety of issues related to air emissions including, but not limited to, leaks of volatile organic compounds from the facility’s processing equipment. The company has determined that the Notices of Violation will likely result in the payment of a civil penalty in excess of $100,000.

B. Clean Air Act — New Source Review Environmental Protection Agency (EPA) Negotiations

EPA has initiated a national enforcement initiative involving the refining industry, focused on New Source Review requirements under the Clean Air Act. In response to this initiative, ChevronTexaco and EPA are negotiating the potential or actual settlement of any environmental claims at the Company’s refineries that may fall within the scope of the initiative. If a settlement is consummated, it is reasonably anticipated to involve the payment of civil penalties exceeding $100,000.


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

None.

Executive Officers of the Registrant at March 1, 2003


Name and Age		Executive Office Held	Major Area of Responsibility

D. J. O’Reilly	56	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	56	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	Worldwide Exploration and Production Activities
D. W. Callahan	60	Executive Vice President since 2000 Vice President since 1999 President of Chevron Chemical Company from 1999 to 2000 Executive Committee Member since 1999	Chemicals, Coal, Power and Gasification, Technology
C. A. James	48	Vice President and General Counsel since 2002 Executive Committee Member since 2002	Law
G. L. Kirkland	52	President of ChevronTexaco Overseas Petroleum Inc. since 2002 Vice President since 2002 President of Chevron U.S.A. Production Company from 2000 to 2002 Executive Committee Member from 2000 to 2001	Overseas Exploration and Production
J. S. Watson	46	Vice President and Chief Financial Officer since 2000 Vice President since 1998 Executive Committee Member since 2000	Finance
R. I. Wilcox	57	President, ChevronTexaco Exploration & Production Company since 2002 Vice President since 2002	North American Exploration and Production
P. A. Woertz	49	Executive Vice President since 2001 Vice President since 1998 President of Chevron Products Company from 1998 to 2001 Executive Committee Member since 1998	Worldwide Refining, Marketing and Transportation Activities

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.


D. W. Callahan	—	Senior Vice President, Chevron Chemical Company — 1991
	—	President, Chevron Chemical Company — 1999
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. L. Kirkland	—	General Manager, Asset Management, Chevron Nigeria Limited — 1996
	—	Chairman and Managing Director, Chevron Nigeria Limited — 1996
	—	President, Chevron USA Production Company — 2000
J. S. Watson	—	President, Chevron Canada Limited — 1996
	—	Vice President, Strategic Planning, Chevron Corporation — 1998
	—	Vice President and Chief Financial Officer, Chevron Corporation — 2000
R. I. Wilcox	—	Vice President and General Manager, Marine Transportation, Chevron Shipping Company — 1996
	—	General Manager, Asset Management, Chevron Nigeria Limited — 1999
	—	Chairman and Managing Director, Chevron Nigeria Limited — 2000
	—	Corporate Vice President and President, ChevronTexaco Exploration & Production Company — 2002
P. A. Woertz	—	President, Chevron International Oil Company — 1996
	—	Vice President, Logistics and Trading, Chevron Products Company — 1996
	—	President, Chevron Products Company — 1998

PART II


Item 5.	Market for the Registrant’s Common Equity and Related Stockholder Matters

The information on ChevronTexaco’s common stock market prices, dividends, principal exchanges on which the stock is traded and number of stockholders of record is contained in the Quarterly Results and Stock Market Data tabulations, on page FS-46 of this Annual Report on Form 10-K.


Item 6.	Selected Financial Data

The selected financial data for years 1998 through 2002 are presented on page FS-47 of this Annual Report on Form 10-K.


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

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


Item 7A.	Quantitative and Qualitative Disclosures About Market Risk

The company’s discussion of interest rate, foreign currency and commodity price market risk is contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations — “Financial and Derivative Instruments” beginning on page FS-11 and Note 9 to the Consolidated Financial Statements — “Financial and Derivative Instruments” beginning on page FS-30.


Item 8.	Financial Statements and Supplementary Data

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


Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

PART III


Item 10.	Directors and Executive Officers of the Registrant

The information on Directors appearing under the heading “Election of Directors — Nominees For Directors” in the Notice of the 2003 Annual Meeting of Stockholders and 2003 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company’s 2003 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K. See Executive Officers of the Registrant on pages 25 and 26 of this Annual Report on Form 10-K for information about Executive Officers of the company.

The information contained under the heading “Stock Ownership Information — Section 16(a) Beneficial Ownership Reporting Compliance” in the Notice of the 2003 Annual Meeting of Stockholders and 2003 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company’s 2003 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K. ChevronTexaco believes all filing requirements were complied with during 2002.


Item 11.	Executive Compensation

The information appearing under the headings “Executive Compensation” and “Directors’ Compensation” in the Notice of the 2003 Annual Meeting of Stockholders and 2003 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company’s 2003 Annual Meeting of Stockholders, is incorporated herein by reference in this Annual Report on Form 10-K.


Item 12.	Security Ownership of Certain Beneficial Owners and Management

The information appearing under the headings “Stock Ownership Information — Directors’ and Executive Officers’ Stock Ownership” and “Stock Ownership Information — Other Security Holders” in the Notice of the 2003 Annual Meeting of Stockholders and 2003 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company’s 2003 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K.

The information contained under the heading “Equity Compensation Plan Information” in the Notice of the 2003 Annual Meeting of Stockholders and 2003 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934 in connection with the company’s 2003 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K.


Item 13.	Certain Relationships and Related Transactions

The information appearing under the heading “Board Operations — Certain Business Relationships Between ChevronTexaco and its Directors and Officers” in the Notice of the 2003 Annual Meeting of Stockholders and 2003 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company’s 2003 Annual Meeting of Stockholders, is incorporated by reference in this Annual Report on Form 10-K.


Item 14.	Controls and Procedures


	(a) Evaluation of disclosure controls and procedures

ChevronTexaco Corporation’s Chief Executive Officer and Chief Financial Officer, after evaluating the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-14(c) and

15d-14(c) under the Securities Exchange Act of 1934 (the “Exchange Act”)), as of a date (the “Evaluation Date”) within 90 days prior to the filing date of this Annual Report, have concluded that, as of the Evaluation Date, the Company’s disclosure controls and procedures were adequate and designed to ensure 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) Changes in internal controls

Since the Evaluation Date, there have not been any significant changes in the Company’s internal controls or in other factors that could significantly affect the company’s disclosure controls and procedures, nor any significant deficiencies or material weaknesses in such disclosure controls and procedures requiring corrective actions.

PART IV


Item 15.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K

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

(1) Financial Statements:


	Page(s)

Report of Independent Accountants — PricewaterhouseCoopers LLP		FS-18
Report of Independent Public Accountants — Arthur Andersen LLP		FS-18
Consolidated Statement of Income for the three years ended December 31, 2002		FS-19
Consolidated Statement of Comprehensive Income for the three years ended December 31, 2002		FS-20
Consolidated Balance Sheet at December 31, 2002 and 2001		FS-21
Consolidated Statement of Cash Flows for the three years ended December 31, 2002		FS-22
Consolidated Statement of Stockholders’ Equity for the three years ended December 31, 2002		FS-23 to FS-24
Notes to Consolidated Financial Statements		FS-25 to FS-45

(2) Financial Statement Schedules:

We have included on page 30 of this Annual Report on Form 10-K, Financial Statement Schedule II — Valuation and Qualifying Accounts.

(3) Exhibits:

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

(b) Reports on Form 8-K:

      (1) A Current Report on Form 8-K was filed by the company on November 20, 2002. In this report, ChevronTexaco filed a press release dated November 19, 2002, announcing that the company amended the Rights Agreement, dated as of November 23, 1998, as amended, between ChevronTexaco and Mellon Investor Services LLC, as rights agent. The Rights Agreement was amended so that ChevronTexaco’s Series A Preferred Stock Purchase Rights will expire on November 23, 2003, five years earlier than November 23, 2008, the initial expiration date of the agreement.

      (2) A Current Report on Form 8-K was filed by the company on January 31, 2003. In this report, ChevronTexaco filed a press release announcing preliminary unaudited fourth quarter 2002 net income of $904 million.

      (3) A Current Report on Form 8-K was filed by the company on February 18, 2003. This report included a Second Supplemental Indenture among ChevronTexaco Capital Company, as Issuer, ChevronTexaco Corporation, as Guarantor, and JPMorgan Chase Bank, as Trustee, dated as of February 12, 2003.

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS ($ MILLIONS)



	Year Ended December 31,

	2002			2001			2000

Employee Termination Benefits:
Balance at January 1	$	659		$	1		$	130
Additions charged to expense		71			763			15
Payments		(400	)		(105	)		(144	)

Balance at December 31	$	330		$	659		$	1


Other Merger-related Expenses:
Balance at January 1	$	127		$	—		$	—
(Deductions) additions (credited) charged to expense		(11	)		128			—
Payments		(70	)		(1	)		—

Balance at December 31	$	46		$	127		$	—


Allowance for Doubtful Accounts:
Balance at January 1	$	183		$	136		$	113
Additions charged to expense		131			116			74
Bad debt write-offs		(89	)		(69	)		(51	)

Balance at December 31	$	225		$	183		$	136


Deferred Income Tax Valuation Allowance:*
Balance at January 1	$	1,512		$	1,574		$	1,588
Additions charged to deferred income tax expense		776			339			326
Deductions credited to deferred income tax expense		(548	)		(401	)		(340	)

Balance at December 31	$	1,740		$	1,512		$	1,574


Inventory Valuation Allowance:
Balance at January 1	$	—		$	4		$	—
Additions		—			—			4
Deductions		—			(4	)		—

Balance at December 31	$	—		$	—		$	4

* See also Note 15 to the consolidated financial statements on page FS-37

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 17th day of March, 2003.

CHEVRONTEXACO CORPORATION

By DAVID J. O’REILLY*

David J. O’Reilly

Chairman of the Board

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 17th day of March, 2003.



Principal Executive Officers (And Directors)		Directors


DAVID J. O’REILLY* David J. O’Reilly Chairman of the Board PETER J. ROBERTSON* Peter J. Robertson Vice Chairman of the Board Principal Financial Officer JOHN S. WATSON* John S. Watson Vice President, Finance and Chief Financial Officer Principal Accounting Officer STEPHEN J. CROWE* Stephen J. Crowe Vice President and Comptroller		SAMUEL H. ARMACOST* ----------------------------------------------- Samuel H. Armacost ROBERT J. EATON* ----------------------------------------------- Robert J. Eaton SAM GINN* ----------------------------------------------- Sam Ginn CARLA A. HILLS* ----------------------------------------------- Carla A. Hills FRANKLYN G. JENIFER* ----------------------------------------------- Franklyn G. Jenifer J. BENNETT JOHNSTON* ----------------------------------------------- J. Bennett Johnston SAM NUNN* ----------------------------------------------- Sam Nunn CHARLES R. SHOEMATE* ----------------------------------------------- Charles R. Shoemate FRANK A. SHRONTZ* ----------------------------------------------- Frank A. Shrontz THOMAS A. VANDERSLICE* ----------------------------------------------- Thomas A. Vanderslice CARL WARE* ----------------------------------------------- Carl Ware

*By:	/s/ LYDIA I. BEEBE Lydia I. Beebe Attorney-in-Fact	JOHN A. YOUNG* ----------------------------------------------- John A. Young

CERTIFICATIONS

I, David J. O’Reilly, certify that:

      1.     I have reviewed this Annual Report on Form 10-K of ChevronTexaco Corporation;

      2.     Based on my knowledge, this Annual Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Annual Report;

      3.     Based on my knowledge, the financial statements, and other financial information included in this Annual Report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this Annual Report;

      4.     The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

      a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Annual Report is being prepared;

      b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this Annual Report (the “Evaluation Date”); and

      c) presented in this Annual Report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officer and I have indicated in this Annual Report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

/s/ DAVID J. O’REILLY

David J. O’Reilly

Chairman of the Board and Chief Executive Officer

Date March 17, 2003

I, John S. Watson, certify that:

/s/ JOHN S. WATSON

John S. Watson

Vice-President, Finance and Chief Financial Officer

Date March 17, 2003

INDEX TO MANAGEMENT’S DISCUSSION AND ANALYSIS

CONSOLIDATED FINANCIAL STATEMENT AND SUPPLEMENTARY DATA


		Page(s)

Management’s Discussion and Analysis of Financial Condition and Results of Operations		FS-2 to FS-17
Report of Independent Accountants		FS-18
Report of Independent Public Accountants		FS-18
Consolidated Statement of Income		FS-19
Report of Management		FS-19
Consolidated Statement of Comprehensive Income		FS-20
Consolidated Balance Sheet		FS-21
Consolidated Statement of Cash Flows		FS-22
Consolidated Statement of Stockholders’ Equity		FS-23 to FS-24
Notes to Consolidated Financial Statements		FS-25 to FS-45
Quarterly Results and Stock Market Data		FS-46
Five-Year Financial Summary		FS-47
Supplemental Information on Oil and Gas Producing Activities		FS-47 to FS-54

FS-1

TABLE OF CONTENTS


PART I
	Item 1. Business
	(a) General Development of Business
	Capital and Exploratory Expenditures
	Petroleum -- Exploration and Production
	Liquids and Natural Gas Production
	Acreage
	Reserves and Contract Obligations
	Development Activities
	Exploration Activities
	Review of Ongoing Exploration and Production Activities in Key Areas
	Petroleum -- Natural Gas and Natural Gas Liquids
	Petroleum -- Refining
	Petroleum -- Refined Products Marketing
	Petroleum -- Transportation
	Chemicals
	Coal
	Other Activities -- Synthetic Crude Oil
	Power and Gasification
	Research and Technology
	Environmental Protection
	Web Site Access to SEC Reports
	Compliance with Certification Requirements
	Item 2. Properties
	Item 3. Legal Proceedings
	Item 4. Submission of Matters to a Vote of Security Holders
PART II
	Item 5. Market for the Registrant’s Common Equity and Related Stockholder Matters
	Item 6. Selected Financial Data
	Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 7A. Quantitative and Qualitative Disclosures About Market Risk
	Item 8. Financial Statements and Supplementary Data
	Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
PART III
	Item 10. Directors and Executive Officers of the Registrant
	Item 11. Executive Compensation
	Item 12. Security Ownership of Certain Beneficial Owners and Management
	Item 13. Certain Relationships and Related Transactions
	Item 14. Controls and Procedures
PART IV
	Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS ($ MILLIONS)
SIGNATURES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
REPORT OF INDEPENDENT ACCOUNTANTS
CONSOLIDATED STATEMENT OF INCOME
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
CONSOLIDATED BALANCE SHEET
CONSOLIDATED STATEMENT OF CASH FLOWS
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
QUARTERLY RESULTS AND STOCK MARKET DATA
FIVE-YEAR FINANCIAL SUMMARY
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
EXHIBIT INDEX
Form 10-K
EXHIBIT 3.2
EXHIBIT 10.12
Exibit 12.1
EXHIBIT 21.1
EXHIBIT 23.1
EXHIBIT 23.2
EXHIBIT 24.1
EXHIBIT 24.2
EXHIBIT 24.3
EXHIBIT 24.4
EXHIBIT 24.5
EXHIBIT 24.6
EXHIBIT 24.7
EXHIBIT 24.8
EXHIBIT 24.9
EXHIBIT 24.10
EXHIBIT 24.11
EXHIBIT 24.12
EXHIBIT 24.13
EXHIBIT 24.14
EXHIBIT 24.15
EXHIBIT 24.16
EXHIBIT 99.1

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

KEY FINANCIAL RESULTS


Millions of dollars, except per-share amounts			2002			2001			2000

Net Income			$	1,132		$	3,288		$	7,727
Per Share:
	Net Income — Basic		$	1.07		$	3.10		$	7.23
		— Diluted	$	1.07		$	3.09		$	7.21
	Dividends*		$	2.80		$	2.65		$	2.60
Sales and Other Operating Revenues			$	98,691		$	104,409		$	117,095
Return on:
	Average Capital Employed			3.2	%		7.8	%		17.3	%
	Average Stockholders’ Equity			3.5	%		9.8	%		24.5	%

*Chevron Corporation dividend pre-merger.

A summary of the company’s net income by major operating area follows:

NET INCOME (LOSS) BY MAJOR OPERATING AREA


Millions of dollars		2002			2001			2000

Exploration and Production
	United States	$	1,717		$	1,779		$	3,453
	International		2,839			2,533			3,702

Total Exploration and Production			4,556			4,312			7,155

Refining, Marketing and Transportation
	United States		(398	)		1,254			721
	International		31			560			414

Total Refining, Marketing and Transportation			(367	)		1,814			1,135

Chemicals			86			(128	)		40
All Other			(3,143	)		(2,710	)		(603	)

Net Income*		$	1,132		$	3,288		$	7,727

* Includes Foreign Currency (Losses) Gains:		$	(43	)	$	191		$	182

Net income in each period presented includes amounts for matters that management characterizes as “special items,” as described in the table below.

SPECIAL ITEMS


Millions of dollars	2002			2001			2000

Asset Write-Offs and Revaluations	$	(2,642	)	$	(1,709	)	$	(301	)
Asset Dispositions, Net		(149	)		49			72
Prior-Year Tax Adjustments		60			(5	)		107
Environmental Remediation Provisions, Net		(160	)		(78	)		(264	)
Merger-related Expenses		(386	)		(1,136	)		—
Extraordinary Loss from Merger-Related Asset Sales		—			(643	)		—
Other, Net		(57	)		—			8

Total Special Items	$	(3,334	)	$	(3,522	)	$	(378	)

Because of their nature and sufficiently large amounts, the special items in the table above are identified separately to help explain the changes in net income and segment income between periods as well as to help distinguish the underlying trends for the company’s businesses. The categories “Merger-related expenses” and “Extraordinary Loss from Merger-Related Asset Sales” are amounts in 2001 and 2002 that are described in detail in the “Texaco Merger Transaction” section on page FS-3. Other special items are discussed in detail for each major operating area in the “Results of Operations” section beginning on page FS-4.

BUSINESS ENVIRONMENT AND OUTLOOK

As shown in the “Special Items” table, large special-item charges adversely affected net income in 2002 and 2001. In 2002, $2.3 billion of the $3.3 billion of net charges related to the company’s investment in its Dynegy Inc. affiliate. Refer to pages FS-7 and FS-8 for discussion of these matters. Approximately one half of the $3.5 billion of net charges in 2001 related to asset impairments, primarily the result of downward revisions to crude oil and natural gas reserve quantities. These items are discussed in the U.S. and international exploration and production analyses of segment income beginning on page FS-4. Other major charges against earnings in 2002 and 2001 related to the Texaco merger transaction, which is discussed on page FS-3.

Apart from the effects of special items, ChevronTexaco’s earnings depend largely on the profitability of its upstream — exploration and production — and downstream — refining, marketing and transportation — businesses. Overall earnings trends are typically less affected by results from the company’s commodity chemicals sector and investments in other businesses. Key components of the company’s competitive position, particularly given the capital-intensive infrastructure and the commodity-based nature of many of its products, are the ability to invest capital in projects that provide adequate financial returns and managing operating expenses successfully. The company also continuously evaluates opportunities to acquire assets or operations complementary to its asset base to help sustain the company’s growth. During 2003, the company intends to evaluate and determine which assets in its overall post-merger portfolio are key to providing long-term value. Accordingly, certain asset dispositions may result.

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

Upstream Year-to-year changes in exploration and production earnings align most closely with industry price levels for crude oil and natural gas. Crude oil and natural gas prices are subject to certain external factors, over which the company has no control, including product demand connected with global economic conditions, industry inventory levels, weather-related damages and disruptions, competing fuel prices, and the regional supply interruptions that may be caused by military conflicts or political uncertainty. Longer-term trends in earnings for this segment are also a function of a range of factors in addition to price trends, including the company’s ability to find or acquire reserves and efficiently produce them.

Average worldwide industry prices for crude oil in 2002 were little changed from 2001. However, the company’s average natural gas realization in the United States fell about one third from the prior year and contributed to the decline in the company’s U.S segment income between periods. Segment income in 2002 for

FS-2

international operations reflected relatively little change in prices for both crude oil and natural gas.

During 2002, industry price levels for crude oil trended upward from the $20 per-barrel level to about $30. In early March 2003, the spot price for West Texas Intermediate (WTI), a benchmark crude oil was quoted between $35 and $40 per barrel — a 12-year high. Benchmark prices for Henry Hub U.S. natural gas started 2002 in the low-$2 range per thousand cubic feet and also trended upward during the year, to about the $5 level. Through mid-March 2003, the benchmark natural gas price was volatile and averaged about $7 per thousand cubic feet for that period. The relatively strong prices for crude oil in early 2003 in part reflected the geopolitical uncertainty in Iraq and Venezuela. The higher U.S. natural gas price was primarily attributable to falling inventory storage levels reflecting withdrawals to meet the demands of a cold winter over much of the United States.

Segment income during 2002 was also dampened by lower worldwide oil-equivalent production — down 3 percent from 2001 levels. Part of the production decline was the result of OPEC quotas, which accounted for a decrease in Nigeria of about 30,000 barrels of crude oil per day in 2002. Storms in the Gulf of Mexico reduced 2002 oil-equivalent production by about 20,000 barrels per day. The impact of revised terms on a production-sharing contract in Indonesia lowered 2002 net oil-equivalent production by about 25,000 barrels per day. Absent these effects, worldwide oil-equivalent production was at about the same level in both years. The expected production level in 2003 and beyond is uncertain, in part because of the possibility of additional quota adjustments by OPEC and the potential for local civil unrest and changing geopolitics that could cause production disruptions. Capital expenditures are weighted heavily to international areas due to the greater number of economic opportunities.

Downstream Refining, marketing and transportation earnings are closely tied to regional demand and industry refining and marketing margins. Other, company-specific, factors influencing the company’s profitability in this segment include the operating efficiencies of its refinery network, including any downtime due to operating incidents and maintenance.

Industry margins worldwide were strong in the early part of 2001 but trended downward worldwide during the year, as worldwide demand for refined products weakened. By early 2002, ChevronTexaco margins were at their lowest levels since the mid-1990s, as weak market conditions would not allow feedstock costs to be fully recovered from consumers of refined products. As a result, worldwide earnings plummeted between 2001 and 2002 to below break-even. Additionally, the decline in earnings from 2001 included the absence of ongoing earnings from U.S. downstream assets that were sold as a condition of the merger. Into early 2003, U.S. refined products margins strengthened on the combined effects of the general strike in Venezuela, colder-than-normal winter weather and low inventory levels. Based on current industry and economic conditions, the company does not expect a rebound of earnings for this segment in 2003 to levels similar to 2001 and 2000.

Chemicals Earnings for the company’s Oronite subsidiary improved in 2002, and losses from the 50 percent-owned Chevron Phillips Chemical Co. LLC affiliate were lower. Demand and margins for commodity chemicals have been at low levels for a protracted period, and significant improvement is not expected in the near future.

TEXACO MERGER TRANSACTION

Basis of Presentation On October 9, 2001, Texaco Inc. (Texaco) became a wholly owned subsidiary of Chevron Corporation (Chevron) pursuant to a merger transaction, and Chevron changed its name to ChevronTexaco Corporation. Certain operations that were jointly owned by the combining companies are consolidated in the accompanying financial statements. These operations are primarily those of the Caltex Group of Companies, which was previously owned 50 percent each by Chevron and Texaco. The combination was accounted for as a pooling of interests, and the accompanying audited consolidated financial statements for all periods are presented as if Chevron and Texaco had always been combined.

Merger Effects Under mandate of the Federal Trade Commission (FTC) as a condition to FTC approval of the merger, the company sold its interests in Equilon and Motiva — joint ventures engaged in U.S. downstream businesses — in February 2002, resulting in cash proceeds of $2.2 billion, including dividends due. Indemnification by ChevronTexaco against certain Equilon and Motiva contingent liabilities at the date of sale are discussed in the “Guarantees, Off-Balance-Sheet Arrangements and Contractual Obligations, and Other Contingencies” section beginning on page FS-10. Other mandated asset dispositions were also completed during 2002. Net income and cash proceeds from these other sales were not material. Net income during 2001 for all assets that were sold as a condition of the merger was approximately $375 million. The net loss on assets sold under the FTC mandate is presented in the 2001 income statement as an extraordinary item.

The company incurred before-tax merger-related expenses of $1.563 billion ($1.136 billion after tax) and $576 million ($386 million after tax) in 2001 and 2002, respectively. Major expenses included employee severance payments; incremental pension and medical plan benefit costs associated with workforce reductions; legal, accounting, Securities and Exchange Commission (SEC) filing and investment banker fees; employee and office relocations; and costs for the elimination of redundant facilities and operations. No significant merger-related expenses are anticipated for 2003.

Included in merger-related expenses were accruals of $891 million and $60 million in 2001 and 2002, respectively, for severance-related benefits for approximately 4,500 employees and other merger-related expenses that will not benefit future operations.

Activity for this accrual balance is summarized in the table below:


Millions of dollars	Amount

Additions — 2001	$	891
Payments — 2001		(105	)

Balance at December 31, 2001		786
Additions — 2002		60
Payments — 2002		(470	)

Balance at December 31, 2002	$	376

Of the 4,500 employees to be terminated, approximately 450 remained on the payroll at December 31, 2002. The year-end 2002 accrual balance is not expected to be extinguished for approximately two years, reflecting a severance payment deferral option exercised by some employees.

FS-3

OPERATING DEVELOPMENTS

Operating developments and events during 2002 and early 2003 included:

Worldwide Oil and Gas Reserves and Production The company added approximately 1.1 billion barrels of oil-equivalent reserves during 2002. These additions equated to 114 percent of production for the year. Included were nearly 600 million barrels of oil-equivalent from major discoveries and extensions in Africa, Australia, Europe and China. Additionally, 500 million barrels were added through improved recovery and expansion projects, primarily in Africa, Eurasia and California. Worldwide oil-equivalent production declined in 2002 about 3 percent, compared with 2001 and about 4 percent compared with 2000. The decreases between years reflect lower U.S. production levels, partially offset by increased international production.

U.S. Gulf of Mexico Two deepwater discoveries were made — Tahiti and Great White — and are in the process of being evaluated. ChevronTexaco, with a 58 percent interest, operates the Tahiti prospect. The company has a one-third non-operated interest in Great White. In December, the company submitted an application to construct and operate the Port Pelican Liquefied Natural Gas (LNG) receiving and regasification terminal, located approximately 50 miles offshore in the Gulf of Mexico. Phase 1 of the project is designed to process up to 800 million cubic feet of natural gas per day and will connect to existing infrastructure along the Gulf Coast. ChevronTexaco’s interest is 100 percent. LNG projects like Port Pelican can help offset the effect of an expected long-term decline in the industry’s U.S. natural gas production.

Angola The eighth and ninth discoveries — Gabela and Negage — were announced in ChevronTexaco-operated deepwater Block 14. These latest discoveries will be followed by geological and engineering studies to assess their reserve potential. The company, as operator, holds a 31 percent interest in Block 14.

Nigeria A second oil discovery — Usan — was made in the non-operated deepwater Nigeria Block OPL 222, where the company holds a 30 percent interest. The prospect is approximately 60 miles offshore in a water depth greater than 2,000 feet. The company also confirmed its deepwater Block OPL 213 Aparo oil discovery (100 percent company interest) with a successful appraisal well. The Aparo discovery shares a structure with an adjacent concession and will likely become part of a joint oil development.

U.K. North Sea The company announced first oil from Alba Extreme South, the latest phase in the field’s development in which ChevronTexaco, as operator, has a 21 percent interest. The phased development expansion is expected near-term to add more than 50,000 barrels of oil per day to Alba production (100 percent field basis), offsetting existing production declines and maintaining a plateau rate of up to 100,000 barrels of oil per day. The Caledonia Field produced first oil in February 2003 with total production expected to average about 10,000 barrels of crude oil per day during 2003. ChevronTexaco is operator with a 27 percent interest.

Tengiz Following a delay in late 2002, Tengizchevroil (TCO) announced in early 2003 that its partners had approved the detailed engineering and construction of the Second Generation Program and Sour Gas Injection Project. These two projects are expected to increase TCO’s oil production capacity from the current rate of about 285,000 barrels per day to between 430,000 and 500,000 barrels per day. Current development plans call for the two projects to be completed mid-2006. ChevronTexaco has a 50 percent ownership interest in TCO.

Australia The People’s Republic of China selected the North West Shelf Venture, in which ChevronTexaco has a one-sixth interest, as the sole supplier of LNG to the proposed Guangdong LNG project in southern China. A conditional 25-year LNG Sale and Purchase Agreement for more than 3.9 trillion cubic feet of natural gas (equivalent to about 400 million cubic feet per day) was signed in October.

China The company entered into a unitization agreement with China National Offshore Oil Corp (CNOOC) in October to jointly develop the Bozhong Field in Bohai Bay. This is the first unitization agreement between CNOOC and a foreign partner. ChevronTexaco holds an approximate 16 percent interest.

U.S. Refining An expansion project to produce low sulfur motor gasoline and diesel at the company’s Pascagoula, Mississippi, refinery will become operational during the first quarter of 2003.

Chemicals In Qatar, a world-scale olefins and polyolefins complex is currently being commissioned. The facility is owned and operated by Qatar Chemical Company, a joint venture between Chevron Phillips Chemical Company LLC (CPChem), the company’s 50 percent-owned petrochemical affiliate, and its partner Qatar General Petroleum. CPChem has signed agreements to develop a second petrochemical complex in Qatar. The project will include a world-scale olefins facility, along with derivatives units. Final approvals are anticipated in mid-2004.

U.S. Natural Gas Marketing The company’s natural gas purchase and sale agreements with its 26 percent-owned Dynegy affiliate were terminated at the end of January 2003. Under the transition arrangements, Dynegy is to act in an agency role for the company until the contracts become managed by ChevronTexaco Natural Gas — a new wholesale natural gas marketing unit that is expected to be fully operational in April 2003. The contract terminations followed Dynegy’s decision to exit the gas trading and marketing business as part of a companywide restructuring plan. See page FS-8 for information related to the company’s investment in Dynegy.

RESULTS OF OPERATIONS

Major Business Areas The following section presents the results of operations for the company’s business segments as well as for the departments and companies managed at the corporate level. To aid in the understanding of changes in segment income between periods, the discussion is in two parts - first, on underlying trends and second, for special items that tended to obscure these trends.

U.S. Exploration and Production


Millions of dollars	2002			2001			2000

Segment Income	$	1,717		$	1,779		$	3,453

Special Items Included in Segment Income:
Asset Write-Offs and Revaluations		(183	)		(1,168	)		(176	)
Asset Dispositions		—			49			(107	)
Environmental Remediation Provisions		(31	)		—			—
Prior-Year Tax Adjustments		—			8			—

Total Special Items	$	(214	)	$	(1,111	)	$	(283	)

Segment income in 2002 reflected significantly lower natural gas realizations and an 11 percent decrease in natural gas production. Also contributing to the earnings decline was lower liquids production, which dropped 2 percent from 2001 levels. Lower earnings in 2001 from 2000 partially resulted from significantly lower liquids realizations and lower oil-equivalent production, offset by higher natural gas prices.

FS-4

The average natural gas realization was $2.89 per thousand cubic feet in 2002, compared with $4.38 and $3.87 in 2001 and 2000, respectively. The company’s average 2002 U.S. liquids realization was $21.34 per barrel, compared with $21.33 in 2001 and $25.61 in 2000.

Net oil-equivalent production averaged 1.002 million barrels per day in 2002, down 6 percent from 2001 and 13 percent from 2000. The net liquids component for 2002 averaged 602,000 barrels per day, down 2 percent from 2001 and 10 percent from 2000. Net natural gas production averaged 2.4 billion cubic feet per day in 2002, down 11 percent from 2001 and 17 percent from 2000. The company’s 2002 production of crude oil and natural gas was constrained by tropical storms that occurred in September and October in the Gulf of Mexico. The storms reduced the company’s 2002 oil-equivalent production by about 20,000 barrels per day, split equally between liquids and natural gas. The negative impact on the company’s net income was about $100 million, including casualty losses for the uninsured portion of property damages and associated costs. In addition to the impacts of the storms on 2002 production, the lower oil-equivalent production reflected normal field declines and the absence of production from assets sold in 2001, partially offset by new and enhanced production in the deepwater and other areas of the Gulf of Mexico. The reductions in net natural gas production reflected, in part, steep decline rates in areas of the Gulf of Mexico Shelf that were brought onto production in late 2000 and early 2001 to take advantage of a period of high natural gas prices.

Special items during the three years included asset write-offs and revaluations resulting mainly from asset impairments caused by write-downs in proved oil and gas reserve quantities for various fields. In 2001, a $1.0 billion impairment was recorded for the Midway Sunset Field in California’s San Joaquin Valley, upon determining lower-than-projected oil recovery from the field’s steam-injection process.

International Exploration and Production


Millions of dollars	2002			2001			2000

Segment Income*	$	2,839		$	2,533		$	3,702

*Includes Foreign Currency Gains	$	90		$	181		$	97
Special Items Included in Segment Income:
Asset Write-Offs and Revaluations	$	(100	)	$	(247	)	$	—
Asset Dispositions		—			—			80
Prior-Year Tax Adjustments		(37	)		(125	)		—

Total Special Items	$	(137	)	$	(372	)	$	80

The earnings improvement in 2002 versus 2001 was marginally affected by a combination of higher liquids realizations and natural gas production and lower exploration and income tax expense, offset in part by lower liquids production and natural gas realizations and higher depreciation expense. The earnings decline in 2001 versus 2000 reflected lower average liquids realizations, the effect of which was partially offset by a 3 percent increase in oil-equivalent production and higher natural gas prices.

The average liquids realization, including equity affiliates, was $23.06 per barrel in 2002, compared with $22.17 in 2001 and $26.04 in 2000. The average natural gas realization was $2.14 per thousand cubic feet in 2002, compared with $2.36 in 2001 and $2.09 in 2000.

Daily net liquids production of 1.295 million barrels in 2002 decreased about 4 percent from 1.345 million barrels in 2001 and about 3 percent from 1.330 million barrels in 2000. Production decreases during 2002 in Indonesia, primarily due to changes in contractual terms, and Nigeria, primarily due to OPEC constraints, were slightly offset by increased production in Kazakhstan. During 2001, increases in Kazakhstan more than offset lower volumes from Indonesia.

Net natural gas production of 1.971 billion cubic feet per day in 2002 was up 15 percent from 2001 and more than 26 percent from 2000. A major factor in the 2002 production increase was a full year of new production from the Malampaya Field in the Philippines. Other geographic areas with production increases were Kazakhstan, Nigeria and Australia. These increases were slightly offset by lower production from mature fields in Canada. In 2001, areas with production increases were Kazakhstan, Trinidad and Tobago, South Korea and Canada.

Special-item charges in 2002 for asset write-offs and revaluations were for asset impairments associated with write-downs in quantities of proved oil and gas reserves for fields in Africa and Canada. Special items in 2001 included a $247 million impairment of the LL-652 Field in Venezuela, as slower-than-expected reservoir repressurization resulted in a reduction in the projected volumes of oil recoverable during the company’s remaining contract period of operation.

U.S. Refining, Marketing and Transportation


Millions of dollars	2002			2001			2000

Segment (Loss) Income	$	(398	)	$	1,254		$	721

Special Items Included in Segment (Loss) Income:
Asset Write-Offs and Revaluations	$	(66	)	$	—		$	—
Environmental Remediation Provisions		(92	)		(78	)		(191	)
Litigation and Regulatory		(57	)		—			(62	)

Total Special Items	$	(215	)	$	(78	)	$	(253	)

The U.S. refining, marketing and transportation segment loss in 2002 was primarily the result of significantly lower refined product margins. Results for 2001 and 2000 included earnings of $375 million and $215 million, respectively, associated with assets sold as a condition of the merger, which included the company’s Equilon and Motiva joint ventures. In addition, sales volumes for operations that were retained following the merger were down in 2002, primarily due to lower fuel oil trading activity and jet fuel sales volumes. The decline in jet fuel sales volumes reflected the weakened travel industry. The earnings increase in 2001 reflected significantly higher gasoline sales margins — especially early in the year - partially offset by weaker distillate sales margins and higher operating expenses. Higher sales volumes also contributed to the improvement in 2001.

Excluding the company’s share of sales volumes associated with assets sold as a condition of the merger, refined products sales volumes of 1.610 million barrels per day in 2002 decreased about 4 percent from 2001 and about 2 percent from 2000. The average U.S. refined products sales realization of $34.33 per barrel in 2002 was down from the 2001 average of $36.26 per barrel and down from $39.32 per barrel in 2000.

Special items in 2002 included environmental remediation provisions and asset write-downs for certain refining and marketing assets and a $57 million charge connected with a lawsuit related to groundwater contamination caused by MTBE (methyl tertiary butyl ether), an additive used in the manufacture of certain gasoline.

FS-5

SELECTED OPERATING DATA


		2002		2001		2000

U.S. Exploration and Production
Net Crude Oil and Natural Gas Liquids Production (MBPD)			602		614		667
Net Natural Gas Production (MMCFPD)			2,405		2,706		2,910
Natural Gas Sales (MMCFPD)¹			5,463		7,830		7,302
Natural Gas Liquids Sales (MBPD)¹			241		185		170
Revenues from Net Production
	Liquids ($/Bbl)	$	21.34	$	21.33	$	25.61
	Natural Gas ($/MCF)	$	2.89	$	4.38	$	3.87
International Exploration and Production¹
Net Crude Oil and Natural Gas Liquids Production (MBPD)			1,295		1,345		1,330
Net Natural Gas Production (MMCFPD)			1,971		1,711		1,556
Natural Gas Sales (MMCFPD)			3,131		2,675		2,398
Natural Gas Liquids Sales (MBPD)			131		115		67
Revenues from Liftings
	Liquids ($/Bbl)	$	23.06	$	22.17	$	26.04
	Natural Gas ($/MCF)	$	2.14	$	2.36	$	2.09
Other Produced Volumes (MBPD)²			97		105		123
U.S. Refining, Marketing and Transportation^1,3
Gasoline Sales (MBPD)			733		709		717
Other Refined Products Sales (MBPD)			877		974		934
Refinery Input (MBPD)			979		983		943
Average Refined Products Sales Price ($/Bbl)		$	34.33	$	36.26	$	39.32
International Refining, Marketing and Transportation¹
Refined Products Sales (MBPD)			2,258		2,454		2,521
Refinery Input (MBPD)			1,100		1,136		1,150

MBPD = Thousands of barrels per day; MMCFPD = Millions of cubic feet per day;

Bbl = Barrel; MCF = Thousands of cubic feet.

¹ Includes equity in affiliates, except as explained in footnote 3.

² Represents total field production under the Boscan operating service agreement in Venezuela, and in 2000 included a Colombian operating service agreement.

³ Excludes Equilon and Motiva pre-merger.

International Refining, Marketing and Transportation


Millions of dollars	2002			2001			2000

Segment Income*	$	31		$	560		$	414

*Includes Foreign Currency (Losses) Gains:	$	(176	)	$	23		$	107
Special Items Included in Segment Income:
Asset Write-Offs and Revaluations		(136	)		(46	)		(112	)
Prior-Year Tax Adjustments		—			8			—

Total Special Items	$	(136	)	$	(38	)	$	(112	)

The international refining, marketing and transportation segment includes the company’s consolidated refining and marketing businesses, international marine operations, international supply and trading activities, and equity earnings of affiliates, primarily in the Asia-Pacific region.

Earnings in 2002 included foreign currency losses of $176 million, compared with gains of $23 million and $107 million in 2001 and 2000, respectively. Currency losses in 2002 occurred mainly in Brazil, New Zealand, Australia, South Korea and the United Kingdom.

Income in most of the company’s operating areas declined in 2002, with the exception of Latin America, where earnings increased. In the areas with lower earnings, supply-demand fundamentals did not allow the immediate recovery of rising crude oil costs in the marketplace, with product price changes lagging those for feedstock costs. This condition reflected weak demand, stiff competition and, in some areas, regulated price environments. Lower refining margins in 2002 reflected continued excess refining capacity in these regions. The improved results in Latin America for 2002 were primarily from reduced operating expenses, offset slightly by lower product margins and lower volumes. Results from the company’s international shipping operations also declined in 2002, compared with 2001, primarily on lower freight rates.

After excluding the effects of foreign currency gains in both 2001 and 2000 for the segment as a whole, results for 2001 were significantly improved because of improved marketing margins, particularly early in the year. Partially offsetting the marketing improvement were higher operating costs and somewhat lower refining margins.

Total international refined products sales volumes were 2.258 million barrels per day in 2002, down about 8 percent from 2.454 million in 2001 and about 10 percent from 2.521 million in 2000. Weak economic conditions continued to dampen demand in 2002.

The special item amount in 2002 was for a write-down of the company’s investment in its publicly traded Caltex Australia affiliate to its fair value, as a result of protracted weak business conditions in the Australian downstream markets. The write-down was based on management’s judgment that the decline in the investment’s fair value below its carrying value was deemed to be other than temporary. Special items in 2001 included the impairment of refinery assets in Central America. The special item asset write-offs and revaluations in 2000 included impairments of marketing assets in eastern Europe and Central America.

Chemicals


Millions of dollars	2002		2001			2000

Segment Income (Loss)*	$	86	$	(128	)	$	40

*Includes Foreign Currency Gains (Losses):	$	3	$		(3)	$	(2	)
Special Items Included in Segment Income (Loss):
Asset Write-Offs and Revaluations	$	—	$	(96	)	$	(90	)

Chemicals includes the company’s Oronite subsidiary, the petrochemicals business prior to its contribution to CPChem in July 2000 and equity earnings in CPChem from that date. Results for all years reflect a protracted period of generally weak demand for commodity chemicals and industry over-capacity. Results for both CPChem and the company’s Oronite subsidiary improved in 2002 primarily on lower feedstock and utility costs.

Special items in 2001 and 2000 included write-downs of the CPChem Puerto Rico operations. There were no special items in 2002.

FS-6

All Other


Millions of dollars	2002			2001			2000

Segment Charges*	$	(3,143	)	$	(2,710	)	$	(603	)

*Includes Foreign Currency Gains (Losses):	$	40		$	(10	)	$	(20	)
Special Items Included in Segment Charges:
Asset Write-Offs and Revaluations	$	(2,157	)	$	(152	)	$	77
Asset Dispositions		(149	)		—			99
Prior-Year Tax Adjustments		97			104			107
Environmental Remediation		(37	)		—			(73	)
Merger-Related Expenses		(386	)		(1,136	)		—
Extraordinary Loss from Merger-Related Asset Sales		—			(643	)		—
Other		—			—			70

Total Special Items	$	(2,632	)	$	(1,827	)	$	280

All Other consists of the company’s equity interest in Dynegy, coal mining operations, power and gasification ventures, worldwide cash management and debt financing activities, corporate administrative costs, insurance operations, real estate activities, and technology companies.

Aside from the effect of special items, the change between 2001 and 2002 reflected primarily the favorable effect of lower corporate charges, including an increase in favorable tax adjustments of $245 million and lower net interest expense of $71 million, offset, in part, by a decline in the company’s share of Dynegy’s operating results.

During 2002, Dynegy results were severely affected by a downturn in the energy merchant sector, which was characterized by lower liquidity levels, reduced power prices and credit concerns. Special items in 2002 included $2.306 billion related to Dynegy, composed of $1.626 billion for the write-down of the company’s investment in Dynegy common and preferred stock to their estimated fair values and $680 million for the company’s share of items Dynegy classified as special for asset write-downs and revaluations and a loss on an asset sale. Refer to page FS-8 for further information relating to the company’s investments in Dynegy.

Consolidated Statement of Income In the following table, amounts for special items by income statement category are shown to assist in the explanation of changes in those categories between periods. In addition to the effects of special items shown in the table, separately disclosed on the face of the Consolidated Income Statement, are merger-related expenses, write-downs of investments in equity affiliates and the extraordinary after-tax loss on the sale of assets mandated as a condition of the merger. These matters are discussed elsewhere in this discussion and in Note 2 to the Consolidated Financial Statements on page FS-27.


Millions of dollars	2002		2001		2000

Income from equity affiliates	$	111	$	1,144	$	1,077

Memo: Special charges, before tax		693		123		141

Other income	$	247	$	692	$	958

Memo: Special gains, before tax		—		84		356

Operating expenses	$	7,848	$	7,650	$	8,323

Memo: Special charges, before tax		259		25		394

Selling, general and administrative expenses	$	4,155	$	3,984	$	3,626

Memo: Special charges, before tax		180		139		94

Depreciation, depletion and amortization	$	5,231	$	7,059	$	5,321

Memo: Special charges, before tax		298		2,294		561

Interest and debt expense	$	565	$	833	$	1,110

Memo: Special charges, before tax		—		—		4

Minority interest	$	57	$	121	$	111

Memo: Special gains, before tax		—		—		9

Taxes other than on income	$	16,689	$	15,156	$	15,827

Memo: Special charges, before tax		—		12		—

Income tax expense	$	3,024	$	4,360	$	6,322

Memo: Special gains		604		1,193		451

Explanations are provided below of variations between years for the amounts in the table above — after consideration of the effects of special items — as well as for other income statement categories.

Sales and other operating revenues were $99 billion in 2002, compared with $104 billion in 2001 and $117 billion in 2000. Revenues from worldwide upstream operations decreased 27 percent on lower prices for natural gas, particularly in the United States. Sales volumes of natural gas were also down in the United States. Downstream sales and other operating revenues were about 6 percent higher in 2002, primarily on higher prices for refined products in the fourth quarter of 2002. Total sales and other operating revenues in 2001 declined from 2000 on lower average realizations for crude oil and refined products.

Income from equity affiliates declined in 2002, reflecting the absence of earnings from assets sold as a condition of the merger and lower earnings from Dynegy. Equity income increased marginally in 2001 on the strength of improved earnings for Equilon, Motiva and Dynegy, partially offset by lower earnings for TCO and LG-Caltex and by larger losses from CPChem.

Other income decreased in 2002 as a result of lower interest income, changes in net foreign exchange gains and losses, and net gains and losses from asset sales.

Foreign currency losses in 2002 were $43 million, compared with gains of $191 million and $182 million in 2001 and 2000, respectively. In 2002, net gains from fluctuations of the U.S. dollar against the Argentine peso, which began to float against the dollar during the year, were more than offset by losses related to currencies of most other countries in which the company has significant operations.

Purchased crude oil and products costs of $57 billion in 2002 were 5 percent lower than 2001 — primarily due to lower natural gas prices and sales volumes — and about 18 percent lower than 2000 — primarily due to lower crude oil and natural gas prices and lower natural gas volumes.

FS-7

Operating, selling, general and administrative expenses benefited from merger synergy savings, which were substantially offset by increases related to pension expense, payroll and other employee benefits.

Exploration expenses were $0.6 billion in 2002, compared with $1.0 billion in 2001 and $0.9 billion in 2000. In 2002, well write-offs and other exploration expenses were $358 million and $90 million lower, respectively, compared with 2001. The reduced expenses in 2002 reflect, in part, the high-grading of the company’s exploration portfolio following the merger. In 2001, well write-offs were $184 million higher compared with 2000, which more than offset declines in other exploration expenses.

Depreciation, depletion and amortization expense increased for international upstream operations in 2002, but this effect was slightly offset by lower expenses in the U.S. upstream segment. In 2001, the absence of charges relating to chemicals assets contributed to the CPChem joint venture that was formed in mid-2000 were essentially offset by increases in amounts for other segments.

Interest and debt expense was $0.6 billion in 2002, compared with $0.8 billion in 2001 and $1.1 billion in 2000. The declines between periods primarily reflected lower average interest rates on debt.

Income tax expense for each year corresponded to effective tax rates of 45 percent in each year after taking into account the effect of special items. See also Note 15 to the Consolidated Financial Statements.

INFORMATION RELATED TO INVESTMENT IN DYNEGY INC.

ChevronTexaco owns approximately 26 percent of the common stock of its Dynegy affiliate, an energy merchant engaged in power generation, natural gas liquids and regulated energy delivery. The company also holds $1.5 billion aggregate principal amount of Dynegy preferred stock, which is due to be redeemed at par in November 2003.

As a result of a collapse of the U.S. merchant-energy sector during 2002, Dynegy experienced a significant reduction in the value of its common stock, as well as a marked reduction in available liquidity. This resulted in limited access by Dynegy to the capital markets and an increasing use of its assets as collateral for its liabilities. Dynegy is also the subject of regulatory investigations and is the defendant in a number of lawsuits seeking large damage amounts. During 2002, debt ratings of Dynegy securities were downgraded below investment-grade level. Dynegy’s ability to meet its obligations in a timely fashion depends in part on completion of its announced plans for recapitalization and restructuring of the business. The company does not currently anticipate that Dynegy will have sufficient liquidity to redeem the preferred stock when due.

ChevronTexaco’s net income for 2002 included special charges of $2.306 billion related to Dynegy. These charges were composed of $1.626 billion for the company’s write-down of the combined investment in Dynegy common and preferred stock, and $680 million for the company’s share of Dynegy’s own special items during the year. The write-down of the company’s investments in Dynegy during 2002 was required because the declines in the fair values of the common and preferred stock investments below their respective carrying values were deemed to be other than temporary.

Additional write-downs of the investments in Dynegy would be required to the extent the fair values of the Dynegy securities at the end of any subsequent period were below their respective carrying values at that time, and the declines in value were deemed to be other than temporary. In the event Dynegy records losses in future periods, the company’s share of those losses would be recorded first against any remaining carrying value of the common stock and then against the carrying value of the preferred stock.

At December 31, 2002, the remaining book value of the company’s investment in Dynegy was $347 million — composed of $300 million for the preferred stock and $47 million for the common stock. The market value of ChevronTexaco’s share of Dynegy common stock was $114 million, based on equivalent closing market prices. No quoted market price exists for the preferred stock. Refer to “Dynegy Preferred Stock Investment” on page FS-12 for a description of the methodology used to estimate the fair value at December 31, 2002.

For the common and preferred stock, if future declines in the fair value are deemed other than temporary, a charge would be recorded against income. However, the effect of a temporary decline, or any increase, in fair value of the preferred stock would be recorded in “Other comprehensive income” and would be recognized in income at the time of redemption or disposition of the security, or in the event of a further other-than-temporary decline in its fair value.

At December 31, 2002, the carrying value of the common stock investment was approximately $500 million below the company’s proportionate amount of Dynegy net equity. This difference will be accreted to income over the estimated economic life of the underlying net assets in the absence of any future impairment of the investment.

At the request of Dynegy, its independent accountant is conducting a re-audit of the 1999-2001 financial statements, which has resulted thus far in certain restatements of prior periods. To date, ChevronTexaco’s share of the known restatements has not been material and, accordingly, prior periods in the accompanying Consolidated Financial Statements have not been restated. Upon conclusion of the audit, the independent accountants will perform reviews of the 2002 quarterly financial statements. The results of these audits and reviews may require further restatements by Dynegy. ChevronTexaco will evaluate the effects on its Consolidated Financial Statements at that time.

LIQUIDITY AND CAPITAL RESOURCES

Cash, cash equivalents and marketable securities were $3.8 billion and $3.2 billion at December 31, 2002 and 2001, respectively. Cash provided by operating activities in 2002 was $9.9 billion, compared with $11.5 billion in 2001 and $13.5 billion in 2000. The 2002 decline in cash provided by operating activities mainly reflected lower earnings in the U.S. upstream and worldwide downstream businesses. Cash provided by asset sales was $2.3 billion in 2002, $0.3 billion in 2001 and $1.2 billion in 2000. In February 2002, the company received proceeds of $2.2 billion, including dividends due, from the FTC-mandated sale of the company’s investments in Equilon and Motiva. In 2002, these proceeds and cash provided by operating activities generated sufficient funds for the company’s capital and exploratory expenditure program, the payment of dividends to stockholders, and a reduction in overall debt levels.

FS-8

Dividends ChevronTexaco made payments of $2.991 billion, $2.858 billion and $2.789 billion for dividends or distributions for common stock, preferred stock and minority interests in 2002, 2001 and 2000, respectively.

Debt, Lease and Minority Interest Obligations ChevronTexaco’s total debt and capital lease obligations were $16.3 billion at December 31, 2002, down from $17.4 billion at year-end 2001. The company also had minority interest obligations of $303 million, up from $283 million at December 31, 2001.

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 $9.5 billion at December 31, 2002, down from $11.6 billion at the end of 2001. Of these totals, $4.1 billion and $3.2 billion were reclassified to long-term at the end of each period, respectively. Settlement of these obligations is not expected to require the use of working capital in 2003, as the company has the intent and the ability, as evidenced by committed credit facilities, to refinance them on a long-term basis. The company’s practice has been to continually refinance its commercial paper, maintaining levels it believes appropriate.

At year-end 2002, ChevronTexaco had $4.1 billion in committed credit facilities with various major banks, which permit the refinancing of short-term obligations on a long-term basis. These facilities support commercial paper borrowings and also can be used for general credit requirements. No borrowings were outstanding under these facilities during the year or at year-end 2002.

During 2002, the company increased the total value of “shelf” registrations on file with the Securities and Exchange Commission (SEC) by $2.0 billion, to $4.8 billion. At December 31, 2002, the company had three existing effective shelf registrations on file with the SEC that together would permit additional registered debt offerings up to an aggregate of $2.8 billion of securities.

The company issued $2.0 billion of 3.5 percent Guaranteed Notes Due 2007 under a shelf registration in 2002. The proceeds from this issue are expected to be used to retire commercial paper. Repayments of long-term debt in 2002 included $250 million of Texaco North Sea U.K. notes, $285 million of Texaco Capital Inc. bonds, $192 million of New Zealand debt, $120 million of Philippine debt, $114 of South African debt and $100 million of ChevronTexaco Corporation 8.11 percent notes. The change in long-term debt during 2002 also included a noncash reduction of $100 million in the company-guaranteed Employee Stock Ownership Plan (ESOP) debt.

In February 2003, the company redeemed $200 million of Texaco Capital Inc. bonds originally due in 2033. Under a shelf registration also in February, the company issued $750 million of 3.375 percent bonds due in February 2008. The company plans to use the proceeds from this issuance to pay down outstanding commercial paper borrowings.

ChevronTexaco’s senior debt is rated AA by Standard and Poor’s Corporation and Aa2 by Moody’s Investor Service. Bonds issued by Texaco Inc. are rated Aa3. ChevronTexaco’s U.S. commercial paper is rated A-1+ by Standard and Poor’s and Prime 1 by Moody’s, and the company’s Canadian commercial paper is rated R-1 (middle) by Dominion Bond Rating Service. All of these ratings denote high-quality, investment-grade securities.

The company’s future debt level is dependent primarily on results of operations, the capital-spending program and cash that may be generated from asset dispositions. The company believes it has substantial borrowing capacity to meet unanticipated cash requirements, and 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.

Pension Obligations Based on the expected changes in plan asset values and pension obligations in 2003, the company does not believe any significant funding of its pension plans will be required during the year. Additional funding may ultimately be required in subsequent periods if investment returns are insufficient to offset increases in the plans’ obligations. Refer also to the discussion of pension accounting in “Application of Critical Accounting Policies” beginning on page FS-15.

Capital and exploratory expenditures for 2002 totaled $9.3 billion, including the company’s equity share of affiliates’ expenditures. Capital and exploratory expenditures were $12.0 billion in 2001 and $9.5 billion in 2000. The company’s equity share of affiliates’ expenditures, which did not require cash outlays by the company, were $1.4 billion, $1.7 billion and $1.2 billion in 2002, 2001 and 2000, respectively. Expenditures of $6.3 billion in 2002 for exploration and production activities represented 68 percent of total outlays in 2002, compared with 59 percent in 2001 and 66 percent in 2000. International exploration and production spending of $4.4 billion was 70 percent of worldwide exploration and production expenditures in 2002, compared with 66 percent in 2001 and 62 percent in 2000, reflecting the company’s continuing focus on international exploration and production activities. Expenditures in 2002 included lower additional investments in equity affiliates than in 2001, reflecting the absence of the company’s share of expenditures in its Equilon and Motiva investments, which were sold as a condition of the merger. The 2001 expenditures included additional investments in TCO and Dynegy, including the purchase of $1.5 billion of Dynegy preferred stock.

The company estimates 2003 capital and exploratory expenditures will be $8.5 billion, which is about 8 percent lower than expenditures in 2002. Included in this amount is about $1.6 billion in affiliates’ expenditures. About $6.4 billion, or 75 percent of the total, is budgeted for exploration and production activities, with $4.7 billion of that outside the United States. Worldwide exploration and production expenditures will target the most promising exploratory prospects in Nigeria, Angola and deepwater Gulf of Mexico and major development projects in Kazakhstan, Venezuela and Africa. Worldwide downstream spending is estimated to be $1.3 billion, with about $1.1 billion of the amount on refining and marketing and $200 million on transportation projects. Investments in chemicals are budgeted at $300 million. Estimates for power and related businesses are $300 million, down from about $600 million in 2002. The remaining $200 million is primarily for emerging technologies and information technology infrastructure.

FS-9

Capital and Exploratory Expenditures


					2002						2001						2000

			Inter-						Inter-						Inter-
Millions of dollars	U.S.		national		Total		U.S.		national		Total		U.S.		national		Total

Exploration and Production	$	1,888	$	4,395	$	6,283	$	2,420	$	4,709	$	7,129	$	2,354	$	3,897	$	6,251
Refining, Marketing and Transportation		750		882		1,632		873		1,271		2,144		919		1,121		2,040
Chemicals		272		37		309		145		34		179		135		51		186
All Other		811		220		1,031		2,570		6		2,576		891		152		1,043

Total	$	3,721	$	5,534	$	9,255	$	6,008	$	6,020	$	12,028	$	4,299	$	5,221	$	9,520

Total, Excluding Equity in Affiliates	$	3,268	$	4,634	$	7,902	$	4,934	$	5,382	$	10,316	$	3,594	$	4,697	$	8,291

FINANCIAL RATIOS

Current Ratio – current assets divided by current liabilities. Generally, two items adversely affect ChevronTexaco’s current ratio, but in the company’s opinion do not affect its liquidity. First, current assets in all years included inventories valued on a LIFO basis, which at year-end 2002 were lower than replacement costs, based on average acquisition costs during the year, by nearly $1.6 billion. Second, the company benefits from lower interest rates available on short-term debt by continually refinancing its commercial paper; however, the company’s proportionately large amount of short-term debt keeps its current ratio at relatively low levels.

Interest Coverage Ratio – income before income tax expense, plus interest and debt expense and amortization of capitalized interest, divided by before-tax interest costs. ChevronTexaco’s interest coverage ratio was lower in 2002, primarily due to lower before-tax income partially offset by lower interest expense as a result of lower interest rates.

Debt Ratio – total debt divided by total debt plus equity. This ratio was 34 percent at December 31, 2002, compared to 33.9 percent a year earlier.

Financial Ratios


	At December 31

	2002			2001			2000

Current Ratio		0.9			0.9			1.1
Interest Coverage Ratio		7.6			9.6			12.5
Total Debt/Total Debt Plus Equity		34.0	%		33.9	%		32.3	%

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

Direct or Indirect Guarantees*


Millions of dollars	Commitment Expiration by Period

					2004 –				After
	Total		2003		2006		2007		2007

Guarantees of non-consolidated affiliates or joint venture obligations	$	1,038	$	346	$	131	$	50	$	511
Guarantees of obligations of third parties		437		218		73		15		131
Guarantees of Equilon debt and leases		369		23		70		22		254

*The above amounts exclude indemnifications of contingencies associated with the sales of the company’s interests in Equilon and Motiva.

At December 31, 2002, the company and its subsidiaries provided guarantees, either directly or indirectly, of $1.038 billion for notes and other contractual obligations of affiliated companies and $806 million for third parties, as discussed by major category below. There are no amounts being carried as liabilities for the company’s obligations under these guarantees.

Of the guarantees issued in regard to affiliates’ operations, $775 million relates to borrowings for capital projects or general corporate purposes. These guarantees were undertaken to achieve lower interest rates and generally cover the construction period of the capital projects. Approximately 50 percent of the amounts guaranteed will expire within the 2003–2006 period, with the remaining guarantees expiring by the end of 2015. Under the terms of the guarantees, the company would be required to perform should an affiliate be in default of its loan terms, generally for the full amounts disclosed. There are no provisions for recourse to third parties, and no assets are held as collateral for these guarantees.

The company provides guarantees of $263 million relating to obligations in connection with pricing of power purchase agreements for certain of its cogeneration affiliates. Under the terms of these guarantees, the company may be required to make payments under certain conditions if the affiliates do not perform under the agreements. There are no provisions for recourse to third parties, and no assets are held as collateral for these pricing guarantees.

Guarantees of $437 million have been issued in regard to obligations of third parties, including approximately $100 million of construction loans to host governments in the company’s international upstream operations. The remaining guarantees of $337 million were provided principally as conditions of sale of the company’s interest in certain operations, to provide a source of liquidity to the guaranteed parties and in connection with company marketing programs. No amounts of the company’s obligations under these guarantees are recorded as liabilities. Approximately half of the total amounts guaranteed will expire in 2003, with the remainder expiring after 2007. The company would be required to perform under the terms of the guarantees should an entity be in default of its loan or contract terms, generally for the full amounts disclosed. Approximately $200 million of the guarantees have recourse provisions, which enable the company to recover any payments made under the terms of the guarantees from securities held over the guaranteed parties’ assets.

Guarantees of $369 million relate to Equilon debt and leases. In connection with the February 2002 disposition of its interest in Equilon, Shell Oil Company agreed to indemnify the company against any claims arising out of these guarantees. The company has not recorded a liability for these guarantees. Guarantees on approximately 30 percent of the debt and leases will expire within the 2003–2007 period, with the guarantees of the remaining amounts expiring by 2024.

Indemnities The company also provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell Oil Com-

FS-10

pany and Saudi Refining Inc. in connection with the February 2002 sale of the company’s interests in those investments. The indemnities cover contingent general liabilities, certain contingent environmental liabilities and liabilities associated with the Unocal patent litigation. The company would be required to perform should the contingent general liabilities become actual liabilities within 18 months of the sale and could be required to make maximum future payments of $300 million. The company has not recorded liabilities for these contingencies. There are no recourse provisions enabling recovery of any amounts from third parties nor are any assets held as collateral. Within five years of the February 2002 sale, at the buyer’s option, the company also may be required to purchase certain assets from Shell Oil Company for their net book value, as determined at the time of the company’s purchase.

The indemnities pertaining to the contingent environmental liabilities relate 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 periods of ChevronTexaco’s ownership interests in the joint ventures. In general, the environmental conditions or events that are subject to these indemnities must have arisen prior to December 12, 2001. Claims relating to Equilon must be asserted no later than February 13, 2009, and claims relating to Motiva must be asserted no later than February 13, 2012. Under the terms of the 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 amounts indemnified 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. The company holds no assets as collateral. During 2002, the company made no payments under the above indemnities.

Securitization In other off-balance-sheet arrangements, the company securitizes certain retail and trade accounts receivable in its U.S. downstream business through the use of qualifying special purpose entities (SPEs). At December 31, 2002, approximately $1 billion, representing about 11 percent of ChevronTexaco’s total current accounts receivable balance, were securitized. ChevronTexaco’s total estimated financial exposure under these arrangements at December 31, 2002, was approximately $75 million. These arrangements have the effect of accelerating Chevron-Texaco’s collection of the securitized amounts. In the event of the SPEs experiencing major defaults in the collection of receivables, ChevronTexaco believes that it would have no loss exposure connected with third-party investments in these securitization arrangements.

Long-Term Unconditional Purchase Obligations and Commitments, Throughput Agreements and Take-or-Pay Agreements. The company and its subsidiaries have entered into long-term unconditional purchase obligations and commitments, throughput agreements, and take-or-pay agreements, some of which relate to suppliers’ financing arrangements. These agreements typically provide goods and services, such as pipeline and storage capacity, utilities, and petroleum products to be used or sold in the ordinary course of the company’s business. The aggregate amounts of estimated payments that will be required over the life of the agreements is approximately $9 billion. The most significant take-or-pay agreement calls for the company to purchase approximately 55,000 barrels per day of refined products from an equity affiliate refiner in Thailand. This purchase agreement is in conjunction with the financing of a refinery owned by the affiliate, which is due in 2009. The future estimated commitments under this contract are: 2003 – $800 million; 2004 – $800 million; 2005 – $900 million; 2006 – $900 million; 2007 – $900 million; 2008 and 2009 – $1.8 billion.

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

Contractual Obligations


Millions of dollars		Payments Due by Period

						2004 –				After
		Total		2003		2006		2007		2007

On balance sheet:
	Short-term debt	$	3,786	$	3,786	$	–	$	–	$	–
	Redeemable long-term debt		787		787		–		–		–
	Current portion of long-term debt and capital leases		785		785		–		–		–
	Long-term debt^1,2		10,666		–		1,592		2,192		6,882
	Noncancelable capital lease obligations		245		–		83		21		141
	Redemption of subsidiary’s preferred shares		234		75		124		–		35
Off balance sheet:
	Noncancelable operating lease obligations		2,203		360		869		214		760
	Unconditional purchase obligations		1,373		393		603		84		293
	Throughput and take-or-pay agreements		7,481		927		3,037		1,012		2,505

¹ Includes $4.110 billion of short-term debt that the company expects to continually refinance and will not have to repay until after 2007.

² Includes guarantees of $385 million of LESOP debt, $25 million due in 2004 and $360 million due after 2007.

Minority Interests Preferred shares issued by subsidiary companies to third parties are accounted for as minority interest. MVP Production Inc., a subsidiary, has variable rate cumulative preferred shares of $75 million owned by one minority holder. The shares are voting and are redeemable in 2003. Texaco Capital LLC, a wholly owned finance subsidiary, has issued $65 million of deferred preferred shares. Dividends of $59 million, equivalent to an interest rate of 7.17 percent compounded annually, will be paid at the redemption date of February 28, 2005, unless earlier redemption occurs.

FINANCIAL AND DERIVATIVE INSTRUMENTS

Commodity Derivative Instruments ChevronTexaco is exposed to market risks related to the volatility of crude oil, refined products, natural gas and refinery feedstock prices. The company uses derivative commodity instruments to manage its exposure to price volatility on a small portion of its activity, including firm commitments and anticipated transactions for the purchase or sale of crude oil, feedstock purchases for company refineries, crude oil and refined products inventories, and fixed-price contracts to sell natural gas and natural gas liquids.

ChevronTexaco also uses derivative commodity instruments for trading purposes, and the results of this activity were not

FS-11

material to the company’s financial position, results of operations or cash flows in 2002.

The company’s positions are monitored and managed on a daily basis by an internal risk control group to ensure compliance with the company’s risk management policy that has been approved by the company’s Board of Directors.

The derivative instruments used in the company’s risk management and trading activities consist mainly of futures contracts traded on the New York Mercantile Exchange and the International Petroleum Exchange, crude oil and natural gas swap contracts, options, and other derivative products entered into principally with major financial institutions and other oil and gas companies. 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 market quotes and other independent third-party quotes.

The aggregate effect on derivative activity of a hypothetical 15 percent change in prices for natural gas, crude oil and petroleum products would not be material to the company’s financial position, net income or cash flows. The hypothetical loss on the related commodity contracts was estimated by calculating the cash value of the contracts as the difference between the hypothetical and contract delivery prices, multiplied by the contract amounts.

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

The aggregate effect on foreign currency swaps of a hypothetical adverse change of 10 percent to year-end exchange rates (a weakening of the U.S. dollar) would not be material to the company’s financial position, results of operations or cash flows.

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 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. During 2002, no new swaps were initiated in connection with debt issues in the year. At year-end 2002, the weighted average maturity of interest rate swaps was approximately 5.6 years.

A hypothetical 10 percent increase in interest rates upon the interest rate swaps would cause the fair value of the “receive fixed” swaps to decline. The aggregate effect of these changes would not be material to the company’s financial position, results of operations or cash flows.

Dynegy Preferred Stock Investment The company’s $1.5 billion investment in mandatorily redeemable convertible preferred stock of Dynegy was carried at an estimated fair value of $300 million at December 31, 2002. Because the investment is not publicly traded, an estimate of its fair value was required. This estimate was based on a comparison to the pricing of marketable Dynegy bonds and an added factor for an estimated liquidity discount. Other methodologies could have resulted in a higher or lower fair-value estimation. See also page FS-8 for further information about Dynegy.

TRANSACTIONS WITH RELATED PARTIES

ChevronTexaco enters into a number of business arrangements with related parties, principally its equity affiliates. These arrangements include long-term supply or offtake agreements. In the United States, long-term agreements have been in place with Dynegy for the purchase of substantially all natural gas and natural gas liquids produced by the company in the United States, excluding Alaska, and the supply of natural gas and natural gas liquids feedstocks to the company’s U.S. refineries and chemicals plants. In 2003, ChevronTexaco and Dynegy agreed to terminate the natural gas sale and purchase agreements at the end of January 2003. Internationally, there are long-term purchase agreements in place with the company’s refining affiliate in Thailand. See page FS-11 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

Unocal Patent Litigation Chevron, Texaco and four other oil companies (refiners) filed suit in 1995 contesting the validity of a patent (‘393’ patent) granted to Unocal Corporation (Unocal) for certain reformulated gasoline blends. ChevronTexaco sells reformulated gasolines in California in certain months of the year. In March 2000, the U.S. Court of Appeals for the Federal Circuit upheld a September 1998 District Court decision that Unocal’s patent was valid and enforceable and assessed damages of 5.75 cents per gallon for gasoline produced during the summer of 1996, which infringed on the claims of the patent. In February 2001, the U.S. Supreme Court concluded it would not review the lower court’s ruling, and the case was sent back to the District Court for an accounting of all infringing gasoline produced after August 1, 1996. The District Court has now ruled that the per-gallon damages awarded by the jury are limited to infringement that occurs in California only. Additionally, the U.S. Patent and Trademark Office (USPTO) granted two petitions by the refiners to re-examine the validity of Unocal’s ‘393’ patent and has now twice rejected all of the claims in the ‘393’ patent. The District Court judge requested further briefing and advised that she would not enter a final judgment in this case until the USPTO had completed its re-examination of the ‘393’ patent. During 2002, the USPTO also rejected the validity of another Unocal patent, the ‘126’ patent, which could affect a larger share of U.S. gasoline production. Separately, the FTC has issued an administrative complaint alleging that Unocal’s conduct in this matter represented an unfair method of competition, which may make Unocal’s patents unenforceable.

Unocal has obtained additional patents that could affect a larger share of U.S. gasoline production. ChevronTexaco believes these additional patents are invalid, unenforceable and/or not infringed. The company’s financial exposure in the event of unfavorable conclusions to the patent litigation and regulatory reviews may include royalties, plus interest, for production of gasoline that is proved to have infringed the patents. The competitive and financial effects on the company’s refining and marketing operations, while presently indeterminable, could be material. ChevronTexaco has been accruing in the normal course of business any future estimated liability for potential infringement of the ‘393’ patent covered by the 1998 trial court’s ruling. In 2000, prior to the merger, Chevron and Texaco made payments to

FS-12

Unocal totaling approximately $30 million for the original court ruling, including interest and fees.


Millions of dollars	2002			2001			2000

Balance at January 1	$	1,160		$	1,234		$	1,079
Expense Provisions		229			216			429
Expenditures		(299	)		(290	)		(274	)

Balance at December 31	$	1,090		$	1,160		$	1,234

Under provisions of the Superfund law, the Environmental Protection Agency (EPA) has designated ChevronTexaco a potentially responsible party, or has otherwise involved the company, in the remediation of 420 hazardous waste sites. The company made provisions or payments in 2002 and prior years for 293 of these sites. No single site is expected to result in a material liability for the company. For the remaining sites, investigations are not yet at a stage where the company is able to quantify a probable liability or determine a range of reasonably possible exposures. The Superfund law provides for joint and several liability for all responsible parties. Any future actions by the EPA and other regulatory agencies to require ChevronTexaco 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. Remediation reserves at year-end 2002, 2001 and 2000 for Superfund sites were $95 million, $62 million and $73 million, respectively.

Another issue involving the company is the petroleum industry’s use of methyl tertiary butyl ether (MTBE) as a gasoline additive and its potential environmental impact through seepage into groundwater. Along with other oil companies, the company is a party to lawsuits and claims related to the use of the chemical MTBE in certain oxygenated gasolines. These actions may require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE, including personal-injury claims, may be filed in the future. The company’s ultimate exposure related to these lawsuits and claims is not currently determinable, but could be material to net income in any one period. ChevronTexaco has worked to reduce the use of MTBE in gasoline it manufactures in the United States. The state of California has directed that MTBE be phased out of the manufacturing process by the end of 2003, and the company intends to comply with this mandate. By May 2003, the company plans to market branded gasoline that uses ethanol as an oxygenate instead of MTBE in southern California and will complete the changeover in northern California later in the year.

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 indeterminable 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. While the amount of future costs may be material to the company’s results of operations in the period in which they are recognized, the company does not expect these costs will have a material adverse 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 petroleum or chemicals companies.

The company maintains additional reserves for dismantlement, abandonment and restoration of its worldwide oil and gas and coal properties at the end of their productive lives. Many of these costs are related to environmental issues. Expense provisions are recognized on a unit-of-production basis. The reserves balance at year-end 2002 was $2.3 billion and is included in “Accumulated depreciation, depletion and amortization” in the company’s Consolidated Balance Sheet. Please refer to pages FS-16 to FS-17 for information relating to the company’s 2003 implementation of Financial Accounting Standards Board (FASB) Standard No. 143, “Accounting for 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.

See “Environmental Matters” on page FS-14 for additional information related to environmental matters.

Income Taxes The company estimates its income tax expense and liabilities annually. These liabilities generally are not finalized with the individual taxing authorities until several years after the end of the annual period for which income taxes have been estimated. The U.S. federal income tax liabilities have been settled through 1996 for ChevronTexaco (formerly Chevron), through 1993 for ChevronTexaco Global Energy Inc. (formerly Caltex), and through 1991 for Texaco. California franchise tax liabilities have been settled through 1991 for Chevron and through 1987 for Texaco. Settlement of open tax years, as well as tax issues in other countries where the company conducts its businesses, is not expected to have a material effect on the consolidated financial position or liquidity of the company, and in the opinion of management, adequate provision has been made for income and franchise taxes for all years under examination or subject to future examination.

Equity Redetermination For oil and gas producing operations, ownership agreements may provide for periodic reassessments of equity interests in estimated oil and 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 ChevronTexaco’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 of estimates exist for a possible net settlement amount for the four zones. ChevronTexaco currently estimates its maximum possible net before-tax liability at approximately $200 million. At the same time, a possible maximum net amount that could be owed to ChevronTexaco is

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estimated at about $50 million. The timing of the settlement and the exact amount within this range of estimates are uncertain.

Global Operations Areas in which the company and its affiliates have major operations include the United States of America, Canada, Australia, the United Kingdom, Norway, Denmark, France, Partitioned Neutral Zone between Kuwait and Saudi Arabia, Republic of Congo, Democratic Republic of Congo, Angola, Nigeria, Chad, Equatorial Guinea, Indonesia, Papua New Guinea, China, Thailand, Venezuela, Argentina, Brazil, Colombia, Trinidad and Tobago, South Korea, the Philippines, Singapore, and South Africa. The company’s TCO affiliate operates in Kazakhstan. The company’s CPChem affiliate manufactures and markets a wide range of petrochemicals and plastics on a worldwide basis, with manufacturing facilities in existence or under construction in the United States, Puerto Rico, Singapore, China, South Korea, Saudi Arabia, Qatar, Mexico and Belgium. The company’s Dynegy affiliate has operations in the United States, Canada, and the United Kingdom and other European countries.

The company’s operations, particularly exploration and production, can be affected by other changing economic, regulatory and political environments in the various countries in which it operates, including the United States. For instance, in December 2002, Caltex Oil (SA)(Pty) Limited (“Caltex Oil (SA)”) announced the signing of a shareholders agreement with a South African consortium of Black Economic Empowerment partners. The agreement is intended to ultimately provide the consortium a 25 percent equity interest in all aspects of Caltex’s operations in South Africa. It is uncertain as to whether any additional actions will be taken by host governments in other countries to increase public ownership of the company’s partially or wholly owned businesses.

In certain locations, host 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 or strained relations between a host 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.

Suspended Wells The company also suspends the costs of exploratory wells pending a final determination of the commercial potential of the related oil and gas fields. The ultimate disposition of these well costs is dependent on the results of future drilling activity and/or development decisions. If the company decides not to continue development, the costs of these wells are expensed. At December 31, 2002, the company had $450 million of suspended exploratory wells included in properties, plant and equipment, a decrease of $238 million from 2001 and $332 million from 2000.

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

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

ENVIRONMENTAL MATTERS

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

Accidental leaks and spills requiring cleanup may occur in the ordinary course of business. In addition to the costs for environmental protection associated with its ongoing operations and products, the company may incur expenses for corrective actions at various owned and previously owned facilities and at third-party-owned waste-disposal sites used by the company. An obligation may arise when operations are closed or sold or at non-ChevronTexaco 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 and/or remedial work to meet current standards. Using definitions and guidelines established by the American Petroleum Institute, ChevronTexaco estimated its worldwide environmental spending in 2002 at $1.324 billion for its consolidated companies. Included in these expenditures were $399 million of environmental capital expenditures and $925 million of costs associated with the control and abatement of hazardous substances and pollutants from ongoing operations.

For 2003, total worldwide environmental capital expenditures are estimated at $458 million. These capital costs are in addition to the ongoing costs of complying with environmental regulations and the costs to remediate previously contaminated sites.

APPLICATION OF CRITICAL ACCOUNTING POLICIES

In May 2002, the SEC issued a proposed rule: “Disclosure in Management’s Discussion and Analysis about the Application of Critical Accounting Policies.” Although the SEC had not issued a final rule by mid-March 2003, the following discussion has been prepared on the basis of the guidelines in the SEC rule proposal.

If adopted as proposed, the rule would require disclosures connected with “estimates a company makes in applying its accounting policies.” However, such discussion would be limited to “critical accounting estimates,” or those that management believes meet two criteria in the proposal: “First, the accounting estimate must require a company to make assumptions about matters that are highly uncertain at the time the accounting estimate is made. Second, different estimates that the company reasonably could have used for the accounting estimate in the current period, or changes in the accounting estimate that are reasonably likely to occur from period to period, must have a material impact on the presentation of the company’s financial condition, changes in financial condition or results of operations.”

Beside estimates that meet the “critical” estimate criteria, the company makes many other accounting estimates in preparing its financial statements and related disclosures. All estimates, whether or not deemed critical, affect reported amounts of assets, liabilities, revenues and expenses as well as disclosures of contingent assets and liabilities. Estimates are based on experience and other information available prior to the issuance of the financial statements. Materially different results can occur as circumstances

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change and additional information becomes known, including for estimates not deemed “critical” under the SEC rule proposal.

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 oil and 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” on pages FS-51 and FS-52 for the changes in these estimates for the three years ending December 31, 2002, and to Table VII “Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves” on page FS-54 for estimates of proved-reserve values for each year-end 2000–2002, which were based on year-end prices at the time.

Note 1 to the Consolidated Financial Statements includes a description of the “successful efforts” method of accounting for oil and gas exploration and production activities. The estimates of crude oil and natural gas reserves are important to the timing of expense recognition for costs incurred.

The upcoming discussion of the critical accounting policy for “Impairment of Property, Plant and Equipment and Investments in Affiliates” includes reference to conditions under which downward revisions of proved reserve quantities could result in impairments of oil and gas properties.

The 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-25. The development and selection of accounting estimates, 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 made by the company are as follows:

Pension and Other Postretirement Benefit Plans The determination of pension plan expense and the requirements for funding the company’s major pension plans are based on a number of actuarial assumptions. Two critical assumptions are the rate of return on pension 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 for qualifying retired employees and which are not funded, critical assumptions in determining OPEB expense are the discount rate applied to benefit obligations and the assumed health care cost-trend rates used in the calculation of benefit obligations.

Note 19 to the Consolidated Financial Statements on page FS-39 includes information for the three years ending December 31, 2002, on the components of pension and OPEB expense and the underlying discount rate assumptions as well as the funded status for the company’s pension plans at the end of 2002 and 2001.

To determine the estimate of long-term rate of return on pension assets, the company employs a process that incorporates actual historical asset-class returns and an assessment of expected future performance, which takes into consideration external actuarial advice. For example, at December 31, 2002, the estimated long-term rate of return on U.S. pension plan assets, which accounted for the majority of the company’s pension plan assets, was 7.8 percent, as compared with rates of 8.8 percent and 10.0 percent at the end of 2001 and 2000, respectively. The year-end market-related value of the U.S. pension plan assets used in the determination of pension expense was based on the market values in the preceding three months, as opposed to the maximum allowable period of five years under the pension accounting rules. Management considers the three-month time period long enough to minimize the effects of distortions from day-to-day market volatility and yet still be contemporaneous to the end of the year.

The discount rate used in the determination of pension benefit obligations and pension expense is based on high-quality fixed income investment interest rates. At December 31, 2002, the company calculated the U.S. pension obligations using a 6.8 percent discount rate. The discount rates used at the ends of 2001 and 2000 were 7.3 percent and 7.5 percent, respectively.

An increase in the expected return on pension plan assets or the discount rate would reduce pension plan expense and vice versa. Total pension expense for 2002 was $457 million. As an indication of interest-rate sensitivity to the determination of pension expense, a 1 percent increase in the expected return on assets of the company’s main U.S. pension plan, which accounted for a significant majority of the companywide pension obligation, would have reduced total pension plan expense for 2002 by approximately $30 million. A 1 percent increase in the discount rate for this same plan would have reduced total benefit plan expense by approximately $130 million. 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.

Based on the expected changes in pension plan asset values and pension obligations in 2003, the company does not believe any significant funding of the pension plans will be required during the year. For the U.S. plans, this determination was made in accordance with the minimum funding standard of the Employee Retirement Income Security Act (ERISA).

Pension expense is included on the Consolidated Statement of Income in “Operating expenses” or “Selling, general and administrative expenses” and applies to all business segments. Depending upon the funding status of the different plans, either a long-term prepaid asset or long-term liability is recorded for plans with overfunding or underfunding, respectively. Any unfunded accumulated benefit obligation in excess of recorded liabilities is recorded in “other comprehensive income.” See Note 19 to the Consolidated Financial Statements on page FS-40 for the pension-related balance sheet effects at the end of 2002 and 2001.

For the company’s OPEB plans, expense for 2002 was $199 million and was also recorded as “Operating expenses” or “Selling, general and administrative expenses” in all business segments. The discount rate applied to the company’s OPEB obligations at December 31, 2002, was 6.75 percent – the same discount rate used for U.S. pension obligations. The assumed health care cost-trend rates used to calculate OPEB obligations at December 31, 2002, start with a 12 percent cost increase over the previous year in 2002, gradually dropping over five years to a long-term ultimate rate-increase assumption of 4.5 percent for 2007 and thereafter. The 12 percent rate assumption for 2002 was provided by external consultants. The 4.5 percent rate-increase assumption and duration to reach that rate is a company estimate.

As an indication of discount-rate sensitivity to the determination of OPEB expense in 2002, the impact of a 1 percent increase in the discount rate for the company’s main U.S. OPEB plan, which accounted for the significant majority of the companywide OPEB obligation, would not have been significant. The sensitivity of OPEB expense to discount rate changes may vary in

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the future depending on the combination of factors that enter into the determination of OPEB expense in any one period.

Impairment of Property, Plant and Equipment and Investments in Affiliates The company assesses its property, 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 oil and gas properties significant downward revisions of estimated proved reserve quantities. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, an impairment charge is recorded for the excess of carrying value of the asset over its fair value.

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

The amount and income statement classification of major impairments of PP&E for the three years ending December 31, 2002, are included in the commentary on the business segments elsewhere in this discussion, as well as in Note 4 to the Consolidated Financial Statements on page FS-28. An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in the impairment reviews and impairment calculations is not practicable, given the broad range of the company’s PP&E and the number of assumptions involved in the estimates. That is, favorable changes to some assumptions might have avoided the need to impair any assets in these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired.

Investments in common stock of affiliates that are accounted for under the equity method, as well as investments in other securities of these equity investees, are reviewed for impairment when the fair value of the investment falls below the company’s carrying value. When such a decline is deemed to be other than temporary, an impairment charge is recorded 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.

In 2002, the company recorded impairments of its investments in Dynegy and Caltex Australia. The impairment of Dynegy is discussed in MD&A in the explanation of 2002 results for “All Other” on page FS-7, in “Information Related to Investment in Dynegy Inc.” on page FS-8, and in Notes 4 and 13 to the Consolidated Financial Statements. The impairment of Caltex Australia is discussed in the explanation of 2002 results for international downstream on page FS-6 and is included in Note 13 to the Consolidated Financial Statements.

The impairment charges taken in 2002 for Dynegy and Caltex Australia common stock investments were based on fair values determined from publicly quoted prices. The impairment charges recorded for the company’s investment in Dynegy preferred stock was based upon the company’s own estimate of the instrument’s fair value at the time, since ChevronTexaco was the sole preferred stock shareholder and the instrument was not publicly traded. In making its estimate, reference was made to, among other things, the pricing of marketable Dynegy bonds and an added factor for an estimated liquidity discount. See also page FS-12 for further information relating to the company’s investment in Dynegy preferred stock.

Different effects on company earnings would have resulted from making different assumptions related to the investments in Dynegy and Caltex Australia. While the qualitative factors considered in making the assessments as to whether declines in fair value were “other than temporary” were not subject to sensitivity analysis, different assumptions might have resulted in no impairments being recorded, a greater or lesser amount of impairment charge, and/or a difference in the timing of any impairment charges.

Contingent Losses Management also makes judgments and estimates in recording liabilities for claims, litigation, tax matters and environmental remediation. Actual costs can frequently vary from estimates for a variety of reasons. For example, the costs from settlement of claims and litigation can vary from estimates based on differing interpretations of laws, opinions on culpability and assessments on the amount of damages. Similarly, liabilities for environmental remediation are subject to change because of changes in laws, regulations and their interpretation; the determination of additional information on the extent and nature of site contamination; and improvements in technology.

Under the accounting rules, a liability is recorded for these types of contingencies if management determines the loss to be both probable and estimable. The company generally records these losses as “Operating Expenses” or “Selling, general and administrative expenses” on the Consolidated Statement of Income. Refer to the business segment discussions elsewhere in this discussion and in Note 4 to the Consolidated Financial Statements on page FS-28 for the effect on earnings from losses associated with certain litigation and environmental remediation and tax matters for the three years ended December 31, 2002.

An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in recording these liabilities is not practical 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

FS-16

Other than the cumulative-effect change, the effect of the new accounting standard on 2003 net income is not expected to be materially different from what the result would have been under FAS 19 accounting. Upon adoption, legal obligations, if any, to retire downstream and chemical, long-lived assets generally were not recognized because of indeterminate settlement dates for the asset retirement. Therefore, insufficient information exists to estimate the potential settlement dates and to apply the net-present-value techniques to estimate the fair value of the retirement obligation.

In July 2002, the FASB issued Statement No. 146, “Accounting for Costs Associated With Exit or Disposal Activities” (FAS 146). The standard requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. Examples of costs covered by the standard include lease termination costs and certain employee severance costs that are associated with a restructuring, discontinued operations, a plant closing, or other exit or disposal activity. The statement replaces EITF (Emerging Issues Task Force of the FASB) Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (Including Certain Costs Incurred in a Restructuring).” FAS 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002.

In November 2002, the FASB issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45). The disclosure provisions of FIN 45 are effective for fiscal years ending after December 15, 2002, and are included in Note 21, “Other Contingencies and Commitments,” whereas the recognition and measurement requirements are to be applied on a prospective basis to guarantees issued or modified after December 31, 2002. As these requirements relate to future events, the effect cannot be determined.

In December 2002, the FASB issued Statement No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure” (FAS 148), which amends FASB Statement No. 123, “Accounting for Stock-Based Compensation.” FAS 148 permits two additional transition methods for entities that adopt the fair-value-based method of accounting for stock-based employee compensation and amends the disclosure requirements in both annual and interim financial statements. ChevronTexaco will continue to apply Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations in accounting for stock options. The amended disclosure requirements of FAS 148 have been incorporated into Note 1 to the Consolidated Financial Statements.

In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46). FIN 46 amended ARB 51, “Consolidated Financial Statements,” and established standards for determining under what circumstances a variable interest entity (VIE) should be consolidated with its primary beneficiary. FIN 46 also requires disclosures about VIEs that the company is not required to consolidate but in which it has a significant variable interest. The consolidation requirements of FIN 46 apply immediately to VIEs created after January 31, 2003. The consolidation requirements apply to older entities in the first fiscal year or interim period beginning after June 15, 2003. Certain of the disclosure requirements apply in all financial statements issued after January 31, 2003, regardless of when the VIE was established. The company does not expect that adoption of FIN 46 will have a significant impact on its results of operations, financial position or liquidity.

FS-17

REPORT OF INDEPENDENT ACCOUNTANTS

TO THE STOCKHOLDERS AND THE BOARD OF DIRECTORS OF CHEVRONTEXACO CORPORATION:

In our opinion, based on our audits and the report of other auditors who have ceased operations, the consolidated financial statements listed in the index appearing under Item 15(a)(1) on page 29 present fairly, in all material respects, the financial position of ChevronTexaco Corporation and its subsidiaries at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. In addition, based on our audits and the report of other auditors who have ceased operations, the financial statement schedule listed in the index appearing under Item 15(a)(2) on page 29 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the company’s management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. The consolidated financial statements give retroactive effect to the merger of Texaco Inc. on October 9, 2001, in a transaction accounted for as a pooling of interests, as described in Note 2 to the consolidated financial statements. We did not audit the financial statements or financial statement schedule of Texaco Inc., which statements reflect total revenues of $51,130 million for the year ended December 31, 2000. Those statements and schedule were audited by other auditors who have ceased operations and whose report thereon has been furnished to us, and our opinion expressed herein, insofar as it relates to the amounts included for Texaco Inc., is based solely on the report of the other auditors. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.

/S/ PRICEWATERHOUSECOOPERS LLP
San Francisco, California
March 7, 2003

THE FOLLOWING REPORT IS A COPY OF A REPORT PREVIOUSLY ISSUED BY ARTHUR ANDERSEN LLP AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

TO SHAREHOLDERS, TEXACO INC.:

We have audited the consolidated balance sheet of Texaco Inc. (a Delaware corporation) and subsidiary companies as of December 31, 2000, and the related consolidated statements of income, stockholders’ equity, comprehensive income and cash flows for each of the two years in the period ended December 31, 2000. These financial statements (not presented separately herein) are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above (not presented separately herein) present fairly, in all material respects, the financial position of Texaco Inc. and subsidiary companies as of December 31, 2000, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States.

Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in Item 14 on Texaco Inc.’s 2000 Form 10-K (not presented separately herein) is the responsibility of the Company’s management and is presented for purposes of complying with the Securities and Exchange Commission’s rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.

ARTHUR ANDERSEN LLP
New York, New York
February 22, 2001

FS-18

CONSOLIDATED STATEMENT OF INCOME


				Year ended December 31

Millions of dollars, except per-share amounts					2002		2001			2000

REVENUES AND OTHER INCOME
	Sales and other operating revenues*				$	98,691	$	104,409		$	117,095
	Income from equity affiliates					111		1,144			1,077
	Other income					247		692			958

TOTAL REVENUES AND OTHER INCOME						99,049		106,245			119,130

COSTS AND OTHER DEDUCTIONS
	Purchased crude oil and products					57,249		60,549			69,814
	Operating expenses					7,848		7,650			8,323
	Selling, general and administrative expenses					4,155		3,984			3,626
	Exploration expenses					591		1,039			949
	Depreciation, depletion and amortization					5,231		7,059			5,321
	Write-down of investments in equity affiliates					1,932		–			–
	Merger-related expenses					576		1,563			–
	Interest and debt expense					565		833			1,110
	Taxes other than on income*					16,689		15,156			15,827
	Minority interests					57		121			111

TOTAL COSTS AND OTHER DEDUCTIONS						94,893		97,954			105,081

INCOME BEFORE INCOME TAX EXPENSE						4,156		8,291			14,049
INCOME TAX EXPENSE						3,024		4,360			6,322

NET INCOME BEFORE EXTRAORDINARY ITEM					$	1,132	$	3,931		$	7,727
	Extraordinary loss, net of income tax					–		(643	)		–

NET INCOME					$	1,132	$	3,288		$	7,727

PER-SHARE AMOUNTS
NET INCOME BEFORE EXTRAORDINARY ITEM			– BASIC		$	1.07	$	3.71		$	7.23
			– DILUTED		$	1.07	$	3.70		$	7.21
NET INCOME – BASIC					$	1.07	$	3.10		$	7.23
		– DILUTED			$	1.07	$	3.09		$	7.21

*Includes consumer excise taxes:					$	7,006	$	6,546		$	6,601

See accompanying Notes to Consolidated Financial Statements.

REPORT OF MANAGEMENT

TO THE STOCKHOLDERS OF CHEVRONTEXACO CORPORATION:

Management of ChevronTexaco is responsible for preparing the accompanying financial statements and for ensuring their integrity and objectivity. 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 judgments.

The company’s statements have been audited by PricewaterhouseCoopers LLP, independent accountants, selected by the Audit Committee and approved by the stockholders. Management has made available to PricewaterhouseCoopers LLP all the company’s financial records and related data, as well as the minutes of stockholders’ and directors’ meetings.

Management of the company has established and maintains a system of internal accounting controls that is designed to provide reasonable assurance that assets are safeguarded, transactions are properly recorded and executed in accordance with management’s authorization, and the books and records accurately reflect the disposition of assets. The system of internal controls includes appropriate division of responsibility. The company maintains an internal audit department that conducts an extensive program of internal audits and independently assesses the effectiveness of the internal controls.

The Audit Committee is composed of directors who are not officers or employees of the company. It meets regularly with members of management, the internal auditors and the independent accountants to discuss the adequacy of the company’s internal controls, its financial statements, and the nature, extent and results of the audit effort. Both the internal auditors and the independent accountants have free and direct access to the Audit Committee without the presence of management.


/s/ David J. O’Reilly DAVID J. O’REILLY Chairman of the Board and Chief Executive Officer		/s/ John S. Watson JOHN S. WATSON Vice President and Chief Financial Officer		/s/ Stephen J. Crowe STEPHEN J. CROWE Vice President and Comptroller

March 7, 2003

FS-19

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME


			Year ended December 31

Millions of dollars			2002			2001			2000

NET INCOME			$	1,132		$	3,288		$	7,727

Unrealized holding gain on securities
	Net (loss) gain arising during period
		Before income taxes		(149	)		3			87
		Income taxes		52			–			(30	)
	Reclassification to net income of net realized loss (gain)
		Before income taxes		217			–			(154	)
		Income taxes		(76	)		–			54

	Total			44			3			(43	)

	Net derivatives gain on hedge transactions
		Before income taxes		52			3			–
		Income taxes		(18	)		–			–

	Total			34			3			–

Minimum pension liability adjustment
		Before income taxes		(1,208	)		14			(28	)
		Income taxes		423			(5	)		9

	Total			(785	)		9			(19	)

Currency translation adjustment
	Unrealized net change arising during period			15			(11	)		(14	)

OTHER COMPREHENSIVE (LOSS) GAIN, NET OF TAX				(692	)		4			(76	)

COMPREHENSIVE INCOME			$	440		$	3,292		$	7,651

See accompanying Notes to Consolidated Financial Statements.

FS-20

CONSOLIDATED BALANCE SHEET


			At December 31

Millions of dollars, except per-share amounts			2002			2001

ASSETS
	Cash and cash equivalents		$	2,957		$	2,117
	Marketable securities			824			1,033
	Accounts and notes receivable (less allowance: 2002 – $181; 2001 – $152)			9,385			8,279
	Inventories:
		Crude oil and petroleum products		2,019			2,207
		Chemicals		193			209
		Materials, supplies and other		551			532

				2,763			2,948
	Prepaid expenses and other current assets			1,847			1,769
	Assets held for sale – merger related			–			2,181

	TOTAL CURRENT ASSETS			17,776			18,327
	Long-term receivables, net			1,338			1,225
	Investments and advances			11,097			12,252
	Properties, plant and equipment, at cost			105,231			99,860
	Less: Accumulated depreciation, depletion and amortization			61,076			56,978

				44,155			42,882
	Deferred charges and other assets			2,993			2,886

	TOTAL ASSETS		$	77,359		$	77,572

LIABILITIES AND STOCKHOLDERS’ EQUITY
	Short-term debt		$	5,358		$	8,429
	Accounts payable			8,455			6,427
	Accrued liabilities			3,364			3,399
	Federal and other taxes on income			1,626			1,398
	Other taxes payable			1,073			1,001

	TOTAL CURRENT LIABILITIES			19,876			20,654
	Long-term debt			10,666			8,704
	Capital lease obligations			245			285
	Deferred credits and other noncurrent obligations			4,474			4,394
	Noncurrent deferred income taxes			5,619			6,132
	Reserves for employee benefit plans			4,572			3,162
	Minority interests			303			283

	TOTAL LIABILITIES			45,755			43,614

	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; 1,137,021,057 shares issued)			853			853
	Capital in excess of par value			4,833			4,811
	Retained earnings			30,942			32,767
	Accumulated other comprehensive loss			(998	)		(306	)
	Deferred compensation and benefit plan trust			(652	)		(752	)
	Treasury stock, at cost (2002 – 68,884,416 shares; 2001 – 69,800,315 shares)			(3,374	)		(3,415	)

	TOTAL STOCKHOLDERS’ EQUITY			31,604			33,958

	TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	77,359		$	77,572

See accompanying Notes to Consolidated Financial Statements.

FS-21

CONSOLIDATED STATEMENT OF CASH FLOWS


			Year ended December 31

Millions of dollars			2002			2001			2000

OPERATING ACTIVITIES
	Net income		$	1,132		$	3,288		$	7,727
	Adjustments
		Write-down of investments in equity affiliates, before tax		1,932			–			–
		Depreciation, depletion and amortization		5,231			7,059			5,321
		Dry hole expense		288			646			462
		Distributions more than (less than) income from equity affiliates		374			(489	)		(26	)
		Net before-tax gains on asset retirements and sales		(33	)		(116	)		(371	)
		Net foreign currency loss (gain)		5			(122	)		(130	)
		Deferred income tax (credits) charges		(81	)		(768	)		521
		Extraordinary before-tax loss on merger-related asset dispositions		–			787			–
		Net decrease in operating working capital		1,125			643			91
		Minority interest in net income		57			121			111
		Other, net		(89	)		408			(239	)

NET CASH PROVIDED BY OPERATING ACTIVITIES				9,941			11,457			13,467

INVESTING ACTIVITIES
	Capital expenditures			(7,597	)		(9,713	)		(7,629	)
	Proceeds from asset sales			2,341			298			1,229
	Net sales (purchases) of marketable securities			209			(183	)		80
	Net sales (purchases) of other short-term investments			–			56			(84	)
	Distribution from Chevron Phillips Chemical Company LLC			–			–			835
	Other, net			–			–			(73	)

NET CASH USED FOR INVESTING ACTIVITIES				(5,047	)		(9,542	)	$	(5,642	)

FINANCING ACTIVITIES
	Net (repayments) borrowings of short-term obligations			(1,810	)		3,830			(3,254	)
	Proceeds from issuances of long-term debt			2,045			412			1,293
	Repayments of long-term debt and other financing obligations			(1,356	)		(2,856	)		(1,241	)
	Redemption of Market Auction Preferred Shares			–			(300	)		–
	Redemption of subsidiary preferred stock			–			(463	)		–
	Issuance of preferred stock by subsidiaries			–			12			–
	Dividends paid
		Common stock		(2,965	)		(2,733	)		(2,664	)
		Preferred stock		–			(6	)		(15	)
	Dividends paid to minority interests			(26	)		(119	)		(110	)
	Net sales (purchases) of treasury shares			43			128			(1,498	)

NET CASH USED FOR FINANCING ACTIVITIES				(4,069	)		(2,095	)		(7,489	)

EFFECT OF FOREIGN CURRENCY EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS				15			(31	)		(5	)

NET CHANGE IN CASH AND CASH EQUIVALENTS				840			(211	)		331
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR				2,117			2,328			1,997

CASH AND CASH EQUIVALENTS AT YEAR–END			$	2,957		$	2,117		$	2,328

See accompanying Notes to Consolidated Financial Statements.

FS-22

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY


				2002					2001						2000

Shares in thousands; amounts in millions of dollars				Shares		Amount			Shares			Amount			Shares		Amount

PREFERRED STOCK					–	$	–			–		$	–			–	$	–

MARKET AUCTION PREFERRED SHARES
	Balance at January 1				–		–			1		$	300			1	$	300
	Redemptions				–		–			(1	)		(300	)		–		–

	BALANCE AT DECEMBER 31				–	$	–			–		$	–			1	$	300

COMMON STOCK
	Balance at January 1				1,137,021	$	853			1,149,521		$	862			1,149,521	$	1,724
	Retirement of Texaco treasury stock				–		–			(12,500	)		(9	)		–		–
	Change in par value				–		–			–			–			–		(862	)

	BALANCE AT DECEMBER 31				1,137,021	$	853			1,137,021		$	853			1,149,521	$	862

CAPITAL IN EXCESS OF PAR
	Balance at January 1					$	4,811					$	5,505				$	4,621
	Retirement of Texaco treasury stock						–						(739	)				–
	Change in common stock par value						–						–					862
	Treasury stock transactions						22						45					22

	BALANCE AT DECEMBER 31					$	4,833					$	4,811				$	5,505

RETAINED EARNINGS
Balance at January 1						$	32,767					$	32,206				$	27,148
	Net income						1,132						3,288					7,727
	Cash dividends
		Common stock					(2,965	)					(2,733	)				(2,664	)
		Preferred stock
			Market Auction Preferred Shares				–						(6	)				(17	)
	Tax benefit from dividends paid on unallocated ESOP shares and other						8						12					12

	BALANCE AT DECEMBER 31					$	30,942					$	32,767				$	32,206

See accompanying Notes to Consolidated Financial Statements.

FS-23

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY – Continued


				2002						2001						2000

Shares in thousands; amounts in millions of dollars				Shares			Amount			Shares			Amount			Shares			Amount

ACCUMULATED OTHER COMPREHENSIVE LOSS
	Currency translation adjustment
		Balance at January 1					$	(223	)				$	(212	)				$	(198	)
		Change during year						15						(11	)					(14	)

		Balance at December 31					$	(208	)				$	(223	)				$	(212	)
	Minimum pension liability adjustment
		Balance at January 1					$	(91	)				$	(100	)				$	(81	)
		Change during year						(785	)					9						(19	)

		Balance at December 31					$	(876	)				$	(91)					$	(100	)
	Unrealized net holding gain on securities
		Balance at January 1					$	5					$	2					$	45
		Change during year						44						3						(43	)

		Balance at December 31					$	49					$	5					$	2
	Net derivatives gain on hedge transactions
		Balance at January 1					$	3					$	–					$	–
		Change during year						34						3						–

		Balance at December 31					$	37					$	3					$	–

	BALANCE AT DECEMBER 31						$	(998	)				$	(306	)				$	(310	)

DEFERRED COMPENSATION AND BENEFIT PLAN TRUST
	DEFERRED COMPENSATION
		Balance at January 1					$	(512	)				$	(681	)				$	(712	)
		Net reduction of ESOP debt and other						100						106						35
		Restricted stock
			Awards					–						(35	)					(30	)
			Amortization and other					–						12						26
			Vesting upon merger					–						86						–

		BALANCE AT DECEMBER 31						(412	)					(512	)					(681	)
	BENEFIT PLAN TRUST (COMMON STOCK)				7,084			(240	)		7,084			(240	)		7,084			(240	)

	BALANCE AT DECEMBER 31				7,084		$	(652	)		7,084		$	(752	)		7,084		$	(921	)

TREASURY STOCK AT COST
	Balance at January 1				69,800		$	(3,415	)		84,835		$	(4,273	)		67,282		$	(2,816	)
	Purchases				38			(3	)		141			(9	)		19,517			(1,580	)
	Retirement of Texaco treasury stock				–			–			(12,500	)		748			–			–
	Other – mainly employee benefit plans				(954	)		44			(2,676	)		119			(1,964	)		123

BALANCE AT DECEMBER 31					68,884		$	(3,374	)		69,800		$	(3,415	)		84,835		$	(4,273	)

TOTAL STOCKHOLDERS’ EQUITY AT DECEMBER 31							$	31,604					$	33,958					$	33,369

See accompanying Notes to Consolidated Financial Statements.

FS-24

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Millions of dollars, except per-share amounts

NOTE 1.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation – Merger of Chevron and Texaco On October 9, 2001, Texaco Inc. (Texaco) became a wholly owned subsidiary of Chevron Corporation (Chevron) pursuant to a merger transaction, and Chevron changed its name to ChevronTexaco Corporation (ChevronTexaco). The combination was accounted for as a pooling of interests.

These Consolidated Financial Statements give retroactive effect to the merger, with all periods presented as if Chevron and Texaco had always been combined. Certain reclassifications have been made to conform the separate presentations of Chevron and Texaco. The reclassifications had no impact on the amount of net income or stockholders’ equity.

The Consolidated Financial Statements include the accounts of all majority-owned, controlled subsidiaries after the elimination of significant intercompany accounts and transactions. Included in the consolidation are the accounts of the Caltex Group of Companies (Caltex), a joint venture owned 50 percent each by Chevron and Texaco prior to the merger and accounted for under the equity method by both companies.

General ChevronTexaco manages its investments in and provides administrative, financial and management support to U.S. and foreign subsidiaries and affiliates that engage in fully integrated petroleum operations, chemicals operations and coal mining activities. In addition, ChevronTexaco holds investments in power generation and gasification businesses. Collectively, these companies operate in approximately 180 countries. Petroleum operations consist of exploring for, developing and producing crude oil and natural gas; refining crude oil into finished petroleum products; marketing crude oil, natural gas and the many products derived from petroleum; and transporting crude oil, natural gas and petroleum products by pipelines, marine vessels, motor equipment and rail car. Chemicals operations include the manufacture and marketing of commodity petrochemicals, plastics for industrial uses, and fuel and lube oil additives.

In preparing its Consolidated Financial Statements, the company follows accounting principles generally accepted in the United States of America. This requires 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. While 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 it 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. 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 there are indications 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 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 the common stock of 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.”

For other than goodwill, differences between the company’s carrying value of an equity investment and its underlying equity in the net assets of the affiliate are amortized to income generally over the estimated economic life of the underlying net assets. Differences attributable to goodwill are subject to assessment for impairment.

Derivatives The majority of the company’s activity in commodity derivative instruments is intended to manage the price 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 and their limited use, the company has elected not to apply hedge accounting, and changes in the fair value of those contracts are reflected in current income. For the company’s 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.

Short-Term Investments All short-term investments are classified as available for sale and are in highly liquid debt or equity securities. Those investments that are part of the company’s cash management portfolio with original maturities of three months or less are reported as “Cash equivalents.” The balance of the short-term investments is reported as “Marketable securities.” Short-term investments are marked-to-market with any unrealized gains or losses included in “Other comprehensive income.”

FS-25

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – Continued

Inventories Crude oil, petroleum products and chemicals are generally stated at cost, using a Last-In, First-Out (LIFO) method. In the aggregate, these costs are below market. “Materials, supplies and other” inventories generally are stated at average cost.

Properties, Plant and Equipment The successful efforts method is used for oil and gas exploration and production activities. All costs for development wells, related plant and equipment, and proved mineral interests in oil and gas properties are capitalized. Costs of exploratory wells are capitalized pending determination of whether the wells found proved reserves. Costs of wells that are assigned proved reserves remain capitalized. Costs also are capitalized for wells that find commercially producible reserves that cannot be classified as proved, pending one or more of the following: (1) decisions on additional major capital expenditures, (2) the results of additional exploratory wells that are under way or firmly planned, and (3) securing final regulatory approvals for development. Otherwise, well costs are expensed if a determination as to whether proved reserves were found cannot be made within one year following completion of drilling. All other exploratory wells and costs are expensed.

Long-lived assets, including proved oil and gas properties, are assessed for possible impairment by comparing their carrying values with the 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, and significant change in the extent or manner of use or physical change in an asset. Impaired assets are written down to their estimated fair values, generally their discounted future net before-tax cash flows. For proved oil and 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 or field basis, as appropriate. Impairment amounts are recorded as incremental “Depreciation, depletion and amortization” expense.

Depreciation and depletion (including provisions for future abandonment and restoration costs) of all capitalized costs of proved oil and 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 coal are determined using the unit-of-production method as the proved reserves are produced. The capitalized costs of all other plant and equipment are depreciated or amortized over their estimated useful lives. In general, the declining-balance method is used to depreciate plant and equipment in the United States; the straight-line method generally is used to depreciate international plant and equipment and to amortize all capitalized leased assets.

Gains or losses are not recognized for normal retirements of properties, plant and equipment subject to composite group amortization or depreciation. Gains or losses from abnormal retirements are recorded as expenses and from sales as “Other income.”

Expenditures for maintenance, repairs and minor renewals to maintain facilities in operating condition are generally expensed as incurred. Major replacements and renewals are capitalized.

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 and/or cleanups are probable and the costs can be reasonably estimated. Other than for assessments, the timing and magnitude of these accruals are generally based on the company’s commitment to a formal plan of action, such as an approved remediation plan or the sale or disposal of an asset. For the company’s U.S. and Canadian marketing facilities, the accrual is based on the probability that a future remediation commitment will be required. For oil, gas and coal producing properties, a provision is made through depreciation expense for anticipated abandonment and restoration costs at the end of a property’s useful life. See also Note 18 related to Financial Accounting Standards Board Statement No. 143, “Accounting for Asset Retirement Obligations,” which became effective for ChevronTexaco on January 1, 2003.

For Superfund sites, the company records a liability for its share of costs when it has been named as a potentially responsible party (PRP) and when an assessment or cleanup plan has been developed. This liability includes the company’s own portion of the costs and also the company’s portion of amounts for other PRPs when it is probable that they will not be able to pay their share of the cleanup obligation.

The company records the gross amount of its liability based on its best estimate of future costs using currently available technology and applying current regulations as well as 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 or 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 ChevronTexaco has an interest with other producers are generally recognized on the basis of the company’s net working interest (entitlement method).

Stock Compensation At December 31, 2002, the company had stock-based employee compensation plans, which are described more fully in Note 20. The company accounts for those plans under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. The following table illustrates the effect on net income and earnings per share if

FS-26

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – Continued

the company had applied the fair value-recognition provisions of Financial Accounting Standards Board (FASB) Statement No. 123, “Accounting for Stock-Based Compensation,” to stock-based employee compensation:


		Year ended December 31

		2002			2001			2000

Net income, as reported		$	1,132		$	3,288		$	7,727
Add: Stock-based employee compensation expense included in reported net income determined under APB No. 25, net of related tax effects			(1	)		68			(1	)
Deduct: Total stock-based employee compensation expense determined under fair-value-based method for all awards, net of related tax effects			(48	)		(154	)		(39	)

Pro forma net income		$	1,083		$	3,202		$	7,687

Earnings per share:
	Basic – as reported	$	1.07		$	3.10		$	7.23
	Basic – pro forma	$	1.02		$	3.02		$	7.19
	Diluted – as reported	$	1.07		$	3.09		$	7.21
	Diluted – pro forma	$	1.02		$	3.01		$	7.18

NOTE 2.

TEXACO MERGER TRANSACTION AND EXTRAORDINARY ITEM

The following table presents summarized financial data for the combined company for periods prior to the merger.


		Nine months ended			Year ended
		September 30			December 31

Millions of dollars		2001			2000

Revenues and other income
	Chevron	$	37,213		$	52,129
	Texaco¹		39,469			53,520
	Adjustments/eliminations²		8,103			13,481

ChevronTexaco		$	84,785		$	119,130

Net income
	Chevron	$	4,092		$	5,185
	Texaco¹		2,214			2,542

	Net income, before extraordinary item	$	6,306		$	7,727
	Extraordinary loss net of income tax³		(496	)		–

ChevronTexaco		$	5,810		$	7,727

¹ Includes certain reclassification adjustments to conform to historical Chevron presentation.

² Consolidation of former equity operations and intercompany eliminations.

³ Loss associated with the sales of the company’s interests in Equilon and Motiva.

At the time of the merger, each share of Texaco common stock was converted, on a tax-free basis, into the right to receive 0.77 shares of ChevronTexaco common stock. Approximately 425 million additional shares of common stock were issued, representing about 40 percent of the outstanding ChevronTexaco common stock after the merger.

As a condition of approving the merger, the U.S. Federal Trade Commission (FTC) required the divestment of certain Texaco assets: Texaco’s investments in its U.S. refining, marketing and transportation affiliates, Equilon Enterprises LLC (Equilon) and Motiva Enterprises LLC (Motiva), as well as other interests in U.S. natural gas processing and transportation facilities and general aviation fuel marketing.

At the time of the merger, Texaco placed its interests in Equilon and Motiva in trust, as required by the FTC. Because the company no longer exercised significant influence over these investments, the associated accounting method was changed from equity to cost basis.

Net income for 2001 included a loss of $643, net of a tax benefit of $144 ($0.61 per common share – diluted), related to the disposition of assets that were required as a condition of the FTC approval of the merger and other assets that were made duplicative by the merger. The after-tax loss on these dispositions was reported as an extraordinary item in accordance with pooling-of-interests accounting requirements.

Included in the total after-tax loss was a loss of $564 connected with the sale of interests in Equilon and Motiva. Proceeds from the sale, which closed in February 2002, were approximately $2,200.

For both assets that were being sold by order of the FTC and other assets that were being disposed of because they were made duplicative by the merger, the total net book value at year-end 2001 was $2,181. This amount was included in “Current assets” on the Consolidated Balance Sheet at December 31, 2001, as “Assets held for sale – merger related.” Net income for 2001 associated with all such assets sold as a result of the merger was approximately $375. The corresponding amount in 2002 was not significant.

NOTE 3.

EMPLOYEE TERMINATION BENEFITS AND OTHER RESTRUCTURING COSTS

In connection with the merger, the company incurred significant incremental expenses, which included: employee severance payments; incremental pension and medical plan benefits associated with workforce reductions; legal, accounting, SEC filing and investment banker fees; employee and office relocations; and the elimination of redundant facilities and operations. In 2002, before-tax merger-related expenses were $576 ($386 after tax). In 2001, such expenses were $1,563 ($1,136 after tax). Included in these amounts were accruals of $891 and $60 in 2001 and 2002, respectively, for severance-related benefits for approximately 4,500 employees and other merger-related expenses that will not benefit future operations.

Activity for this merger-related accrual balance is summarized in the table below:


Millions of dollars	Amount

Additions – 2001	$	891
Payments – 2001		(105	)

Balance at December 31, 2001		786
Additions – 2002		60
Payments – 2002		(470	)

Balance at December 31, 2002	$	376

Of the 4,500 employees, approximately 450 remained on the payroll at December 31, 2002. About 130 of the remaining employees are expected to terminate their employment in the first quarter 2003. The year-end 2002 accrual balance is not expected to be extinguished for approximately two years, reflecting a severance payment deferral option exercised by certain employees. The company does not expect to incur significant amounts for merger-related expenses in 2003.

FS-27

NOTE 4.

SPECIAL ITEMS AND OTHER FINANCIAL INFORMATION

Net income for each period presented includes amounts categorized by the company as “special items,” which management separately identifies to assist in the identification and explanation of the trend of results.

Listed in the following table are categories of these items and their net increase (decrease) to net income, after related tax effects.


				Year ended December 31

				2002			2001			2000

Special Items
Asset write-offs and revaluations
	Exploration and production
		Impairments – U.S.		$	(183	)	$	(1,168	)	$	(176	)
			– International		(100	)		(247	)		–
	Refining, marketing and transportation
		Impairments – U.S.			(66	)		–			–
			– International		(136	)		(46	)		(112	)
	Chemicals
		Manufacturing facility impairment – U.S.			–			(32	)		(90	)
		Other asset write-offs			–			(64	)		–
	All other
		Mining asset write-off			–			(152	)		–
		Equity share of Dynegy’s write-offs and revaluations			(531	)		–			–
		Other Dynegy-related			(1,626	)		–			77

					(2,642	)		(1,709	)		(301	)

Asset dispositions, net
	Pipeline interests – Dynegy				(149	)		–			–
	Oil and gas assets – U.S.				–			49			(107	)
	Oil and gas assets – International				–			–			80
	Real estate and other				–			–			99

					(149	)		49			72

Prior-year tax adjustments					60			(5	)		107

Environmental remediation provisions, net					(160	)		(78	)		(264	)

Merger-related expenses					(386	)		(1,136	)		–
Extraordinary loss on merger-related asset sales					–			(643	)		–

Other, net
	Litigation and regulatory issues				(57	)		–			(62	)
	Tax benefits on asset sales				–			–			70

					(57	)		–			8

Total Special Items				$	(3,334	)	$	(3,522	)	$	(378	)

In 2002, the company recorded write-downs of $1,626 of its investment in Dynegy common and preferred stock and $136 of its investment in its publicly traded Caltex Australia affiliate to their respective estimated fair values. The write-downs were required because the declines in the fair values of the investments below their carrying values were deemed to be other than temporary. Refer to Note 13 for additional information on the company’s investment in Dynegy and Caltex Australia.

Also in 2002, impairments of $183 were recorded for various U.S. exploration and production properties and $100 for international projects, reflecting lower expected recovery of proved oil reserves. Impairments in 2001 included $1,022 for the Midway Sunset Field in California – the result of a write-down in proved oil reserve quantities – upon determination of a lower-than-projected oil recovery from the field’s steam injection process. A $247 impairment of the LL-652 Field in Venezuela was also recorded in 2001 – as slower-than-expected reservoir repressurization resulted in a reduction in the projected volumes of oil recoverable during the company’s remaining contract period of operation. Asset impairments included in “Asset write-offs and revaluations” were for assets held for use.

The aggregate effects on income statement categories from special items are reflected in the following table, including ChevronTexaco’s proportionate share of special items related to equity affiliates.


	Year ended December 31

	2002			2001			2000

Revenues and other income
Income from equity affiliates	$	(693	)	$	(123	)	$	(141	)
Other income		–			84			356

Total revenues and other income		(693	)		(39	)		215

Costs and other deductions
Operating expenses		259			25			394
Selling, general and administrative expenses		180			139			94
Depreciation, depletion and amortization		298			2,294			561
Merger-related expenses		576			1,563			–
Taxes other than on income		–			12			–
Write-down of investments in equity affiliates		1,932			–			–
Interest and debt expense		–			–			4
Minority interest		–			–			(9	)

Total costs and other deductions		3,245			4,033			1,044

Income before income tax expense		(3,938	)		(4,072	)		(829	)
Income tax expense		(604	)		(1,193	)		(451	)

Net income before extraordinary item	$	(3,334	)	$	(2,879	)	$	(378	)
Extraordinary loss, net of income tax		–			(643	)		–

Net income	$	(3,334	)	$	(3,522	)	$	(378	)

Other financial information is as follows:


	Year ended December 31

	2002			2001		2000

Total financing interest and debt costs	$	632		$	955	$	1,218
Less: Capitalized interest		67			122		108

Interest and debt expense	$	565		$	833	$	1,110

Research and development expenses	$	221		$	209	$	211
Foreign currency (losses) gains*	$	(43	)	$	191	$	182

*Includes $(66), $12 and $66 in 2002, 2001 and 2000, respectively, for the company’s share of equity affiliates’ foreign currency (losses) gains.

The excess of market value over the carrying value of inventories for which the LIFO method is used was $1,578, $1,580 and $2,339 at December 31, 2002, 2001 and 2000, respectively. Market value is generally based on average acquisition costs for the year.

FS-28

NOTE 5.

INFORMATION RELATING TO THE CONSOLIDATED STATEMENT OF CASH FLOWS

“Net decrease in operating working capital” is composed of the following:


	Year ended December 31

	2002			2001			2000

(Increase) decrease in accounts and notes receivable	$	(1,135	)	$	2,472		$	(2,162	)
Decrease (increase) in inventories		185			(294	)		120
Decrease (increase) in prepaid expenses and other current assets		92			(211	)		73
Increase (decrease) in accounts payable and accrued liabilities		1,845			(742	)		1,327
Increase (decrease) in income and other taxes payable		138			(582	)		733

Net decrease in operating working capital	$	1,125		$	643		$	91

Net cash provided by operating activities includes the following cash payments for interest and income taxes:
Interest paid on debt (net of capitalized interest)	$	533		$	873		$	1,095
Income taxes paid	$	2,916		$	5,465		$	4,883

Net (purchases) sales of marketable securities consists of the following gross amounts:
Marketable securities purchased	$	(5,789	)	$	(2,848	)	$	(6,671	)
Marketable securities sold		5,998			2,665			6,751

Net sales (purchases) of marketable securities	$	209		$	(183	)	$	80

The major components of “Capital expenditures” and the reconciliation of this amount to the capital and exploratory expenditures, excluding equity in affiliates, presented in the Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) are detailed in the following table.


	Year ended December 31

	2002			2001			2000

Additions to properties, plant and equipment¹	$	6,262		$	6,445		$	6,173
Additions to investments		1,138			2,902	²		1,118
Current-year dry-hole expenditures		252			418			402
Payments for other liabilities and assets, net		(55	)		(52	)		(64	)

Capital expenditures		7,597			9,713			7,629
Expensed exploration expenditures		303			393			487
Payments of long-term debt and other financing obligations, net		2			210	³		175

Capital and exploratory expenditures, excluding equity affiliates		7,902			10,316			8,291
Equity in affiliates’ expenditures		1,353			1,712			1,229

Capital and exploratory expenditures, including equity affiliates	$	9,255		$	12,028		$	9,520

¹ Net of noncash items of $195 in 2002 and $63 in 2001.

² Includes $1,500 for investment in Dynegy preferred stock.

³ Represents a deferred payment related to 1993 acquisition of an interest in the Tengizchevroil joint venture.

In 2000, Chevron contributed $2,800 of net noncash assets to Chevron Phillips Chemical Company LLC (CPChem). The investment is accounted for under the equity method.

NOTE 6.

SUMMARIZED FINANCIAL DATA – CHEVRON U.S.A. INC.

Chevron U.S.A. Inc. (CUSA) is a major subsidiary of ChevronTexaco Corporation. CUSA and its subsidiaries manage and operate most of ChevronTexaco’s U.S. businesses and assets related to the exploration and production of crude oil, natural gas and natural gas liquids and also those associated with refining, marketing, supply and distribution of products derived from petroleum, other than natural gas liquids, excluding most of the pipeline operations of ChevronTexaco. CUSA also holds divisions overseeing or operating global businesses such as aviation fuel, lubricants, shipping and trading, and divisions providing administrative, technical and other services to affiliated companies. CUSA holds ChevronTexaco’s investment in the CPChem joint venture and Dynegy, which are accounted for using the equity method.

In 2002, ChevronTexaco implemented a legal reorganization in which certain ChevronTexaco subsidiaries transferred assets to or under CUSA and other ChevronTexaco companies were merged with and into CUSA. The summarized financial information for CUSA and its consolidated subsidiaries presented in the table below gives retroactive effect to the reorganization in a manner similar to a pooling of interests, with all periods presented as if the companies had always been combined and the reorganization had occurred on January 1, 2000. However, the financial information included below may not reflect the financial position and operating results in the future or the historical results in the periods presented had the reorganization actually occurred on January 1, 2000.


	Year ended December 31

	2002			2001		2000

Sales and other operating revenues	$	66,899		$	57,318	$	62,559
Total costs and other deductions		68,583			56,117		57,952
Net (loss) income		(1,897	)		1,265		3,702


	At December 31

	2002		2001

Current assets	$	12,852	$	10,584
Other assets		24,554		25,433
Current liabilities		19,164		11,370
Other liabilities		12,976		14,935
Net equity		5,266		9,712

Memo: Total debt	$	8,137	$	9,768

CUSA’s net loss of $1,897 for 2002 included net charges of $2,555 for asset write-downs and dispositions, of which $2,306 was related to Dynegy.

NOTE 7.

SUMMARIZED FINANCIAL DATA – CHEVRON TRANSPORT CORPORATION LTD.

Chevron Transport Corporation Ltd. (CTC), incorporated in Bermuda, is an indirect, wholly owned subsidiary of ChevronTexaco Corporation. CTC is the principal operator of ChevronTexaco’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 ChevronTexaco companies. ChevronTexaco Corporation has guaranteed this subsidiary’s obligations in con-

FS-29

NOTE 7. SUMMARIZED FINANCIAL DATA – CHEVRON TRANSPORT CORPORATION LTD. – Continued

nection with certain debt securities issued by a third party. Summarized financial information for CTC and its consolidated subsidiaries is presented as follows:


	Year ended December 31

	2002			2001		2000

Sales and other operating revenues	$	850		$	859	$	728
Total costs and other deductions		922			793		777
Net (loss) income		(79	)		67		(47	)


	At December 31

	2002		2001

Current assets	$	273	$	196
Other assets		464		527
Current liabilities		334		280
Other liabilities		344		311
Net equity		59		132

During 2002, CTC’s paid-in capital increased by $6 from additional capital contributions and settlements.

There were no restrictions on CTC’s ability to pay dividends or make loans or advances at December 31, 2002.

NOTE 8.

STOCKHOLDERS’ EQUITY

Retained earnings at December 31, 2002 and 2001, included approximately $1,559 and $ 2,015, respectively, for the company’s share of undistributed earnings of equity affiliates.

Upon the merger of Chevron and Texaco, the authorized common stock of ChevronTexaco was increased from 2 billion shares of $0.75 par value to 4 billion shares of $0.75 par value. Under the terms of the merger agreement, approximately 425 million shares of ChevronTexaco common stock were issued in exchange for all of the outstanding shares of Texaco common stock based upon an exchange ratio of 0.77 of a ChevronTexaco share for each Texaco share. Texaco’s common stock held in treasury was canceled at the effective time of the merger.

In 1998, in connection with the renewal of Chevron’s Stockholder Rights Plan, Chevron declared a dividend distribution on each outstanding share of its common stock of one Right to purchase participating preferred stock. Since this distribution in 1998, all newly issued shares of the corporation’s common stock have been accompanied by a preferred stock purchase Right, including the shares issued in connection with the merger between Chevron and Texaco. Following the merger, the Chevron Stockholder Rights Plan has continued as the Stockholder Rights Plan of ChevronTexaco. The Rights issued under the plan become exercisable, unless redeemed earlier by ChevronTexaco, if a person or group acquires or obtains the right to acquire 10 percent or more of the outstanding shares of common stock or commences a tender or exchange offer that would result in that person or group acquiring 10 percent or more of the outstanding shares of common stock, either event occurring without the prior consent of ChevronTexaco. The ChevronTexaco Series A Participating Preferred Stock that the holder of a Right is entitled to receive and the purchase price payable upon exercise of the ChevronTexaco Right are both subject to adjustment. The person or group who acquired 10 percent or more of the outstanding shares of common stock without the prior consent of ChevronTexaco would not be entitled to this purchase.

In November 2002, the Stockholder Rights agreement was amended so that the Rights will expire in November 2003, five years earlier than the initial expiration date in November 2008.

The Rights may be redeemed by the company at 1 cent per Right prior to the expiration date. The Rights do not have voting or dividend rights and until they become exercisable have no dilutive effect on the earnings per share of the company. Five million shares of the company’s preferred stock were designated Series A Participating Preferred Stock and reserved for issuance upon exercise of the Rights. No event during 2002 made the Rights exercisable.

Until June 2001, there were 1,200 shares of Texaco cumulative variable rate preferred stock, called Market Auction Preferred Shares (MAPS), outstanding, with an aggregate value of $300. The MAPS were redeemed in June 2001, at a liquidation preference of $250,000 per share, plus premium and accrued and unpaid dividends.

At December 31, 2002, 30 million shares of ChevronTexaco’s authorized but unissued common stock were reserved for issuance under the ChevronTexaco Corporation Long-Term Incentive Plan (LTIP), which was approved by the stockholders in 1990. To date, all of the plan’s common stock requirements have been met from the company’s treasury stock, and there have been no issuances of reserved shares.

NOTE 9.

FINANCIAL AND DERIVATIVE INSTRUMENTS

Commodity Derivative Instruments ChevronTexaco is exposed to market risks related to price volatility of crude oil, refined products, natural gas and refinery feedstock.

The company uses derivative commodity instruments to manage this exposure on a small portion of its activity, including: firm commitments and anticipated transactions for the purchase or sale of crude oil; feedstock purchases for company refineries; crude oil and refined products inventories; and fixed price contracts to sell natural gas and natural gas liquids.

The company also uses derivative commodity instruments for limited trading purposes.

The company maintains a policy of requiring that an International Swaps and Derivatives Association Agreement govern derivative contracts with certain counterparties to mitigate credit risk. Depending on the nature of the derivative transaction, bilateral collateral arrangements may also be required. When the company is engaged in more than one outstanding derivative transaction with the same counterparty and also has a legally enforceable netting agreement with that counterparty, the “net” mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of the company’s credit risk. It is the company’s policy to use other netting agreements with certain counterparties with which it conducts significant transactions.

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.” These activities are reported under “Operating activities” in the Consolidated Statement of Cash Flows.

FS-30

NOTE 9. FINANCIAL AND DERIVATIVE INSTRUMENTS – Continued

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 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.” These activities are reported under “Operating activities” in the Consolidated Statement of Cash Flows.

Interest Rates The company enters into interest rate swaps as part of its overall strategy to manage the interest rate risk on its debt. Under the terms of the swaps, net cash settlements are based on the difference between fixed-rate and floating-rate interest amounts calculated by reference to agreed notional principal amounts. Interest rate swaps related to a portion of the company’s fixed-rate debt are accounted for as fair value hedges, whereas interest rate swaps related to a portion of the company’s floating-rate debt are recorded at fair value on the balance sheet with resulting gains and losses reflected in income.

During 2002, no new swaps were initiated. At year-end 2002, the interest rate swaps outstanding related to fixed-rate debt, and their weighted average maturity was approximately 5.6 years.

Fair values of the interest rate swaps are reported on the Consolidated Balance Sheet as “Accounts and notes receivables” or “Accounts payable,” with gains and losses reported directly in income as part of “Interest and debt expense.” These activities are reported under “Operating activities” in the Consolidated Statement of Cash Flows.

Concentrations of Credit Risk The company’s financial instruments that are exposed to concentrations of credit risk consist primarily of its cash equivalents, marketable securities, derivative financial instruments and trade receivables. The company’s short-term investments are placed with a wide array of financial institutions with high credit ratings. This diversified investment policy limits the company’s exposure both to credit risk and to concentrations of credit risk. Similar standards of diversity and creditworthiness are applied to the company’s counterparties in derivative instruments.

The trade receivable balances, reflecting the company’s diversified sources of revenue, are dispersed among the company’s broad customer base worldwide. As a consequence, 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, Letters of Credit are the principal security obtained to support lines of credit.

Fair Value Fair values are derived either from quoted market prices 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 $7,296 and $6,599 had estimated fair values of $7,971 and $7,097 at December 31, 2002 and 2001, respectively.

For interest rate swaps, the notional principal amounts of $665 and $930 had estimated fair values of $70 and $2 at December 31, 2002 and 2001, respectively.

The company holds cash equivalents and U.S. dollar marketable securities in domestic and offshore portfolios. Eurodollar bonds, floating-rate notes, time deposits and commercial paper are the primary instruments held. Cash equivalents and marketable securities had fair values of $2,506 and $2,449 at December 31, 2002 and 2001, respectively. Of these balances, $1,682 and $1,446 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 3.9 years.

The company’s $1,500 investment in redeemable, convertible preferred stock of its Dynegy affiliate had an estimated fair value of $300 at December 31, 2002.

NOTE 10.

OPERATING SEGMENTS AND GEOGRAPHIC DATA

ChevronTexaco separately manages its exploration and production; refining, marketing and transportation; and chemicals businesses. “All Other” activities include corporate administrative costs, worldwide cash management and debt financing activities, the company’s investment in Dynegy, coal mining operations, power and gasification operations, technology investments, insurance operations, real estate activities, and expenses and net losses associated with the merger. The company’s primary country of operation is the United States of America, its country of domicile. Other components of the company’s operations are reported as “International” (outside the United States).

Segment Earnings The company evaluates the performance of its operating segments on an after-tax basis, without considering the effects of debt financing interest expense or investment interest income, both of which are managed by the company on a worldwide basis. Corporate administrative costs and assets are not allocated to the operating segments. However, operating segments are billed for the direct use of corporate services. Nonbillable costs and merger effects remain at the corporate level. After-tax segment income (loss) is presented in the following table:


	Year ended December 31

	2002			2001			2000

Exploration and Production
United States	$	1,717		$	1,779		$	3,453
International		2,839			2,533			3,702

Total Exploration and Production		4,556			4,312			7,155

Refining, Marketing and Transportation
United States		(398	)		1,254			721
International		31			560			414

Total Refining, Marketing and Transportation		(367	)		1,814			1,135

Chemicals
United States		13			(186	)		(31	)
International		73			58			71

Total Chemicals		86			(128	)		40

Total Segment Income		4,275			5,998			8,330
Merger-related expenses		(386	)		(1,136	)		–
Extraordinary loss		–			(643	)		–
Interest expense		(406	)		(552	)		(766	)
Interest income		72			147			139
Other		(2,423	)		(526	)		24

Net Income	$	1,132		$	3,288		$	7,727

FS-31

NOTE 10. OPERATING SEGMENTS AND GEOGRAPHIC DATA – Continued

Segment Assets Segment assets do not include intercompany investments or intercompany receivables. At December 31, 2001, “All Other” also included $2,181 for merger-related assets held for sale. Segment assets at year-end 2002 and 2001 follow:


	At December 31

	2002		2001

Exploration and Production
United States	$	11,671	$	12,718
International		26,172		24,177

Total Exploration and Production		37,843		36,895

Refining, Marketing and Transportation
United States		9,681		8,902
International		17,699		16,426

Total Refining, Marketing and Transportation		27,380		25,328

Chemicals
United States		2,154		2,059
International		698		701

Total Chemicals		2,852		2,760

Total Segment Assets		68,075		64,983

All Other
United States		5,364		8,950
International		3,920		3,639

Total All Other		9,284		12,589

Total Assets – United States		28,870		32,629
Total Assets – International		48,489		44,943

Total Assets	$	77,359	$	77,572

Segment Sales and Other Operating Revenues Operating segment sales and other operating revenues, including internal transfers, for the years 2002, 2001 and 2000 are presented in the following table. Sales from the transfer of products between segments are at prices that approximate market.

Revenues for the exploration and production segment are derived primarily from the production of crude oil and natural gas. Revenues for the refining, marketing and transportation 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 from the manufacture and sale of additives for lubricants and fuel. Prior to the July 2000 formation of CPChem, chemicals segment revenues were derived from the manufacture and sale of petrochemicals, plastic resins, and lube oil and fuel additives. Subsequent to the formation of the joint venture, only revenues from the manufacture and sale of lube oil and fuel additives were included. Revenues from “All Other” activities include coal mining operations, power and gasification operations, technology investments, insurance operations and real estate activities.

Other than the United States, the only country where ChevronTexaco generates significant revenues is the United Kingdom, which amounted to $10,816, $10,350 and $12,101 in 2002, 2001 and 2000, respectively.


		Year ended December 31

		2002			2001*			2000*

Exploration and Production
United States		$	4,500		$	11,874		$	13,397
	Intersegment		4,326			3,167			3,542

	Total United States		8,826			15,041			16,939

International			5,637			9,127			9,052
	Intersegment		8,377			7,376			6,189

	Total International		14,014			16,503			15,241

Total Exploration and Production			22,840			31,544			32,180

Refining, Marketing and Transportation
United States			33,880			29,294			31,926
	Excise Taxes		3,990			3,954			3,837
	Intersegment		163			392			414

	Total United States		38,033			33,640			36,177

International			45,759			45,248			52,501
	Excise Taxes		3,006			2,580			2,737
	Intersegment		43			452			930

	Total International		48,808			48,280			56,168

Total Refining, Marketing and Transportation			86,841			81,920			92,345

Chemicals
United States			323			335			1,985
	Excise Taxes		–			–			1
	Intersegment		109			89			137

	Total United States		432			424			2,123

International			638			670			701
	Excise Taxes		10			12			26
	Intersegment		68			65			–

	Total International		716			747			727

Total Chemicals			1,148			1,171			2,850

All Other
United States			911			1,278			933
	Intersegment		212			60			90

	Total United States		1,123			1,338			1,023

International			37			37			(1	)
	Intersegment		–			9			19

	Total International		37			46			18

Total All Other			1,160			1,384			1,041

Segment Sales and Other Operating Revenues

	United States		48,414			50,443			56,262
	International		63,575			65,576			72,154

Total Segment Sales and Other Operating Revenues			111,989			116,019			128,416
Elimination of Intersegment Sales			(13,298	)		(11,610	)		(11,321	)

Total Sales and Other Operating Revenues		$	98,691		$	104,409		$	117,095

2001 and 2000 include certain reclassifications to conform to 2002 presentation.

FS-32

NOTE 10. OPERATING SEGMENTS AND GEOGRAPHIC DATA – Continued

Segment Income Taxes Segment income tax expenses for the years 2002, 2001 and 2000 are as follows:


	Year ended December 31

	2002			2001			2000

Exploration and Production
United States	$	862		$	965		$	1,901
International		3,433			3,569			4,363

Total Exploration and Production		4,295			4,534			6,264

Refining, Marketing and Transportation
United States		(254	)		744			383
International		138			260			152

Total Refining, Marketing and Transportation		(116	)		1,004			535

Chemicals
United States		(17	)		(78	)		31
International		17			23			30

Total Chemicals		–			(55	)		61

All Other*		(1,155	)		(1,123	)		(538	)

Total Income Tax Expense*	$	3,024		$	4,360		$	6,322

2001 excludes tax of $144 for extraordinary item.

Other Segment Information Additional information for the segmentation of major equity affiliates is contained in Note 13. Information related to properties, plant and equipment by segment is contained in Note 14.

NOTE 11.

LITIGATION

Unocal Chevron, Texaco and four other oil companies (refiners) filed suit in 1995 contesting the validity of a patent (‘393’ patent) granted to Unocal Corporation (Unocal) for certain reformulated gasoline blends. ChevronTexaco sells reformulated gasolines in California in certain months of the year. In March 2000, the U.S. Court of Appeals for the Federal Circuit upheld a September 1998 District Court decision that Unocal’s patent was valid and enforceable and assessed damages of 5.75 cents per gallon for gasoline produced during the summer of 1996, which infringed on the claims of the patent. In February 2001, the U.S. Supreme Court concluded it would not review the lower court’s ruling, and the case was sent back to the District Court for an accounting of all infringing gasoline produced after August 1, 1996. The District Court has now ruled that the per-gallon damages awarded by the jury are limited to infringement that occurs in California only. Additionally, the U.S. Patent and Trademark Office (USPTO) granted two petitions by the refiners to re-examine the validity of Unocal’s ‘393’ patent and has twice rejected all of the claims in the ‘393’ patent. The District Court judge requested further briefing and advised that she would not enter a final judgment in this case until the USPTO also had completed its re-examination of the ‘393’ patent. During 2002, the USPTO also rejected the validity of another Unocal patent, the ‘126’ patent, which could affect a larger share of U.S. gasoline production. Separately, the FTC has issued an administrative complaint alleging that Unocal’s conduct in this matter represented an unfair method of competition, which may make Unocal’s patents unenforceable.

MTBE Another issue involving the company is the petroleum industry’s use of methyl tertiary butyl ether (MTBE) as a gasoline additive and its potential environmental impact through seepage into groundwater. Along with other oil companies, the company is a party to lawsuits and claims related to the use of the chemical MTBE in certain oxygenated gasolines. These actions may require the company to correct or ameliorate the alleged effects on the environment of prior release of MTBE by the company or other parties. Additional lawsuits and claims related to the use of MTBE, including personal-injury claims, may be filed in the future. The company’s ultimate exposure related to these lawsuits and claims is not currently determinable, but could be material to net income in any one period. ChevronTexaco has worked to reduce the use of MTBE in gasoline it manufactures in the United States. The state of California has directed that MTBE be phased out of the manufacturing process by the end of 2003, and the company intends to comply with this mandate. By May 2003, the company plans to market branded gasoline that uses ethanol as an oxygenate instead of MTBE in southern California and will complete the changeover in northern California later in the year.

NOTE 12.

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, 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

		2002		2001

Exploration and production		$	176	$	172
Refining, marketing and transportation			843		848

	Total		1,019		1,020
Less: Accumulated amortization			595		567

Net capitalized leased assets		$	424	$	453

FS-33

NOTE 12. LEASE COMMITMENTS – Continued

Rental expenses incurred for operating leases during 2002, 2001 and 2000 were as follows:


		Year ended December 31

		2002		2001		2000

Minimum rentals		$	1,270	$	1,132	$	1,062
Contingent rentals			4		14		35

	Total		1,274		1,146		1,097
Less: Sublease rental income			53		76		77

Net rental expense		$	1,221	$	1,070	$	1,020

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 from one to 25 years, and/or 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, 2002, the estimated future minimum lease payments (net of noncancelable sublease rentals) under operating and capital leases, which at inception had a noncancelable term of more than one year, were as follows:


		At December 31

		Operating		Capital
		Leases		Leases

Year: 2003		$	360	$	74
	2004		321		84
	2005		285		48
	2006		263		45
	2007		215		38
	Thereafter		759		566

Total		$	2,203	$	855

Less: Amounts representing interest and executory costs					265

Net present values					590
Less: Capital lease obligations included in short-term debt					345

Long-term capital lease obligations				$	245

NOTE 13.

INVESTMENTS AND ADVANCES

Equity in earnings, together with investments in and advances to companies accounted for using the equity method, and other investments accounted for at or below cost, are as follows:


		Investments and Advances					Equity in Earnings
		At December 31					Year ended December 31

		2002			2001		2002			2001			2000

Exploration and Production
	Tengizchevroil	$	2,949		$	2,459	$	490		$	332		$	376
	Other		876			808		116			205			163

	Total Exploration and Production		3,825			3,267		606			537			539

Refining, Marketing and Transportation
	Equilon¹		–			–		–			274			151
	Motiva¹		–			–		–			276			154
	LG-Caltex Oil Corporation		1,513			1,491		46			60			80
	Caspian Pipeline Consortium		1,014			928		66			38			22
	Star Petroleum Refining Company Ltd.		449			394		(25	)		(56	)		(4	)
	Caltex Australia Ltd.		109			267		(20	)		16			13
	Other		994			755		110			92			117

	Total Refining, Marketing and Transportation		4,079			3,835		177			700			533

Chemicals
	Chevron Phillips Chemical Company LLC		1,710			1,587		2			(229	)		(114	)
	Other		21			17		4			2			(9	)

	Total Chemicals		1,731			1,604		6			(227	)		(123	)

All Other
	Dynegy Inc.		347			2,628		(679	)		188			127
	Other		681	²		507		1			(54	)		1

	Total Equity Method	$	10,663		$	11,841	$	111		$	1,144		$	1,077
	Other at or Below Cost		434			411

	Total Investments and Advances	$	11,097		$	12,252

Total U.S		$	3,216		$	5,370	$	(559	)	$	693		$	562
Total International		$	7,881		$	6,882	$	670		$	451		$	515

¹		Placed in trust at the time of the merger and accounting changed from the equity method to the cost basis. Interests were classified as “Assets held for sale – merger related” at December 31, 2001.
²		Includes $96 for Star Petroleum Refining Company Ltd.

Descriptions of major affiliates during 2002 are as follows:

Tengizchevroil Tengizchevroil (TCO) is a joint venture formed in 1993 to develop the Tengiz and Korolev oil fields in Kazakhstan over a 40-year period. Chevron’s ownership was 45 percent during 1999 and 2000. In January 2001, the company purchased an additional 5 percent interest. Upon formation of the joint venture, the company incurred an obligation of $420, payable to the Republic of Kazakhstan upon attainment of a dedicated export system with the capability of the greater of 260,000 barrels of oil per day or TCO’s production capacity. As a part of the January 2001 transaction, the company paid $210 of the $420 obligation. The $420 was also included in the carrying value of the original investment, as the company believed, beyond a reasonable doubt, that its full payment would be made.

FS-34

NOTE 13. INVESTMENTS AND ADVANCES – Continued

Equilon Enterprises LLC and Motiva Enterprises LLC Until February 2002, the company had equity interests in Equilon and Motiva – joint ventures engaged in U.S. refining and marketing activities. Under mandate of the FTC as a condition of the merger, the company’s ownership interests were placed in trust on October 9, 2001. The trust completed the dispositions of the company’s investments in Equilon and Motiva in February 2002. See Note 2 for additional information on Equilon and Motiva.

LG-Caltex Oil Corporation ChevronTexaco owns 50 percent of LG-Caltex, a joint venture formed in 1967 between the LG Group and Caltex, to engage in importing, refining and marketing of petroleum products in South Korea.

Star Petroleum Refining Company Ltd. ChevronTexaco has a 64 percent equity ownership interest in Star Petroleum Refining Company Limited (SPRC), which owns the Star refinery at Ma Ta Phut, Thailand. The Petroleum Authority of Thailand owns the remaining 36 percent of SPRC.

Caltex Australia Ltd. ChevronTexaco has a 50 percent equity ownership interest in Caltex Australia Limited (CAL). The remaining 50 percent of CAL is publicly owned. During 2002, the company wrote down its investment in CAL by $136 to its estimated fair value at September 30, 2002. At December 31, 2002, the fair value of ChevronTexaco’s share of CAL common stock was $163. The aggregate carrying value of the company’s investment in CAL was approximately $100 lower than the amount of underlying equity in CAL net assets.

Chevron Phillips Chemical Company LLC ChevronTexaco owns 50 percent of CPChem, formed in July 2000 when Chevron merged most of its petrochemicals businesses with those of Phillips Petroleum Company. Because CPChem is a limited liability company, ChevronTexaco records the provision for income taxes and related tax liability applicable to its share of the venture’s income separately in its consolidated financial statements. At December 31, 2002, the company’s carrying value of its investment in CPChem was approximately $40 lower than the amount of underlying equity in CPChem’s net assets.

Dynegy Inc. ChevronTexaco’s Dynegy affiliate owns operating divisions engaged in power generation, natural gas liquids and regulated energy delivery. ChevronTexaco owns approximately 26 percent of Dynegy’s common stock and also holds $1,500 aggregate principal amount of Dynegy preferred stock. During 2002, the company wrote down its investments in Dynegy common and preferred stock to their estimated fair market values. The market value of ChevronTexaco’s share of Dynegy common stock at December 31, 2002, was $114, based on equivalent closing market prices, and the estimated fair value of the preferred stock was $300. At December 31, 2002, the company’s carrying value of the common-stock investment in Dynegy was approximately $500 lower than the amount of underlying equity in Dynegy’s net assets available to common shareholders.

“Sales and other operating revenues” on the Consolidated Statement of Income include $6,218, $13,868 and $15,741 with major affiliated companies for 2002, 2001 and 2000, respectively. “Purchased crude oil and products” include $1,720, $3,859 and $4,824 with major affiliated companies for 2002, 2001 and 2000, respectively.

“Accounts and notes receivable” on the Consolidated Balance Sheet include $615 and $481 due from affiliated companies at December 31, 2002 and 2001, respectively. “Accounts payable” include $161 and $168 due to major affiliated companies at December 31, 2002 and 2001, respectively. The 2001 amounts exclude balances with Equilon and Motiva.

The following table provides summarized financial information on a 100 percent basis for Equilon, Motiva and all other equity affiliates, as well as ChevronTexaco’s total share.


	Equilon¹						Motiva¹						Other Affiliates								ChevronTexaco Share

YEAR ENDED DECEMBER 31	2002		2001		2000		2002		2001		2000		2002			2001			2000		2002			2001		2000

Total revenues	$	–	$	36,501	$	50,010	$	–	$	14,459	$	19,446	$	31,877		$	69,549		$	56,602	$	15,049		$	46,649	$	48,925
Income (loss) before income tax expense		–		604		228		–		771		461		(1,517	)		646			2,420		94			1,430		1,230
Net income (loss)		–		397		148		–		486		300		(1,540	)		(74	)		1,689		111			1,144		1,077

At December 31

Current assets	$	–	$	–	$	3,134	$	–	$	–	$	1,381	$	16,808		$	17,015		$	18,442	$	6,270		$	5,922	$	8,456
Noncurrent assets		–		–		6,830		–		–		5,110		40,884			40,191			34,620		15,849			16,276		16,965
Current liabilities		–		–		4,587		–		–		1,150		14,414			14,688			16,109		5,158			4,757		7,820
Noncurrent liabilities		–		–		897		–		–		2,017		24,129			23,255			20,905		5,668			5,600		6,263

Net equity	$	–	$	–	$	4,480	$	–	$	–	$	3,324	$	19,149		$	19,263		$	16,048	$	11,293	²	$	11,841	$	11,338

¹		Accounted for under the equity method pre-merger and the cost basis post-merger.
²		Differs by $630 from $10,663 shown in the preceding table for “Investments and Advances – Total Equity Method.” Relates primarily to differences for Dynegy Inc. and Caltex Australia Ltd., as described above.

FS-35

NOTE 14.

PROPERTIES, PLANT AND EQUIPMENT ¹


		At December 31																		Year ended December 31

		Gross Investment at Cost						Net Investment						Additions at Cost²						Depreciation Expense

		2002		2001		2000		2002		2001		2000		2002		2001		2000		2002		2001		2000

Exploration and Production
	United States	$	39,986	$	38,582	$	37,342	$	10,457	$	10,560	$	12,093	$	1,658	$	1,973	$	1,931	$	1,806	$	3,508	$	2,138
	International		36,382		33,273		30,396		18,908		17,743		16,938		3,343		2,900		3,019		2,132		2,085		1,787

Total Exploration and Production			76,368		71,855		67,738		29,365		28,303		29,031		5,001		4,873		4,950		3,938		5,593		3,925

Refining, Marketing and Transportation
	United States		13,423		12,944		12,557		6,296		6,237		6,176		671		626		484		570		476		516
	International		11,194		10,878		10,635		6,310		6,349		6,367		411		566		457		530		555		651

Total Refining, Marketing and Transportation			24,617		23,822		23,192		12,606		12,586		12,543		1,082		1,192		941		1,100		1,031		1,167

Chemicals
	United States		614		602		610		317		321		342		16		10		78		21		22		77
	International		731		698		672		420		405		395		37		31		42		21		19		18

Total Chemicals			1,345		1,300		1,282		737		726		737		53		41		120		42		41		95

All Other³			2,901		2,883		3,005		1,447		1,267		1,657		285		174		202		151		394		134

Total United States			56,806		54,954		53,485		18,404		18,367		20,275		2,575		2,780		2,695		2,544		4,391		2,825
Total International			48,425		44,906		41,732		25,751		24,515		23,693		3,846		3,500		3,518		2,687		2,668		2,496

	Total	$	105,231	$	99,860	$	95,217	$	44,155	$	42,882	$	43,968	$	6,421	$	6,280	$	6,213	$	5,231	$	7,059	$	5,321

¹		Net of accumulated abandonment and restoration costs of $2,263, $2,155 and $2,259 at December 31, 2002, 2001 and 2000, respectively.
²		Net of dry hole expense related to prior years’ expenditures of $36, $228 and $60 in 2002, 2001 and 2000, respectively.
³		Primarily coal, real estate assets and management information systems.

FS-36

NOTE 15.

TAXES


		Year ended December 31

		2002			2001			2000

Taxes on income
U.S. federal
	Current	$	(72	)	$	946		$	1,238
	Deferred		(414	)		(643	)		363
State and local			21			276			185

	Total United States		(465	)		579			1,786

International
	Current		3,156			3,764			4,378
	Deferred		333			17			158

	Total International		3,489			3,781			4,536

Total taxes on income		$	3,024		$	4,360		$	6,322

In 2002, the before-tax loss, including related corporate and other charges, for U.S. operations was $2,140, compared with before-tax income of $1,778 in 2001 and $5,823 in 2000. For international operations, before-tax income was $6,296, $6,513 and $8,226 in 2002, 2001 and 2000, respectively. U.S. federal income tax expense was reduced by $208, $202 and $165 in 2002, 2001 and 2000, respectively, for business tax credits.

The above table does not include a current U.S. tax benefit of $2 and a U.S. deferred tax benefit of $142 associated with the extraordinary item in 2001.

The company’s effective income tax rate varied from the U.S. statutory federal income tax rate because of the following:


	Year ended December 31

	2002			2001			2000

U.S. statutory federal income tax rate		35.0	%		35.0	%		35.0	%
Effect of income taxes from international operations in excess of taxes at the U.S. statutory rate		29.6			19.0			11.0
State and local taxes on income, net of U.S. federal income tax benefit		1.1			2.2			0.9
Prior-year tax adjustments		(7.0	)		1.1			(0.6	)
Tax credits		(5.0	)		(2.4	)		(1.2	)
Effects of enacted changes in tax laws/rates on deferred tax liabilities		2.0			–			–
Impairment of investments in equity affiliates		12.4			–			–
Other		–			(1.7	)		0.2

Consolidated companies		68.1			53.2			45.3
Effect of recording income from certain equity affiliates on an after-tax basis		4.7			(0.6	)		(0.3	)

Effective tax rate		72.8	%		52.6	%		45.0	%

The increase in the 2002 effective tax rate was due to a number of factors. The primary reason was that U.S. before-tax income (generally subject to a lower tax rate) was a significantly smaller percentage of overall before-tax income in 2002 compared with 2001. Prior-year tax adjustments arose from revisions to deferred tax valuation allowances and other tax related accruals. The impairment of the investments in Dynegy and Caltex Australia were capital losses for which no offsetting capital gains were available.

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

		2002			2001

Deferred tax liabilities
	Properties, plant and equipment	$	7,818		$	7,478
	Inventory		14			50
	Investments and other		521			1,334

	Total deferred tax liabilities		8,353			8,862

Deferred tax assets
	Abandonment/environmental reserves		(902	)		(913	)
	Employee benefits		(1,414	)		(863	)
	Tax loss carryforwards		(747	)		(692	)
	AMT/other tax credits		(380	)		(511	)
	Other accrued liabilities		(234	)		(158	)
	Miscellaneous		(1,927	)		(2,164	)

	Total deferred tax assets		(5,604	)		(5,301	)

Deferred tax assets valuation allowance			1,740			1,512

Total deferred taxes, net		$	4,489		$	5,073

The valuation allowance relates to foreign tax credit carry-forwards, tax loss carryforwards and temporary differences that are not expected to be realized.

At December 31, 2002 and 2001, deferred taxes were classified in the Consolidated Balance Sheet as follows:


		At December 31

		2002			2001

Prepaid expenses and other current assets		$	(760	)	$	(671	)
Deferred charges and other assets			(455	)		(399	)
Federal and other taxes on income			85			11
Noncurrent deferred income taxes			5,619			6,132

	Total deferred income taxes, net	$	4,489		$	5,073

It is the company’s policy for subsidiaries included in the U.S. consolidated tax return to record income tax expense as though they filed separately, with the parent recording the adjustment to income tax expense for the effects of consolidation. Income taxes are accrued for retained earnings of international subsidiaries and corporate joint ventures intended to be remitted. 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 approximately $10,108 at December 31, 2002. Substantially all of this amount represents earnings reinvested as part of the company’s ongoing business. It is not practicable to estimate the amount of taxes that might be payable on the eventual remittance of such earnings. On remittance, certain countries impose withholding

FS-37

NOTE 15. TAXES – Continued

taxes that, subject to certain limitations, are then available for use as tax credits against a U.S. tax liability, if any.

Taxes other than on income were as follows:


			Year ended December 31

			2002		2001		2000

United States
	Excise taxes on products and merchandise		$	3,990	$	3,954	$	3,909
	Import duties and other levies			12		8		25
	Property and other miscellaneous taxes			348		410		345
	Payroll taxes			141		148		139
	Taxes on production			179		225		238

		Total United States		4,670		4,745		4,656

International
	Excise taxes on products and merchandise			3,016		2,592		2,692
	Import duties and other levies			8,587		7,461		8,073
	Property and other miscellaneous taxes			291		268		271
	Payroll taxes			46		79		69
	Taxes on production			79		11		66

		Total International		12,019		10,411		11,171

Total taxes other than on income			$	16,689	$	15,156	$	15,827

NOTE 16.

SHORT-TERM DEBT


		At December 31

		2002			2001

Commercial paper*		$	7,183		$	8,664
Notes payable to banks and others with originating terms of one year or less			713			1,036
Current maturities of long-term debt			740			1,095
Current maturities of long-term capital leases			45			45
Redeemable long-term obligations
	Long-term debt		487			488
	Capital leases		300			301

	Subtotal		9,468			11,629
Reclassified to long-term debt			(4,110	)		(3,200	)

	Total short-term debt	$	5,358		$	8,429

Weighted-average interest rates at December 31, 2002 and 2001, were 1.47 percent and 1.99 percent, respectively, including the effect of interest rate swaps.

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 9 for information concerning the company’s debt-related derivative activities.

At December 31, 2002, the company had $4,110 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 on the London Interbank Offered Rate, the Reserve Adjusted Domestic Certificate of Deposit Rate or bank prime rate. No amounts were outstanding under these credit agreements during 2002 or at year-end.

At December 31, 2002 and 2001, the company classified $4,110 and $3,200, respectively, of short-term debt as long-term. Settlement of these obligations is not expected to require the use of working capital in 2003, as the company has both the intent and ability to refinance this debt on a long-term basis.

NOTE 17.

LONG-TERM DEBT

ChevronTexaco has three “shelf” registrations on file with the Securities and Exchange Commission that together would permit the issuance of $2,050 of debt securities pursuant to Rule 415 of the Securities Act of 1933. The company’s long-term debt outstanding at year-end 2002 and 2001 are as follows:


			At December 31

			2002			2001

3.5% guarantees due 2007			$	1,992		$	–
6.625% notes due 2004				499			499
5.5% note due 2009				439			393
7.327% amortizing notes due 2014¹				410			430
8.11% amortizing notes due 2004²				350			450
6% notes due 2005				299			299
9.75% debentures due 2020				250			250
5.7% notes due 2008				224			201
8.5% notes due 2003				200			200
7.75% debentures due 2003				199			199
8.625% debentures due 2031				199			199
8.625% debentures due 2032				199			199
7.5% debentures due 2043				198			198
6.875% debentures due 2023				196			196
7.09% notes due 2007				150			150
8.25% debentures due 2006				150			150
8.625% debentures due 2010				150			150
8.875% debentures due 2021				150			150
8.375% debentures due 2022				–			199
Medium-term notes, maturing from 2003 to 2043 (7.1%)³				277			360
Other foreign currency obligations (5.1%)³				87			193
Other long-term debt (3.9%)³				678			1,534

	Total including debt due within one year			7,296			6,599
		Debt due within one year		(740	)		(1,095	)
		Reclassified from short-term debt		4,110			3,200

Total long-term debt			$	10,666		$	8,704

¹		Guarantee of ESOP debt.
²		Debt assumed from ESOP in 1999.
³		Less than $150 individually; weighted-average interest rates at December 31, 2002.

Consolidated long-term debt maturing after December 31, 2002, is as follows: 2003 – $740; 2004 – $818; 2005 – $550; 2006 –$224; and 2007 – $2,192; after 2007 – $2,772.

In February 2003, the company redeemed $200 of Texaco Capital Inc. bonds originally due in 2033. Also in February, the company issued $750 of 3.375 percent bonds due in February 2008 under a shelf registration. The proceeds from this issuance were used to pay down commercial paper borrowings.

FS-38

NOTE 18.

NEW ACCOUNTING STANDARDS

In June 2001, the FASB issued Statement No. 143, “Accounting for Asset Retirement Obligations” (FAS 143). This new standard was adopted effective January 1, 2003, and applies to legal obligations associated with the retirement of tangible long-lived assets. Adoption of FAS 143 primarily affects the company’s accounting for oil and gas producing assets. FAS 143 differs in several significant respects from current accounting under FAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” Adoption of FAS 143 affects future accounting and reporting of the assets, liabilities and expenses related to these obligations. In the first quarter 2003, the company will report an after-tax loss of $200 to $250 for the cumulative effect of this change in accounting principle, including the company’s share of the effect of adoption by its equity affiliates. The effect of adoption also included an increase of total assets and total liabilities of $2.6 billion and $2.8 billion, respectively. Other than the cumulative-effect change, the effect of the new accounting standard on 2003 net income is not expected to be materially different from what the result would have been under FAS 19 accounting. Upon adoption, legal obligations, if any, to retire downstream and chemical long-lived assets generally were not recognized because of indeterminate settlement dates for the asset retirement. Therefore, insufficient information exists to estimate the potential settlement dates and to apply the net-present-value techniques to estimate the fair value of the retirement obligation.

In July, the FASB issued Statement No. 146, “Accounting for Costs Associated with Exit or Disposal Activities” (FAS 146). The standard requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. Examples of costs covered by the standard include lease termination costs and certain employee severance costs that are associated with a restructuring, discontinued operations, a plant closing, or other exit or disposal activity. The statement replaces EITF (Emerging Issues Task Force of the FASB) Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” FAS 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002.

In November, the FASB issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45). The disclosure provisions of FIN 45 are effective for fiscal years ending after December 15, 2002, and are included in Note 21. The recognition and measurement requirements are to be applied on a prospective basis to guarantees issued or modified after December 31, 2002. As these requirements relate to future events, the effect cannot be determined.

In December, the FASB issued Statement No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure” (FAS 148), which amends FASB Statement No. 123, “Accounting for Stock-Based Compensation.” FAS 148 permits two additional transition methods for entities that adopt the fair-value-based method of accounting for stock-based employee compensation and amends the disclosure requirements in both annual and interim financial statements. ChevronTexaco will continue to apply Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations in accounting for stock options. The amended disclosure requirements of FAS 148 have been incorporated into Note 1 to the Consolidated Financial Statements.

In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46). FIN 46 amended ARB 51, “Consolidated Financial Statements,” and established standards for determining under what circumstances a variable interest entity (VIE) should be consolidated with its primary beneficiary. FIN 46 also requires disclosures about VIEs that the company is not required to consolidate but in which it has a significant variable interest. The consolidation requirements of FIN 46 apply immediately to VIEs created after January 31, 2003. The consolidation requirements apply to older entities in the first fiscal year or interim period beginning after June 15, 2003. Certain of the disclosure requirements apply in all financial statements issued after January 31, 2003, regardless of when the VIE was established. The company does not expect that adoption of FIN 46 will have a significant impact on the results of operations, financial position or liquidity.

NOTE 19.

EMPLOYEE BENEFIT PLANS

Pension Plans and Other Postretirement Benefits The company has defined benefit pension plans for many employees and provides for certain health care and life insurance plans for some active and qualifying retired employees. The company typically funds only those defined benefit plans where legal funding is required. In the United States, this includes all qualified plans subject to the Employee Retirement Income Security Act (ERISA) minimum funding standard. The company does not fund domestic nonqualified plans or international plans that are not subject to any legal funding requirements. The aggregated funded status for the funded and unfunded pension plans is depicted in the following table.

The company’s annual contribution for medical and dental benefits are limited to the lesser of actual medical and dental claims or a defined fixed per-capita amount. Life insurance benefits are paid by the company, and annual contributions are based on actual plan experience. Nonfunded pension and postretirement benefits are paid directly when incurred; accordingly, these payments are not reflected as changes in plan assets in the following table.

FS-39

NOTE 19. EMPLOYEE BENEFIT PLANS – Continued

The status of the company’s pension plans and other postretirement benefit plans for 2002 and 2001 is as follows:


		Pension Benefits

		2002						2001						Other Benefits

		U.S.			Int'l.			U.S.			Int'l.			2002			2001

CHANGE IN BENEFIT OBLIGATION
	Benefit obligation at January 1	$	5,180		$	1,848		$	4,977		$	1,736		$	2,526		$	2,247
	Service cost		112			47			111			47			25			21
	Interest cost		334			143			355			136			178			165
	Plan participants’ contributions		2			3			2			2			–			–
	Plan amendments		298			9			12			13			–			(10	)
	Actuarial loss		410			36			341			108			307			244
	Foreign currency exchange rate changes		–			154			–			(94	)		5			(9	)
	Benefits paid		(1,028	)		(123	)		(532	)		(110	)		(176	)		(158	)
	Curtailment		–			–			(47	)		–			–			(3	)
	Special termination benefits		–			–			47			14			–			29
	Plan divestiture		–			–			–			(4	)		–			–
	Acquisitions/joint ventures		–			46			(86	)		–			–			–

Benefit obligation at December 31			5,308			2,163			5,180			1,848			2,865			2,526

CHANGE IN PLAN ASSETS
Fair value of plan assets at January 1			4,400			1,547			5,098			1,757			–			–
	Actual return on plan assets		(284	)		(139	)		(221	)		(90	)		–			–
	Foreign currency exchange rate changes		–			179			–			(56	)		–			–
	Employer contribution		14			117			2			26			–			–
	Plan participants’ contributions		2			1			2			2			–			–
	Expenses		–			–			(6	)		–			–			–
	Benefits paid		(942	)		(94	)		(475	)		(88	)		–			–
	Plan divestiture		–			–			–			(4	)		–			–
	Acquisitions/joint ventures		–			34			–			–			–			–

Fair value of plan assets at December 31			3,190			1,645			4,400			1,547			–			–

FUNDED STATUS			(2,118	)		(518	)		(780	)		(301	)		(2,865	)		(2,526	)
	Unrecognized net actuarial loss		1,686			793			837			493			414			93
	Unrecognized prior-service cost		363			74			129			70			(21	)		(24	)
	Unrecognized net transitional assets		–			(1	)		–			(7	)		–			–

Total recognized at December 31		$	(69	)	$	348		$	186		$	255		$	(2,472	)		(2,457	)

AMOUNTS RECOGNIZED IN THE CONSOLIDATED BALANCE SHEET AT DECEMBER 31
	Prepaid benefit cost	$	164		$	652		$	568		$	574		$	–		$	–
	Accrued benefit liability¹		(1,928	)		(324	)		(529	)		(334	)		(2,472	)		(2,457	)
	Intangible asset		360			8			10			12			–			–
	Accumulated other comprehensive income²		1,335			12			137			3			–			–

Net amount recognized		$	(69	)	$	348		$	186		$	255		$	(2,472	)	$	(2,457	)

Weighted-average assumptions as of December 31
	Discount rate		6.8	%		7.1	%		7.3	%		7.7	%		6.8	%		7.3	%
	Expected return on plan assets		7.8	%		8.3	%		8.8	%		8.9	%		–			–
	Rate of compensation increase		4.0	%		5.1	%		4.0	%		5.4	%		4.1	%		4.1	%

¹		Includes additional minimum pension liabilities of $1,695 and $20 in 2002 for U.S. and International, respectively, and $147 and $15 in 2001 for U.S. and International, respectively. As a result, recorded liabilities reflect the amount of unfunded accumulated benefit obligations. The additional minimum pension liabilities are offset by intangible assets and a charge to “Accumulated other comprehensive income.”
²		Accumulated other comprehensive income includes deferred income taxes of $467 and $4 in 2002 for U.S. and International, respectively, and $48 and $1 in 2001 for U.S. and International, respectively. This item is presented net of these taxes in the Consolidated Statement of Stockholder’s Equity.

FS-40

NOTE 19. EMPLOYEE BENEFIT PLANS – Continued

The components of net periodic benefit cost for 2002, 2001 and 2000 were:


	Pension Benefits

	2002						2001						2000						Other Benefits

	U.S.			Int'l.			U.S.			Int'l.			U.S.			Int'l.			2002			2001			2000

Service cost	$	112		$	47		$	111		$	47		$	118		$	47		$	25		$	21		$	20
Interest cost		334			143			355			136			363			133			178			165			161
Expected return on plan assets		(288	)		(138	)		(443	)		(170	)		(503	)		(167	)		–			–			–
Amortization of transitional assets		–			(3	)		(2	)		(4	)		(31	)		(6	)		–			–			–
Amortization of prior-service costs		32			12			25			12			30			12			(3	)		(1	)		(1	)
Recognized actuarial losses (gains)		32			27			13			7			10			(2	)		(1	)		(6	)		(10	)
Settlement losses (gains)		146			1			12			–			(61	)		1			–			–			–
Curtailment losses (gains)		–			–			26			–			(20	)		2			–			20			(15	)
Special termination benefit recognition		–			–			47			14			–			6			–			29			–

Net periodic benefit cost	$	368		$	89		$	144		$	42		$	(94	)	$	26		$	199		$	228		$	155

The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for pension plans with accumulated benefit obligations in excess of plan assets were $5,761, $5,327 and $3,283, respectively, at December 31, 2002, and $2,496, $2,187 and $1,269, respectively, at December 31, 2001.

For postretirement benefit measurement purposes, one set of health care cost-trend rates was used for pre-age 65 and 65-and-over retirees. Starting in 2002, with approximately a 12 percent cost increase over the previous year, the trend rates gradually drop to 4.5 percent for 2007 and beyond. A one-percentage-point change in the assumed health care cost-trend rates would have had the following effects:


	1 Percent		1 Percent
	Increase		Decrease

Effect on total service and interest cost components	$	24	$	(20	)
Effect on postretirement benefit obligation	$	285	$	(237	)

Employee Savings Investment Plan Eligible employees of ChevronTexaco and certain of its subsidiaries participate in the ChevronTexaco Employee Savings Investment Plan (ESIP). In 2002, the Employees Thrift Plan of Texaco Inc., Employees Savings Plan of ChevronTexaco Global Energy Inc. (formerly Caltex Corporation), Stock Plan of ChevronTexaco Global Energy Inc. and Employees Thrift Plan of Fuel and Marine Marketing LLC were merged into the ChevronTexaco ESIP. Charges to expense for these plans were $161, $157 and $63 in 2002, 2001 and 2000, respectively.

Employee Stock Ownership Plans (ESOP) Within the ChevronTexaco Employee Savings Investment Plan, the company has established an employee stock ownership plan. In December 1989, Chevron established a leveraged employee stock ownership plan (LESOP) as a constituent part of the ESOP. The LESOP provides partial pre-funding of the company’s future commitments to the ESIP, which will result in annual income tax savings for the company.

In 1988, Texaco established a leveraged employee stock ownership plan as a component of the Employees Thrift Plan of Texaco Inc. The thrift plan LESOP loan was satisfied in December 2000. During 2002 the Employees Thrift Plan of Texaco Inc. was subsumed into the ChevronTexaco 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 Statement of Position 76-3, “Accounting Practices for Certain Employee Stock Ownership Plans,” and subsequent consensus of the Emerging Issues Task Force of the Financial Accounting Standards Board. The debt of the LESOPs is recorded as debt, and shares pledged as collateral are reported as “Deferred compensation and benefit plan trust” in 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 by the LESOPs. Interest incurred on the 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.

Expense recorded for the LESOPs was $98, $75 and $26 in 2002, 2001 and 2000, respectively, including $32, $43 and $48 of interest expense related to LESOP debt. All dividends paid on the LESOP shares held are used to service the LESOP debt. The dividends used were $49, $86 and $77 in 2002, 2001 and 2000, respectively.

The company made LESOP contributions of $102, $75 and $1 in 2002, 2001 and 2000, respectively, to satisfy LESOP debt service in excess of dividends received by the LESOP. The LESOP shares were pledged as collateral for the debt. Shares are released from a suspense account and allocated to the accounts of plan participants, based on the debt service deemed to be paid in the year in proportion to the total of current-year and remaining debt service. The charge (credit) to compensation expense was $66, $32 and $(22) in 2002, 2001 and 2000, respectively. LESOP shares as of December 31, 2002 and 2001, were as follows:


Thousands	2002		2001

Allocated shares		12,513		12,541
Unallocated shares		7,743		8,836

Total LESOP shares		20,256		21,377

Benefit Plan Trust Texaco established a benefit plan trust for funding obligations under some of its benefit plans. At year-end 2002, the trust contained 7.1 million shares of ChevronTexaco treasury

FS-41

NOTE 19. EMPLOYEE BENEFIT PLANS – Continued

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.

Management Incentive Plans ChevronTexaco 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 plans were expanded in 2002 to include former employees of Texaco and Caltex. 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 conversion to stock units or other investment fund alternatives. Awards under the LTIP may take the form of, but are not limited to, stock options, restricted stock, stock units and nonstock grants. Texaco also had a cash incentive program and a Stock Incentive Plan (SIP) that included stock options, restricted stock and other incentive awards for executives, directors and key employees. Awards under the Caltex LTIP were in the form of performance units and stock appreciation rights. Charges to expense for the combined management incentive plans, excluding expense related to LTIP and SIP stock options and restricted stock awards, that are discussed in Note 20, were $48, $101 and $83 in 2002, 2001 and 2000, respectively.

Other Incentive Plans The company has a program that provides eligible employees with an annual cash bonus if the company achieves certain financial and safety goals. Charges for the program were $158, $154 and $230 in 2002, 2001 and 2000, respectively.

NOTE 20.

STOCK OPTIONS

The company applies APB Opinion No. 25 and related interpretations in accounting for its stock-based compensation programs, which are described below. Stock-based compensation (credit) expense recognized in connection with these programs was $(2), $111 and $23 in 2002, 2001 and 2000, respectively.

The pro forma effect on net income and earnings per share, had the company applied the fair-value-recognition provisions of FAS No. 123, are shown in Note 1.

Broad-Based Employee Stock Options In 1998, Chevron granted to all its eligible employees an option that varied from 100 to 300 shares of stock or equivalents, dependent on the employee’s salary or job grade. These options vested after two years in February 2000. Options for 4,820,800 shares were awarded at an exercise price of $76.3125 per share. Outstanding option shares were 3,064,367 at year-end 2000. Exercises of 653,096 and forfeitures of 44,960 reduced the outstanding option shares to 2,366,311 at the end of 2001. In 2002, exercises of 295,985 and forfeitures of 61,151 reduced the outstanding option shares to 2,009,175 at the end of the year. The options expire February 11, 2008. The company recorded (credit) expense of $(2), $1 and $(2) for these options in 2002, 2001 and 2000, respectively.

The fair value of each option share on the date of grant under FAS No. 123 was estimated at $19.08 using the average results of Black-Scholes models for the preceding 10 years. The 10-year averages of each assumption used by the Black-Scholes models were: a risk-free interest rate of 7.0 percent, a dividend yield of 4.2 percent, an expected life of seven years and a volatility of 24.7 percent.

Long-Term Incentive Plan Stock options granted under the LTIP extend for 10 years from the date of grant. Effective with options granted in June 2002, one third of the options vest on each of 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, while options granted by Texaco under its SIP vested over a two-year period at a rate of 50 percent each year. The maximum number of shares that may be granted each year is 1 percent of the total outstanding shares of common stock as of January 1 of such year.

On the closing of the merger on October 9, 2001, outstanding options granted under the Texaco SIP were converted to ChevronTexaco options at the merger exchange rate of 0.77. These options retained a provision for restored options. This feature enables a participant who exercises a stock option by exchanging previously acquired common stock 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 fair market value of the common stock on the day the restored option is granted. Restricted shares granted under the former Texaco plan contained a performance element that had to be satisfied in order for all or a specified portion of the shares to vest. Upon the merger, all restricted shares became vested and converted to ChevronTexaco shares at the merger exchange ratio of 0.77. Apart from the restored options, no further awards may be granted under the former Texaco plans. Amounts charged to compensation expense in 2002, 2001 and 2000, including the former Texaco plans, were $0, $110 and $25, respectively. Restricted performance shares granted under SIP were as follows:


	2002		2001		2000

Shares (thousands)		–		392		409
Weighted-average fair value	$	–	$	91.05	$	73.40

The fair market value of each stock option granted is estimated on the date of grant under FAS No. 123 using the Black-Scholes option-pricing model with the following weighted-average assumptions:


		2002			2001			2000

ChevronTexaco plans:
	Expected life in years		7			7			7
	Risk-free interest rate		4.6	%		4.1	%		5.8	%
	Volatility		21.6	%		24.4	%		25.6	%
	Dividend yield		3.0	%		3.0	%		3.0	%
Texaco plans:
	Expected life in years		2			2			2
	Risk-free interest rate		1.6	%		3.9	%		6.4	%
	Volatility		24.1	%		25.9	%		33.8	%
	Dividend yield		3.1	%		3.1	%		3.0	%

FS-42

NOTE 20. STOCK OPTIONS – Continued

The Black-Scholes weighted-average fair value of the ChevronTexaco options granted during 2002, 2001 and 2000 was $18.59, $20.45 and $22.34 per share, respectively, and the weighted-average fair value of the SIP restored options granted during 2002 and the Texaco options granted during 2001 and 2000 was $10.29, $12.90 and $11.56 per share.

A summary of the status of stock options awarded under the company’s LTIP, as well as the former Texaco plans, for 2002, 2001 and 2000 follows:


	Options			Weighted-Average
	(thousands)			Exercise Price

Outstanding at December 31, 1999		18,923		$	73.99

Granted		3,763			77.18
Exercised		(1,460	)		53.99
Restored		456			78.42
Forfeited		(812	)		84.18

Outstanding at December 31, 2000		20,870		$	75.67

Granted		3,777			89.84
Exercised		(8,209	)		78.16
Restored		6,766			89.77
Forfeited		( 584	)		85.76

Outstanding at December 31, 2001		22,620		$	81.13

Granted		3,291			86.15
Exercised		(1,818	)		73.01
Restored		1,274			89.38
Forfeited		(745	)	$	88.10

Outstanding at December 31, 2002		24,622		$	82.66

Exercisable at December 31
2000		16,021		$	74.95
2001		19,028		$	79.64
2002		21,445		$	82.14

The following table summarizes information about stock options outstanding, including those from former Texaco plans, at December 31, 2002:


			Options Outstanding				Options Exercisable

			Weighted-
			Average		Weighted-				Weighted-
Range of	Number		Remaining		Average		Number		Average
Exercise	Outstanding		Contractual		Exercise		Exercisable		Exercise
Prices	(thousands)		Life (years)		Price		(thousands)		Price

$31 to $ 41		1		0.2	$	38.56		1	$	38.56
41 to 51		1,824		1.9		45.56		1,824		45.56
51 to 61		24		3.7		56.15		24		56.15
61 to 71		716		3.9		66.30		710		66.28
71 to 81		4,212		5.5		79.10		4,212		79.10
81 to 91		13,798		6.9		86.90		10,627		87.11
91 to 101		4,047		6.4		91.67		4,047		91.67

$31 to $101		24,622		6.1	$	82.66		21,445	$	82.14

NOTE 21.

OTHER CONTINGENCIES AND COMMITMENTS

Income Taxes The company estimates its income tax expense and liabilities annually. These liabilities generally are not finalized with the individual taxing authorities until several years after the end of the annual period for which income taxes have been estimated. The U.S. federal income tax liabilities have been settled through 1996 for ChevronTexaco (formerly Chevron), 1993 for ChevronTexaco Global Energy Inc. (formerly Caltex), and 1991 for Texaco. California franchise tax liabilities have been settled through 1991 for Chevron and 1987 for Texaco. Settlement of open tax years, as well as tax issues in other countries where the company conducts its businesses, is not expected to have a material effect on the consolidated financial position or liquidity of the company, and in the opinion of management, adequate provision has been made for income and franchise taxes for all years under examination or subject to future examination.

Guarantees At December 31, 2002, the company and its subsidiaries provide guarantees, either directly or indirectly, of $1,038 for notes and other contractual obligations of affiliated companies and $806 for third parties, as discussed by major category below. There are no amounts being carried as liabilities for the company’s obligations under these guarantees.

Of the guarantees provided to affiliates, $775 relate to borrowings for capital projects or general corporate purposes. These guarantees were undertaken to achieve lower interest rates and generally cover the construction period of the capital projects. Approximately 50 percent of the amounts guaranteed will expire within the 2003–2006 period, with the remaining guarantees expiring by the end of 2015. Under the terms of the guarantees, the company would be required to perform should an affiliate be in default of its loan terms, generally for the full amounts disclosed. There are no recourse provisions, and no assets are held as collateral for these guarantees.

The company provides guarantees of $263 relating to obligations in connection with pricing of power purchase agreements for certain of its cogeneration affiliates. Under the terms of these guarantees, the company may be required to make payments under certain conditions if the affiliates do not perform under the agreements. There are no provisions for recourse to third parties, and no assets are held as collateral for these pricing guarantees.

Guarantees of $437 have been provided to third parties, including approximately $100 of construction loans to host governments in the company’s international upstream operations. The remaining guarantees of $337 were provided principally as conditions of sale of the company’s interest in certain operations, to provide a source of liquidity to the guaranteed parties and in connection with company marketing programs. No amounts of the company’s obligations under these guarantees are recorded as liabilities. Approximately half of the total amounts guaranteed will expire in 2003, with the remainder expiring after 2007. The company would be required to perform under the terms of the guarantees should an entity be in default of its loan or contract terms, generally for the full amounts disclosed. Approximately $200 of the guarantees have recourse provisions that enable the company to recover any payments made under the terms of the guarantees from securities held over the guaranteed parties’ assets.

Guarantees of $369 relate to Equilon debt and leases. In connection with the February 2002 disposition of its interest in Equilon, Shell Oil Company agreed to indemnify the company against any claims arising out of these guarantees. The company has not recorded a liability for these guarantees. Guarantees on approximately 30 percent of the debt and leases will expire within the 2003–2007 period, with the guarantees of the remaining amounts expiring by 2024.

Indemnities The company also provided certain indemnities of contingent liabilities of Equilon and Motiva to Shell Oil Com-

FS-43

NOTE 21. OTHER CONTINGENCIES AND COMMITMENTS – Continued

pany Saudi Refining Inc. in connection with the February 2002 sale of the company’s interests in those investments. The indemnities cover contingent general liabilities, certain contingent environmental liabilities and liabilities associated with the Unocal patent litigation. The company would be required to perform should the contingent general liabilities become actual liabilities within 18 months of the sale and could be required to make maximum future payments of $300. The company has not recorded liabilities for these contingencies. There are no recourse provisions enabling recovery of any amounts from third parties nor are any assets held as collateral. Within five years of the February 2002 sale, at the buyer’s option, the company also may be required to purchase certain assets from Shell Oil Company for their net book value, as determined at the time of the company’s purchase.

Securitization In other off-balance-sheet arrangements, the company securitizes certain retail and trade accounts receivable in its downstream business through the use of qualifying special purpose entities (SPEs). At December 31, 2002, approximately $1,000, representing about 11 percent of ChevronTexaco’s total current accounts receivables balance, were securitized. ChevronTexaco’s total estimated financial exposure under these arrangements at December 31, 2002, was approximately $75. These arrangements have the effect of accelerating ChevronTexaco’s collection of the securitized amounts. In the event of the SPEs experiencing major defaults in the collection of receivables, ChevronTexaco would have no loss exposure connected with third-party investments in these securitization arrangements.

Long-Term Unconditional Purchase Obligations and Commitments, Throughput Agreements and Take-or-Pay Agreements The company and its subsidiaries have certain other contingent liabilities relating to long-term unconditional purchase obligations and commitments, throughput agreements, 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, utilities, and petroleum products, to be used or sold in the ordinary course of the company’s business. The aggregate amounts of required payments under these various commitments are 2003 – $1,320; 2004 – $1,257; 2005 – $1,274; 2006 – $1,109; 2007 – $1,096; 2008 and after – $2,798. Total payments under the agreements were $1,188 in 2002, $1,509 in 2001 and $1,506 in 2000. The most significant take-or-pay agreement calls for the company to purchase approximately 55,000 barrels per day of refined products from an equity affiliate refiner in Thailand. This purchase agreement is in conjunction with the financing of a refinery owned by the affiliate and expires in 2009. The future estimated commitments under this contract are: 2003 – $800; 2004 – $800; 2005 – $900; 2006 – $900; 2007 – $900; 2008 and 2009 – $1,800.

Minority Interests The company has commitments related to preferred shares of subsidiary companies, which are accounted for as minority interest. MVP Production Inc., a subsidiary, has variable rate cumulative preferred shares of $75 owned by one minority holder. The shares are voting and are redeemable in 2003. Texaco Capital LLC, a wholly owned finance subsidiary, has issued $65 of Deferred Preferred Shares, Series C. Dividends amounting to $59 on Series C, at a rate of 7.17 percent compounded annually, will be paid at the redemption date of February 28, 2005, unless earlier redemption occurs. Early redemption may result upon the occurrence of certain specific events.

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 chemical or petroleum substances, including MTBE, by the company or other parties. Such contingencies may exist for various sites, including but not limited to: Superfund sites and refineries, oil fields, service stations, terminals, and land development areas, whether operating, closed or sold. The amount of such future cost is indeterminable 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. While 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 chemicals concerns.

The company believes it has no material market or credit risks to its operations, financial position or liquidity as a result of its commodities and other derivatives activities, including forward exchange contracts and interest rate swaps. However, the results of operations and the financial position of certain equity affiliates may be affected by their business activities involving the use of derivative instruments.

Global Operations Areas in which the company and its affiliates have significant operations include the United States of America, Canada, Australia, the United Kingdom, Norway, Denmark, France, Partitioned Neutral Zone between Kuwait and Saudi Arabia, Republic of Congo, Angola, Nigeria, Chad, Equatorial Guinea, Democratic Republic of Congo, South Africa,

FS-44

NOTE 21. OTHER CONTINGENCIES AND COMMITMENTS – Continued

Indonesia, Papua New Guinea, the Philippines, Singapore, China, Thailand, Venezuela, Argentina, Brazil, Colombia, Trinidad and Tobago and South Korea. The company’s Tengizchevroil affiliate operates in Kazakhstan. The company’s Chevron Phillips Chemical Company LLC affiliate manufactures and markets a wide range of petrochemicals and plastics on a worldwide basis, with manufacturing facilities in existence or under construction in the United States, Puerto Rico, Singapore, China, South Korea, Saudi Arabia, Qatar, Mexico and Belgium. The company’s Dynegy affiliate has operations in the United States, Canada, and the United Kingdom and other European countries.

The company’s operations, particularly exploration and production, can be affected by other changing economic, regulatory and political environments in the various countries in which it operates, including the United States. For instance, in December 2002, Caltex Oil (SA) (Pty) Limited (“Caltex Oil (SA)”) announced the signing of a shareholders agreement with a South African consortium of Black Economic Empowerment partners. The agreement is intended to ultimately provide the consortium a 25 percent equity interest in all aspects of Caltex’s operations in South Africa. It is uncertain as to whether any additional actions will be taken by host governments in other countries to increase public ownership of the company’s partially- or wholly-owned businesses.

In certain locations, host 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 or strained relations between a host 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 Redetermination For oil and gas producing operations, ownership agreements may provide for periodic reassessments of equity interests in estimated oil and 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 ChevronTexaco’s interests in four producing zones at the Naval Petroleum Reserve at Elk Hills in 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. ChevronTexaco currently estimates its maximum possible net before-tax liability at less than $200. At the same time, a possible maximum net amount that could be owed to ChevronTexaco is estimated at more than $50. The timing of the settlement and the exact amount within this range of estimates are uncertain.

NOTE 22.

EARNINGS PER SHARE

Basic earnings per share (EPS) includes the effects of deferrals of salary and other compensation awards that are invested in ChevronTexaco stock units by certain officers and employees of the company and is based upon net income less preferred stock dividend requirements. Diluted EPS includes the effects of these deferrals as well as the dilutive effects of outstanding stock options awarded under the company’s stock option programs (see Note 20, “Stock Options”). The following table sets forth the computation of basic and diluted EPS:


	2002						2001							2000

	Net		Shares		Per-Share		Net			Shares		Per-Share		Net			Shares		Per-Share
	Income		(millions)		Amount		Income			(millions)		Amount		Income			(millions)		Amount

Net income	$	1,132					$	3,288						$	7,727
Weighted-average common shares outstanding				1,060.7							1,059.3							1,066.6
Dividend equivalents paid on Chevron stock units		3						2							2
Deferred awards held as Chevron stock units				0.8							0.8							0.9
Preferred stock dividends		–						(6	)						(15	)

Basic EPS Computation	$	1,135		1,061.5	$	1.07	$	3,284			1,060.1	$	3.10	$	7,714			1,067.5	$	7.23
Dilutive effects of stock options, restricted stock and convertible debentures		2		1.9				4			2.8				3			2.4

Diluted EPS Computation	$	1,137		1,063.4	$	1.07	$	3,288			1,062.9	$	3.09	$	7,717			1,069.9	$	7.21

FS-45

QUARTERLY RESULTS AND STOCK MARKET DATA

Unaudited


		2002												2001

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 revenues¹		$	26,943		$	25,681		$	25,223		$	20,844		$	21,239		$	25,430		$	28,883		$	28,857
Income (loss) from equity affiliates			111			(193	)		81			112			(38	)		320			574			288
Other income			4			15			29			199			259			217			89			127

TOTAL REVENUES AND OTHER INCOME			27,058			25,503			25,333			21,155			21,460			25,967			29,546			29,272

COSTS AND OTHER DEDUCTIONS
Purchased crude oil and products, operating and other expenses			19,462			18,187			17,681			14,513			15,634			17,502			20,267			19,819
Depreciation, depletion and amortization			1,271			1,514			1,241			1,205			3,562			1,172			1,168			1,157
Taxes other than on income¹			4,403			4,369			4,137			3,780			3,556			4,023			3,793			3,784
Merger-related expenses			163			111			119			183			1,407			83			48			25
Write-down of equity affiliates			–			1,230			702			–			–			–			–			–
Minority interests			22			13			10			12			31			18			34			38
Interest and debt expense			141			117			160			147			171			186			217			259

TOTAL COSTS AND OTHER DEDUCTIONS			25,462			25,541			24,050			19,840			24,361			22,984			25,527			25,082

INCOME (LOSS) BEFORE INCOME TAX			1,596			(38	)		1,283			1,315			(2,901	)		2,983			4,019			4,190
INCOME TAX EXPENSE (CREDIT)			692			866			876			590			(526	)		1,218			1,911			1,757

NET INCOME (LOSS) BEFORE EXTRAORDINARY ITEM		$	904		$	(904	)	$	407		$	725		$	(2,375	)	$	1,765		$	2,108		$	2,433
EXTRAORDINARY LOSS, NET OF INCOME TAX			–			–			–			–			(147	)		(496	)		–			–

NET INCOME (LOSS)²		$	904		$	(904	)	$	407		$	725		$	(2,522	)	$	1,269		$	2,108		$	2,433

NET INCOME (LOSS) PER SHARE BEFORE EXTRAORDINARY ITEM – BASIC		$	0.85		$	(0.85	)	$	0.39		$	0.68		$	(2.24	)	$	1.66		$	1.99		$	2.30
– DILUTED		$	0.85		$	(0.85	)	$	0.39		$	0.68		$	(2.24	)	$	1.66		$	1.99		$	2.29

NET INCOME (LOSS) PER SHARE – BASIC		$	0.85		$	(0.85	)	$	0.39		$	0.68		$	(2.38	)	$	1.19		$	1.99		$	2.30
	– DILUTED	$	0.85		$	(0.85	)	$	0.39		$	0.68		$	(2.38	)	$	1.19		$	1.99		$	2.29

DIVIDENDS PAID PER SHARE³		$	0.70		$	0.70		$	0.70		$	0.70		$	0.70		$	0.65		$	0.65		$	0.65
COMMON STOCK PRICE RANGE – HIGH		$	75.43		$	88.93		$	91.04		$	91.60		$	93.77		$	93.61		$	98.49		$	93.45
	– LOW	$	65.41		$	65.64		$	83.55		$	80.80		$	82.00		$	78.60		$	84.59		$	78.44

¹ Includes consumer excise taxes:		$	1,785		$	1,782		$	1,749		$	1,690		$	1,633		$	1,680		$	1,624		$	1,609
² Net charges for special items and merger effects included in NET INCOME (LOSS):		$	(161	)	$	(2,141	)	$	(826	)	$	(206	)	$	(3,020	)	$	(445	)	$	(36	)	$	(21	)
³ Chevron dividend pre-merger

The company’s common stock is listed on the New York Stock Exchange (trading symbol: CVX) and on the Pacific Exchange. As of March 7, 2003, stockholders of record numbered approximately 247,000. Through October 9, 2001, the common stock traded under the name of Chevron Corporation (trading symbol: CHV).

There are no restrictions on the company’s ability to pay dividends.

FS-46

FIVE-YEAR FINANCIAL SUMMARY


Millions of dollars, except per-share amounts		2002		2001			2000		1999		1998

COMBINED STATEMENT OF INCOME DATA
REVENUES AND OTHER INCOME
Total sales and other operating revenues		$	98,691	$	104,409		$	117,095	$	84,004	$	71,937
Income from equity affiliates and other income			358		1,836			2,035		1,709		1,321

TOTAL REVENUES AND OTHER INCOME			99,049		106,245			119,130		85,713		73,258
TOTAL COSTS AND OTHER DEDUCTIONS			94,893		97,954			105,081		79,901		70,422

INCOME BEFORE INCOME TAXES			4,156		8,291			14,049		5,812		2,836
INCOME TAX EXPENSE			3,024		4,360			6,322		2,565		919

INCOME BEFORE EXTRAORDINARY ITEM		$	1,132	$	3,931		$	7,727	$	3,247	$	1,917
EXTRAORDINARY LOSS, NET OF INCOME TAX			–		(643	)		–		–		–

NET INCOME		$	1,132	$	3,288		$	7,727	$	3,247	$	1,917

NET INCOME PER SHARE BEFORE EXTRAORDINARY ITEM – BASIC		$	1.07	$	3.71		$	7.23	$	3.01	$	1.76
	– DILUTED	$	1.07	$	3.70		$	7.21	$	3.00	$	1.75

NET INCOME PER SHARE – BASIC		$	1.07	$	3.10		$	7.23	$	3.01	$	1.76
	– DILUTED	$	1.07	$	3.09		$	7.21	$	3.00	$	1.75

CASH DIVIDENDS PER SHARE*		$	2.80	$	2.65		$	2.60	$	2.48	$	2.44

COMBINED BALANCE SHEET DATA (AT DECEMBER 31)
Current assets		$	17,776	$	18,327		$	17,913	$	17,043	$	14,157
Noncurrent assets			59,583		59,245			59,708		58,337		55,967

TOTAL ASSETS			77,359		77,572			77,621		75,380		70,124

Short-term debt			5,358		8,429			3,094		6,063		5,579
Other current liabilities			14,518		12,225			13,567		11,620		9,480
Long-term debt and capital lease obligations			10,911		8,989			12,821		13,145		11,675
Other noncurrent liabilities			14,968		13,971			14,770		14,761		14,523

TOTAL LIABILITIES			45,755		43,614			44,252		45,589		41,257

STOCKHOLDERS’ EQUITY		$	31,604	$	33,958		$	33,369	$	29,791	$	28,867

*Chevron dividend pre-merger.

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES

Unaudited

In accordance with Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities” (FAS 69), 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, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows. The Africa geographic area includes activities principally in Nigeria, Angola, Chad, Republic of Congo and Democratic Republic of Congo. The Asia-Pacific geographic area includes activities principally in Australia, China, Indonesia, Kazakhstan, Partitioned Neutral Zone between Kuwait and Saudi Arabia, Papua New Guinea, the Philippines and Thailand. The “Other” geographic category includes activities in the United Kingdom, Canada, Denmark, the Netherlands, Norway, Trinidad and Tobago, Colombia, Venezuela, Brazil, Argentina, and other countries. Amounts shown for affiliated companies are ChevronTexaco’s 50 percent equity share of Tengizchevroil (TCO), an exploration and production partnership operating in the Republic of Kazakhstan, and a 30 percent equity share of Hamaca, an exploration and production partnership operating in Venezuela, beginning in 2000. The company increased its ownership in TCO from 45 percent to 50 percent in January 2001.

FS-47

TABLE I — COSTS INCURRED IN EXPLORATION, PROPERTY ACQUISITIONS AND DEVELOPMENT¹


		Consolidated Companies										Affiliated Companies

Millions of dollars		U.S.		Africa		Asia-Pacific		Other		Total		TCO²		Hamaca		Worldwide

YEAR ENDED DECEMBER 31, 2002
Exploration
	Wells	$	477	$	131	$	48	$	92	$	748	$	–	$	–	$	748
	Geological and geophysical		95		69		43		53		260		–		–		260
	Rentals and other		35		29		38		43		145		–		–		145

	Total exploration		607		229		129		188		1,153		–		–		1,153

Property acquisitions
	Proved³		106		–		–		–		106		–		–		106
	Unproved		51		6		2		1		60		–		–		60

	Total property acquisitions		157		6		2		1		166		–		–		166

Development			1,091		661		1,017		926		3,695		447		353		4,495

TOTAL COSTS INCURRED		$	1,855	$	896	$	1,148	$	1,115	$	5,014	$	447	$	353	$	5,814

YEAR ENDED DECEMBER 31, 2001
Exploration
	Wells	$	620	$	172	$	186	$	197	$	1,175	$	–	$	–	$	1,175
	Geological and geophysical		46		35		42		65		188		–		–		188
	Rentals and other		65		48		15		98		226		–		–		226

	Total exploration		731		255		243		360		1,589		–		–		1,589

Property acquisitions
	Proved³		25		4		–		–		29		362		–		391
	Unproved		50		38		12		–		100		108		–		208

	Total property acquisitions		75		42		12		–		129		470		–		599

Development			1,754		551		1,168		494		3,967		266		275		4,508

TOTAL COSTS INCURRED		$	2,560	$	848	$	1,423	$	854	$	5,685	$	736	$	275	$	6,696

YEAR ENDED DECEMBER 31, 2000
Exploration
	Wells	$	526	$	139	$	179	$	63	$	907	$	–	$	–	$	907
	Geological and geophysical		60		35		67		105		267		–		–		267
	Rentals and other		73		43		55		83		254		–		–		254

	Total exploration		659		217		301		251		1,428		–		–		1,428

Property acquisitions
	Proved³		162		1		278		1		442		–		–		442
	Unproved		66		9		–		184		259		–		–		259

	Total property acquisitions		228		10		278		185		701		–		–		701

Development			1,453		435		1,067		718		3,673		240		–		3,913

TOTAL COSTS INCURRED		$	2,340	$	662	$	1,646	$	1,154	$	5,802	$	240	$	–	$	6,042

¹		Includes costs incurred whether capitalized or expensed. Excludes support equipment expenditures.
²		Includes acquisition costs for an additional 5 percent interest in 2001.
³		Includes wells, equipment and facilities associated with proved reserves. Does not include properties acquired through property exchanges.

FS-48

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES – Continued

Unaudited

TABLE II – CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES


	Consolidated Companies										Affiliated Companies

Millions of dollars	U.S.		Africa		Asia-Pacific		Other		Total		TCO		Hamaca*		Worldwide

AT DECEMBER 31, 2002
Unproved properties	$	1,362	$	330	$	259	$	1,134	$	3,085	$	108	$	–	$	3,193
Proved properties and related producing assets		37,441		5,993		10,172		10,367		63,973		1,975		144		66,092
Support equipment		774		447		2,188		377		3,786		338		–		4,124
Deferred exploratory wells		106		130		103		111		450		–		–		450
Other uncompleted projects		502		1,406		1,597		497		4,002		676		683		5,361

GROSS CAPITALIZED COSTS		40,185		8,306		14,319		12,486		75,296		3,097		827		79,220

Unproved properties valuation		961		80		90		277		1,408		24		–		1,432
Proved producing properties – depreciation and depletion		27,115		3,251		5,392		5,457		41,215		270		9		41,494
Future abandonment and restoration		999		508		304		392		2,203		24		–		2,227
Support equipment depreciation		557		289		1,145		223		2,214		138		–		2,352

Accumulated provisions		29,632		4,128		6,931		6,349		47,040		456		9		47,505

NET CAPITALIZED COSTS	$	10,553	$	4,178	$	7,388	$	6,137	$	28,256	$	2,641	$	818	$	31,715

AT DECEMBER 31, 2001
Unproved properties	$	1,178	$	304	$	565	$	1,168	$	3,215	$	108	$	–	$	3,323
Proved properties and related producing assets		35,665		5,487		10,332		9,435		60,919		1,878		88		62,885
Support equipment		766		390		2,177		313		3,646		293		–		3,939
Deferred exploratory wells		91		390		128		79		688		–		–		688
Other uncompleted projects		1,080		750		654		472		2,956		245		376		3,577

GROSS CAPITALIZED COSTS		38,780		7,321		13,856		11,467		71,424		2,524		464		74,412

Unproved properties valuation		807		86		73		222		1,188		–		–		1,188
Proved producing properties – depreciation and depletion		25,844		2,998		4,733		4,827		38,402		219		3		38,624
Future abandonment and restoration		1,016		449		281		342		2,088		19		–		2,107
Support equipment depreciation		452		160		1,122		162		1,896		123		–		2,019

Accumulated provisions		28,119		3,693		6,209		5,553		43,574		361		3		43,938

NET CAPITALIZED COSTS	$	10,661	$	3,628	$	7,647	$	5,914	$	27,850	$	2,163	$	461	$	30,474

AT DECEMBER 31, 2000
Unproved properties	$	1,233	$	176	$	540	$	1,219	$	3,168	$	378	$	63	$	3,609
Proved properties and related producing assets		34,587		5,050		8,905		8,702		57,244		1,158		71		58,473
Support equipment		721		366		2,126		272		3,485		254		42		3,781
Deferred exploratory wells		182		354		120		126		782		–		–		782
Other uncompleted projects		741		693		674		605		2,713		136		–		2,849

GROSS CAPITALIZED COSTS		37,464		6,639		12,365		10,924		67,392		1,926		176		69,494

Unproved properties valuation		317		69		66		170		622		–		–		622
Proved producing properties – depreciation and depletion		23,528		2,700		3,986		3,940		34,154		131		–		34,285
Future abandonment and restoration		1,071		413		274		317		2,075		13		–		2,088
Support equipment depreciation		380		141		1,224		172		1,917		97		1		2,015

Accumulated provisions		25,296		3,323		5,550		4,599		38,768		241		1		39,010

NET CAPITALIZED COSTS	$	12,168	$	3,316	$	6,815	$	6,325	$	28,624	$	1,685	$	175	$	30,484

Existing costs were transferred from a consolidated subsidiary to an affiliate at year-end 2000. Previously reported in Consolidated Companies – Other.

FS-49

TABLE III – RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES¹

The company’s results of operations from oil and gas producing activities for the years 2002, 2001 and 2000 are shown in the following table. Net income from exploration and production activities as reported on pages FS-4 and FS-5 reflects income taxes computed on an effective rate basis. In accordance with FAS No. 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 pages FS-4 and FS-5.


		Consolidated Companies															Affiliated Companies

Millions of dollars		U.S.			Africa			Asia-Pacific			Other			Total			TCO			Hamaca			Worldwide

YEAR ENDED DECEMBER 31, 2002
Revenues from net production
	Sales	$	2,737		$	1,121		$	1,410		$	2,080		$	7,348		$	955		$	44		$	8,347
	Transfers		4,425			1,663			3,090			1,202			10,380			–			–			10,380

	Total		7,162			2,784			4,500			3,282			17,728			955			44			18,727
Production expenses			(2,321	)		(439	)		(958	)		(683	)		(4,401	)		(166	)		(4	)		(4,571	)
Proved producing properties: depreciation, depletion and abandonment provision			(1,577	)		(352	)		(673	)		(694	)		(3,296	)		(91	)		(5	)		(3,392	)
Exploration expenses			(216	)		(106	)		(109	)		(160	)		(591	)		–			–			(591	)
Unproved properties valuation			(35	)		(14	)		(9	)		(67	)		(125	)		–			–			(125	)
Other (expense) income²			(359	)		(179	)		(399	)		59			(878	)		(5	)		(12	)		(895	)

	Results before income taxes		2,654			1,694			2,352			1,737			8,437			693			23			9,153
Income tax expense			(933	)		(1,202	)		(1,434	)		(677	)		(4,246	)		(208	)		–			(4,454	)

RESULTS OF PRODUCING OPERATIONS		$	1,721		$	492		$	918		$	1,060		$	4,191		$	485		$	23		$	4,699

YEAR ENDED DECEMBER 31, 2001
Revenues from net production
	Sales	$	5,024		$	1,147		$	1,264		$	2,181		$	9,616		$	673		$	6		$	10,295
	Transfers		3,991			1,913			2,796			1,107			9,807			–			–			9,807

	Total		9,015			3,060			4,060			3,288			19,423			673			6			20,102
Production expenses			(2,442	)		(447	)		(856	)		(687	)		(4,432	)		(142	)		(6	)		(4,580	)
Proved producing properties: depreciation, depletion and abandonment provision			(1,614	)		(344	)		(498	)		(658	)		(3,114	)		(80	)		(1	)		(3,195	)
Exploration expenses			(424	)		(132	)		(234	)		(298	)		(1,088	)		–			–			(1,088	)
Unproved properties valuation			(38	)		(33	)		(9	)		(77	)		(157	)		–			–			(157	)
Other (expense) income²			(1,653	)		(110	)		(209	)		(5	)		(1,977	)		9			2			(1,966	)

	Results before income taxes		2,844			1,994			2,254			1,563			8,655			460			1			9,116
Income tax expense			(1,074	)		(1,455	)		(1,432	)		(620	)		(4,581	)		(138	)		–			(4,719	)

RESULTS OF PRODUCING OPERATIONS		$	1,770		$	539		$	822		$	943		$	4,074		$	322		$	1		$	4,397

YEAR ENDED DECEMBER 31, 2000
Revenues from net production
	Sales	$	5,878		$	2,804		$	1,404		$	2,310		$	12,396		$	710		$	–		$	13,106
	Transfers		4,387			650			3,203			1,409			9,649			–			–			9,649

	Total		10,265			3,454			4,607			3,719			22,045			710			–			22,755
Production expenses			(2,182	)		(405	)		(865	)		(727	)		(4,179	)		(114	)		–			(4,293	)
Proved producing properties: depreciation, depletion and abandonment provision			(1,558	)		(337	)		(585	)		(676	)		(3,156	)		(53	)		–			(3,209	)
Exploration expenses			(395	)		(166	)		(176	)		(217	)		(954	)		–			–			(954	)
Unproved properties valuation			(49	)		(16	)		(7	)		(75	)		(147	)		–			–			(147	)
Other (expense) income²			(631	)		45			(13	)		237			(362	)		(56	)		–			(418	)

	Results before income taxes		5,450			2,575			2,961			2,261			13,247			487			–			13,734
Income tax expense			(1,927	)		(1,974	)		(1,724	)		(984	)		(6,609	)		(146	)		–			(6,755	)

RESULTS OF PRODUCING OPERATIONS		$	3,523		$	601		$	1,237		$	1,277		$	6,638		$	341		$	–		$	6,979

¹		The value of owned production consumed 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		Includes net sulfur income, foreign currency transaction gains and losses, certain significant impairment write-downs, miscellaneous expenses, etc. Also includes net income from related oil and gas activities that do not have oil and gas reserves attributed to them (for example, net income from technical and operating service agreements) and items identified in the Management’s Discussion and Analysis on pages FS-4 and FS-5.

FS-50

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES – Continued

Unaudited

TABLE IV – RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES – UNIT PRICES AND COSTS^1,2


		Consolidated Companies										Affiliated Companies

		U.S.		Africa		Asia-Pacific		Other		Total		TCO		Hamaca		Worldwide

YEAR ENDED DECEMBER 31, 2002
	Average sales prices
	Liquids, per barrel	$	21.34	$	24.33	$	21.76	$	23.31	$	22.36	$	18.16	$	18.91	$	22.03
	Natural gas, per thousand cubic feet		2.89		0.04		2.67		2.11		2.62		0.57		–		2.55
Average production costs, per barrel			6.41		3.70		4.41		4.05		5.08		2.79		1.58		4.92

YEAR ENDED DECEMBER 31, 2001
	Average sales prices
	Liquids, per barrel	$	21.33	$	23.70	$	20.11	$	22.59	$	21.68	$	13.31	$	12.45	$	21.08
	Natural gas, per thousand cubic feet		4.38		0.04		3.04		2.51		3.78		0.47		–		3.69
Average production costs, per barrel			6.35		3.39		4.20		4.17		5.01		2.54		13.09		4.86

YEAR ENDED DECEMBER 31, 2000
	Average sales prices
	Liquids, per barrel	$	25.61	$	26.58	$	22.97	$	27.34	$	25.35	$	20.14	$	–	$	25.09
	Natural gas, per thousand cubic feet		3.87		0.03		2.57		2.29		3.39		0.13		–		3.33
Average production costs, per barrel			5.23		3.04		4.17		4.49		4.55		2.91		–		4.48

¹		The value of owned production consumed 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 crude oil-equivalent gas (OEG) barrels at a rate of 6 MCF = 1 OEG barrel.

TABLE V – RESERVE QUANTITY INFORMATION

The company’s estimated net proved underground oil and gas reserves and changes thereto for the years 2002, 2001 and 2000 are shown in the following table. Proved reserves are estimated by company asset teams composed of earth scientists and reservoir engineers. These proved reserve estimates are reviewed annually by the company’s Reserves Advisory Committee to ensure that rigorous professional standards and the reserves definitions prescribed by the U.S. Securities and Exchange Commission are consistently applied throughout the company.

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. 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 do not include additional quantities that may result from extensions of currently proved areas or from applying secondary or tertiary recovery processes not yet tested and determined to be economic.

Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods.

“Net” reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at the time of the estimate.

FS-51

TABLE V – RESERVE QUANTITY INFORMATION – CONTINUED

ChevronTexaco operates, under a risked service agreement, Venezuela’s Block LL-652, located in the northeast section of Lake Maracaibo. ChevronTexaco is accounting for LL-652 as an oil and gas activity and, at December 31, 2002, had recorded 17 million barrels of proved crude oil reserves.

No reserve quantities have been recorded for the company’s other service agreements – the Boscan Field in Venezuela and a long-term purchase agreement associated with a service agreement for the Chuchupa Field in Colombia for the period 2005–2016.


NET PROVED RESERVES OF CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS

		Millions of barrels

		Consolidated Companies															Affiliates

								Asia-															World-
		U.S.			Africa			Pacific			Other			Total			TCO			Hamaca			wide

RESERVES AT JANUARY 1, 2000			2,854			1,344			1,887			946			7,031			1,233			–			8,264
Changes attributable to:
	Revisions		(26	)		48			109			14			145			105			–			250
	Improved recovery		83			20			69			9			181			–			–			181
	Extensions and discoveries		85			92			40			57			274			7			374			655
	Purchases¹		8			131			–			3			142			–			–			142
	Sales²		(146	)		–			–			(96	)		(242	)		–			–			(242	)
	Production		(244	)		(130	)		(211	)		(111	)		(696	)		(35	)		–			(731	)

RESERVES AT DECEMBER 31, 2000			2,614			1,505			1,894			822			6,835			1,310			374			8,519
Changes attributable to:
	Revisions		(225	)		45			135			(60	)		(105	)		46			(2	)		(61	)
	Improved recovery		79			35			47			51			212			–			–			212
	Extensions and discoveries		67			88			34			40			229			88			115			432
	Purchases¹		1			–			–			–			1			146			–			147
	Sales²		(11	)		–			–			–			(11	)		–			–			(11	)
	Production		(224	)		(129	)		(204	)		(108	)		(665	)		(49	)		–			(714	)

RESERVES AT DECEMBER 31, 2001			2,301			1,544			1,906			745			6,496			1,541			487			8,524
Changes attributable to:
	Revisions		(116	)		164			(114	)		17			(49	)		199			–			150
	Improved recovery		99			82			22			36			239			–			–			239
	Extensions and discoveries		48			301			85			8			442			–			–			442
	Purchases¹		8			–			–			–			8			–			–			8
	Sales²		(3	)		–			–			–			(3	)		–			–			(3	)
	Production		(220	)		(115	)		(195	)		(109	)		(639	)		(51	)		(2	)		(692	)

RESERVES AT DECEMBER 31, 2002			2,117			1,976			1,704			697			6,494			1,689			485			8,668

Developed reserves

	At January 1, 2000		2,266			980			1,314			636			5,196			790			–			5,986
	At December 31, 2000		2,083			976			1,276			538			4,873			795			–			5,668
	At December 31, 2001		1,887			923			1,491			517			4,818			1,007			38			5,863
	At December 31, 2002		1,766			1,042			1,297			529			4,634			999			63			5,696

[Additional columns below]

[Continued from above table, first column(s) repeated]

NET PROVED RESERVES OF NATURAL GAS

Billions of cubic feet

Consolidated Companies Affiliates

Asia- World-

U.S. Africa Pacific Other Total TCO Hamaca wide

RESERVES AT JANUARY 1, 2000
7,993 326 4,088 3,175 15,582 1,581 – 17,163

Changes attributable to:

Revisions
92 450 308 67 917 126 – 1,043

Improved recovery
17 – – 5 22 – – 22

Extensions and discoveries
990 1 236 143 1,370 9 33 1,412

Purchases¹
262 12 – – 274 – – 274

Sales²
(367 ) – – (70 ) (437 ) – – (437 )

Production
(1,064 ) (17 ) (190 ) (329 ) (1,600 ) (33 ) – (1,633 )

RESERVES AT DECEMBER 31, 2000
7,923 772 4,442 2,991 16,128 1,683 33 17,844

Changes attributable to:

Revisions
(20 ) 780 330 (10 ) 1,080 317 – 1,397

Improved recovery
24 7 11 16 58 – – 58

Extensions and discoveries
587 329 164 445 1,525 130 9 1,664

Purchases¹
41 – 6 6 53 187 – 240

Sales²
(180 ) – – – (180 ) – – (180 )

Production
(988 ) (16 ) (194 ) (360 ) (1,558 ) (55 ) – (1,613 )

RESERVES AT DECEMBER 31, 2001
7,387 1,872 4,759 3,088 17,106 2,262 42 19,410

Changes attributable to:

Revisions
(598 ) 277 390 92 161 293 1 455

Improved recovery
21 42 4 10 77 – – 77

Extensions and discoveries
395 134 260 103 892 – – 892

Purchases¹
93 – 8 – 101 – – 101

Sales²
(3 ) – – – (3 ) – – (3 )

Production
(878 ) (27 ) (257 ) (369 ) (1,531 ) (66 ) – (1,597 )

RESERVES AT DECEMBER 31, 2002
6,417 2,298 5,164 2,924 16,803 2,489 43 19,335

Developed reserves

At January 1, 2000
6,733 276 2,342 2,368 11,719 1,011 – 12,730

At December 31, 2000
6,408 294 3,108 2,347 12,157 1,019 – 13,176

At December 31, 2001
6,246 444 3,170 2,231 12,091 1,477 6 13,574

At December 31, 2002
5,636 582 3,196 2,157 11,571 1,474 6 13,051

¹ Includes reserves acquired through property exchanges.

² Includes reserves disposed of through property exchanges.

INFORMATION ON CANADIAN OIL SANDS NET PROVED RESERVES NOT INCLUDED ABOVE:

In addition to conventional liquids and natural gas proved reserves, ChevronTexaco has significant interests in proved oil sands reserves in Canada associated with the Athabasca project. For internal management purposes, ChevronTexaco views these reserves and their development as an integral part of total upstream operations. However, U.S. Securities and Exchange Commission regulations define these reserves as mining-related and not a part of conventional oil and gas reserves. Net proved oil sands reserves were 183 million barrels as of December 31, 2002. Production began in late 2002.

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-53.

FS-52

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES – Continued

Unaudited

TABLE VI – 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 No. 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. 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 No. 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.


	Consolidated Companies															Affiliated Companies

Millions of dollars	U.S.			Africa			Asia-Pacific			Other			Total			TCO			Hamaca			Worldwide

AT DECEMBER 31, 2002
Future cash inflows from production	$	77,912		$	52,513		$	59,550		$	26,531		$	216,506		$	52,457		$	9,777		$	278,740
Future production and development costs		(29,948	)		(9,889	)		(18,591	)		(7,838	)		(66,266	)		(10,336	)		(2,308	)		(78,910	)
Future income taxes		(16,231	)		(25,060	)		(17,781	)		(6,797	)		(65,869	)		(11,899	)		(2,540	)		(80,308	)

Undiscounted future net cash flows		31,733			17,564			23,178			11,896			84,371			30,222			4,929			119,522
10 percent midyear annual discount for timing of estimated cash flows		(13,872	)		(8,252	)		(9,971	)		(3,691	)		(35,786	)		(18,964	)		(3,581	)		(58,331	)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS	$	17,861		$	9,312		$	13,207		$	8,205		$	48,585		$	11,258		$	1,348		$	61,191

AT DECEMBER 31, 2001
Future cash inflows from production	$	54,238		$	28,019		$	43,389		$	20,432		$	146,078		$	29,433		$	5,922		$	181,433
Future production and development costs		(30,871	)		(10,106	)		(20,845	)		(8,873	)		(70,695	)		(8,865	)		(1,093	)		(80,653	)
Future income taxes		(7,981	)		(10,476	)		(9,858	)		(4,370	)		(32,685	)		(5,805	)		(1,642	)		(40,132	)

Undiscounted future net cash flows		15,386			7,437			12,686			7,189			42,698			14,763			3,187			60,648
10 percent midyear annual discount for timing of estimated cash flows		(6,882	)		(3,609	)		(5,857	)		(2,602	)		(18,950	)		(9,121	)		(2,433	)		(30,504	)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS	$	8,504		$	3,828		$	6,829		$	4,587		$	23,748		$	5,642		$	754		$	30,144

AT DECEMBER 31, 2000
Future cash inflows from production	$	127,945		$	34,856		$	47,351		$	27,426		$	237,578		$	30,350		$	3,917		$	271,845
Future production and development costs		(30,305	)		(8,023	)		(18,416	)		(7,466	)		(64,210	)		(7,250	)		(679	)		(72,139	)
Future income taxes		(33,614	)		(16,124	)		(13,245	)		(7,481	)		(70,464	)		(6,440	)		(1,101	)		(78,005	)

Undiscounted future net cash flows		64,026			10,709			15,690			12,479			102,904			16,660			2,137			121,701
10 percent midyear annual discount for timing of estimated cash flows		(27,747	)		(4,186	)		(6,764	)		(4,405	)		(43,102	)		(11,180	)		(1,431	)		(55,713	)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS	$	36,279		$	6,523		$	8,926		$	8,074		$	59,802		$	5,480		$	706		$	65,988

FS-53

TABLE VII – 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 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									Worldwide

Millions of dollars	2002			2001			2000			2002			2001			2000			2002			2001			2000

PRESENT VALUE AT JANUARY 1	$	23,748		$	59,802		$	41,750		$	6,396		$	6,186		$	4,100		$	30,144		$	65,988		$	45,850

Sales and transfers of oil and gas produced, net of production costs		(13,327	)		(15,161	)		(17,866	)		(829	)		(531	)		(596	)		(14,156	)		(15,692	)		(18,462	)
Development costs incurred		3,695			3,967			3,673			800			541			240			4,495			4,508			3,913
Purchases of reserves		181			40			2,055			–			778			–			181			818			2,055
Sales of reserves		(42	)		(366	)		(5,010	)		–			–			–			(42	)		(366	)		(5,010	)
Extensions, discoveries and improved recovery, less related costs		7,472			2,747			8,710			–			484			1,112			7,472			3,231			9,822
Revisions of previous quantity estimates		104			524			(428	)		917			400			1,284			1,021			924			856
Net changes in prices, development and production costs		41,044			(59,995	)		29,358			6,722			(2,457	)		457			47,766			(62,452	)		29,815
Accretion of discount		3,987			10,144			7,027			895			876			582			4,882			11,020			7,609
Net change in income tax		(18,277	)		22,046			(9,467	)		(2,295	)		119			(993	)		(20,572	)		22,165			(10,460	)

Net change for the year		24,837			(36,054	)		18,052			6,210			210			2,086			31,047			(35,844	)		20,138

PRESENT VALUE AT DECEMBER 31	$	48,585		$	23,748		$	59,802		$	12,606		$	6,396		$	6,186		$	61,191		$	30,144		$	65,988

FS-54

EXHIBIT INDEX


Exhibit No.			Description

	3	.1	Restated Certificate of Incorporation of ChevronTexaco Corporation, dated October 9, 2001, filed as Exhibit 3.1 to ChevronTexaco Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated herein by reference.
	3	.2*	By-Laws of ChevronTexaco Corporation, as amended September 26, 2001.
	4	.1	Rights Agreement dated as of November 23, 1998, between ChevronTexaco Corporation and ChaseMellon Shareholder Services L.L.C., as Rights Agent, filed as Exhibit 4.1 to ChevronTexaco Corporation’s Current Report on Form 8-K dated November 23, 1998, and incorporated herein by reference.
	4	.2	Amendment No. 1 to Rights Agreement dated as of October 15, 2000, between ChevronTexaco Corporation and ChaseMellon Shareholder Services L.L.C., as Rights Agent, filed as Exhibit 4.2 of the Amendment No. 1 on Form 8-A/ A filed by ChevronTexaco Corporation on December 7, 2000, and incorporated herein by reference.
	4	.3	Amendment No. 2 to Rights Agreement, dated as of November 19, 2002, between ChevronTexaco Corporation and Mellon Investor Services L.L.C., as Rights Agent, filed as Exhibit 4.3 of the Amendment No. 2 on Form 8-A/ A filed by ChevronTexaco Corporation on November 20, 2002, and incorporated herein by reference.
			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	ChevronTexaco Corporation Deferred Compensation Plan for Directors, as amended and restated effective January 1, 2001, filed as Exhibit 10.1 to ChevronTexaco Corporation’s Annual Report on Form 10-K for the year ended December 31, 2000, and incorporated herein by reference.
	10	.2	Management Incentive Plan of ChevronTexaco Corporation, as amended effective October 9, 2001, filed as Appendix A to ChevronTexaco Corporation’s Notice of Annual Meeting of Stockholders and Proxy Statement dated April 15, 2002, and incorporated herein by reference.
	10	.3	ChevronTexaco Corporation Excess Benefit Plan, amended and restated as of July 1, 1996, filed as Exhibit 10 to ChevronTexaco Corporation’s Report on Form 10-Q for the quarterly period ended March 31, 1997, and incorporated herein by reference.
	10	.4	ChevronTexaco Restricted Stock Plan for Non-Employee Directors, as amended and restated effective April 30, 1997, filed as Appendix A to ChevronTexaco Corporation’s Notice of Annual Meeting of Stockholders and Proxy Statement dated March 21, 1997, and incorporated herein by reference.
	10	.5	ChevronTexaco Corporation Long-Term Incentive Plan, including March 27, 2002 amendments, filed as Appendix B to ChevronTexaco Corporation’s Notice of Annual Meeting of Stockholders and Proxy Statement dated April 15, 2002, and incorporated herein by reference.
	10	.6	ChevronTexaco Corporation Deferred Compensation Plan for Management Employees, as amended and restated effective April 1, 2002, filed as Exhibit 10.1 to ChevronTexaco Corporation’s Report on Form 10-Q for the quarterly period ended March 31, 2002, and incorporated herein by reference.
	10	.7	Employment Agreement dated as of December 4, 2001 between ChevronTexaco Corporation and Glenn Tilton, filed as Exhibit 10.12 to ChevronTexaco Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated herein by reference.

E-1


Exhibit No.			Description

	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 ChevronTexaco Corporation’s Annual Report on Form 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 ChevronTexaco Corporation’s Annual Report on Form 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 ChevronTexaco Corporation’s Annual Report on Form 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 ChevronTexaco Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001, and incorporated herein by reference.
	10	.12*	ChevronTexaco Corporation 1998 Stock Option Program for U.S. Dollar Payroll Employees
	12	.1*	Computation of Ratio of Earnings to Fixed Charges (page E-3).
	21	.1*	Subsidiaries of ChevronTexaco Corporation (page E-4 to E-6).
	23	.1*	Consent of PricewaterhouseCoopers LLP (page E-7).
	23	.2*	Notice of inability to obtain Consent from Arthur Andersen LLP (page E-8)
	24	.1 to	Powers of Attorney for directors and certain officers of ChevronTexaco Corporation,
	24	.16*	authorizing the signing of the Annual Report on Form 10-K on their behalf.
	99	.1*	Definitions of Selected Financial Terms (page E-9).

* Filed herewith.

On October 9, 2001, the company changed its name from Chevron Corporation to ChevronTexaco Corporation. Filings with the Securities and Exchange Commission prior to that date may be found under the company’s former name.

Copies of above exhibits not contained herein are available, to any security holder upon written request to the Secretary’s Department, ChevronTexaco Corporation, 6001 Bollinger Canyon Road, San Ramon, California 94583.

E-2


	•	Operational excellence through safe, reliable, efficient and environmentally sound operations;

	•	Cost reduction by lowering unit costs through innovation and technology;

	•	Capital stewardship by investing in the best project opportunities and executing them successfully (safer, faster, and at lower cost); and

	•	Profitable growth through leadership in developing new business opportunities in both existing and new markets.


	•	Organizational Capability: Having the right people, processes and culture to achieve and sustain industry-leading performance in the four priorities described above.


⁽¹⁾	Net production excludes royalty interests owned by others.
⁽²⁾	Natural gas converted to oil-equivalent gas (OEG) barrels at 6 MCF = 1 OEG barrel.
⁽³⁾	Located between the Kingdom of Saudi Arabia and the State of Kuwait.
⁽⁴⁾	Affiliates include TCO in Kazakhstan and Hamaca in Venezuela.
⁽⁵⁾	Represents total field production under the Boscan operating service agreement in Venezuela.


⁽¹⁾	Gross acreage includes the total number of acres in all tracts in which the company has an interest. Net acreage is the sum of the company’s fractional interests in gross acreage.

⁽²⁾	Undeveloped acreage is acreage where wells have not been drilled or completed to permit commercial production, and may contain undeveloped proved reserves. Developed acreage is spaced or assignable to productive wells.


⁽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 are the sum of the company’s fractional interests in gross wells.


⁽¹⁾	mmbbls = millions of barrels

⁽²⁾	bcf = billions of cubic feet

⁽³⁾	Includes equity in affiliates

⁽⁴⁾	Natural gas converted to oil-equivalent gas (OEG) barrels at 6 MCF = 1 OEG barrel.


⁽¹⁾	Indicates the 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 oil or gas or, in the case of a dry well, the reporting of abandonment to the appropriate agency.

⁽²⁾	Gross wells include the total number of wells in which the company has an interest. Net wells are the sum of the company’s fractional interests in gross wells.


⁽¹⁾	Capacity and input amounts for El Paso represent ChevronTexaco’s share.

⁽²⁾	Refineries in Perth Amboy, New Jersey and Portland, Oregon, which are primarily asphalt plants.


⁽³⁾	Represents ChevronTexaco interests in Equilon and Motiva refineries, which were placed in trust on October 9, 2001, as required by the U.S. Federal Trade Commission, and disposed of in February 2002.

⁽⁴⁾	ChevronTexaco ceased refining operations at the Panama and Guatemala refineries on July 21, 2002 and September 12, 2002, respectively. The Guatemala facility was converted to terminal operations in 2002 while the Panama facility is expected to be converted to a terminaling facility in 2003.


⁽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.


	(1) A Current Report on Form 8-K was filed by the company on November 20, 2002. In this report, ChevronTexaco filed a press release dated November 19, 2002, announcing that the company amended the Rights Agreement, dated as of November 23, 1998, as amended, between ChevronTexaco and Mellon Investor Services LLC, as rights agent. The Rights Agreement was amended so that ChevronTexaco’s Series A Preferred Stock Purchase Rights will expire on November 23, 2003, five years earlier than November 23, 2008, the initial expiration date of the agreement.

	(2) A Current Report on Form 8-K was filed by the company on January 31, 2003. In this report, ChevronTexaco filed a press release announcing preliminary unaudited fourth quarter 2002 net income of $904 million.

	(3) A Current Report on Form 8-K was filed by the company on February 18, 2003. This report included a Second Supplemental Indenture among ChevronTexaco Capital Company, as Issuer, ChevronTexaco Corporation, as Guarantor, and JPMorgan Chase Bank, as Trustee, dated as of February 12, 2003.


*	See also Note 15 to the consolidated financial statements on page FS-37


	1. I have reviewed this Annual Report on Form 10-K of ChevronTexaco Corporation;

	2. Based on my knowledge, this Annual Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Annual Report;

	3. Based on my knowledge, the financial statements, and other financial information included in this Annual Report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this Annual Report;

	4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:


	a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Annual Report is being prepared;

	b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this Annual Report (the “Evaluation Date”); and

	c) presented in this Annual Report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;


	a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

	b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and


	/s/ DAVID J. O’REILLY

	David J. O’Reilly
	Chairman of the Board and Chief Executive Officer


	/s/ JOHN S. WATSON

	John S. Watson
	Vice-President, Finance and Chief Financial Officer


		NET PROVED RESERVES OF NATURAL GAS

		Billions of cubic feet

		Consolidated Companies															Affiliates

								Asia-														World-
		U.S.			Africa			Pacific			Other			Total			TCO			Hamaca		wide

RESERVES AT JANUARY 1, 2000			7,993			326			4,088			3,175			15,582			1,581			–		17,163
Changes attributable to:
	Revisions		92			450			308			67			917			126			–		1,043
	Improved recovery		17			–			–			5			22			–			–		22
	Extensions and discoveries		990			1			236			143			1,370			9			33		1,412
	Purchases¹		262			12			–			–			274			–			–		274
	Sales²		(367	)		–			–			(70	)		(437	)		–			–		(437	)
	Production		(1,064	)		(17	)		(190	)		(329	)		(1,600	)		(33	)		–		(1,633	)

RESERVES AT DECEMBER 31, 2000			7,923			772			4,442			2,991			16,128			1,683			33		17,844
Changes attributable to:
	Revisions		(20	)		780			330			(10	)		1,080			317			–		1,397
	Improved recovery		24			7			11			16			58			–			–		58
	Extensions and discoveries		587			329			164			445			1,525			130			9		1,664
	Purchases¹		41			–			6			6			53			187			–		240
	Sales²		(180	)		–			–			–			(180	)		–			–		(180	)
	Production		(988	)		(16	)		(194	)		(360	)		(1,558	)		(55	)		–		(1,613	)

RESERVES AT DECEMBER 31, 2001			7,387			1,872			4,759			3,088			17,106			2,262			42		19,410
Changes attributable to:
	Revisions		(598	)		277			390			92			161			293			1		455
	Improved recovery		21			42			4			10			77			–			–		77
	Extensions and discoveries		395			134			260			103			892			–			–		892
	Purchases¹		93			–			8			–			101			–			–		101
	Sales²		(3	)		–			–			–			(3	)		–			–		(3	)
	Production		(878	)		(27	)		(257	)		(369	)		(1,531	)		(66	)		–		(1,597	)

RESERVES AT DECEMBER 31, 2002			6,417			2,298			5,164			2,924			16,803			2,489			43		19,335

Developed reserves

	At January 1, 2000		6,733			276			2,342			2,368			11,719			1,011			–		12,730
	At December 31, 2000		6,408			294			3,108			2,347			12,157			1,019			–		13,176
	At December 31, 2001		6,246			444			3,170			2,231			12,091			1,477			6		13,574
	At December 31, 2002		5,636			582			3,196			2,157			11,571			1,474			6		13,051

¹		Includes reserves acquired through property exchanges.
²		Includes reserves disposed of through property exchanges.